TSX, NYSE MKT: BXE
CALGARY, March 7, 2013 /CNW/ - Bellatrix Exploration Ltd. ("Bellatrix"
or the "Company") (TSX, NYSE MKT: BXE) announces its financial and
operating results for the year ended December 31, 2012.
Forward-Looking Statements
This press release, including the report to shareholders, contains
forward-looking statements. Please refer to our cautionary language on
forward-looking statements and the other matters set forth at the
beginning of the management's discussion and analysis (the "MD&A")
attached to this press release.
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HIGHLIGHTS
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Years ended December 31,
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2012
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2011
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FINANCIAL (unaudited)
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(CDN$000s except share and per share amounts)
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Revenue (before royalties and risk management (1))
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219,314
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202,318
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Funds flow from operations (2)
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111,038
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94,237
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Per basic share (6)
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$1.03
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$0.91
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Per diluted share (6)
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$0.96
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$0.84
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Cash flow from operating activities
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109,328
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98,192
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Per basic share (6)
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$1.02
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$0.95
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Per diluted share (6)
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$0.95
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$0.87
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Net profit before certain non-cash items (5)
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21,746
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17,105
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Per basic share (6)
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$0.20
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$0.16
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Per diluted share (6)
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$0.20
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$0.16
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Net profit (loss)
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27,771
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(5,949)
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Per basic share (6)
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$0.26
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($0.06)
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Per diluted share (6)
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$0.25
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($0.06)
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Exploration and development
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164,187
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175,495
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Corporate and property acquisitions
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21,160
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4,066
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Capital expenditures - cash
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185,348
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179,561
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Property dispositions - cash
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(6,660)
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(4,203)
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Non-cash items
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25,875
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10,575
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Total capital expenditures - net
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204,563
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185,933
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Long-term debt
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133,047
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56,701
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Convertible debentures (7)
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50,687
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49,076
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Adjusted working capital deficiency (3)
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5,843
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13,473
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Total net debt (3)
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189,577
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119,250
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Total assets
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681,421
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580,422
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Shareholders' equity
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381,106
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348,405
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OPERATING
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Years ended December 31,
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2012
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2011
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Average daily sales volumes
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Crude oil, condensate and NGLs
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(bbls/d)
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5,717
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4,540
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Natural gas
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(mcf/d)
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65,812
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44,484
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Total oil equivalent
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(boe/d)
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16,686
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11,954
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Average prices
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Light crude oil and condensate
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($/bbl)
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86.47
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92.51
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NGLs (excluding condensate)
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($/bbl)
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38.88
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53.54
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Heavy oil
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($/bbl)
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68.51
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68.23
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Crude oil, condensate and NGLs
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($/bbl)
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73.59
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83.89
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Crude oil, condensate and NGLs (including risk
management (1))
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($/bbl)
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72.65
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81.47
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Natural gas
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($/mcf)
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2.62
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3.77
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Natural gas (including risk management (1))
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($/mcf)
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3.17
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4.05
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Total oil equivalent
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($/boe)
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35.56
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45.88
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Total oil equivalent (including risk management (1))
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($/boe)
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37.40
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46.01
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Statistics
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Operating netback (4)
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($/boe)
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19.66
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25.09
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Operating netback (4) (including risk management (1))
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($/boe)
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21.51
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25.22
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Transportation
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($/boe)
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0.82
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1.31
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Production expenses
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($/boe)
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8.73
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11.53
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General & administrative
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($/boe)
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2.34
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2.83
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Royalties as a % of sales after
Transportation
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18%
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18%
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COMMON SHARES
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Common shares outstanding
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107,868,774
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107,407,241
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Share options outstanding
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9,420,451
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7,985,320
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Shares issuable on conversion of convertible debentures (7)
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9,821,429
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9,821,429
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Diluted common shares outstanding
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127,110,654
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125,213,990
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Diluted weighted average shares - net profit (loss) (6)
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109,125,094
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103,857,689
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Diluted weighted average shares - funds flow from
operations and cash flow from operating activities (2) (6)
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118,946,523
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116,046,595
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SHARE TRADING STATISTICS
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TSX and Other (8) (CDN$, except volumes) based on intra-day trading
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High
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5.67
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6.19
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Low
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2.45
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3.15
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Close
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4.27
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4.91
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Average daily volume
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1,127,281
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1,152,846
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NYSE MKT (9) (US$, except volumes) based on intra-day trading
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High
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4.54
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Low
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3.69
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Close
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4.28
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Average daily volume
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37,924
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(1)
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The Company has entered into various commodity price risk management
contracts which are considered to be economic hedges. Per unit metrics
after risk management include only the realized portion of gains or
losses on commodity contracts.
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The Company does not apply hedge accounting to these contracts. As
such, these contracts are revalued to fair value at the end of each
reporting date. This results in recognition of unrealized gains or
losses over the term of these contracts which is reflected each
reporting period until these contracts are settled, at which time
realized gains or losses are recorded. These unrealized gains or
losses on commodity contracts are not included for purposes of per unit
metrics calculations disclosed.
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(2)
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The highlights section contains the term "funds flow from operations"
which should not be considered an alternative to, or more meaningful
than cash flow from operating activities as determined in accordance
with generally accepted accounting principles ("GAAP") as an indicator
of the Company's performance. Therefore reference to the additional
GAAP measures of funds flow from operations, or funds flow from
operations per share may not be comparable with the calculation of
similar measures for other entities. Management uses funds flow from
operations to analyze operating performance and leverage and considers
funds flow from operations to be a key measure as it demonstrates the
Company's ability to generate the cash necessary to fund future capital
investments and to repay debt. The reconciliation between cash flow
from operating activities and funds flow from operations can be found
in the MD&A. Funds flow from operations per share is calculated using
the weighted average number of common shares for the period.
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(3)
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Net debt and total net debt are considered additional GAAP measures.
The Company's calculation of total net debt includes the liability
component of convertible debentures and excludes deferred liabilities,
long-term commodity contract liabilities, decommissioning liabilities,
long-term finance lease obligations and the deferred tax liability.
Net debt and total net debt include the net working capital deficiency
(excess) before short-term commodity contract assets and liabilities
and current finance lease obligations. Net debt also excludes the
liability component of convertible debentures. A reconciliation between
total liabilities under GAAP and total net debt and net debt as
calculated by the Company is found in the MD&A.
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(4)
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Operating netbacks is considered a non-GAAP term. Operating netbacks
are calculated by subtracting royalties, transportation, and operating
costs from revenues before other income.
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(5)
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Net profit before certain non-cash items is considered a non-GAAP term.
Net profit before certain non-cash items is calculated as net profit
(loss) per the Consolidated Statement of Comprehensive Income,
excluding the non-cash impairment loss, unrealized gain or loss on
commodity contracts, gain property acquisition, and gain or loss on
property dispositions, net of the deferred tax impact on these
adjustments. The Company's reconciliation between net profit (loss) and
net profit before certain non-cash items is found in the MD&A.
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(6)
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Basic weighted average shares for the year ended December 31, 2012 were
107,543,811 (2011: 103,857,689).
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In computing weighted average diluted earnings and weighted average
diluted net profit before certain non-cash items per share for the year
ended December 31, 2012, a total of 1,581,283 (2011: 2,367,477) common
shares, were added to the denominator as a consequence of applying the
treasury stock method to the Company's outstanding share options as
they were dilutive, and a total of 9,821,429 (2011: 9,821,429) common
shares issuable on conversion of convertible debentures were excluded
from the denominator as they were not dilutive, resulting in diluted
weighted average shares of 109,125,094 (2011: 106,225.166).
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In computing weighted average diluted cash flow from operating
activities and funds flow from operations per share for the year ended
December 31, 2012, a total of 1,581,283 (2011: 2,367,477) common shares
were added to the denominator as a consequence of applying the treasury
stock method to the Company's outstanding share options and a total of
9,821,429 (2011: 9,821,429) common shares issuable on conversion of
convertible debentures were also added to the denominator as they were
dilutive, resulting in diluted weighted average common shares of
118,946,523 (2011: 116,046,595). As a consequence, a total of $3.2
million (2011: $3.0 million) for interest accretion expense (net of
income tax effect) were added to the numerator.
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(7)
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Shares issuable on conversion of convertible debentures are calculated
by dividing the $55.0 million principal amount of the convertible
debentures by the conversion price of $5.60 per share.
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(8)
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TSX and Other includes the trading statistics for the Toronto Stock
Exchange and other Canadian trading markets.
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(9)
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The Company's common shares commenced trading on the NYSE MKT on
September 24, 2012.
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REPORT TO SHAREHOLDERS
Bellatrix's corporate strategy encompasses effective execution of a
defined exploitation oriented growth plan in the Western Canadian
Sedimentary Basin complemented with opportunistic tuck in
acquisitions. In 2012 the Company excelled as a "drill bit driven growth" story defined by;
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An experienced innovative management team with a long history and proven
track record
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A highly technical/creative staff
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Being a low cost producer/operator/finder
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Preserving a strong balance sheet with hedging and debt maintenance
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Possessing and expanding a top tier asset base
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Exceptional industry leading well results on the core Cardium and
Notikewin resource plays
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Large inventory of high IRR opportunities (692 net locations in the
Cardium and 401 net locations in the Notikewin/Falher totaling net
capital development opportunity of $4.34 billion)
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Near term catalysts with forecast 2013 exit rate of 30,000 to 31,000
boe/d.
Despite average oil & gas prices softening in 2012 when compared to 2011
by 10.8% and 30.5%, respectively, Bellatrix posted its fourth
consecutive year of industry leading drill bit growth. Since
converting to an exploration company in November of 2009 the Company
has grown production by 155%, liquids production by 235%, reserves per
share by 191% and cash flow per share by 164%. Fiscal year 2012 proved
to be an exceptional year punctuated by the following;
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Record production levels of 6.1 million boe
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Achieving Company average annual guidance of 16,686 boe/d and exit
production guidance of 19,500 boe/d
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Reducing lease operating expenses to $8.73/boe
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Establishing industry leading 2P FD&A including FDC of $6.95/boe
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Posting a 2P excluding FDC Recycle Ratio of 5.02 times
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Increased 2P reserves by 54% to 104 million barrels with a 10% NPV of
$1.07 billion and a net asset value of $9.90 per basic share.
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At December 31, 2012, the Company had approximately $87 million or 40%
was undrawn under the existing $220 million credit facility.
Currently the Company is focusing on developing its two core resource
plays, the Cardium and the Notikewin/Falher intervals in Western
Canada. The Notikewin/Falher in Alberta's deep basin boasts abundant,
liquids-rich natural gas with compelling economics. The Cardium is a
highly economic investment that we believe has the potential to add
substantial reserves, production and long term economic value for our
shareholders. Both plays have thick resource rich reservoirs with
exceptional subsurface control which have proven to be predictable and
repeatable with the application of modern drilling and completion
techniques. To date the Company has drilled 111 Cardium wells and 24
Notikewin/Falher wells posting a 100% success rate.
To accelerate the development of the aforementioned 24 year drilling
inventory on the Company's key plays while maintaining a strong balance
sheet and minimizing the issuing of equity Bellatrix entered into a
joint venture agreement with a Seoul Korea based company ("JV
Partner"), to accelerate development of Bellatrix's extensive
undeveloped Cardium land holdings in west-central Alberta. Under the
terms of the agreement, the JV Partner will contribute 50%, or CDN$150
million, to a $300 million joint venture (the "Joint Venture") to
participate in an expected 83 Cardium well program. Under the
agreement, the JV Partner will earn 33% of Bellatrix's working interest
in the Cardium well program until payout (being recovery of the JV
Partner's capital investment plus an 8% return on investment) on the
total program, which is expected to occur prior to a maximum of 7
years, reverting to a 20% working interest after payout. The effective
date of the agreement is April 1, 2013 but with the ability of the JV
Partner to elect to invest in the wells drilled between January 1 and
up to April 30, 2013. Certain conditions precedent are expected to be
satisfied or waived by April 22, 2013 which is expected to enable
closing to occur on or before April 30, 2013. Bellatrix will be
required to provide a guarantee of the return of the JV Partner's
capital investment of up to $30 million if not recovered within 7
years.
Operational highlights for the three months and year ended December 31,
2012 include:
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During the 2012 year, Bellatrix posted a 100% success rate drilling
and/or participating in 34 gross (26.32 net) wells, resulting in 28
gross (21.32 net) Cardium oil wells, 2 gross (2.0 net) Cardium
condensate-rich gas wells, 1 gross (1.0 net) Duvernay gas well, and 3
gross (2.0 net) Notikewin/Falher liquids-rich gas wells. In the fourth
quarter of 2012, Bellatrix drilled or participated in 10 gross wells
(6.17 net), all of which were Cardium light oil horizontal wells.
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During fiscal 2012 the Company operated 24 gross Cardium wells of the 28
gross wells reported. The following average initial production ("IP")
rates for the first 7 days ("IP7"), for the first 15 days ("IP15") and
the first 30 days ("IP30") were achieved:
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Time
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# of wells
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Boe/d
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IP 7
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24
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769
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IP 15
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24
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715
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IP 30
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24
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656
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Q4 2012 sales volumes averaged 18,763 boe/d (weighted 31% to oil,
condensate and NGLs and 69% to natural gas). This represents a 32%
increase from the fourth quarter 2011 average sales volumes of 14,209
boe/d and a 21% increase from third quarter 2012 average sales volumes
of 15,503 boe/d.
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2012 annual sales volumes averaged 16,686 boe/d (weighted 34% to oil,
condensate and NGLs and 66% to natural gas). This represents a 40%
increase from 2011 average sales volumes of 11,954 boe/d.
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In the fourth quarter of 2012 the Company spent $53.0 million on capital
projects, including $21.0 on a tuck in acquisition in the Willesden
Green area, compared to $47.3 million during the fourth quarter of
2011.
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On December 14, 2012, Bellatrix acquired an additional 11 gross and net
sections of highly prospective Cardium and Notikewin/Falher lands in
the Ferrier area of west-central Alberta. This acquisition is
anticipated to provide an additional 37 net drilling locations in the
Cardium, 9 net locations in the Notikewin/Falher and an additional 66
net locations in the Duvernay formation.
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As at December 31, 2012, Bellatrix had approximately 206,638 net
undeveloped acres of land in Alberta, British Columbia and
Saskatchewan.
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Effective November 1, 2012, Bellatrix acquired additional highly
prospective Cardium and Notikewin/Falher lands and production in the
Willesden Green area of Alberta with 500 boe/d of production, 16 gross
(11.95 net) sections of Cardium and Mannville prospective lands, 25 net
Cardium development locations, 4 net Notikewin/Falher development
locations and a 25% working interest in an operated compressor station
and gathering system. The purchase price of $21 million was funded
using the Company's existing credit facility.
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During Q3 2012, Bellatrix closed on the disposition of a minor non-core
property interest in the Wainwright Alberta area for $4.3 million after
adjustments.
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During Q2 2012, Bellatrix closed on the disposition of the Girouxville
property in Alberta, a minor non-core interest, for $0.6 million after
adjustments.
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During Q2 2012, Bellatrix closed on the disposition of a non-core
property interest in Cypress-Chowade in British Columbia for $1.4
million after adjustments.
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Bellatrix continued with its 2 year crusade toward inviolable
sovereignty of the infrastructure in its core areas of Brazeau and
Ferrier. In 2012 and 2013 the Company is connecting to over half a BCF
of daily capacity in third party operated gas plants in close
proximity. In 2012 and Q1 2013 the Company has installed a total of 7.5
km of 6" pipeline, 64 km of 8" pipeline, 47.4 km of 10" pipeline and 25
km of 12" pipeline providing unfettered access to the aforementioned
facilities. In addition Bellatrix commissioned a 3,300 HP compressor
station in Ferrier and is currently constructing an additional 3,300 HP
compressor station in the Ferrier area.
Financial highlights for the three months and year ended December 31,
2012 include:
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Q4 2012 revenue was $62.3 million, 5% higher than the $59.2 million
recorded in Q4 2011. Revenue for the year ended December 31, 2012 was
$219.3 million, up 8% from $202.3 million in 2011. The increase in
revenues is a result of higher sales volumes between periods, offset
partially by reduced liquids and natural gas prices experienced in the
2012 periods.
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Funds flow from operations for Q4 2012 was $29.9 million ($0.28 per
basic share), up 12% from $26.6 million ($0.25 per basic share) in Q3
2012 and down 1% from $30.1 million ($0.28 per basic share) in Q4
2012. Funds flow from operations for the year ended December 31, 2012
was $111.0 million ($1.03 per basic share), up 18% from $94.2 million
($0.91 per basic share) in 2011.
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For the three and twelve months ended December 31, 2012, net profit
before non-cash impairment loss, unrealized gain (loss) on commodity
contracts, gain on property acquisition, and gain (loss) on property
dispositions, net of associated deferred tax impacts, was $7.3 million
and $21.7 million, compared to $7.9 million and $17.1 million in 2011
periods, respectively.
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The net profit for Q4 2012 was $9.3 million, compared to a net loss of
$13.6 million in Q4 2011.
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The net profit for the year ended December 31, 2012 was $27.8 million,
compared to a net loss of $5.9 million in 2011.
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Crude oil, condensate and NGLs produced 60% and 71% of petroleum and natural gas sales revenue for the three and
twelve month periods ended December 31, 2012, respectively.
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Production expenses for Q4 2012 were $8.91/boe ($15.4 million), compared
to $10.78/boe ($14.1 million) for Q4 2011. Production expenses for the
year ended December 31, 2012 were $8.73/boe ($53.3 million) compared to
$11.53/boe ($50.3 million) in 2011. The decrease was due to increased
production volumes which is a result of 2011 and 2012 drilling in areas
with lower production expenses, as well as reduced processing fees in
certain areas and continued field optimization projects.
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Operating netbacks after including risk management for Q4 2012 were
$20.83/boe, down from $26.38/boe in Q4 2011. Operating netbacks before
risk management for Q4 2012 were $19.20/boe, down from $26.00/boe in Q4
2011 and up from $18.29/boe in Q3 2012. The decreased netback for Q4
2012 compared to Q4 2011 was primarily the result of reduced commodity
prices and slightly higher royalties, despite a reduction in
transportation and production expenses. The Q4 2012 netback reflects
slightly increased overall commodity prices, despite slightly increased
expenses compared to Q3 2012.
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Operating netbacks before risk management for the year ended December
31, 2012 were $19.66/boe, down from $25.09/boe in 2011.
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Bellatrix spent $53.0 million on capital projects during Q4 2012
compared to $47.3 million in Q4 2011. For the year ended December 31,
2012, Bellatrix spent $185.3 million on capital projects compared to
$179.6 million in 2011.
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Proceeds from property dispositions were $6.7 million for the year ended
December 31, 2012, compared to $4.2 million for 2011.
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G&A expenses for Q4 2012 decreased to $2.54/boe ($4.4 million), compared
to $2.88/boe ($3.8 million) for Q4 2011. G&A expenses for the year
ended December 31, 2012 were $2.34/boe ($14.3 million), compared to
$2.83/boe ($12.4 million) in 2011.
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On September 20, 2012, Bellatrix received approval for listing of its
common shares on the NYSE MKT, and its common shares commenced trading
on September 24, 2012 under the symbol "BXE".
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A syndicate of banks led by National Bank of Canada recently completed
its semi-annual borrowing base determination for November 30, 2012.
Effective December 13, 2012, the Company's borrowing base was increased
by $20 million to $220 million, through to the next redetermination
date of May 31, 2013.
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As at December 31, 2012, Bellatrix had $87.0 million drawn on its total
$220 million credit facility.
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Total net debt as of December 31, 2012 was $189.6 million, including the
liability component of convertible debentures.
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As at December 31, 2012, Bellatrix has approximately $584 million in tax
pools available for deduction against future income.
RESERVES
Highlights from Bellatrix's December 31, 2012 reserves include:
Total proved plus probable company interest reserves, including all
royalties receivable but before deducting royalty burdens, as evaluated
by Sproule Associates Limited. ("Sproule") at December 31, 2012 were
104,258 mboe (gas converted 6:1). This represents a 54% increase from
the 67,550 mboe of 2P reserves as at December 31, 2011. By commodity
type, natural gas makes up 67%, oil and natural gas liquids 33% of
total reserves. At December 31, 2012, the Company's total proved
company interest reserves were 55,490 mboe, an increase of 33% compared
to 41,818 mboe at December 31, 2011.
-
Including properties which were disposed in 2012, proved and probable
company interest reserve additions in 2012 replaced 702% of total
production.
-
The net present value of future net revenue of working interest reserves
(which does not represent fair market value) at a 10% discount rate
improved to $1,106.9 million up from $722.5 million posted in 2011
representing an increase of 53%.
-
Bellatrix's net asset value, as at December 31, 2012, based on the
Sproule evaluation at a 10% discount rate, internal estimates of the
value of undeveloped lands and seismic, and 107.9 million common
shares outstanding, equates to $9.90 per basic share outstanding and is
$13.77 per basic share outstanding at a 5% discount rate.
-
The Company's reserve life index has improved to 8.6 years for total
company interest proved reserves up from 8.0 years in 2011 with total
company interest proved and probable reserve life index of 12.4 years
compared to 10.0 years presented in 2011. These 2012 indices were
based on first year production as set forth in Sproule Report with 2012
company interest production of 17,655 boe/d and 22,888 boe/d for total
company interest proved reserves and proved and probable reserves,
respectively.
-
2012 finding, development and acquisition costs ("FD&A") including
changes to future development capital ("FDC") for total proved plus
probable reserves were $6.95/boe. The three year average FD&A
including FDC is $9.04/boe.
-
2012 FD&A including changes to FDC for proved reserves equated to
$11.77/boe.
-
At year end, 2012, Sproule had evaluated certain future development
opportunities on Company lands including 161 gross (112.7 net) future
undrilled Cardium horizontal locations and 56 gross (23.3 net)
evaluated future undrilled Notikewin/Falher horizontal locations. Of
the 161 Cardium locations, 104 were assigned proved and probable
reserves, with 57 assigned probable reserves only. Of the 56
Notikewin/Falher locations, 41 were assigned proved and probable
reserves, with the remaining 15 assigned probable reserves only.
-
The Company established recycle ratios, after commodity price risk
management contracts and excluding future development costs of 2.35
times on a proved basis and 5.02 times on a proved and probable basis.
The Company recorded all-in annual FD&A cost of $9.16 per boe in 2012
before consideration of FDC for proved reserves category. The three
year average FD&A cost is $8.69 per boe for the proved category before
FDC; for the proved category including FDC, the three year average FD&A
cost is $13.22 per boe.
In addition to the information disclosed herein, more detailed
information on the Company's reserves will be included in the Company's
Annual Information Form and SEC Annual Report on Form 40-F. For
additional information please refer to the reserves news release dated
February 21, 2013 (posted on www.sedar.com and filed with the SEC at www.sec.gov).
COMMODITY PRICE RISK MANAGEMENT
In January 2013, Bellatrix reset the fixed prices on two of its
commodity price risk management contracts for natural gas fixed price
swaps. The first existing swap contract for 20,000 GJ/d for the period
April 1, 2013 to October 31, 2013 was reset from a price of
CDN$4.0875/GJ to $3.05/GJ (CDN$3.51/mcf) for a net payment to Bellatrix
of $4.3 million. The second existing swap contract for 10,000 GJ/d for
the period April 1, 2013 to October 31, 2013 was reset from a price of
CDN $4.15/GJ to CDN$3.095/GJ (CDN$3.56/mcf) for a net payment to
Bellatrix of $2.2 million. Bellatrix now has 55,000 GJ/d (47.8 mmcf/d)
for the period April 1, 2013 through to October 31, 2013 hedged at an
average fixed price of $3.058/GJ ($3.52/mcf). By resetting the fixed
prices on the natural gas commodity price risk management contracts for
the period from April 1, 2013 through to October 31, 2013, the Company
has crystalized and realized $6.5 million in cash proceeds while
continuing to have put in place ongoing down side price protection on
the existing 55,000 GJ/d (47.8 mmcf/d) if natural gas prices were to
move lower than the fixed price of $3.058/GJ ($3.52/mcf).
As of March 6, 2013, the Company has entered into the following
commodity price risk management arrangements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
|
Period
|
|
Volume
|
|
|
Price Floor
|
|
|
Price Ceiling
|
|
Index
|
|
Crude oil fixed (1)
|
|
|
January 1, 2013 to Dec. 31, 2013
|
|
1,500 bbl/d
|
|
$
|
94.50 CDN
|
|
$
|
94.50 CDN
|
|
WTI
|
|
Crude oil call option
|
|
|
January 1, 2013 to Dec. 31, 2013
|
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3,000 bbl/d
|
|
|
-
|
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$
|
110.00 US
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WTI
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Crude oil call option
|
|
|
January 1, 2014 to Dec. 31, 2014
|
|
3,000 bbl/d
|
|
|
-
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|
$
|
105.00 US
|
|
WTI
|
|
Natural gas fixed
|
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|
April 1, 2013 to Oct. 31, 2013
|
|
20,000 GJ/d
|
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$
|
3.05 CDN
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$
|
3.05 CDN
|
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AECO
|
|
Natural gas fixed
|
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April 1, 2013 to Oct. 31, 2013
|
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10,000 GJ/d
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$
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3.095 CDN
|
|
$
|
3.095 CDN
|
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AECO
|
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Natural gas fixed
|
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|
Feb. 1, 2013 to Dec. 31, 2013
|
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10,000 GJ/d
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$
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3.05 CDN
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$
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3.05 CDN
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AECO
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Natural gas fixed
|
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April 1, 2013 to June 30, 2014
|
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15,000 GJ/d
|
|
$
|
3.05 CDN
|
|
$
|
3.05 CDN
|
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AECO
|
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(1)
|
A call has been placed on 3,000 bbl/d at $110 US/bbl for the year 2013
and at $105 US/bbl for the calendar year 2014.
|
OUTLOOK
As a result of the recently announced joint venture with a Seoul Korea
based company, Bellatrix's 2013 capital expenditure budget has been
increased to between $230 and $240 million. A total capital program of $365 million is anticipated including the capital expected to be invested by the JV
partner. Based on the timing of proposed expenditures, downtime for
scheduled and unscheduled plant turnarounds, completion of required
infrastructure, and normal production declines, execution of the 2013
capital expenditure plan is expected to provide average daily
production of approximately 24,000 boe/d to 25,000 boe/d, and an exit
rate of approximately 30,000 boe/d to 31,000 boe/d.
The Company has initiated the 2013 program by instituting drilling of
multiple horizontal wells from single surface locations. Pad drilling
enhances the opportunity to efficiently develop the resource while
minimizing the environmental footprint and improving our cost and
on-stream efficiencies. Pad drilling also facilitates drilling through
the spring breakup months of Q2. As a result the Company plans to run
3 rigs throughout the second quarter ramping up to 7 or 8 rigs for the
second half of 2013.
The key operational strategy Bellatrix employs is to focus on full cycle
profitability, indifferent to product type, with every investment
decision.
As always the Company's priority is to bring together the technical,
operational and financial talent required to create long term value growth for our shareholders.
Raymond G. Smith, P. Eng.
President and CEO
March 6, 2013
Note:
A conference call to discuss Bellatrix's annual financial and reserves
results will be held on March 7, 2013 at [11:00 am MDT/1:00 pm EDT]. To
participate, please call toll-free 1-888-231-8191 or 647-427-7450. The
conference call will also be recorded and available by calling
1-855-859-2056 or 403-451-9481 and entering passcode 16291676 followed
by the pound sign.
Bellatrix's annual meeting is scheduled for 3:00 pm on May 22, 2013 in
the Devonian Room at the Calgary Petroleum Club.
MANAGEMENT'S DISCUSSION AND ANALYSIS
March 6, 2013 - The following Management's Discussion and Analysis of
financial results ("MD&A") as provided by the management of Bellatrix
Exploration Ltd. ("Bellatrix" or the "Company") should be read in
conjunction with the audited consolidated financial statements of the
Company for the years ended December 31, 2012 and 2011. This
commentary is based on information available to, and is dated as of,
March 6, 2013. The financial data presented is in Canadian dollars,
except where indicated otherwise.
CONVERSION: The term barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio
of six thousand cubic feet of natural gas to one barrel of oil
equivalent (6 mcf/bbl) is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. Given that the value ratio based on
the current price of crude oil as compared to natural gas is
significantly different from the energy equivalency of 6:1, utilizing a
conversion on a 6:1 basis may be misleading as an indication of value.
All boe conversions in this report are derived from converting gas to
oil in the ratio of six thousand cubic feet of gas to one barrel of
oil.
INITIAL PRODUCTION RATES: Initial production rates disclosed herein may
not necessarily be indicative of long-term performance or ultimate
recovery.
ADDITIONAL GAAP MEASURES: This Management's Discussion and Analysis and
the accompanying report to shareholders and financial statements
contain the term "funds flow from operations" which should not be
considered an alternative to, or more meaningful than "cash flow from
operating activities" as determined in accordance with generally
accepted accounting principles ("GAAP") as an indicator of the
Company's performance. Therefore reference to funds flow from
operations or funds flow from operations per share may not be
comparable with the calculation of similar measures for other entities.
Management uses funds flow from operations to analyze operating
performance and leverage and considers funds flow from operations to be
a key measure as it demonstrates the Company's ability to generate the
cash necessary to fund future capital investments and to repay debt.
The reconciliation between cash flow from operating activities and
funds flow from operations can be found in this Management's Discussion
and Analysis. Funds flow from operations per share is calculated using
the weighted average number of shares for the period.
This Management's Discussion and Analysis and the accompanying report to
shareholders and financial statements contain the term total net debt
and net debt. Total net debt is calculated as long-term debt plus the
liability component of the convertible debentures and the net working
capital deficiency (excess) before short-term commodity contract assets
and liabilities and current finance lease obligations. Management
believes these measures are useful supplementary measures of the total
amount of current and long-term debt.
NON-GAAP MEASURES: This Management's Discussion and Analysis and the
accompanying report to shareholders also contains other terms such as
net profit before certain non-cash items and operating netbacks, which
are not recognized measures under GAAP. Net profit before certain
non-cash items is calculated as net profit (loss) per the Consolidated
Statement of Comprehensive Income, excluding the non-cash impairment
loss, net unrealized gain or loss on commodity contracts, gain on
property acquisition, and gain or loss on property dispositions net of
the deferred tax impact on these adjustments. Net debt is calculated as
long-term debt plus the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities and current
finance lease obligations. Operating netbacks are calculated by
subtracting royalties, transportation, and operating expenses from
revenues before other income. Management believes these measures are
useful supplemental measures of firstly, the amount of net profit
before certain non-cash items, and secondly, the amount of revenues
received after transportation, royalties and operating expenses.
Readers are cautioned, however, that these measures should not be
construed as an alternative to net income determined in accordance with
GAAP as measures of performance. Bellatrix's method of calculating
these measures may differ from other entities, and accordingly, may not
be comparable to measures used by other companies.
Additional information relating to the Company, including the
Bellatrix's Annual Information Form, is available on SEDAR at www.sedar.com.
FORWARD LOOKING STATEMENTS: Certain information contained herein and in
the accompanying report to shareholders may contain forward looking
statements including management's assessment of future plans and
operations, drilling plans and the timing thereof, commodity price risk
management strategies, 2013 capital expenditure budget, the nature of
expenditures and the method of financing thereof, expected 2013 average
production and exit rate, anticipated liquidity of the Company and
various matters that may impact such liquidity, expected 2013 operating
expenses and general and administrative expenses, expected costs to
satisfy drilling commitments and method of funding drilling
commitments, commodity prices and expected volatility thereof,
estimated amount and timing of incurring decommissioning liabilities,
plans to utilize pad drilling and effect thereof, use of funds from
property dispositions, timing of closing of joint venture agreement,
the effect of certain acquisitions, and plans for facility construction
may constitute forward-looking statements under applicable securities
laws and necessarily involve risks including, without limitation, risks
associated with oil and gas exploration, development, exploitation,
production, marketing and transportation, loss of markets, volatility
of commodity prices, currency fluctuations, risks related to
satisfaction of conditions precedent to closing of joint venture
agreement, imprecision of reserve estimates, environmental risks,
competition from other producers, inability to retain drilling rigs and
other services, incorrect assessment of the value of acquisitions,
failure to realize the anticipated benefits of acquisitions, delays
resulting from or inability to obtain required regulatory approvals and
ability to access sufficient capital from internal and external
sources. Events or circumstances may cause actual results to differ
materially from those predicted, as a result of the risk factors set
out and other known and unknown risks, uncertainties, and other
factors, many of which are beyond the control of Bellatrix. In
addition, forward-looking statements or information are based on a
number of factors and assumptions which have been used to develop such
statements and information but which may prove to be incorrect and
which have been used to develop such statements and information in
order to provide shareholders with a more complete perspective on
Bellatrix's future operations. Such information may prove to be
incorrect and readers are cautioned that the information may not be
appropriate for other purposes. Although the Company believes that the
expectations reflected in such forward-looking statements or
information are reasonable, undue reliance should not be placed on
forward-looking statements because the Company can give no assurance
that such expectations will prove to be correct. In addition to other
factors and assumptions which may be identified herein, assumptions
have been made regarding, among other things: the impact of increasing
competition; the general stability of the economic and political
environment in which the Company operates; the timely receipt of any
required regulatory approvals; the ability of the Company to obtain
qualified staff, equipment and services in a timely and cost efficient
manner; drilling results; the ability of the operator of the projects
which the Company has an interest in to operate the field in a safe,
efficient and effective manner; the ability of the Company to obtain
financing on acceptable terms; field production rates and decline
rates; the ability to replace and expand oil and natural gas reserves
through acquisition, development of exploration; the timing and costs
of pipeline, storage and facility construction and expansion and the
ability of the Company to secure adequate product transportation;
future commodity prices; currency, exchange and interest rates; the
regulatory framework regarding royalties, taxes and environmental
matters in the jurisdictions in which the Company operates; and the
ability of the Company to successfully market its oil and natural gas
products. Readers are cautioned that the foregoing list is not
exhaustive of all factors and assumptions which have been used. As a
consequence, actual results may differ materially from those
anticipated in the forward-looking statements. Additional information
on these and other factors that could effect Bellatrix's operations and
financial results are included in reports on file with Canadian and US
securities regulatory authorities and may be accessed through the SEDAR
website (www.sedar.com, and at Bellatrix's website www.bellatrixexploration.com). Furthermore, the forward-looking statements contained herein are
made as at the date hereof and Bellatrix does not undertake any
obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information,
future events or otherwise, except as may be required by applicable
securities laws.
The reader is further cautioned that the preparation of financial
statements in accordance with GAAP requires management to make certain
judgments and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimating reserves is also
critical to several accounting estimates and requires judgments and
decisions based upon available geological, geophysical, engineering and
economic data. These estimates may change, having either a negative or
positive effect on net earnings as further information becomes
available, and as the economic environment changes.
Overview and Description of the Business
Bellatrix Exploration Ltd. ("Bellatrix" or the "Company") is a Western
Canadian based growth oriented oil and gas company engaged in the
exploration for, and the acquisition, development and production of oil
and natural gas reserves in the provinces of Alberta, British Columbia
and Saskatchewan.
Bellatrix's common shares and convertible debentures are listed on the
Toronto Stock Exchange under the symbols BXE and BXE.DB.A,
respectively, and the common shares of Bellatrix trade on the NYSE MKT
under the symbol BXE.
Cardium Joint Venture
Bellatrix has entered into a joint venture agreement with a Seoul Korea
based company ("JV Partner"), to accelerate development of Bellatrix's
extensive undeveloped Cardium land holdings in west-central Alberta.
Under the terms of the agreement, the JV Partner will contribute 50%,
or CDN$150 million, to a $300 million joint venture (the "Joint
Venture") to participate in an expected 83 Cardium well program. Under
the agreement, the JV Partner will earn 33% of Bellatrix's working
interest in the Cardium well program until payout (being recovery of
the JV Partner's capital investment plus an 8% return on investment) on
the total program, which is expected to occur prior to a maximum of 7
years, reverting to a 20% working interest after payout. The effective
date of the agreement is April 1, 2013 but with the ability of the JV
Partner to elect to invest in the wells drilled between January 1 and
up to April 30, 2013. Certain conditions precedent are expected to be
satisfied or waived by April 22, 2013 which is expected to enable
closing to occur on or before April 30, 2013. Bellatrix will be
required to provide a guarantee of the return of the JV Partner's
capital investment of up to $30 million if not recovered within 7
years.
Fourth Quarter 2012
|
HIGHLIGHTS
|
|
|
Three months ended December 31,
|
|
(CDN$000s except share and per share amounts)
|
|
|
2012
|
2011
|
|
FINANCIAL
|
|
|
|
|
|
Revenue (before royalties and risk management (1))
|
|
|
62,283
|
59,194
|
|
|
|
|
|
|
|
Funds flow from operations (2)
|
|
|
29,865
|
30,120
|
|
|
Per basic share (6)
|
|
|
$0.28
|
$0.28
|
|
|
Per diluted share (6)
|
|
|
$0.26
|
$0.26
|
|
Cash flow from operating activities
|
|
|
32,007
|
30,626
|
|
|
Per basic share (6)
|
|
|
$0.30
|
$0.28
|
|
|
Per diluted share (6)
|
|
|
$0.28
|
$0.26
|
|
Net profit before certain non-cash items (5)
|
|
|
7,299
|
7,938
|
|
|
Per basic share (6)
|
|
|
$0.07
|
$0.07
|
|
|
Per diluted share (6)
|
|
|
$0.07
|
$0.07
|
|
Net profit (loss)
|
|
|
9,251
|
(13,597)
|
|
|
Per basic share (6)
|
|
|
$0.09
|
($0.13)
|
|
|
Per diluted share (6)
|
|
|
$0.08
|
($0.13)
|
|
Exploration and development
|
|
|
32,083
|
47,141
|
|
Corporate and property acquisitions
|
|
|
20,965
|
121
|
|
Capital expenditures - cash
|
|
|
53,048
|
47,262
|
|
Property dispositions - cash
|
|
|
10
|
(22)
|
|
Non-cash items
|
|
|
27,487
|
6,165
|
|
Total capital expenditures - net
|
|
|
80,545
|
53,405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended December 31,
|
|
(CDN$000s except share and per share amounts)
|
|
|
2012
|
2011
|
|
OPERATING
|
|
|
|
|
|
Average daily sales volumes
|
|
|
|
|
|
|
Crude oil, condensate and NGLs
|
(bbls/d)
|
|
5,730
|
5,420
|
|
|
Natural gas
|
(mcf/d)
|
|
78,195
|
52,734
|
|
|
Total oil equivalent
|
(boe/d)
|
|
18,763
|
14,209
|
|
Average prices
|
|
|
|
|
|
|
Light crude oil and condensate
|
($/bbl)
|
|
82.58
|
95.18
|
|
|
NGLs (excluding condensate)
|
($/bbl)
|
|
38.84
|
54.31
|
|
|
Heavy oil
|
($/bbl)
|
|
65.30
|
74.30
|
|
|
Crude oil, condensate and NGLs
|
($/bbl)
|
|
69.55
|
85.09
|
|
|
Crude oil, condensate and NGLs (including risk management (1))
|
($/bbl)
|
|
72.11
|
82.90
|
|
|
Natural gas
|
($/mcf)
|
|
3.46
|
3.30
|
|
|
Natural gas (including risk management (1))
|
($/mcf)
|
|
3.67
|
3.62
|
|
|
Total oil equivalent
|
($/boe)
|
|
35.67
|
44.69
|
|
|
Total oil equivalent (including risk management (1))
|
($/boe)
|
|
37.30
|
45.07
|
|
Statistics
|
|
|
|
|
|
|
Operating netback (4)
|
($/boe)
|
|
19.20
|
26.00
|
|
|
Operating netback (4) (including risk management (1))
|
($/boe)
|
|
20.83
|
26.38
|
|
|
Transportation
|
($/boe)
|
|
0.70
|
1.21
|
|
|
Production expenses
|
($/boe)
|
|
8.91
|
10.78
|
|
|
General & administrative
|
($/boe)
|
|
2.54
|
2.88
|
|
|
Royalties as a % of sales after transportation
|
|
|
20%
|
15%
|
|
DILUTED WEIGHTED AVERAGE SHARES
|
|
|
|
|
|
Diluted weighted average shares - net profit (loss) (6)
|
|
|
118,931,047
|
109,349,045
|
Diluted weighted average shares - funds flow from
operations and cash flow from operating activities (2) (6)
|
|
|
118,931,047
|
119,170,474
|
|
SHARE TRADING STATISTICS
|
|
|
|
|
|
TSX and Other (7) (CDN$, except volumes) based on intra-day trading
|
|
|
|
|
|
High
|
|
|
4.47
|
5.05
|
|
Low
|
|
|
3.59
|
3.15
|
|
Close
|
|
|
4.27
|
4.91
|
|
Average daily volume
|
|
|
842,840
|
928,836
|
|
NYSE MKT (8) (US$, except volumes) based on intra-day trading
|
|
|
|
|
|
High
|
|
|
4.54
|
-
|
|
Low
|
|
|
3.69
|
-
|
|
Close
|
|
|
4.28
|
-
|
|
Average daily volume
|
|
|
39,079
|
-
|
|
(1)
|
The Company has entered into various commodity price risk management
contracts which are considered to be economic hedges. Per unit metrics
after risk management includes only the realized portion of gains or
losses on commodity contracts.
|
|
|
|
|
|
The Company does not apply hedge accounting to these contracts. As
such, these contracts are revalued to fair value at the end of each
reporting date. This results in recognition of unrealized gains or
losses over the term of these contracts which is reflected each
reporting period until these contracts are settled, at which time
realized gains or losses are recorded. These unrealized gains or
losses on commodity contracts are not included for purposes of per
share metrics calculations disclosed.
|
|
|
|
|
(2)
|
The highlights section contains the term "funds flow from operations"
which should not be considered an alternative to, or more meaningful
than cash flow from operating activities as determined in accordance
with generally accepted accounting principles ("GAAP") as an indicator
of the Company's performance. Therefore reference to additional GAAP
terms of diluted funds flow from operations or funds flow from
operations per share may not be comparable with the calculation of
similar measures for other entities. Management uses funds flow from
operations to analyze operating performance and leverage and considers
funds flow from operations to be a key measure as it demonstrates the
Company's ability to generate the cash necessary to fund future capital
investments and to repay debt. The reconciliation between cash flow
from operating activities and funds flow from operations can be found
further in the MD&A. Funds flow from operations per share is
calculated using the weighted average number of common shares for the
period.
|
|
|
|
|
(3)
|
Net debt and total net debt are considered additional GAAP terms. The
Company's calculation of total net debt includes the liability
component of convertible debentures and excludes deferred liabilities,
long-term commodity contract liabilities, decommissioning liabilities,
long-term finance lease obligations and the deferred tax liability.
Net debt and total net debt include the net working capital deficiency
(excess) before short-term commodity contract assets and liabilities
and current finance lease obligations. Net debt also excludes the
liability component of convertible debentures. A reconciliation between
total liabilities under GAAP and total net debt and net debt as
calculated by the Company is found further in the MD&A.
|
|
|
|
|
(4)
|
Operating netbacks is considered a non-GAAP term. Operating netbacks
are calculated by subtracting royalties, transportation, and operating
costs from revenues before other income.
|
|
|
|
|
(5)
|
Net profit before certain non-cash items is considered a non-GAAP term.
Net profit before certain non-cash items is calculated as net profit
(loss) per the Consolidated Statement of Comprehensive Income,
excluding the impairment loss (reversal) on property, plant and
equipment, the unrealized gain or loss on commodity contracts, the gain
on property acquisition, and the gain or loss on property dispositions,
net of deferred tax impacts on each item. The Company's reconciliation
between the net profit and net profit before certain non-cash items is
found in this MD&A.
|
|
|
|
|
(6)
|
Basic weighted average shares for the three months ended December 31,
2012 were 107,734,134 (2011: 107,397,265).
|
|
|
|
|
|
In computing weighted average diluted earnings per share for the three
months ended December 31, 2012, a total of 1,375,484 common shares were
added to the denominator as a consequence of applying the treasury
stock method to the Company's outstanding share options and a total of
9,821,429 common shares issuable on conversion of convertible
debentures were also added to the denominator as they were dilutive,
resulting in diluted weighted average common shares of 118,931,047. In
computing weighted average diluted earnings per share for the three
months ended December 31, 2011, a total of 1,951,780 common shares were
added to the denominator as a consequence of applying the treasury
stock method to the Company's outstanding share options and a total of
9,821,429 common shares issuable on conversion of convertible
debentures were excluded from the denominator as they were not
dilutive, resulting in diluted weighted average common shares of
107,397,265.
|
|
|
|
|
|
In computing weighted average diluted net profit before certain items
per share for the three months ended December 31, 2012, a total of
1,375,484 (2011: 1,951,780) common shares were added to the denominator
as a consequence of applying the treasury stock method to the Company's
outstanding share options as they were dilutive, and a total of
9,821,429 (2011: 9,821,429) common shares issuable on conversion of
convertible debentures were excluded from the denominator as they were
not dilutive, resulting in diluted weighted average common shares of
109,109,618 (2011:109,349,045).
|
|
|
|
|
|
In computing weighted average diluted cash flow from operating
activities and funds flow from operations per share for the three
months ended December 31, 2012, a total of 1,375,484 (2011: 1,951,780)
common shares were added to the denominator as a consequence of
applying the treasury stock method to the Company's outstanding share
options and a total of 9,821,429 (2011: 9,821,429) common shares
issuable on conversion of convertible debentures were also added to the
denominator as they were dilutive, resulting in diluted weighted
average common shares of 118,931,047 (2011: 119,170,474). As a
consequence, a total of $0.8 million (2011: $0.8 million) for interest
accretion expense (net of income tax effect) was added to the
numerator.
|
|
|
|
|
(7)
|
TSX and Other includes the trading statistics for the Toronto Stock
Exchange and other Canadian trading markets.
|
|
|
|
|
(8)
|
The Company's common shares commenced trading on the NYSE MKT on
September 24, 2012.
|
As detailed previously in this Management's Discussion and Analysis,
funds flow from operations is a term that does not have any
standardized meaning under GAAP. Funds flow from operations is
calculated as cash flow from operating activities before asset
retirement costs incurred and changes in non-cash working capital
incurred.
|
Reconciliation of Cash Flow from Operating Activities to Funds Flow from
Operations
|
|
|
|
Three months ended December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Cash flow from operating activities
|
|
|
32,007
|
30,626
|
|
Decommissioning costs incurred
|
|
|
76
|
186
|
|
Change in non-cash working capital
|
|
|
(2,218)
|
(692)
|
|
Funds flow from operations
|
|
|
29,865
|
30,120
|
Funds flow from operations during the fourth quarter of 2012 was $29.9
million, a decrease of 0.9% compared to $30.1 million for the fourth
quarter of 2011. The decrease in funds flow from operations between
the periods was due primarily to lower pricing for light and heavy oil,
condensate, and NGL's, largely offset by higher production volumes and
slightly higher natural gas prices in the 2012 fourth quarter.
Fluctuations in oil and gas prices during the fourth quarter of 2012
resulted in an increase in net realized gains on commodity risk
management contracts by approximately $2.3 million compared to the
fourth quarter of 2011. Cash flow from operating activities during
the fourth quarter of 2012 was $32.0 million, compared to $30.6 million
for the fourth quarter of 2011. The increase in cash flow from
operating activities between the periods was reflective of an increase
in cash from changes in working capital, and a minor decrease in
decommissioning costs incurred.
In the fourth quarter of 2012, Bellatrix realized a net profit of $9.3
million compared to a net loss of $13.6 million in the fourth quarter
of 2011. The net profit recorded in the fourth quarter of 2012
compared to the net loss in the fourth quarter of 2011 is primarily a
consequence of a $1.3 million non-cash unrealized gain on commodity
risk management compared to a $17.7 million loss in the 2011 period,
and a $16.2 million non-cash gain on property acquisition recognized in
the 2012 fourth quarter, offset by a higher non-cash impairment loss on
oil and gas properties, slightly increased depletion and depreciation
expenses, and a deferred income tax expense of $3.3 million in the 2012
fourth quarter compared to a $4.0 million recovery in the 2011 period.
As previously noted in this MD&A, net profit before certain non-cash
items is a non-GAAP measure. A reconciliation between this measure and
net profit per the Consolidated Statement of Comprehensive Income is
provided below.
For the fourth quarter of 2012, net profit before certain non-cash
items, net of associated deferred tax impacts, was $7.3 million
compared to $7.9 million in 2011.
|
Reconciliation of Net Profit (Loss) to Net Profit Before Certain
Non-Cash Items
|
|
Three months ended December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Net profit (loss) per financial statements
|
|
|
9,251
|
(13,597)
|
|
Items subject to reversal
|
|
|
|
|
|
|
Impairment loss on property, plant and equipment
|
|
|
14,820
|
11,018
|
|
|
Unrealized (gain) loss on commodity contracts
|
|
|
(1,313)
|
17,676
|
|
|
Gain on property acquisition
|
|
|
(16,160)
|
-
|
|
|
Loss on property dispositions
|
|
|
50
|
20
|
|
|
Deferred tax impact of above items
|
|
|
651
|
(7,179)
|
|
Net profit before certain non-cash items
|
|
|
7,299
|
7,938
|
|
Sales Volumes
|
|
|
|
|
|
|
Three months ended December 31,
|
|
|
|
|
|
|
2012
|
2011
|
|
Light oil and condensate
|
|
(bbls/d)
|
|
|
3,910
|
3,925
|
|
NGLs (excluding condensate)
|
|
(bbls/d)
|
|
|
1,631
|
1,173
|
|
Heavy oil
|
|
(bbls/d)
|
|
|
189
|
322
|
|
Total crude oil, condensate and NGLs
|
|
(bbls/d)
|
|
|
5,730
|
5,420
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
(mcf/d)
|
|
|
78,195
|
52,734
|
|
|
|
|
|
|
|
|
|
Total boe/d
|
|
(6:1)
|
|
|
18,763
|
14,209
|
Sales volumes for the three months ended December 31, 2012 averaged
18,763 boe/d, an increase of 32% from the 14,209 boe/d sold in the
fourth quarter of 2011. The weighting toward crude oil, condensate and
NGLs sales volumes decreased to 31% in the 2012 fourth quarter,
compared to 38% in the corresponding period in 2011. Fourth quarter
2012 natural gas, NGL, and total overall sales volumes were higher than
the same period in 2011 primarily due to the continued success achieved
from the Company's liquids rich drilling program.
Natural gas sales averaged 78.2 Mmcf/d during the fourth quarter of
2012, compared to 52.7 Mmcf/d in the fourth quarter of 2011. The
weighting toward natural gas sales volumes averaged 69% in the fourth
quarter of 2012, an increase over the 62% weighting realized in the
corresponding period in 2011. Crude oil, condensate and NGL sales
volumes increased to 5,730 bbls/d in the fourth quarter of 2012
compared to 5,420 bbls/d during the same period of 2011.
|
Revenue
|
|
|
|
Three months ended December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Light crude oil and condensate
|
|
|
29,702
|
34,366
|
|
NGLs (excluding condensate)
|
|
|
5,829
|
5,862
|
|
Heavy oil
|
|
|
1,136
|
2,204
|
|
Crude oil and NGLs
|
|
|
36,667
|
42,432
|
|
Natural gas
|
|
|
24,904
|
15,995
|
|
Total revenue before other
|
|
|
61,571
|
58,247
|
|
Other (1)
|
|
|
712
|
767
|
|
Total revenue before royalties and risk management
|
|
|
62,283
|
59,194
|
|
1)
|
Other revenue primarily consists of processing and other third party
income.
|
Revenue before other income, royalties and commodity price risk
management contracts for the fourth quarter of 2012 was $61.6 million,
an increase of 6% from $58.2 million in the fourth quarter of 2011.
The increase in revenues between the periods was due to increased sales
volumes and slightly higher natural gas prices in the 2012 period,
partially offset by lower crude oil, condensate, and NGL prices.
Light oil and condensate revenues for the fourth quarter of 2012 were
down 14% from the same period in 2011 due to lower prices. For light
oil and condensate, Bellatrix recorded an average $82.58/bbl before
commodity price risk management contracts during the fourth quarter of
2012, 13% lower than the average price of $95.18/bbl received in the
comparative 2011 period. In comparison, the Edmonton par price
decreased by 14% over the same period. The average WTI crude oil
benchmark price decreased by 6% in fourth quarter of 2012 compared to
the same period in 2011. The average US$/CDN$ foreign exchange rate
was 1.0093 for the three months ended December 31, 2012, an increase of
3% compared to an average rate of 0.9773 in the same period in 2011.
NGL revenues for the fourth quarter of 2012 were comparable to the 2011
period as a result of higher sales volumes offset by lower prices. For
NGLs (excluding condensate), Bellatrix recorded an average $38.84/bbl
during the fourth quarter of 2012, a 28% decrease from the $54.31/bbl
received in the comparative 2011 period. The decrease in NGL pricing
between the 2012 and 2011 periods is largely attributable to changes in
NGL market supply conditions between the periods.
The decrease in heavy oil revenue from the fourth quarter of 2011 to the
same period in 2012 is reflective of lower sales volumes and reduced
prices. Bellatrix sold its Wainwright heavy oil property, with 59
bbls/d of current production, in the third quarter of 2012. For heavy
crude oil, Bellatrix received an average price before commodity risk
management contracts of $65.30/bbl in the 2012 fourth quarter, a
decrease of 12% from the $74.30/bbl realized in the fourth quarter of
2011. In comparison, the Bow River reference price decreased by 19%,
and the Hardisty Heavy reference price decreased by 21% between the
fourth quarter of 2011 and the fourth quarter of 2012. The majority
of Bellatrix's heavy crude oil density ranges between 11 and 16 degrees
API, consistent with the Hardisty Heavy reference price.
Natural gas revenues in the fourth quarter of 2012 were up 56% from the
same period in 2011 as a result of a 48% increase in sales volumes and
a slight increase in natural gas prices between the periods.
Bellatrix's natural gas sales are priced with reference to the daily or
monthly AECO indices. Bellatrix's natural gas sold has a higher heat
content than the industry average, which results in slightly higher
prices per mcf than the daily AECO index. During the fourth quarter of
2012, the AECO daily reference price increased by 1%, and the AECO
monthly reference price decreased by approximately 12% compared to the
fourth quarter of 2011. Bellatrix's natural gas average sales price
before commodity price risk management contracts for the fourth quarter
of 2012 increased by 5% to $3.46/mcf compared to the $3.30/mcf realized
in the same period in 2011. The more significant increase in
Bellatrix's realized natural gas prices compared to the daily AECO
index between the periods was primarily due to the weighting of sales
volumes realized at increased prices during the fourth quarter of
2012. Bellatrix's natural gas average price after including commodity
price risk management contracts for the three months ended December 31,
2012 was $3.67/mcf, compared to $3.62/mcf for the three months ended
December 31, 2011.
In the fourth quarter of 2012, average sales volumes increased 21% from
the third quarter 2012 average volumes of 15,503 boe/d. The increase
was due to the success achieved from the Company's drilling program in
2012.
During the fourth quarter of 2012, Bellatrix spent $32.1 million on
capital projects, excluding corporate and asset acquisitions and
dispositions, compared to $47.1 million in 2011. In the fourth quarter
of 2012, Bellatrix drilled or participated in 10 gross wells (6.17
net), all of which were Cardium light oil horizontal wells. In the
fourth quarter of 2011, Bellatrix drilled or participated in 12 (7.64
net) wells including 8 gross (6.68 net) oil wells, 3 gross (0.95 net)
natural gas wells, and participated in 1 gross (0.007 net) dry hole
that was drilled in a non-operated oil unit.
In the fourth quarter of 2012, the Company paid $11.8 million in
royalties, compared to $8.8 million in the same period in 2011. As a
percentage of pre-commodity price risk management sales (after
transportation costs), royalties were 20% in the fourth quarter of 2012
compared to 15% in the same period in 2011. Royalties for the fourth
quarter of 2011 were reduced by $1.5 million in adjustments relating to
previous quarter estimates, primarily for wells under the recent
Alberta royalty programs. Excluding these adjustments, the average
royalty rate percentage for the fourth quarter of 2011 would be 18%.
Certain light oil wells are now incurring higher royalty rates as they
come off the initial royalty incentive rates. The Company's heavy oil
properties are minor, and consist of principally the Frog Lake Alberta
assets which are subject to high crown royalty rates. The Company's
royalty percentage for natural gas royalties continues to decline due
to increased production from recently drilled wells which take
advantage of Alberta royalty incentive programs.
In the fourth quarter of 2012, operating costs totaled $15.4 million,
compared to $14.1 million recorded in the same period of 2011. During
the fourth quarter of 2012, operating costs averaged $8.91/boe, down
from the $10.78/boe incurred during the fourth quarter of 2011. The
decrease was primarily due to increased production from recent drilling
in areas with lower production expenses and the Company's continued
efforts to streamline operations and field optimization projects. In
comparison, operating costs for the third quarter of 2012 averaged
$7.96/boe. The increase between the third and fourth quarters of 2012
was primarily due to additional chemical well treating, compressor
rentals, and other maintenance expenses.
During the fourth quarter of 2012, the Company's field operating
netbacks before commodity risk management contracts decreased by 26% to
$19.20/boe compared to $26.00/boe in the comparative 2011 period,
driven primarily by a 20% decrease in overall commodity prices and a
slight 2% increase in royalties, partially offset by a 17% reduction in
production expenses and a 41% reduction in transportation costs. In
comparison, the Company's field operating netback before commodity risk
management contracts for the third quarter of 2012 was $18.29/boe.
Field operating netbacks for natural gas before commodity price risk
management contracts during the fourth quarter of 2012 of $1.85/mcf
were 52% higher than the $1.22/mcf recorded in the same period in
2011. The increase was primarily a result of slightly higher gas
prices, as well as lower transportation, royalties, and production
expenses. In comparison, the field operating netback for natural gas
before commodity risk management contracts for the third quarter of
2012 was $1.12/mcf.
Field operating netbacks before commodity price risk management
contracts for crude oil, condensate and NGLs during the fourth quarter
of 2012 averaged $37.60/bbl, a decrease of 33% from the $56.26/bbl
realized during the fourth quarter of 2011. The decrease between the
periods was primarily as a result of weaker commodity prices and
increased royalties, offset partially by decreases in production and
transportation expenses. In comparison, the field operating netback
for crude oil, condensate and NGLs for the third quarter of 2012 was
$41.12/bbl.
In the fourth quarter of 2012, general and administrative expenses
("G&A"), net of capitalized G&A and recoveries, were $4.4 million,
compared to $3.8 million in the comparable 2011 period. The increase to
net G&A was primarily attributable to increases in staffing costs
between the periods. The overall increase in G&A expenses was offset
slightly by higher capitalized G&A and recoveries as a result of the
increase in capital activity in the fourth quarter of 2012 compared to
the fourth quarter of 2011.
Depletion, depreciation and accretion expense for the fourth quarter of
2012 was $18.6 million ($10.77/boe), compared to $17.6 million
($13.48/boe) in 2011. The increase in depletion, depreciation and
accretion expense from the 2011 fourth quarter to that in 2012 is
reflective of the 32% increase in sales volumes between the same
comparative periods, offset by the additional reserves achieved through
the Company's drilling success.
2012 Annual Financial and Operational Results
Acquisition and Dispositions
Effective November 1, 2012, Bellatrix acquired Cardium and
Notikewin/Falher lands and production in the Willesden Green area
adjacent to Bellatrix's core area in the Ferrier/Willesden Green
Cardium light oil resource play in West Central Alberta. The assets
acquired included then current production capability of approximately
500 boe/d (32% oil and liquids and 68% natural gas), 16 gross (11.95
net) sections of Cardium and Mannville prospective lands, 25 net
Cardium development locations, 4 net Notikewin/Falher development
locations, and a 25% working interest in an operated compressor station
and gathering system. Bellatrix acquired these assets for a net
purchase price of $21 million, which was funded using the Company's
existing credit facilities.
On December 14, 2012, Bellatrix acquired an additional 11 gross and net
sections of highly prospective Cardium and Notikewin/Falher lands in
the Ferrier area of west-central Alberta, subject to the receipt of
land permits anticipated in Q1 2013. This acquisition is anticipated
to provide an additional 37 net drilling locations in the Cardium, 9
net locations in the Notikewin/Falher, and an additional 66 net
locations in the Duvernay formation. The Company continues to focus on
adding Cardium and Notikewin prospective lands.
During the third quarter of 2012, Bellatrix closed on the disposition of
a minor non-core property interest in the Wainwright area, Alberta for
$4.25 million after adjustments. This non-operated unit heavy oil
property had production of approximately 59 boe/d. The net proceeds
from the disposition were initially used to reduce the Company's bank
indebtedness, and ultimately were directed towards the development of
the Company's Cardium oil resource program.
During the second quarter of 2012, Bellatrix closed on the disposition
of the Girouxville property in Alberta, a minor non-core property
interest. The property was sold for $0.6 million after adjustments.
Additionally, in the second quarter of 2012, Bellatrix closed on the
disposition of the Cypress-Chowade property in British Columbia, a
minor non-core property interest. The property was sold for $1.4
million after adjustments. There was no current production from the
Cypress-Chowade property.
Bellatrix had other minor property dispositions in 2012 resulting in
total cumulative property dispositions of $6.7 million.
Sales Volumes
Sales volumes for the year ended December 31, 2012 averaged 16,686 boe/d
compared to 11,954 boe/d for the 2011 year, representing a 40%
increase. Total crude oil, condensate and NGLs averaged approximately
34% of sales volumes for the year ended December 31, 2012, compared to
38% of sales volumes in the 2011 year. The increase in sales was
primarily a result of a year over year increased capital program and
the associated drilling success achieved in the Cardium and Notikewin
resource plays. Capital expenditures for the year ended December 31,
2012 were $185.3 million, compared to $179.6 million for the 2011 year.
|
Sales Volumes
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
|
|
|
2012
|
2011
|
|
Light oil and condensate
|
|
(bbls/d)
|
|
|
3,996
|
3,416
|
|
NGLs (excluding condensate)
|
|
(bbls/d)
|
|
|
1,441
|
808
|
|
Heavy oil
|
|
(bbls/d)
|
|
|
280
|
316
|
|
Total crude oil, condensate and NGLs
|
|
(bbls/d)
|
|
|
5,717
|
4,540
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
(mcf/d)
|
|
|
65,812
|
44,484
|
|
|
|
|
|
|
|
|
|
Total boe/d
|
|
(6:1)
|
|
|
16,686
|
11,954
|
During the 2012 year, Bellatrix posted a 100% success rate drilling
and/or participating in 34 gross (26.32 net) wells, resulting in 28
gross (21.32 net) Cardium oil wells, 2 gross (2.0 net) Cardium
condensate-rich gas wells, 1 gross (1.0 net) Duvernay gas well, and 3
gross (2.0 net) Notikewin/Falher liquids-rich gas wells.
By comparison, Bellatrix drilled or participated in 54 gross (34.84 net)
wells during the 2011 year, including 39 gross (29.04 net) oil wells,
14 gross (5.79 net) liquids-rich natural gas wells, and 1 gross (0.007
net) dry hole that was drilled in a non-operated oil unit.
For the year ended December 31, 2012, crude oil, condensate and NGL
sales volumes increased by approximately 26%, averaging 5,717 bbl/d
compared to 4,540 bbl/d in the 2011 year. For the year ended December
31, 2012, sales volumes for crude oil, condensate and NGLs averaged
approximately 34% of total sales volumes compared to approximately 38%
of total sales volumes in the 2011 year. The reduction in liquids
weighting between the years was a direct result of adding the dry gas
producing Duvernay well during the second quarter of 2012, as well as
bringing on several other high-productivity gas wells throughout the
2012 year.
Sales of natural gas averaged 65.8 Mmcf/d for the year ended December
31, 2012, compared to 44.5 Mmcf/d in the 2011 year, an increase of
approximately 48%. The weighting towards natural gas sales volumes
averaged approximately 66% for the year ended December 31, 2012,
compared to 62% in the 2011 year.
For 2013, Bellatrix will utilize pad drilling, involving the drilling of
multiple horizontal wells from single surface locations, enhancing
resource development efficiency, minimizing the Company's environmental
footprint, and improving cost and on-stream efficiencies. An initial
capital expenditure budget of between $230 to $240 million has been set
for fiscal 2013. Based on the timing of proposed expenditures,
downtime for scheduled and unscheduled plant turnarounds, completion of
required infrastructure, and normal production declines, execution of
the 2013 capital expenditure plan is anticipated to provide average
daily production of approximately 24,000 to 25,000 boe/d and an exit
rate of approximately 30,000 boe/d to 31,000 boe/d.
|
Commodity Prices
|
|
Average Commodity Prices
|
|
|
|
Years ended December 31,
|
|
|
|
|
|
2012
|
2011
|
% Change
|
|
|
|
|
|
|
|
|
|
Average exchange rate (US$/Cdn$)
|
|
|
|
1.0009
|
1.0111
|
(1)
|
|
|
|
|
|
|
|
|
|
Crude oil:
|
|
|
|
|
|
|
|
WTI (US$/bbl)
|
|
|
|
94.14
|
95.12
|
(1)
|
|
Edmonton par - light oil ($/bbl)
|
|
|
|
86.53
|
95.16
|
(9)
|
|
Bow River - medium/heavy oil ($/bbl)
|
|
|
|
74.30
|
78.30
|
(5)
|
|
Hardisty Heavy - heavy oil ($/bbl)
|
|
|
|
64.99
|
69.10
|
(6)
|
|
Bellatrix's average prices ($/bbl)
|
|
|
|
|
|
|
|
|
Light crude oil and condensate
|
|
|
|
86.47
|
92.51
|
(7)
|
|
|
NGLs (excluding condensate)
|
|
|
|
38.88
|
53.54
|
(27)
|
|
|
Heavy crude oil
|
|
|
|
68.51
|
68.23
|
-
|
|
|
Total crude oil and NGLs
|
|
|
|
73.59
|
83.89
|
(12)
|
|
|
Total crude oil and NGLs (including risk management (1))
|
|
|
|
72.65
|
81.47
|
(11)
|
|
|
|
|
|
|
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
NYMEX (US$/mmbtu)
|
|
|
|
2.83
|
4.03
|
(30)
|
|
AECO daily index (CDN$/mcf)
|
|
|
|
2.39
|
3.62
|
(34)
|
|
AECO monthly index (CDN$/mcf)
|
|
|
|
2.40
|
3.67
|
(35)
|
|
Bellatrix's average price ($/mcf)
|
|
|
|
2.62
|
3.77
|
(31)
|
|
Bellatrix's average price (including risk management (1)) ($/mcf)
|
|
|
|
3.17
|
4.05
|
(22)
|
|
|
|
|
|
|
|
|
|
(1)
|
Per unit metrics including risk management include realized gains or
losses on commodity contracts and exclude unrealized gains or losses on
commodity contracts.
|
During 2012, the differential between West Texas Intermediate ("WTI")
and Edmonton par price widened, whereas for 2011 the differential was
nearly non-existent. North America has seen significant increases in
light oil production as a result of the rapid pace of development in
the shale oil reservoirs. These volumes have displaced Canadian
production resulting in lower demand for Edmonton light oil. This
factor, along with higher incidences of refinery maintenance in 2012
and continued refinery conversions to run heavier streams, has resulted
in the widening of the price differential between WTI and Edmonton
par. For light oil and condensate, Bellatrix recorded an average
$86.47/bbl before commodity price risk management contracts during the
year ended December 31, 2012, 7% lower than the average price received
in the 2012 year. In comparison, the Edmonton par price decreased by
9% over the same period. The average WTI crude oil benchmark price
decreased by 1% in the year ended December 31, 2012 compared to the
2011 year. The average US$/CDN$ foreign exchange rate was 1.0009 for
the year ended December 31, 2012, a decrease of 1% compared to an
average rate of 1.0111 in the 2011 year.
For NGLs (excluding condensate), Bellatrix recorded an average
$38.88/bbl during the year ended December 31, 2012, a 27% decrease from
the $53.54/bbl received in the 2011 year. The decrease in NGL pricing
between the 2012 and 2011 years is largely attributable to changes in
NGL market supply conditions between the years.
For heavy crude oil, Bellatrix received an average price before
commodity risk management contracts of $68.51/bbl in the 2012 year,
consistent with the average price of $68.23/bbl realized in the 2011
year. In comparison, the Bow River reference price decreased by 5%, and
the Hardisty Heavy reference price decreased by 6% between the 2012 and
2011 years. The majority of Bellatrix's heavy crude oil density
ranges between 11 and 16 degrees API, consistent with the Hardisty
Heavy reference price.
Bellatrix's natural gas sales are priced with reference to the daily or
monthly AECO indices. Bellatrix's natural gas sold has a higher heat
content than the industry average, which results in slightly higher
prices per mcf than the daily AECO index. During the 2012 year, the
AECO daily reference price decreased by 34%, and the AECO monthly
reference price decreased by approximately 35% compared to the 2011
year. Bellatrix's natural gas average sales price before commodity
price risk management contracts for the 2012 year decreased by 31% to
$2.62/mcf compared to $3.77/mcf in the 2011 year. The lower decrease in
Bellatrix's realized natural gas prices compared to the daily AECO
index between the years was primarily due to the weighting of
additional sales volumes realized at increasing prices throughout the
2012 year. Bellatrix's natural gas average price after including
commodity price risk management contracts for the year ended December
31, 2012 was $3.17/mcf, compared to $4.05/mcf for the year ended
December 31, 2011.
Revenue
Revenue before other income, royalties and commodity price risk
management contracts for the year ended December 31, 2012 was $217.1
million, 8% higher than the $200.2 million in the 2011 year. The
increase in revenues between the years was due to increased sales
volumes between the years, partially offset by reduced liquids and
natural gas prices experienced in the 2012 year.
Revenue before other income, royalties and commodity price risk
management contracts for crude oil and NGLs for the year ended December
31, 2012 increased by 11% from the 2011 year, resulting from higher
sales volumes, partially offset by lower light crude oil, condensate
and NGL prices when compared to the 2011 year. In the 2012 year,
total crude oil, condensate and NGL revenues contributed 71% of total
revenue (before other) compared to 69% in the 2011 year. Light crude
oil, condensate and NGL revenues in the year ended December 31, 2012
comprised 95% of total crude oil, condensate and NGL revenues (before
other) for those periods, compared to 94% in the 2011 year.
Natural gas revenue before other income, royalties and commodity price
risk management contracts for the year ended December 31, 2012
increased by approximately 3% compared to the 2011 year as a result of
an approximate 48% increase in sales volumes between the years, largely
offset by a 31% decrease in realized gas prices before risk management.
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Light crude oil and condensate
|
|
|
126,468
|
115,353
|
|
NGLs (excluding condensate)
|
|
|
20,504
|
15,782
|
|
Heavy oil
|
|
|
7,023
|
7,866
|
|
Crude oil and NGLs
|
|
|
153,995
|
139,001
|
|
Natural gas
|
|
|
63,143
|
61,186
|
|
Total revenue before other
|
|
|
217,138
|
200,187
|
|
Other (1)
|
|
|
2,176
|
2,131
|
|
Total revenue before royalties and risk management
|
|
|
219,314
|
202,318
|
|
(1)
|
Other revenue primarily consists of processing and other third party
income.
|
Commodity Price Risk Management
The Company has a formal commodity price risk management policy which
permits management to use specified price risk management strategies
including fixed price contracts, collars and the purchase of floor
price options and other derivative financial instruments and physical
delivery sales contracts to reduce the impact of price volatility for a
maximum of eighteen months beyond the transaction date. The program is
designed to provide price protection on a portion of the Company's
future production in the event of adverse commodity price movement,
while retaining significant exposure to upside price movements. By
doing this, the Company seeks to provide a measure of stability to
funds flow from operations, as well as to ensure Bellatrix realizes
positive economic returns from its capital development and acquisition
activities. The Company plans to continue its commodity price risk
management strategies focusing on maintaining sufficient cash flow to
fund Bellatrix's capital expenditure program. Any remaining production
is realized at market prices.
A summary of the financial commodity price risk management volumes and
average prices by quarter currently outstanding as of March 6, 2013 is
shown in the following tables:
|
Natural gas
|
|
|
|
|
|
|
|
|
|
Average Volumes (GJ/d)
|
|
|
|
|
|
|
|
|
|
|
Q1 2013
|
|
Q2 2013
|
|
Q3 2013
|
|
Q4 2013
|
|
Fixed
|
|
6,556
|
|
55,000
|
|
55,000
|
|
35,109
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2014
|
|
Q2 2014
|
|
Q3 2014
|
|
Q4 2014
|
|
Fixed
|
|
15,000
|
|
15,000
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
Average Price ($/GJ AECO C)
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2013
|
|
Q2 2013
|
|
Q3 2013
|
|
Q4 2013
|
|
Fixed
|
|
3.05
|
|
3.06
|
|
3.06
|
|
3.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2014
|
|
Q2 2014
|
|
Q3 2014
|
|
Q4 2014
|
|
Fixed
|
|
3.05
|
|
3.05
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Volumes (bbls/d)
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2013
|
|
Q2 2013
|
|
Q3 2013
|
|
Q4 2013
|
|
Call option
|
|
3,000
|
|
3,000
|
|
3,000
|
|
3,000
|
|
Fixed
|
|
1,500
|
|
1,500
|
|
1,500
|
|
1,500
|
|
Total bbls/d
|
|
4,500
|
|
4,500
|
|
4,500
|
|
4,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2014
|
|
Q2 2014
|
|
Q3 2014
|
|
Q4 2014
|
|
Call option
|
|
3,000
|
|
3,000
|
|
3,000
|
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Price ($/bbl WTI)
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2013
|
|
Q2 2013
|
|
Q3 2013
|
|
Q4 2013
|
|
Call option (ceiling price) (US$/bbl)
|
|
110.00
|
|
110.00
|
|
110.00
|
|
110.00
|
|
Fixed price (CDN$/bbl)
|
|
94.50
|
|
94.50
|
|
94.50
|
|
94.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2014
|
|
Q2 2014
|
|
Q3 2014
|
|
Q4 2014
|
|
Call option (ceiling price) (US$/bbl)
|
|
105.00
|
|
105.00
|
|
105.00
|
|
105.00
|
As of December 31, 2012, the fair value of Bellatrix's outstanding
commodity contracts is a net unrealized asset of $0.2 million as
reflected in the financial statements. The fair value or
mark-to-market value of these contracts is based on the estimated
amount that would have been received or paid to settle the contracts as
at December 31, 2012 and will be different from what will eventually be
realized. Changes in the fair value of the commodity contracts are
recognized in the Consolidated Statements of Comprehensive Income
within the financial statements.
The following is a summary of the gain (loss) on commodity contracts for
the years ended December 31, 2012 and 2011 as reflected in the
Consolidated Statements of Comprehensive Income in the financial
statements:
|
Commodity contracts
|
|
($000s)
|
Crude Oil
& Liquids
|
Natural
Gas
|
2012
Total
|
|
Realized cash gain (loss) on contracts
|
(1,976)
|
13,245
|
11,269
|
|
Unrealized gain on contracts (1)
|
6,267
|
4,539
|
10,806
|
|
Total gain on commodity contracts
|
4,291
|
17,784
|
22,075
|
|
|
|
Commodity contracts
|
|
($000s)
|
Crude Oil
& Liquids
|
Natural
Gas
|
2011
Total
|
|
Realized cash gain (loss) on contracts
|
(4,015)
|
4,582
|
567
|
|
Unrealized gain (loss) on contracts (1)
|
(9,879)
|
2,979
|
(6,900)
|
|
Total gain (loss) on commodity contracts
|
(13,894)
|
7,561
|
(6,333)
|
|
(1)
|
Unrealized gain (loss) on commodity contracts represents non-cash
adjustments for changes in the fair value of these contracts during the
period.
|
Royalties
For the year ended December 31, 2012, total royalties were $38.8 million
compared to $34.7 million incurred in the 2011 year. Overall royalties
as a percentage of revenue (after transportation costs) in the 2012
year were 18%, compared with 18% in the 2011 year.
Certain light oil wells are now incurring higher royalty rates as they
come off the initial royalty incentive rates. The Company's heavy oil
properties are minor, and consist of principally the Frog Lake Alberta
assets which are subject to high crown royalty rates. The Company's
royalty percentage for natural gas royalties continues to decline due
to increased production from recently drilled wells which take
advantage of Alberta royalty incentive programs. Natural gas royalties
and total royalties recognized in 2012 were reduced by $1.5 million and
$1.7 million, respectively, in adjustments relating to prior period
estimates, primarily for Ferrier area wells for Indian Oil and Gas
Canada royalties under recent royalty incentive programs. Excluding
these adjustments, the average natural gas and overall corporate
royalty rate percentages for 2012 would be 6% and 19%, respectively.
|
|
|
|
|
|
|
Royalties by Commodity Type
|
|
Years ended December 31,
|
|
($000s, except where noted)
|
|
|
2012
|
2011
|
|
Light crude oil, condensate and NGLs
|
|
|
33,607
|
23,065
|
|
|
$/bbl
|
|
|
16.89
|
14.96
|
|
|
Average light crude oil, condensate and
NGLs royalty rate (%)
|
|
|
23
|
18
|
|
|
|
|
|
|
|
Heavy Oil
|
|
|
3,496
|
3,538
|
|
|
$/bbl
|
|
|
34.11
|
30.69
|
|
|
Average heavy oil royalty rate (%)
|
|
|
52
|
46
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
1,653
|
8,095
|
|
|
$/mcf
|
|
|
0.07
|
0.50
|
|
|
Average natural gas royalty rate (%)
|
|
|
3
|
14
|
|
|
|
|
|
|
|
Total
|
|
|
38,756
|
34,698
|
|
$/boe
|
|
|
6.35
|
7.95
|
|
Average total royalty rate (%)
|
|
|
18
|
18
|
|
Royalties, by Type
|
|
|
|
Years ended December 31,
|
|
|
($000s)
|
|
|
2012
|
2011
|
|
|
Crown royalties
|
|
|
11,518
|
12,264
|
|
|
Indian Oil and Gas Canada royalties
|
|
|
8,038
|
8,346
|
|
|
Freehold & GORR
|
|
|
19,200
|
14,088
|
|
Total
|
|
|
38,756
|
34,698
|
|
Expenses
|
|
|
|
Years ended December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Production
|
|
|
53,316
|
50,313
|
|
Transportation
|
|
|
4,978
|
5,715
|
|
General and administrative
|
|
|
14,272
|
12,358
|
|
Interest and financing charges (1)
|
|
|
9,834
|
7,041
|
|
Share-based compensation
|
|
|
3,219
|
2,939
|
|
(1)
|
Does not include financing charges in relation to the Company's
accretion of decommissioning liabilities.
|
|
Expenses per boe
|
|
|
|
Years ended December 31,
|
|
($ per boe)
|
|
|
2012
|
2011
|
|
Production
|
|
|
8.73
|
11.53
|
|
Transportation
|
|
|
0.82
|
1.31
|
|
General and administrative
|
|
|
2.34
|
2.83
|
|
Interest and financing charges
|
|
|
1.61
|
1.61
|
|
Share-based compensation
|
|
|
0.53
|
0.67
|
Production Expenses
For the year ended December 31, 2012, production expenses totaled $53.3
million ($8.73/boe), compared to $50.3 million ($11.53/boe) in the 2011
year. For the year ended December 31, 2012, production expenses
increased overall, while decreasing on a per boe basis when compared to
the 2011 year. The decrease in production expenses on a boe basis in
the 2012 year was primarily due to increased production, which is a
result of drilling in both 2011 and 2012 in areas with lower production
expenses, as well as reduced processing fees in certain areas and
continued field optimization projects.
Bellatrix is targeting operating costs of approximately $73.6 million
($8.00/boe) in the 2013 year, which is a reduction from the $8.73/boe
operating costs incurred for the 2012 year. This is based upon
assumptions of estimated 2013 average production of approximately
24,000 boe/d to 25,000 boe/d, continued field optimization work and
planned capital expenditures in producing areas which are anticipated
to have lower operating costs.
|
Production Expenses, by Commodity Type
|
|
|
|
Years ended December 31,
|
|
($000s, except where noted)
|
|
|
2012
|
2011
|
|
Light crude oil, condensate and NGLs
|
|
|
21,840
|
20,536
|
|
$/bbl
|
|
|
10.97
|
13.32
|
|
|
|
|
|
|
|
Heavy oil
|
|
|
1,555
|
2,587
|
|
$/bbl
|
|
|
15.17
|
22.44
|
|
|
|
|
|
|
|
Natural gas
|
|
|
29,921
|
27,190
|
|
$/mcf
|
|
|
1.24
|
1.67
|
|
|
|
|
|
|
|
Total
|
|
|
53,316
|
50,313
|
|
$/boe
|
|
|
8.73
|
11.53
|
|
|
|
|
|
|
|
Total
|
|
|
53,316
|
50,313
|
|
Processing and other third party income (1)
|
|
|
(2,176)
|
(2,131)
|
|
Total after deducting processing and other third party income
|
|
|
51,140
|
48,182
|
|
$/boe
|
|
|
8.37
|
11.04
|
|
(1)
|
Processing and other third party income is included within petroleum and
natural gas sales on the Consolidated Statements of Comprehensive
Income.
|
Transportation
Transportation expenses for the year ended December 31, 2012 were $5.0
million ($0.82/boe), compared to $5.7 million ($1.31/boe) in the 2011
year. The decrease in overall and per boe costs is reflective of a
higher volume of oil production being shipped through pipelines rather
than through trucking at a higher cost, as well as reduced gas
transportation fees resulting from the acquisition of an ownership
interest in certain gathering and processing facilities in the first
half of 2011.
|
Operating Netback
|
|
|
|
|
|
Field Operating Netback - Corporate (before risk management)
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
($/boe)
|
|
|
2012
|
2011
|
|
Sales
|
|
|
35.56
|
45.88
|
|
Transportation
|
|
|
(0.82)
|
(1.31)
|
|
Royalties
|
|
|
(6.35)
|
(7.95)
|
|
Production expense
|
|
|
(8.73)
|
(11.53)
|
|
Field operating netback
|
|
|
19.66
|
25.09
|
For the year ended December 31, 2012, the corporate field operating
netback (before commodity price risk management contracts) was
$19.66/boe compared to $25.09/boe in the 2011 year. The reduced
netback was primarily the result of reduced commodity prices, offset by
reduced transportation, royalty and production expenses. After
including commodity price risk management contracts, the corporate
field operating netback for the 2012 year was $21.51/boe compared to
$25.22/boe in the 2011 year. Per unit metrics including risk management
include realized gains or losses on commodity contracts and exclude
unrealized gains or losses on commodity contracts.
|
Field Operating Netback - Crude Oil, Condensate and NGLs (before risk
management)
|
|
|
|
|
|
|
Years ended December 31,
|
|
($/bbl)
|
|
|
2012
|
2011
|
|
Sales
|
|
|
73.59
|
83.89
|
|
Transportation
|
|
|
(0.98)
|
(1.86)
|
|
Royalties
|
|
|
(17.73)
|
(16.06)
|
|
Production expense
|
|
|
(11.18)
|
(13.96)
|
|
Field operating netback
|
|
|
43.70
|
52.01
|
|
|
|
|
|
|
Field operating netback for crude oil, condensate and NGLs averaged
$43.70/bbl for the year ended December 31, 2012, a decrease of 16% from
$52.01/bbl realized in the 2011 year. In the 2012 year, Bellatrix's
combined crude oil and NGLs average price (before risk management)
decreased by approximately 12% compared to the 2011 year. The
commodity price decrease in conjunction with a slight increase in
royalties was partially offset by reductions in production and
transportation expenses, resulting in the overall decrease to the field
operating netback for crude oil, condensate and NGLs. After including
commodity price risk management contracts, field operating netback for
crude oil and NGLs for the year ended December 31, 2012 decreased to
$42.76/boe compared to $49.58/boe in the 2011 year.
|
Field Operating Netback - Natural Gas (before risk management)
|
|
|
|
|
|
Years ended December 31,
|
|
($/mcf)
|
|
|
2012
|
2011
|
|
Sales
|
|
|
2.62
|
3.77
|
|
Transportation
|
|
|
(0.12)
|
(0.16)
|
|
Royalties
|
|
|
(0.07)
|
(0.50)
|
|
Production expense
|
|
|
(1.24)
|
(1.67)
|
|
Field operating netback
|
|
|
1.19
|
1.44
|
Field operating netback for natural gas in the year ended December 31,
2012 year decreased by 17% to $1.19/mcf, compared to $1.44/mcf realized
in the 2011 year, reflecting depressed natural gas prices, offset
somewhat by lower production, transportation and royalty expenses.
After including commodity price risk management contracts, field
operating netback for natural gas for the year ended December 31, 2012
increased to $1.74/mcf, which compared to $1.72/mcf in the 2011 year.
General and Administrative
General and administrative ("G&A") expenses (after capitalized G&A and
recoveries) for the year ended December 31, 2012 were $14.3 million
($2.34/boe), compared to $12.4 million ($2.83/boe) for the 2011 year.
G&A expenses in the 2012 year were higher in comparison to the 2011
year, which is reflective of higher compensation costs and slightly
reduced recoveries, offset partially by higher capitalized G&A. On a
boe basis, G&A for the year ended December 31, 2012 decreased by
approximately 17% when compared to the 2011 year. The decrease was
primarily as a result of higher average sales volumes in the 2012 year,
despite higher overall costs.
For 2013, the Company is anticipating G&A expenses after capitalization
to be approximately $23.0 million ($2.50/boe) based on estimated 2013
average production volumes of approximately 24,000 boe/d to 25,000
boe/d.
|
General and Administrative Expenses
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
($000s, except where noted)
|
|
|
2012
|
2011
|
|
Gross expenses
|
|
|
21,170
|
18,582
|
|
Capitalized
|
|
|
(4,335)
|
(3,553)
|
|
Recoveries
|
|
|
(2,563)
|
(2,671)
|
|
G&A expenses
|
|
|
14,272
|
12,358
|
|
G&A expenses, per unit ($/boe)
|
|
|
2.34
|
2.83
|
Interest and Financing Charges
Bellatrix recorded $9.8 million ($1.61/boe) of interest and financing
charges related to bank debt and its debentures for the year ended
December 31, 2012, compared to $7.0 million ($1.61/boe) in the 2011
year. The overall increase in interest and financing charges between
the years was primarily due to greater interest and accretion charges
in relation to the Company's outstanding debentures in conjunction with
higher interest charges related to the Company's long-term debt as the
Company carried a higher average debt balance in the 2012 year compared
to the 2011 year. Bellatrix's total net debt at December 31, 2012 of
$189.6 million includes the $50.7 million liability portion of its $55
million principal amount of 4.75% convertible unsecured subordinated
debentures (the "4.75% Debentures"), $133.0 million of bank debt and
the net balance of the working capital deficiency. The 4.75% Debentures
have a maturity date of April 30, 2015.
|
|
|
|
|
|
|
Debt to Funds Flow from Operations Ratio
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
($000s, except where noted)
|
|
|
2012
|
2011
|
|
|
|
|
|
|
|
Shareholders' equity
|
|
|
381,106
|
348,405
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
133,047
|
56,701
|
|
Convertible debentures (liability component)
|
|
|
50,687
|
49,076
|
|
Working capital deficiency (2)
|
|
|
5,843
|
13,473
|
|
Total net debt (2) at year end
|
|
|
189,577
|
119,250
|
|
|
|
|
|
|
|
Debt to funds flow from operations (1) ratio (annualized) (3)
|
|
|
|
|
|
Funds flow from operations (1) (annualized)
|
|
|
119,460
|
120,480
|
|
Total net debt (2) at year end
|
|
|
189,577
|
119,250
|
Total net debt to periods funds flow from operations ratio
(annualized) (3)
|
|
|
1.6x
|
1.0x
|
|
|
|
|
|
|
|
Net debt (2) (excluding convertible debentures) at year end
|
|
|
138,890
|
70,174
|
Net debt to periods funds flow from operations
ratio (annualized) (3)
|
|
|
1.2x
|
0.6x
|
|
|
|
|
|
|
|
Debt to funds flow from operations (1) ratio
|
|
|
|
|
|
Funds flow from operations (1) for the year
|
|
|
111,038
|
94,237
|
|
Total net debt (2) to funds flow from operations for the year
|
|
|
1.7x
|
1.3x
|
|
|
|
|
|
|
Net debt (2) (excluding convertible debentures) to funds flow
from operations for the year
|
|
|
1.3x
|
0.7x
|
|
|
|
|
|
|
|
(1)
|
As detailed previously in this Management's Discussion and Analysis,
funds flow from operations is a term that does not have any
standardized meaning under GAAP. Funds flow from operations is
calculated as cash flow from operating activities, less decommissioning
costs incurred and changes in non-cash working capital incurred. Refer
to the reconciliation of cash flow from operating activities to funds
flow from operations appearing elsewhere herein.
|
|
|
|
|
(2)
|
Net debt and total net debt are considered additional GAAP measures.
The Company's calculation of total net debt includes the liability
component of convertible debentures and excludes deferred liabilities,
long-term commodity contract liabilities, decommissioning liabilities,
long-term finance lease obligation and the deferred tax liability. Net
debt and total net debt include the net working capital deficiency
(excess) before short-term commodity contract assets and liabilities
and current finance lease obligation. Net debt also excludes the
liability component of convertible debentures. Total net debt and net
debt are additional GAAP measures; refer to the following
reconciliation of total liabilities to total net debt and net debt.
|
|
|
|
|
(3)
|
Total net debt and net debt to periods funds flow from operations ratio
(annualized) is calculated based upon fourth quarter funds flow from
operations annualized.
|
|
Reconciliation of Total Liabilities to Total Net Debt and Net Debt
|
|
|
|
|
|
|
|
As at December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Total liabilities per financial statements
|
|
|
300,315
|
232,017
|
|
|
Current liabilities included within working capital calculation
|
|
|
(53,327)
|
(73,578)
|
|
|
Commodity contract liability
|
|
|
(6,214)
|
(2,944)
|
|
|
Decommissioning liabilities
|
|
|
(43,909)
|
(45,091)
|
|
|
Finance lease obligation
|
|
|
(13,131)
|
(4,627)
|
|
|
|
|
|
|
|
Working Capital
|
|
|
|
|
|
|
Current assets
|
|
|
(52,447)
|
(51,927)
|
|
|
Current liabilities
|
|
|
53,327
|
73,578
|
|
|
Current portion of finance lease
|
|
|
(1,425)
|
(490)
|
|
|
Net commodity contract asset (liability)
|
|
|
6,388
|
(7,688)
|
|
|
|
|
5,843
|
13,473
|
|
Total net debt
|
|
|
189,577
|
119,250
|
|
|
Convertible debentures
|
|
|
(50,687)
|
(49,076)
|
|
Net debt
|
|
|
138,890
|
70,174
|
Share-Based Compensation
Non-cash share-based compensation expense for the year ended December
31, 2012 was an expense of $3.2 million compared to $2.9 million in the
2011 year. The overall increase in non-cash share-based compensation
expense between the years is primarily a result of a larger number of
outstanding share options expensed during the year and greater Deferred
Share Unit Plan expenses of $1.0 million (2011: $0.8 million), offset
partially by higher capitalized share-based compensation of $1.6
million (2011: $1.4 million).
Depletion and Depreciation
Depletion and depreciation expense for the year ended December 31, 2012
was $75.7 million ($12.40/boe), compared to $63.4 million ($14.53/boe)
recognized in the 2011 year. The decrease in depletion and
depreciation expense between the years, on a per boe basis, was
primarily a result of an increase in the reserve base used for the
depletion calculation, partially offset by a higher cost base and
increased future development costs.
For the year ended December 31, 2012 Bellatrix has included a total of
$524.6 million (2011: $376.8 million) for future development costs in
the depletion calculation and excluded from the depletion calculation a
total of $37.2 million (2011: $35.1 million) for estimated salvage.
|
Depletion and Depreciation
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
($000s, except where noted)
|
|
|
2012
|
2011
|
|
Depletion and Depreciation
|
|
|
75,720
|
63,384
|
|
Per unit ($/boe)
|
|
|
12.40
|
14.53
|
Property Acquisition
Effective November 1, 2012, Bellatrix acquired production and working
interest in certain facilities, as well as undeveloped land in the
Willesden Green area of Alberta for a cash purchase price of $20.9
million after adjustments. In accordance with IFRS, a property
acquisition is accounted for as a business combination when certain
criteria are met, such as the acquisition of inputs and processes to
convert those inputs into beneficial outputs. Bellatrix assessed the
property acquisition and determined that it constitutes a business
combination under IFRS. In a business combination, acquired assets
and liabilities are recognized by the acquirer at their fair market
value at the time of purchase. Any variance between the determined
fair value of the assets and liabilities and the purchase price is
recognized as either a gain or loss in the statement of comprehensive
income in the period of acquisition.
The estimated fair value of the property, plant and equipment acquired
was determined using both internal estimates and an independent reserve
evaluation. The decommissioning liabilities assumed were determined
using the timing and estimated costs associated with the abandonment,
restoration and reclamation of the wells and facilities acquired. A
summary of the acquired property is provided below:
|
|
|
|
|
|
|
|
|
($000s)
|
|
Estimated fair value of acquisition:
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
29,530
|
|
|
Exploration and evaluation assets
|
|
|
8,525
|
|
|
Decommissioning liabilities
|
|
|
(973)
|
|
|
|
|
37,082
|
|
|
|
|
|
|
Cash consideration
|
|
|
20,922
|
|
|
|
|
|
|
Gain on property acquisition
|
|
|
16,160
|
Impairment of Assets
In accordance with IFRS, the Company calculates an impairment test when
there are indicators of impairment. The impairment test is performed
at the asset or cash generating unit ("CGU") level. IAS 36 -
"Impairment of Assets" ("IAS 36") is a one step process for testing and
measuring impairment of assets. Under IAS 36, the asset or CGU's
carrying value is compared to the higher of: value-in-use and fair
value less costs to sell. Value in use is defined as the present value
of the future cash flows expected to be derived from the asset or CGU.
When performed, the impairment test is based upon the higher of
value-in-use and estimated fair market values for the Company's
properties, including but not limited to an updated external reserve
engineering report which incorporates a full evaluation of reserves on
an annual basis or internal reserve updates at quarterly periods, and
the latest commodity pricing deck. Estimating reserves is very
complex, requiring many judgments based on available geological,
geophysical, engineering and economic data. Changes in these judgments
could have a material impact on the estimated reserves. These
estimates may change, having either a negative or positive effect on
net earnings as further information becomes available and as the
economic environment changes.
2012 Impairment
Bellatrix engaged an external reserve evaluator to prepare an updated
company reserve report effective December 31, 2012. Overall corporate
proved and probable reserve volumes increased significantly at December
31, 2012 compared to evaluated reserves at December 31, 2011. However,
the fair values of two largely natural gas-weighted CGUs and one CGU
with significant natural gas and heavy oil weightings were reduced,
largely as a result of suppressed commodity prices.
As at December 31, 2012, Bellatrix performed an impairment test using
VIU values in accordance with IAS 36, resulting in an excess of the
carrying value of three CGUs over their recoverable amount, resulting
in a non-cash $14.8 million impairment loss. In performing the test,
future cash flows at between a 10% and 20% discount rate were used for
the Company's largely gas weighted North East Alberta, South East
Alberta, and British Columbia CGUs. The Company's core West Central
Alberta CGU had no indicators of impairment. Discounted salvage values
and discounted future associated general and administrative costs were
also incorporated into the VIU calculation. The $14.8 million
impairment loss was comprised of $11.4 million recognized in the
Company's North East Alberta CGU, $2.9 million in the South East
Alberta CGU, and $0.5 million in the British Columbia CGU. The
reduction in the fair values of these CGUs between December 31, 2011
and December 31, 2012 was predominantly due to weak natural gas prices.
2011 Impairment
During the year ended December 31, 2011, Bellatrix performed an
impairment test in accordance with IAS 36 resulting in an excess of the
carrying value of three CGUs over their recoverable amount, resulting
in a non-cash $25.6 million impairment loss.
IAS 36 requires impairment losses to be reversed when there has been a
subsequent increase in the recoverable amount. In the case of an
impairment loss reversal, the carrying amount of the asset or CGU is
limited to the original carrying amount less depreciation, depletion
and amortization as if no impairment had been recognized for the asset
or CGU for prior periods. In 2011, a partial reversal of impairment
was recognized relating to a previous impairment for the Company`s
South East Alberta CGU. As a result of the reversal, impairment
expense for the 2011 year was reduced by $2.7 million.
The impairment test is based upon fair market values for the Company's
properties, including but not limited to an updated external reserve
engineering report which incorporates a full evaluation of reserves on
an annual basis or internal reserve updates at quarterly periods, and
the latest commodity pricing deck. Estimating reserves is very
complex, requiring many judgments based upon available geological,
geophysical, engineering and economic data. Changes in these judgments
could have a material impact on the Company's estimated reserves.
These estimates may change, having either a negative or positive impact
on net earnings as further information becomes available and as the
economic environment changes.
Income Taxes
Deferred income taxes arise from differences between the accounting and
tax basis of the Company's assets and liabilities. For the year ended
December 31, 2012, the Company recognized a deferred income tax expense
of $10.1 million compared to $0.8 million in the 2011 year.
At December 31, 2012, the Company had a total deferred tax asset balance
of $1.0 million. IFRS requires that a deferred tax asset be recorded
when the tax pools exceeds the book value of assets, to the extent the
amount is probable to be realized.
At December 31, 2012, Bellatrix had approximately $584 million in tax
pools available for deduction against future income as follows:
|
|
|
|
|
|
|
|
($000s)
|
|
|
Rate %
|
2012
|
2011
|
|
Intangible resource pools:
|
|
|
|
|
|
|
|
Canadian exploration expenses
|
|
|
100
|
56,200
|
47,600
|
|
|
Canadian development expenses
|
|
|
30
|
358,700
|
326,900
|
|
|
Canadian oil and gas property expenses
|
|
|
10
|
40,400
|
25,100
|
|
|
Foreign resource expenses
|
|
|
10
|
800
|
800
|
|
Attributed Canadian Royalty Income
|
|
|
(Alberta) 100
|
16,100
|
16,100
|
|
Undepreciated capital cost (1)
|
|
|
6 - 55
|
98,000
|
83,100
|
|
Non-capital losses (expire through 2027)
|
|
|
100
|
10,000
|
10,000
|
|
Financing costs
|
|
|
20 S.L.
|
3,300
|
4,700
|
|
|
|
|
|
583,500
|
514,300
|
|
(1)
|
Approximately $91 million of undepreciated capital cost pools are class
41, which is claimed at a 25% rate.
|
Cash Flow from Operating Activities, Funds Flow from Operations and Net
Profit (Loss)
As detailed previously in this MD&A, funds flow from operations is a
term that does not have any standardized meaning under GAAP. Funds
flow from operations is calculated as cash flow from operating
activities before decommissioning costs incurred and changes in
non-cash working capital incurred.
|
Reconciliation of Cash Flow from Operating Activities and Funds Flow
from Operations
|
|
|
|
|
|
Years ended December 31,
|
|
($000s)
|
|
|
2012
|
2011
|
|
Cash flow from operating activities
|
|
|
109,328
|
98,192
|
|
Decommissioning costs incurred
|
|
|
635
|
569
|
|
Change in non-cash working capital
|
|
|
1,075
|
(4,524)
|
|
Funds flow from operations
|
|
|
111,038
|
94,237
|
Bellatrix's cash flow from operating activities of $109.3 million ($1.02
per basic share and $0.95 per diluted share) for the year ended
December 31, 2012 increased approximately 11% from the $98.2 million
($0.95 per basic share and $0.87 per diluted share) generated in the
2011 year. Bellatrix generated funds flow from operations of $111.0
million ($1.03 per basic share and $0.96 per diluted share) for the
year ended December 31, 2012, an increase of 18% from $94.2 million
($0.91 per basic share and $0.84 per diluted share) for the 2011 year.
The increase in funds flow from operations between the 2012 and 2011
years was principally due to higher funds from operating netbacks,
despite significantly reduced commodity prices, as well as higher net
realized gains on the Company's commodity risk management contracts,
and offset partially by increased financing expenses and slightly
higher general and administrative expenses in 2012 compared to 2011.
Bellatrix maintains a commodity price risk management program to provide
a measure of stability to funds flow from operations. Unrealized
mark-to-market gains or losses are non-cash adjustments to the current
fair market value of the contract over its entire term and are included
in the calculation of net profit.
As previously noted in this MD&A, net profit before certain non-cash
items is a non-GAAP measure. A reconciliation between this measure and
net loss per the Consolidated Statement of Comprehensive Income is
provided below.
For the year ended December 31, 2012, net profit before certain non-cash
items, net of associated deferred tax impacts, was $21.7 million
compared to a net profit of $17.1 million in the 2011 year.
|
Reconciliation of Net Profit (Loss) to Net Profit Before Certain
Non-Cash Items
|
|
|
|
|
Years ended December 31,
|
|
($000s)
|
2012
|
2011
|
|
Net profit (loss) per financial statements
|
27,771
|
(5,949)
|
|
Items subject to reversal
|
|
|
|
|
Impairment loss on property, plant and equipment
|
14,820
|
25,569
|
|
|
Unrealized (gain) loss on commodity contracts
|
(10,806)
|
6,900
|
|
|
Loss (gain) on property dispositions
|
4,113
|
(1,730)
|
|
|
Gain on property acquisition
|
(16,160)
|
-
|
|
|
Deferred tax impact of above items
|
2,008
|
(7,685)
|
|
Net profit before certain non-cash items
|
21,746
|
17,105
|
A net profit of $27.8 million ($0.26 per basic share and $0.25 per
diluted share) was recognized for the year ended December 31, 2012,
compared to a net loss of $5.9 million ($0.06 per basic share and $0.06
per diluted share) in the 2011 year. The net profit recorded in the
year ended December 31, 2012 compared to the net loss recorded in the
2011 year is primarily a consequence of higher cash flows as noted
above, a $16.2 million gain on property acquisition recognized in 2012,
a net unrealized gain on commodity contracts in the 2012 year compared
to a loss in 2011, and a lower non-cash impairment loss on oil and gas
properties, offset somewhat by a higher depletion and depreciation
expense, a total net loss on property dispositions compared to a minor
gain on property dispositions in the comparative 2011 year, and a
higher deferred tax expense.
|
Cash Flow from Operating Activities, Funds Flow from Operations and Net
Profit (Loss)
|
|
|
Years ended December 31,
|
|
($000s, except per share amounts)
|
2012
|
2011
|
|
Cash flow from operating activities
|
109,328
|
98,192
|
|
|
Basic ($/share)
|
1.02
|
0.95
|
|
|
Diluted ($/share)
|
0.95
|
0.87
|
|
|
|
|
|
Funds flow from operations
|
111,038
|
94,237
|
|
|
Basic ($/share)
|
1.03
|
0.91
|
|
|
Diluted ($/share)
|
0.96
|
0.84
|
|
|
|
|
|
Net profit (loss)
|
27,771
|
(5,949)
|
|
|
Basic ($/share)
|
0.26
|
(0.06)
|
|
|
Diluted ($/share)
|
0.25
|
(0.06)
|
Capital Expenditures
Bellatrix invested $185.3 million in capital expenditures, including a
$21.0 million property acquisition, during the year ended December 31,
2012, compared to $179.6 million in the 2011 year.
|
Capital Expenditures
|
|
|
|
|
Years ended December 31,
|
|
($000s)
|
2012
|
2011
|
|
Lease acquisitions and retention
|
8,303
|
16,367
|
|
Geological and geophysical
|
290
|
433
|
|
Drilling and completion costs
|
118,783
|
141,051
|
|
Facilities and equipment
|
36,811
|
18,471
|
|
|
164,187
|
176,322
|
|
Drilling incentive credits
|
-
|
(827)
|
|
|
Exploration and development (1)
|
164,187
|
175,495
|
|
Corporate (2)
|
195
|
268
|
|
Property acquisition
|
20,966
|
3,798
|
|
|
Total capital expenditures - cash
|
185,348
|
179,561
|
|
Property dispositions - cash
|
(6,660)
|
(4,203)
|
|
|
Total net capital expenditures - cash
|
178,688
|
175,358
|
|
Capital lease additions - non-cash
|
10,000
|
3,700
|
|
Adjustment on property acquisition - non-cash
|
16,160
|
-
|
|
Other - non-cash (3)
|
(285)
|
6,875
|
|
|
Total non-cash
|
25,875
|
10,575
|
|
Total net capital expenditures
|
204,563
|
185,933
|
|
(1)
|
Excludes capitalized costs related to decommissioning liabilities
expenditures incurred during the year.
|
|
(2)
|
Corporate includes office furniture, fixtures and equipment.
|
|
(3)
|
Other includes non-cash adjustments for the current year's
decommissioning liabilities and share based compensation.
|
During the 2012 year, Bellatrix posted a 100% success rate drilling
and/or participating in 34 gross (26.32 net) wells, resulting in 28
gross (21.32 net) Cardium oil wells, 2 gross (2.0 net) Cardium
condensate-rich gas wells, 1 gross (1.0 net) Duvernay gas well, and 3
gross (2.0 net) Notikewin/Falher liquids-rich gas wells.
By comparison, Bellatrix drilled or participated in 54 gross (34.84 net)
wells during the year ended December 31, 2011, including 39 gross
(29.04 net) oil wells, 14 gross (5.79 net) liquids-rich natural gas
wells, and 1 gross (0.007 net) dry hole that was drilled in a
non-operated oil unit.
The $185.3 million capital program for the year ended December 31, 2012
was financed from funds flow from operations and bank debt.
Based on the current economic conditions and Bellatrix's operating
forecast for 2013, the Company budgets a capital program between $230
to $240 million funded from the Company's cash flows and to the extent
necessary, bank indebtedness. The 2013 capital budget is expected to
be directed primarily towards horizontal drilling and completions
activities in the Cardium and Notikewin areas.
Decommissioning Liabilities
At December 31, 2012, Bellatrix has recorded decommissioning liabilities
of $43.9 million, compared to $45.1 million at December 31, 2011, for
future abandonment and reclamation of the Company's properties. For
the year ended December 31, 2012, decommissioning liabilities decreased
by a net $1.2 million as a result of a reduction of $3.0 million for
liabilities reversed on dispositions, a $0.7 million decrease for
changes in estimates, and a $0.6 million decrease for liabilities
settled during the year, offset by $2.4 million incurred on property
acquisitions and development activities, and $0.7 million as a result
of charges for the unwinding of the discount rates used for fair
valuing the liabilities. The $0.7 million decrease as a result of
changes in estimates is primarily due to a discount rate variations at
December 31, 2012 compared to 2011, in addition to other abandonment
liability revisions.
Liquidity and Capital Resources
As an oil and gas business, Bellatrix has a declining asset base and
therefore relies on ongoing development and acquisitions to replace
production and add additional reserves. Future oil and natural gas
production and reserves are highly dependent on the success of
exploiting the Company's existing asset base and in acquiring
additional reserves. To the extent Bellatrix is successful or
unsuccessful in these activities, cash flow could be increased or
reduced.
Bellatrix is focused on growing oil and natural gas production from its
diversified portfolio of existing and emerging resource plays in
Western Canada. Bellatrix remains highly focused on key business
objectives of maintaining financial strength, optimizing capital
investments - attained through a disciplined approach to capital
spending, a flexible investment program and financial stewardship.
Natural gas prices are primarily driven by North American supply and
demand, with weather being the key factor in the short term. Bellatrix
believes that natural gas represents an abundant, secure, long-term
supply of energy to meet North American needs. Bellatrix's results are
affected by external market and risk factors, such as fluctuations in
the prices of crude oil and natural gas, movements in foreign currency
exchange rates and inflationary pressures on service costs. Market
conditions have resulted in Bellatrix experiencing primarily downward
trends in crude oil pricing for 2012 compared to 2011, and a more
significant downward trend in natural gas pricing, although natural gas
prices started to recover in the second half of 2012.
Liquidity risk is the risk that Bellatrix will not be able to meet its
financial obligations as they become due. Bellatrix actively manages
its liquidity through daily and longer-term cash, debt and equity
management strategies. Such strategies encompass, among other factors:
having adequate sources of financing available through its bank credit
facilities, estimating future cash generated from operations based on
reasonable production and pricing assumptions, analysis of economic
risk management opportunities, and maintaining sufficient cash flows
for compliance with operating debt covenants. Bellatrix is fully
compliant with all of its operating debt covenants.
Bellatrix generally relies on operating cash flows and its credit
facilities to fund capital requirements and provide liquidity. Future
liquidity depends primarily on cash flow generated from operations,
existing credit facilities and the ability to access debt and equity
markets. From time to time, the Company accesses capital markets to
meet its additional financing needs and to maintain flexibility in
funding its capital programs. There can be no assurance that future
debt or equity financing, or cash generated by operations will be
available or sufficient to meet these requirements or for other
corporate purposes or, if debt or equity financing is available, that
it will be on terms acceptable to Bellatrix.
Credit risk is the risk of financial loss to Bellatrix if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from Bellatrix's trade receivables
from joint venture partners, petroleum and natural gas marketers, and
financial derivative counterparties.
A substantial portion of Bellatrix's accounts receivable are with
customers and joint interest partners in the petroleum and natural gas
industry and are subject to normal industry credit risks. Bellatrix
sells substantially all of its production to seven primary purchasers
under standard industry sale and payment terms. The most significant
60 day exposure to a single counterparty is currently approximately
$12.6 million. Purchasers of Bellatrix's natural gas, crude oil and
natural gas liquids are subject to a periodic internal credit review to
minimize the risk of non-payment. Bellatrix has continued to closely
monitor and reassess the creditworthiness of its counterparties,
including financial institutions. This has resulted in Bellatrix
reducing or mitigating its exposures to certain counterparties where it
is deemed warranted and permitted under contractual terms.
Bellatrix may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture
partners, marketers of its petroleum and natural gas production,
derivative counterparties and other parties. In the event such
entities fail to meet their contractual obligations to Bellatrix, such
failures may have a material adverse effect on the Company's business,
financial condition, results of operations and prospects. In addition,
poor credit conditions in the industry and of joint venture partners
may impact a joint venture partner's willingness to participate in
Bellatrix's ongoing capital program, potentially delaying the program
and the results of such program until Bellatrix finds a suitable
alternative partner.
Total net debt levels of $189.6 million at December 31, 2012 have
increased by $70.3 million from $119.3 million at December 31, 2011,
primarily as a consequence of an increase in a working capital
deficiency and bank debt as the Company executed its 2012 capital
program. Total net debt includes the liability component of the 4.75%
Debentures and excludes unrealized commodity contract assets and
liabilities, deferred taxes, finance lease obligations, deferred
liabilities and decommissioning liabilities.
Funds flow from operations represents 60% of the funding requirements
for Bellatrix's capital expenditures for the year ended December 31,
2012.
Effective December 13, 2012, the Company's borrowing base was increased
from $200 million to $220 million through to the next scheduled
borrowing base determination to be completed on or before May 31, 2013.
Effective May 31, 2012, the revolving period of the credit facility was
extended from June 26, 2012 to June 25, 2013. The Company's credit
facilities consist of a $25 million demand operating facility provided
by a Canadian bank and a $195 million extendible revolving term credit
facility provided by two Canadian banks and a Canadian financial
institution. Amounts borrowed under the credit facility bear interest
at a floating rate based on the applicable Canadian prime rate, U.S.
base rate, the LIBOR margin rate, or the bankers' acceptance stamping
fee, plus between 1.00% and 3.50%, depending on the type of borrowing
and the Company's debt to cash flow ratio. The credit facilities are
secured by a $400 million debenture containing a first ranking charge
and security interest. Bellatrix has provided a negative pledge and
undertaking to provide fixed charges over its properties in certain
circumstances. A standby fee is charged of between 0.50% and 0.875% on
the undrawn portion of the credit facilities, depending on the
Company's debt to cash flow ratio.
The revolving period for the revolving term credit facility will end on
June 25, 2013, unless extended for a further 364 day period. Should
the facility not be extended it will convert to a non-revolving term
facility with the full amount outstanding due 366 days after the last
day of the revolving period of June 25, 2013. The borrowing base will
be subject to re-determination on May 31 and November 30 in each year
prior to maturity, with the next semi-annual redetermination occurring
on May 31, 2013.
As at December 31, 2012, approximately $87.0 million or 40% of unused
and available bank credit under its credit facilities was available to
fund Bellatrix's ongoing capital spending and operational requirements.
Bellatrix currently has commitments associated with its credit
facilities outlined above and the commitments outlined under the
"Commitments" section. Bellatrix continually monitors its capital
spending program in light of the recent volatility with respect to
commodity prices and Canadian dollar exchange rates with the aim of
ensuring the Company will be able to meet future anticipated
obligations incurred from normal ongoing operations with funds flow
from operations and draws on Bellatrix's credit facility, as
necessary. Bellatrix has the ability to fund its 2013 capital program
of $230 to $240 million by utilizing cash flow, and to the extent
necessary, bank indebtedness.
As at February 25, 2013, Bellatrix had outstanding a total of 9,334,894
options exercisable at an average exercise price of $3.45 per share,
$55.0 million principal amount of 4.75% Debentures convertible into
common shares (at a conversion price of $5.60 per share) and
107,880,996 common shares.
Related Party Transactions
Previous to 2012, the Company entered into agreements to obtain
financing in the amount of $5.3 million for the construction of certain
facilities.
Members of the Company's management team and entities affiliated with
them provided financing of $900,000. The terms of the transactions with
those related parties were the same as those with arms-length
participants.
Commitments
As at December 31, 2012, Bellatrix committed to drill 3 gross (1.7 net)
wells pursuant to farm-in agreements. Bellatrix expects to satisfy
these drilling commitments at an estimated cost of approximately $6.5
million.
In addition, Bellatrix entered into two joint venture agreements during
the 2011 year and an additional joint venture agreement during 2012.
The agreements include a minimum commitment for the Company to drill a
specified number of wells each year over the term of the individual
agreements. The details of these agreements are provided in the table
below:
|
|
|
|
|
|
|
|
|
Joint Venture Agreement
|
|
Feb. 1, 2011
|
|
Aug. 4, 2011
|
|
Dec. 14, 2012
|
|
Agreement Term
|
|
2011 to 2015
|
|
2011 to 2016
|
|
2014 to 2018
|
|
Minimum wells per year (gross and net)
|
|
3
|
|
5 to 10
|
|
2
|
|
Minimum total wells (gross and net)
|
|
15
|
|
40
|
|
10
|
|
Estimated total cost ($000s)
|
|
$52.5
|
|
$140.0
|
|
$35.0
|
|
Remaining wells to drill at December 31, 2012
|
|
8
|
|
32
|
|
10
|
|
Remaining estimated total cost ($000s)
|
|
$28.0
|
|
$112.0
|
|
$35.0
|
The Company has the following liabilities as at December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities ($000s)
|
|
Total
|
|
< 1 Year
|
|
1-3 Years
|
|
4-5 Years
|
|
More than
5 years
|
|
Accounts payable and accrued liabilities (1)
|
|
$ 50,771
|
|
$ 50,771
|
|
$ -
|
|
$ -
|
|
$ -
|
|
Long-term debt - principal (2)
|
|
133,047
|
|
-
|
|
133,047
|
|
-
|
|
-
|
|
Convertible debentures - principal
|
|
55,000
|
|
-
|
|
55,000
|
|
-
|
|
-
|
|
Convertible debentures - interest (3)
|
|
6,085
|
|
2,613
|
|
3,472
|
|
-
|
|
-
|
|
Commodity contract liability
|
|
7,345
|
|
1,131
|
|
6,214
|
|
-
|
|
-
|
|
Decommissioning liabilities (4)
|
|
43,909
|
|
-
|
|
7,187
|
|
5,796
|
|
30,926
|
|
Finance lease obligation
|
|
14,556
|
|
1,425
|
|
3,069
|
|
3,172
|
|
6,890
|
|
Total
|
|
$ 310,713
|
|
$ 55,940
|
|
$ 207,989
|
|
$ 8,968
|
|
$ 37,816
|
|
(1)
|
Includes $0.4 million of accrued coupon interest payable in relation to
the 4.75% Debentures and $0.2 million of accrued interest payable in
relation to the credit facilities is included in Accounts Payable and
Accrued Liabilities.
|
|
(2)
|
Bank debt is based on a revolving term which is reviewed annually and
converts to a 366 day non-revolving facility if not renewed. Interest
due on the bank credit facility is calculated based upon floating
rates.
|
|
(3)
|
The 4.75% Debentures outstanding at December 31, 2012 bear interest at a
coupon rate of 4.75%, which currently requires total annual interest
payments of $2.6 million.
|
|
(4)
|
Amounts represent the inflated, discounted future abandonment and
reclamation expenditures anticipated to be incurred over the life of
the Company's properties (between 2013 and 2053).
|
Bellatrix will also have drilling commitments associated with its
recently announced joint venture agreement in January, 2013 with a
South Korean based company. Closing of this agreement is expected to
occur on or before April 30, 2013. Refer to the details discussed
earlier herein.
Off-Balance Sheet Arrangements
The Company has certain fixed term lease agreements, including primarily
office space leases, which were entered into in the normal course of
operations. All leases have been treated as operating leases whereby
the lease payments are included in operating expenses or G&A expenses
depending on the nature of the lease. The lease agreements do not
currently provide for early termination. No asset or liability value
has been assigned to these leases in the balance sheet as of December
31, 2012.
The Company is committed to payments under fixed term operating leases
which do not currently provide for early termination. The Company's
commitment for office space as at December 31, 2012 is as follows:
|
|
|
|
|
|
|
|
|
|
|
($000s)
Year
|
|
|
Gross
Amount
|
|
|
Expected
Recoveries
|
|
|
Net amount
|
|
2013
|
|
|
$ 2,254
|
|
|
$ 947
|
|
|
$ 1,307
|
|
2014
|
|
|
1,520
|
|
|
641
|
|
|
879
|
Subsequent to year end, Bellatrix entered into a fixed term operating
lease agreement for corporate office space in a new location,
commencing September 1, 2013. Bellatrix is currently pursuing
subleasing options for the remaining term of its existing corporate
office space. A summary of the Company's commitment for the new office
space is as follows:
|
|
|
|
|
|
($000s)
Year
|
|
|
Total amount
|
|
|
2013
|
|
|
$ 388
|
|
|
2014
|
|
|
2,153
|
|
|
2015
|
|
|
2,243
|
|
|
2016
|
|
|
2,243
|
|
|
2017
|
|
|
2,243
|
|
|
More than 5 years
|
|
|
14,449
|
Business Prospects and 2013 Year Outlook
Bellatrix continues to develop its core assets and conduct exploration
programs utilizing its large inventory of geological prospects. As at
December 31, 2012, Bellatrix has approximately 206,638 net undeveloped
acres and including all opportunities has in excess of 1,700 net
exploration drilling opportunities identified.
As a result of the recently announced joint venture with a Seoul Korea
based company, Bellatrix's 2013 capital expenditure budget has been
increased to between $230 and $240 million. A total capital program of
$365 million is anticipated including the capital expected to be
invested by the joint venture partner. Based on the timing of proposed
expenditures, downtime for scheduled and unscheduled plant turnarounds,
completion of required infrastructure, and normal production declines,
execution of the 2013 capital expenditure plan is expected to provide
average daily production of approximately 24,000 boe/d to 25,000 boe/d,
and an exit rate of approximately 30,000 boe/d to 31,000 boe/d.
The Company has initiated the 2013 program by instituting drilling of
multiple horizontal wells from single surface locations. Pad drilling
enhances the opportunity to efficiently develop the resource while
minimizing the environmental footprint and improving our cost and
on-stream efficiencies. Pad drilling also facilitates drilling through
the spring breakup months of Q2. As a result the Company plans to run
3 rigs throughout the second quarter ramping up to 7 or 8 rigs for the
second half of 2013.
Financial Reporting Update
Future Accounting Pronouncements
The following pronouncements from the IASB are applicable to Bellatrix
and will become effective for future reporting periods, but have not
yet been adopted:
IFRS 9 - "Financial Instruments", which is the result of the first phase
of the IASB's project to replace IAS 39, "Financial Instruments:
Recognition and Measurement". The new standard replaces the current
multiple classification and measurement models for financial assets and
liabilities with a single model that has only two classification
categories: amortized cost and fair value. This standard is effective
for annual periods beginning on or after January 1, 2015 with different
transitional arrangements depending on the date of initial application.
The extent of the impact of the adoption of IFRS 9 has not yet been
determined.
IFRS 10 - "Consolidated Financial Statements" ("IFRS 10"), which
requires an entity to consolidate an investee when it is exposed, or
has rights, to variable returns from its involvement with the investee
and has the ability to affect those returns through its power over the
investee. Under existing IFRS, consolidation is required when an entity
has the power to govern the financial and operating policies of an
entity so as to obtain benefits from its activities. This standard
replaces SIC-12 - "Consolidation—Special Purpose Entities" and parts of
IAS 27 - "Consolidated and Separate Financial Statements." Bellatrix
intends to adopt IFRS 10, including the amendments issued in June 2012,
in its financial statements for the annual period beginning on January
1, 2013. The adoption of IFRS 10 is currently not anticipated to
impact the Company's financial statements.
IFRS 11 - "Joint Arrangements" ("IFRS 11"), requires a venturer to
classify its interest in a joint arrangement as a joint venture or
joint operation, each having its own accounting model. Joint ventures
will be accounted for using the equity method of accounting, whereas
for a joint operation the venture will recognize its share of the
assets, liabilities, revenue and expenses of the joint operation. The
standard provides for a more substance based reflection of joint
arrangements by focusing on the rights and obligations of the
arrangement, rather than its legal form. IFRS 11 replaces IAS 31 -
"Interests in Joint Ventures" and SIC-13 - "Jointly Controlled
Entities—Non-monetary Contributions by Venturers" and establishes
principles for accounting for all joint arrangements. Bellatrix
intends to adopt IFRS 11, including the amendments issued in June 2012,
in its financial statements for the annual period beginning on January
1, 2013. The adoption of IFRS 11 is currently not anticipated to have
a significant impact on the Company's financial statements.
IFRS 12 - "Disclosure of Interests in Other Entities" ("IFRS 12"),
establishes disclosure requirements for interests in other entities,
such as joint arrangements, associates, special purpose vehicles and
off balance sheet vehicles. The standard carries forward existing
disclosures and also introduces significant additional disclosure
requirements that address the nature of, and risks associated with, an
entity's interests in other entities. Bellatrix intends to adopt IFRS
12, including the amendments issued in June 2012, in its financial
statements for the annual period beginning on January 1, 2013. The
adoption of IFRS 12 is currently not anticipated to have a significant
impact on the Company's financial statements.
IFRS 13 - "Fair Value Measurement" ("IFRS 13"), is a comprehensive
standard for fair value measurement and disclosure requirements for use
across all IFRSs. The new standard clarifies that fair value is the
price that would be received to sell an asset, or paid to transfer a
liability in an orderly transaction between market participants, at the
measurement date. It also establishes disclosures about fair value
measurement. Under existing IFRS, guidance on measuring and disclosing
fair value is dispersed among the specific standards requiring fair
value measurements and in many cases does not reflect a clear
measurement basis or consistent disclosures. IFRS 13 is effective for
annual periods beginning on or after January 1, 2013 and applies
prospectively from the beginning of the annual period in which the
standard is adopted. The extent of the impact of the adoption of IFRS
13 on the Company's financial statements has not yet been determined.
In June 2011, the IASB issued an amendment to IAS 1 - "Presentation of
Financial Statements" ("IAS 1") requiring companies to group items
presented within Other Comprehensive Income based on whether they may
be subsequently reclassified to profit or loss. This amendment to IAS
1 is effective for annual periods beginning on or after July 1, 2012
with full retrospective application. Early adoption is permitted.
Bellatrix intends to adopt the amendments in its financial statements
for the annual period beginning on January 1, 2013. The extent of the
impact of the amendments on the financial statements has not yet been
determined.
Business Risks and Uncertainties
General
Bellatrix's production and exploration activities are concentrated in
the Western Canadian Sedimentary Basin, where activity is highly
competitive and includes a variety of different sized companies ranging
from smaller junior producers to the much larger integrated petroleum
companies.
Bellatrix is subject to the various types of business risks and
uncertainties including:
-
Finding and developing oil and natural gas reserves at economic costs;
-
Production of oil and natural gas in commercial quantities; and
-
Marketability of oil and natural gas produced.
In order to reduce exploration risk, the Company strives to employ
highly qualified and motivated professional employees with a
demonstrated ability to generate quality proprietary geological and
geophysical prospects. To help maximize drilling success, Bellatrix
combines exploration in areas that afford multi-zone prospect
potential, targeting a range of low to moderate risk prospects with
some exposure to select high-risk with high-reward opportunities.
Bellatrix also explores in areas where the Company has significant
drilling experience.
The Company mitigates its risk related to producing hydrocarbons through
the utilization of the most appropriate technology and information
systems managed by qualified personnel. In addition, Bellatrix seeks to
maintain operational control of the majority of its prospects.
Oil and gas exploration and production can involve environmental risks
such as pollution of the environment and destruction of natural
habitat, as well as safety risks such as personal injury. In order to
mitigate such risks, Bellatrix conducts its operations at high
standards and follows safety procedures intended to reduce the
potential for personal injury to employees, contractors and the public
at large. The Company maintains current insurance coverage for general
and comprehensive liability as well as limited pollution liability. The
amount and terms of this insurance are reviewed on an ongoing basis and
adjusted as necessary to reflect changing corporate requirements, as
well as industry standards and government regulations. Bellatrix may
periodically use financial or physical delivery contracts to reduce its
exposure against the potential adverse impact of commodity price
volatility, as governed by formal policies approved by senior
management subject to controls established by the Board.
Pricing and Marketing
Oil
The producers of oil are entitled to negotiate sales contracts directly
with oil purchasers, with the result that the market determines the
price of oil. Worldwide supply and demand primarily determines oil
prices. The specific price depends in part on oil quality, prices of
competing fuels, distance to market, the availability of
transportation, the value of refined products, the supply/demand
balance and contractual terms of sale. Oil exporters are also entitled
to enter into export contracts with terms not exceeding one year in the
case of light crude oil and two years in the case of heavy crude oil,
provided that an order approving such export has been obtained from the
National Energy Board of Canada (the "NEB"). Any oil export to be made
pursuant to a contract of longer duration (to a maximum of 25 years)
requires an exporter to obtain an export licence from the NEB. The NEB
is currently undergoing a consultation process to update the current
regulations governing the issuance of export licences. The updating
process is necessary to meet the criteria set out in the federal Jobs,
Growth and Long-term Prosperity Act which received Royal Assent on June
29, 2012 (the "Prosperity Act"). In this transitory period, the NEB
has issued, and is currently following an "Interim Memorandum of
Guidance concerning Oil and Gas Export Applications and Gas Import
Applications under Part VI of the National Energy Board Act".
Natural Gas
Alberta's natural gas market has been deregulated since 1985. Supply
and demand determine the price of natural gas and price is calculated
at the sale point, being the wellhead, the outlet of a gas processing
plant, on a gas transmission system such as the Alberta "NIT" (Nova
Inventory Transfer), at a storage facility, at the inlet to a utility
system or at the point of receipt by the consumer. Accordingly, the
price for natural gas is dependent upon such producer's own
arrangements (whether long or short term contracts and the specific
point of sale). As natural gas is also traded on trading platforms
such as the Natural Gas Exchange (NGX) or the New York Mercantile
Exchange (NYMEX) in the United States, spot and future prices can be
set by such supply and demand. Natural gas exported from Canada is
subject to regulation by the NEB and the Government of Canada.
Exporters are free to negotiate prices and other terms with purchasers,
provided that the export contracts must continue to meet certain other
criteria prescribed by the NEB and the Government of Canada. Natural
gas (other than propane, butane and ethane) exports for a term of less
than two years or for a term of two to 20 years (in quantities of not
more than 30,000 m3/day) must be made pursuant to an NEB order. Any
natural gas export to be made pursuant to a contract of longer duration
(to a maximum of 25 years) or for a larger quantity requires an
exporter to obtain an export licence from the NEB.
Royalties and Incentives - General
In addition to federal regulation, each province has legislation and
regulations which govern royalties, production rates and other
matters. The royalty regime in a given province is a significant
factor in the profitability of oil sands projects, crude oil, natural
gas liquids, sulphur and natural gas production. Royalties payable on
production from lands other than Crown lands are determined by
negotiation between the mineral freehold owner and the lessee, although
production from such lands is subject to certain provincial taxes and
royalties. Royalties from production on Crown lands are determined by
governmental regulation and are generally calculated as a percentage of
the value of gross production. The rate of royalties payable generally
depends in part on prescribed reference prices, well productivity,
geographical location, field discovery date, method of recovery and the
type or quality of the petroleum product produced. Other royalties and
royalty like interests are carved out of the working interest owner's
interest, from time to time, through non public transactions. These
are often referred to as overriding royalties, gross overriding
royalties, net profits interests, or net carried interests.
Occasionally the governments of the western Canadian provinces create
incentive programs for exploration and development. Such programs
often provide for royalty rate reductions, royalty holidays or royalty
tax credits and are generally introduced when commodity prices are low
to encourage exploration and development activity by improving earnings
and cash flow within the industry.
Land Tenure
The respective provincial governments predominantly own crude oil and
natural gas located in the western provinces. Provincial governments
grant rights to explore for and produce oil and natural gas pursuant to
leases, licences, and permits for varying terms, and on conditions set
forth in provincial legislation including requirements to perform
specific work or make payments. Private ownership of oil and natural
gas also exists in such provinces and rights to explore for and produce
such oil and natural gas are granted by lease on such terms and
conditions as may be negotiated.
Each of the provinces of Alberta, British Columbia and Saskatchewan has
implemented legislation providing for the reversion to the Crown of
mineral rights to deep, non-productive geological formations at the
conclusion of the primary term of a lease or license. On March 29,
2007, British Columbia expanded its policy of deep rights reversion for
new leases to provide for the reversion of both shallow and deep
formations that cannot be shown to be capable of production at the end
of their primary term.
Alberta also has a policy of "shallow rights reversion" which provides
for the reversion to the Crown of mineral rights to shallow,
non-productive geological formations for all leases and licenses. For
leases and licenses issued subsequent to January 1, 2009, shallow
rights reversion will be applied at the conclusion of the primary term
of the lease or license. Holders of leases or licences that have been
continued indefinitely prior to January 1, 2009 will receive a notice
regarding the reversion of the shallow rights, which will be
implemented three years from the date of the notice. Leases and
licences granted prior to January 1, 2009, but continued after that
date, are not subject to shallow rights reversion until they continue
past their primary term (at which time the application of deep rights
reversion occurs). Afterwards, the holders of such agreements will be
served with shallow rights reversion notices based on vintage and
location similar to leases and licences that were already continued as
of January 1, 2009. The order in which these agreements will receive
reversion notices will depend on their vintage and location.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal
legislation, all of which is subject to governmental review and
revision from time to time. Such legislation provides for restrictions
and prohibitions on the release or emission of various substances
produced in association with certain oil and gas industry operations,
such as sulphur dioxide and nitrous oxide. In addition, such
legislation sets out the requirements for the satisfactory abandonment
and reclamation of well and facility sites. Compliance with such
legislation can require significant expenditures and a breach of such
requirements may result in suspension or revocation of necessary
licenses and authorizations, civil liability for pollution damage, and
the imposition of material fines and penalties. Implementation of
strategies for reducing greenhouse gases could have a material impact
on the nature of oil and gas operations, including those of the
Company. Given the evolving nature of the debate related to climate
change and the control of greenhouse gases and resulting requirements,
it is not possible to predict either the nature of those requirements
or the impact on the Company and its operations and financial
condition.
Global Financial Crisis
Recent market events and conditions, including disruptions in the
international credit markets and other financial systems and the
American and European sovereign debt levels have caused significant
volatility in commodity prices. These events and conditions have
caused a decrease in confidence in the broader U.S. and global credit
and financial markets and have created a climate of greater volatility,
less liquidity, widening of credit spreads, a lack of price
transparency, increased credit losses and tighter credit conditions.
Notwithstanding various actions by governments, concerns about the
general condition of the capital markets, financial instruments, banks,
investment banks, insurers and other financial institutions caused the
broader credit markets to further deteriorate and stock markets to
decline substantially. While there are signs of economic recovery,
these factors have negatively impacted company valuations and are
likely to continue to impact the performance of the global economy
going forward. Petroleum prices are expected to remain volatile for
the near future as a result of market uncertainties over the supply and
demand of these commodities due to the current state of the world
economies, actions taken by OPEC and the ongoing global credit and
liquidity concerns. This volatility may in the future affect the
Company's ability to obtain equity or debt financing on acceptable
terms.
Substantial Capital Requirements
The Company anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of oil and natural
gas reserves in the future. As future capital expenditures will be
financed out of cash generated from operations, borrowings and possible
future equity offerings, the Company's ability to do so is dependent
on, among other factors, the overall state of the capital markets, the
Company's credit rating (if applicable), interest rates, royalty rates,
tax burden due to current and future tax laws, and investor appetite
for investments in the energy industry and the Company's securities in
particular. Further, if the Company's revenues or reserves decline, it
may not have access to the capital necessary to undertake or complete
future drilling programs. There can be no assurance that debt or
equity financing, or cash generated by operations will be available or
sufficient to meet these requirements or for other corporate purposes
or, if debt or equity financing is available, that it will be on terms
acceptable to the Company. The inability of the Company to access
sufficient capital for its operations could have a material adverse
effect on the Company's business financial condition, results of
operations and prospects.
Third Party Credit Risk
The Company may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture
partners, marketers of its petroleum and natural gas production and
other parties. In the event such entities fail to meet their
contractual obligations to the Company, such failures may have a
material adverse effect on the Company's business, financial condition,
results of operations and prospects. In addition, poor credit
conditions in the industry and of joint venture partners may impact a
joint venture partner's willingness to participate in the Company's
ongoing capital program, potentially delaying the program and the
results of such program until the Company finds a suitable alternative
partner.
Critical Accounting Estimates
The reader is advised that the critical accounting estimates, policies,
and practices as described herein continue to be critical in
determining Bellatrix's financial results.
The reader is cautioned that the preparation of financial statements in
accordance with GAAP requires management to make certain judgments and
estimates that affect the reported amounts of assets, liabilities,
revenues and expenses. The following discussion outlines accounting
policies and practices that are critical to determining Bellatrix's
financial results.
Derivatives
The fair value of commodity contracts is estimated, whenever possible,
based on published market prices, and if not available, on estimates
from third party brokers, as at the balance sheet date and may differ
from what will eventually be realized.
Oil and gas reserves
Reserves and resources are used in the units of production calculation
for depreciation, depletion and amortization and the impairment
analysis which affect net profit. There are numerous uncertainties
inherent in estimating oil and gas reserves. Estimating reserves is
very complex, requiring many judgments based on geological,
geophysical, engineering and economic data. Changes in these judgments
could have a material impact on the estimated reserves. These
estimates may change, having either a negative or positive effect on
net profit as further information becomes available and as the economic
environment changes.
Depreciation and depletion
Depletion of petroleum and natural gas properties is provided using the
unit-of-production method based on production volumes before royalties
in relation to total estimated proved and probable reserves as
determined annually by independent engineers and internal reserve
evaluations on a quarterly basis determined in accordance with National
Instrument 51-101. Natural gas reserves and production are converted
at the energy equivalent of six thousand cubic feet to one barrel of
oil.
Calculations for depletion and depreciation of production equipment are
based on total capitalized costs plus estimated future development
costs of proved and probable undeveloped reserves less the estimated
net realizable value of production equipment and facilities after the
proved reserves are fully produced. The costs of acquiring and
evaluating unproved properties are excluded from depletion
calculations.
Recoverability of asset carrying values
The Company assesses its oil and gas properties, including exploration
and evaluation assets, for possible impairment if there are events or
changes in circumstances that indicate that carrying values of the
assets may not be recoverable, or at least at every reporting date.
The assessment of any impairment of property, plant and equipment is
dependent upon estimates of recoverable amount that take into account
factors such as reserves, economic and market conditions, timing of
cash flows, the useful lives of assets and their related salvage
values.
Bellatrix's assets are aggregated into CGUs, for the purpose of
calculating impairment, based on their ability to generate largely
independent cash flows, geography, geology, production profile and
infrastructure of its assets. By their nature, these estimates and
assumptions are subject to measurement uncertainty and may impact the
carrying value of the Company's assets in future periods.
Decommissioning obligations
Provisions for decommissioning obligations associated with the Company's
drilling operations are based on current legal and constructive
requirements, technology, price levels and expected plans for
remediation. Actual costs and cash outflows can differ from estimates
because of changes in laws and regulations, public expectations,
prices, discovery and analysis of site conditions and changes in clean
up technology.
Share-based compensation
The fair value of stock options granted is measured using a Black
Scholes model. Measurement inputs include share price on measurement
date, exercise price of the option, expected volatility, expected life
of the options, expected dividends and the risk-free rate. The Company
estimates volatility based on the historical share price. The expected
life of the options is based on historical experience and general
option holder behavior. Dividends were not taken into consideration as
the Company does not expect to pay dividends. Management also makes an
estimate of the number of options that will be forfeited and the rate
is adjusted to reflect the actual number of options that actually vest.
Income taxes
Related assets and liabilities are recognized for the estimated tax
consequences between amounts included in the financial statements and
their tax base using substantively enacted future income tax rates.
Timing of future revenue streams and future capital spending changes
can affect the timing of any temporary differences, and accordingly
affect the amount of the deferred tax asset or liability calculated at
a point in time. These differences could materially impact earnings.
Business combinations
Business combinations are accounted for using the acquisition method of
accounting. The determination of fair value often requires management
to make assumptions and estimates about future events. The assumptions
and estimates with respect to determining the fair value of property,
plant, and equipment, and exploration and evaluation assets acquired
generally require the most judgment and include estimates of reserves
acquired, forecast benchmark commodity prices, and discount rates.
Changes in any of the assumptions or estimates used in determining the
fair value of acquired assets and liabilities could impact the amounts
assigned to assets, liabilities in the purchase price allocation, and
any resulting gain or loss. Future net earnings can be affected as a
result of changes in future depletion, depreciation and accretion, and
asset impairments.
Legal, Environmental Remediation and Other Contingent Matters
The Company is involved in various claims and litigation arising in the
normal course of business. While the outcome of these matters is
uncertain and there can be no assurance that such matters will be
resolved in the Company's favor, the Company does not currently believe
that the outcome of adverse decisions in any pending or threatened
proceeding related to these and other matters or any amount which it
may be required to pay by reason thereof would have a material adverse
impact on its financial position or results of operations.
The Company reviews legal, environmental remediation and other
contingent matters to both determine whether a loss is probable based
on judgment and interpretation of laws and regulations and determine
that the loss can reasonably be estimated. When the loss is
determined, it is charged to earnings. The Company's management
monitor known and potential contingent matters and make appropriate
provisions by charges to earnings when warranted by the circumstances.
With the above risks and uncertainties the reader is cautioned that
future events and results may vary substantially from that which
Bellatrix currently foresees.
Controls and Procedures
Disclosure Controls and Procedures
The Company's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, disclosure
controls and procedures to provide reasonable assurance that: (i)
material information relating to the Company is made known to the
Company's Chief Executive Officer and Chief Financial Officer by
others, particularly during the period in which the annual and interim
filings are being prepared; and (ii) information required to be
disclosed by the Company in its annual filings, interim filings or
other reports filed or submitted by it under securities legislation is
recorded, processed, summarized and reported within the time period
specified in securities legislation. Such officers have evaluated, or
caused to be evaluated under their supervision, the effectiveness of
the Company's disclosure controls and procedures at the financial year
end of the Company and have concluded that the Company's disclosure
controls and procedures are effective at the financial year end of the
Company for the foregoing purposes.
Internal Control over Financial Reporting
The Company's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, internal
control over financial reporting to provide reasonable assurance
regarding the reliability of the Company's financial reporting and the
preparation of financial statements for external purposes in accordance
with GAAP. Such officers have evaluated, or caused to be evaluated
under their supervision, the effectiveness of the Company's internal
control over financial reporting at the financial year end of the
Company and concluded that the Company's internal control over
financial reporting is effective at the financial year end of the
Company for the foregoing purpose.
The Company is required to disclose herein any change in the Company's
internal control over financial reporting that occurred during the
period beginning on October 1, 2012 and ended on December 31, 2012 that
has materially affected, or is reasonably likely to materially affect,
the Company's internal control over financial reporting. No material
changes in the Company's internal control over financial reporting were
identified during such period that has materially affected, or are
reasonably likely to materially affect, the Company's internal control
over financial reporting.
It should be noted that a control system, including the Company's
disclosure and internal controls and procedures, no matter how well
conceived, can provide only reasonable, but not absolute, assurance
that the objectives of the control system will be met and it should not
be expected that the disclosure and internal controls and procedures
will prevent all errors or fraud.
Sensitivity Analysis
The table below shows sensitivities to funds flow from operations as a
result of product price, exchange rate, and interest rate changes.
This is based on actual average prices received for the fourth quarter
of 2012 and average production volumes of 18,763 boe/d during that
period, as well as the same level of debt outstanding at December 31,
2012. Diluted weighted average shares are based upon the fourth
quarter of 2012. These sensitivities are approximations only, and not
necessarily valid under other significantly different production levels
or product mixes. Commodity price risk management activities can
significantly affect these sensitivities. Changes in any of these
parameters will affect funds flow as shown in the table below:
|
|
|
|
|
|
Funds Flow from Operations (1)
|
Funds Flow from Operations (1)
|
|
|
(annualized)
|
Per Diluted Share
|
|
Sensitivity Analysis
|
($000s)
|
($)
|
|
Change of US $1/bbl WTI
|
1,500
|
0.01
|
|
Change of $0.10/ mcf
|
2,600
|
0.02
|
|
Change of US $0.01 CDN/ US exchange rate
|
1,100
|
0.01
|
|
Change in prime of 1%
|
1,300
|
0.01
|
|
(1)
|
The term "funds flow from operations" should not be considered an
alternative to, or more meaningful than cash flow from operating
activities as determined in accordance with GAAP as an indicator of the
Company's performance. Therefore reference to additional GAAP measures
of diluted funds flow from operations or funds flow from operations per
share may not be comparable with the calculation of similar measures
for other entities. Management uses funds flow from operations to
analyze operating performance and leverage and considers funds flow
from operations to be a key measure as it demonstrates the Company's
ability to generate the cash necessary to fund future capital
investments and to repay debt. The reconciliation between cash flow
from operating activities and funds flow from operations can be found
elsewhere herein. Funds flow from operations per share is calculated
using the weighted average number of common shares for the period.
|
Selected Quarterly Consolidated Information
The following table sets forth selected consolidated financial
information of the Company for the quarters in 2012 and 2011.
|
|
|
|
|
|
|
|
|
|
2012 - Quarter ended (unaudited)
($000s, except per share amounts)
|
|
March 31
|
|
June 30
|
|
Sept. 30
|
|
Dec. 31
|
|
Revenues before royalties and risk management
|
|
58,191
|
|
50,714
|
|
48,126
|
|
62,283
|
|
Cash flow from operating activities
|
|
24,056
|
|
28,458
|
|
24,807
|
|
32,007
|
|
Cash flow from operating activities per share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$0.22
|
|
$0.24
|
|
$0.23
|
|
$0.30
|
|
|
Diluted
|
|
$0.21
|
|
$0.22
|
|
$0.22
|
|
$0.28
|
|
Funds flow from operations (1)
|
|
29,194
|
|
25,366
|
|
26,613
|
|
29,865
|
|
Funds flow from operations per share (1)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$0.27
|
|
$0.24
|
|
$0.25
|
|
$0.28
|
|
|
Diluted
|
|
$0.25
|
|
$0.22
|
|
$0.23
|
|
$0.26
|
|
Net profit (loss)
|
|
9,172
|
|
9,963
|
|
(615)
|
|
9,251
|
|
Net profit (loss) per share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$0.09
|
|
$0.09
|
|
($0.01)
|
|
$0.09
|
|
|
Diluted
|
|
$0.08
|
|
$0.09
|
|
($0.01)
|
|
$0.08
|
|
Net capital expenditures (cash)
|
|
73,831
|
|
16,284
|
|
35,515
|
|
64,383
|
|
|
|
|
|
|
|
|
|
|
2011 - Quarter ended (unaudited)
($000s, except per share amounts)
|
|
March 31
|
|
June 30
|
|
Sept. 30
|
|
Dec. 31
|
|
Revenues before royalties and risk management
|
|
40,535
|
|
53,444
|
|
49,145
|
|
59,194
|
|
Cash flow from operating activities
|
|
15,718
|
|
23,825
|
|
28,023
|
|
30,626
|
|
Cash flow from operating activities per share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$0.16
|
|
$0.23
|
|
$0.26
|
|
$0.28
|
|
|
Diluted
|
|
$0.15
|
|
$0.22
|
|
$0.24
|
|
$0.26
|
|
Funds flow from operations (1)
|
|
17,027
|
|
23,126
|
|
23,964
|
|
30,120
|
|
Funds flow from operations per share (1)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$0.17
|
|
$0.22
|
|
$0.22
|
|
$0.28
|
|
|
Diluted
|
|
$0.16
|
|
$0.21
|
|
$0.21
|
|
$0.26
|
|
Net profit (loss)
|
|
(5,487)
|
|
12,315
|
|
820
|
|
(13,597)
|
|
Net profit (loss) per share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
($0.06)
|
|
$0.12
|
|
$0.01
|
|
($0.13)
|
|
|
Diluted
|
|
($0.06)
|
|
$0.11
|
|
$0.01
|
|
($0.13)
|
|
Net capital expenditures (cash)
|
|
59,247
|
|
28,784
|
|
40,087
|
|
47,240
|
|
(1)
|
Refer to "Additonal GAAP Measures" in respect of the term "funds flow
from operations" and "funds flow from operations per share".
|
The quarterly results for 2012 compared to 2011 were positively impacted
by increased production resulting from the expansion of Bellatrix's
2011 and 2012 drilling programs, offset somewhat by lower overall
commodity prices realized in the 2012 quarters compared to the 2011
quarters.
During the first quarter of 2012, the Company spent $74.1 million in
capital expenditures, compared to $59.1 million in the first quarter of
2011. The Company drilled or participated in 13 gross (10.72 net)
wells in the first quarter of 2012, compared to 21 gross (12.07 net)
wells in the comparative 2011 quarter. Higher sales volumes of 15,900
boe/d in the 2012 first quarter compared to 10,084 boe/d in the 2011
period, in conjunction with stronger crude oil and NGL pricing and
offset slightly by depressed natural gas prices, resulted in increased
revenue of $58.2 million in the first quarter of 2012, compared to
$40.5 million in the 2011 first quarter.
In the second quarter of 2012, the Company closed on the disposition of
two minor non-core properties for total proceeds of $2.0 million after
adjustments. In the 2012 second quarter, the Company spent $18.3
million (2011: $29.0 million) in capital expenditures, and drilled 2
gross (1.72 net) wells, compared to 2 gross (1.71 net) wells in the
same period in 2011. Due primarily to Bellatrix's 2012 drilling
program executed in the first and second quarters, sales volumes
increased by 42% to 16,569 boe/d in the second quarter of 2012,
compared to 11,643 boe/d in the second quarter of 2011.
During the third quarter of 2012, the Company closed on the disposition
of a minor non-core property interest in the Wainwright area for
proceeds of $4.3 million after adjustments. In the third quarter of
2012, the Company spent $39.8 million on capital expenditures compared
to $44.2 million in the third quarter of 2011. In the third quarter of
2012, Bellatrix drilled 9 gross (7.71 net) wells, compared to 19 gross
(13.41 net) wells in the third quarter of 2011.
Fourth quarter of 2012 results are compared in detail to fourth quarter
2011 results throughout this MD&A.
Overall, the success and execution of the Company's 2012 drilling
program resulted in increased sales volumes and cash flows, despite
weaker commodity prices experienced during most of the 2012 year.
Selected Annual Consolidated Information
The following table sets forth selected consolidated financial
information of the Company for the most recently completed year ending
December 31, 2012 and for comparative 2011 and 2010 years. The
adoption date of IFRS of January 1, 2011 required restatement for
comparative purposes, of the Company's opening balance sheet as at
January 1, 2010, all interim quarterly periods in 2010 and for its year
ended December 31, 2010.
|
|
|
|
|
|
|
|
Years ended December 31,
($000s, except per share amounts)
|
|
2012
|
|
2011
|
|
2010
|
|
Revenues (before royalties and risk management)
|
|
219,314
|
|
202,318
|
|
117,673
|
|
Funds flow from operations (1)
|
|
111,038
|
|
94,237
|
|
53,042
|
|
Funds flow from operations per share (1)
|
|
|
|
|
|
|
|
|
Basic
|
|
$1.03
|
|
$0.91
|
|
$0.57
|
|
|
Diluted
|
|
$0.96
|
|
$0.87
|
|
$0.54
|
|
Cash flow from operating activities
|
|
|
|
|
|
|
|
Cash flow from operating activities per share
|
|
109,328
|
|
98,192
|
|
44,272
|
|
|
Basic
|
|
$1.02
|
|
$0.95
|
|
$0.47
|
|
|
Diluted
|
|
$0.95
|
|
$0.87
|
|
$0.46
|
|
Net profit (loss)
|
|
27,771
|
|
(5,949)
|
|
(4,985)
|
|
Net profit (loss) per share
|
|
|
|
|
|
|
|
|
Basic
|
|
$0.26
|
|
($0.06)
|
|
($0.05)
|
|
|
Diluted
|
|
$0.25
|
|
($0.06)
|
|
($0.05)
|
|
Net capital expenditures (cash)
|
|
(178,688)
|
|
(175,358)
|
|
(92,181)
|
|
Total assets
|
|
681,421
|
|
580,422
|
|
477,054
|
|
Total net debt (1) (2)
|
|
189,577
|
|
119,250
|
|
87,444
|
|
Non-current financial liabilities
|
|
|
|
|
|
|
|
|
Future income taxes
|
|
-
|
|
-
|
|
-
|
|
|
Decommissioning liabilities
|
|
43,909
|
|
45,091
|
|
38,710
|
|
Sales volumes (boe/d)
|
|
16,775
|
|
11,954
|
|
8,519
|
|
Distributions declared
|
|
-
|
|
-
|
|
-
|
|
Distributions per share/unit
|
|
-
|
|
-
|
|
-
|
|
(1)
|
Refer to " Additional GAAP Measures" in respect of the terms "funds flow
from operations," "funds flow from operations per share," "net debt"
and "total net debt."
|
|
(2)
|
Net debt includes the net working capital deficiency before short-term
commodity contract assets and liabilities, current finance lease
obligations and short-term future income tax assets and liabilities.
Total net debt also includes the liability component of convertible
debentures and excludes finance lease obligations, decommissioning
liabilities and future income tax liabilities.
|
2012 annual results are compared in detail to 2011 annual results
throughout this MD&A.
The annual results for 2011 compared to 2010 were most notably impacted
by an expanded drilling program resulting in increased sales volumes.
Revenues and cash flows were impacted by increased sales volumes,
higher crude oil, condensate and NGL prices and lower natural gas
prices realized, as well as lower operating costs per boe between the
years.
Bellatrix's capital expenditures totaled $179.6 million in 2011,
compared to $106.7 million in 2010. Due in large part to the expanded
capital program in 2011, total sales volumes increased by 40% to 11,954
boe/d in 2011, compared to 8,519 boe/d in 2010. Primarily due to the
significant increase in sales volumes between the years, revenues
before royalties and risk management increased to $202.3 million in
2011, compared to $117.7 million realized in 2010, despite reductions
in commodity prices between the years.
|
BELLATRIX EXPLORATION LTD.
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS
As at December 31,
|
|
|
|
|
|
(expressed in Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
Accounts receivable (note 21)
|
|
$ 40,792
|
|
$ 45,322
|
|
|
Deposits and prepaid expenses
|
|
4,136
|
|
3,626
|
|
|
Commodity contract asset (note 21)
|
|
7,519
|
|
2,979
|
|
|
|
52,447
|
|
51,927
|
|
Exploration and evaluation assets (note 6)
|
|
38,177
|
|
33,089
|
|
Property, plant and equipment (note 7)
|
|
589,759
|
|
484,301
|
|
Deferred taxes (note 15)
|
|
1,038
|
|
11,105
|
|
Total assets
|
|
$ 681,421
|
|
$ 580,422
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$ 50,771
|
|
$ 62,421
|
|
|
Current portion of finance lease obligation (note 10)
|
|
1,425
|
|
490
|
|
|
Commodity contract liability (note 21)
|
|
1,131
|
|
10,667
|
|
|
|
53,327
|
|
73,578
|
|
|
|
|
|
|
|
Commodity contract liability (note 21)
|
|
6,214
|
|
2,944
|
|
Long-term debt (note 8)
|
|
133,047
|
|
56,701
|
|
Convertible debentures (note 9)
|
|
50,687
|
|
49,076
|
|
Finance lease obligation (note 10)
|
|
13,131
|
|
4,627
|
|
Decommissioning liabilities (note 11)
|
|
43,909
|
|
45,091
|
|
Total liabilities
|
|
300,315
|
|
232,017
|
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
Shareholders' capital (note 12)
|
|
371,576
|
|
370,048
|
|
|
Equity component of convertible debentures (note 9)
|
|
4,378
|
|
4,378
|
|
|
Contributed surplus
|
|
37,284
|
|
33,882
|
|
|
Deficit
|
|
(32,132)
|
|
(59,903)
|
|
Total shareholders' equity
|
|
381,106
|
|
348,405
|
|
Total liabilities and shareholders' equity
|
|
$ 681,421
|
|
$ 580,422
|
|
|
|
|
|
|
COMMITMENTS (note 20)
SUBSEQUENT EVENT (note 22)
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
|
|
|
|
BELLATRIX EXPLORATION LTD.
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
(expressed in Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
REVENUES
|
|
|
|
|
|
Petroleum and natural gas sales
|
|
$ 217,138
|
|
$ 200,187
|
|
Other income
|
|
2,176
|
|
2,131
|
|
Royalties
|
|
(38,756)
|
|
(34,698)
|
|
Total revenues
|
|
180,558
|
|
167,620
|
|
|
|
|
|
|
|
Realized gain on commodity contracts
|
|
11,269
|
|
567
|
|
Unrealized gain (loss) on commodity contracts
|
|
10,806
|
|
(6,900)
|
|
|
|
202,633
|
|
161,287
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
Production
|
|
53,316
|
|
50,313
|
|
Transportation
|
|
4,978
|
|
5,715
|
|
General and administrative (note 17)
|
|
14,272
|
|
12,358
|
|
Share-based compensation (note 13)
|
|
3,219
|
|
2,939
|
|
Depletion and depreciation (note 7)
|
|
75,720
|
|
63,384
|
|
Gain on property acquisition (note 7)
|
|
(16,160)
|
|
-
|
|
Loss (gain) on property dispositions (note 7)
|
|
4,113
|
|
(1,730)
|
|
Impairment loss on property, plant and equipment (note 7)
|
|
14,820
|
|
25,569
|
|
|
|
154,278
|
|
158,548
|
|
|
|
|
|
|
|
NET PROFIT BEFORE FINANCE AND TAXES
|
|
48,355
|
|
2,739
|
|
|
|
|
|
|
|
Finance expenses (note 16)
|
|
10,517
|
|
7,920
|
|
|
|
|
|
|
|
NET PROFIT (LOSS) BEFORE TAXES
|
|
37,838
|
|
(5,181)
|
|
|
|
|
|
|
|
TAXES
|
|
|
|
|
|
Deferred tax expense (note 15)
|
|
10,067
|
|
768
|
|
|
|
|
|
|
|
NET PROFIT (LOSS) AND COMPREHENSIVE INCOME
|
|
27,771
|
|
(5,949)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net profit (loss) per share (note 19)
|
|
|
|
|
|
Basic
|
|
$0.26
|
|
($0.06)
|
|
Diluted
|
|
$0.25
|
|
($0.06)
|
See accompanying notes to the consolidated financial statements.
BELLATRIX EXPLORATION LTD.
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
|
(expressed in Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
SHAREHOLDERS' CAPITAL (note 12)
|
|
|
|
|
|
|
|
Common shares
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
$ 370,048
|
|
$ 316,779
|
|
|
|
Issued for cash, net of transaction costs
|
|
|
-
|
|
52,734
|
|
|
|
Issued on exercise of share options
|
|
|
1,093
|
|
381
|
|
|
|
Contributed surplus transferred on exercised options
|
|
|
435
|
|
154
|
|
|
|
Balance, end of year
|
|
|
371,576
|
|
370,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EQUITY COMPONENT OF CONVERTIBLE DEBENTURES (note 9)
|
|
|
|
|
|
|
|
|
Balance, beginning and end of year
|
|
|
4,378
|
|
4,378
|
|
|
|
|
|
|
|
|
CONTRIBUTED SURPLUS (note 13)
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
33,882
|
|
30,489
|
|
|
|
Share-based compensation expense
|
|
|
4,024
|
|
3,632
|
|
|
|
Adjustment of share-based compensation expense for forfeitures of
unvested share options
|
|
|
(187)
|
|
(85)
|
|
|
|
Transfer to share capital for exercised options
|
|
|
(435)
|
|
(154)
|
|
|
|
Balance, end of year
|
|
|
37,284
|
|
33,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFICIT
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
(59,903)
|
|
(53,954)
|
|
|
|
Net profit (loss)
|
|
|
27,771
|
|
(5,949)
|
|
|
|
Balance, end of year
|
|
|
(32,132)
|
|
(59,903)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL SHAREHOLDERS' EQUITY
|
|
|
$ 381,106
|
|
$ 348,405
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
|
BELLATRIX EXPLORATION LTD.
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
|
(expressed in Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
|
2011
|
|
|
|
|
|
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net profit (loss)
|
$
|
27,771
|
|
$
|
(5,949)
|
|
Adjustments for:
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
75,720
|
|
|
63,384
|
|
|
|
Finance expenses (note 16)
|
|
2,294
|
|
|
2,356
|
|
|
|
Share-based compensation (note 13)
|
|
3,219
|
|
|
2,939
|
|
|
|
Unrealized (gain) loss on commodity contracts
|
|
(10,806)
|
|
|
6,900
|
|
|
|
Gain on property acquisition (note 7)
|
|
(16,160)
|
|
|
-
|
|
|
|
Loss (gain) on property dispositions
|
|
4,113
|
|
|
(1,730)
|
|
|
|
Impairment loss on property, plant and equipment
|
|
14,820
|
|
|
25,569
|
|
|
|
Deferred tax expense (note 15)
|
|
10,067
|
|
|
768
|
|
|
|
Decommissioning costs incurred
|
|
(635)
|
|
|
(569)
|
|
|
|
Change in non-cash working capital (note 14)
|
|
(1,075)
|
|
|
4,524
|
|
|
|
109,328
|
|
|
98,192
|
|
|
|
|
|
|
|
|
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Issuance of share capital
|
|
1,093
|
|
|
55,385
|
|
|
|
Issue costs on share capital
|
|
-
|
|
|
(3,088)
|
|
|
|
Advances from loans and borrowings
|
|
528,529
|
|
|
372,141
|
|
|
|
Repayment of loans and borrowings
|
|
(452,183)
|
|
|
(356,612)
|
|
|
|
Obligations under finance lease (note 10)
|
|
(560)
|
|
|
(172)
|
|
|
|
76,879
|
|
|
67,654
|
|
|
|
Change in non-cash working capital (note 14)
|
|
(55)
|
|
|
136
|
|
|
|
76,824
|
|
|
67,790
|
|
|
|
|
|
|
|
|
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Expenditure on exploration and evaluation assets
|
|
(17,118)
|
|
|
(16,839)
|
|
|
|
Additions to property, plant and equipment
|
|
(168,230)
|
|
|
(162,722)
|
|
|
|
Proceeds on sale of property, plant and equipment
|
|
6,660
|
|
|
4,203
|
|
|
|
(178,688)
|
|
|
(175,358)
|
|
|
|
Change in non-cash working capital (note 14)
|
|
(7,464)
|
|
|
9,376
|
|
|
|
(186,152)
|
|
|
(165,982)
|
|
|
|
|
|
|
|
|
|
|
Change in cash
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Cash, beginning of year
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Cash, end of year
|
$
|
-
|
|
$
|
-
|
|
|
|
|
|
|
|
|
Cash paid:
|
|
|
|
|
|
|
|
Interest
|
$
|
5,676
|
|
$
|
4,738
|
|
|
Taxes
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(expressed in Canadian dollars)
1. CORPORATE INFORMATION
Bellatrix Exploration Ltd. (the "Company" or "Bellatrix") is a growth
oriented, public exploration and production company.
2. BASIS OF PREPARATION
a. Statement of compliance
These consolidated financial statements ("financial statements") were
authorized by the Board of Directors on March 6, 2013. The Company
prepared these financial statements in accordance with International
Financial Reporting Standards as issued by the International Accounting
Standards Board ("IFRS").
b. Basis of measurement
The consolidated financial statements are presented in Canadian dollars,
the Company's functional currency, and have been prepared on the
historical cost basis except for derivative financial instruments and
liabilities for cash-settled share-based payment arrangements measured
at fair value. The consolidated financial statements have, in
management's opinion, been properly prepared using careful judgment and
reasonable limits of materiality and within the framework of the
significant policies summarized in note 3. The areas involving a
higher degree of judgment or complexity, or areas where assumptions and
estimates are significant to the financial statements are disclosed in
note 4.
3. SIGNIFICANT ACCOUNTING POLICIES
a. Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its subsidiary. Any reference to the "Company" throughout
these consolidated financial statements refers to the Company and its
subsidiary. All inter-entity transactions have been eliminated.
b. Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when
title to the products transfers to the purchasers based on volumes
delivered and contracted delivery points and prices. Royalty income is
recognized as it accrues in accordance with the terms of the overriding
royalty agreements and is included with petroleum and natural gas
sales.
Processing charges to other entities for use of facilities owned by the
Company are recognized as revenue as they accrue in accordance with the
terms of the service agreements and are presented as other income.
c. Joint Interests
A significant portion of the Company's exploration and development
activities are conducted jointly with others. The financial statements
reflect only the Company's proportionate share of the assets,
liabilities, revenues, expenses and cash flows from these activities.
d. Property, Plant and Equipment and Exploration and Evaluation Assets
|
|
I.
|
Pre-exploration expenditures
|
|
|
|
Expenditures made by the Company before acquiring the legal right to
explore in a specific area do not meet the definition of an asset and
therefore are expensed by the Company as incurred.
|
|
|
|
|
|
|
II.
|
Exploration and evaluation expenditures
|
|
|
|
Costs incurred once the legal right to explore has been acquired are
capitalized as exploration and evaluation assets. These costs include,
but are not limited to, exploration license expenditures, leasehold
property acquisition costs, evaluation costs, including drilling costs
directly attributable to an identifiable well and directly attributable
general and administrative costs. These costs are accumulated in cost
centres by property and are not subject to depletion until technical
feasibility and commercial viability have been determined.
|
|
|
|
Exploration and evaluation assets are assessed for impairment if
sufficient data exists to determine technical feasibility and
commercial viability, or if facts and circumstances suggest that the
carrying amount is unlikely to be recovered.
|
|
|
|
|
|
|
III.
|
Developing and production costs
|
|
|
|
Items of property, plant and equipment, which include oil and gas
development and production assets, are measured at cost less
accumulated depletion and depreciation and accumulated impairment
losses.
|
|
|
|
Gains and losses on disposal of an item of property, plant and
equipment, including oil and natural gas interests, are determined by
comparing the proceeds from disposal with the carrying amount of
property, plant and equipment, and are recognized within the
Consolidated Statements of Comprehensive Income.
|
|
|
|
|
|
|
IV.
|
Subsequent costs
|
|
|
|
Costs incurred subsequent to the determination of technical feasibility
and commercial viability and the costs of replacing parts of property,
plant and equipment are recognized as oil and natural gas interests
only when they increase the future economic benefits embodied in the
specific asset to which they relate. All other expenditures are
recognized in profit or loss as incurred. Such capitalized oil and
natural gas interests generally represent costs incurred in developing
proved and/or probable reserves and bringing in or enhancing production
from such reserves, and are accumulated on a well, field or
geotechnical area basis. The carrying amount of any replaced or sold
component is derecognized. The costs of the day-to-day servicing of
property, plant and equipment are recognized in profit or loss as
incurred.
|
|
|
|
|
|
|
V.
|
Depletion and depreciation
|
|
|
|
Depletion of petroleum and natural gas properties is provided using the
unit-of-production method based on production volumes in relation to
total estimated proven and probable reserves as determined annually by
independent engineers and determined in accordance with National
Instrument 51-101. Natural gas reserves and production are converted
at the energy equivalent of six thousand cubic feet to one barrel of
oil.
|
|
|
|
Calculations for depletion and depreciation of production equipment are
based on total capitalized costs plus estimated future development
costs of proven and probable undeveloped reserves less the estimated
net realizable value of production equipment and facilities after the
proved and probable reserves are fully produced.
|
|
|
|
Depreciation of office furniture and equipment is provided for on a 20%
declining balance basis. Depreciation methods, useful lives and
residual values are reviewed at each reporting date.
|
|
|
|
|
e. Impairment
|
|
I.
|
Financial assets
|
|
|
|
A financial asset is assessed at each reporting date to determine
whether there is any objective evidence that it is impaired. A
financial asset is considered to be impaired if objective evidence
indicates that one or more events have had a negative effect on the
estimated future cash flows of that asset.
|
|
|
|
An impairment loss in respect of a financial asset measured at amortized
cost is calculated as the difference between its carrying amount and
the present value of the estimated future cash flows discounted at the
original effective interest rate. All impairment losses are recognized
in profit or loss.
|
|
|
|
|
|
|
II.
|
Non-financial assets
|
|
|
|
For the purpose of impairment testing, assets are grouped together into
the smallest group of assets that generates cash inflows from
continuing use that are largely independent of the cash inflows of
other assets or groups of assets (the "cash-generating unit" or
"CGU"). Developing and producing assets are assessed for impairment if
facts and circumstances suggest that the carrying amount exceeds the
recoverable amount.
|
|
|
|
The recoverable amount of an asset or a CGU is the greater of its value
in use and its fair value less costs to sell. Fair value less costs to
sell is determined to be the amount for which the asset could be sold
in an arm's length transaction. Fair value less costs to sell can be
determined by using an observable market metric or by using discounted
future net cash flows of proved and probable reserves using forecasted
prices and costs. Value in use is determined by estimating the present
value of the future net cash flows expected to be derived from the
continued use of the asset or cash generating unit.
|
|
|
|
An impairment loss is recognized if the carrying amount of an asset or
its CGU exceeds its estimated recoverable amount. Impairment losses are
recognized in profit or loss. Impairment losses recognized in respect
of CGU's are allocated first to reduce the carrying amount of goodwill,
if any, allocated to the units and then to reduce the carrying amounts
of the other assets in the unit (group of units) on a pro rata basis.
|
|
|
|
Impairment losses recognized in prior years are assessed at each
reporting date for any indications that the loss has decreased or no
longer exists. An impairment loss is reversed if there has been a
change in the estimates used to determine the recoverable amount. An
impairment loss is reversed only to the extent that the asset's
carrying amount does not exceed the carrying amount that would have
been determined, net of depletion and depreciation or amortization, if
no impairment loss had been recognized.
|
|
|
|
Exploration and evaluation assets are grouped together with the
Company's CGU's when they are assessed for impairment, both at the time
of any triggering facts and circumstances as well as upon their
eventual reclassification to producing assets (oil and natural gas
interests in property, plant and equipment).
|
f. Provisions
Provisions are recognized when the Company has a present legal or
constructive obligation as a result of a past event, it is probable
that an outflow of economic benefits will be required to settle the
obligation and a reliable estimate can be made of the amount of the
obligation. Provisions are determined by discounting the expected cash
flows at a pre-tax rate that reflects current market assessments of the
time value of money and the risks specific to the liability if the
risks have not been incorporated into the estimate of cash flows. The
increase in the provision due to the passage of time is recognized
within finance costs.
|
|
I.
|
Decommissioning obligations
|
|
|
|
The Company's activities give rise to dismantling, decommissioning and
site disturbance re-mediation activities. A provision is made for the
estimated cost of site restoration and capitalized in the relevant
asset category.
|
|
|
|
Decommissioning obligations are measured at the present value of
management's best estimate of the expenditure required to settle the
present obligation at the balance sheet date. Changes in the present
value of the estimated expenditure are reflected as an adjustment to
the provision and the relevant asset. The unwinding of the discount on
the decommissioning provision is recognized as a finance cost. Actual
costs incurred upon settlement of the decommissioning liabilities are
charged against the provision to the extent the provision was
recognized.
|
|
|
|
|
|
|
II.
|
Environmental Liabilities
|
|
|
|
The Company records liabilities on an undiscounted basis for
environmental remediation efforts that are likely to occur and where
the cost can be reasonably estimated. The estimates, including
associated legal costs, are based on available information using
existing technology and enacted laws and regulations. The estimates
are subject to revision in future periods based on actual costs
incurred or new circumstances. Any amounts expected to be recovered
from other parties, including insurers, are recorded as an asset
separate from the associated liability.
|
|
|
|
|
g. Share-based Payments
|
|
I.
|
Equity-settled transactions
|
|
|
|
Bellatrix accounts for options issued under the Company's share option
plan to employees, directors, officers, consultants and other service
providers by reference to the fair value of the equity instruments
granted. The fair value of each share option is estimated on the date
of the grant using the Black-Scholes options pricing model and charged
to earnings over the vesting period with a corresponding increase to
contributed surplus. The Company estimates a forfeiture rate on the
grant date and the rate is adjusted to reflect the actual number of
options that actually vest. The expected life of the options granted
is adjusted, based on the Company's best estimate, for the effects of
non-transferability, exercise restrictions and behavioural
considerations.
|
|
|
|
|
|
|
II.
|
Cash-settled transactions
|
|
|
|
The Company's Deferred Share Unit Plan (the "Plan") is accounted for as
a cash settled share based payment plan in accordance with IFRS 2 -
"Share-based Payments" in which the fair value of the amount payable
under the Plan is recognized as an expense with a corresponding
increase in liabilities. The liability is re-measured at each reporting
date and at settlement date. Any changes in the fair value of the
liability are recognized in profit or loss.
|
|
|
|
|
h. Income Taxes
Income tax expense is comprised of current and deferred tax. Income tax
expense is recognized in profit or loss except to the extent that it
relates to items recognized directly in equity, in which case it is
recognized in equity.
|
|
I.
|
Current income tax
|
|
|
|
Current income tax assets and liabilities for the current and prior
periods are measured at the amount expected to be recovered from or
paid to the taxation authorities. The tax rates and tax laws used to
compute the amount are those that are enacted or substantively enacted
by the date of the statement of financial position.
|
|
|
|
|
|
|
II.
|
Deferred income tax
|
|
|
|
Deferred tax is recognized using the balance sheet method, providing for
temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for
taxation purposes. Deferred tax is not recognized on the initial
recognition of assets or liabilities in a transaction that is not a
business combination. In addition, deferred tax is not recognized for
taxable temporary differences arising on the initial recognition of
goodwill. Deferred tax is measured at the tax rates that are expected
to be applied to temporary differences when they reverse, based on the
laws that have been enacted or substantively enacted by the reporting
date. Deferred tax assets and liabilities are offset if there is a
legally enforceable right to offset, and they relate to income taxes
levied by the same tax authority on the same taxable entity, or on
different tax entities, but they intend to settle current tax
liabilities and assets on a net basis or their tax assets and
liabilities will be realized simultaneously.
|
|
|
|
A deferred tax asset is recognized to the extent that it is probable
that future taxable profits will be available against which the
temporary difference can be utilized. Deferred tax assets are reviewed
at each reporting date and are reduced to the extent that it is no
longer probable that the related tax benefit will be realized.
|
|
|
|
|
i. Financial Instruments
All financial instruments, including all derivatives, are recognized on
the balance sheet initially at fair value. Subsequent measurement of
all financial assets and liabilities except those held-for-trading and
available for sale are measured at amortized cost determined using the
effective interest rate method. Held-for-trading financial assets are
measured at fair value with changes in fair value recognized in
income. Available-for-sale financial assets are measured at fair value
with changes in fair value recognized in comprehensive income and
reclassified to income when derecognized or impaired. The Company has
the following classifications:
|
Financial Assets and Liabilities
|
Category
|
Subsequent Measurement
|
|
Cash and cash equivalents
|
Held-for-trading
|
Fair value through profit or loss
|
|
Accounts receivable
|
Loans and receivables
|
Amortized cost
|
|
Deposits and prepaid expenses
|
Other assets
|
Amortized cost
|
|
Commodity risk management contracts
|
Held-for-trading
|
Fair value through profit or loss
|
|
Accounts payable and accrued liabilities
|
Other liabilities
|
Amortized cost
|
|
Long-term debt
|
Other liabilities
|
Amortized cost
|
|
Convertible debentures
|
Other liabilities
|
Amortized cost
|
|
Finance lease obligation
|
Other liabilities
|
Amortized cost
|
Transaction costs attributable to financial instruments classified as
other than held-for-trading are included in the recognized amount of
the related financial instrument and recognized over the life of the
resulting financial instrument using the effective interest rate
method.
The Company utilizes financial derivatives and commodity sales contracts
requiring physical delivery, to manage the price risk attributable to
anticipated sale of petroleum and natural gas production and foreign
exchange exposures. The Company does not enter into derivative
financial instruments for trading or speculative purposes. The Company
has not designated its financial derivative contracts as effective
accounting hedges, and thus not applied hedge accounting, even though
the Company considers all commodity contracts to be economic hedges.
As a result, financial derivatives are classified as fair value through
profit or loss and are recorded on the balance sheet at fair value.
The derivative financial instruments are initiated within the guidelines
of the Company's commodity price risk management policy. This includes
linking all derivatives to specific assets and liabilities on the
balance sheet or to specific firm commitments or forecasted
transactions.
The Company accounts for its commodity sales and purchase contracts,
which were entered into and continue to be held for the purpose of
receipt or delivery of non-financial items in accordance with its
expected purchase, sale or usage requirements as executory contracts.
As such, physical sales and purchase contracts are not recorded at fair
value on the balance sheet. Settlements on these physical sales
contracts are recognized in petroleum and natural gas sales.
Financial instruments measured at fair value on the balance sheet
require classification into one of the following levels of the fair
value hierarchy:
Level 1 - Quoted prices (unadjusted) in active markets for identical
assets or liabilities
Level 2 - Inputs other than quoted prices included in level 1 that are
observable for the asset or liability, either directly or indirectly.
Level 3 - inputs for the asset or liability that are not based on
observable market data.
The fair value hierarchy level at which a fair value measurement is
categorized is determined on the basis of the lowest level input that
is significant to the fair value measurement in its entirety. The
Company has categorized its financial instruments that are fair valued
on the balance sheet according to the fair value hierarchy.
j. Compound Financial Instruments
The Company's compound financial instruments comprise of its convertible
debentures that can be converted to common shares at the option of the
holder, and the number of shares to be issued does not vary with
changes in fair value.
The liability component of the convertible debentures is recognized
initially at the fair value of a similar liability that does not have
an equity conversion option. The equity component is recognized
initially as the difference between the fair value of the convertible
debenture and the fair value of the liability component. Any directly
attributable transaction costs are allocated to the liability and
equity components in proportion to their initial carrying amounts.
Subsequent to initial recognition, the liability component of the
convertible debentures is measured at amortized cost using the
effective interest method. The equity component of the convertible
debentures is not re-measured subsequent to initial recognition.
k. Finance Lease Obligation
Leases which effectively transfer substantially all of the risks and
rewards of ownership to the Company are classified as finance leases
and are accounted for as an acquisition of an asset and an assumption
of an obligation at the inception of the lease, measured as the present
value of minimum lease payments to a maximum of the asset's fair
value. The asset is amortized in accordance with the Company's
depletion and depreciation policy. The obligations recorded under
finance lease payments are reduced by the lease payments made.
l. Basic and Diluted per Share Calculations
Basic per share amounts are calculated using the weighted average number
of shares outstanding during the period. The Company uses the treasury
share method to determine the dilutive effect of share options. Under
the treasury share method, only "in the money" dilutive instruments
impact the diluted calculations in computing diluted per share
amounts. The Company uses the "if-converted" method to determine the
dilutive effect of convertible debentures.
m. Finance Income and Expenses
Finance income is recognized as it accrues in profit or loss, using the
effective interest method. Finance expense comprises interest expense
on borrowings, amortization of deferred charges, accretion of the
discount rate on provisions, accretion of the liability component of
the convertible debentures and impairment losses recognized on
financial assets.
n. Borrowing Costs
Borrowing costs incurred for the construction of qualifying assets are
capitalized during the period of time that is required to complete and
prepare the assets for their intended use or sale. Qualifying assets
are assets that necessarily take a substantial period of time to get
ready for their intended use. All other borrowing costs are recognized
in profit or loss using the effective interest method. The
capitalization rate used to determine the amount of borrowing costs to
be capitalized is the weighted average interest rate applicable to the
Company's outstanding borrowings during the period.
o. Cash and Cash Equivalents
Cash and cash equivalents include cash and short-term investments with
original maturities of three months or less.
p. Business Combinations
Business combinations are accounted for using the acquisition method.
The identifiable assets acquired and liabilities and contingent
liabilities assumed are measured at their fair values at the
acquisition date. The cost of an acquisition is measured as the
aggregate consideration transferred, measured at the acquisition date
fair value. If the cost of the acquisition is less than the fair value
of the net assets acquired, the difference is recognized immediately in
net income. Acquisition costs incurred are expensed.
4. CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES
The consolidated financial statements of the Company have been prepared
by management in accordance with IFRS. The preparation of consolidated
financial statements in conformity with IFRS requires management to
make judgment, estimates and assumptions that affect the reported
amounts of assets, liabilities, and contingent liabilities at the date
of the consolidated financial statements and reported amounts of
revenues and expenses during the reporting period and accompanying
notes. By their nature, these estimates are subject to measurement
uncertainty and the effect on the financial statements of changes in
such estimates in future periods could be material. Revisions to
accounting estimates are recognized in the period in which the
estimates are revised and in any future periods affected.
|
|
I.
|
Derivatives
|
|
|
|
|
|
|
|
The fair value of commodity contracts is estimated, whenever possible,
based on published market prices, and if not available, on estimates
from third party brokers, as at the balance sheet date and may differ
from what will eventually be realized.
|
|
|
|
|
|
|
II.
|
Oil and gas reserves
|
|
|
|
|
|
|
|
Reserves and resources are used in the units of production calculation
for depreciation, depletion and amortization and the impairment
analysis which affect net profit. There are numerous uncertainties
inherent in estimating oil and gas reserves. Estimating reserves is
very complex, requiring many judgments based on geological,
geophysical, engineering and economic data. Changes in these judgments
could have a material impact on the estimated reserves. These
estimates may change, having either a negative or positive effect on
net profit as further information becomes available and as the economic
environment changes.
|
|
|
|
|
|
|
III.
|
Depreciation and depletion
|
|
|
|
|
|
|
|
Depletion of petroleum and natural gas properties is provided using the
unit-of-production method based on production volumes before royalties
in relation to total estimated proved and probable reserves as
determined annually by independent engineers and internal reserve
evaluations on a quarterly basis determined in accordance with National
Instrument 51-101. Natural gas reserves and production are converted
at the energy equivalent of six thousand cubic feet to one barrel of
oil.
|
|
|
|
|
|
|
|
Calculations for depletion and depreciation of production equipment are
based on total capitalized costs plus estimated future development
costs of proved and probable undeveloped reserves less the estimated
net realizable value of production equipment and facilities after the
proved reserves are fully produced. The costs of acquiring and
evaluating unproved properties are excluded from depletion
calculations.
|
|
|
|
|
|
|
IV.
|
Recoverability of asset carrying values
|
|
|
|
|
|
|
|
The Company assesses its oil and gas properties, including exploration
and evaluation assets, for possible impairment if there are events or
changes in circumstances that indicate that carrying values of the
assets may not be recoverable, or at least at every reporting date.
|
|
|
|
|
|
|
|
The assessment of any impairment of property, plant and equipment is
dependent upon estimates of recoverable amount that take into account
factors such as reserves, economic and market conditions, timing of
cash flows, the useful lives of assets and their related salvage
values.
|
|
|
|
|
|
|
|
Bellatrix's assets are aggregated into CGUs, for the purpose of
calculating impairment, based on their ability to generate largely
independent cash flows, geography, geology, production profile and
infrastructure of its assets. By their nature, these estimates and
assumptions are subject to measurement uncertainty and may impact the
carrying value of the Company's assets in future periods.
|
|
|
|
|
|
|
V.
|
Decommissioning obligations
|
|
|
|
|
|
|
|
Provisions for decommissioning obligations associated with the Company's
drilling operations are based on current legal and constructive
requirements, technology, price levels and expected plans for
remediation. Actual costs and cash outflows can differ from estimates
because of changes in laws and regulations, public expectations,
prices, discovery and analysis of site conditions and changes in clean
up technology.
|
|
|
|
|
|
|
VI.
|
Share-based compensation
|
|
|
|
|
|
|
|
The fair value of stock options granted is measured using a Black
Scholes model. Measurement inputs include share price on measurement
date, exercise price of the option, expected volatility, expected life
of the options, expected dividends and the risk-free rate. The Company
estimates volatility based on the historical share price. The expected
life of the options is based on historical experience and general
option holder behavior. Dividends were not taken into consideration as
the Company does not expect to pay dividends. Management also makes an
estimate of the number of options that will be forfeited and the rate
is adjusted to reflect the actual number of options that actually vest.
|
|
|
|
|
|
|
VII.
|
Income taxes
|
|
|
|
|
|
|
|
Related assets and liabilities are recognized for the estimated tax
consequences between amounts included in the financial statements and
their tax base using substantively enacted future income tax rates.
Timing of future revenue streams and future capital spending changes
can affect the timing of any temporary differences, and accordingly
affect the amount of the deferred tax asset or liability calculated at
a point in time. These differences could materially impact earnings.
|
|
|
|
|
|
|
VIII.
|
Business combinations
|
|
|
|
|
|
|
|
Business combinations are accounted for using the acquisition method of
accounting. The determination of fair value often requires management
to make assumptions and estimates about future events. The assumptions
and estimates with respect to determining the fair value of property,
plant, and equipment, and exploration and evaluation assets acquired
generally require the most judgment and include estimates of reserves
acquired, forecast benchmark commodity prices, and discount rates.
Changes in any of the assumptions or estimates used in determining the
fair value of acquired assets and liabilities could impact the amounts
assigned to assets, liabilities in the purchase price allocation, and
any resulting gain or loss. Future net earnings can be affected as a
result of changes in future depletion, depreciation and accretion, and
asset impairments.
|
|
|
|
|
5. NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED
The following pronouncements from the IASB are applicable to Bellatrix
and will become effective for future reporting periods, but have not
yet been adopted:
IFRS 9 - "Financial Instruments", which is the result of the first phase
of the IASB's project to replace IAS 39, "Financial Instruments:
Recognition and Measurement". The new standard replaces the current
multiple classification and measurement models for financial assets and
liabilities with a single model that has only two classification
categories: amortized cost and fair value. This standard is effective
for annual periods beginning on or after January 1, 2015 with different
transitional arrangements depending on the date of initial application.
The extent of the impact of the adoption of IFRS 9 has not yet been
determined.
IFRS 10 - "Consolidated Financial Statements" ("IFRS 10"), which
requires an entity to consolidate an investee when it is exposed, or
has rights, to variable returns from its involvement with the investee
and has the ability to affect those returns through its power over the
investee. Under existing IFRS, consolidation is required when an entity
has the power to govern the financial and operating policies of an
entity so as to obtain benefits from its activities. This standard
replaces SIC-12 - "Consolidation—Special Purpose Entities" and parts of
IAS 27 - "Consolidated and Separate Financial Statements." Bellatrix
intends to adopt IFRS 10, including the amendments issued in June 2012,
in its financial statements for the annual period beginning on January
1, 2013. The adoption of IFRS 10 is currently not anticipated to
impact the Company's financial statements.
IFRS 11 - "Joint Arrangements" ("IFRS 11"), requires a venturer to
classify its interest in a joint arrangement as a joint venture or
joint operation, each having its own accounting model. Joint ventures
will be accounted for using the equity method of accounting, whereas
for a joint operation the venture will recognize its share of the
assets, liabilities, revenue and expenses of the joint operation. The
standard provides for a more substance based reflection of joint
arrangements by focusing on the rights and obligations of the
arrangement, rather than its legal form. IFRS 11 replaces IAS 31 -
"Interests in Joint Ventures" and SIC-13 - "Jointly Controlled
Entities—Non-monetary Contributions by Venturers" and establishes
principles for accounting for all joint arrangements. Bellatrix
intends to adopt IFRS 11, including the amendments issued in June 2012,
in its financial statements for the annual period beginning on January
1, 2013. The adoption of IFRS 11 is currently not anticipated to have
a significant impact on the Company's financial statements.
IFRS 12 - "Disclosure of Interests in Other Entities" ("IFRS 12"),
establishes disclosure requirements for interests in other entities,
such as joint arrangements, associates, special purpose vehicles and
off balance sheet vehicles. The standard carries forward existing
disclosures and also introduces significant additional disclosure
requirements that address the nature of, and risks associated with, an
entity's interests in other entities. Bellatrix intends to adopt IFRS
12, including the amendments issued in June 2012, in its financial
statements for the annual period beginning on January 1, 2013. The
adoption of IFRS 12 is currently not anticipated to have a significant
impact on the Company's financial statements.
IFRS 13 - "Fair Value Measurement" ("IFRS 13"), is a comprehensive
standard for fair value measurement and disclosure requirements for use
across all IFRSs. The new standard clarifies that fair value is the
price that would be received to sell an asset, or paid to transfer a
liability in an orderly transaction between market participants, at the
measurement date. It also establishes disclosures about fair value
measurement. Under existing IFRS, guidance on measuring and disclosing
fair value is dispersed among the specific standards requiring fair
value measurements and in many cases does not reflect a clear
measurement basis or consistent disclosures. IFRS 13 is effective for
annual periods beginning on or after January 1, 2013 and applies
prospectively from the beginning of the annual period in which the
standard is adopted. The extent of the impact of the adoption of IFRS
13 on the Company's financial statements has not yet been determined.
In June 2011, the IASB issued an amendment to IAS 1 - "Presentation of
Financial Statements" ("IAS 1") requiring companies to group items
presented within Other Comprehensive Income based on whether they may
be subsequently reclassified to profit or loss. This amendment to IAS
1 is effective for annual periods beginning on or after July 1, 2012
with full retrospective application. Early adoption is permitted.
Bellatrix intends to adopt the amendments in its financial statements
for the annual period beginning on January 1, 2013. The extent of the
impact of the amendments on the financial statements has not yet been
determined.
6. EXPLORATION AND EVALUATION ASSETS
|
($000s)
|
|
|
|
|
|
|
|
Cost
|
|
|
|
Balance, December 31, 2010
|
$
|
18,535
|
|
Additions
|
|
16,839
|
|
Transfer to oil and natural gas properties
|
|
(1,817)
|
|
Disposals (1)
|
|
(468)
|
|
Balance, December 31, 2011
|
|
33,089
|
|
Additions
|
|
17,118
|
|
Transfer to oil and natural gas properties
|
|
(10,301)
|
|
Disposals (1)
|
|
(1,729)
|
|
Balance, December 31, 2012
|
$
|
38,177
|
(1) Disposals include swaps.
7. PROPERTY, PLANT AND EQUIPMENT
|
($000s)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
natural gas
properties
|
|
Office
furniture and
equipment
|
|
Total
|
|
Cost
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
$
|
484,600
|
|
$
|
2,236
|
|
$
|
486,836
|
|
Additions
|
|
|
173,595
|
|
|
267
|
|
|
173,862
|
|
Transfer from exploration and evaluation assets
|
|
|
1,817
|
|
|
-
|
|
|
1,817
|
|
Disposals (1)
|
|
|
(2,697)
|
|
|
-
|
|
|
(2,697)
|
|
Balance, December 31, 2011
|
|
|
657,315
|
|
|
2,503
|
|
|
659,818
|
|
Additions
|
|
|
194,442
|
|
|
299
|
|
|
194,741
|
|
Transfer from exploration and evaluation assets
|
|
|
10,301
|
|
|
-
|
|
|
10,301
|
|
Disposals (1)
|
|
|
(10,950)
|
|
|
-
|
|
|
(10,950)
|
|
Balance, December 31, 2012
|
|
$
|
851,108
|
|
$
|
2,802
|
|
$
|
853,910
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Depletion, Depreciation and Impairment losses
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
$
|
86,482
|
|
$
|
774
|
|
$
|
87,256
|
|
Charge for time period
|
|
|
63,085
|
|
|
299
|
|
|
63,384
|
|
Impairment loss
|
|
|
28,039
|
|
|
194
|
|
|
28,233
|
|
Impairment reversal
|
|
|
(2,664)
|
|
|
-
|
|
|
(2,664)
|
|
Disposals (1)
|
|
|
(692)
|
|
|
-
|
|
|
(692)
|
|
Balance, December 31, 2011
|
|
$
|
174,250
|
|
$
|
1,267
|
|
$
|
175,517
|
|
Charge for time period
|
|
|
75,466
|
|
|
254
|
|
|
75,720
|
|
Impairment loss
|
|
|
14,760
|
|
|
60
|
|
|
14,820
|
|
Disposals (1)
|
|
|
(1,906)
|
|
|
-
|
|
|
(1,906)
|
|
Balance, December 31, 2012
|
|
$
|
262,570
|
|
$
|
1,581
|
|
$
|
264,151
|
|
(1) Disposals include swaps.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amounts
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2011
|
|
$
|
483,065
|
|
$
|
1,236
|
|
$
|
484,301
|
|
At December 31, 2012
|
|
$
|
588,538
|
|
$
|
1,221
|
|
$
|
589,759
|
Bellatrix has included $524.6 million (2011: $376.8 million) for future
development costs and excluded $37.2 million (2011: $35.1 million) for
estimated salvage from the depletion calculation for the three months
ended December 31, 2012.
For the year ended December 31, 2012, the Company capitalized $4.3
million (2011: $3.6 million) of general and administrative expenses and
$1.6 million (2011: $1.4 million) of share-based compensation expense
directly related to exploration and development activities.
Bellatrix's credit facilities are secured against all of the assets of
the Corporation by a $400 million debenture containing a first ranking
floating charge and security interest. The Corporation has provided a
negative pledge and undertaking to provide fixed charges over major
petroleum and natural gas reserves in certain circumstances.
Property Acquisition
Effective November 1, 2012, Bellatrix acquired production and working
interest in certain facilities, as well as undeveloped land in the
Willesden Green area of Alberta for a cash purchase price of $20.9
million after adjustments. In accordance with IFRS, a property
acquisition is accounted for as a business combination when certain
criteria are met, such as the acquisition of inputs and processes to
convert those inputs into beneficial outputs. Bellatrix assessed the
property acquisition and determined that it constitutes a business
combination under IFRS. In a business combination, acquired assets
and liabilities are recognized by the acquirer at their fair market
value at the time of purchase. Any variance between the determined
fair value of the assets and liabilities and the purchase price is
recognized as either a gain or loss in the statement of comprehensive
income in the period of acquisition.
The estimated fair value of the property, plant and equipment acquired
was determined using both internal estimates and an independent reserve
evaluation. The decommissioning liabilities assumed were determined
using the timing and estimated costs associated with the abandonment,
restoration and reclamation of the wells and facilities acquired. A
summary of the acquired property is provided below:
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
Estimated fair value of acquisition:
|
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
|
29,530
|
|
|
Exploration and evaluation assets
|
|
|
|
8,525
|
|
|
Decommissioning liabilities
|
|
|
|
(973)
|
|
|
|
|
|
37,082
|
|
|
|
|
|
|
|
Cash consideration
|
|
|
|
20,922
|
|
|
|
|
|
|
|
Gain on property acquisition
|
|
|
|
16,160
|
Included in the Company's deferred tax expense for the year was a $4.0
million expense relating to the gain recognized on the property
acquisition. If the acquisition had been effective January 1, 2012,
the Company would have realized an estimated additional $5.6 million
(unaudited) of production revenue and an estimated additional $2.1
million (unaudited) of profit before tax. Between the acquisition date
and December 31, 2012, approximately $0.6 million of production revenue
and $0.1 million of profit before tax was recognized relating to the
acquired properties.
Impairment
Bellatrix assesses the recoverability of the carrying values of its oil
and natural gas properties on a CGU basis. The composition of each CGU
is determined based on factors such as common processing facilities,
sales points, and commonalities in the geological and geophysical
structure of individual areas.
In accordance with IFRS, the recoverability of a CGU's carrying value is
determined by calculating and using the greater of its Value in Use
("VIU") or Fair Value Less Costs to Sell ("FVLCS"). VIU is determined
by estimating the present value of the future net cash flows expected
to be derived from the continued use of the assets in the CGU. FVLCS
is determined to be the amount for which the assets in the CGU could be
sold in an arm's length transaction. FVLCS is calculated for each CGU
based on independently available data on recent industry acquisition
transactions ("transaction metrics") applicable to the CGU based on
similarities in assets involved in the transactions. These transaction
metrics are determined as a dollar-value per boe for proved plus
probable reserves. The per-boe value for each CGU is applied to the
estimated boe proved plus probable reserves remaining in that CGU as
determined at least annually by independent reserve engineers. The
recoverable amount is compared to the carrying value of that CGU in
order to determine if impairment exists. Impairment is recognized as an
expense included in the Company's consolidated statement of
comprehensive income in the period in which it occurs.
A 1% increase to the discount rates applied in 2012 year-end impairment
calculations would result in an increase in impairment expense of $0.8
million. Identical decreases would result from a 1% decrease to the
discount rates applied.
2012 Impairment
Bellatrix engaged an external reserve evaluator to prepare an updated
company reserve report effective December 31, 2012. Overall corporate
proved and probable reserve volumes increased significantly at December
31, 2012 compared to evaluated reserves at December 31, 2011. However,
the fair values of two largely natural gas-weighted CGUs and one CGU
with significant natural gas and heavy oil weightings were reduced,
largely as a result of suppressed commodity prices.
As at December 31, 2012, Bellatrix performed an impairment test using
VIU values in accordance with IAS 36, resulting in an excess of the
carrying value of three CGUs over their recoverable amount, resulting
in a non-cash $14.8 million impairment loss. In performing the test,
future cash flows at between a 10% and 20% discount rate were used for
the Company's largely gas weighted North East Alberta, South East
Alberta, and British Columbia CGUs. The Company's core West Central
Alberta CGU had no indicators of impairment. Discounted salvage values
and discounted future associated general and administrative costs were
also incorporated into the VIU calculation.
2011 Impairment
During the year ended December 31, 2011, Bellatrix performed an
impairment test in accordance with IAS 36 resulting in an excess of the
carrying value of three CGUs over their recoverable amount, resulting
in a non-cash $25.6 million impairment loss.
IAS 36 requires impairment losses to be reversed when there has been a
subsequent increase in the recoverable amount. In the case of an
impairment loss reversal, the carrying amount of the asset or CGU is
limited to the original carrying amount less depreciation, depletion
and amortization as if no impairment had been recognized for the asset
or CGU for prior periods. In 2011, a partial reversal of impairment
was recognized relating to a previous impairment for the Company`s
South East Alberta CGU. As a result of the reversal, impairment
expense for the 2011 year was reduced by $2.7 million.
8. LONG-TERM DEBT
|
($000s)
|
|
|
|
|
2012
|
|
|
2011
|
|
Operating facility
|
|
|
|
$
|
4,047
|
|
$
|
5,701
|
|
Revolving term facility
|
|
|
|
|
129,000
|
|
|
51,000
|
|
Balance, end of year
|
|
|
|
$
|
133,047
|
|
$
|
56,701
|
Effective December 13, 2012, the Company's borrowing base was increased
from $200 million to $220 million through to the next scheduled
borrowing base determination to be completed on or before May 31,
2013. Effective May 31, 2012, the revolving period of the credit
facility was extended from June 26, 2012 to June 25, 2013. As of
December 31, 2012, the Company's credit facilities consist of a $25
million demand operating facility provided by a Canadian bank and a
$195 million extendible revolving term credit facility provided by two
Canadian banks and a Canadian financial institution. Amounts borrowed
under the credit facility will bear interest at a floating rate based
on the applicable Canadian prime rate, U.S. base rate, LIBOR margin
rate, or the bankers' acceptance stamping fee, plus between 1.00% and
3.50%, depending on the type of borrowing and the Company's debt to
cash flow ratio. The credit facilities are secured by a $400 million
debenture containing a first ranking charge and security interest.
Bellatrix has provided a negative pledge and undertaking to provide
fixed charges over its properties in certain circumstances. A standby
fee is charged of between 0.50% and 0.875% on the undrawn portion of
the credit facilities, depending on the Company's debt to cash flow
ratio.
The revolving period for the revolving term credit facility will end on
June 25, 2013, unless extended for a further 364 day period. Should
the facility not be extended it will convert to a non-revolving term
facility with the full amount outstanding due 366 days after the last
day of the revolving period of June 25, 2013. The borrowing base will
be subject to re-determination on May 31 and November 30 in each year
prior to maturity, with the next semi-annual redetermination occurring
on May 31, 2013.
Principal payment will not be required under the revolving term facility
for more than 365 days from December 31, 2012 and as there is
sufficient availability under the revolving term credit facility to
cover the operating facility, the entire amounts owing on the credit
facilities have been classified as long-term.
Pursuant to Bellatrix's credit facilities, the Company is permitted to
pay the semi-annual interest payments on the debentures, and payments
by the Company to debenture holders in relation to the redemption of
debentures and in relation to debenture normal course issuer bids
approved by the Toronto Stock Exchange (the "TSX"), provided that the
aggregate of all such normal course issuer bids and redemptions do not
exceed $10.0 million in any fiscal year.
As at December 31, 2012, the Company had outstanding letters of credit
totaling $0.6 million that reduce the amount otherwise available to be
drawn on the syndicated facility.
As at December 31, 2012, the Company had approximately $87.0 million, or
40% of unused and available bank credit under its credit facilities.
Bellatrix was fully compliant with all of its operating debt covenants.
9. CONVERTIBLE DEBENTURES
The following table sets forth a reconciliation of the convertible
debentures:
|
Convertible debentures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($000s except number of debentures)
|
|
|
|
|
4.75%
|
|
Number of Debentures
|
|
|
|
|
|
|
Balance, December 31, 2011 and 2012
|
|
|
|
|
55,000
|
|
Debt Component
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
|
$
|
47,599
|
|
Accretion
|
|
|
|
|
1,477
|
|
Balance, December 31, 2011
|
|
|
|
$
|
49,076
|
|
Accretion
|
|
|
|
|
1,611
|
|
Balance, December 31, 2012
|
|
|
|
$
|
50,687
|
|
|
|
|
|
|
|
|
Equity Component
|
|
|
|
|
|
|
Balance, December 31, 2011 and 2012
|
|
|
|
$
|
4,378
|
On April 20, 2010, Bellatrix issued $55 million of 4.75% convertible
unsecured subordinated debentures (the "4.75% Debentures") on a bought
deal basis. The 4.75% Debentures have a face value of $1,000 each,
bear interest at the rate of 4.75% per annum payable semi-annually in
arrears on the last day of April and October of each year commencing on
October 31, 2010 and mature on April 30, 2015 (the "Maturity Date").
The 4.75% Debentures are convertible at the holder's option and at any
time prior to the close of business on the earlier of the close of
business on the business day immediately preceding the Maturity Date
and the date specified by the Corporation for redemption of the 4.75%
Debentures into common shares of the Corporation at a conversion price
of $5.60 per common share (the "Conversion Price"), subject to
adjustment in certain events. The 4.75% Debentures are not redeemable
by the Corporation before April 30, 2013. On and after April 30, 2013
and prior to April 30, 2014, the 4.75% Debentures are redeemable at the
Corporation's option, in whole or in part, at par plus accrued and
unpaid interest if the weighted average trading price of the common
shares for the specified period is not less than 125% of the Conversion
Price. On and after April 30, 2014, the 4.75% Debentures are redeemable
at the Corporation's option, in whole or in part, at any time at par
plus accrued and unpaid interest. The 4.75% Debentures are listed and
posted for trading on the TSX under the symbol "BXE.DB.A".
As the 4.75% Debentures are convertible into common shares, the
liability and equity components are presented separately. The initial
carrying amount of the financial liability is determined by discounting
the stream of future payments of interest and principal and has been
determined to be $48.8 million. A total of $2.2 million of issue costs
has been allocated to the liability component of the debentures. Using
the residual method, the carrying amount of the conversion feature is
the difference between the principal amount and the carrying value of
the financial liability. Within the Shareholder's Equity section of
the consolidated financial statements, $4.4 million has been recorded
as the carrying amount of the conversion feature of the debentures, net
of $0.3 million of issue costs and $1.5 million of deferred taxes. The
4.75% Debentures, net of the equity component and issue costs is
accreted using the effective interest rate method over the term of the
4.75% Debentures such that the carrying amount of the financial
liability will equal the principal balance at maturity.
10. FINANCE LEASE OBLIGATION
The Company entered into separate agreements in December 2012, 2011, and
2010 to raise $10 million, $3.7 million, and $1.6 million,
respectively, for the Company's proportionate share of the construction
of certain facilities in each of the years.
The agreements resulted in the recognition of finance leases in 2012,
2011, and 2010 for the use of the constructed facilities. The
agreements will expire in years 2030 to 2032, respectively, or earlier
if certain circumstances are met. At the end of the term of each
agreement, the ownership of the facilities is transferred to the
Company. Assets under these finance leases at December 31, 2012 totaled
$15.3 million (2011: $5.3 million) with accumulated depreciation of
$1.4 million (2011: $0.4 million).
Multiple participants of the joint ventures were involved in the 2012,
2011, and 2010 agreements. Although the majority of participants were
fully external to the Company, some related parties were involved in
the 2011 and 2010 agreements. See note 18.
The following is a schedule of future minimum lease payments under the
finance lease obligations:
|
|
|
|
|
|
Year ending December 31,
|
|
|
($000s)
|
|
2013
|
|
$
|
3,552
|
|
2014
|
|
|
3,399
|
|
2015
|
|
|
3,244
|
|
2016
|
|
|
3,059
|
|
2017
|
|
|
2,719
|
|
Thereafter
|
|
|
13,472
|
|
Total lease payments
|
|
|
29,445
|
|
Amount representing implicit interest at 15.28%
|
|
|
(14,889)
|
|
|
|
|
14,556
|
|
Current portion of finance lease obligation
|
|
|
(1,425)
|
|
Finance lease obligation
|
|
$
|
13,131
|
11. DECOMMISSIONING LIABILITIES
The Company's decommissioning liabilities result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Company estimates the
total undiscounted amount of cash flows required to settle its
decommissioning liabilities is approximately $51 million which will be
incurred between 2013 and 2053. A risk-free rate between 1.14% - 2.36%
(2011: 0.95% - 2.49%) and an inflation rate of 2.4% (2011: 2.4%) were
used to calculate the fair value of the decommissioning liabilities as
at December 31, 2012.
|
|
|
|
|
|
|
|
|
($000s)
|
|
|
2012
|
|
|
2011
|
|
Balance, beginning of year
|
|
$
|
45,091
|
|
$
|
38,710
|
|
Incurred on development activities
|
|
|
1,400
|
|
|
1,694
|
|
Acquired through business combinations
|
|
|
973
|
|
|
-
|
|
Revisions on estimates
|
|
|
(648)
|
|
|
4,703
|
|
Reversed on dispositions
|
|
|
(2,955)
|
|
|
(326)
|
|
Settled during the year
|
|
|
(635)
|
|
|
(569)
|
|
Accretion expense
|
|
|
683
|
|
|
879
|
|
Balance, end of year
|
|
$
|
43,909
|
|
$
|
45,091
|
12. SHAREHOLDERS' CAPITAL
Bellatrix is authorized to issue an unlimited number of common shares.
All shares issued are fully paid and have no par value. The common
shareholders are entitled to dividends declared by the Board of
Directors; Bellatrix does not anticipate paying dividends.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
|
|
Number
|
|
|
Amount
($000s)
|
|
Number
|
|
|
Amount
($000s)
|
|
Common shares, opening balance
|
|
107,407,241
|
|
$
|
370,048
|
|
97,446,026
|
|
$
|
316,779
|
Shares issued for cash, net of transaction costs and
tax effect of $0.8 million in 2011
|
|
-
|
|
|
-
|
|
9,822,000
|
|
|
52,734
|
|
Shares issued on exercise of options
|
|
461,533
|
|
|
1,093
|
|
139,215
|
|
|
381
|
Contributed surplus transferred on
exercised options
|
|
-
|
|
|
435
|
|
-
|
|
|
154
|
|
Balance, end of year
|
|
107,868,774
|
|
$
|
371,576
|
|
107,407,241
|
|
$
|
370,048
|
13. SHARE-BASED COMPENSATION PLANS
a. Share Option Plan
Bellatrix has a share option plan where the Company may grant share
options to its directors, officers, employees and service providers.
Under this plan, the exercise price of each share option is not less
than the volume weighted average trading price of the Company's share
price for the five trading days immediately preceding the date of
grant. The maximum term of an option grant is five years. Option
grants are non-transferable or assignable except in accordance with the
share option plan and the holding of share options shall not entitle a
holder to any rights as a shareholder of Bellatrix. Share options,
entitling the holder to purchase common shares of the Company, have
been granted to directors, officers, employees and service providers of
Bellatrix. One third of the initial grant of share options normally
vests on each of the first, second, and third anniversary from the date
of grant.
During the year ended December 31, 2012, Bellatrix granted 2,648,000
(2011: 2,544,000) share options. During the year ended December 31,
2012, the Company recorded share-based compensation of $3.8 million
(2011: $3.5 million) related to its outstanding share options, net of
forfeitures of $0.2 million (2011: $0.1 million), of which $1.6 million
(2011: $1.4 million) was capitalized to property, plant and equipment.
In addition, $1.0 million (2011: $0.8 million) (note 13 b.) was
expensed in relation to the Director's Deferred Share Unit Plan,
resulting in total net share-based compensation of $3.2 million
recognized as an expense for the 2012 year (2011: $2.9 million).
The fair values of all share options granted are estimated on the date
of grant using the Black-Scholes option-pricing model. The weighted
average fair market value of share options granted during the years
ended December 31, 2012 and 2011, and the weighted average assumptions
used in their determination are as noted below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
|
|
|
|
Inputs:
|
|
|
|
|
|
|
|
|
|
|
Share price
|
|
3.60
|
|
|
5.21
|
|
|
|
|
|
Exercise price
|
|
3.60
|
|
|
5.21
|
|
|
|
|
|
Risk free interest rate (%)
|
|
1.1
|
|
|
1.8
|
|
|
|
|
|
Option life (years)
|
|
2.8
|
|
|
3.6
|
|
|
|
|
|
Option volatility (%)
|
|
53
|
|
|
65
|
|
|
|
|
|
Results:
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of each share option granted
|
|
1.28
|
|
|
2.48
|
Bellatrix calculates volatility based on historical share price.
Bellatrix incorporates an estimated forfeiture rate between 3% and 10%
(2011: 3% to 10%) for stock options that will not vest, and adjusts for
actual forfeitures as they occur.
The weighted average TSX share trading price for the year ended December
31, 2012 was $4.31 (2011: $5.01).
The following tables summarize information regarding Bellatrix's Share
Option Plan:
|
Share Options Continuity
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
Exercise Price
|
|
|
Number
|
|
Balance, December 31, 2010
|
|
$
|
2.69
|
|
|
5,823,377
|
|
Granted
|
|
$
|
5.21
|
|
|
2,544,000
|
|
Exercised
|
|
$
|
2.74
|
|
|
(139,215)
|
|
Forfeited and cancelled
|
|
$
|
4.37
|
|
|
(242,842)
|
|
Balance, December 31, 2011
|
|
$
|
3.44
|
|
|
7,985,320
|
|
Granted
|
|
$
|
3.61
|
|
|
2,648,000
|
|
Exercised
|
|
$
|
2.37
|
|
|
(461,533)
|
|
Forfeited and cancelled
|
|
$
|
4.50
|
|
|
(751,336)
|
|
Balance, December 31, 2012
|
|
$
|
3.46
|
|
|
9,420,451
|
As of December 31, 2012, a total of 10,739,129 share options were
reserved, leaving an additional 1,318,678 available for future grants.
|
Share Options Outstanding, December 31, 2012
|
|
|
|
|
|
Outstanding
|
|
|
|
Exercisable
|
|
Exercise Price
|
|
At
December, 2012
|
|
Weighted
Average
Exercise Price
|
|
Weighted
Average
Remaining
Contractual Life
|
|
At
December 31, 2012
|
|
Exercise Price
|
|
$ 0.65 - $ 1.45
|
|
682,949
|
|
|
$
|
1.02
|
|
1.3
|
|
682,949
|
|
|
$
|
1.02
|
|
$ 1.46 - $ 1.99
|
|
1,177,449
|
|
|
$
|
1.65
|
|
1.2
|
|
1,177,449
|
|
|
$
|
1.65
|
|
$ 2.00 - $ 3.36
|
|
1,407,052
|
|
|
$
|
2.41
|
|
2.2
|
|
973,718
|
|
|
$
|
2.08
|
|
$ 3.37 - $ 3.84
|
|
1,575,000
|
|
|
$
|
3.42
|
|
4.3
|
|
84,665
|
|
|
$
|
3.70
|
|
$ 3.85 - $ 4.72
|
|
2,271,001
|
|
|
$
|
3.95
|
|
2.8
|
|
1,172,313
|
|
|
$
|
3.90
|
|
$ 4.73 - $ 5.50
|
|
2,307,000
|
|
|
$
|
5.28
|
|
3.5
|
|
723,975
|
|
|
$
|
5.26
|
|
$ 0.65 - $ 5.50
|
|
9,420,451
|
|
|
$
|
3.46
|
|
2.8
|
|
4,815,069
|
|
|
$
|
2.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share Options Outstanding, December 31, 2011
|
|
|
|
|
|
Outstanding
|
|
|
|
Exercisable
|
|
Exercise Price
|
|
At
December, 2011
|
|
Weighted
Average
Exercise Price
|
|
Weighted
Average
Remaining
Contractual Life
|
|
At
December 31, 2011
|
|
Exercise Price
|
|
$ 0.65 - $ 1.45
|
|
758,028
|
|
|
$
|
1.01
|
|
2.4
|
|
483,628
|
|
|
$
|
1.02
|
|
$ 1.46 - $ 1.99
|
|
1,244,115
|
|
|
$
|
1.66
|
|
2.3
|
|
914,105
|
|
|
$
|
1.66
|
|
$ 2.00 - $ 3.36
|
|
1,273,676
|
|
|
$
|
2.15
|
|
2.0
|
|
964,805
|
|
|
$
|
2.19
|
|
$ 3.37 - $ 3.84
|
|
171,000
|
|
|
$
|
3.66
|
|
4.1
|
|
38,333
|
|
|
$
|
3.75
|
|
$ 3.85 - $ 4.72
|
|
1,921,001
|
|
|
$
|
3.93
|
|
3.1
|
|
685,646
|
|
|
$
|
3.98
|
|
$ 4.73 - $ 5.57
|
|
2,617,500
|
|
|
$
|
5.25
|
|
4.0
|
|
287,833
|
|
|
$
|
5.11
|
|
$ 0.65 - $ 5.57
|
|
7,985,320
|
|
|
$
|
3.44
|
|
3.1
|
|
3,374,350
|
|
|
$
|
2.51
|
b. Deferred Share Unit Plan
On May 11, 2011, the Board of Directors of Bellatrix approved a
Directors' Deferred Share Unit Plan ("the Plan") where the Company may
grant to non-employee directors Deferred Share Units ("DSUs"), each DSU
being a right to receive, on a deferred payment basis, a cash payment
equivalent to the volume weighted average trading price of the
Company's common shares for the five trading days immediately preceding
the redemption date of such DSU. Participants of the Plan may also
elect to receive their annual remuneration in the form of DSUs.
Subject to TSX and shareholder approval, Bellatrix may elect to deliver
common shares from treasury in satisfaction in whole or in part of any
payment to be made upon the redemption of the DSUs. The DSUs vest
immediately and must be redeemed by December 1st of the calendar year immediately following the year in which the
participant ceases to hold all positions with Bellatrix or earlier if
the participant elects to have the DSUs redeemed at an earlier date
(provided that the DSUs may not be redeemed prior to the date that the
participant ceases to hold all positions with Bellatrix). On a go
forward basis, it is intended that in the event of a share based award,
non-employee directors would receive DSU grants instead of share option
grants.
During the year ended December 31, 2012, the Company granted 249,298
(2011: 159,226) DSUs and had 408,524 DSUs outstanding as at December
31, 2012 (2011: 159,226). For the year ended December 31, 2012,
Bellatrix recorded approximately $1.0 million (2011: $0.8 million) of
share based compensation expense and had a liability balance of $1.7
million (2011: $0.8 million) relating to the Company's outstanding
DSUs.
14. SUPPLEMENTAL CASH FLOW INFORMATION
|
Change in Non-cash Working Capital
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
|
2012
|
|
|
2011
|
|
Changes in non-cash working capital items:
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
$
|
4,530
|
|
|
$
|
(5,822)
|
|
|
Deposits and prepaid expenses
|
|
|
|
(510)
|
|
|
|
993
|
|
|
Accounts payable and accrued liabilities
|
|
|
|
(12,614)
|
|
|
|
18,865
|
|
|
|
|
|
$
|
(8,594)
|
|
|
$
|
14,036
|
|
Changes related to:
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
$
|
(1,075)
|
|
|
$
|
4,524
|
|
|
Financing activities
|
|
|
|
(55)
|
|
|
|
136
|
|
|
Investing activities
|
|
|
|
(7,464)
|
|
|
|
9,376
|
|
|
|
|
$
|
(8,594)
|
|
|
$
|
14,036
|
15. INCOME TAXES
Bellatrix is a corporation as defined under the Income Tax Act (Canada)
and is subject to Canadian federal and provincial taxes. Bellatrix is
subject to provincial taxes in Alberta, British Columbia and
Saskatchewan as the Company operates in those jurisdictions.
Deferred taxes reflect the tax effects of differences between the
carrying amounts of assets and liabilities for financial reporting
purposes and the amounts reported for tax purposes. As at December 31,
2012, Bellatrix had approximately $584 million in tax pools available
for deduction against future income. Included in this tax basis are
estimated non-capital loss carry forwards of approximately $10 million
that expire in years through 2027.
The provision for income taxes differs from the expected amount
calculated by applying the combined Federal and Provincial corporate
income tax rate of 25.0% (2011: 26.5%) to loss before taxes. This
difference results from the following items:
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
|
2011
|
|
Expected income tax expense (recovery)
|
|
$
|
9,459
|
|
|
$
|
(1,373)
|
|
Share based compensation expense
|
|
|
564
|
|
|
|
576
|
|
Change in tax rates
|
|
|
-
|
|
|
|
(6)
|
|
Flow through shares
|
|
|
-
|
|
|
|
1,537
|
|
Other
|
|
|
44
|
|
|
|
34
|
|
Deferred tax expense (recovery)
|
|
$
|
10,067
|
|
|
$
|
768
|
The statutory tax rate decreased to 25.0% in 2012 from 26.5% in 2011 as
a result of tax legislation enacted in 2007.
The components of the net deferred tax asset at December 31 are as
follows:
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
|
2011
|
|
Deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
|
Equity component of 4.75% Debentures
|
|
$
|
(799)
|
|
|
$
|
(1,078)
|
|
|
Property, plant and equipment and exploration and evaluation assets
|
|
|
(17,737)
|
|
|
|
(8,126)
|
|
|
Commodity contract asset
|
|
|
(43)
|
|
|
|
-
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
|
Finance lease obligation
|
|
|
3,639
|
|
|
|
1,279
|
|
|
Property, plant and equipment and exploration and evaluation assets
|
|
|
-
|
|
|
|
-
|
|
|
Commodity contract liability
|
|
|
-
|
|
|
|
2,658
|
|
|
Decommissioning liabilities
|
|
|
10,977
|
|
|
|
11,273
|
|
|
Share issue costs
|
|
|
834
|
|
|
|
1,174
|
|
|
Non-capital losses
|
|
|
2,500
|
|
|
|
2,500
|
|
|
Attributed Canadian Royalty Income
|
|
|
1,209
|
|
|
|
1,209
|
|
|
Other
|
|
|
458
|
|
|
|
216
|
|
Deferred income tax asset
|
|
$
|
1,038
|
|
|
$
|
11,105
|
The Company has recognized a net deferred tax asset based on the
independently evaluated reserve report as cash flows are expected to be
sufficient to realize the deferred tax asset.
A continuity of the net deferred income tax asset (liability) for 2012
and 2011 is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Movement of temporary differences during the year
|
|
($000s)
|
|
Balance,
Jan. 1, 2012
|
|
Recognized in
profit or loss
|
|
Recognized
in equity
|
|
Flow
through
shares
|
|
Balance,
Dec. 31, 2012
|
Property, plant and equipment and
exploration and evaluation assets
|
|
$
|
(8,126)
|
|
$
|
(9,611)
|
|
$
|
-
|
|
$
|
-
|
|
$
|
(17,737)
|
|
Decommissioning liabilities
|
|
|
11,273
|
|
|
(296)
|
|
|
-
|
|
|
-
|
|
|
10,977
|
|
Commodity contract liability
|
|
|
2,658
|
|
|
(2,701)
|
|
|
-
|
|
|
-
|
|
|
(43)
|
|
Share issue costs
|
|
|
1,174
|
|
|
(340)
|
|
|
-
|
|
|
-
|
|
|
834
|
|
Non-capital losses
|
|
|
2,500
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2,500
|
Equity component of 4.75%
debentures
|
|
|
(1,078)
|
|
|
279
|
|
|
-
|
|
|
-
|
|
|
(799)
|
|
Finance lease obligation
|
|
|
1,279
|
|
|
2,360
|
|
|
-
|
|
|
-
|
|
|
3,639
|
|
Attributed Canadian Royalty Income
|
|
|
1,209
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1,209
|
|
Other
|
|
|
216
|
|
|
242
|
|
|
-
|
|
|
-
|
|
|
458
|
|
|
|
$
|
11,105
|
|
$
|
(10,067)
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
Balance,
Jan. 1, 2011
|
|
Recognized in
profit or loss
|
|
Recognized
in equity
|
|
Flow
through
shares
|
|
Balance,
Dec. 31, 2011
|
Property, plant and equipment and
exploration and evaluation assets
|
|
$
|
2,991
|
|
$
|
(7,349)
|
|
$
|
-
|
|
$
|
(3,768)
|
|
$
|
(8,126)
|
|
Decommissioning liabilities
|
|
|
9,729
|
|
|
1,544
|
|
|
-
|
|
|
-
|
|
|
11,273
|
|
Commodity contract liability
|
|
|
989
|
|
|
1,669
|
|
|
-
|
|
|
-
|
|
|
2,658
|
|
Share issue costs
|
|
|
752
|
|
|
(399)
|
|
|
821
|
|
|
-
|
|
|
1,174
|
|
Non-capital losses
|
|
|
79
|
|
|
2,421
|
|
|
-
|
|
|
-
|
|
|
2,500
|
Equity component of 4.75%
debentures
|
|
|
(1,354)
|
|
|
276
|
|
|
-
|
|
|
-
|
|
|
(1,078)
|
|
Finance lease obligation
|
|
|
399
|
|
|
880
|
|
|
-
|
|
|
-
|
|
|
1,279
|
|
Attributed Canadian Royalty Income
|
|
|
1,209
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1,209
|
|
Other
|
|
|
26
|
|
|
190
|
|
|
-
|
|
|
-
|
|
|
216
|
|
|
|
$
|
14,820
|
|
$
|
(768)
|
|
$
|
821
|
|
$
|
(3,768)
|
|
$
|
11,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16. FINANCE INCOME AND EXPENSES
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
|
2011
|
|
Finance expense
|
|
|
|
|
|
|
|
|
|
Interest on long-term debt
|
|
$
|
5,603
|
|
|
$
|
2,952
|
|
|
Interest on convertible debentures
|
|
|
2,620
|
|
|
|
2,612
|
|
|
|
|
|
|
|
|
|
|
|
Accretion on convertible debentures
|
|
|
1,611
|
|
|
|
1,477
|
|
|
Accretion on decommissioning liabilities
|
|
|
683
|
|
|
|
879
|
|
|
|
|
2,294
|
|
|
|
2,356
|
|
Finance expense
|
|
$
|
10,517
|
|
|
$
|
7,920
|
17. CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME PRESENTATION
A mixed presentation of nature and function was used for the Company`s
presentation of operating expenses in the consolidated statement of
comprehensive income for the current and comparative years. General and
administrative expenses are presented by their function. Other
expenses, including production, transportation, depletion and
dispositions are presented by their nature. Such presentation is in
accordance with industry practice.
Total employee compensation costs included in total production and
general administrative expenses in the consolidated statements of
comprehensive income are detailed in the following table:
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
|
2011
|
|
|
Production
|
|
|
885
|
|
|
|
818
|
|
|
General and administrative (1)
|
|
|
8,292
|
|
|
|
6,497
|
|
Employee compensation
|
|
$
|
9,177
|
|
|
$
|
7,315
|
(1) Amount shown is net of capitalization
18. RELATED PARTY TRANSACTIONS
a. Finance lease agreements
Previous to 2012, the Company entered into agreements to obtain
financing in the amount of $5.3 million for the construction of certain
facilities.
Members of the Company's management team and entities affiliated with
them provided financing of $900,000. The terms of the transactions with
those related parties were the same as those with arms-length
participants.
b. Key Management Compensation
Key management includes senior officers and directors (executive and
non-executive) of the Company. The compensation paid or payable to key
management for employee services is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($000s)
|
|
2012
|
|
|
2011
|
|
Salaries and other short-term employee benefits
|
|
$
|
4,611
|
|
|
$
|
3,960
|
|
Long-term incentive compensation
|
|
|
77
|
|
|
|
59
|
|
Share-based compensation (1)
|
|
|
2,942
|
|
|
|
2,506
|
|
|
|
$
|
7,630
|
|
|
$
|
6,525
|
|
(1)
|
Share-based compensation include share options and DSUs.
|
19. PER SHARE AMOUNTS
The calculation of basic earnings per share for the year ended December
31, 2012 was based on a net profit of $27.8 million (2011: net loss of
$5.9 million).
|
|
|
|
2012
|
|
|
2011
|
|
Basic common shares outstanding
|
|
|
107,868,774
|
|
|
107,407,241
|
|
Dilutive effect of:
|
|
|
|
|
|
|
|
|
Share options outstanding
|
|
|
9,420,451
|
|
|
7,985,320
|
|
|
Shares issuable for convertible debentures
|
|
|
9,821,429
|
|
|
9,821,429
|
|
Diluted common shares outstanding
|
|
|
127,110,654
|
|
|
125,213,990
|
|
Weighted average shares outstanding
|
|
|
107,543,811
|
|
|
103,857,689
|
|
Dilutive effect of share options and convertible debentures (1)
|
|
|
1,581,283
|
|
|
-
|
|
Diluted weighted average shares outstanding
|
|
|
109,125,094
|
|
|
103,857,689
|
|
(1)
|
For the year ended December 31, 2012, a total of 7,839,168 (2011:
7,985,320) share options and 9,821,429 (2011: 9,821,429) common shares
issuable pursuant to the conversion of the 4.75% Debentures were
excluded from the calculation as they were not dilutive.
|
20. COMMITMENTS
The Company is committed to payments under fixed term operating leases
which do not currently provide for early termination. The Company's
commitment for office space as at December 31, 2012 is as follows:
|
|
|
|
|
|
|
|
|
|
($000s)
Year
|
Gross
Amount
|
Recoveries
|
Net amount
|
|
|
2013
|
$
|
2,254
|
$
|
947
|
$
|
1,307
|
|
|
2014
|
|
1,520
|
|
641
|
|
879
|
Subsequent to year end, Bellatrix entered into a fixed term operating
lease agreement for corporate office space in a new location,
commencing September 1, 2013. Bellatrix is currently pursuing
subleasing options for the remaining term of its existing corporate
office space. A summary of the Company's commitment for the new office
space is as follows:
|
|
|
|
|
|
|
|
($000s)
|
|
|
|
Year
|
|
|
Total amount
|
|
|
2013
|
|
|
$
|
388
|
|
|
2014
|
|
|
|
2,153
|
|
|
2015
|
|
|
|
2,243
|
|
|
2016
|
|
|
|
2,243
|
|
|
2017
|
|
|
|
2,243
|
|
|
More than 5 years
|
|
|
|
14,449
|
As at December 31, 2012, Bellatrix committed to drill 3 gross (1.7 net)
wells pursuant to farm-in agreements. Bellatrix expects to satisfy
these drilling commitments at an estimated cost of approximately $6.5
million.
In addition, Bellatrix entered into two joint venture agreements during
the 2011 year and an additional joint venture agreement during 2012.
The agreements include a minimum commitment for the Company to drill a
specified number of wells each year over the term of the individual
agreements. The details of these agreements are provided in the table
below:
|
|
|
|
|
|
|
|
|
|
|
|
Joint Venture Agreement
|
|
|
Feb. 1, 2011
|
|
|
Aug. 4, 2011
|
|
|
Dec. 14, 2012
|
|
Agreement Term
|
|
|
2011 to 2015
|
|
|
2011 to 2016
|
|
|
2014 to 2018
|
|
Minimum wells per year (gross and net)
|
|
|
3
|
|
|
5 to 10
|
|
|
2
|
|
Minimum total wells (gross and net)
|
|
|
15
|
|
|
40
|
|
|
10
|
|
Estimated total cost ($000s)
|
|
|
$52.5
|
|
|
$140.0
|
|
|
$35.0
|
|
Remaining wells to drill at December 31, 2012
|
|
|
8
|
|
|
32
|
|
|
10
|
|
Remaining estimated total cost ($000s)
|
|
|
$28.0
|
|
|
$112.0
|
|
|
$35.0
|
21. FINANCIAL RISK MANAGEMENT
a. Overview
The Company has exposure to the following risks from its use of
financial instruments:
-
Credit risk
-
Liquidity risk
-
Market risk
This note presents information about the Company's exposure to each of
the above risks, the Company's objectives, policies and processes for
measuring and managing risk, and the Company's management of capital.
Further quantitative disclosures are included throughout these
financial statements.
The Board of Directors has overall responsibility for the establishment
and oversight of the Company's risk management framework. The Board has
implemented and monitors compliance with risk management policies.
The Company's risk management policies are established to identify and
analyze the risks faced by the Company, to set appropriate risk limits
and controls, and to monitor risks and adherence to market conditions
and the Company's activities.
b. Credit risk
As at December 31, 2012, accounts receivable was comprised of the
following:
|
|
|
|
|
|
|
|
|
|
|
Aging ($000s)
|
|
Not past due
(less than 90 days)
|
|
|
Past due
(90 days or more)
|
|
|
Total
|
|
Joint venture and other trade accounts receivable
|
|
10,084
|
|
|
1,737
|
|
|
11,821
|
|
Amounts due from government agencies
|
|
188
|
|
|
729
|
|
|
917
|
|
Revenue and other accruals
|
|
21,688
|
|
|
4,677
|
|
|
26,365
|
|
Cash call receivables
|
|
-
|
|
|
65
|
|
|
65
|
|
Plant revenue allocation receivable
|
|
-
|
|
|
2,855
|
|
|
2,855
|
|
Less: Allowance for doubtful accounts
|
|
-
|
|
|
(1,231)
|
|
|
(1,231)
|
|
Total accounts receivable
|
|
31,960
|
|
|
8,832
|
|
|
40,792
|
|
Less:
|
|
|
|
|
|
|
|
|
|
Accounts payable due to same partners
|
|
-
|
|
|
(241)
|
|
|
(241)
|
|
Subsequent receipts to February 22, 2013
|
|
(24,190)
|
|
|
(506)
|
|
|
(24,696)
|
|
|
|
7,770
|
|
|
8,085
|
|
|
15,855
|
Amounts due from government agencies include GST and royalty
adjustments. Plant revenue allocation receivable includes amounts
under dispute over plant revenue allocations, net of expenses, from an
operator. The Company has commenced legal action for collection of
these amounts. Accounts payable due to same partners includes amounts
which may be available for offset against certain receivables.
Cash calls receivables consist of advances paid to joint interest
partners for capital projects.
The carrying amount of accounts receivable and derivative assets
represents the maximum credit exposure.
c. Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its
financial obligations as they become due. The Company's approach to
managing liquidity is to make reasonable efforts to sustain sufficient
liquidity to meet its liabilities when they become due, under both
normal and stressed conditions, without incurring unacceptable losses
or risking harm to the Company's reputation.
The Company prepares annual capital expenditure budgets which are
regularly monitored and updated as necessary. Further, the Company
utilizes authorizations for expenditures on both operated and
non-operated projects to further manage capital expenditures. To
facilitate the capital expenditure program, the Company has a revolving
reserve-based credit facility, as outlined in note 8, which is reviewed
at least annually by the lender. The Company attempts to match its
payment cycle with the collection of petroleum and natural gas revenues
on the 25th of each month. The Company also mitigates liquidity risk by maintaining
an insurance program to minimize exposure to insurable losses.
The following are the contractual maturities of liabilities as at
December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities ($000s)
|
|
|
Total
|
|
< 1 Year
|
|
1-3 Years
|
|
4-5 Years
|
|
More than
5 years
|
|
Accounts payable and accrued liabilities (1)
|
|
|
$
|
50,771
|
|
$
|
50,771
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
Long-term debt - principal (2)
|
|
|
|
133,047
|
|
|
-
|
|
|
133,047
|
|
|
-
|
|
|
-
|
|
Convertible debentures - principal
|
|
|
|
55,000
|
|
|
-
|
|
|
55,000
|
|
|
-
|
|
|
-
|
|
Convertible debentures - interest (3)
|
|
|
|
6,085
|
|
|
2,613
|
|
|
3,472
|
|
|
-
|
|
|
-
|
|
Commodity contract liability
|
|
|
|
7,345
|
|
|
1,131
|
|
|
6,214
|
|
|
-
|
|
|
-
|
|
Decommissioning liabilities (4)
|
|
|
|
43,909
|
|
|
-
|
|
|
7,187
|
|
|
5,796
|
|
|
30,926
|
|
Finance lease obligation
|
|
|
|
14,556
|
|
|
1,425
|
|
|
3,069
|
|
|
3,172
|
|
|
6,890
|
|
Total
|
|
|
$
|
310,713
|
|
$
|
55,940
|
|
$
|
207,989
|
|
$
|
8,968
|
|
$
|
37,816
|
|
(1)
|
Includes $0.4 million of accrued coupon interest payable in relation to
the 4.75% Debentures and $0.2 million of accrued interest payable in
relation to the credit facilities is included in Accounts Payable and
Accrued Liabilities.
|
|
(2)
|
Bank debt is based on a revolving term which is reviewed annually and
converts to a 366 day non-revolving facility if not renewed. Interest
due on the bank credit facility is calculated based upon floating
rates.
|
|
(3)
|
The 4.75% Debentures outstanding at December 31, 2012 bear interest at a
coupon rate of 4.75% per annum, which currently requires total annual
interest payments of $2.6 million.
|
|
(4)
|
Amounts represent the inflated, discounted future abandonment and
reclamation expenditures anticipated to be incurred over the life of
the Company's properties (between 2013 and 2053).
|
d. Market risk
Market risk is the risk that changes in market prices, such as foreign
exchange rates, commodity prices, and interest rates will affect the
Company's net profit or the value of financial instruments. The
objective of market risk management is to manage and control market
risk exposures within acceptable limits, while maximizing returns.
Foreign Currency Exchange Rate Risk
Foreign currency exchange rate risk is the risk that the fair value of
future cash flows will fluctuate as a result of changes in foreign
exchange rates. Although substantially all of the Company's petroleum
and natural gas sales are denominated in Canadian dollars, the
underlying market prices in Canada for petroleum and natural gas are
impacted by changes in the exchange rate between the Canadian and
United States dollar. As at December 31, 2012, if the Canadian/US
dollar exchange rate had decreased by US$0.01 with all other variables
held constant, after tax net profit for the year ended December 31,
2012 would have been approximately $0.8 million higher. An equal and
opposite impact would have occurred to net profit had the Canadian/US
dollar exchange rate increased by US$0.01.
The Company had no forward exchange rate contracts in place as at or
during the year ended December 31, 2012.
Commodity Price Risk
Commodity price risk is the risk that the fair value or future cash
flows will fluctuate as a result of changes in commodity prices.
Commodity prices for petroleum and natural gas are impacted by not only
the relationship between the Canadian and United States dollar, as
outlined above, but also world economic events that dictate the levels
of supply and demand.
The Company utilizes both financial derivatives and physical delivery
sales contracts to manage commodity price risks. All such transactions
are conducted in accordance with the commodity price risk management
policy that has been approved by the Board of Directors.
The Company's formal commodity price risk management policy permits
management to use specified price risk management strategies including
fixed price contracts, costless collars and the purchase of floor price
options, other derivative financial instruments, and physical delivery
sales contracts to reduce the impact of price volatility and ensure
minimum prices for a maximum of eighteen months beyond the current
date. The program is designed to provide price protection on a portion
of the Company's future production in the event of adverse commodity
price movement, while retaining significant exposure to upside price
movements. By doing this, the Company seeks to provide a measure of
stability to cash flows from operating activities, as well as, to
ensure Bellatrix realizes positive economic returns from its capital
developments and acquisition activities.
As at December 31, 2012, the Company has entered into commodity price
risk management arrangements as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
|
Period
|
|
|
Volume
|
|
|
Price Floor
|
|
|
Price Ceiling
|
|
|
Index
|
|
Crude oil fixed
|
|
|
January 1, 2013 to Dec. 31, 2013
|
|
|
1,500 bbl/d
|
|
$
|
94.50 CDN
|
|
$
|
94.50 CDN
|
|
|
WTI
|
|
Crude oil call option
|
|
|
January 1, 2013 to Dec. 31, 2013
|
|
|
3,000 bbl/d
|
|
|
-
|
|
$
|
110.00 US
|
|
|
WTI
|
|
Crude oil call option
|
|
|
January 1, 2014 to Dec. 31, 2014
|
|
|
3,000 bbl/d
|
|
|
-
|
|
$
|
105.00 US
|
|
|
WTI
|
|
Natural gas fixed (1)
|
|
|
April 1, 2013 to Oct. 31, 2013
|
|
|
20,000 GJ/d
|
|
$
|
4.0875 CDN
|
|
$
|
4.0875 CDN
|
|
|
AECO
|
|
Natural gas fixed (2)
|
|
|
April 1, 2013 to Oct. 31, 2013
|
|
|
10,000 GJ/d
|
|
$
|
4.15 CDN
|
|
$
|
4.15 CDN
|
|
|
AECO
|
|
(1)
|
Subsequent to year end, the fixed price on this contract was reset to
$3.05/GJ, resulting in cash proceeds of $4.3 million paid to the
Company.
|
|
(2)
|
Subsequent to year end, the fixed price on this contract was reset to
$3.095/GJ resulting in cash proceeds of $2.2 million paid to the
Company.
|
Subsequent to December 31, 2012, the Company has entered into commodity
price risk management arrangements as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
|
Period
|
|
|
Volume
|
|
|
Price Floor
|
|
|
Price Ceiling
|
|
|
Index
|
|
Natural gas fixed
|
|
|
April 1, 2013 to June 30, 2014
|
|
|
15,000 GJ/d
|
|
|
$ 3.05 CDN
|
|
|
$ 3.05 CDN
|
|
|
AECO
|
|
Natural gas fixed
|
|
|
Feb. 1, 2013 to Dec. 31, 2013
|
|
|
10,000 GJ/d
|
|
|
$ 3.05 CDN
|
|
|
$ 3.05 CDN
|
|
|
AECO
|
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as
a result of changes in the market interest rates. The Company is
exposed to interest rate fluctuations on its bank debt which bears a
floating rate of interest. As at December 31, 2012, if interest rates
had been 1% lower with all other variables held constant, after tax net
profit for the year ended December 31, 2012 would have been
approximately $1.0 million higher, due to lower interest expense. An
equal and opposite impact would have occurred to net earnings had
interest rates been 1% higher.
The Company had no interest rate swap or financial contracts in place as
at or during the year ended December 31, 2012.
e. Capital management
The Company's policy is to maintain a strong capital base so as to
maintain investor, creditor and market confidence and to sustain the
future development of the business. The Company manages its capital
structure and makes adjustments to it in the light of changes in
economic conditions and the risk characteristics of the underlying
petroleum and natural gas assets. The Company considers its capital
structure to include shareholders' equity, bank debt, convertible
debentures and working capital. In order to maintain or adjust the
capital structure, the Company may from time to time issue common
shares, issue convertible debentures, adjust its capital spending,
and/or dispose of certain assets to manage current and projected debt
levels.
The Company monitors capital based on the ratio of total net debt to
annualized funds flow (the "ratio"). This ratio is calculated as total
net debt, defined as outstanding bank debt, plus the liability
component of convertible debentures, plus or minus working capital
(excluding commodity contract assets and liabilities and deferred tax
assets or liabilities), divided by funds flow from operations (cash
flow from operating activities before changes in non-cash working
capital and deductions for decommissioning costs) for the most recent
calendar quarter, annualized (multiplied by four). The total net debt
to annualized funds flow ratio may increase at certain times as a
result of acquisitions, fluctuations in commodity prices, timing of
capital expenditures and other factors. In order to facilitate the
management of this ratio, the Company prepares annual capital
expenditure budgets which are reviewed and updated as necessary
depending on varying factors including current and forecast prices,
successful capital deployment and general industry conditions. The
annual and updated budgets are approved by the Board of Directors.
Bellatrix does not pay dividends.
As at December 31, 2012 the Company's ratio of total net debt to
annualized funds flow (based on fourth quarter funds flow) was 1.6
times. The total net debt to annualized funds flow ratio as at
December 31, 2012 increased from that at December 31, 2011 of 1.0 times
due an increase in total net debt resulting from the timing of the
Company's 2012 capital expenditure program, a property acquisition in
the fourth quarter of 2012 and slightly lower annualized funds flow.
The Company continues to take a balanced approach to the priority use
of funds flows. The 4.75% Debentures have a maturity date of April 30,
2015. Upon maturity, the Company may settle the principal in cash or
issuance of additional common shares.
Excluding the 4.75% Debentures, net debt to annualized funds flow based
on year-end results was 1.2 times.
The Company's capital structure and calculation of total net debt and
total net debt to funds flow ratios as defined by the Company is as
follows:
|
|
|
|
|
|
|
|
Debt to Funds Flow from Operations Ratio
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
($000s, except where noted)
|
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Shareholders' equity
|
|
|
381,106
|
|
348,405
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
133,047
|
|
56,701
|
|
Convertible debentures (liability component)
|
|
|
50,687
|
|
49,076
|
|
Working capital deficiency (2)
|
|
|
5,843
|
|
13,473
|
|
Total net debt (2) at year end
|
|
|
189,577
|
|
119,250
|
|
|
|
|
|
|
|
|
Debt to funds flow from operations (1) ratio (annualized) (3)
|
|
|
|
|
|
|
Funds flow from operations (1) (annualized)
|
|
|
119,460
|
|
120,480
|
|
Total net debt (2) at year end
|
|
|
189,577
|
|
119,250
|
|
Total net debt to periods funds flow from operations ratio (annualized) (3)
|
|
|
1.6x
|
|
1.0x
|
|
|
|
|
|
|
|
|
Net debt (2) (excluding convertible debentures) at year end
|
|
|
138,890
|
|
70,174
|
Net debt to periods funds flow from operations
ratio (annualized) (3)
|
|
|
1.2x
|
|
0.6x
|
|
|
|
|
|
|
|
|
Debt to funds flow from operations (1) ratio
|
|
|
|
|
|
|
Funds flow from operations (1) for the year
|
|
|
111,038
|
|
94,237
|
|
Total net debt (2) to funds flow from operations for the year
|
|
|
1.7x
|
|
1.3x
|
|
|
|
|
|
|
|
|
Net debt (2) (excluding convertible debentures) to funds flow from operations for the
year
|
|
|
1.3x
|
|
0.7x
|
|
|
|
|
|
|
|
|
(1)
|
As detailed previously in this Management's Discussion and Analysis,
funds flow from operations is a term that does not have any
standardized meaning under Generally Accepted Accounting Principles
("GAAP"). Funds flow from operations is calculated as cash flow from
operating activities, less decommissioning costs incurred and changes
in non-cash working capital incurred.
|
|
(2)
|
Net debt and total net debt are considered additional GAAP measures.
The Company's calculation of total net debt includes the liability
component of convertible debentures and excludes deferred liabilities,
long-term commodity contract liabilities, decommissioning liabilities,
long-term finance lease obligation and the deferred tax liability. Net
debt and total net debt include the net working capital deficiency
(excess) before short-term commodity contract assets and liabilities
and current finance lease obligation. Net debt also excludes the
liability component of convertible debentures. Total net debt and net
debt are additional GAAP measures.
|
|
(3)
|
Total net debt and net debt to periods funds flow from operations ratio
(annualized) is calculated based upon fourth quarter funds flow from
operations annualized.
|
The Company's credit facility is based on petroleum and natural gas
reserves (see note 8). The credit facility outlines limitations on
percentages of forecasted production, from external reserve engineer
data, which may be hedged through financial commodity price risk
management contracts.
f. Fair value of financial instruments
The Company's financial instruments as at December 31, 2012 include
accounts receivable, deposits, commodity contract asset, accounts
payable and accrued liabilities, long-term debt and convertible
debentures. The fair value of accounts receivable, deposits, accounts
payable and accrued liabilities approximate their carrying amounts due
to their short-terms to maturity.
The fair value of commodity contracts is determined by discounting the
difference between the contracted price and published forward price
curves as at the balance sheet date, using the remaining contracted
petroleum and natural gas volumes. The fair value of commodity
contracts as at December 31, 2012 was a net asset of $0.2 million
(2011: $10.6 million net liability). The commodity contracts are
classified as level 2 within the fair value hierarchy.
Long-term bank debt bears interest at a floating market rate and the
credit and market premiums therein are indicative of current rates;
accordingly the fair market value approximates the carrying value.
The fair value of the 4.75% Debentures of $57.5 million is based on
exchange traded values. The 4.75% Debentures are classified as level 1
within the fair value hierarchy.
22. SUBSEQUENT EVENT
Cardium Joint Venture
Bellatrix has entered into a joint venture agreement with a Seoul Korea
based company ("JV Partner"), to accelerate development of Bellatrix's
extensive undeveloped Cardium land holdings in west-central Alberta.
Under the terms of the agreement, the JV Partner will contribute 50%,
or CDN$150 million, to a $300 million joint venture (the "Joint
Venture") to participate in an expected 83 Cardium well program. Under
the agreement, the JV Partner will earn 33% of Bellatrix's working
interest in the Cardium well program until payout (being recovery of
the JV Partner's capital investment plus an 8% return on investment) on
the total program, which is expected to occur prior to a maximum of 7
years, reverting to a 20% working interest after payout. The effective
date of the agreement is April 1, 2013 but with the ability of the JV
Partner to elect to invest in the wells drilled between January 1 and
up to April 30, 2013. Certain conditions precedent are expected to be
satisfied or waived by April 22, 2013 which is expected to enable
closing to occur on or before April 30, 2013. Bellatrix will be
required to provide a guarantee of the return of the JV Partner's
capital investment of up to $30 million if not recovered within 7
years.
ADDITIONAL INFORMATION
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Working Interest (1) Gross Reserves
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Proved Reserves (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs
(mbbl)
|
|
|
Natural gas
(mmcf)
|
|
|
Equivalent units
(mboe)
|
|
December 31, 2011
|
|
|
15,405
|
|
|
158,144
|
|
|
41,761
|
|
Revision of previous estimates
|
|
|
2,054
|
|
|
16,574
|
|
|
4,816
|
|
Discoveries, extensions, infill drilling and improved recovery
|
|
|
4,203
|
|
|
56,382
|
|
|
13,600
|
|
Acquisitions, net of dispositions
|
|
|
86
|
|
|
6,300
|
|
|
1,136
|
|
Production
|
|
|
(2,090)
|
|
|
(24,052)
|
|
|
(6,098)
|
|
December 31, 2012
|
|
|
19,657
|
|
|
213,348
|
|
|
55,215
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved plus probable reserves
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
|
34,515
|
|
|
415,310
|
|
|
103,754
|
|
December 31, 2011
|
|
|
25,151
|
|
|
253,705
|
|
|
67,435
|
|
(1)
|
"Working interest" refers to Bellatrix's working interest (operated or
non-operated) share before deduction of royalties and without including
any royalty interests of Bellatrix. Also referred to as "gross" under
National Instrument 51-101 ("NI 51-101"). May not add due to rounding.
|
|
(2)
|
Based on forecast prices.
|
|
Finding, Development and Acquisition Costs ("FD&A")
|
|
|
|
|
|
|
|
|
|
($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
|
2010-2012
Average
|
|
Proved (excluding FDC)
|
|
|
9.16
|
|
|
8.37
|
|
|
8.69
|
|
Proved (including FDC)
|
|
|
11.77
|
|
|
13.00
|
|
|
13.22
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved plus probable (excluding FDC)
|
|
|
4.28
|
|
|
6.06
|
|
|
5.00
|
|
Proved plus probable (including FDC)
|
|
|
6.95
|
|
|
9.29
|
|
|
9.04
|
NI 51-101 specifies how finding and development costs ("FDC") should be
calculated if they are reported. Essentially NI 51-101 requires that
the exploration and development costs incurred in the year along with
the change in estimated FDC be aggregated and then divided by the
applicable reserve additions. The calculation specifically excludes
the effects of acquisitions and dispositions on both reserves and
costs. By excluding the effects of acquisitions and dispositions
Bellatrix believes that the provisions of the NI 51-101 do not fully
reflect Bellatrix's ongoing reserve replacement costs. Since
acquisitions can have a significant impact on Bellatrix's annual
reserve replacement costs, excluding these amounts could result in an
inaccurate portrayal of Bellatrix's cost structure. Accordingly,
Bellatrix also provides FD&A costs that incorporate all acquisitions
and excludes dispositions during the year. Finding and development
costs disclosed herein is based on working interest gross reserves.
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 F&D costs
related to reserve additions for that year.
Finding and development costs (excluding acquisitions and dispositions),
excluding FDC, for proved reserves, were $8.87/boe and $8.28/boe in
2012 and 2011, respectively, (proved plus probable - $4.29/boe in 2012
and $5.99/boe in 2011) and $8.43/boe on a three year average (proved
plus probable $4.95/boe).
Finding and development costs (excluding acquisitions and dispositions),
including FDC, for proved reserves, were $11.73/boe and $12.97/boe in
2012 and 2011, respectively, (proved plus probable - $7.31/boe in 2012
and $9.26/boe in 2011) and $9.25/boe on a three year average (proved
plus probable $13.17/boe).
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.
The net present value of future net revenue of reserves do not represent
fair market value.
The Company's updated corporate presentation is available at www.bellatrixexploration.com.
Bellatrix Exploration Ltd. is a Western Canadian based growth oriented
oil and gas company engaged in the exploration for, and the
acquisition, development and production of oil and natural gas reserves
in the provinces of Alberta, British Columbia and Saskatchewan. Common
shares and convertible debentures of Bellatrix trade on the Toronto
Stock Exchange ("TSX") under the symbols BXE and BXE.DB.A,
respectively, and the common shares of Bellatrix trade on the NYSE MKT
under the symbol BXE.
SOURCE: Bellatrix Exploration Ltd.
Raymond G. Smith, P.Eng., President and CEO (403) 750-2420
or
Edward J. Brown, CA, Vice President, Finance and CFO (403) 750-2655
or
Brent A. Eshleman, P.Eng., Executive Vice President (403) 750-5566
or
Troy Winsor, Investor Relations (800) 663-8072
