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Bellatrix Exploration Ltd. Announces Year End 2013 Financial Results

TSX, NYSE MKT: BXE

CALGARY, March 13, 2014 /PRNewswire/ - Bellatrix Exploration Ltd. ("Bellatrix" or the "Company") (TSX, NYSE MKT: BXE) announces its financial and operating results for the year ended December 31, 2013.

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.

HIGHLIGHTS
    Years ended December 31,
    2013 (9) 2012
FINANCIAL (unaudited)    
(CDN$000s except share and per share amounts)    
Revenue (before royalties and risk management (1)) 291,891 219,314
Funds flow from operations (2) 143,459 111,038
  Per basic share (5) $1.27 $1.03
  Per diluted share (5) $1.24 $0.96
Cash flow from operating activities 128,458 109,328
  Per basic share (5) $1.14 $1.02
  Per diluted share (5) $1.11 $0.95
Net profit 71,657 27,771
  Per basic share (5) $0.63 $0.26
  Per diluted share (5) $0.62 $0.25
Exploration and development 281,009 164,187
Corporate 9,270 195
Property acquisitions 13,380 20,966
Capital expenditures - cash 303,659 185,348
Property dispositions - cash (70,936) (6,660)
Corporate acquisitions and other non-cash items 608,078 25,875
Total capital expenditures - net (4) 840,801 204,563
Long-term debt 287,092 133,047
Convertible debentures (6) - 50,687
Adjusted working capital (excess) deficiency (3) 108,390 5,843
Total net debt (3) 395,482 189,577
Total assets 1,555,180 681,421
Total shareholders' equity 903,874 381,106

 

OPERATING   Years ended December 31,
    2013 (9) 2012
Average daily sales volumes      
  Crude oil, condensate and NGLs (bbls/d) 6,489 5,717
  Natural gas (mcf/d) 92,042 65,812
  Total oil equivalent (boe/d) 21,829 16,686
Average prices    
  Light crude oil and condensate ($/bbl) 92.66 86.47
  NGLs (excluding condensate) ($/bbl) 43.85 38.88
  Heavy oil ($/bbl) 68.41 68.51
  Crude oil, condensate and NGLs ($/bbl) 72.29 73.59
  Crude oil, condensate and NGLs (including risk management (1)) ($/bbl) 69.82 72.65
  Natural gas ($/mcf) 3.49 2.62
  Natural gas (including risk management (1)) ($/mcf) 3.71 3.17
  Total oil equivalent ($/boe) 36.18 35.56
  Total oil equivalent (including risk management (1)) ($/boe) 36.42 37.40
         
Statistics      
  Operating netback (4) ($/boe) 20.76 19.66
  Operating netback (4) (including risk management (1)) ($/boe) 20.99 21.51
  Transportation ($/boe) 0.88 0.82
  Production expenses ($/boe) 8.74 8.73
  General & administrative ($/boe) 2.03 2.34
  Royalties as a % of sales after transportation   16% 18%
COMMON SHARES    
Common shares outstanding   170,990,605 107,868,774
Share options outstanding   11,182,963 9,420,451
Shares issuable on conversion of convertible debentures (6)   - 9,821,429
Fully diluted common shares outstanding   182,173,568 127,110,654
Diluted weighted average shares - net profit (5)   115,768,436 109,125,094
Diluted weighted average shares - funds flow from operations and
cash flow from operating activities (2) (5)
  115,768,436 118,946,523
SHARE TRADING STATISTICS      
TSX and Other (7)      
(CDN$, except volumes) based on intra-day trading      
High   8.52 5.67
Low   4.03 2.45
Close   7.81 4.27
Average daily volume   1,336,726 1,127,281
NYSE MKT (8)      
(US$, except volumes) based on intra-day trading      
High   8.43 4.54
Low   4.10 3.69
Close   7.33 4.28
Average daily volume   99,851 37,924

(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 include 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 unit 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 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 year.
   
(3) Net debt and total net debt are considered additional GAAP measures. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company's 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. 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.  
   
(4) Operating netbacks and total capital expenditures - net are considered non-GAAP measures. Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income. Total capital expenditures - net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company's decommissioning liabilities, and share based compensation.
   
(5) Basic weighted average shares for the year ended December 31, 2013 were 112,927,251 (2012: 107,543,811).
   
  In computing weighted average diluted earnings per share for the year ended December 31, 2013, a total of 2,841,185 (2012: 1,581,283) 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 nil (2012: 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 115,768,436 (2012: 109,125,094).  
     
  In computing weighted average diluted cash flow from operating activities and funds flow from operations per share for the year ended December 31, 2013, a total of 2,841,185 (2012: 1,581,283) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company's outstanding share options and no common shares issuable (2012: 9,821,429) on conversion of convertible debentures were added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 115,768,436 (2012: 118,946,523).  As a consequence, no interest and accretion expense (net of income tax effect) was added to the numerator (2012: $3.2 million).
   
(6) During the year ended December 31, 2013, the Company announced a notice of redemption of its then outstanding $55.0 million 4.75% convertible debentures, with a redemption date set of October 21, 2013.  During September and October 2013, the $55.0 million principal amount of remaining convertible debentures were converted or redeemed in exchange for an aggregate of 9,794,848 common shares of the Company.  For the year ended December 31, 2012, shares issuable on conversion of convertible debentures were calculated by dividing the $55.0 million principal amount of the convertible debentures by the conversion price of $5.60 per share. 
   
(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.
   
(9) The Company's financial and operating results for the year ended December 31, 2013 include financial and operating results from Angle Energy Inc. for the period from December 11, 2013 to December 31, 2013.

REPORT TO SHAREHOLDERS

Bellatrix's corporate strategy is value creation through effective execution of a defined exploitation oriented growth plan in the Western Canadian Sedimentary Basin, complemented with synergistic acquisitions within our core fairway and strategic Joint Ventures specifically designed to accelerate monetizing the Company's large undeveloped oil and gas resources.  The Company focuses on operating with integrity and conducting operations in a safe and environmentally responsible manner while providing sustained shareholder growth in value.  In 2013, the Company defined itself irrefragably as an industry leader with a unique platform comprised of concluding three strategic Joint Ventures, closing an accretive opportunistic acquisition that increased base production by 50% while adding significant drill ready opportunities to the Company's existing inventory and posting another 100% drilling success year which resulted in offsetting corporate declines and further increasing the Company's production base year over year by an additional 50%.  Bellatrix's ability to excel as a "drill bit driven growth" story is defined by the following:

  • An experienced visionary management team with a proven track record of value creation

  • A highly technical/innovative staff

  • Possessing and expanding a top tier asset base

  • Ability to access capital through either the equity markets or joint ventures

  • Being a low cost producer/operator/finder

  • Preserving a strong balance sheet with hedging and debt maintenance

  • Exceptional industry leading well results in the core Cardium and Notikewin/Falher resource plays

  • A large inventory of high IRR opportunities (742 net locations in the Cardium, 381 net locations in the Notikewin/Falher, 128 net locations in the Lower Mannville, totaling net capital development opportunity of $5.0 billion)

  • Extensive undeveloped  land base of approximately 416,631 net acres

  • Controlling 120 net sections of highly perspective Duvernay land in the liquids rich fairway

Each and every year in the industry, companies face a multitude of challenges that either can be controlled or that are outside of our ability to influence.  2013 presented a combination of three speed bumps beyond our control including low gas pricing, an elongated breakup period followed by extended delays obtaining well licenses from the Alberta Energy Regulator.  Despite these issues Bellatrix posted a record year of growth and profit punctuated by:

  • Record annual production levels of 8.0 million boe up 31% year-over-year

  • Drilling the top well in Alberta in 2013 at 16-23 (a two mile Spirit River horizontal) which produced in its first full year 4.4 BCF of gas and 144,000 bbl of condensate and  NGL's

  • Record daily production of 21,829 boe/d and exiting at 38,000 boe/d

  • 100% drill bit success rate with 80 gross (52.83 net) wells

  • Industry leading Proved and Probable FD&A including FDC of $9.67 /boe

  • Proved and Probable, excluding FDC and acquisitions, Recycle Ratio of 4.44 times

  • Proved and Probable, excluding FDC, Recycle Ratio of 2.9 times

  • Proved and Probable reserves increased by 103% to 212 million boes with a 10% NPVBT of $2.1 billion resulting in a net asset value of $11.40 per basic share up from $1.1 billion and $9.90 per basic share respectively

  • Replaced production by 1,452%

  • Record earnings of $71.7 million equating to $0.63 per basic share

  • Posted revenue of $292 million up 33% year over year

  • Funds flow from operations of $143.5 million equating to $1.27 per basic share

  • Credit Facility increased from $220 million to $500 million

To accelerate the development of the aforementioned 30 year drilling inventory on the Company's key plays while maintaining a strong balance sheet and minimizing the issuing of equity, Bellatrix entered into two strategic joint venture agreements and one long term strategic partnership detailed below.  In addition, in the fourth quarter Bellatrix closed a strategic acquisition of Angle Energy facilitated by an equity placement and bought back the Company's convertible debenture which is also detailed below.

$244 million Grafton Joint Venture

On June 27, 2013, Bellatrix closed a joint venture (the "Grafton Joint Venture") with Grafton Energy Co I Ltd. ("Grafton"), to accelerate development on a portion of Bellatrix's extensive undeveloped land holdings.  Subsequently on September 10, 2013, the Company announced that Grafton elected to exercise an option to increase its committed capital investment by an additional $100 million on the same terms and conditions as the initial Grafton Joint Venture.

The Grafton Joint Venture is in Ferrier, Willesden Green and Brazeau areas of West-Central Alberta. Under the terms of the amended agreement, Grafton will contribute 82%, or $200 million, to the $244 million Grafton Joint Venture to participate in an expected 58 Notikewin/Falher and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix's working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix's working interest ("WI") after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty ("GORR") on Bellatrix's pre-Grafton Joint Venture working interest.  Grafton also has an additional one-time option within 12 months of the effective date to increase its exposure by an additional $50 million on the same terms and conditions. The effective date of the agreement is July 1, 2013 and has a term of 2 years.  If the $50 million option is exercised, Bellatrix shall have until the end of the third anniversary of the effective date to spend the additional capital.

Baptiste Asset Sale and Strategic Partnership

On September 3, 2013, the Company announced the closing of an asset sale (the "Asset Sale") and joint venture (the "Daewoo and Devonian Joint Venture") with Canadian Subsidiaries of two Korean entities, Daewoo International Corporation ("Daewoo") and Devonian Natural Resources Private Equity Fund ("Devonian").  Under the terms of the associated agreements, Bellatrix sold, effective July 1, 2013, to Daewoo and Devonian an aggregate 50% of the Company's working interest share of its producing assets, an operated compressor station and gathering system and related land acreage in the Baptiste area of West Central Alberta (the "Sold Assets") for gross consideration of $52.5 million, subject to closing adjustments.  The Sold Assets were producing approximately 268 boe/d (67% gas and 33% oil and liquids) net to the Sold Assets and included 3,858 net acres of Cardium rights and 1,119 net acres of Mannville rights.

The Daewoo and Devonian Joint Venture which was effective as of July 1, 2013 encompasses a multiyear commitment to jointly develop the aforementioned acreage in Ferrier and Willesden Green of West Central Alberta encompassing 70 gross wells with anticipated total capital expenditures to the Daewoo and Devonian Joint Venture of approximately $200 million.

Redemption of Convertible Debentures

On September 4, 2013, the Company announced the issuance of a notice of redemption to holders of its then outstanding $55.0 million 4.75% convertible unsecured subordinated debentures (the "convertible debentures"), with the redemption date set as October 21, 2013. During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company. A reduction to the deficit as contained in shareholder's equity of $1.3 million was recognized in connection with the settlement of the convertible debentures during the year ended December 31, 2013.

Bought Deal Financing

On November 5, 2013, Bellatrix closed a bought deal financing of 21,875,000 Bellatrix common shares at a price of $8.00 per Bellatrix Share for aggregate gross proceeds of $175.0 million (net proceeds of $165.7 million after transaction costs) through a syndicate of underwriters.

The net proceeds from this financing were used to temporarily repay a portion of the indebtedness of Bellatrix under its credit facilities; subsequently utilized to fund the cash portion of the acquisition of Angle, the acquisition of the Angle Debentures, and a portion of Bellatrix's obligations under the Troika Joint Venture described below.

Troika Joint Venture

On November 11, 2013, the Company announced that it had successfully closed the previously announced $240 million joint venture partnership (the "Troika Joint Venture") with TCA Energy Ltd. ("TCA").  TCA is a Canadian incorporated special purpose vehicle for Troika Resources Private Equity Fund which is based in Seoul, Korea and managed by KDB Bank, SK Energy and Samchully AMC.

Pursuant to the agreement forming the Troika Joint Venture, Bellatrix and TCA will drill and develop lands in the Ferrier Cardium area of West Central Alberta, with the program to be completed by December 31, 2014.  TCA will contribute $120 million, representing a 50% share, towards the capital program for the drilling of an expected 63 gross wells, and in exchange, will receive 35% of Bellatrix's working interest until payout (being recovery of TCA's capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's working interest.  As part of this agreement, TCA participated in 14 gross wells (as included in the total expected 63 gross well program) for wells that have been drilled since January 1, 2013, resulting in net proceeds of $16.7 million that was received by Bellatrix at closing.

The net proceeds from the disposition were initially used to reduce the Company's indebtedness, and ultimately will be directed towards the continued development of its Cardium and Mannville asset base.

Angle Acquisition

On December 11, 2014, Bellatrix acquired all of the issued and outstanding common shares of Angle Energy Inc. ("Angle") for consideration consisting of $69.7 million in cash and approximately 30.2 million Bellatrix common shares. The announced  $576 million aggregate transaction value included the assumption of net Angle debt of approximately $261 million after taking into account $16 million in transaction costs and  severance costs, terminated options and RSU's and a  premium paid to the Angle  debenture holders.

Through the strategic combination of Bellatrix's top-tier asset base with Angle's high quality, low-cost, high working interest asset base the Company has created one of the largest, intermediate producers in the West Central Alberta fairway with a dominant and highly focused position in the Cardium and Mannville intervals. The strategic combination was highly complementary and accretive to Bellatrix on current production, cash flow, reserves and net asset value per share. The combination creates a high growth intermediate company with a sizeable, strategic and opportunity rich asset base with a drillable inventory of over 2,000 locations ($10 billion capital investment at today's cost per well) and with 416,631 net undeveloped acres.

Property Acquisition

During the fourth quarter of 2013, the Company increased its current working interest in certain Cardium and Notikewin/Falher lands and production in the Willesden Green (Baptiste) area of Alberta through the acquisition of additional working interests from several companies for a total combined net purchase price of $10 million.

Operational highlights for the three months and year ended December 31, 2013 include:

  • Bellatrix posted a 100% success rate during the 2013 year, drilling and/or participating in 80 gross (52.83 net) wells, resulting in 57 gross (41.22 net) Cardium oil wells, 22 gross (10.86 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.  In the fourth quarter of 2013, Bellatrix drilled or participated in 35 gross wells (21.36 net), which included 24 gross (16.24 net) Cardium oil wells, 10 gross (4.37 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.

  • Q4 2013 sales volumes averaged 23,968 boe/d (weighted 32% to oil, condensate, and NGLs, and 68% to natural gas).  This represents a 28% increase over fourth quarter 2012 average sales volumes of 18,763 boe/d, and a 10% increase from third quarter 2013 average sales volumes of 21,852 boe/d.

  • 2013 annual sales volumes averaged 21,829 boe/d (weighted 30% to oil, condensate and NGLs and 70% to natural gas).  This represents a 31% increase from sales volumes of 16,686 boe/d realized in 2012.

  • Significant 2013 Facility Projects:
    • Installed a 25 km pipeline to the MBL Gas Plant facilitating processing an additional 85 mmcf/d capacity

    • Installed 6 field compressors  totaling 9700 hp capable of handling 75 mmcf/d

    • Installed 45+ km of large diameter group pipelines
  • Near term 2014 catalysts:
    • In the first quarter jointly with the Blaze Gas Plant install 60 km pipeline to the Blaze Gas Plant from the Ferrier Area to facilitate access to 120 mmcf/d capacity

    • In the third quarter install a 20  km pipeline to the Brazeau Gas Plant to access an additional 40-50 mmcf/d capacity

    • Throughout 2014 install 21 field compressors totaling 30,500 hp, capable of handling 245 mmcfd

    • In the third quarter build 2 oil batteries with 5000 Bbls/d processing capacity

    • Throughout 2014 install 60+ km of large diameter group pipelines
  • Long term 2015 - 2016 catalysts:
    • Build a new BXE Gas Plant in the Alder Flats Area  (In Service July 2015)
      • 110 mmcf/d capacity

      • C3 Recovery 99% ; C4+ Recovery 100%

      • Permitting and field construction underway

      • Potentially double the capacity in 2016
  • During the fourth quarter of 2013, the Company spent $115.9 million on capital projects, compared to $53.0 million during the fourth quarter of 2012.

  • As at December 31, 2013, Bellatrix had approximately 416,631 net undeveloped acres of land in Alberta, British Columbia and Saskatchewan.

Financial highlights for the three months and year ended December 31, 2013 include:

  • Q4 2013 revenue before royalties and risk management contracts was $83.5 million, 34% higher than the $62.3 million recorded in Q4 2012.  Revenue before royalties and risk management contracts for the year ended December 31, 2013 was $291.9 million, up 33% from $219.3 million in 2012.  The increase in revenues in the 2013 year was primarily due to increased natural gas and NGL sales volumes and higher realized prices for light oil and condensate, NGLs, and natural gas, partially offset by reduced crude oil and condensate sales volumes as well as lower heavy oil prices compared to 2012.

  • Funds flow from operations for Q4 2013 was $39.3 million ($0.31 per basic share), an increase of 31% from $30.0 million in Q3 2013, and up 31% from $29.9 million ($0.28 per basic share) in Q4 2012.  Funds flow from operations for the year ended December 31, 2013 was $143.5 million ($1.27 per basic share), up 29% from $111.0 million ($1.03 per basic share) in 2012.  The increase in funds flow from operations between the 2013 and 2012 was principally due to increased production volumes and increased light oil, condensate, NGL, and natural gas prices positively impacting revenues and netbacks, partially offset by a higher net realized loss on commodity contracts, increased general and administrative expenses, operating, transportation, and royalties expenses, and the impact of lower heavy oil commodity prices.

  • The net profit for Q4 2013 was $22.2 million, compared to $9.3 million in Q4 2012.

  • The net profit for the year ended December 31, 2013 was $71.7 million, compared to $27.8 million in 2012.

  • Crude oil, condensate and NGLs produced 57% and 59% of petroleum and natural gas sales revenue for the three and twelve month periods ended December 31, 2013, respectively.

  • Production expenses for Q4 2013 were $8.70/boe ($19.2 million), compared to $8.91/boe ($15.4 million) for Q4 2012 and $8.98/boe ($18.1 million) for Q3 2013.  The quarter over quarter decreases in production expenses per boe were primarily due to increased production volumes resulting from 2012 and 2013 drilling in areas with lower production expenses, as well as continued field optimization projects.  Production expenses, after deducting processing and other third party income, for the year ended December 31, 2013 were $8.29/boe ($66.1 million), compared to $8.37/boe ($51.1 million) in 2012.

  • Operating netbacks after including risk management for Q4 2013 were $20.64/boe, down from $20.83/boe in Q4 2012.  Operating netbacks before risk management for Q4 2013 were $21.10/boe, up from $19.20/boe in Q4 2012.  The reduced netbacks including risk management were primarily the result of a net realized loss on commodity contracts in 2013 compared to a net gain in 2012 in conjunction with higher transportation expenses and slightly lower heavy oil prices, offset partially by higher natural gas, light oil and condensate, and NGL prices, and lower production and royalty expenses.

  • Operating netbacks before risk management for the year ended December 31, 2013 were $20.76/boe, up from $19.66/boe in 2012.

  • During Q4 2013, Bellatrix spent $115.9 million on capital projects, compared to $53.0 million during Q4 2012.  For the year ended December 31, 2013, Bellatrix spent $303.7 million on capital projects compared to $185.3 million in 2012.

  • G&A expenses for Q4 2013 decreased slightly on a per boe basis to $2.53/boe ($5.6 million), compared to $2.54/boe ($4.4 million) for Q4 2012.  G&A expenses for the year ended December 31, 2013 were $2.03/boe ($16.2 million), compared to $2.34/boe ($14.3 million) in 2012.

  • As at December 31, 2013, Bellatrix had $212.9 million undrawn on its total $500 million credit facility.

  • Total net debt as of December 31, 2013 was $395.5 million.

OUTLOOK

With the consummation of two innovative joint ventures, one strategic partnership, and the accretive acquisition of Angle Energy Ltd, Bellatrix's 2014 gross capital expenditure program of $610 million is comprised of $370 million net Bellatrix capital and $240 million joint venture/partner capital.  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 2014 capital expenditure plan is expected to provide average daily production of approximately 42,500 boe/d to 43,500 boe/d, and an exit rate of approximately 47,000 boe/d.

Currently, the Company is concentrating on further development of its core resource plays, the Cardium Light Oil and the multi-zone Mannville Liquids Rich Gas intervals in Western Canada. The multi-zone Mannville in Alberta's deep basin boasts abundant, liquids-rich natural gas with high deliverability gas wells delivering substantial economics. The Cardium is a massive light oil resource play that has added 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. The company anticipates drilling approximately 146 gross wells in 2014; of which 115 gross wells are estimated to be in the Cardium Oil zone and 31 are estimated to be in the liquids-rich Mannville gas zones.

The key operational strategy Bellatrix employs is to focus on full cycle profitability, indifferent to product type, with every investment decision.  Bellatrix's ability to reinvent ourselves and continuously apply new technology is one of the keys to being successful and a market leader.  Our ability to be informed of these new technologies, understand their application, and then try them in new ways allows us to increase deliverability and ultimate resource recovery. 

We focus for long term success on our ability to manage, enhance and exploit our current assets while simultaneously developing new and potentially exciting plays in the Deep Basin for the future.  Thus continuing our overall priority of bringing 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 12, 2014

Note:

A conference call to discuss Bellatrix's annual financial and reserves results will be held on March 13, 2014 at 9:00 am MDT/11:00 am 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 33160756 followed by the pound sign.

Bellatrix's annual meeting is scheduled for 3:00 pm on May 21, 2014 in the Devonian Room at the Calgary Petroleum Club.

The Company's current corporate presentation is available at www.bellatrixexploration.com.

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 12, 2014 - 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, 2013 and 2012.   This commentary is based on information available to, and is dated as of, March 12, 2014. 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.

NET ASSET VALUE: Net asset value is calculated based on the Sproule evaluation as at December 31, 2013 of future net revenue of the Company's proved plus probable reserves before tax discounted at 10%, which does not represent fair market value and does not take into account possible reserve additions from reinvestment of cash flow in existing properties.  Net asset value per share is determined using the basic weighted average number of shares outstanding at December 31, 2013 of 112,927,251.

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 also contain the terms total net debt and net debt. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company's 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. 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 the terms of operating netbacks and total capital expenditures - net, which are not recognized measures under GAAP. Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from revenues before other income. Management believes this measure is a useful supplemental measure of the amount of revenues received after transportation, royalties and operating expenses. Readers are cautioned, however, that this measure should not be construed as an alternative to net profit or loss determined in accordance with GAAP as a measure of performance. Bellatrix's method of calculating this measure may differ from other entities, and accordingly, may not be comparable to measures used by other companies. Total capital expenditures - net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company's decommissioning liabilities, and share based compensation.

JOINT ARRANGEMENTS: Bellatrix is a partner of the following joint arrangements, which have been classified under IFRS as joint operations. This classification is on the basis that the arrangement is not conducted through a separate legal entity and the partners are legally obligated to pay their share of costs incurred and take their share of output produced from the various production areas. For purposes of disclosure throughout the MD&A and financial statements, Bellatrix has referred to these arrangements by the common oil and gas industry term of joint ventures.

GRAFTON JOINT VENTURE - Bellatrix has a joint venture (the "Grafton Joint Venture") with Grafton Energy Co I Ltd. ("Grafton") in the Willesden Green and Brazeau areas of West-Central Alberta, whereby Grafton will contribute 82% or $200 million to the joint venture to participate in an expected 58 Notikewin/Falher and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix's working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix's working interest ("WI") after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty ("GORR") on Bellatrix's pre-Grafton Joint Venture WI.

DAEWOO AND DEVONIAN PARTNERSHIP - Bellatrix has a joint venture arrangement (the "Daewoo and Devonian Partnership") with Canadian subsidiaries of two Korean entities, Daewoo International Corporation ("Daewoo") and Devonian Natural Resources Private Equity Fund ("Devonian") in the Baptiste area of West-Central Alberta, whereby Daewoo and Devonian own a combined 50% working interest share of producing assets, an operated compressor station and gathering system and related land acreage.

TROIKA JOINT VENTURE - Bellatrix has a joint venture (the "Troika Joint Venture") with TCA Energy Ltd. ("TCA") in the Ferrier Cardium area of West-Central Alberta, whereby Troika will contribute 50% or $120 million towards a capital program for drilling of an expected 63 gross wells and will receive a 35% working interest until payout (being recovery of TCA's capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's working interest.

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, operations and strategy, drilling plans and the timing thereof, commodity price risk management strategies, 2014 capital expenditure budget, the nature of expenditures and the method of financing thereof, anticipated liquidity of the Company and various matters that may impact such liquidity, expected 2014 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, the Company's drilling inventory and capital required therefor, estimated capital expenditures and wells to be drilled under joint venture agreements, the ability to fund the 2014 capital expenditure program utilizing various available sources of capital, expected 2014 average daily production and exit rate, plans to continue commodity risk management strategies and timing of redetermination of borrowing base and plans for additional facilities and infrastructure and timing thereof may constitute forward-looking statements under applicable securities laws. Forward-looking statements 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, 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), through the SEC website (www.sec.gov), 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.

Common shares of Bellatrix trade on the Toronto Stock Exchange ("TSX") and on the NYSE MKT under the symbol BXE.

2013 Transactions

Acquisition of Angle Energy Inc.

On December 11, 2013, Bellatrix acquired all issued and outstanding common shares of Angle Energy Inc. ("Angle") for the consideration consisting of $69.7 million in cash and the issuance of 30,230,998 Bellatrix common shares.  Bellatrix also acquired for cancellation all of the issued and outstanding 5.75% convertible unsecured subordinated debentures of Angle with a maturity date of January 31, 2016 (the "Angle Debentures") in the aggregate principal amount of $60.0 million on the basis of $1,040 in cash per $1,000 principal amount of the Angle Debentures or $62.4 million total, plus total accrued and unpaid interest of approximately $1.3 million.  Bellatrix's financial and operating results for the year ended December 31, 2013 include financial and operating results from Angle for the period from December 11, 2013 to December 31, 2013.

The acquisition of Angle resulted in the combination of Bellatrix's top-tier asset base with Angle's high quality, low-cost, high working interest asset base to create one of the largest intermediate producers in the West Central Alberta fairway, with a dominant and highly focused position in the Cardium and Mannville intervals. The strategic combination was considered by Bellatrix to be highly complementary and accretive to Bellatrix in terms of current production, cash flow, reserves, and net asset value per share.  The combination resulted in a high growth intermediate company with a sizeable, strategic and opportunity rich asset base with a drillable inventory of over 2,000 locations ($10 billion capital investment at current cost per well) and with 416,631 net undeveloped acres.

Bought Deal Financing

On November 5, 2013, Bellatrix closed a bought deal financing of 21,875,000 Bellatrix common shares at a price of $8.00 per Bellatrix Share for aggregate gross proceeds of $175.0 million (net proceeds of $165.7 million after transaction costs) through a syndicate of underwriters.

The net proceeds from this financing were used to temporarily repay a portion of the indebtedness of Bellatrix under its credit facilities; subsequently utilized to fund the cash portion of the acquisition of Angle, the acquisition of the Angle Debentures, and a portion of Bellatrix's obligations under the Troika Joint Venture described below.

Troika Joint Venture

On November 11, 2013, the Company announced that it had successfully closed the previously announced $240 million joint venture partnership with TCA Energy Ltd. TCA is a Canadian incorporated special purpose vehicle for Troika Resources Private Equity Fund which is based in Seoul, Korea and managed by KDB Bank, SK Energy and Samchully AMC.

Pursuant to the agreement forming the Troika Joint Venture, Bellatrix and TCA will drill and develop lands in the Ferrier Cardium area of West Central Alberta, with the program to be completed by December 31, 2014.  TCA will contribute $120 million, representing a 50% share, towards the capital program for the drilling of an expected 63 gross wells, and in exchange, will receive 35% of Bellatrix's working interest until payout (being recovery of TCA's capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's working interest.  As part of this agreement, TCA participated in 14 gross wells (as included in the total expected 63 gross well program) for wells that have been drilled since January 1, 2013, resulting in net proceeds of $16.7 million that was received by Bellatrix at closing.

The net proceeds from the disposition were initially used to reduce the Company's indebtedness, and ultimately will be directed towards the continued development of its Cardium and Mannville asset base.

Grafton Joint Venture

On June 27, 2013, Bellatrix closed the Grafton Joint Venture to accelerate development on a portion of Bellatrix's extensive undeveloped land holdings.  Subsequently on September 10, 2013, the Company announced that Grafton elected to exercise an option to increase its committed capital investment by an additional $100 million on the same terms and conditions as the initial Grafton Joint Venture.

The Grafton Joint Venture is in Willesden Green and Brazeau areas of West-Central Alberta. Under the terms of the amended agreement, Grafton will contribute 82%, or $200 million, to the $244 million Grafton Joint Venture to participate in an expected 58 Notikewin/Falher and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix's working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix's working interest ("WI") after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty ("GORR") on Bellatrix's pre-Grafton Joint Venture working interest.  Grafton also has an additional one-time option within 12 months of the effective date to increase its exposure by an additional $50 million on the same terms and conditions. The effective date of the agreement is July 1, 2013 and has a term of 2 years.  If the $50 million option is exercised, Bellatrix shall have until the end of the third anniversary of the effective date to spend the additional capital.

Baptiste Asset Sale and Strategic Partnership

On September 3, 2013 the Company announced the closing of an asset sale to Daewoo and Devonian, and the Daewoo and Devonian Partnership. Under the terms of the associated agreements, Bellatrix sold, effective July 1, 2013, to Daewoo and Devonian an aggregate 50% of the Company's working interest share of its producing assets, an operated compressor station and gathering system and related land acreage in the Baptiste area of West Central Alberta (the "Sold Assets") for gross consideration of $52.5 million, subject to closing adjustments. A $29.1 million gain on dispositions was recognized during the year ended December 31, 2013 in relation to the disposition. The Sold Assets were producing approximately 268 boe/d (67% gas and 33% oil and liquids) net to the Sold Assets and included 3,858 net acres of Cardium rights and 1,119 net acres of Mannville rights.

The Daewoo and Devonian Partnership which was effective as of July 1, 2013 encompasses a multiyear commitment to jointly develop the aforementioned acreage in Ferrier and Willesden Green of West Central Alberta encompassing 70 gross wells with anticipated total capital expenditures to the Daewoo and Devonian Partnership of approximately $200 million.

Redemption of Convertible Debentures

On September 4, 2013, the Company issued a notice of redemption to holders of its then outstanding $55.0 million 4.75% convertible unsecured, unsubordinated debentures (the "convertible debentures"), with the redemption date set as October 21, 2013.  During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company.   A reduction to the deficit as contained in shareholder's equity of $1.3 million was recognized in connection with the settlement of the convertible debentures during the year ended December 31, 2013.

Fourth Quarter 2013

HIGHLIGHTS     Three months ended December 31,
(CDN$000s except share and per share amounts)     2013 (8) 2012
FINANCIAL        
Revenue (before royalties and risk management (1))     83,455 62,283
         
Funds flow from operations (2)     39,349 29,865
  Per basic share (5)     $0.31 $0.28
  Per diluted share (5)     $0.30 $0.26
Cash flow from operating activities     38,025 32,007
  Per basic share (5)     $0.30 $0.30
  Per diluted share (5)     $0.29 $0.28
Net profit     22,195 9,251
  Per basic share (5)     $0.17 $0.09
  Per diluted share (5)     $0.17 $0.08
Exploration and development     101,232 32,083
Corporate     4,282 43
Property acquisitions     10,385 20,922
Capital expenditures - cash     115,899 53,048
Property dispositions - cash     (16,700) 10
Corporate acquisitions and other non-cash items     607,727 27,487
Total capital expenditures - net (4)     706,926 80,545
         
OPERATING          
Average daily sales volumes          
  Crude oil, condensate and NGLs (bbls/d)     7,564 5,730
  Natural gas (mcf/d)     98,423 78,195
  Total oil equivalent (boe/d)     23,968 18,763
Average prices        
  Light crude oil and condensate ($/bbl)     83.26 82.58
  NGLs (excluding condensate) ($/bbl)     46.20 38.84
  Heavy oil ($/bbl)     63.70 65.30
  Crude oil, condensate and NGLs ($/bbl)     66.75 69.55
  Crude oil, condensate and NGLs (including risk management (1)) ($/bbl)     64.32 72.11
  Natural gas ($/mcf)     3.89 3.46
  Natural gas (including risk management (1)) ($/mcf)     3.97 3.67
  Total oil equivalent ($/boe)     37.05 35.67
  Total oil equivalent (including risk management (1)) ($/boe)     36.59 37.30
Statistics          
  Operating netback (4) ($/boe)     21.10 19.20
  Operating netback (4) (including risk management (1)) ($/boe)     20.64 20.83
  Transportation ($/boe)     1.02 0.70
  Production expenses ($/boe)     8.70 8.91
  General & administrative ($/boe)     2.53 2.54
  Royalties as a % of sales after transportation       17% 20%
DILUTED WEIGHTED AVERAGE SHARES      
Diluted weighted average shares - net profit (5)     130,875,349 118,931,047
Diluted weighted average shares - funds flow from operations and cash
flow from operating activities (2) (5)
    130,875,349 118,931,047
SHARE TRADING STATISTICS        
TSX and Other (6) (CDN$, except volumes) based on intra-day trading        
High     8.52 4.47
Low     6.65 3.59
Close     7.81 4.27
Average daily volume     2,678,253 842,840
NYSE MKT (7) (US$, except volumes) based on intra-day trading        
High     8.43 4.54
Low     6.38 3.69
Close     7.33 4.28
Average daily volume     171,620 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 include 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 unit 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 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 year.
 
(3) Net debt and total net debt are considered additional GAAP measures. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company's 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. 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.
   
(4) Operating netbacks and total capital expenditures - net are considered non-GAAP measures. Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income. Total capital expenditures - net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company's decommissioning liabilities, and share based compensation.
 
(5) Basic weighted average shares for the three months ended December 31, 2013 were 127,489,592 (2012: 107,734,134).
 
  In computing weighted average diluted earnings per share and weighted average diluted cash flow from operating activities and funds flow from operations per share for the three months ended December 31, 2013, a total of 3,385,757 (2012: 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 no common shares (2012: 9,821,429) issuable on conversion of convertible debentures were added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 130,875,349 (2012: 118,931,047). As a consequence, a total of no interest and accretion expense (net of income tax effect) was added to the numerator (2012: $0.8 million).
 
(6) TSX and Other includes the trading statistics for the Toronto Stock Exchange and other Canadian trading markets.
 
(7) The Company's common shares commenced trading on the NYSE MKT on September 24, 2012.
 
(8) The Company's financial and operating results for the three months ended December 31, 2013 include financial and operating results from Angle for the period from December 11, 2013 to December 31,2013.

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. Bellatrix's method of calculating funds flow from operations may differ from that of other companies, and accordingly, may not be comparable to measures used by other companies. Funds flow from operations is calculated as cash flow from operating activities before decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.

Reconciliation of Cash Flow from Operating Activities to Funds Flow from Operations        
    Three months ended December 31,
($000s)     2013 2012
Cash flow from operating activities     38,025 32,007
Decommissioning costs incurred     223 76
Transaction costs     5,344 -
Change in non-cash working capital     (4,243) (2,218)
Funds flow from operations     39,349 29,865

Funds flow from operations during the fourth quarter of 2013 was $39.3 million, an increase of 32% compared to $29.9 million for the fourth quarter of 2012.  The increase in funds flow from operations between the periods was due primarily due to the impact on revenues and netbacks of increased natural gas, light oil and condensate, and NGL sales volumes, higher light oil, condensate, NGL, and natural gas prices, partially offset by lower heavy oil sales volumes, a net realized loss on commodity contracts compared to a net realized gain in the 2012 fourth quarter, increased general and administrative expenses, the impact of lower heavy oil commodity prices and higher overall operating, transportation, and royalties expenses.

Cash flow from operating activities during the fourth quarter of 2013 increased to $38.0 million, compared to $32.0 million for the fourth quarter of 2012, primarily due to a higher overall operating netback as discussed above. The increase from the higher netbacks between the periods was partially offset by transaction costs, as well as a slight increase in decommissioning costs incurred in the 2013 fourth quarter compared to 2012.

In the three months ended December 31, 2013, Bellatrix realized a net profit of $22.2 million compared to a net profit of $9.3 million in the same period of 2012.  The higher net profit recorded in the fourth quarter of 2013 compared to the same period in 2012 is primarily the result of higher revenue before other, a $20.6 million non-cash gain on corporate acquisition, a $5.1 million gain on property dispositions compared to a $0.1 million loss on property dispositions in the 2012 period, a $6.5 million non-cash unrealized loss on commodity risk management compared to a $1.3 million gain in the 2012 period, and a deferred income tax expense of $2.6 million in the 2013 fourth quarter compared to an expense of $3.3 million in the 2012 period, offset partially by increased depletion and depreciation expenses, higher royalty expenses, and a non-cash gain on property acquisition of $16.6 million recognized in 2012.

Sales Volumes          
        Three months ended December 31,
        2013 2012
Light oil and condensate (bbls/d)     4,111 3,910
NGLs (excluding condensate) (bbls/d)     3,278 1,631
Heavy oil (bbls/d)     175 189
Total crude oil, condensate and NGLs (bbls/d)     7,564 5,730
           
Natural gas (mcf/d)     98,423 78,195
           
Total boe/d (6:1)     23,968 18,763

Sales volumes for the three months ended December 31, 2013 averaged 23,968 boe/d, an increase of 28% from the 18,763 boe/d sold in the fourth quarter of 2012.  The weighting toward crude oil, condensate and NGLs sales volumes increased to 32% in the 2013 fourth quarter, compared to 31% in the corresponding period in 2012.  Fourth quarter 2013 natural gas, NGL, and total overall sales volumes were higher than the same period in 2012 primarily due to the continued success achieved from the Company's liquids rich drilling program as well as additional sales volumes realized from the Angle acquisition.

Natural gas sales averaged 98.4 Mmcf/d during the three months ended December 31, 2013, compared to 78.2 Mmcf/d in the fourth quarter of 2012.  The weighting toward natural gas sales volumes averaged 68% in the 2013 fourth quarter, a slight decrease from the 69% weighting realized in the same period in 2012.  Crude oil, condensate and NGL sales volumes increased by 32% to 7,564 bbls/d in the final quarter of 2012 compared to 5,730 bbls/d during the same period of 2012.

Revenue        
    Three months ended December 31,
($000s)     2013 2012
Light crude oil and condensate     31,493 29,702
NGLs (excluding condensate)     13,934 5,829
Heavy oil     1,029 1,136
Crude oil and NGLs     46,456 36,667
Natural gas     35,252 24,904
Total revenue before other     81,708 61,571
Other income (1)     1,747 712
Total revenue before royalties and risk management     83,455 62,283
(1) Other income primarily consists of processing and other third party income.

Revenue before other income, royalties and commodity price risk management contracts for the final quarter of 2013 was $81.7 million, an increase of 33% from $61.6 million in the same period in 2012.  The increase in revenues between the periods was due to increased light oil and condensate, NGLs, and natural gas sales volumes in conjunction with higher light oil and condensate, NGLs, and natural gas prices in the 2013 period, partially offset by lower heavy oil sales volumes and prices.

Light oil and condensate revenues for the fourth quarter of 2013 increased by 6% from the same period in 2012 as a result of both higher prices and sales volumes realized between the periods.  For light oil and condensate, Bellatrix recorded an average $83.26/bbl before commodity price risk management contracts during the fourth quarter of 2013, 1% higher than the average price of $82.58/bbl received in the comparative 2012 period.  In comparison, the Edmonton par price increased by 2% over the same period.  The average WTI crude oil benchmark price increased by 11% in fourth quarter of 2013 compared to the same period in 2012.  The average US$/CDN$ foreign exchange rate was 0.9528 for the three months ended December 31, 2013, a decrease of 6% compared to an average rate of 1.0093 in the fourth quarter of 2012.

NGL revenues for the fourth quarter of 2013 increased by 139% compared to the 2012 period as a result of higher sales volumes in conjunction with increased prices.  For NGLs (excluding condensate), Bellatrix recorded an average $46.20/bbl during the fourth quarter of 2013, a 19% increase from the $38.84/bbl received in the comparative 2012 period.  The increase in NGL pricing between the 2013 and 2012 periods is largely attributable to changes in NGL market supply conditions between the periods.

Natural gas revenues in the final quarter of 2013 increased by 42% from the same period in 2012 as a result of a 26% increase in sales volumes and a 12% increase in realized natural gas prices before transportation 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 2013, the AECO daily reference price increased by 10%, and the AECO monthly reference price increased by approximately 3% compared to the fourth quarter of 2012.  Bellatrix's natural gas average sales price before commodity price risk management contracts for the fourth quarter of 2013 increased by 12% to $3.89/mcf compared to the $3.46/mcf realized in the same period in 2012.  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 2013.  Bellatrix's natural gas average price after including commodity price risk management contracts for the three months ended December 31, 2013 was $3.97/mcf, compared to $3.67/mcf for the three months ended December 31, 2012.

In the fourth quarter of 2013, average sales volumes increased by 10% from the third quarter 2013 average volumes of 21,852 boe/d.  The increase was due to the success achieved from the Company's drilling program in 2013 and its acquisition of Angle.

During the three months ended December 31, 2013, Bellatrix spent $101.2 million on capital projects, excluding corporate and property acquisitions and dispositions, compared to $32.1 million in the same period in 2012.  In the fourth quarter of 2013, Bellatrix drilled or participated in 35 gross wells (21.36 net), which included 24 gross (16.24 net) Cardium oil wells, 10 gross (4.37 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.  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 2013, the Company had $13.8 million in royalties, compared to $11.8 million in the same period in 2012.  As a percentage of pre-commodity price risk management sales (after transportation costs), royalties were 17% in the three months ended December 31, 2013 compared to 20% in the same period in 2012.  The Company's minor heavy oil properties, principally consisting of the Frog Lake Alberta assets, are also subject to high Crown royalty rates. The Company's light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more recent wells in their early years of production under the Alberta royalty incentive program, offset by increased royalty rates on other wells now coming off initial royalty incentive rates and as other wells are drilled on Ferrier lands with higher combined Indian Oil and Gas Canada ("IOGC") and gross overriding royalty ("GORR") royalty rates.

In the final quarter of 2013, operating costs totaled $19.2 million, compared to $15.4 million recorded in the same period of 2012.  During the three months ended December 31, 2013, operating costs averaged $8.70/boe, down from the $8.91/boe incurred during the same period in 2012.  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 2013 averaged $8.98/boe.

During the fourth quarter of 2013, the Company's corporate operating netback before commodity risk management contracts increased by 10% to $21.10/boe compared to $19.20/boe in the comparative 2012 period, driven primarily by a 4% increase in overall commodity prices, a 9% decrease in royalties, and a 2% decrease in production expenses, partially offset by a 46% increase in transportation expenses.  In comparison, the Company's corporate operating netback before commodity risk management contracts for the third quarter of 2013 was $19.85/boe.

The operating netback before commodity price risk management contracts for crude oil, condensate and NGLs during the fourth quarter of 2013 averaged $43.19/bbl, an increase of 15% from the $37.60/bbl realized during the fourth quarter of 2012. The increase between the periods was primarily as a result of lower royalties and reduced production expenses, offset partially by weaker commodity prices and higher transportation expenses.  In comparison, the operating netback for crude oil, condensate and NGLs for the third quarter of 2013 was $57.05/bbl.

The operating netback for natural gas before commodity price risk management contracts during the fourth quarter of 2013 of $1.82/mcf was 2% lower than the $1.85/mcf recorded in the same period in 2012.  The decrease was primarily a result of increased royalties, production expenses, and transportation expenses, slightly offset by higher natural gas prices.  In comparison, the operating netback for natural gas before commodity risk management contracts for the third quarter of 2013 was $0.86/mcf.

In the three months ended December 31, 2013, general and administrative expenses ("G&A"), net of capitalized G&A and recoveries, were $5.6 million, compared to $4.4 million in the comparable 2012 period. The increase to net G&A was primarily attributable to increases in staffing and office 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 2013 compared to the fourth quarter of 2012.

Depletion, depreciation and accretion expense for the final quarter of 2013 was $27.3 million ($12.38/boe), compared to $18.6 million ($10.77/boe) in the same period in 2012.  The increase in depletion, depreciation and accretion expense from the 2012 fourth quarter to that in 2013 is reflective of the 28% increase in sales volumes and a higher depletable base between the comparative periods, partially offset by the additional reserves achieved through the Company's drilling success.

2013 Annual Financial and Operational Results

Sales Volumes

Sales volumes for the year ended December 31, 2013 averaged 21,829 boe/d compared to 16,686 boe/d in 2012, representing a 31% increase.  Total crude oil, condensate and NGLs averaged approximately 30% of sales volumes for 2013, compared to 34% of sales volumes in 2012.  The increase in total sales was primarily a result of a year over year increase in capital expenditures by $118.43 million, attributable in part to the Grafton Joint Venture, the Daewoo and Devonian Partnership, and the Troika Joint Venture entered into during the 2013 year, Bellatrix's continuing drilling success achieved in the Cardium and Notikewin resource plays, and additional sales volumes acquired through the acquisition of Angle in December, 2013.  Capital expenditures for the year ended December 31, 2013 were $303.7 million, compared to $185.3 million for the 2012 year.

Sales Volumes            
        Years ended December 31,
          2013 2012
Light oil and condensate   (bbls/d)     3,684 3,996
NGLs (excluding condensate)   (bbls/d)     2,612 1,441
Heavy oil   (bbls/d)     193 280
Total crude oil, condensate and NGLs   (bbls/d)     6,489 5,717
             
Natural gas   (mcf/d)     92,042 65,812
             
Total boe/d   (6:1)     21,829 16,686

During the 2013 year, Bellatrix posted a 100% success rate, drilling and/or participating in 80 gross (52.83 net) wells, resulting in 57 gross (41.22 net) Cardium light oil wells, 22 gross (10.86 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.

By comparison, during the 2012 year, Bellatrix drilled or participated in 34 gross (26.32 net) wells, which included 28 gross (21.32 net) Cardium light oil horizontal wells, 2 gross (2.0 net) Cardium condensate-rich natural gas wells, 1 gross (1.0 net) Duvernay natural gas horizontal well, and 3 gross (2.0 net) Notikewin/Falher natural gas horizontal wells.

Angle drilled and/or participated in a total of 39 gross (33.71 net) wells prior to the acquisition which were comprised of 29 gross (25.26 net) Cardium light oil wells, 8 gross (6.45 net) Mannville natural gas wells, and 2 gross (2.0 net) wells drilled in other minor formations.

For the year ended December 31, 2013, crude oil, condensate and NGL sales volumes increased by approximately 14%, averaging 6,489 bbl/d compared to 5,717 bbl/d in the 2012 year. The weighting towards crude oil, condensate and NGLs for the year ended December 31, 2013 was 30%, compared to 34% in the 2012 year.  The reduction in liquids weighting was a result of bringing on several high-productivity natural gas wells throughout 2012 and 2013.

Sales of natural gas averaged 92.0 Mmcf/d for the year ended December 31, 2013, compared to 65.8 Mmcf/d in the 2012 year, an increase of 40%.

For 2014, Bellatrix will continue to be active in drilling with 10 to 12 rigs operating in its two core resource plays, the Cardium oil and Mannville condensate rich gas, utilizing horizontal drilling multi-fracturing technology.  An initial net capital budget of $370 million has been set for fiscal 2014.   Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2014 budget is anticipated to provide 2014 average daily production of approximately 42,500 boe/d to 43,500 boe/d and an exit rate of approximately 47,000 boe/d.

Commodity Prices

Average Commodity Prices            
    Years ended December 31,
    2013   2012   % Change
             
Exchange rate (US$/CDN$)   0.9712   1.0009   (3)
             
Crude oil:            
WTI (US$/bbl)   98.05   94.14   4
Edmonton par - light oil ($/bbl)   93.24   86.53   8
Bow River - medium/heavy oil ($/bbl)   76.16   74.30   3
Hardisty Heavy - heavy oil ($/bbl)   65.48   64.99   1
Bellatrix's average prices ($/bbl)            
  Light crude oil and condensate   92.66   86.47   7
  NGLs (excluding condensate)   43.85   38.88   13
  Heavy crude oil   68.41   68.51   -
  Total crude oil and NGLs   72.29   73.59   (2)
  Total crude oil and NGLs (including risk management (1))   69.82   72.65   (4)
             
Natural gas:            
NYMEX (US$/mmbtu)   3.73   2.83   32
AECO daily index (CDN$/mcf)   3.17   2.39   33
AECO monthly index (CDN$/mcf)   3.16   2.40   32
Bellatrix's average price ($/mcf)   3.49   2.62   33
Bellatrix's average price (including risk management (1)) ($/mcf)   3.71   3.17   17
(1) Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.

For light oil and condensate, Bellatrix recorded an average price of $92.66/bbl before commodity price risk management contracts during 2013, 7% higher than the average price received in 2012.  In comparison, the Edmonton par price increased by 8% over the same period. The average WTI crude oil benchmark price increased by 4% between 2012 and 2013.  The average US$/CDN$ foreign exchange rate was 0.9712 for the year ended December 31, 2013, a decrease of 3% compared to an average rate of 1.0009 in 2012.

For NGLs (excluding condensate), Bellatrix recorded an average price of $43.85/bbl during 2013, an increase of 13% from the $38.88/bbl received in the comparative 2012 year.  The increase in NGL pricing 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 $68.41/bbl in the year ended December 31, 2013, relatively consistent with the $68.51/bbl realized in the 2012 year.  In comparison, the Bow River reference price increased by 3%, and the Hardisty Heavy reference price increased by 1% between the 2012 and 2013 year.  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 year ended December 31, 2013, the AECO daily reference price increased by 33%, and the AECO monthly reference price increased by approximately 32% compared to 2012. Bellatrix's natural gas average sales price before commodity price risk management contracts for the year ended December 31, 2013 increased by 33% to $3.49/mcf compared to $2.62/mcf in 2012. Bellatrix's natural gas average price after including commodity price risk management contracts for 2013 was $3.71/mcf, compared to $3.17 in 2012.

Revenue

Revenue before other income, royalties and commodity price risk management contracts for the year ended December 31, 2013 was $288.3 million, 33% higher than the $217.1 million realized in 2012. The increase in revenues was primarily due to increased natural gas and NGL sales volumes and higher realized prices for light oil and condensate, NGLs, and natural gas, partially offset by reduced crude oil and condensate sales volumes as well as lower heavy oil prices experienced in the 2013 year.

Revenue before other income, royalties and commodity price risk management contracts for crude oil and NGLs for the year ended December 31, 2013 increased from the comparative 2012 year by approximately 11%, resulting from higher NGL sales volumes in conjunction with increased light oil, condensate, and NGL prices, partially offset by lower crude oil and condensate sales volumes and reduced heavy oil prices when compared to the 2012 year.  In the 2013 year, total crude oil, condensate and NGL revenues contributed 59% of total revenue (before other income) compared to 71% in the 2012 year.  Light crude oil, condensate and NGL revenues in the year ended December 31, 2013 comprised 97% of total crude oil, condensate and NGL revenues (before other income), compared to a 95% composition realized in 2012.

Natural gas revenue before other income, royalties and commodity price risk management contracts for the year ended December 31, 2013 increased by approximately 85% compared to the 2012 year as a result of a 33% increase in realized gas prices before risk management in conjunction with an approximate 40% increase in sales volumes.

     
  Years ended December 31,
($000s) 2013 2012
Light crude oil and condensate 124,590 126,468
NGLs (excluding condensate) 41,804 20,504
Heavy oil 4,822 7,023
Crude oil and NGLs 171,216 153,995
Natural gas 117,094 63,143
Total revenue before other 288,310 217,138
Other income (1) 3,581 2,176
Total revenue before royalties and risk management 291,891 219,314
(1) Other income 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 12, 2014 is shown in the following tables:

Natural gas 

Average Volumes (GJ/d)        
             Q1 2014      Q2 2014      Q3 2014      Q4 2014
Fixed 91,056 110,000 110,000 110,000
         
Average Price ($/GJ AECO C)        
  Q1 2014 Q2 2014 Q3 2014 Q4 2014
Fixed 3.57 3.61 3.70 3.70

Crude oil and liquids      

Average Volumes (bbls/d)        
         
    Q1 2014 Q2 2014 Q3 2014 Q4 2014
Fixed (CDN$) 5,000 5,000 5,000 5,000
Fixed (US$) 1,000 1,000 1,000 1,000
         
         
Average Price ($/bbl WTI)        
         
         
  Q1 2014 Q2 2014 Q3 2014 Q4 2014
Fixed price (CDN$/bbl) 96.46 96.46 96.46 96.46
Fixed price (US$/bbl) 94.15 94.15 94.15 94.15

As of December 31, 2013, the fair value of Bellatrix's outstanding commodity contracts was a net unrealized liability of $16.9 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, 2013 and will differ 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, 2013 and 2012 as reflected in the Consolidated Statements of Comprehensive Income:

Commodity contracts            
($000s)   Crude Oil & Liquids   Natural Gas   2013 Total
Realized cash gain (loss) on contracts   (5,851)   7,710   1,859
Unrealized gain (loss) on contracts (1)   (4,112)   (13,015)   (17,127)
Total gain (loss) on commodity contracts   (9,963)   (5,305)   (15,268)
             
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
(1) Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts  during the year.

Royalties

For the year ended December 31, 2013, total royalties were $46.2 million compared to $38.8 million incurred in 2012.  Overall royalties as a percentage of revenue (after transportation costs) in the 2013 year were 16% compared with 18% in 2012.

The Company's minor heavy oil properties, principally consisting of the Frog Lake Alberta assets, are subject to high Crown royalty rates.  The Company's light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more recent wells in their early years of production under the Alberta royalty incentive program. This is offset by increased royalty rates on wells coming off initial royalty incentive rates and wells drilled on Ferrier lands with higher combined IOGC and GORR royalty rates.

       
Royalties by Commodity Type   Years ended December 31,
($000s, except where noted)   2013 2012
Light crude oil, condensate and NGLs   33,807 33,607
     $/bbl   14.71 16.89
     Average light crude oil, condensate and
       NGLs royalty rate (%)
  20 23
       
Heavy Oil   2,106 3,496
     $/bbl   29.90 34.11
     Average heavy oil royalty rate (%)   44 52
       
Natural Gas   10,304 1,653
     $/mcf   0.31 0.07
     Average natural gas royalty rate (%)   9 3
       
Total   46,217 38,756
$/boe   5.80 6.35
Average total royalty rate (%)   16 18
       
       
Royalties by Type      
    Years ended December 31,
($000s)   2013 2012
Crown royalties   15,051 11,518
Indian Oil and Gas Canada royalties   10,473 8,038
Freehold & GORR   20,693 19,200
Total                                       46,217 38,756
       
       
Expenses      
    Years ended December 31,
($000s)   2013 2012
Production   69,668 53,316
Transportation   7,014 4,978
General and administrative   16,214 14,272
Interest and financing charges (1)   12,488 9,834
Share-based compensation   4,960 3,219
(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)   2013 2012
Production   8.74 8.73
Transportation   0.88 0.82
General and administrative   2.03 2.34
Interest and financing charges   1.57 1.61
Share-based compensation   0.62 0.53

Production Expenses

For the year ended December 31, 2013, production expenses totaled $69.7 million ($8.74/boe), compared to $53.3 million ($8.73/boe) in 2012.  In 2013, production expenses increased overall and remained consistent on a per boe basis when compared to 2012.

Bellatrix is targeting production expenses of approximately $118.0 million ($7.50/boe) in the 2014 year, which is a reduction from the $8.74/boe production expenses incurred for the 2013 year.  This is based upon assumptions of estimated 2014 average production of approximately 42,500 boe/d to 43,500 boe/d, continued field optimization work and planned capital expenditures in producing areas which are anticipated to incur lower production expenses.

Production Expenses by Commodity Type    
  Years ended December 31,
($000s, except where noted) 2013 2012
Light crude oil, condensate and NGLs 24,768 21,840
      $/bbl 10.78 10.97
     
Heavy oil 1,071 1,555
      $/bbl 15.20 15.17
     
Natural gas 43,829 29,921
      $/mcf 1.30 1.24
     
Total                                     69,668 53,316
      $/boe 8.74 8.73
     
Total  69,668 53,316
Processing and other third party income (1) (3,581) (2,176)
Total after deducting processing and other third party income 66,087 51,140
$/boe 8.29 8.37
(1)  Processing and other third party income is included within petroleum and natural gas sales in the Consolidated Statements of Comprehensive Income.

Transportation

Transportation expenses for the year ended December 31, 2013 were $7.0 million ($0.88/boe), compared to $5.0 million ($0.82/boe) in 2012. Transportation expenses increased on an overall and per boe basis due primarily to light oil, condensate and NGL hauling required for some new wells added throughout 2013.

Operating Netback

Operating Netback - Corporate (before risk management)      
    Years ended December 31,
($/boe)   2013 2012
Sales   36.18 35.56
Transportation   (0.88) (0.82)
Royalties   (5.80) (6.35)
Production expense   (8.74) (8.73)
Operating netback   20.76 19.66

For the year ended December 31, 2013, the corporate operating netback (before commodity risk management contracts) was $20.76/boe compared to $19.66/boe in 2012.  The increased netback was primarily the result of higher commodity prices and lower royalties, partially offset by increased transportation expenses.  After including commodity risk management contracts, the corporate operating netback for the year ended December 31, 2013 was $20.99/boe compared to $21.51/boe in 2012. Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.

Operating Netback - Crude Oil, Condensate and NGLs (before risk management)      
    Years ended December 31,
($/bbl)   2013 2012
Sales   72.29 73.59
Transportation   (0.86) (0.98)
Royalties   (15.16) (17.73)
Production expense   (10.91) (11.18)
Operating netback   45.36 43.70

Operating netback for crude oil, condensate and NGLs averaged $45.36/bbl for the year ended December 31, 2013, a 4% increase from $43.70/bbl realized in 2012. Reduced production, royalties, and transportation expenses, partially offset by slightly lower average realized commodity prices resulted in the increase to operating netback for crude oil, condensate and NGLs.  After including commodity price risk management contracts, operating netback for crude oil, condensate, and NGLs for the year ended December 31, 2013 decreased to $42.89/bbl compared to $42.76/bbl in 2012.

Operating Netback - Natural Gas (before risk management)      
    Years ended December 31,
($/mcf)   2013 2012
Sales   3.49 2.62
Transportation   (0.15) (0.12)
Royalties   (0.31) (0.07)
Production expense   (1.30) (1.24)
Operating netback   1.73 1.19

Operating netback for natural gas in the year ended December 31, 2013 increased by 45% to $1.73/mcf, compared to $1.19/mcf realized in 2012, reflecting increased natural gas prices, partially offset by increased production, transportation, and royalty expenses.  After including commodity risk management contracts, operating netback for natural gas for the year ended December 31, 2013 increased to $1.96/mcf, which compared to $1.74/mcf in the 2012 year.

General and Administrative

General and administrative ("G&A") expenses (after capitalized G&A and recoveries) for the year ended December 31, 2013 were $16.2 million ($2.03/boe), compared to $14.3 million ($2.34/boe) realized in the 2012 year.  G&A expenses in the 2013 year were higher in comparison to 2012, which is reflective of higher compensation costs and additional office rent, partially offset by increased recoveries and capitalization. On a per boe basis, G&A for the year ended December 31, 2013 decreased by approximately 13% when compared to 2012. The decrease was primarily a result of higher average sales volumes, which more than offset the higher overall costs realized in 2013 versus 2012.

For 2014, the Company is anticipating G&A expenses after capitalization and recoveries to be approximately $25.0 million ($1.60/boe) based on estimated 2014 average production volumes of approximately 42,500 boe/d to 43,500 boe/d.

General and Administrative Expenses    
  Years ended December 31,
($000s, except where noted) 2013 2012
Gross expenses 29,145 21,170
Capitalized (5,343) (4,335)
Recoveries (7,588) (2,563)
G&A expenses 16,214 14,272
G&A expenses, per unit ($/boe) 2.03 2.34

Interest and Financing Charges

During the year ended December 31, 2013, Bellatrix recorded $12.5 million ($1.57/boe) of interest and financing charges related to bank debt and its convertible debentures, compared to $9.8 million ($1.61/boe) in 2012.  Bellatrix's convertible debentures were settled during September and October of 2013. The overall increase in interest and financing charges was primarily due to higher interest charges related to the Company's long-term debt as the Company carried a higher average debt balance in the 2013 year compared to 2012.  Bellatrix's total net debt at December 31, 2013 of $395.5 million includes $287.1 million of bank debt and the net balance of the working capital deficiency.

Interest and Financing Charges (1)    
  Years ended December 31,
($000s, except where noted) 2013 2012
Interest and financing charges 12,488 9,834
Interest and financing charges ($/boe) 1.57 1.61
(1) Does not include financing charges in relation to the Company's accretion of decommissioning liabilities

Debt to Funds Flow from Operations Ratio    
  Years ended December 31,
($000s, except where noted) 2013 2012
     
Shareholders' equity 903,874 381,106
     
Long-term debt 287,092 133,047
Convertible debentures (liability component) - 50,687
Working capital (excess) deficiency (2) 108,390 5,843
Total net debt (2) at year end 395,482 189,577
     
Debt to funds flow from operations (1) ratio (annualized) (3)    
Funds flow from operations (1) (annualized) 157,396 119,460
Funds flow from operations (1) (annualized, including Angle funds flow from
operations for the full October 1 to December 31, 2013 period)
203,985 119,460
Total net debt (2) at year end 395,482 189,577
Total net debt to periods funds flow from operations ratio (annualized) (3) 2.5x 1.6x
Total net debt to periods funds flow from operations ratio (annualized,  including
Angle funds flow from operations for the full October 1 to December 31, 2013 period) (3)
1.9x 1.6x
     
Net debt (2) (excluding convertible debentures) at year end 395,482 138,890
Net debt to periods funds flow from operations
ratio (annualized) (3)
2.5x 1.2x
Net debt to periods funds flow from operations
ratio (annualized,  including Angle funds flow from operations for the full
October 1 to December 31, 2013 period) (3)
1.9x 1.2x
     
Debt to funds flow from operations (1) ratio    
Funds flow from operations (1) for the year 143,459 111,038
Funds flow from operations (1) for the year (including Angle funds flow from operations
for the full October 1 to December 31, 2013 period)
155,106 111,038
Funds flow from operations (1) for the year (including Angle funds flow from operations for the full January 1
to December 31, 2013 period)
219,240 111,038
Total net debt (2)  to funds flow from operations for the year 2.8x 1.7x
Total net debt (2)  to funds flow from operations for the year (including Angle funds flow
from operations for the full October 1 to December 31, 2013 period)
2.5x 1.7x
     
Net debt (2) (excluding convertible debentures) to funds flow from operations for the year 2.8x 1.3x
Net debt (2) (excluding convertible debentures) to funds flow from operations for the year
(including Angle funds flow from operations for the full January 1 to December 31, 2013 period)
1.8x 1.3x
     

(1) 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, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs. 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. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company's 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. 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.
(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)     2013   2012
Total liabilities per financial statements     651,306   300,315
    Current liabilities included within working capital calculation      (255,903)   (53,327)
    Commodity contract liability - long term     -   (6,214)
    Decommissioning liabilities     (67,075)   (43,909)
    Finance lease obligation     (11,637)   (13,131)
    Deferred lease inducements     (2,565)   -
    Deferred taxes     (27,034)   -
           
Working Capital          
    Current assets     (128,800)   (52,447)
    Current liabilities     255,903   53,327
    Current portion of finance lease     (1,495)   (1,425)
    Current portion of deferred lease inducements     (285)   -
    Net commodity contract asset (liability)     (16,933)   6,388
      108,390   5,843
Total net debt     395,482   189,577
    Convertible debentures     -   (50,687)
Net debt     395,482   138,890

As at December 31, 2013 the Company's ratio of total net debt to annualized funds flow from operations (based on fourth quarter funds flow from operations) was 2.5 times.  The total net debt to annualized funds flow from operations ratio as at December 31, 2013 increased from that at December 31, 2012 of 1.6 times primarily due to an increase in total net debt resulting from the timing and expansion of the Company's 2013 capital expenditure program, and the acquisition of Angle in the fourth quarter of 2013. As at December 31, 2013 the Company's ratio of total net debt to annualized funds flow from operations (based on fourth quarter funds flow from operations, including funds flow from operations from Angle had the acquisition occurred effective October 1, 2013) was 1.9 times.  The Company continues to take a balanced approach to the priority use of funds flows.

Share-Based Compensation

Non-cash share-based compensation expense for the year ended December 31, 2013 was $5.0 million compared to $3.2 million in 2012. The increase in non-cash share-based compensation expense is primarily a result of a Deferred Share Unit Plan expense of $2.3 million (2012: $1.0 million) which resulted from the issuance of new grants during 2013, and the revaluation of outstanding grants to a higher share trading price at December 31, 2013 than at December 31, 2012, an expense of $1.0 million for Restricted Share Units issued during the year, and an expense of $0.5 million for Performance Share Units issued during the year. The increase is partially offset by higher capitalized share-based compensation of $1.7 million (2012: $1.6 million), and a lower expense net of forfeitures for the Company's outstanding share options of $2.9 million (2012: $3.8 million).

Depletion and Depreciation

Depletion and depreciation expense for the year ended December 31, 2013 was $85.8 million ($10.77/boe), compared to $75.7 million ($12.40/boe) recognized in 2012.  The decrease in depletion and depreciation expense 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, 2013 Bellatrix has included a total of $1.3 billion (2012: $524.6 million) for future development costs in the depletion calculation and excluded from the depletion calculation a total of $69.0 million (2012: $37.2 million) for estimated salvage.


Depletion and Depreciation    
  Years ended December 31,
($000s, except where noted) 2013 2012
Depletion and Depreciation 85,829 75,720
Per unit ($/boe) 10.77 12.40

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.  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.

The impairment test uses, but is not limited to, an 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.

2013 Impairment

As at December 31, 2013, Bellatrix determined there were no impairment indicators requiring an impairment test to be performed.

2012 Impairment

During the year ended December 31, 2012, Bellatrix performed an impairment test using value-in-use 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 impairment loss of $14.8 million, using future cash flows at between a 10% - 20% discount rate. The impairment indicators were predominantly weak natural gas prices.

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. This report 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.

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, 2013, the Company recognized a deferred income tax expense of $19.5 million, compared to a $10.1 million in the 2012 year.

At December 31, 2013, the Company had a total deferred tax liability balance of $27.0 million.

At December 31, 2013, Bellatrix had approximately $1.2 billion in tax pools available for deduction against future income as follows:

             
($000s)     Rate %   2013   2012
Intangible resource pools:            
      Canadian exploration expenses   100   99,000   56,200
      Canadian development expenses   30   691,500   358,700
      Canadian oil and gas property expenses   10   80,200   40,400
      Foreign resource expenses   10   900   800
Attributed Canadian Royalty Income   (Alberta) 100   -   16,100
Alberta non-capital losses greater than
   Federal non-capital losses
  (Alberta) 100   16,100   -
Undepreciated capital cost (1)   6 - 55   224,900   98,000
Non-capital losses (expire through 2027)   100   94,500   10,000
Financing costs   20 S.L.   15,600   3,300
        1,222,700   583,500

(1) Approximately $207 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

As detailed previously in this MD&A, funds flow from operations is a term that does not have any standardized meaning under GAAP.  Bellatrix's method of calculating funds flow from operations may differ from that of other companies, and accordingly, may not be comparable to measures used by other companies.   Funds flow from operations is calculated as cash flow from operating activities before decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.

Reconciliation of Cash Flow from Operating Activities and Funds Flow from Operations    
  Years ended December 31,
($000s) 2013 2012
Cash flow from operating activities 128,458 109,328
Decommissioning costs incurred 1,057 635
Transaction costs 5,344 -
Change in non-cash working capital 8,600 1,075
Funds flow from operations 143,459 111,038

Bellatrix's cash flow from operating activities of $128.5 million ($1.14 per basic share and $1.11 per diluted share) for the year ended December 31, 2013 increased by 17% from the $109.3 million ($1.02 per basic share and $0.95 per diluted share) generated in 2012.  Bellatrix generated funds flow from operations of $143.5 million ($1.27 per basic share and $1.24 per diluted share) for the year ended December 31, 2013, an increase of 29% from $111.0 million ($1.03 per basic share and $0.96 per diluted share) for 2012.  The increase in funds flow from operations was primarily due to increased light oil, condensate, NGL, and natural gas prices positively impacting revenues and netbacks, partially offset by a higher net realized loss on commodity contracts, increased general and administrative expenses, operating, transportation, and royalties expenses, and the impact of lower heavy oil commodity prices.

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 fair market value of the contract over its entire term and are included in the calculation of net profit.

A net profit of $71.7 million ($0.63 per basic share and $0.62 per diluted share) was recognized for the year ended December 31, 2013, compared to a net profit of $27.8 million ($0.26 per basic share and $0.25 per diluted share) in 2012.  The higher net profit recorded in the year ended December 31, 2013 compared to 2012 was primarily the result of higher funds from operating activities as noted above, a gain on property dispositions compared to a loss recognized in 2012, a gain on corporate acquisition recognized in 2013, and impairment expenses recognized during 2012 but not in 2013, partially offset by increased depletion and depreciation, stock-based compensation, and deferred tax expenses, a lower realized gain on commodity contracts, and an unrealized loss on commodity contracts in 2013 compared to an unrealized gain recognized in 2012.

Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit    
  Years ended December 31,
($000s, except per share amounts) 2013 2012
Cash flow from operating activities 128,458 109,328
     Basic   ($/share) 1.14 1.02
     Diluted ($/share) 1.11 0.95
Funds flow from operations 143,459 111,038
     Basic   ($/share) 1.27 1.03
     Diluted ($/share) 1.24 0.96
Net profit 71,675 27,771
     Basic   ($/share) 0.63 0.26
     Diluted ($/share) 0.62 0.25

Capital Expenditures

Bellatrix invested $303.7 million in capital expenditures during the year ended December 31, 2013, compared to $185.3 million in 2012.

Capital Expenditures      
    Years ended December 31,
($000s)   2013 2012
Lease acquisitions and retention   11,190 8,303
Geological and geophysical   140 290
Drilling and completion costs   211,912 118,783
Facilities and equipment   57,767 36,811
    Exploration and development (1)   281,009 164,187
Corporate (2)   9,270 195
Property acquisitions   13,380 20,966
   Total capital expenditures - cash   303,659 185,348
Property dispositions - cash   (70,936) (6,660)
    Total net capital expenditures - cash   232,723 178,688
Capital lease additions - non-cash   - 10,000
Corporate acquisition - non-cash   595,891 -
Adjustment on property acquisition - non-cash   - 16,160
Other - non-cash (3)   12,187 (285)
    Total non-cash   608,078 25,875
Total net capital expenditures   840,801 204,563
(1) Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the year.
(2) Corporate includes office leasehold improvements, furniture, fixtures and equipment before recoveries realized from landlord lease inducements.
(3) Other includes non-cash adjustments for the current year's decommissioning liabilities and share based compensation. 

During the 2013 year, Bellatrix posted a 100% success rate, drilling and/or participating in 80 gross (52.83 net) wells, resulting in 57 gross (41.22 net) Cardium oil wells, 22 gross (10.86 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.

By comparison, Bellatrix drilled or participated in 34 gross (26.32 net) wells during 2012, which included 28 gross (21.32 net) Cardium light oil horizontal wells, 2 gross (2.0 net) Cardium condensate-rich natural gas wells, 1 gross (1.0 net) Duvernay natural gas horizontal well, and 3 gross (2.0 net) Notikewin/Falher natural gas horizontal wells.

During 2013, the Company installed a 25 km pipeline to the MBL Gas Plant which facilitated processing of an additional 85 mmcf/d capacity.  The Company also installed six field compressors totaling 9,700 hp and capable of handling 75 mmcf/d.   Additionally, the Company installed approximately 45 km of large diameter group pipelines during 2013.

During the third quarter of 2013, Bellatrix relocated to a new corporate office location.  Leasehold improvements and furniture and fixture additions related to the move resulted in approximately $8.6 million of corporate capital additions (before landlord lease inducements) during the third and fourth quarters of 2013.

The $303.7 million capital program for the year ended December 31, 2013 was financed from a combination of funds flow from operations, bank debt, proceeds from dispositions of $70.9 million, and proceeds from the $175.0 million bought deal financing.

Based on the current economic conditions and Bellatrix's operating forecast for 2014, the Company budgets a net capital program of $370 million funded from the Company's cash flows and to the extent necessary, bank indebtedness.  The 2014 capital budget is expected to be directed primarily towards horizontal drilling and completions activities in the Cardium and Mannville formations.

During the year ended December 31, 2013, Bellatrix realized cash proceeds on dispositions of $70.9 million.  Of these proceeds, $51.2 million were related to the disposition of properties in the Baptiste area of West Central Alberta to Daewoo and Devonian.  A total net gain on dispositions of $42.5 million was recognized for the year ended December 31, 2013, of which $29.1 million was related to the Daewoo and Devonian disposition.  The remainder of the net gain on dispositions was related to a gain on Grafton Joint Venture wells and Troika Joint Venture wells completed during the year ended December 31, 2013, as well as other minor dispositions and swaps which occurred during the year.

During the year ended December 31, 2013, the Company increased its working interest in certain Cardium and Notikewin/Falher lands and production in the Willesden Green (Baptiste) area of Alberta through the acquisition of additional working interests from several companies for a total combined net purchase price of $10 million.

Decommissioning Liabilities

At December 31, 2013, Bellatrix has recorded decommissioning liabilities of $67.1 million, compared to $43.9 million at December 31, 2012, for future abandonment and reclamation of the Company's properties.  For the year ended December 31, 2013, decommissioning liabilities increased by a net $23.2 million as a result of $3.4 million incurred on development activities, $12.1 million incurred from corporate and property acquisitions, $8.5 million resulting from changes in estimates, and $0.9 million as a result of charges for the unwinding of the discount rates used for assessing liability fair values, partially offset by a $0.6 million decrease  related to dispositions, and a decrease of $1.1 million for liabilities settled during the period.  The $8.5 million increase as a result of changes in estimates was related to increased cost estimates for abandonment and reclamation of the Company's core and non-core operating areas as a result of actual abandonment costs incurred and revised industry guidance.  In addition, the Company revised the timing of future decommissioning cash flows to better reflect the anticipated abandonment timelines.

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 upon 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 decreased.

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 and optimizing capital investments - which it seeks to attain 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. Recent market conditions have resulted in Bellatrix experiencing recent upward trends in natural gas, light oil and condensate, and NGL pricing.

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 upon its 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 currently sells substantially all of its production to eight primary purchasers under standard industry sale and payment terms.  The most significant 60 day exposure to a single counterparty is approximately $16.5 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 partners and 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 $395.5 million at December 31, 2013 have increased by $205.9 million from $189.6 million at December 31, 2012, primarily as a consequence of an increase in a working capital deficiency and bank debt as the Company executed its capital program for the 2013 year. Included within the working capital deficiency is $99.4 million in advances from joint venture partners representing drilling obligations predominantly under the Company's joint venture obligations with TCA and Grafton, and under the Daewoo and Devonian Partnership.  Total net debt excludes unrealized commodity contract assets and liabilities, deferred taxes, finance lease obligations, deferred liabilities and decommissioning liabilities, and for the year ended December 31, 2012, it included the liability component of convertible debentures.

Funds flow from operations represents 47% of the funding requirements for Bellatrix's capital expenditures for the year ended December 31, 2013.

As of December 31, 2013, the Company's credit facilities are available on an extendible revolving term basis and consist of a $50 million operating facility provided by a Canadian bank and a $450 million syndicated facility provided by nine financial institutions. Bellatrix's credit facility was redetermined by its lenders to $500 million concurrent with the closing of the acquisition of Angle on December 11, 2013.

Amounts borrowed under the credit facilities will bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.00% to 3.50%, depending on the type of borrowing and the Company's debt to cash flow ratio.  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 credit facilities are secured by a $1 billion 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.

The revolving period for the revolving term credit facility will end on June 24, 2014, 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 24, 2014.  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, 2014.

As at December 31, 2013, approximately $212.4 million or 42% of unused and available bank credit under its credit facilities was available to fund Bellatrix's ongoing capital spending and operational requirements.

On September 4, 2013, the Company announced the issuance of a notice of redemption to holders of its then outstanding $55.0 million convertible debentures, with the redemption date set as October 21, 2013.  During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company.  A reduction to the deficit of $1.3 million was recognized in connection with the settlement of the convertible debentures during the year ended December 31, 2013.

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 2014 capital program of $370 million by utilizing cash flow, proceeds from asset dispositions, and to the extent necessary, bank indebtedness.

As at February 28, 2014, Bellatrix had outstanding a total of 10,561,007 options exercisable at an average exercise price of $4.89 per share and 171,511,226 common shares. 

Related Party Transactions

Previous to 2013, 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, 2013, Bellatrix committed to drill 10 gross (5.7 net) wells pursuant to farm-in agreements.  Bellatrix expects to satisfy these drilling commitments at an estimated cost of approximately $20.1 million.

In addition, Bellatrix entered into two joint operating agreements during the 2011 year and an additional joint operation 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 Operating Agreement Feb. 1, 2011 Aug. 4, 2011 Dec. 14, 2012
Commitment 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, 2013 - 12 7
Remaining estimated total cost ($000s) $       - $   42.0 $  24.5

Bellatrix also has certain drilling commitments relating to the Grafton Joint Venture, the Daewoo and Devonian Partnership, and the Troika Joint Venture previously discussed.  In meeting the drilling commitments under these agreements, Bellatrix will satisfy some of the drilling commitments under the joint operating agreements described above.

       
Agreement Grafton Daewoo and
Devonian
Troika
Commitment Term 2013 to 2015 2013 to 2016 2013 to 2014
Minimum total wells (gross)(1) 58 70 63
Minimum total wells (net)(1) 10.44 35.0 31.5
Estimated total cost  ($000s) (gross)(1) $ 244.0 $ 200.0 $ 240.0
Estimated total cost  ($000s) (net)(1) $   44.0 $ 100.0 $ 120.0
Remaining wells to drill at December 31, 2013 (gross) 46 51 42
Remaining wells to drill at December 31, 2013 (net) 8.2 25.6 21.0
Remaining estimated total cost ($000s) (gross) $ 192.3 $ 198.3 $ 160.0
Remaining estimated total cost ($000s) (net) $   34.6 $   99.2 $   80.0
(1) Gross and net estimated total cost values and gross and net minimum total wells for the Troika and Grafton Joint Ventures represent Bellatrix's total capital and well commitments pursuant to the Troika and Grafton Joint Venture agreements.  Gross and net minimum total wells for the Daewoo and Devonian Partnership represent Bellatrix's total well commitments pursuant to the Daewoo and Devonian Partnership agreement.  Gross and net estimated total cost values for the Daewoo and Devonian Partnership represent Bellatrix's estimated cost associated with its well commitments under the Daewoo and Devonian Partnership agreement.

The Company had the following liabilities as at December 31, 2013:

           
Liabilities ($000s) Total < 1 Year 1-3 Years 3-5 Years More than
5 years
Accounts payable and accrued liabilities (1) $  137,465 $   137,465 $             - $            - $            -
Advances from joint venture partners 99,380 99,380 - - -
Long-term debt - principal (2) 287,092 - 287,092 - -
Commodity contract liability 17,278 17,278 - - -
Decommissioning liabilities (3) 67,075 - 2,198 3,361 61,516
Finance lease obligation 13,132 1,495 3,208 2,708 5,721
Deferred lease inducements 2,850 285 570 570 1,425
Total $  624,272 $   255,903 $  293,068 $    6,639 $   68,662
    (1) Includes $0.7 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)  Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over the life of the Company's properties (between 2016 and 2063).

  

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, 2013.

The Company's commitment for office space as at December 31, 2013 is as follows:

       
($000s)
   Year  
Gross
Amount
Recoveries Net amount
    2014 $   4,562 $  (1,014) $   3,548
    2015 3,094 - 3,094
    2016 3,094 - 3,094
    2017 3,094 - 3,094
    2018 2,911 - 2,911
    More than 5 years 12,206 - 12,206

 

Business Prospects and 2014 Year Outlook

Bellatrix continues to develop its core assets and conduct exploration programs utilizing its large inventory of geological prospects.

For the 2014 year, Bellatrix will continue to be active in drilling with 10 to 12 rigs operating in its two core resource plays, the Cardium oil and Mannville condensate rich gas, utilizing horizontal drilling multi-fracturing technology.  During the first quarter of 2014, Bellatrix plans jointly with the Blaze Gas Plant to install 60 km of pipeline to the Blaze Gas Plant from the Ferrier area to facilitate access to 120 mmcf/d capacity.  In the third quarter of 2014, Bellatrix plans to install a 20 km pipeline to the Brazeau Gas Plant in order to access an additional 40-50 mmcf/d of capacity, and to build two oil batteries with 5,000 bbls/d of processing capacity. Additionally, throughout 2014 Bellatrix intends to install 21 field compressors totalling 30,500 hp and capable of handling 245 mmcf/d, and to install more than 60 km of large diameter group pipelines. A new Bellatrix gas plant is planned to be built in the Alder Flats to be in service July, 2015.  The new plant is anticipated to provide 110 mmcf/d capacity, 99% C3 Recovery and 100% C4+ Recovery, with the potential to double the capacity in 2016.

An initial net capital budget of $370 million has been set for fiscal 2014.   Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2014 budget is anticipated to provide 2014 average daily production of approximately 42,500 boe/d to 43,500 boe/d and an exit rate of approximately 47,000 boe/d.

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.  The effective date of the new standard has been deferred indefinitely.  The extent of the impact of the adoption of IFRS 9 has not yet been determined.

Amendments to "Offsetting Financial Assets and Financial Liabilities" addressed within IAS 32 - "Financial Instruments: Presentation", which provides guidance regarding when it is appropriate and permissible for an entity to disclose offsetting financial assets and financial liabilities on a net basis.  The amendments to this standard are effective for annual periods beginning on or after January 1, 2014. The extent of the impact of the adoption of IAS 32 amendments has not yet been determined.

IFRIC 21 - "Levies", which establishes guidelines for the recognition and accounting treatment of a liability relating to a levy imposed by a government.  This standard is effective for annual periods beginning on or after January 1, 2014.  The extent of the impact of the adoption of IFRIC 21 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 the rights to 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.

Environmental Regulation

The oil and natural gas industry is currently subject to regulation pursuant to a variety of provincial and federal environmental legislation, all of which is subject to governmental review and revision from time to time.  Such legislation provides for, among other things, restrictions and prohibitions on the spill, 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 with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, 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, 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 Judgments and 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.

Critical Accounting Judgments

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.

Identification of CGUs

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.

Joint Arrangements

Judgement is required to determine when the Company has joint control over an arrangement. In establishing joint control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the returns of the arrangement, such as the capital and operating activities of the arrangement.

Once joint control has been established, judgement is also required to classify as a joint arrangement. The type of joint arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its structure, legal form, and terms agreed upon by the parties sharing control. An arrangement where the controlling parties have rights to the assets and revenues and obligations for the liabilities and expenses is classified as a joint operation.

Impairment Indicators

Judgment is required to assess when impairment indicators exist and impairment testing is required. In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimate of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land and other relevant assumptions.

Critical Estimates and Assumptions

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.

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 President and Chief Executive Officer ("CEO") and Executive Vice President, Finance and Chief Financial Officer ("CFO") 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. Based on the evaluation, the officers concluded that Bellatrix's disclosure controls and procedures were effective as at December 31, 2013.

Management's Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting, which is a process designed by, or designed under the supervision of, our President and CEO and our Executive Vice President, Finance and CFO, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for the external purposes in accordance with GAAP.

Under the supervision and with the participation of management, including our CEO and our CFO, an evaluation of the effectiveness of the Company's internal control over financial reporting was conducted as of December 31, 2013 based on the criteria described in "Internal Control - Integrated Framework" issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this assessment, management determined that, as of December 31, 2013, the Company's internal control over financial reporting was effective.

Bellatrix acquired 100% of the issued and outstanding common shares and 5.75% convertible unsecured subordinated debentures of Angle Energy Inc. ("Angle") on December 11, 2013, as more fully described in note 6 of the Company's notes to the audited consolidated financial statements as at and for the year ended December 31, 2013.  This business was excluded from management's evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2013, due to the proximity of the acquisition to year-end.  For the quarter and year ended December 31, 2013, total revenue attributable to Angle was approximately 12% and 3%, respectively, of the consolidated total revenues as reported in the Company's audited consolidated financial statements. For the quarter and year ended December 31, 2013, a net profit before tax of $1.7 million and $1.7 million, respectively, was attributable to Angle as compared to pre-tax earnings of $24.8 million and $91.2 million, respectively, for the consolidated entity.

Additionally, at December 31, 2013, current assets and current liabilities attributable to Angle were approximately 19% and 13% of consolidated current assets and liabilities, respectively, and its non-current assets and non-current liabilities attributable to Angle were approximately 42% and 52% of consolidated non-current assets and non-current liabilities, respectively.

The Company is required to disclose herein any change in the Company's internal control over financial reporting that occurred during the year ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.  There has been no change in our internal control over financial reporting that occurred during the year ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 

Limitations of the Effectiveness of Controls

It should be noted that a control system, 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 controls and procedures and internal controls over financial reporting will prevent all errors or fraud.

CEO and CFO Certifications

Our President and CEO and our Executive Vice President, Finance and CFO have attested to the quality of the public disclosure in our fiscal 2013 reports filed with the Canadian securities regulators and the SEC, and have filed certifications with them.

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 2013 and average production volumes of 23,968 boe/d during that period, as well as the same level of debt outstanding as at December 31, 2013.  Diluted weighted average shares are based upon the fourth quarter of 2013.  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 2,300 0.02
Change of $0.10/ mcf 3,200 0.02
Change of US $0.01 CDN/ US exchange rate 1,400 0.01
Change in prime of 1% 2,900 0.02
    (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 2013 and 2012.

         
2013 - Quarter ended (unaudited)
($000s, except per share amounts)
March 31 June 30 Sept. 30 Dec. 31
Revenues before royalties and risk management 65,543 74,564 68,329 83,455
Cash flow from operating activities 35,527 29,611 25,069 38,025
Cash flow from operating activities per share        
  Basic $0.33 $0.27 $0.23 $0.30
  Diluted $0.30 $0.25 $0.21 $0.29
Funds flow from operations (1) 37,545 36,563 30,002 39,349
Funds flow from operations per share (1)        
  Basic $0.35 $0.34 $0.28 $0.31
  Diluted $0.32 $0.31 $0.25 $0.30
Net profit 4,561 15,466 29,453 22,195
Net profit per share        
  Basic $0.04 $0.14 $0.27 $0.17
  Diluted $0.04 $0.13 $0.25 $0.17
Net capital expenditures (cash) 91,614 46,700 49,452 99,199
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
(1)      Refer to "Additional GAAP Measures" in respect of the term "funds flow from operations" and "funds flow from operations per share".

 

The quarterly results for 2013 compared to 2012 were positively impacted by increased production resulting from the significant expansion of Bellatrix's 2013 drilling program and higher overall commodity prices realized during the 2013 quarters compared to the 2012 quarters.

During the first quarter of 2013, the Company spent $91.6 million in capital expenditures, compared to $74.1 million in the first quarter of 2012.  The Company drilled or participated in 21 gross (17.08 net) wells in the first quarter of 2013, compared to 13 gross (10.72 net) wells in the comparative 2012 quarter. Increased sales volumes of 19,343 boe/d in the first quarter of 2013 compared to 15,900 boe/d in the first quarter of 2012 contributed to increased total revenue before other income of $64.9 million in the first quarter of 2013, compared to $57.7 million in the first quarter of 2012. The increase resulted from the 2012 and first quarter 2013 drilling programs, in conjunction with stronger natural gas and light oil and condensate prices, offset slightly by depressed NGL and heavy oil pricing.

In the second quarter of 2013, the Company closed the Grafton Joint Venture, under which Grafton agreed to contribute 82%, or $100 million, to the $122 million joint venture to participate in an expected 29 Notikewin/Falher wells in exchange for 54% of the Company's working interest until payout under the terms of the joint venture.  In the second quarter of 2013, the Company spent $46.7 million (2012: $18.3 million) in capital expenditures, and drilled 5 gross (5.00 net) wells, compared to 2 gross (1.72 net) wells in the same period in 2012.  Sales volumes increased by 33% to 22,102 boe/d in the second quarter of 2013, compared to 16,569 boe/d in the second quarter of 2012.

The Company completed several major transactions during the third quarter of 2013.  During September 2013, an asset sale associated with the Daewoo and Devonian Partnership arrangement was closed, resulting in gross proceeds of $52.5 million (subject to closing adjustments).  Additionally during September 2013, Grafton elected to exercise an option to increase its committed capital investment by an additional $100 million on the same terms and conditions as the Grafton Joint Venture which closed during the second quarter of 2013.  In the third quarter of 2013, the Company spent $49.5 million on capital expenditures compared to $39.8 million in the third quarter of 2012. In the third quarter of 2013, Bellatrix drilled 19 gross (9.40 net) wells, compared to 9 gross (7.71 net) wells in the third quarter of 2012.

Fourth quarter 2013 results are compared in detail to fourth quarter 2012 results throughout this MD&A.

Overall, the Company's cash flows were positively impacted primarily due to increased sales volumes and cash flows resulting from the success and execution of the Company's 2013 drilling program and stronger natural gas commodity prices.

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, 2013 and for comparative 2012 and 2011 years.

       
Years ended December 31,
($000s, except per share amounts)
2013 2012 2011
Revenues (before royalties and risk management) 291,891 219,314 202,318
Funds flow from operations (1) 143,459 111,038 94,237
Funds flow from operations per share (1)      
    Basic $1.27 $1.03 $0.91
    Diluted $1.24 $0.96 $0.87
Cash flow from operating activities 128,458 109,328 98,192
Cash flow from operating activities per share      
    Basic $1.14 $1.02 $0.95
    Diluted $1.11 $0.95 $0.87
Net profit (loss) 71,675 27,771 (5,949)
Net profit (loss) per share      
    Basic $0.63 $0.26 ($0.06)
    Diluted $0.62 $0.25 ($0.06)
Net capital expenditures - cash 232,723 178,688 175,358
Total assets 1,555,180 681,421 580,422
Total net debt (1) 395,482 189,577 119,250
Non-current financial liabilities      
   Future income taxes 27,034 - -
   Decommissioning liabilities 67,075 43,909 45,091
Sales volumes (boe/d) 21,829 16,686 11,954
   
(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."

Detailed discussions on variations from 2013 annual results to 2012 annual results are contained throughout this MD&A.

Sales volumes increased by 40% to 16,686 boe/d in 2012 from 11,954 boe/d in 2011, largely as a result of an increased capital program of $185.3 million in 2012, compared to $179.6 million in 2011, and drilling success achieved in the Cardium and Notikewin resource plays. As a result of the significant increase in sales volumes between the years, revenues before royalties and risk management increased to $219.3 million in 2012, compared to $202.3 million realized in 2011, despite reductions in commodity prices between the years. Cash flows were impacted by the increased sales volumes, decreased commodity prices, and lower operating costs, transportation costs, and royalty expenses per boe between the years.

BELLATRIX EXPLORATION LTD.      
CONSOLIDATED BALANCE SHEETS
(expressed in Canadian dollars)

As at December 31,
     
($000s)                                                                               2013 2012
       
ASSETS      
Current assets      
  Restricted cash   $       38,148 $                 -
  Accounts receivable (note 22)       80,306      40,792
  Deposits and prepaid expenses   10,001 4,136
  Commodity contract asset (note 22)   345 7,519
      128,800 52,447
Exploration and evaluation assets (note 7)   132,971 38,177
Property, plant and equipment (note 8)   1,293,409 589,759
Deferred taxes (note 16)   - 1,038
Total assets   $  1,555,180 $     681,421
         
LIABILITIES       
Current liabilities      
  Accounts payable and accrued liabilities   $     137,465 $       44,223
  Advances from joint venture partners   99,380 6,548
  Current portion of finance lease obligation (note 11)   1,495 1,425
  Current portion of deferred lease inducements   285 -
  Commodity contract liability (note 22)   17,278 1,131
      255,903 53,327
         
Commodity contract liability (note 22)   - 6,214
Long-term debt (note 9)   287,092 133,047
Convertible debentures (note 10)   - 50,687
Finance lease obligation (note 11)   11,637 13,131
Deferred lease inducements   2,565 -
Decommissioning liabilities (note 12)   67,075 43,909
Deferred taxes (note 16)   27,034 -
Total liabilities   651,306 300,315
       
SHAREHOLDERS' EQUITY      
  Shareholders' capital (note 13)   824,065 371,576
  Equity component of convertible debentures (note 10)   - 4,378
  Contributed surplus   38,958 37,284
  Retained earnings (deficit)   40,851 (32,132)
Total shareholders' equity   903,874 381,106
Total liabilities and shareholders' equity    $   1,555,180 $     681,421

 
 
COMMITMENTS (note 21)
 
See accompanying notes to the consolidated financial statements.

BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(expressed in Canadian dollars)

For the years ended December 31,
($000s, except per share amounts)  2013 2012
       
REVENUES    
  Petroleum and natural gas sales $  288,310 $  217,138
  Other income 3,581 2,176
  Royalties (46,217) (38,756)
  Total revenues 245,674 180,558
       
  Realized gain on commodity contracts 1,859 11,269
  Unrealized gain (loss) on commodity contracts (17,127) 10,806
    230,406 202,633
       
EXPENSES    
  Production 69,668 53,316
  Transportation 7,014 4,978
  General and administrative (note 18) 16,214 14,272
  Transaction costs (note 6) 5,344 -
  Share-based compensation (note 14) 4,960 3,219
  Depletion and depreciation (note 8) 85,829 75,720
  Gain on property acquisition (note 6) - (16,160)
  Loss (gain) on property dispositions and swaps (note 8) (42,494) 4,113
  Gain on corporate acquisition (note 6) (20,630) -
  Impairment loss on property, plant and equipment (note 8) - 14,820
    125,905 154,278
       
       
NET PROFIT BEFORE FINANCE AND TAXES 104,501 48,355
     
  Finance expenses (note 17) 13,343 10,517
     
NET PROFIT BEFORE TAXES 91,158 37,838
       
TAXES    
  Deferred tax expense (note 16) 19,483 10,067
       
NET PROFIT AND COMPREHENSIVE INCOME $  71,675 $  27,771
     
       
       
Net profit per share (note 20)    
  Basic $0.63 $0.26
  Diluted $0.62 $0.25
   
See accompanying notes to the consolidated financial statements.  

BELLATRIX EXPLORATION LTD.  
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY  
(expressed in Canadian dollars)

For the years ended December 31,
($000s)       2013 2012
           
SHAREHOLDERS' CAPITAL (note 13)        
    Common shares        
  Balance, beginning of year     $  371,576 $  370,048
  Issued for cash on equity issue     175,000 -
  Share issue costs on equity issue, net of tax     (7,020) -
  Issued for the Angle acquisition (note 6)     225,221 -
  Share issue costs on the Angle acquisition, net of tax     (576) -
  Issued on settlement of convertible debentures (note 10)     55,568 -
  Issued for cash on exercise of share options     3,088 1,093
  Contributed surplus transferred on exercised options     1,208 435
  Balance, end of year     824,065 371,576
           
EQUITY COMPONENT OF CONVERTIBLE DEBENTURES (note 10)        
  Balance, beginning of year     4,378 4,378
  Adjustment for settlement of convertible debentures (note 10)     (4,378) -
  Balance, end of year     - 4,378
           
CONTRIBUTED SURPLUS (note 14)         
  Balance, beginning of year     37,284 33,882
  Share-based compensation expense     3,045 4,024
  Adjustment of share-based compensation expense             
     for forfeitures of unvested share options     (163) (187)
  Transfer to share capital for exercised options     (1,208) (435)
  Balance, end of year     38,958 37,284
           
RETAINED EARNINGS (DEFICIT)        
  Balance, beginning of year     (32,132) (59,903)
  Adjustment for settlement of convertible debentures (note 10)     1,308 -
  Net profit     71,675 27,771
  Balance, end of year     40,851 (32,132)
           
           
TOTAL SHAREHOLDERS' EQUITY     $  903,874 $  381,106
           
See accompanying notes to the consolidated financial statements.

BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENT OF CASH FLOWS
(expressed in Canadian dollars)

For the years ended December 31,
($000s) 2013 2012
       
Cash provided by (used in):    
     
CASH FLOW FROM (USED IN) OPERATING ACTIVITIES    
Net profit $    71,675 $   27,771
Adjustments for:    
  Depletion and depreciation 85,829 75,720
  Finance expenses (note 17) 2,151 2,294
  Interest paid on redemption of convertible debentures 14 -
  Share-based compensation (note 14) 4,960 3,219
  Unrealized (gain) loss on commodity contracts 17,127 (10,806)
  Gain on property acquisitions (note 8) - (16,160)
  Loss (gain) on property dispositions and swaps (note 8) (42,494) 4,113
  Gain on corporate acquisition (note 6) (20,630) -
  Impairment loss on property, plant and equipment (note 8) - 14,820
  Deferred tax expense (note 16) 19,483 10,067
  Decommissioning costs incurred (1,057) (635)
  Change in non-cash working capital (note 15) (8,600) (1,075)
    128,458 109,328
       
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES    
  Issuance of share capital (note 13) 178,088 1,093
  Issue costs on share capital (10,128) -
  Advances from loans and borrowings 1,022,835 528,529
  Repayment of loans and borrowings (1,051,917) (452,183)
  Repayment of Angle convertible debentures (note 6) (62,400) -
  Obligations under finance lease (note 11) (1,425) (560)
  Deferred lease inducements 2,565  -
  Change in non-cash working capital (note 15) (960) (55)
    76,658 76,824
       
CASH FLOW FROM (USED IN) investing ACTIVITIES    
  Expenditure on exploration and evaluation assets (10,391) (17,118)
  Additions to property, plant and equipment (293,268) (168,230)
  Proceeds on sale of property, plant and equipment (note 8) 70,936 6,660
  Cash portion of Angle Energy acquisition (69,701) -
  Change in non-cash working capital (note 15) 97,308 (7,464)
    (205,116) (186,152)
       
  Change in cash - -
       
  Cash, beginning of year - -
       
  Cash, end of year $             -    $           -
       
Cash paid:    
   Interest   $     7,609     $    5,676
   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 oil and gas company.

2. BASIS OF PREPARATION

a. Statement of compliance

These consolidated financial statements ("financial statements") were authorized by the Board of Directors on March 12, 2014.  The Company prepared these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS").

b.  Change in accounting policies

On January 1, 2013, the Company adopted new standards with respect to consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests in other entities (IFRS 12), fair value measurements (IFRS 13), and amendments to financial instrument disclosures (IFRS 7).  The adoption of these standards had no impact on the amounts recorded in the consolidated financial statements as at January 1, 2013 or on the comparative periods.

c. 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.

Bellatrix is a partner of the following joint arrangements, which have been classified under IFRS as joint operations. This classification is on the basis that the arrangement is not conducted through a separate legal entity and the partners are legally obligated to pay their share of costs incurred and take their share of output produced from the various production areas. For purposes of disclosure throughout the financial statements, Bellatrix has referred to these arrangements by the common oil and gas industry term of joint ventures.

Grafton Joint Venture - Bellatrix has a joint venture (the "Grafton Joint Venture") with Grafton Energy Co I Ltd. ("Grafton") in the Willesden Green and Brazeau areas of West-Central Alberta, whereby Grafton will contribute 82% or $200 million to the joint venture to participate in an expected 58 Notikewin/Falher and Cardium well program.  Under the agreement, Grafton will earn 54% of Bellatrix's working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix's working interest ("WI") after payout.  At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty ("GORR") on Bellatrix's pre-Grafton Joint Venture WI.

Daewoo and Devonian Partnership - Bellatrix has a joint venture arrangement (the "Daewoo and Devonian Partnership") with Canadian subsidiaries of two Korean entities, Daewoo International Corporation ("Daewoo") and Devonian Natural Resources Private Equity Fund ("Devonian") in the Baptiste area of West-Central Alberta, whereby Daewoo and Devonian own a combined 50% working interest share of producing assets, an operated compressor station and gathering system and related land acreage.

Troika Joint Venture - Bellatrix has a joint venture (the "Troika Joint Venture") with TCA Energy Ltd. ("Troika") in the Ferrier Cardium area of West-Central Alberta, whereby Troika will contribute 50% or $120 million towards a capital program for drilling of an expected 63 gross wells and will receive a 35% working interest until payout (being recovery of TCA's capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's working interest.

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.     Joint arrangements

The Company has entered into certain joint arrangements whereby the joint arrangement partner ("partner") will earn a working interest on certain properties through the payment of a pre-determined portion of the costs of drilling, completing and equipping.  Bellatrix recognizes a disposal of the partner's working interest once the commitment has been met and the difference between the proceeds received and the carrying amount of the asset are recognized as a gain or loss in the Consolidated Statements of Comprehensive Income.  The assessment of when the partner has earned the working interest and subsequent recognition of the gain or loss is determined on an individual well basis.  Bellatrix has both exploration and evaluation assets and property, plant and equipment assets that are subject to these arrangements.

V.     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.

VI.     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, 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 expense.

I.     Decommissioning liabilities

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 liability and the relevant asset.  The unwinding of the discount on the decommissioning provision is recognized as a finance expense.  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 "DSU 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 DSU 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.

The Company's Restricted and Performance Award Plan (the "Incentive 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 amounts payable under the Incentive Plan are recognized incrementally as an expense over the term of the corresponding grant, with a corresponding change in liabilities.

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 tax

Current 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 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
Restricted cash 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
Advances from joint venture partners Other liabilities Amortized cost
Long-term debt Other liabilities Amortized cost
Convertible debentures Other liabilities Amortized cost
Deferred lease inducements 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 fully settled its convertible debentures by October 21, 2013.  As at December 31, 2013, the Company did not have any outstanding convertible debentures.  The Company's compound financial instruments as at December 31, 2012 were comprised 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. Lease Obligations

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.

Assets held under other leases are classified as operating leases and are not recognized in the balance sheet. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received from landlords are deferred and recognized as an integral part of the total lease expense, over the term of the lease.

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. Restricted Cash

Restricted cash represents funds advanced by a certain joint venture partner for specific future drilling projects.  These funds are released for general purposes as each project reaches a predetermined progress point.

q. 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 profit.  If the cost of the acquisition is more than the fair value of the net assets acquired, the difference is recognized on the balance sheet as goodwill. 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.

a. Critical Accounting Judgments

I.     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 or loss.  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.

II.     Identification of CGUs

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.

III. Impairment Indicators

Judgment is required to assess when impairment indicators exist and impairment testing is required. In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimate of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land and other relevant assumptions.

IV. Joint Arrangements

Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the returns of the arrangement, such as the capital and operating activities of the arrangement.

Once joint control has been established, judgment is also required to classify as a joint arrangement. The type of joint arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its structure, legal form, and terms agreed upon by the parties sharing control. An arrangement where the controlling parties have rights to the assets and revenues and obligations for the liabilities and expenses is classified as a joint operation.

b. Critical Estimates and Assumptions

I.     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.  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.

II.     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.

III.     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.

IV.     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 goodwill. 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.

Amendments to "Offsetting Financial Assets and Financial Liabilities" addressed within IAS 32 - "Financial Instruments: Presentation", which provides guidance regarding when it is appropriate and permissible for an entity to disclose offsetting financial assets and financial liabilities on a net basis.  The amendment to this standard are effective for annual periods beginning on or after January 1, 2014. The extent of the impact of the adoption of IAS 32 amendments has not yet been determined.

IFRIC 21 - "Levies", which establishes guidelines for the recognition and accounting treatment of a liability relating to a levy imposed by a government.  This standard is effective for annual periods beginning on or after January 1, 2014.  The extent of the impact of the adoption of IFRIC 21 has not yet been determined.

6. ACQUISITIONS

a) Corporate acquisition of Angle Energy Inc.

On December 11, 2013, Bellatrix acquired all issued and outstanding shares of Angle Energy Inc. ("Angle") for the issuance of 30,230,998 Bellatrix common shares with a total value of $225.2 million, and cash consideration of $69.7 million.  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 were determined using internal estimates of the timing and estimated costs associated with the abandonment, restoration and reclamation of the wells and facilities acquired. The strategic combination was considered by Bellatrix to be highly complementary and accretive to Bellatrix's current operations. A summary of the acquired assets and liabilities is provided below:

     
    ($000s)
Estimated fair value of acquisition:    
Accounts receivable   25,181
Deposits and prepaid expenses   3,526
Commodity contract asset   20
Exploration and evaluation assets   97,520
Property, plant and equipment   498,371
Accounts payable and accrued liabilities   (40,046)
Long-term debt   (183,127)
Convertible debentures   (62,400)
Decommissioning liabilities   (11,817)
Deferred taxes   (11,676)
            315,552
Cost of acquisition:    
Bellatrix shares issued (30,226,413 shares)   225,221
Cash consideration   69,701
            294,922
Gain on corporate acquisition   20,630

A gain on corporate acquisition of $20.6 million was recognized for the Angle acquisition. The gain was primarily due to a decrease in Bellatrix's share trading price between the announcement of the acquisition on October 15, 2013, and the closing of the acquisition on December 11, 2013.

Concurrent with the acquisition, on December 11, 2013 Bellatrix acquired for cancellation all the issued and outstanding 5.75% convertible unsecured subordinated debentures of Angle (the "Angle Debentures") with a maturity date of January 31, 2016 in the aggregate principal amount of $60.0 million on the basis of $1,040 in cash per $1,000 principal amount of the Angle Debentures, plus accrued and unpaid interest.  Subsequent to closing, Bellatrix also extinguished Angle's long-term debt through the concurrent increase to its credit facility.  

The fair value of identifiable assets acquired and liabilities assumed are preliminary, pending the finalization of the analysis of the deductibility of certain amounts for tax purposes.  Angle's results of operations are included in Bellatrix's consolidated results of operations beginning December 11, 2013.  If the acquisition had been effective January 1, 2013, the Company would have realized an estimated $165.2 million (unaudited) of production revenue and an estimated additional $19.3 million (unaudited) of profit before tax.  The Company's financial and operating results for the year ended December 31, 2013 include financial and operating results from Angle Energy Inc. for the period from December 11, 2013 to December 31, 2013.  Between the acquisition date and December 31, 2013, approximately $10.1 million of production revenue and $1.7 million of profit before tax was recognized relating to the acquired properties.

In the year ended December 31, 2013, Bellatrix incurred approximately $5.3 million of transaction costs related to the corporate acquisition that are expensed on the Consolidated Statements of Comprehensive Income.

b) 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 goodwill or a gain 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:

     
Year ended December 31, 2012   ($000s)
Estimated fair value of acquired properties:    
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 2012 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.

7. EXPLORATION AND EVALUATION ASSETS

($000s)    
     
Cost    
Balance, December 31, 2011 $ 33,089
Acquisitions through business combinations, net   8,525
Additions   8,593
Transfer to oil and natural gas properties   (10,301)
Disposals (1)   (1,729)
Balance, December 31, 2012   38,177
Acquisitions through business combinations, net   97,520
Additions   10,391
Transfer to oil and natural gas properties   (7,424)
Disposals (1)   (5,693)
Balance, December 31, 2013 $ 32,971

(1) Disposals include swaps.

8. PROPERTY, PLANT AND EQUIPMENT

($000s)            
    Oil and
natural gas
properties
  Office
furniture and
equipment
  Total
Cost            
Balance, December 31, 2011 $ 657,315 $ 2,503 $ 659,818
Acquisitions through business combinations, net   29,530   -   29,530
Additions   164,912   299   165,211
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
Acquisitions through business combinations, net   498,371   -   498,371
Additions   298,288   9,270   307,558
Transfer from exploration and evaluation assets   7,424   -   7,424
Farmout wells   11,244   -   11,244
Disposals (1)   (37,408)   (487)   (37,895)
Balance, December 31, 2013 $ 1,629,027 $ 11,585 $ 1,640,612
             
Accumulated Depletion, Depreciation and Impairment losses        
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
Charge for time period   84,902   927   85,829
Disposals (1)   (2,510)   (267)   (2,777)
Balance, December 31, 2013 $ 344,962 $ 2,241 $ 347,203
(1) Disposals include swaps.            
             
Carrying amounts            
At December 31, 2012 $ 588,538 $ 1,221 $ 589,759
At December 31, 2013 $ 1,284,065 $ 9,344 $ 1,293,409

During the year ended December 31, 2013, Bellatrix realized cash proceeds on dispositions of $70.9 million. Of these proceeds, $51.2 million were related to the disposition of properties in the Baptiste area of West Central Alberta to Daewoo and Devonian. A total net gain on dispositions of $42.5 million was recognized for the year ended December 31, 2013, of which $29.1 million was related to an asset sale to Daewoo and Devonian. The remainder of the net gain on dispositions was related to gains on wells drilled under the Grafton Joint Venture and the Troika Joint Venture which were completed during the year ended December 31, 2013, as well as other minor dispositions and swaps which occurred during the year.

Bellatrix has included $1.3 billion (2012: $524.6 million) for future development costs and excluded $69.0 million (2012: $37.2 million) for estimated salvage from the depletion calculation for the three months ended December 31, 2013.

For the year ended December 31, 2013, the Company capitalized $5.3 million (2012: $4.3 million) of general and administrative expenses, and $1.7 million (2012: $1.6 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 $1 billion 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.

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 determined to be the amount for which the asset could be sold in an arm's length transaction.  FVLCS 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.  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.

2013 Impairment

As at December 31, 2013, Bellatrix determined there were no impairment indicators requiring an impairment test to be performed.

2012 Impairment

During the year ended December 31, 2012, 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 $14.8 million impairment loss.

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. This report 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. 


9. LONG-TERM DEBT

As of December 31, 2013, the Company's credit facilities are available on an extendible revolving term basis and consist of a $50 million operating facility provided by a Canadian bank and a $450 million syndicated facility provided by nine financial institutions.

Amounts borrowed under the credit facilities will bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.00% to 3.50%, depending on the type of borrowing and the Company's debt to cash ratio.  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 credit facilities are secured by a $1 billion 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.

The revolving period for the revolving term credit facility will end on June 24, 2014, 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 24, 2014.  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, 2014.

As principal payment will not be required under the revolving term facility for more than 365 days from December 31, 2013 the entire amounts owing on the credit facilities have been classified as long-term.

As at December 31, 2013, the Company had outstanding letters of credit totaling $0.5 million that reduce the amount otherwise available to be drawn on the syndicated facility.

As at December 31, 2013, the Company had approximately $212.4 million, or 42% of unused and available bank credit under its credit facilities. Bellatrix was fully compliant with all of its operating debt covenants.

10. 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, 2012   55,000
Debentures converted or redeemed   (55,000)
Balance, December 31, 2013   -
Debt Component    
Balance, December 31, 2012 $ 50,687
Accretion   1,296
Debentures converted or redeemed   (51,983)
Balance, December 31, 2013 $ -
Equity Component    
Balance, December 31, 2012 $ 4,378
Debentures converted or redeemed   (4,378)
Balance, December 31, 2013 $ -

On September 4, 2013, the Company announced issued a notice of redemption to holders of its then outstanding $55.0 million convertible debentures, with the redemption date set as October 21, 2013.  During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company.   A reduction to the deficit of $1.3 million was recognized in connection with the settlement of the convertible debentures during the year ended December 31, 2013.

11. 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, 2013 totaled $15.3 million (2012: $15.3 million) with accumulated depreciation of $3.0 million (2012: $1.4 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 19.

The following is a schedule of future minimum lease payments under the finance lease obligations:

       
Year ending December 31,     ($000s)
2014   $ 3,399
2015     3,244
2016     3,059
2017     2,719
2018     2,138
Thereafter     11,334
Total lease payments     25,893
Amount representing implicit interest at 15.28%     (12,761)
      13,132
Current portion of finance lease obligation     (1,495)
Finance lease obligation   $ 11,637



12. 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 $122.7 million which will be incurred between 2016 and 2063.  A risk-free rate between 1.13% and 3.24% (2012: 1.14% and 2.36%) and an inflation rate of 2.0% (2012: 2.4%) were used to calculate the fair value of the decommissioning liabilities as at December 31, 2013.

             
($000s)     2013     2012
Balance, beginning of year   $ 43,909    $ 45,091
Incurred on development activities     3,423     1,400
Acquired through business combinations     12,071     973
Revisions on estimates     8,493     (648)
Reversed on dispositions       (619)     (2,955)
Settled during the year     (1,057)     (635)
Accretion expense     855     683
Balance, end of year   $    67,075   $   43,909

The revisions on estimates in 2013 was related to increased cost estimates for abandonment and reclamation of the Company's core and non-core operating areas as a result of actual abandonment costs incurred and revised industry guidance.  In addition, the Company revised the timing of future decommissioning cash flows to better reflect the anticipated abandonment timelines.

13. 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; no dividends were declared by the Board of Directors for the year ended December 31, 2013 or 2012.

     
  2013 2012
      Number   Amount
($000s)
  Number   Amount
($000s)
Common shares, opening balance   107,868,774 $ 371,576   107,407,241 $ 370,048
Issued for cash on equity issue   21,875,000   175,000   -   -
Share issue costs on equity issue, net of tax effect of $2.3 million   -   (7,020)   -   -
Issued for the Angle acquisition   30,230,998   225,221   -   -
Share issue costs on the Angle acquisition, net of tax effect of $0.2 million   -   (576)   -   -
Issued on settlement of convertible debentures   9,794,848   55,568   -   -
Shares issued for cash on exercise of options   1,220,985   3,088   461,533   1,093
Contributed surplus transferred on
   exercised options
  -   1,208   -   435
Balance, end of year   170,990,605 $ 824,065   107,868,774 $ 371,576
                 

On November 5, 2013, Bellatrix closed a bought deal financing of 21,875,000 Bellatrix Shares at a price of $8.00 per Bellatrix Share for aggregate gross proceeds of $175.0 million (net proceeds of $165.6 million after transaction costs).

On December 11, 2013, Bellatrix acquired all issued and outstanding shares of Angle in exchange for the issuance of 30,230,998 Bellatrix common shares with a total value of $225.2 million and cash consideration of $69.7 million (note 6).

On September 4, 2013, the Company announced issued a notice of redemption to holders of its then outstanding $55.0 million convertible debentures, with the redemption date set as October 21, 2013.  During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company (note 10).

14. SHARE-BASED COMPENSATION PLANS

The following table provides a summary of the Company's share-based compensation plans for the year ended December 31, 2013:

($000s)                      
      Share
Options
  Deferred
Share Units
  Restricted
Share Units
  Performance
Share Units
  Total
Expense for the year (1)   $    1,699 $     2,317 $      658 $     286 $     4,960
Liability balance, December 31, 2013   $           - $    4,045 $       983 $     445 $     5,473

(1) The expense for share options is net of adjustments for forfeitures of $0.2 million, and capitalization of $1.2 million.  The expense for restricted share units is net of capitalization of $0.3 million.  The expense for performance share units is net of capitalization of $0.2 million.

The following table provides a summary of the Company's share-based compensation plans for the year ended December 31, 2012:

($000s)                      
      Share
Options
  Deferred
Share Units
  Restricted
Share Units
  Performance
Share Units
  Total
Expense for the year (1)   $ 2,255 $ 964 $ - $ - $ 3,219
Liability balance, December 31, 2012   $ - $ 1,728 $ - $ - $ 1,728

(1) The expense for share options is net of adjustments for forfeitures of $0.2 million, and capitalization of $1.6 million.

 

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, 2013, Bellatrix granted 3,281,500 (2012: 2,648,000) share options.  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, 2013 and 2012, and the weighted average assumptions used in their determination are as noted below:

                             
            2013           2012
      Inputs:                      
      Share price     $ 7.68           $ 3.60
      Exercise price     $ 7.68           $ 3.60
      Risk free interest rate (%)       1.3             1.1
      Option life (years)       2.8             2.8
      Option volatility (%)       46             53
      Results:                      
      Weighted average fair value of each share option granted     $ 2.39           $ 1.28
                             

Bellatrix calculates volatility based on historical share price. Bellatrix incorporates an estimated forfeiture rate between 3% and 10% (2012: 3% to 10%) for stock options that will not vest, and adjusts for actual forfeitures as they occur.

The weighted average trading price of the Company's common shares on the Toronto Stock Exchange ("TSX") for the year ended December 31, 2013 was $6.97 (2012: $4.31).

The following tables summarize information regarding Bellatrix's Share Option Plan:

                 
Share Options Continuity                
                 
        Weighted Average
Exercise Price
      Number
Balance, December 31, 2011       $ 3.44       7,985,320
Granted       $ 3.61       2,648,000
Exercised       $ 2.37       (461,533)
Forfeited       $ 4.50       (751,336)
Balance, December 31, 2012       $ 3.46       9,420,451
Granted       $ 7.68       3,281,500
Exercised       $ 2.53       (1,220,985)
Forfeited       $ 5.19       (298,003)
Balance, December 31, 2013       $ 4.75       11,182,963
                   
                   

As of December 31, 2013, a total of 14,067,450 common shares were reserved for issuance on exercise of share options, leaving an additional 2,884,487 available for future share option grants.

Share Options Outstanding, December 31, 2013

                     
    Outstanding       Exercisable
    At   Weighted
Average
  Weighted
Average
Remaining
  At    
Exercise Price   December 31, 2013   Exercise Price   Contractual Life   December 31, 2013   Exercise Price
$  0.65 - $  1.45   462,946   $ 1.03   0.3   462,946   $ 1.02
$  1.46 - $  1.99   830,671   $ 1.63   0.3   830,671   $ 1.63
$  2.00 - $  3.36   1,137,776   $ 2.43   1.5   851,108   $ 2.18
$  3.37 - $  3.84   1,479,000   $ 3.42   3.3   542,992   $ 3.45
$  3.85 - $  4.72   1,918,901   $ 3.93   1.7   1,666,232   $ 3.90
$  4.73 - $  5.50   2,157,169   $ 5.28   2.5   1,375,482   $ 5.27
$  5.51 - $  8.00   3,196,500   $ 7.69   4.9   -     -
$  0.65 - $  8.00   11,182,963   $   4.75   2.8   5,729,431   $ 3.37
                         
                       

Share Options Outstanding, December 31, 2012

                     
    Outstanding       Exercisable
    At   Weighted
Average
  Weighted
Average
Remaining
  At    
Exercise Price   December, 2012   Exercise Price   Contractual Life   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
                         
                         

b. Deferred Share Unit Plan

Bellatrix has a Directors' Deferred Share Unit Plan ("the DSU 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 DSU 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, 2013, the Company granted 124,382 (2012: 249,298) DSUs, and had 532,906 DSUs outstanding as at December 31, 2013 (2012: 408,524).

c. Incentive Plan

On August 7, 2013, the Directors of Bellatrix approved an Incentive Plan where the Company may grant Restricted Share Units ("RSUs") and Performance Share Units ("PSUs") to officers, employees, and service providers.

RSUs granted to employees vest in equal annual amounts over the course of three years.   Each RSU entitles its holder to receive a cash payment equal to the weighted average trading price of the Company's shares trading on the TSX for the five trading days preceding its vesting date or, if and once approved by the TSX and shareholders of the Company, at the Company's discretion, common shares of the Company equal to the nominal number of Common Shares represented by the RSUs. It is the Company's intention that the RSUs will be settled in cash.  Unvested RSUs are forfeited at the time the holder's employment with the Company ends, except on death in which case they vest.  Bellatrix incorporates an estimated forfeiture rate between 3% and 10% for RSUs that will not vest, and adjusts for actual forfeitures as they occur. Outstanding RSUs are revalued at each financial reporting date to their fair market value at that time, determined by the weighted average trading price of the Company's shares on the TSX for the five trading days preceding period end.  The revaluation is captured as part of share-based compensation expense included in the Company's Statements of Comprehensive Income.  The fair value of the outstanding RSUs is recognized as a liability included as part of accounts payable on the Company's Balance Sheet.

During the year ended December 31, 2013, the Company granted 508,300 (2012: nil) RSUs, and had 508,300 RSUs outstanding as at December 31, 2013 (2012: nil).

PSUs vest on the third anniversary date.   Each PSU entitles its holder to receive a cash payment equal to the weighted average trading price of the Company's shares trading on the TSX for the five trading days preceding its vesting date or, if and once approved by the TSX and shareholders of the Company, at the Company's discretion, common shares of the Company equal to the nominal number of Common Shares represented by the PSUs, in each case multiplied by a payout multiplier determined by the Company's Board of Directors based on determined corporate performance measures.  It is the Company's intention that the PSUs will be settled in cash.  Unvested PSUs are forfeited at the time the holder's employment with the Company ends.  Bellatrix incorporates an estimated forfeiture rate of 5% for PSUs that will not vest, and adjusts for actual forfeitures as they occur.   Outstanding PSUs are revalued at each financial reporting date to their fair market value at that time, determined by the weighted average trading price of the Company's shares on the TSX for the five trading days preceding period end.  The revaluation is captured as part of share-based compensation expense included in the Company's Statements of Comprehensive Income.  The fair value of the outstanding PSUs is recognized as a liability included in accounts payable on the Company's Balance Sheet.

During the year ended December 31, 2013, the Company granted 470,700 (2012: nil) PSUs, and had 470,700 PSUs outstanding as at December 31, 2013 (2012: nil).

15. SUPPLEMENTAL CASH FLOW INFORMATION

Change in Non-cash Working Capital

             
  ($000s)   2013   2012
Changes in non-cash working capital items:            
  Restricted cash   $ (38,148)   $ -
  Accounts receivable     (14,333)     4,530
  Deposits and prepaid expenses     (2,339)     (510)
  Accounts payable and accrued liabilities     49,451     (11,500)
  Advances from joint venture partners     92,832     (1,114)
  Deferred lease inducements     285     -
    $   87,748   $ (8,594)
Changes related to:            
  Operating activities   $ (8,600)   $ (1,075)
  Financing activities     (960)     (55)
  Investing activities     97,308     (7,464)
    $ 87,748   $ (8,594)
               
             

16. 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, 2013, Bellatrix had approximately $1.2 billion in tax pools available for deduction against future income.  Included in this tax basis are estimated non-capital loss carry forwards of approximately $94.4 million that expire in years through 2030.

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% (2012: 25.0%) to loss before taxes.  This difference results from the following items:

           
           
($000s)     2013   2012
Expected income tax expense   $ 22,789   $   9,459
Share based compensation expense     446     564
Angle acquisition     (3,923)     -
Other     171     44
Deferred tax expense   $ 19,483   $ 10,067
             

The components of the net deferred tax asset at December 31 are as follows:

             
($000s) 2013   2012
Deferred tax liabilities:          
  Equity component of 4.75% Debentures $ -   $ (799)
  Property, plant and equipment and exploration and evaluation assets   (81,453)     (17,737)
  Commodity contract asset   (86)     (43)
Deferred tax assets:          
  Finance lease obligation   3,283     3,639
  Commodity contract liability   4,319     -
  Decommissioning liabilities   16,769     10,977
  Share issue costs   3,910     834
  Non-capital losses   23,621     2,500
  Attributed Canadian Royalty Income   -     1,209
  Alberta non-capital losses greater than Federal non-capital losses   1,209     -
  Other   1,394     458
Deferred tax asset (liability) $ (27,034)   $ 1,038
             

A continuity of the net deferred income tax asset (liability) for 2013 and 2012 is provided below:

                     
($000s)   Balance,
Jan. 1, 2013
  Recognized in
profit or loss
  Recognized
in equity
  Recognized
in business
combinations
  Balance,
Dec. 31, 2013
Property, plant and equipment and exploration and evaluation assets   $ (17,737)   $ (32,962)   $ -   $ (30,754)   $ (81,453)
Decommissioning liabilities     10,977     2,838     -     2,954     16,769
Commodity contract liability     (43)     3,961     -     315     4,233
Share issue costs     834     (340)     2,532     884     3,910
Non-capital losses     2,500     6,196     -     14,925     23,621
Equity component of 4.75% debentures     (799)     244     555     -     -
Finance lease obligation     3,639     (356)     -     -     3,283
Attributed Canadian Royalty Income     1,209     (1,209)     -     -     -
Alberta non-capital losses greater than Federal non-capital losses     -     1,209     -     -     1,209
Other     458     936     -     -     1,394
    $ 1,038   $ (19,483)   $ 3,087   $ (11,676)   $ (27,034)
                               
                               

                 
($000s)   Balance,
Jan. 1, 2012
  Recognized in
profit or loss
  Recognized
in equity
  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
                         

17. FINANCE INCOME AND EXPENSES

             
             
($000s)   2013   2012
Finance expense            
  Interest on long-term debt   $ 9,238   $ 5,603
  Interest on convertible debentures     1,954     2,620
             
  Accretion on convertible debentures     1,296     1,611
  Accretion on decommissioning liabilities     855     683
      2,151     2,294
Finance expense   $ 13,343   $ 10,517
               
             

18. 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)       2013       2012
  Production         2,107         885
  General and administrative (1)         11,606         8,292
Employee compensation       $ 13,713       $ 9,177
(1) Amount shown is net of capitalization                    
             

19. RELATED PARTY TRANSACTIONS

a. Finance lease agreements

Previous to 2013, 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 $900,000 of the total. 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 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)   2013   2012
Salaries and other short-term employee benefits   $ 6,190   $ 4,611
Long-term incentive compensation     172     77
Share-based compensation (1)     2,816     2,942
    $ 9,178   $ 7,630
(1) Share-based compensation includes share options, RSUs, PSUs, and DSUs.            
     

20. PER SHARE AMOUNTS

The calculation of basic earnings per share for the year ended December 31, 2013 was based on a net profit of $71.7 million (2012: net profit of $27.8 million).

           
    2013   2012
Basic common shares outstanding   170,990,605   107,868,774
Fully dilutive effect of:        
  Share options outstanding   11,182,963   9,420,451
  Shares issuable for convertible debentures   -   9,821,429
Fully diluted common shares outstanding   182,173,568   127,110,654
Weighted average shares outstanding   112,927,251   107,543,811
Dilutive effect of share options and convertible debentures (1)   2,841,185   1,581,283
Diluted weighted average shares outstanding   115,768,436   109,125,094
(1) For the year ended December 31, 2013, a total of 2,841,185 (2012: 1,581,283) share options were included
in the calculation as they were dilutive, and nil (2012: 9,821,429) common shares issuable pursuant to the conversion
of the convertible debentures were excluded from the calculation as they were not dilutive.
 

21. 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, 2013 is as follows:

                   
                   
($000s)   Gross        
  Year   Amount   Recoveries   Net amount
  2014   $ 4,562   $ (1,014)   $ 3,548
  2015     3,094     -     3,094
  2016     3,094     -     3,094
  2017     3,094     -     3,094
  2018     2,911     -     2,911
  More than 5 years     12,206     -     12,206
                 

As at December 31, 2013, Bellatrix committed to drill 10 gross (5.7 net) wells pursuant to farm-in agreements.  Bellatrix expects to satisfy these drilling commitments at an estimated cost of approximately $20.1 million.

In addition, Bellatrix entered into two joint operating agreements during the 2011 year and an additional joint operation 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 Operating Agreement   Feb. 1, 2011   Aug. 4, 2011   Dec. 14, 2012
Commitment 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, 2013     -     12     7
Remaining estimated total cost ($000s)   $ -   $ 42.0   $ 24.5
                   
                   

Bellatrix also has certain drilling commitments relating to the Grafton Joint Venture, the Daewoo and Devonian Joint Venture, and the Troika Joint Venture.  In meeting the drilling commitments under these joint venture agreements, Bellatrix will also satisfy some of the drilling commitments under the joint operating agreements described above.

         
         
Joint Venture Agreement   Grafton Daewoo and
Devonian
Troika
Commitment Term   2013 to 2015 2013 to 2016 2013 to 2014
Minimum total wells (gross)(1)     58   70   63
Minimum total wells (net)(1)     10.44   35.0   31.5
Estimated total cost  ($000s) (gross)(1)   $ 244.0 $ 200.0 $ 240.0
Estimated total cost  ($000s) (net)(1)   $ 44.0 $ 100.0 $ 120.0
Remaining wells to drill at December 31, 2013 (gross)     46   51   42
Remaining wells to drill at December 31, 2013 (net)     8.2   25.6   21.0
Remaining estimated total cost ($000s) (gross)   $ 192.3 $ 198.3 $ 160.0
Remaining estimated total cost ($000s) (net)   $ 34.6 $ 99.2 $ 80.0
               
(1) Gross and net estimated total cost values and gross and net minimum total wells for the Troika and Grafton Joint Ventures represent Bellatrix's total capital and well commitments pursuant to the Troika and Grafton Joint Venture agreements.  Gross and net minimum total wells for the Daewoo and Devonian Partnership represent Bellatrix's total well commitments pursuant to the Daewoo and Devonian Partnership agreement.  Gross and net estimated total cost values for the Daewoo and Devonian Partnership represent Bellatrix's estimated cost associated with its well commitments under the Daewoo and Devonian Partnership agreement.

22. 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, 2013, 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     25,488     2,723     28,211
Amounts due from government agencies     75     1     76
Revenue and other accruals     46,432     6,087     52,519
Cash call receivables     -     21     21
Less:  Allowance for doubtful accounts     -     (521)     (521)
Total accounts receivable     71,995     8,311     80,306
                   
             

Amounts due from government agencies include GST and royalty adjustments.  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 9, 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, 2013:

                               
                               
Liabilities ($000s)   Total   < 1 Year   1-3 Years   3-5 Years   More than
5 years
Accounts payable and accrued liabilities (1)   $ 137,465   $ 137,465   $ -   $ -   $ -
Advances from joint venture partners     99,380     99,380     -     -     -
Long-term debt - principal (2)     287,092     -     287,092     -     -
Commodity contract liability     17,278     17,278     -     -     -
Decommissioning liabilities (3)     67,075     -     2,198     3,361     61,516
Finance lease obligation     13,132     1,495     3,208     2,708     5,721
Deferred lease inducements     2,850     285     570     570     1,425
Total   $ 624,272   $ 255,903   $ 293,068   $ 6,639   $ 68,662
                               
(1) Includes $0.7 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) Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over the life of the Company's properties (between 2016 and 2063).

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, 2013, 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, 2013 would have been approximately $1.1 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, 2013.

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, 2013, 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, 2014 to Dec. 31, 2014   500 bbl/d   $ 93.30    US   $ 93.30 US   WTI
Crude oil fixed   January 1, 2014 to Dec. 31, 2014   1,500 bbl/d   $ 94.00 CDN   $ 94.00 CDN   WTI
Crude oil fixed   January 1, 2014 to Dec. 31, 2014   500 bbl/d   $ 95.00    US   $ 95.00 US   WTI
Crude oil fixed   January 1, 2014 to Dec. 31, 2014   1,500 bbl/d   $ 95.22 CDN   $ 95.22 CDN   WTI
Crude oil fixed   January 1, 2014 to Dec. 31, 2014   500 bbl/d   $ 98.30 CDN   $ 98.30 CDN   WTI
Crude oil fixed   January 1, 2014 to Dec. 31, 2014   1,000 bbl/d   $ 99.50 CDN   $ 99.50 CDN   WTI
Crude oil fixed   January 1, 2014 to Dec. 31, 2014   500 bbl/d   $ 99.60 CDN   $ 99.60 CDN   WTI
Crude oil call option (1)   January 1, 2014 to Dec. 31, 2014   1,500 bbl/d     -   $ 105.00 US   WTI
Natural gas fixed   January 1, 2014 to June 30, 2014   15,000 GJ/d   $ 3.05 CDN   $ 3.05 CDN   AECO
Natural gas fixed   January 1, 2014 to Dec. 31, 2014   20,000 GJ/d   $ 3.30 CDN   $ 3.30 CDN   AECO
Natural gas fixed   January 1, 2014 to Dec. 31, 2014   20,000 GJ/d   $ 3.60 CDN   $ 3.60 CDN   AECO
Natural gas fixed   July 1, 2014 to Dec. 31, 2014   15,000 GJ/d   $ 3.71 CDN   $ 3.71 CDN   AECO
                         
(1) Subsequent to December 31, 2013, the Company settled the crude oil call options for the term of February to December 31, 2014 for US $0.5 million.

Subsequent to December 31, 2013, the Company has entered into commodity price risk management arrangements as follows:

                         
                         
Type   Period   Volume   Price Floor   Price Ceiling   Index
Natural gas fixed   February 1, 2014 to Dec. 31, 2014   10,000 GJ/d   $ 3.79 CDN   $ 3.79 CDN   AECO
Natural gas fixed   February 1, 2014 to Dec. 31, 2014   10,000 GJ/d   $ 3.80 CDN   $ 3.80 CDN   AECO
Natural gas fixed   February 1, 2014 to Dec. 31, 2014   15,000 GJ/d   $ 3.85 CDN   $ 3.85 CDN   AECO
Natural gas fixed   February 1, 2014 to Dec. 31, 2014   10,000 GJ/d   $ 3.84 CDN   $ 3.84 CDN   AECO
Natural gas fixed   February 1, 2014 to February 28, 2014   10,000 GJ/d   $ 4.66 CDN   $ 4.66 CDN   AECO
Natural gas fixed   March 1, 2014 to Dec. 31, 2014   10,000 GJ/d   $ 4.14 CDN   $ 4.14 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, 2013, if interest rates had been 1% lower with all other variables held constant, after tax net profit for the year ended December 31, 2013 would have been approximately $2.2 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, 2013.

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, 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 from operations (the "ratio").  This ratio is calculated as total net debt, defined as outstanding bank debt, plus the liability component of any outstanding convertible debentures, plus or minus working capital (excluding commodity contract assets and liabilities, the current portion of finance lease obligations and deferred lease inducements, 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 from operations 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, 2013 the Company's ratio of total net debt to annualized funds flow from operations (based on fourth quarter funds flow from operations) was 2.5 times.  The total net debt to annualized funds flow from operations ratio as at December 31, 2013 increased from that at December 31, 2012 of 1.6 times primarily due to an increase in total net debt resulting from the timing and expansion of the Company's 2013 capital expenditure program, and the acquisition of Angle in the fourth quarter of 2013. As at December 31, 2013 the Company's ratio of total net debt to annualized funds flow from operations (based on fourth quarter funds flow from operations, including funds flow from operations from Angle had the acquisition occurred effective October 1, 2013) was 1.9 times.  The Company continues to take a balanced approach to the priority use of funds flows.

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) 2013   2012
       
Shareholders' equity 903,874   381,106
       
Long-term debt 287,092   133,047
Convertible debentures (liability component) -   50,687
Working capital (excess) deficiency (2) 108,390   5,843
Total net debt (2) at year end 395,482   189,577
       
Debt to funds flow from operations (1) ratio (annualized) (3)      
Funds flow from operations (1) (annualized) 157,396   119,460
Funds flow from operations (1) (annualized, including Angle funds flow from operations for the full October 1
to December 31, 2013 period - unaudited)
203,985   119,460
Total net debt (2) at year end 395,482   189,577
Total net debt to periods funds flow from operations ratio (annualized) (3) 2.5x   1.6x
Total net debt to periods funds flow from operations ratio (annualized,  including Angle funds flow from
operations for the full October 1 to December 31, 2013 period - unaudited) (3)
1.9x   1.6x
       
Net debt (2) (excluding convertible debentures) at year end 395,482   138,890
Net debt to periods funds flow from operations
ratio (annualized) (3)
2.5x   1.2x
Net debt to periods funds flow from operations
ratio (annualized,  including Angle funds flow from operations for the full October 1 to December 31, 2013 period - unaudited) (3)
1.9x   1.2x
       
Debt to funds flow from operations (1) ratio      
Funds flow from operations (1) for the year 143,459   111,038
Funds flow from operations (1) for the year (including Angle funds flow from operations for the full October 1
to December 31, 2013 period - unaudited)
155,106   111,038
Funds flow from operations (1) for the year (including Angle funds flow from operations for the full January 1
to December 31, 2013 period - unaudited)
219,240   111,038
Total net debt (2)  to funds flow from operations for the year 2.8x   1.7x
Total net debt (2)  to funds flow from operations for the year (including Angle funds flow from operations for
the full October 1 to December 31, 2013 period - unaudited)
2.5x   1.7x
       
Net debt (2) (excluding convertible debentures) to funds flow from operations for the year 2.8x   1.3x
Net debt (2) (excluding convertible debentures) to funds flow from operations for the year (including Angle funds
flow from operations for the full January 1 to December 31, 2013 period - unaudited)
1.8x   1.3x
       
(1) 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,
excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.
(2) Net debt and total net debt are considered additional GAAP measures.  Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable
with the calculation of similar measures for other entities.  The Company's 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract
liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted
working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term
commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements.  For the comparative 2012 calculation, net debt also excludes the liability
component of convertible debentures.
(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 9).  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, 2013 include restricted cash, accounts receivable, deposits, commodity contract asset, accounts payable and accrued liabilities, advances from joint venture partners, deferred lease inducements, finance lease obligations, and long-term debt. The fair value of restricted cash, accounts receivable, deposits, accounts payable and accrued liabilities approximate their carrying amounts due to their short-terms to maturity.

The Company enters into commodity contracts under master netting arrangements. Under these arrangements, the amounts owed by each counterparty for all contracts outstanding in the same currency or commodity are aggregated into a single net amount receivable or payable. If a default occurs, the net amount subject to a master netting arrangement is receivable or payable for settlement purposes. The carrying amounts of commodity contracts held under master netting arrangements are recorded on a net basis. The gross amounts netted are negligible.

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, 2013 was a net liability of $16.9 million (2012: $0.2 million net asset).  The commodity contracts are classified as level 2 within the fair value hierarchy.

         
($000s)   December 31, 2013   December 31, 2012
             
Commodity contract asset   $ 345   $ 7,519
             
Commodity contract liability     (17,278)     (7,345)
             
Net commodity contract asset (liability)   $ (16,933)   $ 174
             
           

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.



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, 2012     19,657     213,348     55,215
Revision of previous estimates     1,588     56,769     11,050
Discoveries, extensions, infill drilling and improved recovery     8,648     153,127     34,168
Acquisitions, net of dispositions     17,527     84,672     31,639
Production     (2,368)     (33,563)     (7,961)
December 31, 2013     45,052     474,353     124,111
                   
Proved plus probable reserves                  
December 31, 2013     78,080     800,418     211,483
December 31, 2012     34,515     415,310     103,754
                   
                   

(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)                  
        2013     2012     2011-2013
Average
Proved (excluding FDC)     11.17     9.16     10.33
Proved (including FDC)     13.76     11.77     13.29
                   
Proved plus probable (excluding FDC)     7.24     4.28     6.40
Proved plus probable (including FDC)     9.67     6.95     9.01
                   
                 

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.

Finding and development costs (excluding acquisitions and dispositions), excluding FDC, for proved reserves, were $6.21/boe and $8.87/boe in 2013 and 2012, respectively, (proved plus probable - $4.73/boe in 2013 and $4.29/boe in 2012) and $7.31/boe on a three year average (proved plus probable $4.89/boe).

Finding and development costs (excluding acquisitions and dispositions), including FDC, for proved reserves, were $10.67/boe and $11.73/boe in 2013 and 2012, respectively, (proved plus probable - $9.65/boe in 2013 and $7.31/boe in 2012) and $11.47/boe on a three year average (proved plus probable $8.86/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.

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 of Bellatrix trade on the Toronto Stock Exchange ("TSX") and on the NYSE MKT under the symbol BXE. 

 

 

 

 

SOURCE Bellatrix Exploration Ltd.

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