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Bellatrix Exploration Ltd. Announces Year End 2013 Financial Results

March 13, 2014

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    291,891        219,314
    (1))

    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        608,078         25,875
    items

    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     108,390          5,843
    (3)

    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 Albertain 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:
      o Installed a 25 km pipeline to the MBL Gas Plant facilitating
        processing an additional 85 mmcf/d capacity

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

      o Installed 45+ km of large diameter group pipelines
        --  Near term 2014 catalysts:
      o 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

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

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

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

      o Throughout 2014 install 60+ km of large diameter group pipelines
        --  Long term 2015 - 2016 catalysts:
      o 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                        3,278                    1,631
    condensate)              (bbls/d)

    Heavy oil                (bbls/d)        175                      189

    Total crude oil,                       7,564                    5,730
    condensate and NGLs      (bbls/d)

    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                 6,489             5,717
    NGLs                              (bbls/d)

    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                   (5,851)         7,710        1,859
    (loss) on contracts

    Unrealized gain (loss)               (4,112)      (13,015)     (17,127)
    on contracts (1)

    Total gain (loss) on                 (9,963)       (5,305)     (15,268)
    commodity contracts

    Commodity contracts                                           

    ($000s)                  Crude Oil & Liquids   Natural Gas   2012 Total

    Realized cash gain                   (1,976)        13,245       11,269
    (loss) on contracts

    Unrealized gain on                     6,267         4,539       10,806
    contracts (1)

    Total gain on                          4,291        17,784       22,075
    commodity contracts

        Unrealized gain (loss) on commodity contracts represents non-cash
    (1) 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          (255,903)   (53,327)
        working capital calculation 

        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                (285)          -
        inducements

        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              3      5 to 10             2
    and net)

    Minimum total wells (gross and            15           40            10
    net)

    Estimated total cost  ($000s)         $ 52.5      $ 140.0       $  35.0

    Remaining wells to drill at                -           12             7
    December 31, 2013

    Remaining estimated total cost     $       -     $   42.0       $  24.5
    ($000s)

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.


                                                   Daewoo and
    Agreement                            Grafton     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                 < 1                               More than
    ($000s)           Total    Year     1-3 Years    3-5 Years      5 years

    Accounts
    payable and
    accrued              $      $   $             $            $
    liabilities (1) 137,465 137,465             -            -            -

    Advances from    99,380  99,380             -            -            -
    joint venture
    partners

    Long-term debt
    - principal (2) 287,092       -       287,092            -            -

    Commodity        17,278  17,278             -            -            -
    contract
    liability

    Decommissioning
    liabilities (3)  67,075       -         2,198        3,361       61,516

    Finance lease    13,132   1,495         3,208        2,708        5,721
    obligation

    Deferred lease    2,850     285           570          570        1,425
    inducements

    Total                $      $      $  293,068   $    6,639   $   68,662
                    624,272 255,903

        (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)                   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

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  Funds Flow  from
                                                      (1)     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                      1,400              0.01
    exchange rate

    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                 -

                                                                                               80,306            40,792
      Accounts receivable (note 22)                                                        

      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                                                                                   $      $     681,421
                                                                                            1,555,180

    LIABILITIES                                                                                                        

    Current liabilities                                                                                                

                                                                                                $        $       44,223
      Accounts payable and accrued liabilities                                                137,465

      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                                                    $       $     681,421
                                                                                            1,555,180

    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    (42,494)      4,113
      (note 8)

      Gain on corporate acquisition (note 6)            (20,630)          -

      Impairment loss on property, plant and                   -     14,820
      equipment (note 8)

                                                         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,          (7,020)          -
            net of tax

            Issued for the Angle acquisition            225,221          -
            (note 6)

            Share issue costs on the Angle                (576)          -
            acquisition, net of tax

            Issued on settlement of convertible          55,568          -
            debentures (note 10)

            Issued for cash on exercise of share          3,088      1,093
            options

            Contributed surplus transferred on            1,208        435
            exercised options

            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                (4,378)          -
            convertible debentures (note 10)

            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          (163)      (187)
            options

            Transfer to share capital for               (1,208)      (435)
            exercised options

            Balance, end of year                         38,958     37,284

    RETAINED EARNINGS (DEFICIT)                                           

            Balance, beginning of year                 (32,132)   (59,903)

            Adjustment for settlement of                  1,308          -
            convertible debentures (note 10)

            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                   14                -
      convertible debentures

      Share-based compensation (note 14)            4,960            3,219

      Unrealized (gain) loss on commodity          17,127         (10,806)
      contracts

      Gain on property acquisitions (note               -         (16,160)
      8)

      Loss (gain) on property                    (42,494)            4,113
      dispositions and swaps (note 8)

      Gain on corporate acquisition (note        (20,630)                -
      6)

      Impairment loss on property, plant                -           14,820
      and equipment (note 8)

      Deferred tax expense (note 16)               19,483           10,067

      Decommissioning costs incurred              (1,057)            (635)

      Change in non-cash working capital          (8,600)          (1,075)
      (note 15)

                                                  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             (62,400)                -
      debentures (note 6)

      Obligations under finance lease             (1,425)            (560)
      (note 11)

      Deferred lease inducements                    2,565                -

      Change in non-cash working capital            (960)             (55)
      (note 15)

                                                   76,658           76,824

    CASH FLOW FROM (USED IN) investing
    ACTIVITIES                             

      Expenditure on exploration and             (10,391)         (17,118)
      evaluation assets

      Additions to property, plant and          (293,268)        (168,230)
      equipment

      Proceeds on sale of property, plant          70,936            6,660
      and equipment (note 8)

      Cash portion of Angle Energy               (69,701)                -
      acquisition

      Change in non-cash working capital           97,308          (7,464)
      (note 15)

                                                (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    |Category             |Subsequent Measurement|
    |Liabilities             |                     |                      |
    |________________________|_____________________|______________________|
    |Cash and cash           |Held-for-trading     |Fair value through    |
    |equivalents             |                     |profit or loss        |
    |________________________|_____________________|______________________|
    |Restricted cash         |Held-for-trading     |Fair value through    |
    |                        |                     |profit or loss        |
    |________________________|_____________________|______________________|
    |Accounts receivable     |Loans and receivables|Amortized cost        |
    |________________________|_____________________|______________________|
    |Deposits and prepaid    |Other assets         |Amortized cost        |
    |expenses                |                     |                      |
    |________________________|_____________________|______________________|
    |Commodity risk          |Held-for-trading     |Fair value through    |
    |management contracts    |                     |profit or loss        |
    |________________________|_____________________|______________________|
    |Accounts payable and    |Other liabilities    |Amortized cost        |
    |accrued liabilities     |                     |                      |
    |________________________|_____________________|______________________|
    |Advances from joint     |Other liabilities    |Amortized cost        |
    |venture partners        |                     |                      |
    |________________________|_____________________|______________________|
    |Long-term debt          |Other liabilities    |Amortized cost        |
    |________________________|_____________________|______________________|
    |Convertible debentures  |Other liabilities    |Amortized cost        |
    |________________________|_____________________|______________________|
    |Deferred lease          |Other liabilities    |Amortized cost        |
    |inducements             |                     |                      |
    |________________________|_____________________|______________________|
    |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          Office
                                    natural gas   furniture and
                                     properties       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

                                            Amount                  Amount
                                 Number     ($000s)      Number     ($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   Deferred   Restricted   Performance
                   Options      Share        Share   Share Units
                                Units        Units                 Total

    Expense     $    1,699 $          $        658 $         286 $
    for the                     2,317                              4,960
    year (1)

    Liability   $          $    4,045 $        983 $         445 $
    balance,                                                       5,473
    December             -
    31, 2013

((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      Deferred    Restricted   Performance
                  Options   Share Units   Share Units   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     $ 2.39           $ 1.28
          share option granted

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

                                           Weighted
                             Weighted       Average
                        At    Average     Remaining          At

    Exercise      December   Exercise   Contractual    December   Exercise
    Price         31, 2013      Price          Life    31, 2013      Price

    $  0.65 -                    1.03           0.3     462,946   $   1.02
    $  1.45        462,946   $                       

    $  1.46 -                    1.63           0.3     830,671   $   1.63
    $  1.99        830,671   $                       

    $  2.00 -                    2.43           1.5     851,108   $   2.18
    $  3.36      1,137,776   $                       

    $  3.37 -                    3.42           3.3     542,992   $   3.45
    $  3.84      1,479,000   $                       

    $  3.85 -                    3.93           1.7   1,666,232   $   3.90
    $  4.72      1,918,901   $                       

    $  4.73 -                    5.28           2.5   1,375,482   $   5.27
    $  5.50      2,157,169   $                       

    $  5.51 -                    7.69           4.9           -          -
    $  8.00      3,196,500   $                       

    $  0.65 -                    4.75           2.8   5,729,431   $   3.37
    $  8.00     11,182,963   $                       

Share Options Outstanding, December 31, 2012


                      Outstanding                          Exercisable

                                          Weighted
                            Weighted       Average
                       At    Average     Remaining          At

    Exercise    December,   Exercise   Contractual    December   Exercise
    Price            2012      Price          Life    31, 2012      Price

    $  0.65 -                   1.02           1.3     682,949   $   1.02
    $  1.45       682,949   $                       

    $  1.46 -                   1.65           1.2   1,177,449   $   1.65
    $  1.99     1,177,449   $                       

    $  2.00 -                   2.41           2.2     973,718   $   2.08
    $  3.36     1,407,052   $                       

    $  3.37 -                   3.42           4.3      84,665   $   3.70
    $  3.84     1,575,000   $                       

    $  3.85 -                   3.95           2.8   1,172,313   $   3.90
    $  4.72     2,271,001   $                       

    $  4.73 -                   5.28           3.5     723,975   $   5.26
    $  5.50     2,307,000   $                       

    $  0.65 -                   3.46           2.8   4,815,069   $   2.78
    $  5.50     9,420,451   $                       

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 1(st) 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   (81,453)     (17,737)
      and evaluation assets

      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            1,209            -
      Federal non-capital losses

      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:


                                   Recognized
                        Balance,           in                  Recognized     Balance,
                         Jan. 1,    profit or   Recognized    in business     Dec. 31,
    ($000s)                 2013         loss    in equity   combinations         2013

    Property, plant     (17,737)   $                     -   $   (30,754)   $ (81,453)
    and equipment
    and exploration
    and evaluation
    assets            $              (32,962)   $           

    Decommissioning       10,977                         -          2,954       16,769
    liabilities                         2,838               

    Commodity               (43)                         -            315        4,233
    contract
    liability                           3,961               

    Share issue              834                     2,532            884        3,910
    costs                               (340)               

    Non-capital            2,500                         -         14,925       23,621
    losses                              6,196               

    Equity                 (799)                       555              -            -
    component of
    4.75%
    debentures                            244               

    Finance lease          3,639                         -              -        3,283
    obligation                          (356)               

    Attributed             1,209                         -              -            -
    Canadian
    Royalty Income                    (1,209)               

    Alberta                    -                         -              -        1,209
    non-capital
    losses greater
    than Federal
    non-capital
    losses                              1,209               

    Other                    458          936            -              -        1,394

                      $    1,038   $ (19,483)   $    3,087   $   (11,676)   $ (27,034)

                                     Recognized
                                             in                  Balance,
                          Balance,    profit or   Recognized     Dec. 31,
    ($000s)           Jan. 1, 2012         loss    in equity         2012

    Property, plant        (8,126)   $                     -   $ (17,737)
    and equipment
    and exploration
    and evaluation
    assets            $                 (9,611)   $

    Decommissioning         11,273                         -       10,977
    liabilities                           (296)    

    Commodity                2,658                         -         (43)
    contract
    liability                           (2,701)    

    Share issue              1,174                         -          834
    costs                                 (340)    

    Non-capital              2,500                         -        2,500
    losses                                    -    

    Equity                 (1,078)                         -        (799)
    component of
    4.75%
    debentures                              279    

    Finance lease            1,279                         -        3,639
    obligation                            2,360    

    Attributed               1,209                         -        1,209
    Canadian
    Royalty Income                            -    

    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                 3        5 to 10               2
    (gross and net)

    Minimum total wells                   15             40              10
    (gross and net)

    Estimated total cost        $       52.5   $      140.0   $        35.0
    ($000s)

    Remaining wells to drill               -             12               7
    at December 31, 2013

    Remaining estimated total   $          -   $       42.0   $        24.5
    cost ($000s)

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.


                                                    Daewoo and
    Joint Venture Agreement               Grafton     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:                            

                                 Not past due
                                (less than 90      Past due (90
    Aging ($000s)                       days)     days or more)      Total

    Joint venture and other            25,488
    trade accounts
    receivable                                            2,723     28,211

    Amounts due from                       75
    government agencies                                       1         76

    Revenue and other                  46,432
    accruals                                              6,087     52,519

    Cash call receivables                   -                21         21

    Less:  Allowance for                    -
    doubtful accounts                                     (521)      (521)

    Total accounts                     71,995
    receivable                                            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 25(th) 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:


                                                                        More
    Liabilities                                               3-5       than
    ($000s)               Total    < 1 Year   1-3 Years     Years    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                                                      Price
                     Period      Volume   Price Floor       Ceiling   Index

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,                  93.30
                       2014   500 bbl/d   $        US   $  93.30 US     WTI

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,       1,500
                       2014       bbl/d   $ 94.00 CDN   $ 94.00 CDN     WTI

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,                  95.00
                       2014   500 bbl/d   $        US   $  95.00 US     WTI

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,       1,500
                       2014       bbl/d   $ 95.22 CDN   $ 95.22 CDN     WTI

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,
                       2014   500 bbl/d   $ 98.30 CDN   $ 98.30 CDN     WTI

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,       1,000
                       2014       bbl/d   $ 99.50 CDN   $ 99.50 CDN     WTI

    Crude oil    January 1,
    fixed           2014 to
                   Dec. 31,
                       2014   500 bbl/d   $ 99.60 CDN   $ 99.60 CDN     WTI

    Crude oil    January 1,
    call            2014 to
    option (1)     Dec. 31,       1,500
                       2014       bbl/d             -   $ 105.00 US     WTI

    Natural      January 1,
    gas fixed       2014 to
                   June 30,      15,000
                       2014        GJ/d   $  3.05 CDN   $  3.05 CDN    AECO

    Natural      January 1,
    gas fixed       2014 to
                   Dec. 31,      20,000
                       2014        GJ/d   $  3.30 CDN   $  3.30 CDN    AECO

    Natural      January 1,
    gas fixed       2014 to
                   Dec. 31,      20,000
                       2014        GJ/d   $  3.60 CDN   $  3.60 CDN    AECO

    Natural         July 1,
    gas fixed       2014 to
                   Dec. 31,      15,000
                       2014        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       February   10,000   $  3.79 CDN   $    3.79 CDN    AECO
    gas fixed   1, 2014 to     GJ/d
                  Dec. 31,
                      2014

    Natural       February   10,000   $  3.80 CDN   $    3.80 CDN    AECO
    gas fixed   1, 2014 to     GJ/d
                  Dec. 31,
                      2014

    Natural       February   15,000   $  3.85 CDN   $    3.85 CDN    AECO
    gas fixed   1, 2014 to     GJ/d
                  Dec. 31,
                      2014

    Natural       February   10,000   $  3.84 CDN   $    3.84 CDN    AECO
    gas fixed   1, 2014 to     GJ/d
                  Dec. 31,
                      2014

    Natural       February   10,000   $  4.66 CDN   $    4.66 CDN    AECO
    gas fixed   1, 2014 to     GJ/d
                  February
                  28, 2014

    Natural       March 1,   10,000   $  4.14 CDN   $    4.14 CDN    AECO
    gas fixed      2014 to     GJ/d
                  Dec. 31,
                      2014

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    $        (16,933)   $             174
    (liability)

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     Natural gas     Equivalent
                                      & NGLs          (mmcf)          units
                                      (mbbl)                         (mboe)

    December 31, 2012                 19,657         213,348         55,215

    Revision of previous               1,588          56,769         11,050
    estimates

    Discoveries, extensions,           8,648         153,127         34,168
    infill drilling and
    improved recovery

    Acquisitions, net of              17,527          84,672         31,639
    dispositions

    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)                                                        

                                                                  2011-2013
                                               2013      2012       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.


Source: PR Newswire



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