EX-99.2 3 v337562_ex99-2.htm EXHIBIT 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

March 6, 2013 – The following Management’s Discussion and Analysis of financial results (“MD&A”) as provided by the management of Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) should be read in conjunction with the audited consolidated financial statements of the Company for the years ended December 31, 2012 and 2011. This commentary is based on information available to, and is dated as of, March 6, 2013. The financial data presented is in Canadian dollars, except where indicated otherwise.

CONVERSION: The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe conversions in this report are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.

INITIAL PRODUCTION RATES: Initial production rates disclosed herein may not necessarily be indicative of long-term performance or ultimate recovery.

ADDITIONAL GAAP MEASURES: This Management’s Discussion and Analysis and the accompanying report to shareholders and financial statements contain the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than “cash flow from operating activities” as determined in accordance with generally accepted accounting principles (“GAAP”) as an indicator of the Company’s performance. Therefore reference to funds flow from operations or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found in this Management’s Discussion and Analysis. Funds flow from operations per share is calculated using the weighted average number of shares for the period.

This Management’s Discussion and Analysis and the accompanying report to shareholders and financial statements also contain the term total net debt and net debt. Total net debt is calculated as long-term debt plus the liability component of the convertible debentures and the net working capital deficiency (excess) before short-term commodity contract assets and liabilities and current finance lease obligations. Net debt is calculated as long-term debt plus the net working capital deficiency (excess) before short-term commodity contract assets and liabilities and current finance lease obligations. Management believes these measures are useful supplementary measures of the total amount of current and long-term debt.

NON-GAAP MEASURES: This Management’s Discussion and Analysis and the accompanying report to shareholders also contains other terms such as net profit before certain non-cash items and operating netbacks, which are not recognized measures under GAAP. Net profit before certain non-cash items is calculated as net profit (loss) per the Consolidated Statement of Comprehensive Income, excluding the non-cash impairment loss, net unrealized gain or loss on commodity contracts, gain on property acquisition, and gain or loss on property dispositions net of the deferred tax impact on these adjustments. Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from revenues before other income. Management believes these measures are useful supplemental measures of firstly, the amount of net profit before certain non-cash items, and secondly, the amount of revenues received after transportation, royalties and operating expenses. Readers are cautioned, however, that these measures should not be construed as an alternative to net income determined in accordance with GAAP as measures of performance. Bellatrix’s method of calculating these measures may differ from other entities, and accordingly, may not be comparable to measures used by other companies.

Additional information relating to the Company, including the Bellatrix’s Annual Information Form, is available on SEDAR at www.sedar.com.

FORWARD LOOKING STATEMENTS: Certain information contained herein and in the accompanying report to shareholders may contain forward looking statements including management’s assessment of future plans and operations, drilling plans and the timing thereof, commodity price risk management strategies, 2013 capital expenditure budget, the nature of expenditures and the method of financing thereof, expected 2013 average production and exit rate, anticipated liquidity of the Company and various matters that may impact such liquidity, expected 2013 operating expenses and general and administrative expenses, expected costs to satisfy drilling commitments and method of funding drilling commitments, commodity prices and expected volatility thereof, estimated amount and timing of incurring decommissioning liabilities, plans to utilize pad drilling and effect thereof, use of funds from property dispositions, timing of closing of joint venture agreement, the effect of certain acquisitions, and plans for facility construction may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, risks related to satisfaction of conditions precedent to closing of joint venture agreement, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix’s future operations. Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could effect Bellatrix’s operations and financial results are included in reports on file with Canadian and US securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), and at Bellatrix’s website (www.bellatrixexploration.com). Furthermore, the forward-looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

Overview and Description of the Business

Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) is a Western Canadian based growth oriented oil and gas company engaged in the exploration for, and the acquisition, development and production of oil and natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan.

Bellatrix’s common shares and convertible debentures are listed on the Toronto Stock Exchange under the symbols BXE and BXE.DB.A, respectively, and the common shares of Bellatrix trade on the NYSE MKT under the symbol BXE.

Cardium Joint Venture

Bellatrix has entered into a joint venture agreement with a Seoul Korea based company (“JV Partner”), to accelerate development of Bellatrix’s extensive undeveloped Cardium land holdings in west-central Alberta. Under the terms of the agreement, the JV Partner will contribute 50%, or CDN$150 million, to a $300 million joint venture (the “Joint Venture”) to participate in an expected 83 Cardium well program. Under the agreement, the JV Partner will earn 33% of Bellatrix’s working interest in the Cardium well program until payout (being recovery of the JV Partner’s capital investment plus an 8% return on investment) on the total program, which is expected to occur prior to a maximum of 7 years, reverting to a 20% working interest after payout. The effective date of the agreement is April 1, 2013 but with the ability of the JV Partner to elect to invest in the wells drilled between January 1 and up to April 30, 2013. Certain conditions precedent are expected to be satisfied or waived by April 22, 2013 which is expected to enable closing to occur on or before April 30, 2013. Bellatrix will be required to provide a guarantee of the return of the JV Partner’s capital investment of up to $30 million if not recovered within 7 years.

Fourth Quarter 2012

HIGHLIGHTS	Three months ended December 31,
(CDN$000s except share and per share amounts)	2012		2011
FINANCIAL
Revenue (before royalties and risk management ⁽¹⁾)		62,283		59,194

Funds flow from operations ⁽²⁾		29,865		30,120
Per basic share ⁽⁶⁾	$	0.28	$	0.28
Per diluted share ⁽⁶⁾	$	0.26	$	0.26
Cash flow from operating activities		32,007		30,626
Per basic share ⁽⁶⁾	$	0.30	$	0.28
Per diluted share ⁽⁶⁾	$	0.28	$	0.26
Net profit before certain non-cash items ⁽⁵⁾		7,299		7,938
Per basic share ⁽⁶⁾	$	0.07	$	0.07
Per diluted share ⁽⁶⁾	$	0.07	$	0.07
Net profit (loss)		9,251		(13,597	)
Per basic share ⁽⁶⁾	$	0.09	$	(0.13	)
Per diluted share ⁽⁶⁾	$	0.08	$	(0.13	)
Exploration and development		32,083		47,141
Corporate and property acquisitions		20,965		121
Capital expenditures – cash		53,048		47,262
Property dispositions – cash		10		(22	)
Non-cash items		27,487		6,165
Total capital expenditures – net		80,545		53,405

		Three months ended December 31,
(CDN$000s except share and per share amounts)		2012			2011
OPERATING
Average daily sales volumes
Crude oil, condensate and NGLs	(bbls/d)		5,730			5,420
Natural gas	(mcf/d)		78,195			52,734
Total oil equivalent	(boe/d)		18,763			14,209
Average prices
Light crude oil and condensate	($/bbl)		82.58			95.18
NGLs (excluding condensate)	($/bbl)		38.84			54.31
Heavy oil	($/bbl)		65.30			74.30
Crude oil, condensate and NGLs	($/bbl)		69.55			85.09
Crude oil, condensate and NGLs (including risk management ⁽¹⁾)	($/bbl)		72.11			82.90
Natural gas	($/mcf)		3.46			3.30
Natural gas (including risk management ⁽¹⁾)	($/mcf)		3.67			3.62
Total oil equivalent	($/boe)		35.67			44.69
Total oil equivalent (including risk management⁽¹⁾)	($/boe)		37.30			45.07
Statistics
Operating netback ⁽⁴⁾	($/boe)		19.20			26.00
Operating netback ⁽⁴⁾ (including risk management ⁽¹⁾)	($/boe)		20.83			26.38
Transportation	($/boe)		0.70			1.21
Production expenses	($/boe)		8.91			10.78
General & administrative	($/boe)		2.54			2.88
Royalties as a % of sales after transportation			20	%		15	%
DILUTED WEIGHTED AVERAGE SHARES
Diluted weighted average shares – net profit (loss) ⁽⁶⁾			118,931,047			109,349,045
Diluted weighted average shares – funds flow from operations and cash flow from operating activities ^{(2) (6)}			118,931,047			119,170,474
SHARE TRADING STATISTICS
TSX and Other ⁽⁷⁾ (CDN$, except volumes) based on intra-day trading
High			4.47			5.05
Low			3.59			3.15
Close			4.27			4.91
Average daily volume			842,840			928,836
NYSE MKT ⁽⁸⁾ (US$, except volumes) based on intra-day trading
High			4.54			-
Low			3.69			-
Close			4.28			-
Average daily volume			39,079			-

⁽¹⁾ The Company has entered into various commodity price risk management contracts which are considered to be economic hedges. Per unit metrics after risk management includes only the realized portion of gains or losses on commodity contracts.

The Company does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per share metrics calculations disclosed.

⁽²⁾ The highlights section contains the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with generally accepted accounting principles (“GAAP”) as an indicator of the Company’s performance. Therefore reference to additional GAAP terms of diluted funds flow from operations or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found further in the MD&A. Funds flow from operations per share is calculated using the weighted average number of common shares for the period.

⁽³⁾ Net debt and total net debt are considered additional GAAP terms. The Company’s calculation of total net debt includes the liability component of convertible debentures and excludes deferred liabilities, long-term commodity contract liabilities, decommissioning liabilities, long-term finance lease obligations and the deferred tax liability. Net debt and total net debt include the net working capital deficiency (excess) before short-term commodity contract assets and liabilities and current finance lease obligations. Net debt also excludes the liability component of convertible debentures. A reconciliation between total liabilities under GAAP and total net debt and net debt as calculated by the Company is found further in the MD&A.

⁽⁴⁾ Operating netbacks is considered a non-GAAP term. Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income.

⁽⁵⁾ Net profit before certain non-cash items is considered a non-GAAP term. Net profit before certain non-cash items is calculated as net profit (loss) per the Consolidated Statement of Comprehensive Income, excluding the impairment loss (reversal) on property, plant and equipment, the unrealized gain or loss on commodity contracts, the gain on property acquisition, and the gain or loss on property dispositions, net of deferred tax impacts on each item. The Company’s reconciliation between the net profit and net profit before certain non-cash items is found in this MD&A.

⁽⁶⁾ Basic weighted average shares for the three months ended December 31, 2012 were 107,734,134 (2011: 107,397,265).

In computing weighted average diluted earnings per share for the three months ended December 31, 2012, a total of 1,375,484 common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and a total of 9,821,429 common shares issuable on conversion of convertible debentures were also added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 118,931,047. In computing weighted average diluted earnings per share for the three months ended December 31, 2011, a total of 1,951,780 common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and a total of 9,821,429 common shares issuable on conversion of convertible debentures were excluded from the denominator as they were not dilutive, resulting in diluted weighted average common shares of 107,397,265.

In computing weighted average diluted net profit before certain items per share for the three months ended December 31, 2012, a total of 1,375,484 (2011: 1,951,780) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options as they were dilutive, and a total of 9,821,429 (2011: 9,821,429) common shares issuable on conversion of convertible debentures were excluded from the denominator as they were not dilutive, resulting in diluted weighted average common shares of 109,109,618 (2011:109,349,045).

In computing weighted average diluted cash flow from operating activities and funds flow from operations per share for the three months ended December 31, 2012, a total of 1,375,484 (2011: 1,951,780) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and a total of 9,821,429 (2011: 9,821,429) common shares issuable on conversion of convertible debentures were also added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 118,931,047 (2011: 119,170,474). As a consequence, a total of $0.8 million (2011: $0.8 million) for interest accretion expense (net of income tax effect) was added to the numerator.

⁽⁷⁾ TSX and Other includes the trading statistics for the Toronto Stock Exchange and other Canadian trading markets.

⁽⁸⁾ The Company’s common shares commenced trading on the NYSE MKT on September 24, 2012.

As detailed previously in this Management’s Discussion and Analysis, funds flow from operations is a term that does not have any standardized meaning under GAAP. Funds flow from operations is calculated as cash flow from operating activities before asset retirement costs incurred and changes in non-cash working capital incurred.

Reconciliation of Cash Flow from Operating Activities to Funds Flow from Operations

	Three months ended December 31,
($000s)	2012			2011
Cash flow from operating activities		32,007			30,626
Decommissioning costs incurred		76			186
Change in non-cash working capital		(2,218	)		(692	)
Funds flow from operations		29,865			30,120

Funds flow from operations during the fourth quarter of 2012 was $29.9 million, a decrease of 0.9% compared to $30.1 million for the fourth quarter of 2011. The decrease in funds flow from operations between the periods was due primarily to lower pricing for light and heavy oil, condensate, and NGL’s, largely offset by higher production volumes and slightly higher natural gas prices in the 2012 fourth quarter. Fluctuations in oil and gas prices during the fourth quarter of 2012 resulted in an increase in net realized gains on commodity risk management contracts by approximately $2.3 million compared to the fourth quarter of 2011. Cash flow from operating activities during the fourth quarter of 2012 was $32.0 million, compared to $30.6 million for the fourth quarter of 2011. The increase in cash flow from operating activities between the periods was reflective of an increase in cash from changes in working capital, and a minor decrease in decommissioning costs incurred.

In the fourth quarter of 2012, Bellatrix realized a net profit of $9.3 million compared to a net loss of $13.6 million in the fourth quarter of 2011. The net profit recorded in the fourth quarter of 2012 compared to the net loss in the fourth quarter of 2011 is primarily a consequence of a $1.3 million non-cash unrealized gain on commodity risk management compared to a $17.7 million loss in the 2011 period, and a $16.2 million non-cash gain on property acquisition recognized in the 2012 fourth quarter, offset by a higher non-cash impairment loss on oil and gas properties, slightly increased depletion and depreciation expenses, and a deferred income tax expense of $3.3 million in the 2012 fourth quarter compared to a $4.0 million recovery in the 2011 period.

As previously noted in this MD&A, net profit before certain non-cash items is a non-GAAP measure. A reconciliation between this measure and net profit per the Consolidated Statement of Comprehensive Income is provided below.

For the fourth quarter of 2012, net profit before certain non-cash items, net of associated deferred tax impacts, was $7.3 million compared to $7.9 million in 2011.

Reconciliation of Net Profit (Loss) to Net Profit Before Certain Non-Cash Items

	Three months ended December 31,
($000s)	2012			2011
Net profit (loss) per financial statements		9,251			(13,597	)
Items subject to reversal
Impairment loss on property, plant and equipment		14,820			11,018
Unrealized (gain) loss on commodity contracts		(1,313	)		17,676
Gain on property acquisition		(16,160	)		-
Loss on property dispositions		50			20
Deferred tax impact of above items		651			(7,179	)
Net profit before certain non-cash items		7,299			7,938

Sales Volumes

		Three months ended December 31,
		2012		2011
Light oil and condensate	(bbls/d)		3,910		3,925
NGLs (excluding condensate)	(bbls/d)		1,631		1,173
Heavy oil	(bbls/d)		189		322
Total crude oil, condensate and NGLs	(bbls/d)		5,730		5,420

Natural gas	(mcf/d)		78,195		52,734

Total boe/d	(6:1)		18,763		14,209

Sales volumes for the three months ended December 31, 2012 averaged 18,763 boe/d, an increase of 32% from the 14,209 boe/d sold in the fourth quarter of 2011. The weighting toward crude oil, condensate and NGLs sales volumes decreased to 31% in the 2012 fourth quarter, compared to 38% in the corresponding period in 2011. Fourth quarter 2012 natural gas, NGL, and total overall sales volumes were higher than the same period in 2011 primarily due to the continued success achieved from the Company’s liquids rich drilling program.

Natural gas sales averaged 78.2 Mmcf/d during the fourth quarter of 2012, compared to 52.7 Mmcf/d in the fourth quarter of 2011. The weighting toward natural gas sales volumes averaged 69% in the fourth quarter of 2012, an increase over the 62% weighting realized in the corresponding period in 2011. Crude oil, condensate and NGL sales volumes increased to 5,730 bbls/d in the fourth quarter of 2012 compared to 5,420 bbls/d during the same period of 2011.

Revenue

	Three months ended December 31,
($000s)	2012		2011
Light crude oil and condensate		29,702		34,366
NGLs (excluding condensate)		5,829		5,862
Heavy oil		1,136		2,204
Crude oil and NGLs		36,667		42,432
Natural gas		24,904		15,995
Total revenue before other		61,571		58,247
Other ⁽¹⁾		712		767
Total revenue before royalties and risk management		62,283		59,194

⁽¹⁾Other revenue primarily consists of processing and other third party income.

Revenue before other income, royalties and commodity price risk management contracts for the fourth quarter of 2012 was $61.6 million, an increase of 6% from $58.2 million in the fourth quarter of 2011. The increase in revenues between the periods was due to increased sales volumes and slightly higher natural gas prices in the 2012 period, partially offset by lower crude oil, condensate, and NGL prices.

Light oil and condensate revenues for the fourth quarter of 2012 were down 14% from the same period in 2011 due to lower prices. For light oil and condensate, Bellatrix recorded an average $82.58/bbl before commodity price risk management contracts during the fourth quarter of 2012, 13% lower than the average price of $95.18/bbl received in the comparative 2011 period. In comparison, the Edmonton par price decreased by 14% over the same period. The average WTI crude oil benchmark price decreased by 6% in fourth quarter of 2012 compared to the same period in 2011. The average US$/CDN$ foreign exchange rate was 1.0093 for the three months ended December 31, 2012, an increase of 3% compared to an average rate of 0.9773 in the same period in 2011.

NGL revenues for the fourth quarter of 2012 were comparable to the 2011 period as a result of higher sales volumes offset by lower prices. For NGLs (excluding condensate), Bellatrix recorded an average $38.84/bbl during the fourth quarter of 2012, a 28% decrease from the $54.31/bbl received in the comparative 2011 period. The decrease in NGL pricing between the 2012 and 2011 periods is largely attributable to changes in NGL market supply conditions between the periods.

The decrease in heavy oil revenue from the fourth quarter of 2011 to the same period in 2012 is reflective of lower sales volumes and reduced prices. Bellatrix sold its Wainwright heavy oil property, with 59 bbls/d of current production, in the third quarter of 2012. For heavy crude oil, Bellatrix received an average price before commodity risk management contracts of $65.30/bbl in the 2012 fourth quarter, a decrease of 12% from the $74.30/bbl realized in the fourth quarter of 2011. In comparison, the Bow River reference price decreased by 19%, and the Hardisty Heavy reference price decreased by 21% between the fourth quarter of 2011 and the fourth quarter of 2012. The majority of Bellatrix’s heavy crude oil density ranges between 11 and 16 degrees API, consistent with the Hardisty Heavy reference price.

Natural gas revenues in the fourth quarter of 2012 were up 56% from the same period in 2011 as a result of a 48% increase in sales volumes and a slight increase in natural gas prices between the periods. Bellatrix’s natural gas sales are priced with reference to the daily or monthly AECO indices. Bellatrix’s natural gas sold has a higher heat content than the industry average, which results in slightly higher prices per mcf than the daily AECO index. During the fourth quarter of 2012, the AECO daily reference price increased by 1%, and the AECO monthly reference price decreased by approximately 12% compared to the fourth quarter of 2011. Bellatrix’s natural gas average sales price before commodity price risk management contracts for the fourth quarter of 2012 increased by 5% to $3.46/mcf compared to the $3.30/mcf realized in the same period in 2011. The more significant increase in Bellatrix’s realized natural gas prices compared to the daily AECO index between the periods was primarily due to the weighting of sales volumes realized at increased prices during the fourth quarter of 2012. Bellatrix’s natural gas average price after including commodity price risk management contracts for the three months ended December 31, 2012 was $3.67/mcf, compared to $3.62/mcf for the three months ended December 31, 2011.

In the fourth quarter of 2012, average sales volumes increased 21% from the third quarter 2012 average volumes of 15,503 boe/d. The increase was due to the success achieved from the Company’s drilling program in 2012.

During the fourth quarter of 2012, Bellatrix spent $32.1 million on capital projects, excluding corporate and asset acquisitions and dispositions, compared to $47.1 million in 2011. In the fourth quarter of 2012, Bellatrix drilled or participated in 10 gross wells (6.17 net), all of which were Cardium light oil horizontal wells. In the fourth quarter of 2011, Bellatrix drilled or participated in 12 (7.64 net) wells including 8 gross (6.68 net) oil wells, 3 gross (0.95 net) natural gas wells, and participated in 1 gross (0.007 net) dry hole that was drilled in a non-operated oil unit.

In the fourth quarter of 2012, the Company paid $11.8 million in royalties, compared to $8.8 million in the same period in 2011. As a percentage of pre-commodity price risk management sales (after transportation costs), royalties were 20% in the fourth quarter of 2012 compared to 15% in the same period in 2011. Royalties for the fourth quarter of 2011 were reduced by $1.5 million in adjustments relating to previous quarter estimates, primarily for wells under the recent Alberta royalty programs. Excluding these adjustments, the average royalty rate percentage for the fourth quarter of 2011 would be 18%. Certain light oil wells are now incurring higher royalty rates as they come off the initial royalty incentive rates. The Company’s heavy oil properties are minor, and consist of principally the Frog Lake Alberta assets which are subject to high crown royalty rates. The Company’s royalty percentage for natural gas royalties continues to decline due to increased production from recently drilled wells which take advantage of Alberta royalty incentive programs.

In the fourth quarter of 2012, operating costs totaled $15.4 million, compared to $14.1 million recorded in the same period of 2011. During the fourth quarter of 2012, operating costs averaged $8.91/boe, down from the $10.78/boe incurred during the fourth quarter of 2011. The decrease was primarily due to increased production from recent drilling in areas with lower production expenses and the Company’s continued efforts to streamline operations and field optimization projects. In comparison, operating costs for the third quarter of 2012 averaged $7.96/boe. The increase between the third and fourth quarters of 2012 was primarily due to additional chemical well treating, compressor rentals, and other maintenance expenses.

During the fourth quarter of 2012, the Company’s field operating netbacks before commodity risk management contracts decreased by 26% to $19.20/boe compared to $26.00/boe in the comparative 2011 period, driven primarily by a 20% decrease in overall commodity prices and a slight 2% increase in royalties, partially offset by a 17% reduction in production expenses and a 41% reduction in transportation costs. In comparison, the Company’s field operating netback before commodity risk management contracts for the third quarter of 2012 was $18.29/boe.

Field operating netbacks for natural gas before commodity price risk management contracts during the fourth quarter of 2012 of $1.85/mcf were 52% higher than the $1.22/mcf recorded in the same period in 2011. The increase was primarily a result of slightly higher gas prices, as well as lower transportation, royalties, and production expenses. In comparison, the field operating netback for natural gas before commodity risk management contracts for the third quarter of 2012 was $1.12/mcf.

Field operating netbacks before commodity price risk management contracts for crude oil, condensate and NGLs during the fourth quarter of 2012 averaged $37.60/bbl, a decrease of 33% from the $56.26/bbl realized during the fourth quarter of 2011. The decrease between the periods was primarily as a result of weaker commodity prices and increased royalties, offset partially by decreases in production and transportation expenses. In comparison, the field operating netback for crude oil, condensate and NGLs for the third quarter of 2012 was $41.12/bbl.

In the fourth quarter of 2012, general and administrative expenses (“G&A”), net of capitalized G&A and recoveries, were $4.4 million, compared to $3.8 million in the comparable 2011 period. The increase to net G&A was primarily attributable to increases in staffing costs between the periods. The overall increase in G&A expenses was offset slightly by higher capitalized G&A and recoveries as a result of the increase in capital activity in the fourth quarter of 2012 compared to the fourth quarter of 2011.

Depletion, depreciation and accretion expense for the fourth quarter of 2012 was $18.6 million ($10.77/boe), compared to $17.6 million ($13.48/boe) in 2011. The increase in depletion, depreciation and accretion expense from the 2011 fourth quarter to that in 2012 is reflective of the 32% increase in sales volumes between the same comparative periods, offset by the additional reserves achieved through the Company’s drilling success.

2012 Annual Financial and Operational Results

Acquisition and Dispositions

Effective November 1, 2012, Bellatrix acquired Cardium and Notikewin/Falher lands and production in the Willesden Green area adjacent to Bellatrix’s core area in the Ferrier/Willesden Green Cardium light oil resource play in West Central Alberta. The assets acquired included then current production capability of approximately 500 boe/d (32% oil and liquids and 68% natural gas), 16 gross (11.95 net) sections of Cardium and Mannville prospective lands, 25 net Cardium development locations, 4 net Notikewin/Falher development locations, and a 25% working interest in an operated compressor station and gathering system. Bellatrix acquired these assets for a net purchase price of $21 million, which was funded using the Company’s existing credit facilities.

On December 14, 2012, Bellatrix acquired an additional 11 gross and net sections of highly prospective Cardium and Notikewin/Falher lands in the Ferrier area of west-central Alberta, subject to the receipt of land permits anticipated in Q1 2013. This acquisition is anticipated to provide an additional 37 net drilling locations in the Cardium, 9 net locations in the Notikewin/Falher, and an additional 66 net locations in the Duvernay formation. The Company continues to focus on adding Cardium and Notikewin prospective lands.

During the third quarter of 2012, Bellatrix closed on the disposition of a minor non-core property interest in the Wainwright area, Alberta for $4.25 million after adjustments. This non-operated unit heavy oil property had production of approximately 59 boe/d. The net proceeds from the disposition were initially used to reduce the Company’s bank indebtedness, and ultimately were directed towards the development of the Company’s Cardium oil resource program.

During the second quarter of 2012, Bellatrix closed on the disposition of the Girouxville property in Alberta, a minor non-core property interest. The property was sold for $0.6 million after adjustments.

Additionally, in the second quarter of 2012, Bellatrix closed on the disposition of the Cypress-Chowade property in British Columbia, a minor non-core property interest. The property was sold for $1.4 million after adjustments. There was no current production from the Cypress-Chowade property.

Bellatrix had other minor property dispositions in 2012 resulting in total cumulative property dispositions of $6.7 million.

Sales Volumes

Sales volumes for the year ended December 31, 2012 averaged 16,686 boe/d compared to 11,954 boe/d for the 2011 year, representing a 40% increase. Total crude oil, condensate and NGLs averaged approximately 34% of sales volumes for the year ended December 31, 2012, compared to 38% of sales volumes in the 2011 year. The increase in sales was primarily a result of a year over year increased capital program and the associated drilling success achieved in the Cardium and Notikewin resource plays. Capital expenditures for the year ended December 31, 2012 were $185.3 million, compared to $179.6 million for the 2011 year.

Sales Volumes

		Years ended December 31,
		2012		2011
Light oil and condensate	(bbls/d)		3,996		3,416
NGLs (excluding condensate)	(bbls/d)		1,441		808
Heavy oil	(bbls/d)		280		316
Total crude oil, condensate and NGLs	(bbls/d)		5,717		4,540

Natural gas	(mcf/d)		65,812		44,484

Total boe/d	(6:1)		16,686		11,954

During the 2012 year, Bellatrix posted a 100% success rate drilling and/or participating in 34 gross (26.32 net) wells, resulting in 28 gross (21.32 net) Cardium oil wells, 2 gross (2.0 net) Cardium condensate-rich gas wells, 1 gross (1.0 net) Duvernay gas well, and 3 gross (2.0 net) Notikewin/Falher liquids-rich gas wells.

By comparison, Bellatrix drilled or participated in 54 gross (34.84 net) wells during the 2011 year, including 39 gross (29.04 net) oil wells, 14 gross (5.79 net) liquids-rich natural gas wells, and 1 gross (0.007 net) dry hole that was drilled in a non-operated oil unit.

For the year ended December 31, 2012, crude oil, condensate and NGL sales volumes increased by approximately 26%, averaging 5,717 bbl/d compared to 4,540 bbl/d in the 2011 year. For the year ended December 31, 2012, sales volumes for crude oil, condensate and NGLs averaged approximately 34% of total sales volumes compared to approximately 38% of total sales volumes in the 2011 year. The reduction in liquids weighting between the years was a direct result of adding the dry gas producing Duvernay well during the second quarter of 2012, as well as bringing on several other high-productivity gas wells throughout the 2012 year.

Sales of natural gas averaged 65.8 Mmcf/d for the year ended December 31, 2012, compared to 44.5 Mmcf/d in the 2011 year, an increase of approximately 48%. The weighting towards natural gas sales volumes averaged approximately 66% for the year ended December 31, 2012, compared to 62% in the 2011 year.

For 2013, Bellatrix will utilize pad drilling, involving the drilling of multiple horizontal wells from single surface locations, enhancing resource development efficiency, minimizing the Company’s environmental footprint, and improving cost and on-stream efficiencies. An initial capital expenditure budget of between $230 to $240 million has been set for fiscal 2013. Based on the timing of proposed expenditures, downtime for scheduled and unscheduled plant turnarounds, completion of required infrastructure, and normal production declines, execution of the 2013 capital expenditure plan is anticipated to provide average daily production of approximately 24,000 to 25,000 boe/d and an exit rate of approximately 30,000 boe/d to 31,000 boe/d.

Commodity Prices

Average Commodity Prices

	Years ended December 31,
	2012		2011		% Change

Average exchange rate (US$/Cdn$)		1.0009		1.0111		(1	)

Crude oil:
WTI (US$/bbl)		94.14		95.12		(1	)
Edmonton par – light oil ($/bbl)		86.53		95.16		(9	)
Bow River – medium/heavy oil ($/bbl)		74.30		78.30		(5	)
Hardisty Heavy – heavy oil ($/bbl)		64.99		69.10		(6	)
Bellatrix’s average prices ($/bbl)
Light crude oil and condensate		86.47		92.51		(7	)
NGLs (excluding condensate)		38.88		53.54		(27	)
Heavy crude oil		68.51		68.23		-
Total crude oil and NGLs		73.59		83.89		(12	)
Total crude oil and NGLs (including risk management ⁽¹⁾)		72.65		81.47		(11	)

Natural gas:
NYMEX (US$/mmbtu)		2.83		4.03		(30	)
AECO daily index (CDN$/mcf)		2.39		3.62		(34	)
AECO monthly index (CDN$/mcf)		2.40		3.67		(35	)
Bellatrix’s average price ($/mcf)		2.62		3.77		(31	)
Bellatrix’s average price (including risk management ⁽¹⁾) ($/mcf)		3.17		4.05		(22	)

⁽¹⁾Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.

During 2012, the differential between West Texas Intermediate (“WTI”) and Edmonton par price widened, whereas for 2011 the differential was nearly non-existent. North America has seen significant increases in light oil production as a result of the rapid pace of development in the shale oil reservoirs. These volumes have displaced Canadian production resulting in lower demand for Edmonton light oil. This factor, along with higher incidences of refinery maintenance in 2012 and continued refinery conversions to run heavier streams, has resulted in the widening of the price differential between WTI and Edmonton par. For light oil and condensate, Bellatrix recorded an average $86.47/bbl before commodity price risk management contracts during the year ended December 31, 2012, 7% lower than the average price received in the 2012 year. In comparison, the Edmonton par price decreased by 9% over the same period. The average WTI crude oil benchmark price decreased by 1% in the year ended December 31, 2012 compared to the 2011 year. The average US$/CDN$ foreign exchange rate was 1.0009 for the year ended December 31, 2012, a decrease of 1% compared to an average rate of 1.0111 in the 2011 year.

For NGLs (excluding condensate), Bellatrix recorded an average $38.88/bbl during the year ended December 31, 2012, a 27% decrease from the $53.54/bbl received in the 2011 year. The decrease in NGL pricing between the 2012 and 2011 years is largely attributable to changes in NGL market supply conditions between the years.

For heavy crude oil, Bellatrix received an average price before commodity risk management contracts of $68.51/bbl in the 2012 year, consistent with the average price of $68.23/bbl realized in the 2011 year. In comparison, the Bow River reference price decreased by 5%, and the Hardisty Heavy reference price decreased by 6% between the 2012 and 2011 years. The majority of Bellatrix’s heavy crude oil density ranges between 11 and 16 degrees API, consistent with the Hardisty Heavy reference price.

Bellatrix’s natural gas sales are priced with reference to the daily or monthly AECO indices. Bellatrix’s natural gas sold has a higher heat content than the industry average, which results in slightly higher prices per mcf than the daily AECO index. During the 2012 year, the AECO daily reference price decreased by 34%, and the AECO monthly reference price decreased by approximately 35% compared to the 2011 year. Bellatrix’s natural gas average sales price before commodity price risk management contracts for the 2012 year decreased by 31% to $2.62/mcf compared to $3.77/mcf in the 2011 year. The lower decrease in Bellatrix’s realized natural gas prices compared to the daily AECO index between the years was primarily due to the weighting of additional sales volumes realized at increasing prices throughout the 2012 year. Bellatrix’s natural gas average price after including commodity price risk management contracts for the year ended December 31, 2012 was $3.17/mcf, compared to $4.05/mcf for the year ended December 31, 2011.

Revenue

Revenue before other income, royalties and commodity price risk management contracts for the year ended December 31, 2012 was $217.1 million, 8% higher than the $200.2 million in the 2011 year. The increase in revenues between the years was due to increased sales volumes between the years, partially offset by reduced liquids and natural gas prices experienced in the 2012 year.

Revenue before other income, royalties and commodity price risk management contracts for crude oil and NGLs for the year ended December 31, 2012 increased by 11% from the 2011 year, resulting from higher sales volumes, partially offset by lower light crude oil, condensate and NGL prices when compared to the 2011 year. In the 2012 year, total crude oil, condensate and NGL revenues contributed 71% of total revenue (before other) compared to 69% in the 2011 year. Light crude oil, condensate and NGL revenues in the year ended December 31, 2012 comprised 95% of total crude oil, condensate and NGL revenues (before other) for those periods, compared to 94% in the 2011 year.

Natural gas revenue before other income, royalties and commodity price risk management contracts for the year ended December 31, 2012 increased by approximately 3% compared to the 2011 year as a result of an approximate 48% increase in sales volumes between the years, largely offset by a 31% decrease in realized gas prices before risk management.

	Years ended December 31,
($000s)	2012		2011
Light crude oil and condensate		126,468		115,353
NGLs (excluding condensate)		20,504		15,782
Heavy oil		7,023		7,866
Crude oil and NGLs		153,995		139,001
Natural gas		63,143		61,186
Total revenue before other		217,138		200,187
Other ⁽¹⁾		2,176		2,131
Total revenue before royalties and risk management		219,314		202,318

⁽¹⁾Other revenue primarily consists of processing and other third party income.

Commodity Price Risk Management

The Company has a formal commodity price risk management policy which permits management to use specified price risk management strategies including fixed price contracts, collars and the purchase of floor price options and other derivative financial instruments and physical delivery sales contracts to reduce the impact of price volatility for a maximum of eighteen months beyond the transaction date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Company seeks to provide a measure of stability to funds flow from operations, as well as to ensure Bellatrix realizes positive economic returns from its capital development and acquisition activities. The Company plans to continue its commodity price risk management strategies focusing on maintaining sufficient cash flow to fund Bellatrix’s capital expenditure program. Any remaining production is realized at market prices.

A summary of the financial commodity price risk management volumes and average prices by quarter currently outstanding as of March 6, 2013 is shown in the following tables:

Natural gas

Average Volumes (GJ/d)

		Q1 2013				Q2 2013				Q3 2013				Q4 2013
Fixed			6,556				55,000				55,000				35,109

		Q1 2014				Q2 2014				Q3 2014				Q4 2014
Fixed			15,000				15,000				-				-

Average Price ($/GJ AECO C)

		Q1 2013				Q2 2013				Q3 2013				Q4 2013
Fixed			3.05				3.06				3.06				3.05

		Q1 2014				Q2 2014				Q3 2014				Q4 2014
Fixed			3.05				3.05				-				-

Crude oil and liquids

Average Volumes (bbls/d)

	Q1 2013		Q2 2013		Q3 2013		Q4 2013
Call option		3,000		3,000		3,000		3,000
Fixed		1,500		1,500		1,500		1,500
Total bbls/d		4,500		4,500		4,500		4,500

		Q1 2014				Q2 2014				Q3 2014				Q4 2014
Call option			3,000				3,000				3,000				3,000

Average Price ($/bbl WTI)

	Q1 2013		Q2 2013		Q3 2013		Q4 2013
Call option (ceiling price) (US$/bbl)		110.00		110.00		110.00		110.00
Fixed price (CDN$/bbl)		94.50		94.50		94.50		94.50

		Q1 2014				Q2 2014				Q3 2014				Q4 2014
Call option (ceiling price) (US$/bbl)			105.00				105.00				105.00				105.00

As of December 31, 2012, the fair value of Bellatrix’s outstanding commodity contracts is a net unrealized asset of $0.2 million as reflected in the financial statements. The fair value or mark-to-market value of these contracts is based on the estimated amount that would have been received or paid to settle the contracts as at December 31, 2012 and will be different from what will eventually be realized. Changes in the fair value of the commodity contracts are recognized in the Consolidated Statements of Comprehensive Income within the financial statements.

The following is a summary of the gain (loss) on commodity contracts for the years ended December 31, 2012 and 2011 as reflected in the Consolidated Statements of Comprehensive Income in the financial statements:

Commodity contracts

($000s)	Crude Oil & Liquids			Natural Gas		2012 Total
Realized cash gain (loss) on contracts		(1,976	)		13,245		11,269
Unrealized gain on contracts ⁽¹⁾		6,267			4,539		10,806
Total gain on commodity contracts		4,291			17,784		22,075

Commodity contracts

($000s)	Crude Oil & Liquids			Natural Gas		2011 Total
Realized cash gain (loss) on contracts		(4,015	)		4,582		567
Unrealized gain (loss) on contracts ⁽¹⁾		(9,879	)		2,979		(6,900	)
Total gain (loss) on commodity contracts		(13,894	)		7,561		(6,333	)

⁽¹⁾

Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts during the period.

Royalties

For the year ended December 31, 2012, total royalties were $38.8 million compared to $34.7 million incurred in the 2011 year. Overall royalties as a percentage of revenue (after transportation costs) in the 2012 year were 18%, compared with 18% in the 2011 year.

Certain light oil wells are now incurring higher royalty rates as they come off the initial royalty incentive rates. The Company’s heavy oil properties are minor, and consist of principally the Frog Lake Alberta assets which are subject to high crown royalty rates. The Company’s royalty percentage for natural gas royalties continues to decline due to increased production from recently drilled wells which take advantage of Alberta royalty incentive programs. Natural gas royalties and total royalties recognized in 2012 were reduced by $1.5 million and $1.7 million, respectively, in adjustments relating to prior period estimates, primarily for Ferrier area wells for Indian Oil and Gas Canada royalties under recent royalty incentive programs. Excluding these adjustments, the average natural gas and overall corporate royalty rate percentages for 2012 would be 6% and 19%, respectively.

Royalties by Commodity Type	Years ended December 31,
($000s, except where noted)	2012		2011
Light crude oil, condensate and NGLs		33,607		23,065
$/bbl		16.89		14.96
Average light crude oil, condensate and NGLs royalty rate (%)		23		18

Heavy Oil		3,496		3,538
$/bbl		34.11		30.69
Average heavy oil royalty rate (%)		52		46

Natural Gas		1,653		8,095
$/mcf		0.07		0.50
Average natural gas royalty rate (%)		3		14

Total		38,756		34,698
$/boe		6.35		7.95
Average total royalty rate (%)		18		18

Royalties, by Type

	Years ended December 31,
($000s)	2012		2011
Crown royalties		11,518		12,264
Indian Oil and Gas Canada royalties		8,038		8,346
Freehold & GORR		19,200		14,088
Total		38,756		34,698

Expenses

	Years ended December 31,
($000s)	2012		2011
Production		53,316		50,313
Transportation		4,978		5,715
General and administrative		14,272		12,358
Interest and financing charges⁽¹⁾		9,834		7,041
Share-based compensation		3,219		2,939

⁽¹⁾Does not include financing charges in relation to the Company’s accretion of decommissioning liabilities.

Expenses per boe

	Years ended December 31,
($ per boe)	2012		2011
Production		8.73		11.53
Transportation		0.82		1.31
General and administrative		2.34		2.83
Interest and financing charges		1.61		1.61
Share-based compensation		0.53		0.67

Production Expenses

For the year ended December 31, 2012, production expenses totaled $53.3 million ($8.73/boe), compared to $50.3 million ($11.53/boe) in the 2011 year. For the year ended December 31, 2012, production expenses increased overall, while decreasing on a per boe basis when compared to the 2011 year. The decrease in production expenses on a boe basis in the 2012 year was primarily due to increased production, which is a result of drilling in both 2011 and 2012 in areas with lower production expenses, as well as reduced processing fees in certain areas and continued field optimization projects.

Bellatrix is targeting operating costs of approximately $73.6 million ($8.00/boe) in the 2013 year, which is a reduction from the $8.73/boe operating costs incurred for the 2012 year. This is based upon assumptions of estimated 2013 average production of approximately 24,000 boe/d to 25,000 boe/d, continued field optimization work and planned capital expenditures in producing areas which are anticipated to have lower operating costs.

Production Expenses, by Commodity Type

	Years ended December 31,
($000s, except where noted)	2012			2011
Light crude oil, condensate and NGLs		21,840			20,536
$/bbl		10.97			13.32

Heavy oil		1,555			2,587
$/bbl		15.17			22.44

Natural gas		29,921			27,190
$/mcf		1.24			1.67

Total		53,316			50,313
$/boe		8.73			11.53

Total		53,316			50,313
Processing and other third party income ⁽¹⁾		(2,176	)		(2,131	)
Total after deducting processing and other third party income		51,140			48,182
$/boe		8.37			11.04

⁽¹⁾

Processing and other third party income is included within petroleum and natural gas sales on the Consolidated Statements of Comprehensive Income.

Transportation

Transportation expenses for the year ended December 31, 2012 were $5.0 million ($0.82/boe), compared to $5.7 million ($1.31/boe) in the 2011 year. The decrease in overall and per boe costs is reflective of a higher volume of oil production being shipped through pipelines rather than through trucking at a higher cost, as well as reduced gas transportation fees resulting from the acquisition of an ownership interest in certain gathering and processing facilities in the first half of 2011.

Operating Netback

Field Operating Netback – Corporate (before risk management)

	For the years ended December 31,
($/boe)	2012			2011
Sales		35.56			45.88
Transportation		(0.82	)		(1.31	)
Royalties		(6.35	)		(7.95	)
Production expense		(8.73	)		(11.53	)
Field operating netback		19.66			25.09

For the year ended December 31, 2012, the corporate field operating netback (before commodity price risk management contracts) was $19.66/boe compared to $25.09/boe in the 2011 year. The reduced netback was primarily the result of reduced commodity prices, offset by reduced transportation, royalty and production expenses. After including commodity price risk management contracts, the corporate field operating netback for the 2012 year was $21.51/boe compared to $25.22/boe in the 2011 year. Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.

Field Operating Netback – Crude Oil, Condensate and NGLs (before risk management)

	Years ended December 31,
($/bbl)	2012			2011
Sales		73.59			83.89
Transportation		(0.98	)		(1.86	)
Royalties		(17.73	)		(16.06	)
Production expense		(11.18	)		(13.96	)
Field operating netback		43.70			52.01

Field operating netback for crude oil, condensate and NGLs averaged $43.70/bbl for the year ended December 31, 2012, a decrease of 16% from $52.01/bbl realized in the 2011 year. In the 2012 year, Bellatrix’s combined crude oil and NGLs average price (before risk management) decreased by approximately 12% compared to the 2011 year. The commodity price decrease in conjunction with a slight increase in royalties was partially offset by reductions in production and transportation expenses, resulting in the overall decrease to the field operating netback for crude oil, condensate and NGLs. After including commodity price risk management contracts, field operating netback for crude oil and NGLs for the year ended December 31, 2012 decreased to $42.76/boe compared to $49.58/boe in the 2011 year.

Field Operating Netback – Natural Gas (before risk management)

	Years ended December 31,
($/mcf)	2012			2011
Sales		2.62			3.77
Transportation		(0.12	)		(0.16	)
Royalties		(0.07	)		(0.50	)
Production expense		(1.24	)		(1.67	)
Field operating netback		1.19			1.44

Field operating netback for natural gas in the year ended December 31, 2012 year decreased by 17% to $1.19/mcf, compared to $1.44/mcf realized in the 2011 year, reflecting depressed natural gas prices, offset somewhat by lower production, transportation and royalty expenses. After including commodity price risk management contracts, field operating netback for natural gas for the year ended December 31, 2012 increased to $1.74/mcf, which compared to $1.72/mcf in the 2011 year.

General and Administrative

General and administrative (“G&A”) expenses (after capitalized G&A and recoveries) for the year ended December 31, 2012 were $14.3 million ($2.34/boe), compared to $12.4 million ($2.83/boe) for the 2011 year. G&A expenses in the 2012 year were higher in comparison to the 2011 year, which is reflective of higher compensation costs and slightly reduced recoveries, offset partially by higher capitalized G&A. On a boe basis, G&A for the year ended December 31, 2012 decreased by approximately 17% when compared to the 2011 year. The decrease was primarily as a result of higher average sales volumes in the 2012 year, despite higher overall costs.

For 2013, the Company is anticipating G&A expenses after capitalization to be approximately $23.0 million ($2.50/boe) based on estimated 2013 average production volumes of approximately 24,000 boe/d to 25,000 boe/d.

General and Administrative Expenses

	Years ended December 31,
($000s, except where noted)	2012			2011
Gross expenses		21,170			18,582
Capitalized		(4,335	)		(3,553	)
Recoveries		(2,563	)		(2,671	)
G&A expenses		14,272			12,358
G&A expenses, per unit ($/boe)		2.34			2.83

Interest and Financing Charges

Bellatrix recorded $9.8 million ($1.61/boe) of interest and financing charges related to bank debt and its debentures for the year ended December 31, 2012, compared to $7.0 million ($1.61/boe) in the 2011 year. The overall increase in interest and financing charges between the years was primarily due to greater interest and accretion charges in relation to the Company’s outstanding debentures in conjunction with higher interest charges related to the Company’s long-term debt as the Company carried a higher average debt balance in the 2012 year compared to the 2011 year. Bellatrix’s total net debt at December 31, 2012 of $189.6 million includes the $50.7 million liability portion of its $55 million principal amount of 4.75% convertible unsecured subordinated debentures (the “4.75% Debentures”), $133.0 million of bank debt and the net balance of the working capital deficiency. The 4.75% Debentures have a maturity date of April 30, 2015.

Debt to Funds Flow from Operations Ratio

	Years ended December 31,
($000s, except where noted)	2012		2011

Shareholders’ equity		381,106		348,405

Long-term debt		133,047		56,701
Convertible debentures (liability component)		50,687		49,076
Working capital deficiency ⁽²⁾		5,843		13,473
Total net debt ⁽²⁾ at year end		189,577		119,250

Debt to funds flow from operations ⁽¹⁾ ratio (annualized) ⁽³⁾
Funds flow from operations ⁽¹⁾ (annualized)		119,460		120,480
Total net debt ⁽²⁾ at year end		189,577		119,250
Total net debt to periods funds flow from operations ratio (annualized) ⁽³⁾		1.6x		1.0x

Net debt ⁽²⁾(excluding convertible debentures) at year end		138,890		70,174
Net debt to periods funds flow from operations ratio (annualized) ⁽³⁾		1.2x		0.6x

Debt to funds flow from operations ⁽¹⁾ ratio
Funds flow from operations ⁽¹⁾ for the year		111,038		94,237
Total net debt ⁽²⁾to funds flow from operations for the year		1.7x		1.3x

Net debt ⁽²⁾(excluding convertible debentures) to funds flow from operations for the year		1.3x		0.7x

⁽¹⁾

As detailed previously in this Management’s Discussion and Analysis, funds flow from operations is a term that does not have any standardized meaning under GAAP. Funds flow from operations is calculated as cash flow from operating activities, less decommissioning costs incurred and changes in non-cash working capital incurred. Refer to the reconciliation of cash flow from operating activities to funds flow from operations appearing elsewhere herein.

⁽²⁾

Net debt and total net debt are considered additional GAAP measures. The Company’s calculation of total net debt includes the liability component of convertible debentures and excludes deferred liabilities, long-term commodity contract liabilities, decommissioning liabilities, long-term finance lease obligation and the deferred tax liability. Net debt and total net debt include the net working capital deficiency (excess) before short-term commodity contract assets and liabilities and current finance lease obligation. Net debt also excludes the liability component of convertible debentures. Total net debt and net debt are additional GAAP measures; refer to the following reconciliation of total liabilities to total net debt and net debt.

⁽³⁾

Total net debt and net debt to periods funds flow from operations ratio (annualized) is calculated based upon fourth quarter funds flow from operations annualized.

Reconciliation of Total Liabilities to Total Net Debt and Net Debt

	As at December 31,
($000s)	2012			2011
Total liabilities per financial statements		300,315			232,017
Current liabilities included within working capital calculation		(53,327	)		(73,578	)
Commodity contract liability		(6,214	)		(2,944	)
Decommissioning liabilities		(43,909	)		(45,091	)
Finance lease obligation		(13,131	)		(4,627	)

Working Capital
Current assets		(52,447	)		(51,927	)
Current liabilities		53,327			73,578
Current portion of finance lease		(1,425	)		(490	)
Net commodity contract asset (liability)		6,388			(7,688	)
		5,843			13,473
Total net debt		189,577			119,250
Convertible debentures		(50,687	)		(49,076	)
Net debt		138,890			70,174

Share-Based Compensation

Non-cash share-based compensation expense for the year ended December 31, 2012 was an expense of $3.2 million compared to $2.9 million in the 2011 year. The overall increase in non-cash share-based compensation expense between the years is primarily a result of a larger number of outstanding share options expensed during the year and greater Deferred Share Unit Plan expenses of $1.0 million (2011: $0.8 million), offset partially by higher capitalized share-based compensation of $1.6 million (2011: $1.4 million).

Depletion and Depreciation

Depletion and depreciation expense for the year ended December 31, 2012 was $75.7 million ($12.40/boe), compared to $63.4 million ($14.53/boe) recognized in the 2011 year. The decrease in depletion and depreciation expense between the years, on a per boe basis, was primarily a result of an increase in the reserve base used for the depletion calculation, partially offset by a higher cost base and increased future development costs.

For the year ended December 31, 2012 Bellatrix has included a total of $524.6 million (2011: $376.8 million) for future development costs in the depletion calculation and excluded from the depletion calculation a total of $37.2 million (2011: $35.1 million) for estimated salvage.

Depletion and Depreciation

	Years ended December 31,
($000s, except where noted)	2012		2011
Depletion and Depreciation		75,720		63,384
Per unit ($/boe)		12.40		14.53

Property Acquisition

Effective November 1, 2012, Bellatrix acquired production and working interest in certain facilities, as well as undeveloped land in the Willesden Green area of Alberta for a cash purchase price of $20.9 million after adjustments. In accordance with IFRS, a property acquisition is accounted for as a business combination when certain criteria are met, such as the acquisition of inputs and processes to convert those inputs into beneficial outputs. Bellatrix assessed the property acquisition and determined that it constitutes a business combination under IFRS. In a business combination, acquired assets and liabilities are recognized by the acquirer at their fair market value at the time of purchase. Any variance between the determined fair value of the assets and liabilities and the purchase price is recognized as either a gain or loss in the statement of comprehensive income in the period of acquisition.

The estimated fair value of the property, plant and equipment acquired was determined using both internal estimates and an independent reserve evaluation. The decommissioning liabilities assumed were determined using the timing and estimated costs associated with the abandonment, restoration and reclamation of the wells and facilities acquired. A summary of the acquired property is provided below:

	*($000s)*
Estimated fair value of acquisition:
Oil and natural gas properties		29,530
Exploration and evaluation assets		8,525
Decommissioning liabilities		(973	)
		37,082

Cash consideration		20,922

Gain on property acquisition		16,160

Impairment of Assets

In accordance with IFRS, the Company calculates an impairment test when there are indicators of impairment. The impairment test is performed at the asset or cash generating unit (“CGU”) level. IAS 36 – “Impairment of Assets” (“IAS 36”) is a one step process for testing and measuring impairment of assets. Under IAS 36, the asset or CGU’s carrying value is compared to the higher of: value-in-use and fair value less costs to sell. Value in use is defined as the present value of the future cash flows expected to be derived from the asset or CGU.

When performed, the impairment test is based upon the higher of value-in-use and estimated fair market values for the Company’s properties, including but not limited to an updated external reserve engineering report which incorporates a full evaluation of reserves on an annual basis or internal reserve updates at quarterly periods, and the latest commodity pricing deck. Estimating reserves is very complex, requiring many judgments based on available geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes.

2012 Impairment

Bellatrix engaged an external reserve evaluator to prepare an updated company reserve report effective December 31, 2012. Overall corporate proved and probable reserve volumes increased significantly at December 31, 2012 compared to evaluated reserves at December 31, 2011. However, the fair values of two largely natural gas-weighted CGUs and one CGU with significant natural gas and heavy oil weightings were reduced, largely as a result of suppressed commodity prices.

As at December 31, 2012, Bellatrix performed an impairment test using VIU values in accordance with IAS 36, resulting in an excess of the carrying value of three CGUs over their recoverable amount, resulting in a non-cash $14.8 million impairment loss. In performing the test, future cash flows at between a 10% and 20% discount rate were used for the Company’s largely gas weighted North East Alberta, South East Alberta, and British Columbia CGUs. The Company’s core West Central Alberta CGU had no indicators of impairment. Discounted salvage values and discounted future associated general and administrative costs were also incorporated into the VIU calculation. The $14.8 million impairment loss was comprised of $11.4 million recognized in the Company’s North East Alberta CGU, $2.9 million in the South East Alberta CGU, and $0.5 million in the British Columbia CGU. The reduction in the fair values of these CGUs between December 31, 2011 and December 31, 2012 was predominantly due to weak natural gas prices.

2011 Impairment

During the year ended December 31, 2011, Bellatrix performed an impairment test in accordance with IAS 36 resulting in an excess of the carrying value of three CGUs over their recoverable amount, resulting in a non-cash $25.6 million impairment loss.

IAS 36 requires impairment losses to be reversed when there has been a subsequent increase in the recoverable amount. In the case of an impairment loss reversal, the carrying amount of the asset or CGU is limited to the original carrying amount less depreciation, depletion and amortization as if no impairment had been recognized for the asset or CGU for prior periods. In 2011, a partial reversal of impairment was recognized relating to a previous impairment for the Company`s South East Alberta CGU. As a result of the reversal, impairment expense for the 2011 year was reduced by $2.7 million.

The impairment test is based upon fair market values for the Company’s properties, including but not limited to an updated external reserve engineering report which incorporates a full evaluation of reserves on an annual basis or internal reserve updates at quarterly periods, and the latest commodity pricing deck. Estimating reserves is very complex, requiring many judgments based upon available geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the Company’s estimated reserves. These estimates may change, having either a negative or positive impact on net earnings as further information becomes available and as the economic environment changes.

Income Taxes

Deferred income taxes arise from differences between the accounting and tax basis of the Company’s assets and liabilities. For the year ended December 31, 2012, the Company recognized a deferred income tax expense of $10.1 million compared to $0.8 million in the 2011 year.

At December 31, 2012, the Company had a total deferred tax asset balance of $1.0 million. IFRS requires that a deferred tax asset be recorded when the tax pools exceeds the book value of assets, to the extent the amount is probable to be realized.

At December 31, 2012, Bellatrix had approximately $584 million in tax pools available for deduction against future income as follows:

*($000s)*	Rate %		2012		2011
Intangible resource pools:
Canadian exploration expenses		100		56,200		47,600
Canadian development expenses		30		358,700		326,900
Canadian oil and gas property expenses		10		40,400		25,100
Foreign resource expenses		10		800		800
Attributed Canadian Royalty Income		(Alberta) 100		16,100		16,100
Undepreciated capital cost ⁽¹⁾		6 – 55		98,000		83,100
Non-capital losses (expire through 2027)		100		10,000		10,000
Financing costs		20 S.L.		3,300		4,700
				583,500		514,300

⁽¹⁾ Approximately $91 million of undepreciated capital cost pools are class 41, which is claimed at a 25% rate.

Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit (Loss)

As detailed previously in this MD&A, funds flow from operations is a term that does not have any standardized meaning under GAAP. Funds flow from operations is calculated as cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital incurred.

Reconciliation of Cash Flow from Operating Activities and Funds Flow from Operations

	Years ended December 31,
($000s)	2012		2011
Cash flow from operating activities		109,328		98,192
Decommissioning costs incurred		635		569
Change in non-cash working capital		1,075		(4,524	)
Funds flow from operations		111,038		94,237

Bellatrix’s cash flow from operating activities of $109.3 million ($1.02 per basic share and $0.95 per diluted share) for the year ended December 31, 2012 increased approximately 11% from the $98.2 million ($0.95 per basic share and $0.87 per diluted share) generated in the 2011 year. Bellatrix generated funds flow from operations of $111.0 million ($1.03 per basic share and $0.96 per diluted share) for the year ended December 31, 2012, an increase of 18% from $94.2 million ($0.91 per basic share and $0.84 per diluted share) for the 2011 year.

The increase in funds flow from operations between the 2012 and 2011 years was principally due to higher funds from operating netbacks, despite significantly reduced commodity prices, as well as higher net realized gains on the Company’s commodity risk management contracts, and offset partially by increased financing expenses and slightly higher general and administrative expenses in 2012 compared to 2011.

Bellatrix maintains a commodity price risk management program to provide a measure of stability to funds flow from operations. Unrealized mark–to–market gains or losses are non-cash adjustments to the current fair market value of the contract over its entire term and are included in the calculation of net profit.

As previously noted in this MD&A, net profit before certain non-cash items is a non-GAAP measure. A reconciliation between this measure and net loss per the Consolidated Statement of Comprehensive Income is provided below.

For the year ended December 31, 2012, net profit before certain non-cash items, net of associated deferred tax impacts, was $21.7 million compared to a net profit of $17.1 million in the 2011 year.

Reconciliation of Net Profit (Loss) to Net Profit Before Certain Non-Cash Items

	Years ended December 31,
($000s)	2012			2011
Net profit (loss) per financial statements		27,771			(5,949	)
Items subject to reversal
Impairment loss on property, plant and equipment		14,820			25,569
Unrealized (gain) loss on commodity contracts		(10,806	)		6,900
Loss (gain) on property dispositions		4,113			(1,730	)
Gain on property acquisition		(16,160	)		-
Deferred tax impact of above items		2,008			(7,685	)
Net profit before certain non-cash items		21,746			17,105

A net profit of $27.8 million ($0.26 per basic share and $0.25 per diluted share) was recognized for the year ended December 31, 2012, compared to a net loss of $5.9 million ($0.06 per basic share and $0.06 per diluted share) in the 2011 year. The net profit recorded in the year ended December 31, 2012 compared to the net loss recorded in the 2011 year is primarily a consequence of higher cash flows as noted above, a $16.2 million gain on property acquisition recognized in 2012, a net unrealized gain on commodity contracts in the 2012 year compared to a loss in 2011, and a lower non-cash impairment loss on oil and gas properties, offset somewhat by a higher depletion and depreciation expense, a total net loss on property dispositions compared to a minor gain on property dispositions in the comparative 2011 year, and a higher deferred tax expense.

Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit (Loss)

	Years ended December 31,
($000s, except per share amounts)	2012		2011
Cash flow from operating activities		109,328		98,192
Basic ($/share)		1.02		0.95
Diluted ($/share)		0.95		0.87
Funds flow from operations		111,038		94,237
Basic ($/share)		1.03		0.91
Diluted ($/share)		0.96		0.84
Net profit (loss)		27,771		(5,949	)
Basic ($/share)		0.26		(0.06	)
Diluted ($/share)		0.25		(0.06	)

Capital Expenditures

Bellatrix invested $185.3 million in capital expenditures, including a $21.0 million property acquisition, during the year ended December 31, 2012, compared to $179.6 million in the 2011 year.

Capital Expenditures

	Years ended December 31,
($000s)	2012			2011
Lease acquisitions and retention		8,303			16,367
Geological and geophysical		290			433
Drilling and completion costs		118,783			141,051
Facilities and equipment		36,811			18,471
		164,187			176,322
Drilling incentive credits		-			(827	)
Exploration and development ⁽¹⁾		164,187			175,495
Corporate ⁽²⁾		195			268
Property acquisition		20,966			3,798
Total capital expenditures – cash		185,348			179,561
Property dispositions – cash		(6,660	)		(4,203	)
Total net capital expenditures – cash		178,688			175,358
Capital lease additions – non-cash		10,000			3,700
Adjustment on property acquisition – non-cash		16,160			-
Other – non-cash ⁽³⁾		(285	)		6,875
Total non-cash		25,875			10,575
Total net capital expenditures		204,563			185,933

(1)

Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the year.

(2)

Corporate includes office furniture, fixtures and equipment.

(3)

Other includes non-cash adjustments for the current year’s decommissioning liabilities and share based compensation.

By comparison, Bellatrix drilled or participated in 54 gross (34.84 net) wells during the year ended December 31, 2011, including 39 gross (29.04 net) oil wells, 14 gross (5.79 net) liquids-rich natural gas wells, and 1 gross (0.007 net) dry hole that was drilled in a non-operated oil unit.

The $185.3 million capital program for the year ended December 31, 2012 was financed from funds flow from operations and bank debt.

Based on the current economic conditions and Bellatrix’s operating forecast for 2013, the Company budgets a capital program between $230 to $240 million funded from the Company’s cash flows and to the extent necessary, bank indebtedness. The 2013 capital budget is expected to be directed primarily towards horizontal drilling and completions activities in the Cardium and Notikewin areas.

Decommissioning Liabilities

At December 31, 2012, Bellatrix has recorded decommissioning liabilities of $43.9 million, compared to $45.1 million at December 31, 2011, for future abandonment and reclamation of the Company’s properties. For the year ended December 31, 2012, decommissioning liabilities decreased by a net $1.2 million as a result of a reduction of $3.0 million for liabilities reversed on dispositions, a $0.7 million decrease for changes in estimates, and a $0.6 million decrease for liabilities settled during the year, offset by $2.4 million incurred on property acquisitions and development activities, and $0.7 million as a result of charges for the unwinding of the discount rates used for fair valuing the liabilities. The $0.7 million decrease as a result of changes in estimates is primarily due to a discount rate variations at December 31, 2012 compared to 2011, in addition to other abandonment liability revisions.

Liquidity and Capital Resources

As an oil and gas business, Bellatrix has a declining asset base and therefore relies on ongoing development and acquisitions to replace production and add additional reserves. Future oil and natural gas production and reserves are highly dependent on the success of exploiting the Company’s existing asset base and in acquiring additional reserves. To the extent Bellatrix is successful or unsuccessful in these activities, cash flow could be increased or reduced.

Bellatrix is focused on growing oil and natural gas production from its diversified portfolio of existing and emerging resource plays in Western Canada. Bellatrix remains highly focused on key business objectives of maintaining financial strength, optimizing capital investments – attained through a disciplined approach to capital spending, a flexible investment program and financial stewardship. Natural gas prices are primarily driven by North American supply and demand, with weather being the key factor in the short term. Bellatrix believes that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs. Bellatrix’s results are affected by external market and risk factors, such as fluctuations in the prices of crude oil and natural gas, movements in foreign currency exchange rates and inflationary pressures on service costs. Market conditions have resulted in Bellatrix experiencing primarily downward trends in crude oil pricing for 2012 compared to 2011, and a more significant downward trend in natural gas pricing, although natural gas prices started to recover in the second half of 2012.

Liquidity risk is the risk that Bellatrix will not be able to meet its financial obligations as they become due. Bellatrix actively manages its liquidity through daily and longer-term cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its bank credit facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic risk management opportunities, and maintaining sufficient cash flows for compliance with operating debt covenants. Bellatrix is fully compliant with all of its operating debt covenants.

Bellatrix generally relies on operating cash flows and its credit facilities to fund capital requirements and provide liquidity. Future liquidity depends primarily on cash flow generated from operations, existing credit facilities and the ability to access debt and equity markets. From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. There can be no assurance that future debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to Bellatrix.

Credit risk is the risk of financial loss to Bellatrix if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Bellatrix’s trade receivables from joint venture partners, petroleum and natural gas marketers, and financial derivative counterparties.

A substantial portion of Bellatrix’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Bellatrix sells substantially all of its production to seven primary purchasers under standard industry sale and payment terms. The most significant 60 day exposure to a single counterparty is currently approximately $12.6 million. Purchasers of Bellatrix’s natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. Bellatrix has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in Bellatrix reducing or mitigating its exposures to certain counterparties where it is deemed warranted and permitted under contractual terms.

Bellatrix may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production, derivative counterparties and other parties. In the event such entities fail to meet their contractual obligations to Bellatrix, such failures may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in Bellatrix’s ongoing capital program, potentially delaying the program and the results of such program until Bellatrix finds a suitable alternative partner.

Total net debt levels of $189.6 million at December 31, 2012 have increased by $70.3 million from $119.3 million at December 31, 2011, primarily as a consequence of an increase in a working capital deficiency and bank debt as the Company executed its 2012 capital program. Total net debt includes the liability component of the 4.75% Debentures and excludes unrealized commodity contract assets and liabilities, deferred taxes, finance lease obligations, deferred liabilities and decommissioning liabilities.

Funds flow from operations represents 60% of the funding requirements for Bellatrix’s capital expenditures for the year ended December 31, 2012.

Effective December 13, 2012, the Company’s borrowing base was increased from $200 million to $220 million through to the next scheduled borrowing base determination to be completed on or before May 31, 2013. Effective May 31, 2012, the revolving period of the credit facility was extended from June 26, 2012 to June 25, 2013. The Company’s credit facilities consist of a $25 million demand operating facility provided by a Canadian bank and a $195 million extendible revolving term credit facility provided by two Canadian banks and a Canadian financial institution. Amounts borrowed under the credit facility bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, the LIBOR margin rate, or the bankers’ acceptance stamping fee, plus between 1.00% and 3.50%, depending on the type of borrowing and the Company’s debt to cash flow ratio. The credit facilities are secured by a $400 million debenture containing a first ranking charge and security interest. Bellatrix has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances. A standby fee is charged of between 0.50% and 0.875% on the undrawn portion of the credit facilities, depending on the Company’s debt to cash flow ratio.

The revolving period for the revolving term credit facility will end on June 25, 2013, unless extended for a further 364 day period. Should the facility not be extended it will convert to a non-revolving term facility with the full amount outstanding due 366 days after the last day of the revolving period of June 25, 2013. The borrowing base will be subject to re-determination on May 31 and November 30 in each year prior to maturity, with the next semi-annual redetermination occurring on May 31, 2013.

As at December 31, 2012, approximately $87.0 million or 40% of unused and available bank credit under its credit facilities was available to fund Bellatrix’s ongoing capital spending and operational requirements.

Bellatrix currently has commitments associated with its credit facilities outlined above and the commitments outlined under the “Commitments” section. Bellatrix continually monitors its capital spending program in light of the recent volatility with respect to commodity prices and Canadian dollar exchange rates with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations with funds flow from operations and draws on Bellatrix’s credit facility, as necessary. Bellatrix has the ability to fund its 2013 capital program of $230 to $240 million by utilizing cash flow, and to the extent necessary, bank indebtedness.

As at February 25, 2013, Bellatrix had outstanding a total of 9,334,894 options exercisable at an average exercise price of $3.45 per share, $55.0 million principal amount of 4.75% Debentures convertible into common shares (at a conversion price of $5.60 per share) and 107,880,996 common shares.

Related Party Transactions

Previous to 2012, the Company entered into agreements to obtain financing in the amount of $5.3 million for the construction of certain facilities.

Members of the Company’s management team and entities affiliated with them provided financing of $900,000. The terms of the transactions with those related parties were the same as those with arms-length participants.

Commitments

As at December 31, 2012, Bellatrix committed to drill 3 gross (1.7 net) wells pursuant to farm-in agreements. Bellatrix expects to satisfy these drilling commitments at an estimated cost of approximately $6.5 million.

In addition, Bellatrix entered into two joint venture agreements during the 2011 year and an additional joint venture agreement during 2012. The agreements include a minimum commitment for the Company to drill a specified number of wells each year over the term of the individual agreements. The details of these agreements are provided in the table below:

Joint Venture Agreement	Feb. 1, 2011		Aug. 4, 2011		Dec. 14, 2012
Agreement Term		2011 to 2015		2011 to 2016		2014 to 2018
Minimum wells per year (gross and net)		3		5 to 10		2
Minimum total wells (gross and net)		15		40		10
Estimated total cost ($000s)	$	52.5	$	140.0	$	35.0
Remaining wells to drill at December 31, 2012		8		32		10
Remaining estimated total cost ($000s)	$	28.0	$	112.0	$	35.0

The Company has the following liabilities as at December 31, 2012:

Liabilities ($000s)	Total		< 1 Year		1-3 Years		4-5 Years		More than 5 years
Accounts payable and accrued liabilities ⁽¹⁾	$	50,771	$	50,771	$	-	$	-	$	-
Long-term debt – principal ⁽²⁾		133,047		-		133,047		-		-
Convertible debentures – principal		55,000		-		55,000		-		-
Convertible debentures – interest ⁽³⁾		6,085		2,613		3,472		-		-
Commodity contract liability		7,345		1,131		6,214		-		-
Decommissioning liabilities ⁽⁴⁾		43,909		-		7,187		5,796		30,926
Finance lease obligation		14,556		1,425		3,069		3,172		6,890
Total	$	310,713	$	55,940	$	207,989	$	8,968	$	37,816

⁽¹⁾

Includes $0.4 million of accrued coupon interest payable in relation to the 4.75% Debentures and $0.2 million of accrued interest payable in relation to the credit facilities is included in Accounts Payable and Accrued Liabilities.

⁽²⁾

Bank debt is based on a revolving term which is reviewed annually and converts to a 366 day non-revolving facility if not renewed. Interest due on the bank credit facility is calculated based upon floating rates.

⁽³⁾

The 4.75% Debentures outstanding at December 31, 2012 bear interest at a coupon rate of 4.75%, which currently requires total annual interest payments of $2.6 million.

⁽⁴⁾

Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over the life of the Company’s properties (between 2013 and 2053).

Bellatrix will also have drilling commitments associated with its recently announced joint venture agreement in January, 2013 with a South Korean based company. Closing of this agreement is expected to occur on or before April 30, 2013. Refer to the details discussed earlier herein.

Off-Balance Sheet Arrangements

The Company has certain fixed term lease agreements, including primarily office space leases, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. The lease agreements do not currently provide for early termination. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2012.

The Company is committed to payments under fixed term operating leases which do not currently provide for early termination. The Company’s commitment for office space as at December 31, 2012 is as follows:

($000s)	Gross		Expected
Year	Amount		Recoveries		Net amount
2013	$	2,254	$	947	$	1,307
2014		1,520		641		879

Subsequent to year end, Bellatrix entered into a fixed term operating lease agreement for corporate office space in a new location, commencing September 1, 2013. Bellatrix is currently pursuing subleasing options for the remaining term of its existing corporate office space. A summary of the Company’s commitment for the new office space is as follows:

($000s)
Year	Total amount
2013	$	388
2014		2,153
2015		2,243
2016		2,243
2017		2,243
More than 5 years		14,449

Business Prospects and 2013 Year Outlook

Bellatrix continues to develop its core assets and conduct exploration programs utilizing its large inventory of geological prospects. As at December 31, 2012, Bellatrix has approximately 206,638 net undeveloped acres and including all opportunities has in excess of 1,700 net exploration drilling opportunities identified.

As a result of the recently announced joint venture with a Seoul Korea based company, Bellatrix’s 2013 capital expenditure budget has been increased to between $230 and $240 million. A total capital program of $365 million is anticipated including the capital expected to be invested by the joint venture partner. Based on the timing of proposed expenditures, downtime for scheduled and unscheduled plant turnarounds, completion of required infrastructure, and normal production declines, execution of the 2013 capital expenditure plan is expected to provide average daily production of approximately 24,000 boe/d to 25,000 boe/d, and an exit rate of approximately 30,000 boe/d to 31,000 boe/d.

The Company has initiated the 2013 program by instituting drilling of multiple horizontal wells from single surface locations. Pad drilling enhances the opportunity to efficiently develop the resource while minimizing the environmental footprint and improving our cost and on-stream efficiencies. Pad drilling also facilitates drilling through the spring breakup months of Q2. As a result the Company plans to run 3 rigs throughout the second quarter ramping up to 7 or 8 rigs for the second half of 2013.

Financial Reporting Update

Future Accounting Pronouncements

The following pronouncements from the IASB are applicable to Bellatrix and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 - “Financial Instruments”, which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. This standard is effective for annual periods beginning on or after January 1, 2015 with different transitional arrangements depending on the date of initial application. The extent of the impact of the adoption of IFRS 9 has not yet been determined.

IFRS 10 - “Consolidated Financial Statements” (“IFRS 10”), which requires an entity to consolidate an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Under existing IFRS, consolidation is required when an entity has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. This standard replaces SIC-12 – “Consolidation—Special Purpose Entities” and parts of IAS 27 – “Consolidated and Separate Financial Statements.” Bellatrix intends to adopt IFRS 10, including the amendments issued in June 2012, in its financial statements for the annual period beginning on January 1, 2013. The adoption of IFRS 10 is currently not anticipated to impact the Company’s financial statements.

IFRS 11 – “Joint Arrangements” (“IFRS 11”), requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation, each having its own accounting model. Joint ventures will be accounted for using the equity method of accounting, whereas for a joint operation the venture will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. The standard provides for a more substance based reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form. IFRS 11 replaces IAS 31 – “Interests in Joint Ventures” and SIC-13 – “Jointly Controlled Entities—Non-monetary Contributions by Venturers” and establishes principles for accounting for all joint arrangements. Bellatrix intends to adopt IFRS 11, including the amendments issued in June 2012, in its financial statements for the annual period beginning on January 1, 2013. The adoption of IFRS 11 is currently not anticipated to have a significant impact on the Company’s financial statements.

IFRS 12 – “Disclosure of Interests in Other Entities” (“IFRS 12”), establishes disclosure requirements for interests in other entities, such as joint arrangements, associates, special purpose vehicles and off balance sheet vehicles. The standard carries forward existing disclosures and also introduces significant additional disclosure requirements that address the nature of, and risks associated with, an entity’s interests in other entities. Bellatrix intends to adopt IFRS 12, including the amendments issued in June 2012, in its financial statements for the annual period beginning on January 1, 2013. The adoption of IFRS 12 is currently not anticipated to have a significant impact on the Company’s financial statements.

IFRS 13 – “Fair Value Measurement” (“IFRS 13”), is a comprehensive standard for fair value measurement and disclosure requirements for use across all IFRSs. The new standard clarifies that fair value is the price that would be received to sell an asset, or paid to transfer a liability in an orderly transaction between market participants, at the measurement date. It also establishes disclosures about fair value measurement. Under existing IFRS, guidance on measuring and disclosing fair value is dispersed among the specific standards requiring fair value measurements and in many cases does not reflect a clear measurement basis or consistent disclosures. IFRS 13 is effective for annual periods beginning on or after January 1, 2013 and applies prospectively from the beginning of the annual period in which the standard is adopted. The extent of the impact of the adoption of IFRS 13 on the Company’s financial statements has not yet been determined.

In June 2011, the IASB issued an amendment to IAS 1 - “Presentation of Financial Statements” (“IAS 1”) requiring companies to group items presented within Other Comprehensive Income based on whether they may be subsequently reclassified to profit or loss. This amendment to IAS 1 is effective for annual periods beginning on or after July 1, 2012 with full retrospective application. Early adoption is permitted. Bellatrix intends to adopt the amendments in its financial statements for the annual period beginning on January 1, 2013. The extent of the impact of the amendments on the financial statements has not yet been determined.

Business Risks and Uncertainties

General

Bellatrix’s production and exploration activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers to the much larger integrated petroleum companies.

Bellatrix is subject to the various types of business risks and uncertainties including:

Finding and developing oil and natural gas reserves at economic costs;

Production of oil and natural gas in commercial quantities; and

Marketability of oil and natural gas produced.

In order to reduce exploration risk, the Company strives to employ highly qualified and motivated professional employees with a demonstrated ability to generate quality proprietary geological and geophysical prospects. To help maximize drilling success, Bellatrix combines exploration in areas that afford multi-zone prospect potential, targeting a range of low to moderate risk prospects with some exposure to select high-risk with high-reward opportunities. Bellatrix also explores in areas where the Company has significant drilling experience.

The Company mitigates its risk related to producing hydrocarbons through the utilization of the most appropriate technology and information systems managed by qualified personnel. In addition, Bellatrix seeks to maintain operational control of the majority of its prospects.

Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. In order to mitigate such risks, Bellatrix conducts its operations at high standards and follows safety procedures intended to reduce the potential for personal injury to employees, contractors and the public at large. The Company maintains current insurance coverage for general and comprehensive liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect changing corporate requirements, as well as industry standards and government regulations. Bellatrix may periodically use financial or physical delivery contracts to reduce its exposure against the potential adverse impact of commodity price volatility, as governed by formal policies approved by senior management subject to controls established by the Board.

Pricing and Marketing

Oil

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Worldwide supply and demand primarily determines oil prices. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the availability of transportation, the value of refined products, the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. The NEB is currently undergoing a consultation process to update the current regulations governing the issuance of export licences. The updating process is necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act which received Royal Assent on June 29, 2012 (the "Prosperity Act"). In this transitory period, the NEB has issued, and is currently following an "Interim Memorandum of Guidance concerning Oil and Gas Export Applications and Gas Import Applications under Part VI of the National Energy Board Act".

Natural Gas

Alberta's natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system such as the Alberta "NIT" (Nova Inventory Transfer), at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange (NGX) or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can be set by such supply and demand. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB.

Royalties and Incentives - General

In addition to federal regulation, each province has legislation and regulations which govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oil sands projects, crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty like interests are carved out of the working interest owner's interest, from time to time, through non public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.

Land Tenure

The respective provincial governments predominantly own crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Each of the provinces of Alberta, British Columbia and Saskatchewan has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license. On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary term.

Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. Leases and licences granted prior to January 1, 2009, but continued after that date, are not subject to shallow rights reversion until they continue past their primary term (at which time the application of deep rights reversion occurs). Afterwards, the holders of such agreements will be served with shallow rights reversion notices based on vintage and location similar to leases and licences that were already continued as of January 1, 2009. The order in which these agreements will receive reversion notices will depend on their vintage and location.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements for the satisfactory abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil and gas operations, including those of the Company. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition.

Global Financial Crisis

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels have caused significant volatility in commodity prices. These events and conditions have caused a decrease in confidence in the broader U.S. and global credit and financial markets and have created a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. While there are signs of economic recovery, these factors have negatively impacted company valuations and are likely to continue to impact the performance of the global economy going forward. Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, actions taken by OPEC and the ongoing global credit and liquidity concerns. This volatility may in the future affect the Company's ability to obtain equity or debt financing on acceptable terms.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity offerings, the Company's ability to do so is dependent on, among other factors, the overall state of the capital markets, the Company’s credit rating (if applicable), interest rates, royalty rates, tax burden due to current and future tax laws, and investor appetite for investments in the energy industry and the Company's securities in particular. Further, if the Company’s revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business financial condition, results of operations and prospects.

Third Party Credit Risk

The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.

Critical Accounting Estimates

The reader is advised that the critical accounting estimates, policies, and practices as described herein continue to be critical in determining Bellatrix’s financial results.

The reader is cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. The following discussion outlines accounting policies and practices that are critical to determining Bellatrix’s financial results.

Derivatives

The fair value of commodity contracts is estimated, whenever possible, based on published market prices, and if not available, on estimates from third party brokers, as at the balance sheet date and may differ from what will eventually be realized.

Oil and gas reserves

Reserves and resources are used in the units of production calculation for depreciation, depletion and amortization and the impairment analysis which affect net profit. There are numerous uncertainties inherent in estimating oil and gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net profit as further information becomes available and as the economic environment changes.

Depreciation and depletion

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes before royalties in relation to total estimated proved and probable reserves as determined annually by independent engineers and internal reserve evaluations on a quarterly basis determined in accordance with National Instrument 51-101. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion and depreciation of production equipment are based on total capitalized costs plus estimated future development costs of proved and probable undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved reserves are fully produced. The costs of acquiring and evaluating unproved properties are excluded from depletion calculations.

Recoverability of asset carrying values

The Company assesses its oil and gas properties, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date.

The assessment of any impairment of property, plant and equipment is dependent upon estimates of recoverable amount that take into account factors such as reserves, economic and market conditions, timing of cash flows, the useful lives of assets and their related salvage values.

Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of its assets. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company’s assets in future periods.

Decommissioning obligations

Provisions for decommissioning obligations associated with the Company’s drilling operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology.

Share-based compensation

The fair value of stock options granted is measured using a Black Scholes model. Measurement inputs include share price on measurement date, exercise price of the option, expected volatility, expected life of the options, expected dividends and the risk-free rate. The Company estimates volatility based on the historical share price. The expected life of the options is based on historical experience and general option holder behavior. Dividends were not taken into consideration as the Company does not expect to pay dividends. Management also makes an estimate of the number of options that will be forfeited and the rate is adjusted to reflect the actual number of options that actually vest.

Income taxes

Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or loss. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

Legal, Environmental Remediation and Other Contingent Matters

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favor, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceeding related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position or results of operations.

The Company reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Company’s management monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances.

With the above risks and uncertainties the reader is cautioned that future events and results may vary substantially from that which Bellatrix currently foresees.

Controls and Procedures

Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company and have concluded that the Company’s disclosure controls and procedures are effective at the financial year end of the Company for the foregoing purposes.

Internal Control over Financial Reporting

The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting to provide reasonable assurance regarding the reliability of the Company’s financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s internal control over financial reporting at the financial year end of the Company and concluded that the Company’s internal control over financial reporting is effective at the financial year end of the Company for the foregoing purpose.

The Company is required to disclose herein any change in the Company’s internal control over financial reporting that occurred during the period beginning on October 1, 2012 and ended on December 31, 2012 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. No material changes in the Company’s internal control over financial reporting were identified during such period that has materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Sensitivity Analysis

The table below shows sensitivities to funds flow from operations as a result of product price, exchange rate, and interest rate changes. This is based on actual average prices received for the fourth quarter of 2012 and average production volumes of 18,763 boe/d during that period, as well as the same level of debt outstanding at December 31, 2012. Diluted weighted average shares are based upon the fourth quarter of 2012. These sensitivities are approximations only, and not necessarily valid under other significantly different production levels or product mixes. Commodity price risk management activities can significantly affect these sensitivities. Changes in any of these parameters will affect funds flow as shown in the table below:

	Funds Flow from Operations ⁽¹⁾		Funds Flow from Operations⁽¹⁾
	(annualized)		Per Diluted Share
Sensitivity Analysis	($000s)		($)
Change of US $1/bbl WTI		1,500		0.01
Change of $0.10/ mcf		2,600		0.02
Change of US $0.01 CDN/ US exchange rate		1,100		0.01
Change in prime of 1%		1,300		0.01

(1)

The term “funds flow from operations” should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with GAAP as an indicator of the Company’s performance. Therefore reference to additional GAAP measures of diluted funds flow from operations or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found elsewhere herein. Funds flow from operations per share is calculated using the weighted average number of common shares for the period.

Selected Quarterly Consolidated Information

The following table sets forth selected consolidated financial information of the Company for the quarters in 2012 and 2011.

2012 – Quarter ended (unaudited)
($000s, except per share amounts)	March 31		June 30		Sept. 30			Dec. 31
Revenues before royalties and risk management		58,191		50,714		48,126			62,283
Cash flow from operating activities		24,056		28,458		24,807			32,007
Cash flow from operating activities per share
Basic	$	0.22	$	0.24	$	0.23		$	0.30
Diluted	$	0.21	$	0.22	$	0.22		$	0.28
Funds flow from operations ⁽¹⁾		29,194		25,366		26,613			29,865
Funds flow from operations per share ⁽¹⁾
Basic	$	0.27	$	0.24	$	0.25		$	0.28
Diluted	$	0.25	$	0.22	$	0.23		$	0.26
Net profit (loss)		9,172		9,963		(615	)		9,251
Net profit (loss) per share
Basic	$	0.09	$	0.09	$	(0.01	)	$	0.09
Diluted	$	0.08	$	0.09	$	(0.01	)	$	0.08
Net capital expenditures (cash)		73,831		16,284		35,515			64,383

2011 – Quarter ended (unaudited)
($000s, except per share amounts)	March 31			June 30		Sept. 30		Dec. 31
Revenues before royalties and risk management		40,535			53,444		49,145		59,194
Cash flow from operating activities		15,718			23,825		28,023		30,626
Cash flow from operating activities per share
Basic	$	0.16		$	0.23	$	0.26	$	0.28
Diluted	$	0.15		$	0.22	$	0.24	$	0.26
Funds flow from operations ⁽¹⁾		17,027			23,126		23,964		30,120
Funds flow from operations per share ⁽¹⁾
Basic	$	0.17		$	0.22	$	0.22	$	0.28
Diluted	$	0.16		$	0.21	$	0.21	$	0.26
Net profit (loss)		(5,487	)		12,315		820		(13,597	)
Net profit (loss) per share
Basic	$	(0.06	)	$	0.12	$	0.01	$	(0.13	)
Diluted	$	(0.06	)	$	0.11	$	0.01	$	(0.13	)
Net capital expenditures (cash)		59,247			28,784		40,087		47,240

⁽¹⁾Refer to “Additional GAAP Measures” in respect of the term “funds flow from operations” and “funds flow from operations per share”.

The quarterly results for 2012 compared to 2011 were positively impacted by increased production resulting from the expansion of Bellatrix’s 2011 and 2012 drilling programs, offset somewhat by lower overall commodity prices realized in the 2012 quarters compared to the 2011 quarters.

During the first quarter of 2012, the Company spent $74.1 million in capital expenditures, compared to $59.1 million in the first quarter of 2011. The Company drilled or participated in 13 gross (10.72 net) wells in the first quarter of 2012, compared to 21 gross (12.07 net) wells in the comparative 2011 quarter. Higher sales volumes of 15,900 boe/d in the 2012 first quarter compared to 10,084 boe/d in the 2011 period, in conjunction with stronger crude oil and NGL pricing and offset slightly by depressed natural gas prices, resulted in increased revenue of $58.2 million in the first quarter of 2012, compared to $40.5 million in the 2011 first quarter.

In the second quarter of 2012, the Company closed on the disposition of two minor non-core properties for total proceeds of $2.0 million after adjustments. In the 2012 second quarter, the Company spent $18.3 million (2011: $29.0 million) in capital expenditures, and drilled 2 gross (1.72 net) wells, compared to 2 gross (1.71 net) wells in the same period in 2011. Due primarily to Bellatrix’s 2012 drilling program executed in the first and second quarters, sales volumes increased by 42% to 16,569 boe/d in the second quarter of 2012, compared to 11,643 boe/d in the second quarter of 2011.

During the third quarter of 2012, the Company closed on the disposition of a minor non-core property interest in the Wainwright area for proceeds of $4.3 million after adjustments. In the third quarter of 2012, the Company spent $39.8 million on capital expenditures compared to $44.2 million in the third quarter of 2011. In the third quarter of 2012, Bellatrix drilled 9 gross (7.71 net) wells, compared to 19 gross (13.41 net) wells in the third quarter of 2011.

Fourth quarter of 2012 results are compared in detail to fourth quarter 2011 results throughout this MD&A.

Overall, the success and execution of the Company’s 2012 drilling program resulted in increased sales volumes and cash flows, despite weaker commodity prices experienced during most of the 2012 year.

Selected Annual Consolidated Information

The following table sets forth selected consolidated financial information of the Company for the most recently completed year ending December 31, 2012 and for comparative 2011 and 2010 years. The adoption date of IFRS of January 1, 2011 required restatement for comparative purposes, of the Company’s opening balance sheet as at January 1, 2010, all interim quarterly periods in 2010 and for its year ended December 31, 2010.

Years ended December 31,
($000s, except per share amounts)	2012			2011			2010
Revenues (before royalties and risk management)		219,314			202,318			117,673
Funds flow from operations ⁽¹⁾		111,038			94,237			53,042
Funds flow from operations per share ⁽¹⁾
Basic	$	1.03		$	0.91		$	0.57
Diluted	$	0.96		$	0.87		$	0.54
Cash flow from operating activities
Cash flow from operating activities per share		109,328			98,192			44,272
Basic	$	1.02		$	0.95		$	0.47
Diluted	$	0.95		$	0.87		$	0.46
Net profit (loss)		27,771			(5,949	)		(4,985	)
Net profit (loss) per share
Basic	$	0.26		$	(0.06	)	$	(0.05	)
Diluted	$	0.25		$	(0.06	)	$	(0.05	)
Net capital expenditures (cash)		(178,688	)		(175,358	)		(92,181	)
Total assets		681,421			580,422			477,054
Total net debt ^{(1) (2)}		189,577			119,250			87,444
Non-current financial liabilities
Future income taxes		-			-			-
Decommissioning liabilities		43,909			45,091			38,710
Sales volumes (boe/d)		16,775			11,954			8,519
Distributions declared		-			-			-
Distributions per share/unit		-			-			-

⁽¹⁾

Refer to “Additional GAAP Measures” in respect of the terms “funds flow from operations,” “funds flow from operations per share,” “net debt” and “total net debt.”

⁽²⁾

Net debt includes the net working capital deficiency before short-term commodity contract assets and liabilities, current finance lease obligations and short-term future income tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes finance lease obligations, decommissioning liabilities and future income tax liabilities.

2012 annual results are compared in detail to 2011 annual results throughout this MD&A.

The annual results for 2011 compared to 2010 were most notably impacted by an expanded drilling program resulting in increased sales volumes. Revenues and cash flows were impacted by increased sales volumes, higher crude oil, condensate and NGL prices and lower natural gas prices realized, as well as lower operating costs per boe between the years.

Bellatrix’s capital expenditures totaled $179.6 million in 2011, compared to $106.7 million in 2010. Due in large part to the expanded capital program in 2011, total sales volumes increased by 40% to 11,954 boe/d in 2011, compared to 8,519 boe/d in 2010. Primarily due to the significant increase in sales volumes between the years, revenues before royalties and risk management increased to $202.3 million in 2011, compared to $117.7 million realized in 2010, despite reductions in commodity prices between the years.