TABLE OF CONTENTS

	Page

ABBREVIATIONS	i
OIL AND GAS INFORMATION ADVISORIES	i
CONVERSIONS	ii
CERTAIN DEFINITIONS	iii
FORWARD-LOOKING STATEMENTS	vi
BACKGROUND	1
GENERAL DEVELOPMENT OF OUR BUSINESS	1
DESCRIPTION OF BUSINESS	6
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	7
Disclosure of Reserves Data	7
Reserves Data (Forecast Prices and Costs)	8
Reconciliation of Changes in Reserves	12
Additional Information Relating to Reserves Data	13
Undeveloped Reserves	13
Significant Factors or Uncertainties	15
Future Development Costs	15
Other Oil and Gas Information	15
Principal Properties	15
Oil and Natural Gas Wells	18
Developed and Undeveloped Lands	18
Forward Contracts and Marketing	19
Additional Information Concerning Abandonment and Reclamation Costs	20
Tax Horizon	20
Capital Expenditures	20
Exploration and Development Activities	21
Production Estimates	21
Production History	21
DIVIDENDS	23
DESCRIPTION OF SHARE CAPITAL	23
MARKET FOR SECURITIES	23
PRIOR SALES	24
ESCROWED SECURITIES	24
BORROWINGS	25
DIRECTORS AND OFFICERS	26
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	31
AUDIT COMMITTEE INFORMATION	31
INDUSTRY CONDITIONS	33
RISK FACTORS	47
HUMAN RESOURCES	59
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	59
INTERESTS OF EXPERTS	59
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	59
MATERIAL CONTRACTS	59
AUDITORS, TRANSFER AGENT AND REGISTRAR	59
ADDITIONAL INFORMATION	60

APPENDIX “A” -	REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
APPENDIX “B” -	REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
APPENDIX “C” -	MANDATE OF THE AUDIT COMMITTEE

ABBREVIATIONS

Oil and Natural Gas Liquids

Bbl		barrel
Bbls		barrels
Mbbls		thousand barrels
MMbbls		million barrels
Mstb		1,000 stock tank barrels
Bbls/d		barrels per day
BOPD		barrels of oil per day
NGLs		natural gas liquids
STB		stock tank barrels

Natural Gas

Mcf		thousand cubic feet
MMcf		million cubic feet
Mcf/d		thousand cubic feet per day
MMcf/d		million cubic feet per day
MMbtu		million British Thermal Units
Bcf		billion cubic feet
GJ		gigajoule
GJ/d		gigajoules per day
MM		Million

Other

AECO		the natural gas storage facility located at Suffield, Alberta.
API		American Petroleum Institute
°API		an indication of the specific gravity of crude oil measured on the API gravity scale.
BOE		barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcf of natural gas
BOE/d		barrel of oil equivalent per day
m3		cubic metres
MBOE		1,000 barrels of oil equivalent
Mcfe		thousand cubic feet of gas equivalent
Mcfe/d		thousand cubic feet of gas equivalent per day
MMcfe/d		million cubic feet of gas equivalent per day
$000s or $M		thousands of dollars
WTI		West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

OIL AND GAS INFORMATION ADVISORIES

Where any disclosure of reserves data is made in this Annual Information Form that does not reflect all of the reserves of Bellatrix, the reader should note that the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

All production and reserves quantities included in this Annual Information Form (including the Appendices hereto) have been prepared in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by United States companies. Nevertheless, as part of Bellatrix’s Annual Report on Form 40-F for the year ended December 31, 2014 filed with the SEC, Bellatrix has disclosed proved reserves quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with the U.S. Financial Accounting Standards Board, “Extractive Activities — Oil and Gas”, which disclosure complies with the SEC’s rules for disclosing oil and gas reserves.

Disclosure provided herein in respect of BOEs or Mcfes may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl and an Mcfe conversion ratio of 1 Bbl:6 Mcf are 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 6Mcf:1Bbl, utilizing a conversion on a 6Mcf:1Bbl basis may be misleading as an indication of value.

FORWARD-LOOKING STATEMENTS

Certain of the statements contained herein including, without limitation, management plans and assessments of future plans and operations, expectations of the number of additional drilling locations resulting from certain acquisitions, expected timing for spending capital associated with certain joint venture arrangements, expected costs and timing of bringing on stream of certain plants and facilities, Bellatrix’s future business plan and strategy, Bellatrix’s criteria for evaluating acquisitions and other opportunities, Bellatrix’s intentions with respect to future acquisitions and other opportunities, timing of bringing new wells on stream, production estimates, plans with respect to the Corporation’s facilities, drilling and completion plans, plans and timing for development of undeveloped and probable reserves, timing of when the Corporation may be taxable, estimated abandonment and reclamation costs, plans regarding hedging, wells to be drilled, the weighting of commodity expenses, and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof, may constitute “forward-looking statements” or “forward-looking information” within the meaning of Applicable Securities Laws (as defined herein) (collectively “forward-looking statements”). Words such as “may”, “will”, “should”, “could”, “anticipate”, “believe”, “expect”, “intend”, “plan”, “potential”, “continue”, “shall”, “estimate”, “expect”, “propose”, “might”, “project”, “predict”, “forecast” and similar expressions may be used to identify these forward-looking statements. These statements reflect management’s current beliefs and are based on information currently available to management. Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements including, but not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and the risk factors outlined under “Risk Factors” and elsewhere herein. The recovery and reserve estimates of Bellatrix’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

Forward-looking statements are based on a number of factors and assumptions which have been used to develop such forward-looking statements but which may prove to be incorrect. Although Bellatrix believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements because Bellatrix can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Bellatrix operates; the timely receipt of any required regulatory approvals; the ability of Bellatrix 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 Bellatrix has an interest in, to operate the field in a safe, efficient and effective manner; the ability of Bellatrix 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 Bellatrix to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Bellatrix operates; and the ability of Bellatrix to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list of factors is not exhausted. Additional information on these and other factors that could affect Bellatrix’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Bellatrix’s website (www.bellatrixexploration.com). Although the forward-looking statements contained herein are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with these forward-looking statements. Investors should not place undue reliance on forward-looking statements. These forward-looking statements are made as of the date hereof and Bellatrix assumes no obligation to update or review them to reflect new events or circumstances except as required by Applicable Securities Laws.

Forward-looking statements contained herein concerning the oil and gas industry and Bellatrix’s general expectations concerning this industry is based on estimates prepared by management using data from publicly

BACKGROUND

General

Bellatrix is a growth oriented oil and gas exploration company based in Calgary which owns and assumed, directly or indirectly, all of the assets and liabilities, respectively, of True Energy Trust pursuant to a plan of arrangement completed on November 1, 2009. Under the plan of arrangement, True Energy Inc. and True Newco Inc. were amalgamated under the ABCA to form a new corporation which was subsequently amalgamated under the ABCA with 1485166 Alberta Ltd. to form Bellatrix.

On December 11, 2013, Bellatrix was amalgamated with Angle and its subsidiary, Angle Resources Inc., under the ABCA and continued under the name “Bellatrix Exploration Ltd.” pursuant to the Angle Arrangement.

Bellatrix does not have, and at December 31, 2014 did not have, any material subsidiaries.

Bellatrix’s principal, head office and registered office is located at 1920, 800 — 5th Avenue S.W., Calgary, Alberta T2P 3T6.

The Common Shares trade on the TSX and the NYSE under the symbol “BXE”.

GENERAL DEVELOPMENT OF OUR BUSINESS

The following is a summary description of the development of our business since January 1, 2012.

Listing on the NYSE MKT

On August 30, 2012, Bellatrix announced that it had filed an Original Listing Application to list the Common Shares on the NYSE MKT. In connection with the filing of the Original Listing Application, Bellatrix filed a Registration Statement on Form 40-F with the SEC. The Common Shares commenced trading on the NYSE MKT on September 24, 2012 under the symbol “BXE”.

2012 Asset Acquisitions and Divestitures

On November 15, 2012 (with an effective date of November 1, 2012), Bellatrix acquired prospective Cardium and Spirit River lands and production in the Willesden Green area of Alberta for approximately $21 million. At the time of the acquisition, the assets to be acquired had production capability of approximately 500 BOE/d (32% oil and liquids and 68% natural gas) and included 16 gross (11.95 net) sections of Cardium and Mannville prospective lands in the Ferrier/Willesden Green Cardium resource play. The assets acquired also included a 25% working interest in an operated compressor station and gathering system. As a result of the acquisition, Bellatrix added an additional 25 net Cardium and 4 net Spirit River drilling locations to the Corporation’s drilling inventory.

In late 2012, as a result of an ongoing joint venture development program with the O’Chiese First Nations, Bellatrix acquired an additional 11 gross and net sections of Cardium and Spirit River lands at Ferrier. This acquisition added an additional 37 net drilling locations in the Cardium, 9 net drilling locations in the Spirit River, and 66 net drilling locations in the Duvernay formation.

2013 Joint Ventures and Asset Acquisitions and Divestures

Joint Venture with Grafton Energy Co I Ltd.

On June 27, 2013, Bellatrix closed a $122 million joint venture (the “Grafton Joint Venture”) with Grafton to accelerate development on a portion of Bellatrix’s undeveloped land holdings. The Grafton Joint Venture is in Willesden Green and Brazeau areas of West-Central Alberta. Under the terms of the initial agreement, Grafton was to contribute 82%, or $100 million, to the $122 million Grafton Joint Venture to participate in an expected 29 Spirit River and Cardium well program. In the event Bellatrix fails to expend all of the commitment capital within two years of the closing date and if the funding period has not been otherwise terminated before such time in accordance with the terms

of the Grafton Joint Venture, Grafton will be entitled to a non-performance payment from the Corporation equal to 0.4 times the unspent capital. Should Grafton fail to fund as required in accordance with the Grafton Joint Venture, Bellatrix shall have the option to terminate the funding period under the Grafton Joint Venture and if it does so, the Corporation will be entitled to a non-funding payment from Grafton equal to 0.2 times of the unpaid commitment capital. In certain circumstances if Bellatrix is in default of its commitments under the Grafton Joint Venture or there is a change of control of Bellatrix, Grafton has the right to cause the Corporation to acquire Grafton’s earned working interest or GORR, as applicable. Under certain circumstances if Grafton fails to fund in accordance with the Grafton Joint Venture, in addition to the non-funding payment, Bellatrix is entitled to elect to acquire Grafton’s earned working interest or GORR, as applicable. The value paid under Grafton’s put option and the Corporation’s call option shall depend on the circumstances and be based on formulas as set out in the Grafton Joint Venture that reference the net present value, discounted at 10%, of the proved plus probable reserves to be acquired, as evaluated by an independent reserves evaluator.

On September 10, 2013, Bellatrix announced that Grafton elected to exercise an option to increase the committed capital investment by an additional $100 million on the same terms and conditions. Under the terms of the amended agreement, Grafton will contribute 82%, or $200 million, to the $244 million Grafton Joint Venture to participate in an expected 58 Spirit River and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix’s working interest in each well drilled in the well program until payout (being recovery of Grafton’s capital investment plus an 8% return) on the total program, reverting to 33% of the Corporation’s working interest after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% working interest to a 17.5% GORR on Bellatrix’s pre-joint venture working interest. Under the agreement, Grafton was also granted an additional one-time option to be exercised within 12 months of the effective date to increase its exposure by an additional $50 million on the same terms and conditions. The effective date of the agreement is July 1, 2013 and has a term of 2 years.

Asset Disposition and Strategic Partnership with Daewoo International Corporation and Devonian Natural Resources Private Equity Fund

On September 3, 2013, Bellatrix announced the closing of a $200 million strategic joint venture (the “Daewoo/Devonian Joint Venture”) and a $52.5 million asset disposition with Daewoo and Devonian whereby Bellatrix sold, effective July 1, 2013, to the Canadian subsidiaries of Daewoo and Devonian an aggregate 50% of the Corporation’s working interest share of its producing assets, an operated compressor station and gathering system and related land acreage in the Baptiste area of West Central Alberta for gross consideration of $52.5 million. The Daewoo/Devonian Joint Venture, which was effective as of July 1, 2013, encompasses a multiyear commitment to jointly develop the aforementioned acreage in Ferrier and Willesden Green of West Central Alberta encompassing 70 gross wells with anticipated total capital expenditures to the Daewoo/Devonian Joint Venture of approximately $200 million.

Joint Venture with TCA Energy Ltd.

On November 11, 2013, Bellatrix announced it had closed a $240 million joint venture partnership (the “TCA Joint Venture”) with TCA. TCA is a Canadian incorporated special purpose vehicle for Troika Resources Private Equity Fund which is based in Seoul, Korea and managed by KDB Bank, SK Energy and Samchully AMC. Pursuant to the agreement forming the TCA Joint Venture, Bellatrix and TCA will drill and develop lands in the Ferrier Cardium area of West Central Alberta, with the program to be completed by December 31, 2014, unless extended by the parties. TCA will contribute $120 million, representing a 50% share, towards the capital program for the drilling of an expected 63 gross wells, and in exchange, will receive 35% of Bellatrix’s working interest until payout (being recovery of TCA’s capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of our working interest. As part of this agreement, TCA participated in 14 gross wells (as included in the total expected 63 gross well program) drilled between January 1, 2013 and November 11, 2013, resulting in net proceeds of $16.7 million that were received by Bellatrix at closing.

2013 Property Acquisition

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

2013 Redemption of 4.75% Debentures

During the third quarter of 2013, Bellatrix issued a notice of redemption of its then outstanding $55.0 million 4.75% Debentures, with a redemption date of October 21, 2013. During September 2013, $5 million principal amount of 4.75% Debentures were converted into an aggregate of 895,605 Common Shares. Subsequent to September 30, 2013, the remaining $50 million principal amount of 4.75% Debentures were converted or redeemed in exchange for an aggregate of 8,898,243 Common Shares.

2013 Public Offering of Common Shares

On November 5, 2013, Bellatrix closed a bought deal offering of 21,875,000 Common Shares at a price of $8.00 per Common Share for aggregate gross proceeds of approximately $175 million.

2013 Angle Arrangement

On December 11, 2013, Bellatrix closed the Angle Arrangement with Angle, pursuant to which, Bellatrix acquired all of the issued and outstanding Angle Shares and all of the issued and outstanding Angle Debentures. Pursuant to the Angle Arrangement, Bellatrix acquired all of the issued and outstanding Angle Shares for consideration consisting of $69.7 million in cash and approximately 30.2 million Common Shares. The Corporation acquired all of the issued and outstanding Angle Debentures in the aggregate principal amount of $60 million on the basis of $1,040 in cash per $1,000 principal amount of the Angle Debentures, plus accrued and unpaid interest to December 10, 2013. As part of the Angle Arrangement, Angle and its subsidiary, Angle Resources Inc., amalgamated with Bellatrix and continued under the name “Bellatrix Exploration Ltd.” and the Angle Shares were delisted from the TSX.

In conjunction with the Angle Arrangement, the Board approved the appointment of Keith Turnbull, a former director of Angle, as a director of Bellatrix effective January 1, 2014.

2014 Joint Ventures and Asset Acquisitions and Divestures

Grafton Joint Venture

On April 10, 2014, Bellatrix announced that Grafton elected to exercise their option to increase their committed capital investment pursuant to the Grafton Joint Venture by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions as described above. Grafton’s increased capital investment will continue to support the accelerated development of a portion of the Corporation’s undeveloped land holdings. With the exercise of the $50 million option, the Corporation has until the end of the third anniversary of the effective date of the initial agreement for the Grafton Joint Venture (July 1, 2013) to spend the additional capital.

CNOR Joint Venture

On September 29, 2014, the Corporation entered into a new multi-year joint venture arrangement with CNOR, a non-operated oil and gas company managed by Grafton Asset Management Inc. pursuant to which CNOR has committed $250 million in capital towards future accelerated development of a portion of the Corporation’s undeveloped land holdings (the “CNOR Joint Venture”). Under the terms of the agreement, commencing on or before October 1, 2015 Bellatrix will propose development plans for approval by a management committee comprised of representatives of Bellatrix and CNOR. Unless otherwise specified in an approved development plan, CNOR will pay 50% of the drilling, completion, equipping and tie-in capital expenditures in order to earn 33% of the Corporation’s working interest before payout and automatically converting to a 10.67% GORR on Bellatrix’s pre-joint venture working interest after payout (being recovery of CNOR’s capital investment plus an 8% return on investment). The CNOR Joint Venture funding is available immediately; however, the Corporation expects the funds to be spent primarily from 2016 through 2018. If any development plan Bellatrix proposes is not approved within 60 days of the Corporation’s submission, such plan will not be funded under the CNOR Joint Venture arrangement, and thereafter neither party will have any obligation to propose, consider or fund any additional proposed development plans. In certain circumstances if the Corporation is in default of its commitments under the CNOR Joint Venture or there is a change of control of Bellatrix, CNOR has the right to cause the Corporation to acquire CNOR’s earned working interest or GORR, as applicable. Under certain circumstances if CNOR fails to fund in accordance with the CNOR Joint Venture, in addition to the non-funding payment, the Corporation will be entitled to elect to acquire CNOR’s earned working interest or GORR, as applicable.

The value paid under CNOR’s put option and Bellatrix’s call option will depend on the circumstances and be based on formulas as set out in the CNOR Joint Venture that reference the net present value, discounted at 10%, of the proved plus probable reserves to be acquired, as evaluated by an independent reserves evaluator.

Tuck-In Acquisitions

In September 2014, the Corporation completed a tuck-in acquisition of working-interests in its core Ferrier area in West Central Alberta, extending the Corporation’s Cardium light oil resource play. The acquired assets included current low decline rate net production of approximately 300 BOE/d (24% oil and liquids and 76% natural gas) and included 8 gross (7.0 net) sections of Cardium mineral rights and 3 gross (1.2 net) sections of Mannville prospective lands. Bellatrix acquired the assets for a net purchase price of $13.9 million, which was funded using the Credit Facilities. The Corporation also entered into a farmin arrangement encompassing 12 gross (9.4 net) sections of Mannville rights and 6 gross (3.5 net) sections Cardium rights in the Ferrier area of West Central Alberta. Under the arrangement, the Corporation has committed to drill a minimum of 6 wells into the Cardium interval and 6 wells into the Mannville interval. By drilling these wells, Bellatrix will earn the farmor’s entire working interest in either the Cardium or Mannville for each section drilled, but reserving a 15% GORR payable on Mannville wells and a 7.5% to 12% GORR payable on Cardium wells to the farmee. After drilling all commitment wells, Bellatrix has the right to drill additional option wells to earn the remaining sections of Cardium and Mannville rights on similar terms. The Corporation was also active in Alberta land sales in 2014 acquiring 2 gross (2 net) sections of mineral rights in the Mannville and Cardium intervals in the highly prospective Alder Flats area in Central Alberta for $4.3 million. In connection with the aforementioned tuck-in acquisition and farmin arrangement, the Corporation increased its 2014 net capital budget to $530 million.

During the fourth quarter of 2014, the Corporation completed the acquisition of complementary assets within its core Alder Flats area of west central Alberta (greater Ferrier region) for total adjusted cash consideration of $33.0 million. Approximately 720 boe/d of unrestricted production (77% natural gas, 23% liquids) was acquired in the transaction from approximately 33 gross (5 net) sections of land at Alder Flats, representing largely joint interest lands where Bellatrix currently maintains existing working interest rights. Production is largely from the Mannville formation, with minor contributions from the Belly River, Rock Creek and other formations. The effective date of the transaction was September 1, 2014.

Alder Flats Acquisition

During the fourth quarter of 2014, the Corporation completed the acquisition of assets in the Alder Flats area of west central Alberta (greater Ferrier region) from a senior oil and gas producer for total cash consideration of approximately $118 million with an effective date of November 1, 2014. The acquisition added approximately 2,200 boe/d of unrestricted production (80% natural gas, 20% liquids) at the time of the acquisition, and largely represented the consolidation of working interest ownership from existing wellbores and Mannville formation rights.

Transfer of Interests in Alder Flats Gas Plant

During the fourth quarter of 2014, Bellatrix completed the transfer at cost of minority interests in its O’Chiese Ness-Ohpawganu’ck deep-cut gas plant at Alder Flats (the “Bellatrix Alder Flats Plant”) and related pipeline infrastructure currently under construction (collectively the “Facilities”) to Keyera and O’Chiese. Under the agreed upon terms, Keyera and O’Chiese will participate as 35% and 5%, respectively, minority interest owners in the Facilities, which consist of the two proposed phases of the Bellatrix-operated deep-cut gas plant and related plant infrastructure, as well as the associated pipelines, all of which are currently under construction. The Corporation will retain a 60% ownership interest in the Facilities and will be the operator.

The sales gas design capacity of the Bellatrix Alder Flats Plant is 220 MMcf/d and will be developed in two phases at an estimated total cost of approximately $190 million; the total cost of the Facilities which includes the Bellatrix Alder Flats Plant and related infrastructure is estimated at $230 million. As at December 31, 2014, approximately $60 million had been spent on Phase I of the Bellatrix Alder Flats Plant including the interests of Keyera and O’Chiese. Phase I of the new Bellatrix Alder Flats Plant has an expected on-stream date of July 1, 2015 and Phase II of the new Bellatrix Alder Flats Plant has an expected on-stream date in 2017.

2014 Pipeline Completion

On April 2, 2014, the Corporation announced the completion of a 1.6 km river bore and a 7 km pipeline in conjunction with the completion by Blaze of a 55 km pipeline to tie-in Bellatrix’s natural gas for processing in the Blaze gas plant located at 04-31-048-12W5. The Corporation has secured firm processing capacity of 100 MMcf/d in the plant. The pipeline was commissioned on April 1, 2014. In the fourth quarter of 2013 and in the first quarter of 2014, Bellatrix installed a total of 8 field booster compressors located at 13-5-45-9W5 (tie-in point to the Blaze pipeline) with capacity of 97 MMcf/d.

2014 Plant Turnarounds

On May 16, 2014, the Corporation announced that during the month of May it was experiencing significant unscheduled temporary plant turnarounds at some of the third party operated gas processing plants where some of the Corporation’s production from west central Alberta is processed. Although the Corporation made every effort to redirect and offload gas to alternative plants during these outages, the cumulative impact of the unscheduled temporary plant turnarounds was a reduction of 4,064 BOE/d in the Corporation’s May net average production volumes.

2014 Firm Processing Agreement

On December 2, 2014, the Corporation announced that it has entered into an agreement with Keyera for 19 MMcf/d of firm service processing capacity beginning immediately, increasing to 30 MMcf/d on April 1, 2016, at Keyera’s Strachan deep-cut gas plant. The Keyera Strachan plant is well connected to multiple gathering pipelines and has inlet compression, gas dehydration and deep-cut natural gas liquids recovery.

2014 Public Offering of Common Shares

On June 5, 2014, the Corporation closed a bought deal offering of 18,170,000 Common Shares at a price of $9.50 per Common Share for aggregate gross proceeds of $172,615,000.

Listing on the NYSE

On October 6, 2014, Bellatrix transferred the listing of the Common Shares from NYSE MKT to the NYSE.

2014 Increased Credit Facilities and 2015 Financial Covenants Amendment

On December 1, 2014, the lenders under the Credit Facilities increased the Corporation’s borrowing base under the Credit Facilities to $725 million from $625 million. The increased Credit Facilities are available to finance the Corporation’s ongoing capital expenditures, working capital requirements, and for general corporate purposes. The Corporation is required to comply with covenants under its Credit Facilities, which include certain financial ratio tests, which from time to time either affect the availability, or price, of additional funding. As a result of the recent precipitous drop in crude oil prices and the concomitant reduction in Bellatrix’s associated future cash flow and EBITDA, the Corporation sought and obtained from its lenders temporary relaxation of certain of the financial covenants under the Credit Facilities. For additional information relating to the Credit Facilities, see “Borrowings”.

2014 Appointment of Directors and Agreement with Orange Capital

On December 15, 2014, Bellatrix announced that Daniel Lewis and Steven J. Pully would be appointed directors of the Corporation, effective January 1, 2015. In connection with the appointment of Messrs. Lewis and Pully, Bellatrix entered into an agreement with Orange Capital, pursuant to which Orange Capital agreed to abide by certain standstill provisions until November 30, 2015. In addition pursuant to the agreement, the Corporation agreed to nominate Messrs. Lewis and Pully (or two other nominees of Orange Capital acceptable to the Board, acting reasonably) at the 2015 annual shareholders meeting of the Corporation provided that Orange Capital (or its affiliates) owns, controls or directs, directly or indirectly 10% or more of the outstanding Common Shares. Orange Capital is only entitled to one nominee if its percentage ownership falls below 10% but remains above 5% of the outstanding Common Shares. In addition, to the standstill provision, Orange Capital has agreed to cause all Common Shares that it or its affiliates are entitled to vote, to be voted in favour of all the management nominees for election as directors of the Corporation and in favour of the resolution approving and authorizing all unallocated options to purchase Common Shares granted under

the Corporation’s share option plan at the 2015 annual shareholders meeting of the Corporation. A copy of the agreement with Orange Capital is filed on SEDAR at www.sedar.com.

2015 Capital Budget

On November 4, 2014, the Corporation announced an initial $450 million net capital budget for 2015 (the “2015 net capital budget”), which was reduced to $400 million on December 1, 2014 in light of recent commodity price changes. On December 22, 2014, the Corporation announced a reduction of the 2015 net capital budget to $300 million in light of rapid declines in crude oil prices. On January 29, 2015, in response to continued volatility of oil and gas prices, the Corporation announced an updated 2015 net capital budget of up to $200 million, reduced from the previously approved $300 million.

Significant Acquisitions

The Corporation has not completed any acquisitions that would be considered significant pursuant to NI 51-102 since January 1, 2014.

DESCRIPTION OF BUSINESS

Business Plan and Growth Strategies

Bellatrix 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. The business plan of Bellatrix is to create sustainable and profitable per share growth in reserves, production and cash flow in the oil and gas industry. To accomplish this, Bellatrix pursued an integrated growth strategy with active development and exploration drilling within its core areas, together with focused acquisitions and strategic joint ventures, and maintenance of a strong flexible financial position. Bellatrix will continue to target areas and prospects that it believes could result in meaningful reserve and production additions.

Bellatrix will continue to pursue internal and external generation of exploration plays that have low to medium risk and multi-zone potential and intends to maintain a balance between exploration, exploitation and development drilling targeting both oil and natural gas reserves over the course of the next several years. Bellatrix considers asset and corporate acquisition opportunities from time to time that meet Bellatrix’s business parameters.

In reviewing potential opportunities, Bellatrix will use the most current methodologies in giving consideration to the following criteria:

· Bellatrix’s technical expertise in the opportunity;

· the amount of risk capital required to secure or evaluate the investment opportunity;

· the potential return on the project, if successful;

· the likelihood of success; and

· risked return versus cost of capital.

In general, Bellatrix is expected to continue to pursue a portfolio approach in developing a large number of opportunities with a balance of risk profiles and commodity exposure in an attempt to generate high levels of sustainable growth.

The Corporation continues to target areas and prospects that it believes could result in meaningful reserve and production additions. Bellatrix may, however, in its discretion, proceed with asset or corporate acquisitions or investments that do not conform to the guidelines discussed above based upon its consideration of the qualitative aspects of the subject properties, including risk profile, technical upside, reserve life and asset quality. In addition, Bellatrix may from time to time consider seeking joint venture partners, strategic investors or other business arrangements to help accelerate development of its properties.

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2014

FORECAST PRICES AND COSTS

	Light And Medium Oil		Heavy Oil		Natural Gas(1)		Natural Gas Liquids
Reserves Category	Gross (Mbbls)	Net (Mbbls)	Gross (Mbbls)	Net (Mbbls)	Gross (MMcf)	Net (MMcf)	Gross (Mbbls)	Net (Mbbls)

Proved Developed Producing	9,008.8	7,305.4	23.9	21.2	291,764	237,063	16,356.0	10,958.6
Proved Developed Non-Producing	203.7	175.4	77.0	59.1	6,373	5,419	304.4	205.1
Proved Undeveloped	7,866.9	6,525.1	108.9	81.2	356,650	296,978	17,508.0	12,849.9
Total Proved	17,079.4	14,005.9	209.8	161.5	654,787	539,460	34,168.4	24,013.5
Probable	7,720.6	6,129.4	213.7	155.1	357,626	288,774	20,738.2	14,744.3
Total Proved Plus Probable	24,800.0	20,135.3	423.5	316.6	1,012,413	828,234	54,906.6	38,757.8

Note:

(1) Includes minor amounts of natural gas from coal bed methane and shale gas reserves. Coal bed methane and shale gas reserves represent an immaterial portion of the Corporation’s natural gas reserves.

	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted At (%/year)					After Income Taxes Discounted at (%/year)					Unit Value Before Income Tax Discounted at 10% Year(1)
Reserves Category	0 ($000s)	5 ($000s)	10 ($000s)	15 ($000s)	20 ($000s)	0 ($000s)	5 ($000s)	10 ($000s)	15 ($000s)	20 ($000s)	($/BOE)	($/Mcfe)

Proved Developed Producing	1,562,159	1,162,721	932,046	782,872	678,792	1,562,159	1,162,721	932,046	782,872	678,792	16.13	2.69
Proved Developed Non—Producing	27,463	21,785	17,872	15,064	12,976	27,463	21,785	17,872	15,064	12,976	13.31	2.22
Proved Undeveloped	1,346,355	768,248	461,602	279,377	162,344	1,018,812	594,238	360,220	216,319	121,175	6.69	1.12
Total Proved	2,935,976	1,952,754	1,411,520	1,077,313	854,112	2,608,434	1,778,744	1,310,138	1,014,255	812,943	11.02	1.84
Probable	1,817,319	1,067,708	704,085	496,725	365,370	1,362,632	796,728	521,876	365,112	265,818	10.18	1.70
Total Proved Plus Probable	4,753,295	3,020,462	2,115,605	1,574,039	1,219,481	3,971,066	2,575,472	1,832,014	1,379,367	1,078,761	10.73	1.79

Note:

(1) Unit values are based upon net reserves.

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

AS OF DECEMBER 31, 2014

FORECAST PRICES AND COSTS

Reserves Category	Revenue ($000s)	Royalties ($000s)	Operating Costs ($000s)	Capital Development Costs ($000s)	Abandonment Costs ($000s)	Future Net Revenue Before Income Taxes ($000s)	Income Tax ($000s)	Future Net Revenue After Income Taxes ($000s)

Proved Reserves	7,486,353	1,548,969	2,050,750	863,249	87,410	2,935,976	327,543	2,608,434

Proved Plus Probable	11,811,840	2,509,849	3,100,103	1,335,990	112,603	4,753,295	782,229	3,971,066

FUTURE NET REVENUE

BY PRODUCTION GROUP(1)

AS OF DECEMBER 31, 2014

FORECAST PRICES AND COSTS

Reserves Category	Production Group(1)	Future Net Revenue Before Income Taxes (discounted at 10%/year) ($000s)	Unit Value(2) Before Income Tax (discounted at 10%/year)
Proved	Light and Medium Crude Oil (including solution gas and other by—products)	501,142	$	13.09/BOE
	Heavy Oil (including solution gas and other by-products)	2,129	$	13.18/BOE
	Natural Gas (including by—products but excluding solution gas from oil wells)(3)	879,811	$	9.81/BOE
	Other(4)	28,438
	Total	1,411,520

Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by—products)	732,299	$	13.05/BOE
	Heavy Oil (including solution gas and other by-products)	4,426	$	13.98/BOE
	Natural Gas (including by—products but excluding solution gas from oil wells)(3)	1,345,247	$	9.55/BOE
	Other(4)	33,633
	Total	2,115,605

Notes:

(1) Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.

(2) Unit values are based on net reserves.

(3) Includes minor amounts of revenue and costs associated with natural gas from coal bed methane and shale gas reserves.

(4) Other is rebated costs from company transportation and processing of royalty volumes, primarily those of the Alberta Crown, denoted as Gas Cost Allowance (“GCA”).

Notes to Reserves Data Tables:

1. Columns may not add due to rounding.

2. The crude oil, natural gas liquids and natural gas reserve estimates presented in the Sproule Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

· Analysis of drilling, geological, geophysical and engineering data;

· The use of established technology;

· Specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed; and

· A remaining reserve life of 50 years.

Reserves are classified according to the degree of certainty associated with the estimates.

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Other criteria that must also be met for the categorization of reserves are provided in Section 5.5 of the COGE Handbook.

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

FORECAST PRICES AND COSTS

	OIL
Year	Canadian Light Sweet Crude 40°API ($Cdn/Bbl)	Western Canada Select 20.5°API ($Cdn/Bbl)	NATURAL GAS AECO Price ($Cdn/MMBtu)	NATURAL GAS LIQUIDS at Edmonton(1) ($Cdn/Bbl)	INFLATION RATES(2) %/Year	EXCHANGE RATE(3) ($US/$Cdn)

Forecast
2015	67.89	57.48	3.38	73.48	1.833	0.85
2016	83.52	70.74	3.83	90.17	1.833	0.87
2017	90.96	77.07	4.06	98.20	1.833	0.87
2018	95.26	80.70	4.41	102.69	1.833	0.87
2019	99.33	84.12	4.76	106.99	1.833	0.87
2020	103.80	87.87	4.97	111.73	1.833	0.87
2021	106.16	89.88	5.18	114.26	1.833	0.87
2022	108.10	91.53	5.36	116.34	1.833	0.87
2023	110.09	93.19	5.54	118.47	1.833	0.87
2024	112.13	94.91	5.70	120.67	1.833	0.87
Thereafter	+1.83%/yr	+1.83%/yr	+1.83%/yr	+1.83%/yr

Notes:

(1) Natural gas liquids is represented by pentanes plus price.

(2) Inflation rates for forecasting prices and costs.

(3) Exchange rates used to generate the benchmark reference prices in this table.

Weighted average historical prices realized by Bellatrix (before commodity price risk management contracts) for the year ended December 31, 2014, were $4.77/Mcf for natural gas, $91.41/Bbl for light and medium gravity crude oil and condensate, and $42.74/Bbl for natural gas liquids (excluding condensate).

Reconciliation of Changes in Reserves

The following table sets out the reconciliation of our gross reserves as at December 31, 2013 compared to December 31, 2014 based on forecast prices and costs by principal product type:

	LIGHT AND MEDIUM OIL						HEAVY OIL
FACTORS	Company Gross Proved (Mbbl)		Company Gross Probable (Mbbl)		Company Gross Proved Plus Probable (Mbbl)		Company Gross Proved (Mbbl)		Company Gross Probable (Mbbl)		Company Gross Proved Plus Probable (Mbbl)

December 31, 2013(2)	18,993.1		11,568.1		30,561.2		216.8		264.9		481.7

Discoveries	57.0		10.5		67.5		—		—		—
Extensions	482.9		601.6		1,084.5		—		—		—
Infill Drilling	749.6		794.4		1,544.0		—		—		—
Improved Recovery	—		—		—		—		—		—
Technical Revisions	(1,715.5	)	(5,120.5	)	(6,836.0	)	19.5		(51.2	)	(31.7	)
Acquisitions	420.6		173.4		594.0		—		—		—
Dispositions	(203.0	)	(38.4	)	(241.4	)	—		—		—
Economic Factors	(12.2	)	(268.5	)	(280.7	)	(0.9	)	—		(0.9	)
Production	(1,693.1	)	—		(1,693.1	)	(25.6	)	—		(25.6	)

December 31, 2014(3)	17,079.4		7,720.6		24,800.0		209.8		213.7		423.5

	NATURAL GAS LIQUIDS						NATURAL GAS(1)
FACTORS	Company Gross Proved (Mbbl)		Company Gross Probable (Mbbl)		Company Gross Proved Plus Probable (Mbbl)		Company Gross Proved (MMcf)		Company Gross Probable (MMcf)		Company Gross Proved Plus Probable (MMcf)

December 31, 2013(2)	25,841.9		21,194.8		47,036.7		474,353		326,065		800,418

Discoveries	42.6		8.8		51.4		1,042		216		1,258
Extensions	1,294.5		1,138.5		2,433.0		28,324		24,394		52,718
Infill Drilling	2,678.4		1,826.0		4,504.4		60,793		40,173		100,966
Improved Recovery	—		—		—		—		—		—
Technical Revisions	4,544.5		(3,633.0	)	911.5		67,307		(66,715	)	592
Acquisitions	4,731.5		1,803.2		6,534.7		109,660		41,797		151,457
Dispositions	(793.5	)	(182.6	)	(976.1	)	(17,844	)	(4,125	)	(21,968	)
Economic Factors	(1,342.5	)	(1,417.5	)	(2,760.0	)	(12,876	)	(4,180	)	(17,055	)
Production	(2,829.0	)	—		(2,829.0	)	(55,972	)	—		(55,972	)

December 31, 2014(3)	34,168.4		20,738.2		54,906.6		654,787		357,626		1,012,413

Notes:

(1) Includes minor amounts of natural gas from coal bed methane and shale gas reserves.

(2) As evaluated by Sproule in a report dated March 4, 2014 and effective as of December 31, 2013.

(3) As evaluated in the Sproule Report.

Additional Information Relating to Reserves Data

Undeveloped Reserves

The following tables set forth the proved undeveloped gross reserves and the probable undeveloped gross reserves, each by product type, attributed to Bellatrix’s assets for the years ended December 31, 2014, 2013 and 2012 and, in the aggregate, before that time based on forecast prices and costs.

Proved Undeveloped Reserves

	Light and Medium Oil (Mbbl)		Heavy Oil (Mbbl)		Natural Gas(1) (MMcf)		NGLs (Mbbl)
Year	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End

Prior thereto	2,552.3	4,425.1	30.0	210.0	49,804	84,812	1,919.4	3,250.4
2012	1,123.7	5,118.5	—	113.3	36,227	120,898	1,495.7	5,199.7
2013	1,430.3	9,481.3	—	112.8	123,060	275,557	5,186.4	13,774.2
2014	796.5	7,866.9	—	108.9	33,762	356,650	1,549.6	17,508.0

Probable Undeveloped Reserves

	Light and Medium Oil (Mbbl)		Heavy Oil (Mbbl)		Natural Gas(1) (MMcf)		NGLs (Mbbl)
Year	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End	First Attributed	At Year End

Prior thereto	2,923.6	3,457.6	5.0	120.0	46,531	65,527	1,843.0	2,654.8
2012	1,619.5	3,858.8	—	199.8	81,223	163,856	4,921.7	7,003.1
2013	2,593.5	8,327.7	—	198.7	116,455	259,669	5,386.1	17,251.5
2014	1,317.9	5,434.6	—	187.0	50,976	276,565	2,367.5	16,324.1

Note:

(1) Includes minor amount of natural gas from coal bed methane and shale gas reserves.

Proved Undeveloped Reserves

A total of 356,650 MMcf of natural gas, 7,975.8 Mbbl of oil and 17,508.0 Mbbl of NGLs were assigned as proved undeveloped reserves as at December 31, 2014, representing approximately 53% of our total proved reserves. The proved undeveloped reserves are generally associated with infill/development drilling locations supported by offset well data. In estimating future net revenue, Sproule reviewed Bellatrix’s future development plans in order to estimate and deduct future development costs. Therefore the future development costs as set under “Future Development Costs” are consistent with Bellatrix’s future development plans at year end. The capital associated with developing proved undeveloped reserves is expected to be spent between 2015 and 2018. With respect to capital development costs associated with proved undeveloped reserves in the Sproule Report, approximately 66% of the capital is scheduled to be spent over the next two years and 90% is scheduled to be spent over the next three years.

The West Central region of Alberta is a significant producing and development area for Bellatrix. Development drilling in both the proved and probable cases is anticipated for oil and gas in Brazeau, Ferrier, Harmattan and Strachan and represents 81% of all assigned proven future development capital. The programs are staged in line with sound development practices and to exploit horizontal drilling and multi-fracturing completion opportunities.

Residual future development capital is assigned across various other properties operated by Bellatrix including Willesden Green and Frog Lake. The majority of this spending is also forecast for the next three years with minor work planned past this point, based on relief of existing wellbore constraints.

Although Bellatrix expects the development of its proved undeveloped reserves to be consistent with that set out above, current industry conditions and other uncertainties as indicated under “Risk Factors” herein could result in development of Bellatrix’s proved undeveloped reserves on a different schedule than set out above. See also the discussion under “Future Development Costs” that references the Corporation’s 2015 net capital budget.

Probable Undeveloped Reserves

A total of 276,565 MMcf of natural gas, 5,621.6 Mbbl of oil and 16,324.1 Mbbl of NGLs were assigned as gross probable undeveloped reserves in 2014, representing approximately 77% of our total probable reserves or 27% of total proved plus probable reserves.

The bulk of the probable undeveloped reserves assigned are associated with projects that have a proved reserves component. Probable reserves are attributed in addition to proved reserves in these cases according to the definitions and guidelines of the COGE Handbook. There are also some projects assigned probable reserves that do not have a proven reserves component, as per the terms of the COGE Handbook.

As was the case with proved undeveloped reserves, the West Central Alberta region has significant probable undeveloped reserves. The expenditures required to develop the probable undeveloped reserves are scheduled in a staggered pattern from 2015 to 2018. With respect to capital development costs associated with probable undeveloped reserves in the Sproule Report, approximately 70% of the capital is scheduled to be spent over the next two years and 92% is scheduled to be spent over the next three years. In scheduling future development capital, priority is given to

projects with a proved component, as those projects have reduced risk and are easier to predict timing or serve to prove up further projects currently only assigned probable reserves.

Although Bellatrix expects the development of its probable undeveloped reserves to be consistent with that set out above, current industry conditions and other uncertainties as indicated under “Risk Factors” herein could result in development of Bellatrix’s probable undeveloped reserves on a different schedule than set out above. See also the discussion under “Future Development Costs” that references the Corporation’s 2015 net capital budget.

Significant Factors or Uncertainties

While we do not anticipate any significant economic factors or uncertainties will affect any particular components of the reserves data, the reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond our control (see “Risk Factors”).

Future Development Costs

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below:

Year	Proved Reserves ($000s)	Proved Plus Probable Reserves ($000s)

2015	234,209	369,262
2016	339,453	532,991
2017	203,473	309,953
2018	85,377	123,046
2019	—	—
Thereafter	736	736
Total: Undiscounted	863,249	1,335,990

The capital expenditure program developed for the reserves evaluation, including estimated future development costs, was developed based on using cash flow from operations and available credit facilities. Equity financing was also considered to fund operations. If cash flows are other than projected, capital expenditure levels may be adjusted. Our practice of continually monitoring spending opportunities in comparison to expected cash flow levels allows for adjustments to the capital program as required. In addition, depending on a number of factors including commodity prices, industry conditions and Bellatrix’s financial and operating results, equity financings may not be available on terms acceptable to the Corporation, which could also result in adjustments to the capital program as required. The expected costs of funding our capital expenditures have been built into the economics of the programs and the reserves evaluation.

As indicated under “General Development of our Business — 2015 Capital Budget”, as a result of continued depressed and volatile oil and gas prices, the Board reduced the 2015 net capital budget to $200 million. As a result, the 2015 net capital budget would not meet the development schedule as contemplated by the Sproule Report. The Corporation continues to monitor commodity prices and may make further changes (either positive or negative) to the 2015 net capital budget. As a result, the reserves as set out in the Sproule Report may not be developed as quickly as contemplated by the Sproule Report.

Other Oil and Gas Information

Principal Properties

The following is a description of Bellatrix’s principal oil and natural gas properties as at December 31, 2014. Unless otherwise indicated, production stated is average daily production for the year ended December 31, 2014 received by Bellatrix in respect of its working interest share before deduction of royalties and without including any royalty interest.

Ferrier

Located 35 kilometres northwest of Rocky Mountain House, Alberta, the Ferrier and Alder Flats areas produce natural gas and natural gas liquids from the Belly River, Cardium, Notikewin, Falher and Rock Creek zones at depths ranging from 1,800 to 2,700 metres. Area production averaged 22,655 BOE/d for 2014, comprised of 80% natural gas, 13% natural gas liquids and 7% light oil and condensate. The majority of oil production from the area is delivered to two batteries in which we have 61.18% and 100% working interests. Gas volumes from the area are delivered to third party non-operated gas plants for processing, including two major gas processing facilities in the area in which the Corporation holds a minor working interest. Our land holdings in the area were 65,834 gross (37,589 net) acres of developed land and 46,072 gross (37,745 net) acres of undeveloped land as at December 31, 2014.

In 2014, Bellatrix operated the drilling of 58 gross (31.6 net) Cardium horizontal oil and liquids-rich gas wells; the Corporation also participated in 1 gross (0.3 net) non-operated Cardium test well. The Corporation also drilled 30 gross (14.0 net) Spirit River liquids-rich gas wells and participated in an additional 2 gross (0.7 net) non-operated Spirit River gas wells.

In September 2014, the Corporation completed a tuck-in acquisition of working-interests at Ferrier, extending its Cardium light oil resource play. The acquired assets have a low decline rate with net production of approximately 300 BOE/d (24% oil and liquids and 76% natural gas) which included 8 gross (7.0 net) sections of Cardium mineral rights and 3 gross (1.2 net) sections of Mannville prospective lands. Bellatrix acquired the assets for a net purchase price of $13.9 million, which was funded using the Credit Facilities. The Corporation also entered into a farmin arrangement encompassing 12 gross (9.4 net) sections of Mannville rights and 6 gross (3.5 net) sections of Cardium rights at Ferrier. Under the arrangement, Bellatrix has committed to drill a minimum of 6 wells into the Cardium interval and 6 wells into the Mannville interval. By drilling these wells, the Corporation will earn the farmor’s entire working interest in either the Cardium or Mannville for each section drilled, but reserving a 15% GORR payable on Mannville wells and a 7.5% to 12% GORR payable on Cardium wells to the farmor. After drilling all commitment wells, Bellatrix has the right to drill additional option wells to earn the remaining sections of Cardium and Mannville rights on similar terms.

In late November 2014, the Corporation closed an acquisition of complementary working interests at Ferrier, focused on the liquids rich Mannville natural gas play, for total cash consideration of approximately $118 million. The acquisition added approximately 2,200 boe/d of currently unrestricted production (80% natural gas, 20% liquids), and largely represents the consolidation of working interest ownership from existing wellbores and Mannville formation rights in Alder Flats.

During the fourth quarter of 2014, the Corporation completed the acquisition of complementary assets within the greater Ferrier region for total adjusted cash consideration of $33.0 million. Approximately 720 boe/d of unrestricted production (77% natural gas, 23% liquids) was acquired in the transaction from approximately 33 gross (5 net) sections of land at Alder Flats, representing largely joint interest lands where Bellatrix currently maintains existing working interest rights. Production is largely from the Mannville formation, with minor contributions from the Belly River, Rock Creek and other formations. The effective date of the transaction was September 1, 2014.

Although Bellatrix continues to monitor the emerging Duvernay resource play at Ferrier, the Corporation did not drill any Duvernay wells in 2014.

To date in 2015 at Ferrier, the Corporation has drilled a total of 2 gross (1.1 net) Cardium horizontal wells, which have been completed and tied-in. The Corporation has drilled 3 gross (2.0 net) Spirit River horizontal gas wells, of which all have been completed, tied in and placed on production.

Willesden Green

The Willesden Green area is located approximately 45 kilometres north of Rocky Mountain House, Alberta. This property produces oil and associated natural gas from the Cardium zone, liquids-rich natural gas from the Notikewin, Falher, Ellerslie, and Rock Creek formations at depths of 1,800 to 2,800 metres, and sweet dry natural gas from five shallower horizons, including the Paskapoo, Ardley, Horseshoe Canyon, Edmonton and Belly River at depths of 300 to 1,200 metres. Production from this area averaged 1,898 BOE/d for 2014, consisting of 62% natural gas, 24% light oil and 14% natural gas liquids. The majority of this production is operated. The Corporation owns and operates three compressor stations in the area with working interests ranging from 46.86% to 84.75%. Gas is delivered to a third party

operated gas plant where Bellatrix holds a minority interest for processing. The Corporation held 35,680 gross (18,041 net) acres of developed land and 9,120 gross (4,839 net) acres of undeveloped land as at December 31, 2014.

Bellatrix drilled and tied-in 5 gross (2.4 net) Cardium oil wells at Willesden Green in 2014. Bellatrix also participated in the drill and tie-in of 2 gross (0.4 net) non-operated Cardium horizontal oil wells. In addition, Bellatrix drilled a successful Spirit River horizontal liquids rich gas well (0.6 net), which was completed and tied-in.

Greater Pembina

Pembina is located about 25 kilometres west of Drayton Valley, Alberta. Significant oil reserves occur in the Cardium zone at a depth of 1,800 metres and, in addition, there is liquids-rich natural gas potential in the Mannville and Jurassic zones at depths of approximately 2,150 to 2,500 metres. Production from this area averaged 1,928 BOE/d for 2014, consisting of 26% natural gas, 68% light oil and condensate and 6% natural gas liquids. Oil production from the area is delivered to Bellatrix owned and operated oil batteries and gas production is delivered to third party non-operated gas plant for processing. The Corporation held 58,747 gross (34,027 net) acres of developed land and 15,372 gross (6,495 net) acres of undeveloped land as at December 31, 2014.

In 2014, Bellatrix operated the drill and tie-in of 6 gross (5.0 net) Cardium oil wells in the Greater Pembina area. In addition, the Corporation drilled 1 gross (0.5 net) successful horizontal well into the Lower Mannville Ellerslie formation, which was completed and tied in.

To date in 2015, the Corporation participated in one non-operated Cardium oil well (0.2 net); the well has been tied in and is on production.

Strachan

Strachan is located approximately 12 kilometres south of Rocky Mountain House, Alberta. Bellatrix acquired the Strachan property pursuant to the Angle Arrangement in December 2013. The area aligns well with the Corporation’s focus on the light oil and liquids rich natural gas fairway in the Alberta Deep Basin. Historically, the area had been the focus of vertical drilling for oil and gas resources in the Cretaceous units; however, the area has experienced a rejuvenation of development activity with the onset of horizontal well development.

The Strachan property produces oil, natural gas and associated natural gas liquids from the Cardium formation from depths of 2,000 and 2,700 meters. Production from this property averaged 1,715 BOE/d for 2014, consisting of 49% light oil and condensate, 23% natural gas and 28% natural gas liquids. As at December 31, 2014, the Corporation owned and operated four facilities and had a 100% working interest in two compressor stations and a 64.75% working interest and 50.25% working interest in two other compressor stations. All gas production volumes are delivered on to a third party non-operated gas plant for processing. Bellatrix held 23,203 gross (14,822 net) acres of developed land and 46,319 gross (35,928 net) acres of undeveloped land as at December 31, 2014.

In 2014, Bellatrix operated the drill and tie-in of 3 gross (3.0 net) Cardium oil wells at Strachan. To date in 2015, Bellatrix has not drilled additional Cardium wells at Strachan.

Harmattan

Harmattan is located approximately 80 kilometres northwest of Calgary near the town of Sundre, Alberta. Bellatrix acquired the Harmattan property pursuant to the Angle Arrangement in December 2013. This property produces oil and associated natural gas from the Cardium and Viking zones and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at depths of 1,200 to 2,600 metres. Production from this property averaged 4,950 BOE/d for 2014, consisting of 39% natural gas, 24% light oil and condensate and 37% natural gas liquids. The majority of the production from the area is operated by Bellatrix. The Corporation owns a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes are handled. All gas is delivered to a third party non-operated gas plant for processing. Bellatrix held 35,764 gross (33,163 net) acres of developed land and 68,390 gross (67,230 net) acres of undeveloped land as at December 31, 2014.

Management believes that current mapping supports very strong potential for resource development of the oil and liquids rich gas reserves in the Lower Mannville and, although management considers the results of drilling in the

Lower Mannville at Harmattan and Davey Lake to be encouraging, they believe there is potential to improve netbacks from this play.

In 2014, Bellatrix drilled and completed 1 gross (0.5 net) horizontal well into the Lower Mannville Ellerslie formation to test the liquids-rich gas potential, using revised drill and completion techniques. The well has been tied in and is currently being monitored for production performance after applying updated completion techniques.

Oil and Natural Gas Wells

The following table sets forth the number and status of oil wells and gas wells in which we have a working interest as at December 31, 2014.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net

Alberta	419	251	115	47	845	455	168	120
Saskatchewan	3	—	1	1	13	13	21	20
British Columbia	—	—	2	1	7	1	7	2
Total	422	251	118	49	865	469	196	142

Developed and Undeveloped Lands

The following table sets out our developed and undeveloped land holdings as at December 31, 2014.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net

Alberta	462,741	282,478	405,991	330,835	868,732	613,313
British Columbia	9,285	2,765	106,180	47,208	115,465	49,973
Saskatchewan	13,327	12,720	7,641	7,641	20,968	20,361
Total	485,353	297,962	519,812	385,685	1,005,165	683,647

Note:

(1) May not add due to rounding.

The following provides details of certain of the Corporation’s drilling commitments as at December 31, 2014:

· Bellatrix committed to drill 10 gross (4.4 net) wells pursuant to farm-in agreements as at December 31, 2014. Bellatrix expects to satisfy these drilling commitments at an estimated net cost of approximately $16.7 million.

· Pursuant to a joint venture agreement dated February 1, 2011, Bellatrix is committed to drilling 3 gross (3.0 net) wells per year between 2011 and 2015 for a total estimated cost of approximately $56.3 million. As at December 31, 2014, 3 wells remained to be drilled under this commitment for a total estimated cost of $11.3 million.

· Pursuant to a joint venture agreement dated August 4, 2011, Bellatrix is committed to drilling 5 to 10 gross and net wells per year between 2011 and 2016 for a total of 40 gross and net wells at an estimated cost of approximately $150.0 million. As at December 31, 2014, 1 well remained to be drilled under this commitment for a total estimated cost of $3.8 million.

· Pursuant to a joint venture agreement dated December 14, 2012, Bellatrix is committed to drilling 2 gross and net wells per year between 2014 and 2018 for a total of 10 gross and net wells at an estimated cost of

approximately $37.5 million. As at December 31, 2014, 1 well remained to be drilled under this commitment for a total estimated cost of $3.8 million.

Potentially, approximately 13% of our mineral rights are under review prior to December 31, 2015 as a result of those rights reaching the end of their initial land tenure or Indian Oil and Gas Canada administrated rights being subject to a standard, cyclic review process. For any of these rights deemed not already capable of production, Bellatrix plans to evaluate and identify potential drilling operations on selected portions of these lands, to be tested prior to expiry to preserve the rights, and/or to submit applications to continue that acreage.

In addition to the above noted drilling commitments the Corporation entered into a number of joint venture agreements in 2013 and 2014 as described under the heading “General Development of our Business “.

Development of Bellatrix properties with no attributable reserves are subject to current industry conditions and uncertainties as indicated under “Risk Factors” herein. In addition, we expect that funding of development operations on such properties will be evaluated in the context of our total capital requirements having regard to rates of return, the likelihood of success and risked return versus cost of capital, and availability and reliability of methods of hydrocarbon delivery.

Forward Contracts and Marketing

Our commodity marketing strategy is to sell production in the spot market, complemented from time to time by price risk management instruments.

We periodically hedge the price on a portion of our crude oil and natural gas production. We hedged an average of 49% of total crude oil and natural gas liquids production and an average of 60% of total natural gas production during the twelve months ended December 31, 2014. The following provides details of the commodity price risk management arrangements outstanding as at December 31, 2014 and as of the date hereof.

As at December 31, 2014, the Corporation had not entered into commodity price risk management arrangements.

Subsequent to December 31, 2014, the Corporation has entered into commodity price risk management arrangements as follows:

Type

Period

Volume

Price Floor

Price Ceiling

Index

Crude oil fixed

February 1, 2015 to Dec. 31, 2015

2,000 bbl/d

70.27 CDN

WTI

Crude oil fixed

February 1, 2015 to Dec. 31, 2015

1,000 bbl/d

70.48 CDN

WTI

Natural gas fixed

March 1, 2015 to March 31, 2015

25,000 GJ/d

2.83 CDN

AECO

Natural gas fixed

March 1, 2015 to March 31, 2015

25,000 GJ/d

2.81 CDN

AECO

Natural gas fixed

March 1, 2015 to March 31, 2015

25,000 GJ/d

2.83 CDN

AECO

Natural gas fixed

March 1, 2015 to March 31, 2015

25,000 GJ/d

2.82 CDN

AECO

Natural gas fixed