**Exhibit 99.2**

 

 

**MANAGEMENT’S DISCUSSION AND ANALYSIS**

 

*March 11, 2015 — 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, 2014 and 2013.  This commentary is based on information available to, and is dated as of, March 11, 2015. 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.*

 

*FINDING, DEVELOPMENT AND ACQUISITION COSTS:  Finding and development costs including acquisitions and dispositions (“FD&A costs”) have been presented herein. While National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities requires that the effects of acquisitions and dispositions be excluded, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. The Company’s finding and development costs, excluding the effects of acquisitions and dispositions, for 2014 were $18.56/boe on a proved basis and $23.80/boe on a proved plus probable basis. The Company’s finding and development costs, excluding the effects of acquisitions and dispositions, for 2013 were $10.67/boe on a proved basis and $9.65/boe on a proved plus probable basis. The Company’s average finding and development costs for the last three years, excluding the effects of acquisitions and dispositions, were $13.45/boe on a proved basis and $11.69/boe on a proved plus probable basis. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.*

 

*ADDITIONAL GAAP MEASURES:  This MD&A and the 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 MD&A.  Funds flow from operations per share is calculated using the weighted average number of shares for the period.*

 

*This MD&A and the financial statements also contain the terms total net debt and adjusted working capital deficiency (excess), which also are not recognized measures under GAAP. Therefore reference to the additional GAAP measures of total net debt or adjusted working capital deficiency (excess) may not be comparable with the calculation of similar measures for other entities.  The Company’s 2014 calculation of total net debt excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, and the deferred tax liability.  Total net debt includes the adjusted working capital deficiency (excess).  The adjusted working capital deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding current finance lease obligation and current*

 

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*deferred lease inducements.  Management believes these measures are useful supplementary measures of the total amount of current and long-term debt.*

 

*NON-GAAP MEASURES: This MD&A and contains the terms of operating netbacks and total capital expenditures - net, which are not recognized measures under GAAP.  Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from revenues before other income.  Management believes this measure is a useful supplemental measure of the amount of revenues received after transportation, royalties and operating expenses.  Readers are cautioned, however, that this measure should not be construed as an alternative to net profit or loss determined in accordance with GAAP as a measure of performance.  Bellatrix’s method of calculating this measure may differ from other entities, and accordingly, may not be comparable to measures used by other companies.  Total capital expenditures - net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.*

 

*DISCLOSURES: Due to immateriality, the Company has combined the previously separated disclosure of “Heavy Oil” revenue, volumes, pricing, production expenses and royalties into “Crude Oil and condensate” revenue, volumes, pricing, production expenses and royalties for the year ending December 31, 2014.  Prior period comparative values have been adjusted for comparative purposes.*

 

*JOINT*ARRANGEMENTS:*Bellatrix is a partner in the Grafton Joint Venture, the CNOR Joint Venture, the Daewoo and Devonian Partnership, and the Troika Joint Venture (all as defined below), which have all been separately assessed and classified under International Financial Reporting Standards (“IFRS”) as joint operations.  This classification is on the basis that the arrangement is not conducted through a separate legal entity and the partners are legally obligated to pay their share of costs incurred and take their share of output produced from the various production areas, and all partners have rights to the assets and obligations for the liabilities resulting from the joint operations.  The Company considered these factors as well as the terms of the individual agreements in determining the classification of a joint operation to be appropriate for each arrangement.  For purposes of disclosure throughout the MD&A and financial statements, Bellatrix has referred to these arrangements by the common oil and gas industry term of joint ventures.*

 

*GRAFTON JOINT VENTURE —**On April 10, 2014, Bellatrix announced that Grafton Energy Co I Ltd. (“Grafton”) elected to exercise an option to increase committed capital investment to the joint venture (the “Grafton Joint Venture”) with Grafton established during 2013 by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions as the previously announced Grafton Joint Venture.  The Grafton Joint Venture properties are in the Willesden Green and Brazeau areas of West-Central Alberta, whereby Grafton will contribute 82%, or $250 million, to the joint venture to participate in a Notikewin/Falher and Cardium well program.  Under the agreement, Grafton will earn 54% of Bellatrix’s working interest (“WI”) in each well drilled in the well program until payout (being recovery of Grafton’s capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix’s WI after payout.  At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty (“GORR”) on Bellatrix’s pre-Grafton Joint Venture WI.*

 

*CNOR JOINT VENTURE - On September 30, 2014, Bellatrix announced that the Company and Canadian Non-Operated Resources Corp. (“CNOR”), a non-operated oil and gas company managed by Grafton Asset Management Inc., had completed the formation of a new multi-year joint venture arrangement (the “CNOR Joint Venture”), pursuant to which CNOR has committed $250 million in capital towards future accelerated development of a portion of Bellatrix’s extensive undeveloped land holdings. Under the terms of the agreement, CNOR will pay 50% of the drilling, completion, equipping and tie-in capital expenditures associated with development plans to be proposed by Bellatrix and approved by a management committee comprised of representatives of Bellatrix and CNOR in order to earn 33% of Bellatrix’s working interest before payout and automatically converting to a 10.67% gross overriding royalty on Bellatrix’s pre-joint venture working interest after payout (being recovery of CNOR’s capital investment plus an 8% return on investment).*

 

*DAEWOO AND DEVONIAN PARTNERSHIP — Bellatrix has a joint venture arrangement (the “Daewoo and Devonian Partnership”) with Canadian subsidiaries of two Korean entities, Daewoo International Corporation (“Daewoo”) and Devonian Natural Resources Private Equity Fund (“Devonian”) in the Baptiste area of West-Central*

 

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*Alberta, whereby Daewoo and Devonian own a combined 50% of Bellatrix’s WI share of producing assets, an operated compressor station and gathering system and related land acreage.*

 

*TROIKA JOINT VENTURE — Bellatrix has a joint venture (the “Troika Joint Venture”) with TCA Energy Ltd. (“TCA”) in the Ferrier Cardium area of West-Central Alberta, whereby Troika will contribute 50% towards a capital program for which they will receive a 35% WI until payout (being recovery of TCA’s capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix’s WI.*

 

*Additional information relating to the Company, including the Bellatrix’s Annual Information Form, is available on SEDAR at www.sedar.com and on the Company’s website at www.bellatrixexploration.com.  The Company’s EDGAR filings and forms are available through the U.S. Securities and Exchange Commission at www.sec.gov.*

 

*FORWARD LOOKING STATEMENTS:  Certain information contained herein and in the accompanying report to shareholders may contain forward looking statements including management’s assessment of future plans, operations and strategy, drilling plans and the timing thereof, commodity price risk management strategies, 2015 capital expenditure budget, the expectation of management to revisit its capital budget on a continuous basis, the nature of expenditures and the method of financing thereof, anticipated liquidity of the Company and various matters that may impact such liquidity, expected 2015 production expenses, general and administrative expenses, royalty rates and operating costs, 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, estimated capital expenditures and wells to be drilled under joint venture agreements, the ability to fund the 2015 capital expenditure program utilizing various available sources of capital, expected 2015 production growth, average daily production and exit rate, plans to continue commodity risk management strategies, timing of redetermination of borrowing base, plans for additional facilities and infrastructure and timing and effects thereof, expected cost and timing for completion of the Bellatrix Alder Flats Plant (as defined below), expected additional ability to grow production resulting from completing the Bellatrix Alder Flats Plant, expectation that Phase I of the Bellatrix Alder Flats Plant will be completed on schedule and on budget, the expectation that the addition of firm service capacity is anticipated to improve overall operational reliability and facilitate the execution of the Company’s projected growth, timing of commissioning of new facilities, including the Bellatrix Alder Flats Plant, and the impact and anticipated benefits of infrastructure investments, expected timing of expenditure of funds under the CNOR Joint Venture (as defined below), the expectation that 2015 will represent a transformational year for the Company given the strategic infrastructure investment made over the past several years, the expectation that the Company’s differentiated joint venture strategy will provide additional insulation from weak commodity prices given, and the expectation that reduced service costs may provide further benefits in 2015, may constitute forward-looking statements under applicable securities laws. To the extent that any forward-looking information contained herein constitute a financial outlook, they were approved by management on March 11, 2015 and are included herein to provide readers with an understanding of the anticipated funds available to Bellatrix to fund its operations and readers are cautioned that the information may not be appropriate for other purposes.  Forward-looking statements necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources.  Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix’s future operations.  Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes.  Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct.  In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field*

 

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*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 affect Bellatrix’s operations and financial results are included in reports on file with Canadian and US securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix’s website (www.bellatrixexploration.com).  Furthermore, the forward looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.*

 

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

 

**Overview and Description of the Business**

 

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

 

Common shares of Bellatrix trade on the Toronto Stock Exchange and, effective October 6, 2014, on the New York Stock Exchange, under the symbol “BXE”.

 

**2014 Transactions**

 

**Consolidation Efforts of Key Operating Area**

 

During the fourth quarter of 2014, Bellatrix completed an acquisition of complementary assets within its core Alder Flats area of west central Alberta (greater Ferrier region) for total cash consideration of $118.0 million.  The strategic tuck-in acquisition added approximately 2,200 boe/d of unrestricted production (80% natural gas, 20% liquids) and largely represented the consolidation of working interest ownership from existing wellbores and Mannville formation rights. The transaction included production from approximately 10 gross (5.7 net) sections of land at Alder Flats, representing largely joint interest lands where Bellatrix maintained existing working interest rights.  The acquired acreage is highly contiguous with Bellatrix acreage and includes operatorship over the majority of the acquired sections. Estimated reserve additions from the transaction totaled 10.9 mmboe of proved reserves and 3.7 mmboe of probable reserves.  The effective date of the transaction was November 1, 2014.

 

Bellatrix completed an additional transaction during the fourth quarter of 2014 for 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.  Estimated reserve additions from the transaction totaled 9.0 mmboe of proved reserves and 3.8 mmboe of probable reserves.  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.

 

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Additionally, during the fourth quarter of 2014, Bellatrix 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 in the Ferrier area of West Central Alberta.  Under the arrangement, Bellatrix has committed to drill a minimum of 6 Cardium wells and 6 Mannville wells.

 

In the third quarter of 2014, Bellatrix completed a tuck-in acquisition of working-interests in the Company’s core Ferrier area in West Central Alberta, extending the Company’s Cardium resource play for a net purchase price of $13.9 million.  The acquired assets included low decline rate net production of approximately 300 boe/d (24% oil and liquids and 76% natural gas). The acquisition included 8 gross (7.0 net) sections of Cardium mineral rights and 3 gross (1.2 net) sections of Mannville prospective lands.  The Company estimates the acquired acreage to contain 18 gross (16.1 net) low risk Cardium development locations, which are adjacent to Bellatrix’s core land base in the Ferrier area.

 

**Bellatrix Alder Flats Plant**

 

Bellatrix continued the construction of the Bellatrix O’Chiese Nees-Ohpawganu’ck deep-cut gas plant (the “Bellatrix Alder Flats Plant”) in the Alder Flats area of Alberta.  The Bellatrix Alder Flats Plant will be developed in two phases with a total sales gas design capacity of 220 mmcf/d.  Phase I and Phase II of the Bellatrix Alder Flats Plant are both designed to process up to 110 mmcf/d, thereby providing Bellatrix the ability to grow its net production to over 80,000 boe/d in 2017 by utilizing existing strategic and third party infrastructure. Phase I of the Bellatrix Alder Flats Plant remains on schedule and on budget for a July 2015 start-up.

 

In the fourth quarter of 2014, Bellatrix completed the transfer at cost of minority interests totaling 40% in Phase I and Phase II of the Plant and related pipeline infrastructure currently under construction to Keyera Partnership and O’Chiese Gas Plant GP Inc.  The transfer of minority interests in the Bellatrix Alder Flats Plant is consistent with the Company’s strategy to maintain operatorship and control of strategic facilities, while being a good steward of available capital. The transaction aligns the Company’s working interest processing capacity in the facilities with its forecasted average net working interest volumes to be processed through the Bellatrix Alder Flats Plant going forward.

 

**Securing Firm Processing Capacity**

 

On April 2, 2014, Bellatrix announced the completion of a 1.6 km river bore and a 7 km pipeline in conjunction with Blaze Energy Ltd. (“Blaze”), completing a 55 km pipeline to tie-in Bellatrix natural gas for processing in the Blaze gas plant located at 4-31-48-12W5.  Bellatrix has secured firm processing capacity of 100 mmcf/d in the plant.  Bellatrix was delivering up to 100 mmcf/d (including partner gas) at its peak to the Blaze plant in December 2014, following the successful completion of the booster compression project.

 

During the fourth quarter of 2014, Bellatrix entered into an arrangement with Keyera whereby Bellatrix has immediately secured 19 mmcf/d of firm processing capacity, 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.  The addition of firm service capacity is anticipated to improve overall operational reliability and facilitate the execution of the Company’s projected growth from the area.

 

**Grafton Additional Commitments**

 

On April 10, 2014, Bellatrix announced that Grafton elected to exercise an option to increase committed capital investment to the Grafton Joint Venture with Grafton established during 2013 by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions as the previously announced Grafton Joint Venture.

 

On September 30, 2014, Bellatrix announced that based upon the success of the first joint venture with Grafton, Bellatrix has entered into the new multi-year CNOR 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 Bellatrix’s extensive undeveloped land holdings. The joint venture funding is available immediately, however Bellatrix expects the funds to be spent primarily from 2016 through 2018. Between Grafton and CNOR, a total of $500 million has been committed to the development of Bellatrix’s lands.

 

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**Transfer of Listing from NYSE MKT to the New York Stock Exchange**

 

On October 1, 2014, Bellatrix announced the transfer of the listing of its common shares from NYSE MKT to the New York Stock Exchange (“NYSE”). Bellatrix’s common shares began trading on the NYSE on Monday, October 6, 2014, under its current trading symbol “BXE”. The Company’s common shares continue to be listed for trading on the Toronto Stock Exchange (“TSX”).

 

**$750.0 Million Short Form Base Shelf Prospectus and $172.6 Million Bought Deal Financing**

 

In May 2014, Bellatrix filed a short form base shelf prospectus (the “$750 million Shelf Prospectus”) of up to $750 million, with the securities regulatory authorities in each of the provinces of Canada (other than Quebec) and a Registration Statement with the United States Securities and Exchange Commission. The $750 million Shelf Prospectus allows Bellatrix to offer and issue common shares, subscription receipts, warrants and units (comprising any combination of the foregoing securities), by way of one or more prospectus supplements at any time during the 25-month period that the $750 million Shelf Prospectus remains in place.

 

Pursuant to a prospectus supplement to the $750 million Shelf Prospectus, on June 5, 2014, Bellatrix closed a bought deal offering of 18,170,000 common shares of the Company (the “Common Shares”) at a price of $9.50 per Common Share for aggregate gross proceeds of $172.6 million (the “Offering”), through a syndicate of underwriters.  Net proceeds of $165.5 million received from the Offering were utilized to temporarily reduce outstanding indebtedness under the Company’s credit facilities, thereby freeing up borrowing capacity that may be redrawn, from time to time, to fund the Company’s ongoing capital expenditure program and for general corporate purposes.

 

As at December 31, 2014, the Company has the ability to offer to sell up to an additional $577.4 million on the $750 million Shelf Prospectus.

 

**Credit Facilities Increased to $725 million and Financial Covenants Amended**

 

Bellatrix maintains extendible revolving reserves-based credit facilities with a syndicate of lenders that mature May 2017.  The credit facilities do not require any mandatory principal payments prior to maturity and can be further extended beyond May 2017 with the consent of the lenders.  As of December 31, 2014, the credit facilities are available on an extendible revolving term basis and consisting of a $75 million operating facility provided by a Canadian chartered bank and a $650 million syndicated facility provided by nine financial institutions.  The available credit facilities and related borrowing base are subject to semi-annual reviews in May and November of each year.

 

In the Company’s semi-annual borrowing base review for November 30, 2014, Bellatrix and its lenders agreed to increase the borrowing base and credit facilities to $725 million from $625 million.  The 16% increase of $100 million to the borrowing base and credit facilities was the result of Bellatrix’s strong 2014 drilling results during the first nine months of 2014, combined with benefits derived from the first of two tuck-in acquisitions completed during the fourth quarter of 2014 (excluding the announced $118.0 million acquisition), cumulatively delivering significant reserves and production growth.  The increased credit facilities will be available to finance Bellatrix’s ongoing capital expenditures, working capital requirements and for general corporate purposes.

 

The Company 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 discussed herein, as a result of the recent precipitous drop in crude oil prices and the concomitant reduction in the Company’s associated future cash flow and EBITDA, the Company sought and obtained from its lenders temporary relaxation of certain of these financial covenants under its credit facilities.

 

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**2014 Guidance and Results**

 

In 2014, Bellatrix successfully completed the most active year in the Company’s history. Sales volumes for the year ended December 31, 2014 increased by 74% to average 38,065 boe/d (weighted 67% natural gas and 33% crude oil, condensate and NGLs) compared to 21,829 boe/d in 2013. Bellatrix invested $504.5 million on exploration and development capital projects, excluding property acquisitions and dispositions, during the year ended December 31, 2014, compared to $281.0 million in 2013. Included in net capital expenditures made during 2014 was $36 million relating to the Bellatrix Alder Flats Plant project. Earnings for the year ended December 31, 2014 were $163.1 million, up 128% over $71.7 million in 2013. Revenue before other income, royalties, and commodity price risk management contracts for the year ended December 31, 2014 increased by 99% to $574.3 million, compared to $288.3 million realized in 2013.

 

**2014 Guidance**

 
| ** **                              | ** ** | **2014 Revised   Forecast ****(1)** | ** ** | **2014   Results** | ** ** | **Variance (%)** | ** ** |
|-----------------------------------------|------------|-----------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| Average daily production (boe/d)        |       | 38,500                                        |       | 38,065             |       | (1                    | )          |
| Average product mix                     |       |                                          |       |               |       |                  |       |
| Crude oil, condensate and   NGLs (%)    |       | 33                                            |       | 33                 |       | —                |       |
| Natural gas (%)                         |       | 67                                            |       | 67                 |       | —                |       |
| Capital spending ($ millions)*(2)* |       | 515                                           |       | 516                |       | —                |       |
| Expenses ($/boe)                        |       |                                          |       |               |       |                  |       |
| Production *(3)*                        |       | 7.95                                          |       | 8.64               |       | 9                     |       |
| General and administrative   *(3)*      |       | 1.67                                          |       | 1.83               |       | 10                    |       |

 

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*(1) **Revised forecast guidance based on outlook as at November 4, 2014.  Primarily as a result of third party facility constraints that began to affect Bellatrix and other producers operating in West Central Alberta in early 2014, the Company revised its original 2014 average daily production guidance in March and May of 2014.  Also in March 2014, the Company increased its net capital budget to $440 million. In each of May, August and October 2014, the Company increased its net capital budget, inclusive of exploration and development capital, corporate assets and property acquisitions and dispositions, to $500 million, $515 million, and $530 million, respectively.  Also in October 2014, as a result of continued tightness in available processing capacity, the Company reduced its 2014 average daily production guidance to 38,500 boe/d.*

 

*(2) **Capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions.*

 

*(3) **Actual full year production expense varied from the revised forecast primarily due to one-time adjustments attributable to turnarounds on third-party operated facilities as well as realized facility equalizations in the fourth quarter of 2014.  Absolute G&A expenses increased in 2014 given higher staffing and compensation costs required to manage increased activity through the year.  On a per boe basis, G&A expenses varied relative to the revised forecast given the increase in absolute costs divided by lower than projected production volumes, which were impacted by third-party facility downtime and TransCanada system pressures.*

 

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**FOURTH QUARTER 2014****HIGHLIGHTS**

 
| ** **                                         | ** ** | **Three months ended December 31,** | ** ** |
|----------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                         | ** ** | **2014**                                                | ** ** | **2013** | ** ** |
| **SELECTED FINANCIAL RESULTS**                     |       |                                                    |       |   |   |
| *(CDN$000s except share and per   share amounts)*  |       |                                                    |       |   |   |
| Revenue (before royalties and risk management (1)) |       | 130,160                                                 |       | 83,455 |   |
| Funds flow from operations (2)                     |       | 61,757                                                  |       | 39,349 |   |
| Per basic share (5)                                |       | $                                                       | 0.32       |   | $ | 0.31 |   |
| Per diluted share (5)                              |       | $                                                       | 0.32       |   | $ | 0.30 |   |
| Cash flow from operating activities                |       | 90,459                                                  |       | 38,025 |   |
| Per basic share (5)                                |       | $                                                       | 0.47       |   | $ | 0.30 |   |
| Per diluted share (5)                              |       | $                                                       | 0.47       |   | $ | 0.29 |   |
| Net profit                                         |       | 54,830                                                  |       | 22,195 |   |
| Per basic share (5)                                |       | $                                                       | 0.29       |   | $ | 0.17 |   |
| Per diluted share (5)                              |       | $                                                       | 0.29       |   | $ | 0.17 |   |
| Capital – exploration and development         |       | 81,873                                                  |       | 101,232 |   |
| Capital – corporate assets                    |       | 3,346                                                   |       | 4,282 |   |
| Property acquisitions                              |       | 148,857                                                 |       | 10,385 |   |
| Capital expenditures – cash                   |       | 234,076                                                 |       | 115,899 |   |
| Property dispositions – cash                  |       | (1,435                                                  | )          | (16,700 | ) |
| Total net capital expenditures – cash         |       | 232,641                                                 |       | 99,199 |   |
| Corporate acquisitions and other non-cash items    |       | 64,612                                                  |       | 607,727 |   |
| Total capital expenditures – net (4)          |       | 297,253                                                 |       | 706,926 |   |
| Long-term debt                                     |       | 549,792                                                 |       | 287,092 |   |
| Adjusted working capital deficiency (3)            |       | 87,934                                                  |       | 108,390 |   |
| Total net debt (3)                                 |       | 637,726                                                 |       | 395,482 |   |
| Total assets                                       |       | 2,213,485                                               |       | 1,555,180 |   |
| Total shareholders’ equity                    |       | 1,248,317                                               |       | 903,874 |   |

 

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**SELECTED OPERATING RESULTS**

 
| ** **                                                       | ** ** | ** ** | ** ** | **Three months ended December 31,** | ** ** |
|------------------------------------------------------------------|------------|------------|------------|---------------------------------------------------------|------------|
| ** **                                                       | ** ** | ** ** | ** ** | **2014**                                                | ** ** | **2013** | ** ** |
| Average daily sales volumes                                      |       |       |       |                                                    |       |   |   |
| Crude oil, condensate and NGLs                                   |       | (bbls/d)   |       | 13,204                                                  |       | 7,564 |   |
| Natural gas                                                      |       | (mcf/d)    |       | 178,443                                                 |       | 98,423 |   |
| Total oil equivalent                                             |       | (boe/d)    |       | 42,945                                                  |       | 23,968 |   |
| Average realized prices                                          |       |       |       |                                                    |       |   |   |
| Crude oil and condensate                                         |       | ($/bbl)    |       | 71.92                                                   |       | 82.46 |   |
| NGLs (excluding condensate)                                      |       | ($/bbl)    |       | 31.26                                                   |       | 46.20 |   |
| Crude oil, condensate and NGLs                                   |       | ($/bbl)    |       | 50.17                                                   |       | 66.75 |   |
| Crude oil, condensate and NGLs (including risk   management (1)) |       | ($/bbl)    |       | 57.16                                                   |       | 64.32 |   |
| Natural gas                                                      |       | ($/mcf)    |       | 4.01                                                    |       | 3.89 |   |
| Natural gas (including risk management (1))                      |       | ($/mcf)    |       | 4.08                                                    |       | 3.97 |   |
| Total oil equivalent                                             |       | ($/boe)    |       | 32.07                                                   |       | 37.05 |   |
| Total oil equivalent (including risk management (1))             |       | ($/boe)    |       | 34.51                                                   |       | 36.59 |   |
|                                                             |       |       |       |                                                    |       |   |   |
| Net wells drilled                                                |       |       |       | 7.1                                                     |       | 21.4 |   |
| Selected Key Operating Statistics                                |       |       |       |                                                    |       |   |   |
| Operating netback (4)                                            |       | ($/boe)    |       | 16.12                                                   |       | 21.10 |   |
| Operating netback (4) (including risk management (1))       |       | ($/boe)    |       | 18.56                                                   |       | 20.64 |   |
| Transportation                                                   |       | ($/boe)    |       | 1.05                                                    |       | 1.02 |   |
| Production expenses                                              |       | ($/boe)    |       | 9.57                                                    |       | 8.70 |   |
| General & administrative                                |       | ($/boe)    |       | 2.33                                                    |       | 2.53 |   |
| Royalties as a % of sales (after transportation)                 |       |       |       | 17%                                                     |       | 17% |   |
| **COMMON SHARES**                                                |       |       |       |                                                    |       |   |   |
| Common shares outstanding                                        |       |       |       | 191,950,576                                             |       | 170,990,605 |   |
| Share options outstanding                                        |       |       |       | 10,913,337                                              |       | 11,182,963 |   |
| Fully diluted common shares outstanding                          |       |       |       | 202,863,913                                             |       | 182,173,568 |   |
| Weighted average shares (5)                                      |       |       |       | 191,579,631                                             |       | 130,875,349 |   |
| **SHARE TRADING STATISTICS**                                     |       |       |       |                                                    |       |   |   |
| **TSX and Other****(6)**                                         |       |       |       |                                                    |       |   |   |
| *(CDN$, except volumes) based on   intra-day trading*            |       |       |       |                                                    |       |   |   |
| High                                                             |       |       |       | 7.03                                                    |       | 8.52 |   |
| Low                                                              |       |       |       | 3.45                                                    |       | 6.65 |   |
| Close                                                            |       |       |       | 4.23                                                    |       | 7.81 |   |
| Average daily volume                                             |       |       |       | 3,166,506                                               |       | 2,678,253 |   |
| **NYSE****(7)**                                                  |       |       |       |                                                    |       |   |   |
| *(US$, except volumes) based on   intra-day trading*             |       |       |       |                                                    |       |   |   |
| High                                                             |       |       |       | 6.28                                                    |       | 8.43 |   |
| Low                                                              |       |       |       | 2.97                                                    |       | 6.38 |   |
| Close                                                            |       |       |       | 3.64                                                    |       | 7.33 |   |
| Average daily volume                                             |       |       |       | 547,564                                                 |       | 171,620 |   |

 

----

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

 

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

 

(2) *The highlights section contains the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with GAAP as an indicator of the Company’s*

 

9

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*performance. Therefore reference to the additional GAAP measures of funds flow from operations, or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt.  The reconciliation between cash flow from operating activities and funds flow from operations can be found in the MD&A.  Funds flow from operations per share is calculated using the weighted average number of common shares for the period.*

 

*(3) **Total net debt is considered to be an additional GAAP measure.  Therefore reference to the additional GAAP measure of total net debt may not be comparable with the calculation of similar measures for other entities.  The Company’s 2014 calculation of total net debt excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability.  Total net debt includes the adjusted working capital deficiency (excess).  The adjusted working capital deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements.  A reconciliation between total liabilities under GAAP and total net debt as calculated by the Company is found in this MD&A.*

 

*(4) **Operating netbacks and total capital expenditures — net are considered non-GAAP measures.  Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income.  Total capital expenditures — net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. The detailed calculations of operating netbacks are found in the MD&A.*

 

*(5) **Basic weighted average shares for the three months ended December 31, 2014 were 191,579,631 (2013: 127,489,592).*

 

*In computing weighted average diluted earnings per share and weighted average diluted cash flow from operating activities and funds flow from operations per share for the three months ended December 31, 2014, a total of nil (2013: 3,385,757) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options, resulting in diluted weighted average common shares of 191,579,631 (2013: 130,875,349).*

 

(6) *TSX and Other includes the trading statistics for the TSX and other Canadian trading markets.*

 

(7) *Effective October 6, 2014, Bellatrix transferred the listing of its common shares from NYSE MKT to the New York Stock Exchange (“NYSE”). The common shares trade on the NYSE under the same ticker symbol, “BXE”, as was used on the NYSE MKT listing and is currently used on the TSX listing.*

 

**Sales Volumes**

 

Sales volumes for the three months ended December 31, 2014 averaged 42,945 boe/d, an increase of 79% from an average of 23,968 boe/d realized in the fourth quarter of 2013.  The increase in total sales volumes experienced between the quarters was primarily a result of a $234.1 million increase in net cash capital expenditures including property acquisitions of 2,920 boe/d during the fourth quarter of 2014, Bellatrix’s ongoing successful drilling activity in the Cardium and Mannville resource plays, and additional sales volumes acquired through the acquisition of Angle Energy Inc. (“Angle”) in December 2013.  The increase in sales volumes between the periods was also attributable in part to the Grafton Joint Venture, the Daewoo and Devonian Partnership entered into by the Company during the third quarter of 2013, and the Troika Joint Venture entered into by the Company during the fourth quarter of 2013 as Bellatrix was able to accelerate and expand its drilling activity through these joint venture arrangements throughout 2014.

 

**Sales Volumes**

 
|                                 |   |     |   | **Three months ended December 31,** |   |
|--------------------------------------|--------|----------|--------|---------------------------------------------------------|--------|
|                                 |   |     |   | **2014**                                                |   | **2013** |   |
| Crude oil and condensate             |   | (bbls/d) |   | 6,139                                                   |   | 4,286 |   |
| NGLs (excluding condensate)          |   | (bbls/d) |   | 7,065                                                   |   | 3,278 |   |
| Total crude oil, condensate and NGLs |   | (bbls/d) |   | 13,204                                                  |   | 7,564 |   |
|                                 |   |     |   |                                                    |   |   |   |
| Natural gas                          |   | (mcf/d)  |   | 178,443                                                 |   | 98,423 |   |
|                                 |   |     |   |                                                    |   |   |   |
| Total sales volumes (6:1 conversion) |   | (boe/d)  |   | 42,945                                                  |   | 23,968 |   |

 

Crude oil, condensate and NGL sales volumes increased by 75% in the fourth quarter of 2014, averaging 13,204 bbls/d compared to 7,564 bbls/d in the same period in 2013.  The weighting towards crude oil, condensate and NGLs for the three months ended December 31, 2014 was 31%, compared to 32% in the fourth quarter of 2013.

 

Sales of natural gas averaged 178.4 mmcf/d during the three months ended December 31, 2014, compared to 98.4 mmcf/d in the same period in 2013, an increase of 81%.

 

10

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**Drilling Activity**

 
| ** **                            | ** ** | **Three months ended   December 31, 2014** | ** ** | **Three months ended   December 31, 2013** | ** ** |
|---------------------------------------|------------|----------------------------------------------------------------|------------|----------------------------------------------------------------|------------|
| ** **                            | ** ** | **Gross**                                                      | ** ** | **Net**                                                        | ** ** | **Success    Rate** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Success    Rate** | ** ** |
| Cardium oil                           |       | 3                                                              |       | 2.0                                                            |       | 100 | % | 24 |   | 16.2 |   | 100 | % |
| Spirit River liquids-rich natural gas |       | 7                                                              |       | 3.8                                                            |       | 100 | % | 10 |   | 4.4 |   | 100 | % |
| Cardium natural gas                   |       | 2                                                              |       | 1.3                                                            |       | 100 | % | 1 |   | 0.8 |   | 100 | % |
| Total                                 |       | 12                                                             |       | 7.1                                                            |       | 100 | % | 35 |   | 21.4 |   | 100 | % |

 

During the fourth quarter of 2014, Bellatrix drilled and/or participated in 12 gross (7.1 net) wells, consisting of 3 gross (2.0 net) Cardium oil wells, 7 gross (3.8 net) Spirit River liquids-rich gas wells, and 2 gross (1.3 net) Cardium gas wells.  Bellatrix’s fourth quarter 2014 drilling activity was weighted 25% towards oil wells, and 75% towards natural gas wells.

 

By comparison, during the fourth quarter of 2013, Bellatrix drilled and/or participated in 35 gross (21.4 net) wells, consisting of 24 gross (16.2 net) Cardium light oil horizontal wells, and 10 gross (4.4 net) Spirit River liquids-rich gas wells, and one gross (0.8 net) Cardium gas well.  Bellatrix’s drilling activity in the fourth quarter of 2013 was weighted 69% towards oil wells, and 31% towards gas wells.

 

**Average Commodity Prices**

 
| ** **                                                                          | ** ** | **Three months ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                                          | ** ** | **2014**                                                | ** ** | **2013** | ** ** | **% Change** | ** ** |
|                                                                                |       |                                                    |       |   |   |   |   |
| Exchange rate *(US$/CDN$1.00)*                                                      |       | 0.8802                                                  |       | 0.9528 |   | (8 | ) |
|                                                                                |       |                                                    |       |   |   |   |   |
| Crude oil:                                                                          | ** ** | ** **                                              |       |   |   |   |   |
| WTI *(US$/bbl)*                                                                     |       | 73.20                                                   |       | 97.61 |   | (25 | ) |
| Edmonton par – light oil / Canadian Light crude   blend *($/bbl)* (1)          |       | 74.37                                                   |       | 86.26 |   | (14 | ) |
| Bellatrix’s average realized prices *($/bbl)*                                  |       |                                                    |       |   |   |   |   |
| Crude oil and condensate                                                            |       | 71.92                                                   |       | 82.46 |   | (13 | ) |
| NGLs (excluding condensate)                                                         |       | 31.26                                                   |       | 46.20 |   | (32 | ) |
| Total crude oil and NGLs                                                            |       | 50.17                                                   |       | 66.75 |   | (25 | ) |
| Total crude oil and NGLs (including risk   management (2))                          |       | 57.16                                                   |       | 64.32 |   | (11 | ) |
|                                                                                |       |                                                    |       |   |   |   |   |
| Natural gas:                                                                        |       |                                                    |       |   |   |   |   |
| NYMEX *(US$/mmbtu)*                                                                 |       | 3.83                                                    |       | 3.85 |   | (1 | ) |
| AECO daily index *(CDN$/mcf)*                                                       |       | 3.60                                                    |       | 3.53 |   | 2 |   |
| AECO monthly index *(CDN$/mcf)*                                                     |       | 4.01                                                    |       | 3.15 |   | 27 |   |
| Bellatrix’s average realized price (*$/mcf)*                                   |       | 4.01                                                    |       | 3.89 |   | 3 |   |
| Bellatrix’s average realized price (including risk   management (2)) (*$/mcf)* |       | 4.08                                                    |       | 3.97 |   | 3 |   |

 

----

*(1) **Edmonton par — light oil prices were discontinued as of May 1, 2014 and replaced by Canadian Light crude blend.  2014 prices reflect the Canadian Light crude blend, while 2013 prices reflect the Edmonton par — light oil.*

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

 

In the fourth quarter of 2014 Bellatrix realized an average price of $71.92/bbl before commodity price risk management contracts for crude oil and condensate, a decrease of 13% from the average price of $82.46/bbl received in the fourth quarter of 2013.  By comparison, the Edmonton par/Canadian Light price decreased by 14% and the average WTI crude oil benchmark price decreased by 25% between the fourth quarters of 2014 and 2013.

 

The global oil markets late in 2014 reacted with a significant price deterioration to the over-supply created from continued production growth from shale plays in the United States, slower than anticipated global demand growth, and sustained production from the Organization of the Petroleum Exporting Countries (“OPEC”).

 

Bellatrix’s average realized price for NGLs (excluding condensate) decreased by 32% to $31.26/bbl during the fourth quarter of 2014, compared to $46.20/bbl received in the 2013 period.

 

11

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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 realized prices per mcf than the daily AECO index.  During the fourth quarter of 2014, the AECO daily reference price increased by 2% and the AECO monthly reference price increased by approximately 27% compared to the fourth quarter of 2013.  Bellatrix’s natural gas average sales price before commodity price risk management contracts for the fourth quarter of 2014 increased by 3% to $4.01/mcf compared to $3.89/mcf in the same period in 2013.

 

Natural gas prices pulled back during the fourth quarter of 2014 as the year-over-year storage levels continued to build due to growing production and a warmer than average start to the winter heating season.

 

**Revenue**

 

Revenue before other income, royalties and commodity price risk management contracts increased by 55% to $126.7 million for the three months ended December 31, 2014, compared to $81.7 million realized in the fourth quarter of 2013.  The higher realized revenue before other income between the 2014 and 2013 fourth quarters was attributable to an increase in sales volumes for all products resulting from drilling activity throughout the 2014 year as well as additional production from wells acquired as part of the acquisition of Angle in December 2013, in conjunction with higher realized natural gas prices which were partially offset by the impacts of reduced crude oil, condensate, and NGL prices experienced in the fourth quarter of 2014.

 

Crude oil and NGLs revenue before other income, royalties and commodity price risk management contracts for the three months ended December 31, 2014 increased by 31% from the same period in 2013, resulting from 75% higher sales volumes partially offset by reduced realized crude oil, condensate, and NGL prices when compared to the fourth quarter of 2013.

 

For the three months ended December 31, 2014, total crude oil, condensate and NGL revenues contributed 48% of total revenue before other income, compared to 57% in the fourth quarter of 2013.

 

Natural gas revenue before other income, royalties and commodity price risk management contracts increased by 87% in the fourth quarter of 2014 compared to the same period in 2013 as a result of a 3% increase in realized gas prices before risk management in conjunction with an 81% increase in sales volumes between the periods.

 
| ** **                                             | ** ** | **Three months ended December 31,** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------------------------|------------|
| **($000s)**                                            | ** ** | **2014**                                                | ** ** | **2013** | ** ** |
| Crude oil and condensate                               |       | 40,621                                                  |       | 32,522 |   |
| NGLs (excluding condensate)                            |       | 20,319                                                  |       | 13,934 |   |
| Crude oil and NGLs                                     |       | 60,940                                                  |       | 46,456 |   |
| Natural gas                                            |       | 65,756                                                  |       | 35,252 |   |
| Total revenue (before other income)                    |       | 126,696                                                 |       | 81,708 |   |
| Other income (1)                                       |       | 3,464                                                   |       | 1,747 |   |
| Total revenue (before royalties and risk   management) |       | 130,160                                                 |       | 83,455 |   |

 

----

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

 

**Royalties**

 

In the fourth quarter of 2014, the Company incurred $21.0 million in royalties, compared to $13.8 million in the fourth quarter of 2013.  As a percentage of revenue before other income, royalties and commodity price risk management contracts (after transportation costs), royalties were 17% in the three months ended December 31, 2014 and 2013.  The Company’s light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more recent wells in their early years of production under the Alberta royalty incentive program, offset by increased royalty rates on other wells now coming off initial royalty incentive rates and as other wells are drilled on Ferrier lands with higher combined Indian Oil and Gas Canada (“IOGC”) royalty and gross overriding royalty (“GORR”) rates.

 

12

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** **

**Royalties**

 
| ** **                                     | ** ** | **Three months ended    December 31,** | ** ** |
|------------------------------------------------|------------|------------------------------------------------------------|------------|
| **($000s, except where noted)** | ** ** | **2014**                                                   | ** ** | **2013** | ** ** |
| Royalties                                      |       | 21,049                                                     |       | 13,755 |   |
| Royalties ($/boe)                              |       | 5.33                                                       |       | 6.23 |   |
| Average royalty rate (%)                       |       | 17                                                         |       | 17 |   |

 

**Production Expenses**

 

In the three months ended December 31, 2014, production expenses totaled $37.8 million, compared to $19.2 million recorded in the same period of 2013.  During the three months ended December 31, 2014, production expenses averaged $9.57/boe, compared to $8.70/boe incurred during the fourth quarter of 2013.  By comparison, production expenses for the third quarter of 2014 averaged $8.85/boe.  Production expenses increased on a per boe basis between the fourth quarter of 2014 and the fourth quarter of 2013 due to one-time adjustments of $1.42/boe primarily attributable to turnarounds on third party operated facilities as well as realized facility equalizations.  Excluding these one-time adjustments, production expenses per boe for the three months ended December 31, 2014 were $8.15/boe.

 

**Production Expenses by Commodity Type**

 
| ** **                                                      | ** ** | **Three months ended    December 31,** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------------|------------|
| **($000s, except where noted)**                  | ** ** | **2014**                                                   | ** ** | **2013** | ** ** |
| Crude oil, condensate and NGLs                                  |       | 11,465                                                     |       | 5,827 |   |
| $/bbl                                                           |       | 9.44                                                       |       | 8.37 |   |
|                                                            |       |                                                       |       |   |   |
| Natural gas                                                     |       | 26,359                                                     |       | 13,346 |   |
| $/mcf                                                           |       | 1.61                                                       |       | 1.47 |   |
|                                                            |       |                                                       |       |   |   |
| Total Production Expenses                                       |       | 37,824                                                     |       | 19,173 |   |
| Total $/boe                                                     |       | 9.57                                                       |       | 8.70 |   |
|                                                            |       |                                                       |       |   |   |
| Total Production Expenses                                       |       | 37,824                                                     |       | 19,173 |   |
| Processing and other third party income (1)                     |       | (3,464                                                     | )          | (1,747 | ) |
| Total after deducting processing and other third   party income |       | 34,360                                                     |       | 17,426 |   |
| Total $/boe                                                     |       | 8.70                                                       |       | 7.90 |   |

 

----

*(1) **Processing and other third party income is included as other income in the Consolidated Statements of Comprehensive Income.*

 

**Transportation**

 

Transportation expenses for the three months ended December 31, 2014 were $4.1 million ($1.05/boe), compared to $2.3 million ($1.02/boe) in the fourth quarter of 2013.

 

**Operating Netback**

 

**Operating Netback — Corporate (before risk management)**

 
| ** **        | ** ** | **Three months ended   December 31,** | ** ** |
|-------------------|------------|------------------------------------------------------|------------|
| **($/boe)**       | ** ** | **2014**                                             | ** ** | **2013** | ** ** |
| Sales             |       | 32.07                                                |       | 37.05 |   |
| Production        |       | (9.57                                                | )          | (8.70 | ) |
| Transportation    |       | (1.05                                                | )          | (1.02 | ) |
| Royalties         |       | (5.33                                                | )          | (6.23 | ) |
| Operating netback |       | 16.12                                                |       | 21.10 |   |

 

During the three months ended December 31, 2014, the Company’s corporate operating netback before commodity risk management contracts decreased by 24% to $16.12/boe compared to $21.10/boe in the fourth quarter of 2013, driven primarily by a 13% decrease in overall commodity prices, a 3% increase in transportation expenses, and a 10% increase 

 

13

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in production expenses, partially offset by a 15% decrease in royalties.  By comparison, the Company’s corporate operating netback before commodity risk management contracts for the third quarter of 2014 was $21.57/boe.

 

**Operating Netback — Crude Oil, Condensate, and NGLs (before risk management)**

 
| ** **        | ** ** | **Three months ended    December 31,** | ** ** |
|-------------------|------------|------------------------------------------------------------|------------|
| **($/boe)**       | ** ** | **2014**                                                   | ** ** | **2013** | ** ** |
| Sales             |       | 50.17                                                      |       | 66.76 |   |
| Production        |       | (9.44                                                      | )          | (8.37 | ) |
| Transportation    |       | (0.79                                                      | )          | (0.84 | ) |
| Royalties         |       | (12.14                                                     | )          | (14.36 | ) |
| Operating netback |       | 27.80                                                      |       | 43.19 |   |

 

Operating netback before commodity price risk management contracts for crude oil, condensate and NGLs during the fourth quarter of 2014 averaged $27.80/bbl, a decrease of 36% from the $43.19/bbl realized during the same period in 2013. The decrease between the periods was primarily as a result of weaker commodity prices.  Between the periods, the operating net back for crude oil, condensate and NGLs was also impacted by higher production expenses, which were partially offset by lower royalties and reduced transportation expenses.  By comparison, the operating netback for crude oil, condensate and NGLs for the third quarter of 2014 was $40.50/bbl.

 

**Operating Netback — Natural Gas (before risk management)**

 
| ** **        | ** ** | **Three months ended    December 31,** | ** ** |
|-------------------|------------|------------------------------------------------------------|------------|
| **($/mcf)**       | ** ** | **2014**                                                   | ** ** | **2013** | ** ** |
| Sales             |       | 4.01                                                       |       | 3.89 |   |
| Production        |       | (1.61                                                      | )          | (1.47 | ) |
| Transportation    |       | (0.19                                                      | )          | (0.18 | ) |
| Royalties         |       | (0.38                                                      | )          | (0.42 | ) |
| Operating netback |       | 1.83                                                       |       | 1.82 |   |

 

The operating netback for natural gas before commodity price risk management contracts during the fourth quarter of 2014 of $1.83/mcf was 1% lower than the $1.82/mcf recorded in the same period in 2013.  The increase was attributable to higher natural gas prices and reduced royalties, partially offset by higher production and transportation expenses.  By comparison, the operating netback for natural gas before commodity risk management contracts for the third quarter of 2014 was $2.19/mcf.

 

**Interest and Financing Charges**

 

Interest and financing charges related to bank debt for the three months ended December 31, 2014, totaled $5.8 million ($1.47/boe), compared to $2.3 million ($1.06/boe) during the fourth quarter of 2013, which included amounts relating to the 4.75% convertible debentures settled during September and October of 2013. The increase in interest and financing charges between the 2013 and 2014 periods was primarily due to higher interest charges as the Company carried a higher average debt balance during the 2014 period and is supported by the expansion of Bellatrix’s credit facility to $725 million.  The higher average debt balance carried during the 2014 period was the result of Bellatrix’s expanded net capital program related to exploration and development projects and acquisitions during 2014 compared to the 2013 year.

 

**General and Administrative**

 

General and administrative expenses (after capitalized G&A and recoveries) for the three months ended December 31, 2014 were $9.2 million ($2.33/boe), compared to $5.6 million ($2.53/boe) in the same period in 2013.  The overall increase to net G&A was primarily attributable to increases in staffing and office costs between the periods related to Bellatrix’s increased production and operation activities. These costs were offset by higher capitalized G&A and recoveries from partners associated with higher capital spending.  The increase in total net G&A expenses was more than offset by higher sales volumes realized during the 2014 period, resulting in an overall decrease to G&A expenses on a per boe basis.

 

14

----

 

**General and Administrative Expenses**

 
| ** **                                     | ** ** | **Three months ended    December 31,** | ** ** |
|------------------------------------------------|------------|------------------------------------------------------------|------------|
| **($000s, except where noted)** | ** ** | **2014**                                                   | ** ** | **2013** | ** ** |
| Gross expenses                                 |       | 16,187                                                     |       | 9,220 |   |
| Capitalized                                    |       | (1,548                                                     | )          | (1,469 | ) |
| Recoveries                                     |       | (5,432                                                     | )          | (2,170 | ) |
| G&A expenses                               |       | 9,207                                                      |       | 5,581 |   |
| G&A expenses, per unit   ($/boe)           |       | 2.33                                                       |       | 2.53 |   |

 

**Share-Based Compensation**

 

For the three months ended December 31, 2014, non-cash share-based compensation was a recovery of $1.5 million ($0.38/boe), compared to a $1.0 million expense ($0.43/boe) in the same period in 2013. The non-cash share-based compensation recovery realized in the 2014 period was composed of a recovery of $1.8 million for Deferred Share Units (“DSUs”) (2013: $0.1 million recovery), a recovery of $0.4 million (2013: $0.3 million expense) for Performance Awards (“PAs”), and a recovery of $0.8 million (2013: $0.7 million expense) for Restricted Awards (“RAs”), partially offset by lower capitalized share-based compensation of $0.3 million (2013: $0.6 million) and a higher expense for the Company’s outstanding share options of $1.8 million (2013: $0.7 million).  The recoveries recognized for DSUs, RAs, and PAs recognized during the fourth quarter of 2014 was primarily due to the revaluation of DSUs, RAs, and PAs to a lower weighted average share trading price at December 31, 2014 than September 30, 2014.

 

**Depletion, Depreciation and Impairment**

 

Depletion and depreciation expense (excluding impairment) for the fourth quarter of 2014 was $50.4 million ($12.76/boe), compared to $27.3 million ($12.38/boe) in the same period in 2013.  The increase in depletion and depreciation between the fourth quarter of 2013 and the same period in 2014 is reflective of a 79% increase in sales volumes and a higher depletable base between the quarters impacted by net facility capital expenditures of $149.1 million in 2014 which excludes $38.7 million of facilities under construction, partially offset by the additional reserves achieved through the Company’s drilling success and property acquisitions.  By comparison, depletion, depreciation and accretion expense for the third quarter of 2014 was $43.1 million ($12.39/boe).  Primarily as a result of declining crude oil and natural gas forward commodity prices, the Company recognized an impairment expense of $10.8 million related to five non-core Cash Generating Units (“CGUs”) during the three months ended December 31, 2014.  No impairment was recognized in relation to the Company’s core West Central Alberta CGU.

 

**Cash Flow from Operating Activities and Funds Flow from Operations**

 

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

 

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

 
| ** **                          | ** ** | **Three months ended December 31,** | ** ** |
|-------------------------------------|------------|---------------------------------------------------------|------------|
| **($000s)**                         | ** ** | **2014**                                                | ** ** | **2013** | ** ** |
| Cash flow from operating activities |       | 90,459                                                  |       | 38,025 |   |
| Decommissioning costs incurred      |       | 727                                                     |       | 223 |   |
| Transaction costs                   |       | —                                                  |       | 5,344 |   |
| Change in non-cash working capital  |       | (29,429                                                 | )          | (4,243 | ) |
| Funds flow from operations          |       | 61,757                                                  |       | 39,349 |   |

 

Bellatrix’s cash flow from operating activities for the three months ended December 31, 2014 increased by 138% to $90.5 million ($0.47 per basic share and $0.47 per diluted share) from $38.0 million ($0.30 per basic share and $0.29 per 

 

15

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diluted share) generated in the fourth quarter of 2013.  Bellatrix generated funds flow from operations of $61.8 million ($0.32 per basic share and $0.32 per diluted share) in the fourth quarter of 2014, an increase of 57% from $39.3 million ($0.31 per basic share and $0.30 per diluted share) generated in the comparative 2013 period.  The greater funds flow from operations in the fourth quarter of 2014 compared to the fourth quarter of 2013 was principally due to a 79% increase in production volumes, higher realized natural gas prices, a net realized gain on commodity contracts in the 2014 period compared to a net realized loss in the 2013 period, partially offset by reduced realized crude oil, condensate, and NGL prices, in addition to increased general and administrative, production, transportation, royalty, and finance expenses.

 

For the three months ended December 31, 2014, Bellatrix recognized a net profit of $54.8 million ($0.29 per basic share and $0.29 per diluted share), compared to a net profit of $22.2 million ($0.17 per basic share and $0.17 per diluted share) in the fourth quarter of 2013.  The higher net profit recorded in the fourth quarter of 2014 compared to the same period in 2013 was primarily the result of increased funds from operating activities as noted above, an unrealized gain on commodity contracts in the 2014 fourth quarter compared to an unrealized loss in the comparative 2013 period, a net stock-based compensation recovery in the 2014 period compared to a net stock-based compensation expense in the fourth quarter of 2013, a gain on property acquisition recognized in the fourth quarter of 2014, and a higher gain on dispositions in the 2014 period compared to the 2013 fourth quarter. These positive impacts to net profit were partially offset by increased depletion and depreciation expense as well as an impairment expense recognized in the fourth quarter of 2014 compared to the same period in 2013.

 

**Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit**

** **
| ** **                                                | ** ** | **Three months ended   December 31,** | ** ** |
|-----------------------------------------------------------|------------|------------------------------------------------------|------------|
| **($000s, except per share amounts)** | ** ** | **2014**                                             | ** ** | **2013** | ** ** |
| Cash flow from operating activities                       |       | 90,459                                               |       | 38,025 |   |
| Basic ($/share)                                           |       | 0.47                                                 |       | 0.30 |   |
| Diluted ($/share)                                         |       | 0.47                                                 |       | 0.29 |   |
| Funds flow from operations                                |       | 61,757                                               |       | 39,349 |   |
| Basic ($/share)                                           |       | 0.32                                                 |       | 0.31 |   |
| Diluted ($/share)                                         |       | 0.32                                                 |       | 0.30 |   |
| Net profit                                                |       | 54,830                                               |       | 22,195 |   |
| Basic ($/share)                                           |       | 0.29                                                 |       | 0.17 |   |
| Diluted ($/share)                                         |       | 0.29                                                 |       | 0.17 |   |

 

During the three months ended December 31, 2014, Bellatrix invested $81.9 million on capital projects, excluding corporate and property acquisitions and dispositions, compared to $101.2 million in the same period in 2013.

 

16

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**Capital Expenditures**

 
| ** **                                       | ** ** | **Three months ended   December 31,** | ** ** |
|--------------------------------------------------|------------|------------------------------------------------------|------------|
| **($000s)**                                      | ** ** | **2014**                                             | ** ** | **2013** | ** ** |
| Lease acquisitions and   retention               |       | 2,878                                                |       | 3,225 |   |
| Geological and geophysical                       |       | (103                                                 | )          | 47 |   |
| Drilling and completion   costs                  |       | 70,980                                               |       | 81,756 |   |
| Facilities and equipment                         |       | 41,039                                               |       | 16,204 |   |
| Property transfers — cash                   |       | (32,921                                              | )          | — |   |
| Capital — exploration and   development (1) |       | 81,873                                               |       | 101,232 |   |
| Capital — corporate assets   (2)            |       | 3,346                                                |       | 4,282 |   |
| Property acquisitions                            |       | 148,857                                              |       | 10,385 |   |
| Total capital expenditures   — cash         |       | 234,076                                              |       | 115,899 |   |
| Property dispositions — cash                |       | (1,435                                               | )          | (16,700 | ) |
| Total net capital   expenditures — cash     |       | 232,641                                              |       | 99,199 |   |
| Corporate acquisition —   non-cash          |       | —                                               |       | 595,891 |   |
| Property acquisitions —   non-cash          |       | 56,845                                               |       | — |   |
| Other — non-cash (3)                        |       | 7,767                                                |       | 11,836 |   |
| Total non-cash                                   |       | 64,612                                               |       | 607,727 |   |
| Total capital expenditures   — net (4)      |       | 297,253                                              |       | 706,926 |   |

 

----

*(1) **Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the period.*

*(2) **Capital - corporate assets includes office leasehold improvements, furniture, fixtures and equipment before recoveries realized from landlord lease inducements.*

*(3) **Other includes non-cash adjustments for the current period’s decommissioning liabilities and share based compensation.*

*(4) **Total capital expenditures — net is considered to be a non-GAAP measure.  Total capital expenditures — net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.*

 

During the fourth quarter of 2014, Bellatrix continued the construction of the Bellatrix Alder Flats Plant.  The Bellatrix Alder Flats Plant will be developed in two phases with total sales gas design capacity of 220 mmcf/d.  Phase I of the Bellatrix Alder Flats Plant remains on schedule and on budget of $90 million for a July 2015 start-up, with $60.1 million total (including partners share) spent to date.

 

In the fourth quarter of 2014, Bellatrix completed the transfer at cost of minority interests totaling 40% in the Bellatrix Alder Flats Plant and related pipeline infrastructure currently under construction to Keyera Partnership and O’Chiese Gas Plant GP Inc.

 

17

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**2014 HIGHLIGHTS**

 
| ** **                                         | ** ** | **Year ended December 31,** | ** ** |
|----------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                         | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| **SELECTED FINANCIAL RESULTS**(unaudited)          |       |                                       |       |   |   |
| *(CDN$000s except share and per   share amounts)*  |       |                                       |       |   |   |
| Revenue (before royalties and risk management (1)) |       | 583,467                                    |       | 291,891 |   |
| Funds flow from operations (2)                     |       | 270,753                                    |       | 143,459 |   |
| Per basic share (5)                                |       | $                                          | 1.48       |   | $ | 1.27 |   |
| Per diluted share (5)                              |       | $                                          | 1.46       |   | $ | 1.24 |   |
| Cash flow from operating activities                |       | 294,828                                    |       | 128,458 |   |
| Per basic share (5)                                |       | $                                          | 1.61       |   | $ | 1.14 |   |
| Per diluted share (5)                              |       | $                                          | 1.59       |   | $ | 1.11 |   |
| Net profit                                         |       | 163,123                                    |       | 71,675 |   |
| Per basic share (5)                                |       | $                                          | 0.89       |   | $ | 0.63 |   |
| Per diluted share (5)                              |       | $                                          | 0.88       |   | $ | 0.62 |   |
| Capital — exploration and development         |       | 504,467                                    |       | 281,009 |   |
| Capital — corporate assets                    |       | 11,163                                     |       | 9,270 |   |
| Property acquisitions                              |       | 176,428                                    |       | 13,386 |   |
| Capital expenditures — cash                   |       | 692,058                                    |       | 303,665 |   |
| Property dispositions — cash                  |       | (9,809                                     | )          | (70,942 | ) |
| Total net capital expenditures — cash         |       | 682,249                                    |       | 232,723 |   |
| Corporate acquisitions and other non-cash items    |       | 88,616                                     |       | 608,078 |   |
| Total capital expenditures — net (4)          |       | 770,865                                    |       | 840,801 |   |
| Long-term debt                                     |       | 549,792                                    |       | 287,092 |   |
| Adjusted working capital deficiency (3)            |       | 87,934                                     |       | 108,390 |   |
| Total net debt (3)                                 |       | 637,726                                    |       | 395,482 |   |
| Total assets                                       |       | 2,213,485                                  |       | 1,555,180 |   |
| Total shareholders’ equity                    |       | 1,248,317                                  |       | 903,874 |   |

 

18

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**SELECTED OPERATING RESULTS**

 
| ** **                                                       | ** ** | ** ** | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------------------------|------------|------------|------------|--------------------------------------------|------------|
| ** **                                                       | ** ** | ** ** | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Average daily sales volumes                                      |       |       |       |                                       |       |   |   |
| Crude oil, condensate and NGLs                                   |       | (bbls/d)   |       | 12,469                                     |       | 6,489 |   |
| Natural gas                                                      |       | (mcf/d)    |       | 153,575                                    |       | 92,042 |   |
| Total oil equivalent                                             |       | (boe/d)    |       | 38,065                                     |       | 21,829 |   |
| Average realized prices                                          |       |       |       |                                       |       |   |   |
| Crude oil and condensate                                         |       | ($/bbl)    |       | 91.41                                      |       | 91.45 |   |
| NGLs (excluding condensate)                                      |       | ($/bbl)    |       | 42.74                                      |       | 43.85 |   |
| Crude oil, condensate and NGLs                                   |       | ($/bbl)    |       | 67.47                                      |       | 72.29 |   |
| Crude oil, condensate and NGLs (including risk   management (1)) |       | ($/bbl)    |       | 65.14                                      |       | 69.82 |   |
| Natural gas                                                      |       | ($/mcf)    |       | 4.77                                       |       | 3.49 |   |
| Natural gas (including risk management (1))                      |       | ($/mcf)    |       | 4.39                                       |       | 3.71 |   |
| Total oil equivalent                                             |       | ($/boe)    |       | 41.33                                      |       | 36.18 |   |
| Total oil equivalent (including risk management (1))             |       | ($/boe)    |       | 39.03                                      |       | 36.42 |   |
|                                                             |       |       |       |                                       |       |   |   |
| Net wells drilled                                                |       |       |       | 59.1                                       |       | 52.8 |   |
|                                                             |       |       |       |                                       |       |   |   |
| Selected Key Operating Statistics                                |       |       |       |                                       |       |   |   |
| Operating netback (4)                                            |       | ($/boe)    |       | 24.34                                      |       | 20.76 |   |
| Operating netback (4) (including risk management (1))       |       | ($/boe)    |       | 22.04                                      |       | 20.99 |   |
| Transportation                                                   |       | ($/boe)    |       | 1.17                                       |       | 0.88 |   |
| Production expenses                                              |       | ($/boe)    |       | 8.64                                       |       | 8.74 |   |
| General & administrative                                |       | ($/boe)    |       | 1.83                                       |       | 2.03 |   |
| Royalties as a % of sales (after transportation)                 |       |       |       | 18%                                        |       | 16% |   |
| **COMMON SHARES**                                                |       |       |       |                                       |       |   |   |
| Common shares outstanding                                        |       |       |       | 191,950,576                                |       | 170,990,605 |   |
| Share options outstanding                                        |       |       |       | 10,913,337                                 |       | 11,182,963 |   |
| Fully diluted common shares outstanding                          |       |       |       | 202,863,913                                |       | 182,173,568 |   |
| Weighted average shares (5)                                      |       |       |       | 184,947,822                                |       | 115,768,436 |   |
| **SHARE TRADING STATISTICS**                                     |       |       |       |                                       |       |   |   |
| **TSX and Other****(6)**                                         |       |       |       |                                       |       |   |   |
| *(CDN$, except volumes) based on   intra-day trading*            |       |       |       |                                       |       |   |   |
| High                                                             |       |       |       | 11.65                                      |       | 8.52 |   |
| Low                                                              |       |       |       | 3.45                                       |       | 4.03 |   |
| Close                                                            |       |       |       | 4.23                                       |       | 7.81 |   |
| Average daily volume                                             |       |       |       | 2,683,578                                  |       | 1,336,726 |   |
| **NYSE****(7)**                                                  |       |       |       |                                       |       |   |   |
| *(US$, except volumes) based on   intra-day trading*             |       |       |       |                                       |       |   |   |
| High                                                             |       |       |       | 10.70                                      |       | 8.43 |   |
| Low                                                              |       |       |       | 2.97                                       |       | 4.10 |   |
| Close                                                            |       |       |       | 3.64                                       |       | 7.33 |   |
| Average daily volume                                             |       |       |       | 384,007                                    |       | 99,851 |   |

 

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

 

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

 

19

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

 

*(3) **Total net debt is considered to be an additional GAAP measures.  Therefore reference to the additional GAAP measure of total net debt may not be comparable with the calculation of similar measures for other entities.  The Company’s 2014 calculation of total net debt excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability.  Total net debt includes the adjusted working capital deficiency (excess).  The adjusted working capital deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements.  A reconciliation between total liabilities under GAAP and total net debt as calculated by the Company is found in the MD&A.*

 

*(4) **Operating netbacks and total capital expenditures — net are considered non-GAAP measures.  Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income.  Total capital expenditures — net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. The detailed calculations of operating netbacks are found in the MD&A.*

 

*(5) **Basic weighted average shares for the year ended December 31, 2014 were 183,216,536 (2013: 112,927,251).*

 

*In computing weighted average diluted earnings per share and weighted average diluted cash flow from operating activities and funds flow from operations per share for the year ended December 31, 2014, a total of 1,731,286 (2013: 2,841,185) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options, resulting in diluted weighted average common shares of 184,947,822 (2013: 115,768,436).*

 

(6) *TSX and Other includes the trading statistics for the TSX and other Canadian trading markets.*

 

(7) *Effective October 6, 2014, Bellatrix transferred the listing of its common shares from NYSE MKT to the New York Stock Exchange (“NYSE”). The common shares trade on the NYSE under the same ticker symbol, “BXE”, as was used on the NYSE MKT listing and is currently used on the TSX listing.*

 

**2014 Annual Financial and Operational Results**

 

**Sales Volumes**

 

Sales volumes for the year ended December 31, 2014 increased by 74% to an average of 38,065 boe/d compared to 21,829 boe/d in the 2013 year.  Total crude oil, condensate and NGLs averaged approximately 33% of sales volumes for 2014, compared to 30% in 2013.  The increase in total sales volumes between the years were primarily a result of $298.3 million of net drilling and completion capital expenditures for the year ended December 31, 2014, Bellatrix’s ongoing successful drilling activity in the Cardium and Mannville resource plays, and additional sales volumes acquired through the acquisition of Angle in December, 2013.  The increase in sales volumes between the periods was also attributable in part to the Grafton Joint Venture, the Daewoo and Devonian Partnership entered into by the Company during the third quarter of 2013, and the Troika Joint Venture entered into by the Company during the fourth quarter of 2013, as Bellatrix was able to accelerate and expand its drilling activity through these joint venture arrangements throughout 2014.

 

During 2014 Bellatrix experienced tightness in available processing capacity in its core area as interruptible capacity became congested due to both system constraints and the influx of new production in the area. These constraints stemmed from significant drilling with the application of new horizontal drilling and multi-stage fracing technology by area operators.  The area plant throughputs were further impacted by fluctuations in the TransCanada system pressures which were elevated to accommodate their maintenance programs.

 

In order to address these production constraints, Bellatrix completed a multitude of infrastructure projects in 2014.  In April 2014, Bellatrix completed a 1.6 km river bore and a 7 km pipeline in conjunction with Blaze Energy Ltd., completing a 55 km pipeline to tie-in Bellatrix’s natural gas for processing in the Blaze gas plant located at 4-31-48-12W5.  In addition, Bellatrix has secured firm processing capacity of 100 mmcf/d in the plant.

 

20

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Bellatrix has also entered into a separate arrangement with Keyera whereby Bellatrix has immediately secured 19 mmcf/d of firm processing capacity, 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.  The addition of firm service capacity is anticipated to improve overall operational reliability and facilitate the execution of the Company’s projected growth from the area.

 

Also, in the fourth quarter Bellatrix added booster compression at its 13-5 compressor station, and completed the construction of the Twin Rivers pipeline. These projects in combination are expected to increase gross processing capability of approximately 30 to 40 mmcf/d; representing potential increased processing capability net to Bellatrix of approximately 3,000 to 4,000 boe/d, based on forecasted working interest volumes.

 

Additionally, the two phases of the Bellatrix Alder Flats Plant and construction and tie-in of new associated pipelines are anticipated to add 110 mmcf/d capacity by July 2015, expanding to a total of 220 mmcf/d in 2017.  In combination, these strategic endeavors provide for potential volume growth and total processing capability net to Bellatrix’s working interest of over 80,000 boe/d in 2017.

 

**Sales Volumes**

 
| ** **                           | ** ** | ** ** | ** ** | **Year ended December 31,** | ** ** |
|--------------------------------------|------------|------------|------------|--------------------------------------------|------------|
| ** **                           | ** ** | ** ** | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Crude oil and condensate             |       | (bbls/d)   |       | 6,336                                      |       | 3,877 |   |
| NGLs (excluding condensate)          |       | (bbls/d)   |       | 6,133                                      |       | 2,612 |   |
| Total crude oil, condensate and NGLs |       | (bbls/d)   |       | 12,469                                     |       | 6,489 |   |
| Natural gas                          |       | (mcf/d)    |       | 153,575                                    |       | 92,042 |   |
| Total sales volumes (6:1 conversion) |       | (boe/d)    |       | 38,065                                     |       | 21,829 |   |

 

In the year ended December 31, 2014, Bellatrix posted a 100% success rate, drilling and/or participating in 110 gross (59.1 net) wells, consisting of 63 gross (36.4 net) Cardium oil wells, 34 gross (16.2 net) Spirit River liquids-rich gas wells, and 13 gross (6.5 net) Cardium gas wells.  Bellatrix’s drilling activity in 2014 was weighted 57% towards oil wells, and 43% towards natural gas wells

 

By comparison, during the year ended December 31, 2013, Bellatrix drilled and/or participated in 80 gross (52.8 net) wells, consisting of 57 gross (41.2 net) Cardium light oil horizontal wells, 22 gross (10.8 net) Spirit River liquids-rich gas wells, and one gross (0.8 net) Cardium gas well.  Bellatrix’s drilling activity in 2013 was weighted 71% towards oil wells, and 29% towards gas wells.

 

**Drilling Activity**

 
| ** **                            | ** ** | **Year ended   December 31, 2014** | ** ** | **Year ended   December 31, 2013** | ** ** |
|---------------------------------------|------------|---------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                            | ** ** | **Gross**                                         | ** ** | **Net**                                           | ** ** | **Success   Rate** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Success   Rate** | ** ** |
| Cardium oil                           |       | 63                                                |       | 36.4                                              |       | 100 | % | 57 |   | 41.2 |   | 100 | % |
| Spirit River liquids-rich natural gas |       | 34                                                |       | 16.2                                              |       | 100 | % | 22 |   | 10.8 |   | 100 | % |
| Cardium natural gas                   |       | 13                                                |       | 6.5                                               |       | 100 | % | 1 |   | 0.8 |   | 100 | % |
| Total                                 |       | 110                                               |       | 59.1                                              |       | 100 | % | 80 |   | 52.8 |   | 100 | % |

 

Crude oil, condensate and NGL sales volumes increased by 92% in the year ended December 31, 2014, averaging 12,469 bbls/d, compared to 6,489 bbls/d in the 2013 year.  Sales volumes were weighted 33% towards crude oil, condensate and NGLs for the year ended December 31, 2014, compared to 30% in 2013.

 

Sales of natural gas averaged 153.6 mmcf/d during the year ended December 31, 2014, an increase of 69% compared to 92.0 mmcf/d in 2013.

 

A net capital budget to not exceed $200 million has been set for fiscal 2015.  Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the $200 million 2015 net capital budget is anticipated to provide 2015 average daily production of approximately 43,000 to 44,000 boe/d.

 

21

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**Commodity Prices**

 

**Average Commodity Prices**

 
| ** **                                                                          | ** ** | **Year ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                          | ** ** | **2014**                                   | ** ** | **2013** | ** ** | **% Change** | ** ** |
|                                                                                |       |                                       |       |   |   |   |   |
| Exchange rate *(US$/CDN$1.00)*                                                      |       | 0.9054                                     |       | 0.9712 |   | (7 | ) |
|                                                                                |       |                                       |       |   |   |   |   |
| Crude oil:                                                                          | ** ** | ** **                                 |       |   |   |   |   |
| WTI *(US$/bbl)*                                                                     |       | 92.21                                      |       | 98.05 |   | (6 | ) |
| Edmonton par — light oil / Canadian Light crude   blend *($/bbl)* (1)          |       | 93.99                                      |       | 93.24 |   | 1 |   |
| Bellatrix’s average realized prices *($/bbl)*                                  |       |                                       |       |   |   |   |   |
| Crude oil and condensate                                                            |       | 91.41                                      |       | 91.45 |   | — |   |
| NGLs (excluding condensate)                                                         |       | 42.74                                      |       | 43.85 |   | (3 | ) |
| Total crude oil and NGLs                                                            |       | 67.47                                      |       | 72.29 |   | (7 | ) |
| Total crude oil and NGLs (including risk   management (2))                          |       | 65.14                                      |       | 69.82 |   | (7 | ) |
|                                                                                |       |                                       |       |   |   |   |   |
| Natural gas:                                                                        |       |                                       |       |   |   |   |   |
| NYMEX *(US$/mmbtu)*                                                                 |       | 4.26                                       |       | 3.73 |   | 14 |   |
| AECO daily index *(CDN$/mcf)*                                                       |       | 4.50                                       |       | 3.17 |   | 42 |   |
| AECO monthly index *(CDN$/mcf)*                                                     |       | 4.41                                       |       | 3.16 |   | 40 |   |
| Bellatrix’s average realized price (*$/mcf)*                                   |       | 4.77                                       |       | 3.49 |   | 37 |   |
| Bellatrix’s average realized price (including risk   management (2)) (*$/mcf)* |       | 4.39                                       |       | 3.71 |   | 18 |   |

 

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*(1) **Edmonton par — light oil prices were discontinued as of May 1, 2014 and replaced by Canadian Light crude blend.  2014 prices reflect the Canadian Light crude blend, while 2013 prices reflect the Edmonton par — light oil.*

 

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

 

For crude oil and condensate, Bellatrix realized an average price of $91.41/bbl before commodity price risk management contracts during the year ended December 31, 2014, consistent with the average price of $91.45/bbl received in the 2013 year.  By comparison, the Edmonton par/Canadian Light price increased by 1% and the average WTI crude oil benchmark price decreased by 6% between the 2014 and 2013 years.

 

In the first nine months of 2014, strong North American crude oil and natural gas prices promoted significant drilling activity in North America.  The elevated drilling activity levels in conjunction with technological enhancements in horizontal drilling resulted in supply growth of both crude oil and natural gas.  The increased supply led to a supply-demand imbalance in the markets, which resulted in price deterioration for both crude oil and natural gas markets late in 2014.

 

The over-supplied nature of the global oil market became more apparent late in 2014, with the continued production growth from shale plays in the United States, slower than expected global demand growth, and sustained production levels by OPEC.  Bellatrix expects significantly reduced drilling activity from the cutback 2015 budgeted capital spending in the energy sector, resulting in a decrease in supply growth and re-balancing of over-supplied markets. However, there will be a lag between drilling activity levels and a decrease in global oil production due to the life cycle of well completions and tie-ins.  In addition to re-balancing supply and demand, it is expected that the decrease in drilling activity will result in a meaningful decrease in oilfield service costs which should result in improved rates of return at lower commodity prices.

 

The average US$/CDN$1.00 foreign exchange rate decreased by 7% to 0.9054 for the year ended December 31, 2014 from an average rate of 0.9712 in 2013.

 

Bellatrix’s average realized price for NGLs (excluding condensate) decreased by 3% to $42.74/bbl during the 2014 year, compared to $43.85/bbl received in the 2013 year.  The overall decrease in NGL pricing between the years was largely attributable to changes in NGL market supply conditions between the years.

 

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 realized prices per mcf than the daily 

 

22

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AECO index.  During the year ended December 31, 2014, the AECO daily reference price increased by 42% and the AECO monthly reference price increased by approximately 40% compared to the 2013 year.  Bellatrix’s natural gas average sales price before commodity price risk management contracts for the 2014 year increased by 37% to $4.77/mcf compared to $3.49/mcf in 2013.  Bellatrix’s natural gas average price after including commodity price risk management contracts for the year ended December 31, 2014 averaged $4.39/mcf compared to $3.71/mcf in 2013.

 

**Revenue**

 

Revenue before other income, royalties and commodity price risk management contracts was $574.3 million for the year ended December 31, 2014, an increase of 99% compared to $288.3 million realized in the year ended December 31, 2013.  In the 2014 year, Bellatrix realized higher light oil, condensate, natural gas, and NGL revenues due primarily to increased sales volumes resulting from Bellatrix’s ongoing successful drilling activity throughout 2014, a 38% increase in wells drilled between the 2013 and 2014 years, higher natural gas prices, and additional sales volumes realized from the acquisition of Angle in December of 2013, which were partially offset by lower NGL prices realized during the 2014 year.

 

Crude oil and NGLs revenue before other income, royalties and commodity price risk management contracts for the 2014 year increased by 79% to $307.1 million from $171.2 million realized during 2013. The increase in revenue realized between the years was the result of 92% higher sales volumes, partly offset by slightly lower realized NGL prices when compared to 2013.

 

For the year ended December 31, 2014, total crude oil, condensate and NGL revenues contributed 53% of total revenue before other income, compared to 59% in the 2013 year.

 

Natural gas revenue before other income, royalties and commodity price risk management contracts was $267.2 million in the year ended December 31, 2014, an increase of 128% from $117.1 million realized in the 2013 year.  The increase in realized revenue was attributable to a 37% increase in realized gas prices before risk management in conjunction with a 69% increase in sales volumes between the 2014 and 2013 years.

 
| ** **                                             | ** ** | **Year ended December 31,** | ** ** |
|--------------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s)**                                            | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Crude oil and condensate                               |       | 211,395                                    |       | 129,412 |   |
| NGLs (excluding condensate)                            |       | 95,673                                     |       | 41,804 |   |
| Crude oil and NGLs                                     |       | 307,068                                    |       | 171,216 |   |
| Natural gas                                            |       | 267,185                                    |       | 117,094 |   |
| Total revenue (before other income)                    |       | 574,253                                    |       | 288,310 |   |
| Other income (1)                                       |       | 9,214                                      |       | 3,581 |   |
| Total revenue (before royalties and risk   management) |       | 583,467                                    |       | 291,891 |   |

 

----

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

 

**Commodity Price Risk Management**

 

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

 

23

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As at December 31, 2014, Bellatrix had no outstanding commodity price risk management contracts and carried no unrealized assets or liabilities related to such contracts.

 

A summary of the financial commodity price risk management volumes and average prices by quarter outstanding as of March 11, 2015 is shown in the following tables:

 

**Natural gas**

 

**Average Volumes (GJ/d)**

 
| ** ** | ** ** | **Q1 2015** | ** ** | **Q2 2015** | ** ** | **Q3 2015** | ** ** | **Q4 2015** | ** ** |
|------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| Fixed      |       | 54,250           |       | 180,000          |       | 180,000          |       | 98,777           |       |

 

**Average Price ($/GJ AECO C)**

 
| ** **  | ** ** | **Q1 2015** | ** ** | **Q2 2015** | ** ** | **Q3 2015** | ** ** | **Q4 2015** | ** ** |
|-------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| Fixed price |       | 2.73             |       | 2.55             |       | 2.55             |       | 2.56             |       |

 

**Crude oil and liquids**

 

**Average Volumes (bbls/d)**

 
| ** **   | ** ** | **Q1 2015** | ** ** | **Q2 2015** | ** ** | **Q3 2015** | ** ** | **Q4 2015** | ** ** |
|--------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| Fixed (CDN$) |       | 1,967            |       | 3,000            |       | 3,000            |       | 3,000            |       |

 

**Average Price ($/bbl WTI)**

 
| ** **             | ** ** | **Q1 2015** | ** ** | **Q2 2015** | ** ** | **Q3 2015** | ** ** | **Q4 2015** | ** ** |
|------------------------|------------|------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| Fixed price (CDN$/bbl) |       | 70.34            |       | 70.34            |       | 70.34            |       | 70.34            |       |

 

When the Company has outstanding commodity price risk management contracts at a reporting date, the fair value, or mark-to-market value, of these contracts reflected in its financial statements as an unrealized asset or liability is based on the estimated amount that would have been received or paid to settle the contracts as at the reporting date and would differ from what would 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 are summaries of the gain (loss) on commodity contracts for the years ended December 31, 2014 and 2013 as reflected in the Consolidated Statements of Comprehensive Income:

 

**Commodity contracts**

 
| **Year ended December 31, 2014** | ** ** | ** **         | ** ** | ** **           | ** ** | ** ** | ** ** |
|------------------------------------------------------|------------|--------------------|------------|----------------------|------------|------------|------------|
| **($000s)**                                          | ** ** | **Crude Oil** | ** ** | **Natural Gas** | ** ** | **Total**  | ** ** |
| Realized cash loss on   contracts (1)                |       | (10,620            | )          | (21,371              | )          | (31,991    | )          |
| Unrealized gain on contracts (4)                     |       | 11,411             |       | 5,522                |       | 16,933     |       |
| Total gain (loss) on   commodity contracts           |       | 791                |       | (15,849              | )          | (15,058    | )          |

 

**Commodity contracts**

 
| **Year ended December 31, 2013**  | ** ** | ** **         | ** ** | ** **           | ** ** | ** ** | ** ** |
|-------------------------------------------------------|------------|--------------------|------------|----------------------|------------|------------|------------|
| **($000s)**                                           | ** ** | **Crude Oil** | ** ** | **Natural Gas** | ** ** | **Total**  | ** ** |
| Realized cash gain (loss)   on contracts (2) (3) |       | (5,851             | )          | 7,710                |       | 1,859      |       |
| Unrealized loss on   contracts (4)                    |       | (4,112             | )          | (13,015              | )          | (17,127    | )          |
| Total loss on commodity   contracts                   |       | (9,963             | )          | (5,305               | )          | (15,268    | )          |

 

----

*(1) **In January 2014, the Company settled a 1,500 bbl/d $105.00 US crude call option for the term of February to December 31, 2014 for US $0.5 million.*

*(2) **In January 2013, the Company crystalized and realized $6.5 million in cash proceeds by resetting the fixed prices on natural gas commodity price risk management contracts for the period from April 1, 2013 through to October 31, 2013.*

*(3) **In September 2013, the Company incurred $0.6 million of costs for the settlement of an oil call commodity price risk management contract for the period from November 1, 2013 through to December 31, 2013.*

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

 

24

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**Royalties**

 

For the year ended December 31, 2014, royalties incurred totaled $99.8 million, compared to $46.2 million incurred in the 2013 year.  Overall royalties as a percentage of revenue (after transportation costs) in 2014 were 18% compared with 16% in 2013.

 

**Royalties by Commodity Type**

 
| ** **                                              | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except where noted)**          | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Crude oil, condensate and NGLs                          |       | 66,128                                     |       | 35,913 |   |
| $/bbl                                                   |       | 14.53                                      |       | 15.16 |   |
| Average crude oil, condensate and NGLs royalty rate (%) |       | 22                                         |       | 21 |   |
|                                                    |       |                                       |       |   |   |
| Natural Gas                                             |       | 33,695                                     |       | 10,304 |   |
| $/mcf                                                   |       | 0.60                                       |       | 0.31 |   |
| Average natural gas royalty rate (%)                    |       | 13                                         |       | 9 |   |
|                                                    |       |                                       |       |   |   |
| Total                                                   |       | 99,823                                     |       | 46,217 |   |
| Total $/boe                                             |       | 7.18                                       |       | 5.80 |   |
| Average total royalty rate   (%)                        |       | 18                                         |       | 16 |   |

 

**Royalties by Type**

 
| ** **               | ** ** | **Year ended December 31,** | ** ** |
|--------------------------|------------|--------------------------------------------|------------|
| **($000s)**              | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Crown royalties          |       | 35,507                                     |       | 15,051 |   |
| IOGC royalties           |       | 18,699                                     |       | 10,473 |   |
| Freehold & GORR |       | 45,617                                     |       | 20,693 |   |
| Total                    |       | 99,823                                     |       | 46,217 |   |

 

The Company’s light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more recent wells in their early years of production under the Alberta royalty incentive program. This is offset by increased royalty rates on wells coming off initial royalty incentive rates and wells drilled on Ferrier lands with higher combined IOGC and GORR royalty rates.

 

**EXPENSES**

 
| ** **                         | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------|------------|--------------------------------------------|------------|
| **($000s)**                        | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Production                         |       | 120,072                                    |       | 69,668 |   |
| Transportation                     |       | 16,259                                     |       | 7,014 |   |
| Royalties                          |       | 99,823                                     |       | 46,217 |   |
| General and administrative         |       | 25,371                                     |       | 16,214 |   |
| Interest and financing charges (1) |       | 19,198                                     |       | 12,488 |   |
| Share-based compensation           |       | 3,673                                      |       | 4,960 |   |

 

----

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

 

**Expenses per boe**

 
| ** **                         | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------|------------|--------------------------------------------|------------|
| **($ per boe)**          | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Production                         |       | 8.64                                       |       | 8.74 |   |
| Transportation                     |       | 1.17                                       |       | 0.88 |   |
| Royalties                          |       | 7.18                                       |       | 5.80 |   |
| General and administrative         |       | 1.83                                       |       | 2.03 |   |
| Interest and financing charges (1) |       | 1.38                                       |       | 1.57 |   |
| Share-based compensation           |       | 0.26                                       |       | 0.62 |   |

 

----

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

 

25

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**Production Expenses**

 

Production expenses totaled $120.1 million ($8.64/boe) for the year ended December 31, 2014, compared to $69.7 million ($8.74/boe) in the 2013 year.  Production expenses increased overall between the years as a result of increased sales volumes and related operational activities.  On a per boe basis, production expenses decreased in 2014 as the overall increase in production expenses was more than offset by continued field optimization projects and increased production in areas of Ferrier and Harmattan with lower production expenses, as well as reduced natural gas gathering fees due to lower rate contracts executed during 2014.

 

Bellatrix is targeting production expenses of approximately $131.0 million ($8.25/boe) in the 2015 year, which represents a reduction on a per unit basis from the $8.64/boe production expenses incurred for the 2014 year.  The lower per boe target is based upon assumptions of estimated 2015 average production of approximately 43,000 to 44,000 boe/d, continued field optimization work, the start-up of the Bellatrix Alder Flats Plant, and planned capital expenditures in producing areas which are anticipated to lower production expenses.

 

**Production Expenses by Commodity Type**

 
| ** **                                                      | ** ** | **Year ended December 31,** | ** ** |
|-----------------------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except where noted)**                  | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Crude oil, condensate and NGLs                                  |       | 38,539                                     |       | 25,839 |   |
| $/bbl                                                           |       | 8.47                                       |       | 10.91 |   |
|                                                            |       |                                       |       |   |   |
| Natural gas                                                     |       | 81,533                                     |       | 43,829 |   |
| $/mcf                                                           |       | 1.45                                       |       | 1.30 |   |
|                                                            |       |                                       |       |   |   |
| Total Production Expenses                                       |       | 120,072                                    |       | 69,668 |   |
| Total $/boe                                                     |       | 8.64                                       |       | 8.74 |   |
|                                                            |       |                                       |       |   |   |
| Total Production Expenses                                       |       | 120,072                                    |       | 69,668 |   |
| Processing and other third party income (1)                     |       | (9,214                                     | )          | (3,581 | ) |
| Total after deducting processing and other third   party income |       | 110,858                                    |       | 66,087 |   |
| Total $/boe                                                     |       | 7.98                                       |       | 8.29 |   |

 

----

*(1) **Processing and other third party income is included as other income in the Consolidated Statements of Comprehensive Income.*

 

**Transportation**

 

Transportation expenses for the year ended December 31, 2014 were $16.3 million ($1.17/boe), compared to $7.0 million ($0.88/boe) in the 2013 year. The increase in transportation costs per boe between 2013 and 2014 was due to increased fuel costs resulting from higher natural gas pricing realized during 2014, as well as higher transporting costs for crude oil and associated products produced from wells commencing production during 2014.

 

**Operating Netback**

 

**Operating Netback — Corporate (before risk management)**

 
| ** **        | ** ** | **Year ended December 31,** | ** ** |
|-------------------|------------|--------------------------------------------|------------|
| **($/boe)**       | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Sales             |       | 41.33                                      |       | 36.18 |   |
| Production        |       | (8.64                                      | )          | (8.74 | ) |
| Transportation    |       | (1.17                                      | )          | (0.88 | ) |
| Royalties         |       | (7.18                                      | )          | (5.80 | ) |
| Operating netback |       | 24.34                                      |       | 20.76 |   |

 

For the year ended December 31, 2014, the corporate operating netback (before commodity risk management contracts) was $24.34/boe, an increase of 17% compared to $20.76/boe in the 2013 year.  The higher netback realized in 2014 was primarily the result of an increase in the average realized combined commodity prices and lower production expenses, partially offset by increased royalty and transportation expenses.  After including commodity risk management contracts, the corporate operating netback for the year ended December 31, 2014 was $22.04/boe, compared to

 

26

----

 

$20.99/boe in 2013.  Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.

 

**Operating Netback — Crude Oil, Condensate, and NGLs (before risk management)**

 
| ** **        | ** ** | **Year ended December 31,** | ** ** |
|-------------------|------------|--------------------------------------------|------------|
| **($/boe)**       | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Sales             |       | 67.47                                      |       | 72.29 |   |
| Production        |       | (8.47                                      | )          | (10.91 | ) |
| Transportation    |       | (1.11                                      | )          | (0.86 | ) |
| Royalties         |       | (14.53                                     | )          | (15.16 | ) |
| Operating netback |       | 43.36                                      |       | 45.36 |   |

 

Operating netback for crude oil, condensate, and NGLs decreased by 4% to $43.36/bbl for the year ended December 31, 2014 from $45.36/bbl realized in the 2013 year.  The lower netback was primarily attributable to lower NGL commodity prices and higher transportation expenses, partially offset by reduced production expenses and royalties.  After including commodity price risk management contracts, operating netback for crude oil, condensate, and NGLs for the year ended December 31, 2014 was $41.03/bbl, compared to $42.89/bbl in 2013.

 

**Operating Netback — Natural Gas (before risk management)**

 
| ** **        | ** ** | **Year ended December 31,** | ** ** |
|-------------------|------------|--------------------------------------------|------------|
| **($/mcf)**       | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Sales             |       | 4.77                                       |       | 3.49 |   |
| Production        |       | (1.45                                      | )          | (1.30 | ) |
| Transportation    |       | (0.20                                      | )          | (0.15 | ) |
| Royalties         |       | (0.60                                      | )          | (0.31 | ) |
| Operating netback |       | 2.52                                       |       | 1.73 |   |

 

For the year ended December 31, 2014, operating netback for natural gas was $2.52/mcf, an increase of 46% from $1.73/mcf realized in 2013.  The higher netback between the years reflected higher natural gas prices, partially offset by increased production, transportation, and royalty expenses.  After including commodity risk management contracts, operating netback for natural gas for the year ended December 31, 2014 was $2.14/mcf, compared to $1.96/mcf in the 2013 year.

 

**General and Administrative**

 

General and administrative expenses (after capitalized G&A and recoveries) for the year ended December 31, 2014 were $25.4 million ($1.83/boe), compared to $16.2 million ($2.03/boe) in 2013.  The higher G&A expenses in 2014 were primarily reflective of higher compensation costs and related staffing costs as Bellatrix’s headcount has increased by 68% between the years to manage the increased activity resulting from the Angle acquisition and increased drilling activity. These cost increases were partially offset by greater capitalization of G&A and recoveries from partners associated with higher capital spending. On a per boe basis, G&A expenses for the year ended December 31, 2014 decreased by 10% compared to 2013 due to increased sales volumes and Bellatrix’s continued increased focus on operational and administrative efficiencies.

 

**General and Administrative Expenses**

 
| ** **                                     | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except where noted)** | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Gross expenses                                 |       | 55,600                                     |       | 29,145 |   |
| Capitalized                                    |       | (8,458                                     | )          | (5,343 | ) |
| Recoveries                                     |       | (21,771                                    | )          | (7,588 | ) |
| G&A expenses                               |       | 25,371                                     |       | 16,214 |   |
| G&A expenses, per unit   ($/boe)           |       | 1.83                                       |       | 2.03 |   |

 

27

----

 

**Interest and Financing Charges**

 

For the year ended December 31, 2014, Bellatrix recorded $19.2 million ($1.38/boe) of interest and financing charges related to bank debt, compared to $12.5 million ($1.57/boe) during the 2013 year, which included amounts relating to the 4.75% convertible debentures outstanding during the majority of 2013.  Bellatrix’s convertible debentures were settled during September and October of 2013.

 

The overall increase in interest and financing charges between 2013 and 2014 was primarily due to higher interest charges as the Company carried a higher average debt balance during the 2014 year resulting from the increased 2014 net capital program and is supported by the expansion of the Bellatrix’s credit facility to $725M.

 

Bellatrix’s total net debt at December 31, 2014 of $637.7 million included $549.8 million of bank debt and an adjusted working capital deficiency of $87.9 million.

** **

**Interest and Financing Charges****(1)**

 
| ** **                                     | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except where noted)** | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Interest and financing charges                 |       | 19,198                                     |       | 12,488 |   |
| Interest and financing charges ($/boe)         |       | 1.38                                       |       | 1.57 |   |

 

----

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

 

**Debt to Funds Flow from Operations Ratio**

 
| ** **                                                                           | ** ** | **Year ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except where noted)**                                       | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Shareholders’ equity                                                            |       | 1,248,317                                  |       | 903,874 |   |
|                                                                                 |       |                                       |       |   |   |
| Long-term debt                                                                       |       | 549,792                                    |       | 287,092 |   |
| Adjusted working capital deficiency (2)                                              |       | 87,934                                     |       | 108,390 |   |
| Total net debt (2) at year end                                                  |       | 637,726                                    |       | 395,482 |   |
|                                                                                 |       |                                       |       |   |   |
| **Debt to funds flow from   operations ratio (annualized)** (1) (3)        |       |                                       |       |   |   |
| Funds flow from operations (1) (annualized)                                     |       | 247,028                                    |       | 157,396 |   |
| Total net debt (2) at year end                                                  |       | 637,726                                    |       | 395,482 |   |
| Total net debt to periods funds flow from   operations ratio (annualized) (3)        |       | 2.6                                        | x          | 2.5 | x |
|                                                                                 |       |                                       |       |   |   |
| **Debt to funds flow from   operations ratio**(1)                                    |       |                                       |       |   |   |
| Funds flow from operations for the year (1)                                          |       | 270,753                                    |       | 143,459 |   |
| Total net debt (2) at year end                                                  |       | 637,726                                    |       | 395,482 |   |
| Total net debt (2)  to funds flow from   operations ratio (1) for the year |       | 2.4                                        | x          | 2.8 | x |

 

----

*(1) **As detailed previously in this MD&A, funds flow from operations is a term that does not have any standardized meaning or definition under GAAP.  Funds flow from operations is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred and transaction costs.  Refer to the reconciliation of cash flow from operating activities to funds flow from operations appearing elsewhere herein.*

 

*(2) **Total net debt is considered to be an additional GAAP measure.  Therefore reference to the additional GAAP measurer of total net debt may not be comparable with the calculation of similar measures for other entities.  The Company’s 2014 calculation of total net debt excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability.  Total net debt includes the adjusted working capital deficiency (excess).  The adjusted working capital deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements.  A reconciliation between total liabilities under GAAP and total net debt as calculated by the Company is found in the MD&A.*

 

*(3) **For the years ended December 31, 2014 and 2013, total net debt to funds flow from operations ratio (annualized) is calculated based upon fourth quarter funds flow from operations annualized.*

 

28

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**Reconciliation of Total Liabilities to Total Net Debt**
| ** **                                                                | ** ** | **As at December 31,** | ** ** |
|---------------------------------------------------------------------------|------------|---------------------------------------|------------|
| **($000s)**                                                               | ** ** | **2014**                              | ** ** | **2013** | ** ** |
| Total liabilities per financial statements                                |       | 965,168                               |       | 651,306 |   |
| Current liabilities (included within working   capital calculation below) |       | (232,396                              | )          | (255,903 | ) |
| Decommissioning liabilities                                               |       | (88,605                               | )          | (67,075 | ) |
| Finance lease obligation                                                  |       | (10,063                               | )          | (11,637 | ) |
| Deferred lease inducements                                                |       | (2,727                                | )          | (2,565 | ) |
| Deferred taxes                                                            |       | (81,585                               | )          | (27,034 | ) |
|                                                                      |       |                                  |       |   |   |
| Adjusted working capital                                                  |       |                                  |       |   |   |
| Current assets                                                            |       | (142,548                              | )          | (128,800 | ) |
| Current liabilities                                                       |       | 232,396                               |       | 255,903 |   |
| Current portion of finance lease                                          |       | (1,574                                | )          | (1,495 | ) |
| Current portion of deferred lease inducements                             |       | (340                                  | )          | (285 | ) |
| Current portion of commodity contract liability                           |       | —                                |       | (16,933 | ) |
|                                                                      |       | 87,934                                |       | 108,390 |   |
| **Total net debt**                                                        |       | 637,726                               |       | 395,482 |   |

 

**Share-Based Compensation**

 

For the year ended December 31, 2014, non-cash share-based compensation expense was $3.7 million compared to $5.0 million in the same period in 2013. The decrease in non-cash share-based compensation expense was composed of a recovery of $1.3 million for Deferred Share Units (“DSUs”) (2013: $2.3 million expense), higher capitalized share-based compensation of $3.4 million (2013: $1.7 million), and a lower expense of $0.9 million (2013: $1.0 million) for Restricted Awards (“RAs”), partially offset by a higher expense for the Company’s outstanding share options of $6.9 million (2013: $2.9 million), and a higher expense of $0.6 million (2013: $0.5 million) for Performance Awards (“PAs”).  The $1.3 million recovery for DSUs and lower expense for RAs recognized during 2014 was primarily due to the revaluation of DSUs and RAs to a lower weighted average share trading price at December 31, 2014 than December 31, 2013.

 

**Depletion and Depreciation and Impairment**

 

Depletion and depreciation expense (excluding impairment) for the year ended December 31, 2014 was $171.0 million ($12.31/boe), compared to $85.8 million ($10.77/boe) recognized in the 2013 year.  The increase in depletion and depreciation expense between the periods on a per boe basis was primarily a result of a higher cost base impacted by net facility capital expenditures of $149.1 million in 2014, which excludes $38.7 million of facilities under construction, and increased future development costs, which was only partially offset by an increase in the reserve base used for the depletion calculation.

 

For the year ended December 31, 2014, Bellatrix has included a total of $1.34 billion (2013: $1.28 billion) for future development costs in the depletion calculation and excluded from the depletion calculation a total of $80.3 million (2013: $69.0 million) for estimated salvage.

 

**Depletion and Depreciation**

 
| ** **                                     | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except where noted)** | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Depletion and Depreciation                     |       | 170,967                                    |       | 85,829 |   |
| Per unit ($/boe)                               |       | 12.31                                      |       | 10.77 |   |

 

**Impairment**

 

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 its recoverable amount, which is defined as the greater of its value-in-use and fair value less costs to sell.  Fair value less costs to sell is determined to be the amount for which the asset could be sold in an arm’s length

 

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transaction.  Fair value less costs to sell can be determined by using an observable market metric or by using discounted future net cash flows of proved and probable reserves using forecasted prices and costs.  Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or cash generating unit.

 

*2014 Impairment*

 

At December 31, 2014, Bellatrix performed an assessment of possible indicators of impairment on all of the Company’s CGUs.  Primarily as a result of declining crude oil and natural gas forward commodity prices, Bellatrix completed impairment tests for each of its CGUs.  The impairment amount was estimated using fair value less costs to sell calculations based on expected future cash flows generated from proved and probable reserves, which incorporated before-tax discount rates ranging from 10-15%. This impairment test resulted in an excess of the carrying value over their recoverable amount in five non-core CGUs.  The total non-cash impairment loss recognized in depletion, depreciation and impairment expense for the year ended December 31, 2014 was $10.8 million.  No impairment was recognized in relation to the Company’s core West Central Alberta CGU.

 

*2013 Impairment*

 

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

 

**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, 2014, the Company recognized a deferred income tax expense of $56.5 million, compared to $19.5 million during 2013.  The increase in deferred income tax expense between 2013 and 2014 was primarily attributable to the increase in net profit after adjusting for non-deductible tax items realized during the 2014 year.

 

At December 31, 2014, the Company had a total deferred tax liability balance of $81.6 million.

 

At December 31, 2014, Bellatrix had approximately $1.64 billion in tax pools available for deduction against future income as follows:

 
| **($000s)   **                                        | ** ** | **Rate %** | ** ** | **December 31,   2014** | ** ** | **December 31,   2013** | ** ** |
|----------------------------------------------------------------------|------------|-----------------|------------|------------------------------|------------|------------------------------|------------|
| Intangible resource pools:                                           |       |            |       |                         |       |                         |       |
| Canadian exploration expenses                                        |       | 100             |       | 116,700                      |       | 99,000                       |       |
| Canadian development expenses                                        |       | 30              |       | 758,700                      |       | 691,500                      |       |
| Canadian oil and gas property expenses                               |       | 10              |       | 207,900                      |       | 80,200                       |       |
| Foreign resource expenses                                            |       | 10              |       | 800                          |       | 900                          |       |
| Alberta non-capital losses greater than Federal   non-capital losses |       | (Alberta) 100   |       | 16,100                       |       | 16,100                       |       |
| Undepreciated capital cost **(1)**                                   |       | 6 — 55     |       | 367,600                      |       | 224,900                      |       |
| Non-capital losses (expire through 2030)                             |       | 100             |       | 162,300                      |       | 94,500                       |       |
| Financing costs                                                      |       | 20 S.L.         |       | 14,100                       |       | 15,600                       |       |
| ** **                                                           | ** ** | ** **      |       | 1,644,200                    |       | 1,222,700                    |       |

 

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*(1) **Approximately $355.0 million of undepreciated capital cost pools are class 41, which is claimed at a 25% rate.*

 

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**Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit**

 

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

 

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

 
| ** **                            | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------|------------|--------------------------------------------|------------|
| **($000s)**                           | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Cash   flow from operating activities |       | 294,828                                    |       | 128,458 |   |
| Decommissioning   costs incurred      |       | 1,743                                      |       | 1,057 |   |
| Transaction   costs                   |       | —                                     |       | 5,344 |   |
| Change   in non-cash working capital  |       | (25,818                                    | )          | 8,600 |   |
| Funds   flow from operations          |       | 270,753                                    |       | 143,459 |   |

 

Bellatrix’s cash flow from operating activities for the year ended December 31, 2014 increased by 130% to $294.8 million ($1.61 per basic share and $1.59 per diluted share) from $128.5 million ($1.14 per basic share and $1.11 per diluted share) generated during the 2013 year.  Bellatrix generated funds flow from operations of $270.8 million ($1.48 per basic share and $1.46 per diluted share) in the year ended December 31, 2014, an increase of 89% from $143.5 million ($1.27 per basic share and $1.24 per diluted share) generated in 2013.  The increase in funds flow from operations between 2013 and 2014 was principally due to an increase of 74% in production volumes and higher realized natural gas prices, partially offset by reduced realized NGL prices, a net realized loss on commodity contracts in 2014 compared to a net realized gain on commodity contracts in 2013, and increased general and administrative, production, transportation, royalty, and finance expenses related to the increased operational activity.

 

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

 

For the year ended December 31, 2014, Bellatrix recognized a net profit of $163.1 million ($0.89 per basic share and $0.88 per diluted share), compared to a net profit of $71.7 million ($0.63 per basic share and $0.62 per diluted share) in 2013.  The higher net profit recorded in 2014 compared to 2013 was primarily the result of increased funds from operating activities as noted above, an unrealized gain on commodity contracts in the 2014 year compared to an unrealized loss in 2013, lower stock-based compensation expense, a gain on property acquisition recognized during 2014, and a higher gain on dispositions in 2014 compared to 2013. These positive impacts to net profit were partially offset by increased depletion and depreciation expense, and an impairment expense recognized in the 2014 year compared to 2013.

 

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**Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit**

** **
| ** **                                                | ** ** | **Year ended December 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s, except per share amounts)** | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Cash flow from operating activities                       |       | 294,828                                    |       | 128,458 |   |
| Basic ($/share)                                           |       | 1.61                                       |       | 1.14 |   |
| Diluted ($/share)                                         |       | 1.59                                       |       | 1.11 |   |
| Funds flow from operations                                |       | 270,753                                    |       | 143,459 |   |
| Basic ($/share)                                           |       | 1.48                                       |       | 1.27 |   |
| Diluted ($/share)                                         |       | 1.46                                       |       | 1.24 |   |
| Net profit                                                |       | 163,123                                    |       | 71,675 |   |
| Basic ($/share)                                           |       | 0.89                                       |       | 0.63 |   |
| Diluted ($/share)                                         |       | 0.88                                       |       | 0.62 |   |

 

**Capital Expenditures**

 

Bellatrix invested $504.5 million on exploration and development capital projects, excluding property acquisitions and dispositions during the year ended December 31, 2014, compared to $281.0 million in 2013.

 

**Capital Expenditures**

 
| ** **                                       | ** ** | **Year ended December 31,** | ** ** |
|--------------------------------------------------|------------|--------------------------------------------|------------|
| **($000s)**                                      | ** ** | **2014**                                   | ** ** | **2013** | ** ** |
| Lease acquisitions and   retention               |       | 16,701                                     |       | 11,190 |   |
| Geological and geophysical                       |       | 1,601                                      |       | 140 |   |
| Drilling and completion   costs                  |       | 298,313                                    |       | 211,912 |   |
| Facilities and equipment                         |       | 220,773                                    |       | 57,767 |   |
| Property transfers — cash                   |       | (32,921                                    | )          | — |   |
| Capital — exploration and   development (1) |       | 504,467                                    |       | 281,009 |   |
| Capital — corporate assets   (2)            |       | 11,163                                     |       | 9,270 |   |
| Property acquisitions                            |       | 176,428                                    |       | 13,386 |   |
| Total capital expenditures   — cash         |       | 692,058                                    |       | 303,665 |   |
| Property dispositions — cash                |       | (9,809                                     | )          | (70,942 | ) |
| Total net capital   expenditures — cash     |       | 682,249                                    |       | 232,723 |   |
| Corporate acquisition —   non-cash          |       | —                                     |       | 595,891 |   |
| Property acquisitions —   non-cash          |       | 68,616                                     |       | — |   |
| Other — non-cash (3)                        |       | 20,000                                     |       | 12,187 |   |
| Total non-cash                                   |       | 88,616                                     |       | 608,078 |   |
| Total capital expenditures   — net (4)      |       | 770,865                                    |       | 840,801 |   |

 

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*(1) **Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the period.*

*(2) **Capital - corporate assets includes office leasehold improvements, furniture, fixtures and equipment before recoveries realized from landlord lease inducements.*

*(3) **Other includes non-cash adjustments for the current period’s decommissioning liabilities and share based compensation.*

*(4) **Total capital expenditures — net is considered to be a non-GAAP measure.  Total capital expenditures — net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.*

 

During the fourth quarter of 2014, Bellatrix continued the construction of the Bellatrix Alder Flats Plant.  The Bellatrix Alder Flats Plant will be developed in two phases with a total sales gas capacity of 220 mmcf/d.  Phase I of the Bellatrix Alder Flats Plant remains on schedule and on budget of $90 million for a July 2015 start-up, with $60.1 million total (including partners’ share) spent to date.

 

In the fourth quarter of 2014, Bellatrix completed the transfer at cost as at the transfer date of minority interests totaling 40% in the Bellatrix Alder Flats Plant and related pipeline infrastructure currently under construction to Keyera Partnership and O’Chiese Gas Plant GP Inc.  The total value of the minority interests transferred related to the Bellatrix Alder Flats Plant was $23.2 million, which reflected total actual costs incurred for the interest transferred as at the transfer date. The remainder of the value transferred during 2014 related to recently constructed pipeline infrastructure.

 

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Bellatrix’s $692.1 million capital program for the year ended December 31, 2014 was financed from a combination of funds flow from operations, bank debt, and net proceeds of $165.5 million from the June 5, 2014 common share bought-deal financing.

 

Based on the current economic conditions and Bellatrix’s operating forecast for 2015, the Company budgets a net capital program to not exceed $200 million funded from the Company’s cash flows and to the extent necessary, bank indebtedness.  The 2015 capital budget is expected to be directed primarily towards horizontal drilling and completions activities in the Cardium and Mannville formations and completion of Phase I of the Bellatrix Alder Flats Plant.

 

**Business Combinations**

 

Bellatrix completed multiple property acquisitions during 2014.  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 acquisitions individually and determined each of them to constitute business combinations 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.

 

For each of the property acquisitions described below, the estimated fair value of the property, plant and equipment acquired was determined using internal estimates and independent reserve evaluations. 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.  The fair value of identifiable assets acquired and liabilities assumed is final.

 

During the third quarter of 2014, Bellatrix closed an acquisition of production and working interests in certain facilities, as well as undeveloped land in the Ferrier area of Alberta for a cash purchase price of $13.9 million after adjustments.  $27.0 million of oil and natural gas properties, the value of which was determined using the present value of associated reserves, and $0.1 million of exploration and evaluation assets were acquired, in addition to $1.4 million of decommissioning liabilities assumed as a result of the acquisition.  A gain on property acquisition of $11.8 million was recognized in relation to the acquisition. The effective date of the transaction was September 1, 2014.

 

During the fourth quarter of 2014, Bellatrix completed a transaction for the acquisition of complementary assets within its core Alder Flats area of west central Alberta (greater Ferrier region) for total cash consideration of $118.0 million. The acquired assets consisted entirely of oil and natural gas properties, the value of which was determined using the present value of associated reserves.  No gain or loss on property acquisition was recognized in relation to the acquisition.  The effective date of the transaction was November 1, 2014.

 

Bellatrix completed an additional transaction during the fourth quarter of 2014 for 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.  $85.5 million of oil and natural gas properties, the value of which was determined using the present value of associated reserves, and $4.5 million of exploration and evaluation assets were acquired in addition to $0.1 million of decommissioning liabilities assumed as a result of the acquisition.  A gain on property acquisition of $56.8 million was recognized in relation to the acquisition.  The effective date of the transaction was September 1, 2014.

 

**Dispositions**

 

In the year ended December 31, 2014, a total net gain on dispositions of $52.3 million (2013: $11.2 million) was recognized relating to gains on wells drilled under the Grafton Joint Venture and the Troika Joint Venture which were completed and tied-in during 2014.  A gain on disposition for each well is recognized to account for the disposal of the pre-payout working interest earned by the joint venture partner on the well, which results from the difference between the percentage of all capital costs contributed for the drilling, completion, equipping and tie-in of the well by the joint venture partner and the pre-payout working interest allocated to the joint venture partner by the Company. The gain on disposition for a well is recognized during the quarter in which the well was completed and tied-in.

 

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Under the Grafton Joint Venture, Grafton contributes 82% of the total capital costs required for each well and in return earns 54% of Bellatrix’s WI in each well drilled in the well program until payout.

 

Under the Troika Joint Venture, Troika contributes 50% of the total capital costs required for each well and in return earns 35% of Bellatrix’s WI in each well drilled in the well program until payout.

 

**Decommissioning Liabilities**

 

At December 31, 2014, Bellatrix has recorded decommissioning liabilities of $88.6 million, compared to $67.1 million at December 31, 2013, for future abandonment and reclamation of the Company’s properties.  During the year ended December 31, 2014, decommissioning liabilities increased by a net $21.5 million as a result of $4.4 million incurred in relation to development activities, $3.1 million related to corporate asset acquisitions, $12.4 million resulting from changes in estimates, and $1.7 million as a result of charges for the unwinding of the discount rates used for assessing liability fair values, partially offset by a $0.1 million decrease related to working interest dispositions during the year.  The $12.4 million increase as a result of changes in estimates was primarily due to reduced market interest rates which resulted in decreases to discount rates applied to the valuation of liabilities between December 31, 2014 and December 31, 2013, as well as revisions to timing estimates of future decommissioning cash flows made to better reflect anticipated abandonment timelines.

 

**Liquidity and Capital Resources**

 

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

 

Bellatrix is focused on growing oil and natural gas production from its diversified portfolio of existing and emerging resource plays in Western Canada.  Bellatrix remains highly focused on key business objectives of maintaining financial strength and optimizing capital investments — which it seeks to attain through a disciplined approach to capital spending, a flexible investment program and financial stewardship. Natural gas prices are primarily driven by North American supply and demand, with weather being the key factor in the short term.  Bellatrix believes that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs.  Bellatrix’s results are affected by external market and risk factors, such as fluctuations in the prices of crude oil and natural gas, movements in foreign currency exchange rates and inflationary pressures on service costs.  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.

 

Even though the Company experienced continual operational success in 2014, volatility in oil and gas prices has resulted in a challenging environment for the energy sector. In response to this volatility and to preserve liquidity and capital resources, Bellatrix announced a reduction to its 2015 net capital budget to not exceed $200 million on January 29, 2015. This represents a 71% reduction from actual 2014 capital spending. Bellatrix has the ability to fund its 2015 capital program to not exceed $200 million by utilizing cash flow and to the extent necessary, bank indebtedness.  Bellatrix anticipates annual 2015 production growth of approximately 14% relative to estimated 2014 average production despite this reduced capital spending program. Bellatrix continues to focus on management of all aspects of capital, operating and general and administrative cost structures and commitment to ongoing risk management efforts to protect future cash flows and capital programs.

 

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 its credit

 

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facility financial covenants.  Bellatrix was fully compliant with all of its credit facility financial covenants as at December 31, 2014.

 

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

 

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

 

A substantial portion of Bellatrix’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks.  Bellatrix currently sells substantially all of its production to nine primary purchasers under standard industry sale and payment terms.  The most significant 60 day exposure to a single counterparty is approximately $16.6 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 mitigating its exposures to certain counterparties by obtaining financial assurances or reducing credit where it is deemed warranted and permitted under contractual terms.

 

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

 

In May 2014, Bellatrix filed the $750 million Shelf Prospectus with the securities regulatory authorities in each of the provinces of Canada (other than Quebec) and Registration Statement with the United States Securities and Exchange Commission. The $750 million Shelf Prospectus allows Bellatrix to offer and issue common shares, subscription receipts, warrants and units (comprising any combination of the foregoing securities), by way of one or more prospectus supplements at any time during the 25-month period that the $750 million Shelf Prospectus remains in place.

 

Pursuant to a prospectus supplement to the $750 million Shelf Prospectus, on June 5, 2014, Bellatrix closed a bought deal offering of 18,170,000 common shares of the Company at a price of $9.50 per common share for aggregate gross proceeds of $172.6 million through a syndicate of underwriters.  Net proceeds of $165.5 million received from the offering were utilized to temporarily reduce outstanding indebtedness under the Company’s credit facilities, thereby freeing up borrowing capacity that may be redrawn, from time to time, to fund the Company’s ongoing capital expenditure program and for general corporate purposes.

 

As at December 31, 2014, the Company has the ability to offer to sell up to an additional $577.4 million on the $750 million Shelf Prospectus.

 

Total net debt levels of $637.7 million at December 31, 2014 increased by $242.2 million from $395.5 million at December 31, 2013. The increase to total net debt was primarily due to capital expenditures for the year ended December 31, 2014 made as the Company executed its $692.1 million 2014 capital program.  Total net debt levels at December 31, 2014 include the net balance of an adjusted working capital deficiency of $87.9 million, which incorporated $76.4 million in advances from joint venture partners, the majority of which represents drilling obligations predominantly under the Company’s joint venture obligations with TCA and Grafton, and under the Daewoo and Devonian Partnership.

 

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Total net debt excludes unrealized commodity contract assets and liabilities, deferred taxes, finance lease obligations, deferred lease inducements and decommissioning liabilities.

 

Funds flow from operations represents 39% of the funding requirements for Bellatrix’s net capital expenditures for the year ended December 31, 2014.

 

As of December 31, 2014, the Company’s credit facilities are available on an extendible revolving term basis and consist of a $75 million operating facility provided by a Canadian bank and a $650 million syndicated facility provided by nine financial institutions, subject to a borrowing base test.

 

Amounts borrowed under the credit facilities will bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 0.8% to 3.75% (expanded to 4.75% in connection with recent amendments described below), depending on the type of borrowing and the Company’s senior debt to EBITDA ratio.  A standby fee is charged of between 0.405% and 0.84375% (expanded to 1.06875% in connection with recent amendments described below) on the undrawn portion of the credit facilities, depending on the Company’s senior debt to EBITDA ratio.  The credit facilities are secured by a $1 billion debenture containing a first ranking charge and security interest.  Bellatrix has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances.

 

The revolving period for the revolving term credit facility will end on May 30, 2017, unless extended for a further period of up to 3 years.  Should the facility not be extended, the outstanding balance is due upon maturity.  The borrowing base will be subject to re-determination on or before May 31 and November 30 in each year prior to maturity, with the next semi-annual redetermination occurring on or before May 31, 2015.

 

The Company’s credit facilities contain market standard terms and conditions, and include, for instance, restrictions on asset dispositions and hedging.  Generally, dispositions of properties to which the Company is given lending value in the determination of the borrowing base require lender approval if the NPV 10% value attributed to all properties sold in a fiscal year exceeds 5% of the borrowing base in effect at the time of such disposition. In addition, asset dispositions are generally not permitted unless there would be no borrowing base shortfall as a result of such properties being sold.  Hedging transactions must not be done for speculative purposes, and the term of any hedging contract cannot exceed 3 years for commodity swaps, interest rate or exchange rate swaps.  The aggregate amount hedged under all oil and gas commodity swaps cannot exceed 70% of the Company’s average daily sales volume for the first year of a rolling 3 year period, 60% for the second year of such period or 50% for the third year of such period, with the average daily sales volume being based on our production for the previous fiscal quarter.  The aggregate amount hedged under all interest rate swaps cannot exceed the outstanding principal amount of any unsecured note debt or have a term exceeding the remaining term of the unsecured note debt.  For interest rate swaps unrelated to any unsecured note debt, the aggregate amount hedged cannot exceed 60% of the amount of the commitment under the credit facilities or exceed a term of 3 years. The aggregate amount hedged under all exchange rate swaps cannot exceed the outstanding principal amount of any unsecured note debt or have a term exceeding the remaining term of the unsecured note debt.  For exchange rate swaps unrelated to any unsecured note debt, the aggregate amount hedged cannot exceed 60% of Bellatrix’s US dollar revenue over the previous 3 months or exceed a term of 3 years.

 

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Bellatrix’s credit facilities are subject to a number of covenants, all of which were met as at December 31, 2014.  Bellatrix calculates its financial covenants quarterly.  The calculation for each financial covenant is based on specific definitions, are not in accordance with IFRS and cannot be readily replicated by referring to Bellatrix’s Consolidated Financial Statements. As at December 31, 2014, the major financial covenants are:

 
| ** **                                                                                    | ** ** | **Position at December 31, 2014** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-------------------------------------------------------|------------|
| Total Debt(1) must not exceed 3.5 times EBITDA(2) for the last four fiscal quarters |       | 2.08                                                  | x          |
| Senior Debt(3) must not exceed 3.0 times EBITDA   for the last four fiscal quarters      |       | 2.08                                                  | x          |
| EBITDA must not be less   than 3.5 times interest expense for the last four fiscal quarters   |       | 14.97                                                 | x          |

 

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*(1) **“Total Debt” is defined as the sum of the bank loan, the principal amount of long-term debt and certain other liabilities defined in the agreement governing the credit facilities.*

*(2) **“EBITDA” refers to earnings before interest, taxes, depreciation and amortization. EBITDA is calculated based on terms and definitions set out in the agreement governing the credit facilities which adjusts net income for financing costs, certain specific unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month basis.*

*(3) **“Senior Debt” is defined as Total Debt, excluding any unsecured or subordinated debt. Bellatrix currently does not have any subordinated or unsecured debt.*

 

In the event of a material acquisition, the Total Debt to EBITDA and Senior Debt to EBITDA covenants are relaxed for two fiscal quarters after the close of the acquisition and must not exceed 4.0 and 3.5 times EBITDA, respectively.  Due to material acquisitions in the quarter ended December 31, 2014, the Total Debt to EBITDA and Senior Debt to EBITDA covenants were temporarily increased until June 30, 2015 to not exceed 4.0 and 3.5 times, respectively.

 

Effective March 11, 2015, the Company’s banking syndicate agreed to amendments to certain of the financial covenants in response to the recent decline in commodity prices.  The Total Debt to EBITDA and Senior Debt to EBITDA financial covenants have been revised such that they each must not exceed:

 

·             4.75 times for the fiscal quarters ending September 30, 2015, December 31, 2015, March 31, 2016 and June 30, 2016; and

 

·             4.0 times for the fiscal quarters ending September 30, 2016, December 31, 2016 and March 31, 2017.

 

During the periods in which these revised financial covenants are in place, the additional automatic relaxation of the debt to EBITDA financial covenants following a material acquisition will not apply.  Commencing with the second quarter of 2017, the maximum Senior Debt to EBITDA covenant will return to 3.0 times (3.5 times for the two fiscal quarters immediately following a material acquisition) and the maximum Total Debt to EBITDA covenant will return to 3.5  times (4.0 times for the two fiscal quarters immediately following a material acquisition).

 

The minimum EBITDA to interest expense ratio of 3.5 times remains unchanged.

 

As a corollary to these revised financial covenants, the applicable margin rate will range from 0.8% to 4.75%, depending on the type of borrowing and the Company’s Senior Debt to EBITDA ratio and the standby fee will range from 0.405% to 1.06875% on the undrawn portion of the credit facilities, depending on the Company’s Senior Debt to EBITDA ratio.

 

Failing a financial covenant may result in cancellation of the credit facilities and/or all or any part of the outstanding loans with all accrued and unpaid interest to be immediately due and payable.  Including $0.7 million of outstanding letters of credit that reduce the amount otherwise available to be drawn on the syndicated facility, as at December 31, 2014, approximately $174.5 million or 24% 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.

 

As at February 28, 2015, Bellatrix had outstanding a total of 10,785,170 options exercisable at an average exercise price of $6.29 per share and 191,957,243 common shares.

 

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**Commitments**

 

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

 

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

 
| **Joint Operating Agreement**            | ** ** | **Feb. 1, 2011** | ** ** | **Aug. 4, 2011** | ** ** | **Dec. 14, 2012** | ** ** |
|----------------------------------------------------|------------|----------------------------|------------|----------------------------|------------|-----------------------------|------------|
| Commitment Term                                    |       | 2011 to 2015               |       | 2011 to 2016               |       | 2014 to 2018                |       |
| Minimum wells per year *(gross and   net)*         |       | 3                          |       | 5 to 10                    |       | 2                           |       |
| Minimum total wells *(gross and   net)*            |       | 15                         |       | 40                         |       | 10                          |       |
| Estimated total cost *($millions)*                 |       | $                          | 56.3       |                       | $          | 150.0                       |       | $ | 37.5 |   |
| Remaining wells to drill at December 31, 2014 |       | 3                          |       | 1                          |       | 1                           |       |
| Remaining estimated total cost *($millions)*       |       | $                          | 11.3       |                       | $          | 3.8                         |       | $ | 3.8 |   |

 

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

 

During September 2014, the CNOR Joint Venture was formed with CNOR a non-operated oil and gas company managed by Grafton Asset Management Inc..  Through the joint venture, CNOR has committed $250 million in capital towards future accelerated development of a portion of Bellatrix’s undeveloped land holdings. Bellatrix is not currently subject to any formal well or cost commitments in relation to the CNOR Joint Venture.

 
| **Agreement**                                                  | ** ** | **Grafton**** (2)** | ** ** | **Daewoo and   Devonian** | ** ** | **Troika**** (3)** | ** ** |
|----------------------------------------------------------------|------------|--------------------------|------------|--------------------------------|------------|-------------------------|------------|
| Commitment Term                                                |       | 2013 to 2015             |       | 2013 to 2016                   |       | 2013 to 2015            |       |
| Minimum total wells *(gross)* (1)                              |       | 85                       |       | 70                             |       | 63                      |       |
| Minimum total wells *(net)* (1)                                |       | 16.9                     |       | 30.4                           |       | 31.5                    |       |
| Estimated total cost *($millions)   (gross)*(1)                |       | $                        | 305.0      |                           | $          | 200.0                   |       | $ | 240.0 |   |
| Estimated total cost *($millions)   (net)*   (1)               |       | $                        | 55.0       |                           | $          | 100.0                   |       | $ | 120.0 |   |
| Remaining wells to drill at December 31, 2014   *(gross)* |       | 38                       |       | 23                             |       | 7                       |       |
| Remaining wells to drill at December 31, 2014   *(net)*   |       | 7.7                      |       | 11.7                           |       | 3.5                     |       |
| Remaining estimated total cost *($millions) (gross)* (1)       |       | $                        | 156.2      |                           | $          | 94.9                    |       | $ | 28.7 |   |
| Remaining estimated total cost *($millions) (net)* (1)         |       | $                        | 31.3       |                           | $          | 47.4                    |       | $ | 14.4 |   |

 

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(1) *Gross and net estimated total cost values and gross and net minimum estimated total wells for the Troika and Grafton Joint Ventures represent Bellatrix’s total capital and well commitments pursuant to the Troika and Grafton joint venture agreements.  Gross and net minimum total wells for the Daewoo and Devonian Partnership represent Bellatrix’s total well commitments pursuant to the Daewoo and Devonian Partnership agreement.  Gross and net estimated total cost values for the Daewoo and Devonian Partnership represent Bellatrix’s estimated cost associated with its well commitments under the Daewoo and Devonian Partnership agreement. Remaining estimated total cost (gross) for the Daewoo and Devonian Partnership is based on initial Daewoo Devonian Partnership gross capital divided by initial total gross capital including third parties.*

 

*(2) **During April 2014, Grafton elected to exercise an option to increase committed capital investment to the Grafton Joint Venture established during 2013 by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions as the previously announced Grafton Joint Venture. Specific well commitments associated with the increase have been incorporated into the commitments table.*

 

*(3) **The commitment term of the Troika Joint Venture has been extended to 2015 for the 7 gross (3.5 net) wells remaining to be drilled.*

 

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| **Liabilities ($000s)**                 | ** ** | **Total** | ** ** | **< 1 Year** | ** ** | **1-3 Years** | ** ** | **3-5 Years** | ** ** | **More than    5 years** | ** ** |
|----------------------------------------------|------------|-----------|------------|---------------------------|------------|--------------------|------------|--------------------|------------|-----------------------------------------|------------|
| Accounts payable and accrued liabilities (1) |       | $         | 154,094    |                      | $          | 154,094            |       | $                  | —     |                                    | $          | — |   | $ | — |   |
| Advances from joint venture partners         |       | 76,388    |       | 76,388                    |       | —             |       | —             |       | —                                  |       |
| Long-term debt — principal (2)          |       | 549,792   |       | —                    |       | 549,792            |       | —             |       | —                                  |       |
| Decommissioning liabilities (3)              |       | 88,605    |       | —                    |       | 776                |       | 3,653              |       | 84,176                                  |       |
| Finance lease obligation                     |       | 11,637    |       | 1,574                     |       | 3,172              |       | 1,645              |       | 5,246                                   |       |
| Deferred lease inducements                   |       | 3,067     |       | 340                       |       | 680                |       | 680                |       | 1,367                                   |       |
| Total                                        |       | $         | 883,583    |                      | $          | 232,396            |       | $                  | 554,420    |                                    | $          | 5,978 |   | $ | 90,789 |   |

 

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*(1) **Includes $0.8 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 three year facility, fully revolving until maturity, and extendable annually at the Company’s option (subject to lender approval), provided that the term after any extension would not be more than three years.  Interest due on the bank credit facility is calculated based upon floating rates.*

*(3) ** Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over the life of the Company’s properties (between 2018 and 2065).*

 

**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, 2014.

 

The Company’s commitment for office space as at December 31, 2014 is as follows:

 
| **($000s)   Year**  | ** ** | **Gross   Amount** | ** ** | **Recoveries** | ** ** | **Net amount** | ** ** |
|---------------------|------------|--------------------|------------|----------------|------------|---------------------|------------|
| 2015                |       | 6,238              |       | (850           | )          | 5,388               |       |
| 2016                |       | 6,195              |       | (904           | )          | 5,291               |       |
| 2017                |       | 6,185              |       | (904           | )          | 5,281               |       |
| 2018                |       | 5,884              |       | (828           | )          | 5,056               |       |
| 2019                |       | 4,983              |       | —         |       | 4,983               |       |
| More   than 5 years |       | 20,413             |       | —         |       | 20,413              |       |

 

**Business Prospects and 2015 Year Outlook**

 

Bellatrix continues to develop its core assets and conduct exploration programs utilizing its large inventory of geological prospects in conjunction with infrastructure investments made through 2014 and continuing into 2015.

 

Looking ahead, 2015 represents a transformational year for the Company given the strategic infrastructure investment made over the past several years.  The decision to build, maintain, and control operatorship of key strategic infrastructure remains critical to the Company’s long term sustainability and growth objectives. In response to continued capricious behavior of oil and gas prices, Bellatrix announced on January 29, 2015 an updated 2015 net capital budget to not exceed $200 million. Bellatrix will revisit its capital budget on a continuous basis, will strategically review all sources and costs of capital available to the Company including monetization of assets, and will further curtail capital spending, if necessary, in order to preserve its balance sheet until commodity prices firmly recover.

 

Despite current commodity price headwinds, the Company maintains focus on profitability for our shareholders.  Drilling and completion capital is focused principally on drilling Spirit River liquids rich natural gas wells that deliver superior rates of return at current commodity prices. The Company’s differentiated joint venture strategy provides additional insulation

 

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from weak commodity prices given the enhanced economic returns and improved capital efficiencies achieved from spending under these funding transactions.  Bellatrix expects to access up to $85 million of joint venture capital in 2015 pursuant to its existing joint venture arrangements.

 

The Company is also focused on the execution of Phase 1 of the Bellatrix Alder Flats Plant.  Phase 1 of the aforementioned Bellatrix Alder Flats Plant is on budget and is anticipated to be on-stream on or before July 1, 2015. Bellatrix anticipates significant benefits from our infrastructure investment including the ability to grow unfettered with improved operational reliability, increased revenue from enhanced liquids extraction, and reduced operating costs.

 

With three year proved plus probable FD&A costs averaging $10.05/boe, Bellatrix continues to demonstrate its efficacy as a low cost finder and producer of hydrocarbons.  The Company continues to drive production down costs, reducing its already low cost profile by 6% in 2014 to $8.23/boe after removing one-time adjustments, with further cost reductions expected in 2015.  Finally, Bellatrix recognized a 10% reduction in G&A costs in 2014 to $1.83/boe, and remains acutely focused on continued cost containment in all areas of its business.

 

Despite the reduction in spending year over year, the Company is positioned to deliver full year annual average production growth of 14% in 2015.  Additionally, the Company has seen service cost reductions in its 2015 activities by up to 15% in some areas, which provide further potential benefits not currently captured in our $200 million budget.

 

**2015 Guidance**

 
| ** **                                                              | ** ** | **2015 Forecast** | ** ** |
|-------------------------------------------------------------------------|------------|------------------------|------------|
| Average daily production (boe/d)                                        |       |                   |       |
| Low range                                                               |       | 43,000                 |       |
| High range                                                              |       | 44,000                 |       |
| Average product mix                                                     |       |                   |       |
| Crude oil, condensate and   NGLs (%)                                    |       | 33                     |       |
| Natural gas (%)                                                         |       | 67                     |       |
| Capital spending ($ millions)*(1) *                           |       | 200                    |       |
| Expenses ($/boe)                                                        |       |                   |       |
| Production                                                              |       | 8.25                   |       |
| General and administrative   (after capitalized G&A and recoveries) |       | 1.50                   |       |

 

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*(1) **Capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions.*

 

**Financial Reporting Update**

 

**Future Accounting Pronouncements**

 

The following pronouncements from the International Accounting Standards Board (“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, 2018 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 15 - “Revenue from Contracts with Customers”, which provides a five-step model to be applied to all contracts formed with customers.  The standard specifies when an entity will recognize revenue and provides guidance regarding disclosures relating to revenue recognition.  IFRS 15 will apply to annual reporting periods beginning on or after January 1, 2017.  The extent of the impact of the adoption of IFRS 15 has not yet been determined.

 

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**Business Risks and Uncertainties**

 

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:

 

·                  financial risks, which includes commodity price risk and risks related to the Company’s financing arrangements;

 

·                  finding and developing oil and natural gas reserves at economic costs; and

 

·                  operational risks such as risks related to health and safety, transportation and processing restrictions, project execution and the environment.

 

A description of the risk factors and uncertainties affecting Bellatrix can be found under the heading “Forward Looking Statements” and a full discussion of the material risk factors affecting Bellatrix can be found in our annual information form for the year ended December 31, 2014, which may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix’s website (www.bellatrixexploration.com).

 

The following explains how material risks and uncertainties impact our business:

 

**Prices, Markets and Marketing**

 

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Company.  These factors include economic conditions, in the United States, Canada and Europe, the actions of OPEC, governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign supply and demand of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources.  Prices for oil and natural gas are also subject to the availability of foreign markets and the Company’s ability to access such markets. Oil prices are expected to remain volatile and may decline in the near future as a result of global excess supply due to the increased growth of shale oil production in the United States, the decline in global demand for exported crude oil commodities, and OPEC’s recent decisions pertaining to the oil production of OPEC member countries, among other factors. A material decline in prices could result in a reduction of the Company’s net production revenue.  The economics of producing from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes of the Company’s reserves.  The Company might also elect not to produce from certain wells at lower prices.

 

All these factors could result in a material decrease in the Company’s expected net production revenue and a reduction in its oil and natural gas acquisition, development and exploration activities.  Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the Company’s carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions, and sanctions imposed on certain oil producing nations by other countries and ongoing credit and liquidity concerns.  Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value.  Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

 

**Credit Facility Arrangements**

 

The Company currently has a syndicated credit facility and the amount authorized thereunder is dependent on the borrowing base determined by its lenders.  The Company 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

 

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funding. As discussed herein, as a result of the recent precipitous drop in crude oil prices and the concomitant reduction in the Company’s associated future cash flow and EBITDA, the Company sought and obtained from its lenders temporary relaxation of certain of these financial covenants under its credit facilities. In the event that the Company is not able to comply with these covenants, as amended, the banking syndicate may not be willing to agree to a further amendment to the financial covenants and as a result the Company’s access to capital could be restricted or repayment could be required.

 

Even if the Company is able to obtain new financing, it may not be on commercially reasonable terms or terms that are acceptable to the Company.  If the Company is unable to repay amounts owing under credit facilities, the lenders under the credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.  The acceleration of the Company’s indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions.  In addition, the Company’s credit facilities may impose operating and financial restrictions on the Company that could include restrictions on, the payment of dividends, repurchase or making of other distributions with respect to the Company’s securities, incurring of additional indebtedness, the provision of guarantees, the assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among others.

 

The Company’s lenders use the Company’s reserves, commodity prices, applicable discount rate and other factors, to periodically determine the Company’s borrowing base.  A further material decline in commodity prices could reduce the Company’s borrowing base, reducing the funds available to the Company under the credit facility. This could result in the requirement to repay a portion, or all, of the Company’s bank indebtedness.

 

**Exploration, Development and Production Risks**

 

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves.  Without the continual addition of new reserves, the Company’s existing reserves, and the production from them, will decline over time as the Company produces from such reserves.  A future increase in the Company’s reserves will depend on both the ability of the Company to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects.  There is no assurance that the Company will be able continue to find satisfactory properties to acquire or participate in.  Moreover, management of the Company may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participations uneconomic.  There is also no assurance that the Company will discover or acquire further commercial quantities of oil and natural gas.

 

Future oil and natural gas exploration may involve unprofitable efforts from dry wells as well as from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs.  Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.

 

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells.  Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, and shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.  While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

 

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards.  These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property, the environment and personal injury.  Particularly, the Company may explore for and produce sour natural gas in certain areas.  An unintentional leak of sour natural gas could result in

 

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personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Company.

 

Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations.  Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

As is standard industry practice, the Company is not fully insured against all risks, nor are all risks insurable.  Although the Company maintains liability insurance in an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered.  In either event the Company could incur significant costs.

 

**Gathering and Processing Facilities and Pipeline Systems**

 

The Company delivers its products through gathering and processing facilities and pipeline systems some of which it does not own. The amount of oil and natural gas that the Company can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities and pipeline systems. In 2014, the Company’s production was constrained due to lack of processing facilities in the Company’s area of operations. Although the Company has taken steps to reduce the risk of constraints in production due to lack of processing capacity, further constraints in production could be experienced. The lack of availability of capacity in any of the gathering and pipeline systems, and in particular the processing facilities, could result in the Company’s inability to realize the full economic potential of its production or in a reduction of the price offered for the Company’s production. Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas. Furthermore, producers are increasingly turning to rail as an alternative means of transportation. In recent years, the volume of crude oil shipped by rail in North America has increased dramatically and it is projected to continue in this upward trend.  Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Company’s business and, in turn, the Company’s financial condition, results of operations and cash flows.

 

A portion of the Company’s production may, from time to time, be processed through facilities owned by third parties and over which the Company does not have control. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could have a materially adverse effect on the Company’s ability to process its production and deliver the same for sale.

 

**Additional Funding Requirements**

 

The Company’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times and from time to time, the Company may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities.  There is risk that if the economy and banking industry experienced unexpected and/or prolonged deterioration, the Company’s access to additional financing may be affected.

 

Because of global economic volatility and the current volatility of oil and gas prices, the Company may from time to time have restricted access to capital and increased borrowing costs.  Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations.  If the Company’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Company’s ability to expend the necessary capital to replace its reserves or to maintain its production.  To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Company’s ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result.  In addition, the future development of the Company’s petroleum properties may require additional financing and

 

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there are no assurances that such financing will be available or, if available, will be available upon acceptable terms.  Failure to obtain any financing necessary for the Company’s capital expenditure plans may result in a delay in development or production on the Company’s properties.

 

**Environmental**

 

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.  Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations.  In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites.

 

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.  The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge.  Although the Company believes that it will be in material compliance with current applicable environmental legislation, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

**Hedging**

 

From time to time, the Company may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline.  However, to the extent that the Company engages in price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk.  In addition, the Company’s hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:

 

·                                          production falls short of the hedged volumes or prices fall significantly lower than projected;

·                                          there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the hedge arrangement;

·                                          the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those arrangements; or

·                                          a sudden unexpected event materially impacts oil and natural gas prices.

 

Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United States dollars or other currencies in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the Company will not benefit from the fluctuating exchange rate.

 

**Critical Judgments and Accounting Estimates**

 

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

 

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

 

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**Critical Accounting Judgments**

 

***Oil and gas reserves***

 

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

 

***Identification of CGUs***

 

Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of its assets.

 

***Impairment Indicators***

 

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

 

***Joint Arrangements***

 

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

 

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

 

**Critical Estimates and Assumptions**

 

***Recoverability of asset carrying values***

 

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

 

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

 

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

 

***Decommissioning obligations***

 

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

 

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***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 monitors known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances.

 

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

 

**Controls and Procedures**

 

**Disclosure Controls and Procedures**

 

The Company’s President and Chief Executive Officer (“CEO”) and Executive Vice President, Finance and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings , interim filings ( as these terms are defined in National Instrument 52-109, *Certification of Disclosure in Issuers’ Annual and Interim Filings* (“NI 52-109”))  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 as defined in Rules 13(a) - 15(e) and 15d — 15(e) under the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), and National Instrument 52-109, Certification of Disclosure in Issuer’s Annual and Interim Filings (“NI 52-109”), the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company. Based on the evaluation, the officers concluded that Bellatrix’s disclosure controls and procedures were effective as at December 31, 2014.

 

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**Management’s Annual Report on Internal Control over Financial Reporting**

 

Management is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting, as defined in Rules 13(a) — 15(f) and 15(d) — 15(f) under both the Securities Exchange Act of 1934 and NI 52-109, as amended.  Internal control over the Company’s financial reporting is a process designed by, or designed under the supervision of, our President and CEO and our Executive Vice President, Finance and CFO, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for the external purposes in accordance with GAAP.

 

Under the supervision and with the participation of management, including our CEO and our CFO, an evaluation of the effectiveness of the Company’s internal control over financial reporting was conducted as of December 31, 2014 based on the criteria described in *“Internal Control — Integrated Framework (2013)”* issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this assessment, management determined that, as of December 31, 2014, the Company’s internal control over financial reporting was effective.

 

The Company is required to disclose herein any change in the Company’s internal control over financial reporting that occurred during the year ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.  Bellatrix acquired Angle on December 11, 2013.  The Company completed the integration of Angle’s operations during 2014, and expanded its internal controls over financial reporting compliance program to incorporate those operations.  With the exception of the integration of Angle there has been no change in the Company’s internal control over financial reporting that occurred during the year ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

The effectiveness of internal control over financial reporting as of December 31, 2014 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Independent Auditors’ Report of Registered Public Accounting Firm, which is included with the consolidated financial statements for the year ended December 31, 2014.

 

**Limitations of the Effectiveness of Controls**

 

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

 

**CEO and CFO Certifications**

 

The Company’s President and CEO and the Executive Vice President, Finance and CFO have attested to the quality of the public disclosure in our fiscal 2014 reports filed with the Canadian securities regulators and the SEC, and have filed certifications with them.

 

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**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 2014 and average production volumes of 42,945 boe/d during that period, as well as the same level of debt outstanding as at December 31, 2014.  Diluted weighted average shares are based upon the fourth quarter of 2014.  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                    |       | 4,100                                                      |       | 0.02                                                       |       |
| Change of $0.10/ mcf                       |       | 5,900                                                      |       | 0.03                                                       |       |
| Change of US $0.01 CDN/ US   exchange rate |       | 1,600                                                      |       | 0.01                                                       |       |
| Change in prime of 1%                      |       | 5,500                                                      |       | 0.03                                                       |       |

 

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*(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.*

 

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**Selected Quarterly Consolidated Information**

 

The following table sets forth selected consolidated financial information of the Company for the quarters in 2014 and 2013.

 
| **2014 — Quarter ended (unaudited)****($000s, except per share amounts)** | ** ** | **March 31** | ** ** | **June 30** | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|------------------|------------|-------------------|------------|------------------|------------|
| Revenue (before royalties and risk management)                                                                         |       | 163,585           |       | 152,311          |       | 137,411           |       | 130,160          |       |
| Cash flow from operating activities                                                                                    |       | 84,300            |       | 60,063           |       | 60,006            |       | 90,459           |       |
| Cash flow from operating activities per share                                                                          |       |              |       |             |       |              |       |             |       |
| Basic                                                                                                                  |       | $                 | 0.49       |             | $          | 0.34              |       | $                | 0.31       |   | $ | 0.47 |   |
| Diluted                                                                                                                |       | $                 | 0.48       |             | $          | 0.33              |       | $                | 0.31       |   | $ | 0.47 |   |
| Funds flow from operations (1)                                                                                         |       | 77,642            |       | 71,014           |       | 60,341            |       | 61,757           |       |
| Funds flow from operations per share (1)                                                                               |       |              |       |             |       |              |       |             |       |
| Basic                                                                                                                  |       | $                 | 0.45       |             | $          | 0.40              |       | $                | 0.32       |   | $ | 0.32 |   |
| Diluted                                                                                                                |       | $                 | 0.45       |             | $          | 0.39              |       | $                | 0.31       |   | $ | 0.32 |   |
| Net profit                                                                                                             |       | 25,167            |       | 38,252           |       | 44,874            |       | 54,830           |       |
| Net profit per share                                                                                                   |       |              |       |             |       |              |       |             |       |
| Basic                                                                                                                  |       | $                 | 0.15       |             | $          | 0.22              |       | $                | 0.23       |   | $ | 0.29 |   |
| Diluted                                                                                                                |       | $                 | 0.14       |             | $          | 0.21              |       | $                | 0.23       |   | $ | 0.29 |   |
| Total net capital expenditures - cash                                                                                  |       | 155,863           |       | 125,955          |       | 167,790           |       | 232,641          |       |

 
| **2013 — Quarter ended (unaudited)****($000s, except per share amounts)** | ** ** | **March 31** | ** ** | **June 30** | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|------------------|------------|-------------------|------------|------------------|------------|
| Revenue (before royalties and risk management)                                                                         |       | 65,543            |       | 74,564           |       | 68,329            |       | 83,455           |       |
| Cash flow from operating activities                                                                                    |       | 35,527            |       | 29,611           |       | 25,295            |       | 38,025           |       |
| Cash flow from operating activities per share                                                                          |       |              |       |             |       |              |       |             |       |
| Basic                                                                                                                  |       | $                 | 0.33       |             | $          | 0.27              |       | $                | 0.23       |   | $ | 0.30 |   |
| Diluted                                                                                                                |       | $                 | 0.30       |             | $          | 0.25              |       | $                | 0.22       |   | $ | 0.29 |   |
| Funds flow from operations (1)                                                                                         |       | 37,545            |       | 36,563           |       | 30,002            |       | 39,349           |       |
| Funds flow from operations per share (1)                                                                               |       |              |       |             |       |              |       |             |       |
| Basic                                                                                                                  |       | $                 | 0.35       |             | $          | 0.34              |       | $                | 0.28       |   | $ | 0.31 |   |
| Diluted                                                                                                                |       | $                 | 0.32       |             | $          | 0.31              |       | $                | 0.25       |   | $ | 0.30 |   |
| Net profit                                                                                                             |       | 4,561             |       | 15,466           |       | 29,453            |       | 22,195           |       |
| Net profit per share                                                                                                   |       |              |       |             |       |              |       |             |       |
| Basic                                                                                                                  |       | $                 | 0.04       |             | $          | 0.14              |       | $                | 0.27       |   | $ | 0.17 |   |
| Diluted                                                                                                                |       | $                 | 0.04       |             | $          | 0.13              |       | $                | 0.25       |   | $ | 0.17 |   |
| Total net capital expenditures - cash                                                                                  |       | 91,614            |       | 46,699           |       | 49,452            |       | 99,199           |       |

 

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

 

Bellatrix’s 2014 quarterly results were positively impacted by an overall 74% increase in production resulting from the success of Bellatrix’s 2014 drilling program, additional sales volumes realized through the December 2013 acquisition of Angle, and higher natural gas prices realized during the 2014 quarters compared to the 2013 quarters.

 

Fourth quarter 2014 results are compared in detail to fourth quarter 2013 results throughout this MD&A.

 

During the third quarter of 2014, Bellatrix completed several asset acquisitions including a tuck-in acquisition of working interests.  In the third quarter of 2014, the Company incurred $167.8 million of net cash capital expenditures, compared to $49.5 million in the third quarter of 2013, and drilled or participated in 35 gross (17.5 net) wells, compared to 19 gross (8.6 net) wells in the third quarter of 2013.  Bellatrix realized a 73% increase in sales volumes from 21,852 boe/d in the third quarter of 2013 to 37,838 boe/d in the comparative 2014 period.  Bellatrix’s revenue before other income, royalties and commodity price risk management contracts increased by 99% to $134.6 million in the third quarter of 2014 from $67.7 million in the comparative quarter in 2013 as a result of the increase in sales volumes between the quarters, in conjunction with higher natural gas prices which were partially offset by reduced crude oil and NGL commodity prices realized in the 2014 third quarter.

 

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In the second quarter of 2014, Grafton elected to exercise an option to increase committed capital under the Grafton Joint Venture by $50 million, resulting in a total commitment of $250 million at the end of that quarter.  In addition to the expansion of the Grafton Joint Venture, the Company experienced additional successes through the $172.6 million bought deal financing, the expansion of its borrowing base and credit facilities to $625 million from $500 million, and the commissioning of the Blaze Pipeline on April 1, 2014.  Bellatrix’s net cash capital spending in the second quarter of 2014 totaled $134.6 million, compared to $46.7 million during the comparative 2013 period.  During the second quarter of 2014, the Company drilled or participated in 19 gross (9.0 net) wells, compared to 5 gross (5.0 net) wells in the same quarter of 2013 and realized a 64% increase in sales volumes to 36,342 boe/d in the second quarter of 2014 from 22,102 boe/d in the second quarter of 2013.  The Company realized revenue before other income, royalties and commodity price risk management contracts of $151.2 million in the second quarter of 2014, an increase of 104% from $74.0 million in the comparative quarter in 2013.  The increased revenue was the result of the increase in sales volumes between the second quarters of 2013 and 2014, in conjunction with higher realized natural gas, crude oil and NGL prices realized in the second quarter of 2014 compared to the second quarter of 2013.

 

During the first quarter of 2014, Bellatrix’s net cash capital expenditures totaled $155.6 million, compared to $91.6 million in the first quarter of 2013.  The Company drilled or participated in 44 gross (25.6 net) wells in the first quarter of 2014, compared to 21 gross (17.1 net) wells in the comparative 2013 quarter.  Sales volumes increased by 81% to 35,049 boe/d from 19,343 boe/d between the 2013 and 2014 first quarters. The Company’s revenue before other income, royalties and commodity price risk management contracts increased by 149% to $161.7 million in the first quarter of 2014 from $64.9 million in the comparative quarter in 2013 as a result of the increase in sales volumes between the quarters, in conjunction with higher realized crude oil, NGL, and natural gas commodity prices.

 

Overall, the Company’s cash flows were positively impacted primarily due to significantly increased sales volumes and cash flows resulting from the success and execution of the Company’s 2014 drilling program in addition to volumes realized from the December 2013 acquisition of Angle, and stronger natural gas prices.

 

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**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, 2014 and for comparative 2013 and 2012 years.

** **
| **Years ended December 31,   ($000s, except per share amounts) ** | ** ** | **2014**  | ** ** | **2013**  | ** ** | **2012** | ** ** |
|-----------------------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|----------|------------|
| Revenues (before royalties and risk management)                                                           |       | 583,467   |       | 291,891   |       | 219,314  |       |
| Funds flow from operations (1)                                                                            |       | 270,753   |       | 143,459   |       | 111,038  |       |
| Funds flow from operations per share (1)                                                                  |       |      |       |      |       |     |       |
| Basic                                                                                                     |       | $         | 1.48       |      | $          | 1.27     |       | $ | 1.03 |   |
| Diluted                                                                                                   |       | $         | 1.46       |      | $          | 1.24     |       | $ | 0.96 |   |
| Cash flow from operating activities                                                                       |       | 294,828   |       | 128,458   |       | 109,328  |       |
| Cash flow from operating activities per share                                                             |       |      |       |      |       |     |       |
| Basic                                                                                                     |       | $         | 1.61       |      | $          | 1.14     |       | $ | 1.02 |   |
| Diluted                                                                                                   |       | $         | 1.59       |      | $          | 1.11     |       | $ | 0.95 |   |
| Net profit                                                                                                |       | 163,123   |       | 71,675    |       | 27,771   |       |
| Net profit per share                                                                                      |       |      |       |      |       |     |       |
| Basic                                                                                                     |       | $         | 0.89       |      | $          | 0.63     |       | $ | 0.26 |   |
| Diluted                                                                                                   |       | $         | 0.88       |      | $          | 0.62     |       | $ | 0.25 |   |
| Total net capital   expenditures — cash                                                              |       | 682,249   |       | 232,723   |       | 178,688  |       |
| Total assets                                                                                              |       | 2,213,486 |       | 1,555,180 |       | 681,421  |       |
| Total net debt (1)                                                                                        |       | 637,726   |       | 395,482   |       | 189,577  |       |
| Non-current financial liabilities                                                                         |       |      |       |      |       |     |       |
| Future income taxes                                                                                       |       | 81,585    |       | 27,034    |       | —   |       |
| Decommissioning liabilities                                                                               |       | 88,605    |       | 67,075    |       | 43,909   |       |
| Sales volumes (boe/d)                                                                                     |       | 38,065    |       | 21,829    |       | 16,686   |       |

 

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

 

Detailed discussions of 2014 annual results by comparison to 2013 annual results are contained throughout this MD&A.

 

Bellatrix expanded its operations significantly between 2012 and 2013 through the continued success of its internal drilling program in conjunction with the completion of several major transactions. The Company closed the Grafton Joint Venture, formed the Daewoo and Devonian Partnership, and closed the Troika Joint Venture during 2013.  On November 5, 2013, Bellatrix closed a bought deal financing of 21,875,000 Bellatrix common shares at a price of $8.00 per Bellatrix Share for aggregate gross proceeds of $175.0 million (net proceeds of $165.7 million after transaction costs) through a syndicate of underwriters.  On December 11, 2013, Bellatrix acquired all of the issued and outstanding common shares of Angle for consideration consisting of $69.7 million in cash and approximately 30.2 million Bellatrix common shares.

 

Bellatrix’s net cash capital expenditures increased to $840.8 million during 2013 compared to $204.6 million in 2012.  During 2013, Bellatrix drilled or participated in 80 gross (52.8 net) wells, compared to 34 gross (26.3 net) wells in 2012.  Sales volumes increased by 31% between the years to 21,829 boe/d in 2013 from 16,686 boe/d in 2012 due to the transactions noted above as well as Bellatrix’s continued drilling success achieved throughout 2013. As a result of the increase in sales volumes as well as higher realized prices for all commodities between the years, revenues before other income, royalties and risk management increased to $288.3 million in 2013, compared to $217.1 million realized in 2012.

 

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