Exhibit 99.2
MANAGEMENT’S DISCUSSION AND ANALYSIS
March 12, 2014 – The following Management’s Discussion and Analysis of financial results (“MD&A”) as provided by the management of Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) should be read in conjunction with the audited consolidated financial statements of the Company for the years ended December 31, 2013 and 2012. This commentary is based on information available to, and is dated as of, March 12, 2014. The financial data presented is in Canadian dollars, except where indicated otherwise.
CONVERSION: The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe conversions in this report are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.
INITIAL PRODUCTION RATES: Initial production rates disclosed herein may not necessarily be indicative of long-term performance or ultimate recovery.
NET ASSET VALUE: Net asset value is calculated based on the Sproule evaluation as at December 31, 2013 of future net revenue of the Company’s proved plus probable reserves before tax discounted at 10%, which does not represent fair market value and does not take into account possible reserve additions from reinvestment of cash flow in existing properties. Net asset value per share is determined using the basic weighted average number of shares outstanding at December 31, 2013 of 112,927,251.
ADDITIONAL GAAP MEASURES: This Management’s Discussion and Analysis and the accompanying report to shareholders and financial statements contain the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than “cash flow from operating activities” as determined in accordance with generally accepted accounting principles (“GAAP”) as an indicator of the Company’s performance. Therefore reference to funds flow from operations or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found in this Management’s Discussion and Analysis. Funds flow from operations per share is calculated using the weighted average number of shares for the period.
This Management’s Discussion and Analysis and the accompanying report to shareholders and financial statements also contain the terms total net debt and net debt. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. Management believes these measures are useful supplementary measures of the total amount of current and long-term debt.
NON-GAAP MEASURES: This Management’s Discussion and Analysis and the accompanying report to shareholders also contains the terms of operating netbacks and total capital expenditures - net, which are not recognized measures under GAAP. Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from revenues before other income. Management believes this measure is a useful supplemental measure of the amount of revenues received after transportation, royalties and operating expenses. Readers are cautioned, however, that this measure should not be construed as an alternative to net profit or loss determined in accordance with GAAP as a measure of performance. Bellatrix’s method of calculating this measure may differ from other entities, and accordingly, may not be comparable to measures used by other companies. Total capital expenditures – net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.
JOINT ARRANGEMENTS: Bellatrix is a partner of the following joint arrangements, which have been classified under IFRS as joint operations. This classification is on the basis that the arrangement is not conducted through a separate legal entity and the partners are legally obligated to pay their share of costs incurred and take their share of output produced from the various production areas. For purposes of disclosure throughout the MD&A and financial statements, Bellatrix has referred to these arrangements by the common oil and gas industry term of joint ventures.
GRAFTON JOINT VENTURE – Bellatrix has a joint venture (the “Grafton Joint Venture”) with Grafton Energy Co I Ltd. (“Grafton”) in the Willesden Green and Brazeau areas of West-Central Alberta, whereby Grafton will contribute 82% or $200 million to the joint venture to participate in an expected 58 Notikewin/Falher and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix’s working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix's working interest ("WI") after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty (“GORR”) on Bellatrix’s pre-Grafton Joint Venture WI.
DAEWOO AND DEVONIAN PARTNERSHIP – Bellatrix has a joint venture arrangement (the “Daewoo and Devonian Partnership”) with Canadian subsidiaries of two Korean entities, Daewoo International Corporation (“Daewoo”) and Devonian Natural Resources Private Equity Fund (“Devonian”) in the Baptiste area of West-Central Alberta, whereby Daewoo and Devonian own a combined 50% working interest share of producing assets, an operated compressor station and gathering system and related land acreage.
TROIKA JOINT VENTURE – Bellatrix has a joint venture (the “Troika Joint Venture”) with TCA Energy Ltd. ("TCA") in the Ferrier Cardium area of West-Central Alberta, whereby Troika will contribute 50% or $120 million towards a capital program for drilling of an expected 63 gross wells and will receive a 35% working interest until payout (being recovery of TCA's capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's working interest.
Additional information relating to the Company, including the Bellatrix’s Annual Information Form, is available on SEDAR at www.sedar.com.
FORWARD LOOKING STATEMENTS: Certain information contained herein and in the accompanying report to shareholders may contain forward looking statements including management’s assessment of future plans, operations and strategy, drilling plans and the timing thereof, commodity price risk management strategies, 2014 capital expenditure budget, the nature of expenditures and the method of financing thereof, anticipated liquidity of the Company and various matters that may impact such liquidity, expected 2014 operating expenses and general and administrative expenses, expected costs to satisfy drilling commitments and method of funding drilling commitments, commodity prices and expected volatility thereof, estimated amount and timing of incurring decommissioning liabilities, the Company’s drilling inventory and capital required therefor, estimated capital expenditures and wells to be drilled under joint venture agreements, the ability to fund the 2014 capital expenditure program utilizing various available sources of capital, expected 2014 average daily production and exit rate, plans to continue commodity risk management strategies and timing of redetermination of borrowing base and plans for additional facilities and infrastructure and timing thereof may constitute forward-looking statements under applicable securities laws. Forward-looking statements necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix’s future operations. Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products.
Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could effect Bellatrix’s operations and financial results are included in reports on file with Canadian and US securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix’s website (www.bellatrixexploration.com). Furthermore, the forward-looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.
Overview and Description of the Business
Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) is a western Canadian based growth oriented oil and gas company engaged in the exploration for, and the acquisition, development and production of oil and natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan.
Common shares of Bellatrix trade on the Toronto Stock Exchange (“TSX”) and on the NYSE MKT under the symbol BXE.
2013 Transactions
Acquisition of Angle Energy Inc.
On December 11, 2013, Bellatrix acquired all issued and outstanding common shares of Angle Energy Inc. (“Angle”) for the consideration consisting of $69.7 million in cash and the issuance of 30,230,998 Bellatrix common shares. Bellatrix also acquired for cancellation all of the issued and outstanding 5.75% convertible unsecured subordinated debentures of Angle with a maturity date of January 31, 2016 (the “Angle Debentures”) in the aggregate principal amount of $60.0 million on the basis of $1,040 in cash per $1,000 principal amount of the Angle Debentures or $62.4 million total, plus total accrued and unpaid interest of approximately $1.3 million. Bellatrix’s financial and operating results for the year ended December 31, 2013 include financial and operating results from Angle for the period from December 11, 2013 to December 31, 2013.
The acquisition of Angle resulted in the combination of Bellatrix’s top-tier asset base with Angle's high quality, low-cost, high working interest asset base to create one of the largest intermediate producers in the West Central Alberta fairway, with a dominant and highly focused position in the Cardium and Mannville intervals. The strategic combination was considered by Bellatrix to be highly complementary and accretive to Bellatrix in terms of current production, cash flow, reserves, and net asset value per share. The combination resulted in a high growth intermediate company with a sizeable, strategic and opportunity rich asset base with a drillable inventory of over 2,000 locations ($10 billion capital investment at current cost per well) and with 416,631 net undeveloped acres.
Bought Deal Financing
On November 5, 2013, Bellatrix closed a bought deal financing of 21,875,000 Bellatrix common shares at a price of $8.00 per Bellatrix Share for aggregate gross proceeds of $175.0 million (net proceeds of $165.7 million after transaction costs) through a syndicate of underwriters.
The net proceeds from this financing were used to temporarily repay a portion of the indebtedness of Bellatrix under its credit facilities; subsequently utilized to fund the cash portion of the acquisition of Angle, the acquisition of the Angle Debentures, and a portion of Bellatrix’s obligations under the Troika Joint Venture described below.
Troika Joint Venture
On November 11, 2013, the Company announced that it had successfully closed the previously announced $240 million joint venture partnership with TCA Energy Ltd. TCA is a Canadian incorporated special purpose vehicle for Troika Resources Private Equity Fund which is based in Seoul, Korea and managed by KDB Bank, SK Energy and Samchully AMC.
Pursuant to the agreement forming the Troika Joint Venture, Bellatrix and TCA will drill and develop lands in the Ferrier Cardium area of West Central Alberta, with the program to be completed by December 31, 2014. TCA will contribute $120 million, representing a 50% share, towards the capital program for the drilling of an expected 63 gross wells, and in exchange, will receive 35% of Bellatrix's working interest until payout (being recovery of TCA's capital investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's working interest. As part of this agreement, TCA participated in 14 gross wells (as included in the total expected 63 gross well program) for wells that have been drilled since January 1, 2013, resulting in net proceeds of $16.7 million that was received by Bellatrix at closing.
The net proceeds from the disposition were initially used to reduce the Company's indebtedness, and ultimately will be directed towards the continued development of its Cardium and Mannville asset base.
Grafton Joint Venture
On June 27, 2013, Bellatrix closed the Grafton Joint Venture to accelerate development on a portion of Bellatrix’s extensive undeveloped land holdings. Subsequently on September 10, 2013, the Company announced that Grafton elected to exercise an option to increase its committed capital investment by an additional $100 million on the same terms and conditions as the initial Grafton Joint Venture.
The Grafton Joint Venture is in Willesden Green and Brazeau areas of West-Central Alberta. Under the terms of the amended agreement, Grafton will contribute 82%, or $200 million, to the $244 million Grafton Joint Venture to participate in an expected 58 Notikewin/Falher and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix's working interest in each well drilled in the well program until payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33% of Bellatrix's working interest ("WI") after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty ("GORR") on Bellatrix's pre-Grafton Joint Venture working interest. Grafton also has an additional one-time option within 12 months of the effective date to increase its exposure by an additional $50 million on the same terms and conditions. The effective date of the agreement is July 1, 2013 and has a term of 2 years. If the $50 million option is exercised, Bellatrix shall have until the end of the third anniversary of the effective date to spend the additional capital.
Baptiste Asset Sale and Strategic Partnership
On September 3, 2013 the Company announced the closing of an asset sale to Daewoo and Devonian, and the Daewoo and Devonian Partnership. Under the terms of the associated agreements, Bellatrix sold, effective July 1, 2013, to Daewoo and Devonian an aggregate 50% of the Company’s working interest share of its producing assets, an operated compressor station and gathering system and related land acreage in the Baptiste area of West Central Alberta (the “Sold Assets”) for gross consideration of $52.5 million, subject to closing adjustments. A $29.1 million gain on dispositions was recognized during the year ended December 31, 2013 in relation to the disposition. The Sold Assets were producing approximately 268 boe/d (67% gas and 33% oil and liquids) net to the Sold Assets and included 3,858 net acres of Cardium rights and 1,119 net acres of Mannville rights.
The Daewoo and Devonian Partnership which was effective as of July 1, 2013 encompasses a multiyear commitment to jointly develop the aforementioned acreage in Ferrier and Willesden Green of West Central Alberta encompassing 70 gross wells with anticipated total capital expenditures to the Daewoo and Devonian Partnership of approximately $200 million.
Redemption of Convertible Debentures
On September 4, 2013, the Company issued a notice of redemption to holders of its then outstanding $55.0 million 4.75% convertible unsecured, unsubordinated debentures (the “convertible debentures”), with the redemption date set as October 21, 2013. During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company. A reduction to the deficit as contained in shareholder’s equity of $1.3 million was recognized in connection with the settlement of the convertible debentures during the year ended December 31, 2013.
Fourth Quarter 2013
| HIGHLIGHTS | | | Three months ended December 31, |
| (CDN$000s except share and per share amounts) | | 2013(8) | 2012 |
| FINANCIAL | | | | |
| Revenue (before royalties and risk management(1)) | | | 83,455 | 62,283 |
| | | | | |
| Funds flow from operations(2) | | | 39,349 | 29,865 |
| | Per basic share(5) | | | $0.31 | $0.28 |
| | Per diluted share(5) | | | $0.30 | $0.26 |
| Cash flow from operating activities | | | 38,025 | 32,007 |
| | Per basic share(5) | | | $0.30 | $0.30 |
| | Per diluted share(5) | | | $0.29 | $0.28 |
| Net profit | | | 22,195 | 9,251 |
| | Per basic share(5) | | | $0.17 | $0.09 |
| | Per diluted share(5) | | | $0.17 | $0.08 |
| Exploration and development | | | 101,232 | 32,083 |
| Corporate | | | 4,282 | 43 |
| Property acquisitions | | | 10,385 | 20,922 |
| Capital expenditures – cash | | | 115,899 | 53,048 |
| Property dispositions – cash | | | (16,700) | 10 |
| Corporate acquisitions and other non-cash items | | | 607,727 | 27,487 |
| Total capital expenditures – net(4) | | | 706,926 | 80,545 |
| | | | Three months ended December 31, |
| (CDN$000s except share and per share amounts) | | | | 2013(8) | 2012 |
| OPERATING | | | | | |
| Average daily sales volumes | | | | | |
| | Crude oil, condensate and NGLs | (bbls/d) | | | 7,564 | 5,730 |
| | Natural gas | (mcf/d) | | | 98,423 | 78,195 |
| | Total oil equivalent | (boe/d) | | | 23,968 | 18,763 |
| Average prices | | | | | |
| | Light crude oil and condensate | ($/bbl) | | | 83.26 | 82.58 |
| | NGLs (excluding condensate) | ($/bbl) | | | 46.20 | 38.84 |
| | Heavy oil | ($/bbl) | | | 63.70 | 65.30 |
| | Crude oil, condensate and NGLs | ($/bbl) | | | 66.75 | 69.55 |
| | Crude oil, condensate and NGLs (including risk management(1)) | ($/bbl) | | | 64.32 | 72.11 |
| | Natural gas | ($/mcf) | | | 3.89 | 3.46 |
| | Natural gas (including risk management(1)) | ($/mcf) | | | 3.97 | 3.67 |
| | Total oil equivalent | ($/boe) | | | 37.05 | 35.67 |
| | Total oil equivalent (including risk management(1)) | ($/boe) | | | 36.59 | 37.30 |
| Statistics | | | | | |
| | Operating netback(4) | ($/boe) | | | 21.10 | 19.20 |
| | Operating netback(4) (including risk management(1)) | ($/boe) | | | 20.64 | 20.83 |
| | Transportation | ($/boe) | | | 1.02 | 0.70 |
| | Production expenses | ($/boe) | | | 8.70 | 8.91 |
| | General & administrative | ($/boe) | | | 2.53 | 2.54 |
| | Royalties as a % of sales after transportation | | | | 17% | 20% |
| DILUTED WEIGHTED AVERAGE SHARES | | |
| Diluted weighted average shares – net profit(5) | 130,875,349 | 118,931,047 |
Diluted weighted average shares – funds flow from operations and cash flow from operating activities(2) (5) | 130,875,349 | 118,931,047 |
| SHARE TRADING STATISTICS | | |
| TSX and Other(6) (CDN$, except volumes) based on intra-day trading | | |
| High | 8.52 | 4.47 |
| Low | 6.65 | 3.59 |
| Close | 7.81 | 4.27 |
| Average daily volume | 2,678,253 | 842,840 |
| NYSE MKT(7) (US$, except volumes) based on intra-day trading | | |
| High | 8.43 | 4.54 |
| Low | 6.38 | 3.69 |
| Close | 7.33 | 4.28 |
| Average daily volume | 171,620 | 39,079 |
| (1) | The Company has entered into various commodity price risk management contracts which are considered to be economic hedges. Per unit metrics after risk management include only the realized portion of gains or losses on commodity contracts. |
| | The Company does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per unit metrics calculations disclosed. |
| (2) | The highlights section contains the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with GAAP as an indicator of the Company’s performance. Therefore reference to the additional GAAP measures of funds flow from operations, or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found in the MD&A. Funds flow from operations per share is calculated using the weighted average number of common shares for the year. |
| (3) | Net debt and total net debt are considered additional GAAP measures. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. A reconciliation between total liabilities under GAAP and total net debt and net debt as calculated by the Company is found in the MD&A. |
| (4) | Operating netbacks and total capital expenditures – netare considered non-GAAP measures. Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income. Total capital expenditures – net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. |
| (5) | Basic weighted average shares for the three months ended December 31, 2013 were 127,489,592 (2012: 107,734,134). |
| | In computing weighted average diluted earnings per share and weighted average diluted cash flow from operating activities and funds flow from operations per share for the three months ended December 31, 2013, a total of 3,385,757 (2012: 1,375,484) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and a total of no common shares (2012: 9,821,429) issuable on conversion of convertible debentures were added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 130,875,349 (2012: 118,931,047). As a consequence, a total of no interest and accretion expense (net of income tax effect) was added to the numerator (2012: $0.8 million). |
| (6) | TSX and Other includes the trading statistics for the Toronto Stock Exchange and other Canadian trading markets. |
| (7) | The Company’s common shares commenced trading on the NYSE MKT on September 24, 2012. |
| (8) | The Company’s financial and operating results for the three months ended December 31, 2013 include financial and operating results from Angle for the period from December 11, 2013 to December 31, 2013. |
As detailed previously in this Management’s Discussion and Analysis, funds flow from operations is a term that does not have any standardized meaning under GAAP. Bellatrix’s method of calculating funds flow from operations may differ from that of other companies, and accordingly, may not be comparable to measures used by other companies. Funds flow from operations is calculated as cash flow from operating activities before decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.
Reconciliation of Cash Flow from Operating Activities to Funds Flow from Operations
| | | Three months ended December 31, |
| ($000s) | | | 2013 | | | | 2012 | |
| Cash flow from operating activities | | | 38,025 | | | | 32,007 | |
| Decommissioning costs incurred | | | 223 | | | | 76 | |
| Transaction costs | | | 5,344 | | | | — | |
| Change in non-cash working capital | | | (4,243 | ) | | | (2,218 | ) |
| Funds flow from operations | | | 39,349 | | | | 29,865 | |
Funds flow from operations during the fourth quarter of 2013 was $39.3 million, an increase of 32% compared to $29.9 million for the fourth quarter of 2012. The increase in funds flow from operations between the periods was due primarily due to the impact on revenues and netbacks of increased natural gas, light oil and condensate, and NGL sales volumes, higher light oil, condensate, NGL, and natural gas prices, partially offset by lower heavy oil sales volumes, a net realized loss on commodity contracts compared to a net realized gain in the 2012 fourth quarter, increased general and administrative expenses, the impact of lower heavy oil commodity prices and higher overall operating, transportation, and royalties expenses.
Cash flow from operating activities during the fourth quarter of 2013 increased to $38.0 million, compared to $32.0 million for the fourth quarter of 2012, primarily due to a higher overall operating netback as discussed above. The increase from the higher netbacks between the periods was partially offset by transaction costs, as well as a slight increase in decommissioning costs incurred in the 2013 fourth quarter compared to 2012.
In the three months ended December 31, 2013, Bellatrix realized a net profit of $22.2 million compared to a net profit of $9.3 million in the same period of 2012. The higher net profit recorded in the fourth quarter of 2013 compared to the same period in 2012 is primarily the result of higher revenue before other, a $20.6 million non-cash gain on corporate acquisition, a $5.1 million gain on property dispositions compared to a $0.1 million loss on property dispositions in the 2012 period, a $6.5 million non-cash unrealized loss on commodity risk management compared to a $1.3 million gain in the 2012 period, and a deferred income tax expense of $2.6 million in the 2013 fourth quarter compared to an expense of $3.3 million in the 2012 period, offset partially by increased depletion and depreciation expenses, higher royalty expenses, and a non-cash gain on property acquisition of $16.6 million recognized in 2012.
| Sales Volumes | | |
| | | Three months ended December 31, |
| | | | | 2013 | 2012 |
| Light oil and condensate | (bbls/d) | | | 4,111 | 3,910 |
| NGLs (excluding condensate) | (bbls/d) | | | 3,278 | 1,631 |
| Heavy oil | (bbls/d) | | | 175 | 189 |
| Total crude oil, condensate and NGLs | (bbls/d) | | | 7,564 | 5,730 |
| | | | | | |
| Natural gas | (mcf/d) | | | 98,423 | 78,195 |
| | | | | | |
| Total boe/d | (6:1) | | | 23,968 | 18,763 |
Sales volumes for the three months ended December 31, 2013 averaged 23,968 boe/d, an increase of 28% from the 18,763 boe/d sold in the fourth quarter of 2012. The weighting toward crude oil, condensate and NGLs sales volumes increased to 32% in the 2013 fourth quarter, compared to 31% in the corresponding period in 2012. Fourth quarter 2013 natural gas, NGL, and total overall sales volumes were higher than the same period in 2012 primarily due to the continued success achieved from the Company’s liquids rich drilling program as well as additional sales volumes realized from the Angle acquisition.
Natural gas sales averaged 98.4 Mmcf/d during the three months ended December 31, 2013, compared to 78.2 Mmcf/d in the fourth quarter of 2012. The weighting toward natural gas sales volumes averaged 68% in the 2013 fourth quarter, a slight decrease from the 69% weighting realized in the same period in 2012. Crude oil, condensate and NGL sales volumes increased by 32% to 7,564 bbls/d in the final quarter of 2012 compared to 5,730 bbls/d during the same period of 2012.
| Revenue | | |
| | | Three months ended December 31, |
| ($000s) | | | 2013 | 2012 |
| Light crude oil and condensate | | | 31,493 | 29,702 |
| NGLs (excluding condensate) | | | 13,934 | 5,829 |
| Heavy oil | | | 1,029 | 1,136 |
| Crude oil and NGLs | | | 46,456 | 36,667 |
| Natural gas | | | 35,252 | 24,904 |
| Total revenue before other | | | 81,708 | 61,571 |
| Other income(1) | | | 1,747 | 712 |
| Total revenue before royalties and risk management | | | 83,455 | 62,283 |
(1)Other income primarily consists of processing and other third party income.
Revenue before other income, royalties and commodity price risk management contracts for the final quarter of 2013 was $81.7 million, an increase of 33% from $61.6 million in the same period in 2012. The increase in revenues between the periods was due to increased light oil and condensate, NGLs, and natural gas sales volumes in conjunction with higher light oil and condensate, NGLs, and natural gas prices in the 2013 period, partially offset by lower heavy oil sales volumes and prices.
Light oil and condensate revenues for the fourth quarter of 2013 increased by 6% from the same period in 2012 as a result of both higher prices and sales volumes realized between the periods. For light oil and condensate, Bellatrix recorded an average $83.26/bbl before commodity price risk management contracts during the fourth quarter of 2013, 1% higher than the average price of $82.58/bbl received in the comparative 2012 period. In comparison, the Edmonton par price increased by 2% over the same period. The average WTI crude oil benchmark price increased by 11% in fourth quarter of 2013 compared to the same period in 2012. The average US$/CDN$ foreign exchange rate was 0.9528 for the three months ended December 31, 2013, a decrease of 6% compared to an average rate of 1.0093 in the fourth quarter of 2012.
NGL revenues for the fourth quarter of 2013 increased by 139% compared to the 2012 period as a result of higher sales volumes in conjunction with increased prices. For NGLs (excluding condensate), Bellatrix recorded an average $46.20/bbl during the fourth quarter of 2013, a 19% increase from the $38.84/bbl received in the comparative 2012 period. The increase in NGL pricing between the 2013 and 2012 periods is largely attributable to changes in NGL market supply conditions between the periods.
Natural gas revenues in the final quarter of 2013 increased by 42% from the same period in 2012 as a result of a 26% increase in sales volumes and a 12% increase in realized natural gas prices before transportation between the periods. Bellatrix’s natural gas sales are priced with reference to the daily or monthly AECO indices. Bellatrix’s natural gas sold has a higher heat content than the industry average, which results in slightly higher prices per mcf than the daily AECO index. During the fourth quarter of 2013, the AECO daily reference price increased by 10%, and the AECO monthly reference price increased by approximately 3% compared to the fourth quarter of 2012. Bellatrix’s natural gas average sales price before commodity price risk management contracts for the fourth quarter of 2013 increased by 12% to $3.89/mcf compared to the $3.46/mcf realized in the same period in 2012. The more significant increase in Bellatrix’s realized natural gas prices compared to the daily AECO index between the periods was primarily due to the weighting of sales volumes realized at increased prices during the fourth quarter of 2013. Bellatrix’s natural gas average price after including commodity price risk management contracts for the three months ended December 31, 2013 was $3.97/mcf, compared to $3.67/mcf for the three months ended December 31, 2012.
In the fourth quarter of 2013, average sales volumes increased by 10% from the third quarter 2013 average volumes of 21,852 boe/d. The increase was due to the success achieved from the Company’s drilling program in 2013 and its acquisition of Angle.
During the three months ended December 31, 2013, Bellatrix spent $101.2 million on capital projects, excluding corporate and property acquisitions and dispositions, compared to $32.1 million in the same period in 2012. In the fourth quarter of 2013, Bellatrix drilled or participated in 35 gross wells (21.36 net), which included 24 gross (16.24 net) Cardium oil wells, 10 gross (4.37 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well. In the fourth quarter of 2012, Bellatrix drilled or participated in 10 gross wells (6.17 net), all of which were Cardium light oil horizontal wells.
In the fourth quarter of 2013, the Company had $13.8 million in royalties, compared to $11.8 million in the same period in 2012. As a percentage of pre-commodity price risk management sales (after transportation costs), royalties were 17% in the three months ended December 31, 2013 compared to 20% in the same period in 2012. The Company’s minor heavy oil properties, principally consisting of the Frog Lake Alberta assets, are also subject to high Crown royalty rates. The Company’s light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more recent wells in their early years of production under the Alberta royalty incentive program, offset by increased royalty rates on other wells now coming off initial royalty incentive rates and as other wells are drilled on Ferrier lands with higher combined Indian Oil and Gas Canada (“IOGC”) and gross overriding royalty (“GORR”) royalty rates.
In the final quarter of 2013, operating costs totaled $19.2 million, compared to $15.4 million recorded in the same period of 2012. During the three months ended December 31, 2013, operating costs averaged $8.70/boe, down from the $8.91/boe incurred during the same period in 2012. The decrease was primarily due to increased production from recent drilling in areas with lower production expenses and the Company’s continued efforts to streamline operations and field optimization projects. In comparison, operating costs for the third quarter of 2013 averaged $8.98/boe.
During the fourth quarter of 2013, the Company’s corporate operating netback before commodity risk management contracts increased by 10% to $21.10/boe compared to $19.20/boe in the comparative 2012 period, driven primarily by a 4% increase in overall commodity prices, a 9% decrease in royalties, and a 2% decrease in production expenses, partially offset by a 46% increase in transportation expenses. In comparison, the Company’s corporate operating netback before commodity risk management contracts for the third quarter of 2013 was $19.85/boe.
The operating netback before commodity price risk management contracts for crude oil, condensate and NGLs during the fourth quarter of 2013 averaged $43.19/bbl, an increase of 15% from the $37.60/bbl realized during the fourth quarter of 2012. The increase between the periods was primarily as a result of lower royalties and reduced production expenses, offset partially by weaker commodity prices and higher transportation expenses. In comparison, the operating netback for crude oil, condensate and NGLs for the third quarter of 2013 was $57.05/bbl.
The operating netback for natural gas before commodity price risk management contracts during the fourth quarter of 2013 of $1.82/mcf was 2% lower than the $1.85/mcf recorded in the same period in 2012. The decrease was primarily a result of increased royalties, production expenses, and transportation expenses, slightly offset by higher natural gas prices. In comparison, the operating netback for natural gas before commodity risk management contracts for the third quarter of 2013 was $0.86/mcf.
In the three months ended December 31, 2013, general and administrative expenses (“G&A”), net of capitalized G&A and recoveries, were $5.6 million, compared to $4.4 million in the comparable 2012 period. The increase to net G&A was primarily attributable to increases in staffing and office costs between the periods. The overall increase in G&A expenses was offset slightly by higher capitalized G&A and recoveries as a result of the increase in capital activity in the fourth quarter of 2013 compared to the fourth quarter of 2012.
Depletion, depreciation and accretion expense for the final quarter of 2013 was $27.3 million ($12.38/boe), compared to $18.6 million ($10.77/boe) in the same period in 2012. The increase in depletion, depreciation and accretion expense from the 2012 fourth quarter to that in 2013 is reflective of the 28% increase in sales volumes and a higher depletable base between the comparative periods, partially offset by the additional reserves achieved through the Company’s drilling success.
2013 Annual Financial and Operational Results
Sales Volumes
Sales volumes for the year ended December 31, 2013 averaged 21,829 boe/d compared to 16,686 boe/d in 2012, representing a 31% increase. Total crude oil, condensate and NGLs averaged approximately 30% of sales volumes for 2013, compared to 34% of sales volumes in 2012. The increase in total sales was primarily a result of a year over year increase in capital expenditures by $118.3 million, attributable in part to the Grafton Joint Venture, the Daewoo and Devonian Partnership, and the Troika Joint Venture entered into during the 2013 year, Bellatrix’s continuing drilling success achieved in the Cardium and Notikewin resource plays, and additional sales volumes acquired through the acquisition of Angle in December, 2013. Capital expenditures for the year ended December 31, 2013 were $303.7 million, compared to $185.3 million for the 2012 year.
Sales Volumes
| | Years ended December 31, |
| | | 2013 | 2012 |
| Light oil and condensate | (bbls/d) | 3,684 | 3,996 |
| NGLs (excluding condensate) | (bbls/d) | 2,612 | 1,441 |
| Heavy oil | (bbls/d) | 193 | 280 |
| Total crude oil, condensate and NGLs | (bbls/d) | 6,489 | 5,717 |
| | | | |
| Natural gas | (mcf/d) | 92,042 | 65,812 |
| | | | |
| Total boe/d | (6:1) | 21,829 | 16,686 |
During the 2013 year, Bellatrix posted a 100% success rate, drilling and/or participating in 80 gross (52.83 net) wells, resulting in 57 gross (41.22 net) Cardium light oil wells, 22 gross (10.86 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.
By comparison, during the 2012 year, Bellatrix drilled or participated in 34 gross (26.32 net) wells, which included 28 gross (21.32 net) Cardium light oil horizontal wells, 2 gross (2.0 net) Cardium condensate-rich natural gas wells, 1 gross (1.0 net) Duvernay natural gas horizontal well, and 3 gross (2.0 net) Notikewin/Falher natural gas horizontal wells.
Angle drilled and/or participated in a total of 39 gross (33.71 net) wells prior to the acquisition which were comprised of 29 gross (25.26 net) Cardium light oil wells, 8 gross (6.45 net) Mannville natural gas wells, and 2 gross (2.0 net) wells drilled in other minor formations.
For the year ended December 31, 2013, crude oil, condensate and NGL sales volumes increased by approximately 14%, averaging 6,489 bbl/d compared to 5,717 bbl/d in the 2012 year. The weighting towards crude oil, condensate and NGLs for the year ended December 31, 2013 was 30%, compared to 34% in the 2012 year. The reduction in liquids weighting was a result of bringing on several high-productivity natural gas wells throughout 2012 and 2013.
Sales of natural gas averaged 92.0 Mmcf/d for the year ended December 31, 2013, compared to 65.8 Mmcf/d in the 2012 year, an increase of 40%.
For 2014, Bellatrix will continue to be active in drilling with 10 to 12 rigs operating in its two core resource plays, the Cardium oil and Mannville condensate rich gas, utilizing horizontal drilling multi-fracturing technology. An initial net capital budget of $370 million has been set for fiscal 2014. Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2014 budget is anticipated to provide 2014 average daily production of approximately 42,500 boe/d to 43,500 boe/d and an exit rate of approximately 47,000 boe/d.
Commodity Prices
Average Commodity Prices
| | Years ended December 31, |
| | 2013 | 2012 | % Change |
| | | | |
| Exchange rate(US$/CDN$) | 0.9712 | 1.0009 | (3) |
| | | | |
| Crude oil: | | | |
| WTI(US$/bbl) | 98.05 | 94.14 | 4 |
| Edmonton par – light oil ($/bbl) | 93.24 | 86.53 | 8 |
| Bow River – medium/heavy oil($/bbl) | 76.16 | 74.30 | 3 |
| Hardisty Heavy – heavy oil($/bbl) | 65.48 | 64.99 | 1 |
| Bellatrix’s average prices($/bbl) | | | |
| Light crude oil and condensate | 92.66 | 86.47 | 7 |
| NGLs (excluding condensate) | 43.85 | 38.88 | 13 |
| Heavy crude oil | 68.41 | 68.51 | - |
| Total crude oil and NGLs | 72.29 | 73.59 | (2) |
| Total crude oil and NGLs (including risk management (1)) | 69.82 | 72.65 | (4) |
| | | | |
| Natural gas: | | | |
| NYMEX(US$/mmbtu) | 3.73 | 2.83 | 32 |
| AECO daily index (CDN$/mcf) | 3.17 | 2.39 | 33 |
| AECO monthly index (CDN$/mcf) | 3.16 | 2.40 | 32 |
| Bellatrix’s average price ($/mcf) | 3.49 | 2.62 | 33 |
| Bellatrix’s average price (including risk management(1)) ($/mcf) | 3.71 | 3.17 | 17 |
(1)Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.
For light oil and condensate, Bellatrix recorded an average price of $92.66/bbl before commodity price risk management contracts during 2013, 7% higher than the average price received in 2012. In comparison, the Edmonton par price increased by 8% over the same period. The average WTI crude oil benchmark price increased by 4% between 2012 and 2013. The average US$/CDN$ foreign exchange rate was 0.9712 for the year ended December 31, 2013, a decrease of 3% compared to an average rate of 1.0009 in 2012.
For NGLs (excluding condensate), Bellatrix recorded an average price of $43.85/bbl during 2013, an increase of 13% from the $38.88/bbl received in the comparative 2012 year. The increase in NGL pricing is largely attributable to changes in NGL market supply conditions between the years.
For heavy crude oil, Bellatrix received an average price before commodity risk management contracts of $68.41/bbl in the year ended December 31, 2013, relatively consistent with the $68.51/bbl realized in the 2012 year. In comparison, the Bow River reference price increased by 3%, and the Hardisty Heavy reference price increased by 1% between the 2012 and 2013 year. The majority of Bellatrix’s heavy crude oil density ranges between 11 and 16 degrees API, consistent with the Hardisty Heavy reference price.
Bellatrix’s natural gas sales are priced with reference to the daily or monthly AECO indices. Bellatrix’s natural gas sold has a higher heat content than the industry average, which results in slightly higher prices per mcf than the daily AECO index. During the year ended December 31, 2013, the AECO daily reference price increased by 33%, and the AECO monthly reference price increased by approximately 32% compared to 2012. Bellatrix’s natural gas average sales price before commodity price risk management contracts for the year ended December 31, 2013 increased by 33% to $3.49/mcf compared to $2.62/mcf in 2012. Bellatrix’s natural gas average price after including commodity price risk management contracts for 2013 was $3.71/mcf, compared to $3.17 in 2012.
Revenue
Revenue before other income, royalties and commodity price risk management contracts for the year ended December 31, 2013 was $288.3 million, 33% higher than the $217.1 million realized in 2012. The increase in revenues was primarily due to increased natural gas and NGL sales volumes and higher realized prices for light oil and condensate, NGLs, and natural gas, partially offset by reduced crude oil and condensate sales volumes as well as lower heavy oil prices experienced in the 2013 year.
Revenue before other income, royalties and commodity price risk management contracts for crude oil and NGLs for the year ended December 31, 2013 increased from the comparative 2012 year by approximately 11%, resulting from higher NGL sales volumes in conjunction with increased light oil, condensate, and NGL prices, partially offset by lower crude oil and condensate sales volumes and reduced heavy oil prices when compared to the 2012 year. In the 2013 year, total crude oil, condensate and NGL revenues contributed 59% of total revenue (before other income) compared to 71% in the 2012 year. Light crude oil, condensate and NGL revenues in the year ended December 31, 2013 comprised 97% of total crude oil, condensate and NGL revenues (before other income), compared to a 95% composition realized in 2012.
Natural gas revenue before other income, royalties and commodity price risk management contracts for the year ended December 31, 2013 increased by approximately 85% compared to the 2012 year as a result of a 33% increase in realized gas prices before risk management in conjunction with an approximate 40% increase in sales volumes.
| | Years ended December 31, |
| ($000s) | 2013 | 2012 |
| Light crude oil and condensate | 124,590 | 126,468 |
| NGLs (excluding condensate) | 41,804 | 20,504 |
| Heavy oil | 4,822 | 7,023 |
| Crude oil and NGLs | 171,216 | 153,995 |
| Natural gas | 117,094 | 63,143 |
| Total revenue before other | 288,310 | 217,138 |
| Other income(1) | 3,581 | 2,176 |
| Total revenue before royalties and risk management | 291,891 | 219,314 |
(1)Other income primarily consists of processing and other third party income.
Commodity Price Risk Management
The Company has a formal commodity price risk management policy which permits management to use specified price risk management strategies including fixed price contracts, collars and the purchase of floor price options and other derivative financial instruments and physical delivery sales contracts to reduce the impact of price volatility for a maximum of eighteen months beyond the transaction date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Company seeks to provide a measure of stability to funds flow from operations, as well as to ensure Bellatrix realizes positive economic returns from its capital development and acquisition activities. The Company plans to continue its commodity price risk management strategies focusing on maintaining sufficient cash flow to fund Bellatrix’s capital expenditure program. Any remaining production is realized at market prices.
A summary of the financial commodity price risk management volumes and average prices by quarter currently outstanding as of March 12, 2014 is shown in the following tables:
Natural gas
Average Volumes (GJ/d)
| | Q1 2014 | Q2 2014 | Q3 2014 | Q4 2014 |
| Fixed | 91,056 | 110,000 | 110,000 | 110,000 |
Average Price ($/GJ AECO C)
| | Q1 2014 | Q2 2014 | Q3 2014 | Q4 2014 |
| Fixed | 3.57 | 3.61 | 3.70 | 3.70 |
Crude oil and liquids
Average Volumes (bbls/d)
| | | | | |
| | Q1 2014 | Q2 2014 | Q3 2014 | Q4 2014 |
| Fixed (CDN$) | 5,000 | 5,000 | 5,000 | 5,000 |
| Fixed (US$) | 1,000 | 1,000 | 1,000 | 1,000 |
Average Price ($/bbl WTI)
| | | | | |
| | | | | |
| | Q1 2014 | Q2 2014 | Q3 2014 | Q4 2014 |
| Fixed price (CDN$/bbl) | 96.46 | 96.46 | 96.46 | 96.46 |
| Fixed price (US$/bbl) | 94.15 | 94.15 | 94.15 | 94.15 |
As of December 31, 2013, the fair value of Bellatrix’s outstanding commodity contracts was a net unrealized liability of $16.9 million as reflected in the financial statements. The fair value or mark-to-market value of these contracts is based on the estimated amount that would have been received or paid to settle the contracts as at December 31, 2013 and will differ from what will eventually be realized. Changes in the fair value of the commodity contracts are recognized in the Consolidated Statements of Comprehensive Income within the financial statements.
The following is a summary of the gain (loss) on commodity contracts for the years ended December 31, 2013 and 2012 as reflected in the Consolidated Statements of Comprehensive Income:
Commodity contracts
| ($000s) | Crude Oil & Liquids | Natural Gas | 2013 Total |
| Realized cash gain (loss) on contracts | (5,851) | 7,710 | 1,859 |
| Unrealized gain (loss) on contracts(1) | (4,112) | (13,015) | (17,127) |
| Total gain (loss) on commodity contracts | (9,963) | (5,305) | (15,268) |
Commodity contracts
| ($000s) | Crude Oil & Liquids | Natural Gas | 2012 Total |
| Realized cash gain (loss) on contracts | (1,976) | 13,245 | 11,269 |
| Unrealized gain on contracts(1) | 6,267 | 4,539 | 10,806 |
| Total gain on commodity contracts | 4,291 | 17,784 | 22,075 |
(1)Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts during the year.
Royalties
For the year ended December 31, 2013, total royalties were $46.2 million compared to $38.8 million incurred in 2012. Overall royalties as a percentage of revenue (after transportation costs) in the 2013 year were 16% compared with 18% in 2012.
The Company’s minor heavy oil properties, principally consisting of the Frog Lake Alberta assets, are subject to high Crown royalty rates. The Company’s light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more recent wells in their early years of production under the Alberta royalty incentive program. This is offset by increased royalty rates on wells coming off initial royalty incentive rates and wells drilled on Ferrier lands with higher combined IOGC and GORR royalty rates.
| Royalties by Commodity Type | Years ended December 31, |
| ($000s, except where noted) | | 2013 | 2012 |
| Light crude oil, condensate and NGLs | 33,807 | 33,607 |
| $/bbl | 14.71 | 16.89 |
| Average light crude oil, condensate and | | |
| NGLs royalty rate (%) | 20 | 23 |
| | | |
| Heavy Oil | 2,106 | 3,496 |
| $/bbl | 29.90 | 34.11 |
| Average heavy oil royalty rate (%) | 44 | 52 |
| | | |
| Natural Gas | 10,304 | 1,653 |
| $/mcf | 0.31 | 0.07 |
| Average natural gas royalty rate (%) | 9 | 3 |
| | | |
| Total | 46,217 | 38,756 |
| $/boe | 5.80 | 6.35 |
| Average total royalty rate (%) | 16 | 18 |
| | | | |
Royalties by Type
| | Years ended December 31, |
| ($000s) | | 2013 | 2012 |
| Crown royalties | 15,051 | 11,518 |
| Indian Oil and Gas Canada royalties | 10,473 | 8,038 |
| Freehold & GORR | 20,693 | 19,200 |
| Total | 46,217 | 38,756 |
Expenses
| | Years ended December 31, |
| ($000s) | | 2013 | 2012 |
| Production | 69,668 | 53,316 |
| Transportation | 7,014 | 4,978 |
| General and administrative | 16,214 | 14,272 |
| Interest and financing charges (1) | 12,488 | 9,834 |
| Share-based compensation | 4,960 | 3,219 |
(1)Does not include financing charges in relation to the Company’s accretion of decommissioning liabilities.
Expenses per boe
| | Years ended December 31, |
| ($ per boe) | | 2013 | 2012 |
| Production | 8.74 | 8.73 |
| Transportation | 0.88 | 0.82 |
| General and administrative | 2.03 | 2.34 |
| Interest and financing charges | 1.57 | 1.61 |
| Share-based compensation | 0.62 | 0.53 |
| | | | |
Production Expenses
For the year ended December 31, 2013, production expenses totaled $69.7 million ($8.74/boe), compared to $53.3 million ($8.73/boe) in 2012. In 2013, production expenses increased overall and remained consistent on a per boe basis when compared to 2012.
Bellatrix is targeting production expenses of approximately $118.0 million ($7.50/boe) in the 2014 year, which is a reduction from the $8.74/boe production expenses incurred for the 2013 year. This is based upon assumptions of estimated 2014 average production of approximately 42,500 boe/d to 43,500 boe/d, continued field optimization work and planned capital expenditures in producing areas which are anticipated to incur lower production expenses.
Production Expenses by Commodity Type
| | Years ended December 31, |
| ($000s, except where noted) | 2013 | 2012 |
| Light crude oil, condensate and NGLs | 24,768 | 21,840 |
| $/bbl | 10.78 | 10.97 |
| | | |
| Heavy oil | 1,071 | 1,555 |
| $/bbl | 15.20 | 15.17 |
| | | |
| Natural gas | 43,829 | 29,921 |
| $/mcf | 1.30 | 1.24 |
| | | |
| Total | 69,668 | 53,316 |
| $/boe | 8.74 | 8.73 |
| | | |
| Total | 69,668 | 53,316 |
| Processing and other third party income(1) | (3,581) | (2,176) |
| Total after deducting processing and other third party income | 66,087 | 51,140 |
| $/boe | 8.29 | 8.37 |
(1)Processing and other third party income is included within petroleum and natural gas sales in the Consolidated Statements of Comprehensive Income.
Transportation
Transportation expenses for the year ended December 31, 2013 were $7.0 million ($0.88/boe), compared to $5.0 million ($0.82/boe) in 2012. Transportation expenses increased on an overall and per boe basis due primarily to light oil, condensate and NGL hauling required for some new wells added throughout 2013.
Operating Netback
Operating Netback – Corporate (before risk management)
| | Years ended December 31, |
| ($/boe) | | 2013 | 2012 |
| Sales | 36.18 | 35.56 |
| Transportation | (0.88) | (0.82) |
| Royalties | (5.80) | (6.35) |
| Production expense | (8.74) | (8.73) |
| Operating netback | 20.76 | 19.66 |
| | | | |
For the year ended December 31, 2013, the corporate operating netback (before commodity risk management contracts) was $20.76/boe compared to $19.66/boe in 2012. The increased netback was primarily the result of higher commodity prices and lower royalties, partially offset by increased transportation expenses. After including commodity risk management contracts, the corporate operating netback for the year ended December 31, 2013 was $20.99/boe compared to $21.51/boe in 2012. Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.
Operating Netback – Crude Oil, Condensate and NGLs (before risk management)
| | Years ended December 31, |
| ($/bbl) | | 2013 | 2012 |
| Sales | 72.29 | 73.59 |
| Transportation | (0.86) | (0.98) |
| Royalties | (15.16) | (17.73) |
| Production expense | (10.91) | (11.18) |
| Operating netback | 45.36 | 43.70 |
| | | | |
Operating netback for crude oil, condensate and NGLs averaged $45.36/bbl for the year ended December 31, 2013, a 4% increase from $43.70/bbl realized in 2012. Reduced production, royalties, and transportation expenses, partially offset by slightly lower average realized commodity prices resulted in the increase to operating netback for crude oil, condensate and NGLs. After including commodity price risk management contracts, operating netback for crude oil, condensate, and NGLs for the year ended December 31, 2013 decreased to $42.89/bbl compared to $42.76/bbl in 2012.
Operating Netback – Natural Gas (before risk management)
| | Years ended December 31, |
| ($/mcf) | | 2013 | 2012 |
| Sales | 3.49 | 2.62 |
| Transportation | (0.15) | (0.12) |
| Royalties | (0.31) | (0.07) |
| Production expense | (1.30) | (1.24) |
| Operating netback | 1.73 | 1.19 |
Operating netback for natural gas in the year ended December 31, 2013 increased by 45% to $1.73/mcf, compared to $1.19/mcf realized in 2012, reflecting increased natural gas prices, partially offset by increased production, transportation, and royalty expenses. After including commodity risk management contracts, operating netback for natural gas for the year ended December 31, 2013 increased to $1.96/mcf, which compared to $1.74/mcf in the 2012 year.
General and Administrative
General and administrative (“G&A”) expenses (after capitalized G&A and recoveries) for the year ended December 31, 2013 were $16.2 million ($2.03/boe), compared to $14.3 million ($2.34/boe) realized in the 2012 year. G&A expenses in the 2013 year were higher in comparison to 2012, which is reflective of higher compensation costs and additional office rent, partially offset by increased recoveries and capitalization. On a per boe basis, G&A for the year ended December 31, 2013 decreased by approximately 13% when compared to 2012. The decrease was primarily a result of higher average sales volumes, which more than offset the higher overall costs realized in 2013 versus 2012.
For 2014, the Company is anticipating G&A expenses after capitalization and recoveries to be approximately $25.0 million ($1.60/boe) based on estimated 2014 average production volumes of approximately 42,500 boe/d to 43,500 boe/d.
General and Administrative Expenses
| | Years ended December 31, |
| ($000s, except where noted) | 2013 | 2012 |
| Gross expenses | 29,145 | 21,170 |
| Capitalized | (5,343) | (4,335) |
| Recoveries | (7,588) | (2,563) |
| G&A expenses | 16,214 | 14,272 |
| G&A expenses, per unit ($/boe) | 2.03 | 2.34 |
Interest and Financing Charges
During the year ended December 31, 2013, Bellatrix recorded $12.5 million ($1.57/boe) of interest and financing charges related to bank debt and its convertible debentures, compared to $9.8 million ($1.61/boe) in 2012. Bellatrix’s convertible debentures were settled during September and October of 2013. The overall increase in interest and financing charges was primarily due to higher interest charges related to the Company’s long-term debt as the Company carried a higher average debt balance in the 2013 year compared to 2012. Bellatrix’s total net debt at December 31, 2013 of $395.5 million includes $287.1 million of bank debt and the net balance of the working capital deficiency.
Interest and Financing Charges(1)
| | Years ended December 31, |
| ($000s, except where noted) | 2013 | 2012 |
| Interest and financing charges | 12,488 | 9,834 |
| Interest and financing charges ($/boe) | 1.57 | 1.61 |
| (1) | Does not include financing charges in relation to the Company’s accretion of decommissioning liabilities |
| Debt to Funds Flow from Operations Ratio | | | |
| | Years ended December 31, |
| ($000s, except where noted) | 2013 | 2012 |
| | | |
| Shareholders’ equity | 903,874 | 381,106 |
| | | |
| Long-term debt | 287,092 | 133,047 |
| Convertible debentures (liability component) | - | 50,687 |
| Working capital (excess) deficiency(2) | 108,390 | 5,843 |
| Total net debt(2) at year end | 395,482 | 189,577 |
| | | |
| Debt to funds flow from operations(1) ratio (annualized)(3) | | |
| Funds flow from operations(1)(annualized) | 157,396 | 119,460 |
| Funds flow from operations(1)(annualized, including Angle funds flow from operations for the full October 1 to December 31, 2013 period) | 203,985 | 119,460 |
| Total net debt(2) at year end | 395,482 | 189,577 |
| Total net debt to periods funds flow from operationsratio (annualized)(3) | 2.5x | 1.6x |
| Total net debt to periods funds flow from operationsratio (annualized, including Angle funds flow from operations for the full October 1 to December 31, 2013 period)(3) | 1.9x | 1.6x |
| | | |
Net debt(2)(excluding convertible debentures)
at year end | 395,482 | 138,890 |
Net debt to periods funds flow from operations ratio (annualized)(3) | 2.5x | 1.2x |
Net debt to periods funds flow from operations ratio (annualized, including Angle funds flow from operations for the full October 1 to December 31, 2013 period)(3) | 1.9x | 1.2x |
| | | |
| Debt to funds flow from operations(1)ratio | | |
| Funds flow from operations(1) for the year | 143,459 | 111,038 |
| Funds flow from operations(1) for the year (including Angle funds flow from operations for the full October 1 to December 31, 2013 period) | 155,106 | 111,038 |
| Funds flow from operations(1) for the year (including Angle funds flow from operations for the full January 1 to December 31, 2013 period) | 219,240 | 111,038 |
| Total net debt(2) to funds flow from operations for the year | 2.8x | 1.7x |
| Total net debt(2) to funds flow from operations for the year (including Angle funds flow from operations for the full October 1 to December 31, 2013 period) | 2.5x | 1.7x |
| | | |
| Net debt(2)(excluding convertible debentures) to funds flow from operations for the year | 2.8x | 1.3x |
| Net debt(2)(excluding convertible debentures) to funds flow from operations for the year (including Angle funds flow from operations for the full January 1 to December 31, 2013 period) | 1.8x | 1.3x |
| | | |
| | | | | | | |
(1)As detailed previously in this MD&A, funds flow from operations is a term that does not have any standardized meaning under GAAP. Funds flow from operations is calculated as cash flow from operating activities, excluding decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs. Refer to the reconciliation of cash flow from operating activities to funds flow from operations appearing elsewhere herein.
(2)Net debt and total net debt are considered additional GAAP measures. Therefore reference to the additional GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2013 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2012 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. A reconciliation between total liabilities under GAAP and total net debt and net debt as calculated by the Company is found in the MD&A.
(3)Total net debt and net debt to periods funds flow from operations ratio (annualized) is calculated based upon fourth quarter funds flow from operations annualized.
Reconciliation of Total Liabilities to Total Net Debt and Net Debt
| | | As at December 31, |
| ($000s) | | | 2013 | 2012 |
| Total liabilities per financial statements | | | 651,306 | 300,315 |
| Current liabilities included within working capital calculation | | | (255,903) | (53,327) |
| Commodity contract liability – long term | | | - | (6,214) |
| Decommissioning liabilities | | | (67,075) | (43,909) |
| Finance lease obligation | | | (11,637) | (13,131) |
| Deferred lease inducements | | | (2,565) | - |
| Deferred taxes | | | (27,034) | - |
| | | | | |
| Working Capital | | | | |
| Current assets | | | (128,800) | (52,447) |
| Current liabilities | | | 255,903 | 53,327 |
| Current portion of finance lease | | | (1,495) | (1,425) |
| Current portion of deferred lease inducements | | | (285) | - |
| Net commodity contract asset (liability) | | | (16,933) | 6,388 |
| | | | 108,390 | 5,843 |
| Total net debt | | | 395,482 | 189,577 |
| Convertible debentures | | | - | (50,687) |
| Net debt | | | 395,482 | 138,890 |
As at December 31, 2013 the Company’s ratio of total net debt to annualized funds flow from operations (based on fourth quarter funds flow from operations) was 2.5 times. The total net debt to annualized funds flow from operations ratio as at December 31, 2013 increased from that at December 31, 2012 of 1.6 times primarily due to an increase in total net debt resulting from the timing and expansion of the Company’s 2013 capital expenditure program, and the acquisition of Angle in the fourth quarter of 2013. As at December 31, 2013 the Company’s ratio of total net debt to annualized funds flow from operations (based on fourth quarter funds flow from operations, including funds flow from operations from Angle had the acquisition occurred effective October 1, 2013) was 1.9 times. The Company continues to take a balanced approach to the priority use of funds flows.
Share-Based Compensation
Non-cash share-based compensation expense for the year ended December 31, 2013 was $5.0 million compared to $3.2 million in 2012. The increase in non-cash share-based compensation expense is primarily a result of a Deferred Share Unit Plan expense of $2.3 million (2012: $1.0 million) which resulted from the issuance of new grants during 2013, and the revaluation of outstanding grants to a higher share trading price at December 31, 2013 than at December 31, 2012, an expense of $1.0 million for Restricted Share Units issued during the year, and an expense of $0.5 million for Performance Share Units issued during the year. The increase is partially offset by higher capitalized share-based compensation of $1.7 million (2012: $1.6 million), and a lower expense net of forfeitures for the Company’s outstanding share options of $2.9 million (2012: $3.8 million).
Depletion and Depreciation
Depletion and depreciation expense for the year ended December 31, 2013 was $85.8 million ($10.77/boe), compared to $75.7 million ($12.40/boe) recognized in 2012. The decrease in depletion and depreciation expense on a per boe basis was primarily a result of an increase in the reserve base used for the depletion calculation, partially offset by a higher cost base and increased future development costs.
For the year ended December 31, 2013 Bellatrix has included a total of $1.3 billion (2012: $524.6 million) for future development costs in the depletion calculation and excluded from the depletion calculation a total of $69.0 million (2012: $37.2 million) for estimated salvage.
Depletion and Depreciation
| | Years ended December 31, |
| ($000s, except where noted) | 2013 | 2012 |
| Depletion and Depreciation | 85,829 | 75,720 |
| Per unit ($/boe) | 10.77 | 12.40 |
Impairment of Assets
In accordance with IFRS, the Company calculates an impairment test when there are indicators of impairment. The impairment test is performed at the asset or cash generating unit (“CGU”) level. IAS 36 – “Impairment of Assets” (“IAS 36”) is a one step process for testing and measuring impairment of assets. Under IAS 36, the asset or CGU’s carrying value is compared to the higher of value-in-use and fair value less costs to sell. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. Fair value less costs to sell is determined to be the amount for which the asset could be sold in an arm’s length transaction. Fair value less costs to sell can be determined by using an observable market metric or by using discounted future net cash flows of proved and probable reserves using forecasted prices and costs. Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or cash generating unit.
The impairment test uses, but is not limited to, an external reserve engineering report which incorporates a full evaluation of reserves on an annual basis or internal reserve updates at quarterly periods, and the latest commodity pricing deck. Estimating reserves is very complex, requiring many judgments based on available geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes.
2013 Impairment
As at December 31, 2013, Bellatrix determined there were no impairment indicators requiring an impairment test to be performed.
2012 Impairment
During the year ended December 31, 2012, Bellatrix performed an impairment test using value-in-use values in accordance with IAS 36 resulting in an excess of the carrying value of three CGUs over their recoverable amount, resulting in a non-cash impairment loss of $14.8 million, using future cash flows at between a 10% - 20% discount rate. The impairment indicators was predominantly weak natural gas prices.
When performed, the impairment test is based upon the higher of value-in-use and estimated fair market values for the Company’s properties, including but not limited to an updated external reserve engineering report. This report incorporates a full evaluation of reserves on an annual basis or internal reserve updates at quarterly periods, and the latest commodity pricing deck. Estimating reserves is very complex, requiring many judgments based on available geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes.
Income Taxes
Deferred income taxes arise from differences between the accounting and tax basis of the Company’s assets and liabilities. For the year ended December 31, 2013, the Company recognized a deferred income tax expense of $19.5 million, compared to a $10.1 million in the 2012 year.
At December 31, 2013, the Company had a total deferred tax liability balance of $27.0 million.
At December 31, 2013, Bellatrix had approximately $1.2 billion in tax pools available for deduction against future income as follows:
($000s) | | Rate % | 2013 | 2012 |
| Intangible resource pools: | | | |
| Canadian exploration expenses | 100 | 99,000 | 56,200 |
| Canadian development expenses | 30 | 691,500 | 358,700 |
| Canadian oil and gas property expenses | 10 | 80,200 | 40,400 |
| Foreign resource expenses | 10 | 900 | 800 |
| Attributed Canadian Royalty Income | (Alberta) 100 | - | 16,100 |
Alberta non-capital losses greater than Federal non-capital losses | (Alberta) 100 | 16,100 | - |
| Undepreciated capital cost(1) | 6 – 55 | 224,900 | 98,000 |
| Non-capital losses (expire through 2027) | 100 | 94,500 | 10,000 |
| Financing costs | 20 S.L. | 15,600 | 3,300 |
| | | 1,222,700 | 583,500 |
| (1) | Approximately $207 million of undepreciated capital cost pools are class 41, which is claimed at a 25% rate. |
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
As detailed previously in this MD&A, funds flow from operations is a term that does not have any standardized meaning under GAAP. Bellatrix’s method of calculating funds flow from operations may differ from that of other companies, and accordingly, may not be comparable to measures used by other companies. Funds flow from operations is calculated as cash flow from operating activities before decommissioning costs incurred, changes in non-cash working capital incurred, and transaction costs.
Reconciliation of Cash Flow from Operating Activities and Funds Flow from Operations
| | Years ended December 31, |
| ($000s) | 2013 | 2012 |
| Cash flow from operating activities | 128,458 | 109,328 |
| Decommissioning costs incurred | 1,057 | 635 |
| Transaction costs | 5,344 | - |
| Change in non-cash working capital | 8,600 | 1,075 |
Funds flow from operations | 143,459 | 111,038 |
Bellatrix’s cash flow from operating activities of $128.5 million ($1.14 per basic share and $1.11 per diluted share) for the year ended December 31, 2013 increased by 17% from the $109.3 million ($1.02 per basic share and $0.95 per diluted share) generated in 2012. Bellatrix generated funds flow from operations of $143.5 million ($1.27 per basic share and $1.24 per diluted share) for the year ended December 31, 2013, an increase of 29% from $111.0 million ($1.03 per basic share and $0.96 per diluted share) for 2012. The increase in funds flow from operations was primarily due to increased light oil, condensate, NGL, and natural gas prices positively impacting revenues and netbacks, partially offset by a higher net realized loss on commodity contracts, increased general and administrative expenses, operating, transportation, and royalties expenses, and the impact of lower heavy oil commodity prices.
Bellatrix maintains a commodity price risk management program to provide a measure of stability to funds flow from operations. Unrealized mark–to–market gains or losses are non-cash adjustments to the fair market value of the contract over its entire term and are included in the calculation of net profit.
A net profit of $71.7 million ($0.63 per basic share and $0.62 per diluted share) was recognized for the year ended December 31, 2013, compared to a net profit of $27.8 million ($0.26 per basic share and $0.25 per diluted share) in 2012. The higher net profit recorded in the year ended December 31, 2013 compared to 2012 was primarily the result of higher funds from operating activities as noted above, a gain on property dispositions compared to a loss recognized in 2012, a gain on corporate acquisition recognized in 2013, and impairment expenses recognized during 2012 but not in 2013, partially offset by increased depletion and depreciation, stock-based compensation, and deferred tax expenses, a lower realized gain on commodity contracts, and an unrealized loss on commodity contracts in 2013 compared to an unrealized gain recognized in 2012.
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
| | Years ended December 31, |
| ($000s, except per share amounts) | 2013 | 2012 |
| Cash flow from operating activities | 128,458 | 109,328 |
| Basic ($/share) | 1.14 | 1.02 |
| Diluted ($/share) | 1.11 | 0.95 |
| Funds flow from operations | 143,459 | 111,038 |
| Basic ($/share) | 1.27 | 1.03 |
| Diluted ($/share) | 1.24 | 0.96 |
| Net profit | 71,675 | 27,771 |
| Basic ($/share) | 0.63 | 0.26 |
| Diluted ($/share) | 0.62 | 0.25 |
Capital Expenditures
Bellatrix invested $303.7 million in capital expenditures during the year ended December 31, 2013, compared to $185.3 million in 2012.
Capital Expenditures
| | Years ended December 31, |
| ($000s) | | 2013 | 2012 |
| Lease acquisitions and retention | 11,190 | 8,303 |
| Geological and geophysical | 140 | 290 |
| Drilling and completion costs | 211,912 | 118,783 |
| Facilities and equipment | 57,767 | 36,811 |
| Exploration and development(1) | 281,009 | 164,187 |
| Corporate(2) | 9,270 | 195 |
| Property acquisitions | 13,380 | 20,966 |
| Total capital expenditures – cash | 303,659 | 185,348 |
| Property dispositions – cash | (70,936) | (6,660) |
| Total net capital expenditures – cash | 232,723 | 178,688 |
| Capital lease additions – non-cash | - | 10,000 |
| Corporate acquisition – non-cash | 595,891 | - |
| Adjustment on property acquisition – non-cash | - | 16,160 |
| Other – non-cash(3) | 12,187 | (285) |
| Total non-cash | 608,078 | 25,875 |
| Total net capital expenditures | 840,801 | 204,563 |
(1)Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the year.
(2)Corporate includes office leasehold improvements, furniture, fixtures and equipment before recoveries realized from landlord lease inducements.
(3)Other includes non-cash adjustments for the current year’s decommissioning liabilities and share based compensation.
During the 2013 year, Bellatrix posted a 100% success rate, drilling and/or participating in 80 gross (52.83 net) wells, resulting in 57 gross (41.22 net) Cardium oil wells, 22 gross (10.86 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.75 net) Cardium gas well.
By comparison, Bellatrix drilled or participated in 34 gross (26.32 net) wells during 2012, which included 28 gross (21.32 net) Cardium light oil horizontal wells, 2 gross (2.0 net) Cardium condensate-rich natural gas wells, 1 gross (1.0 net) Duvernay natural gas horizontal well, and 3 gross (2.0 net) Notikewin/Falher natural gas horizontal wells.
During 2013, the Company installed a 25 km pipeline to the MBL Gas Plant which facilitated processing of an additional 85 mmcf/d capacity. The Company also installed six field compressors totaling 9,700 hp and capable of handling 75 mmcf/d. Additionally, the Company installed approximately 45 km of large diameter group pipelines during 2013.
During the third quarter of 2013, Bellatrix relocated to a new corporate office location. Leasehold improvements and furniture and fixture additions related to the move resulted in approximately $8.6 million of corporate capital additions (before landlord lease inducements) during the third and fourth quarters of 2013.
The $303.7 million capital program for the year ended December 31, 2013 was financed from a combination of funds flow from operations, bank debt, proceeds from dispositions of $70.9 million, and proceeds from the $175.0 million bought deal financing.
Based on the current economic conditions and Bellatrix’s operating forecast for 2014, the Company budgets a net capital program of $370 million funded from the Company’s cash flows and to the extent necessary, bank indebtedness. The 2014 capital budget is expected to be directed primarily towards horizontal drilling and completions activities in the Cardium and Mannville formations.
During the year ended December 31, 2013, Bellatrix realized cash proceeds on dispositions of $70.9 million. Of these proceeds, $51.2 million were related to the disposition of properties in the Baptiste area of West Central Alberta to Daewoo and Devonian. A total net gain on dispositions of $42.5 million was recognized for the year ended December 31, 2013, of which $29.1 million was related to the Daewoo and Devonian disposition. The remainder of the net gain on dispositions was related to a gain on Grafton Joint Venture wells and Troika Joint Venture wells completed during the year ended December 31, 2013, as well as other minor dispositions and swaps which occurred during the year.
During the year ended December 31, 2013, the Company increased its working interest in certain Cardium and Notikewin/Falher lands and production in the Willesden Green (Baptiste) area of Alberta through the acquisition of additional working interests from several companies for a total combined net purchase price of $10 million.
Decommissioning Liabilities
At December 31, 2013, Bellatrix has recorded decommissioning liabilities of $67.1 million, compared to $43.9 million at December 31, 2012, for future abandonment and reclamation of the Company’s properties. For the year ended December 31, 2013, decommissioning liabilities increased by a net $23.2 million as a result of $3.4 million incurred on development activities, $12.1 million incurred from corporate and property acquisitions, $8.5 million resulting from changes in estimates, and $0.9 million as a result of charges for the unwinding of the discount rates used for assessing liability fair values, partially offset by a $0.6 million decrease related to dispositions, and a decrease of $1.1 million for liabilities settled during the period. The $8.5 million increase as a result of changes in estimates was related to increased cost estimates for abandonment and reclamation of the Company’s core and non-core operating areas as a result of actual abandonment costs incurred and revised industry guidance. In addition, the Company revised the timing of future decommissioning cash flows to better reflect the anticipated abandonment timelines.
Liquidity and Capital Resources
As an oil and gas business, Bellatrix has a declining asset base and therefore relies on ongoing development and acquisitions to replace production and add additional reserves. Future oil and natural gas production and reserves are highly dependent upon the success of exploiting the Company’s existing asset base and in acquiring additional reserves. To the extent Bellatrix is successful or unsuccessful in these activities, cash flow could be increased or decreased.
Bellatrix is focused on growing oil and natural gas production from its diversified portfolio of existing and emerging resource plays in Western Canada. Bellatrix remains highly focused on key business objectives of maintaining financial strength and optimizing capital investments – which it seeks to attain through a disciplined approach to capital spending, a flexible investment program and financial stewardship. Natural gas prices are primarily driven by North American supply and demand, with weather being the key factor in the short term. Bellatrix believes that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs. Bellatrix’s results are affected by external market and risk factors, such as fluctuations in the prices of crude oil and natural gas, movements in foreign currency exchange rates and inflationary pressures on service costs. Recent market conditions have resulted in Bellatrix experiencing recent upward trends in natural gas, light oil and condensate, and NGL pricing.
Liquidity risk is the risk that Bellatrix will not be able to meet its financial obligations as they become due. Bellatrix actively manages its liquidity through daily and longer-term cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its bank credit facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic risk management opportunities, and maintaining sufficient cash flows for compliance with operating debt covenants. Bellatrix is fully compliant with all of its operating debt covenants.
Bellatrix generally relies upon its operating cash flows and its credit facilities to fund capital requirements and provide liquidity. Future liquidity depends primarily on cash flow generated from operations, existing credit facilities and the ability to access debt and equity markets. From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. There can be no assurance that future debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to Bellatrix.
Credit risk is the risk of financial loss to Bellatrix if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from Bellatrix’s trade receivables from joint venture partners, petroleum and natural gas marketers, and financial derivative counterparties.
A substantial portion of Bellatrix’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Bellatrix currently sells substantially all of its production to eight primary purchasers under standard industry sale and payment terms. The most significant 60 day exposure to a single counterparty is approximately $16.5 million. Purchasers of Bellatrix’s natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. Bellatrix has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in Bellatrix reducing or mitigating its exposures to certain counterparties where it is deemed warranted and permitted under contractual terms.
Bellatrix may be exposed to third party credit risk through its contractual arrangements with its current or future partners and joint venture partners, marketers of its petroleum and natural gas production, derivative counterparties and other parties. In the event such entities fail to meet their contractual obligations to Bellatrix, such failures may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in Bellatrix’s ongoing capital program, potentially delaying the program and the results of such program until Bellatrix finds a suitable alternative partner.
Total net debt levels of $395.5 million at December 31, 2013 have increased by $205.9 million from $189.6 million at December 31, 2012, primarily as a consequence of an increase in a working capital deficiency and bank debt as the Company executed its capital program for the 2013 year. Included within the working capital deficiency is $99.4 million in advances from joint venture partners representing drilling obligations predominantly under the Company’s joint venture obligations with TCA and Grafton, and under the Daewoo and Devonian Partnership. Total net debt excludes unrealized commodity contract assets and liabilities, deferred taxes, finance lease obligations, deferred liabilities and decommissioning liabilities, and for the year ended December 31, 2012, it included the liability component of convertible debentures.
Funds flow from operations represents 47% of the funding requirements for Bellatrix’s capital expenditures for the year ended December 31, 2013.
As of December 31, 2013, the Company’s credit facilities are available on an extendible revolving term basis and consist of a $50 million operating facility provided by a Canadian bank and a $450 million syndicated facility provided by nine financial institutions. Bellatrix’s credit facility was redetermined by its lenders to $500 million concurrent with the closing of the acquisition of Angle on December 11, 2013.
Amounts borrowed under the credit facilities will bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 1.00% to 3.50%, depending on the type of borrowing and the Company’s debt to cash flow ratio. A standby fee is charged of between 0.50% and 0.875% on the undrawn portion of the credit facilities, depending on the Company’s debt to cash flow ratio. The credit facilities are secured by a $1 billion debenture containing a first ranking charge and security interest. Bellatrix has provided a negative pledge and undertaking to provide fixed charges over its properties in certain circumstances.
The revolving period for the revolving term credit facility will end on June 24, 2014, unless extended for a further 364 day period. Should the facility not be extended it will convert to a non-revolving term facility with the full amount outstanding due 366 days after the last day of the revolving period of June 24, 2014. The borrowing base will be subject to re-determination on May 31 and November 30 in each year prior to maturity, with the next semi-annual redetermination occurring on May 31, 2014.
As at December 31, 2013, approximately $212.4 million or 42% of unused and available bank credit under its credit facilities was available to fund Bellatrix’s ongoing capital spending and operational requirements.
On September 4, 2013, the Company announced the issuance of a notice of redemption to holders of its then outstanding $55.0 million convertible debentures, with the redemption date set as October 21, 2013. During September and October 2013, the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of 9,794,848 common shares of the Company. A reduction to the deficit of $1.3 million was recognized in connection with the settlement of the convertible debentures during the year ended December 31, 2013.
Bellatrix currently has commitments associated with its credit facilities outlined above and the commitments outlined under the “Commitments” section. Bellatrix continually monitors its capital spending program in light of the recent volatility with respect to commodity prices and Canadian dollar exchange rates with the aim of ensuring the Company will be able to meet future anticipated obligations incurred from normal ongoing operations with funds flow from operations and draws on Bellatrix’s credit facility, as necessary. Bellatrix has the ability to fund its 2014 capital program of $370 million by utilizing cash flow, proceeds from asset dispositions, and to the extent necessary, bank indebtedness.
As at February 28, 2014, Bellatrix had outstanding a total of 10,561,007 options exercisable at an average exercise price of $4.89 per share and 171,511,226 common shares.
Related Party Transactions
Previous to 2013, the Company entered into agreements to obtain financing in the amount of $5.3 million for the construction of certain facilities.
Members of the Company’s management team and entities affiliated with them provided financing of $900,000. The terms of the transactions with those related parties were the same as those with arms-length participants.
Commitments
As at December 31, 2013, Bellatrix committed to drill 10 gross (5.7 net) wells pursuant to farm-in agreements. Bellatrix expects to satisfy these drilling commitments at an estimated cost of approximately $20.1 million.
In addition, Bellatrix entered into two joint operating agreements during the 2011 year and an additional joint operation agreement during 2012. The agreements include a minimum commitment for the Company to drill a specified number of wells each year over the term of the individual agreements. The details of these agreements are provided in the table below:
| Joint Operating Agreement | Feb. 1, 2011 | Aug. 4, 2011 | Dec. 14, 2012 |
| Commitment Term | 2011 to 2015 | 2011 to 2016 | 2014 to 2018 |
| Minimum wells per year(gross and net) | 3 | 5 to 10 | 2 |
| Minimum total wells(gross and net) | 15 | 40 | 10 |
| Estimated total cost ($000s) | $ 52.5 | $ 140.0 | $ 35.0 |
| Remaining wells to drill at December 31, 2013 | - | 12 | 7 |
| Remaining estimated total cost($000s) | $ - | $ 42.0 | $ 24.5 |
Bellatrix also has certain drilling commitments relating to the Grafton Joint Venture, the Daewoo and Devonian Partnership, and the Troika Joint Venture previously discussed. In meeting the drilling commitments under these agreements, Bellatrix will satisfy some of the drilling commitments under the joint operating agreements described above.
| Agreement | Grafton | Daewoo and Devonian | Troika |
| Commitment Term | 2013 to 2015 | 2013 to 2016 | 2013 to 2014 |
| Minimum total wells(gross)(1) | 58 | 70 | 63 |
| Minimum total wells(net)(1) | 10.44 | 35.0 | 31.5 |
| Estimated total cost ($000s) (gross)(1) | $ 244.0 | $ 200.0 | $ 240.0 |
| Estimated total cost ($000s) (net) (1) | $ 44.0 | $ 100.0 | $ 120.0 |
| Remaining wells to drill at December 31, 2013(gross) | 46 | 51 | 42 |
| Remaining wells to drill at December 31, 2013(net) | 8.2 | 25.6 | 21.0 |
| Remaining estimated total cost($000s) (gross) | $ 192.3 | $ 198.3 | $ 160.0 |
| Remaining estimated total cost($000s) (net) | $ 34.6 | $ 99.2 | $ 80.0 |
| (1) | Gross and net estimated total cost values and gross and net minimum total wells for the Troika and Grafton Joint Ventures represent Bellatrix’s total capital and well commitments pursuant to the Troika and Grafton Joint Venture agreements. Gross and net minimum total wells for the Daewoo and Devonian Partnership represent Bellatrix’s total well commitments pursuant to the Daewoo and Devonian Partnership agreement. Gross and net estimated total cost values for the Daewoo and Devonian Partnership represent Bellatrix’s estimated cost associated with its well commitments under the Daewoo and Devonian Partnership agreement. |
The Company had the following liabilities as at December 31, 2013:
| Liabilities($000s) | Total | < 1 Year | 1-3 Years | 3-5 Years | More than
5 years |
| Accounts payable and accrued liabilities(1) | $ 137,465 | $ 137,465 | $ - | $ - | $ - |
| Advances from joint venture partners | 99,380 | 99,380 | - | - | - |
| Long-term debt – principal(2) | 287,092 | - | 287,092 | - | - |
| Commodity contract liability | 17,278 | 17,278 | - | - | - |
| Decommissioning liabilities(3) | 67,075 | - | 2,198 | 3,361 | 61,516 |
| Finance lease obligation | 13,132 | 1,495 | 3,208 | 2,708 | 5,721 |
| Deferred lease inducements | 2,850 | 285 | 570 | 570 | 1,425 |
| Total | $ 624,272 | $ 255,903 | $ 293,068 | $ 6,639 | $ 68,662 |
(1)Includes $0.7 million of accrued interest payable in relation to the credit facilities is included in Accounts Payable and Accrued Liabilities.
(2)Bank debt is based on a revolving term which is reviewed annually and converts to a 366 day non-revolving facility if not renewed. Interest due on the bank credit facility is calculated based upon floating rates.
(3)Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over the life of the Company’s properties (between 2016 and 2063).
Off-Balance Sheet Arrangements
The Company has certain fixed-term lease agreements, including primarily office space leases, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. The lease agreements do not currently provide for early termination. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2013.
The Company’s commitment for office space as at December 31, 2013 is as follows:
($000s)
Year | | Gross Amount | Recoveries | Net amount |
| 2014 | $ 4,562 | $ (1,014) | $ 3,548 |
| 2015 | 3,094 | - | 3,094 |
| 2016 | 3,094 | - | 3,094 |
| 2017 | 3,094 | - | 3,094 |
| 2018 | 2,911 | - | 2,911 |
| More than 5 years | 12,206 | - | 12,206 |
| | | | | | |
Business Prospects and 2014 Year Outlook
Bellatrix continues to develop its core assets and conduct exploration programs utilizing its large inventory of geological prospects.
For the 2014 year, Bellatrix will continue to be active in drilling with 10 to 12 rigs operating in its two core resource plays, the Cardium oil and Mannville condensate rich gas, utilizing horizontal drilling multi-fracturing technology. During the first quarter of 2014, Bellatrix plans jointly with the Blaze Gas Plant to install 60 km of pipeline to the Blaze Gas Plant from the Ferrier area to facilitate access to 120 mmcf/d capacity. In the third quarter of 2014, Bellatrix plans to install a 20 km pipeline to the Brazeau Gas Plant in order to access an additional 40-50 mmcf/d of capacity, and to build two oil batteries with 5,000 bbls/d of processing capacity. Additionally, throughout 2014 Bellatrix intends to install 21 field compressors totalling 30,500 hp and capable of handling 245 mmcf/d, and to install more than 60 km of large diameter group pipelines. A new Bellatrix gas plant is planned to be built in the Alder Flats to be in service July, 2015. The new plant is anticipated to provide 110 mmcf/d capacity, 99% C3 Recovery and 100% C4+ Recovery, with the potential to double the capacity in 2016.
An initial net capital budget of $370 million has been set for fiscal 2014. Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2014 budget is anticipated to provide 2014 average daily production of approximately 42,500 boe/d to 43,500 boe/d and an exit rate of approximately 47,000 boe/d.
Financial Reporting Update
Future Accounting Pronouncements
The following pronouncements from the IASB are applicable to Bellatrix and will become effective for future reporting periods, but have not yet been adopted:
IFRS 9 - “Financial Instruments”, which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The effective date of the new standard has been deferred indefinitely. The extent of the impact of the adoption of IFRS 9 has not yet been determined.
Amendments to “Offsetting Financial Assets and Financial Liabilities” addressed within IAS 32 - “Financial Instruments: Presentation”, which provides guidance regarding when it is appropriate and permissible for an entity to disclose offsetting financial assets and financial liabilities on a net basis. The amendments to this standard are effective for annual periods beginning on or after January 1, 2014. The extent of the impact of the adoption of IAS 32 amendments has not yet been determined.
IFRIC 21 - “Levies”, which establishes guidelines for the recognition and accounting treatment of a liability relating to a levy imposed by a government. This standard is effective for annual periods beginning on or after January 1, 2014. The extent of the impact of the adoption of IFRIC 21 has not yet been determined.
Business Risks and Uncertainties
General
Bellatrix’s production and exploration activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers to the much larger integrated petroleum companies.
Bellatrix is subject to the various types of business risks and uncertainties including:
| · | Finding and developing oil and natural gas reserves at economic costs; |
| · | Production of oil and natural gas in commercial quantities; and |
| · | Marketability of oil and natural gas produced. |
In order to reduce exploration risk, the Company strives to employ highly qualified and motivated professional employees with a demonstrated ability to generate quality proprietary geological and geophysical prospects. To help maximize drilling success, Bellatrix combines exploration in areas that afford multi-zone prospect potential, targeting a range of low to moderate risk prospects with some exposure to select high-risk with high-reward opportunities. Bellatrix also explores in areas where the Company has significant drilling experience.
The Company mitigates its risk related to producing hydrocarbons through the utilization of the most appropriate technology and information systems managed by qualified personnel. In addition, Bellatrix seeks to maintain operational control of the majority of its prospects.
Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. In order to mitigate such risks, Bellatrix conducts its operations at high standards and follows safety procedures intended to reduce the potential for personal injury to employees, contractors and the public at large. The Company maintains current insurance coverage for general and comprehensive liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect changing corporate requirements, as well as industry standards and government regulations. Bellatrix may periodically use financial or physical delivery contracts to reduce its exposure against the potential adverse impact of commodity price volatility, as governed by formal policies approved by senior management subject to controls established by the Board.
Pricing and Marketing
Oil
The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Worldwide supply and demand primarily determines oil prices. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the availability of transportation, the value of refined products, the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. The NEB is currently undergoing a consultation process to update the current regulations governing the issuance of export licences. The updating process is necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act which received Royal Assent on June 29, 2012 (the "Prosperity Act"). In this transitory period, the NEB has issued, and is currently following an "Interim Memorandum of Guidance concerning Oil and Gas Export Applications and Gas Import Applications under Part VI of the National Energy Board Act".
Natural Gas
Alberta's natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system such as the Alberta "NIT" (Nova Inventory Transfer), at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange (NGX) or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can be set by such supply and demand. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB.
Royalties and Incentives - General
In addition to federal regulation, each province has legislation and regulations which govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oil sands projects, crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty like interests are carved out of the working interest owner's interest, from time to time, through non public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.
Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.
Land Tenure
The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.
Each of the provinces of Alberta, British Columbia and Saskatchewan has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license. On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary term.
Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license.
Environmental Regulation
The oil and natural gas industry is currently subject to regulation pursuant to a variety of provincial and federal environmental legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability, and the imposition of material fines and penalties. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil and gas operations, including those of the Company. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition.
Global Financial Crisis
Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels have caused significant volatility in commodity prices. These events and conditions have caused a decrease in confidence in the broader U.S. and global credit and financial markets and have created a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. While there are signs of economic recovery, these factors have negatively impacted company valuations and are likely to continue to impact the performance of the global economy going forward. Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, actions taken by OPEC and the ongoing global credit and liquidity concerns. This volatility may in the future affect the Company's ability to obtain equity or debt financing on acceptable terms.
Substantial Capital Requirements
The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity offerings, the Company's ability to do so is dependent on, among other factors, the overall state of the capital markets, the Company’s credit rating (if applicable), interest rates, royalty rates, tax burden due to current and future tax laws, and investor appetite for investments in the energy industry and the Company's securities in particular. Further, if the Company’s revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business financial condition, results of operations and prospects.
Third Party Credit Risk
The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.
Critical Judgments and Accounting Estimates
The reader is advised that the critical accounting estimates, policies, and practices as described herein continue to be critical in determining Bellatrix’s financial results.
The reader is cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. The following discussion outlines accounting policies and practices that are critical to determining Bellatrix’s financial results.
Critical Accounting Judgments
Oil and gas reserves
Reserves and resources are used in the units of production calculation for depreciation, depletion and amortization and the impairment analysis which affect net profit. There are numerous uncertainties inherent in estimating oil and gas reserves. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net profit as further information becomes available and as the economic environment changes.
Identification of CGUs
Bellatrix’s assets are aggregated into CGUs, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows, geography, geology, production profile and infrastructure of its assets.
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.
Income taxes
Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.
Business combinations
Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or loss. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.
Legal, Environmental Remediation and Other Contingent Matters
The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favor, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceeding related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position or results of operations.
The Company reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Company’s management monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances.
With the above risks and uncertainties the reader is cautioned that future events and results may vary substantially from that which Bellatrix currently foresees.
Controls and Procedures
Disclosure Controls and Procedures
The Company’s President and Chief Executive Officer (“CEO”) and Executive Vice President, Finance and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company. Based on the evaluation, the officers concluded that Bellatrix’s disclosure controls and procedures were effective as at December 31, 2013.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting, which is a process designed by, or designed under the supervision of, our President and CEO and our Executive Vice President, Finance and CFO, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for the external purposes in accordance with GAAP.
Under the supervision and with the participation of management, including our CEO and our CFO, an evaluation of the effectiveness of the Company’s internal control over financial reporting was conducted as of December 31, 2013 based on the criteria described in “Internal Control – Integrated Framework” issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that, as of December 31, 2013, the Company’s internal control over financial reporting was effective.
Bellatrix acquired 100% of the issued and outstanding common shares and 5.75% convertible unsecured subordinated debentures of Angle Energy Inc. ("Angle") on December 11, 2013, as more fully described in note 6 of the Company’s notes to the audited consolidated financial statements as at and for the year ended December 31, 2013. This business was excluded from management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, due to the proximity of the acquisition to year-end. For the quarter and year ended December 31, 2013, total revenue attributable to Angle was approximately 12% and 3%, respectively, of the consolidated total revenues as reported in the Company’s audited consolidated financial statements. For the quarter and year ended December 31, 2013, a net profit before tax of $1.7 million and $1.7 million, respectively, was attributable to Angle as compared to pre-tax earnings of $24.8 million and $91.2 million, respectively, for the consolidated entity.
Additionally, at December 31, 2013, current assets and current liabilities attributable to Angle were approximately 19% and 13% of consolidated current assets and liabilities, respectively, and its non-current assets and non-current liabilities attributable to Angle were approximately 42% and 52% of consolidated non-current assets and non-current liabilities, respectively.
The Company is required to disclose herein any change in the Company’s internal control over financial reporting that occurred during the year ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. There has been no change in our internal control over financial reporting that occurred during the year ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Limitations of the Effectiveness of Controls
It should be noted that a control system, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure controls and procedures and internal controls over financial reporting will prevent all errors or fraud.
CEO and CFO Certifications
Our President and CEO and our Executive Vice President, Finance and CFO have attested to the quality of the public disclosure in our fiscal 2013 reports filed with the Canadian securities regulators and the SEC, and have filed certifications with them.
Sensitivity Analysis
The table below shows sensitivities to funds flow from operations as a result of product price, exchange rate, and interest rate changes. This is based on actual average prices received for the fourth quarter of 2013 and average production volumes of 23,968 boe/d during that period, as well as the same level of debt outstanding as at December 31, 2013. Diluted weighted average shares are based upon the fourth quarter of 2013. These sensitivities are approximations only, and not necessarily valid under other significantly different production levels or product mixes. Commodity price risk management activities can significantly affect these sensitivities. Changes in any of these parameters will affect funds flow as shown in the table below:
| | Funds Flow from Operation(1) | Funds Flow from Operations (1) |
| | (annualized) | Per Diluted Share |
| Sensitivity Analysis | ($000s) | ($) |
| Change of US $1/bbl WTI | 2,300 | 0.02 |
| Change of $0.10/ mcf | 3,200 | 0.02 |
| Change of US $0.01 CDN/ US exchange rate | 1,400 | 0.01 |
| Change in prime of 1% | 2,900 | 0.02 |
| | | | | |
(1)The term “funds flow from operations” should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with GAAP as an indicator of the Company’s performance. Therefore reference to additional GAAP measures of diluted funds flow from operations or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found elsewhere herein. Funds flow from operations per share is calculated using the weighted average number of common shares for the period.
Selected Quarterly Consolidated Information
The following table sets forth selected consolidated financial information of the Company for the quarters in 2013 and 2012.
2013 – Quarter ended (unaudited) ($000s, except per share amounts) | | | March 31 | | | | June 30 | | | | Sept. 30 | | | | Dec. 31 | |
| Revenues before royalties and risk management | | | 65,543 | | | | 74,564 | | | | 68,329 | | | | 83,455 | |
| Cash flow from operating activities | | | 35,527 | | | | 29,611 | | | | 25,069 | | | | 38,025 | |
| Cash flow from operating activities per share | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.33 | | | $ | 0.27 | | | $ | 0.23 | | | $ | 0.30 | |
| Diluted | | $ | 0.30 | | | $ | 0.25 | | | $ | 0.21 | | | $ | 0.29 | |
| Funds flow from operations(1) | | | 37,545 | | | | 36,563 | | | | 30,002 | | | | 39,349 | |
| Funds flow from operations per share(1) | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.35 | | | $ | 0.34 | | | $ | 0.28 | | | $ | 0.31 | |
| Diluted | | $ | 0.32 | | | $ | 0.31 | | | $ | 0.25 | | | $ | 0.30 | |
| Net profit | | | 4,561 | | | | 15,466 | | | | 29,453 | | | | 22,195 | |
| Net profit per share | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.04 | | | $ | 0.14 | | | $ | 0.27 | | | $ | 0.17 | |
| Diluted | | $ | 0.04 | | | $ | 0.13 | | | $ | 0.25 | | | $ | 0.17 | |
| Net capital expenditures (cash) | | | 91,614 | | | | 46,700 | | | | 49,452 | | | | 99,199 | |
2012 – Quarter ended (unaudited) ($000s, except per share amounts) | | | March 31 | | | | June 30 | | | | Sept. 30 | | | | Dec. 31 | |
| Revenues before royalties and risk management | | | 58,191 | | | | 50,714 | | | | 48,126 | | | | 62,283 | |
| Cash flow from operating activities | | | 24,056 | | | | 28,458 | | | | 24,807 | | | | 32,007 | |
| Cash flow from operating activities per share | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.22 | | | $ | 0.24 | | | $ | 0.23 | | | $ | 0.30 | |
| Diluted | | $ | 0.21 | | | $ | 0.22 | | | $ | 0.22 | | | $ | 0.28 | |
| Funds flow from operations(1) | | | 29,194 | | | | 25,366 | | | | 26,613 | | | | 29,865 | |
| Funds flow from operations per share(1) | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.27 | | | $ | 0.24 | | | $ | 0.25 | | | $ | 0.28 | |
| Diluted | | $ | 0.25 | | | $ | 0.22 | | | $ | 0.23 | | | $ | 0.26 | |
| Net profit (loss) | | | 9,172 | | | | 9,963 | | | | (615 | ) | | | 9,251 | |
| Net profit (loss) per share | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.09 | | | $ | 0.09 | | | ($ | 0.01 | ) | | $ | 0.09 | |
| Diluted | | $ | 0.08 | | | $ | 0.09 | | | ($ | 0.01 | ) | | $ | 0.08 | |
| Net capital expenditures (cash) | | | 73,831 | | | | 16,284 | | | | 35,515 | | | | 64,383 | |
| (1) | Refer to “Additional GAAP Measures” in respect of the term “funds flow from operations” and “funds flow from operations per share”. |
The quarterly results for 2013 compared to 2012 were positively impacted by increased production resulting from the significant expansion of Bellatrix’s 2013 drilling program and higher overall commodity prices realized during the 2013 quarters compared to the 2012 quarters.
During the first quarter of 2013, the Company spent $91.6 million in capital expenditures, compared to $74.1 million in the first quarter of 2012. The Company drilled or participated in 21 gross (17.08 net) wells in the first quarter of 2013, compared to 13 gross (10.72 net) wells in the comparative 2012 quarter. Increased sales volumes of 19,343 boe/d in the first quarter of 2013 compared to 15,900 boe/d in the first quarter of 2012 contributed to increased total revenue before other income of $64.9 million in the first quarter of 2013, compared to $57.7 million in the first quarter of 2012. The increase resulted from the 2012 and first quarter 2013 drilling programs, in conjunction with stronger natural gas and light oil and condensate prices, offset slightly by depressed NGL and heavy oil pricing.
In the second quarter of 2013, the Company closed the Grafton Joint Venture, under which Grafton agreed to contribute 82%, or $100 million, to the $122 million joint venture to participate in an expected 29 Notikewin/Falher wells in exchange for 54% of the Company’s working interest until payout under the terms of the joint venture. In the second quarter of 2013, the Company spent $46.7 million (2012: $18.3 million) in capital expenditures, and drilled 5 gross (5.00 net) wells, compared to 2 gross (1.72 net) wells in the same period in 2012. Sales volumes increased by 33% to 22,102 boe/d in the second quarter of 2013, compared to 16,569 boe/d in the second quarter of 2012.
The Company completed several major transactions during the third quarter of 2013. During September 2013, an asset sale associated with the Daewoo and Devonian Partnership arrangement was closed, resulting in gross proceeds of $52.5 million (subject to closing adjustments). Additionally during September 2013, Grafton elected to exercise an option to increase its committed capital investment by an additional $100 million on the same terms and conditions as the Grafton Joint Venture which closed during the second quarter of 2013. In the third quarter of 2013, the Company spent $49.5 million on capital expenditures compared to $39.8 million in the third quarter of 2012. In the third quarter of 2013, Bellatrix drilled 19 gross (9.40 net) wells, compared to 9 gross (7.71 net) wells in the third quarter of 2012.
Fourth quarter 2013 results are compared in detail to fourth quarter 2012 results throughout this MD&A.
Overall, the Company’s cash flows were positively impacted primarily due to increased sales volumes and cash flows resulting from the success and execution of the Company’s 2013 drilling program and stronger natural gas commodity prices.
Selected Annual Consolidated Information
The following table sets forth selected consolidated financial information of the Company for the most recently completed year ending December 31, 2013 and for comparative 2012 and 2011 years.
Years ended December 31, ($000s, except per share amounts) | 2013 | 2012 | 2011 |
| Revenues (before royalties and risk management) | 291,891 | 219,314 | 202,318 |
| Funds flow from operations(1) | 143,459 | 111,038 | 94,237 |
| Funds flow from operations per share(1) | | | |
| Basic | $1.27 | $1.03 | $0.91 |
| Diluted | $1.24 | $0.96 | $0.87 |
| Cash flow from operating activities | 128,458 | 109,328 | 98,192 |
| Cash flow from operating activities per share | | | |
| Basic | $1.14 | $1.02 | $0.95 |
| Diluted | $1.11 | $0.95 | $0.87 |
| Net profit (loss) | 71,675 | 27,771 | (5,949) |
| Net profit (loss) per share | | | |
| Basic | $0.63 | $0.26 | ($0.06) |
| Diluted | $0.62 | $0.25 | ($0.06) |
| Net capital expenditures – cash | 232,723 | 178,688 | 175,358 |
| Total assets | 1,555,180 | 681,421 | 580,422 |
| Total net debt(1) | 395,482 | 189,577 | 119,250 |
| Non-current financial liabilities | | | |
| Future income taxes | 27,034 | - | - |
| Decommissioning liabilities | 67,075 | 43,909 | 45,091 |
| Sales volumes (boe/d) | 21,829 | 16,686 | 11,954 |
| (1) | Refer to “Additional GAAP Measures” in respect of the terms “funds flow from operations,” “funds flow from operations per share,” “net debt” and “total net debt.” |
Detailed discussions on variations from 2013 annual results to 2012 annual results are contained throughout this MD&A.
Sales volumes increased by 40% to 16,686 boe/d in 2012 from 11,954 boe/d in 2011, largely as a result of an increased capital program of $185.3 million in 2012, compared to $179.6 million in 2011, and drilling success achieved in the Cardium and Notikewin resource plays. As a result of the significant increase in sales volumes between the years, revenues before royalties and risk management increased to $219.3 million in 2012, compared to $202.3 million realized in 2011, despite reductions in commodity prices between the years. Cash flows were impacted by the increased sales volumes, decreased commodity prices, and lower operating costs, transportation costs, and royalty expenses per boe between the years.
