Exhibit 99.35
For Immediate Release
TSX: BXE
BELLATRIX EXPLORATION LTD. ANNOUNCES YEAR END 2010 FINANCIAL RESULTS
March 10, 2011 — (TSX: BXE) Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) announces its financial and operating results for year ended December 31, 2010.
Forward-Looking Statements
This press release contains forward-looking statements. Please refer to our cautionary language on forward-looking statements and
the other matters set forth at the beginning of the management’s discussion and analysis attached to this press release.
HIGHLIGHTS
| | Years ended December 31, | |
| | 2010 | | 2009 | |
FINANCIAL | | | | | |
(CDN$000s except share and per share amounts) | | | | | |
Revenue (before royalties and risk management(1)) | | 117,673 | | 109,014 | |
Funds flow from operations (2) | | 53,042 | | 36,025 | |
Per basic share | | $ | 0.57 | | $ | 0.46 | |
Per diluted share(5) | | $ | 0.54 | | $ | 0.46 | |
Cash flow from operating activities | | 44,272 | | 30,671 | |
Per basic share | | $ | 0.47 | | $ | 0.39 | |
Per diluted share(5) | | $ | 0.46 | | $ | 0.39 | |
Net loss | | (27,533 | ) | (126,620 | ) |
Per basic share | | $ | (0.30 | ) | $ | (1.61 | ) |
Per diluted share (5) | | $ | (0.30 | ) | $ | (1.61 | ) |
Exploration and development | | 98,387 | | 15,844 | |
Corporate and property acquisitions | | 8,361 | | 643 | |
Capital expenditures – cash | | 106,748 | | 16,487 | |
Property dispositions – cash | | (14,567 | ) | (92,921 | ) |
Non-cash items | | 2,280 | | (492 | ) |
Total capital expenditures – net | | 94,461 | | (76,926 | ) |
Long-term debt | | 41,172 | | 27,902 | |
Convertible debentures(3) | | 47,599 | | 81,684 | |
Working capital excess | | (1,327 | ) | (2,317 | ) |
Total net debt (3) | | 87,444 | | 107,269 | |
Total assets | | 487,156 | | 440,970 | |
Shareholders’ equity | | 322,789 | | 281,351 | |
1
| | | | Years ended December 31, | |
| | | | 2010 | | 2009 | |
OPERATING | | | | | | | |
Average daily sales volumes | | | | | | | |
Crude oil, condensate and NGLs | | (bbls/d) | | 2,550 | | 2,877 | |
Natural gas | | (mcf/d) | | 35,814 | | 33,295 | |
Total oil equivalent | | (boe/d) | | 8,519 | | 8,426 | |
Average prices | | | | | | | |
Light crude oil and condensate | | ($/bbl) | | 76.25 | | 61.24 | |
NGLs | | ($/bbl) | | 39.81 | | 27.73 | |
Heavy oil | | ($/bbl) | | 60.50 | | 49.10 | |
Crude oil, condensate and NGLs | | ($/bbl) | | 65.47 | | 49.65 | |
Crude oil and condensate (including risk management(1)) | | ($/bbl) | | 66.59 | | 49.62 | |
Natural gas | | ($/mcf) | | 4.19 | | 4.50 | |
Natural gas (including risk management (1)) | | ($/mcf) | | 5.28 | | 5.96 | |
Total oil equivalent | | ($/boe) | | 37.20 | | 34.72 | |
Total oil equivalent (including risk management (1)) | | ($/boe) | | 42.15 | | 40.49 | |
| | | | | | | |
Statistics | | | | | | | |
Operating netback(4) | | ($/boe) | | 16.42 | | 13.11 | |
Operating netback(4) (including risk management (1)) | | ($/boe) | | 21.37 | | 18.88 | |
Transportation | | ($/boe) | | 1.20 | | 1.26 | |
Production expenses | | ($/boe) | | 12.21 | | 14.64 | |
General & administrative | | ($/boe) | | 3.03 | | 3.33 | |
Royalties as a % of sales after transportation | | | | 20% | | 17% | |
| | | | | | | |
COMMON SHARES | | | | | | | |
Common shares outstanding | | | | 97,446,026 | | 78,809,039 | |
Share options outstanding | | | | 5,823,377 | | 4,213,733 | |
Shares issuable on conversion of convertible debentures(6) | | | | 9,821,429 | | 5,305,250 | |
Diluted common shares outstanding | | | | 113,090,832 | | 88,328,022 | |
Diluted weighted average shares (5) | | | | 101,232,085 | | 78,548,800 | |
| | | | | | | |
SHARE TRADING STATISTICS | | | | | | | |
| | | | | | | |
(CDN$, except volumes) based on intra-day trading | | | | | | | |
High | | | | 5.05 | | 2.75 | |
Low | | | | 2.53 | | 0.48 | |
Close | | | | 4.80 | | 2.65 | |
Average daily volume | | | | 544,435 | | 235,339 | |
(1) The Company has entered into various commodity price risk management contracts which are considered to be economic hedges. Per unit metrics after risk management includes only the realized portion of gains or losses on commodity contracts.
The Company does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per share metrics calculations disclosed.
(2) The highlights section contains the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with Canadian generally accepted accounting principles (“GAAP”) as an indicator of the Company’s performance. Therefore reference to diluted funds flow from operations or
2
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 Management Discussion and Analysis (“MD&A”). Funds flow from operations per share is calculated using the weighted average number of common shares for the period.
(3) Net debt and total net debt are considered non-GAAP terms. The Company’s calculation of net debt includes the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current capital lease obligation and short-term future income tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes asset retirement obligations, long-term capital lease obligation and the future income tax assets and liabilities. A reconciliation between total liabilities under GAAP and total net debt as calculated by the Company is found in the MD&A.
(4) Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income.
(5) Basic weighted average shares for the year ended December 31, 2010 were 93,286,554 (2009: 78,548,800).
In computing weighted average diluted earnings per share for the year ended December 31, 2010 a total of 5,823,377 (2009: 4,213,733) share options and 9,821,429 (2009: 5,305,250) common shares issuable on conversion of convertible debentures were excluded from the calculation as they were not dilutive.
In computing weighted average diluted cash flow from operations and funds flow from operations for the year ended December 31, 2010 a total of 1,083,985 (2009: nil) 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 6,861,546 (2009: nil) common shares issuable on conversion of convertible debentures were also added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 101,232,085. As a consequence, a total of $2.0 million for interest accretion expense (net of income tax effect) was added to the numerator.
(6) Shares issuable on conversion of convertible debentures are calculated as the $55.0 million principal amount of the convertible debentures divided by the conversion price of $5.60 per share.
3
REPORT TO SHAREHOLDERS
There are vital moments in a Company’s development, when the junction of achievement and opportunity position it for even greater success. Bellatrix Exploration Ltd. has reached this pivotal point in its evolution. Bellatrix has successfully navigated the planned paradigm shift to being a low cost operator with a strong balance sheet and with a technically strong management team providing top decile growth in shareholder value driven by the drill bit. In 2010, the Bellatrix team completed the restructuring of the Company’s balance sheet, provided shrewd hedging on both oil and gas production, drove down field lease operating costs, reduced G&A, posted top decile performance in finding and development costs and recycle ratios while exploiting the Company’s extensive drilling inventory of Cardium oil and Notikewin liquids rich gas assets in West Central Alberta.
MARKET AND SHARE TRADING STATS
Bellatrix’s share price has increased significantly from $0.77 on July 1, 2009 to a closing price of $5.80 on March 1, 2011, representing a 653% increase. In comparison, the S&P/TSX Composite Index and S&P/TSX Energy Index increased by 36% and 37%, respectively. The following graph illustrates the Company’s share performance as compared to the S&P/TSX Composite Index and the S&P/TSX Energy Index through the previous 18 months.
PRODUCTION
Production Operations highlights for the year ended December 31, 2010 are as follows:
· 98% drilling success realized on 48 gross wells, including 14 gross (7.8 net) wells in Q4 2010.
· Installed 29.4km of pipeline, built 3 oil batteries and 2 gas compression facilities.
· 2010 sales volumes averaged 8,519 boe/d with an exit rate of 10,500 boe/d (weighted 42% to crude oil, condensate and NGL’s).
4
· Closed the purchase of certain West Pembina property interests for $4.75 million before adjustments on December 10, 2010. This acquisition included an additional 6.5 gross sections (2.5 net) of Cardium rights, for an increase of an additional 10.0 net Cardium horizontal drilling locations, as well as approximately 70 boe/d of production and associated facilities.
· Closed the sale of a non-core property at Mantario, Saskatchewan for net proceeds of approximately $13.6 million after adjustments on December 22, 2010.
· On January 25, 2011, Bellatrix acquired the interest in a section of Frog Lake First Nations lands from a joint venture partner for a net purchase price of $2.2 million after adjustments.
· On January 25, 2011, Bellatrix exercised a right of first refusal increasing its interest in a joint venture property in the Brazeau Area of West Central Alberta for approximately $1.5 million.
· Bellatrix has 211,893 net undeveloped acres in Alberta, British Columbia and Saskatchewan.
As part of the 2011 capital expenditures budget the Corporation anticipates a very active first quarter in 2011 with participation in 22 gross (12.2 net) wells weighted 2/3 oil and 1/3 liquids rich gas. To date in the first quarter of 2011, the Company has drilled or participated in 9 gross (5.5 net) Cardium oil wells and 6 gross (2.4 net) Notikewin liquids rich gas wells. The remaining 7 gross (4.3 net) potential oil wells are scheduled to be drilled prior to the end of Q1.
To date in Q1 2011 the Company has placed 6 gross (4.2 net) Cardium operated wells on production establishing the following average production rates:
6 Wells | | IP1 7 | | 709 boe/d per well |
5 Wells | | IP1 15 | | 539 boe/d per well |
4 wells | | IP1 30 | | 450 boe/d per well |
1 IP represents average boe/d for 7, 15 and 30 days
Currently the Company is producing approximately 11,000 boe/d but has experienced significant downtime associated with freeze offs, a compressor failure and pump failures resulting in production averaging approximately 10,000 boe/d in the first 2 months of Q1. Behind pipe tested production of 1,500 boe/d net will be tied in by the end of Q1.
DRILLING
The Company dramatically increased its capital program in 2010 as compared to 2009. Exploration and development capital expenditures after drilling credits but excluding acquisitions and dispositions were $98.4 million in 2010, compared to $15.8 million in 2009. During the fourth quarter of 2010, Bellatrix spent $34.9 million on capital projects, excluding corporate and asset acquisitions and dispositions, compared to $9.6 million in 2009. In 2010, Bellatrix drilled or participated in 48 (28.8 net) wells including 9 gross (6.3 net) natural gas wells, and 38 gross (21.5 net) oil wells and 1 gross and net dry hole establishing a 98 percent drill bit success rate.
5
FINANCIAL
Financial highlights for the year ended December 31, 2010 are as follows:
· Sales volumes increased 52% to Q4 2010 (10,002 boe/d) from Q4 2009 (6,572 boe/d)
· In 2010 total crude oil, condensate and NGL revenues contributed 53% of total revenue (before other) compared to 49% in 2009. Light crude oil, condensate and NGL revenues in 2010 contributed 85% of total crude oil, condensate and NGL revenue (before other) compared to 39% in 2009.
· Funds flow from operations increased 47% to 2010 ($53.0 million) from 2009 ($36.0 million).
· Per unit production expenses have decreased to $11.31/boe and $12.21/boe for the three and twelve month periods ended December 31, 2010, respectively, which compares to $16.65/boe and $14.64/boe for the comparable periods in 2009, respectively.
· Total net debt of $87.4 million at the end of 2010 compared to 2009 year end debt of $107.7 million.
· Financings:
· closed an equity offering of 13.61 million common shares for $45 million ($3.30 per share) on January 28, 2010.
· closed a $55 million convertible debenture offering on April 20, 2010; these debentures bear interest at 4.75% per annum payable semi-annually, are convertible into common shares at a conversion price of $5.60 per common share, and mature on April 30, 2015.
· closed a bought deal flow through share financing of 4.71 million common shares for $20 million ($4.25 per share) on August 12, 2010.
· Realized natural gas price after including risk management contracts for year ended December 31, 2010 was $5.28/mcf.
The total net proceeds from property dispositions completed in 2010 were $14.6 million which was initially used to pay down debt and ultimately will be directed towards development of Bellatrix’s Cardium oil resource program. Bellatrix’s total net debt including the liability component of its convertible debentures, excluding unrealized commodity contract assets and liabilities, future income tax assets and liabilities, capital lease obligations and asset retirement obligations, as at December 31, 2010 was $87.4 million, compared to $107.3 million at 2009.
Effective December 15, 2010, the Company’s borrowing base was increased from $85 million to $100 million through to the next scheduled borrowing base determination on May 30, 2011.
As at December 31, 2010, Bellatrix had approximately $41.2 million drawn on its extendible, revolving bank credit facility leaving approximately $58.8 million available on its credit facilities.
Bellatrix has approximately $450 million in tax pools available for deduction against future income.
Funds flow from operations for the 2010 year was $53.0 million on gross sales of $117.7 million compared to funds flow from operations for the 2009 year of $36.0 million on gross sales of $109.0 million.
Funds flow from operations for the 2010 fourth quarter was $15.9 million on gross sales of $37.8 million compared to funds flow from operations for the 2009 fourth quarter of $7.7 million on gross sales of $24.0 million.
The net loss for 2010 year was $27.5 million compared to a net loss of $126.6 million for the same period in 2009. The decrease in net loss from the 2009 to that in 2010 was primarily due to the non-cash $114.2 million loss
6
recognized in Q2 2009 on the sale of petroleum and natural gas properties in Saskatchewan. The net loss for the 2010 fourth quarter was $8.2 million compared to a net loss of $8.2 million in the 2009 fourth quarter. The net loss from the 2009 fourth quarter is comparable the 2010 fourth quarter although the 2010 fourth quarter is reflective of higher sales revenues, offset by increased depletion, depreciation and accretion and a reduction in the future income tax recovery.
COMMODITY PRICE RISK MANAGEMENT
Bellatrix recently added four natural gas fixed price swaps for a total of 20,000 GJ (18.2 Mmcf/d) at an average price of CDN$3.78 GJ/d (CDN$4.155/mcf) for the period April 1, 2011 through October 31, 2011. In addition, the Company has added three crude oil fixed price swaps for 500 bbl/d each at US$89.10/bbl, US$95.00/bbl and US$97.50/bbl, respectively for varying terms within 2011. The Company now has fixed price swaps in place at an annual 2011 average of 2,877 bbl/d of crude oil at an average fixed price of CDN$90.83/bbl. As at March 10, 2011, the Company had entered into commodity price risk management arrangements as follows:
Type | | Period | | Volume | | Price Floor | | Price Ceiling | | Index | |
Oil fixed | | January 1, 2011 to Dec. 31, 2011 | | 1,000 bbl/d | | $ | 88.18 CDN | | $ | 88.18 CDN | | WTI | |
Oil fixed | | January 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 89.00 CDN | | $ | 89.00 CDN | | WTI | |
Oil fixed | | January 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 89.10 US | | $ | 89.10 US | | WTI | |
Oil fixed | | February 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 95.00 US | | $ | 95.00 US | | WTI | |
Oil fixed | | March 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 97.50 US | | $ | 97.50 US | | WTI | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.87 CDN | | $ | 3.87 CDN | | AECO | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.65 CDN | | $ | 3.65 CDN | | AECO | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.805 CDN | | $ | 3.805 CDN | | AECO | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.80 CDN | | $ | 3.80 CDN | | AECO | |
RESERVES
Highlights from Bellatrix’s December 31, 2010 reserves include:
· Total proved plus probable company interest reserves, including all royalties receivable but before deducting royalty burdens, as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) at December 31, 2010 were 42,560 mboe (gas converted 6:1). This represents a 64.5% increase from the 25,872 mboe of 2P reserves as at December 31, 2009.
· Excluding properties which were disposed in 2010, proved and probable company interest reserve additions in 2010 replaced 690% of production.
· The net present value of future net revenue of reserves at 10% discount rate improved to $481.54 million up from $357.34 million posted in 2009 representing an increase of 34.8%.
7
· Bellatrix’s net asset value, as at December 31, 2010, based on the GLJ evaluation at a 10% discount rate and 97,466,026 common shares outstanding, equates to $5.11 per basic share outstanding and is $5.79 per basic share outstanding at an 8% discount rate.
· The Company’s reserve life index has extended to 7.2 years for total company interest proved reserves up from 6.4 years in 2009 with total company interest proved and probable reserve life index increased to 11.2 years up from 9.4 years presented in 2009. These 2010 indices were based on 2011 company interest production of 9,451 boe/d and 10,416 boe/d for total company interest proved reserves and proved and probable reserves, respectively.
· 2010 finding, development and acquisition costs (“FD&A”) including changes to future development capital (“FDC”) for total proved plus probable reserves were $12.89 /boe.
· 2010 FD&A including changes to FDC for proved reserves equated to $15.94 /boe.
· The Company established recycle ratios, after commodity price risk management contracts and excluding future development costs of 2.52 times on a proved basis and 4.31 times on a proved and probable basis.
The Company recorded all-in annual FD&A cost of $8.47 per boe in 2010 before consideration of FDC for proved reserves category. The three year average FD&A cost is $9.42 per boe for the proved category before FDC; including FDC, the three year average FD&A cost is $15.46 per boe.
Based on the reserves information and other data as at December 31, 2010, the Company has performed ceiling test calculations in accordance with the requirements of CICA AcG 16 “Oil and Gas Accounting — Full Cost.” No ceiling test impairment of oil and gas properties was identified for accounting purposes as at December 31, 2010.
For additional information please refer to the reserves news release dated February 17, 2011 (posted on www.sedar.com).
The Company has experienced several years of positive revisions to its established reserve base as reserve confidence increases with production history and expects this trend to continue. Additionally, reserves expected from the Company’s developing Cardium and Notikewin resource plays are only partially evaluated due to the early stage of development of the play and the horizontal drilling and completion technologies involved. Specifically, the reserve evaluation includes 18.9 net undeveloped Notikewin horizontal gas locations at Ferrier and 36.2 net undeveloped Cardium horizontal oil locations at Pembina. Focusing on the Cardium oil play, the Company is in the process of developing and proving up reserves across 144 gross (82 net) sections of land, an average 57% working interest.
At December 31, 2010 the Company’s proved and probable company interest reserves, using forecast prices and costs, were 42,560 mboe, an increase of 64.5% compared to 25,872 mboe at December 31, 2009. By commodity type, natural gas makes up 59.8%, light oil and natural gas liquids 38.6% and heavy oil 1.6% of total reserves. At December 31, 2010, the Company’s total proved company interest reserves were 24,930 mboe, an increase of 50.4% compared to 16,573 mboe at December 31, 2009.
2010 sales volumes averaged 8,519 boe/d compared to 8,426 boe/d for 2009. Fourth quarter 2010 sales volumes averaged 10,002 boe/d compared to 6,572 boe/d for the fourth quarter of 2009. The weighting towards crude oil, condensate and NGLs sales volumes averaged 38% in the 2010 fourth quarter, compared to 25% in the corresponding period in 2009. Sales volumes for the month of December 2010 averaged approximately 10,500 boe/d; crude oil, condensate and NGLs made up 42% of the December 2010 volumes. 2009 sales volumes were impacted by minimal capital spending in 2009 and dispositions totaling approximately 3,600 boe/d for the third and fourth quarter of 2009. Through 2010, the Company significantly increased its capital program and achieved drilling success leading to the dramatic increase in sales volumes in 2010.
8
2011 OUTLOOK
In 2011, Bellatrix will continue to be active in drilling its two core resource plays, the Cardium and Notikewin, utilizing horizontal drilling multi fracturing technology. In West Central Alberta, the Company has developed an inventory of 320 net horizontal drilling locations targeting the Cardium Interval and 100 net horizontal drilling locations to access the Notikewin sequence of channel sands. A capital budget of $100 million has been set for fiscal 2011. In addition, the Company anticipates utilizing up to $10 million from a joint venture partner. Based on the timing of the 2011 capital program, downtime for anticipated plant turnarounds and normal production declines, execution of the 2011 budget is anticipated to provide 2011 average daily production of approximately 12,000 boe/d and an exit rate of approximately 13,000 boe/d.
A conference call to discuss Bellatrix’s annual financial and reserves results will be held on March 10, 2011 at 2:30 pm MDT/4:30 pm EDT. To participate, please call toll-free 1-888-231-8191 or 647-427-7450. The conference call will also be recorded and available by calling 1-800-642-1687 or 416-849-0833 and entering passcode 43811183 followed by the pound sign.
Bellatrix’s annual meeting is scheduled for 3:00 pm on May 25, 2011 in the Devonian Room at the Calgary Petroleum Club.
This is an exciting time for the staff and shareholders of Bellatrix. The Company remains doggedly dedicated to “the pursuit of sustainable growth” for its stakeholders.
Raymond G. Smith, P. Eng.
President and CEO
March 10, 2011
9
MANAGEMENT’S DISCUSSION AND ANALYSIS
March 10, 2011 — The following Management’s Discussion and Analysis of financial results 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, 2010 and 2009. This commentary is based on information available to, and is dated as of, March 10, 2011. The financial data presented is in accordance with Canadian generally accepted accounting principles (“GAAP”) 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. 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.
NON-GAAP MEASURES: This Management’s Discussion and Analysis 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 Canadian 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 the 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 also contains other terms such as total net debt and operating netbacks, which are not recognized measures under Canadian GAAP. Total net debt is calculated as long-term debt plus the liability component of the convertible debentures and the net working capital deficiency (excess) before short-term commodity contract assets and liabilities and short-term future income tax assets and liabilities. Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from revenues before other income. Management believes these measures are useful supplemental measures of firstly, the total amount of current and long-term debt and secondly, the amount of revenues received after transportation, royalties and operating expenses. Readers are cautioned, however, that these measures should not be construed as an alternative to other terms such as current and long-term debt or net income determined in accordance with GAAP as measures of performance. Bellatrix’s method of calculating these measures may differ from other entities, and accordingly, may not be comparable to measures used by other trusts or companies.
Additional information relating to the Company, including the Bellatrix’s Annual Information Form, is available on SEDAR at www.sedar.com.
FORWARD LOOKING STATEMENTS: Certain information contained herein may contain forward looking statements including management’s assessment of future plans and operations, drilling plans and the timing thereof, commodity price risk management strategies, expected 2011 average production and exit rate, expected first quarter 2011 average production and production to be tied in, updating of ceiling test calculations, plans and timing related to the adoption of IFRS and the effects thereof, elections anticipated to be made under IFRS, anticipated liquidity of the Company and various matters that may impact such liquidity, expected 2011 operating expenses and general and administrative expenses, 2011 capital expenditures budget and the nature of capital expenditures and the timing and method of financing thereof, method of funding drilling commitments, commodity prices and expected volatility thereof, estimated amount and timing of incurring asset retirement obligations and use of proceeds from recent financings, may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, 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. The recovery and reserve estimates of Bellatrix’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. 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-
10
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. 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 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 gas 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 securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), 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 is a Western Canadian based growth oriented oil and gas company engaged in the exploration for, and the acquisition, development and production, of oil and natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan.
Bellatrix is the continuing corporation resulting from the reorganization (the “Reorganization”) effective November 1, 2009 pursuant to a plan of arrangement involving, among others, True Energy Trust (the “Trust” or “True”), Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) and securityholders of the Trust.
The Reorganization has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for periods prior to the effective date of the Reorganization will reflect the financial position, results of operations and cash flows as if the Company had always carried on the business formerly carried on by the Trust. Information herein with respect to Bellatrix includes information in respect of the Trust prior to completion of the Reorganization to the extent applicable unless the context otherwise requires. Pursuant to the Arrangement, the Unitholders’ Capital of the Trust Units as of the effective date of November 1, 2009 was reduced by the amount of the deficit of the Trust on October 31, 2009 of $666.8 million.
References to “common shares” and “shares”, “Share Option Plan”, and “options” should be read as references to “Units”, “Unit Rights Incentive Plan”, and “rights” respectively, for periods prior to November 1, 2009.
Bellatrix’s common shares and convertible debentures are listed on the Toronto Stock Exchange under the symbols BXE and BXE.DB.A, respectively.
11
Fourth Quarter 2010
HIGHLIGHTS
| | | | Three months ended
December 31, | |
(CDN$000s except share and per share amounts) | | | | 2010 | | 2009 | |
| | | | | | | |
FINANCIAL | | | | | | | |
| | | | | | | |
Revenue (before royalties and risk management(1)) | | | | 37,826 | | 24,004 | |
| | | | | | | |
Funds flow from operations(2) | | | | 15,892 | | 7,681 | |
Per basic share(3) | | | | $ | 0.16 | | $ | 0.10 | |
Per diluted share(3) | | | | $ | 0.15 | | $ | 0.10 | |
Cash flow from operating activities | | | | 11,285 | | 2,743 | |
Per basic share(3) | | | | $ | 0.12 | | $ | 0.03 | |
Per diluted share (3) | | | | $ | 0.11 | | $ | 0.03 | |
Net loss | | | | (8,173 | ) | (8,216 | ) |
Per basic share(3) | | | | $ | (0.08 | ) | $ | (0.10 | ) |
Per diluted share(3) | | | | $ | (0.08 | ) | $ | (0.10 | ) |
Exploration and development | | | | 34,884 | | 9,606 | |
Corporate and property acquisitions | | | | 4,812 | | 264 | |
Capital expenditures – cash | | | | 39,696 | | 9,870 | |
Property dispositions – cash | | | | (13,980 | ) | 56 | |
Non-cash items | | | | 158 | | 551 | |
Total capital expenditures – net | | | | 25,874 | | 10,477 | |
| | | | | | | |
OPERATING | | | | | | | |
| | | | | | | |
Average daily sales volumes | | | | | | | |
Crude oil, condensate and NGLs | | (bbls/d) | | 3,821 | | 1,642 | |
Natural gas | | (mcf/d) | | 37,083 | | 29,580 | |
Total oil equivalent | | (boe/d) | | 10,002 | | 6,572 | |
Average prices | | | | | | | |
Light crude oil and condensate | | ($/bbl) | | 77.48 | | 73.19 | |
NGLs | | ($/bbl) | | 42.80 | | 29.69 | |
Heavy oil | | ($/bbl) | | 57.83 | | 62.79 | |
Crude oil, condensate and NGLs | | ($/bbl) | | 69.22 | | 59.05 | |
Crude oil, condensate and NGLs (including risk management(1)) | | ($/bbl) | | 69.94 | | 58.85 | |
Natural gas | | ($/mcf) | | 3.79 | | 5.33 | |
Natural gas (including risk management(1)) | | ($/mcf) | | 3.79 | | 6.72 | |
Total oil equivalent | | ($/boe) | | 40.51 | | 38.72 | |
Total oil equivalent (including risk management (1)) | | ($/boe) | | 40.79 | | 44.93 | |
Statistics | | | | | | | |
Operating netback(4) | | ($/boe) | | 19.71 | | 15.36 | |
Operating netback(4) (including risk management(1)) | | ($/boe) | | 19.99 | | 21.57 | |
Transportation | | ($/boe) | | 1.18 | | 1.17 | |
Production expenses | | ($/boe) | | 11.31 | | 16.65 | |
General & administrative | | ($/boe) | | 1.92 | | 3.43 | |
Royalties as a % of sales after transportation | | | | 21% | | 15% | |
(1) The Company has entered into various commodity price risk management contracts which are considered to be economic hedges. Per unit metrics after risk management includes only the realized portion of gains or losses on commodity contracts.
12
The Company does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per share metrics calculations disclosed.
(2) The highlights section contains the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with Canadian GAAP as an indicator of the Company’s performance. Therefore reference to 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 as below. Funds flow from operations per share is calculated using the weighted average number of common shares for the period.
(3) Basic weighted average shares for the fourth quarter of 2010 were 97,332,859 (2009: 78,703,754).
In computing weighted average diluted earnings per share for the three months ended December 31, 2010 a total of 5,823,377 (2009: 4,213,733) share options and 9,821,429 (2009:5,305,250) common shares issuable on conversion of convertible debentures were excluded from the calculation as they were not dilutive.
In computing weighted average diluted cash flow from operations and funds flow from operations for the three months ended December 31, 2010 a total of 992,192 (2009: nil) shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and a total of 9,821,429 (2009: nil) common shares issuable on conversion of convertible debentures were also added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 108,146,480. As a consequence, a total of $0.7 million for interest accretion expense (net of income tax effect) was added to the numerator.
(4) Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income.
As detailed previously in this Management’s Discussion and Analysis, funds flow from operations is a term that does not have any standardized meaning under GAAP. Funds flow from operations is calculated as cash flow from operating activities before asset retirement costs incurred and changes in non-cash working capital incurred.
Reconciliation of Cash Flow from Operating Activities to Funds Flow from Operations
| | Three months ended December 31, | |
($000s, except per share amounts) | | 2010 | | 2009 | |
Cash flow from operating activities | | 11,285 | | 2,743 | |
Asset retirement costs incurred | | 466 | | 241 | |
Change in non-cash working capital | | 4,141 | | 4,697 | |
Funds flow from operations | | 15,892 | | 7,681 | |
Funds flow from operations during the fourth quarter of 2010 was $15.9 million, an increase of 107% compared to $7.7 million for the fourth quarter of 2009. This was reflective of higher overall production and increased pricing for light oil, condensate and NGL’s, offset by a decline in natural gas and heavy oil prices. As prices have increased this quarter compared to that in 2009, realized gains on commodity risk contracts have decreased by approximately $3.5 million. Interest expense for the 2010 fourth quarter decreased approximately $0.9 million compared to the 2009 fourth quarter which is primarily reflective of a combination of the Company’s reduced convertible debenture balance and lower interest rate on the convertible debentures outstanding in the fourth quarter of 2010 as compared to those previously outstanding. Cash flow from operating activities during the fourth quarter of 2010 was $11.3 million, compared to $2.7 million for the fourth quarter of 2009. This increase was further reflective of a slight increase in asset retirement costs incurred, offset by a decrease in cash from changes in working capital. In the last quarter of
13
2010, Bellatrix had a net loss of $8.2 million compared to a net loss of $8.2 million in the fourth quarter of 2009. The net loss from the 2009 fourth quarter is comparable to the net loss in the 2010 fourth quarter although the 2010 fourth quarter is reflective of higher sales revenues, offset by increased depletion, depreciation and accretion and a reduction in future income tax recovery.
Sales volumes for the three months ended December 31, 2010 averaged 10,002 boe/d, up 52% from the 6,572 boe/d sold in the fourth quarter of 2009. The weighting toward crude oil, condensate and NGLs sales volumes averaged 38% in the 2010 fourth quarter, compared to 25% in the corresponding period in 2009. Fourth quarter 2010 sales volumes were higher than the same period in 2009 primarily due to the success achieved from an expanded drilling program in 2010. Sales volumes for the month of December 2010 averaged approximately 10,500 boe/d; crude oil, condensate and NGLs made up 42% of December 2010 sales volumes.
Natural gas sales averaged 37.1 Mmcf/d during the last quarter of 2010, compared to 29.6 Mmcf/d in the fourth quarter of 2009. The Company’s natural gas sales increase was attributed to natural gas wells drilled in the third and fourth quarter of 2010. The weighting toward natural gas sales volumes averaged 62% in the fourth quarter, compared to 75% in the corresponding period of 2009 as Bellatrix concentrates on exploiting its Cardium oil resource play. Crude oil, condensate and NGL sales volumes averaged 3,821 bbls/d in the fourth quarter of 2010 compared to 1,642 bbls/d during the same period of 2009.
During the fourth quarter of 2010, Bellatrix experienced an overall increase of 5% in commodity prices, based on an increase in light oil, condensate and NGL pricing, offset by a decrease in natural gas and heavy oil pricing, as compared to the same period in 2009. The average daily and monthly AECO indices for natural gas during this quarter were 19% and 15%, respectively, lower than in the same period in 2009. For the three months ending December 31, 2010, Bellatrix received an average natural gas price, before transportation and commodity price risk management contracts, of $3.79/mcf, 30% lower than $5.33/mcf in the same period in 2009 and 1% lower than $3.81/mcf in the third quarter of 2010. Bellatrix had a natural gas physical sales contract to deliver 5,275 GJ/day at a fixed price of $7.90/GJ in the fourth quarter of 2009 which contributed to higher pricing experienced in the 2009 period. For heavy crude oil, Bellatrix received an average price before transportation of $57.83/bbl during the fourth quarter of 2010, 8% lower than $62.79/bbl in the same period in 2009 and comparable to $57.89/bbl in the third quarter of 2010. In comparison, the average reference price for Hardisty Heavy crude in the fourth quarter of 2010 was 3% lower than the average 2009 price in the same period. For light oil, and condensate, Bellatrix received an average price of $77.48/bbl before transportation and commodity price risk management contracts for the fourth quarter in 2010, compared to $73.19 during the same 2009 period, representing a 6% increase in price. In comparison, the Edmonton par reference price increased by 5% in the fourth quarter of 2010, compared to the same time period in 2009. In the 2010 fourth quarter, Bellatrix received an average price of $42.80/bbl for NGLs, before transportation and commodity price risk management contracts, representing a 44% increase when compared to fourth quarter of 2009. During the fourth quarter of 2010, revenue before other income and commodity price risk management contracts of $37.2 million was 59% higher than the corresponding 2009 period.
In the fourth quarter of 2010, average sales volumes increased 10% from the third quarter 2010 average volumes of 9,119 boe/d. The increase is due to the success achieved from an expanded drilling program in 2010.
During the fourth quarter of 2010, Bellatrix spent $34.9 million on capital projects, excluding corporate and asset acquisitions and dispositions, compared to $9.6 million in 2009. In the fourth quarter of 2010, Bellatrix drilled or participated in 14 wells in the Ferrier, Lodgepole, Willesden Green and West Pembina areas, resulting in 7.31 net oil wells and a 0.50 net natural gas well. In the fourth quarter of 2009, Bellatrix drilled or participated in 12 (9.50 net) wells including 5.75 net natural gas wells, and 3.5 net oil wells and 0.25 awaiting completion. Fourth quarter 2010 drilling was focused on the Notikewin and Cardium resource plays.
14
In the fourth quarter of 2010, the Company paid $7.7 million in royalties, compared to $3.4 million in the same period in 2009. As a percentage of pre-commodity price risk management sales (after transportation costs), royalties were 21% in the fourth quarter of 2010 compared to 15% in the same period in 2009. Royalties for the fourth quarter of 2010 were impacted by adjustments to natural gas royalties of $1.2 million related to Alberta crown gas cost allowance amendments for the 2009 year. Excluding these Alberta crown adjustments, the average royalty rate percentage for the fourth quarter of 2010 would be 18%. Included in the overall royalties for Q4 2010 is approximately 5% due to additional gross overriding royalties for recent wells drilled which were funded by certain joint venture partners. In this same period of 2010, operating costs totaled $10.4 million, compared to $10.1 million recorded in the same period of 2009. During the fourth quarter of 2010, operating costs averaged $11.31/boe, down from the $16.65/boe incurred during the fourth quarter of 2009. 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 2010 averaged $11.63/boe. During the fourth quarter of 2010, company field operating netbacks before commodity risk management contracts increased by 28% to $19.71/boe compared to 2009, driven primarily by a 32% reduction in production expenses and a 5% increase in overall commodity prices, offset slightly by higher royalties and transportation costs. In comparison, the company field operating netback before commodity risk management contracts for the third quarter of 2010 was $13.22/boe. Field operating netbacks for natural gas before commodity price risk management contracts during the fourth quarter of 2010 of $1.11/mcf were 53% lower than the $2.35/mcf recorded in the same period in 2009. The decrease is primarily a result of the continued deterioration of natural gas prices and higher royalties. In comparison, the field operating netback for natural gas before commodity risk management contracts for the third quarter of 2010 was $1.32/mcf. Field operating netbacks before commodity price risk management contracts for crude oil, condensate and NGLs during the fourth quarter of 2010 averaged $40.78/bbl, up from $19.08/bbl during the fourth quarter of 2009, primarily as a result of a significant reduction in production expenses and royalties, as well as increased pricing. In comparison, the field operating netback for crude oil, condensate and NGLs for the third quarter of 2010 was $28.16/bbl.
In the fourth quarter of 2010, general and administrative expenses, net of capitalized G&A and recoveries, were $1.8 million, compared to $2.1 million in the comparable 2009 period. Although there was an overall increase in G&A expenses, this was offset by higher capitalized G&A and recoveries as a result of the increase in capital activity in the fourth quarter of 2010 compared to the fourth quarter of 2009.
Depletion, depreciation and accretion expense for the fourth quarter of 2010 was $20.7 million ($22.50/boe), compared to $16.4 million ($27.12/boe) in 2009. The increase in depletion, depreciation and accretion expense from the 2009 fourth quarter to that in 2010 is reflective of the 52% increase in sales in the same comparative period, offset by the additional reserves achieved through the Company’s drilling success.
2010 Annual Financial and Operational Results
Financings in 2010
Part of Bellatrix’s focus in 2010 has been directed towards improving the Company’s financial flexibility and building a stronger balance sheet. In January 2010, Bellatrix issued 13.64 million common shares at a price of $3.30 per share for gross proceeds of $45.0 million (net proceeds of $42.4 million after transaction costs). The net proceeds from this financing were used to temporarily reduce outstanding bank indebtedness, thereby freeing up borrowing capacity that could be redrawn to fund Bellatrix’s ongoing capital expenditure program and for general corporate purposes.
On April 20, 2010, Bellatrix issued $55 million of convertible unsecured subordinated debentures (the “4.75% Debentures”) on a bought deal basis. The 4.75% Debentures have a face value of $1,000, bear interest at the rate of
15
4.75% per annum payable semi-annually in arrears on the last day of April and October of each year commencing on October 31, 2010 and mature on April 30, 2015 (the “Maturity Date”). The 4.75% Debentures are convertible at the holder’s option and at any time prior to the close of business on the earlier of the close of business on the business day immediately preceding the Maturity Date and the date specified by the Corporation for redemption of the 4.75% Debentures into common shares of the Corporation at a conversion price of $5.60 per common share (the “Conversion Price”), subject to adjustment in certain events. The 4.75% Debentures are not redeemable by the Corporation before April 30, 2013. On and after April 13, 2013 and prior to April 30, 2014, the 4.75% Debentures are redeemable at the Corporation’s option, in whole or in part, at par plus accrued and unpaid interest if the weighted average trading price of the common shares for the specified period is not less than 125% of the Conversion Price. On and after April 30, 2014, the 4.75% Debentures are redeemable at the Corporation’s option, in whole or in part, at any time at par plus accrued and unpaid interest. Proceeds from the issuance of the 4.75% Debentures have been used by Bellatrix to partially fund the redemption of the convertible unsecured subordinated debentures due June 30, 2011 (the “7.5% Debentures”) and the balance of the redemption amount has been funded through bank indebtedness.
On April 20, 2010, Bellatrix deposited with Computershare Trust Company of Canada, the trustee (the “Trustee”) for Bellatrix’s 7.5% Debentures, sufficient funds to satisfy the principal amount and interest owing on the 7.5% Debentures and on May 3, 2010 the trustee provided notice to the registered holders of the 7.5% Debentures of its intention to redeem the 7.5% Debentures on July 2, 2010. The 7.5% Debentures were redeemed on July 2, 2010 for an amount of $1,025 for each $1,000 principal amount of the 7.5% Debentures plus accrued and unpaid interest, or a total of $88.0 million. The funds deposited with the Trustee on April 20, 2010 and acknowledgment by the Trustee thereof discharged and extinguished the financial liability for the 7.5% Debentures as of that date.
As the 7.5% Debentures were convertible into Common Shares, the Company carried a liability and equity portion on its balance sheet in relation to the debentures. Canadian GAAP provides specific guidelines on the accounting for redemption of convertible debt. Under these guidelines, an amount is determined, using fair value techniques, for the liability and equity portion of the redeemed debentures, resulting in a gain/loss and an adjustment to retained earnings. The net impact on the deficit for Bellatrix as a result of the redemption of the 7.5% Debentures recorded in the second quarter and reflected as at December 31, 2010 is as follows:
(000’s) | | | |
| | | |
Non-cash loss on the redemption of 7.5% Debentures, recorded on the Consolidated Statements of Loss | | $ | 3,514 | |
Adjustment for the redemption of 7.5% Debentures, recorded against the deficit | | (2,915 | ) |
Net increase to deficit | | $ | 599 | |
The $88.0 million cost of redemption of the 7.5% Debentures was reflected in the Statement of Cash Flows for the second quarter of 2010 as follows:
(000’s) | | | |
Cash flows from Operating Activities: | | | |
Realization of imputed interest cost on 7.5% Debentures | | $ | (5,050 | ) |
| | | |
Cash flows from Financing Activities: | | | |
Redemption of 7.5% Debentures | | (88,009 | ) |
Realization of imputed interest cost on 7.5% Debentures allocated to operating activities | | 5,050 | |
Total | | $ | (88,009 | ) |
16
On August 12, 2010, Bellatrix issued 4,710,000 Common Shares on a flow-through basis (“Flow-Through Shares”) at $4.25 a share for gross proceeds of $20.0 million. Proceeds from the issuance of the Flow-Through Shares were used to accelerate the Company’s Cardium light oil exploration program. The Company will incur expenditures eligible for Canadian exploration expenses (“CEE”) that will be renounced to subscribers of the Flow-Through Shares effective December 31, 2010. Bellatrix is committed to incur the $20.0 million CEE expenditures on or before December 31, 2011.
Acquisitions and Dispositions
The Company intends to provide consistent growth by drilling and developing its extensive land position to maximize the value of its reserve and resource potential. Bellatrix has been working on a number of internal initiatives to streamline and optimize our ongoing operations, specifically the ability to expand and accelerate the drilling of its Cardium oil resource.
On December 10, 2010, Bellatrix closed the purchase of certain property interests in the West Pembina area for a purchase price of $4.5 million after adjustments. The transaction, which was effective August 1, 2010, included the acquisition of an additional 6.5 gross net sections (2.5 net) of Cardium rights, for an increase of an additional 10.0 Cardium horizontal drilling locations. The acquisition also included approximately 70 boe/d of production and associated facilities.
On December 22, 2010, Bellatrix disposed of its non-core property at Mantario, Saskatchewan for net proceeds of approximately $13.6 million after adjustments. The sale was effective December 1, 2010. The net proceeds were used to reduce the Company’s bank indebtedness and ultimately will be directed towards the development of its Cardium oil resource program.
On December 30, 2010, the Company closed the Willesden Green Facilities Joint Venture raising the amount of $1.6 million and with the Company contributing the battery facilities located at 4-29-42-8W5 to the joint venture for approximately $1.6 million. This is accounted for as a capital lease transaction.
On December 31, 2010, the Company also closed another minor non-core property sale at Killam for net proceeds of $375,000 after adjustments. The purchase and sale agreement had an effective and closing date of December 31, 2010.
On January 25, 2011, Bellatrix acquired the interest in a section of Frog Lake First Nation lands from a joint venture partner for a net purchase price of $2.2 million after adjustments. The transaction has an effective date of January 1, 2011. These assets consists of approximately 130 boe/d of net production; an additional 20% interest in the Colony formation in these lands (BXE already has 13.75%WI) and an additional 50% WI in the McLaren formation in these lands (BXE already has a 50% WI) except for a ¼ section which the McLaren interests are as per the Colony. The south half of the section is undeveloped with 2 wells scheduled for drilling in Q1 2011.
On January 25, 2011, Bellatrix exercised a right of first refusal increasing its interest in a joint venture property in the Brazeau Area of West Central Alberta for approximately $1.5 million. The asset acquisition consisted of approximately 3,200 gross (1,102.8 net) acres of Cardium rights providing the Company with up to 6.3 additional net Cardium locations and included 15 boe/d of production.
In 2009, the Company’s focus was to restructure and strengthen its balance sheet. The Company had two minor dispositions in the second quarter of 2009 and successfully completed the divestiture of the majority of its petroleum and natural gas properties in Saskatchewan in the third quarter of 2009. Total net proceeds from all dispositions during 2009 were $92.9 million. Net proceeds from the dispositions were used to reduce the Company’s bank indebtedness; these strategic accomplishments allowed the Company to progress forward with substantially improved financial flexibility.
17
On June 30, 2009, Bellatrix sold 145 boe/d, including 0.63 Mmcf/d of natural gas, in the Penhold Area of Central Alberta for $4.7 million, after purchase adjustments and closing costs. In addition, in June 2009, Bellatrix completed a disposition of certain royalty interests for approximately $3.7 million, after purchase adjustments and closing costs. The proceeds from these two dispositions were used to reduce Bellatrix’s bank indebtedness.
On July 30, 2009, the Company successfully completed the divestiture of a majority of its oil and natural gas assets in Saskatchewan for net proceeds of $85 million (the “Saskatchewan Divestiture”). The Saskatchewan Divestiture excluded the Saskatchewan properties of Mantario and Cypress and included Bellatrix’s interests to the base Belly River in three sections in the Ferrier area of West Central Alberta. The disposition was accounted for under the guidance of Accounting Guideline 16 — “Oil and Gas Accounting — Full Cost”. Under full cost accounting, if crediting the proceeds from disposition to costs results in a change of 20 percent or more to the DD&A rate then a gain or loss should be recognized. When a gain or loss is to be recognized the total net book value of capitalized costs should be allocated between the properties sold and the properties retained. The assets sold were an allocation of the Company’s historical full cost pool based on a pro-rata ratio of future cash flows of proved reserves associated with the assets sold, discounted at 10%, as compared to all oil and gas assets as of June 30, 2009. In the second quarter of 2009, the Company recorded a $114.2 million non-cash loss on the assets sold being the excess of the allocated net book value to these assets, compared to the total estimated net proceeds, after purchase adjustments and estimated closing costs.
The 2009 dispositions reduced sales volumes by approximately 3,600 boe/d for the third and fourth quarters of 2009.
Sales Volumes
Sales volumes for the year ended December 31, 2010 averaged 8,519 boe/d compared to 8,426 boe/d for the same period in 2009, representing a 1% increase. Year over year, sales volumes are comparable as the drilling success achieved in fiscal 2010 has offset the impact of 2009 dispositions.
Sales Volumes
| | | | Years ended December 31, | |
| | | | 2010 | | 2009 | |
Light oil and condensate | | (bbls/d) | | 1,563 | | 753 | |
NGLs | | (bbls/d) | | 577 | | 354 | |
Heavy oil | | (bbls/d) | | 410 | | 1,770 | |
Total crude oil, condensate and NGLs | | (bbls/d) | | 2,550 | | 2,877 | |
| | | | | | | |
Natural gas | | (mcf/d) | | 35,814 | | 33,295 | |
| | | | | | | |
Total boe/d | | (6:1) | | 8,519 | | 8,426 | |
During the 2010 year, Bellatrix had a 98% success rate in its drilling program that consisted of 48 gross wells, resulting in 21.5 net oil wells, 6.3 net natural gas wells and one dry hole.
By comparison, Bellatrix had a 100% success rate in its 2009 drilling program which consisted of 18 wells (11.68 net). Of the 18 wells, 5 gross wells in the Willesden Green area were farmed out with Bellatrix retaining a 24% average working interest with no payout account.
For the year ended December 31, 2010, the weighting towards crude oil, condensate and NGLs decreased 11% averaging 2,550 bbls/d compared to 2009 average sales of 2,877 bbls/d. The decrease is a result of the disposition of a significant Saskatchewan heavy oil producing property by the Company in the second half of 2009. Consequently, heavy oil sales volumes dropped to 5% of total production for the 2010 fiscal period compared to 21% of total production in 2009. The decrease in heavy oil sales volumes was offset by an increase in light oil,
18
condensate and NGL sales volumes for the 2010 period which is the result of Bellatrix’s successful 2010 drilling program. Light oil, condensate and NGL sales volumes made up 25% of total production for the 2010 year compared to 13% in 2009. On December 22, 2010, the Company closed on the sale of its Mantario, Saskatchewan heavy oil property, leaving the Company with reduced heavy oil volumes on a go forward basis.
For the year ended December 31, 2010, the weighting towards natural gas sales volumes averaged 70% compared to 66% for the 2009 year. Sales of natural gas averaged 35.8 Mmcf/d for 2010, compared to 33.3 Mmcf/d in 2009, an increase of 26%.
Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2011 budget is anticipated to provide 2011 average daily production of approximately 12,000 boe/d and an exit rate of approximately 13,000 boe/d. The 2011 capital budget is expected to be directed primarily towards horizontal drilling and completions activities in the Cardium and Notikewin resource plays.
Commodity Prices
Average Commodity Prices
| | Years ended December 31, | |
| | 2010 | | 2009 | | % Change | |
| | | | | | | |
Exchange rate (US$/Cdn$) | | 0.9709 | | 0.8757 | | 11 | |
| | | | | | | |
Natural gas: | | | | | | | |
NYMEX (US$/mmbtu) | | 4.38 | | 4.16 | | 5 | |
AECO daily index (CDN$/mcf) | | 4.00 | | 3.95 | | 1 | |
AECO monthly index (CDN$/mcf) | | 4.28 | | 4.14 | | 3 | |
Bellatrix’s average price ($/mcf) | | 4.19 | | 4.50 | | (7 | ) |
Bellatrix’s average price (including risk management(1)) ($/mcf) | | 5.28 | | 5.96 | | (11 | ) |
| | | | | | | |
Crude oil: | | | | | | | |
WTI (US$/bbl) | | 79.58 | | 62.09 | | 28 | |
Edmonton par – light oil ($/bbl) | | 77.81 | | 66.20 | | 18 | |
Bow River – medium/heavy oil ($/bbl) | | 68.26 | | 59.71 | | 14 | |
Hardisty Heavy – heavy oil ($/bbl) | | 62.29 | | 55.59 | | 12 | |
Bellatrix’s average prices ($/bbl) | | | | | | | |
Light crude oil and condensate | | 76.25 | | 61.24 | | 25 | |
NGLs | | 39.81 | | 27.73 | | 44 | |
Heavy crude oil | | 60.50 | | 49.10 | | 23 | |
Total crude oil and NGLs | | 65.47 | | 49.65 | | 32 | |
Total crude oil and NGLs (including risk management (1)) | | 66.59 | | 49.62 | | 34 | |
(1)Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.
Bellatrix’s natural gas sales are priced with reference to the daily or monthly AECO indices. During 2010, the AECO daily and monthly reference price increased by 1% and 3%, respectively, compared to the same period in 2009. Bellatrix’s average sales price before commodity price risk management contracts for 2010 decreased by 7% compared to the same period in 2009. Bellatrix had a natural gas physical sales contract to deliver 5,275 GJ/day at a fixed price of $7.29/GJ and $7.90/GJ in the third and fourth quarter of 2009, respectively, which contributed to higher pricing experienced relative to the AECO indices. Bellatrix’s natural gas price after including commodity price risk management contracts for 2010 was $5.28/mcf compared to $5.96/mcf for 2009.
For light oil and condensate, Bellatrix recorded an average $76.25/bbl before commodity price risk management contracts during 2010, 25% higher than the average price received in the 2009 year. In comparison, the Edmonton par price increased by 18% over the same period. The average WTI crude oil US dollar based price increased 28%
19
from 2009 to 2010. The average US$/CDN$ foreign exchange rate was 0.9709 for the full year of 2010 compared to 0.8757 in 2009.
For heavy crude oil, Bellatrix received an average price before transportation of $60.50/bbl for 2010, an increase of 23% over prices in the 2009 year. The Bow River reference price increased by 14% and the Hardisty Heavy reference price increased by 12% over the same period. The majority of Bellatrix’s heavy crude oil density ranges between 11 and 16 degrees API consistent with the Hardisty Heavy reference price, although primarily all of Bellatrix’s heavy oil production was sold at Saskatchewan delivery points. Bellatrix’s increase in realized price from 2009 to 2010 is higher than the increase in the reference price for the same time period as 2009 heavy crude oil sales volumes included heavy oil from the Kerrobert, Saskatchewan property (sold in July 2009) which had slightly lower pricing than the other heavy oil properties retained.
Revenue
Revenue before other income and commodity price risk management contracts for the year ended December 31, 2010 was $115.7 million, 9% higher than the $106.8 million in the same period in 2009. The increase in revenue from light crude oil, condensate and NGLs were substantially offset by a decrease in heavy oil sales as Bellatrix disposed of the majority of its heavy oil producing property in the second half of 2009. In 2010 total crude oil, condensate and NGL revenues contributed 53% of total revenue (before other) compared to 49% in 2009. Light crude oil, condensate and NGL revenues in 2010 contributed 85% of total crude oil, condensate and NGL revenue (before other) compared to 39% in 2009.
Revenue before other income and commodity price risk management contracts for natural gas for the year ended December 31, 2010 is comparable to the year ended December 31, 2009 as sales volumes increased but natural gas prices weakened.
| | Years ended December 31, | |
($000s) | | 2010 | | 2009 | |
Light crude oil and condensate | | 43,502 | | 16,821 | |
NGLs | | 8,383 | | 3,579 | |
Heavy oil | | 9,062 | | 31,726 | |
Crude oil and NGLs | | 60,947 | | 52,126 | |
Natural gas | | 54,729 | | 54,652 | |
Total revenue before other | | 115,676 | | 106,778 | |
Other (1) | | 1,997 | | 2,236 | |
Total revenue before royalties and risk management | | 117,673 | | 109,014 | |
(1) Other revenue primarily consists of processing and other third party income.
Revenues for 2011 are uncertain due to volatile commodity prices. While sales volumes and crude oil and liquid prices for 2011 are expected to be higher than 2010, natural gas prices remain relatively weak.
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 current date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Company seeks to provide a measure of stability to funds flow from operations, as well as, to ensure Bellatrix realizes positive economic returns from its capital
20
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 10, 2011 is shown in the following tables:
Natural gas
Average Volumes (GJ/d)
| | Q1 2011 | | Q2 2011 | | Q3 2011 | | Q4 2011 | |
Fixed | | — | | 20,000 | | 20,000 | | 6,739 | |
Total GJ/d | | — | | 20,000 | | 20,000 | | 6,739 | |
Average Price ($/GJ AECO C)
| | Q1 2011 | | Q2 2011 | | Q3 2011 | | Q4 2011 | |
Fixed | | — | | 3.78 | | 3.78 | | 3.78 | |
Crude oil and liquids
Average Volumes (bbls/d)
| | Q1 2011 | | Q2 2011 | | Q3 2011 | | Q4 2011 | |
Fixed (CDN$/bbl) | | 1,500 | | 1,500 | | 1,500 | | 1,500 | |
Fixed (US$/bb) | | 1,000 | | 1,500 | | 1,500 | | 1,500 | |
Total bbls/d | | 2,500 | | 3,000 | | 3,000 | | 3,000 | |
Average Price ($/bbl WTI)
| | Q1 2011 | | Q2 2011 | | Q3 2011 | | Q4 2011 | |
Fixed price (CDN$/bbl) | | 88.45 | | 88.45 | | 88.45 | | 88.45 | |
Fixed Price (US$/bb) | | 92.48 | | 93.87 | | 93.87 | | 93.87 | |
As of December 31, 2010, the fair value of Bellatrix’s outstanding commodity contracts is an unrealized liability of $3.7 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, 2010 and may be different from what will eventually be realized. Changes in the fair value of the commodity contracts are recognized in the Consolidated Statements of Loss within the financial statements.
The following is a summary of the gain (loss) on commodity contracts for the years ended December 31, 2010 and 2009 as reflected in the Consolidated Statements of Loss in the financial statements:
Commodity contracts
($000s) | | Crude Oil
& Liquids | | Natural
Gas | | 2010 Total | |
Realized cash gain on contracts | | 1,036 | | 14,352 | | 15,388 | |
Unrealized loss on contracts (1) | | (3,785 | ) | (3,321 | ) | (7,106 | ) |
Total gain (loss) on commodity contracts | | (2,749 | ) | 11,031 | | 8,282 | |
21
Commodity contracts
($000s) | | Crude Oil
& Liquids | | Natural
Gas | | 2009 Total | |
Realized cash gain (loss) on contracts | | (31 | ) | 17,777 | | 17,746 | |
Unrealized gain (loss) on contracts (1) | | 53 | | (405 | ) | (352 | ) |
Total gain on commodity contracts | | 22 | | 17,372 | | 17,394 | |
(1)Unrealized gain (loss) commodity contracts represent non-cash adjustments for changes in the fair value of these contracts during the period.
Royalties
For the year ended December 31, 2010, total royalties were $22.9 million, compared to $17.6 million incurred in 2009. Overall royalties as a percentage of revenue (after transportation costs) in 2010 were 20%, compared with 17% in 2009. Royalties for 2010 were impacted by Saskatchewan crown amendments of approximately $0.7 million relating primarily to natural gas properties sold in 2008 and 2009 and additional natural gas royalties of $1.2 million related to Alberta crown gas cost allowance amendments for 2009. Excluding these crown adjustments, the average royalty rate percentage for 2010 would be 18%. Included in the overall royalties for 2010 is approximately 4% due to additional gross overriding royalties for 2010 wells drilled which were funded by certain joint venture partners.
Royalties by Commodity Type | | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
Light crude oil, condensate and NGLs | | 11,695 | | 5,758 | |
$/bbl | | 14.97 | | 14.26 | |
Average light crude oil, condensate and NGLs royalty rate (%) | | 23 | | 28 | |
| | | | | |
Heavy Oil | | 2,012 | | 5,975 | |
$/bbl | | 13.44 | | 9.25 | |
Average heavy oil royalty rate (%) | | 23 | | 20 | |
| | | | | |
Natural Gas | | 9,207 | | 5,821 | |
$/mcf | | 0.70 | | 0.48 | |
Average natural gas royalty rate (%) | | 18 | | 11 | |
| | | | | |
Total | | 22,914 | | 17,554 | |
$/boe | | 7.37 | | 5.71 | |
Average total royalty rate (%) | | 20 | | 17 | |
Royalties, by Type
| | Years ended December 31, | |
($000s) | | 2010 | | 2009 | |
Crown royalties | | 7,095 | | 4,027 | |
Indian Oil and Gas Canada royalties | | 4,199 | | 3,198 | |
Freehold & GORR | | 11,499 | | 9,651 | |
Saskatchewan resource surcharge | | 121 | | 678 | |
Total | | 22,914 | | 17,554 | |
22
Expenses
| | Years ended December 31, | |
($000s) | | 2010 | | 2009 | |
Production | | 37,964 | | 45,015 | |
Transportation | | 3,723 | | 3,880 | |
General and administrative | | 9,414 | | 10,239 | |
Interest and financing charges | | 7,403 | | 13,657 | |
Share-based compensation (recovery) | | 1,618 | | (159 | ) |
Expenses per boe
| | Years ended December 31, | |
($ per boe) | | 2010 | | 2009 | |
Production | | 12.21 | | 14.64 | |
Transportation | | 1.20 | | 1.26 | |
General and administrative | | 3.03 | | 3.33 | |
Interest and financing charges | | 2.38 | | 4.44 | |
Share-based compensation (recovery) | | 0.52 | | (0.05 | ) |
Production Expenses
For the year ended December 31, 2010, production expenses totaled $38.0 million ($12.21/boe), compared to $45.0 million ($14.64/boe) recorded in 2009. The decrease in production expenses in 2010 on a boe basis is due to increased production from 2010 drilling in areas with lower production expenses and the Company’s continued efforts to streamline operations and field optimization projects.
Bellatrix is targeting operating costs of approximately $48.2 million ($11.00/boe) in 2011. This is based upon assumptions of estimated 2011 average production of approximately 12,000 boe/d, continued field optimization work and planned capital expenditures in producing areas which are anticipated to have lower operating costs.
Production Expenses, by Commodity Type
| | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
Light crude oil, condensate and NGLs | | 12,142 | | 8,730 | |
$/bbl | | 15.54 | | 21.62 | |
| | | | | |
Heavy oil | | 2,644 | | 11,180 | |
$/bbl | | 17.67 | | 17.30 | |
| | | | | |
Natural gas | | 23,178 | | 25,105 | |
$/mcf | | 1.77 | | 2.07 | |
| | | | | |
Total | | 37,964 | | 45,015 | |
$/boe | | 12.21 | | 14.64 | |
| | | | | |
Total | | 37,964 | | 45,015 | |
Processing and other third party income (1) | | (1,997 | ) | (2,237 | ) |
Total after deducting processing and other third party income | | 35,967 | | 42,778 | |
$/boe | | 11.57 | | 13.91 | |
(1) Processing and other third party income is included within petroleum and natural gas sales on the Consolidated Statements of Loss.
23
Transportation
Transportation expenses for the year ended December 31, 2010 were $3.7 million ($1.20/boe) compared to $3.9 million ($1.26/boe) in the same 2009 period.
Operating Netback
Field Operating Netback — Corporate (before risk management)
| | For the years ended December 31, | |
($/boe) | | 2010 | | 2009 | |
Sales | | 37.20 | | 34.72 | |
Transportation | | (1.20 | ) | (1.26 | ) |
Royalties | | (7.37 | ) | (5.71 | ) |
Production expense | | (12.21 | ) | (14.64 | ) |
Field operating netback | | 16.42 | | 13.11 | |
For the 2010 year, corporate field operating netback (before commodity price risk management contracts) was $16.42/boe compared to $13.11/boe in fiscal 2009. This was primarily the result of higher pricing received for crude, condensate and NGL’s along with a reduction in production expenses as we increase production in areas with lower production costs and streamline our operations, offset by overall higher royalties. After including commodity price risk management contracts, the corporate field operating netback for 2010 was $21.37/boe compared to $18.88/boe in 2009.
Field Operating Netback — Natural Gas (before risk management)
| | Years ended December 31, | |
($/mcf) | | 2010 | | 2009 | |
Sales | | 4.19 | | 4.50 | |
Transportation | | (0.22 | ) | (0.20 | ) |
Royalties | | (0.71 | ) | (0.48 | ) |
Production expense | | (1.77 | ) | (2.07 | ) |
Field operating netback | | 1.49 | | 1.75 | |
Field operating netback for natural gas in 2010 decreased 15% to $1.49/mcf, compared to $1.75/mcf in 2009, reflecting weaker realized natural gas prices and higher royalties, offset by a reduction in production expenses. After including commodity price risk management contracts, field operating netback for natural gas for fiscal 2010 was $2.59/mcf compared to $3.21/mcf in the same period in 2009.
Field Operating Netback — Crude Oil, Condensate and NGLs (before risk management)
| | Years ended December 31, | |
($/bbl) | | 2010 | | 2009 | |
Sales | | 65.48 | | 49.65 | |
Transportation | | (0.95 | ) | (1.34 | ) |
Royalties | | (14.72 | ) | (11.18 | ) |
Production expense | | (15.88 | ) | (18.96 | ) |
Field operating netback | | 33.93 | | 18.17 | |
Field operating netback for crude oil, condensate and NGLs averaged $33.93/bbl for 2010, up 87% compared to $18.17/bbl for 2009. The increase in the netback is primarily the result of a 32% increase in the crude oil, condensate and NGLs sales price, along with a reduction in transportation and production expenses, offset by an increase in royalties. After including commodity price risk management contracts, field operating netback for crude oil and NGLs for 2010 was $35.03/boe compared to $18.14/boe in 2009.
24
General and Administrative
General and administrative (“G&A”) expenses (after capitalized G&A and recoveries) for 2010 were $9.4 million ($3.03/boe) compared to $10.2 million ($3.33/boe) for 2009. Gross expenses increased in 2010 compared to 2009 due to higher compensation and base costs which were offset by an increase in capitalized G&A and recoveries; consistent with Bellatrix’s increased 2010 capital program.
For 2011, the Company is anticipating G&A costs after capitalization to be approximately $12.0 million ($2.74/boe) based on estimated 2011 average production volumes of approximately 12,000 boe/d.
General and Administrative Expenses
| | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
Gross expenses | | 14,154 | | 12,371 | |
Capitalized | | (1,977 | ) | (648 | ) |
Recoveries | | (2,763 | ) | (1,484 | ) |
G&A expenses | | 9,414 | | 10,239 | |
G&A expenses, per unit ($/boe) | | 3.03 | | 3.33 | |
Interest and Financing Charges
Bellatrix recorded $7.4 million of interest and financing charges for the year ended December 31, 2010 compared to $13.7 million in 2009. The reduction in interest and financing charges is primarily due to a combination of lower average bank debt in 2010 and the Company’s issuance of its 4.75% Debentures in April 2010 which facilitated the redemption of Bellatrix’s 7.5% Debentures. Bellatrix’s total net debt at December 31, 2010 of $87.4 million includes the $47.6 million liability portion of convertible debentures, $41.2 million of bank debt and the net balance of working capital. The 4.75% Debentures have a maturity date of April 30, 2015.
Interest and Financing Charges
| | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
Interest and financing charges | | 7,403 | | 13,657 | |
Interest and financing charges ($/boe) | | 2.38 | | 4.44 | |
| | | | | |
Debt to funds flow from operations(1) ratio annualized(3) | | | | | |
Funds flow from operations(1) (annualized) | | 63,568 | | 30,724 | |
Total net debt (2) at year end | | 87,444 | | 107,269 | |
Total net debt to periods funds flow from operations ratio annualized(3) | | 1.4x | | 3.5x | |
| | | | | |
Net debt (2) (excluding convertible debentures) at year end | | 39,845 | | 25,585 | |
Net debt to periods funds flow from operations ratio annualized (3) | | 0.6x | | 0.8x | |
| | | | | |
Debt to funds flow from operations(1) ratio | | | | | |
Funds flow from operations(1) for the year | | 53,042 | | 36,025 | |
Total net debt (2) to funds flow from operations for the year | | 1.6x | | 3.0x | |
| | | | | |
Net debt (2) (excluding convertible debentures) to funds flow from operations for the year | | 0.8x | | 0.7x | |
(1) As detailed previously in this Management’s Discussion and Analysis, funds flow from operations is a term that does not have any standardized meaning under GAAP. Funds flow from operations is calculated as cash flow from operating activities before realization of imputed interest costs on 7.5% Debentures, asset retirement costs incurred and changes in non-cash working capital incurred.
25
(2) Net debt includes the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current capital lease obligation and short-term future tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes capital lease obligation, asset retirement obligations and the future income tax assets and liabilities. Total net debt is a non-GAAP measure; refer to the following reconciliation of total liabilities to total net debt.
(3)Total net debt and net debt to periods funds flow from operations ratio (annualized) is calculated based upon fourth quarter funds flow from operations annualized.
Reconciliation of Total Liabilities to Total Net Debt
| | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
Total liabilities per financial statements | | 164,367 | | 159,619 | |
Current liabilities included within working capital calculation | | (46,670 | ) | (24,305 | ) |
Asset retirement obligations | | (27,483 | ) | (25,728 | ) |
Capital lease obligation | | (1,443 | ) | — | |
| | | | | |
Working Capital | | | | | |
Current assets | | (45,108 | ) | (29,036 | ) |
Current liabilities | | 46,670 | | 24,305 | |
Current portion of capital lease | | (146 | ) | — | |
Net commodity contract asset (liability) | | (3,732 | ) | 3,374 | |
Net future income taxes – current | | 989 | | (960 | ) |
| | (1,327 | ) | (2,317 | ) |
Total net debt | | 87,444 | | 107,269 | |
Share-Based Compensation
Non-cash share-based compensation expense for the year ended December 31, 2010 was $1.6 million compared to a recovery of $0.2 million in 2009. The 2010 expense reflects a $2.4 million (2009: $0.8 million) share-based compensation expense, offset by $0.8 million (2009: $0.2 million) of share-based compensation expense capitalized and $0.03 million (2009: $0.8 million) of prior year share-based compensation expense for 2010 cancellation of unvested share options. The increase in the share-based compensation expense is due to a higher weighted fair value per option for 2010 grants compared to 2009. The increase in capitalized share-based compensation is consistent with capitalized G&A and Bellatrix’s increased 2010 capital program.
In connection with the Reorganization, a new option plan under Bellatrix was approved. As a result, the existing 4,067,733 incentive unit rights as at November 1, 2009 were exchanged for an equal number of common share options of Bellatrix with the same terms and conditions, including as to exercise price, vesting and expiry dates.
Depletion, Depreciation and Accretion
Depletion, depreciation and accretion expense for 2010 was $74.9 million ($24.07/boe), compared to the $90.8 million ($29.51/boe) in 2009. The reduction in the depletion, depreciation and accretion expense in 2010 compared to 2009 is primarily due to a $15.7 million decrease in depletion and depreciation which reflects Bellatrix’s increased cost base due to capital additions in 2010 and higher future development costs, offset by the additional reserves achieved through the Company’s drilling success.
For the year ended December 31, 2010, Bellatrix has included $157.9 million (2009: $57.2 million) for future development costs in the depletion calculation and excluded from the depletion calculation $18.6 million (2009: $20.5 million) for undeveloped land and $32.6 million (2009: $27.8 million) for estimated salvage.
26
Depletion, Depreciation and Accretion Costs
| | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
Depletion and Depreciation | | 72,703 | | 88,441 | |
Accretion | | 2,153 | | 2,319 | |
Total | | 74,856 | | 90,760 | |
Per unit ($/boe) | | 24.07 | | 29.51 | |
Reorganization Costs
The Company incurred $0.9 million in costs for legal, financial advisory, accounting, printing, mailing and other expenses that are included as reorganization costs within the Consolidated Statements of Loss for the year ended December 31, 2009 associated with the Reorganization resulting in the conversion from an open-ended, unincorporated investment trust to Bellatrix Exploration Ltd., a publicly traded exploration and development corporation.
Income Taxes
Future income taxes arise from differences between the accounting and tax bases of the Company’s assets and liabilities. For the year ended December 31, 2010, the Company recognized a future income tax recovery of $8.2 million compared to a recovery of $44.4 million in 2009, which is consistent with pre-tax losses of $35.7 million and $171.6 million for the respective periods.
As at December 31, 2010, the Company had a total net future income tax asset balance of $9.3 million. Canadian GAAP requires that a future income tax asset be recorded when the tax pools exceeds the book value of assets, to the extent the amount is more than likely than not to be realized.
At December 31, 2010, Bellatrix had approximately $449 million in tax pools available for deduction against future income as follows:
($000s) | | Rate % | | 2010 | | 2009 | |
Intangible resource pools: | | | | | | | |
Canadian exploration expenses | | 100 | | 44,000 | | 43,200 | |
Canadian development expenses | | 30 | | 286,500 | | 210,500 | |
Canadian oil and gas property expenses | | 10 | | 9,100 | | 15,100 | |
Foreign resource expenses | | 10 | | 900 | | 1,100 | |
Attributed Canadian Royalty Income | | 100 (Alberta) | | 16,100 | | 16,100 | |
Undepreciated capital cost | | 6 – 55(1) | | 89,100 | | 100,600 | |
Non-capital losses (expire through 2027) | | 100 | | 300 | | 13,100 | |
Financing costs | | 20 straight line | | 3,000 | | 200 | |
| | | | 449,000 | | 399,900 | |
(1) Approximately $84 million of undepreciated capital cost pools are class 41, which is claimed at a 25% rate.
As a result of the issuance of the Flow-Through Shares on August 12, 2010, Bellatrix is committed to incur approximately $20.0 million in qualifying Canadian Exploration Expenses prior to December 31, 2011.
Approximately $1.7 million of tax pools related to financing costs were eliminated as a result of the Reorganization from the Trust to the Company, effective November 1, 2009.
27
Cash Flow from Operating Activities, Funds Flow from Operations and Net Loss
Reconciliation of Cash Flow from Operating Activities and Funds Flow from Operations
| | Years ended December 31, | |
($000s, except per share amounts) | | 2010 | | 2009 | |
Cash flow from operating activities | | 44,272 | | 30,671 | |
Realization of imputed interest costs on 7.5% Debentures | | 5,050 | | — | |
Asset retirement costs incurred | | 1,373 | | 1,510 | |
Change in non-cash working capital | | 2,347 | | 3,844 | |
Funds flow from operations | | 53,042 | | 36,025 | |
Bellatrix’s cash flow from operating activities of $44.3 million ($0.46 per diluted share) for the year ended December 31, 2010 increased approximately 44% from the $30.7 million ($0.39 per diluted share) generated in 2009. Bellatrix generated funds flow from operations of $53.0 million ($0.54 per diluted share) for the year ended December 31, 2010, up 47% from $36.0 million ($0.46 per diluted share) for 2009. The increase in cash flow from operating activities and funds flow from operations for 2010 compared to 2009 was primarily the result of higher petroleum and natural gas sales, lower production, G&A and interest and financing expenses, offset by a decrease in realized gains on commodity price risk management contracts and higher royalties.
Bellatrix maintains a commodity price risk management program to provide a measure of stability to funds flow from operations. Unrealized mark—to—market gains or losses are non-cash adjustments to the current fair market value of the contract over its entire term and are included in the calculation of net loss.
The net loss for the 2010 year was $27.5 million ($0.30 per diluted share) compared to a net loss of $126.6 million ($1.61 per diluted share) in 2009. The decrease in the net loss from 2009 to 2010 was primarily due to a $114.2 million non-cash loss recorded in 2009 on the disposition of the majority of the Company’s petroleum and natural gas properties in Saskatchewan, reduced production, depletion, depreciation and accretion expenses offset by a decrease in gains on commodity price risk management contracts.
Cash Flow from Operating Activities, Funds Flow from Operations and Net Loss
| | Years Ended December 31, | |
($000s, except per share amounts) | | 2010 | | 2009 | |
Cash flow from operating activities | | 44,272 | | 30,671 | |
Basic ($/share) | | 0.47 | | 0.39 | |
Diluted ($/share) | | 0.46 | | 0.39 | |
Funds flow from operations | | 53,042 | | 36,025 | |
Basic ($/share) | | 0.57 | | 0.46 | |
Diluted ($/share) | | 0.54 | | 0.46 | |
Net loss | | (27,533 | ) | (126,620 | ) |
Basic ($/share) | | (0.30 | ) | (1.61 | ) |
Diluted ($/share) | | (0.30 | ) | (1.61 | ) |
Capital Expenditures
Bellatrix invested $98.4 million on exploration and development activities during 2010 compared to $15.8 million in 2009. The increase in these expenditures during the period is consistent with the higher capital budget for 2010.
28
Capital Expenditures
| | Years ended December 31, | |
($000s) | | 2010 | | 2009 | |
Lease acquisitions and retention | | 480 | | 649 | |
Geological and geophysical | | 737 | | 31 | |
Drilling and completion costs | | 90,914 | | 13,715 | |
Facilities and equipment | | 9,384 | | 3,616 | |
| | 101,515 | | 18,011 | |
Drilling incentive credits | | (3,128 | ) | (2,168 | ) |
Exploration and development(1) | | 98,387 | | 15,843 | |
Corporate (2) | | 521 | | 644 | |
Property acquisitions | | 7,840 | | — | |
Total capital expenditures — cash | | 106,748 | | 16,487 | |
Property dispositions — cash | | (14,567 | ) | (92,921 | ) |
Total net capital expenditures — cash | | 92,181 | | (76,434 | ) |
Capital lease additions- non-cash | | 1,600 | | — | |
Other — non-cash (3) | | 680 | | (492 | ) |
Total- non-cash | | 2,280 | | (492 | ) |
Total net capital expenditures | | 94,461 | | (76,926 | ) |
(1) Excludes capitalized costs related to asset retirement obligation expenditures incurred during the year.
(2) Corporate costs include office furniture, fixtures and equipment and other costs.
(3) Other includes non-cash adjustments for current period’s asset retirement obligations and unit based compensation.
During the 2010 year, Bellatrix achieved a 98% success rate in its 2010 drilling program that consisted of 48 (28.8 net) wells including 9 gross (6.3 net) natural gas wells, and 38 gross (21.5 net) oil wells and 1 gross and net dry hole.
The $101.5 million capital program, before drilling incentive credits, for the year ended December 31, 2010, was financed entirely with funds flow from operations, bank indebtedness, proceeds from equity financings and joint venture partners.
Based on the current economic conditions and Bellatrix’s operating forecast for 2011, the Company budgets a capital program of $100 million funded from the Company’s cash flows and debt facilities. In addition, the Company anticipates utilizing up to $10 million from a joint venture partner.
Ceiling Test
The Company calculates a ceiling test quarterly and annually to place a limit on the aggregate carrying value of its capitalized costs, which may be amortized against revenues of future periods. The ceiling test is performed in accordance with the requirements of the Canadian Institute of Chartered Accountants (“CICA”) AcG-16 “Oil and Gas Accounting — Full Cost”, a two step process.
The Company performed a ceiling test calculation at December 31, 2010 resulting in undiscounted cash flows from proved reserves and the undeveloped properties exceeding the carrying value of oil and gas assets. Consequently, no impairment in oil and gas assets was identified as at December 31, 2010.
In 2011, an impairment test calculation will be performed in accordance with International Financial Reporting Standards (“IFRS”) and will be updated on a quarterly basis. Under IFRS, the impairment test is calculated at the cash generating unit level which is discussed in more detail in the Financial Reporting Update section of this MD&A. The impairment test will be based upon fair market values for the Company’s properties using the latest available data, including but not limited to an updated annual external reserve engineering report which incorporates a full evaluation of reserves 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
29
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.
Asset Retirement Obligations
As at December 31, 2010, Bellatrix has recorded an Asset Retirement Obligation (“ARO”) of $27.5 million, compared to $25.7 million at December 31, 2009, for future abandonment and reclamation of the Company’s properties. For the year ended December 31, 2010, the ARO increased by $1.8 million as a result of $1.6 million incurred on property acquisitions and development activities, $2.0 million as a result of changes in estimates and $2.2 million for accretion expense, offset by a reduction of $2.6 million for liabilities reversed on dispositions and $1.4 million for liabilities settled during the year.
Liquidity and Capital Resources
As an oil and gas business, Bellatrix has a declining asset base and therefore relies on ongoing development and acquisitions to replace production and add additional reserves. Future oil and natural gas production and reserves are highly dependent on the success of exploiting the Company’s existing asset base and in acquiring additional reserves. To the extent Bellatrix is successful or unsuccessful in these activities, cash flow could be increased or reduced.
Bellatrix is focused on growing oil and natural gas production from its diversified portfolio of existing and emerging resource plays in Western Canada. Bellatrix remains highly focused on key business objectives of maintaining financial strength, optimizing capital investments — attained through a disciplined approach to capital spending, a flexible investment program and financial stewardship. Natural gas prices are primarily driven by North American supply and demand, with weather being the key factor in the short term. Bellatrix believes that natural gas represents an abundant, secure, long-term supply of energy to meet North American needs. Bellatrix’s results are affected by external market and risk factors, such as fluctuations in the prices of crude oil and natural gas, movements in foreign currency exchange rates and inflationary pressures on service costs.
Liquidity risk is the risk that Bellatrix will not be able to meet its financial obligations as they fall 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 debt covenants. Bellatrix is fully compliant with all of its operating debt covenants.
Bellatrix generally relies on operating cash flows and its credit facilities to fund capital requirements and provide liquidity. Future liquidity depends primarily on cash flow generated from operations, existing credit facilities and the ability to access debt and equity markets. From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. While Bellatrix completed a January 2010 equity offering, issued the 4.75% Debentures in April 2010 and completed a Flow-Through Share offering in August 2010, 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.
30
A substantial portion of Bellatrix’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Bellatrix sells substantially all of its production to five primary purchasers under standard industry sale and payment terms. Purchasers of Bellatrix’s natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. Bellatrix has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in Bellatrix reducing or mitigating its exposures to certain counterparties where it is deemed warranted and permitted under contractual terms.
Bellatrix may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production 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.
During 2010, Bellatrix has concentrated on executing its considerable drilling program and improving its balance sheet. Bellatrix has taken advantage of several financial opportunities that have improved the Company’s financial flexibility. In January 2010, Bellatrix closed an equity issuance of 13.64 million common shares at a price of $3.30 per share for gross proceeds of $45.0 million (net proceeds of $42.4 million after transaction costs). The net proceeds from this financing were used to temporarily reduce outstanding indebtedness. On April 20, 2010, the Company issued $55 million of 4.75% Debentures, in order to facilitate the repayment of its 7.5% Debentures. The balance of the repayment of the 7.5% Debentures was funded through bank indebtedness.
On August 12, 2010, Bellatrix issued 4.71 million Flow-Through Shares at $4.25 each for gross proceeds of $20.0 million. Proceeds of the Flow-Through Shares were used to accelerate the Company’s Cardium light oil exploration program. The Company will incur expenditures eligible for Canadian exploration expenses which will be renounced to subscribers of the Flow-Through Shares effective on or before December 31, 2010. The Company is committed to incur the $20.0 million CEE expenditures on or before December 31, 2011.
Total net debt levels at December 31, 2010 have decreased $19.9 million from $107.3 million at December 31, 2009, primarily as a consequence of the January 2010 equity issuance, the Company’s issuance of its 4.75% Debentures which facilitated the redemption of its 7.5% Debentures and the Flow-Through Share financing. Total net debt includes the liability component of the convertible debentures and excludes unrealized commodity contract assets and liabilities, future income taxes, capital lease obligations and asset retirement obligations.
Funds flow from operations represents 50% of the funding requirements for Bellatrix’s capital expenditures for the year ended December 31 2010. The remainder has been funded through bank indebtedness, equity financings and funds available through joint venture partners.
Effective December 15, 2010, the Company’s borrowing base was increased from $85 million to $100 million. The Company’s expanded facilities consists of a $15 million demand operating facility provided by a Canadian bank and an $85 million extendible revolving term credit facility provided by a Canadian bank and a Canadian financial institution. Amounts borrowed under the credit facility will bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate or LIBOR rate, plus between 1.25% and 4.25%, depending on the type of borrowing and the Company’s debt to cash ratio. The credit facilities are secured by a $400 million debenture containing a first ranking charge and security interest. Bellatrix has provided a negative pledge and undertaking to provide fixed charges over major petroleum and natural gas reserves in certain circumstances. A standby fee is charged of between 0.55% and 1.02% on the undrawn portion of the credit facilities, depending on the Company’s debt to cash flow ratio.
31
On June 8, 2010, Bellatrix executed an amending agreement with its banking syndicate that provided for the extension of the revolving period of existing credit facility from June 29, 2010 to June 28, 2011. 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 28, 2011. The Company’s borrowing base will be subject to re-determination on May 30, 2011. Thereafter, a semi-annual re-determination of the borrowing base will occur, with the next such re-determination occurring on November 30, 2011.
Pursuant to Bellatrix’s credit facilities, the Company is permitted to pay the semi-annual interest payments on the 4.75% Debentures, and payments by the Company to debenture holders in relation to the redemption of the 4.75% Debentures and in relation to debenture normal course issuer bids for the 4.75% Debentures approved by the Toronto Stock Exchange, provided that the aggregate of all such normal course issuer bids and redemptions do not exceed $10.0 million in any fiscal year.
As at December 31, 2010, approximately $58.8 million was undrawn under the existing credit facilities.
As an added layer of protection of its cash flows, Bellatrix has 1,000 bbl/d and 500 bbl/d of oil protected by fixed price swaps at CDN$88.18/bbl and CDN$89.00/bbl, respectively and 500 bbl/d of oil protected by a fixed price swap at US$89.10 for the 2011 calendar year. Subsequent to December 31, 2010, the Company added further crude oil fixed price swaps; one for 500 bbl/d at US$95.00 for February 1 to December 31, 2011 and another for 500 bbl/d at US$97.50 for March 1 to December 31, 2011, and four natural gas fixed price swaps for 20,000 GJ/d total at an average of $3.78/GJ for April 1 to October 31, 2011.
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 2011 capital program of $100 million by utilizing undrawn amounts on its credit facility and ongoing cash flows. In addition, the Company anticipates utilizing up to $10 million from a joint venture partner.
As at February 28, 2011, Bellatrix had outstanding a total of 5,834,543 options exercisable at an average exercise price of $2.70 per share, $55.0 million principal amount of 4.75% Debentures convertible into common shares (at a conversion price of $5.60 per share) and 97,447,360 common shares.
Related Party Transactions
The Company received legal services from a law firm in which a director and corporate secretary is a partner. The fees charged are based on standard rates and time spent on matters pertaining to the Company. The services provided were in the normal course of operations and have been recorded at the exchange amount. For the year ended December 31, 2010, legal fees invoiced by the related party totaled $0.6 million (2009: $1.1 million).
Commitments
As at December 31, 2010, the Company had committed to drill 9 gross (4.7 net) wells pursuant to farm-in agreements. Bellatrix expects to satisfy this drilling commitment at an estimated cost of approximately $12.9 million. On February 1, 2011, the Company entered into a joint venture agreement which includes a minimum commitment for Bellatrix to drill 3 gross (3.0 net) wells per year for 2011 to 2015 for a total estimated cost of approximately $52.5 million.
As a result of the issuance of the Flow-Through Shares on August 12, 2010, Bellatrix is committed to incur approximately $20.0 million in qualifying Canadian Exploration Expenses on or before December 31, 2011.
32
The following are the contractual maturities of financial liabilities as at December 31, 2010:
Financial liability ($000s) | | < 1 Year | | 1-2 Years | | 2-5 Years | | Thereafter | |
Accounts payable and accrued liabilities(1) | | $ | 42,792 | | $ | — | | $ | — | | $ | — | |
Bank debt — principal(2) | | — | | 41,172 | | — | | — | |
Convertible debentures — principal | | — | | — | | 55,000 | | — | |
Convertible debentures — interest(3) | | 2,613 | | 2,620 | | 6,084 | | — | |
Capital lease obligation | | 379 | | 363 | | 991 | | 1,516 | |
Total | | $ | 45,784 | | $ | 44,155 | | $ | 62,075 | | $ | 1,516 | |
(1) As at December 31, 2010, $0.4 million of accrued coupon interest payable in relation to the 4.75% Debentures and $0.1 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.
(3) The 4.75% Debentures outstanding at December 31, 2010 bear interest at a coupon rate of 4.75%, which currently requires total annual interest payments of $2.6 million.
Interest due on the bank credit facilities is calculated based on floating rates.
The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations to be approximately $63 million which is estimated to be incurred between 2014 and 2054.
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, 2010.
The Company is committed to payments under operating leases for office space as follows:
($000s)
Year | | Gross Amount | | Expected
Recoveries | | Net amount | |
2011 | | $ | 2,192 | | $ | 1,027 | | $ | 1,165 | |
2012 | | 2,203 | | 1,062 | | 1,141 | |
2013 | | 2,218 | | 1,103 | | 1,115 | |
2014 | | 1,469 | | 753 | | 716 | |
| | | | | | | | | | |
Business Prospects and 2011 Year Outlook
At December 31, 2010, Bellatrix reports 211,893 net undeveloped acres (compared to 258,507 net in 2009). The change is attributable to normal course lease expiries in non-core gas areas (approximately 62% of the change), strategic non-core asset sales (approximately 25% of the change), and reclassification of lands (such as drilling). In the Greater Pembina core area of Bellatrix, expiries to the undeveloped net acreage were largely offset by recent acquisitions. During 2010, Bellatrix negotiated a Joint Venture Agreement which would grant access to significant Cardium rights. This arrangement was concluded on February 1, 2011 and grants Bellatrix access to 20 net sections of prospective Cardium rights. The addition of these lands closely balances the 22 net sections of Cardium rights on first nation lands which were unable to be continued in Q4 2010.
33
In 2011, Bellatrix will continue to be active in drilling its two core resource plays, the Cardium and Notikewin, utilizing horizontal drilling multi fracturing technology. Bellatrix has developed an inventory of 320 net horizontal drilling locations targeting the Cardium Interval and 100 net horizontal drilling locations to access the Notikewin sequence of channel sands.
Bellatrix plans to operate within funds flow from operations and available credit facilities. Bellatrix has set a $100 million capital expenditures budget for 2011. In addition, the Company anticipates utilizing up to $10 million from a joint venture partner. Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2011 budget is anticipated to provide 2011 average daily production of approximately 12,000 boe/d and an exit rate of approximately 13,000 boe/d. The 2011 capital budget is expected to be directed primarily towards horizontal drilling and completions activities in the Cardium and Notikewin resource plays.
As part of the 2011 capital expenditures budget the Corporation anticipates a very active first quarter in 2011 with participation in 22 gross (12.2 net) wells weighted 2/3 oil and 1/3 liquids rich gas. To date in the first quarter of 2011, the Company has drilled or participated in 9 gross (5.5 net) Cardium oil wells and 6 gross (2.4 net) Notikewin liquids rich gas wells. The remaining 7 gross (4.3 net) potential oil wells are scheduled to be drilled prior to the end of Q1.
Currently the Company is producing approximately 11,000 boe/d but has experienced significant downtime associated with freeze offs, a compressor failure and pump failures resulting in production averaging approximately 10,000 boe/d in the first 2 months of Q1. Behind pipe tested production of 1,500 boe/d net will be tied in by the end of Q1.
As an added layer of protection of its cash flows, Bellatrix has 1,000 bbl/d and 500 bbl/d of oil protected by fixed price swaps at CDN$88.18/bbl and CDN$89.00/bbl, respectively and 500 bbl/d of oil protected by a fixed price swap at US$89.10 for the 2011 calendar year. Subsequent to December 31, 2010, the Company added further crude oil fixed price swaps; one for 500 bbl/d at US$95.00 for February 1 to December 31, 2011 and another for 500 bbl/d at US$97.50 for March 1 to December 31, 2011, and four natural gas fixed price swaps for 20,000 GJ/d total at an average of $3.78/GJ for April 1 to October 31, 2011.
Financial Reporting Update
Future Accounting Pronouncements
International Financial Reporting Standards (“IFRS”)
On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”), which will replace current Canadian GAAP for years beginning on or after January 1, 2011. The transition date of January 1, 2011 will require restatement for comparative purposes, of the Company’s opening balance sheet as at January 1, 2010, all interim quarterly periods in 2010 and for its year ended December 31, 2010. The objective is to improve financial reporting by having one single set of accounting standards that are comparable with other entities on an international basis.
An internal project team was set up to manage this transition and to ensure successful implementation within the required time frame. Members of the internal project team and key finance personnel have attended industry specific seminars. Members of the Board and Audit Committee possess financial expertise and are provided with quarterly updates, including accounting policy choices among IFRSs and recommendations to date.
In 2009 and 2010, the Company completed high level analyses to determine the areas impacted by the conversion and is finalizing the financial reporting impacts on the adoption of IFRS. The assessment provided insight as to the most significant areas of GAAP differences applicable to Bellatrix and include treatment of exploration and evaluation
34
costs, depreciation and depletion of property, plant and equipment, and impairment of assets, as well as more extensive presentation and disclosure requirements under IFRS. The analysis has been reviewed by the Company’s external auditors for consistency in the interpretation of the standards.
IFRS in-depth reviews have been concentrated on cash generating units, options available under IFRS for modified full cost accounting, decommissioning liabilities, share-based compensation and a preliminary analysis of the impact on our data gathering and reporting systems. We are still assessing the impact of IFRS and have not finalized all of our accounting policy choices and IFRS 1 exemptions. Throughout 2010 and to date, efforts are underway to fully quantify the impact of IFRS on the Company’s January 1, 2010 transition date balance sheet and the future financial position and results of operations.
IFRS 1 — “First-time Adoption of International Financial Reporting Standards” is the standard that governs mandatory exceptions and optional exemptions that an entity may elect for its transition to IFRS in order to assist the entity with the transition process. This standard is only applicable to the opening balance sheet of the entity on the transition date of January 1, 2010.
The following are IFRS 1 exemptions that Bellatrix currently anticipates electing on transition date. The quantification of certain of the effects of the adoption of IFRS discussed below are an estimate of the impact based on the policy elections currently proposed which may change prior to finalization. In addition, other differences may exist between amounts reported by the Company under Canadian GAAP versus IFRS. New or revised IFRS are being developed by the International Accounting Standards Board (“IASB”) that may impact the adoption of IFRS by the Corporation. The Company continues to monitor these and other accounting standard developments within IFRS which might impact its IFRS conversion. The following also is not exhaustive as to all actual or potential differences, which remain subject to determination and change.
Property, Plant and Equipment (“PP&E”)
The adopter has the option to elect fair value at the date of transition as the deemed cost for its PP&E or to use a revalued amount according to its previous GAAP if the revaluation, at the date of revaluation, is comparable to fair value or depreciated cost in accordance with IFRS. On July 23, 2009 the IASB published amendments to IFRS 1 which will allow an election to measure oil and gas assets at the date of transition to IFRS at the amount determined under Canadian GAAP. The Company plans to make this election under IFRS 1 for its opening balance sheet at January 1, 2010. The standard allows the adopter to allocate its PP&E asset base to the Company’s cash generating units based on reserve volumes or values. Bellatrix anticipates the method of allocation that it will use on the transition date will be based upon proved plus probable company interest reserve cash flow values. Once the Company’s petroleum and natural gas assets are allocated to the Company’s petroleum and natural gas assets, it is required to perform an impairment test.
Business Combinations
An exemption under IFRS 1 provides the entity with relief on the restatement of business combinations prior to the transition date. Under IFRS 3 — “Business Combinations,” the determination of the fair value of share consideration differs from the determination under current Canadian accounting standards. Any difference in the fair value calculation would have a resulting impact on the carrying amount of net assets acquired, non-controlling interest and any goodwill. The Company plans to make the election under IFRS 1, allowing Bellatrix to be exempt from restating business combinations prior to the transition date to IFRS.
Share Based Payments
Differences in the accounting for the Company’s share option plan have been identified. IFRS 2 — “Share-based Payments,” requires the Company to estimate the number of options expected to vest when a grant of equity instruments do not vest immediately. An estimate of the option’s life is also required for the estimation of the fair
35
value of the instruments. IFRS 2 does not allow the recognition of the expense on a straight-line basis and requires each installment to be treated as a separate arrangement. Currently, the Company accounts for forfeitures as they occur and considers the estimated life of the options to be consistent with their expiry date. Share-based compensation expense is accounted for using the graded method which is required under IFRS. IFRS 1 provides an elective exemption which the Company plans to elect which will allow Bellatrix to apply IFRS 2 to the 3,571,955 unvested options outstanding on the transition date of January 1, 2010. As a result of applying IFRS 2, the Company anticipates a decrease to contributed surplus of less than $0.5 million with an offsetting increase to the January 1, 2010 deficit. The adjustment is a result of applying an estimated forfeiture rate of 3%, 5% and 10% for options vesting in year 1, 2 and 3, respectively.
Decommissioning Liabilities
IAS 37 — “Provisions, Contingent Liabilities and Contingent Assets,” will govern how the Company accounts for its decommissioning liabilities (currently referred to as asset retirement obligations). The decommissioning liability should reflect risks specific to the liability and will be based on management’s best assumptions and estimates versus the fair value of the obligation. The amount recognized should be the best estimate of the expenditure required to settle the present obligation at the end of the period. If there are uncertainties surrounding the amount to be recognized as a provision then the obligation is estimated by weighting all possible outcomes by their associated probabilities. The discount rate used for the decommissioning liability will be a risk free rate as the estimated provision is adjusted to reflect risks specific to the liability. Currently under Canadian GAAP, the Company uses a credit-adjusted risk free rate. Therefore, under IFRS, the decommissioning liabilities are expected to be higher due to lower discount rates. Under IFRS, the unwinding of the discount rate is charged as interest expense versus accretion expense under current Canadian standards. IFRS 1 provides an exemption that the Company plans to elect which will allow Bellatrix to measure decommissioning liabilities as at the date of transition to IFRS in accordance with IAS 37 and recognize directly in retained earnings any difference between that amount and the carrying amount of those liabilities at the date of transition to IFRS determined under Canadian GAAP. The Company has calculated its decommissioning liabilities using risk free rates that coincide with the expected time frame of the abandonments which range from 1.45% to 4.1%. As a result of applying IAS 37, the Company anticipates its opening January 1, 2010 decommissioning liability to increase by approximately $10 million to $15 million, with an offsetting charge to the January 1, 2010 deficit.
Impairment of Assets
Currently, under Canadian GAAP, the ceiling test is a two step process that is performed at the country cost centre level. If the undiscounted cash flows from proved reserves and the undeveloped properties do not exceed the carrying value of oil and gas assets; impairment exists. The impairment is measured by comparing the carrying value of oil and gas assets to the discounted cash flows from proved plus probable reserves. Accounting Guideline 16 — “Oil and Gas Accounting — Full Cost” suggests discounting the cash flows using a risk-free rate.
IFRS uses the concept of cash generating units (“CGU”) to accumulate asset carrying costs to test and measure impairment. Bellatrix anticipates initially having a total of 6 CGU’s. IAS 36 — “Impairment of Assets” (“IAS 36”) is a one step process for testing and measuring impairment of assets. Under IAS 36, the asset or CGU’s carrying value is compared to the higher of: value-in-use and fair value less costs to sell. Value in use is defined as the present value of future cash flows expected to be derived from the asset or CGU.
The impairment test under IFRS is performed at a level that is lower than the current country cost centre level used under Canadian GAAP which may result in more frequent write downs. Also, the test uses discounted cash flows to test and measure asset impairment, whereas under Canadian GAAP, the asset carrying values have been supported by undiscounted cash flows. IAS 36 requires impairment losses that were previously recognized to be reversed when
36
circumstances exist such that the impairment is reduced or no longer exists. Canadian GAAP prohibits the reversal of previously recognized impairment losses.
Bellatrix is required to perform an impairment test on the transition date to IFRS and when indicators suggest the possibility of impairment. The Company anticipates an impairment to its PP&E in certain non-core heavy oil and minor natural gas related properties on transition to IFRS as at January 1, 2010 to be between $40 million to $50 million, with an offsetting charge to the January 1, 2010 deficit. Bellatrix has used the fair value less costs to sell to measure the fair value of its CGU’s.
Oil and Gas Expenditures
Petroleum and natural gas expenditures fall under IFRS 6 — “Exploration for and Evaluation of Mineral Resources,” and IAS 16 — “Property, Plant and Equipment.” Capital expenditures incurred will be segregated into three categories:
1) Pre-exploration expenditures
2) Exploration and evaluation expenditures
3) Development and production expenditures
Pre-exploration expenditures
These are costs incurred by the Company before acquiring the legal right to explore in a specific area. These expenditures do not meet the definition of an asset as defined by IAS 16 and therefore will be expensed by the Company as incurred. We do not anticipate these costs to be significant to the Company.
Exploration and evaluation expenditures
IFRS 6 provides flexibility on the accounting for exploration and evaluation (“E&E”) expenditures, allowing the Company to choose what type of expenditures will be capitalized or expensed. The costs incurred in the E&E phase will be capitalized once the legal right to explore in a specific area has been obtained. The assets are classified as E&E assets until technical feasibility and commercial viability of extracting resources is proven.
The Company does not intend to amortize its E&E expenditures until technical feasibility and commercial viability has been established. The standard does not define technical feasibility and commercial feasibility. Bellatrix intends to classify E&E assets as technically feasible and commercially viable once the property has proved reserves. Once proved reserves are established, the respective E&E assets will be transferred into the development and production category. E&E assets will be assessed for impairment if such information becomes available or there has been a change in facts and circumstances that would lead management to believe that the assets may be impaired. The following is a list of examples of changes in facts and circumstances that indicate an impairment test is needed:
· Remaining land lease terms have expired or expire in the near future and is not expected to be renewed
· Dry holes
· Management decisions to continue or discontinue activities in an area
· Budgeted or planned capital spending in an area is significantly reduced or eliminated
· Other information that may come to management’s attention indicating that the carrying amount of the E&E asset is unlikely to be recovered in full
37
A company has the option to test E&E assets for impairment separate from developing and producing (“D&P”) assets, at the cash generating unit level or an aggregated cash generating unit level (as long as it is not at a level higher than an operating segment).
The Company intends on testing the E&E assets for impairment along with the respective developing and producing assets at the aggregated cash generating unit level. An impairment test is required before any E&E asset is transferred to the developing and producing phase.
Developing and production expenditures
Once technical feasibility and commercial viability has been established, the assets are classified as D&P assets and will be subject to depreciation and depletion.
Depletion of Petroleum and Natural Gas Assets
Under Canadian GAAP, depletion of petroleum and natural gas assets is based on proved reserves and is calculated at the country cost centre level. Under IFRS, depletion is to be calculated at a lower unit of account level. For Bellatrix, the unit of account level will be at the area level. Also, under IFRS, a company has the option of choosing the reserve base that it will use for its depletion calculation. Bellatrix anticipates on using proved plus probable reserves for its depletion calculations. It is anticipated that depletion charges will be lower under IFRS as the reserve base for which the calculations are based on will be larger.
Asset Divestitures
Under Canadian GAAP, proceeds of a divestiture are deducted from the country cost centre pool without recognition of a gain or loss unless such a deduction resulted in a change to the depletion rate of 20% or greater. Under IFRS, proceeds of a divestiture are deducted from the carrying value of the asset and a gain or loss is recognized in earnings.
Future Income Taxes
IFRS does not use the terminology of future income taxes; IFRS refers to deferred income taxes.
The transition to IFRS will require the Company to re-measure its deferred income taxes for its January 1, 2010 balance sheet. Adjustments to deferred income taxes will be made accordingly in conjunction with other transitionary IFRS adjustments discussed earlier, with an offsetting adjustment to the January 1, 2010 deficit.
A transitionary deferred income tax adjustment will be required for the Company’s convertible debentures. Convertible debentures have both a debt and equity component. The allocation of deferred tax on the convertible debentures differs under Canadian GAAP and IFRS. Under Canadian GAAP, the tax basis of the liability is considered to be the same as its carrying amount; therefore, no temporary difference exists. IFRS does not contain this special exemption and requires the temporary difference to be recognized. The deferred tax expense is charged directly to the carrying amount of the equity component of the convertible debentures. Bellatrix anticipates recording a deferred tax liability of less than $1 million, with an offsetting debit to the equity component of its 7.5% Debentures. Subsequent changes in the deferred tax liability are recognized in profit or loss.
In addition to the adjustments required to deferred income taxes as a result of the January 1, 2010 transitionary adjustments, the Company will require adjustments for its comparative periods in 2010 for share issue costs and flow-through shares. Under Canadian GAAP, the accounting treatment of flow-through shares is addressed by EIC 146 — “Flow-Through Shares”. The proceeds received for the flow-through shares are credited to shareholders’ capital and the deferred tax liability is recognized when the company files the renouncement documents with the tax authorities to renounce the tax credits associated with the expenditures.
38
Under IFRS, Bellatrix expects to set up a liability for the difference between the proceeds received and the market price of the shares on the date of the transaction (the “premium”). Once the renouncement documents are filed with the tax authorities, Bellatrix will record the tax liability associated with the renouncement of the tax benefits and remove the deferred liability originally set up. The difference between the deferred tax liability and the original liability set up will go through profit or loss.
A temporary difference exists for share issue costs under Canadian GAAP and IFRS. The difference between Canadian GAAP and IFRS is where changes in the deferred tax liability are recorded. Unlike Canadian GAAP, changes in the deferred tax liability are recognized where they were originally recognized; therefore, changes in the deferred tax liability related to share issue costs are recorded against share capital as opposed to profit or loss. The Company does not have any transitionary adjustments related to share issue costs.
Information technology and data systems
Bellatrix has performed an assessment of the implications of IFRS on its information technology and data systems. The Company’s current data gathering and accounting system is capable of obtaining and recording data at a level of detail required for IFRS. The Company has identified transactions relating to its property, plant and equipment in relation to requirements under IFRS to have the most impact on its information technology and data systems. In order to comply with some of the requirements under IFRS, the Company will need to be able to record assets at the E&E and D&P categories, have the ability to transfer expenditures from the E&E phase to the D&P phase and record depletion, depreciation and accretion at the unit of account or lower. A test environment has been set up and Bellatrix is still in the process of testing the requirements and amending system modifications. Based on the test environment set up, minor modifications are needed.
Business activities
Bellatrix has reviewed the impact of IFRS on its commodity price risk management practices, debt covenants and compensation arrangements. It is not expected that IFRS will result in any significant changes to the Company’s business activities. Currently, Bellatrix’s credit facility agreement provides for a notice which allows for consideration to be given to revise the method of calculating one or more of the financial calculations which are materially different as a result of the adoption of IFRS. The Company must provide notice within 45 days of the end of a quarter or 90 days at the end of the fourth quarter or in respect of an entire fiscal year.
Internal control over financial reporting and disclosure controls and procedures
The implementation of IFRS may require changes to the Company’s internal controls over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”). The Company plans to assess the changes required in its ICFR and DC&P as accounting policy choices are finalized and its implications on ICFR and DC&P are identified.
Bellatrix continues to quantify the effects of choices available under IFRS which impact the opening balance sheet and the Company’s external auditors have commenced their review process. The Company previously anticipated finalizing the opening balance sheet adjustments in the third quarter of 2010, but is still in the process of calculating all of the anticipated adjustments. Certain proposed opening balance sheet adjustments have been reviewed with the Company’s Audit Committee and Board of Directors. Once the opening balance sheet adjustments are finalized, the Company will complete the roll-forward of the first to fourth quarter 2010 financial statements to IFRS.
IFRS will likely result in additional disclosures in Bellatrix’s financial statements for items already disclosed in other security documents in Canada. As part of preparing draft IFRS disclosures, the Company has analyzed and will continue to analyze the additional disclosures to ensure sufficient information is available upon adoption of IFRS.
During the fourth quarter of 2010, the Company concentrated on its information technology and data systems, as well as deferred income taxes and its impairment test upon transition to IFRS.
39
We will continue to monitor standards development as issued by the International Accounting Standards Board and the AcSB, as well as regulatory developments as issued by the Canadian Securities Administrators (CSA), which may affect the timing, nature or disclosure of our adoption of IFRS.
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.
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 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
40
produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner’s interest 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.
Alberta
Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.
On October 25, 2007, the Government of Alberta released a report entitled “The New Royalty Framework” (“NRF”) containing the Government’s proposals for Alberta’s new royalty regime which were subsequently implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008. The NRF took effect on January 1, 2009. On March 11, 2010, the Government of Alberta announced changes to Alberta’s royalty system intended to increase Alberta’s competitiveness in the upstream oil and natural gas sectors, which changes included a decrease in the maximum royalty rates for conventional oil and natural gas production effective for the January 2011 production month. Royalty curves incorporating the changes announced on March 11, 2010 were released on May 27, 2010.
With respect to conventional oil, the NRF eliminated the classification system used by the previous royalty structure which classified oil based on the date of discovery of the pool. Under the NRF, royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and incorporates separate variables to account for production rates and market prices. Royalty rates for conventional oil under the NRF ranged from 0-50%, an increase from the previous maximum rates of 30-35% depending on the vintage of the oil, and rate caps were set at $120 per barrel. Effective January 1, 2011, the maximum royalty payable under the NRF was reduced to 40%. The royalty curve for conventional oil announced on May 27, 2010 amends the price component of the conventional oil royalty formula to moderate the increase in the royalty rate at prices higher than $535/m3 compared to the previous royalty curve.
Royalty rates for natural gas under the NRF are similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices. Royalty rates for natural gas under the NRF ranged from 5-50%, an increase from the previous maximum rates of 5-35%, and rate caps were set at $16.59/GJ. Effective January 1, 2011, the maximum royalty payable under the NRF was reduced to 36%. The royalty curve for natural gas announced on May 27, 2010 amends the price component of the natural gas royalty formula to moderate the increase in the royalty rate at prices higher than $5.25/GJ compared to the previous royalty curve.
Producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold production taxes. The level of the freehold production tax is based on the volume of monthly production and a specified rate of tax for both oil and gas.
In April 2005, the Government of Alberta implemented the Innovative Energy Technologies Program (the “IETP”), which has the stated objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques and improving the recovery of natural gas from coal seams. The IETP is backed by a $200 million funding commitment over a five-year period beginning April 1, 2005 and provides royalty adjustments to specific pilot and demonstration projects that utilize new or innovative technologies to increase recovery from existing reserves.
On April 10, 2008, the Government of Alberta introduced two new royalty programs to be implemented along with the NRF and intended to encourage the development of deeper, higher cost oil and gas reserves. A five-year program
41
for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million or 12 months of royalty relief, whichever comes first, and a five-year program for natural gas wells deeper than 2,500 metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre. On May 27, 2010, the natural gas deep drilling program was amended, retroactive to May 1, 2010, by reducing the minimum qualifying depth to 2,000 metres, removing a supplemental benefit of $875,000 for wells exceeding 4,000 metres that are spud subsequent to that date, and including wells drilled into pools drilled prior to 1985, among other changes.
On November 19, 2008, in response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced the introduction of a five-year program of transitional royalty rates with the intent of promoting new drilling. The 5-year transition option is designed to provide lower royalties at certain price levels in the initial years of a well’s life when production rates are expected to be the highest. Under this new program, companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 m) are given a one-time option, on a well-by-well basis, to adopt either the new transitional royalty rates or those outlined in the NRF. Pursuant to the changes made to Alberta’s royalty structure announced on March 11, 2010, producers were only able to elect to adopt the transitional royalty rates prior to January 1, 2011 and producers that had already elected to adopt such rates as of that date were permitted to switch to Alberta’s conventional royalty structure up until February 15, 2011. On January 1, 2014, all producers operating under the transitional royalty rates will automatically become subject to Alberta’s conventional royalty structure. The revised royalty curves for conventional oil and natural gas will not be applied to production from wells operating under the transitional royalty rates.
On March 3, 2009, the Government of Alberta announced a three-point incentive program in order to stimulate new and continued economic activity in Alberta. The program introduced a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program, both applying to conventional oil or natural gas wells drilled between April 1, 2009 and March 31, 2010. The drilling royalty credit provides up to a $200 per metre royalty credit for new wells and is primarily expected to benefit smaller producers since the maximum credit available will be determined using the company’s production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010, favouring smaller producers with lower activity levels. The new well incentive program initially applied to wells that began producing conventional oil or natural gas between April 1, 2009 and March 31, 2010 and provided for a maximum 5% royalty rate for the first 12 months of production on a maximum of 50,000 barrels of oil or 500 MMcf of natural gas. In June, 2009, the Government of Alberta announced the extension of these two incentive programs for one year to March 31, 2011. On March 11, 2010, the Government of Alberta announced that the incentive program rate of 5% for the first 12 months of production would be made permanent, with the same volume limitations.
In addition to the foregoing, on May 27, 2010, in conjunction with the release of the new royalty curves, the Government of Alberta announced a number of new initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the “Emerging Resources and Technologies Initiative”). Specifically:
· Coalbed methane wells will receive a maximum royalty rate of 5% for 36 producing months on up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;
· Shale gas wells will receive a maximum royalty rate of 5% for 36 producing months with no limitation on production volume, retroactive to wells that began producing on or after May 1, 2010;
· Horizontal gas wells will receive a maximum royalty rate of 5% for 18 producing months on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010;
· Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of 5% with volume and production month limits set according to the depth of the well, retroactive to wells that commenced drilling on or after May 1, 2010.
42
The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice at that time if it decides to discontinue the program.
In addition to the foregoing, Alberta currently maintains a royalty reduction program for low productivity oil and oil sands wells, a royalty adjustment program for deep marginal gas wells and a royalty exemption for re-entry wells, among others.
Land Tenure
Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms from two years, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned 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’s policy of deep rights reversion was expanded 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.
In Alberta, the NRF includes a policy of “shallow rights reversion” which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. The order in which these agreements will receive the reversion notice will depend on their vintage and location, with the older leases and licenses receiving reversion notices first beginning in January 2011. Leases and licences that were granted prior to January 1, 2009 but continued after that date will not be subject to shallow rights reversion until they reach the end of their primary term and are continued (at which time deep rights reversion will be applied); thereafter, the holders of such agreements will be served with shallow rights reversion notices based on vintage and location similar to leases and licences that were already continued as of January 1, 2009.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil and the natural gas operations, including those of the Corporation. 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 Corporation 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 deterioration of global economic conditions, have caused significant volatility to commodity prices.
43
These conditions worsened in 2008 and continued in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating 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. Although economic conditions improved towards the latter portion of 2009 and in 2010, these factors have negatively impacted company valuations and will 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, OPEC actions and the ongoing global credit and liquidity concerns.
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 the Company’s revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the present global credit crisis exposes the Company to additional access to capital risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company’s business financial condition, results of operations and prospects.
Third Party Credit Risk
The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in the Company’s ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.
Critical Accounting Estimates
The reader is advised that the critical accounting estimates, policies, and practices as described herein continue to be critical in determining Bellatrix’s financial results.
The reader is cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. The following discussion outlines accounting policies and practices that are critical to determining Bellatrix’s financial results.
Reserves
The Company uses the full cost method of accounting for oil and gas properties. Generally, all costs of exploring and developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved reserves using forecast pricing.
44
Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. Estimated reserves are also utilized by Bellatrix’s bank in determining credit facilities. Reserves affect net income through depletion and the ceiling test calculation. 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. Changes in these judgments and estimates could have a material impact on the financial results and financial condition.
Asset retirement obligations
The discounted, expected future cost of statutory, contractual or legal obligations to retire long-lived assets are recorded as an Asset Retirement Obligation (“ARO”) liability with a corresponding increase to the carrying amount of the related asset. The recorded ARO liability increases over time to its future amount through accretion charges to earnings. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to the ARO liability. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset.
Share based compensation
Options granted under the Share Option Plan to employees and the Board of Directors is accounted for in accordance with the fair-value based method of accounting. Accordingly, the stock based compensation expense is measured at the grant date based on the fair value, using the Black-Scholes model, and is expensed over the vesting period of the options using the graded vesting method. Determination of the fair value of options granted at the grant date requires judgment, including the expected share price volatility. The Company calculates volatility based on historical share price excluding specific time frames in which volatility was affected by specific transactions that are not considered to be indicative of the Company’s normal share price volatility.
Fair value of derivatives
The fair value or mark-to-market value of commodity contracts is based on the estimated amount that would have been received or paid to settle the contracts as at December 31, 2010, and may be different from what will eventually be realized. Changes in the fair value of the commodity contracts are recognized in the Consolidated Statements of Loss within the financial statements. The actual gains and losses realized on eventual cash settlement can vary due to subsequent fluctuations in commodity prices.
Accounts receivable
The Company employs judgment to estimate the carrying value of accounts receivable. After making assessments of credit risk from customers and joint venture partners, the Company may provide for an allowance for doubtful accounts as required. Actual accounts receivable amounts collected in future periods may differ from these estimates.
Income taxes
In following the liability method of accounting for 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 future income tax liability calculated at a point in time. These differences could materially impact earnings.
45
Legal, Environmental Remediation and Other Contingent Matters
The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favor, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceeding related to these and other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position or results of operations.
The Company reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Company’s management monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances.
With the above risks and uncertainties the reader is cautioned that future events and results may vary substantially from that which Bellatrix currently foresees.
Controls and Procedures
Disclosure Controls and Procedures
The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company and have concluded that the Company’s disclosure controls and procedures are effective at the financial year end of the Company for the foregoing purposes.
Internal Control over Financial Reporting
The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting to provide reasonable assurance regarding the reliability of the Company’s financial reporting and the preparation of financial statements for external purposes in accordance with the Canadian GAAP. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s internal control over financial reporting at the financial year end of the Company and concluded that the Company’s internal control over financial reporting is effective, at the financial year end of the Company, for the foregoing purpose.
The Company is required to disclose herein any change in the Company’s internal control over financial reporting that occurred during the period beginning on October 1, 2010 and ended on December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. No material changes in the Company’s internal control over financial reporting were identified during such period, that has materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the
46
control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
Sensitivity Analysis
The table below shows sensitivities to funds flow from operations as a result of product price and operational changes. This is based on actual average prices received for the fourth quarter of 2010 and average production volumes of 10,002 boe/d during that period, as well as the same level of debt outstanding at December 31, 2010. Diluted weighted average shares are based upon the fourth quarter of 2010. These sensitivities are approximations only, and not necessarily valid under other significantly different production levels or product mixes. Commodity price risk management activities can significantly affect these sensitivities. Changes in any of these parameters will affect funds flow as shown in the table below:
| | Funds Flow from Operations(1) | | Funds Flow from Operations(1) | |
Sensitivity Analysis | | (annualized)
($000s) | | Per Diluted Share
($) | |
Change of US $1/bbl WTI | | 1,100 | | 0.01 | |
Change of $0.10/ mcf | | 1,000 | | 0.01 | |
Change of US $0.01 CDN/ US exchange rate | | 800 | | 0.01 | |
Change in prime of 1% | | 400 | | 0.00 | |
(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 Canadian GAAP as an indicator of the Company’s performance. Therefore reference to 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.
47
Selected Quarterly Consolidated Information
The following table sets forth selected consolidated financial information of the Company for the eight most recently completed quarters at the end of 2010.
2010 — Quarter ended
($000s, except per share amounts) | | March 31 | | June 30 | | Sept. 30 | | Dec. 31 | |
Revenues before royalties and risk management | | 26,929 | | 25,574 | | 27,344 | | 37,826 | |
Funds flow from operations(1) | | 10,198 | | 10,610 | | 16,342 | | 15,892 | |
Funds flow from operations per share(1) | | | | | | | | | |
Basic | | $ | 0.12 | | $ | 0.11 | | $ | 0.17 | | $ | 0.16 | |
Diluted | | $ | 0.11 | | $ | 0.11 | | $ | 0.17 | | $ | 0.15 | |
Cash flow from operating activities | | 13,456 | | 6,065 | | 13,466 | | 11,285 | |
Cash flow from operating activities per share | | | | | | | | | |
Basic | | $ | 0.15 | | $ | 0.07 | | $ | 0.14 | | $ | 0.12 | |
Diluted | | $ | 0.15 | | $ | 0.07 | | $ | 0.14 | | $ | 0.11 | |
Net income (loss) | | 7 | | (10,812 | ) | (8,555 | ) | (8,173 | ) |
Net income (loss) per share | | | | | | | | | |
Basic and Diluted | | $ | 0.00 | | $ | (0.12 | ) | $ | (0.09 | ) | $ | (0.08 | ) |
Net capital expenditures (cash) | | 18,393 | | 17,656 | | 30,416 | | 25,716 | |
2009 — Quarter ended
($000s, except per share amounts) | | March 31 | | June 30 | | Sept. 30 | | Dec. 31 | |
Revenues before royalties and risk management | | 31,345 | | 29,805 | | 23,860 | | 24,004 | |
Cash flow from operating activities | | 9,311 | | 6,467 | | 12,150 | | 2,743 | |
Cash flow from operating activities per share | | | | | | | | | |
Basic and Diluted | | $ | 0.12 | | $ | 0.08 | | $ | 0.15 | | $ | 0.03 | |
Funds flow from operations(1) | | 6,489 | | 10,765 | | 11,090 | | 7,681 | |
Funds flow from operations per share(1) | | | | | | | | | |
Basic and Diluted | | $ | 0.08 | | $ | 0.14 | | $ | 0.14 | | $ | 0.10 | |
Net loss | | (9,056 | ) | (99,715 | ) | (9,363 | ) | (8,216 | ) |
Net loss per share | | | | | | | | | |
Basic and Diluted | | $ | (0.12 | ) | $ | (1.27 | ) | $ | (0.12 | ) | $ | (0.10 | ) |
Net capital expenditures (cash) | | 2,764 | | (7,138 | ) | (81,986 | ) | 9,926 | |
Distributions declared | | 1,570 | | — | | — | | — | |
Distributions per share | | $ | 0.02 | | — | | — | | — | |
(1) Refer to “Non-GAAP Measures” in respect of the term “funds flow from operations” and “funds flow from operations per share”.
The quarterly results for 2010 compared to 2009 were impacted by Bellatrix’s increased capital program, improved pricing for crude oil, condensate and NGL’s, increased production efficiencies and lower total net debt levels.
The Company’s focus in 2010 was to continue to reduce total net debt levels, expand its capital program and continue to streamline its operations and field optimization projects. In 2009, Bellatrix was focused on reducing operating costs and general and administrative charges in light of the volatile economic environment. Capital spending for 2009 was kept to a minimum and the Company concentrated on field optimization projects in order to arrest decline and maintain production.
During the first quarter of 2010, the Company closed a $45 million equity offering, allowing debt to be temporarily reduced in order to fund its 2010 capital program. Total net debt levels decreased by $140.3 million, from the $213.9
48
million of total net debt at the end of the first quarter of 2011. The Company spent $18.3 million in capital expenditures in Q1 2010 compared to $2.8 million in the same period in 2009.
During the second quarter of 2010, Bellatrix issued the 4.75% Debentures in order to facilitate the redemption of its 7.5% Debentures. This allowed the Company to move forward with reduced total net debt levels at a reduced carrying cost. The Company invested $18.3 million in capital expenditures in the second quarter of 2010, compared to $1.2 million for the same period in 2009.
During the third quarter of 2010, Bellatrix issued $20 million of Flow-Through Shares, allowing the Company to further reduce debt levels in order to fund its capital program. In the third and fourth quarters of 2010, the Company continued to invest in its 2010 capital program in order to replace production of approximately 3,600 boe/d that was sold in the second half of 2009. Proceeds of approximately $92.9 million for the 2009 dispositions were used to reduce the Company’s indebtedness.
Overall, the Company’s increased and successful capital program, higher realized prices for crude oil, condensate and NGL’s, reduced production, G&A and interest and financing expenses, have resulted in the Company having increased cash flows, sales volumes and reserves for 2010, as compared to 2009.
49
Selected Annual Information
Years ended December 31,
($000s, except per share amounts) | | 2010 | | 2009 | | 2008 | |
Revenues before royalties and risk management | | 117,673 | | 109,014 | | 265,385 | |
Funds flow from operations(1) | | 53,042 | | 36,025 | | 77,893 | |
Funds flow from operations per share(1) | | | | | | | |
Basic | | $ | 0.57 | | $ | 0.46 | | $ | 0.99 | |
Diluted | | $ | 0.54 | | $ | 0.46 | | $ | 0.98 | |
Cash flow from operating activities | | | | | | | |
Cash flow from operating activities per share | | 44,272 | | 30,671 | | 78,784 | |
Basic | | $ | 0.47 | | $ | 0.39 | | $ | 1.00 | |
Diluted | | $ | 0.46 | | $ | 0.39 | | $ | 0.99 | |
Net loss | | (27,533 | ) | (126,620 | ) | (19,590 | ) |
Net loss per share | | | | | | | |
Basic | | $ | (0.30 | ) | $ | (1.61 | ) | $ | (0.25 | ) |
Diluted | | $ | (0.30 | ) | $ | (1.61 | ) | $ | (0.25 | ) |
Net capital expenditures (cash) | | (92,181 | ) | (76,434 | ) | (1,338 | ) |
Total assets | | 487,156 | | 440,970 | | 736,117 | |
Total net debt (1) (2) | | 87,444 | | 107,269 | | 215,004 | |
Long-term financial liabilities | | | | | | | |
Future income taxes | | — | | — | | 42,777 | |
Asset retirement obligations | | 27,483 | | 25,728 | | 33,682 | |
Exchangeable shares of subsidiary | | — | | — | | 2,887 | |
Sales volumes (boe/d) | | 8,519 | | 8,426 | | 11,867 | |
Distributions declared | | — | | 1,570 | | 36,334 | |
Distributions per share | | — | | $ | 0.02 | | $ | 0.46 | |
(1) Refer to “Non-GAAP Measures” in respect of the term “funds flow from operations,” “funds flow from operations per share,” “net debt” and “total net debt.”
(2) Net debt includes the net working capital deficiency before short-term commodity contract assets and liabilities, current capital lease obligation and short-term future income tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes capital lease obligations, asset retirement obligations and the future income tax liability.
The annual results for 2009 compared to 2008 were impacted by dispositions, fluctuating commodity prices, lower operating costs and reduced capital spending.
In 2008, average daily sales volumes were 11,867 boe/d compared to 8,426 boe/d in 2009. The reduction in average daily sales volumes was primarily a result of the disposition of two minor properties in the second quarter of 2009 and the majority of its Saskatchewan properties in the third quarter of 2009. The dispositions completed in 2009 reduced sales volumes by approximately 3,600 boe/d for the third and fourth quarters in 2009. Total proceeds of approximately $92.9 million, after purchase adjustments and closing costs, were used to reduce the Company’s indebtedness.
2008 revenues before royalties and risk management contracts decreased by approximately 59% when compared to the same period in 2009, primarily as a result of the dispositions discussed above and extreme volatile commodity prices experienced. WTI crude oil prices varied significantly in 2008, increasing to a high of US$147/bbl in July and dramatically falling during the fourth quarter of 2008 with December 2008 prices of under US$40/bbl. WTI crude oil prices averaged over US$60/bbl through 2009.
50
In 2009, the Company made an effort to reduce operating costs and general and administrative charges in light of the volatile economic environment. Capital spending was kept to a minimum and the Company concentrated on field optimization projects in order to arrest decline and maintain production. Bellatrix invested approximately $15.8 million in exploration and development in 2009 compared to $36.7 million in 2008.
As a result of the efforts made in 2009, Bellatrix was able to reduce total net debt by $107.7 million from the $215.0 million outstanding as at December 31, 2008.
51
BELLATRIX EXPLORATION LTD.
CONSOLIDATED BALANCE SHEETS
As at December 31
($000s) | | 2010 | | 2009 | |
ASSETS | | | | | |
Current assets | | | | | |
Accounts receivable | | $ | 39,500 | | $ | 20,722 | |
Deposits and prepaid expenses | | 4,619 | | 4,940 | |
Future income taxes (note 13) | | 989 | | — | |
Commodity contract asset (note 17) | | — | | 3,374 | |
| | 45,108 | | 29,036 | |
Property, plant and equipment (note 4) | | 433,697 | | 410,566 | |
Future income taxes (note 13) | | 8,351 | | 1,368 | |
Total assets | | $ | 487,156 | | $ | 440,970 | |
| | | | | |
LIABILITIES | | | | | |
Current liabilities | | | | | |
Accounts payable and accrued liabilities | | $ | 42,792 | | $ | 23,345 | |
Current portion of capital lease obligation (note 7) | | 146 | | — | |
Future income taxes (note 13) | | — | | 960 | |
Commodity contract liability (note 17) | | 3,732 | | — | |
| | 46,670 | | 24,305 | |
Long-term debt (note 5) | | 41,172 | | 27,902 | |
Convertible debentures (note 6) | | 47,599 | | 81,684 | |
Capital lease obligation (note 7) | | 1,443 | | — | |
Asset retirement obligations (note 8) | | 27,483 | | 25,728 | |
Total liabilities | | 164,367 | | 159,619 | |
| | | | | |
SHAREHOLDERS’ EQUITY | | | | | |
Shareholders’ capital (note 1 and 10) | | 315,510 | | 252,592 | |
Equity component of convertible debentures (note 6) | | 5,881 | | 5,037 | |
Contributed surplus (note 11) | | 30,526 | | 28,232 | |
Deficit (note 10) | | (29,128 | ) | (4,510 | ) |
Total shareholders’ equity | | 322,789 | | 281,351 | |
Total liabilities and shareholders’ equity | | $ | 487,156 | | $ | 440,970 | |
COMMITMENTS (note 16)
See accompanying notes to the consolidated financial statements.
52
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
For the years ended December 31
($000s) | | 2010 | | 2009 | |
| | | | | |
REVENUES | | | | | |
Petroleum and natural gas sales | | $ | 117,673 | | $ | 109,014 | |
Royalties | | (22,914 | ) | (17,554 | ) |
Gain (loss) on commodity contracts (note 17) | | 8,282 | | 17,394 | |
| | 103,041 | | 108,854 | |
| | | | | |
EXPENSES | | | | | |
Production | | 37,964 | | 45,015 | |
Transportation | | 3,723 | | 3,880 | |
General and administrative | | 9,414 | | 10,239 | |
Interest and financing charges | | 7,403 | | 13,657 | |
Share-based compensation (notes 10 and 11) | | 1,618 | | (159 | ) |
Depletion, depreciation and accretion | | 74,856 | | 90,760 | |
Provision for uncollectible accounts (note 17) | | 250 | | 1,400 | |
Loss on redemption of 7.5% Debentures (note 6) | | 3,514 | | — | |
Loss on repurchase of convertible debentures (note 6) | | — | | 51 | |
Loss on sale of marketable securities | | — | | 501 | |
Loss on sale of petroleum and natural gas properties (note 4) | | — | | 114,182 | |
Reorganization costs (note 1) | | — | | 885 | |
| | 138,742 | | 280,411 | |
| | | | | |
LOSS BEFORE TAXES | | (35,701 | ) | (171,557 | ) |
| | | | | |
TAXES | | | | | |
Future income tax recovery (note 13) | | (8,168 | ) | (44,448 | ) |
| | | | | |
NET LOSS BEFORE NON-CONTROLLING INTEREST | | (27,533 | ) | (127,109 | ) |
Non-controlling interest | | — | | (489 | ) |
| | | | | |
NET LOSS and COMPREHENSIVE LOSS | | $ | (27,533 | ) | $ | (126,620 | ) |
| | | | | |
Net loss per share | | | | | |
Basic | | $ | (0.30 | ) | $ | (1.61 | ) |
Diluted | | $ | (0.30 | ) | $ | (1.61 | ) |
See accompanying notes to the consolidated financial statements.
53
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
For the years ended December 31
($000s) | | 2010 | | 2009 | |
| | | | | |
SHAREHOLDERS’ CAPITAL | | | | | |
Trust units of True Energy Trust | | | | | |
Balance, beginning of year | | $ | — | | $ | 917,012 | |
Reduction in capital for deficit (note 1) | | — | | (666,818 | ) |
Exchanged for common shares of Bellatrix (note 1) | | — | | (250,194 | ) |
Balance, end of year | | — | | — | |
Common shares of Bellatrix Exploration Ltd. | | | | | |
Balance, beginning of year | | 252,592 | | — | |
Issued for cash, net of transaction costs | | 62,358 | | — | |
Issued on exercise of share options | | 434 | | — | |
Contributed surplus transferred on exercised options | | 126 | | | |
Issued on corporate reorganization (note 1) | | — | | 250,194 | |
Issued on conversion of exchangeable shares pursuant to reorganization (note 1) | | — | | 2,398 | |
Balance, end of year | | 315,510 | | 252,592 | |
| | 315,510 | | 252,592 | |
| | | | | |
EQUITY COMPONENT OF CONVERTIBLE DEBENTURES | | | | | |
Balance, beginning of year | | 5,037 | | 5,119 | |
Conversion feature of 7.5% Debentures redeemed (note 6) | | (5,037 | ) | — | |
Conversion feature of 4.75% Debentures issued (note 6) | | 5,881 | | — | |
Adjustment for repurchase of convertible debentures under normal course issuer bid (note 6) | | — | | (82 | ) |
Balance, end of year | | 5,881 | | 5,037 | |
| | | | | |
CONTRIBUTED SURPLUS | | | | | |
Balance, beginning of year | | 28,232 | | 28,240 | |
Share-based compensation expense (note 10 and 11) | | 2,452 | | 812 | |
Adjustment of prior period share-based compensation expense for forfeitures of unvested share options | | (32 | ) | (820 | ) |
Transfer to share capital for exercised options | | (126 | ) | — | |
Balance, end of year | | 30,526 | | 28,232 | |
| | | | | |
DEFICIT | | | | | |
Balance, beginning of year | | (4,510 | ) | (543,290 | ) |
Distributions declared | | — | | (1,570 | ) |
Reduction of deficit on Reorganization (note 1) | | — | | 666,818 | |
Adjustment for repurchase of convertible debentures | | — | | 152 | |
Adjustment for redemption of 7.5% Debentures (note 6) | | 2,915 | | — | |
Net loss | | (27,533 | ) | (126,620 | ) |
Balance, end of year | | (29,128 | ) | (4,510 | ) |
| | | | | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | | | | | |
Balance, beginning of year | | — | | (620 | ) |
Realized loss on sale of marketable securities | | — | | 620 | |
Balance, end of year | | — | | — | |
| | | | | |
TOTAL SHAREHOLDERS’ EQUITY | | $ | 322,789 | | $ | 281,351 | |
See accompanying notes to the consolidated financial statements.
54
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31
($000s) | | 2010 | | 2009 | |
| | | | | |
Cash provided by (used in): | | | | | |
CASH FLOW FROM OPERATING ACTIVITIES | | | | | |
Net loss | | $ | (27,533 | ) | $ | (126,620 | ) |
Items not involving cash: | | | | | |
Non-controlling interest (note 9) | | — | | (489 | ) |
Depletion, depreciation and accretion | | 74,856 | | 90,760 | |
Share-based compensation (notes 10 and 11) | | 1,618 | | (159 | ) |
Unrealized loss (gain) on commodity contracts (note 17) | | 7,106 | | 352 | |
Accretion on convertible debentures (note 6) | | 1,649 | | 1,895 | |
Future income tax recovery (note 13) | | (8,168 | ) | (44,448 | ) |
Loss on redemption of 7.5% Debentures (note 6) | | 3,514 | | — | |
Realization of imputed interest costs on 7.5% Debentures (note 6) | | (5,050 | ) | — | |
Loss on repurchase of convertible debentures (note 6) | | — | | 51 | |
Loss on sale of marketable securities | | — | | 501 | |
Loss on sale of petroleum and natural gas properties (note 4) | | — | | 114,182 | |
Asset retirement costs incurred (note 8) | | (1,373 | ) | (1,510 | ) |
Change in non-cash working capital (note 12) | | (2,347 | ) | (3,844 | ) |
| | 44,272 | | 30,671 | |
| | | | | |
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES | | | | | |
Increase (Decrease) in bank debt | | 13,270 | | (104,486 | ) |
Issuance of share capital, net of share issue costs (note 10) | | 61,318 | | — | |
Issuance of 4.75% Debentures, net of issue costs (note 6) | | 52,520 | | — | |
Redemption of 7.5% Debentures (note 6) | | (88,009 | ) | — | |
Realization of imputed interest costs on 7.5% Debentures allocated to operating activities (note 6) | | 5,050 | | — | |
Proceeds from exercise of options (note 10) | | 434 | | — | |
Obligations under capital lease (note 7) | | (11 | ) | | |
Repurchase of convertible debentures under normal course issuer bid | | — | | (1,315 | ) |
Distributions declared | | — | | (1,570 | ) |
| | 44,572 | | (107,371 | ) |
Change in non-cash working capital (note 12) | | 493 | | (1,584 | ) |
| | 45,065 | | (108,955 | ) |
| | | | | |
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES | | | | | |
Additions to property, plant and equipment | | (106,748 | ) | (16,487 | ) |
Proceeds on sale of property, plant and equipment | | 14,567 | | 92,921 | |
Proceeds on sale of marketable securities | | — | | 349 | |
| | (92,181 | ) | 76,783 | |
Change in non-cash working capital (note 12) | | 2,844 | | 1,501 | |
| | (89,337 | ) | 78,284 | |
| | | | | |
Change in cash | | — | | — | |
| | | | | |
Cash, beginning of year | | — | | — | |
| | | | | |
Cash, end of year | | $ | — | | $ | — | |
See accompanying notes to the consolidated financial statements.
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. CORPORATE STRUCTURE AND THE ARRANGEMENT
Bellatrix Exploration Ltd. (the “Company” or “Bellatrix”) is a growth oriented, public exploration and production company. The Company resulted from a reorganization (the “Reorganization) effective November 1, 2009 pursuant to a plan of arrangement (the “Arrangement”) involving, among others, True Energy Trust (the “Trust” or “True”), Bellatrix Exploration Ltd. and securityholders of the Trust.
Pursuant to the Reorganization, the Trust was restructured from an open-ended, unincorporated investment trust to Bellatrix Exploration Ltd., a publicly traded corporation. Unitholders of the Trust received an equal number of common shares of Bellatrix which holds the assets and liabilities previously held, directly or indirectly, by the Trust. Exchangeable shares of the Trust were exchanged for common shares of Bellatrix at the current exchange ratio in effect on the effective date. The outstanding 7.5% convertible debentures of the Trust were assumed by Bellatrix as a result of the Arrangement and were convertible into common shares of the Company, rather than trust units of the Trust, at a conversion price of $16.00 per share. All outstanding incentive unit rights to acquire Trust units of True became share options to acquire an equal number of common shares of Bellatrix Exploration Ltd. on the same terms and conditions, including as to exercise price, vesting and expiry dates.
Pursuant to the Arrangement, the Unitholders’ Capital of the Trust Units as of the effective date of November 1, 2009 was reduced by the amount of the deficit of the Trust on October 31, 2009 of $666.8 million.
The cost of the Reorganization of $885,000 was expensed during the year ended December 31, 2009.
The Reorganization has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for periods prior to the effective date of the Reorganization reflect the financial position, results of operations and cash flows as if the Company had always carried on the business formerly carried on by the Trust. Information herein with respect to Bellatrix includes information in respect of the Trust prior to completion of the Reorganization to the extent applicable unless the context otherwise requires. In addition, references to “common shares” and “shares”, “Share Option Plan”, and “options” should be read as references to “Units”, “Unit Rights Incentive Plan”, and “rights” respectively, for periods prior to November 1, 2009.
2. SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared by management in accordance with generally accepted accounting principles in Canada. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Amounts recorded for depreciation, depletion and amortization, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of natural gas, and crude oil reserves and future costs required to develop those reserves. Accounts receivable are recorded at the estimated recoverable amount which involves the estimates of uncollectable accounts. Share-based compensation involves the calculation of the option’s fair value which includes the estimate of the Company’s share price volatility. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. The consolidated financial statements have, in management’s opinion, been properly prepared using careful judgment and reasonable limits of materiality and within the framework of the significant policies summarized below.
56
a. Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its subsidiary. Any reference to the “Company” throughout these consolidated financial statements refers to the Company and its subsidiary. All inter-entity transactions have been eliminated.
b. Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title to the products transfers to the purchasers based on volumes delivered and contracted delivery points and prices.
c. Joint Interests
A significant portion of the Company’s exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company’s proportionate interest in such activities.
d. Petroleum and Natural Gas Properties
The Company follows the full cost method of accounting for petroleum and natural gas operations whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized. These costs include land acquisition costs, geological and geophysical expenses, the costs of drilling both productive and non-productive wells, directly related overhead and estimated abandonment costs. Proceeds from the disposal of properties are deducted from the full cost pool without recognition of a gain or loss unless such a sale would significantly alter the rate of depletion and depreciation.
e. Depletion and Depreciation
Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes before royalties in relation to total estimated proved reserves as determined annually by independent engineers and determined in accordance with National Instrument 51-101. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.
Calculations for depletion and depreciation of production equipment are based on total capitalized costs plus estimated future development costs of proved undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved reserves are fully produced. The costs of acquiring and evaluating unproved properties are excluded from depletion calculations. These properties are assessed periodically to ascertain whether impairment has occurred. When the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.
Depreciation of office furniture and equipment is provided for on a 20% declining balance basis.
f. Ceiling Test
The Company applies a two-stage ceiling test on the aggregate carrying value of its capitalized costs, which may be amortized against revenues of future periods. The first stage of this process is to ensure that such costs do not exceed the undiscounted future cash flows from production of proved reserves. Undiscounted future cash flows are calculated based on management’s best estimate of forward indexed prices applied to estimated future production of proved reserves plus the carrying cost of undeveloped properties, less estimated future operating costs, royalties, future development costs and abandonment costs. When the carrying amount of a cost centre is not recoverable, the second stage of the process will determine the impairment whereby the cost centre would be written down to its fair value. The second stage requires the calculation of discounted future cash flows from proved plus probable reserves plus the carrying cost of
57
undeveloped properties net of any impairment allowance. The fair value of proved and probable reserves is estimated using accepted present value techniques, which incorporate risks and other uncertainties when determining expected cash flows.
The cost of undeveloped properties is excluded from the impairment test described above and subject to a separate impairment test.
g. Asset Retirement Obligations
The Company records a provision for the future retirement obligations associated with the Company’s property, plant, and equipment. The fair value of the asset retirement obligation is based on discounted cash flow methodology. This amount is also capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the Company settles the obligation.
h. Flow-through Shares
Resource expenditures for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. The tax effect related to renounced expenditures is recorded as a reduction of share capital and increase in future income tax liabilities on the date that the Company files the renouncement documents with the tax authorities.
i. Environmental Liabilities
The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Any amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.
j. Share-based Compensation Plan
The Company accounts for Share Option Plan issued to employees and the Board of Directors using the fair value method. The fair value of each share option is estimated on the date of the grant using the Black-Scholes options pricing model and charged to earnings over the vesting period with a corresponding increase to contributed surplus.
k. Obligations under Lease
Leases which effectively transfer substantially all of the risks and rewards of ownership to the Company are classified as capital leases and are accounted for as an acquisition of an asset and an assumption of an obligation at the inception of the lease, measured as the present value of minimum lease payments to a maximum of the asset’s fair value. The asset is amortized in accordance with the Company’s depletion and depreciation policy. The obligations recorded under capital lease payments are reduced by the lease payments made.
l. Income Taxes
Income taxes are recorded using the liability method of tax allocation. Future income tax assets and liabilities are determined based on “temporary differences” and are measured using the current, or substantively enacted, tax rates and laws expected to apply when these differences reverse. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized.
58
m. Financial Instruments
All financial instruments, including all derivatives, are recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in income. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to income when derecognized or impaired. The Company has the following classifications:
Financial Assets and Liabilities | | Category |
Accounts receivable | | Loans and receivables |
Marketable securities | | Available-for-sale |
Commodity risk management contracts | | Held-for-trading |
Accounts payable and accrued liabilities | | Other liabilities |
Long-term debt | | Other liabilities |
Convertible debentures | | Other liabilities |
Capital lease obligation | | Other liabilities |
Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument.
The Company utilizes financial derivatives and non-financial derivatives, such as commodity sales contracts requiring physical delivery, to manage the price risk attributable to anticipated sale of petroleum and natural gas production and foreign exchange exposures. The Company does not enter into derivative financial instruments for trading or speculative purposes.
The derivative financial instruments are initiated within the guidelines of the Company’s commodity price risk management policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.
The Company accounts for its commodity sales and purchase contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as derivatives. As such, physical sales and purchase contracts are not recorded at fair value on the balance sheet with changes in fair value included in earnings.
Subsequent changes in fair value of derivatives that are not designated or do not qualify for hedge accounting or normal purchase, sale or usage contracts are recognized in net income as incurred. For derivatives that are designated and qualify for cash flow hedge accounting at inception or the date of adoption, the effective portion of the change in fair value is recognized in other comprehensive income as incurred with the remaining portion of the change in fair value recognized in net income as incurred in the same financial statement caption as the hedged transaction. Net derivative gains (losses) in accumulated other comprehensive income are reclassified to net income in the same financial statement caption and future periods as the hedged transactions affect net income.
Financial instruments measured at fair value on the balance sheet require classification into one of the following levels of the fair value hierarchy:
59
Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities
Level 2 — Inputs other than quoted prices included in level 1 that are observable for the asset or liability, either directly or indirectly.
Level 3 — inputs for the asset or liability that are not based on observable market data.
The fair value hierarchy level at which a fair value measurement is categorized is determined on the basis of the lowest level input that is significant to the fair value measurement in its entirety. The Company has categorized its financial instruments that are fair valued on the balance sheet according to the fair value hierarchy (note 17).
n. Basic and Diluted per Share Calculations
Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. The Company uses the treasury stock method to determine the dilutive effect of share options. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted per share amounts. The Company uses the “if-converted” method to determine the dilutive effect of convertible debentures.
o. Cash and cash equivalents
Cash and cash equivalents include cash and short-term investments with original maturities of three months or less.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
International Financial Reporting Standards (“IFRS”)
On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”), which will replace Canadian generally accepted accounting principles for years beginning on or after January 1, 2011. The Company’s first IFRS compliant financial statements will be for the three months ended March 31, 2011.
4. PROPERTY, PLANT AND EQUIPMENT
($000s) | | Cost | | Accumulated
depletion and
depreciation | | Net book value | |
December 31, 2010 | | | | | | | | | | |
Petroleum and natural gas properties | | $ | 1,045,239 | | $ | 613,408 | | $ | 431,831 | |
Office furniture and equipment | | 4,531 | | 2,665 | | 1,866 | |
| | $ | 1,049,770 | | $ | 616,073 | | $ | 433,697 | |
| | | | | | | |
December 31, 2009 | | | | | | | |
Petroleum and natural gas properties | | $ | 949,892 | | $ | 541,075 | | $ | 408,817 | |
Office furniture and equipment | | 4,045 | | 2,296 | | 1,749 | |
| | $ | 953,937 | | $ | 543,371 | | $ | 410,566 | |
Bellatrix has included $157.9 million (2009: $57.2 million) for future development costs and excluded $18.5 million (2009: $20.5 million) for undeveloped land and $32.6 million (2009: $27.8 million) for estimated salvage from the depletion calculation during the year ended December 31, 2010.
60
For the year ended December 31, 2010, the Company capitalized $1.9 million (2009: $0.6 million) of general and administrative expenses and $1.1 million (2098: $0.2 million), including the future tax effect thereon of $0.3 million (2009: $0.1 million), of share-based compensation expense directly related to exploration and development activities.
The Company performed a ceiling test calculation as at December 31, 2010 resulting in undiscounted cash flows from proved reserves and the undeveloped properties exceeding the carrying value of oil and gas assets. No impairment in oil and gas assets was identified as at December 31, 2010 and 2009.
The prices used in the ceiling test evaluation of the Company’s crude oil and natural gas reserves at December 31, 2010 were based on the following benchmark price forecasts adjusted for quality and transportation differentials:
| | Hardisty Heavy
Crude Oil | | Edmonton Light
Sweet Crude Oil | | AECO Natural
Gas | |
Year | | ($/bbl) | | ($/bbl) | | ($/mmbtu) | |
2011 | | 69.98 | | 87.83 | | 4.15 | |
2012 | | 70.70 | | 90.51 | | 4.77 | |
2013 | | 69.50 | | 92.05 | | 5.23 | |
2014 | | 69.91 | | 93.77 | | 6.08 | |
2015 | | 71.80 | | 96.28 | | 6.42 | |
2016 | | 73.56 | | 98.63 | | 6.69 | |
2017 | | 75.11 | | 100.71 | | 6.92 | |
2018 | | 76.61 | | 102.71 | | 7.11 | |
2019 | | 78.21 | | 104.83 | | 7.27 | |
2020 | | 79.66 | | 106.79 | | 7.41 | |
2021 | | 81.11 | | 108.73 | | 7.52 | |
2022 | | 82.61 | | 110.76 | | 7.68 | |
2023 | | 84.13 | | 112.77 | | 7.81 | |
2024 | | 85.67 | | 114.84 | | 7.97 | |
2025 | | 87.25 | | 117.00 | | 8.09 | |
Percentage increase each year after 2025 | | 1.8% | | 1.8% | | 1.8% | |
Loss on Petroleum and Natural Gas Properties Sold
On July 30, 2009, the Company closed a divestiture for the majority of its petroleum and natural gas properties in Saskatchewan (the “Saskatchewan Divestiture”) for net proceeds of approximately $85 million, net of closing adjustments and closing costs. These petroleum and natural gas properties were classified as held for sale on June 30, 2009.
The disposition was accounted for in accordance with Accounting Guideline 16 — “Oil and Gas Accounting — Full Cost”. Under full cost accounting, if crediting the proceeds from disposition to costs results in a change of 20 percent or more to the depletion rate then a gain or loss on disposition should be recognized. When a gain or loss is to be recognized the total net book value of capitalized costs should be allocated between the properties sold and the properties retained. The carrying amount of the assets sold was an allocation of the Company’s historical full cost pool based on a pro-rata ratio of future cash flows of proved reserves associated with the assets sold, discounted at 10%, as compared to all oil and gas assets on June 30, 2009. In the second quarter of 2009, the Company recorded a $114.2 million loss on the assets sold for the excess of the allocated net book
61
value of the assets, compared to the total net proceeds, after purchase adjustments and closing costs, of approximately $85 million.
5. LONG-TERM DEBT
($000s) | | 2010 | | 2009 | |
| | | | | |
Operating facility | | $ | 6,172 | | $ | 2,656 | |
Revolving term facility | | 35,000 | | 25,246 | |
Balance, end of year | | $ | 41,172 | | $ | 27,902 | |
Effective December 15, 2010, the Company’s borrowing base was increased from $85 million to $100 million. The Company’s expanded facilities consists of a $15 million demand operating facility provided by a Canadian bank and an $85 million extendible revolving term credit facility provided by a Canadian bank and a Canadian financial institution. Amounts borrowed under the credit facility will bear interest at a floating rate based on the applicable Canadian prime rate, U.S. base rate or LIBOR rate, plus between 1.25% and 4.25%, depending on the type of borrowing and the Company’s debt to cash ratio. The credit facilities are secured by a $400 million debenture containing a first ranking charge and security interest. Bellatrix has provided a negative pledge and undertaking to provide fixed charges over major petroleum and natural gas reserves in certain circumstances. A standby fee is charged of between 0.55% and 1.02% on the undrawn portion of the credit facilities, depending on the Company’s debt to cash flow ratio.
On June 8, 2010, Bellatrix executed an amending agreement with its banking syndicate that provided for the extension of the revolving period of existing credit facility from June 29, 2010 to June 28, 2011. 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 28, 2011. The Company’s borrowing base will be subject to re-determination on May 30, 2011. Thereafter, a semi-annual re-determination of the borrowing base will occur, with the next such re-determination occurring on November 30, 2011.
Payment will not be required under the revolving term facility for more than 365 days from December 31, 2010 and as there is sufficient availability under the revolving term credit facility to cover the operating facility, the entire amounts owing on the credit facilities have been classified as long-term.
Pursuant to Bellatrix’s credit facilities, the Company is permitted to pay the semi-annual interest payments on the Debentures, and payments by the Company to debenture holders in relation to the redemption of Debentures and in relation to debenture normal course issuer bids approved by the Toronto Stock Exchange, provided that the aggregate of all such normal course issuer bids and redemptions do not exceed $10.0 million in any fiscal year.
As at December 31, 2010, approximately $58.8 million was not drawn under the existing facilities and Bellatrix was fully compliant with all of its operating debt covenants.
62
6. CONVERTIBLE DEBENTURES
The following table sets forth a reconciliation of the convertible debentures:
($000s except number of debentures) | | 7.5% | | 4.75% | | Total | |
Number of Debentures | | | | | | | |
Balance, December 31, 2009 | | 84,884 | | — | | 84,884 | |
Issued | | — | | 55,000 | | 55,000 | |
Redeemed | | (84,884 | ) | — | | (84,884 | ) |
Balance, December 31, 2010 | | — | | 55,000 | | 55,000 | |
Debt Component | | | | | | | |
Balance, December 31, 2009 | | $ | 81,684 | | $ | — | | $ | 81,684 | |
Issued | | — | | 48,841 | | 48,841 | |
Issue costs | | — | | (2,202 | ) | (2,202 | ) |
Accretion | | 689 | | 960 | | 1,649 | |
Redeemed | | (82,373 | ) | — | | (82,373 | ) |
Balance, December 31, 2010 | | $ | — | | $ | 47,599 | | $ | 47,599 | |
Equity Component | | | | | | | |
Balance, December 31, 2009 | | $ | 5,037 | | — | | $ | 5,037 | |
Issued | | — | | 6,159 | | 6,159 | |
Issue costs | | — | | (278 | ) | (278 | ) |
Redeemed | | (5,037 | ) | — | | (5,037 | ) |
Balance, December 31, 2010 | | $ | — | | $ | 5,881 | | $ | 5,881 | |
On April 20, 2010, Bellatrix issued $55 million of convertible unsecured subordinated debentures (the “4.75% Debentures”) on a bought deal basis. The 4.75% Debentures have a face value of $1,000 each, bear interest at the rate of 4.75% per annum payable semi-annually in arrears on the last day of April and October of each year commencing on October 31, 2010 and mature on April 30, 2015 (the “Maturity Date”). The 4.75% Debentures are convertible at the holder’s option and at any time prior to the close of business on the earlier of the close of business on the business day immediately preceding the Maturity Date and the date specified by the Corporation for redemption of the 4.75% Debentures into common shares of the Corporation at a conversion price of $5.60 per common share (the “Conversion Price”), subject to adjustment in certain events. The 4.75% Debentures are not redeemable by the Corporation before April 30, 2013. On and after April 13, 2013 and prior to April 30, 2014, the 4.75% Debentures are redeemable at the Corporation’s option, in whole or in part, at par plus accrued and unpaid interest if the weighted average trading price of the common shares for the specified period is not less than 125% of the Conversion Price. On and after April 30, 2014, the 4.75% Debentures are redeemable at the Corporation’s option, in whole or in part, at any time at par plus accrued and unpaid interest. The 4.75% Debentures are listed and posted for trading on the TSX under the symbol “BXE.DB.A”.
As the 4.75% Debentures are convertible into common shares, the liability and equity components are presented separately. The initial carrying amount of the financial liability is determined by discounting the stream of future payments of interest and principal and has been determined to be $48.8 million. Using the residual method, the carrying amount of the conversion feature is the difference between the principal amount and the carrying value of the financial liability. Within the Shareholder’s Equity section of the consolidated financial statements, $5.9 million has been recorded as the carrying amount of the conversion feature of the debentures, net of $0.3 million of issue costs. The 4.75% Debentures, net of the equity component and issue costs, of $46.6 million, is accreted using the effective interest rate method over the term of the 4.75% Debentures such that the carrying amount of the financial liability will equal the principal balance at maturity.
63
On April 20, 2010, Bellatrix deposited with Computershare Trust Company of Canada, the trustee (the “Trustee”) for Bellatrix’s previously outstanding series of debentures, being the 7.5% convertible unsecured subordinated debentures due June 30, 2011 (the “7.5% Debentures”), sufficient funds to satisfy the principal amount and interest owing on the 7.5% Debentures and on May 3, 2010 the trustee provided notice to the registered holders of the 7.5% Debentures of its intention to redeem the 7.5% Debentures on July 2, 2010. The 7.5% Debentures were redeemed for an amount of $1,025 for each $1,000 principal amount of the 7.5% Debentures plus accrued and unpaid interest, or a total of $88.0 million. Proceeds from the issuance of the 4.75% Debentures have been used by Bellatrix to partially fund the redemption of the 7.5% Debentures and the balance of the redemption amount has been funded through bank indebtedness. The funds deposited with the Trustee on April 20, 2010 and acknowledgment by the Trustee thereof discharged and extinguished the Company’s financial liability for the 7.5% Debentures as of that date.
The Company recorded a $3.6 million loss and a reduction of the deficit of $2.9 million in connection with the redemption of the 7.5% Debentures.
7. CAPITAL LEASE OBLIGATION
Bellatrix entered into an agreement with a certain joint venture (“Joint Venture”) for the use of certain facilities which will expire in year 2030 or earlier if certain circumstances are met. At the end of the term of the agreement, ownership of the facilities is transferred to the Company. The agreement is accounted for as a capital lease in accordance with CICA Handbook Section 3065 — “Leases”. Assets under capital lease at December 31, 2010 totaled $1.6 million with accumulated depreciation of $0.06 million.
The following is a schedule of future minimum lease payments under the capital lease obligation:
Year ending December 31, | | ($000s) | |
2011 | | $ | 379 | |
2012 | | 363 | |
2013 | | 347 | |
2014 | | 331 | |
2015 | | 313 | |
Thereafter | | 1,516 | |
Total lease payments | | 3,249 | |
Amount representing implicit interest at 15.28% | | (1,660 | ) |
| | 1,589 | |
Current portion of capital lease obligation | | (146 | ) |
Capital lease obligation | | $ | 1,443 | |
8. ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $63 million which will be incurred between 2014 and 2054. A credit-adjusted risk-free rate of 8 percent and an inflation rate of 2.4 percent were used to calculate the fair value of the asset retirement obligation.
64
($000s) | | 2010 | | 2009 | |
Balance, beginning of year | | $ | 25,728 | | $ | 33,682 | |
Acquired through asset acquisitions | | 223 | | — | |
Incurred on development activities | | 1,418 | | 584 | |
Changes in prior period estimates | | 1,972 | | 1,652 | |
Reversed on dispositions | | (2,638 | ) | (10,999 | ) |
Settled during the year | | (1,373 | ) | (1,510 | ) |
Accretion expense | | 2,153 | | 2,319 | |
Balance, end of year | | $ | 27,483 | | $ | 25,728 | |
9. EXCHANGEABLE SHARES OF SUBSIDIARY / NON-CONTROLLING INTEREST
As a result of the 2005 conversion to a Trust, 843,304 exchangeable shares were issued by a subsidiary of the Trust. An unlimited number of exchangeable shares were authorized, issuable in series of which the first series in an unlimited number was designated for Series A exchangeable shares.
The Series A exchangeable shares were non-voting (but holders were entitled to equivalent voting rights in the Trust) and could have been converted, at the option of the holder into trust units at any time. The number of trust units issued upon conversion was based on the exchange ratio in effect on the date of conversion. The exchange ratio was calculated monthly based on the five day weighted average trust unit trading price preceding the monthly effective date. The exchangeable shares were not eligible for cash distributions; however cash distributions increased the exchange ratio.
Pursuant to the Reorganization, effective November 1, 2009, the issued and outstanding exchangeable shares were exchanged for common shares of Bellatrix based upon the exchange ratio in effect immediately prior to the effective time of the Arrangement.
The following table summarizes the information regarding the exchangeable shares for the year ended December 31, 2009:
| | December 31, 2009 | |
| | Number | | Amount
($000s) | |
Balance, beginning of year | | 294,026 | | $ | 2,887 | |
Non-controlling interest recovery | | — | | (489 | ) |
Cancelled | | (8 | ) | — | |
Converted pursuant to Reorganization | | (294,018 | ) | (2,398 | ) |
Balance, end of year | | — | | $ | — | |
10. SHAREHOLDERS’ EQUITY
a. Common Shares
Bellatrix is authorized to issue an unlimited number of common shares.
65
| | 2010 | | 2009 | |
| | Number | | Amount
($000s) | | Number | | Amount
($000s) | |
Balance, beginning of year | | 78,809,039 | | $ | 252,592 | | — | | $ | — | |
Shares issued for cash, net of transaction costs and tax effect of $1.1 million | | 18,350,000 | | 62,358 | | | | | |
Shares issued on exercise of options | | 286,987 | | 434 | | | | | |
Contributed surplus transferred on exercised options | | — | | 126 | | | | | |
Issued pursuant to Reorganization | | — | | — | | 78,496,581 | | 250,194 | |
Issued on conversion of exchangeable shares pursuant to Reorganization (note 1) | | — | | — | | 312,458 | | 2,398 | |
Balance, end of year | | 97,466,026 | | $ | 315,510 | | 78,809,039 | | $ | 252,592 | |
On January 28, 2010, Bellatrix closed a bought deal equity financing whereby 13,640,000 common shares were issued for gross proceeds of $45.0 million (net proceeds of $42.4 million after transaction costs and before tax effect). The net proceeds of the issuance were used to temporarily reduce outstanding indebtedness.
On August 12, 2010, Bellatrix issued 4,710,000 common shares on a flow-through basis (“Flow-Through Shares”) at $4.25 each for gross proceeds of $20.0 million (net proceeds of $18.9 after transaction costs and before tax effect). The net proceeds from the issuance of the Flow-Through Shares were used to accelerate the Company’s Cardium light oil exploration program. The Company will incur eligible Canadian exploration expenses (“CEE”) that will be renounced to subscribers effective December 31, 2010. Bellatrix is committed to incur the $20.0 million CEE expenditures on or before December 31, 2011.
b. Trust Units
The Trust Indenture provided for an unlimited number of trust units to be authorized and issued. Each trust unit was transferable, carried the right to one vote and represented an equal undivided beneficial interest in any distributions from the Trust and in the net assets of the Trust in the event of termination or winding-up of the Trust. All trust units were of the same class with equal rights and privileges. Trust units were redeemable at any time at the lesser of 90% of the market price (as determined in accordance with the Trust Indenture) and the closing price of the trust units on the date tendered for redemption to a maximum, unless waived, of $250,000 per calendar month in which case the redemption price was payable by distributing notes of the Trust’s subsidiary or notes of the Trust.
The Reorganization from the Trust to the Company, effective November 1, 2009, followed securityholder and regulatory approval pursuant to a Special Meeting.
In connection with the Reorganization, the unitholders’ capital was reduced by the deficit of the Trust as of October 31, 2009 of $666.8 million and trust units were exchanged for common shares of Bellatrix.
| | 2009 | |
| | Number | | Amount
($000s) | |
Balance, beginning of year | | 78,496,581 | | $ | 917,012 | |
Repurchased under normal course issuer bid | | — | | — | |
Exchangeable shares converted | | — | | — | |
Reduction in capital for deficit amount | | — | | (666,818 | ) |
Exchanged for Bellatrix common shares | | (78,496,581 | ) | (250,194 | ) |
Balance, end of year | | — | | $ | — | |
66
c. Share Option Plan
In connection with the Arrangement, Bellatrix assumed all of the obligations of the Trust in respect of outstanding incentive rights. The Arrangement did not result in the acceleration of vesting of any outstanding incentive rights. Incentive rightsholders surrendered the incentive rights held by them in exchange for the same number of share options of Bellatrix, having the same terms as the incentive rights so held as to exercise price, vesting and expiry dates.
Upon approval of the Arrangement effective November 1, 2009, Bellatrix has a Share Option Plan where the Company may grant share options to its directors, officers, employees and service providers. Under this plan, the exercise price of each share option is not less than the volume weighted average trading price of the Company’s share price for the five trading days immediately preceding the date of grant. The maximum term of an option grant is five years. Option grants are non-transferable or assignable except in accordance with the Share Option Plan and the holding of share options shall not entitle a holder to any rights as a shareholder of Bellatrix. Share options, entitling the holder to purchase common shares of the Company, have been granted to directors, officers, employees and service providers of Bellatrix. One third of the initial grant of share options normally vests on each of the first, second, and third anniversary from the date of grant.
Under the terms of the Trust’s Incentive Plan, the exercise price of each incentive right was initially equal to the per trust unit closing price on the trading day immediately preceding the date of grant, unless otherwise determined, and thereafter was reduced pursuant to a formula. The formula provided that the exercise price of each incentive right was reduced by any decreases in the daily closing price on the Toronto Stock Exchange of the Trust Units, provided, however, that such decreases in the exercise price did not exceed the amount of Trust unit distributions.
As of December 31, 2010, a total of 9,720,186 share options were reserved, leaving an additional 3,896,809 available for future grants.
The following tables summarize information regarding Bellatrix’s Share Option Plan:
Share Options Continuity(a)
| | Weighted Average
Exercise Price(b) | | Number | |
Balance, December 31, 2008 | | $ | 3.97 | | 2,700,500 | |
Granted | | $ | 1.44 | | 3,295,800 | |
Forfeited and cancelled | | $ | 4.05 | | (1,782,567 | ) |
Balance, December 31, 2009 | | $ | 2.01 | | 4,213,733 | |
Granted | | $ | 3.65 | | 2,178,500 | |
Exercised | | $ | 1.51 | | (286,987 | ) |
Forfeited and cancelled | | $ | 2.77 | | (281,869 | ) |
Balance, December 31, 2010 | | $ | 2.69 | | 5,823,377 | |
(a) As a result of the Reorganization, the existing 4,067,733 incentive unit rights as of November 1, 2009, were exchanged for an equal number of common share options of Bellatrix with the same terms as to exercise price, vesting and expiry dates.
(b) Exercise prices prior to the November 1, 2009 Reorganization reflect grant prices less reduction in exercise prices for rights issued under the Trust unit incentive plan.
67
Share Options Outstanding, December 31, 2010
| | Outstanding | | Weighted | | Exercisable | |
| | | | Weighted | | Average | | | | | |
| | At | | Average | | Remaining | | At | | | |
Exercise Price | | Dec. 31, 2010 | | Exercise Price | | Contractual Life | | Dec. 31, 2010 | | Exercise Price | |
$ 0.65 - $ 0.83 | | 339,575 | | $ | 0.69 | | 3.3 | | 104,856 | | $ | 0.69 | |
$ 1.07 - $ 1.50 | | 886,014 | | $ | 1.36 | | 3.3 | | 280,635 | | $ | 1.37 | |
$ 1.64 - $ 2.00 | | 1,735,120 | | $ | 1.88 | | 3.3 | | 660,074 | | $ | 1.85 | |
$ 2.47 - $ 3.94 | | 2,406,668 | | $ | 3.64 | | 3.9 | | 365,334 | | $ | 2.52 | |
$ 3.98 - $ 5.57 | | 456,000 | | $ | 4.88 | | 1.8 | | 396,500 | | $ | 4.96 | |
$ 0.65 - $ 5.57 | | 5,823,377 | | $ | 2.69 | | 3.5 | | 1,807,399 | | $ | 2.53 | |
Share Options Outstanding, December 31, 2009
| | Outstanding | | Weighted | | Exercisable | |
| | At | | Weighted
Average | | Average
Remaining | | At | | | |
Exercise Price | | Dec. 31, 2009 | | Exercise Price | | Contractual Life | | Dec. 31, 2009 | | Exercise Price | |
$ 0.65 - $ 0.83 | | 459,641 | | $ | 0.68 | | 4.3 | | — | | — | |
$ 1.07 - $ 1.50 | | 1,015,631 | | $ | 1.35 | | 4.3 | | — | | — | |
$ 1.64 - $ 2.00 | | 1,847,628 | | $ | 1.88 | | 4.3 | | 85,000 | | $ | 1.70 | |
$ 2.47 - $ 3.94 | | 445,833 | | $ | 2.55 | | 3.0 | | 274,823 | | $ | 2.52 | |
$ 3.98 - $ 5.57 | | 445,000 | | $ | 4.90 | | 2.5 | | 284,156 | | $ | 4.93 | |
$ 0.65 - $ 5.57 | | 4,213,733 | | $ | 2.01 | | 4.0 | | 643,979 | | $ | 3.47 | |
d. Employee Stock Savings Plan
Effective October 1, 2006, the Company introduced an employee unit savings plan for the benefit of all employees. Effective November 1, 2009, with the Reorganization, the employee unit savings plan continued as the employee stock savings plan. Under the stock savings plan, employees may elect to contribute up to 10 percent of their salary and contributions are used to fund the acquisition of common shares. The Company matches employee contributions at a rate of $1.00 for each $1.00 contributed up to 5% of the employees’ salary. Shares are purchased in the open market by the plan administrator, an investment firm, on behalf of the participants in the plan. For the year ended December 31, 2010, the Company matched $0.2 million (2009 - $0.1 million) under the plan.
11. CONTRIBUTED SURPLUS
($000s) | | 2010 | | 2009 | |
Balance, beginning of year | | $ | 28,232 | | $ | 28,240 | |
Share-based compensation expense | | 2,452 | | 812 | |
Adjustment of prior period share-based compensation expense for forfeitures of unvested share options | | (32 | ) | (820 | ) |
Transfer to share capital for exercised options | | (126 | ) | — | |
Balance, end of year | | $ | 30,526 | | $ | 28,232 | |
Share-based Compensation Expense
During the year ended December 31, 2010, Bellatrix granted 2,178,500 (2009: 3,295,800) share options. During the year ended December 31, 2010, the Company recorded share-based compensation of $2.5 million (2009: $0.8 million), of which $0.8 million (2009: $0.2 million) was capitalized to property, plant and equipment.
68
The fair values of all share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of share options granted during the years ended December 31, 2010 and 2009 and the assumptions used in their determination are as noted below:
| | 2010 | | 2009 | |
Assumptions: | | | | | |
Risk free interest rate (%) | | 1-3 | | 2-3 | |
Expected life (years) | | 3-5 | | 5 | |
Expected volatility (%) | | 68-75 | | 69-104 | |
Results: | | | | | |
Weighted average fair value of each share option granted | | $ | 1.99 | | $ | 0.31 | |
| | | | | | | |
12. SUPPLEMENTAL CASH FLOW INFORMATION
Cash Interest and Taxes Paid
($000s) | | 2010 | | 2009 | |
| | | | | |
Cash paid: | | | | | |
Interest | | $ | 4,675 | | $ | 10,104 | |
Taxes (net of refunds) | | $ | — | | $ | (272 | ) |
Change in Non-cash Working Capital
($000s) | | 2010 | | 2009 | |
Changes in non-cash working capital items: | | | | | |
Accounts receivable | | $ | (18,778 | ) | $ | 7,397 | |
Deposits and prepaid expenses | | 321 | | 1,029 | |
Accounts payable and accrued liabilities | | 19,447 | | (10,783 | ) |
Distributions payable | | — | | (1,570 | ) |
| | $ | 990 | | $ | (3,927 | ) |
Changes related to: | | | | | |
Operating activities | | $ | (2,347 | ) | $ | (3,844 | ) |
Financing activities | | 493 | | (1,584 | ) |
Investing activities | | 2,844 | | 1,501 | |
| | $ | 990 | | $ | (3,927 | ) |
13. INCOME TAXES
Bellatrix is a corporation as defined under the Income Tax Act (Canada) and is subject to Canadian federal and provincial taxes. Bellatrix is subject to provincial taxes in Alberta, British Columbia and Saskatchewan as the Company operates in those jurisdictions.
True was a mutual fund trust as defined under the Income Tax Act (Canada). All taxable income earned by the Trust prior to the Reorganization was allocated to unitholders and such allocations were deducted for income tax purposes.
Future income taxes reflect the tax effects of differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts reported for tax purposes. As at December 31, 2010, Bellatrix has approximately $449 million in tax pools available for deduction against future income. Included in this tax basis are estimated non-capital loss carry forwards of approximately $0.3 million that expire in years through 2027.
69
The provision for income taxes differs from the expected amount calculated by applying the combined Federal and Provincial corporate income tax rate of 28.05% (2009: 29.39%) to loss before taxes. This difference results from the following items:
Years ended December 31 ($000s) | | 2010 | | 2009 | |
Expected income tax recovery | | $ | (10,014 | ) | $ | (50,421 | ) |
Distributions deducted for tax purposes | | — | | (575 | ) |
Share based compensation expense | | 454 | | (47 | ) |
Change in tax rates | | 1,240 | | 6,746 | |
Other | | 152 | | (151 | ) |
Future income tax recovery | | $ | (8,168 | ) | $ | (44,448 | ) |
The components of the net future income tax asset at December 31 are as follows:
($000s) | | 2010 | | 2009 | |
Future income tax liabilities: | | | | | |
Petroleum and natural gas properties | | $ | (1,021 | ) | $ | (10,306 | ) |
Commodity contract asset | | — | | (958 | ) |
Future income tax assets: | | | | | |
Future site restoration/asset retirement obligation | | 6,907 | | 6,652 | |
Share issue costs | | 753 | | 58 | |
Capital lease | | 399 | | — | |
Commodity contract liability | | 989 | | — | |
Non-capital losses | | 79 | | 3,728 | |
Attributed Canadian Royalty Income | | 1,209 | | 1,209 | |
Other | | 25 | | 25 | |
Net future income tax asset | | $ | 9,340 | | $ | 408 | |
14. PER SHARE AMOUNTS
| | 2010 | | 2009 | |
Basic common shares outstanding, as at December 31 | | 97,446,026 | | 78,809,039 | |
Dilutive effect of: | | | | | |
Share options outstanding | | 5,823,377 | | 4,213,733 | |
Shares issuable for convertible debentures | | 9,821,429 | | 5,305,250 | |
Diluted common shares outstanding | | 113,090,832 | | 88,328,022 | |
Weighted average shares outstanding | | 93,286,554 | | 78,548,800 | |
Dilutive effect of exchangeable shares, share options and convertible debentures (1) | | — | | — | |
Diluted weighted average shares outstanding | | 93,286,554 | | 78,548,800 | |
(1) A total of 5,823,377 (2009: 4,213,733) share options and 9,821,429 (2009: 5,305.250) common shares issuable pursuant to the conversion of convertible debentures were excluded from the calculation for the year ended December 31, 2010 as they were not dilutive.
70
15. RELATED PARTY TRANSACTIONS
During the year ended December 31, 2010, the Company incurred fees of $0.6 million (2009: $1.1 million) for legal services provided by a firm in which a director and corporate secretary is a partner. The services provided were made in the normal course of operations, on commercial terms, and therefore were recorded at the exchange amount. As at December 31, 2010, an amount due to this firm of $0.1 million was included in accounts payable (2009: $0.1 million).
16. COMMITMENTS
The Company is committed to payments under fixed term operating leases which do not currently provide for early termination. The Company’s commitment for office space is as follows:
($000s)
Year | | Gross
Amount | | Expected
Recoveries | | Net amount | |
2011 | | $ | 2,192 | | $ | 1,027 | | $ | 1,165 | |
2012 | | 2,203 | | 1,062 | | 1,141 | |
2013 | | 2,218 | | 1,103 | | 1,115 | |
2014 | | 1,469 | | 753 | | 716 | |
| | | | | | | | | | |
As at December 31, 2010, the Company had committed to drill 9 gross (4.7 net) wells pursuant to farm-in agreements. Bellatrix expects to satisfy this drilling commitment at an estimated cost of approximately $12.9 million. On February 1, 2011, the Company entered into a joint venture agreement which includes a minimum commitment for Bellatrix to drill 3 gross (3.0 net) wells per year for 2011 to 2015 for a total estimated cost of approximately $52.5 million.
As a result of the issuance of the Flow-Through shares on August 12, 2010, Bellatrix is committed to incur approximately $20.0 million in qualifying Canadian Exploration Expenses on or before December 31, 2011.
17. FINANCIAL RISK MANAGEMENT
a. Overview
The Company has exposure to the following risks from its use of financial instruments:
· Credit risk
· Liquidity risk
· Market risk
This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies.
The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.
71
b. Credit risk
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company’s trade receivables from joint interest partners, petroleum and natural gas marketers, and financial derivative counterparties.
A substantial portion of the Company’s accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to standard industry credit risks. The Company sells substantially all of its production to five primary purchasers under normal industry sale and payment terms. Purchasers of the Company’s natural gas, crude oil and natural gas liquids are subject to an internal credit review to minimize the risk of non-payment.
The Company has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in the Company reducing or mitigating its exposures to certain counterparties where it is deemed warranted and permitted under contractual terms.
Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company’s policy to mitigate credit risk associated with these balances is to establish marketing relationships with a range of medium to large purchasers and to conduct credit reviews of these parties on a regular basis. Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to expenditure. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling, in addition further risk exists with joint venture partners as disagreements occasionally arise that increase the potential for non-collection. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, in certain instances the Company does have the ability to withhold production from joint venture partners in the event of non-payment. Bellatrix recorded a $0.3 million provision for uncollectible accounts for the year ended December 31, 2010 (2009: $1.4 million).
As at December 31, 2010, accounts receivable was comprised of the following:
Aging ($000s) | | Not past due
(less than 90
days) | | Past due (90
days or more) | | Total | |
Joint venture and other trade accounts receivable | | 14,095 | | 2,587 | | 16,682 | |
Amounts due from government agencies | | 901 | | 2,193 | | 3,094 | |
Revenue and other accruals | | 15,477 | | 442 | | 15,919 | |
Cash call receivables | | 14 | | 2,183 | | 2,197 | |
Plant revenue allocation receivable | | — | | 2,855 | | 2,855 | |
Less: Allowance for doubtful accounts | | — | | (1,247 | ) | (1,247 | ) |
Total accounts receivable | | 30,487 | | 9,013 | | 39,500 | |
Less: | | | | | | | |
Accounts payable due to same partners | | (1,101 | ) | (461 | ) | (1,562 | ) |
Subsequent receipts | | (19,788 | ) | (1,599 | ) | (21,387 | ) |
| | 9,598 | | 6,953 | | 16,551 | |
72
Amounts due from government agencies include drilling incentive credits, GST and royalty and other adjustments. During the year ended December 31, 2010, the Company has collected $3.3 million attributable to drilling incentive credits. Plant revenue allocation receivable includes amounts under dispute over plant revenue allocations, net of expenses, from an operator. The Company has commenced legal action for collection of these amounts. Accounts payable due to same partners includes amounts which may be available for offset against certain receivables.
Cash calls receivables consist of advances paid to joint interest partners for capital projects.
The carrying amount of accounts receivable and derivative assets represents the maximum credit exposure. The Company has an allowance for doubtful accounts as at December 31, 2010 of $1.2 million.
c. Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The Company’s approach to managing liquidity is to make reasonable efforts to sustain sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company’s reputation.
The Company prepares annual capital expenditure budgets which are regularly monitored and updated as necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has a revolving reserve based credit facility, as outlined in note 5, which is reviewed at least annually by the lender. The Company attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.
The following are the contractual maturities of financial liabilities as at December 31, 2010:
Financial liability ($000s) | | < 1 Year | | 1-2 Years | | 2-5 Years | | Thereafter | |
Accounts payable and accrued liabilities(1) | | $ | 42,792 | | $ | — | | $ | — | | $ | — | |
Bank debt — principal(2) | | — | | 41,172 | | — | | — | |
Convertible debentures — principal | | — | | — | | 55,000 | | — | |
Convertible debentures — interest(3) | | 2,613 | | 2,620 | | 6,084 | | — | |
Capital lease obligation | | 379 | | 363 | | 991 | | 1,516 | |
Total | | $ | 45,784 | | $ | 44,155 | | $ | 62,075 | | $ | 1,516 | |
(1) As at December 31, 2010, $0.4 million of accrued coupon interest payable in relation to the 4.75% Debentures and $0.1 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.
(3) The 4.75% Debentures outstanding at December 31, 2010 bear interest at a coupon rate of 4.75%, which currently requires total annual interest payments of $2.6 million.
Interest due on the bank credit facilities is calculated based upon floating rates.
73
d. Market risk
Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.
Foreign currency exchange rate risk
Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company’s petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar. As at December 31, 2010, if the Canadian/US dollar exchange rate had decreased by US$0.01 with all other variables held constant, after tax net earnings for the year ended December 31, 2010 would have been approximately $0.6 million lower/higher. An equal and opposite impact would have occurred to net earnings had the Canadian/US dollar exchange rate increased by US$0.01.
The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2010.
Commodity price risk
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined above, but also world economic events that dictate the levels of supply and demand.
The Company utilizes both financial derivatives and physical delivery sales contracts to manage commodity price risks. All such transactions are conducted in accordance with the commodity price risk management policy that has been approved by the Board of Directors.
The Company’s formal commodity price risk management policy permits management to use specified price risk management strategies including fixed price contracts, costless collars and the purchase of floor price options, other derivative financial instruments, and physical delivery sales contracts to reduce the impact of price volatility for a maximum of eighteen months beyond the current date. The program is designed to provide price protection on a portion of the Company’s future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Company seeks to provide a measure of stability to cash flows from operating activities, as well as, to ensure Bellatrix realizes positive economic returns from its capital developments and acquisition activities.
As at December 31, 2010, the Company had entered into commodity price risk management arrangements as follows:
Type | | Period | | Volume | | Price Floor | | Price Ceiling | | Index | |
Oil fixed | | January 1, 2011 to Dec. 31, 2011 | | 1,000 bbl/d | | $ | 88.18 CDN | | $ | 88.18 CDN | | WTI | |
Oil fixed | | January 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 89.00 CDN | | $ | 89.00 CDN | | WTI | |
Oil fixed | | January 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 89.10 US | | $ | 89.10 US | | WTI | |
74
Subsequent to December 31, 2010, the Company entered into commodity price risk management arrangements as follows:
Type | | Period | | Volume | | Price Floor | | Price Ceiling | | Index | |
Oil fixed | | February 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 95.00 US | | $ | 95.00 US | | WTI | |
Oil fixed | | March 1, 2011 to Dec. 31, 2011 | | 500 bbl/d | | $ | 97.50 US | | $ | 97.50 US | | WTI | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.87 CDN | | $ | 3.87 CDN | | AECO | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.65 CDN | | $ | 3.65 CDN | | AECO | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.805 CDN | | $ | 3.805 CDN | | AECO | |
Natural gas fixed | | April 1, 2011 to Oct. 31, 2011 | | 5,000 GJ/d | | $ | 3.80 CDN | | $ | 3.80 CDN | | AECO | |
For the years ended December 31, 2010 and 2009, the gain (loss) on commodity contracts was comprised of the following:
($000s) | | 2010 | | 2009 | |
| | | | | |
Gain (loss) on commodity contracts | | | | | |
Realized (1) | | $ | 15,388 | | $ | 17,746 | |
Unrealized (2) | | (7,106 | ) | (352 | ) |
| | $ | 8,282 | | $ | 17,394 | |
(1) Realized gains and losses on commodity contracts represent actual cash settlements and other amounts paid under these contracts.
(2) Unrealized gains and losses on commodity contracts represent non-cash adjustments for changes in the fair value of these contracts during the period.
As at December 31, 2010, if oil and natural gas liquids prices had been US$1 per barrel and natural gas prices $0.10 per mcf lower, with all other variables held constant, after tax net earnings for the year ended December 31, 2010 would have been approximately $1.6 million lower. An equal and opposite impact would have occurred to net earnings had oil and natural gas liquids prices been US$1 per barrel and natural gas $0.10 per mcf higher.
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. As at December 31, 2010, if interest rates had been 1% lower with all other variables held constant, after tax net earnings for the year ended December 31, 2010 would have been approximately $0.3 million higher, due to lower interest expense. An equal and opposite impact would have occurred to net earnings had interest rates been 1% higher.
The Company had no interest rate swap or financial contracts in place as at or during the year ended December 31, 2010.
e. Capital management
The Company’s policy is to maintain a strong capital base so as to maintain investor, creditor and market confidence and to sustain the future development of the business. The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company considers its capital structure to include
75
shareholders’ equity, bank debt, convertible debentures and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue common shares, issue convertible debentures, adjust its capital spending, and/or dispose of certain assets to manage current and projected debt levels
The Company monitors capital based on the ratio of total net debt to annualized funds flow (the “ratio”). This ratio is calculated as total net debt, defined as outstanding bank debt, plus the liability component of convertible debentures, plus or minus working capital (excluding commodity contract assets and liabilities and future income tax assets or liabilities), divided by funds flow from operations (cash flow from operating activities before realization of imputed interest costs on 7.5% Debentures, changes in non-cash working capital and deductions for asset retirement costs) for the most recent calendar quarter, annualized (multiplied by four). The total net debt to annualized funds flow ratio may increase at certain times as a result of acquisitions, fluctuations in commodity prices, timing of capital expenditures and other factors. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets which are reviewed and updated as necessary depending on varying factors including current and forecast prices, successful capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors. Bellatrix does not pay dividends.
In January 2010 (note 10), the Company closed an equity issuance on a bought deal basis to further Bellatrix’s financial flexibility. On April 20, 2010 (note 6), the Company closed an offering of $55 million of 4.75% Debentures on a bought deal basis in order to facilitate the redemption of the Company’s 7.5% Debentures. On August 12, 2010 (note 10), Bellatrix issued $20.0 million of Flow-Through shares on a bought deal private placement basis. The Company plans to continue to monitor forecasted debt levels to manage its operations within forecasted funds flow. Bellatrix expects the total net debt to annualized funds flow ratio to reflect its strategic accomplishments in reducing the Company’s total net debt while funds flow are exposed to the current volatile economic environment.
The Company’s long-term strategy is to target a total net debt to annualized funds flow ratio of 1.2 times. As at December 31, 2010, the Company’s ratio of total net debt to annualized funds flow based on fourth quarter results was 1.4 times. The total net debt to annualized funds flow ratio as at December 31, 2010 decreased from that at December 31, 2009 of 3.5 times due to a reduction of the Company’s convertible debenture indebtedness and higher annualized funds flow from operations, offset slightly by higher long-term debt. Bellatrix continues to take a balanced approach to the priority use of funds flows. The 4.75% Debentures have a maturity date of April 30, 2015. Upon maturity, the Company may settle the principal in cash or issuance of additional common shares.
Excluding Debentures, net debt to annualized funds flow based on fourth quarter results was 0.6 times.
Bellatrix’s capital structure and calculation of total net debt and total net debt to funds flow ratios as defined by the Company is as follows:
76
| | Years ended December 31, | |
($000s, except where noted) | | 2010 | | 2009 | |
| | | | | |
Shareholders’ equity | | 322,789 | | 281,351 | |
| | | | | |
Long-term debt | | 41,172 | | 27,902 | |
Convertible debentures (liability component) | | 47,599 | | 81,684 | |
Working capital surplus | | (1,327 | ) | (2,317 | ) |
Total net debt (1) at year end | | 87,444 | | 107,269 | |
| | | | | |
Debt to funds flow from operations ratio (annualized) (2) | | | | | |
Funds flow from operations (annualized) | | 63,568 | | 30,724 | |
Total net debt(1) to periods funds flow from operations ratio (annualized) | | 1.4x | | 3.5x | |
| | | | | |
Net debt(1) (excluding convertible debentures) at quarter end | | 39,845 | | 25,585 | |
Net debt to periods funds flow from operations ratio (annualized) | | 0.6x | | 0.8x | |
| | | | | |
Debt to funds flow from operations ratio | | | | | |
Funds flow from operations for the year | | 53,042 | | 36,025 | |
Total net debt(1) to funds flow from operations for the year | | 1.6x | | 3.0x | |
| | | | | |
Net debt(1) (excluding convertible debentures) to funds flow from operations for the year | | 0.8x | | 0.7x | |
(1) Net debt and total net debt are non-GAAP terms. Net debt includes the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current capital lease obligation and short-term future income tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes capital lease obligation, asset retirement obligations and the future income tax liability.
(2)Debt to funds flow from operations ratio annualized is calculated based upon fourth quarter funds flow from operations annualized.
The Company’s credit facility is based on petroleum and natural gas reserves (see note 5). The credit facility outlines limitations on percentages of forecasted production, from external reserve engineer data, which may be hedged through financial commodity price risk management contracts.
f. Fair value of financial instruments
The Company’s financial instruments as at December 31, 2010 include accounts receivable, deposits, commodity contract asset, accounts payable and accrued liabilities, long-term debt, convertible debentures and capital lease obligation. The fair value of accounts receivable, deposits, accounts payable, accrued liabilities and capital lease obligation approximate their carrying amounts due to their short-terms to maturity.
The fair value of commodity contracts is determined by discounting the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted petroleum and natural gas volumes. The fair value of commodity contracts as at December 31, 2010 was a liability of $3.7 million compared to an asset of $3.4 million in 2009. The commodity contracts are classified as level 2 within the fair value hierarchy.
Long-term bank debt bears interest at a floating market rate and the credit and market premiums therein are indicative of current rates; accordingly the fair market value approximates the carrying value.
The fair value of the 4.75% Debentures of $56.9 million is based on exchange traded values. The convertible debentures are classified as level 1 within the fair value hierarchy.
77
ADDITIONAL INFORMATION
Oil and Gas Working Interest (1) Gross Reserves
Reconciliation of Proved Reserves (2)
| | Crude oil &
NGL
(mbbl) | | Coal bed
methane
(mmcf) | | Natural
gas
(mmcf) | | Equivalent
units
(mboe) | |
December 31, 2009 | | 4,803 | | 1,518 | | 68,613 | | 16,492 | |
Revision of previous estimates | | (337 | ) | 323 | | 668 | | (172 | ) |
Discoveries, extensions, infill drilling and improved recovery | | 6,911 | | 1 | | 33,057 | | 12,421 | |
Dispositions, net of acquisitions | | (943 | ) | — | | 740 | | (820 | ) |
Production | | (923 | ) | (211 | ) | (12,724 | ) | (3,079 | ) |
December 31, 2010 | | 9,511 | | 1,632 | | 90,353 | | 24,842 | |
| | | | | | | | | |
Proved plus probable reserves | | | | | | | | | |
December 31, 2010 | | 17,063 | | 1,991 | | 150,284 | | 42,442 | |
December 31, 2009 | | 7,096 | | 1,950 | | 109,976 | | 25,750 | |
(1) “Working interest” refers to Bellatrix’s working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of Bellatrix. Also referred to as “gross” under National Instrument 51-101 (“NI 51-101”). May not add due to rounding.
(2) Based on forecast prices.
Finding, Development and Acquisition Costs (“FD&A”)
($/boe) | | 2010 | | 2009 | | 2008-2010
Average | |
Proved (excluding FDC) | | 8.47 | | 6.01 | | 9.42 | |
Proved (including FDC) | | 15.94 | | 8.61 | | 15.46 | |
| | | | | | | |
Proved plus probable (excluding FDC) | | 4.96 | | 6.90 | | 6.58 | |
Proved plus probable (including FDC) | | 12.89 | | 5.93 | | 13.36 | |
NI 51-101 specifies how finding and development costs (“FDC”) should be calculated if they are reported. Essentially NI 51-101 requires that the exploration and development costs incurred in the year along with the change in estimated FDC be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserves and costs. By excluding the effects of acquisitions and dispositions Bellatrix believes that the provisions of the NI 51-101 do not fully reflect Bellatrix’s ongoing reserve replacement costs. Since acquisitions can have a significant impact on Bellatrix’s annual reserve replacement costs, excluding these amounts could result in an inaccurate portrayal of Bellatrix’s cost structure. Accordingly, Bellatrix also provides FD&A costs that incorporate all acquisitions and excludes dispositions during the year. Finding and development costs disclosed herein is based on working interest gross reserves.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserve additions for that year.
Finding and development costs, excluding FDC, for proved reserves, were $8.47/boe and $6.01/boe in 2010 and 2009, respectively (proved plus probable - $4.96/boe in 2010 and $6.90/boe in 2009) and $9.42/boe on a three year average (proved plus probable $6.58/boe).
The net present value of future net revenue of reserves do not represent fair market value.
78
The Company’s corporate presentation is available at www.bellatrixexploration.com.
Bellatrix Exploration Ltd. is a Western Canadian based growth oriented oil and gas company engaged in the exploration for, and the acquisition, development and production of oil and natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan. Common shares and convertible debentures of Bellatrix trade on the Toronto Stock Exchange (“TSX”) under the symbols BXE and BXE.DB.A, respectively. For further information, please contact:
Raymond G. Smith, P.Eng., President and CEO (403) 750-2420
or
Edward J. Brown, CA, Vice President, Finance and CFO (403) 750-2655
or
Troy Winsor, Investor Relations (800) 663-8072
Bellatrix Exploration Ltd.
2300, 530 — 8th Avenue SW
Calgary, Alberta, Canada T2P 3S8
Phone: (403) 266-8670
Fax: (403) 264-8163
www.bellatrixexploration.com
79
