BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the three months and nine months ended September 30, 2011
Dated November 9, 2011
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months and nine months ended September 30, 2011. This information is provided as of November 9, 2011. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The third quarter results have been compared with the corresponding period in 2010. This MD&A should be read in conjunction with the Company’s condensed interim unaudited consolidated financial statements (“consolidated financial statements”) for the three months and nine months ended September 30, 2011 and 2010, and its audited consolidated comparative financial statements for the years ended December 31, 2010 and 2009, together with accompanying notes, and the Annual Information Form for the year ended December 31, 2010. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com. The consolidated financial statements for the third quarter of 2011 are prepared in accordance with International Financial Reporting Standards (“IFRS”). Comparative periods in 2010 have been restated to conform to IFRS presentation. Reconciliations from IFRS to Canadian general accepted accounting principles (“previous GAAP”) are shown in the notes to our consolidated financial statements. The adoption of IFRS did not have a material impact on the amounts reported as funds from operations. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share or per trust unit amounts or as otherwise noted.
In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.
This MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our advisory on forward-looking information and statements.
CORPORATE CONVERSION
At year end 2010, Baytex Energy Trust (the "Trust") completed a plan of arrangement under the Business Corporations Act (Alberta) pursuant to which it converted its legal structure from an income trust to a corporation (the "Corporate Conversion"). Pursuant to the Corporate Conversion: (i) on December 31, 2010, holders of trust units of the Trust exchanged their trust units for our common shares on a one-for-one basis; and (ii) on January 1, 2011, the Trust was dissolved and terminated, with the result that we became the successor to the Trust. The reorganization into a corporation has been accounted for on a continuity of interest basis, and accordingly, the consolidated financial statements 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.
Despite the change in legal structure from a trust to a corporation, the Company’s business objectives and strategies remain unchanged and the officers and directors remained the same. Baytex's business objectives are directed towards growing its production and asset base through internal property development and acquisitions with the objectives of providing monthly income to its shareholders and creating long-term value for its shareholders. To achieve these objectives, Baytex intends to invest capital to enhance the value of its assets, operate its producing petroleum and natural gas properties in a low cost manner while maximizing the recovery of reserves, and pay monthly dividends to shareholders.
Baytex will continue to direct its efforts to increase the value of its assets through development drilling and associated development activities and enhanced oil recovery activities. Baytex will also seek to acquire undeveloped and producing petroleum and natural gas properties and primarily participate in development activities that are generally considered to be lower risk. Also, a minor percentage of each year's capital budget will be devoted to moderate risk development and lower risk exploration opportunities on its properties.
The common shares of Baytex trade on the Toronto Stock Exchange and the New York Stock Exchange under the trading symbol BTE. Beginning with the January 31, 2011 record date, shareholders of Baytex will receive payments in the form of dividends. Prior to the Corporate Conversion on December 31, 2010, unitholders of the Trust received payments in the form of distributions.
NON-GAAP FINANCIAL MEASURES
In this MD&A, we refer to certain financial measures (such as funds from operations, payout ratio, total monetary debt and operating netback) which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada ("GAAP"). While funds from operations, payout ratio and operating netback are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures for other issuers.
Funds from Operations
We define funds from operations as cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. However, funds from operations should not be construed as an alternative to traditional performance measures determined in accordance with IFRS or previous GAAP, such as cash flow from operating activities and net income. For a reconciliation of funds from operations to cash flow from operating activities, see "Funds from Operations, Payout Ratio and Dividends or Distributions".
Payout Ratio
We define payout ratio as cash dividends (net of participation in our dividend reinvestment plan) divided by funds from operations. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to Shareholders and capital investments.
Total Monetary Debt
We define total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred income tax assets or liabilities and unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and the balance sheet amount of any convertible debentures and long-term bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.
Operating Netback
We define operating netback as product revenue less royalties, operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. We believe that this measure assists in evaluating the specific operating performance by product.
Page 2 of 19
RESULTS OF OPERATIONS
Production
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
Daily Production | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Light oil and NGL (bbl/d) | 7,170 | 6,600 | 9 | % | 6,612 | 6,567 | 1 | % | ||||||||||||||||
Heavy oil (bbl/d) (1) | 37,280 | 28,959 | 29 | % | 34,324 | 28,172 | 22 | % | ||||||||||||||||
Natural gas (mmcf/d) | 49.0 | 55.4 | (12 | %) | 49.3 | 56.2 | (12 | %) | ||||||||||||||||
Total production (boe/d) | 52,625 | 44,799 | 17 | % | 49,147 | 44,113 | 11 | % | ||||||||||||||||
Production Mix | ||||||||||||||||||||||||
Light oil and NGL | 14 | % | 15 | % | - | 13 | % | 15 | % | - | ||||||||||||||
Heavy oil | 71 | % | 65 | % | - | 70 | % | 64 | % | - | ||||||||||||||
Natural gas | 15 | % | 20 | % | - | 17 | % | 21 | % | - |
(1) Heavy oil sales volumes may differ from reported production volumes due to changes to Baytex's heavy oil inventory. For the three months ended September 30, 2011, heavy oil sales volumes were 369 bbl/d lower than production volumes (three months ended September 30, 2010 – 10 bbl/d lower). For the nine months ended September 30, 2011, heavy oil sales volumes were 89 bbl/d higher than production volumes (nine months ended September 30, 2010 – 75 bbl/d higher). |
Production for the three months ended September 30, 2011 averaged 52,625 boe/d, as compared to 44,799 boe/d for the same period in 2010. Light oil and natural gas liquids (“NGL”) production for the third quarter of 2011 increased by 9% to 7,170 bbl/d from 6,600 bbl/d due to development activities in the US, which increased production by 95%, as compared to the same quarter in 2010. Heavy oil production for the third quarter of 2011 increased by 29% to 37,280 bbl/d from 28,959 bbl/d a year ago primarily due to development activities and the acquisition of producing assets in the first quarter of 2011. Natural gas production decreased by 12% to 49.0 mmcf/d for the third quarter of 2011, as compared to 55.4 mmcf/d for the same period last year primarily due to natural declines as we focused our drilling effort on our oil portfolio, partially offset by a natural gas-weighted acquisition that closed in the third quarter of 2011 .
Production for the nine months ended September 30, 2011 averaged 49,147 boe/d, as compared to 44,113 boe/d for the same period in 2010. Light oil and NGL production for the nine months ended September 30, 2011 increased by 1% to 6,612 bbl/d from 6,567 bbl/d a year earlier due to development activities in the US, which increased US production by 75%, as compared to the same period in 2010. This increase was partially offset by second quarter production interruptions in North Dakota, Alberta and British Columbia. Heavy oil production for the nine months ended September 30, 2011 increased by 22% to 34,324 bbl/d from 28,172 bbl/d a year ago primarily due to development activities and the acquisition of producing assets in the first quarter of 2011. Natural gas production decreased by 12% to 49.3 mmcf/d for the nine months ended September 30, 2011, as compared to 56.2 mmcf/d for the same period last year primarily due to natural declines as we focused our drilling effort on our oil portfolio, partially offset by a natural gas-weighted acquisition that closed in the third quarter of 2011.
Commodity Prices
Crude Oil
For the first nine months of 2011, the prompt price of WTI fluctuated between a low of US$79.20/bbl and a high of US$113.93/bbl. This was a period of significant volatility, as oil prices reacted to rapidly changing macroeconomic issues and uncertainty, political and social unrest, and underlying energy market fundamentals. After rallying early in the third quarter of 2011, the WTI price declined on renewed macroeconomic concerns, a US budget stalemate and the release of 60 million barrels of oil from emergency stock by the International Energy Agency. During the third quarter of 2011, the prompt WTI price ranged from a high of US$99.87/bbl to a low of US$79.20/bbl at September 30, 2011. The average WTI price in the third quarter of 2011 was US$89.76/bbl, compared to the second quarter of 2011 average price of US$102.56/bbl. Also during the third quarter of 2011, the discount for WTI crude to Brent crude continued to widen, at times exceeding US$25/bbl, due to market expectations of an increasing transportation bottleneck out of Cushing, Oklahoma.
Page 3 of 19
The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged nearly 20% in third quarter of 2011, compared to 17% for second quarter of 2011. This increase in WCS differentials from second quarter levels was largely due to the effect of declining WTI prices. As the WCS differential is set a month prior to the delivery of heavy crude, a decline in the WTI price after the WCS differential is set results in a wider percentage differential of WCS to WTI. During the nine months ended September 30, 2011, the WCS heavy oil price differential was 20% as compared to 17% in the first nine months of 2010.
Natural Gas
For the three months ended September 30, 2011, AECO natural gas prices averaged $3.72/mcf, unchanged from the same period of 2010. After rallying early in the third quarter, natural gas prices trended lower over the remainder of the third quarter due to increasing US gas production and expectations of higher gas storage levels. For the nine months ended September 30, 2011, the average AECO natural gas price was $3.75/mcf, as compared to $4.31/mcf in the same period last year.
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
2011 | 2010 | Change | 2011 | 2010 | Change | |||||||||||||||||||
Benchmark Averages | ||||||||||||||||||||||||
WTI oil (US$/bbl) (1) | $ | 89.76 | $ | 76.20 | 18 | % | $ | 95.48 | $ | 77.65 | 23 | % | ||||||||||||
WCS heavy oil (US$/bbl) (2) | $ | 72.14 | $ | 60.55 | 19 | % | $ | 76.10 | $ | 64.72 | 18 | % | ||||||||||||
Heavy oil differential (3) | (20 | %) | (21 | %) | - | (20 | %) | (17 | %) | - | ||||||||||||||
USD/CAD average exchange rate | 1.0220 | 0.9624 | 6 | % | 1.0231 | 0.9654 | 6 | % | ||||||||||||||||
Edmonton par oil ($/bbl) | $ | 92.45 | $ | 74.43 | 24 | % | $ | 94.85 | $ | 76.73 | 24 | % | ||||||||||||
AECO natural gas price ($/mcf) (4) | $ | 3.72 | $ | 3.72 | - | % | $ | 3.75 | $ | 4.31 | (13 | %) | ||||||||||||
Baytex Average Sales Prices | ||||||||||||||||||||||||
Light oil and NGL ($/bbl) | $ | 80.48 | $ | 63.13 | 27 | % | $ | 81.53 | $ | 65.18 | 25 | % | ||||||||||||
Heavy oil ($/bbl) (5) | $ | 59.12 | $ | 57.59 | 3 | % | $ | 62.53 | $ | 60.28 | 4 | % | ||||||||||||
Physical forward sales contracts gain (loss) ($/bbl) | 0.80 | 0.38 | 1.01 | (1.13 | ) | |||||||||||||||||||
Heavy oil, net ($/bbl) | $ | 59.92 | $ | 57.97 | 3 | % | $ | 63.54 | $ | 59.15 | 7 | % | ||||||||||||
Total oil and NGL, net ($/bbl) | $ | 63.26 | $ | 58.93 | 7 | % | $ | 66.45 | $ | 60.29 | 10 | % | ||||||||||||
Natural gas ($/mcf) (6) | $ | 3.89 | $ | 3.76 | 3 | % | $ | 3.95 | $ | 4.38 | (10 | %) | ||||||||||||
Physical forward sales contracts gain ($/mcf) | 0.31 | 0.13 | 0.30 | 0.09 | ||||||||||||||||||||
Natural gas, net ($/mcf) | $ | 4.20 | $ | 3.89 | 8 | % | $ | 4.25 | $ | 4.47 | (5 | %) | ||||||||||||
Summary | ||||||||||||||||||||||||
Weighted average ($/boe) (6) | $ | 56.32 | $ | 51.11 | 10 | % | $ | 58.45 | $ | 53.90 | 8 | % | ||||||||||||
Physical forward sales contracts gain (loss) ($/boe) | 0.99 | 0.48 | 1.16 | (0.72 | ) | |||||||||||||||||||
Weighted average, net ($/boe) | $ | 57.31 | $ | 51.59 | 11 | % | $ | 59.61 | $ | 53.18 | 12 | % |
(1) WTI refers to the calendar monthly average based on NYMEX prompt month WTI.
(2) WCS refers to the average posting price for the benchmark WCS heavy oil.
(3) Heavy oil differential refers to the WCS discount to WTI.
(4) AECO refers to the AECO monthly index price published by the Canadian Gas Price Reporter.
(5) Baytex’s realized heavy oil prices are calculated based on sales volumes, net of blending costs.
(6) | Baytex's risk management strategy employs both oil and natural gas financial and physical forward contracts (fixed price forward sales and collars) and heavy oil differential physical delivery contracts (fixed price and percentage of WTI). The above pricing information in the table excludes the impact of financial derivatives. |
During the third quarter of 2011, Baytex’s average sales price for light oil and NGL was $80.48/bbl, up 27% from $63.13/bbl in the third quarter of 2010. Baytex’s realized heavy oil price during the third quarter of 2011, prior to physical forward sales contracts, was $59.12/bbl, or 84% of WCS. This compares to a realized heavy oil price in the third quarter of 2010, prior to physical forward sales contracts, of $57.59/bbl, or 92% of WCS. The differential to WCS largely reflects the cost of blending Baytex’s heavy oil with diluent to meet pipeline specifications. Net of physical forward sales contracts, Baytex’s realized heavy oil price during the third quarter of 2011 was $59.92/bbl, up 3% from $57.97/bbl in the third quarter of 2010. Baytex’s realized natural gas price for the three months ended September 30, 2011 was $3.89/mcf prior to physical forward sales contracts and $4.20/mcf inclusive of physical forward sales contracts (three months ended September 30, 2010 - $3.76/mcf prior to physical forward sales contracts and $3.89/mcf inclusive of physical forward sales contracts).
Page 4 of 19
For the first nine months of 2011, Baytex’s average sales price for light oil and NGL was $81.53/bbl, up 25% from $65.18/bbl in the first nine months of 2010. Baytex’s realized heavy oil price during the first nine months of 2011, prior to physical forward sales contracts, was $62.53/bbl, or 84% of WCS. This compares to a realized heavy oil price in the first nine months of 2010, prior to physical forward sales contracts, of $60.28/bbl, or 90% of WCS. The differential to WCS largely reflects the cost of blending Baytex’s heavy oil with diluent to meet pipeline specifications. Net of physical forward sales contracts, Baytex’s realized heavy oil price during the first nine months of 2011 was $63.54/bbl, up 7% from $59.15/bbl in the first nine months of 2010. Baytex’s realized natural gas price for the nine months ended September 30, 2011 was $3.95/mcf prior to physical forward sales contracts and $4.25/mcf inclusive of physical forward sales contracts (nine months ended September 30, 2010 - $4.38/mcf prior to physical forward sales contracts and $4.47/mcf inclusive of physical forward sales contracts).
Gross Revenues
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands except for %) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Oil revenue | ||||||||||||||||||||||||
Light oil and NGL | $ | 53,808 | $ | 38,632 | 39 | % | $ | 147,899 | $ | 117,164 | 26 | % | ||||||||||||
Heavy oil | 203,486 | 154,381 | 32 | % | 595,838 | 456,162 | 31 | % | ||||||||||||||||
Total oil revenue | 257,294 | 193,013 | 33 | % | 743,737 | 573,326 | 30 | % | ||||||||||||||||
Natural gas revenue | 18,962 | 19,830 | (4 | %) | 57,155 | 68,561 | (17 | %) | ||||||||||||||||
Total oil and natural gas revenue | 276,256 | 212,843 | 30 | % | 800,892 | 641,887 | 25 | % | ||||||||||||||||
Sales of heavy oil blending diluent | 37,531 | 25,433 | 48 | % | 140,109 | 99,752 | 40 | % | ||||||||||||||||
Total petroleum and natural gas sales | $ | 313,787 | $ | 238,276 | 32 | % | $ | 941,001 | $ | 741,639 | 27 | % |
Petroleum and natural gas sales increased 32% to $313.8 million for the three months ended September 30, 2011 from $238.3 million for the same period in 2010. During this period, the change was driven by heavy oil revenues which increased by 32% due to a 3% increase in realized price and a 29% increase in sales volume compared to the three months ended September 30, 2010.
For the nine months ended September 30, 2011, petroleum and natural gas sales increased 27% to $941.0 million from $741.6 million for the same period in 2010. During this period, the change was driven by heavy oil revenues which increased by 31% due to a 7% increase in realized price and an 22% increase in sales volume compared to the nine months ended September 30, 2010.
Royalties
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands except for % and per boe) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Royalties | $ | 50,656 | $ | 42,750 | 18 | % | $ | 150,617 | $ | 135,797 | 11 | % | ||||||||||||
Royalty rates: | ||||||||||||||||||||||||
Light oil, NGL and natural gas | 20.8 | % | 17.3 | % | - | 18.9 | % | 21.0 | % | - | ||||||||||||||
Heavy oil | 17.6 | % | 21.1 | % | - | 18.8 | % | 21.2 | % | - | ||||||||||||||
Average royalty rates (1) | 18.4 | % | 20.1 | % | - | 18.8 | % | 21.2 | % | - | ||||||||||||||
Royalty expenses per boe | $ | 10.54 | $ | 10.37 | 2 | % | $ | 11.22 | $ | 11.26 | - | % |
(1) Average royalty rate excludes sales of heavy oil blending diluents and the effects of financial derivatives.
Total royalties for the third quarter of 2011 increased to $50.7 million from $42.8 million in the third quarter of 2010. Total royalties for the third quarter of 2011 were 18.4% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 20.1% for the same period in 2010. Royalty rates for light oil, NGL and natural gas increased from 17.3% in the three months ended September 30, 2010 to 20.8% in the three months ended September 30, 2011 due to the increase in reference pricing for light oil and NGL, partially offset by reductions in conventional oil royalty rates on new wells. Royalty rates for heavy oil decreased from 21.1% in the three months ended September 30, 2010 to 17.6% in the three months ended September 30, 2011 due to lower royalty rates at Seal and Kerrobert.
Total royalties for the nine months ended September 30, 2011 increased to $150.6 million from $135.8 million in the nine months ended September 30, 2010. Total royalties for the first nine months of 2011 were 18.8% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 21.2% for the same period in 2010. Royalty rates for light oil, NGL and natural gas decreased from 21.0% in the nine months ended September 30, 2010 to 18.9% in the nine months ended September 30, 2011 due to royalty incentives on new wells realized in the period. Royalty rates for heavy oil decreased from 21.2% in the nine months ended September 30, 2010 to 18.8% in the nine months ended September 30, 2011 due to lower royalty rates at Seal and Kerrobert, in addition to a $1.0 million Alberta Royalty Tax Credit reassessment related to 2004 and 2005 periods received in the first quarter of 2011.
Page 5 of 19
Certain additional credits earned under the Alberta Royalty Drilling Credit program, which are based on drilling activity and drilling depths, are recorded as a reduction to capital expenditures, rather than as a reduction to royalties.
Financial Derivatives
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Realized gain (loss) on financial derivatives (1) | ||||||||||||||||||||||||
Crude oil | $ | 3,114 | $ | 4,501 | $ | (1,387 | ) | $ | (14,355 | ) | $ | 8,409 | $ | (22,764 | ) | |||||||||
Natural gas | 102 | 3,620 | (3,518 | ) | 59 | 7,665 | (7,606 | ) | ||||||||||||||||
Foreign currency | 2,907 | 6,553 | (3,646 | ) | 13,701 | 19,660 | (5,959 | ) | ||||||||||||||||
Interest rate | 104 | 567 | (463 | ) | 32 | 1,079 | (1,047 | ) | ||||||||||||||||
Total | $ | 6,227 | $ | 15,241 | $ | (9,014 | ) | $ | (563 | ) | $ | 36,813 | $ | (37,376 | ) | |||||||||
Unrealized gain (loss) on financial derivatives (2) | ||||||||||||||||||||||||
Crude oil | $ | 58,710 | $ | (9,932 | ) | $ | 68,642 | $ | 62,303 | $ | 6,171 | $ | 56,132 | |||||||||||
Natural gas | 2,287 | (643 | ) | 2,930 | 3,792 | 3,545 | 247 | |||||||||||||||||
Foreign currency | (23,372 | ) | 4,361 | (27,733 | ) | (26,069 | ) | (13,123 | ) | (12,946 | ) | |||||||||||||
Interest rate | (6,609 | ) | (6,243 | ) | (366 | ) | (5,878 | ) | (15,706 | ) | 9,828 | |||||||||||||
Total | $ | 31,016 | $ | (12,457 | ) | $ | 43,473 | $ | 34,148 | $ | (19,113 | ) | $ | 53,261 | ||||||||||
Total gain (loss) on financial derivatives | ||||||||||||||||||||||||
Crude oil | $ | 61,824 | $ | (5,431 | ) | $ | 67,255 | $ | 47,948 | $ | 14,580 | $ | 33,368 | |||||||||||
Natural gas | 2,389 | 2,977 | (588 | ) | 3,851 | 11,210 | (7,359 | ) | ||||||||||||||||
Foreign currency | (20,465 | ) | 10,914 | (31,379 | ) | (12,368 | ) | 6,537 | (18,905 | ) | ||||||||||||||
Interest rate | (6,505 | ) | (5,676 | ) | (829 | ) | (5,846 | ) | (14,627 | ) | 8,781 | |||||||||||||
Total | $ | 37,243 | $ | 2,784 | $ | 34,459 | $ | 33,585 | $ | 17,700 | $ | 15,885 |
(1) Realized gain (loss) on financial derivatives represents actual cash settlement or receipts under the financial derivatives. |
(2) Unrealized gain (loss) on financial derivatives represents the change in fair value of the financial derivatives during the period. |
The total gain on financial derivatives for the three months ended September 30, 2011 was $37.2 million, as compared to a gain of $2.8 million for the same period in 2010. This includes a realized gain of $6.2 million and an unrealized mark-to-market gain of $31.0 million for the third quarter of 2011, as compared to $15.2 million in realized gains and $12.5 million in unrealized losses for the third quarter of 2010. The realized gain of $6.2 million for the three months ended September 30, 2011 relates to the realization of gains on commodity contracts due to lower oil prices and gains on foreign currency contracts. The unrealized mark-to-market gain of $31.0 million for the three months ended September 30, 2011 relates to lower oil prices at September 30, 2011, as compared to June 30, 2011, partially offset by a strengthening US dollar against the Canadian dollar.
The total gain on financial derivatives for the nine months ended September 30, 2011 was $33.6 million, as compared to a gain of $17.7 million for the same period in 2010. This includes a realized loss of $0.6 million and an unrealized mark-to-market gain of $34.1 million for the first nine months of 2011, as compared to $36.8 million in realized gains and $19.1 million in unrealized losses for the same period in 2010. The realized loss of $0.6 million for the nine months ended September 30, 2011 relates to the realization of losses on commodity contracts due to higher oil prices in the first seven months of the year offset by gains on foreign currency contracts. The unrealized gain of $34.1 million for the nine months ended September 30, 2011, is mainly due to lower commodity prices at September 30, 2011, as compared to December 31, 2010, offset by a strengthening US dollar against the Canadian dollar.
A summary of the risk management contracts in place as at September 30, 2011 and the accounting treatment of the Company’s financial instruments are disclosed in note 22 to the consolidated financial statements as at and for the three months and nine months ended September 30, 2011.
Page 6 of 19
Evaluation and Exploration Expense
Evaluation and exploration expense for the three months and nine months ended September 30, 2011 decreased to $3.3 million and $10.1 million respectively, as compared to $6.2 million and $18.2 million for the same periods of 2010, due to a decrease in lease expiries of undeveloped land during 2011.
Production and Operating Expenses
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands except for % and per boe) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Production and operating expenses | $ | 55,936 | $ | 43,890 | 27 | % | $ | 153,601 | $ | 128,511 | 20 | % | ||||||||||||
Production and operating expenses per boe | $ | 11.64 | $ | 10.65 | 9 | % | $ | 11.44 | $ | 10.65 | 7 | % |
Production and operating expenses for the three months ended September 30, 2011 increased to $55.9 million from $43.9 million for the same period of 2010 due to increases in total production volumes from development activities, the cost of energy inputs and the number of turnarounds conducted at Baytex operated and non-operated oil and natural gas processing facilities. Production and operating expenses were $11.64 per boe for the three months ended September 30, 2011, as compared to $10.65 per boe for the same period in 2010. For the three months ended September 30, 2011, production and operating expenses were $12.98 per boe of light oil, NGL and natural gas and $11.08 per barrel of heavy oil, as compared to $10.62 and $10.67, respectively, for the same period in 2010.
Production and operating expenses for the nine months ended September 30, 2011 increased to $153.6 million from $128.5 million for the same period of 2010 due to an increase in total production volumes from development activities and difficult year-to-date weather conditions. In the winter months, Baytex experienced increased costs for energy inputs and snow removal. In the spring months, Baytex experienced increased costs due to forest fires in northern Alberta and extremely wet ground conditions in North Dakota. In the summer months, production and operating expenses increased due to the increased cost of energy inputs and number of turnarounds conducted at Baytex operated and non-operated oil and natural gas processing facilities. Production and operating expenses were $11.44 per boe for the nine months ended September 30, 2011, as compared to $10.65 per boe for the same period in 2010. For the nine months ended September 30, 2011, production and operating expenses were $12.14 per boe of light oil, NGL and natural gas and $11.14 per barrel of heavy oil, as compared to $10.92 and $10.50, respectively, for the same period in 2010.
Transportation and Blending Expenses
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands except for % and per boe) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Blending expenses | $ | 37,531 | $ | 25,433 | 48 | % | $ | 140,109 | $ | 99,752 | 40 | % | ||||||||||||
Transportation expenses (1) | 16,528 | 12,122 | 36 | % | 45,628 | 35,759 | 28 | % | ||||||||||||||||
Total transportation and blending expenses | $ | 54,059 | $ | 37,555 | 44 | % | $ | 185,737 | $ | 135,511 | 37 | % | ||||||||||||
Transportation expense per boe (1) | $ | 3.44 | $ | 2.94 | 17 | % | $ | 3.40 | $ | 2.96 | 15 | % |
(1) Transportation expenses per boe are before the purchase of blending diluent.
Transportation and blending expenses for the third quarter of 2011 were $54.1 million, as compared to $37.6 million for the third quarter of 2010. Transportation and blending expenses for the first nine months of 2011 were $185.7 million, as compared to $135.5 million for the first nine months of 2010.
The heavy oil produced by Baytex requires blending to reduce its viscosity in order to meet pipeline specifications. Baytex mainly purchases condensate from industry producers as the blending diluent to facilitate the marketing of its heavy oil. In the third quarter of 2011, blending expenses were $37.5 million for the purchase of 4,287 bbl/d of condensate at $95.16 per barrel, as compared to $25.4 million for the purchase of 3,411 bbl/d at $81.03 per barrel for the same period last year. In the nine months ended September 30, 2011, blending expenses were $140.1 million for the purchase of 5,116 bbl/d of condensate at $100.32 per barrel, as compared to $99.8 million for the purchase of 4,331 bbl/d at $84.36 per barrel for the same period last year. The cost of blending diluent is effectively recovered in the sale price of a blended product.
Page 7 of 19
Transportation expenses were $3.44 per boe for the three months ended September 30, 2011, as compared to $2.94 per boe for the same period of 2010. Transportation expenses were $0.85 per boe of light oil, NGL and natural gas and $4.51 per barrel of heavy oil in the third quarter of 2011, as compared to $0.82 and $4.10 per barrel, respectively, for the same period in 2010. The increase in transportation expenses per barrel of heavy oil is primarily due to a larger portion of our heavy oil production coming from Seal, which requires long-haul trucking, and increased fuel prices.
Transportation expenses were $3.40 per boe for the nine months ended September 30, 2011, as compared to $2.96 per boe for the same period of 2010. Transportation expenses were $0.81 per boe of light oil, NGL and natural gas and $4.52 per barrel of heavy oil in the first nine months of 2011, as compared to $0.86 and $4.15 per barrel, respectively, for the same period in 2010. The increase in transportation expenses per barrel of heavy oil is primarily due to a larger portion of our heavy oil production coming from Seal, which requires long-haul trucking, and increased fuel prices.
Operating Netback
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ per boe except for % and volume) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Sales volume (boe/d) | 52,256 | 44,789 | 17 | % | 49,171 | 44,188 | 11 | % | ||||||||||||||||
Operating netback (1): | ||||||||||||||||||||||||
Sales price (2) | $ | 57.31 | $ | 51.59 | 11 | % | $ | 59.61 | $ | 53.18 | 12 | % | ||||||||||||
Less: | ||||||||||||||||||||||||
Royalties | 10.54 | 10.37 | 2 | % | 11.22 | 11.26 | - | % | ||||||||||||||||
Operating expenses | 11.64 | 10.65 | 9 | % | 11.44 | 10.65 | 7 | % | ||||||||||||||||
Transportation expenses | 3.44 | 2.94 | 17 | % | 3.40 | 2.96 | 15 | % | ||||||||||||||||
Operating netback before financial derivatives | $ | 31.69 | $ | 27.63 | 15 | % | $ | 33.55 | $ | 28.31 | 19 | % | ||||||||||||
Financial derivatives gain (loss) (3) | 1.30 | 3.70 | (65 | %) | (0.04 | ) | 3.05 | (101 | %) | |||||||||||||||
Operating netback after financial derivatives (loss) gain | $ | 32.99 | $ | 31.33 | 5 | % | $ | 33.51 | $ | 31.36 | 7 | % |
(1) Operating netback table includes revenues and costs associated with sulphur production.
(2) Sales price is shown net of blending costs and gains (losses) on physical delivery contracts.
(3) Financial derivatives reflect realized gains (losses) only. |
General and Administrative Expenses
Three Months Ended September 30 | Nine Months Ended September 30 | |||||
($ thousands except for % and per boe) | 2011 | 2010 | Change | 2011 | 2010 | Change |
General and administrative expenses | $ 9,604 | $ 8,606 | 12% | $ 29,423 | $ 29,628 | (1%) |
General and administrative expenses per boe | $ 2.00 | $ 2.09 | (4%) | $ 2.19 | $ 2.46 | (11%) |
General and administrative expenses for the third quarter of 2011 increased to $9.6 million from $8.6 million for the comparable period in 2010. The increase is a result of higher general office and salary costs, partially offset by higher capital overhead recoveries from increased capital expenditures.
General and administrative expenses for the nine months ended September 30, 2011 decreased slightly to $29.4 million from $29.6 million for the same period in 2010. This decrease is a result of higher capital overhead recoveries from increased capital expenditures and lower consulting expenses, partially offset by increases in rent and independent reserves evaluator fees.
Page 8 of 19
Share-based Compensation Expense
Compensation expense related to the Common Share Rights Incentive Plan (the “Share Rights Plan”) was $3.9 million for the three months ended September 30, 2011, as compared to a $35.0 million expense related to the Trust Unit Rights Incentive Plan of the Trust (the “Unit Rights Plan”) for the same period in 2010. For the nine months ended September 30, 2011, the compensation expense was $13.7 million, as compared to $63.1 million for the same period in 2010. The significant decrease in compensation expense is primarily due to the change in classification of the plans. Under IFRS, prior to our conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability is re-measured at each reporting date and at settlement date. Any changes in fair value are recognized in net income for the period. Upon conversion to a corporation, the outstanding Unit Rights Plan was modified to become the new Share Rights Plan, effectively changing the related classification from liability-settled to equity-settled. The expense recognized from the date of the plan modification over the remainder of the vesting period is determined based on the fair value of the reclassified unit rights at the date of the modification.
On January 1, 2011, the Company adopted a full-value award plan (the “Share Award Incentive Plan”) pursuant to which restricted awards and performance awards may be granted to directors, officers and employees of the Company and its subsidiaries. During the three months and nine months ended September 30, 2011, the Company recorded $5.9 million and $11.5 million, respectively, related to the share awards ($nil for the three months and nine months ended September 30, 2010). This increase is the result of the compensation expense related to share awards granted in 2011.
Compensation expense associated with the Share Rights Plan and the Share Award Incentive Plan are recognized in income over the vesting period of the share rights or share awards with a corresponding increase in contributed surplus. The issuance of common shares upon the exercise of share rights or settlement of share awards is recorded as an increase in shareholders’ capital with a corresponding reduction in contributed surplus
Financing Costs
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands except for %) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Bank loan and other | $ | 2,583 | $ | 3,616 | (29 | %) | $ | 9,389 | $ | 9,213 | 2 | % | ||||||||||||
Long-term debt | 6,088 | 3,823 | (59 | %) | 16,793 | 10,763 | 56 | % | ||||||||||||||||
Accretion on asset retirement obligations | 1,558 | 1,473 | 6 | % | 4,558 | 4,331 | 5 | % | ||||||||||||||||
Convertible debentures | - | (93 | ) | (100 | %) | - | 155 | (100 | %) | |||||||||||||||
Debt financing costs | 154 | 11 | 1300 | % | 2,998 | 1,425 | 110 | % | ||||||||||||||||
Financing costs | $ | 10,383 | $ | 8,830 | 18 | % | $ | 33,738 | $ | 25,887 | 30 | % |
Financing costs for the three months ended September 30, 2011 increased to $10.4 million, as compared to $8.8 million in the third quarter of 2010. The increase in financing costs was primarily attributable to the interest on the US$150.0 million principal amount of 6.75% Series B senior unsecured debentures issued on February 17, 2011, higher fees paid in 2011 associated with our revolving credit facilities, offset by lower borrowing rates on the US$180.0 million portion of bank loan.
Financing costs for the nine months ended September 30, 2011 increased to $33.7 million, as compared to $25.9 million in the nine months ended September 30, 2010. The increase in financing costs was primarily attributable to the interest on the US$150.0 million principal amount of 6.75% Series B senior unsecured debentures issued on February 17, 2011 and higher debt financing costs related to the issuance of these debentures. .
Foreign Exchange
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
($ thousands except for %) | 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||||||||||||
Unrealized foreign exchange loss (gain) | $ | 24,257 | $ | (5,321 | ) | (556 | %) | $ | 14,655 | $ | (2,824 | ) | (619 | %) | ||||||||||
Realized foreign exchange (gain) loss | (4,418 | ) | 903 | (589 | %) | (2,752 | ) | (1,186 | ) | 132 | % | |||||||||||||
Total loss (gain) | $ | 19,839 | $ | (4,418 | ) | (549 | %) | $ | 11,903 | $ | (4,010 | ) | (397 | %) |
Page 9 of 19
The foreign exchange loss for the three months ended September 30, 2011 was $19.8 million, as compared to a gain of $4.4 million for the three months ended September 30, 2010. This loss was comprised of an unrealized foreign exchange loss of $24.3 million and a realized foreign exchange gain of $4.4 million. The third quarter of 2011 unrealized loss of $24.3 million, as compared to a gain of $5.3 million for the third quarter of 2010, was due to the translation of the US$180 million portion of the bank loan and US$150 million Series B senior unsecured debentures as the USD/CAD foreign exchange rates strengthened at September 30, 2011 (as compared to June 30, 2011) and weakened at September 30, 2010 (as compared to June 30, 2010). The current quarter realized gain was related to day-to-day US dollar denominated transactions.
The foreign exchange loss for the nine months ended September 30, 2011 was $11.9 million, as compared to a gain of $4.0 million for the nine months ended September 30, 2010. This gain was comprised of an unrealized foreign exchange loss of $14.7 million and a realized foreign exchange gain of $2.8 million. The nine months ended September 30, 2011 unrealized loss of $14.7 million, as compared to a gain of $2.8 million for the same period in 2010, was due to the translation of the US$180 million portion of the bank loan as the USD/CAD foreign exchange rates strengthened at September 30, 2011 (as compared to December 31, 2010) and strengthened at September 30, 2010 (as compared to December 31, 2009). In addition, the translation of the US$150 million Series B senior unsecured debentures issued on February 17, 2011 contributed to the year to date unrealized foreign exchange loss as the USD/CAD foreign exchange rate strengthened from the issue date of the debentures to September 30, 2011. The realized gain for the nine months ended September 30, 2011 was related to day-to-day US dollar denominated transactions.
Depletion and Depreciation
Depletion and depreciation for the three months ended September 30, 2011 increased to $63.4 million from $50.9 million for the same period in 2010. On a sales-unit basis, the provision for the current quarter was $12.56 per boe, as compared to $11.67 per boe for the same quarter in 2010.
Depletion and depreciation for the nine months ended September 30, 2011 increased to $176.5 million from $147.7 million for the same period in 2010. On a sales-unit basis, the provision for the first nine months of 2011 was $13.15 per boe, as compared to $12.24 per boe for the same period in 2010.
Income Taxes
For the nine months ended September 30, 2011, deferred income tax expense totaled $39.7 million, as compared to a recovery of $114.9 million for the nine months ended September 30, 2010. The decrease in the deferred income tax recovery is primarily due to the $109.8 million recovery in the second quarter of 2010 related to the difference between the deferred income tax asset and the cash paid for the acquisition of private entities.
As at September 30, 2011, net deferred income tax liability was $70.5 million (December 31, 2010 - $6.5 million). The increase relates to the additional liability recognized in the corporate acquisition in the current year of $24.5 million and the impact of accounting income net of adjustments due to decrease in rates and adjustments to opening tax pool balances.
Tax Pools
During 2010 and prior years, Baytex was organized as a mutual fund trust for Canadian income tax purposes. Partially as a result of tax deductions taken for distributions paid to unitholders in 2010 and prior years, no material Canadian cash tax was payable by the Trust, other than the Saskatchewan resource surcharge which is classified as a royalty expense under IFRS.
Following the conversion from a trust structure to a corporate legal form on December 31, 2010, Baytex will not be entitled to a deduction from Canadian taxable income for its distributions, nor will a deduction be available for future dividends. As such, it is likely that cash income tax expense attributable to our Canadian operations will be higher in future. Baytex has accumulated the Canadian and US tax pools as noted in the table below, which will be available to reduce the future taxable income. Our cash income tax liability is dependant upon many factors, including the prices at which we sell our production, available income tax deductions and the legislative environment in place during the taxation year. Based upon the current forward commodity price outlook, projected production and cost levels, and the proposed legislation on partnership deferral, Baytex expects to become liable for Canadian income taxes between 2012 and 2013. The income tax pools detailed below are deductible at various rates as prescribed by law.
Page 10 of 19
($ thousands) | September 30, 2011 | December 31, 2010 | ||||||
Canadian Tax Pools | ||||||||
Canadian oil and natural gas property expenditures | $ | 330,224 | $ | 271,741 | ||||
Canadian development expenditures | 332,132 | 292,500 | ||||||
Canadian exploration expenditures | 17,483 | 11,757 | ||||||
Undepreciated capital costs | 261,142 | 184,586 | ||||||
Non-capital losses | 769,922 | 775,727 | ||||||
Financing costs and other | 8,966 | 10,334 | ||||||
Total Canadian tax pools | $ | 1,719,869 | $ | 1,546,645 | ||||
US Tax Pools | ||||||||
Taxable depletion | $ | 172,367 | $ | 125,628 | ||||
Intangible drilling costs | 12,932 | 35,000 | ||||||
Tangibles | 12,434 | 3,634 | ||||||
Non-capital losses | 84,501 | 66,530 | ||||||
Total US tax pools | $ | 282,234 | $ | 230,792 |
Net Income
Net income for the three months ended September 30, 2011 was $51.8 million, as compared to $23.3 million for the same period in 2010. The increase in net income was primarily the result of a decrease in share-based compensation, an increase in gain on financial derivative and an increase in production volume coupled with a higher operating netback for the current period. This was partially offset by an increase in foreign exchange loss and increase in depletion and depreciation.
Net income for the nine months ended 2011 was $159.7 million, as compared to $210.3 million for the same period in 2010. The decrease in net income was primarily the result of a $109.8 million deferred income tax recovery in 2010 relating to the acquisition of private entities, which was partially mitigated by an increase in production volume coupled with a higher operating netback and lower share-based compensation expense for the current period.
Other Comprehensive Income
Revenues and expenses of foreign operations are translated to Canadian dollars using average foreign currency exchange rates for the period. Monetary assets and liabilities that form part of the net investment in the foreign operation are translated at the period-end foreign currency exchange rate. Gains or losses resulting from the translation are included in accumulated other comprehensive income (loss) in shareholders’/unitholders’ equity and are recognized in net income when there has been a disposal or partial disposal of the foreign operation.
Under IFRS, the Company has elected to deem cumulative currency translation differences as $nil at January 1, 2010. The $2.5 million balance of accumulated other comprehensive income at September 30, 2011 is the sum of a $10.3 million foreign currency translation loss incurred in 2010 and a $12.8 million foreign currency translation gain for the nine months ended September 30, 2011 as USD/CAD foreign exchange rates strengthened at September 30, 2011.
FUNDS FROM OPERATIONS, PAYOUT RATIO AND DIVIDENDS OR DISTRIBUTIONS
Funds from operations and payout ratio are non-GAAP measures. Funds from operations represents cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Payout ratio is calculated as cash dividends/distributions (net of participation in the Dividend Reinvestment Plan (“DRIP”)) divided by funds from operations. Baytex considers these to be key measures of performance as they demonstrate its ability to generate the cash flow necessary to fund dividends and capital investments.
Page 11 of 19
The following table reconciles cash flow from operating activities (a GAAP measure) to funds from operations (a non-GAAP measure):
Three Months Ended | Nine Months Ended | Year Ended | ||||||||||||||||||||||
($ thousands except for %) | September 30, 2011 | June 30, 2011 | September 30, 2010 | September 30, 2011 | September 30, 2010 | December 31, 2010 | ||||||||||||||||||
Cash flow from operating activities | $ | 148,678 | $ | 146,199 | $ | 137,142 | $ | 414,777 | $ | 353,112 | $ | 459,732 | ||||||||||||
Change in non-cash working capital | 1,758 | 2,206 | (19,627 | ) | 1,553 | (9,424 | ) | 13,399 | ||||||||||||||||
Asset retirement expenditures | 3,064 | 959 | 683 | 4,942 | 2,027 | 2,829 | ||||||||||||||||||
Financing costs | (10,383 | ) | (12,793 | ) | (8,830 | ) | (33,738 | ) | (25,887 | ) | (34,570 | ) | ||||||||||||
Accretion on asset retirement obligations | 1,558 | 1,516 | 1,473 | 4,558 | 4,331 | 5,862 | ||||||||||||||||||
Accretion on debentures and long-term debt | 150 | 146 | 113 | 418 | 335 | 426 | ||||||||||||||||||
Funds from operations | $ | 144,825 | $ | 138,233 | $ | 110,954 | $ | 392,510 | $ | 324,494 | $ | 447,678 | ||||||||||||
Cash distributions declared, net of DRIP | $ | 50,270 | $ | 52,764 | $ | 45,795 | $ | 155,035 | $ | 141,698 | $ | 189,824 | ||||||||||||
Payout ratio | 35 | % | 38 | % | 41 | % | 39 | % | 44 | % | 42 | % |
Baytex does not deduct capital expenditures when calculating the payout ratio. Due to the depleting nature of petroleum and natural gas assets, certain levels of capital expenditures are required to minimize production declines. In the petroleum and natural gas industry, due to the nature of reserve reporting, natural production declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Should the costs to explore for, develop or acquire petroleum and natural gas assets increase significantly, it is possible that Baytex would be required to reduce or eliminate its dividends in order to fund capital expenditures. There can be no certainty that Baytex will be able to maintain current production levels in future periods. Cash dividends declared, net of DRIP participation, of $50.3 million for the third quarter of 2011 were funded through funds from operations of $144.8 million.
The following table compares cash dividends or distributions declared (net of DRIP participation) to cash flow from operating activities and net income:
Three Months Ended | Nine Months Ended | Year Ended | ||||||||||||||||||||||
($ thousands) | September 30, 2011 | June 30, 2011 | September 30, 2010 | September 30, 2011 | September 30, 2010 | December 31, 2010 | ||||||||||||||||||
Cash flow from operating activities | $ | 148,678 | $ | 146,199 | $ | 137,142 | $ | 414,777 | $ | 353,112 | $ | 459,732 | ||||||||||||
Cash dividends or distributions declared, net of DRIP | 50,270 | 52,764 | 45,795 | 155,035 | 141,698 | 189,824 | ||||||||||||||||||
Excess of cash flow from operating activities over cash dividends or distributions declared, net of DRIP | $ | 98,408 | $ | 93,435 | $ | 91,347 | $ | 259,742 | $ | 211,414 | $ | 269,908 | ||||||||||||
Net income | $ | 51,839 | $ | 106,863 | $ | 23,319 | $ | 159,652 | $ | 210,260 | $ | 231,615 | ||||||||||||
Cash dividends or distributions declared, net of DRIP | 50,270 | 52,764 | 45,795 | 155,035 | 141,698 | 189,824 | ||||||||||||||||||
Excess (shortfall) of earnings over cash dividends or distributions declared, net of DRIP | $ | 1,569 | $ | 54,099 | $ | (22,476 | ) | $ | 4,617 | $ | 68,562 | $ | 41,791 |
It is Baytex’s long-term operating objective to substantially fund cash dividends and capital expenditures for exploration and development activities through funds from operations. Future production levels are highly dependent upon our success in exploiting our asset base and acquiring additional assets. The success of these activities, along with commodity prices realized, are the main factors influencing the sustainability of our cash dividends. During periods of lower commodity prices or periods of higher capital spending, it is possible that funds from operations will not be sufficient to fund both cash dividends and capital spending. In these instances, the cash shortfall may be funded through a combination of equity and debt financing.
For the three months ended September 30, 2011, the Company’s net income was in excess of cash dividends declared (net of DRIP participation) by $1.6 million, with net income reduced by $96.8 million for non-cash items. For the nine months ended September 30, 2011, the Company’s net income was in excess of cash dividends declared (net of DRIP participation) by $4.6 million, with net income reduced by $255.1 million for non-cash items. Non-cash items such as depletion and depreciation may not be fair indicators for the cost of maintaining our productive capacity as they are based on historical costs of assets and not the fair value of replacing those assets under current market conditions.
Page 12 of 19
LIQUIDITY AND CAPITAL RESOURCES
We regularly review our liquidity sources as well as our exposure to counterparties, and have concluded that our capital resources are sufficient to meet our on-going short, medium and long-term commitments. Specifically, we believe that our internally generated funds from operations, augmented by our hedging program and existing credit facilities, will provide sufficient liquidity to sustain our operations in the short, medium and long-term. Further, we believe that our counterparties currently have the financial capacities to honor outstanding obligations to us in the normal course of business. We periodically review the financial capacity of our counterparties and, in certain circumstances, we will seek enhanced credit protection from a counterparty.
($ thousands) | September 30, 2011 | December 31, 2010 | ||||||
Bank loan | $ | 368,184 | $ | 303,773 | ||||
Long-term debt (1) | 305,835 | 150,000 | ||||||
Working capital deficiency | 65,180 | 52,462 | ||||||
Total monetary debt | $ | 739,199 | $ | 506,235 |
(1) Principal amount of long-term debt.
At September 30, 2011, total monetary debt was $739.2 million, as compared to $506.2 million at December 31, 2010. Bank borrowings at September 30, 2011 were $368.2 million, as compared to total credit facilities of $700.0 million. Subsequent to the end of the third quarter, we entered into definitive agreements to sell certain primarily-undeveloped lands in Alberta and Saskatchewan for $47.1 million. The proceeds from these dispositions will be used to reduce the amount drawn on the credit facilities.
Our wholly-owned subsidiary, Baytex Energy Ltd. (“Baytex Energy”), has established credit facilities with a syndicate of chartered banks. On June 14, 2011, Baytex Energy reached agreement with its lending syndicate to amend the credit facilities to (i) increase the amount available under the facilities to $700 million (from $650 million), (ii) extend the revolving period from 364 days (with a one-year term out following the revolving period) to three years, which is extendible annually for a 1, 2 or 3 year period (subject to a maximum three-year term at any time), and (iii) change the structure of the facilities from reserves-based to covenant-based (with standard commercial covenants for facilities of this nature). The credit facilities do not require any mandatory principal payments during the three-year term. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or US funds and bear interest at the agent bank's prime lending rate, bankers' acceptance discount rates or London Interbank Offer Rates, plus applicable margins. The credit facilities are secured by a floating charge over all of Baytex Energy's assets and are guaranteed by us and certain of our material subsidiaries. The credit facilities do not include a term-out feature or a borrowing base restriction. In the event that Baytex Energy does not comply with covenants under the credit facilities, our ability to pay dividends to shareholders may be restricted. A copy of the amended and restated credit agreement which establishes the credit facilities is accessible on the SEDAR website at www.sedar.com (filed under the category "Material Document" on July 22, 2011).
Financing costs for the nine months ended September 30, 2011 include facility amendment fees of $2.2 million ($1.4 million for nine months ended September 30, 2010). The weighted average interest rate on the bank loan for nine months ended September 30, 2011 was 3.45% (3.94% for the year ended December 31, 2010 and 3.91% for the nine months ended September 30, 2010).
On February 17, 2011, Baytex issued US$150.0 million principal amount of Series B senior unsecured debentures bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. Net proceeds of this issue were used to repay a portion of the amount drawn in Canadian currency on Baytex Energy’s credit facilities. These debentures are unsecured and are subordinate to Baytex Energy’s credit facilities.
Pursuant to various agreements with our lenders, we are restricted from paying dividends to shareholders where the dividend would or could have a material adverse effect on us or our subsidiaries' ability to fulfill our respective obligations under the Series A or Series B senior unsecured debentures and Baytex Energy’s credit facilities.
Baytex believes that funds from operations, together with the existing credit facilities, will be sufficient to finance current operations, dividends to the shareholders and planned capital expenditures for the ensuing year. The timing of most of the capital expenditures is discretionary and there are no material long-term capital expenditure commitments. The level of dividend is also discretionary, and the Company has the ability to modify dividend levels should funds from operations be negatively impacted by factors such as reductions in commodity prices or production volumes.
Page 13 of 19
Capital Expenditures
Capital expenditures are summarized as follows:
Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
($ thousands) | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Land | $ | (463 | ) | $ | (1,115 | ) | $ | 4,088 | $ | 9,656 | ||||||
Seismic | 211 | 263 | 379 | 66 | ||||||||||||
Drilling and completion | 67,042 | 42,568 | 203,981 | 115,752 | ||||||||||||
Equipment | 33,632 | 17,841 | 87,404 | 46,822 | ||||||||||||
Other | (54 | ) | 2 | (17 | ) | (27 | ) | |||||||||
Total exploration and development | $ | 100,368 | $ | 59,559 | $ | 295,835 | $ | 172,269 | ||||||||
Acquisitions - Corporate | 22 | - | 118,693 | 40,314 | ||||||||||||
Acquisitions - Properties | 28,502 | 11,452 | 65,835 | 19,316 | ||||||||||||
Proceeds from divestitures | - | (18,137 | ) | - | (18,137 | ) | ||||||||||
Total Acquisitions and divestitures | 28,524 | (6,685 | ) | 184,528 | 41,493 | |||||||||||
Total oil and natural gas expenditures | 128,892 | 52,874 | 480,363 | 213,762 | ||||||||||||
Other plant and equipment, net | 591 | 6,715 | 1,416 | 13,447 | ||||||||||||
Total capital expenditures | $ | 129,483 | $ | 59,589 | $ | 481,779 | $ | 227,209 |
Shareholders’ Capital
On December 31, 2010, all of the outstanding trust units of the Trust were exchanged for common shares of Baytex on a one-for-one basis in connection with the Corporate Conversion.
Baytex is authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. Baytex establishes the rights and terms of preferred shares upon issuance. As at November 4, 2011, the Company had 117,342,527 common shares and no preferred shares issued and outstanding.
Contractual Obligations
Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s funds from operations on an ongoing manner. A significant portion of these obligations will be funded through funds from operations. These obligations as of September 30, 2011, and the expected timing of funding of these obligations, are noted in the table below.
($ thousands) | Total | Less than 1 year | 1-3 years | 3-5 years | Beyond 5 years | |||||||||||||||
Trade and other payables | $ | 221,960 | $ | 221,960 | $ | - | $ | - | $ | - | ||||||||||
Dividends payable to shareholders | 23,351 | 23,351 | - | - | - | |||||||||||||||
Bank loan (1) | 368,184 | - | 368,184 | - | - | |||||||||||||||
Long-term debt (2) | 305,835 | - | - | 150,000 | 155,835 | |||||||||||||||
Operating leases | 51,581 | 5,774 | 12,311 | 11,766 | 21,730 | |||||||||||||||
Processing and transportation agreements | 2,206 | 1,610 | 594 | 2 | - | |||||||||||||||
Total | $ | 973,117 | $ | 252,695 | $ | 381,089 | $ | 161,768 | $ | 177,565 |
(1) The bank loan is a three-year covenant-based revolving loan that is extendible annually for a one, two or three year period (subject to a maximum three-year term at any time). Unless extended, the revolving period will end on June 14, 2014 with all amounts to be re-paid on such date. |
(2) Principal amount of instruments. |
Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives. Programs to abandon and reclaim them are undertaken regularly in accordance with applicable legislative requirements.
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Baytex is exposed to a number of financial risks, including market risk, liquidity risk and credit risk. Market risk is the risk that the fair value of future cash flows will fluctuate due to movements in market prices, and is comprised of foreign currency risk, interest rate risk and commodity price risk. Market risk is managed by Baytex through a series of derivative contracts intended to manage the volatility of its operating cash flow. Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Credit risk is the risk that a counterparty to a financial asset will default resulting in the Company incurring a loss. Baytex manages credit risk by entering into sales contracts with creditworthy entities and reviewing its exposure to individual entities on a regular basis.
Page 14 of 19
A summary of the risk management contracts in place as at September 30, 2011 and the accounting treatment of the Company’s financial instruments are disclosed in note 22 to the consolidated financial statements as at and for the three months and nine months ended September 30, 2011.
QUARTERLY FINANCIAL INFORMATION
2011 | 2010 | 2009 | |||||||||||||||||||||||||||||||
($ thousands, except per common share or trust unit amounts) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | |||||||||||||||||||||||||
Gross revenues | 313,787 | 336,899 | 290,315 | 263,497 | 238,276 | 241,581 | 261,782 | 237,962 | |||||||||||||||||||||||||
Net income | 51,839 | 106,863 | 950 | 21,356 | 23,319 | 157,440 | 29,501 | 27,956 | |||||||||||||||||||||||||
Per common share or trust unit - basic | 0.45 | 0.92 | 0.01 | 0.19 | 0.21 | 1.42 | 0.27 | 0.26 | |||||||||||||||||||||||||
Per common share or trust unit - diluted | 0.44 | 0.90 | 0.01 | 0.18 | 0.20 | 1.38 | 0.26 | 0.25 |
(1) Financial information for 2011 and 2010 has been prepared in accordance with IFRS and financial information for 2009 has been prepared in accordance with the previous GAAP. |
CHANGES IN ACCOUNTING POLICIES
Adoption of International Financial Reporting Standards
IFRS replaces GAAP in Canada for financial periods beginning on January 1, 2011. At the transition date, publicly accountable enterprises are required to prepare financial statements in accordance with IFRS. The adoption date of January 1, 2011 requires the restatement, for comparative purposes, of 2010 amounts reported by Baytex, including the opening statement of financial position as at January 1, 2010.
Our IFRS financial statements for the year ending December 31, 2011 must use the standards that are in effect on December 31, 2011, and therefore our consolidated financial statements have been prepared using the standards expected to be effective at the end of 2011. IFRS accounting policies will only be finalized when our first annual IFRS financial statements are prepared for the year ending December 31, 2011 and as a result, our consolidated financial statements for the three months and nine months ended September 30, 2011 are subject to change. Reconciliations to IFRS from the previously published consolidated financial statements, prepared in accordance with previous GAAP are shown in note 25 to the consolidated financial statements. The accounting policies described in note 3 to the consolidated financial statements set out those policies that have been applied retrospectively and consistently in preparing the consolidated financial statements, except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1 (as disclosed in note 25 to the consolidated financial statements).
Page 15 of 19
The following table reconciles Baytex’s 2010 previous GAAP results to IFRS for the three months and nine months ended September 30, 2010.
2010 | ||||||||
($ thousands) | Three months ended September 30 | Nine months ended September 30 | ||||||
Net income – Previous GAAP | $ | 35,061 | $ | 120,042 | ||||
Exploration and evaluation | (6,158 | ) | (18,163 | ) | ||||
Depletion and depreciation | 17,169 | 51,558 | ||||||
Gain on oil and gas properties | 16,209 | 16,209 | ||||||
Accretion on asset retirement obligation | (320 | ) | (970 | ) | ||||
Unit-based compensation | (33,121 | ) | (56,335 | ) | ||||
Conversion feature of convertible debentures | (1,622 | ) | (3,866 | ) | ||||
Deferred income tax | (3,528 | ) | 102,490 | |||||
Other | (371 | ) | (705 | ) | ||||
Net income - IFRS | $ | 23,319 | $ | 210,260 |
2010 | ||||||||
($ thousands) | Three months ended September 30 | Nine months ended September 30 | ||||||
Funds from operations – Previous GAAP | $ | 112,786 | $ | 329,407 | ||||
Exploration and evaluation | (1,615 | ) | (4,476 | ) | ||||
Other | (217 | ) | (437 | ) | ||||
Funds from operations - IFRS | $ | 110,954 | $ | 324,494 |
Listed below is a summary of the significant effects of the transition from previous GAAP to IFRS:
Exploration and Evaluation
Under previous GAAP, petroleum and natural gas properties included certain exploration and evaluation expenditures incurred within a country-by-country cost centre. Under IFRS, such exploration and evaluation expenditures are recognized as tangible or intangible based on their nature and subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are expensed.
Exploration and evaluation assets at January 1, 2010 were deemed to be $124.6 million, being the amount recorded as the undeveloped land balance under previous GAAP. This has resulted in the reclassification from property, plant and equipment to intangible exploration assets of $124.6 million in the opening IFRS statement of financial position.
During the three months ended September 30, 2010, Baytex expensed $4.6 million of exploration and evaluation assets related to lease expiries and $1.6 million in direct exploration costs. For the nine months ended September 30, 2010, Baytex had exploration and evaluation capital expenditures of $30.0 million, corporate acquisitions of $2.5 million, transfers to oil and gas properties of $22.0 million, transfers to expense related to lease expiries of $13.7 million and a decrease due to foreign currency translation of $1.1 million. For the nine months ended September 30, 2010, Baytex expensed $13.7 million of exploration and evaluation assets related to lease expiries and $4.5 million in direct exploration costs.
Depletion
Upon transition to IFRS, the Company adopted a policy of depleting oil and natural gas properties on a “units of production” basis over proved plus probable reserves on an area basis rather than a cost pool basis under previous GAAP. The depletion policy under previous GAAP was units of production over proved reserves on a country basis.
There is no impact to depletion on transition to IFRS at January 1, 2010. For the three months ended September 30, 2010, this change to IFRS resulted in a decrease in depletion expense of $18.0 million with a corresponding increase in oil and natural gas properties. For the nine months ended September 30, 2010, this change to IFRS resulted in a decrease in depletion expense of $54.3 million with a corresponding increase in oil and natural gas properties.
Page 16 of 19
Divestiture of Oil and Gas Assets
Previous GAAP utilized the full cost accounting, whereby gains and losses were not recognized upon the divestiture of oil and gas assets unless such a divestiture would alter the rate of depletion by 20% or more. Under IFRS, gains and losses are recognized based on the difference between the net proceeds from the divestiture and the carrying value of the asset disposed. For the three months and nine months ended September 30, 2010, a gain of $16.2 million was recognized relating to a divestiture of oil and gas assets.
Impairment of Property, Plant and Equipment (“PP&E”) Assets
Under IFRS, impairment of PP&E must be calculated at a more detailed level than what was required under previous GAAP. Impairment calculations are performed at the cash generating unit (“CGU”) level using the higher of its fair value less costs to sell and its value in use. Baytex uses discounted estimated cash flows from proved plus probable reserves for impairment tests of PP&E. Under previous GAAP, estimated future net cash flows used to assess impairments were not discounted. As such, impairment losses may be recognized earlier under IFRS than under previous GAAP. Impairment losses are reversed under IFRS when there is an increase in the recoverable amount.
Baytex has allocated the PP&E amount recognized under previous GAAP as at January 1, 2010 to the assets at a CGU level using reserve values calculated using the discounted net cash flows. There is no change in the overall net book value of our PP&E as there were no impairments upon transition to IFRS at January 1, 2010.
Asset Retirement Obligations
Under IFRS, Baytex uses a risk free interest rate to discount the estimated fair value of its asset retirement obligations associated with the related oil and natural gas properties. Under previous GAAP, the Company used a credit-adjusted risk free interest rate. A lower discount rate under IFRS will increase the asset retirement obligations. In addition, under IFRS the asset retirement obligations are measured using the best estimate of the expenditure to be incurred and current discount rates at each remeasurement date with the corresponding adjustment to the cost of the related oil and natural gas properties. Existing liabilities under previous GAAP are not remeasured using current discount rates.
Under previous GAAP, the Company’s asset retirement obligations were recorded using the credit-adjusted risk free rate of 8.0%. Under IFRS, the Company’s asset retirement obligations are recorded using the risk free rate of 3.5% at September 30, 2010 (4.0% at January 1, 2010). Under IFRS, an additional liability of $87.3 million was charged to deficit at January 1, 2010.
For the three months ended September 30, 2010, the $1.2 million accretion expense on asset retirement obligations under previous GAAP was reclassified to finance costs and an additional accretion expense on asset retirement obligations of $0.3 million has been recognized in net income under IFRS. For the nine months ended September 30, 2010, $3.4 million was reclassified to finance costs and an additional accretion expense of $1.0 million has been recognized.
Unit-based Compensation
Under previous GAAP, the obligation associated with the Unit Rights Plan is considered to be equity-based and the related unit-based compensation was calculated using the binomial-lattice model to estimate the fair value of the outstanding unit rights at grant date. The exercise of unit rights was recorded as an increase in unitholders’ capital with a corresponding reduction in contributed surplus.
Under IFRS, prior to the conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability is remeasured at each reporting date and at settlement date. Any changes in fair value are recognized in net income for the period. For periods prior to the conversion to a corporation, remeasuring the fair value of the obligation each reporting period will increase or decrease the unit-based payment liability, unitholders’ capital and compensation expense recognized. Upon conversion to a corporation, the outstanding Unit Rights Plan was modified to become the new Share Rights Plan, effectively changing the related classification from liability-settled to equity-settled. The expense recognized from the date of the plan modification over the remainder of the vesting period is determined based on the fair value of the reclassified unit rights at the date of the modification. Upon transition of IFRS at January 1, 2010, an additional unit-based payment liability of $91.6 million and a decrease of $20.4 million in contributed surplus resulted in a corresponding $71.2 million charge to deficit.
Under IFRS, in addition to the January 1, 2010 adjustments discussed above, at September 30, 2010 the remeasurement of the liability at reporting date and at settlement date resulted in the recognition of an additional unit-based compensation expense of $56.3 million, with a corresponding decrease of $0.6 million in contributed surplus, an increase of $30.3 million in shareholders’/unitholders’ equity and an increase of $26.6 million in unit-based payment liability (three months ended September 30, 2010 - $33.1 million additional unit-based compensation expense).
Conversion Feature of Convertible Debentures
Under previous GAAP, the convertible debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders’ or shareholders’ equity. The debt portion accreted up to the principal balance at maturity. If the debentures were converted to trust units, a portion of the value of the conversion feature under unitholders’ equity was reclassified to unitholders’ capital along with principal amounts converted.
Under IFRS, the conversion feature of the convertible debentures has been classified as a financial derivative liability. The financial derivative liability requires a fair value method of accounting and changes in the fair value of the derivative liability are recognized in the statements of income and comprehensive income. If the debentures were converted to trust units, the fair value of the conversion feature under financial derivative liability was reclassified to unitholders’/shareholders’ capital along with the principal amounts converted. The impact on adoption to IFRS at January 1, 2010 was an additional liability of $7.4 million, an increase of $33.4 million in unitholders’ capital with a corresponding $40.4 million charge to deficit and a decrease of $0.4 million in the conversion feature of convertible debentures.
Under IFRS, for the nine months ended September 30, 2010, the increase in unitholders’/shareholders’ equity of $3.3 million and the increase of $0.1 million in conversion feature of convertible debentures had a corresponding increase in the $0.4 million liability recorded at January 1, 2010 and a $3.8 million decrease in gain on financial derivatives in net income (three months ended September 30, 2010 - $1.6 million decrease in gain on financial derivatives in net income).
Page 17 of 19
Accumulated Other Comprehensive Loss
Under previous GAAP, amounts are composed entirely of currency translation adjustments on self-sustaining foreign operations. Under IFRS, the Company has elected to deem cumulative currency translation differences as $nil at January 1, 2010. At January 1, 2010, this has resulted in an decrease in accumulated other comprehensive loss with a corresponding increase in deficit of $3.9 million.
Deferred Income Taxes
Under IFRS, deferred income taxes are required to be presented as non-current. Upon transition to IFRS, the Company recognized a $27.6 million reduction in the net deferred income tax liability entirely resulting from the tax impact of the adjustments from previous GAAP to IFRS with a decrease to deficit of $25.8 million and a decrease to unitholders’ capital of $1.8 million.
In May 2010, Baytex acquired several private entities to be used in its internal financing structure. Under previous GAAP, the excess of amounts assigned to the acquired assets over the consideration paid is classified as a deferred credit. Under IFRS, the deferred credit is derecognized through net income as a deferred income tax recovery. For the nine months ended September 30, 2010, deferred income tax recovery of $109.8 million was recorded in net income for amounts previously recognized as a deferred credit (three months ended September 30, 2010, $nil was recorded in net income for amounts previously recognized as a deferred credit).
For the three months ended September 30, 2010, the application of the IFRS adjustments resulted in a $3.6 million increase to the Company’s deferred income tax expense. For the nine months ended September 30, 2010, the transition to IFRS resulted in a $102.5 million increase to the Company’s deferred income tax recovery. The increase in deferred income tax recovery is due to the deferred credit derecognized through net income under IFRS.
Under IFRS, taxable and deductible temporary differences related to the legal entity of the Trust must be measured using the highest marginal personal tax rate of 39%, as opposed to the corporate tax rates used under previous GAAP, resulting in an increase to the deferred income tax asset of $5.1 million at January 1, 2010. Upon conversion to a dividend paying corporation on December 31, 2010, the total deferred income tax asset related to the Trust was adjusted to the corporate tax rate of approximately 25% and derecognized through net income on December 31, 2010.
Page 18 of 19
FORWARD-LOOKING STATEMENTS
In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.
Specifically, this document contains forward-looking statements relating to: crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; our business strategies, plans and objectives; our ability to fund our capital expenditures and dividends on our common shares from funds from operations; our ability to utilize our tax pools to reduce or potentially eliminate our taxable income for the initial period post-conversion; the timing of payment of Canadian income taxes; the sufficiency of our capital resources to meet our on-going short, medium and long-term commitments; the financial capacity of counterparties to honor outstanding obligations to us in the normal course of business; funding sources for our cash dividends and capital program; the timing of funding our financial obligations; the existence, operation, and strategy of our risk management program; the impact of the adoption of new accounting standards on our financial results; and the impact of the adoption of IFRS on our financial position and results of operations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. The reader is cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: fluctuations in market prices for petroleum and natural gas; fluctuations in foreign exchange or interest rates; general economic, market and business conditions; stock market volatility and market valuations; changes in income tax laws; industry capacity; geological, technical, drilling and processing problems and other difficulties in producing petroleum and natural gas reserves; uncertainties associated with estimating petroleum and natural gas reserves; liabilities inherent in oil and natural gas operations; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; risks associated with oil and natural gas operations; changes in royalty rates and incentive programs relating to the oil and natural gas industry; changes in environmental and other regulations; incorrect assessments of the value of acquisitions; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2010, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex 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 law.
Page 19 of 19