MANAGEMENT’S DISCUSSION AND ANALYSIS
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the year ended December 31, 2010. This information is provided as of March 15, 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. This MD&A should be read in conjunction with the Company’s 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. The Company’s Annual Information Form for the year ended December 31, 2010, will be filed in late March 2011. These documents and additional information about Baytex are available on SEDAR at www.sedar.com. All amounts are in Canadian dollars, unless otherwise stated and all tabular amounts are in thousands of Canadian dollars, except for percentage 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 dividend paying corporation, the Company’s business objectives and strategies remain unchanged and all officers and directors remain 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. This will be maintained by investing capital to enhance the value of Baytex’s assets, operating Baytex’s producing oil and gas properties in a low cost manner to maximize the recovery of reserves, and paying 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 as well as by the periodic acquisition of undeveloped and producing oil and gas properties. Baytex will also seek to acquire oil and natural gas producing properties and primarily participate in development activities that are generally considered to be of a low risk nature in the oil and gas industry. 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 (the “TSX”) and the New York Stock Exchange (the “NYSE”) 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, distributions were paid to unitholders.
NON-GAAP FINANCIAL MEASURES
Baytex evaluates performance based on net income and funds from operations. Funds from operations is not a measurement based on Generally Accepted Accounting Principles in Canada (“Canadian GAAP”), but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash flow from operating activities before changes in non-cash working capital and other operating items. The Company’s determination of funds from operations may not be comparable with the calculation of similar measures for other issuers. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. The most directly comparable measures calculated in accordance with Canadian GAAP are 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 Distributions or Dividends”.
Total monetary debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as future income tax assets or liabilities and unrealized gains or losses on financial derivative contracts)), the principal amount of long-term debt and the balance sheet amount of the convertible debentures and long-term bank loan.
Operating netback is a non-GAAP measure commonly used in the oil and gas industry. This measurement helps management and investors to evaluate the specific operating performance by product. There is no standardized measure of operating netback and therefore operating netback as presented may not be comparable to similar measures presented by other issuers. Operating netback is equal to product revenue less royalties, operating expenses and transportation expenses divided by barrels of oil equivalent.
OUTLOOK – ECONOMIC ENVIRONMENT
In 2010, the energy and commodity markets continued to improve. The spot price for West Texas Intermediate (“WTI”) at December 31, 2010 was US$91.38/bbl, up from US$79.36/bbl at December 31, 2009 showing continued strength in crude oil prices in the commodity marketplace. Going forward, Baytex continues to be focused on the following objectives: preserving balance sheet strength and liquidity, maintaining and, where possible, profitably expanding its productive capacity and delivering a sustainable dividend to its shareholders.
2010 OVERVIEW
Baytex is a Calgary, Alberta based conventional oil and gas corporation engaged in the acquisition, development and production of petroleum and natural gas in the Western Canadian Sedimentary Basin and the United States.
Our business has been to increase production levels through investing approximately half of our internally generated funds from operations in Exploration and Development (“E&D”) activities while distributing most of the balance of our funds from operations to holders of our trust units. Over our life as a trust, we have grown our reserve base and added to production levels through E&D activities complimented by strategic acquisitions.
During 2010, Baytex executed a successful capital program, resulting in the replacement of 274% of production (on a proved plus probable basis) by reinvesting 52% of our internally generated funds from operations into E&D activities. When acquisitions are included, Baytex replaced 297% of production.
As at December 31, 2010, we had a reserve base of 229 million boe on a proved plus probable basis. During the year ended December 31, 2010, our production averaged 44,341 boe/d, primarily from Canada.
On May 26, 2010, we closed the acquisition of a private entity with heavy oil assets in the Lloydminster area of Saskatchewan for total net consideration of $40.9 million, adding approximately 900 bbl/d of oil production at accretive metrics.
In the second quarter of 2010, Baytex expanded our Bakken/Three Forks position in the United States to approximately 124,000 net acres, including the addition of high working interest lands in Williams County, North Dakota.
In 2010, we conducted a number of successful thermal development projects employing technology to create greater production rates, increased recovery and stronger capital efficiencies.
RESULTS OF OPERATIONS
Production
| | | Years Ended December 31 | |
| | | 2010 | | | 2009 | | | Change | |
| Daily Production | | | | | | | | | |
| Light oil and NGL (bbl/d) | | | 6,539 | | | | 6,937 | | | | (6 | %) |
Heavy oil (bbl/d)(1) | | | 28,585 | | | | 24,678 | | | | 16 | % |
| Natural gas (mmcf/d) | | | 55.3 | | | | 58.6 | | | | (6 | %) |
| Total production (boe/d) | | | 44,341 | | | | 41,382 | | | | 7 | % |
| Production Mix | | | | | | | | | | | | |
| Light oil and NGL | | | 15 | % | | | 17 | % | | | | |
| Heavy oil | | | 64 | % | | | 60 | % | | | | |
| Natural gas | | | 21 | % | | | 23 | % | | | | |
| (1) | Heavy oil sales volumes may differ from reported production volumes due to changes to the Company’s heavy oil inventory. For the year ended December 31, 2010, heavy oil sales volumes were 36 bbl/d lower than production volumes (year ended December 31, 2009 – 91 bbl/d lower). |
Production for the year ended December 31, 2010 totaled 44,341 boe/d, as compared to 41,382 boe/d for the same period in 2009. Light oil and natural gas liquids (“NGL”) production for the year ended December 31, 2010 decreased by 6% to 6,539 bbl/d from 6,937 bbl/d in the same period last year due to production declines in conventional fields in Alberta and British Columbia, partially offset by increasing production from light oil resource plays. Heavy oil production for the year ended December 31, 2010 increased by 16% to 28,585 bbl/d from 24,678 bbl/d in the same period last year primarily due to increased production from development programs and, to a lesser extent, the acquisition of producing assets. Natural gas production decreased by 6% to 55.3 mmcf/d for the year ended December 31, 2010, as compared to 58.6 mmcf/d for the same period last year primarily due to natural declines as we focused our drilling effort on our oil portfolio.
Commodity Prices
Crude Oil
For the year ended December 31, 2010, the price of WTI fluctuated between a low of US$68.01/bbl and a high of US$92.19/bbl, as global markets showed sustained signs of recovery from the largest economic downturn since the Great Depression of the 1930s. As concerns over a “double-dip” United States recession began to fade, aided by the United States Federal Reserve’s announced second round of quantitative easing in November 2010, and the European Central Bank intervention in the emerging fiscal crises of some smaller members, markets refocused on the global recovery and renewed growth potential. Oil prices were buoyed by this improving economic climate and evidence of significant third and fourth quarter petroleum demand growth from China and other emerging economies. As a result, the average prompt WTI price in the year ended December 31, 2010 increased 29% to US$79.53/bbl, from US$61.80/bbl in year ended December 31, 2009.
The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 18% in the year ended December 31, 2010, compared to 16% in year ended December 31, 2009. This increased WCS discount was due, in large part, to transportation constraints resulting from service disruptions on key oil export pipelines, which temporarily curtailed oil shipments to United States mid-continent refineries and resulted in wider price differentials for all Canadian crude oil grades for September and October 2010 production. During the fourth quarter, these pipelines were repaired and deliveries resumed.
Natural Gas
For the year ended December 31, 2010, AECO natural gas prices averaged $4.13/mcf, which was essentially unchanged from 2009 ($4.14/mcf). This was due to continued United States natural gas production increases and high natural gas storage levels. Canadian natural gas prices were further hindered by the increasing value of the Canadian dollar in 2010 versus the U.S. dollar during the year.
| | Years Ended December 31 | |
| | | 2010 | | | 2009 | | | Change | |
| Benchmark Averages | | | | | | | | | |
WTI oil (US$/bbl)(1) | | $ | 79.53 | | | $ | 61.80 | | | | 29 | % |
WCS heavy oil (US$/bbl)(2) | | $ | 65.30 | | | $ | 52.14 | | | | 25 | % |
Heavy oil differential(3) | | | (18 | %) | | | (16 | %) | | | | |
| USD/CAD average exchange rate | | | 0.9708 | | | | 0.8760 | | | | 11 | % |
| Edmonton par oil ($/bbl) | | $ | 77.81 | | | $ | 66.20 | | | | 18 | % |
AECO natural gas price ($/mcf)(4) | | $ | 4.13 | | | $ | 4.14 | | | | – | % |
Baytex Average Sales Prices(6) | | | | | | | | | | | | |
| Light oil and NGL ($/bbl) | | $ | 65.90 | | | $ | 54.25 | | | | 21 | % |
Heavy oil ($/bbl)(5) | | $ | 60.08 | | | $ | 55.01 | | | | 9 | % |
| Physical forward sales contracts loss ($/bbl) | | | (0.68 | ) | | | (5.13 | ) | | | | |
| Heavy oil, net ($/bbl) | | $ | 59.40 | | | $ | 49.88 | | | | 19 | % |
| Total oil and NGL, net ($/bbl) | | $ | 60.61 | | | $ | 50.85 | | | | 19 | % |
Natural gas ($/mcf)(6) | | $ | 4.22 | | | $ | 4.09 | | | | 3 | % |
| Physical forward sales contracts gain ($/mcf) | | | 0.10 | | | | 0.26 | | | | | |
| Natural gas, net ($/mcf) | | $ | 4.32 | | | $ | 4.35 | | | | (1 | %) |
| Summary | | | | | | | | | | | | |
Weighted average ($/boe)(6) | | $ | 53.75 | | | $ | 48.23 | | | | 11 | % |
| Physical forward sales contracts loss ($/boe) | | | (0.36 | ) | | | (3.23 | ) | | | | |
| Weighted average, net ($/boe) | | $ | 53.39 | | | $ | 45.00 | | | | 19 | % |
| (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 pricing information in the table excludes the impact of financial derivative contracts. |
For the year ended December 31, 2010, Baytex’s average sales price for light oil and NGL was $65.90/bbl, up 21% from $54.25/bbl in the year ended December 31, 2009. Baytex’s realized heavy oil price during the year of 2010, prior to physical forward sales contracts, was $60.08/bbl, or 89% of WCS. This compares to a realized heavy oil price in year ended December 31, 2009, prior to physical forward sales contracts, of $55.01/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 year ended December 31, 2010, was $59.40/bbl, up 19% from $49.88/bbl in the year ended December 31, 2009. Baytex’s realized natural gas price for the year ended December 31, 2010 was $4.22/mcf, prior to physical forward sales contracts, and $4.32/mcf inclusive of physical forward sales contracts (year ended December 31, 2009 – $4.09/mcf prior to, and $4.35/mcf inclusive of, physical forward sales contracts).
Revenue
| | | Years Ended December 31 | |
| ($ thousands except for %) | | 2010 | | | 2009 | | | Change | |
| Oil revenue | | | | | | | | | |
| Light oil and NGL | | $ | 157,603 | | | $ | 137,379 | | | | 15 | % |
| Heavy oil | | | 618,969 | | | | 447,674 | | | | 38 | % |
| Total oil revenue | | | 776,572 | | | | 585,053 | | | | 33 | % |
| Natural gas revenue | | | 87,116 | | | | 93,918 | | | | (7 | %) |
| Total oil and gas revenue | | | 863,688 | | | | 678,971 | | | | 27 | % |
| Sales of heavy oil blending diluent | | | 141,448 | | | | 110,772 | | | | 28 | % |
| Total petroleum and natural gas sales | | $ | 1,005,136 | | | $ | 789,743 | | | | 27 | % |
For the year ended December 31, 2010, petroleum and natural gas sales increased 27% to $1,005.1 million from $789.7 million for the same period in 2009. During this period, the change was driven by a 38% increase in heavy oil revenues, which was comprised of a 19% increase in realized price and a 16% increase in sales volume compared to the year ended December 31, 2009.
Royalties
| | | Years Ended December 31 | |
| ($ thousands except for % and per boe) | | 2010 | | | 2009 | | | Change | |
| Royalties | | $ | 162,332 | | | $ | 130,705 | | | | 24 | % |
| Royalty rates: | | | | | | | | | | | | |
| Light oil, NGL and natural gas | | | 20.5 | % | | | 20.5 | % | | | | |
| Heavy oil | | | 18.2 | % | | | 18.7 | % | | | | |
Average royalty rates(1) | | | 18.8 | % | | | 19.3 | % | | | | |
| Royalty expenses per boe | | $ | 10.04 | | | $ | 8.67 | | | | 16 | % |
| (1) | Average royalty rate excludes sales of heavy oil blending diluents and the effects of financial derivative contracts. |
Total royalties for the year ended December 31, 2010 increased 24% to $162.3 million from $130.7 million in the year ended December 31, 2009 as petroleum and natural gas sales increased 27%. Total royalties for the year ended December 31, 2010 averaged 18.8% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 19.3% for the same period in 2009.
Certain additional credits earned under the Alberta Royalty Drilling Credit program, which are based on drilling activity and drilling depths, are recorded as a reduction to capital expenditures, rather than as a reduction in royalties.
Financial Derivative Contracts
| | | Years Ended December 31 | |
| ($ thousands) | | 2010 | | | 2009 | | | Change | |
Realized gain on financial derivative contracts(1) | | | | | | | | | |
| Crude oil | | $ | 7,609 | | | $ | 62,076 | | | $ | (54,467 | ) |
| Natural gas | | | 11,322 | | | | 3,565 | | | | 7,757 | |
| Foreign currency | | | 28,119 | | | | 15,177 | | | | 12,942 | |
| Interest rate | | | 1,079 | | | | – | | | | 1,079 | |
| Total | | $ | 48,129 | | | $ | 80,818 | | | $ | (32,689 | ) |
Unrealized gain (loss) on financial derivative contracts(2) | | | | | | | | | | | | |
| Crude oil | | $ | (17,546 | ) | | $ | (77,093 | ) | | $ | 59,547 | |
| Natural gas | | | (641 | ) | | | (1,142 | ) | | | 501 | |
| Foreign currency | | | (9,261 | ) | | | 23,804 | | | | (33,065 | ) |
| Interest rate | | | (10,746 | ) | | | (379 | ) | | | (10,367 | ) |
| Total | | $ | (38,194 | ) | | $ | (54,810 | ) | | $ | 16,616 | |
| Total gain (loss) on financial derivative contracts | | | | | | | | | | | | |
| Crude oil | | $ | (9,937 | ) | | $ | (15,017 | ) | | $ | 5,080 | |
| Natural gas | | | 10,681 | | | | 2,423 | | | | 8,258 | |
| Foreign currency | | | 18,858 | | | | 38,981 | | | | (20,123 | ) |
| Interest rate | | | (9,667 | ) | | | (379 | ) | | | (9,288 | ) |
| Total | | $ | 9,935 | | | $ | 26,008 | | | $ | (16,073 | ) |
| (1) | Realized gain on financial derivative contracts represents actual cash settlement or receipts under the financial derivative contracts. |
| (2) | Unrealized gain (loss) on financial derivative contracts represents the change in fair value of the financial derivative contracts during the period. |
The total gain on financial derivative contracts for the year ended December 31, 2010 was $9.9 million, as compared to a gain of $26.0 million in the year ended December 31, 2009. This includes realized gains of $48.1 million and unrealized mark-to-market losses of $38.2 million for the year ended December 31, 2010, as compared to $80.8 million in realized gains and $54.8 million in unrealized mark-to-market losses for the same period in 2009. The realized gain of $48.1 million for the year ended December 31, 2010 is due to the settlement of gains on favorable foreign currency and commodity derivative contracts. The unrealized mark-to-market losses of $38.2 million for the year ended December 31, 2010 is due to settlement of previously unrealized gains from foreign currency swaps and commodity derivatives and a decrease in floating interest rates in the year ended December 31, 2010 as compared to December 31, 2009.
Details of the risk management contracts in place as at December 31, 2010, and the accounting treatment of the Company’s financial instruments are disclosed in note 17 to the consolidated financial statements as at and for the year ended December 31, 2010.
Operating Expenses
| | | Years Ended December 31 | |
| ($ thousands except for % and per boe) | | 2010 | | | 2009 | | | Change | |
| Operating expenses | | $ | 171,740 | | | $ | 163,183 | | | | 5 | % |
| Operating expenses per boe | | $ | 10.62 | | | $ | 10.83 | | | | (2 | %) |
Operating expenses for the year ended December 31, 2010 increased to $171.7 million from $163.2 million for the same period of 2009 due to an increase in production volumes. Operating expenses were $10.62 per boe for the year ended December 31, 2010, as compared to $10.83 per boe for the same period in 2009. For the year ended December 31, 2010, operating expenses were $10.66 per boe of light oil, NGL and natural gas and $10.60 per barrel of heavy oil, as compared to $11.70 and $10.24, respectively, for the year ended December 31, 2009.
Transportation and Blending Expenses
| | | Years Ended December 31 | |
| ($ thousands except for % and per boe) | | 2010 | | | 2009 | | | Change | |
| Blending expenses | | $ | 141,448 | | | $ | 110,772 | | | | 28 | % |
Transportation expenses(1) | | | 47,143 | | | | 48,582 | | | | (3 | %) |
| Total transportation and blending expenses | | $ | 188,591 | | | $ | 159,354 | | | | 18 | % |
Transportation expense per boe(1) | | $ | 2.92 | | | $ | 3.22 | | | | (9 | %) |
| (1) | Transportation expenses per boe are before the purchase of blending diluent. |
Transportation and blending expenses for year ended December 31, 2010, were $188.6 million, as compared to $159.4 million for the year ended December 31, 2009.
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 year ended December 31, 2010, the blending cost was $141.4 million for the purchase of 4,557 bbl/d of condensate at $85.05 per barrel, as compared to $110.8 million for the purchase of 4,240 bbl/d at $71.58 per barrel for the same period last year. The cost of blending diluent is effectively recovered in the sale price of a blended product.
Transportation expenses before blending costs were $2.92 per boe for the year ended December 31, 2010, as compared to $3.22 per boe for the same period of 2009. Transportation expenses were $0.85 per boe of light oil, NGL and natural gas and $4.05 per barrel of heavy oil in 2010, as compared to $0.79 and $4.88, respectively, for the same period in 2009. The decrease in transportation cost per barrel of heavy oil was primarily attributable to the reduced use of long-haul trucking at Seal.
Operating Netback
| | | Years Ended December 31 | |
| ($ per boe except for % and volume) | | 2010 | | | 2009 | | | Change | |
| Sales volume (boe/d) | | | 44,305 | | | | 41,291 | | | | 7 | % |
Operating netback(1): | | | | | | | | | | | | |
Sales price(2) | | $ | 53.39 | | | $ | 45.00 | | | | 19 | % |
| Less: | | | | | | | | | | | | |
| Royalties | | | 10.04 | | | | 8.67 | | | | 16 | % |
| Operating expenses | | | 10.62 | | | | 10.83 | | | | (2 | %) |
| Transportation expenses | | | 2.92 | | | | 3.22 | | | | (9 | %) |
| Operating netback before financial derivative contracts | | $ | 29.81 | | | $ | 22.28 | | | | 34 | % |
Financial derivative contract gains(3) | | | 2.98 | | | | 5.36 | | | | (44 | %) |
| Operating netback after financial derivative contracts | | $ | 32.79 | | | $ | 27.64 | | | | 19 | % |
| (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 derivative contracts reflect realized financial derivative contract gains (losses) only. |
General and Administrative Expenses
| | | Years Ended December 31 | |
| ($ thousands except for % and per boe) | | 2010 | | | 2009 | | | Change | |
| General and administrative expenses | | $ | 39,774 | | | $ | 35,006 | | | | 14 | % |
| General and administrative expenses per boe | | $ | 2.46 | | | $ | 2.32 | | | | 6 | % |
General and administrative expenses for the year ended December 31, 2010, increased to $39.8 million from $35.0 million for the same period in 2009. This increase consists of costs relating to our Income Tracking Unit Plan of $1.9 million, $1.2 million in tax indemnification payments relating to our Trust Unit Rights Incentive Plan (compared to $3.4 million in the year ended December 31, 2009), higher operating overhead recoveries in the year ended 2009 due to retroactive recoveries, as well as increased rent related to head office relocation and costs related to the Corporate Conversion as compared to the year ended December 31, 2009. Excluding the tax indemnification payments identified above, general and administrative expenses for the year ended December 31, 2010, would have been $2.39/boe (year ended December 31, 2009 – $2.10/boe).
Unit-Based Compensation Expense
For the year ended December 31, 2010, compensation expense related to our Trust Unit Rights Incentive Plan was $8.3 million, an increase of 30% compared to $6.4 million for the same period in 2009. This increase is the result of higher average fair values assigned to new unit rights granted.
Compensation expense associated with our Trust Unit Rights Incentive Plan is recognized in income over the vesting period of the unit rights with a corresponding increase in contributed surplus. The exercise of unit rights was recorded as an increase in unitholders’ capital with a corresponding reduction in contributed surplus.
Interest Expense
Interest expense for the year ended December 31, 2010 decreased to $26.7 million, as compared to $32.7 million in the same period in 2009. The decrease was attributable to a lower effective interest rate on long-term debt due to the issuance on August 26, 2009 of $150 million of 9.15% Series A senior unsecured debentures and the retirement on September 25, 2009 of US$179.7 million of 9.625% senior subordinated notes and US$0.2 million of 10.5% senior subordinated notes, offset by a higher bank loan balance and prime lending rate in 2010 compared to 2009.
Financing Charges
Financing charges for the year ended December 31, 2010 were $1.6 million, as compared to $5.5 million for the year ended December 31, 2009. This decrease is due to lower fees associated with our revolving credit facilities and the issuance of $150.0 million of 9.15% Series A senior unsecured debentures on August 26, 2009.
Foreign Exchange
| | | Years Ended December 31 | |
| ($ thousands) | | 2010 | | | 2009 | | | Change | |
| Unrealized foreign exchange gain | | $ | (8,999 | ) | | $ | (2,623 | ) | | $ | (6,376 | ) |
| Realized foreign exchange gain | | | (149 | ) | | | (20,201 | ) | | | 20,052 | |
| Total gain | | $ | (9,148 | ) | | $ | (22,824 | ) | | $ | 13,676 | |
Foreign exchange gain in the year ended December 31, 2010 was $9.1 million, as compared to a gain of $22.8 million in the year ended 2009. This gain was comprised of an unrealized foreign exchange gain of $9.0 million and a realized foreign exchange gain of $0.1 million. The unrealized gains of $9.0 million in 2010 and $2.6 million in 2009 were due to the translation of the US$180 million portion of our bank loan as the CAD/USD foreign exchange rates strengthened at December 31, 2010 (as compared to December 31, 2009) and December 31, 2009 (as compared to December 31, 2008). The current year realized gain relates to US$ denominated financial derivative contract gains and from day-to-day US$ denominated transactions, as compared to the prior year gain of $20.2 million which was mainly due to redemption of the US$ senior subordinated notes in September 2009.
Depletion, Depreciation and Accretion
Depletion, depreciation and accretion for the year ended December 31, 2010 increased to $271.0 million from $237.2 million for the same period in 2009. On a sales-unit basis, the provision for the year ended December 31, 2010, was $16.76 per boe, as compared to $15.74 per boe for the same period in 2009.
Taxes
Current tax expense for the year ended December 31, 2010 was $8.5 million, $2.9 million lower than the year ended 2009. The lower current tax expense is due to an out of period adjustment of $4.0 million related to Saskatchewan resource surcharge tax.
For the year ended December 31, 2010, future tax recovery totaled $32.1 million, as compared to a future tax recovery $30.5 million for the year ended 2009. The increase in future tax recovery is primarily due to higher distributed earnings in the current year, offset by higher operating income.
As at December 31, 2010, future income tax liability was $15.4 million (December 31, 2009 – $186.6 million). In May 2010, Baytex acquired a number of private entities for use in its internal financing structure for approximately $38.0 million. The transaction resulted in the recognition of future income tax asset of $147.8 million with a corresponding deferred credit of $109.8 million. This credit reflects the difference between the future income tax asset recognized upon the completion of this transaction and the cash paid. This credit will be amortized on the same basis as the related future income tax asset.
Tax Pools
During 2010 and 2009, Baytex was organized as a Mutual Fund Trust for Canadian income tax purposes. Partially as a result of tax deductions taken for distributions paid to unitholders in 2010 and 2009, no material Canadian cash tax expense, other than the Saskatchewan resource surcharge, was payable by Baytex. Following the conversion from a trust structure to a corporate legal form on December 31, 2010, Baytex will not be entitled to a deduction from Canadian taxable income for its distributions, nor will a deduction be available for future dividends. As such it is likely that cash income tax expense attributable to our Canadian operations will be higher in future years than it was during the time we operated as a trust. Baytex has accumulated the Canadian and U.S. tax pools as noted in the table below which will be available to reduce future taxable income. Our cash income tax liability is dependant upon many factors, including the prices at which we sell our production, available income tax deductions, and the legislative environment in place during the taxation year. Based upon the current forward commodity price outlook and a projected production and cost levels, Baytex does not expect to become liable for Canadian income tax, other than the Saskatchewan resource surcharge, until 2012. The income tax pools detailed below are deductible at various rates as prescribed by law.
| ($ thousands) | | December 31, 2010 | | | December 31, 2009 | |
| Canadian Tax Pools | | | | | | |
| Canadian oil and gas property expenditures | | $ | 286,879 | | | $ | 299,220 | |
| Canadian development expenditures | | | 234,836 | | | | 189,791 | |
| Canadian exploration expenditures | | | 9,716 | | | | – | |
| Undepreciated capital costs | | | 236,192 | | | | 241,071 | |
| Non-capital losses | | | 773,396 | | | | 19,470 | |
| Finance costs | | | 10,334 | | | | 169 | |
| Total Canadian tax pools | | $ | 1,551,353 | | | $ | 749,721 | |
| U.S. Tax Pools | | | | | | | | |
| Taxable depletion | | $ | 117,765 | | | $ | 148,031 | |
| Intangible drilling costs | | | 35,000 | | | | 9,182 | |
| Tangibles | | | 13,048 | | | | 3,686 | |
| Non-capital losses | | | 64,541 | | | | 4,178 | |
| Total U.S. tax pools | | $ | 230,354 | | | $ | 165,077 | |
Net Income
Net income for the year ended December 31, 2010, was $177.6 million, as compared to net income of $87.6 million for the year ended December 31, 2009. Revenues, net of royalties, increased $183.8 million or 28% in the year ended December 31, 2010, as compared to the same period in 2009. In addition, lower interest expense and financing charges in 2010 also increased net income by $6.0 million and $3.9 million, respectively, in the year ended December 31, 2010, as compared to same period in 2009. These increases were partially offset by operating costs of $8.6 million, foreign exchange of $13.7 million and depletion and accretion of $33.8 million for the year ended December 31, 2010, as compared to the same period in 2009.
Other Comprehensive Loss
The Company’s foreign operations are considered to be “self-sustaining operations”, financially and operationally independent. As a result, the accounts of the self-sustaining foreign operations are translated using the current rate method whereby assets and liabilities are translated using the exchange rate in effect at the balance sheet date, while revenues and expenses are translated using the average exchange rate for the year ended December 31, 2010. Translation gains and losses are deferred and included in other comprehensive income in shareholders’ capital and are recognized in net income when there has been a reduction in the net investment.
This change was adopted prospectively on January 1, 2009 resulting in a currency translation adjustment of $15.4 million upon adoption with a corresponding increase in petroleum and natural gas properties. The reduction of $19.3 million for 2009 plus the reduction of $10.7 million in the year ended December 31, 2010 resulted in a balance of $14.6 million in accumulated other comprehensive loss at December 31, 2010.
FUNDS FROM OPERATIONS, PAYOUT RATIO AND DISTRIBUTIONS OR DIVIDENDS
Funds from operations and payout ratio are non-GAAP measures. Funds from operations represents cash flow from operating activities before changes in non-cash working capital and other operating items. Payout ratio is calculated as cash distributions (net of participation in the Distribution Reinvestment Plan (“DRIP”)) divided by funds from operations. Baytex considers these to be key measures of performance as they demonstrate its ability to generate the cash flow necessary to fund dividends and capital investments.
The following table reconciles cash flow from operating activities (a Canadian GAAP measure) to funds from operations (a non-GAAP measure):
| | | Years Ended | |
| ($ thousands except for %) | | December 31, 2010 | | | December 31, 2009 | |
| Cash flow from operating activities | | $ | 441,438 | | | $ | 303,162 | |
| Change in non-cash working capital | | | 9,967 | | | | 27,878 | |
| Asset retirement expenditures | | | 2,778 | | | | 1,146 | |
| Funds from operations | | $ | 454,183 | | | $ | 332,186 | |
| Cash distributions declared, net of DRIP | | $ | 189,824 | | | $ | 137,601 | |
| Payout ratio | | | 42 | % | | | 41 | % |
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 distributions declared, net of DRIP participation, of $189.8 million for the year ended December 31, 2010 were funded through funds from operations of $454.2 million. The following table compares cash distributions to cash flow from operating activities and net income:
| | | Years Ended | |
| ($ thousands except for %) | | December 31, 2010 | | | December 31, 2009 | |
| Cash flow from operating activities | | $ | 441,438 | | | $ | 303,162 | |
| Cash distributions declared, net of DRIP | | | 189,824 | | | | 137,601 | |
| Excess of cash flow from operating activities over cash distributions declared, net of DRIP | | $ | 251,614 | | | $ | 165,561 | |
| Net income | | $ | 177,631 | | | $ | 87,574 | |
| Cash distributions declared, net of DRIP | | | 189,824 | | | | 137,601 | |
| Shortfall of net income over cash distributions declared, net of DRIP | | $ | (12,193 | ) | | $ | (50,027 | ) |
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.
As at December 31, 2010, Baytex had approximately $246.2 million in available undrawn credit facilities to fund any such shortfall. As a result of our semi-annual borrowing base review, and following the completion of an acquisition, subsequent agreements effective January 1, 2011 and February 17, 2011 provided an additional $100.0 million in available credit facilities.
For the year ended December 31, 2010, the Company’s net income was less than cash distributions declared (net of DRIP) by $12.2 million, with net income reduced by $263.8 million for non-cash items. Non-cash items such as depletion, depreciation and accretion may not be fair indicators for the cost of maintaining our productive capacity as they are based on historical costs of assets and not the fair value of replacing those assets under current market conditions.
LIQUIDITY AND CAPITAL RESOURCES
We regularly review our liquidity sources as well as our exposure to counterparties, and have concluded that our capital resources are sufficient to meet our on-going short, medium and long-term commitments. Specifically, we believe that our internally generated funds from operations, augmented by our hedging program and existing credit facilities, will provide sufficient liquidity to sustain our operations in the short, medium and long-term. Further, we believe that our counterparties currently have the financial capacities to honor outstanding obligations to us in the normal course of business. We periodically review the financial capacity of our counterparties and, in certain circumstances, we will seek enhanced credit protection from a counterparty.
| ($ thousands) | | December 31, 2010 | | | December 31, 2009 | |
| Bank loan | | $ | 303,773 | | | $ | 265,088 | |
| Convertible debentures | | | – | | | | 7,736 | |
| Long-term notes | | | 150,000 | | | | 150,000 | |
| Working capital deficiency | | | 48,417 | | | | 51,452 | |
| Total monetary debt | | $ | 502,190 | | | $ | 474,276 | |
At December 31, 2010, total monetary debt was $502.2 million, as compared to $474.3 million at December 31, 2009. Bank borrowings at December 31, 2010 were $303.8 million, as compared to total credit facilities of $550.0 million.
Our wholly-owned subsidiary, Baytex Energy Ltd (“Baytex Energy”), has established credit facilities with a syndicate of financial institutions. The credit facilities consist of an operating loan and a 364-day revolving loan. In June 2010, Baytex Energy reached agreement with its lending syndicate to amend its revolving credit facilities to increase the amount of the facilities to $550 million (from $515 million), extend the revolving period to June 2011 and add a one-year term out following the revolving period. In the event that the revolving period is not extended by June 2011, all amounts then outstanding under the credit facilities will be payable in June 2012. Advances under the credit facilities or letters of credit can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance rates or LIBOR rates, plus applicable margins. The credit facilities are subject to semi-annual review and are secured by a floating charge over all of our assets. The weighted average interest rate on our bank loan for the year ended December 31, 2010 was 4.60% (December 31, 2009 – 4.42%).
A subsequent agreement effective January 1, 2011 was reached between Baytex Energy and its lending syndicate to increase the amount of the credit facilities to $625 million (from $550 million), to decrease its margins on advances based on the prime lending rate, bankers’ acceptance rates or LIBOR rates and to decrease standby fees. The credit facilities were further increased to $650 million (from $625 million) effective February 17, 2011.
The credit facilities were arranged pursuant to an agreement with a syndicate of financial institutions. A copy of the credit agreement and related amendments are accessible on the SEDAR website at www.sedar.com (filed on March 28, 2008, September 15, 2008, July 9, 2009, August 14, 2009, October 5, 2009, July 15, 2010, August 31, 2010, January 10, 2011 and February 24, 2011).
Subsequent to year-end, on February 17, 2011, Baytex issued US$150.0 million principal amount of Series B senior unsecured debentures bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. Net proceeds of this issue were used to repay a portion of the amount drawn in Canadian currency on our credit facilities. These debentures are unsecured and are subordinate to Baytex Energy’s credit facilities.
Pursuant to various agreements with our lenders, we are restricted from making dividends to shareholders where the dividend would or could have a material adverse effect on us or our subsidiaries’ ability to fulfill our respective obligations under the Series A or Series B senior unsecured debentures and the credit facilities.
Baytex believes that funds from operations, together with the existing credit facilities, will be sufficient to finance current operations, dividends to the shareholders and planned capital expenditures for the ensuing year. The timing of most of the capital expenditures is discretionary and there are no material long-term capital expenditure commitments. The level of dividend is also discretionary, and the Company has the ability to modify dividend levels should funds from operations be negatively impacted by factors such as reductions in commodity prices or production volumes.
Capital Expenditures
Capital expenditures are summarized as follows:
| | | Years Ended December 31 | |
| ($ thousands) | | 2010 | | | 2009 | |
| Land | | $ | 17,908 | | | $ | 13,514 | |
| Seismic | | | 569 | | | | 2,222 | |
| Drilling and completion | | | 157,464 | | | | 113,959 | |
| Equipment | | | 61,200 | | | | 26,164 | |
| Other | | | (162 | ) | | | 1,185 | |
| Total exploration and development | | $ | 236,979 | | | $ | 157,044 | |
| Corporate acquisition | | | 40,914 | | | | – | |
| Property acquisitions | | | 24,763 | | | | 133,155 | |
| Property dispositions | | | (19,033 | ) | | | (78 | ) |
| Total oil and gas expenditures | | | 283,623 | | | $ | 290,121 | |
| Corporate assets | | | 8,457 | | | | 7,050 | |
| Total capital expenditures | | $ | 292,080 | | | $ | 297,171 | |
Shareholders’ Equity
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 March 1, 2011, the Company had 114,709,978 common shares and no preferred shares issued and outstanding.
Off Balance Sheet Arrangements
Baytex is not party to any contractual arrangement under which a non-consolidated entity may have any obligation under certain guarantee contracts, a retained or contingent interest in assets transferred to a non-consolidated entity or similar arrangement that serves as credit, liquidity or market risk support to that entity for such assets. Baytex has no obligation under financial instruments or a material variable interest in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.
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 in an ongoing manner. A significant portion of these obligations will be funded through funds from operations. These obligations as of December 31, 2010, and the expected timing of funding of these obligations, are noted in the table below.
| ($ thousands) | | Total | | | Less than 1 year | | | 1-2 years | | | 3-5 years | | | Beyond 5 years | |
| Accounts payable and accrued liabilities | | $ | 179,269 | | | $ | 179,269 | | | $ | – | | | $ | – | | | $ | – | |
| Distributions payable to unitholders | | | 22,742 | | | | 22,742 | | | | – | | | | – | | | | – | |
Bank loan(1) | | | 303,773 | | | | – | | | | 303,773 | | | | – | | | | – | |
Long-term debt(2) | | | 150,000 | | | | – | | | | – | | | | – | | | | 150,000 | |
| Operating leases | | | 55,645 | | | | 5,667 | | | | 11,435 | | | | 12,284 | | | | 26,259 | |
| Processing and transportation agreements | | | 4,207 | | | | 3,175 | | | | 1,006 | | | | 26 | | | | – | |
| Total | | $ | 715,636 | | | $ | 210,853 | | | $ | 316,214 | | | $ | 12,310 | | | $ | 176,259 | |
| (1) | The bank loan is a 364-day revolving loan with a one year term-out following the 364-day revolving period with the ability to extend the term. Unless extended, the revolving period will end on June 27, 2011 with all amounts to be re-paid by June 27, 2012. |
| (2) | Principal amount of instruments. |
Baytex also has on-going 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
The exploration for and the development, production and marketing of petroleum and natural gas involves a wide range of business and financial risks, some of which are beyond the Company’s control. Included in these risks are the uncertainty of finding new reserves, fluctuations in commodity prices, the volatile nature of interest and foreign exchange rates, and the possibility of changes to royalty, tax and environmental regulations. The petroleum industry is highly competitive and Baytex competes with a number of other entities, many of which have greater financial and operating resources.
The business risks facing Baytex are mitigated in a number of ways. Geological, geophysical, engineering, environmental and financial analyses are performed on new exploration prospects, development projects and potential acquisitions to ensure a balance between risk and reward. Baytex’s ability to increase its production, revenues and funds from operations depends on its success in not only developing its existing properties but also in acquiring, exploring for and developing new reserves and production and managing those assets in an efficient manner.
Despite best practice analysis being conducted on all projects, there are numerous uncertainties inherent in estimating quantities of petroleum and natural gas reserves, including future petroleum and natural gas prices, engineering data, projected future rates of production and the timing of future expenditures. The process of estimating petroleum and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. An independent engineering firm evaluates the Company’s properties annually to determine a fair estimate of reserves. The Reserves Committee, consisting of members of the Board of Directors of Baytex (the “Board”), assists the Board in their annual review of the reserve estimates.
The provision for depletion and depreciation in the financial statements and the ceiling test are based on proved reserves estimates. Any future significant revisions could result in a full cost accounting write-down or material changes to the annual rate of depletion and depreciation.
The financial risks that Baytex is exposed to as part of the normal course of its business are managed, in part, with various financial derivative instruments, in addition to physical delivery contracts. The use of derivative instruments is governed under formal internal policies and subject to limits established by the Board. Derivative instruments are not used for speculative or trading purposes.
The Company’s financial results can be significantly affected by the prices received for petroleum and natural gas production as commodity prices fluctuate in response to changing market forces. This pricing volatility is expected to continue. As a result, Baytex has a risk management program that may be used to protect the prices of oil and natural gas on a portion of the total expected production. The objective of the risk management program is to decrease exposure to market volatility and ensure the Company’s ability to finance its dividends and capital program.
Baytex’s financial results are also impacted by fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Crude oil and, to a large extent, natural gas prices are based on reference prices denominated in U.S. dollars, while the majority of expenses are denominated in Canadian dollars. The exchange rate also impacts the valuation of the U.S. dollar borrowings. The related foreign exchange gains and losses are included in net income.
Baytex is exposed to changes in interest rates as the Company’s credit facilities are based on the lenders’ prime lending rate, bankers’ acceptance rates or LIBOR rates.
Details of the risk management contracts in place as at December 31, 2010 and the accounting for the Company’s financial instruments are disclosed in note 17 to the consolidated financial statements. A summary of certain risk factors relating to our business is included in our Annual Information Form for the year ended December 31, 2010 under the Risk Factors section.
CRITICAL ACCOUNTING ESTIMATES
A summary of Baytex’s significant accounting policies can be found in notes 1 and 2 to the consolidated financial statements. The preparation of the consolidated financial statements in accordance with generally accepted accounting principles requires management to make judgments and estimates that affect the financial results of the Company. The financial and operating results of Baytex incorporate certain estimates including:
| | • | estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received; |
| | • | estimated capital expenditures on projects that are in progress; |
| | • | estimated depletion, depreciation and accretion that are based on estimates of petroleum and natural gas reserves that Baytex expects to recover in the future; |
| | • | estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices, interest rates and foreign exchange rates; |
| | • | estimated value of asset retirement obligations that are dependant upon estimates of future costs and timing of expenditures; and |
| | • | estimated future recoverable value of petroleum and natural gas properties and goodwill. |
Baytex has hired individuals who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.
CHANGES IN ACCOUNTING POLICIES
Future Accounting Changes
In 2006, Canada’s Accounting Standards Board (the “AcSB”) ratified a strategic plan to converge Canadian GAAP with International Financial Reporting Standards (“IFRS”) by 2011 for publicly accountable entities. On February 13, 2008 the AcSB confirmed that IFRS would replace Canadian GAAP for public companies beginning January 1, 2011. As a result, Baytex will issue financial statements under IFRS in 2011.
Convergence of Canadian GAAP with IFRS
IFRS replaces Canadian GAAP 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 balance sheet as at January 1, 2010. Baytex expects that IFRS will not have a major impact on the Company’s operations or strategic decisions.
Management continues to monitor new IFRS and amendments to existing IFRS that may impact the adoption of IFRS by Baytex in 2011Our 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 IFRS accounting policies will only be finalized when our first annual IFRS financial statements are prepared for the year ending December 31, 2011.
Management has not yet finalized the quantification of the impact on Baytex’s 2010 financial statements. Baytex continues to draft IFRS compliant financial statements and develop the corresponding accounting entries to comply with the proposed IFRS accounting policies. The various accounting policy choices and results remain subject to further review by management. The IFRS implementation will continue into 2011 and will conclude with the issuance of the first quarter financial statements of 2011. The Company’s external auditors are expected to continue to review draft IFRS accounting policies and the IFRS 2010 comparative periods during the first few months of 2011.
Management expects to apply the following accounting policies under IFRS. The adjustments and resulting IFRS amounts are unaudited and subject to change.
First-Time Adoption of IFRS
IFRS 1, “First-Time Adoption of International Financial Reporting Standards”, provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Baytex expects to apply the following exemptions:
Property, Plant and Equipment, (“PP&E”) – IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at its time of adoption, to measure exploration and evaluation assets at the amount determined under the entity’s previous GAAP and to measure oil and gas assets in the development and production (“D&P”) phases by allocating the amount determined under the entity’s previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date.
Asset retirement obligations – Decommissioning provisions, included in the cost of PP&E, are measured as at January 1, 2010 in accordance with International Accounting Standards (“IAS”) 37, “Provisions, Contingent Liabilities and Contingent Assets”, and the difference between that amount and the carrying amount of those liabilities at January 1, 2010 determined under Canadian GAAP are recognized directly in deficit.
Business combinations – IFRS 1 permits the use of IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations.
Share-based payments – IFRS 1 provides an exemption on IFRS 2 (“Share-Based Payments”) to liabilities arising from share-based payment transactions that were settled before the Company’s transition date to IFRS.
Cumulative translation differences – An option is available to deem cumulative translation differences on all foreign operations as zero at the date of transition. Under Canadian GAAP, accumulated other comprehensive loss amounts are composed entirely of currency translation adjustments on self-sustaining foreign operations. Under IFRS, the Company has elected to deem cumulative translation differences as $nil at January 1, 2010. At January 1, 2010, this has resulted in an increase in other comprehensive income and deficit of $3.9 million.
Borrowing Costs – IFRS 1 allows application of the IAS 23 (“Borrowing Costs”) to borrowing costs related to qualifying assets for which the commencement date for capitalization is on or after January 1, 2010.
Leases – International Financial Reporting Interpretations Committee 1, “Determining whether an Arrangement contains a Lease” transition rules allow determination of whether any existing arrangement at January 1, 2010 contains a lease on the basis of the facts and circumstances existing at that date.
Estimated Impact on Reported Financial Position
The following information summarizes the key transitional adjustments required for the January 1, 2010 opening balance sheet on adoption of IFRS. These amounts will be impacted by the deferred tax effect of the IFRS adjustments.
| (thousands of Canadian dollars) (unaudited) | | Canadian GAAP | | | IFRS Adjustments | | | IFRS | |
| Current assets | | | 179,539 | | | | (1,371 | ) | | | 178,168 | |
| Non-current assets | | | 1,704,466 | | | | 1,371 | | | | 1,705,837 | |
| | | | 1,884,005 | | | | – | | | | 1,884,005 | |
| Current liabilities | | | 486,324 | | | | (1,329 | ) | | | 484,995 | |
| Non-current liabilities | | | 385,684 | | | | 161,834 | | | | 547,518 | |
| Unitholders’ Equity | | | 1,011,997 | | | | (160,505 | ) | | | 851,492 | |
| | | | 1,884,005 | | | | – | | | | 1,884,005 | |
Exploration and Evaluation (“E&E”) expenditures – On transition to IFRS, Baytex will re-classify all E&E expenditures that are currently included in the PP&E balance on the consolidated balance sheet. This will consist of the book value of undeveloped land that relates to exploration properties. Baytex will initially capitalize these costs as E&E assets on the balance sheet. E&E assets will not be depleted and must be assessed for impairment when indicators of impairment exist.
Under the IFRS 1 election, Baytex has measured exploration and evaluation assets at the amount determined under the entity’s previous GAAP resulting in $124.6 million reclassified from oil and gas properties to exploration and evaluation assets.
Depletion expense – Under Canadian GAAP depletion was calculated on a unit of production basis using proved reserves at the country level. Under IFRS, costs will be depleted on a unit of production basis at a more granular level than the country level. Baytex will calculate the depletion calculation using proved plus probable reserves at an area level.
Derecognition of D&P assets – Under Canadian GAAP, full cost accounting gains and losses were not recognized upon disposition of oil and gas assets unless such a disposition 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 disposition and carrying value.
Impairment of PP&E assets – Under IFRS, impairment of PP&E must be calculated at a more granular level than what is currently required under Canadian GAAP. Impairment calculations will be performed at the cash generating unit (“CGU”) level using fair values of the PP&E assets. Baytex anticipates using discounted proved plus probable reserve values for impairment tests of PP&E. Under Canadian GAAP, estimated future cash flows used to assess impairments are not discounted. As such, impairment losses may be recognized earlier under IFRS than under Canadian GAAP. Impairment losses are reversed under IFRS when there is an increase in the recoverable amount.
Baytex has allocated the property, plant and equipment amount recognized under Canadian GAAP as at January 1, 2010 to the assets at 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 no IFRS impairments are expected at January 1, 2010.
Decommissioning provisions – Under IFRS, Baytex will use a risk-free interest rate to discount the estimated fair value of its asset retirement obligations and the related PP&E. Under Canadian GAAP, the Company uses a credit-adjusted interest rate. A lower discount rate will increase the asset retirement obligation liability. In addition, under IFRS, asset retirement obligations are measured using the best estimate of the expenditure to be incurred and requires the use of current discount rates at each re-measurement date with the corresponding adjustment to the cost of the related PP&E. Existing liabilities under Canadian GAAP are not re-measured using current discount rates.
Under Canadian GAAP, the Company’s decommissioning provision is recorded using the credit-adjusted risk free rate of 8.0%. Under IFRS, the Company’s decommissioning provision is recorded using the risk-free rate of 4.0%. Under IFRS, an additional liability of $87.3 million has been recognized with an offsetting charge to deficit at January 1, 2010.
Unit-based compensation – Under IFRS, prior to the conversion to a corporation, the obligation associated with the Trust Unit Rights Incentive Plan is 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 profit or loss for the period. Under Canadian GAAP, the obligation associated with the Trust Unit Rights Incentive Plan is considered to be equity-based and the related unit-based compensation is calculated using the binomial-lattice model to estimate the fair value of the outstanding rights at grant date. The exercise of unit rights is recorded as an increase in unitholders’ capital with a corresponding reduction in contributed surplus. Re-measuring the fair value of the obligation each reporting period for periods prior to the conversion to a corporation will increase the unit-based payment liability, unitholders’ capital and compensation expense recognized. The modification that converts the outstanding rights to acquire trust units to rights to acquire common shares in connection with the Corporate Conversion effectively changes the related classification to equity-settled. The expense recognized from the date of modification over the remainder of the vesting period is determined based on the fair value of the reclassified equity awards at the date of the modification.
At January 1, 2010 under IFRS, an additional unit-based payment liability of $69.4 million and a decrease of $20.4 million in contributed surplus is offset by a $49.0 million charge to deficit.
Convertible debentures – 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 instrument are recognized in the statement of comprehensive income. If the debentures are converted to trust units, the fair value of the conversion feature under financial derivative liability is reclassified to unitholders’ or shareholders’ capital along with the principal amounts converted. Under Canadian 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 were reclassified to unitholders’ capital along with principal amounts converted.
At January 1, 2010 under IFRS, an additional financial derivative liability of $7.4 million, an increase of $33.4 million in unitholders’ equity, a decrease of $0.4 million in conversion feature of convertible debentures has been recognized with the offsetting $40.4 million increase in deficit.
Trust Units Classification – IFRS prescribes the principles for determining the classification of the financial instruments as debt or equity. Under Canadian GAAP Baytex’s trust units were considered permanent equity and included within unitholders’ capital. Under IFRS, the trust units are considered puttable financial instruments however a specific exemption for trust units specifies they are classified as permanent equity within unitholders’ capital. Although Baytex converted to a corporation on December 31, 2010, Baytex was required to determine if it met the criteria for this exemption to conclude on the appropriate presentation for the pre-conversion period. Baytex has assessed that the application of IFRS principles and standards to Baytex’s trust units results in their treatment as equity.
Income taxes – Under IFRS, future income taxes are required to be presented as non-current deferred tax assets and liabilities. In transitioning to IFRS, the Company’s deferred tax liability will be impacted by the tax effects resulting from the IFRS adjustments.
Internal Controls Over Financial Reporting
Along with review of the accounting policy choices and analysis, assessments are also made to determine the changes required to internal controls over financial reporting. The internal controls documentation will continue to be updated to reflect changes in accounting polices and appropriate additional controls and procedures for reporting under IFRS.
Disclosure controls and procedures
Throughout the transition process, Baytex will be assessing stakeholders’ information requirements to ensure that appropriate and timely information is provided once available. Management anticipates disclosure in investor presentations and in shareholder publications during 2011 to explain differences between the historical Canadian GAAP statements and the IFRS statements.
Information Technology Systems
The most significant information systems challenges for the IFRS conversion were ensuring the Company had the ability to track its IFRS adjustments in the year of transition and that new IFRS reports could be produced to facilitate the preparation of IFRS financial statements. The Company has successfully tested its ability to track IFRS adjustments for its 2010 comparative periods and has successfully implemented the modifications required to existing and new reports to facilitate the preparation of the increased note disclosure required under IFRS.
Baytex is unable to quantify the full impact on the financial statements of adopting IFRS; however the company has disclosed certain expectations above based on information known to date. Certain items may be subject to change based on facts and circumstances as they arise after the date of this MD&A.
SELECTED ANNUAL INFORMATION
| ($ thousands, except per common share or trust unit amounts) | | 2010 | | | 2009 | | | 2008 | |
| Petroleum and natural gas sales | | $ | 1,005,136 | | | $ | 789,743 | | | $ | 1,159,718 | |
Net income(1) | | $ | 177,631 | | | $ | 87,574 | | | $ | 259,894 | |
Per common share or trust unit – basic(1) | | $ | 1.59 | | | $ | 0.83 | | | $ | 2.83 | |
Per common share or trust unit – diluted(1) | | $ | 1.54 | | | $ | 0.82 | | | $ | 2.74 | |
| Total assets | | $ | 2,047,212 | | | $ | 1,884,005 | | | $ | 1,812,333 | |
| Total other long-term financial liabilities | | $ | 453,773 | | | $ | 150,000 | | | $ | 227,468 | |
| Cash distributions declared per common share or trust unit | | $ | 2.18 | | | $ | 1.56 | | | $ | 2.64 | |
| (1) | Net income and net income per common share or trust unit is after non-controlling interest related to exchangeable shares. |
Overall production for 2010 was 44,341 boe/d which represented a 7% increase from 41,382 boe/d in 2009 and a 10% increase from 40,239 boe/d in 2008. Average wellhead prices net of blending costs received were $53.39 per boe during 2010, $45.00 per boe during 2009 and $65.66 per boe during 2008.
FOURTH QUARTER 2010
For a discussion and analysis of our operating and financial results for the three months ended December 31, 2010, please see our Management’s Discussion and Analysis for the three months and year ended December 31, 2010 dated March 7, 2011, which is incorporated by reference into this MD&A and is accessible on SEDAR at www.sedar.com.
2011 GUIDANCE
Baytex has set a 2011 exploration and development capital budget of $325 million designed to generate production levels at an average annual rate of 49,000 to 50,000 boe/d, including production from our heavy oil acquisition which closed on February 3, 2011. Approximately 60% of our 2011 capital program will be directed to our heavy oil operations, with the single largest project being horizontal-well cold development at Seal in the Peace River Oil Sands. We also plan to complete our first 10-well commercial thermal module at Seal, with start-up scheduled before the end of 2011.
During 2011, we plan increased development in our cold drilling program in the Lloydminster area where, for the first time, horizontal wells will constitute the majority of wells drilled. In addition, the 2011 heavy oil program provides for two new steam assisted gravity drainage well pairs at Kerrobert in Saskatchewan. The balance of our capital program will be directed primarily towards light oil development, with the two largest projects being the Bakken/Three Forks in North Dakota and the Viking in southeast Alberta. Other development projects include light oil development in the Viking in southwest Saskatchewan and the Cardium in central Alberta.
We viewed 2010 as the transition year for our shift from a predominantly income-focused model as a trust to a growth-and-income model in the new corporate era. Our 2011 capital program completes this transition to the growth-and-income model. Based on the high end of the production guidance ranges for 2011, the 2011 plan reflects an organic production growth rate of approximately 8%. Our 2011 production mix is forecast to be approximately 66% heavy oil, 17% light oil and natural gas liquids and 17% natural gas, based on a 6:1 gas-to-oil equivalency.
Environmental Regulation and Risk
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.
Climate Change Regulation
The Government of Canada ratified the Kyoto Protocol in 2002, calling for Canada to reduce its greenhouse gas emissions to 6% below 1990 “business as usual” levels by 2012. In December 2009, representatives of approximately 170 countries meet in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol. The Copenhagen negotiations resulted in the Copenhagen Accord, a non-binding political accord which reinforced the Kyoto Protocol’s commitment to reducing greenhouse gas emissions. In response to the Copenhagen Accord, the government of Canada revised its emissions reduction goals and now aims to achieve a 17% reduction in greenhouse gas emissions from 2005 levels by 2020. Despite the commitments made under the Kyoto Protocol and the Copenhagen Accord, no federal legislation has been implemented to regulate the emission of greenhouse gases and the Government of Canada has indicated that it will delay the implementation of climate change legislation and regulations in order to ensure consistency with the approach ultimately taken by the United States with respect to greenhouse gas emissions.
There has been much public debate with respect to Canada’s ability to meet these targets and the Government of Canada’s strategy or alternative strategies with respect to climate change and the control of greenhouse gases. The implementation of strategies for reducing greenhouse gases, whether to meet the goals of the Kyoto Protocol, the Copenhagen Accord or otherwise, could have a material impact on the nature of oil and natural gas operations, including those of Baytex. 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 the impact of those requirements on Baytex and its operations and financial condition.
Further information regarding environmental and climate change regulation is contained in our Annual Information Form for the year ended December 31, 2010 under the Industry Conditions section.
Broad-based Federal Tax Reductions
On October 30, 2007, the Federal Government presented the fall economic statement that proposed significant reductions in corporate income tax rates from 22.1% to 15%. The reductions will be phased in between 2008 and 2012. In addition, the Federal Government announced that it plans to collaborate with the provinces and territories to reach a 25% combined federal-provincial-territorial statutory corporate income tax rate.
DISCLOSURE CONTROLS AND PROCEDURES
As of December 31, 2010, an evaluation was conducted of the effectiveness of the Baytex’s “disclosure controls and procedures” (as defined in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”) and in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”)) by management, with the participation of the President and Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the Baytex’s disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that the Baytex files or submits under the Exchange Act or under Canadian securities legislation is (i) recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms and (ii) accumulated and communicated to the Company’s management, including the President and Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding the required disclosure.
It should be noted that while the President and Chief Executive Officer and the Chief Financial Officer believe that the Company’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Baytex’s disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Baytex. “Internal control over financial reporting” (as defined in the United States by Rules 13a-15(f) and 15d-15(f) under the Exchange Act and in Canada by NI 52-109) is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely financial information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. The assessment was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010. The effectiveness of the Baytex’s internal control over financial reporting as of December 31, 2010 has been audited by Deloitte & Touche LLP, as reflected in their report for 2010.
No changes were made to our internal control over financial reporting during the year ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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 utilize our tax pools to reduce or potentially eliminate our taxable income for the initial period post-conversion; our ability to fund our capital expenditures and dividends on our common shares from funds from operations; 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; our exploration and development capital expenditures for 2011 and the allocation thereof; our average production rate for 2011; development plans for our properties, including the number of wells to be drilled and the timing of completing a 10-well thermal module at our Seal heavy oil resource play; our organic production growth rate in 2011; and our 2011 production mix. 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 gas operations; changes in royalty rates and incentive programs relating to the oil and 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.
