Exhibit 2
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following discussion and analysis should be read in conjunction with the Company’s audited consolidated financial statements for the fiscal years ended December 31, 2002 and 2001. Per 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.
Corporate Strategy As a mid-sized public Canadian oil and gas producer, Baytex focuses its attention on the low-cost development and production of its heavy oil and natural gas assets in the Western Canadian Sedimentary Basin. The Company emphasizes full-cycle exploration and development activity targeting operated, high working interest, heavy oil and natural gas reserves that can be discovered and produced quickly at a below average cost. Baytex enhances this activity with the strategic acquisition of corporations and individual properties that contain assets that are complementary to the Company’s existing assets and, more importantly, provide significant development potential.
2002 Overview During the past year, Baytex focused on financial stability. A strategic divestiture program that began in the fourth quarter of 2001 and continued through the first quarter of 2002 significantly strengthened Baytex’s financial position. The focus on financial stability continued throughout 2002 with a conservative capital-spending program that emphasized financial discipline, while successfully positioning the Company for future production growth. Exploration and development spending was enhanced by the key acquisition of heavy oil assets at Ardmore, Alberta in the fourth quarter. This acquisition provides significant heavy oil development opportunities for 2003 and beyond. In addition to the Ardmore purchase, the signing of a five-year, heavy oil supply agreement with a U.S.-based refining company further highlighted the Company’s commitment to heavy oil. Commencing in 2003, this agreement allows Baytex to sell the majority of its heavy oil production at a fixed differential to benchmark WTI price, thereby significantly reducing the added volatility of the Company’s cash flow from its heavy oil production.
Production The Company’s average production for fiscal 2002 decreased by 10 percent to 39,214 barrels of oil equivalent per day from 43,488 barrels of oil equivalent per day for fiscal 2001. This decrease was the result of the property dispositions that occurred in the fourth quarter of 2001 and the first quarter of 2002 along with a decrease in capital spending on heavy oil in the last half of 2001.
Light oil production decreased 39 percent to 3,154 barrels per day during 2002 from 5,152 barrels per day in 2001. Heavy oil production
Production by Area
|
| Conventional |
| Barrels of |
| Natural Gas |
| Oil Equivalent |
|
2002 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| — |
| 23,967 |
| 10.5 |
| 25,710 |
|
Plains District |
| 2,124 |
| — |
| 43.8 |
| 9,418 |
|
Northern District |
| 1,030 |
| — |
| 18.3 |
| 4,086 |
|
Total production |
| 3,154 |
| 23,967 |
| 72.6 |
| 39,214 |
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| 368 |
| 26,533 |
| 11.5 |
| 28,813 |
|
Plains District |
| 3,721 |
| — |
| 35.5 |
| 9,192 |
|
Northern District |
| 1,063 |
| — |
| 23.8 |
| 5,483 |
|
Total production |
| 5,152 |
| 26,533 |
| 70.8 |
| 43,488 |
|
2
during 2002 decreased by 10 percent to 23,967 barrels per day from 26,533 barrels per day during fiscal 2001. Natural gas production for 2002 increased by two percent to 72.6 million cubic feet per day compared to 70.8 million cubic feet per day for the prior year.
Revenue Petroleum and natural gas sales for 2002 increased by 11percent to $365.9 million from $329.7 million for fiscal 2001. Benchmark WTI crude oil averaged US$26.08 per barrel for 2002, representing a one percent increase over the US$25.90 per barrel for 2001. Correspondingly, Baytex’s light oil and NGLs price increased to $33.86 per barrel in 2002 from$33.65 per barrel in 2001. Baytex’s heavy oil price increased 58 percent to $26.39 per barrel in 2002 from $16.69 per barrel, as heavy oil differentials decreased in 2002. The Company’s heavy oil received 66 percent of the Canadian par crude price in 2002 compared to 43 percent in 2001. Natural gas prices were 11 percent lower in 2002 averaging $3.94 per thousand cubic feet compared to $4.42 per thousand cubic feet during the previous year. Overall, after accounting for financial derivative contracts, Baytex averaged $25.56 per barrel of oil equivalent for 2002 production, a 23percent increase from $20.77 per barrel of oil equivalent received in the prior year.
For 2002, light oil revenue decreased 38 percent over 2001, as production decreased 39 percent while wellhead prices were consistent. Revenue from heavy oil increased 43 percent as the 10 percent decrease in production was offset by the 58 percent increase in wellhead prices. Natural gas revenue decreased nine percent as production increased two percent and wellhead prices declined by 11 percent.
Gross Revenue Analysis
|
| 2002 |
| 2001 |
| ||||
|
| ($thousands) |
| ($/unit) |
| ($thousands) |
| ($/unit) |
|
|
|
|
|
|
|
|
|
|
|
Oil revenue (barrels) |
|
|
|
|
|
|
|
|
|
Light oil |
| 38,985 |
| 33.86 |
| 63,288 |
| 33.65 |
|
Heavy oil |
| 230,874 |
| 26.39 |
| 161,681 |
| 16.69 |
|
Derivative contract loss |
| (10,622 | ) | (1.07 | ) | (9,513 | ) | (0.82 | ) |
Total oil revenue |
| 259,237 |
| 26.19 |
| 215,456 |
| 18.63 |
|
Natural gas revenue (mcf) |
| 104,284 |
| 3.94 |
| 114,244 |
| 4.42 |
|
Derivative contract gain |
| 2,339 |
| 0.09 |
| — |
| — |
|
Total natural gas revenue |
| 106,623 |
| 4.03 |
| 114,244 |
| 4.42 |
|
Total revenue (boe @ 6:1) |
| 365,860 |
| 25.56 |
| 329,700 |
| 20.77 |
|
Operating Netbacks
|
| Conventional |
| Heavy Oil |
| Total Oil &NGLs |
| Natural Gas |
| BOE |
| ||||||||||
|
| 2002 |
| 2001 |
| 2002 |
| 2001 |
| 2002 |
| 2001 |
| 2002 |
| 2001 |
| 2002 |
| 2001 |
|
Sales price |
| 33.86 |
| 33.65 |
| 26.39 |
| 16.69 |
| 27.26 |
| 19.45 |
| 3.94 |
| 4.42 |
| 26.14 |
| 21.37 |
|
Royalties |
| (5.67 | ) | (6.44 | ) | (3.66 | ) | (1.77 | ) | (3.89 | ) | (2.53 | ) | (0.77 | ) | (1.11 | ) | (4.12 | ) | (3.64 | ) |
Operating costs |
| (5.83 | ) | (6.82 | ) | (5.99 | ) | (5.59 | ) | (5.97 | ) | (5.79 | ) | (0.61 | ) | (0.64 | ) | (5.26 | ) | (5.26 | ) |
Operating netbacks |
| 22.36 |
| 20.39 |
| 16.74 |
| 9.33 |
| 17.40 |
| 11.13 |
| 2.56 |
| 2.67 |
| 16.76 |
| 12.47 |
|
Note: Sales prices in this table are before the loss/gain recognized on financial derivative contracts.
3
Royalties Total royalties increased two percent to $58.9 million for the year ended December 31, 2002 from $57.8 million for last year due to an increase in revenue and an increase in heavy oil royalty rates. The overall royalty rate for 2002 was 15.7 percent of sales compared to 17 percent of sales for fiscal 2001. The decrease in the overall royalty rate resulted from the sale of properties that carried a higher royalty burden. In 2002, royalties were 16.7 percent of sales for light oil (2001 - 19.1 percent), 13.9 percent for heavy oil (2001 - 10.6 percent) and 19.5 percent for natural gas (2001 - 25.1 percent).
Operating Expenses Operating expenses for 2002 decreased 10percent to $75.2 million from $83.4 million during the previous year. This decrease is attributable to a 10 percent reduction in overall production. For 2002, operating expenses by product were $5.83 per barrel of light oil, $5.99 per barrel of heavy oil and $0.61 per thousand cubic feet of natural gas. In comparison, operating expenses by product for 2001 were $6.82 per barrel of light oil, $5.59 per barrel of heavy oil and $0.64 per thousand cubic feet of natural gas. Overall operating expenses were consistent on a unit basis at $5.26 per barrel of oil equivalent during 2002 and 2001.
General and Administrative Expenses General and administrative expenses, after capitalization, increased to $6.7 million for 2002 compared to $5.3 million for 2001. On a per-unit-of-production basis, these expenses increased to $0.47 per barrel of oil equivalent in 2002 from $0.33 per barrel of oil equivalent in 2001. This increase was due to higher staff levels associated with the Company’s 2001 corporate acquisitions. In accordance with the full-cost accounting policy, $6.7million of expenses were capitalized in 2002 compared to $5.3million in 2001.
($thousands) |
| 2002 |
| 2001 |
|
Gross corporate expense |
| 19,328 |
| 16,504 |
|
Operator’s recoveries |
| (5,842 | ) | (5,980 | ) |
Subtotal |
| 13,486 |
| 10,524 |
|
Capitalized expense |
| (6,743 | ) | (5,262 | ) |
Net expense |
| 6,743 |
| 5,262 |
|
Interest Expense For the year ended December 31, 2002, interest expense decreased to $25.2 million from $32.9million for the prior year. Average debt levels decreased to $336.9 million in 2002 from $388.8 million in 2001. Interest expense was further reduced by interest rate swap agreements that the Company negotiated in December 2001. These swaps were settled during the third quarter of 2002 for total proceeds of $14.1 million, which is being amortized as a reduction of interest expense. This amortization reduces the effective interest rate of the senior secured notes from 7.23 percent to 5.7 percent until November 2004 and the senior subordinated notes from 10.5 percent to 9.2 percent until February 2006.
Depletion and Depreciation Depletion and depreciation, before ceiling test considerations, decreased to $106.8 million for 2002 compared to $132.9 million for 2001. The decrease is due to lower production and the ceiling test write-down taken at year-end 2001. On a unit-of-production basis, the provision for 2002 was $7.46 per barrel of oil equivalent compared to $8.37 per barrel of oil equivalent for last year.
4
Due to wide heavy oil differentials at year-end 2001, the Company incurred a $131.3 million ceiling test write-down (net of $103.2 million of future income taxes). This amount was recognized as additional depletion and depreciation for the year ended December 31, 2001.
Site Restoration Costs Site restoration costs for 2002 decreased to $2.8 million from $3.9 million last year due to lower production and property dispositions. On a unit-of-production basis, the provision for 2002 was $0.20 per barrel of oil equivalent compared to $0.25 per barrel of oil equivalent for the previous year.
Foreign Exchange Effective January 1, 2002, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) amended accounting standard with respect to foreign currency translation. The amended standard eliminates the practice to defer and amortize foreign exchange gains and losses on long-term monetary items. As a result, all foreign exchange gains and losses on long-term monetary items are now recognized in earnings based on the exchange rates at the end of the reporting periods. The amended standard also requires that prior years’ comparative figures be restated to comply with the new standard.
The foreign exchange gain for the year ended December 31, 2002 was $2.7 million compared to a loss of $16.3 million for the prior year. The 2002 gain is based on the translation of the Company’s U.S. dollar denominated long-term debt at 0.6331 at December 31, 2002 compared to 0.6279 at December 31, 2001. The 2001 loss is based on the translation of the U.S. dollar denominated senior secured notes at 0.6279 at December 31, 2001 compared to 0.6660 at December31, 2000 along with the senior subordinated notes translated at 0.6279 at December 31, 2001 compared to 0.6582 on February 13, 2001 when the notes were issued.
Income Taxes Current tax expenses were $9.7 million for 2002 compared to $7.1million in 2001. The current tax expenses are comprised of $8.1million of Saskatchewan Capital Tax and $1.6 million of Large Corporation Tax, compared to $6.1 million and $1.0 million, respectively, for the prior year. Saskatchewan Capital Tax increased as higher commodity prices have resulted in higher revenues earned in Saskatchewan.
The fiscal 2002 provision for future income taxes was $38.0 million compared to recovery of $107.3 million for the prior year. The increase in future income taxes was the result of higher corporate earnings in 2002 due to increased commodity prices. Future income taxes for 2001 included a $103.2 million recovery associated with the year-end ceiling test write-down.
Cash Flow Netbacks
|
| 2002 |
| 2001 |
| ||||
|
| ($/boe) |
| (percent) |
| ($/boe) |
| (percent) |
|
Production revenue |
| 26.14 |
| 100 |
| 21.37 |
| 100 |
|
Derivative contract loss |
| (0.57 | ) | (2 | ) | (0.60 | ) | (3 | ) |
Royalties |
| (4.12 | ) | (16 | ) | (3.64 | ) | (17 | ) |
Operating expenses |
| (5.26 | ) | (20 | ) | (5.26 | ) | (25 | ) |
Operating netbacks |
| 16.19 |
| 62 |
| 11.87 |
| 55 |
|
General and administrative expenses |
| (0.47 | ) | (2 | ) | (0.33 | ) | (1 | ) |
Interest expense |
| (1.69 | ) | (6 | ) | (2.02 | ) | (9 | ) |
Current income taxes |
| (0.68 | ) | (3 | ) | (0.45 | ) | (2 | ) |
Cash flow netbacks |
| 13.35 |
| 51 |
| 9.07 |
| 43 |
|
5
Canadian Tax Pools
($thousands) |
| December 31, 2002 |
|
Cumulative Canadian Exploration Expense |
| 123,000 |
|
Cumulative Canadian Development Expense |
| 127,000 |
|
Cumulative Canadian Oil and Gas |
|
|
|
Property Expense |
| 59,000 |
|
Undepreciated Capital Cost |
| 150,000 |
|
Total tax pools |
| 459,000 |
|
Cash Flow from Operations Cash flow from operations for the year ended December 31, 2002 increased 33 percent to $191.1 million from $144.1 million for the previous year, as a result of higher field netbacks. Field netbacks increased on a year-over-year basis due to higher oil prices. On a barrel of oil equivalent basis, cash flow from operations was $13.35 for 2002 compared to $9.07 for 2001.
Capital Expenditures Total exploration and development expenditures for 2002 were $136.3 million, which is consistent with $135.9 million for 2001. Overall net capital expenditures decreased 66 percent to $126.5 million in 2002 from $375.9 million in 2001. Two corporate acquisitions were completed in the prior year, which accounted for $249.1 million of the 2001 expenditures.
Capital Expenditures
($thousands) |
| 2002 |
| 2001 |
|
Land |
| 13,834 |
| 11,494 |
|
Seismic |
| 8,183 |
| 7,242 |
|
Drilling and completions |
| 81,862 |
| 71,928 |
|
Equipment |
| 24,507 |
| 37,206 |
|
Other |
| 7,949 |
| 8,019 |
|
Total exploration and development |
| 136,335 |
| 135,889 |
|
Corporate acquisitions |
| — |
| 249,152 |
|
Property acquisitions |
| 45,713 |
| 53,394 |
|
Dispositions |
| (55,580 | ) | (62,582 | ) |
Net capital expenditures |
| 126,468 |
| 375,853 |
|
Liquidity and Capital Resources At December 31, 2002, total net debt (including working capital) was $362.8 million compared to $379.1million at December 31, 2001. The decrease in total debt at the end of 2002 was the result of cash flow from operations exceeding capital spending, proceeds from property dispositions, and proceeds received on the settlement of the interest rate swaps. The U.S. dollar denominated senior secured notes and senior subordinated notes decreased by a combined $2.7 million as a result of foreign exchange gains.
6
The Company’s debt structure consists of three main components. The first component is the Company’s senior credit facilities. At yearend, the Company had undrawn bank facilities with a total commitment of $77 million. These facilities are provided by a syndicate of chartered banks and are limited by a total senior funded debt borrowing base of $165 million. Total senior funded debt is defined to include the Company’s senior secured term notes. Effective January 1, 2002, the CICA’s Emerging Issues Committee issued an abstract giving guidance on disclosure of callable debt obligations. Specifically, the abstract requires the classification of borrowings under a 364-day revolving credit facility as current liabilities. The Company’s bank loans are structured under this type of credit facility and, as such, the comparative balance at December 31, 2001 has been reclassified as current liabilities.
The second component is the senior secured notes which are due November 2004. These senior secured notes are governed by certain financial covenants measured at the end of each fiscal quarter. The principal covenants are: (i) consolidated tangible net worth not to be less than $200 million, excluding accounting ceiling test write-down (such net worth was $529 million as at December 31, 2002); (ii) consolidated total debt not to exceed 300 percent of consolidated cash flow (such ratio was 145 percent as at December 31, 2002); and (iii) consolidated cash flow not to be less than 400 percent of consolidated interest expense (such ratio was 892 percent as at December 31, 2002).
The final component is the US$150 million senior subordinated notes. These notes were issued in February 2001 and have a 10-year term. The notes bear interest at 10.5 percent payable semi-annually, are unsecured and have no financial maintenance covenants.
Baytex believes that cash flow generated from its operations, together with existing capacity under the bank facilities, will be sufficient to finance current operations and planned capital expenditures for the next year. The timing of most of the Company’s capital expenditures is discretionary and there are no material long-term capital expenditure commitments.
Risk 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 economically recoverable reserves, the fluctuation of 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 companies, many of which have greater financial and personnel 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 cash flow 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 practise analysis being conducted on all projects, there are numerous uncertainties inherent in estimating quantities of proved petroleum and natural gas reserves, including future oil and natural gas prices, engineering data, projected future rates of production and the timing of future expenditures. The process of estimating petroleum and
7
natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. An independent engineering firm evaluates Baytex’s properties annually to determine a fair estimate of reserves. A Reserve Evaluation Committee of the Board of Directors assists the Board in their annual review of the Company’s reserve estimates.
The financial risks that Baytex is exposed to as part of the normal course of its business are managed with various financial derivative instruments, in addition to fixed-price physical delivery contracts. The use of derivative instruments is governed under formal policies and subject to limits established by the Board of Directors. 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 fix the price of oil and natural gas on a percentage of the Company’s total expected production. The objective is to lock in prices on a portion of the Company’s future production to decrease exposure to market volatility and ensure the Company’s ability to finance its capital program. The Company recognizes gains or losses on financial derivative contracts as oil and natural gas production revenue when the associated production occurs.
Baytex’s financial results are also impacted by fluctuations in the exchange rate between the Canadian dollar and the US dollar. Crude oil and, to a large extent, natural gas prices are based on reference prices denominated in US dollars, while the majority of expenses are denominated in Canadian dollars. The exchange rate also impacts the valuation of the Company’s US dollar denominated term notes. The related foreign exchange gains and losses are included in net income.
Baytex is exposed to changes in interest rates as the Company’s banking facilities are based on its lenders’ prime lending rate and short-term Bankers’ Acceptance rates. In December 2001, the Company entered into interest rate swap contracts converting the fixed rate on the US denominated term notes to a floating rate reset quarterly based on the three-month LIBOR rate. During 2002, the Company terminated all outstanding interest rate swap agreements for total proceeds of $14.1 million. This amount has been deferred and is being amortized as a reduction of interest expense over the original terms of the agreements. There is no plan at this time to fix the exchange rate on any of Baytex’s long-term borrowings.
The Company’s current position with respect to its financial derivative contracts is detailed in Note 12 of the Consolidated Financial Statements.
Critical Accounting Policies The preparation of the consolidated financial statements in accordance with generally accepted accounting principles requires management to make judgements and estimates that affect the financial results of the Company. These critical estimates are discussed below.
Oil and Gas Accounting Baytex follows the full-cost accounting guideline to account for its crude oil and natural gas properties. Under this method, all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized in one Canadian cost centre. These capitalized costs, along with estimated future development costs, are depleted and depreciated on a unit-of-production basis using estimated proven petroleum and natural gas reserves. Unit-of-production calculations are also used in the determination of the site restoration expense. By their inclusion in the unit-of-production calculation, reserve estimates are a significant component of the calculation of depletion and depreciation and site restoration expense.
8
Independent engineers engaged by the Company use all available geological, reservoir, and production performance data to prepare the reserve estimates. These estimates are reviewed and revised, either upward or downward, as new information becomes available. Revisions are necessary due to changes in assumptions based on reservoir performance, prices, economic conditions, government restrictions and other relevant factors. If reserve estimates are revised downward, net income could be affected by increased depletion and depreciation and site restoration expense.
Impairment of Petroleum and Natural Gas Assets Companies that use the full-cost method of accounting for oil and natural gas operations are required to perform a ceiling test each quarter that calculates a limit for the net carrying cost of petroleum and natural gas assets. The ceiling test calculation utilizes and holds constant the prices and costs in effect at the end of the period. An estimate is made of the ultimate recoverable amount from future net revenues using proved reserves and period end prices, plus the net costs of major development projects and unproved properties, less future removal and site restoration costs, overhead, financing costs and income taxes. The calculation of future net revenues in the ceiling test can be significantly impacted by fluctuations in any of these estimates. An impairment loss is recognized if the amount calculated under the ceiling test is less than the carrying costs of the Company’s petroleum and natural gas assets and can result in a significant loss for a particular period.
New Accounting Pronouncements In November 2002, the CICA amended its accounting guideline on hedging relationships, which was originally issued in November 2001. The guideline establishes certain conditions where hedge accounting may be applied. It is effective for years beginning on or after July 1, 2003.
The CICA has amended the Handbook sections dealing with cash flow statements and earnings per share to restrict the disclosure of cash flow per share amounts in the financial statements. Under the amended standard, effective January 1, 2003, companies are no longer permitted to disclose cash flow per share amounts on either the face of the cash flow statement or in the notes to the financial statements.
In December 2002, the CICA issued a new standard on the accounting for asset retirement obligations. This standard requires recognition of a liability at discounted fair value for the future abandonment and reclamation associated with petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized over its useful life. The liability accumulates until the date of expected settlement of the retirement obligations. The new standard is effective for all fiscal years beginning on or after January1, 2004. Baytex is currently assessing the impact the adoption of this new standard will have on its consolidated financial statements.
9
Quarterly Information
|
| 2002 |
| 2001 |
| ||||||||||||
|
| Q4 |
| Q3 |
| Q2 |
| Q1 |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
|
Financial (unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($thousands, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
| 100,590 |
| 94,633 |
| 91,507 |
| 79,130 |
| 64,327 |
| 101,689 |
| 84,454 |
| 79,230 |
|
Cash flow from operations |
| 53,116 |
| 48,637 |
| 49,208 |
| 40,125 |
| 24,353 |
| 46,330 |
| 35,770 |
| 37,617 |
|
Per share - basic |
| 1.00 |
| 0.93 |
| 0.95 |
| 0.77 |
| 0.47 |
| 0.89 |
| 0.74 |
| 0.82 |
|
- diluted |
| 0.99 |
| 0.91 |
| 0.93 |
| 0.76 |
| 0.47 |
| 0.87 |
| 0.72 |
| 0.80 |
|
Net income (loss) |
| 12,791 |
| 3,687 |
| 21,354 |
| 7,304 |
| (141,371 | ) | (4,626 | ) | 10,583 |
| (1,693 | ) |
Per share - basic |
| 0.24 |
| 0.07 |
| 0.41 |
| 0.14 |
| (2.71 | ) | (0.09 | ) | 0.22 |
| (0.04 | ) |
- diluted |
| 0.24 |
| 0.07 |
| 0.40 |
| 0.14 |
| (2.71 | ) | (0.09 | ) | 0.21 |
| (0.04 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional oil and NGLs (bbls/d) |
| 2,909 |
| 2,999 |
| 2,904 |
| 3,818 |
| 5,808 |
| 6,077 |
| 4,782 |
| 3,911 |
|
Heavy oil (bbls/d) |
| 25,009 |
| 23,504 |
| 24,498 |
| 22,838 |
| 24,528 |
| 29,078 |
| 26,545 |
| 25,970 |
|
Total oil and NGLs (bbls/d) |
| 27,918 |
| 26,503 |
| 27,402 |
| 26,656 |
| 30,336 |
| 35,155 |
| 31,327 |
| 29,881 |
|
Natural gas (mmcf/d) |
| 71.8 |
| 71.3 |
| 73.3 |
| 73.7 |
| 75.9 |
| 78.2 |
| 71.3 |
| 57.6 |
|
Barrels of oil equivalent (boe/d @ 6:1) |
| 39,890 |
| 38,391 |
| 39,625 |
| 38,948 |
| 42,990 |
| 48,187 |
| 43,201 |
| 39,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI oil (US$/bbl) |
| 28.15 |
| 28.27 |
| 26.25 |
| 21.64 |
| 20.43 |
| 26.49 |
| 27.96 |
| 28.73 |
|
Edmonton par oil ($/bbl) |
| 42.81 |
| 44.02 |
| 40.40 |
| 33.51 |
| 31.00 |
| 40.37 |
| 42.19 |
| 43.00 |
|
BTE light oil ($/bbl) |
| 37.67 |
| 37.36 |
| 34.53 |
| 27.58 |
| 25.41 |
| 35.37 |
| 37.53 |
| 38.65 |
|
BTE heavy oil ($/bbl) |
| 26.09 |
| 31.03 |
| 26.64 |
| 21.58 |
| 10.39 |
| 23.75 |
| 16.77 |
| 14.62 |
|
BTE total oil ($/bbl) |
| 27.30 |
| 31.75 |
| 27.47 |
| 22.44 |
| 13.27 |
| 25.76 |
| 19.94 |
| 17.77 |
|
BTE natural gas ($/mcf) |
| 5.29 |
| 3.33 |
| 3.94 |
| 3.19 |
| 3.09 |
| 3.35 |
| 5.11 |
| 6.83 |
|
BTE oil equivalent ($/boe) |
| 28.64 |
| 28.10 |
| 26.29 |
| 21.39 |
| 14.82 |
| 24.23 |
| 22.88 |
| 23.41 |
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Share Trading Information |
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BTE - TSX |
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High ($) |
| 8.92 |
| 8.40 |
| 8.45 |
| 6.89 |
| 5.25 |
| 11.50 |
| 13.55 |
| 14.84 |
|
Low ($) |
| 6.65 |
| 5.65 |
| 6.35 |
| 3.95 |
| 3.00 |
| 4.64 |
| 9.60 |
| 9.00 |
|
Close ($) |
| 8.48 |
| 7.59 |
| 7.20 |
| 6.85 |
| 4.37 |
| 4.80 |
| 9.80 |
| 12.15 |
|
Average daily volume |
| 296,000 |
| 164,000 |
| 293,000 |
| 270,000 |
| 455,000 |
| 156,000 |
| 203,000 |
| 191,000 |
|
10