Baytex Energy Trust Announces Record Production and Cash Flow for 2007
Posted on: Wednesday, 12 March 2008, 09:00 CDT
Baytex Energy Trust (TSX: BTE.UN) (NYSE: BTE) is pleased to announce its operating and financial results for the three months and year ended December 31, 2007.
Highlights
- Record cash flow of $98.7 million ($1.10 per diluted unit) for the fourth quarter of 2007, 32% higher than the previous record set in Q3/07;
- Record cash flow of $286 million ($3.34 per diluted unit) for 2007, 4% higher than the previous record set in 2006;
- Record average quarterly production of 39,304 boe/d for Q4/07 and annual production of 36,222 boe/d for 2007;
- Maintained monthly distributions at $0.18 per unit, with conservative and sustainable payout ratios of 38% after DRIP (46% before DRIP) for Q4/07 and 51% after DRIP (61% before DRIP) for 2007;
- Increased proved plus probable reserves by 16% to 168.1 million boe at year end 2007;
- Replaced 123% of production through an exploration and development capital program equal to 52% of cash flow and 274% of production through an overall capital program (including acquisitions) equal to 138% of cash flow;
- Achieved finding, development and acquisition ("FD&A") costs of $10.90/boe (one-year) and $7.83/boe (three-year); - Realized recycle ratios of 2.4 (one-year) and 3.4 (three-year); and
- Improved financial position with year-end total monetary debt of $444 million or 1.3 times annualized second half 2007 cash flow.
FINANCIAL Three Months Ended Year Ended -------------------------------------------------- ($ thousands, except per December September December December December unit amounts) 31, 2007 30, 2007 31, 2006 31, 2007 31, 2006 -------------------------------------------------- Petroleum and natural gas sales 197,348 164,228 134,541 618,927 556,689 Cash flow from operations (1) 98,667 74,957 63,519 286,030 274,662 Per unit - basic 1.17 0.90 0.85 3.57 3.77 - diluted 1.10 0.84 0.79 3.34 3.45 Cash distributions 37,314 38,746 34,516 145,927 143,072 Per unit 0.54 0.54 0.54 2.16 2.16 Net Income 41,353 36,674 19,988 132,860 147,069 Per unit - basic 0.49 0.44 0.27 1.66 2.02 - diluted 0.48 0.43 0.26 1.60 1.91 Exploration and development 34,349 43,533 24,343 148,719 132,381 Acquisitions - net of dispositions 5,064 752 7 245,427 702 Total capital expenditures 39,413 44,285 24,350 394,146 133,083 Long-term notes 177,805 179,280 209,691 177,805 209,691 Bank loan 241,748 259,328 127,495 241,748 127,495 Convertible debentures 16,150 16,531 18,906 16,150 18,906 Working capital deficiency 8,362 12,189 10,718 8,362 10,718 Total monetary debt 444,065 467,328 366,810 444,065 366,810 Three Months Ended Year Ended -------------------------------------------------- December September December December December 31, 2007 30, 2007 31, 2006 31, 2007 31, 2006 -------------------------------------------------- OPERATING Daily production Light oil & NGL (bbl/d) 8,123 6,556 3,643 5,483 3,735 Heavy oil (bbl/d) 22,196 22,593 22,416 22,092 21,325 Total oil (bbl/d) 30,319 29,149 26,059 27,575 25,060 Natural gas (MMcf/d) 53.9 53.7 51.4 51.9 55.4 Oil equivalent (boe/d @ 6:1) 39,304 38,094 34,631 36,222 34,292 Average prices (before hedging) WTI oil (US$/bbl) 90.68 75.38 60.21 72.31 66.22 Edmonton par oil ($/bbl) 86.41 80.24 64.49 76.35 72.77 BTE light oil & NGL ($/bbl) 74.77 67.82 48.62 65.53 53.84 BTE heavy oil ($/bbl) 50.13 45.89 41.15 44.28 43.57 BTE total oil ($/bbl) 56.37 50.85 42.19 48.45 45.10 BTE natural gas ($/Mcf) 6.31 5.80 7.03 6.61 7.13 BTE oil equivalent ($/boe) 52.32 47.06 42.19 46.38 44.48 TRUST UNIT INFORMATION TSX (C$) Unit price High $20.65 $21.45 $25.82 $22.92 $28.66 Low $18.08 $16.68 $18.95 $16.68 $16.81 Close $19.00 $20.13 $22.28 $19.00 $22.28 Volume traded (thousands) 17,426 26,365 31,901 86,185 102,652 NYSE (US$) (2) Unit price High $21.74 $21.03 $22.84 $21.74 $25.87 Low $18.19 $15.51 $16.63 $15.51 $16.63 Close $19.11 $20.33 $18.96 $19.11 $18.96 Volume traded (thousands) 5,433 5,315 8,580 18,063 21,496 Units outstanding (thousands) (3) 87,169 86,478 77,498 87,169 77,498 (1) Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other operating items (see reconciliation under MD&A). The Trust's cash flow from operations may not be comparable to other companies. The Trust considers cash flow a key measure of performance as it demonstrates the Trust's ability to generate the cash flow necessary to fund future distributions and capital investments. (2) Data reflects the periods since commencement of trading on March 27, 2006 on the NYSE. (3) Number of trust units outstanding includes the conversion of exchangeable shares at the respective exchange ratios in effect at the end of the reporting periods.
Operations Review
Capital expenditures for exploration and development activities totaled $34.3 million for the fourth quarter of 2007. During this quarter, Baytex participated in the drilling of 16 (12.2 net) wells, resulting in 11 (9.9 net) oil wells, three (0.3 net) gas wells, one (1.0 net) service well and one (1.0 net) dry hole for a 94% (91.9% net) success rate. In addition, two wells were drilled by other operators on farm-outs from Baytex, with Baytex retaining overriding royalty interests.
Production averaged 39,304 boe/d during the fourth quarter compared to 38,094 for the third quarter of this year. The fourth quarter volume includes 460 boe/d of under-accrued production from the previous quarter. The average production for the second half of 2007, reflecting the acquisition of the assets at Pembina and Lindbergh completed at the end June, was 38,698 boe/d. At Pembina, production averaged 5,124 boe/d during the second half of 2007, exceeding the 3,500 boe/d production level at the announcement of this acquisition in May of this year. Battery and compression modifications conducted since the purchase have increased operational reliability, which, together with improved industry cooperation, have contributed to production from this area exceeding expectations. Baytex is maintaining our 2008 average production guidance of between 37,000 and 38,000 boe/d as production is expected to be modestly curtailed by severe cold weather in the first quarter and spring break-up conditions in the second quarter. The exploration and development capital budget to deliver this production level is set at $150 million.
Financial Review
Cash flow from operations for the fourth quarter was a record $98.7 million, an increase of 32% compared to $75.0 million for the third quarter of 2007. Baytex received an average oil price of $56.37/bbl in the fourth quarter, an increase of 11% compared to $50.85/bbl in the third quarter as benchmark WTI price increased 20% to an average of US$90.68/bbl. Natural gas prices also improved in the fourth quarter, with Baytex receiving an average wellhead price of $6.31/Mcf, 9% higher than that in the third quarter. In addition to the increase in production and commodity prices, cash flow in the fourth quarter was aided by the following non-recurring items. Firstly, with the expiry of the Frontier heavy oil supply agreement on December 31, 2007, inventory in transit via the Express Pipeline was settled at year-end, resulting in an additional $6.0 million of sales proceeds being reported in the fourth quarter. A similar amount of sales proceeds from inventory adjustment will also be recorded in the first quarter of 2008. Secondly, we terminated the interest rate swap arrangement associated with our senior subordinated notes during the quarter, resulting in a cash gain of $2.0 million. We have reverted to paying the fixed rate coupon of 9.625% on these notes.
Lloyd Blend heavy oil pricing differentials averaged 36% of WTI price for the fourth quarter compared to 29% in the third quarter, in part due to lower seasonal demand. This higher differential was also caused by several operational issues in December, including the shut-down of the main pipeline to the Chicago refining region for a short period following an accident, and two refinery accidents affecting Canadian through-put. These issues have since been rectified, and Lloyd Blend differential has narrowed significantly and is expected to average below 25% in the first quarter of 2008, reflecting fundamental improvements brought on by infrastructure development and supply issues affecting the North American market.
The cash flow capability of Baytex's asset base under prevailing commodity prices is demonstrated by our results in the second half of 2007. Our average production of 38,698 boe/d in the second half was 77% weighted towards crude oil. Cash flow in this six-month period was $174 million ($2.09 per basic unit), generated under average benchmarks of WTI price at US$83.03, CAD/USD exchange rate at 1.0132, Lloyd Blend differential at 33% and AECO monthly index gas price at C$5.65/Mcf. Capital spending during this period was $84 million, or 48% of cash flow. Combined with payout ratios in the second half of 44% net of DRIP and 52% before DRIP, our financial position continued to improve alongside operational gains. Total net monetary debt, excluding notional mark-to-market liabilities and future income tax assets at the end of the year, was $444 million and represented a reduction of $23 million from the end of the third quarter. This net debt represents 1.3 times annualized second half 2007 cash flow. Baytex's excellent financial strength, together with our industry-leading capital efficiency and prudent operational and financial practices, will position us well to continue to deliver superior market performance under the current operating environment.
Capital Program Efficiency
Since the conversion to an income trust in late 2003, Baytex has consistently demonstrated superior capital and operational efficiencies as we prudently execute our strategy for long-term sustainability. Based on the reports prepared in accordance with National Instrument ("NI") 51-101 by our independent reserves evaluator, Sproule Associates Limited ("Sproule"), the efficiency of Baytex's capital programs is summarized as follows:
Three Year Average 2007 2005 - 2007 ----------------------- Excluding Changes in Future Development Costs (1) ------------------------------------------------- FD&A Costs - Proved ($/boe) Exploration and development $ 10.03 $ 9.53 Acquisitions (net of dispositions) 20.63 10.00 ----------------------- Total $ 14.75 $ 9.71 ----------------------- ----------------------- FD&A costs - Proved plus Probable ($/boe) Exploration and development $ 9.17 $ 8.19 Acquisitions (net of dispositions) 12.30 7.32 ----------------------- Total $ 10.90 $ 7.83 ----------------------- ----------------------- Operating Netback ($/boe) $ 26.42 $ 26.34 Recycle Ratio - Proved plus Probable 2.4 3.4 Reserves Replacement Ratio - Proved plus Probable 274% 224% Including Changes in Future Development Costs (1) ------------------------------------------------- FD&A costs - Proved ($/boe) Exploration and development $ 8.82 $ 14.12 Acquisitions (net of dispositions) 22.93 12.11 ----------------------- Total $ 15.10 $ 13.35 ----------------------- ----------------------- FD&A costs - Proved plus Probable ($/boe) Exploration and development $ 9.27 $ 12.15 Acquisitions (net of dispositions) 14.05 8.87 ----------------------- Total $ 11.91 $ 10.76 ----------------------- ----------------------- (1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Net Asset Value
The following net asset value calculation utilizes what is generally referred to as the "produce-out" net present value of Baytex's oil and gas reserves as evaluated by Sproule. It does not take into account the possibility of Baytex being able to recognize additional reserves through future capital investment in our existing properties beyond those included in the 2007 year-end report.
Forecast Prices Before Tax -------------------------- ($ thousands) ------------- Proved plus probable reserves (1) 2,494,267 Undeveloped land (2) 117,907 Net debt (3) (427,915) Asset retirement obligations (45,113) ------------- Net asset value 2,139,146 ------------- ------------- Diluted trust units (4) 88,295,627 Net asset value per trust unit $24.23 Forecast Prices After Tax ------------------------- ($ thousands) ------------- Proved plus probable reserves (1) 2,214,845 Undeveloped land (2) 117,907 Net debt (3) (427,915) Asset retirement obligations (45,113) ------------- Net asset value 1,859,724 ------------- ------------- Diluted trust units (4) 88,295,627 Net asset value per trust unit $21.06 Notes: (1) Net present value of future net revenue discounted at 10% as evaluated by Sproule as at December 31, 2007. Net present value of future net revenue does not represent fair market value of the reserves. (2) As evaluated by Baytex as at December 31, 2007 on 638,975 net acres of undeveloped land. (3) Long-term debt net of working capital as at December 31, 2007, excluding convertible debentures, future income tax assets, and notional liabilities associated with the mark-to-market value of derivative contracts. (4) Includes 84,539,945 trust units, 1,565,615 exchangeable shares converted at an exchange ratio of 1.67915 and 1,126,780 trust units issuable on the conversion of the outstanding convertible debentures as at December 31, 2007.
Oil and Gas Reserves
Baytex announced certain of its year-end 2007 reserves information on February 20, 2008. Following is additional summary information with regard to oil and gas reserves as at December 31, 2007. Other detailed information as required under NI 51-101 will be included in Baytex's Annual Information Form.
Reconciliation of Gross Company Interest Reserves (1)() By Principal Product Type Forecast Prices and Costs ---------------------------------------------------------------------------- Light and Medium Crude Oil Heavy Oil --------------------------------------------------------- Proved + Proved + Proved Probable Probable Proved Probable Probable (2) (2) (2) (2) (2) (2) --------------------------------------------------------- (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) December 31, 2006 5,186 2,044 7,230 75,808 32,929 108,737 Extensions 72 21 93 8,252 3,187 11,439 Discoveries - - - - - - Improved Recoveries 329 322 651 3,362 1,127 4,489 Technical Revisions (344) (2,463) (2,807) 1,989 (1,014) 975 Acquisitions 6,081 5,292 11,373 2,997 770 3,767 Dispositions - - - - - - Economic Factors 114 79 193 725 393 1,118 Production (1,401) - (1,401) (8,064) - (8,064) --------------------------------------------------------- December 31, 2007 10,037 5,295 15,332 85,069 37,392 122,461 --------------------------------------------------------- --------------------------------------------------------- Natural Gas Liquids Natural Gas including solution gas --------------------------------------------------------- Proved + Proved+ Proved Probable Probable Proved Probable Probable (2) (2) (2) (2) (2) (2) --------------------------------------------------------- (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf) December 31, 2006 3,462 1,014 4,476 108,421 39,637 148,058 Extensions 80 41 121 3,680 977 4,657Discoveries 9 2 11 2,275 586 2,861 Improved Recoveries - - - 2,767 718 3,485 Technical Revisions (198) 170 (28) (7,147) (5,831) (12,978) Acquisitions 838 638 1,476 11,871 8,140 20,011 Dispositions - - - - - - Economic Factors 12 5 17 1,039 661 1,700 Production (600) - (600) (18,937) - (18,937) --------------------------------------------------------- December 31, 2007 3,603 1,870 5,473 103,969 44,888 148,857 --------------------------------------------------------- --------------------------------------------------------- Oil Equivalent (3) -------------------------- Proved + Proved Probable Probable (2) (2) (2) ---------------------------- (Mboe) (Mboe) (Mboe) December 31, 2006 102,528 42,592 145,120 Extensions 9,017 3,412 12,429 Discoveries 388 100 488 Improved Recoveries 4,152 1,569 5,721 Technical Revisions 254 (4,277) (4,023) Acquisitions 11,895 8,056 19,951 Dispositions - - - Economic Factors 1,025 586 1,611 Production (13,221) - (13,221) ---------------------------- December 31, 2007 116,038 52,038 168,076 ---------------------------- ---------------------------- Notes: (1) Gross Company interest reserves include solution gas but do not include royalty interest. (2) Reserves information as at December 31, 2006 and 2007 is prepared in accordance with NI 51-101. (3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Management's Discussion and Analysis
Management's discussion and analysis ("MD&A"), dated March 11, 2008, should be read in conjunction with the unaudited interim consolidated financial statements for the three months and year ended December 31, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006. 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 equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boe's may be misleading, particularly if used in isolation.
Non-GAAP Financial Measures
This MD&A refers to certain financial measures, such as payout ratio and cash flow from operations, that are not in accordance with Generally Accepted Accounting Principles ("GAAP") in Canada. These measures do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. We discuss these measures because we believe that they facilitate the understanding of the results of our operations and financial position.
Production. Light oil and natural gas liquids ("NGL") production for the fourth quarter of 2007 increased by 123% to 8,123 bbl/d from 3,643 bbl/d a year earlier primarily as a result of the acquisition of the Pembina assets near the end of the second quarter of 2007. Heavy oil production was little changed from year-ago levels, averaging 22,196 bbl/d for the fourth quarter of 2007 compared to 22,416 bbl/d a year ago. Natural gas production increased by 5% to 53.9 MMcf/d for the fourth quarter of 2007 compared to 51.4 MMcf/d for the same period last year. The increase was primarily the result of the Pembina acquisition offsetting natural declines during a quarter in which Baytex engaged in a very low level of gas development activity due to economic factors.
For the year ended December 31, 2007, light oil and NGL production increased by 47% to 5,483 bbl/d from 3,735 bbl/d for last year. Heavy oil production for 2007 increased by 4% to 22,092 bbl/d compared to 21,325 bbl/d for 2006. Natural gas production decreased by 6% to an average 51.9 MMcf/d for 2007 compared to 55.4 MMcf/d for 2006.
Revenue. Petroleum and natural gas sales increased 47% to $197.4 million for the fourth quarter of 2007 from $134.5 million for the same period in 2006.
For the per sales unit calculations, heavy oil sales for the three months ended December 31, 2007 were 1,717 bbl/d higher (three months ended December 31, 2006 - 28 bbl/d higher) than the production for the period due to sales of pipeline inventory pursuant to the expiry of the Frontier supply agreement. The corresponding number for the year ended December 31, 2007 was an increase of 340 bbl/d (year ended December 31, 2006 - a decrease of 4 bbl/d).
Three Months ended December 31 --------------------------------------- 2007 2006 ------------------- ------------------- $000s $/Unit(1) $000s $/Unit(1) --------- --------- --------- --------- Oil revenue (barrels) Light oil & NGL 55,872 74.77 16,294 48.62 Heavy oil 110,281 50.13 84,961 41.15 Derivative contracts gain (loss) (4,367) (1.99) 503 0.24 --------- --------- --------- --------- Total oil revenue 161,786 54.89 101,758 42.40 Natural gas revenue (Mcf) 31,285 6.31 33,286 7.03 --------- --------- --------- --------- Total revenue (boe) 193,071 51.16 135,044 42.35 --------- --------- --------- --------- --------- --------- --------- --------- (1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is in $/Mcf.
Revenue from light oil and NGL for the fourth quarter of 2007 increased 243% from the same period a year ago due to a 123% increases in sales volume and a 54% increase in wellhead prices. Revenue from heavy oil increased 30% as the result of a 22% increase in wellhead prices in addition to a 7% increase in sales volume. Revenue from natural gas decreased 6% as the result of a 5% increase in volume offset by a 10% decrease in wellhead prices.
Year ended December 31 --------------------------------------- 2007 2006 ------------------- ------------------- $000s $/Unit(1) $000s $/Unit(1) --------- --------- --------- --------- Oil revenue (barrels) Light oil & NGL 131,143 65.53 73,387 53.84 Heavy oil 362,549 44.28 339,066 43.57 Derivative contracts gain (loss) (3,164) (0.39) 2,529 0.32 --------- --------- --------- --------- Total oil revenue 490,528 48.14 414,982 45.38 Natural gas revenue (Mcf) 125,235 6.61 144,236 7.13 --------- --------- --------- --------- Total revenue (boe) 615,763 46.14 559,218 44.68 --------- --------- --------- --------- --------- --------- --------- --------- (1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is in $/Mcf.
For the year ended December 31, 2007, light oil and NGL revenue increased 79% from last year due to a 22% increase in wellhead prices and a 47% increase in volume. Revenue from heavy oil increased by 7% from last year, as a result of a 2% increase in wellhead prices and a 5% increase in sales volume. Revenue from natural gas decreased 13% compared to 2006 due to a 6% decrease in volume combined with a 7% decrease in wellhead prices.
Royalties. Total royalties increased to $32.5 million for the fourth quarter of 2007 from $18.5 million in 2006. Total royalties for the fourth quarter of 2007 were 16.5% of sales compared to 13.8% of sales for the same period in 2006. For the fourth quarter of 2007, royalties were 19.9% of sales for light oil, NGL and natural gas, and 13.7% for heavy oil. These rates compared to 16.6% and 12.1%, respectively, for the same period last year. Royalties are generally based on market index prices realized by the industry in the period, with rates increasing as price and volume escalate. For the year ended December 31, 2007, royalties increased to $102.8 million from $85.0 million for last year. Total royalties for the year ended December 31, 2007 were 16.6% of sales, compared to 15.3% of sales a year ago. For 2007, royalties were 18.8% of sales for light oil, NGL and natural gas and 15.1% for heavy oil. These rates compared to 16.3% and 14.6%, respectively, for 2006.
Operating Expenses. Operating expenses for the fourth quarter of 2007 increased to $38.7 million from $29.8 million in the corresponding quarter last year. Operating expenses were $10.25 per boe for the fourth quarter of 2007 compared to $9.36 per boe for the fourth quarter of 2006. For the fourth quarter of 2007, operating expenses were $9.67 per boe of light oil, NGL and natural gas, and $10.66 per barrel of heavy oil. The operating expenses for the same period a year ago were $9.15 and $9.47, respectively. The increase in operating costs for conventional oil and gas was in part due to the addition of higher cost sour operations at Pembina. With respect to our operations, in general, the inflationary environment affecting operating costs has not entirely subsided as certain cost categories such as property taxes, labour costs and fuel costs continued to increase. This is particularly prevalent in heavy oil operating areas as industry activity levels remain strong due to robust economics associated with the current heavy oil pricing environment.
Operating expenses for 2007 increased to $134.7 million from $112.4 million in 2006. Operating expenses were $10.09 per boe for 2007 compared to $8.98 per boe for the prior year. In 2007, operating expenses were $9.61 per boe of light oil, NGL and natural gas and $10.40 per barrel of heavy oil compared to $8.58 and $9.23, respectively, for the year earlier.
Transportation Expenses. Transportation expenses for the fourth quarter of 2007 were $7.5 million compared to $6.4 million for the fourth quarter of 2006. These expenses were $1.98 per boe for the fourth quarter of 2007 compared to $2.00 for the same period in 2006. Transportation expenses were $0.67 per boe of light oil, NGL and natural gas and $2.92 per barrel of heavy oil. The corresponding amounts for fourth quarter of 2006 were $0.82 and $2.64, respectively.
Transportation expenses for 2007 were $28.8 million compared to $24.3 million for 2006. These expenses were $2.16 per boe in 2007 compared to $1.95 in 2006. Transportation expenses were $0.80 per boe of light oil, NGL and natural gas and $3.01 per barrel of heavy oil in 2007, compared to $0.87 and $2.60, respectively, in 2006. The increase in transportation expenses for heavy oil primarily reflects higher fuel costs and longer haul distances for production at Seal in order to access higher value markets.
General and Administrative Expenses. General and administrative expenses for the fourth quarter of 2007 increased to $6.8 million from $5.9 million a year earlier. On a per sales unit basis, these expenses were $1.81 per boe for the fourth quarter of 2007 compared to $1.84 per boe for the same period in 2006. In accordance with our full cost accounting policy, no expenses were capitalized in either period.
General and administrative expenses for 2007 were $23.6 million, compared to $20.8 million for the prior year. On a per sales unit basis, these expenses were $1.77 per boe in 2007 and $1.67 per boe in 2006. In accordance with our full cost accounting policy, no expenses were capitalized in either 2007 or 2006.
Unit-based Compensation Expense. Compensation expense related to the Trust's unit rights incentive plan was $1.8 million for the fourth quarter of 2007 compared to $2.2 million for the fourth quarter of 2006. For the year-ended December 31, 2007, compensation expense was $8.0 million compared to $7.5 million for 2006.
Compensation expense associated with rights granted under the plan is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. The exercise of trust unit rights are recorded as an increase in trust units with a corresponding reduction in contributed surplus.
Interest Expenses. Interest expense for the fourth quarter of 2007 remained consistent at $8.7 million compared to the same quarter last year. Interest expense was affected by the recognition of a $2.0 million gain on the termination of the interest rate swap associated with the senior subordinated notes, a more favourable exchange rate on the U.S. dollar denominated interest expenses, offset by the accretion of the deferred adjustment on adoption of Section 3865 and by higher interest on increased bank borrowings.
In 2007, interest expense was $35.2 million compared to $35.0 million for last year. The items affecting interest expense are the same factors influencing the fourth quarter variance.
Foreign Exchange. Foreign exchange gain in the fourth quarter of 2007 was $1.3 million compared to a loss of $9.0 million in the fourth quarter of 2006. The 2007 amount is comprised of an unrealized foreign exchange gain of $1.5 million and a realized foreign exchange loss of $0.2 million. The loss in the 2006 period was entirely unrealized. The current quarter's unrealized gain is based on the translation of the U.S. dollar denominated long-term debt at 1.0120 at December 31, 2007 compared to 1.0037 at September 30, 2007. The prior period loss is based on translation at 0.8581 at December 31, 2006 compared to 0.8966 at September 30, 2006.
Foreign exchange gain for 2007 was $32.5 million compared to $0.1 million in the prior year. The 2007 gain is comprised of an unrealized foreign exchange gain of $32.6 million and a realized foreign exchange loss of $0.1 million. The 2006 gain was substantially unrealized. The 2007 unrealized gain is based on the translation of the U.S. dollar denominated long-term debt at 1.0120 at December 31, 2007 compared to 0.8581 at December 31, 2006. The 2006 unrealized gain is based on translation at 0.8581 at December 31, 2006 compared to 0.8577 at December 31, 2005.
Depletion, Depreciation and Accretion. The provision for depletion, depreciation and accretion for the fourth quarter of 2007 increased to $54.1 million from $39.5 million for the same quarter in 2006. On a sales-unit basis, the provision for the current quarter was $14.33 per boe compared to $12.38 per boe for the same quarter in 2006. The higher rate is due to increased future development costs reflected in the reserves evaluation, the higher per unit cost of the proved reserves acquired at the end of the second quarter of 2007, as well as the resulting accounting adjustments for future income taxes and asset retirement obligations.
Depletion, depreciation and accretion increased to $189.5 million for the year ended December 31, 2007 compared to $152.6 million for 2006. On a sales-unit basis, the provision for the current year was $14.20 per boe compared to $12.19 per boe for 2006. The increase is attributable to the same factors influencing the fourth quarter calculations.
Taxes. On June 22, 2007, the federal government's bill (the "government's bill") regarding the taxation of distributions of publicly traded income trusts beginning January 1, 2011 received Royal Assent. As a result, a future income tax recovery of $0.5 million was recognized in the second quarter relating to unutilized tax pools in the Trust which will be deductible to the Trust after 2010. The majority of the Trust's temporary differences resides in a consolidated subsidiary which is not subject to the distribution tax, and is therefore not impacted by this legislative change.
The government's bill provides that the new tax regime for income trusts will not apply until January 1, 2011 so long as the Trust experiences only "normal growth" and no "undue expansion". As part of the government's bill, a "safe harbour" limit was established for existing income trusts by limiting future equity issues to 40 percent of that trust's October 31, 2006 market capitalization for the period November 1, 2006 to December 31, 2007, and an additional 20 percent of this market capitalization for each of 2008, 2009 and 2010. For Baytex, the limits are approximately $730 million for 2006 / 2007 and $365 million for each of the subsequent three years. Issuance of equity or convertible debt beyond these limits will result in the new regime applying to the Trust before 2011.
The provision for future income taxes for the current quarter was a recovery of $27.6 million compared to a recovery of $10.2 million in the same period in 2006. For the year ended December 31, 2007, the provision for future income taxes was a recovery of $49.3 million compared to a recovery of $41.2 million for 2006. As a result of the Pembina/Lindbergh acquisition, Baytex recognized a future income tax liability of $74.5 million arising from the difference between the $64.0 million in tax pools acquired and the value assigned to the assets.
Current tax of $2.1 million for the fourth quarter of 2007 is comprised primarily of Saskatchewan Capital Tax and Resource Surcharge. Current tax for the same period a year ago was $2.5 million which included $1.8 million of Saskatchewan Capital Tax and Resource Surcharge and a $0.7 million adjustment of Large Corporation Tax, which tax was eliminated during 2006.
Current tax expenses were $6.7 million for the year ended December 31, 2007 compared to $8.4 million for 2006. The 2007 current tax expense is comprised of $7.2 million of Saskatchewan Capital Tax and Resource Surcharge and a recovery of $0.5 million relating to prior period recoveries. The 2006 current tax expense included $8.2 million of Saskatchewan Capital Tax and Resource Surcharge, a recovery of $0.4 million of Large Corporation Taxes and $0.6 million of prior period adjustments.
Net Income. Net income for the fourth quarter of 2007 was $41.4 million compared to $20.0 million for the fourth quarter in 2006. The variance was the result of higher production, higher sales prices, foreign exchange gains and future income tax recovery, offset by higher operating costs. Net income for 2007 was $132.9 million compared to $147.1 million for 2006. The variance was due to higher operating and transportations costs, higher depletion rates, and higher general and administrative costs. These negative factors were partially offset by higher sales volumes and prices and a higher foreign exchange gain.
Cash Flow from Operations, Payout Ratio and Distributions
Cash flow from operations and payout ratio are non-GAAP terms. Cash flow from operations represents cash flow from operating activities before changes in non-cash working capital and other operating items. The Trust's payout ratio is calculated as cash distributions declared divided by cash flow from operations. The Trust considers these to be key measures of performance as they demonstrate the Trust's ability to generate the cash flow necessary to fund future distributions and capital investments.
Three Months Ended Year Ended -------------------------------------------------- December September December December December 31, 2007 30, 2007 31, 2006 31, 2007 31, 2006 -------------------------------------------------- Cash flow from operating activities $100,131 $ 73,722 $ 60,999 $286,450 $261,982 Change in non-cash working capital (3,145) 308 1,878 (5,140) 9,058 Asset retirement expenditures 1,131 351 233 2,442 1,747 Decrease (increase) in deferred charges and other assets 550 576 409 2,278 1,875 --------- --------- --------- --------- --------- Cash flow from operations $ 98,667 $ 74,957 $ 63,519 $286,030 $274,662 --------- --------- --------- --------- --------- Cash Distributions declared $ 37,314 $ 38,746 $ 34,516 $145,927 $143,072 Payout ratio (1) 38% 52% 54% 51% 52% (1) Payout ratio is calculated as cash distributions declared divided by cash flow from operations
The Trust does not deduct capital expenditures when calculating the payout ratio. Due to the depleting nature of oil and gas assets, certain levels of capital expenditures are required to minimize production declines. In the oil and gas industry, due to the nature of reserves 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 oil and natural gas assets increase significantly, it is possible that the Trust would be required to reduce or eliminate its distributions in order to fund capital expenditures. There can be no certainty that the Trust will be able to maintain current production levels in future periods.
Cash distributions of $37.3 million for the fourth quarter of 2007 were funded through cash flow from operations of $98.7 million. For the year ended December 31, 2007, cash distributions of $145.9 million were funded through cash flow from operations of $286.0 million.
The following tables compare cash distributions to cash flow from operating activities and net income:
Three Months Ended Year Ended December 31, December 31, ------------------- ------------------- 2007 2006 2007 2006 --------- --------- --------- --------- Cash flow from operating activities $100,131 $ 60,999 $286,450 $261,982 Actual cash distributions payable 37,314 34,516 145,927 143,072 --------- --------- --------- --------- Excess of cash flow from operating activities over cash distributions paid $ 62,817 $ 26,483 $140,523 $118,910 --------- --------- --------- --------- Net Income $ 41,353 $ 19,988 $132,860 $147,069 Actual cash distributions payable 37,314 34,516 145,927 143,072 --------- --------- --------- --------- Excess (shortfall) of net income over cash distributions paid $ 4,039 $(14,528) $(13,067) $ 3,997 --------- --------- --------- ---------
It is Baytex's long term operating objective to substantially fund cash distributions and capital expenditures required to maintain production and reserves through cash flow from operating activities. Future production levels are highly dependant 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 distributions. During periods of temporary decline in commodity prices, or periods of higher capital spending for acquisitions, it is possible that internally generated cash flow will not be sufficient to fund both cash distributions and capital spending. In these instances, the cash shortfall will be funded through a combination of equity and debt financing. As at December 31, 2007, Baytex had approximately $120 million in available credit facilities to fund such shortfall. As Baytex strives to maintain a consistent distribution level under the guidance of prudent financial parameters, there may be times when a portion of our cash distributions would represent a return of capital.
For the three months ended December 31, 2007, the Trust's net income exceeded cash distributions by $4.0 million. For the year ended December 31, 2007, the Trust's cash distribution exceeded net income by $13.1 million with net income reduced by $153.6 million of non-cash items. Non-cash charges such as depletion, depreciation and accretion are not 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. At December 31, 2007, total net monetary debt was $444 million compared to $367 million at the end of 2006. The increase is mainly attributable to the bank loan incurred to partially finance the acquisition of the Pembina and Lindbergh properties at the end of the second quarter. Bank borrowings and working capital deficiency at the end of fourth quarter 2007 was $250.1 million compared to total credit facilities of $370 million. The syndicated credit facilities were increased from $300 million to $370 million during June 2007.
Corporate Acquisition. On June 26, 2007, Baytex acquired all the issued and outstanding shares of a private company which had interests in certain petroleum and natural gas properties and related assets located primarily in the Pembina and Lindbergh areas of Alberta. The results of operations from these properties have been included in the consolidated financial statements since June 26, 2007. The acquisition was financed partly by the issuance of equity and partly by bank loan. Subsequent to the acquisition, the private company was amalgamated with Baytex.
Capital Expenditures Capital expenditures for the three months and years ended December 31, 2007 and 2006 are summarized as follows: Three Months Ended Year Ended December 31, December 31 --------------------------------------- ($thousands) 2007 2006 2007 2006 --------- -------- -------- -------- Land 1,197 3,277 7,253 11,118 Seismic 471 239 1,994 2,202 Drilling and completion 23,041 18,019 108,106 97,273 Equipment 8,148 2,439 26,624 19,240 Other 1,492 369 4,742 2,548 --------- -------- -------- -------- Total exploration and development 34,349 24,343 148,719 132,381 Corporate acquisition (net of working capital) 3,389 - 243,273 - Property acquisitions 2,038 37 2,877 1,530 Property dispositions (363) (30) (723) (828) --------- -------- -------- -------- Total capital expenditures 39,413 24,350 394,146 133,083 --------- -------- -------- -------- --------- -------- -------- --------
Changes in Accounting Policies. Effective January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants ("CICA") section 3855 "Financial Instruments - Recognition and Measurement", section 3865 "Hedges", section 1530 "Comprehensive Income" and section 3861 "Financial Instruments - Disclosure and Presentation". These standards have been adopted prospectively. See Note 2 to the Consolidated Financial Statements for further detail and the impact on the Trust's financial statements from application of these new standards.
Effective January 1, 2007 the Trust also adopted the recommendation of CICA revised section 1506 "Accounting Changes" and section 3251 "Equity". The revised section 1506 provides clarification on the criteria for changes in accounting policies as well as the accounting treatment and disclosure of changes in accounting policies, changes in estimates and corrections of errors. The revised section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period. 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. In 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of Baytex.
On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12% starting July 1, 2007; if such reduction is not initially possible the companies owning the large emitting facilities will be required to pay $15 per tonne for every tonne above the 12% target. These payments will be deposited into an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support research into innovative climate change solutions. As an alternate option, large emitters can invest in projects outside of their operations that reduce or offset emissions on their behalf, provided that these projects are based in Alberta. Prior to investing, the offset reductions, offered by a prospective operation, must be verified by a third party to ensure that the emission reductions are real.
The Federal Government released on April 26, 2007, its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as ecoACTION and which includes the Regulatory Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Regarding large industry and industry related projects the Government's Action Plan intends to achieve the following: (i) an absolute reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing mandatory targets; and (ii) air pollution from industry is to be cut in half by 2015 by setting certain targets. New facilities using cleaner fuels and technologies will have a grace period of three years. In order to facilitate the companies' compliance of the Action Plan's requirements, while at the same time allowing them to be cost-effective, innovative and adopt cleaner technologies, certain options are provided. These are: (i) in-house reductions; (ii) contributions to technology funds; (iii) trading of emissions with below-target emission companies; (iv) offsets; and (v) access to Kyoto's Clean Development Mechanism.
The Federal Government and the Province of Alberta released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and targeting research to lower the cost of technology.
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 our operations and financial condition.
The New Royalty Framework
On September 18, 2007, the Royalty Review Panel appointed by the Alberta government released a report entitled "Our Fair Share", providing recommendations on changes to the province's royalty regime. On October 25, 2007, the Alberta government announced the "New Royalty Framework", accepting many of the recommendations by the Royalty Review Panel. Major changes introduced to Alberta's royalty regime effective January 2009 are as follows:
Conventional oil - overall royalty rates will increase from the current maximum of 30% and 35% for old and new tiers. The new rates will range up to 50%, and rate caps will be raised to $120 per barrel for West Texas Intermediate (WTI) crude.
Natural gas - the Government will eliminate "old" and "new" tiers. Royalty rates, currently 5% to 35% will increase to 5% to 50%, based on a sliding rate formula sensitive to price and production volume, with rate caps at Cdn$16.59/GJ.
Oil Sands - currently, the pre-payout royalty rate is 1%. Under the new system, this rate will increase for prices above $55 per barrel, to a maximum of 9% when oil is priced at $120 or higher. Under the current regime, once an oil sands project reaches payout, the 1% royalty converts to a 25% net profits interest. Under the new regime, the net profits interest will apply at the rate of 25% when oil is less than $55 per bbl of WTI, and increase for every dollar oil is priced above $55 per barrel to a maximum of 40% when oil is priced at $120 or higher.
We cannot provide any assurance that the NRF will be implemented in the form proposed. If changes are made to the NRF before it is implemented by the Alberta government, such changes could result in the implementation of a new royalty regime that impacts us in a materially different manner, and that is more adverse to us, than the NRF as currently proposed.
As previously reported, we had requested that our reserves evaluator, Sproule, estimate the impact to our reserves evaluation based upon the currently released information on the new royalty regime. As of December 31, 2007, the province had not introduced the enabling legislation nor had they provided enough clarity on a number of issues for Sproule to provide a precise calculation of reserves and net present value under the new regime. It is possible that the announced changes may be amended before coming into force. Under the forecast price assumptions, Sproule has estimated that the change to the net present value, discounted at 10%, of future net revenue from our proved plus probable reserves would be a reduction of 2.1%.
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 per cent to 15 per cent. The reductions will be phased in between 2008 and 2012. In addition, the Government announced that it plans to collaborate with the provinces and territories to reach a 25 per cent combined federal-provincial-territorial statutory corporate income tax rate. The reduction in the federal rate will also reduce the specified investment flow-through ("SIFT") tax rate to 28 per cent as compared to the rate of 31.5 per cent previously announced subject to comments below concerning the provincial SIFT Tax proposal.
Federal Government's Trust Tax Legislation
In 2007, the Federal Government introduced and passed into law trust taxation that will result in a tax of 29.5 per cent (previously 31.5 per cent as discussed above) on all trust distributions commencing January 1, 2011 (28 percent commencing January 1, 2012.). Cash flow earned by the trust and not distributed has always been and continues to form part of taxable income at the trust level, which may result in cash taxes being paid if there are not sufficient tax pool claims and deductions obtained upon incurring capital expenditures or acquiring assets.
On December 20, 2007, the Finance Minister announced technical amendments to provide some clarification to the trust tax legislation. As part of the announcement the Minister indicated that the federal government intends to provide legislation in 2008 to permit income trusts to convert to taxable Canadian corporations without any undue tax consequence to investors or the trusts.
Currently, the SIFT Rules provide that the SIFT Tax rate will be the federal general corporate income tax rate (which is anticipated to be 16.5% in 2011) plus the provincial SIFT tax factor (which is set at a fixed rate of 13%), for a combined SIFT tax rate of 29.5% in 2011. On February 26, 2008, the Minister of Finance announced (the "Provincial SIFT Tax Proposal") that instead of basing the provincial component of the SIFT tax on a flat rate of 13%, the provincial component will be based on the general provincial corporate income tax rate in each province in which the SIFT has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable income allocation formula will be used. Specifically, the Trust's taxable distributions will be allocated to provinces by taking half of the aggregate of:
- that proportion of the Trust's taxable distributions for the year that the Trust's wages and salaries in the province are of its total wages and salaries in Canada; and
- that proportion of the Trust's taxable distributions for the year that the Trust's gross revenues in the province are of its total gross revenues in Canada.
Under the Provincial SIFT Tax Proposal, the Trust would be considered to have a permanent establishment in Alberta, where the provincial tax rate in 2011 is expected to be 10%. Taxable distributions that are not allocated to any province would instead be subject to a 10% rate constituting the provincial component. There can be no assurance, however, that the Provincial SIFT Tax Proposal will be enacted as proposed. Disclosure Controls and Procedures
As of December 31, 2007, an internal evaluation was conducted of the effectiveness of the Trust's disclosure controls and procedures as defined in Rule 13a-15 under the U.S. Securities Exchange Act of 1934 (the "Exchange Act') and as defined in Canada by Multilateral Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that the Trust files or submits under the Exchange Act or under Canadian securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act or under Canadian securities legislation is accumulated and communicated to the Trust's management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.
Internal Controls over Financial Reporting
Internal control over financial reporting 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 information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of the Trust's internal control over financial reporting as defined in Rule 13a-15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada by Multilateral Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. 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 Trust's internal control over financial reporting was effective as of December 31, 2007. The effectiveness of the Trust's internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, as reflected in their report for 2007. No changes were made to our internal controls over financial reporting during the year ended December 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Conference Call
Baytex will host a conference call and question and answer session at 2:00 p.m. MT (4:00 p.m. ET) on Wednesday, March 12, 2008 to discuss our 2007 results. The conference call will be hosted by Raymond Chan, Chief Executive Officer, Anthony Marino, President and Chief Operating Officer, and Derek Aylesworth, Chief Financial Officer. Interested parties are invited to participate by calling toll-free across North America at 1-800-771-7943. An archived recording of the call will be available from March 12, 2008 until March 26, 2008 by dialing 1-800-558-5253 or 416-626-4100 within the Toronto area, and entering the access code 21374995. The conference call will also be archived on Baytex's website at www.baytex.ab.ca.
Forward-Looking Statements
Certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995. Specifically, this press release contains forward-looking statements relating to Management's approach to operations and Baytex's production, cash flow, debt levels and cash distribution practices. The reader is cautioned that assumptions used in the preparation of such information, 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 re
Source: MARKET WIRE
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