Baytex Energy Trust
TSX : BTE.UN

Baytex Energy Trust

November 08, 2005 09:00 ET

Baytex Energy Trust Announces Third Consecutive Quarter of Record Cash Flow

CALGARY, ALBERTA--(CCNMatthews - Nov. 8, 2005) - Baytex Energy Trust (TSX:BTE.UN) is pleased to announce its operating and financial results for the three months and nine months ended September 30, 2005.

Highlights of the third quarter in 2005 include:

- Increased average production to 34,780 boe/d, 6% higher than Q2/05.

- Achieved a third consecutive quarter of record cash flow of $67.5 million, 109% higher than the same period last year and 35% higher than the previous record set in Q2/05.

- Attained a payout ratio of 41% for the third quarter, after incurring hedging losses of $17.9 million. Excluding losses from hedges which are expiring at the end of 2005, the payout ratio would have been 32%.

- Completed an acquisition of heavy oil properties for $69 million which is highly accretive to production, reserves and cash flow as well as opportunities for future development.



Three Months Ended Nine Months Ended
-------------------------------- ----------------------
September June 30, September September September
FINANCIAL 30, 2005 2005 30, 2004 30,2005 30, 2004
-------------------------------- ----------------------
($ thousands,
except per
unit amounts)
Petroleum and
natural gas sales 154,930 118,379 108,216 384,584 308,879
Cash flow from
operations (1) 67,501 49,937 32,235 161,978 107,868
Per unit
- basic 1.00 0.75 0.50 2.42 1.66
- diluted 0.89 0.71 0.49 2.23 1.65
Cash distributions 27,495 28,823 28,266 85,639 84,207
Per unit 0.41 0.45 0.45 1.35 1.35
Net income (loss) 38,211 18,804 (12,554) 40,204 (28,345)
Per unit
- basic 0.57 0.28 (0.20) 0.60 (0.45)
- diluted 0.51 0.27 (0.20) 0.57 (0.45)

Exploration and
development 39,395 31,586 20,686 99,446 65,460
Acquisitions - net
of dispositions 68,678 847 110,316 69,434 110,760
Total capital
expenditures 108,073 32,433 131,002 168,880 176,220

Long-term notes 208,935 220,542 227,434 208,935 227,434
Convertible
debentures 82,695 95,255 - 82,695 -
Bank loan 188,441 109,267 113,843 188,441 113,843
Other working
capital deficiency 5,482 16,916 20,237 5,482 20,237
Notional
mark-to-market
liabilities 21,226 30,761 50,098 21,226 50,098
Total net debt 506,779 472,741 411,612 506,779 411,612


Three Months Ended Nine Months Ended
-------------------------------- ----------------------
September June 30, September September September
30, 2005 2005 30, 2004 30,2005 30, 2004
-------------------------------- ----------------------
OPERATING
Daily production
Light oil (bbl/d) 4,063 3,404 1,890 3,782 1,966
Heavy oil (bbl/d) 20,061 19,653 22,083 20,326 22,775
Total oil (bbl/d) 24,124 23,058 23,974 24,108 24,741
Natural gas (mmcf/d) 63.9 59.3 50.9 60.9 54.7
Oil equivalent
(boe/d @ 6:1) 34,780 32,937 32,454 34,261 33,853

Average prices
(before hedging)
WTI oil (US$/bbl) 63.19 53.17 43.88 55.40 39.11
Edmonton par oil
($/bbl) 76.51 65.76 56.32 67.90 50.83
BTE light oil
($/bbl) 59.24 53.06 52.63 53.15 47.78
BTE heavy oil
($/bbl) 45.39 35.71 34.69 37.23 30.00
BTE total oil
($/bbl) 47.74 38.27 36.11 39.73 31.41
BTE natural gas
($/mcf) 8.39 7.08 6.16 7.42 6.41
BTE oil equivalent
($/boe) 48.54 39.53 36.34 41.14 33.31

TRUST UNIT INFORMATION
Unit Price
High $18.60 $15.20 $13.13 $18.60 $13.13
Low $13.45 $12.71 $11.65 $12.42 $ 9.78
Close $18.55 $13.48 $12.88 $18.55 $12.88

Units traded
(thousands) 22,134 17,403 13,696 65,947 70,457
Units outstanding
(thousands) (2) 70,524 69,264 65,044 70,524 65,044
Foreign ownership 30% 32% 33% 30% 33%

(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. 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) 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

On September 30, 2005, Baytex completed an acquisition of heavy oil properties in the Celtic area in Saskatchewan. Production from these properties is approximately 3,500 boe/d (3,350 bbl/d of heavy oil and 0.9 mmcf/d of natural gas) which will be included in Baytex's corporate production commencing in the fourth quarter of 2005. This transaction represents the first acquisition of producing properties in heavy oil since the Ardmore acquisition three years ago in October 2002, demonstrating the success of our commitment to focus on maintaining our production and asset base through internal development activities. The purchase price of the Celtic properties was earlier reported to be $73 million. A joint interest owner of certain associated operating facilities has since exercised a right of first refusal for Baytex's interest in such facilities, resulting in a $4 million reimbursement to Baytex and thereby reducing our net purchase price to $69 million. This auxiliary transaction has no impact on the production, reserves and land that are acquired by Baytex.

During the third quarter, capital expenditures for exploration and development activities totaled $39.4 million. Baytex participated in the drilling of 41 (37.1 net) wells, resulting in 19 (15.6 net) oil wells, 18 (18.0 net) gas wells and four (3.5 net) dry holes for an overall success rate of 90.2% (90.6% net). In addition, four farm-out wells were drilled at no costs to Baytex. Following record rainfall in the second quarter this year, wet field conditions were still prevalent in the third quarter which caused delays in drilling and completion activities as well as the tie-in of new production. Nevertheless, production increased to average 34,780 boe/d in the third quarter, 6% higher than the production of the previous quarter. Natural gas and light oil production increased 11% quarter-over-quarter as new wells drilled in the Stoddart area were brought on-stream. Baytex completed a new 3D seismic survey in this area during the third quarter, which is expected to add to development inventory in this key natural gas project.

Financial Review

Baytex achieved record cash flow for the third consecutive quarter thus far in 2005. Cash flow of $67.5 million ($1.00/unit basic) for the third quarter was 109% higher than the $32.2 million ($0.50/unit) for the same period last year and 35% higher than the previous record of $49.9 million ($0.75/unit) set in the second quarter this year. Baytex's strategy of minimizing dilution to unitholders is evident in these cash flow per unit comparisons as total units outstanding increased by only 8% between Q3/05 and Q3/04 and by only 2% between Q3/05 and Q2/05. The majority of the new units issued in the third quarter were conversions from the 6.5% debentures, where $13.4 million of the original $100 million issue had been tendered for conversion as of September 30, 2005.

Cash distributions, net of DRIP participation, were 41% of cash flow in the quarter and 53% in the nine months ended September 30, 2005. These conservative payout ratios were achieved despite significant hedging losses incurred during these periods. Excluding hedging losses, the payout ratio would have been 32% for the third quarter and 44% for the first nine months in 2005. The underlying below-market hedging contracts will expire at the end of 2005.

For calendar 2006, Baytex has entered into WTI derivative contracts aggregating 8,000 bbl/d with a floor price of US$55.00 and an average cap price of US$84.39 (ranging between US$80.85 and US$87.35). These contracts will provide significant downside protection to 2006 cash flow while allowing for participation in the benefits of continued high oil prices. Baytex has also entered into several physical sales contracts for natural gas. For the upcoming winter season (November 2005 to March 2006), Baytex has sold 14.2 mmcf/d at an average fixed price of C$10.90 and another 4.7 mmcf/d at a collar between C$9.50 and C$14.14. For the summer season (April to October 2006), Baytex has sold 6.6 mmcf/d at an average fixed price of C$9.05 and another 6.6 mmcf/d at a collar between C$8.00 and C$11.09.

Outlook

Production in the fourth quarter of 2005 is anticipated to average between 37,500 and 38,000 boe/d, reflecting contributions from the Celtic properties. For 2006, Baytex is targeting an average production level of 37,000 boe/d, comprised of 23,000 bbl/d of heavy oil, 4,000 bbl/d of light oil and NGL and 60.0 mmcf/d of natural gas. The capital budget associated with this production target is projected to be $105 million on a preliminary basis. With the wealth of internal development projects, highlighted by optimization and exploitation at Celtic, continued testing and delineation at Seal, and natural gas and NGL development at Stoddart, Baytex is very confident in our ability to sustain our production efficiently. The outlook for financial sustainability is also positive in 2006. At 37,000 boe/d of production, moderate commodity prices of US$40.00 for WTI oil and US$6.50 for NYMEX gas would generate sufficient cash flow to fully fund cash distributions at the current rate and the 2006 capital budget. With outstanding operational and financial flexibility, Baytex is well positioned to continue delivering superior returns to our unitholders.

Recent Industry Development

The federal government has recently made a number of pronouncements on tax and other issues relating to publicly listed flow-through entities (income trusts and limited partnerships). The resulting uncertainty has contributed to increased volatility and a significant loss of market value for the income trust sector.

The concerns of the government are the perceived loss of tax revenue due to taxable corporations converting to the income trust structure and a reduction in productivity as income trusts are more focused on maintaining distributions than economic growth. These concerns are not supported by Baytex's historical performance. In our ten-year history from 1993 to 2003 as a taxable corporation, Baytex did not pay any income taxes. Since conversion to an income trust in September 2003, Baytex has paid out $237 million in distributions to unitholders, of which approximately 85% is designated as taxable income. In terms of productivity and reinvestment, Baytex continues to be an active operator as we focus on replacing depletion through organic exploration and development activities. Since the trust conversion, we have invested $226 million in exploration and development expenditures, plus $256 million in the acquisition of assets. All of our investments during this period have been made exclusively in Canada. We believe that the trust structure enforces capital reinvestment discipline which is not always present in the oil and gas industry under a corporation structure, and that distribution of a portion of cash flow to unitholders provides the opportunity for reinvestments in other sectors of the economy. We are proud of our contributions to the Canadian economy, from the standpoints of tax revenue and productivity, as they are both substantial and transparent.

The income trust model has served as an effective vehicle for Canadians to invest for purposes of generating fixed income in a low interest rate environment and funding for retirement. Any potential tax levy or additional restrictions on income trusts would negatively affect their ability to maintain distributions and hence would likely further reduce their valuation. Baytex is a member of the Canadian Association of Income Funds ("CAIF") and will support CAIF in making submissions as part of the government's consultation process. In addition, Baytex strongly encourages unitholders to participate in the process so that their opinions can be accounted for in the government's resolution of these important issues.

For written submission, send an e-mail to: trusts-fiducies@fin.gc.ca. To contact the Minister of Finance, you may write to The Honourable Ralph Goodale, Department of Finance, 140 O'Connor Street, Ottawa, Ontario K1A 0A6, or you may reach him at phone number (613) 996-4743, fax number (613) 996-9790, or via e-mail at goodale.R@parl.gc.ca. To contact your Member of Parliament, direct your comments to www.canada.gc.ca/directories/direct_e.html.

Management's Discussion and Analysis

Management's discussion and analysis ("MD&A"), dated November 8, 2005, should be read in conjunction with the unaudited interim consolidated financial statements for the three months and the nine months ended September 30, 2005 and the audited consolidated financial statements and MD&A for the year ended December 31, 2004. 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.

Cash flow from operations is not a measure based on generally accepted accounting principles ("GAAP"), but is a financial term commonly used in the oil and gas industry. It represents cash generated from operating activities before changes in non-cash working capital, site restoration and reclamation expenditures, other assets and deferred credits. The Trust's cash flow from operations may not be comparable to other companies. The Trust considers it a key measure as it demonstrates the ability of the Trust to generate the cash flow necessary to fund future distributions and capital investments.

Production. Light oil production for the third quarter of 2005 more than doubled to 4,063 bbl/d from 1,890 bbl/d a year earlier. Heavy oil production decreased 9% to 20,061 bbl/d for the third quarter of 2005 compared to 22,083 bbl/d a year ago. Natural gas production increased by 26% to 63.9 mmcf/d for the third quarter of 2005 compared to 50.9 mmcf/d for the same period last year. The increase in light oil and natural gas production is due to the acquisitions completed in 2004 and the subsequent development of these assets. The decrease in heavy oil production is due to the lower number of wells drilled, where 103.7 net oil wells were drilled in 2004 compared to 59.0 net oil wells drilled in the first nine months of 2005.

For the first nine months of 2005, light oil production increased by 92% to 3,782 bbl/d from 1,966 bbl/d for the same period last year. Heavy oil production for the first nine months of 2005 was down 11% to 20,326 bbl/d compared to 22,775 bbl/d for the same period in 2004. Natural gas production increased by 11% to average 60.9 mmcf/d for the first nine months of 2005 compared to 54.7 mmcf/d for 2004. The reasons for the differences in production are as discussed in the quarterly comparisons.

Revenue. Petroleum and natural gas sales increased 43% to $154.9 million for the third quarter of 2005 from $108.2 million for the third quarter of 2004. For the first nine months, petroleum and natural gas sales increased by 25% to $384.6 million in 2005 from $308.9 million a year earlier.

For the per sales unit calculations, heavy oil sales for the three months ended September 30, 2005 were 84 barrels per day lower (three months ended September 30, 2004 - 88 barrels per day lower) than the production for the period due to inventory in transit under the Frontier supply agreement. The corresponding number for the nine months ended September 30, 2005 was a decrease of 22 barrels per day (nine months ended September 30, 2004 - a decrease of 14 barrels per day).


Three Months ended September 30
------------------------------------------
2005 2004
------------------------------------------
$000s $/Unit(1) $000s $/Unit(1)
---------- --------- --------- ---------
Oil revenue (barrels)
Light oil 22,146 59.24 9,152 52.63
Heavy oil 83,430 45.39 70,214 34.70
Derivative contracts loss (17,914) (9.75) (24,716) (12.21)
---------- --------- --------- ---------
Total oil revenue 87,662 39.64 54,650 24.87
Natural gas revenue (mcf) 49,353 8.39 28,850 6.16
---------- --------- --------- ---------
Total revenue (boe @ 6:1) 137,015 42.92 83,500 28.04
---------- --------- --------- ---------
---------- --------- --------- ---------

(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue
is in $/mcf.


Revenue from light oil for the third quarter of 2005 increased 142% from the same period a year ago due to a 115% increase in production and a 13% increase in wellhead prices. Revenue from heavy oil increased 19% as a 9% decrease in production was more than offset by a 31% increase in wellhead prices. Revenue from natural gas increased 71% as the result of a 36% increase in wellhead prices and a 26% increase in production.



Nine Months ended September 30
------------------------------------------
2005 2004
------------------------------------------
$000s $/Unit(1) $000s $/Unit(1)
---------- --------- --------- ---------
Oil revenue (barrels)
Light oil 54,870 53.15 25,743 47.78
Heavy oil 206,379 37.23 187,134 30.01
Derivative contracts loss (34,353) (6.20) (50,554) (8.11)
---------- --------- --------- ---------
Total oil revenue 226,896 34.51 162,323 23.96
Natural gas revenue (mcf) 123,335 7.42 96,002 6.41
---------- --------- --------- ---------
Total revenue (boe @ 6:1) 350,231 37.47 258,325 27.86
---------- --------- --------- ---------
---------- --------- --------- ---------

(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue
is in $/mcf.


For the first nine months of 2005, light oil revenue increased 113% from the same period last year due to an 11% increase in wellhead prices and an 92% increase in production. Revenue from heavy oil increased 10% due to a 24% increase in wellhead prices partially offset by an 11% decrease in production. Revenue from natural gas increased 28% compared to the first nine months of 2004, as production increased 11% combined with a price increase of 16%.

Royalties. Total royalties increased to $22.6 million for the third quarter of 2005 from $17.1 million in 2004. This increase is reflective of the increase in total revenue. Total royalties for the third quarter of 2005 were 14.6% of sales compared to 15.8% of sales for the same period in 2004. For the third quarter of 2005, royalties were 14.4% of sales for light oil, 15.0% for heavy oil and 13.9% for natural gas. These rates compared to 12.7%, 14.7% and 19.4%, respectively, for the same period last year.

For the nine months ended September 30, 2005, royalties increased to $54.6 million from $48.6 million for the same period last year. Total royalties for the first three quarters of 2005 were 14.2% of sales, compared to 15.7% of sales for the corresponding period a year ago. For the first nine months of 2005, royalties were 14.7% of sales for light oil, 12.7% for heavy oil and 16.6% for natural gas. These rates compared to 13.3%, 13.2% and 21.4%, respectively, for the same period in 2004. The royalty rate for natural gas was lower in the current period due to a retroactive adjustment in the gas cost allowance used in the calculation of royalties.

Operating Expenses. Operating expenses for the third quarter of 2005 increased to $27.5 million from $22.1 million in the corresponding quarter last year. Operating expenses were $8.61 per boe for the third quarter of 2005 compared to $7.43 per boe for the third quarter of 2004. The increase in operating expenses per boe was primarily due to an inflationary cost environment for fuel and oilfield services. For the third quarter of 2005, operating expenses were $10.40 per barrel of light oil, $9.49 per barrel of heavy oil and $1.05 per mcf of natural gas. The operating expenses for the same period a year ago were $11.67, $7.93 and $0.87, respectively.

Operating expenses for the first nine months of 2005 increased to $77.3 million from $64.8 million for the first three quarters in 2004. Operating expenses were $8.27 per boe for the first nine months of 2005 compared to $6.99 per boe for the corresponding period of the prior year. For the first three quarters of 2005, operating expenses were $10.06 per barrel of light oil, $8.98 per barrel of heavy oil and $1.03 per mcf of natural gas versus $9.96, $7.57 and $0.82, respectively, for the same period a year earlier.

Transportation Expenses. Transportation expenses for the third quarter of 2005 were $5.3 million compared to $4.6 million for the third quarter of 2004. These expenses were $1.67 per boe for the third quarter of 2005 compared to $1.53 for the same period in 2004. Transportation expenses were $2.03 per barrel of oil and $0.14 per mcf of natural gas. The corresponding amounts for 2004 were $1.70 and $0.18, respectively.

Transportation expenses for the nine months ended September 30, 2005 were $16.4 million compared to $14.2 million for the first nine months of 2004. These expenses were $1.76 per boe in 2005 compared to $1.53 in 2004. Transportation expenses were $2.15 per barrel of oil and $0.14 per mcf of natural gas in the 2005 period, and $1.68 per barrel of oil and $0.18 per mcf of natural gas in the 2004 period.

General and Administrative Expenses. General and administrative expenses for the third quarter of 2005 decreased to $3.9 million from $4.0 million in 2004. On a per sales unit basis, these expenses were $1.21 per boe for the third quarter of 2005 compared to $1.34 per boe for 2004. In accordance with our full cost accounting policy, no expenses were capitalized in either the third quarter of 2005 or 2004.

General and administrative expenses for the first nine months of 2005 were $11.4 million, compared to $11.2 million for the prior year. On a per sales unit basis, these expenses were $1.22 per boe in 2005 and $1.21 per boe in 2004. In accordance with our full cost accounting policy, no expenses were capitalized in either 2005 or 2004.

Unit-based Compensation Expense. Compensation expense related to the Trust's unit rights incentive plan was $2.5 million for the third quarter of 2005 compared to an expense of $3.2 million for the third quarter of 2004. For the nine months ended September 30, 2005, compensation expense was $8.2 million compared to $6.1 million for the same period in 2004.

Compensation expense associated with rights granted under the plan is recognized in income over the vesting period of the plan with a corresponding increase or decrease in contributed surplus. The exercise of trust unit rights are recorded as an increase in trust units with a corresponding reduction in contributed surplus.

On July 1, 2005, the Trust prospectively applied the fair value based method of estimating the compensation expense related to the unit rights plan. Previously, the Trust applied the intrinsic value methodology due to the difficulty of estimating certain key components of a fair value calculation, under a new corporate structure, including unit price volatility, unit right exercise history, unit distribution patterns and commodity price volatility. As the Trust now has an extended period of trading and operating history, the Trust is better equipped to determine fair value estimates of unit rights at the grant date. As this is a change in estimate under accounting standards, the fair value methodology has been applied prospectively without restatement of prior periods.

As at September 30, 2005, the fair value calculation resulted in cumulative expense of $16.1 million compared to the $13.6 million recorded as cumulative compensation expense to June 30, 2005 under the intrinsic value method. Accordingly, the $2.5 million difference was recorded as compensation expense in the third quarter of 2005.

Interest Expenses. Interest expenses on long-term debt increased to $8.5 million for the third quarter of 2005 from $3.9 million for the same quarter last year, primarily due to the increased debt used to finance acquisitions completed in 2004, plus a gradual increase in interest rates.

For the first nine months of 2005, interest expenses on long-term debt was $23.4 million compared to $13.0 million for the same period last year. The increase is attributable to the same factors influencing the third quarter variance.

Foreign Exchange. Foreign exchange gain in the third quarter of 2005 was $11.6 million compared to a gain of $13.8 million in the prior year. The gain is based on the translation of the U.S. dollar denominated long-term debt at 0.8613 at September 30, 2005 compared to 0.8159 at June 30, 2005. The 2004 gain is based on translation at 0.7912 at September 30, 2004 compared to 0.7460 at June 30, 2004.

Foreign exchange gain for the first nine months of 2005 was $7.6 million compared to $5.1 million in the prior year. The 2005 gain is based on the translation of the U.S. dollar denominated long-term debt at 0.8613 at September 30, 2005 compared to 0.8308 at December 31, 2004. The 2004 gain is based on translation at 0.7912 at September 30, 2004 compared to 0.7737 at December 31, 2003.

Depletion, Depreciation and Accretion. The provision for depletion, depreciation and accretion increased to $40.8 million for the third quarter of 2005 compared to $39.4 million for the same quarter a year ago due to higher production volumes. On a sales-unit basis, the provision for the current quarter was $12.77 per boe compared to $13.23 per boe for the same quarter in 2004.

Depletion, depreciation and accretion increased to $125.5 million for the first three quarters of 2005 compared to $119.3 million for the same period last year. On a sales-unit basis, the provision for the current period was $13.43 per boe compared to $12.87 per boe for the same period a year earlier.

Income Taxes. Current tax expenses at $2.4 million for the third quarter of 2005 is unchanged from the same quarter a year ago. The current tax expense is comprised of $1.8 million of Saskatchewan Capital Tax and $0.6 million of Large Corporation Tax compared to $2.2 million and $0.2 million, respectively, in the corresponding period in 2004.

Current tax expenses were $6.3 million for the first nine months of 2005 compared to $7.2 million for the same period last year. The current tax expense is comprised of $4.8 million of Saskatchewan Capital Tax and $1.5 million of Large Corporation Tax compared to $5.4 million and $1.8 million, respectively, in 2004.

Net Income. Net income for the third quarter of 2005 was $38.2 million compared to a $12.6 million loss incurred in the third quarter in 2004. The favourable variance was the result of higher production, higher sales prices, and an unrealized gain on financial derivatives compared to a loss in the prior period.

Net income for the first nine months of 2005 was $40.2 million compared to a $28.3 million loss for the same period in 2004. The variance was primarily due to higher production, higher sales prices and lower loss in financial derivatives for the 2005 period.

Liquidity and Capital Resources. On June 6, 2005 the Trust issued $100 million principal amount of 6.5 percent convertible unsecured subordinated debentures for net proceeds of $95.8 million. The debentures pay interest semi-annually and are convertible at the option of the holder at any time into fully paid trust units at a conversion price of $14.75 per trust unit. The debentures mature on December 31, 2010 at which time they are due and payable. The net proceeds were used to reduce outstanding bank indebtedness.

The debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders' equity. This resulted in $95.2 million being classified as debt and $4.8 million being classified as equity as at the date of issue. Issue costs are amortized over the term of the debentures, and the debt portion will accrete up to the principal balance at maturity. The accretion, amortization of issue costs and the interest paid are expensed as interest expense in the consolidated statements of operations. As at September 30, 2005, $13.4 million principal amount of debentures had been tendered for conversion into trust units.

At September 30, 2005, total net debt (including working capital) was $506.8 million compared to $411.6 million at September 30, 2004 and $422.0 million at December 31, 2004. The increase was primarily due to the financing of properties acquired. The September 30, 2005 net debt included $21.2 million of notional liabilities based on the mark-to-market valuations of derivative contracts as at September 30, 2005.



Capital Expenditures.

The Trust's total capital expenditures for these periods are summarized
as follows:

Nine Months ended September 30
--------------------------------
($ thousands) 2005 2004
----------------- --------------
Land 6,030 4,888
Seismic 4,378 537
Drilling and completion 69,008 39,136
Equipment 17,629 18,092
Other 2,401 2,807
----------------- --------------
Total exploration and development 99,446 65,460
Property acquisitions 72,424 111,042
Property dispositions (2,990) (282)
----------------- --------------
Net capital expenditures 168,880 176,220
----------------- --------------
----------------- --------------


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 Tuesday, November 8, 2005 to discuss our third quarter results. The conference call will be hosted by Raymond Chan, President and Chief Executive Officer, Derek Aylesworth, Chief Financial Officer and Anthony Marino, Chief Operating Officer. Interested parties are invited to participate by calling toll-free across North America at 1-888-939-6306. A recorded playback of the call will be available from November 8, 2005 until November 22, 2005 by dialing 1-800-558-5253 or 416-626-4100 within the Toronto area, entering the reservation number 21265984. 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 result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the ability to produce and transport crude oil and natural gas to markets; the result of exploration and development drilling and related activities; fluctuation in foreign currency exchange rates; the imprecision of reserve estimates; the ability of suppliers to meet commitments; actions by governmental authorities including increases in taxes; decisions or approvals of administrative tribunals; change in environmental and other regulations; risks associated with oil and gas operations; the weather in Baytex's areas of operations; and other factors, many of which are beyond the control of Baytex. 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.

Baytex Energy Trust is a conventional oil and gas income trust focused on maintaining its production and asset base through internal property development and delivering consistent returns to its unitholders. Trust units of Baytex are traded on the Toronto Stock Exchange under the symbol BTE.UN.

Financial statements for the periods ended September 30, 2005 are attached.



Baytex Energy Trust
Consolidated Balance Sheets
(thousands) (Unaudited)
September 30, 2005 December 31, 2004
-----------------------------------------
Assets
Current assets
Accounts receivable $ 70,334 $ 41,154
Crude oil inventory 9,214 7,299
-----------------------------------------
79,548 48,453

Deferred charges and other
assets 9,725 6,491
Petroleum and natural gas
properties 1,048,546 1,009,933
Goodwill (note 4) 37,755 39,259
-----------------------------------------
$ 1,175,574 $ 1,104,136
-----------------------------------------
-----------------------------------------

Liabilities
Current liabilities
Accounts payable and accrued
liabilities $ 74,772 $ 72,976
Distributions payable to
unitholders 10,258 9,981
Bank loan 188,441 161,444
Financial derivative
contracts (note 14) 21,226 9,513
-----------------------------------------
294,697 253,914

Long-term debt (note 5) 208,935 216,583
Convertible debentures
(note 6 ) 82,695 -
Asset retirement obligations
(note 7) 54,284 73,297
Deferred obligations (note 8) 4,969 -
Future income taxes 148,621 164,909
-----------------------------------------
794,201 708,703

Non-controlling interest (note 10) 11,948 12,962

Unitholders' Equity
Unitholders' capital (note 9) 542,739 515,728
Conversion feature of debentures
(note 6 ) 4,152 -
Contributed surplus 13,640 7,494
Accumulated distributions (237,004) (146,445)
Accumulated income 45,898 5,694
-----------------------------------------
369,425 382,471
-----------------------------------------
$ 1,175,574 $ 1,104,136
-----------------------------------------
-----------------------------------------

See accompanying notes to the consolidated financial statements.



Baytex Energy Trust
Consolidated Statements of Operations and Accumulated Income (Deficit)
(thousands, except per unit data) (Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2005 2004 2005 2004
--------------------- ---------------------
(restated (restated
Revenue - note 3) - note 3)
Petroleum and natural
gas sales $ 154,930 $ 108,216 $ 384,584 $ 308,879
Royalties (22,617) (17,068) (54,629) (48,596)
Realized loss on
financial derivatives (17,914) (24,716) (34,353) (50,554)
Unrealized gain (loss)
on financial derivatives 9,535 (18,595) (11,713) (39,988)
--------------------- ---------------------
123,934 47,837 283,889 169,741
--------------------- ---------------------

Expenses
Operating 27,490 22,126 77,304 64,785
Transportation 5,323 4,570 16,440 14,164
General and administrative 3,853 4,005 11,393 11,174
Unit-based compensation
(note 11) 2,550 3,161 8,157 6,149
Interest (note 12) 8,490 3,931 23,384 12,964
Foreign exchange gain (11,607) (13,765) (7,648) (5,128)
Depletion, depreciation
and accretion 40,772 39,383 125,548 119,291
--------------------- ---------------------
76,871 63,411 254,578 223,399
--------------------- ---------------------

Income (loss) before income
taxes and non-controlling
interest 47,063 (15,574) 29,311 (53,658)
--------------------- ---------------------
Income taxes
Current expense 2,355 2,359 6,337 7,150
Future expense (recovery) 5,603 (5,005) (18,162) (31,616)
--------------------- ---------------------
7,958 (2,646) (11,825) (24,466)
--------------------- ---------------------
Income (loss) before
non-controlling interest 39,105 (12,928) 41,136 (29,192)
Non-controlling interest
(notes 3 and 10) (894) 374 (932) 847
--------------------- ---------------------

Net income (loss) 38,211 (12,554) 40,204 (28,345)

Accumulated income (deficit),
beginning of period, as
previously reported 7,687 (24,064) 5,694 (8,598)

Accounting policy change for
non-controlling interest
(note 3) - 204 - 529
--------------------- ---------------------

Accumulated income (deficit),
beginning of period,
as restated 7,687 (23,860) 5,694 (8,069)
--------------------- ---------------------

Accumulated income (deficit),
end of period $ 45,898 $ (36,414) $ 45,898 $ (36,414)
--------------------- ---------------------

Net income (loss) per
trust unit
Basic $ 0.57 $ (0.20) $ 0.60 $ (0.45)
Diluted $ 0.51 $ (0.20) $ 0.57 $ (0.45)

Weighted average trust
units
Basic 67,348 62,805 66,948 62,302
Diluted 77,840 65,406 70,868 65,198


See accompanying notes to the consolidated financial statements.

Baytex Energy Trust
Consolidated Statements of Cash Flows
(thousands) (Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2005 2004 2005 2004
-------------------- --------------------
(restated (restated
Cash provided by (used in) - note 3) - note 3)

OPERATING ACTIVITIES
Net income (loss) $ 38,211 $ (12,554) $ 40,204 $ (28,345)
Items not affecting cash:
Unit-based compensation
(note 11) 2,550 3,161 8,157 6,149
Amortization of deferred
charges 459 2,794 1,033 8,376
Foreign exchange gain (11,607) (13,765) (7,648) (5,128)
Depletion, depreciation
and accretion 40,772 39,383 125,548 119,291
Accretion on debentures 155 - 201 -
Unrealized loss (gain) on
financial derivatives
(note 14) (9,535) 18,595 11,713 39,988
Future income tax (recovery) 5,602 (5,005) (18,162) (31,616)
Non-controlling interest
(note 10) 894 (374) 932 (847)
-------------------- --------------------
Funds flow from operations 67,501 32,235 161,978 107,868
Change in non-cash working
capital (6,392) (1,627) (23,605) (1,753)
Asset retirement expenditures (233) (665) (1,255) (1,550)
Decrease in deferred charges
and other assets 401 53 157 159
-------------------- --------------------
61,277 29,996 137,275 104,724
-------------------- --------------------

FINANCING ACTIVITIES
Issuance of convertible
debentures (note 6) - - 100,000 -
Convertible debentures issue
costs (note 6) - - (4,250) -
Increase in bank loan 79,174 113,843 26,997 113,843
Payments of distributions (30,241) (28,259) (90,282) (83,905)
Issue of trust units 3,523 210 6,367 210
-------------------- --------------------
52,456 85,794 38,832 30,148
-------------------- --------------------

INVESTING ACTIVITIES
Petroleum and natural gas
property expenditures (110,871) (20,673) (171,870) (65,460)
Corporate acquisitions - (111,042) - (111,042)
Disposal of petroleum and
natural gas properties 2,798 713 2,990 282
Change in non-cash working
capital (5,660) 987 (7,227) (10,600)
-------------------- --------------------
(113,733) (130,015) (176,107) (186,820)
-------------------- --------------------

Change in cash and
short-term investments - (14,225) - (51,948)

Cash and short-term
investments, beginning
of period - 16,008 - 53,731
-------------------- --------------------

Cash and short-term
investments, end of
period $ - $ 1,783 $ - $ 1,783
-------------------- --------------------
-------------------- --------------------

See accompanying notes to the consolidated financial statements.

Notes to the Consolidated Financial Statements
Three Months and Nine Months Ended September 30, 2005 and 2004
(all tabular amounts in thousands, except per unit amounts) (unaudited)



1. Basis of Presentation

Baytex Energy Trust (the "Trust") was established on September 2, 2003 under a Plan of Arrangement involving the Trust, Baytex Energy Ltd. (the "Company") and Crew Energy Inc. ("Crew"). The Trust is an open-ended investment trust created pursuant to a trust indenture. Subsequent to the Plan of Arrangement, the Company is a subsidiary of the Trust.

Prior to the Plan of Arrangement, the consolidated financial statements included the accounts of the Company and its subsidiaries and partnership. After giving effect to the Plan of Arrangement, the consolidated financial statements have been prepared on a continuity of interests basis which recognizes the Trust as the successor to the Company. The consolidated financial statements include the accounts of the Trust and its subsidiaries and have been prepared by management in accordance with Canadian generally accepted accounting principles as described in note 2.

2. Accounting Policies

The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements of the Trust as at December 31, 2004. The interim consolidated financial statements contain disclosures, which are supplemental to the Trust's annual consolidated financial statements. Certain disclosures, which are normally required to be included in the notes to the annual consolidated financial statements, have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the Trust's consolidated financial statements and notes thereto for the year ended December 31, 2004.

3. Changes in Accounting Policy

Non-controlling Interest

The Trust has implemented the accounting for the exchangeable shares issued by the Company as required by EIC Abstract 151, "Exchangeable Securities Issued by Subsidiaries of Income Trusts" (EIC 151), issued in January 2005. Under EIC 151, exchangeable shares issued by a subsidiary of an income trust are presented as non-controlling interest, unless certain conditions are met. The exchangeable shares of the Company are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary in order for them to be classified as equity. The presentation of the exchangeable shares at September 30, 2004 was restated to conform to the presentation for the current year, pursuant to the transitional provisions contained in EIC 151. Previously, the exchangeable shares were reflected as a component of unitholders' equity.

As a result of the adoption of EIC 151, net income was reduced in the first nine months of 2004 by $0.28 million (three months ended September 30, 2004 - increase of $0.05 million). As the exchangeable shares are converted to trust units, the exchange is accounted for as a step-by-step acquisition where unitholders' capital is increased by the fair value of the trust units issued. The difference between the fair value of the trust units issued and the book value of the exchangeable shares is recorded as an increase in petroleum and natural gas properties. During the nine months ended September 30, 2004, the adoption of EIC 151 resulted in a $15.5 million increase in petroleum and natural gas properties (three months ended September 30, 2004 - decrease of $0.03 million), a $5.9 million increase in future income taxes (three months ended September 30, 2004 - decrease of $0.12 million) and a $10.9 million increase in unitholders' capital (three months ended September 30, 2004 - $0.13 million).

4. Corporate Acquisition

The Company has finalized its purchase allocation related to the acquisition made in 2004.Goodwill of $37.8 million was determined based on the excess of the total consideration paid less the value assigned to the identifiable assets and liabilities including the future income tax liability.



5. Long-term Debt

September 30, December 31,
2005 2004
------------- ------------
10.5% senior subordinated notes
(US$247) $ 287 $ 297
9.625% senior subordinated notes
(US$179,699) 208,648 216,286
------------- ------------
$ 208,935 $ 216,583
------------- ------------
------------- ------------


6. Convertible Unsecured Subordinated Debentures

On June 6, 2005 the Trust issued $100 million principal amount of 6.5 percent convertible unsecured subordinated debentures for net proceeds of $95.8 million. The debentures pay interest semi-annually and are convertible at the option of the holder at any time into fully paid trust units at a conversion price of $14.75 per trust unit. The debentures mature on December 31, 2010 at which time they are due and payable.

The debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders' equity. This resulted in $95.2 million being classified as debt and $4.8 million being classified as equity. Issue costs will be amortized over the term of the debentures, and the debt portion will accrete up to the principal balance at maturity. The accretion, amortization of issue costs and the interest paid are expensed as interest expense in the consolidated statements of operations. If the debentures are converted to trust units, a portion of the value of the conversion feature under unitholders' equity will be reclassified to unitholders' capital along with the principal amounts converted.



Issuance on June 6, 2005 $ 100,000
Portion allocated to equity (4,152)
Accretion of non-cash interest expense 201
Conversion into Trust Units (13,354)
------------
Balance, September 30, 2005 $ 82,695
------------
------------


7. Asset Retirement Obligations

Nine months Ended
----------------------------
September 30, September 30,
2005 2004
----------------------------
Balance, beginning of period $ 73,297 $ 55,996
Liabilities incurred 182 2,116
Liabilities acquired 8,169 8,435
Liabilities settled (1,255) (1,550)
Accretion 4,358 3,360
Change in estimate (30,467) -
----------------------------
Balance, end of period $ 54,284 $ 68,357
----------------------------
----------------------------


The Trust's asset retirement obligations are based on the Trust's net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities and the estimated time period during which these costs will be incurred in the future. The undiscounted amount of estimated cash flow required to settle the retirement obligations at September 30, 2005 is $225.8 million. Estimated cash flow has been discounted at a credit-adjusted risk free rate of 8.0 percent and an inflation rate of 1.5 percent.

8. Deferred Obligations

The Company has future contractual processing obligations with respect to assets acquired. These obligations continue until October 2008.



9. Unitholders' Capital

Trust Units

The Trust is authorized to issue an unlimited number of trust units.

Number of units Amount
---------------- ------------

Balance, December 31, 2004 66,538 $ 515,728
Issued on conversion of exchangeable
shares 358 5,279
Issued on conversion of debentures 905 13,354
Issued on exercise of trust unit rights 304 2,409
Transfer from contributed surplus on
exercise of trust unit rights - 2,011
Issued pursuant to distribution
reinvestment program 279 3,958
---------------- ------------
Balance, September 30, 2005 68,384 $ 542,739
---------------- ------------
---------------- ------------


10. Non-Controlling Interest

The Company is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares can be converted (at the option of the holder) into trust units at any time up to September 2, 2013. Up to 1.9 million exchangeable shares may be redeemed annually by the Company for either a cash payment or the issue of trust units. The number of trust units issued upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid divided by the weighted average trust unit price of the five day trading period ending on the record date. The exchange ratio at September 30, 2005 was 1.33655 trust units per exchangeable share. Cash distributions are not paid on the exchangeable shares. The exchangeable shares are not publicly traded, although they may be transferred by the holder without first being converted to trust units.

The exchangeable shares of the Company are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary in order for them to be classified as equity. Net income has been reduced by an amount equivalent to the non-controlling interest proportionate share of the Trust's consolidated net income (loss) with a corresponding increase (decrease) to the non-controlling interest on the balance sheet.



Number of
exchangeable shares Amount
------------------- ------------
Balance, December 31, 2004 1,876 $ 12,962
Exchanged for trust units (275) (1,946)
Non-controlling interest in net income - 932
------------------- ------------
Balance, September 30, 2005 1,601 $ 11,948
------------------- ------------
------------------- ------------


11. Trust Unit Rights

The Trust has a Trust Unit Rights Incentive Plan (the "Plan") whereby the maximum number of trust units issuable pursuant to the plan is a "rolling" maximum equal to 10% of the outstanding trust units plus the number of trust units which may be issued on the exchange of outstanding exchangeable shares. Any increase in the issued and outstanding units will result in an increase in the available number of trust units issuable under the plan, and any exercises of incentive rights will make new grants available under the plan, effectively resulting in a re-loading of the number of rights available to grant under the plan. Trust unit rights are granted at the volume weighted average trading price of the trust units for the five trading days prior to the date of grant, vest over three years and have a term of five years. The Plan allows for the exercise price of the rights to be reduced in future periods by a portion of the future distributions.

The Trust recorded compensation expense of $8.2 million for the nine months ending September 30, 2005 ($6.1 million in 2004).

On July 1, 2005, the Trust prospectively applied the fair value based method of estimating the compensation expense related to the unit rights plan. Previously, the Trust applied the intrinsic value methodology due to the difficulty of estimating certain key components of a fair value calculation under a new corporate structure, including unit price volatility, unit right exercise history, and cash distribution patterns. As the Trust now has an extended period of trading and operating history, the Trust is better equipped to determine fair value estimates of unit rights at the grant date and has applied the fair value methodology prospectively without restatement of prior periods.

The Trust used the Black-Scholes option-pricing model to calculate the estimated fair value of the outstanding rights. The following assumptions were used to arrive at the estimate of fair value as at September 30, 2005:



Expected annual right's exercise price reduction $ 1.80
Expected volatility 32.5%
Risk-free interest rate 4.5%
Expected life of option (years) 5


As at September 30, 2005, the fair value calculation resulted in cumulative expense of $16.1 million compared to the $13.6 million recorded as cumulative compensation expense to June 30, 2005 under the intrinsic value method. Accordingly, the $2.5 million difference was recorded as compensation expense in the third quarter of 2005. The $5.1 million remaining future value of the rights will be recognized in earnings over the remaining vesting period of the outstanding rights.



The number of unit rights issued and exercise prices are detailed below:

Weighted
average
exercise
Number of rights price (1)
----------------- ------------
Balance, December 31, 2004 3,537 $ 9.60
Granted 579 $ 13.79
Exercised (304) $ 7.93
Cancelled (177) $ 9.38
-----------------
Balance, September 30, 2005 3,635 $ 9.15
-----------------
-----------------
(1) Exercise price reflects grant prices less reduction in exercise
price as discussed above.

Number Number
Outstanding Weighted Weighted Exercisable Weighted
at Average Average at Average
Range of September Remaining Exercise September Exercise
Exercise Prices 30, 2005 Term(years) Price($) 30, 2005 Price($)
----------------- ------------ ---------- --------- ---------- ---------
$5.86 to $7.47 1,929 2.97 7.09 1,149 7.09
$7.93 to $9.87 182 3.54 8.74 50 8.61
$10.00 to $11.47 974 4.12 10.96 94 10.10
$11.90 to $13.16 454 4.67 12.92 - -
$13.58 to $16.37 96 4.69 14.95 - -
------------ ---------- --------- ---------- ---------
$5.86 to $16.37 3,635 3.56 9.15 1,293 7.37
------------ ---------- --------- ---------- ---------


12. Interest Expense

The Trust incurred interest expense on its outstanding debt as follows:


Three Months Ended Nine Months Ended
September 30 September 30
2005 2004 2005 2004
-------------------- -------------------
Credit facility charges $ 1,472 $ 201 $ 5,804 $ 458
Amortization of deferred charge 459 267 1,034 794
Long-term debt 6,559 3,463 16,546 11,712
-------------------- -------------------
Total interest $ 8,490 $ 3,931 $ 23,384 $ 12,964
-------------------- -------------------
-------------------- -------------------

13. Supplemental Cash Flow Information


Three Months Ended Nine Months Ended
September 30 September 30
2005 2004 2005 2004
-------------------- -------------------
Interest paid $ 10,687 $ 8,744 $ 23,887 $ 19,297
Income taxes paid $ 2,662 $ 2,025 $ 6,943 $ 15,077


14. Financial Derivative Contracts

At September 30, 2005, the Trust had financial derivative contracts for
the following:

---------------------------------------------------------
Period Volume Price Index
---------------------------------------------------------
Oil
Price collar Calendar 2005 3,000 bbl/d US$35.00 - $42.40 WTI
Price collar Calendar 2005 2,000 bbl/d US$35.00 - $42.50 WTI
Price collar Calendar 2005 1,000 bbl/d US$35.00 - $42.70 WTI
Price collar Calendar 2005 2,000 bbl/d US$35.00 - $42.75 WTI
Price collar Calendar 2006 2,000 bbl/d US$55.00 - $80.85 WTI
Price collar Calendar 2006 2,000 bbl/d US$55.00 - $84.18 WTI
Price collar Calendar 2006 2,000 bbl/d US$55.00 - $85.30 WTI
Price collar Calendar 2006 1,000 bbl/d US$55.00 - $87.10 WTI
Price collar Calendar 2006 1,000 bbl/d US$55.00 - $87.35 WTI


---------------------------------------------------------------
Period Amount Exchange Rate
---------------------------------------------------------------
Foreign
currency Floor Cap
Collar Calendar 2005 US$2,000,000 CAD/USD $1.2140 CAD/USD $1.2500
per month
Collar Calendar 2005 US$3,000,000 CAD/USD $1.2200 CAD/USD $1.2500
per month
Collar Calendar 2005 US$4,000,000 CAD/USD $1.2150 CAD/USD $1.2500
per month


---------------------------------------------------------------
Period Principal Rate
---------------------------------------------------------------
Interest
rate swap
November 2003
to July 2010 US$179,699,000 3-month LIBOR plus 5.2%



Under the CICA guideline for hedge accounting, the Trust's financial derivative contracts for oil and foreign currency do not qualify as effective accounting hedges. Accordingly, these contracts have been accounted for based on the fair value method.

Contact Information

  • Baytex Energy Trust
    Ray Chan
    President & C.E.O.
    (403) 267-0715
    or
    Baytex Energy Trust
    Derek Aylesworth
    Chief Financial Officer
    (403) 538-3639
    or
    Baytex Energy Trust
    Kathy Robertson
    Investor Relations Representative
    (403) 538-3645 or Toll Free Number: 1-800-524-5521
    Website: www.baytex.ab.ca