Baytex Energy Trust
TSX : BTE.UN

Baytex Energy Trust

August 09, 2005 09:00 ET

Baytex Energy Trust Announces Second Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 9, 2005) - Baytex Energy Trust (TSX:BTE.UN) is pleased to announce its operating and financial results for the three months and six months ended June 30, 2005.

Highlights of the second quarter in 2005 include:

- Achieved a second consecutive quarter of record cash flow of $50 million, 12 percent higher than the previous quarter and 35 percent higher than the same quarter last year.

- Reduced payout ratio to 58 percent of cash flow from operations compared to 66 percent in the previous quarter and 76 percent in the same quarter last year.

- Established Stoddart as a major natural gas development area with production commencing from two new wells. Current production in August at Stoddart is approximately 35 percent higher than at the time of acquisition in December 2004.

- Improved financial flexibility by issuing $100 million of convertible debentures.



Three Months Ended Six Months Ended
----------------------------- -------------------
FINANCIAL June 30, March 31, June 30, June 30, June 30,
2005 2005 2004 2005 2004
-------------------------------------------------
($ thousands, except
per unit amounts)
Petroleum and natural
gas sales 118,379 111,275 104,517 229,654 200,663
Cash flow from
operations (1) 49,937 44,540 36,944 94,477 75,633
Per unit - basic 0.75 0.67 0.57 1.42 1.17
- diluted 0.71 0.64 0.57 1.35 1.16
Cash distributions 28,823 29,321 28,237 58,144 55,941
Per unit 0.45 0.45 0.45 0.90 0.90
Net income (loss) 18,804 (16,811) (11,213 1,993 (15,791)
Per unit - basic 0.28 (0.25) (0.18) 0.03 (0.25)
- diluted 0.27 (0.25) (0.18) 0.03 (0.25)

Exploration and
development 31,586 28,465 15,975 60,051 45,218
Acquisitions - net
of dispositions 847 (91) - 756 -
Total capital
expenditures 32,433 28,374 15,975 60,807 45,218

Long-term notes 220,542 217,663 241,199 220,542 241,199
Convertible debentures 95,255 - - 95,255 -
Bank loan 109,267 190,270 - 109,267 -
Other working
capital deficiency 16,916 20,013 7,315 16,916 7,315
Notional mark-to-market
liabilities 30,761 41,826 31,503 30,761 31,503
Total net debt 472,741 469,772 280,017 472,741 280,017

OPERATING
Daily production
Light oil (bbl/d) 3,404 3,876 1,952 3,639 2,005
Heavy oil (bbl/d) 19,653 21,279 22,927 20,462 23,125
Total oil (bbl/d) 23,058 25,155 24,879 24,100 25,130
Natural gas (mmcf/d) 59.3 59.5 57.2 59.4 56.6
Oil equivalent
(boe/d @ 6:1) 32,937 35,068 34,411 33,996 34,560



Three Months Ended Six Months Ended
----------------------------- -------------------
June 30, March 31, June 30, June 30, June 30,
2005 2005 2004 2005 2004
-------------------------------------------------
Average prices
(before hedging)
WTI oil (US$/bbl) 53.17 49.84 38.32 51.51 36.73
Edmonton par oil
($/bbl) 65.76 61.44 50.59 63.60 48.09
BTE light oil ($/bbl) 53.06 46.69 47.55 49.68 45.47
BTE heavy oil ($/bbl) 35.71 30.83 29.21 33.18 27.75
BTE total oil ($/bbl) 38.27 33.27 30.63 35.67 29.16
BTE natural gas ($/mcf) 7.08 6.69 6.61 6.88 6.52
BTE oil equivalent
($/boe) 39.53 35.21 33.12 37.31 31.88

TRUST UNIT INFORMATION
Unit Price
High $15.20 $15.70 $12.60 $15.70 $12.60
Low $12.71 $12.42 $12.32 $12.42 $ 9.78
Close $13.48 $14.91 $12.00 $13.48 $12.00

Units traded
(thousands) 17,403 26,410 21,983 43,813 56,761
Units outstanding
(thousands) (2) 69,264 69,075 62,783 69,264 62,783
Foreign ownership 32% 32% 31% 32% 31%

(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

Heavy oil operations during the second quarter were significantly hampered by extreme weather conditions in most of Baytex's operating areas. Record rainfall caused widespread flooding in many parts of Alberta and Saskatchewan, limiting the trucking of oil production from well sites to sales terminals. Unfavourable road conditions delayed the deployment of equipment to complete many of the 29 heavy oil wells drilled in the quarter. Similarly, routine workover and maintenance operations were curtailed with both production volume and operating cost efficiency negatively affected.

As a result, Baytex's heavy oil production for the second quarter of 2005 averaged 19,653 bbl/d, eight percent below that of the previous quarter. With improving weather and road conditions thus far in the summer, current production has recovered to approximately 20,500 bbl/d. Baytex will continue to increase its heavy oil production during the second half of 2005.

At Seal, production averaged 805 bbl/d during the second quarter at an average sales price (net of trucking expenses) of $17.27 per barrel. This compares to the corporate sales price (net of trucking) of $33.22 per barrel in the same period. Baytex is continuing to investigate various marketing alternatives. Large scale development at Seal will commence once a marketing arrangement which provides higher wellhead price realization is secured.

Natural Gas production was essentially unchanged at 59.3 mmcf/d in the second quarter of 2005 compared to 59.5 mmcf/d in the previous quarter. At Stoddart, two wells drilled in March and April were put on production in mid-June. Current production from this area totals 4,500 boe/d compared to 3,300 boe/d at the time of acquisition in December 2004. Baytex plans to drill five new wells at Stoddart in the second half of 2005, together with a similar number of recompletions. At Leahurst in central Alberta, Baytex is currently completing its first program of 12 wells for Horseshoe Canyon coalbed methane (CBM) production. The production performance of these wells will help determine future development plans for CBM production. Baytex is excited about the growing ability of its in-house inventory of prospects to sustain its natural gas and light oil production.

Exploration and development capital expenditures in the second quarter totaled $31.6 million. During this period, Baytex participated in the drilling of 37 (35.3 net) wells, resulting in 29 (28.8 net) oil wells, six (4.5 net) gas wells and two (2.0 net) dry holes for an overall success rate of 94.6 percent (94.3 percent net). In addition, one well was drilled through farm-out arrangement at no cost to Baytex.

Baytex was successful in holding its operating costs to $8.07 per boe in the second quarter of 2005 compared to $8.11 per boe in the first quarter. Cost pressure in the industry brought on by high commodity prices and record activity levels is increasing rapidly for both operating and capital expenditures. Nonetheless, in this environment for oilfield goods and services, Baytex will strive to control its costs of doing business through efficiency improvements in its operations.

Financial Review

Cash flow from operations of $50 million for the second quarter represents yet another record for the Trust, up 12 percent from the previous record set in the first quarter of 2005. This record cash flow was achieved despite the temporary loss of six percent in production as described earlier. On a quarter-over-quarter basis, Baytex's wellhead oil price increased by 15 percent and wellhead gas price increased by six percent. The oil price increase was attributable to a seven percent increase in WTI price and a reduction in the relative cost of diluent for heavy oil blending. Condensate prices in the second quarter averaged 12 percent higher than Edmonton par crude oil price, compared to a 26 percent premium in the first quarter. Lloyd Blend heavy oil differentials were similar during the first two quarters of 2005, with the average differential at 41 percent of WTI price in the second quarter compared to 40 percent in the first quarter. The impact from the volatility of heavy oil differentials on Baytex's cash flow is substantially mitigated by the long-term supply contract with Frontier Oil Corporation, which fixes the differential for approximately 15,500 bbl/d of Baytex's heavy oil sales at 29% of WTI price until the end of 2007.

Hedging losses from WTI and foreign exchange collar contracts amounted to $9.8 million in the second quarter of 2005. These contracts expire at the end of 2005 and Baytex currently has not entered into any hedging contracts for 2006.

Baytex completed the issuance of $100 million of 6.5% convertible unsecured subordinated debentures in early June 2005. The debentures have a maturity date of December 31, 2010 and are convertible into trust units at a price of $14.75 per unit. Net proceeds from this financing were used to reduce outstanding bank indebtedness, thus substantially improving the financial flexibility of the Trust.

Outlook

Current production is approximately 34,500 boe/d and increasing. Baytex is very encouraged by the growing size and quality of its internal inventory of development prospects, which will lead to positive momentum for production gains heading into 2006. Cash distributions in the second quarter represent a payout ratio of 58 percent which was achieved under an average WTI price of US$53.17, Lloyd Blend differentials of 41%, wellhead gas price of $7.08 and realized hedging losses of $9.8 million. The payout ratio in the second half of 2005 should be lower than that of the second quarter due to higher production and stronger prevailing commodity prices. With the hedging contracts set to expire at the end of 2005, the outlook for 2006 is for further improvement in cash flow which will allow Baytex better flexibility in managing its distributions and capital investments.

Management's Discussion and Analysis

Management's discussion and analysis ("MD&A"), dated August 9, 2005, should be read in conjunction with the unaudited interim consolidated financial statements for the three months and the six months ended June 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 second quarter of 2005 increased by 74% to 3,404 bbl/d from 1,952 bbl/d a year earlier. Heavy oil production decreased 14% to 19,653 bbl/d for the second quarter of 2005 compared to 22,927 bbl/d a year ago. Natural gas production increased by 4% to 59.3 mmcf/d for the second quarter of 2005 compared to 57.2 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.

For the first half of 2005, light oil production increased by 82% to 3,639 bbl/d from 2,005 bbl/d for the same period last year. Heavy oil production for the first six months of 2005 was down 12% to 20,462 bbl/d compared to 23,125 bbl/d for the same period in 2004. Natural gas production increased by 5% to average 59.4 mmcf/d for the first six months of 2005 compared to 56.6 mmcf/d for 2004. The increase in light oil and natural gas production is due to the acquisitions completed in 2004.

Revenue. Petroleum and natural gas sales increased 13% to $118.4 million for the second quarter of 2005 from $104.5 million for the second quarter of 2004. For the first six months, petroleum and natural gas sales increased by 14% to $229.7 million in 2005 from $200.7 million a year earlier.

For the per sales unit calculations, heavy oil sales for the three months ended June 30, 2005 were 31 barrels per day lower (three months ended June 30, 2004 - 266 barrels per day higher) than the production for the period due to inventory in transit under the Frontier supply agreement. The corresponding number for the six months ended June 30, 2005 was an increase of 10 barrels per day (six months ended June 30, 2004 - an increase of 24 barrels per day).



Three Months ended June 30
------------------------------------------
2005 2004
------------------------------------------
$000s $/Unit(1) $000s $/Unit(1)
--------- ------- -------- -------
Oil revenue (barrels)
Light oil 16,438 53.06 8,444 47.55
Heavy oil 63,756 35.71 61,651 29.21
Derivative contracts loss (9,797) (5.49) (16,416) (7.17)
--------- ------- -------- -------
Total oil revenue 70,397 33.60 53,679 23.46
--------- ------- -------- -------
Natural gas revenue (mcf) 38,185 7.08 34,422 6.61
--------- ------- -------- -------
Total revenue (boe @ 6:1) 108,582 36.26 88,101 27.92
--------- ------- -------- -------
--------- ------- -------- -------
(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is
in $/mcf.


Revenue from light oil for the second quarter of 2005 increased 95% from the same period a year ago due to a 74% increase in production and a 12% increase in wellhead prices. Revenue from heavy oil increased 3% as a 14% decrease in production was offset by a 22% increase in wellhead prices. Revenue from natural gas increased 11% as the result of a 7% increase in wellhead prices and a 4% increase in production.



Six Months ended June 30
------------------------------------------
2005 2004
------------------------------------------
$000s $/Unit(1) $000s $/Unit(1)
--------- ------- -------- -------
Oil revenue (barrels)
Light oil 32,724 49.69 16,590 45.47
Heavy oil 122,949 33.18 116,920 27.75
Derivative contracts loss (16,439) (4.44) (25,838) (5.64)
--------- ------- -------- -------
Total oil revenue 139,234 37.58 107,672 23.52
--------- ------- -------- -------
Natural gas revenue (mcf) 73,981 6.88 67,153 6.52
--------- ------- -------- -------
Total revenue (boe @ 6:1) 213,215 34.64 174,825 27.78
--------- ------- -------- -------
--------- ------- -------- -------
(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is
in $/mcf.


For the first six months of 2005, light oil revenue increased 97% from the same period last year due to a 9% increase in wellhead prices and an 81% increase in production. Revenue from heavy oil increased 5% due to a 20% increase in wellhead prices partially offset by a 12% decrease in production. Revenue from natural gas increased 10% compared to the first half of 2004, as production increased 4% combined with a price increase of 6%.

Royalties. Total royalties decreased to $15.4 million for the second quarter of 2005 from $16.2 million in 2004. Total royalties for the second quarter of 2005 were 13.0% of sales compared to 15.5% of sales for the same period in 2004. For the second quarter of 2005, royalties were 16.0% of sales for light oil, 10.8% for heavy oil and 15.4% for natural gas. These rates compared to 13.4%, 11.8% and 22.8%, respectively, for the same period last year.

For the six months ended June 30, 2005, royalties increased to $32.0 million from $31.5 million for the same period last year. Total royalties for the first half of 2005 were 13.9% of sales, compared to 15.7% of sales for the corresponding period a year ago. For the first six months of 2005, royalties were 14.9% of sales for light oil, 11.1% for heavy oil and 18.3% for natural gas. These rates compared to 13.6%, 12.3% and 22.2%, respectively, for the same period in 2004.

Operating Expenses. Operating expenses for the second quarter of 2005 increased to $24.2 million from $21.4 million in the corresponding quarter last year. Operating expenses were $8.07 per boe for the second quarter of 2005 compared to $6.96 per boe for the second 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 second quarter of 2005, operating expenses were $9.12 per barrel of light oil, $8.88 per barrel of heavy oil and $1.02 per mcf of natural gas. The operating expenses for the same period a year ago were $9.97, $7.55 and $0.82, respectively.

Operating expenses for the first half of 2005 increased to $49.8 million from $42.7 million for the first half in 2004. Operating expenses were $8.09 per boe for the first six months of 2005 compared to $6.78 per boe for the corresponding period of the prior year. For the first half of 2005, operating expenses were $9.87 per barrel of light oil, $8.73 per barrel of heavy oil and $1.02 per mcf of natural gas versus $9.14, $7.39 and $0.79, respectively, for the same period a year earlier.

Transportation Expenses. Transportation expenses for the second quarter of 2005 were $5.6 million compared to $4.7 million for the second quarter of 2004. These expenses were $1.89 per boe for the second quarter of 2005 compared to $1.30 for the same period in 2004. Transportation expenses were $2.34 per barrel of oil and $0.14 per mcf of natural gas. The corresponding amounts for 2004 were $1.37 and $0.19, respectively.

Transportation expenses for the six months ended June 30, 2005 were $11.1 million compared to $9.6 million for the first six months of 2004. These expenses were $1.81 per boe in 2005 compared to $1.52 in 2004. Transportation expenses were $2.20 per barrel of oil and $0.14 per mcf of natural gas in the 2005 period, and $1.68 per barrel of oil and $0.19 per mcf of natural gas in the 2004 period.

General and Administrative Expenses. General and administrative expenses for the second quarter of 2005 at $3.9 million remain unchanged from the $3.9 million in 2004. On a per sales unit basis, these expenses were $1.30 per boe for the second quarter of 2005 compared to $1.22 per boe for 2004. In accordance with our full cost accounting policy, no expenses were capitalized in either the second quarter of 2005 or 2004.

General and administrative expenses for the first six months of 2005 were $7.5 million, compared to $7.2 million for the prior year. On a per sales unit basis, these expenses were $1.22 per boe in 2005 and $1.14 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 a recovery of $1.0 million for the second quarter of 2005 compared to an expense of $1.7 million for the second quarter of 2004.

For the six months ended June 30, 2005, compensation expense was $5.6 million compared to $3.0 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. Changes in the intrinsic value of unexercised rights after the vesting period are recognized in income in the period of change 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.

This method of determining compensation expense may result in large fluctuations, even recoveries, in compensation expense due to changes in the underlying trust unit price. Recoveries of compensation expense will only be recognized to the extent of previously recorded cumulative compensation expense associated with rights outstanding at the date of the financial statements.

Interest Expenses. Interest expenses on long-term debt increased to $7.8 million for the second quarter of 2005 from $5.2 million for the same quarter last year, primarily due to the increased debt used to finance acquisitions completed in late 2004, plus a general increase in interest rates.

For the first six months of 2005, interest expenses on long-term debt was $14.8 million compared to $9.0 million for the same period last year. The increase is attributable to the same factors influencing the second quarter variance.

Foreign Exchange. The foreign exchange loss in the second quarter of 2005 was $2.9 million compared to a loss of $5.4 million in the prior year. The loss is based on the translation of the U.S. dollar denominated long-term debt at 0.8159 at June 30, 2005 compared to 0.8267 at March 31,2005. The 2004 loss is based on translation at 0.7460 at June 30, 2004 compared to 0.7631 at March 31, 2004.

The foreign exchange loss for the first six months of 2005 was $4.0 million compared to $8.6 million in the prior year. The 2005 loss is based on the translation of the U.S. dollar denominated long-term debt at 0.8159 at June 30, 2005 compared to 0.8308 at December 31, 2004. The 2004 loss is based on translation at 0.7460 at June 30, 2004 compared to 0.7737 at December 31, 2003.

Depletion, Depreciation and Accretion. The provision for depletion, depreciation and accretion increased to $41.5 million for the second quarter of 2005 compared to $39.2 million for the same quarter a year ago. On a sales-unit basis, the provision for the current quarter was $13.86 per boe compared to $12.43 per boe for the same quarter in 2004.

Depletion, depreciation and accretion increased to $84.8 million for the first half of 2005 compared to $79.9 million for the same period last year. On a sales-unit basis, the provision for the current period was $13.77 per boe compared to $12.70 per boe for the same period a year earlier.

Income Taxes. Current tax expenses were $2.0 million for the second quarter of 2005 compared to $2.6 million for the same quarter a year ago. The current tax expense is comprised of $1.5 million of Saskatchewan Capital Tax and $0.5 million of Large Corporation Tax compared to $1.8 million and $0.8 million, respectively, in the corresponding period in 2004.

Current tax expenses were $4.0 million for the first half of 2005 compared to $4.8 million for the same period last year. The current tax expense is comprised of $3.0 million of Saskatchewan Capital Tax and $0.9 million of Large Corporation Tax compared to $3.2 million and $1.6 million, respectively, in 2004.

Net Income. Net income for the second quarter of 2005 was $18.8 million compared to a $11.2 million loss incurred in the second quarter in 2004. The favourable variance was the result of higher sales prices, unrealized gain on the financial derivatives, lower foreign exchange loss, and a recovery on the unit-based compensation expense.

Net income for the first six months of 2005 was $2.0 million compared to a $15.8 million loss for the same period in 2004. The variance was primarily due to higher sales revenue 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. 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.

At June 30, 2005, total net debt (including working capital) was $472.7 million compared to $280.0 million at June 30, 2004 and $422.0 million at December 31, 2004. The increase from June 30, 2004 was primarily due to the financing of acquisitions made in the second half of 2004. The June 30, 2005 net debt balance included $30.8 million of notional liabilities based on the mark-to-market valuations of derivative contracts as at June 30, 2005.

Capital Expenditures.

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



Six Months ended June 30
-------------------------
($ thousands) 2005 2004
-------------- ---------
Land 4,007 4,108
Seismic 1,359 517
Drilling and completion 42,225 26,767
Equipment 10,359 12,324
Other 2,101 1,502
-------------- ---------
Total exploration and development 60,051 45,218
Property acquisitions 948 -
Property dispositions (192) -
-------------- ---------
Net capital expenditures 60,807 45,218
-------------- ---------
-------------- ---------


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, August 9, 2005 to discuss our second quarter results. The conference call will be hosted by Raymond Chan, President and Chief Executive Officer, Dan Belot, Vice-President, Finance and Chief Financial Officer and Anthony Marino, Chief Operating Officer. Interested parties are invited to participate by calling toll-free across North America at 1-888-882-0144. A recorded playback of the call will be available from August 9, 2005 until August 23, 2005 by dialing 1-800-558-5253 or 416-626-4100 within the Toronto area, entering the reservation number 21252152. 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 June 30, 2005 are attached.



Baytex Energy Trust
Consolidated Balance Sheets
(thousands) (Unaudited)
June 30, 2005 December 31, 2004
-----------------------------------
Assets
Current assets
Accounts receivable $ 58,557 $ 41,154
Crude oil inventory 8,624 7,299
-----------------------------------
67,181 48,453

Deferred charges and other assets 10,412 6,491
Petroleum and natural gas properties 998,365 1,009,933
Goodwill (note 4) 37,755 39,259
-----------------------------------
$ 1,113,713 $ 1,104,136
-----------------------------------
-----------------------------------


Liabilities
Current liabilities
Accounts payable and
accrued liabilities $ 74,056 $ 72,976
Distributions payable to unitholders 10,041 9,981
Bank loan 109,267 161,444
Financial derivative contracts
(note 14) 30,761 9,513
-----------------------------------
224,125 253,914

Long-term debt (note 5) 220,542 216,583
Convertible debentures (note 6) 95,255 -
Asset retirement obligations (note 7) 75,431 73,297
Deferred obligations (note 8) 5,196 -
Future income taxes 141,656 164,909
-----------------------------------
762,205 708,703

Non-controlling interest (note 10) 12,399 12,962

Unitholders' Equity
Unitholders' capital (note 9) 521,404 515,728
Conversion feature of debentures (note 6) 4,791 -
Contributed surplus 11,773 7,494
Accumulated distributions (206,546) (146,445)
Accumulated income 7,687 5,694
-----------------------------------
339,109 382,471
-----------------------------------
$ 1,113,713 $ 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 Six Months Ended
June 30 June 30
2005 2004 2005 2004
--------------------- ---------------------
Revenue (restated (restated
- note 3) - note 3)
Petroleum and natural
gas sales $ 118,379 $ 104,517 $ 229,654 $ 200,663
Royalties (15,434) (16,237) (32,012) (31,528)
Realized loss on
financial derivatives (9,797) (16,416) (16,439) (25,838)
Unrealized gain (loss) on
financial derivatives 11,066 (7,109) (21,247) (21,393)
--------------------- ---------------------
104,214 64,755 159,956 121,904
--------------------- ---------------------

Expenses
Operating 24,176 21,384 49,814 42,659
Transportation 5,647 4,684 11,117 9,594
General and administrative 3,885 3,853 7,540 7,169
Unit-based compensation
(recovery) (note 11) (1,030) 1,707 5,607 2,988
Interest (note 12) 7,848 5,161 14,894 9,033
Foreign exchange loss 2,879 5,380 3,959 8,637
Depletion, depreciation
and accretion 41,497 39,220 84,776 79,908
--------------------- ---------------------
84,902 81,389 177,707 159,988
--------------------- ---------------------

Income (loss) before income
taxes and non-controlling
interest 19,312 (16,634) (17,751) (38,084)
--------------------- ---------------------

Income taxes
Current expense 2,015 2,629 3,982 4,791
Future recovery (2,007) (7,711) (23,764) (26,611)
--------------------- ---------------------
8 (5,082) (19,782) (21,820)
--------------------- ---------------------

Income (loss) before
non-controlling interest 19,304 (11,552) 2,031 (16,264)
Non-controlling interest
(notes 3 and 10) (500) 339 (38) 473
--------------------- ---------------------

Net income (loss) 18,804 (11,213) 1,993 (15,791)

Accumulated income (deficit),
beginning of period,
as previously reported (11,117) (12,894) 5,694 (8,598)

Accounting policy change for
non-controlling
interest (note 3) - 247 - 529
--------------------- ---------------------

Accumulated income (deficit),
beginning of period,
as restated (11,117) (12,647) 5,694 (8,069)
--------------------- ---------------------

Accumulated income (deficit),
end of period $ 7,687 $ (23,860) $ 7,687 $ (23,860)
--------------------- ---------------------
--------------------- ---------------------

Net income (loss) per trust unit
Basic $ 0.28 $ (0.18) $ 0.03 $ (0.25)
Diluted $ 0.27 $ (0.18) $ 0.03 $ (0.25)

Weighted average trust units
Basic 66,874 62,734 66,745 62,047
Diluted 71,922 65,243 71,017 65,033

See accompanying notes to the consolidated financial statements.



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

Three Months Ended Six Months Ended
June 30 June 30
--------------------- ---------------------
2005 2004 2005 2004
--------------------- ---------------------
Cash provided by (used in): (restated (restated
- note 3) - note 3)

OPERATING ACTIVITIES
Net income (loss) $ 18,804 $ (11,213) $ 1,993 $ (15,791)
Items not affecting cash:
Unit-based compensation
(recovery) (note 11) (1,030) 1,707 5,607 2,988
Amortization of deferred
charges 314 2,791 574 5,582
Foreign exchange loss 2,879 5,380 3,959 8,637
Depletion, depreciation
and accretion 41,497 39,220 84,776 79,908
Accretion on debenture 46 - 46 -
Unrealized (gain) loss on
financial derivatives
(note 14) (11,066) 7,109 21,248 21,393
Future income tax recovery (2,007) (7,711) (23,764) (26,611)
Non-controlling interest
(note 10) 500 (339) 38 (473)
--------------------- ---------------------
Funds flow from operations 49,937 36,944 94,477 75,633
Change in non-cash working
capital (208) 4,015 (17,213) (126)
Asset retirement expenditures (50) (207) (1,022) (885)
Decrease (increase) in deferred
charges and other assets 228 53 (244) 106
--------------------- ---------------------
49,907 40,805 75,998 74,728
--------------------- ---------------------

FINANCING ACTIVITIES
Issuance of convertible
debentures (note 6) 100,000 - 100,000 -
Convertible debentures issue
costs (note 6) (4,250) (4,250)
Increase (decrease) in
bank loan (81,003) - (52,177) -
Payments of distributions (29,381) (28,224) (58,779) (55,646)
Issue of trust units 479 - 1,582 -
--------------------- ---------------------
(14,155) (28,224) (13,624) (55,646)
--------------------- ---------------------

INVESTING ACTIVITIES
Petroleum and natural gas
property expenditures (32,534) (15,975) (60,999) (45,218)
Disposal of petroleum and
natural gas properties 101 - 192 -
Change in non-cash working
capital (3,319) (13,129) (1,567) (11,587)
--------------------- ---------------------
(35,752) (29,104) (62,374) (56,805)
--------------------- ---------------------

Change in cash and
short-term investments - (16,523) - (37,723)

Cash and short-term investments,
beginning of period - 32,531 - 53,731
--------------------- ---------------------

Cash and short-term investments,
end of period $ - $ 16,008 $ - $ 16,008
--------------------- ---------------------
--------------------- ---------------------

See accompanying notes to the consolidated financial statements.



Notes to the Consolidated Financial Statements
Three Months and Six Months Ended June 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 June 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 six months of 2004 by $0.33 million (three months ended June 30, 2004 - $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 was 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 six months ended June 30, 2004, the adoption of EIC 151 resulted in a $15.8 million increase in petroleum and natural gas properties (three months ended June 30, 2004 - $0.02 million), a $6.0 million increase in future income taxes (three months ended June 30, 2004 - $0.01 million) and a $10.7 million increase in unitholders' capital (three months ended June 30, 2004 - $0.04 million).

4. Corporate Acquisition

The Company continues to evaluate the final adjustments related to the acquisition made in 2004. Therefore, the purchase price allocation is subject to change.

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

June 30, December 31,
2005 2004
----------- ------------
10.5% senior subordinated notes (US$247) $ 303 $ 297
9.625% senior subordinated notes (US$179,699) 220,239 216,286
----------- ------------
$ 220,542 $ 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 conversion price paid.



Issuance on June 6, 2005 $ 100,000
Portion allocated to equity (4,791)
Accretion of non-cash interest expense 46
------------
Balance, June 30, 2005 $ 95,255
------------
------------



7. Asset Retirement Obligations

Six months Ended
--------------------------
June 30, June 30,
2005 2004
--------------------------
Balance, beginning of period $ 73,297 $ 55,996
Liabilities incurred 922 1,729
Liabilities settled (1,022) (885)
Change in estimate (671) -
Accretion 2,905 2,240
---------------------------
Balance, end of period $ 75,431 $ 59,080
--------------------------
--------------------------


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 June 30, 2005 is $196.0 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 107 1,504
Issued on exercise of trust unit rights 199 1,664
Transfer from contributed surplus on
exercise of trust unit rights - 1,246
Issued pursuant to distribution
reinvestment program 96 1,262
----------------- -----------
Balance, June 30, 2005 66,940 $ 521,404
----------------- -----------
----------------- -----------


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 the 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 June 30, 2005 was 1.29701 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 with a corresponding increase or decrease to the non-controlling interest on the balance sheet.




Number of
exchangable shares Amount
-------------------- -----------
Balance, December 31, 2004 1,876 $ 12,962
Exchanged for trust units (85) (601)
Non-controlling interest in net income - 38
-------------------- -----------
Balance, June 30, 2005 1,791 $ 12,399
-------------------- -----------
-------------------- -----------


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 market price of the trust units at the time of the 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 has determined that the amount of the reduction cannot be reasonably estimated, as it is dependent upon a number of factors including, but not limited to, future oil and natural gas prices, production of oil and natural gas, determination of amounts to be withheld from future distributions to fund capital expenditures, and the purchase and sale of oil and natural gas assets. Therefore, it is not possible to determine a fair value for the rights granted under the plan.

Compensation expense is therefore determined based on the amount that the market price of the trust unit exceeds the exercise price for rights issued as at the date of the consolidated financial statements and is recognized in earnings over the vesting period of the plan. Compensation expense for the unit rights for the second quarter was a recovery of $1.0 million in 2005 (an expense of $1.7 million in 2004) and for the six months ended June 30 was an expense of $5.6 million in 2005 (an expense of $3.0 million in 2004).

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



Number of Weighted average
rights exercise price (1)
----------- -------------------
Balance, December 31, 2004 3,537 $ 9.60
Granted 185 $ 15.53
Exercised (199) $ 7.78
Cancelled (121) $ 9.14
-----------
Balance, June 30, 2005 3,402 $ 9.04
-----------
-----------

(1) Exercise price reflects grant prices less reduction in exercise
price as discussed above.



12. Interest Expense

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

Three Months Ended Six Months Ended
June 30 June 30
2005 2004 2005 2004
-------------------- --------------------
Credit facility charges $ 2,088 $ 117 $ 4,332 $ 257
Amortization of
deferred charge 314 264 575 527
Long-term debt 5,446 4,780 9,987 8,249
-------------------- --------------------
Total interest $ 7,848 $ 5,161 $14,894 $ 9,033
-------------------- --------------------
-------------------- --------------------



13. Supplemental Cash Flow Information

Three Months Ended Six Months Ended
June 30 June 30
2005 2004 2005 2004
-------------------- --------------------
Interest paid $ 1,766 $ 55 $13,200 $10,553
Income taxes paid $ 2,434 $ 8,201 $ 4,281 $13,052



14. Financial Derivative Contracts

At June 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


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


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

15. Reclassification

Certain comparative figures have been reclassified to conform to the current periods' presentation.

Contact Information

  • Baytex Energy Trust
    Ray Chan
    President & Chief Executive Officer
    (403) 267-0715
    or
    Baytex Energy Trust
    Dan Belot
    Vice-President, Finance & Chief Financial Officer
    (403) 267-0784
    or
    Baytex Energy Trust
    Kathy Robertson
    Investor Relations Representative
    (403) 538-3645
    Toll Free Number: 1-800-524-5521
    Website: www.baytex.ab.ca