Baytex Energy Trust
TSX : BTE.UN
NYSE : BTE

Baytex Energy Trust

August 12, 2008 09:01 ET

Baytex Energy Trust Announces Second Quarter 2008 Results

CALGARY, ALBERTA--(Marketwire - Aug. 12, 2008) - Baytex Energy Trust (TSX:BTE.UN) (NYSE:BTE) is pleased to announce its operating and financial results for the three months and six months ended June 30, 2008.

Highlights

- Completed the acquisition of Burmis Energy Inc. on June 4, 2008, adding production and reserves at accretive metrics, further diversifying our product mix and expanding our light oil and natural gas development inventory;

- Generated record cash flow of $125.2 million in the quarter, 137% higher than Q2/07 and 23% higher than the previous record set in Q1/08;

- Increased monthly distributions for the second time in 2008 to $0.25 per unit commencing with the distribution in respect of June operations, maintaining a second quarter payout ratio of 47% before DRIP (37% after DRIP);

- Reduced total monetary debt by $22 million to $414 million during the quarter or 0.8 times annualized Q2/08 cash flow;

- Increased our syndicated credit facilities to $485 million, resulting in available undrawn credit facilities of $263 million at June 30, 2008;

- Commenced a thermal pilot test at our Seal heavy oil resource play; and

- Generated a total market return (1) of 56.5% during the quarter and 86.9% during the first half of the year.

(1) total market return = unit price appreciation plus cash distributions, assuming distributions are reinvested



Three Months Ended Six Months Ended
-------------------------------------------------------
FINANCIAL June 30, March 31, June 30, June 30, June 30,
2008 2008 2007 2008 2007
-------------------------------------------------------
($ thousands,
except per unit
amounts)
Petroleum and
natural gas sales 331,851 263,957 156,133 595,808 317,322
Cash flow from
operations (1) 125,195 101,570 52,755 226,765 112,406
Per unit - basic 1.42 1.19 0.69 2.61 1.48
- diluted 1.33 1.12 0.65 2.45 1.39
Cash distributions 46,005 38,474 35,815 84,479 69,867
Per unit 0.65 0.56 0.54 1.21 1.08
Net income 34,417 35,848 31,050 70,265 54,833
Per unit - basic 0.39 0.42 0.41 0.81 0.72
- diluted 0.38 0.41 0.39 0.78 0.70

Exploration and
development 41,827 51,003 25,628 92,830 70,837
Acquisitions -
net of dispositions 178,409 581 239,848 178,990 239,611
Total capital
expenditures 220,236 51,584 265,476 271,820 310,448

Long-term notes 179,900 184,967 191,355 179,900 191,355
Bank loan 180,000 198,045 257,977 180,000 257,977
Convertible
debentures 11,654 15,041 17,030 11,654 17,030
Working capital
deficiency 42,119 37,909 4,798 42,119 4,798
Total monetary
debt (2) 413,673 435,962 471,160 413,673 471,160



Three Months Ended Six Months Ended
-------------------------------------------------------
OPERATING June 30, March 31, June 30, June 30, June 30,
2008 2008 2007 2008 2007
-------------------------------------------------------
Daily production
Light oil & NGL
(bbl/d) 6,778 7,330 3,705 7,054 3,595
Heavy oil (bbl/d) 22,905 22,484 21,444 22,695 21,785
Total oil (bbl/d) 29,683 29,814 25,149 29,749 25,380
Natural gas (MMcf/d) 51.0 50.1 49.3 50.5 50.0
Oil equivalent
(boe/d @ 6:1) 38,179 38,157 33,372 38,168 33,705

Average prices
(before hedging)
WTI oil (US$/bbl) 123.98 97.90 65.03 110.94 61.60
Edmonton par oil
($/bbl) 126.29 97.50 72.15 111.90 69.62
BTE light oil
& NGL ($/bbl) 109.26 84.91 54.42 96.61 52.81
BTE heavy oil
($/bbl) (3) 78.92 59.65 40.14 69.19 40.15
BTE total oil
($/bbl) 85.82 65.66 42.26 75.58 41.95
BTE natural gas
($/Mcf) 9.29 7.42 7.02 8.37 7.23
BTE oil equivalent
($/boe) 79.15 61.16 42.22 70.06 42.30

TRUST UNIT INFORMATION
TSX (C$)
Unit Price
High $35.37 $23.40 $22.92 $35.37 $22.92
Low $22.60 $16.30 $20.15 $16.30 $18.83
Close $34.79 $22.78 $21.34 $34.79 $21.34
Volume traded
(thousands) 34,782 25,748 20,544 60,530 42,394

NYSE (US$)
Unit Price
High $34.98 $23.34 $21.18 $34.98 $21.18
Low $21.90 $15.88 $17.42 $15.88 $16.01
Close $34.28 $22.16 $19.99 $34.79 $19.99
Volume traded
(thousands) 4,990 4,786 3,135 9,776 7,315

Units outstanding
(thousands) (4) 96,017 88,474 85,914 96,017 85,914

(1) Cash flow from operations is a non-GAAP term that represents cash
generated from operating activities before changes in non-cash working
capital and other operating items (see reconciliation under MD&A). The
Trust's cash flow from operations may not be comparable to other
issuers. The Trust considers cash flow from operations 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) Total monetary debt is a non-GAAP term, and is defined in note 16 to
the consolidated financial statements.

(3) Heavy oil wellhead prices are net of blending costs.

(4) 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.


This press release contains certain forward-looking information and statements. We refer you to the end of the Management's Discussion and Analysis section of this press release for our advisory on forward-looking information and statements.

Operations Review

Exploration and development expenditures totaled $41.8 million for the second quarter of 2008. During this quarter, Baytex participated in the drilling of 32 (30.6 net) wells, resulting in 29 (28.3 net) oil wells, one (1.0 net) gas wells and two (1.3 net) dry holes for a 94% (95.8% net) success rate.

Production averaged 38,179 boe/d during the second quarter of 2008 compared to 38,157 boe/d for the first quarter. Second quarter production was reduced as a result of spring breakup and scheduled turnaround activities at several light oil and natural gas facilities, offset by the inclusion of production from the acquisition of Burmis Energy Inc. commencing on June 4, 2008. Current production from the Burmis properties of approximately 3,900 boe/d is ahead of our pre-acquisition expectations.

Driven by particularly strong heavy oil prices, drilling in the second quarter was predominantly conducted in the Lloydminster area of southwestern Saskatchewan, where Baytex successfully drilled 27 oil wells. In the second half of 2008, drilling activities will be augmented by continued heavy oil development at Seal and light oil and natural gas drilling, primarily in our central Alberta areas.

During the second quarter, we commenced our cyclic steam pilot project at our Seal heavy oil resource play in north central Alberta. We have completed the steam injection and soak phases of the pilot, and are currently in the production phase. We expect to be in a position to discuss the results of this pilot test later in the fall of 2008 when we have sufficient production data for a definitive assessment of the viability of the cyclic steam process. Conventional production at Seal continues to grow, with second quarter production averaging approximately 3,850 bbl/d compared to 2,500 bbl/d in the first quarter of 2008.

As discussed in our first quarter interim report, we are planning an exploration and development capital program of $170 million for the year, including expenditures relating to properties acquired through the Burmis transaction. We are also projecting our overall production to average approximately 41,000 boe/d in the second half of 2008.

Financial Review

Cash flow from operations for the second quarter of 2008 was a record $125.2 million, an increase of 137% over the same period one year ago and 23% higher than the previous record generated in the first quarter of 2008. Continued improvement in commodity prices buoyed these results. During the second quarter of 2008, WTI price averaged US$123.98 per barrel, up 27% from the first quarter of 2008. Our corporate wellhead oil price averaged $85.82 per barrel for the quarter, an increase of 31% compared to $65.66 per barrel received in the first quarter of 2008. Natural gas prices also improved significantly, with our wellhead price averaging $9.29 per Mcf for the second quarter of 2008, up 25% from the previous quarter.

Canadian heavy oil pricing continues to set all-time high, with western Canadian heavy oil differentials averaging only 18% of WTI in the second quarter, compared to 21% in the first quarter this year and 29% in the second quarter of 2007. Combining these low differentials with the strength in WTI, Baytex realized an average heavy oil wellhead price of $78.92 per bbl in the second quarter, an increase of 32% over first quarter heavy oil pricing. The near term financial impact of narrower differentials on Baytex is partially muted by our fixed differential supply agreements covering approximately one-half of our heavy oil production for 2008. Cash flow for the current quarter was also affected by a $25 million realized loss from derivative contracts mainly associated with the WTI price collars in effect for 2008. Net income in the second quarter was negatively impacted by $48 million in unrealized losses related to our WTI price collars for the balance of 2008 and 2009.

On June 4, 2008, we successfully closed the acquisition of Burmis Energy Inc., acquiring all of the issued and outstanding shares of Burmis on the basis of 0.1525 Baytex trust unit for each Burmis common share. Approximately 6.38 million trust units were issued pursuant to this transaction. Burmis had approximately $24 million in net debt at the time of closing of the transaction which was assumed by Baytex.

Total monetary debt, excluding notional mark-to-market liabilities at the end of the quarter and including $24 million of net debt from Burmis, was $414 million and represented a reduction of $22 million from the end of the first quarter of 2008. This debt level represents 0.8 times annualized second quarter cash flow. Concurrent with the closing of the Burmis acquisition, our credit facilities were increased to $485 million. With the decrease in net debt and increase in borrowing capacity, Baytex continues to have a strong and liquid balance sheet with $263 million in available undrawn credit facilities at the end of the second quarter.

During the quarter, Baytex announced a 25% increase to our monthly distribution to $0.25 per unit, the second distribution increase this year and the third in our history as an income trust against no reduction. We are pleased to be able to share the benefit of higher commodity prices directly with our unitholders. Based upon our production and capital spending guidance, and assuming 15% of our cash distributions are reinvested under our DRIP, Baytex will be able to sustain this level of distribution and fund our capital programs from internally generated cash flow at an average WTI price of US$95.00 per barrel and an average wellhead gas price of $8.00 per Mcf. Our strong balance sheet would also allow us to manage our distribution practice on a consistent basis within a period of high volatility for commodity prices.

Management's Discussion and Analysis

The following is management's discussion and analysis ("MD&A") of the operating and financial results of Baytex Energy Trust ("Baytex" or the "Trust") for the three and six months ended June 30, 2008. This information is provided as of August 11, 2008. The second quarter results have been compared with the corresponding period in 2007. This MD&A should be read in conjuction with the Trust's unaudited interim comparative consolidated financial statements for the three and six months ended June 30, 2008 and 2007 and our audited consolidated comparative financial statements for the years ended December 31, 2007 and 2006, together with accompanying notes, and the Annual Information Form for the year ended December 31, 2007 (the "AIF"). These documents and additional information about the Trust are available on SEDAR at www.sedar.com.

In this MD&A, barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

This MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our advisory on forward-looking information and statements.

Non-GAAP Financial Measures

The Trust evaluates performance based on net income and cash flow from operations. Cash flow from operations and cash flow from operations per unit are not measurements based on Generally Accepted Accounting Principles in Canada ("GAAP"), but are financial terms commonly used in the oil and gas industry. Cash flow from operations represents cash generated from operating activities before changes in non-cash working capital, site restoration and reclamation expenditures, deferred charges and other assets. The Trust's determination of cash flow from operations may not be comparable with the calculation of similar measures for other entities. The Trust considers cash flow from operations a key measure of performance as it demonstrates the ability of the Trust to generate the cash flow necessary to fund future distributions to unitholders and capital investments. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income per unit. For a reconciliation of cash flow from operations to cash flow from operating activities, see "Cash Flow from Operations, Payout Ratio and Distributions".

Production. Light oil and natural gas liquids ("NGL") production for the second quarter of 2008 increased by 83% to 6,778 bbl/d from 3,705 bbl/d a year earlier due to the acquisition of the properties at Pembina in June 2007 and the acquisition of Burmis Energy Inc. in June 2008. Heavy oil production increased 7% to 22,905 bbl/d for the second quarter of 2008 compared to 21,444 bbl/d for the same period last year. Natural gas production increased 3% from year-ago levels, averaging 51.0 MMcf/d for the second quarter of 2008 compared to 49.3 MMcf/d for the same period last year.

For the first half of 2008, light oil and NGL production increased by 96% to 7,054 bbl/d from 3,595 bbl/d for the same period last year. Heavy oil production for the first six months in 2008 increased by 4% to 22,695 bbl/d compared to 21,785 bbl/d for the same period in 2007. Natural gas production increased by 1% to 50.5 MMcf/d for the first six months in 2008 compared to 50.0 MMcf/d for the same period in 2007.

Revenue. Petroleum and natural gas sales increased 113% to $331.9 million for the second quarter of 2008 from $156.1 million for the same period in 2007. Commencing with the first quarter of 2008, Baytex is reporting revenue from our heavy oil sales based on the price of the blend crude sold to the refineries. The cost of the blending diluent is reported as an expense. There is no impact to cash flow compared to the previous practice of reporting revenue based on heavy oil wellhead price net of blending charges.

For the per sales unit calculations, heavy oil sales for the three months ended June 30, 2008 were 107 bbl/d higher (three months ended June 30, 2007 - 183 bbl/d lower) than the production for the period due to sales of pipeline inventory. The corresponding number for the six months ended June 30, 2008 was an increase of 531 bbl/d (six months ended June 30, 2007 - a decrease of 104 bbl/d).



Three Months ended June 30
---------------------------------------------------
2008 2007
------------------------------- -------------------
$000s $/Unit(1) $000s $/Unit(1)
-------- --------- -------- ---------
Oil revenue
Light oil & NGL 67,390 109.26 18,349 54.42
Heavy oil (2) 165,260 78.92 77,658 40.14
-------- --------- -------- ---------
Total oil revenue 232,650 85.82 96,007 42.26
Natural gas revenue 43,103 9.29 31,503 7.02
-------- --------- -------- ---------
Total revenue 275,753 79.15 127,510 42.22
--------- ---------
--------- ---------
Sulphur revenue 1,298 -
Sales of heavy oil
blending diluent 54,800 28,623
-------- --------
Total petroleum and
natural gas sales 331,851 156,133
-------- --------
-------- --------

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

(2) Heavy oil wellhead prices are net of blending costs.


Revenue from light oil and NGL for the second quarter of 2008 increased 267% from the same period a year ago due to an 83% increase in production and a 101% increase in wellhead prices. Revenue from heavy oil increased 113% as a result of a 97% increase in wellhead prices and a 7% increase in production. Revenue from natural gas increased 37% due to a 3% increase in production and a 32% increase in wellhead prices.



Six Months ended June 30
---------------------------------------------------
2008 2007
------------------------------- -------------------
$000s $/Unit(1) $000s $/Unit(1)
-------- --------- -------- ---------
Oil revenue
Light oil & NGL 124,027 96.61 34,367 52.81
Heavy oil (2) 292,487 69.19 157,566 40.15
-------- --------- -------- ---------
Total oil revenue 416,514 75.58 191,933 41.95
Natural gas revenue 76,926 8.37 65,328 7.23
-------- --------- -------- ---------
Total revenue 493,440 70.06 257,261 42.30
--------- ---------
--------- ---------
Sulphur revenue 2,653 -
Other income 2,000 -
Sales of heavy oil
blending diluent 97,715 60,061
-------- --------
Total Petroleum and
natural gas sales 595,808 317,322
-------- --------
-------- --------

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

(2) Heavy oil wellhead prices are net of blending costs.


For the first six months of 2008, light oil and NGL revenue increased 261% from the same period last year due to an 83% increase in wellhead prices and a 97% increase in production. Revenue from heavy oil increased 86% due to a 72% increase in wellhead prices and a 5% increase in production. Revenue from natural gas increased 18% due to a 2% increase in production combined with a 16% increase in wellhead prices.

During the current quarter, sulphur production averaged 26.8 tonnes per day with an average price of $520.66 per tonne. For the six months ended June 30, 2008, sulphur production averaged 33.3 tonnes per day with an average price of $390.60 per tonne. In prior years, sulphur revenue was not material for reporting purposes.

During the first quarter of 2008, Baytex received a $2.0 million payment from a partner as compensation for non-performance of a drilling obligation which was reported as other income under petroleum and natural gas sales.

Financial Derivatives. The loss on financial derivatives for the second quarter was $73.5 million compared to $3.9 million in the second quarter of 2007. This is comprised of $25.1 million in realized loss and $48.4 million in unrealized loss for the second quarter of 2008 compared to $0.1 million in realized gain and $4.0 million in unrealized loss in the same period one year ago.

The loss on financial derivatives for the six months ended June 30, 2008 was $91.2 million compared to $4.0 million for the same period in 2007. This is comprised of $35.6 million in realized loss and $55.6 million in unrealized loss for the first six months of 2008 compared to $0.7 million in realized gain and $4.7 million in unrealized loss in the same period one year ago.

Royalties. Total royalties increased to $58.0 million for the second quarter of 2008 from $21.3 million in the same period last year. Total royalties for the second quarter of 2008 were 21.0% of oil and gas revenue excluding sales of heavy oil diluent compared to 16.7% for the same period in 2007. For the second quarter of 2008, royalties were 23.4% of revenue for light oil, NGL and natural gas, and 19.5% for heavy oil excluding sales of heavy oil diluent. These rates compared to 18.3% and 15.7%, respectively, for the same period last year. Royalties are generally based on well productivity and market index prices in the period, with rates increasing as price and volume escalate. Oil royalties as a percentage of revenue were higher in the current quarter as market prices were higher than the prices realized by Baytex under fixed differential supply agreements.

For the six months ended June 30, 2008, royalties increased to $103.0 million from $41.6 million for the same period last year. Total royalties for the first six months of 2008 were 20.9% of revenue excluding sales of diluent, compared to 16.2% for the corresponding period a year ago. For the first six months of 2008, royalties were 23.4% of revenue for light oil, NGL and natural gas and 19.1% for heavy oil excluding sales of diluent. These rates compared to 16.8% and 15.8%, respectively, for the same period in 2007.

Operating Expenses. Operating expenses for the second quarter of 2008 increased to $41.0 million from $30.2 million in the corresponding quarter last year. Included in operating expenses for the current quarter is $0.1 million of costs related to the production of sulphur. Operating expenses were $11.76 per boe for the second quarter of 2008 compared to $10.00 per boe for the second quarter of 2007. For the second quarter of 2008, operating expenses were $12.51 per boe of light oil, NGL and natural gas, and $11.24 per barrel of heavy oil. Operating expenses for the same period a year ago were $9.40 and $10.33, respectively. The increase in expense per unit was primarily due to the acquisition of higher cost operations at Pembina and Lindbergh in June 2007, an inflationary cost environment for fuel, oilfield services and labour, and production curtailment associated with spring break-up and scheduled turnaround activities at several light oil and natural gas facilities in the second quarter of 2008.

Operating expenses for the first six months of 2008 increased to $78.7 million from $58.2 million for the first six months of 2007. Operating expenses were $11.18 per boe for the first six months of 2008 compared to $9.56 per boe for the corresponding period of the prior year. For the first half of 2008, operating expenses were $11.45 per boe of light oil, NGL and natural gas and $10.96 per barrel of heavy oil compared to $9.23 and $9.75, respectively, for the same period a year earlier. The increase in operating expenses per unit results from the same factors noted above. With the addition of the lower cost production from the Burmis properties, and the resumption of normal production operations, operating expenses for the second half of 2008 are expected to average approximately $11.00 per boe.

Transportation and Blending Expenses. Transportation and blending expenses for the second quarter of 2008 were $64.4 million compared to $36.6 million for the second quarter of 2007. Transportation expenses for the current quarter includes $0.3 million related to transportation of sulphur. Transportation expenses were $2.67 per boe for the second quarter of 2008 compared to $2.64 per boe for the same period in 2007. Transportation expenses were $0.69 per boe of light oil, NGL and natural gas, and $3.98 per barrel of heavy oil. The corresponding amounts for 2007 were $1.08 and $3.52, respectively.

Transportation expenses for the six months ended June 30, 2008 were $114.9 million compared to $74.9 million for the first six months of 2007. These expenses were $2.36 per boe in 2008 compared to $2.44 in 2007. Transportation expenses were $0.70 per boe of light oil, NGL and natural gas and $3.46 per barrel of heavy oil in the 2008 period, compared to $0.99 and $3.24, respectively, for the same period in 2007.

The heavy oil produced by Baytex requires blending to reduce its viscosity in order to meet pipeline specifications. Baytex purchases primarily condensate as the blending diluent from industry producers to facilitate the marketing of our heavy oil. In the second quarter of 2008, the blending cost was $54.8 million for the purchase of 4,332 bbl/d of condensate at $139.02 per barrel as compared to 3,995 bbl/d at $86.48 per barrel in the same period last year. The cost of diluent is effectively recovered through the sale price of a blended product. For the six months ended June 30, 2008, the blending cost was $97.7 million for the purchase of 4,389 bbl/d of condensate at $122.32 per barrel as compared to 4,390 bbl/d at $75.59 per barrel in the same period last year.

General and Administrative Expenses. General and administrative expenses for the second quarter of 2008 increased to $7.7 million from $5.5 million in 2007. On a per sales unit basis, these expenses were $2.22 per boe for the second quarter of 2008 compared to $1.84 per boe for the same period in 2007. In the current quarter, Baytex recorded a provision for non-recoverable accounts receivable of $612,000 (or $0.18 per boe) in general and administrative expenses. Of this provision, $350,000 relates to Baytex's entire exposure for the second quarter for potentially uncollectable amounts from a marketing counterparty which has filed for protection under the Companies Creditors Arrangement Act. The remainder of the increase in general and administrative expenses is a reflection of the escalating cost environment in our industry, particularly in our Calgary head office area.

General and administrative expenses for the first six months of 2008 were $14.9 million, compared to $11.1 million for the prior period. On a per sales unit basis, these expenses were $2.12 per boe in 2008 and $1.83 per boe in 2007.
In accordance with our full cost accounting policy, no expenses were capitalized in either 2008 or 2007.

Unit-based Compensation Expense. Compensation expense related to the Trust's unit rights incentive plan was $2.1 million for the second quarter of 2008 compared to $1.9 million for the second quarter of 2007. For the six months ended June 30, 2008, compensation expense was $4.2 million compared to $3.8 million for the same period in 2007.

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

Interest Expenses. Interest expenses decreased to $8.2 million for the second quarter of 2008 from $8.9 million for the same quarter last year, primarily due to the decrease in prime lending rates on the bank loan plus the lower foreign exchange rates on payment of interest on the U.S. dollar denominated debt.

Interest expense of $16.9 million for the first six months of 2008 was comparable to the same period last year as the effect of lower interest and foreign exchange rates were offset by the higher average debt outstanding.

Foreign Exchange. Foreign exchange gain in the second quarter of 2008 was $1.6 million compared to $16.7 million in the prior year. This gain is based on the translation of the U.S. dollar denominated long-term debt at 0.9817 at June 30, 2008 compared to 0.9729 at March 31, 2008. The 2007 gain is based on translation at 0.9404 at June 30, 2007 compared to 0.8674 at March 31, 2007.

Foreign exchange loss for the first six months of 2008 was $5.9 million compared to a gain of $18.6 million in the prior year. The 2008 loss is based on the translation of the U.S. dollar denominated long-term debt at 0.9817 at June 30, 2008 compared to 1.0120 at December 31, 2007. The 2007 gain is based on translation at 0.9404 at June 30, 2007 compared to 0.8581 at December 31, 2006.

Depletion, Depreciation and Accretion. The provision for depletion, depreciation and accretion at $50.9 million for the second quarter of 2008 represents an increase of 20% from $42.5 million for the same quarter in 2007 primarily due to a 14% increase in production. On a per sales unit basis, the provision for the current quarter was $14.62 per boe compared to $14.09 per boe for the same quarter in 2007. The higher rate is primarily due to the costs of the acquisitions completed in June 2008 and June 2007.

Depletion, depreciation and accretion increased to $101.4 million for the first half of 2008 compared to $83.9 million for the same period last year. On a sales-unit basis, the provision for the current period was $14.40 per boe compared to $13.80 per boe for the same period a year earlier. The increase is attributable to the same factors influencing the second quarter calculations.

Taxes. On June 22, 2007, the federal government's bill regarding the taxation of distributions of publicly traded income trusts beginning January 1, 2011 received Royal Assent. As a result, a future income tax recovery of $0.5 million was recognized in the second quarter of 2007 relating to unutilized tax pools in the Trust which will be deductible to the Trust after 2010. The majority of the Trust's temporary differences reside in a consolidated subsidiary which is not subject to the distribution tax, and is therefore not impacted by this legislative change.

The government's bill provides that the new tax regime for income trusts will not apply until January 1, 2011 so long as the Trust experiences only "normal growth" and no "undue expansion". As part of the government's bill, a "safe harbour" limit was established for existing income trusts by limiting future equity issues to 40% of each trust's October 31, 2006 market capitalization for the period November 1, 2006 to December 31, 2007, and an additional 20% of this market capitalization for each of 2008, 2009 and 2010. For Baytex, the limits are approximately $730 million for 2006 / 2007 and $365 million for each of the subsequent three years. Issuance of equity or convertible debt beyond these limits will result in the new regime applying to the Trust before 2011. As of June 30, 2008, Baytex has issued $347.5 million of equity since November 2006.

On July 14, 2008, the Department of Finance released proposed amendments (the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the conversion of existing income trusts into corporations. In general, the proposed amendments will permit a conversion to be tax deferred for both the unitholders and the trust. However, the Conversion Rules provide alternative approaches to completing a tax deferred conversion. The Department of Finance has requested comments on the Conversion Rules by September 15, 2008 and it is anticipated that there will be further amendments to the Conversion Rules. Management and the Board of Directors continue to review the impact of the future taxation of distributions on our business strategy but at this time have made no decision as to the ultimate legal form under which Baytex will operate post 2010.

The provision for future income taxes for the current quarter was a recovery of $10.3 million compared to a recovery of $11.3 million in the same period in 2007.

Current tax of $2.8 million for the second quarter of 2008 is comprised of Saskatchewan Capital Tax and Resource Surcharge. Current tax for the same period a year ago was $1.2 million, also comprised entirely of this Saskatchewan levy. Current tax expenses were $5.3 million for the first half of 2008 compared to $2.7 million for the same period last year. Current tax expenses were comprised entirely of Saskatchewan Capital Tax and Resource Surcharge.

Net Income. Net income for the second quarter of 2008 was $34.4 million compared to $31.1 million for the second quarter in 2007. The variance is the result of increased production and increased sales prices partially offset by increased royalties, increased loss on financial derivatives, foreign exchange and depletion.

Net income for the first six months of 2008 was $70.3 million compared to $54.8 million for the same period in 2007. The variance is due to higher sales prices partially offset by an increased loss on financial derivatives, higher operating and transportation costs, higher depletion rates and foreign exchange losses, and lower future tax recoveries.


Cash Flow from Operations, Payout Ratio and Distributions

Cash flow from operations and payout ratio are non-GAAP terms. Cash flow from operations represents cash flow from operating activities before changes in non-cash working capital, deferred charges and other assets and asset retirement expenditures. The Trust's payout ratio is calculated as cash distributions (net of participation in our Distribution Reinvestment Plan ("DRIP")) divided by cash flow from operations. The Trust considers these to be key measures of performance as they demonstrate the Trust's ability to generate the cash flow necessary to fund future distributions and capital investments.

The following table reconciles cash flow from operating activities (a GAAP measure) to cash flow from operations (a non-GAAP measure):



Three Months Ended Six Months Ended Year Ended
-------------------------- ---------------- ------------------
June March June June June December December
30, 31, 30, 30, 30, 31, 31,
($000s) 2008 2008 2007 2008 2007 2007 2006
--------- -------- ------- -------- -------- -------- --------
Cash flow
from operating
activities 101,070 120,945 52,878 222,015 112,597 286,450 261,982
Change in
non-cash
working
capital 24,141 (19,779) (956) 4,362 (2,303) (5,140) 9,058
Asset
retirement
expenditures (27) 394 257 367 960 2,442 1,747
Decrease
(increase)
in deferred
charges and
other assets 11 10 576 21 1,152 2,278 1,875
--------- -------- ------- -------- -------- -------- --------
Cash flow
from
operations 125,195 101,570 52,755 226,765 112,406 286,030 274,662
--------- -------- ------- -------- -------- -------- --------

Cash
Distributions 46,005 38,474 35,815 84,479 69,867 145,927 143,072

Payout ratio 37% 38% 68% 37% 62% 51% 52%


The Trust does not deduct capital expenditures when calculating the payout ratio. Due to the depleting nature of oil and gas assets, certain levels of capital expenditures are required to minimize production declines. In the oil and gas industry, due to the nature of reserves reporting, natural production declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Should the costs to explore for, develop or acquire oil and natural gas assets increase significantly, it is possible that the Trust would be required to reduce or eliminate its distributions in order to fund capital expenditures. There can be no certainty that the Trust will be able to maintain current production levels in future periods.

Cash distributions, net of DRIP participation, of $46.0 million for the second quarter of 2008 were funded through cash flow from operations of $125.2 million.



The following tables compare cash distributions to cash flow from operating
activities and net income:

Three Months Ended Six Months Ended Year Ended
-------------------------- ---------------- ------------------
June March June June June December December
30, 31, 30, 30, 30, 31, 31,
($000s) 2008 2008 2007 2008 2007 2007 2006
--------- -------- ------- -------- -------- -------- --------
Cash flow
from
operating
activities 101,070 120,945 52,878 222,015 112,597 286,450 261,982
Actual cash
distributions 46,005 38,474 35,815 84,479 69,867 145,927 143,072
--------- -------- ------- -------- -------- -------- --------
Excess of
cash flow
from
operating
activities
over cash
distributions 55,065 82,471 17,063 137,536 42,730 140,523 118,910
--------- -------- ------- -------- -------- -------- --------

Net Income 34,417 35,848 31,050 70,265 54,833 132,860 147,069
Actual cash
distributions 46,005 38,474 35,815 84,479 69,867 145,927 143,072
--------- -------- ------- -------- -------- -------- --------
Excess
(shortfall)
of net
income
over cash
distributions (11,588) (2,626) (4,765) (14,214) (15,034) (13,067) 3,997
--------- -------- ------- -------- -------- -------- --------


It is Baytex's long term operating objective to substantially fund cash distributions and capital expenditures required to maintain production and reserves through cash flow from operating activities. Future production levels are highly dependent upon our success in exploiting our asset base and acquiring additional assets. The success of these activities, along with commodity prices realized are the main factors influencing the sustainability of our cash distributions. During periods of temporary decline in commodity prices, or periods of higher capital spending for acquisitions, it is possible that internally generated cash flow will not be sufficient to fund both cash distributions and capital spending. In these instances, the cash shortfall will be funded through a combination of equity and debt financing. As at June 30, 2008, Baytex had approximately $263 million in available undrawn credit facilities to fund such shortfall. As Baytex strives to maintain a consistent distribution level under the guidance of prudent financial parameters, there may be times when a portion of our cash distributions would represent a return of capital.

For the three months ended June 30, 2008, the Trust's cash distributions exceeded net income by $11.6 million, with net income reduced by $66.7 million of non-cash items. For the six months ended June 30, 2008, the Trust's cash distributions exceeded net income by $14.2 million, with net income reduced by $151.8 million of non-cash items. Non-cash charges such as depletion, depreciation and accretion are not fair indicators for the cost of maintaining our productive capacity as they are based on historical costs of assets and not the fair value of replacing those assets under current market conditions. Other non-cash charges, such as unrealized losses on financial instruments and unrealized foreign exchange losses, reduce the net income of a current period, but may not have the same impact on future periods' cash flow. Accordingly, net income is not a fair representation of the Trust's ability to fund our distributions and capital programs.

Liquidity and Capital Resources. At June 30, 2008, total net monetary debt was $414 million compared to $444 million at the end of 2007, with the decrease mainly attributable to the surplus in cash flow after the funding of distributions and capital expenditures. Bank borrowings and working capital deficiency at the end of second quarter 2008 was $222 million compared to total credit facilities of $485 million. Effective June 4, 2008, total credit facilities were increased to $485 million from $370 million.

The Trust has a number of financial obligations in the ordinary course of business. These obligations are of a recurring and consistent nature and impact the Trust's cash flows in an ongoing manner. A significant portion of these obligations will be funded through operating cash flow. These obligations as of June 30, 2008, and the expected timing of funding of these obligations are noted in the table below.



2-3 4-5 Beyond
($000s) Total 1 year years years 5 years
-------- -------- -------- ----------- -----------
Accounts payable and
accrued liabilities 151,464 151,464 - - -
Distributions payable to
unitholders 23,647 23,647 - - -
Bank loan (1) 180,000 180,000 - - -
Derivative contracts 89,843 81,709 8,134 - -
Long term debt (2) 183,293 - 183,293 - -
Convertible
debentures (2) 11,940 - 11,940 - -
Deferred obligations 92 44 48 - -
Operating leases 6,668 2,862 2,940 866 -
Processing and
transportation
agreements 19,449 6,270 10,625 2,554 -
-------- -------- --------- ------------ -----------
Total 666,396 445,996 216,980 3,420 -
-------- -------- --------- ------------ -----------
-------- -------- --------- ------------ -----------

(1) The bank loan is a 364-day revolving loan with the ability to extend the
term. The Trust has no reason to believe that it will be unable to
extend the credit facility when it matures on June 3, 2009.
(2) Principal amount of instruments.


The Trust is authorized to issue an unlimited number of trust units. As at August 5, 2008, the Trust had 94,942,555 trust units issued and outstanding, and $11.0 million in convertible debentures outstanding which are convertible into 748,339 trust units. In addition, as at August 5, 2008, Baytex Energy Ltd. had 807,242 exchangeable shares outstanding, which are exchangeable for 1,437,723 trust units based on the exchange ratio in effect on this date. On May 30, 2008, the Trust announced Baytex Energy Ltd. has elected to redeem all of its exchangeable shares outstanding on August 29, 2008.



Capital Expenditures.

Capital expenditures for the three months and six months ended June 30, 2008
and 2007 are summarized as follows:

Three Months Ended Six Months Ended
June 30 June 30
-------------------- -------------------
($000s) 2008 2007 2008 2007
--------- --------- -------- ---------
Land 3,026 1,710 4,186 3,059
Seismic 607 360 908 1,369
Drilling and completion 27,225 17,748 68,976 53,177
Equipment 10,502 4,932 17,256 11,137
Other 467 878 1,504 2,095
--------- --------- -------- ---------
Total exploration and development 41,827 25,628 92,830 70,837
Corporate acquisition 178,351 239,884 178,351 239,884
Property acquisitions 60 4 701 35
Property dispositions (2) (40) (62) (308)
--------- --------- -------- ---------
Total capital expenditures 220,236 265,476 271,820 310,448
--------- --------- -------- ---------
--------- --------- -------- ---------


Financial Instruments and Risk Management.

The Trust is exposed to a number of financial risks, including market risk, credit risk and liquidity risk. Market risk is the risk that the fair value of future cash flows will fluctuate due to movements in market prices, and is comprised of currency risk, interest rate risk and commodity price risk. Market risk is managed by the Trust through a series of derivative contracts intended to manage the volatility of our operating cash flow. Liquidity risk is the risk that the Trust will encounter difficulty in meeting obligations associated with financial liabilities. The Trust manages its liquidity risk through cash and debt management. Credit risk is the risk that a counterparty to a financial asset will default resulting in the Trust incurring a loss. The Trust manages this credit risk by entering into sales contracts only with credit worthy entities and reviewing its exposure to individual entities on a regular basis.

Details of the risk management contracts in place as at June 30 2008, and the accounting for the Trust's financial instruments are disclosed in Note 14 to the consolidated financial statements, which are incorporated herein by reference.



Selected Quarterly Financial Information

($000s,
except per
unit data) 2008 2007 2006
--------------- ------------------------------- ----------------
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
------- ------- ------- ------- ------- ------- ------- --------
Petroleum
and natural
gas sales 331,851 263,957 233,348 193,182 156,133 161,189 164,103 175,583
------- ------- ------- ------- ------- ------- ------- --------
Net income 34,417 35,848 41,353 36,674 31,050 23,783 19,988 42,040
------- ------- ------- ------- ------- ------- ------- --------
Net income
per trust
unit
Basic 0.39 0.42 0.49 0.44 0.41 0.32 0.27 0.57
------- ------- ------- ------- ------- ------- ------- --------
Diluted 0.38 0.41 0.46 0.43 0.39 0.30 0.26 0.54
------- ------- ------- ------- ------- ------- ------- --------


Changes in Accounting Policies. Effective January 1, 2008, the Trust adopted the following accounting standards of the Canadian Institute of Chartered Accountants ("CICA"): Section 3862 "Financial Instruments - Disclosures"; Section 3863 "Financial Instruments - Presentation"; and Section 1535 "Capital Disclosures". The adoption of the new standards resulted in additional disclosures with regard to financial instruments (note 14) and the Trust's objectives, policies and process for managing capital (note 16).

The Trust also adopted Section 3031 "Inventories". This new standard replaces the previous inventories standard and requires inventory to be valued on a first-in, first-out or weighted average basis. The adoption of Section 3031 did not have an impact on the consolidated financial statements of the Trust.

Future Accounting Changes

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public issuers are expected to converge with International Financial Reporting Standards ("IFRS"). In March 2007, the AcSB released an "Implementation Plan for Incorporating IFRS into Canadian GAAP", which assumes a convergence date of January 1, 2011. Following a progress review on February 13, 2008, the AcSB has confirmed this changeover date. The Trust continues to monitor and assess the impact of the convergence of Canadian GAAP and IFRS.

In February 2008, the CICA issued Section 3064 "Goodwill and Intangible Assets", which replaces Sections 3062 "Goodwill and Other Intangible Assets" and 3450 "Research and Development Costs". This section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets by profit-oriented enterprises subsequent to their initial measurement. The new standard will be effective on January 1, 2009. The Trust does not expect the adoption of this new Section to have a material impact on its consolidated financial statements.

Controls and Procedures

Disclosure Controls and Procedures. Raymond Chan, the Chief Executive Officer, and Derek Aylesworth, the Chief Financial Officer of Baytex Energy Ltd. (together the "Disclosure Officers"), are responsible for establishing and maintaining disclosure controls and procedures for Baytex. We have designed such disclosure controls and procedures, or caused them to be designed under our supervision, to provide reasonable assurance that all material or potentially material information about the activities of Baytex is made known to us by others within Baytex.

It should be noted that while our Disclosure Officers believe that Baytex's disclosure controls and procedures provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the disclosure controls and procedures or internal controls over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

Internal Controls over Financial Reporting. Under the supervision and with participation of Raymond Chan, the Chief Executive Officer, and Derek Aylesworth, the Chief Financial Officer of Baytex Energy Ltd., we conducted an evaluation of the design and effectiveness of our internal control over financial reporting as of December 31, 2007 based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that as of December 31, 2007, Baytex did maintain effective internal control over financial reporting.

There were no changes in our internal control over financial reporting during the six months ended June 30, 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Conference Call

Baytex will host a conference call and question and answer session at 2:00 p.m. MT (4:00 p.m. ET) on Tuesday, August 12, 2008 to discuss our 2008 second quarter results. The conference call will be hosted by Raymond Chan, Chief Executive Officer, Anthony Marino, President and Chief Operating Officer, and Derek Aylesworth, Chief Financial Officer. Interested parties are invited to participate by calling toll-free across North America at 1-800-920-5526. An archived recording of the call will be available from August 12, 2008 until August 26, 2008 by dialing 1-800-558-5253 or 1-416-626-4100 within the Toronto area, and entering the access code 21388899. The conference call will also be archived on Baytex's website at www.baytex.ab.ca.

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex's unitholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to: our ability to realize the anticipated benefits from our acquisition of Burmis Energy Inc.; our debt to cash flow ratio; our drilling activities; our cyclic steam pilot project at our Seal heavy oil resource play; our exploration and development capital program for 2008; our production levels for the second half of 2008; heavy oil prices; our liquidity and financial capacity; funding sources for our cash distributions and capital program; our distribution policy; operating expenses for the second half of 2008; and the impact of the adoption of new accounting standards on our financial results.

These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the availability and cost of labour and other industry services; the amount of future cash distributions that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. The reader is cautioned such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; fluctuations in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; fluctuations in foreign exchange or interest rates; stock market volatility and market valuations; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; changes in income tax laws, royalty rates and incentive programs relating to the oil and gas industry and income trusts; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in Baytex's Annual Information Form, Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2007, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

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 and on the New York Stock Exchange under the symbol BTE.

Financial statements for the three months and six months ended June 30, 2008 and 2007 are attached.



Baytex Energy Trust
Consolidated Balance Sheets
(thousands) (Unaudited)

June 30, December 31,
2008 2007
--------------- -------------
Assets
Current assets
Accounts receivable $ 131,823 $ 105,176
Crude oil inventory 1,169 5,997
Future income taxes 28,156 11,525
--------------- -------------
161,148 122,698

Petroleum and natural gas properties 1,501,146 1,246,697
Goodwill 37,755 37,755
--------------- -------------
$ 1,700,049 $ 1,407,150
--------------- -------------
--------------- -------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 151,464 $ 104,318
Distributions payable to unitholders 23,647 15,217
Bank loan 180,000 241,748
Financial derivative contracts (note 14) 81,709 34,239
--------------- -------------
436,820 395,522

Financial derivative contracts (note 14) 8,134 -
Long-term debt (note 4) 179,900 173,854
Convertible debentures (note 5) 11,654 16,150
Asset retirement obligations (note 6) 48,228 45,113
Deferred obligations 92 113
Future income taxes 206,313 153,943
--------------- -------------
891,141 784,695

Non-controlling interest (note 8) 12,454 21,235

Unitholders' Equity
Unitholders' capital (note 7) 1,052,897 821,624
Conversion feature of debentures (note 5) 572 796
Contributed surplus (note 9) 18,575 18,527
Deficit (275,590) (239,727)
--------------- -------------
796,454 601,220
--------------- -------------
$ 1,700,049 $ 1,407,150
--------------- -------------
--------------- -------------

See accompanying notes to the consolidated financial statements.


Baytex Energy Trust
Consolidated Statement of Income and Comprehensive Income
(thousands, except per unit data)
(Unaudited)

Three Months Ended Six Months Ended
June 30 June 30
-------------------- -------------------
2008 2007 2008 2007
-------- -------- -------- --------
Revenue
Petroleum and natural gas
sales $ 331,851 $ 156,133 $ 595,808 $ 317,322
Royalties (58,012) (21,277) (102,999) (41,601)
Loss on financial derivatives
(note 14) (73,460) (3,914) (91,179) (4,035)
-------- -------- -------- --------
200,379 130,942 401,630 271,686
-------- -------- -------- --------

Expenses
Operating 40,973 30,188 78,717 58,171
Transportation and blending 64,356 36,596 114,935 74,898
General and administrative 7,746 5,543 14,897 11,131
Unit based compensation (note
9) 2,129 1,946 4,211 3,806
Interest (note 12) 8,155 8,864 16,875 16,926
Foreign exchange loss (gain)
(note 13) (1,645) (16,661) 5,873 (18,576)
Depletion, depreciation and
accretion 50,941 42,541 101,399 83,901
-------- -------- -------- --------
172,655 109,017 336,907 230,257
-------- -------- -------- --------
Income before taxes and
non-controlling
interest 27,724 21,925 64,723 41,429
-------- -------- -------- --------

Taxes (recovery) (note 11)
Current 2,755 1,201 5,269 2,670
Future (10,318) (11,307) (12,796) (17,815)
-------- -------- -------- --------
(7,563) (10,106) (7,527) (15,145)
-------- -------- -------- --------

Income before non-controlling
interest 35,287 32,031 72,250 56,574
Non-controlling interest
(note 8) (870) (981) (1,985) (1,741)
-------- -------- -------- --------
Net income/Comprehensive
income $ 34,417 $ 31,050 $ 70,265 $ 54,833
-------- -------- -------- --------
-------- -------- -------- --------


Baytex Energy Trust
Consolidated Statement of
Deficit
(thousands, except per unit
data)
(Unaudited)
Three Months Ended Six Months Ended
June 30 June 30
--------------------- -------------------
2008 2007 2008 2007
-------- --------- -------- --------
Deficit, beginning of period $(251,736) $(219,528) $(239,727) $(202,471)
Net income 34,417 31,050 70,265 54,833
Distributions to unitholders (58,271) (42,438) (106,128) (83,278)
-------- -------- -------- --------
Deficit, end of period $(275,590) (230,916) $(275,590) (230,916)
-------- -------- -------- --------
-------- -------- -------- --------
Net income per trust unit
(note 10)
Basic $ 0.39 $ 0.41 $ 0.81 $ 0.72
Diluted $ 0.38 $ 0.39 $ 0.78 $ 0.70
Weighted average trust units
(note 10)
Basic 88,472 76,553 86,863 76,025
Diluted 94,511 82,196 92,682 81,850

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
--------------------- -------------------
2008 2007 2008 2007
-------- -------- -------- --------
Cash provided by (used in):

OPERATING ACTIVITIES
Net income $ 34,417 $ 31,050 $ 70,265 $ 54,833
Items not affecting cash:
Unit based compensation (note 9) 2,129 1,946 4,211 3,806
Unrealized foreign exchange
loss (gain) (note 13) (1,636) (16,495) 5,374 (18,785)
Depletion, depreciation and
accretion 50,941 42,541 101,399 83,901
Accretion on debentures and
long term debt (note 4 & note 5) 359 34 723 70
Unrealized loss on financial
derivatives (note 14) 48,433 4,005 55,604 4,655
Future income tax recovery (10,318) (11,307) (12,796) (17,815)
Non-controlling interest (note 8) 870 981 1,985 1,741
-------- -------- -------- --------
125,195 52,755 226,765 112,406
Change in non-cash working
capital (24,141) 956 (4,362) 2,303
Asset retirement expenditures 27 (257) (367) (960)
Decrease in deferred
obligations (11) (576) (21) (1,152)
-------- -------- -------- --------
101,070 52,878 222,015 112,597
-------- -------- -------- --------

FINANCING ACTIVITIES
Increase (decrease) in bank loan (18,046) 116,590 (61,748) 130,482
Payments of distributions (41,404) (34,410) (78,684) (68,235)
Issue of trust units, net of
issuance costs (note 7) 4,705 142,992 8,496 145,299
-------- -------- -------- --------
(54,745) 225,172 (131,936) 207,546
-------- -------- -------- --------

INVESTING ACTIVITIES
Petroleum and natural gas
property expenditures (42,527) (25,628) (93,530) (70,837)
Acquisition (net of disposal)
of petroleum and natural
gas properties (1,176) (253,077) (1,757) (252,840)
Change in non-cash working
capital (2,622) 655 5,208 3,534
-------- -------- -------- --------
(46,325) (278,050) (90,079) (320,143)
-------- -------- -------- --------
Change in cash and cash
equivalents - - - -
Cash and cash equivalents,
beginning of period - - - -
-------- -------- -------- --------
Cash and cash equivalents, end
of period $ - $ - $ - $ -
-------- -------- -------- --------
-------- -------- -------- --------

See accompanying notes to the consolidated financial statements.

Baytex Energy Trust
Notes to the Consolidated Financial Statements
Three Months and Six Months Ended June 30, 2008 and 2007
(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 and Baytex Energy Ltd. (the "Company"). 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.

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.

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, 2007, except as noted below. 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, 2007.

2. Changes in Accounting Policies

Effective January 1, 2008, the Trust adopted the Canadian Institute of Chartered Accountants ("CICA") accounting standards Section 3862 "Financial Instruments - Disclosures", Section 3863 'Financial Instruments - Presentation" and Section 1535 "Capital Disclosures". The adoption of the new standards resulted in additional disclosures with regard to financial instruments (note 14) and the Trust's objectives, policies and process for managing capital (note 15).

The Trust also adopted Section 3031 "Inventories". This new standard replaces the previous inventories standard and requires inventory to be valued on a first-in, first-out or weighted average basis. The adoption of Section 3031 did not have an impact on the consolidated financial statements of the Trust.

Future Accounting Changes

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards ("IFRS"). In March 2007, the AcSB released an "Implementation Plan for Incorporating IFRS into Canadian GAAP", which assumes a convergence date of January 1, 2011. Following a progress review on February 13, 2008, the AcSB has confirmed this changeover date. The Trust continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.

In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", which replaces Sections 3062 "Goodwill and Other Intangible Assets" and 3450 "Research and Development Costs". This section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets by profit-oriented enterprises subsequent to their initial measurement. The new standard will be effective on January 1, 2009. The Trust does not expect the adoption of this new Section to have a material impact on its consolidated financial statements.

3. Corporate Acquisitions

On June 4, 2008, Baytex acquired all the issued and outstanding shares of Burmis Energy Inc., a public company which had interests in certain natural gas and light oil properties located primarily in west central Alberta. The results of operations from these properties have been included in the consolidated financial statements since the closing of the acquisition on June 4, 2008. In conjunction with the acquisition, Burmis Energy Inc. was amalgamated with the Company.

This transaction has been accounted for using the purchase method of accounting. The estimated fair value of the assets acquired and liabilities assumed at the date of acquisition is summarized below:



Consideration for the acquisition:
Trust units issued $ 152,053
Net debt assumed 24,480
Costs associated with acquisition 1,818
-----------
Total purchase price $ 178,351
-----------
-----------

Allocation of purchase price:
Property, plant and equipment $ 217,087
Future income taxes (37,200)
Asset retirement obligations (1,536)
-----------
Total net assets acquired $ 178,351
-----------
-----------


All of the issued and outstanding shares of Burmis were acquired on the basis of 0.1525 Baytex trust unit for each Burmis share, resulting in the issuance of 6,383,416 Baytex trust units valued at $23.82 per unit, which was the average closing price of Baytex trust units for the ten days bordering the initial public announcement of the transaction. Amendments may be made to the purchase equation as the cost estimates and balance are finalized.

On June 26, 2007, Baytex acquired all the issued and outstanding shares of a private company which had interests in certain petroleum and natural gas properties and related assets located primarily in the Pembina and Lindbergh areas of Alberta. The results of operations from these properties have been included in the consolidated financial statements since the closing of the acquisition on June 26, 2007. Subsequent to the acquisition, the private company was amalgamated with the Company.

This transaction has been accounted for using the purchase method of accounting. The fair value of the assets acquired and liabilities assumed at the date of acquisition is summarized below:



Consideration for the acquisition:
Cash paid for property, plant and equipment $ 241,092
Costs associated with acquisition 2,181
Cash paid for working capital 13,229
-----------
Total purchase price $ 256,502
-----------
-----------

Allocation of purchase price:
Working capital $ 13,229
Property, plant and equipment 320,036
Future income taxes (74,524)
Asset retirement obligations (2,239)
-----------
Total net assets acquired $ 256,502
-----------
-----------


Amendments may be made to the purchase equation as the cost estimates and
balance are finalized.


4. Long-term Debt

June 30, December 31,
2008 2007
------------- -------------
10.5% senior subordinated notes (US$247) $ 252 $ 244
9.625% senior subordinated notes (US$179,699) 183,041 177,561
------------- -------------
183,293 177,805
Discontinued fair value hedge (3,393) (3,951)
------------- -------------
$ 179,900 $ 173,854
------------- -------------
------------- -------------


The Company has US$247,000 senior subordinated notes bearing interest at 10.5% payable semi-annually with principal repayable on February 15, 2011. These notes are unsecured and are subordinate to the Company's bank credit facilities.

The Company also has US$179.7 million senior subordinated notes bearing interest at 9.625% payable semi-annually with principal repayable on July 15, 2010. These notes are unsecured and are subordinate to the Company's bank credit facilities. After July 15 in each of the following years, these notes are redeemable at the Company's option, in whole or in part with not less than 30 nor more than 60 days' notice at the following redemption prices (expressed as percentage of the principal amount of the notes): 2007 at 104.813%, 2008 at 102.406%, 2009 and thereafter at 100%. These notes are carried at amortized cost net of a discontinued fair value hedge of $6.0 million recorded on adoption of Section 3865. The notes will accrete up to the principal balance at maturity using the effective interest method. Accretion expense of $0.7 million had been recorded for the six months ended June 30, 2008. The effective interest rate is 10.6%. The Company had an interest rate swap contract converting the fixed rate to a floating rate reset quarterly at the three month LIBOR rate plus 5.2% until the maturity of these notes. In November 2007, the Company terminated the interest rate swap contract. A gain on termination of $2.0 million was recorded as a reduction to interest expense in 2007.

5. Convertible Unsecured Subordinated Debentures

In June 2005, the Trust issued $100 million principal amount of 6.5% 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. The debt portion will accrete up to the principal balance at maturity, using the effective interest rate of 7.57%. The accretion and the interest paid are expensed as interest expense in the consolidated statement of income and comprehensive income. 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.



Number of Amount of Conversion Feature
Debentures Debentures of Debentures
------------ ------------- -------------------
Balance, December 31, 2006 19,619 $ 18,906 $ 940
Conversion (2,999) (2,895) (144)
Accretion - 139 -
------------ ------------- -------------------
Balance, December 31, 2007 16,620 16,150 796
Conversion (4,680) (4,547) (224)
Accretion - 51 -
------------ ------------- -------------------
Balance, June 30, 2008 11,940 $ 11,654 $ 572
------------ ------------- -------------------
------------ ------------- -------------------


6. Asset Retirement Obligations

Six Months
Ended Year Ended
June 30, December 31,
2008 2007
------------- -------------
Balance, beginning of period $ 45,113 $ 39,855
Liabilities incurred 549 2,180
Liabilities settled (367) (2,442)
Acquisition of liabilities 1,536 2,239
Disposition of liabilities (125) (585)
Accretion 1,820 3,404
Change in estimate(1) (298) 462
------------- -------------
Balance, end of period $ 48,228 $ 45,113
------------- -------------
------------- -------------

(1) Change in status of wells and change in the estimated costs of
abandonment and reclamations are factors resulting in a change in
estimate.


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. These costs are expected to be incurred over the next 52 years. The undiscounted amount of estimated cash flow required to settle the retirement obligations at June 30, 2008 was $276 million. Estimated cash flow has been discounted at a credit-adjusted risk free rate of 8.0% and an estimated annual inflation rate of 2.0%.



7. Unitholders' Capital

Trust Units

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

Number of Units Amount
----------------- -------------
Balance, December 31, 2006 75,122 $ 637,156
Issued from treasury for cash 7,000 142,135
Issued on conversion of debentures 203 3,037
Issued on conversion of exchangeable shares 12 230
Issued on exercise of trust unit rights 739 5,482
Transfer from contributed surplus on
exercise of trust unit rights - 2,816

Issued pursuant to distribution reinvestment
plan 1,464 27,763
Cumulative effect of change in accounting
policy - 3,005
----------------- -------------
Balance, December 31, 2007 84,540 821,624
Issued on conversion of debentures 318 4,771
Issued on conversion of exchangeable shares 1,337 42,776
Issued on exercise of trust unit rights 1,138 8,646
Transfer from contributed surplus on
exercise of trust unit rights - 4,163
Issued on acquisition of Burmis Energy Inc.
net of issuance costs 6,383 151,903
Issued pursuant to distribution reinvestment
plan 874 19,014
----------------- -------------
Balance, June 30, 2008 94,590 $ 1,052,897
----------------- -------------
----------------- -------------


8. 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 adjusted monthly to account for distributions paid on the trust units by dividing the cash distribution paid by the weighted average trust unit price for the five day trading period ending on the record date. The exchange ratio at June 30, 2008 was 1.76792 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 to the non-controlling interest on the balance sheet.



Number of
Exchangeable Shares Amount
--------------------- -------------
Balance, December 31, 2006 1,573 $ 17,187
Exchanged for trust units (7) (83)
Non-controlling interest in net income - 4,131
--------------------- -------------
Balance, December 31, 2007 1,566 21,235
Exchanged for trust units (759) (10,766)
Non-controlling interest in net income - 1,985
--------------------- -------------
Balance, June 30, 2008 807 $ 12,454
--------------------- -------------
--------------------- -------------


On May 30, 2008, the Trust announced Baytex Energy Ltd. has elected to redeem all of its exchangeable shares outstanding on August 29, 2008. In connection with this redemption, Baytex ExchangeCo Ltd. has exercised its overriding "redemption call right" to purchase such exchangeable shares from holders of record. Each exchangeable share will be purchased for trust units of the Trust in accordance with the exchange ratio in effect at August 28, 2008.

9. Trust Unit Rights Incentive Plan

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 trust units will result in an increase in the number of trust units available for issuance under the Plan, and any exercises of 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 provides for the exercise price of the rights to be reduced in future periods by a portion of the future distributions, subject to certain performance criteria.

The Trust recorded compensation expense of $2.1 million for the three months ended June 30, 2008 ($1.9 million in 2007) and $4.2 million for the first six months in 2008 ($3.8 million in 2007) pursuant to rights granted under the Plan.

The Trust uses the binomial-lattice model to calculate the estimated fair value of $4.66 per right for rights issued during the six month period ended June 30, 2008 ($4.00 per right in 2007). The following assumptions were used to arrive at the estimate of fair values:



Six Months Six Months
Ended Ended
June 30, 2008 June 30, 2007
---------------------------------
Expected annual exercise price reduction $ 2.71 $ 2.16
Expected volatility 28% 28%
Risk-free interest rate 2.98% - 4.17% 3.77% - 4.05%
Expected life of right (years) Various (1) Various (1)

(1) The binomial-lattice model calculates the fair values based on an
optimal strategy, resulting in various expected life of unit rights.
The maximum term is limited to five years by the Plan.


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

Weighted Average
Number of Rights Exercise Price (1)
------------------ -------------------
Balance, December 31, 2006 6,313 $ 14.00
Granted 2,642 $ 19.85
Exercised (739) $ 7.42
Cancelled (554) $ 16.91
------------------ -------------------
Balance, December 31, 2007 7,662 $ 14.67
Granted 219 $ 24.39
Exercised (1,138) $ 7.60
Cancelled (141) $ 17.86
------------------ -------------------
Balance, June 30, 2008 6,602 $ 14.87
------------------ -------------------
------------------ -------------------

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


The following table summarizes information about the unit rights outstanding
at June 30, 2008:



Number Weighted Weighted Number Weighted
Outstanding Average Average Exercisable Average
Range of Exercise at June 30, Remaining Exercise at June 30, Exercise
Prices 2008 Term Price 2008 Price
------------------ ----------- ----------- ---------- ----------- ----------
(years)
$ 1.00 to $ 6.00 658 1.2 $ 4.31 658 $ 4.31
$ 6.01 to $ 11.00 1,344 2.2 $ 8.95 780 $ 8.88
$ 11.01 to $ 16.00 272 2.6 $ 12.13 121 $ 11.98
$ 16.01 to $ 21.00 4,139 3.8 $ 18.21 690 $ 18.33
$ 21.01 to $ 26.00 114 4.8 $ 22.67 - -
$ 26.01 to $ 33.31 75 4.9 $ 28.09 - -
------------------ ----------- ----------- ---------- ----------- ----------
$ 1.00 to $ 33.31 6,602 3.4 $ 14.87 2,249 $ 10.61
------------------ ----------- ----------- ---------- ----------- ----------
------------------ ----------- ----------- ---------- ----------- ----------

The following table summarizes the changes in contributed surplus:

Balance, December 31, 2006 $ 13,357
Compensation expense 7,986
Transfer from contributed surplus on exercise of trust unit
rights (1) (2,816)
----------

Balance, December 31, 2007 18,527
Compensation expense 4,211
Transfer from contributed surplus on exercise of trust unit
rights (1) (4,163)
----------

Balance, June 30, 2008 $ 18,575
----------
----------

(1) Upon exercise of rights, contributed surplus is reduced with a
corresponding increase in unitholders' capital.


10. Net Income Per Unit

The Trust applies the treasury stock method to assess the dilutive effect of outstanding trust unit rights on net income per unit. The weighted average exchangeable shares outstanding during the period, converted at the period-end exchange ratio, and the trust units issuable on conversion of convertible debentures, have also been included in the calculation of the diluted weighted average number of trust units outstanding:



Three Months Ended
------------------- June 30, 2008 June 30, 2007
------------------------- ---------------------------
Net Net
Income Income
Net Trust per Net Trust per
Income Units Unit Income Units Unit
---------- ------- ------- ------- ------- -------
Net income per
basic unit $ 34,417 88,472 $ 0.39 $ 31,050 76,553 $ 0.41
Dilutive effect of
trust unit rights - 3,033 - 2,022
Conversion of
convertible
debentures 173 961 206 1,132
Exchange of
exchangeable shares 871 2,045 980 2,489
---------- ------- ------- -------
Net income per diluted
unit $ 35,461 94,511 $ 0.38 $ 32,236 82,196 $ 0.39
---------- ------- ------- ------- ------- -------
---------- ------- ------- ------- ------- -------

Six Months Ended
------------------- June 30, 2008 June 30, 2007
------------------------- ---------------------------
Net Net
Income Income
Net Trust per Net Trust per
Income Units Unit Income Units Unit
---------- ------- ------- ------- ------- -------
Net income per
basic unit $ 70,265 86,863 $ 0.81 $ 54,833 76,025 $ 0.72
Dilutive effect of
trust unit rights - 2,671 - 2,081
Conversion of
convertible
debentures 379 1,033 423 1,253
Exchange of
exchangeable shares 1,985 2,115 1,741 2,491
---------- ------- ------- -------
Net income per diluted
unit $ 72,629 92,682 $ 0.78 $ 56,997 81,850 $ 0.70
---------- ------- ------- ------- ------- -------
---------- ------- ------- ------- ------- -------


The dilutive effect of trust unit rights for the six months ended June 30, 2008 did not include 0.2 million trust unit rights (2007 - 2.4 million) because the respective proceeds of exercise plus the amount of compensation expense attributed to future services not yet recognized exceeded the average market price of the trust units during the period.

11. Income Taxes (Recovery)

The provision for (recovery of) income taxes has been computed as follows:



Six Months Ended June 30
---------------------------
2008 2007
------------ ------------

Income before income taxes and non-controlling
interest $ 64,723 $ 41,429

Expected income taxes at the statutory rate of
30.75% (2007 - 34.02%) 19,905 14,094
Increase (decrease) in taxes resulting from:
Net income of the Trust (34,657) (29,981)
Non-taxable portion of foreign exchange loss
(gain) 809 (3,195)
Effect of change in tax rate (2,577) 1,116
Effect of change in opening tax pool balances 1,786 (1,017)
Unit based compensation 1,295 1,295
Other 643 (127)
------------ ------------
Recovery of taxes (12,796) (17,815)
Current taxes 5,269 2,670
------------ ------------
Total tax $ (7,527) $ (15,145)
------------ ------------
------------ ------------


On June 22, 2007, Bill C-52 Budget Implementation Act, which contains legislative provisions to tax publicly traded income trusts in Canada, received Royal Assent in the Canadian House of Commons. The new tax is not expected to apply to the Trust until 2011. As a result of the tax legislation becoming enacted, an additional future tax recovery of $0.5 million was recorded in 2007.

12. Interest Expense

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



Three Months Ended Six Months Ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
---------- --------- --------- ---------
Bank loan and miscellaneous
financing $ 3,192 $ 3,232 $ 6,935 $ 5,327
Convertible debentures 248 326 547 671
Long-term debt 4,715 5,306 9,393 10,928
---------- --------- --------- ---------
Total interest $ 8,155 $ 8,864 $16,875 $16,926
---------- --------- --------- ---------
---------- --------- --------- ---------


13. Supplemental Cash Flow Information

Three Months Ended Six Months Ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
---------- --------- --------- ---------

Interest paid $ 4,084 $ 2,211 $16,480 $15,749
Income taxes paid $ 1,929 $ 3,347 $ 2,369 $ 4,986


Three Months Ended Six Months Ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
---------- --------- --------- ---------
Unrealized foreign exchange gain
(loss) $ 1,636 $16,495 $(5,374) $18,785
Realized foreign exchange gain
(loss) 9 166 (499) (209)
---------- --------- --------- ---------
Total foreign exchange gain (loss) $ 1,645 $16,661 $(5,873) $18,576
---------- --------- --------- ---------
---------- --------- --------- ---------


14. Financial Instruments and Risk Management

The Trust's financial assets and liabilities are comprised of cash, accounts receivable, accounts payable and accrued liabilities, distributions payable to unitholders, bank loan, financial derivative contracts, long-term debt, convertible debentures and deferred obligations.

Categories of Financial Instruments

Under Canadian generally accepted accounting principles, financial instruments are classified into one of the following 5 categories: held-for-trading, held to maturity, loans and receivables, available-for-sale and other financial liabilities. The carrying value and fair value of the Trust's financial instruments on the consolidated balance sheet are classified into the following categories:



June 30, 2008 December 31, 2007
--------------------- ---------------------
Carrying Fair Carrying Fair
Value Value Value Value
---------- ---------- ---------- ----------
Financial Assets
Loans and receivables
Accounts receivable $ 131,823 $ 131,823 $ 105,176 $ 105,176
---------- ---------- ---------- ----------
Total loans and receivables $ 131,823 $ 131,823 $ 105,176 $ 105,176
---------- ---------- ---------- ----------

Financial Liabilities
Held for trading
Derivatives designated as held
for trading $ (89,843) $ (89,843) $ (34,239) $ (34,239)
---------- ---------- ---------- ----------
Total held for trading $ (89,843) $ (89,843) $ (34,239) $ (34,239)
---------- ---------- ---------- ----------

Other financial liabilities
Accounts payable and accrued
liabilities $(151,464) $(151,464) $(104,318) $(104,318)
Distributions payable to
unitholders (23,647) (23,647) (15,217) (15,217)
Bank loan (180,000) (180,000) (241,748) (241,748)
Long term debt (179,900) (188,327) (173,854) (182,132)
Convertible debentures (11,654) (14,190) (16,150) (19,481)
Deferred obligations (92) (92) (113) (113)
---------- ---------- ---------- ----------
Total other financial
liabilities $(546,757) $(557,720) $(551,400) $(563,009)
---------- ---------- ---------- ----------


The estimated fair values of the financial instruments have been determined based on the Trust's assessment of available market information. These estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. The fair values of financial instruments, other than bank loan, and long-term borrowings approximate their book amounts due to the short-term maturity of these instruments. The fair value of the bank loan approximates its book value as it is at a market rate of interest. The fair value of the long term debt is based on the trading value of the instrument. The fair value of the convertible debentures has been calculated as the present value of future cash flows associated with the debentures.

Financial Risk

The Trust is exposed to a variety of financial risk, including market risk, credit risk and liquidity risk. The Trust monitors and, when appropriate, utilizes derivative contracts to manage its exposure to these risks. The Trust does not enter into derivative contracts for speculative purposes.

Market Risk

Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market prices. Market risk is comprised of foreign currency risk, interest rate risk and commodity price risk.

Foreign currency risk

The Trust is exposed to fluctuations in foreign currency as a result of its U.S. dollar denominated notes, crude oil sales based on U.S. dollar indices and commodity contracts that are settled in U.S. dollars. The Trust's net income and cash flow will therefore be impacted by fluctuations in foreign exchange rates.

In order to manage these risks, the Trust may enter into agreements to fix the exchange rate of Canadian to U.S. dollar in order to lessen the impact of currency rate fluctuations.



At June 30, 2008, the Trust had in place the following currency swap:

Period Amount Swap Price
----------------------------------- --------------- ----------------
US$10 million
Swap July 1, 2008 to December 31, 2008 per month CAD/US$ 0.9935
----------------------------------- --------------- ----------------


The following table demonstrates the effect of exchange rate movement on net income before taxes and non-controlling interest due to changes in the fair value of its currency swap as well as gains and losses on the revaluation of U.S. dollar denominated monetary assets and liabilities at June 30, 2008.



$0.01 Increase/Decrease in
CAD/US$ Exchange Rate
----------------------------
Gain/loss on currency swap $ 15
Gain/loss on other monetary assets/liabilities 2,414
----------------------------
Impact on income before taxes and
non-controlling interest $ 2,429
----------------------------


The carrying amounts of the Trust's foreign currency denominated monetary assets and liabilities at the reporting date are as follows:



Assets Liabilities
------------------------ -------------------------
June 30, December 31, June 30, December 31,
2008 2007 2008 2007
------------ ----------- ------------ ------------
U.S. dollar denominated US$ 40,987 US$ 54,674 US$ 283,918 US$ 226,528
------------ ----------- ------------ ------------


Interest rate risk

The Trust's interest rate risk arises from its floating rate bank loan. As at June 30, 2008, $180 million of the Trust's total debt is subject to movements in floating interest rates. An increase or decrease of 1.0% in interest rates would impact cash flow for the six months ended June 30, 2008 by approximately $1.1 million.

Commodity Price Risk

The Trust monitors and, when appropriate, utilizes financial derivative agreements or fixed price physical delivery contracts to manage the risk associated with changes in commodity prices. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors of the Company. Under the Trust's risk management policy, financial instruments are not used for speculative purposes.

When assessing the potential impact of commodity price changes, a 10% increase in commodity prices could have resulted in an additional unrealized loss in the second quarter of 2008 of $90.5 million relating to the financial derivative instruments outstanding as at June 30, 2008, while a 10% decrease could have resulted in a $44.3 million reduction.



At June 30, 2008, the Trust has the following commodity derivative
contracts:

OIL Period Volume Price Index
------------- --------------- ------------- --------------------- -------
Price collar Calendar 2008 2,000 bbl/d US$ 60.00 - $ 80.25 WTI
Price collar Calendar 2008 2,000 bbl/d US$ 65.00 - $ 77.05 WTI
Price collar Calendar 2008 2,000 bbl/d US$ 65.00 - $ 80.10 WTI
Price collar Calendar 2009 2,000 bbl/d US$ 90.00 - $136.40 WTI
Price collar Calendar 2009 2,000 bbl/d US$110.00 - $172.70 WTI


Derivative contacts are marked to market at the end of each reporting
period, with the following reflected in the income statement:


Three Months Ended Six Months Ended
June 30 June 30
-------------------- --------------------
2008 2007 2008 2007
----------- -------- ---------- ---------
Realized gain (loss) on financial
derivatives $ (25,027) $ 91 $(35,575) $ 620
Unrealized gain (loss) on
financial derivatives (48,433) (4,005) (55,604) (4,655)
----------- -------- ---------- ---------
$ (73,460) $ (3,914) $(91,179) $ (4,035)
----------- -------- ---------- ---------


Liquidity risk

Liquidity risk is the risk that the Trust will encounter difficulty in meeting obligations associated with financial liabilities. The Trust manages its liquidity risk through cash and debt management. As at June 30, 2008, the Trust had available unused bank credit facilities in the amount of $263 million. The Trust believes it has sufficient funding capacity through its credit facilities to meet foreseeable borrowing requirements.



The timing of cash outflows relating to financial liabilities are outlined
in the table below:

Total 1 year 2-3 years 4-5 years Beyond 5 years
-------- ------- --------- --------- --------------
$ $ $ $ $
Accounts payable and
accrued liabilities 151,464 151,464 - - -
Distributions payable to
unitholders 23,647 23,647 - - -
Bank loan (1) 180,000 180,000 - - -
Derivative contracts 89,843 81,709 8,134 - -
Long term debt (2) 183,293 - 183,293 - -
Convertible debentures(2) 11,940 - 11,940 - -
Deferred obligations 92 44 48 - -

(1) The bank loan is a 364-day revolving loan with the ability to extend
the term. The Trust has no reason to believe that it will be unable to
extend the credit facility when it matures on June 3, 2009.
(2) Principal amount of instruments.


Credit risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in the Trust incurring a loss. Most of the Trust's accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Trust manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. Credit risk may also arise from financial derivative instruments. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The carrying amount of accounts receivable are reduced through the use of an allowance for doubtful accounts and the amount of the loss is recognized in net income.

As at June 30, 2008, the Trust has no material amount of accounts receivable that are past due and no material allowance for doubtful accounts.

15. COMMITMENTS AND CONTINGENCIES

At June 30, 2008, the Trust had the following crude oil supply contracts:



HEAVY OIL Period Volume Price
------------- --------------- -------------- -------------------------------

Price Swap
- WCS Blend Calendar 2008 13,340 bbl/d WTI x 67.1% (weighted average)
Price Swap
- LLB Blend Calendar 2008 2,000 bbl/d WTI less US$24.55
Price Swap
- WCS Blend Calendar 2009 10,340 bbl/d WTI x 67.0% (weighted average)


At June 30, 2008, the Trust had the following natural gas physical sales
contracts:

GAS Period Volume Price/GJ
------------- -------------------- ------------ -------------------------

Price collar Calendar 2008 5,000 GJ/d $6.15 - $7.00
Price collar Calendar 2008 5,000 GJ/d $6.15 - $7.46
Price collar April 1, 2008 to
October 31, 2008 5,000 GJ/d $6.15 - $7.50
Price collar April 1, 2008 to
October 31, 2008 2,500 GJ/d $6.15 - $9.35
Price Swap June 4, 2008 to
December 31, 2008 7,000 GJ/d $7.67 (weighted average)


At June 30, 2008, the Trust had operating lease and transportation
obligations as summarized below:

Payments Due Within
---------------------------------------------------------
Total 1 year 2 years 3 years 4 years 5 years
--------- -------- ---------- --------- --------- ---------
Operating leases $ 6,668 $ 2,862 $ 2,411 $ 529 $ 518 $ 348
Processing and
transportation
agreements 19,449 6,270 5,563 5,062 2,492 62
--------- -------- ---------- --------- --------- ---------
Total $26,117 $ 9,132 $ 7,974 $ 5,591 $ 3,010 $ 410
--------- -------- ---------- --------- --------- ---------
--------- -------- ---------- --------- --------- ---------


OTHER

At June 30, 2008, there were outstanding letters of credit aggregating $2.2 million (June 30, 2007 - $7.4 million) issued as security for performance under certain contracts.

The Company has future contractual processing obligations with respect to assets acquired. The fair value of $7.8 million of the original obligation is being drawn down over the life of the obligations, which continue until October 2008. The fair value of the remaining obligation at June 30, 2008 was $1.0 million, all of which has been included in current liabilities.

In connection with a purchase of properties in 2005, Baytex became liable for contingent consideration whereby an additional amount would be payable by Baytex if the price for crude oil exceeds a base price in each of the succeeding six years. An amount payable was not reasonably determinable at the time of the purchase, therefore such consideration should be recognized only when the contingency is resolved. As at June 30, 2008, additional payments totaling $1.7 million have been paid under the agreement and have been recorded as an adjustment to the original purchase price of the properties. It is currently not determinable if further payments will be required under this agreement, therefore no accrual has been made.

The Trust is engaged in litigation and claims arising in the normal course of operations, none of which could reasonably be expected to materially affect the Trust's financial position or reported results of operations.

16. CAPITAL STRUCTURE

The Trust's objectives when managing capital are to (i) maintain financial flexibility in its capital structure; (ii) optimize its cost of capital at an acceptable level of risk; and (iii) preserve its ability to access capital to sustain the future development of the business through maintenance of investor, creditor and market confidence.

The Trust considers its capital structure to include total monetary debt and unitholders' equity. Total monetary debt is a non-GAAP term which we define to be the sum of monetary working capital, which is current assets less current liabilities excluding non-cash items such as future income tax assets or liabilities and unrealized financial derivative gains or losses, the principal amount of long term debt and the balance sheet value of the convertible debentures.

The Trust's financial strategy is designed to maintain a flexible capital structure consistent with the objectives above and to respond to changes in economic conditions and the risk characteristics of its underlying assets. In order to maintain the capital structure, the Trust may adjust the amount of its distributions, adjust its level of capital spending, issue new units, issue new debt or sell assets to reduce debt.

The Trust monitors capital based on current and projected ratios of total monetary debt to cash flow, and the current and projected level of its undrawn bank credit facilities. The Trust's objectives are to maintain a total monetary debt to cash flow from operations ratio of less than two times and to have access to undrawn bank credit facilities of not less than $100 million. The total monetary debt to cash flow ratio may increase beyond two times, and the undrawn credit facilities may decrease to below $100 million at certain times due to a number of factors, including acquisitions, changes to commodity prices and changes in the credit market. To facilitate management of the total monetary debt to cash flow from operations ratio and the level of undrawn bank credit facilities, the Trust continuously monitors its cash flow from operations and evaluates its distribution policy and capital spending plans.

The Trust's financial objectives and strategy as described above have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. The Trust believes its financial metrics are within acceptable limits pursuant to its capital management objectives.

The Trust is subject to financial covenants relating to its bank loan, senior subordinated notes and convertible debentures. The Trust is in compliance with all financial covenants.

On June 22, 2007, new tax legislation modifying the taxation of specified investment flow-through entities, including income trusts such as the Trust, was enacted (the "New Tax Legislation"). The New Tax Legislation will apply a tax at the trust level on distributions of certain income from trusts. The New Tax Legislation permits "normal growth" for income trusts through the transitional period ending December 31, 2010. However, "undue expansion" could cause the transitional relief to be revisited, and the New Tax Legislation to be effective at a date earlier than January 1, 2011. On December 15, 2006, the Department of Finance released guidelines on normal growth for income trusts and other flow-through entities (the "Guidelines"). Under the Guidelines, trusts will be able to increase their equity capital each year during the transitional period by an amount equal to a safe harbour amount. The safe harbour amount is measured by reference to a trust's market capitalization as of the end of trading on October 31, 2006. The safe harbour amounts are 40% for the period from November 2006 to the end of 2007, and 20% per year for each of 2008, 2009 and 2010. For Baytex, the limits are approximately $730 million for 2006 / 2007 and $365 million for each of the subsequent three years. The safe harbour amounts are cumulative allowing amounts not used in one year to be carried forward to a future year. Two trusts can merge without being impacted by the growth limitations. Limits are not impacted by non-convertible debt-financed growth, but rather focus solely on the issuance of equity to facilitate growth. At June 30, 2008, the Trust had not exceeded its "normal growth" limits.



Contact Information

  • Baytex Energy Trust
    Ray Chan
    Chief Executive Officer
    (403) 267-0715
    or
    Baytex Energy Trust
    Anthony Marino
    President and Chief Operating Officer
    (403) 267-0708
    or
    Baytex Energy Trust
    Derek Aylesworth
    Chief Financial Officer
    (403) 538-3639
    or
    Baytex Energy Trust
    Erin Cripps
    Investor Relations Representative
    (403) 538-3681 or Toll Free: 1-800-524-5521
    Website: www.baytex.ab.ca