Exhibit 99.1

HIGHLIGHTS

• Produced an average of 39,762 boe/d in the quarter, an increase of 4% over Q1/08;

• Generated cash flow of $59.4 million ($0.60 per diluted unit) for the first quarter of 2009;

• Continued Seal development with the drilling of four cold producers in the first quarter, continuing our record of 100% success and demonstrating commercial productivity of our heavy oil resource at West Harmon Valley; and

• Subsequent to the end of the first quarter, completed a bought deal equity financing, issuing 7.9 million units for net proceeds of $109 million, and increased our credit facilities from $485 million to $515 million.

	Three Months Ended
	March 31, 2009			December 31, 2008		March 31, 2008
FINANCIAL ($ thousands, except per unit amounts)
Petroleum and natural gas sales		150,943			199,890		264,448
Cash flow from operations(1)		59,372			60,472		101,570
Per unit – basic		0.61			0.62		1.19
– diluted		0.60			0.61		1.12
Cash distributions		34,947			55,314		38,474
Per unit		0.42			0.68		0.56
Net income (loss)		(8,490	)		52,401		35,848
Per unit – basic		(0.09	)		0.54		0.42
– diluted		(0.09	)		0.53		0.41
Exploration and development		47,664			42,969		51,003
Acquisitions – net of dispositions		(16	)		8,174		581
Total capital expenditures		47,648			51,143		51,584
Long-term notes		226,768			220,362		184,967
Bank loan		272,421			208,482		198,045
Convertible debentures		10,219			10,195		15,041
Working capital deficiency		52,531			93,979		37,909
Total monetary debt(2)		561,939			533,018		435,962

Baytex Energy Trust First Quarter Report 2009

1

	Three Months Ended
	March 31, 2009		December 31, 2008		March 31, 2008
OPERATING
Daily production
Light oil & NGL (bbl/d)		7,120		7,803		7,330
Heavy oil (bbl/d)		23,432		24,635		22,484
Total oil (bbl/d)		30,552		32,438		29,814
Natural gas (MMcf/d)		55.3		57.6		50.1
Oil equivalent (boe/d @ 6:1)(3)		39,762		42,035		38,157
Average prices (before hedging)
WTI oil (US$/bbl)		42.98		58.35		97.90
Edmonton par oil ($/bbl)		50.29		63.94		97.50
BTE light oil & NGL ($/bbl)		43.05		55.31		84.91
BTE heavy oil ($/bbl)(4)		33.97		38.93		59.88
BTE total oil ($/bbl)		36.11		42.83		65.84
BTE natural gas ($/Mcf)		5.39		7.05		7.42
BTE oil equivalent ($/boe)		35.23		42.71		61.30
TRUST UNIT INFORMATION
TSX (C$)
Unit price
High	$	17.49	$	27.05	$	23.40
Low	$	9.77	$	12.81	$	16.30
Close	$	15.10	$	14.65	$	22.78
Volume traded (thousands)		38,989		31,267		25,748
NYSE (US$)
Unit price
High	$	14.85	$	25.49	$	23.34
Low	$	7.84	$	10.16	$	15.88
Close	$	12.07	$	11.95	$	22.16
Volume traded (thousands)		12,545		14,498		4,786
Units outstanding (thousands)(5)		98,479		97,685		88,474

(1) Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other operating items. The Trust’s cash flow from operations may not be comparable to other 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. For a reconciliation of cash flow from operations to cash flow from operating activities, see Management’s Discussion and Analysis of the operating and financial results of the Trust for the three months ended March 31, 2009.

(2) 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.

(3) 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. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

(5) Number of trust units outstanding at March 31, 2008 includes the conversion of exchangeable shares at the exchange ratio in effect at the end of such reporting period.

Forward-Looking Statements

This report contains forward-looking information and statements relating to: our production levels for 2009; our exploration and development capital program for 2009; the amount of deferred acquisition payments for the North Dakota acquisition to be paid in 2009; our heavy oil resource play at Seal, including the economics of drilling heavy oil wells and the resource potential of our undeveloped land; oil and gas prices and differentials between light, medium and heavy oil prices; our light oil resource play in North Dakota, including the use of seismic data to enhance the identification of drilling prospects and the timing of the resumption of drilling on this project; the demand for and supply of crude oil; and our ability to fund cash distributions and our capital program from internally-generated cash flow. We refer you to the end of the Management’s Discussion and Analysis section of this report for our advisory on forward- looking information and statements.

Baytex Energy Trust First Quarter Report 2009

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MESSAGE TO UNITHOLDERS

Operations Review

Capital expenditures for exploration and development activities totaled $47.7 million for the first quarter of 2009. During this quarter, Baytex participated in drilling 29 (27.8 net) wells, resulting in 19 (19.0 net) oil wells, four (2.8 net) gas wells, two (2.0 net) stratigraphic test wells and four (4.0 net) dry and abandoned wells, for an 86% success rate. First quarter drilling included 11 (11.0 net) oil wells and three (3.0 net) dry holes in the Lloydminster area, four (4.0 net) horizontal production wells and two (2.0 net) stratigraphic test wells at Seal, one (1.0 net) oil well and three (1.8 net) gas wells in the Pembina/Ferrier area, two (2.0 net) oil wells in the Stoddart area, and one (1.0 net) oil well, one (1.0 net) gas well and one (1.0 net) dry hole in east-central Alberta.

Production averaged 39,762 boe/d during the first quarter of 2009, as compared to 42,035 boe/d for the fourth quarter of 2008. Production was consistent with our guidance of approximately 40,000 boe/d for 2009 under the reduced capital program announced in February 2009. Production is expected to be roughly flat at this level for each quarter of 2009. Capital spending guidance also remains unchanged at $150 million for exploration and development activities and $10 million for deferred acquisition payments for our North Dakota assets.

Although in-line with guidance, heavy oil production was modestly curtailed by our decision early in the first quarter to defer well servicing on a small number of higher-cost wells until oil pricing improves. In addition, a portion of our originally-planned Seal drilling program was deferred until after breakup based on our expectation of higher oil prices. Although drilling of Seal wells is economic at first quarter oil prices, we deferred some of the drilling based on the expectation of increasing net present value by selling oil from the high production rate early-time period at higher prices later in the year. In the reduced first quarter Seal program, we drilled three horizontal producing wells in our Harmon Valley development area, which commenced production at an average initial rate of 275 bbl/d per well. In addition, we drilled the first producing well in our West Harmon Valley area, which commenced production at an initial rate of 180 bbl/d, demonstrating commercial productivity of our heavy oil resource using cold methods in a new area approximately six miles from our existing development area.

Light oil and gas production was also in-line with guidance for the first quarter, but should be modestly positively affected by commencing production from several Alberta wells in April 2009. In the first quarter, we completed construction of an eight kilometre gas pipeline in the Ferrier/O’Chiese area which reduced production constraints and improved operating netbacks. In North Dakota, we completed a 260 square mile 3D seismic survey over our Bakken-Three Forks project area. The survey is expected to assist in the high-grading of future Bakken-Three Forks locations and also may lead to identification of conventional drilling prospects in other formations. We plan to resume drilling in the third quarter of 2009.

Financial Review

Cash flow from operations for the first quarter was $59.4 million, a decrease of 2% compared to $60.5 million for the fourth quarter of 2008. The largest contributor to the decline was decreased commodity prices in the first quarter of 2009. Baytex received an average oil price of $36.11 per barrel before hedging in the first quarter, a decrease of 16% compared to $42.83 per barrel before hedging in the fourth quarter of 2008. Natural gas prices also decreased in the first quarter, with Baytex receiving an average wellhead price of $5.39 per Mcf, 24% lower than the previous quarter. The decline in commodity prices was partially offset by a $25.1 million realized gain on financial instruments in the first quarter of 2009. This gain is primarily related to a series of costless WTI collars with an average floor price of US$100 per barrel, covering a total of 4,000 bbl/d for calendar 2009.

Net loss for the first quarter of 2009 computed in accordance with Generally Accepted Accounting Principles (“GAAP”) in Canada was $8.5 million compared to net income of $35.8 million for the first quarter in 2008. A key contributor to the loss was the timing of recognition of income related to our financial derivative instruments. The WTI collar contracts were entered into in 2008 to provide cash flow protection for 2009. Under Canadian GAAP, the unrealized mark-to-market net income benefit of those WTI collars was required to be recorded in 2008. In the first quarter of 2009, the realized benefit of those contracts is reflected in our cash flows, but not in our net income,

Baytex Energy Trust First Quarter Report 2009

3

because the net income impact had previously been recorded. If the benefit of these financial contracts were permitted to be recorded in the period to which the contracts relate, our pre-tax net income would have been higher in the first quarter by approximately $26 million.

Heavy oil pricing differential, as measured by market pricing for Lloyd Blend, averaged 22% of WTI for the first quarter of 2009, as compared to 34% in the fourth quarter of 2008. This decline in differential through the historically higher-differential winter months supports our view that there has been a structural change in heavy oil supply and demand, which bodes very well for the longer term outlook for heavy oil pricing. The differential for the second quarter of 2009 is currently being traded at approximately 15% of WTI, resulting in estimated wellhead pricing of $50 per barrel for Lloydminster-area raw heavy crude, based on current WTI prices, foreign exchange rates and condensate costs.

After the end of the first quarter, Baytex entered into a series of contracts concurrently to lock in the raw heavy oil price on a portion of our production for calendar 2010. By simultaneously entering into forward contracts for WTI, blend differential, condensate differential and foreign exchange, we established a raw Hardisty heavy oil price of $55.26 per barrel on 1,925 bbl/d for 2010. When compared to historic pricing, the only year in which Hardisty pricing exceeded this contracted price was 2008, and this price exceeded the next highest year by over 30%. We believe that the availability of this type of contract pricing provides support for our long-term positive outlook for heavy oil pricing.

Total cash distributions in the quarter of $34.9 million, or $0.42 per unit, represented a payout ratio of 59% net of distribution reinvestment plan (“DRIP”) participation (69% before DRIP). In order to conserve our financial liquidity, and to better match our distribution levels with the prevailing commodity price, we reduced our monthly distribution from $0.18 to $0.12 per unit in respect of February 2009 operations. At the current commodity price outlook, we expect to be able to fully fund this adjusted distribution level along with our capital expenditure program from our internally generated cash flow.

Total monetary debt, excluding notional mark-to-market assets at the end of the quarter, was $561.9 million which was an increase of $28.9 million from the end of 2008. At the end of the first quarter, Baytex had over $160 million in available undrawn credit lines.

Subsequent to the end of the first quarter, we completed a bought deal equity financing, issuing 7.9 million trust units for net proceeds of $109.3 million. In addition, through the regularly scheduled annual review, we reached agreement with our lending syndicate to increase our credit facilities from $485 million to $515 million. The equity issuance and increase in bank facilities have significantly strengthened our balance sheet and expanded our financial liquidity. We are appreciative of the confidence in Baytex shown by the equity market and our lenders in this challenging economic time, and believe that both represent a strong endorsement of our business model.

On behalf of the Board of Directors,

Anthony Marino

President and Chief Executive Officer

May 12, 2009

Baytex Energy Trust First Quarter Report 2009

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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 months ended March 31, 2009. This information is provided as of May 8, 2009. The first quarter results have been compared with the corresponding period in 2008. This MD&A should be read in conjunction with the Trust’s unaudited interim consolidated comparative financial statements for the three months ended March 31, 2009 and 2008 and our audited consolidated comparative financial statements for the years ended December 31, 2008 and 2007, together with accompanying notes, and Annual Information Form for the year ended December 31, 2008 (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 is not a measurement based on Generally Accepted Accounting Principles (“GAAP”) in Canada, but is a financial term 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. For a reconciliation of cash flow from operations to cash flow from operating activities, see “Cash Flow from Operations, Payout Ratio and Distributions”.

Economic Environment

The current economic environment outlook continues to be challenging with the global recession and tightening of available credit and volatility of commodity prices. Sustained improvement in commodity prices will depend on a combination of demand stabilization through economic recovery and natural declines around the world due to reduced capital investment and stability of the financial markets. In this economic environment Baytex is focused on key business objectives of preserving balance sheet strength and liquidity, maintaining the productive capacity of the Trust, and delivering a sustainable distribution to our unitholders. In the first quarter of 2009, we reduced our monthly distribution to $0.12 per unit per month and reduced our capital budget to $150 million. Both of these measures were undertaken to preserve our corporate liquidity. Our capital spending has been focused on those projects which will provide the greatest returns in the reduced commodity price environment. Subsequent to the end of the quarter, we issued 7.9 million trust units for net proceeds of $109 million, and increased the amount of our credit facilities to $515 million from $485 million previously. Both events serve to strengthen our balance sheet and, together with the actions we have taken to limit our cash outflows, will ensure that Baytex maintains sufficient financial strength to continue to prosper in this recessionary environment.

Production

Light oil and natural gas liquids (“NGL”) production for the first quarter of 2009 decreased by 3% to 7,120 bbl/d from 7,330 bbl/d in the first quarter of 2008. Heavy oil production for the first quarter of 2009 increased by 4% to

Baytex Energy Trust First Quarter Report 2009

5

23,432 bbl/d from 22,484 bbl/d a year ago due to development drilling over the past year in the Seal and Lloydminster areas. Natural gas production increased by 10% to 55.3 MMcf/d for the first quarter of 2009, as compared to 50.1 MMcf/d for the same period last year, primarily due to the acquisition of Burmis Energy Inc. in June 2008.

Revenue

Petroleum and natural gas sales decreased 43% to $150.9 million for the first quarter of 2009 from $264.4 million for the same period in 2008. For the per sales unit calculations, heavy oil sales for the three months ended March 31, 2009 were 420 bbl/d lower (three months ended March 31, 2008 – 956 bbl/d higher) than the production for the period due to changes in inventory.

Revenue from light oil and NGL for the first quarter of 2009 decreased 51% from the same period a year ago due to a 3% decrease in sales volume and a 49% decrease in wellhead prices. Revenue from heavy oil decreased 45% despite a 4% increase in sales volume, as wellhead prices decreased by 43%. Revenue from natural gas decreased 21% due to a 10% increase in sales volume offset by a 27% decrease in wellhead prices.

	Three Months Ended
	March 31, 2009				March 31, 2008
	$	000s	$/Unit(1)		$	000s	$/Unit(1)
Oil revenue
Light oil & NGL		27,583		43.05		56,636		84.91
Heavy oil(2)		70,349		33.97		127,718		59.88
Total oil revenue		97,932		36.11		184,354		65.84
Natural gas revenue		26,811		5.39		33,823		7.42
Total oil and gas revenue		124,743		35.23		218,177		61.30
Sulphur revenue		160				1,355
Processing income		617				–
Other income		–				2,000
Sales of heavy oil blending diluent		25,423				42,916
Total petroleum and natural gas sales		150,943				264,448

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

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

During the current quarter, sulphur production averaged 30.2 tonnes per day with an average price of $59 per tonne, as compared to 39.3 tonnes per day with an average price of $374 per tonne in the same period last year.

Financial Instruments

The loss on financial instruments for the first quarter was $2.9 million, as compared to a loss of $17.7 million in the first quarter of 2008. This is comprised of $25.2 million in realized gain and $28.1 million in unrealized loss for the first quarter of 2009 as compared to $10.6 million in realized loss and $7.1 million in unrealized loss in the first quarter of 2008.

Royalties

Total royalties decreased to $21.7 million for the first quarter of 2009 from $45.0 million in 2008. Royalties for the current quarter related to the production of sulphur were immaterial as compared to $0.4 million for the same period in 2008.

Total royalties for the first quarter of 2009 were 17.4% of petroleum and natural gas revenue (excluding sales of heavy oil diluent and processing income), as compared to 20.5% for the same period in 2008. For the first quarter of 2009, royalties at 23.5% of sales for light oil, NGL and natural gas remained constant from the first quarter of 2008. Royalties for heavy oil was 12.7% of sales (excluding sales of heavy oil diluent and processing income) for the first

Baytex Energy Trust First Quarter Report 2009

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quarter of 2009 as compared to 18.6% for the first quarter of 2008. Royalties are generally based on well productivity and market index prices in the period, with rates increasing as price and volume increase.

Operating Expenses

Operating expenses for the first quarter of 2009 increased to $39.2 million from $37.7 million in the corresponding quarter last year. Operating expenses for the current quarter include $0.1 million related to the production of sulphur, same as for the first quarter in 2008.

Operating expenses were $11.06 per boe for the first quarter of 2009 compared to $10.60 per boe for the first quarter of 2008. For the first quarter of 2009, operating expenses were $11.89 per boe of light oil, NGL and natural gas, and $10.44 per barrel of heavy oil, as compared to $10.42 and $10.69, respectively, for the first quarter of 2008. In the case of light oil, NGL and natural gas, the largest single driver of the increase in unit operating expense was third-party processing costs. In the case of heavy oil, the reduction in per barrel expense resulted from higher production levels while maintaining flat expense.

Transportation and Blending Expenses

Transportation and blending expenses for the first quarter of 2009 were $37.8 million compared to $51.1 million for the first quarter of 2008. Transportation expenses for the current quarter include $0.3 million related to the transportation of sulphur compared to $0.4 million for the same period in 2008.

Transportation expenses were $3.43 per boe for the first quarter of 2009 compared to $2.19 per boe for the same period of 2008. Transportation expenses were $0.60 per boe of light oil, NGL and natural gas and $5.44 per barrel of heavy oil in the first quarter of 2009 as compared to $0.72 and $3.17, respectively, for the same period of 2008. The increase in transportation cost per unit was driven by increased long-haul trucking from Seal.

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 its heavy oil. In the first quarter of 2009, the blending cost was $25.4 million for the purchase of 4,799 bbl/d of condensate at $58.86 per barrel, as compared to 4,447 bbl/d at $106.05 per barrel for the same period last year. The cost of diluent is effectively recovered in the sale price of a blended product.

General and Administrative Expenses

General and administrative expenses for the first quarter of 2009 increased to $8.7 million from $7.2 million a year earlier. On a per sales unit basis, these expenses were $2.47 per boe for the first quarter of 2009 compared to $2.01 per boe for the first quarter of 2008. The majority of the increase was due to lower overhead recoveries on capital expenditures, which are dependant on the expenditure components. The remaining causes for the increase are attributable to escalating costs in the labor market and additional expenses associated with insurance and rent. In accordance with our full cost accounting policy, no expenses were capitalized in the respective periods.

Unit-based Compensation Expense

Compensation expense related to Baytex’s trust unit rights incentive plan was $1.7 million for the first quarter of 2009 compared to $2.1 million for the first quarter of 2008.

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 Expense

Interest expense for the first quarter of 2009 decreased to $8.1 million compared to $8.7 million in the same quarter last year. The decrease is primarily due to the significant decrease in prime lending rates offset slightly by an increase in the amount of the bank loan and by the higher foreign exchange rate effect of the interest on the U.S. dollar long-term debt.

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7

Foreign Exchange

Foreign exchange loss in the first quarter of 2009 was $4.0 million compared to a loss of $7.5 million in the first quarter of 2008. The loss is comprised of an unrealized foreign exchange loss of $4.6 million and a realized foreign exchange gain of $0.6 million. The loss for the same period in 2008 was comprised of an unrealized foreign exchange loss of $7.0 million and a realized foreign exchange loss of $0.5 million. The current quarter’s unrealized loss is based on the translation of the U.S. dollar denominated long-term debt at 0.7935 at March 31, 2009 compared to 0.8166 at December 31, 2008. The prior period loss is based on translation at 0.9729 at March 31, 2008 compared to 1.0120 at December 31, 2007.

Depletion, Depreciation and Accretion

Depletion, depreciation and accretion for the first quarter of 2009 increased to $55.2 million from $50.5 million for the same quarter in 2008. On a sales-unit basis, the provision for the current quarter was $15.59 per boe compared to $14.18 per boe for the same quarter in 2008. The higher rate is primarily due to the acquisition of Burmis Energy Inc. completed in June 2008.

Taxes

Current tax of $2.2 million for the first quarter of 2009 is comprised primarily of Saskatchewan capital tax and resource surcharge. Current tax of the same period a year ago was $2.5 million and was also comprised primarily of Saskatchewan capital tax and resource surcharge.

For the first quarter of 2009, future tax recovery totaled $22.2 million compared to a recovery of $2.5 million in the same period in 2008. As at March 31, 2009, total future tax liability of $195.5 million (December 31, 2008 – $217.8 million) consisted of a $0.4 million future tax asset (December 31, 2008 – $nil), $18.2 million current future tax liability (December 31, 2008 – $25.4 million current future tax liability) and a $177.8 million long-term future tax liability (December 31, 2008 – $192.4 million). The decrease from the prior year is due to lower cash flows from operations and recognition of non-capital losses previously included in the valuation allowance.

Net Income (Loss)

Net loss for the first quarter of 2009 computed in accordance with Generally Accepted Accounting Principles (“GAAP”) in Canada was $8.5 million compared to net income of $35.8 million for the first quarter in 2008. A key contributor to the loss was the timing of recognition of income related to our financial derivative instruments. The WTI collar contracts were entered into in 2008 to provide cash flow protection for 2009. Under Canadian GAAP, the unrealized mark-to-market net income benefit of those WTI collars was required to be recorded in 2008. In the first quarter of 2009, the realized benefit of those contracts is reflected in our cash flows, but not in our net income, because the net income impact had previously been recorded. If the benefit of these financial contracts were permitted to be recorded in the period to which the contracts relate, our pre-tax net income would have been higher in the first quarter by approximately $26 million.

Cash Flow from Operations, Payout Ratio and Distributions

Cash flow from operations and payout ratio are non-GAAP terms. Cash flow from operations represents cash flow from operating activities before changes in non-cash working capital, and other operating items. The Trust’s payout ratio is calculated as cash distributions (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.

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

	Three Months Ended									Year Ended
($ thousands)	March 31, 2009			December 31, 2008			March 31, 2008			December 31, 2008			December 31, 2007
Cash flow from operating activities	$	36,056		$	98,407		$	120,945		$	471,237		$	286,450
Change in non-cash working capital		22,854			(38,667	)		(19,779	)		(38,896	)		(5,140	)
Asset retirement expenditures		451			725			394			1,443			2,442
Decrease in deferred obligations		11			7			10			39			2,278
Cash flow from operations	$	59,372		$	60,472		$	101,570		$	433,823		$	286,030
Cash distributions declared	$	34,947		$	55,314		$	38,474		$	197,026		$	145,927
Payout ratio		59	%		91	%		38	%		45	%		51	%

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 reserve 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 $34.9 million for the first quarter of 2009 were funded through cash flow from operations of $59.4 million.

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

	Three Months Ended									Year Ended
($ thousands)	March 31, 2009			December 31, 2008			March 31, 2008			December 31, 2008		December 31, 2007
Cash flow from operating activities		36,056			98,407			120,945			471,237		286,450
Cash distributions declared		34,947			55,314			38,474			197,026		145,927
Excess of cash flow from operating activities over cash distributions declared		1,109			43,093			82,471			274,211		140,523
Net income (loss)		(8,490	)		52,401			35,848			259,894		132,860
Cash distributions declared		34,947			55,314			38,474			197,026		145,927
Excess (shortfall) of earnings over cash distributions declared		(43,437	)		(2,913	)		(2,626	)		62,868		(13,067	)

It is Baytex’s long-term operating objective to substantially fund cash distributions and capital expenditures for exploration and development activities through cash flow from operations. 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 lower 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 may be funded through a combination of equity and debt financing. As at March 31, 2009, Baytex had approximately $160 million in available undrawn credit facilities to fund any 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 March 31, 2009, the Trust’s cash distributions exceeded earnings by $43.4 million. Included in the net loss of $8.5 million is $44.5 million of non-cash items such as depletion, depreciation and accretion which 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.

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Liquidity and Capital Resources

The current worldwide economic crisis has resulted in disruptions in the availability of credit. In light of this situation, we have undertaken a thorough review of our liquidity sources as well as our exposure to counterparties and have concluded that our capital resources are sufficient to meet our ongoing short, medium and long-term commitments. Specifically, we believe that our internally generated cash flow from operations, augmented by our hedging program and existing credit facilities, will provide sufficient liquidity to sustain our operations in the short, medium, and long-term. Further, we believe that our counterparties currently have the financial capacities to honor outstanding obligations to us in the normal course of business and, where necessary, we have implemented enhanced credit protection with certain of these counterparties.

At March 31, 2009, total net monetary debt was $561.9 million compared to $533.0 million at the end of 2008. Bank borrowings and working capital deficiency at March 31, 2009 were $325.0 million compared to total credit facilities of $485.0 million.

Baytex has a credit agreement with a syndicate of chartered banks. The credit facilities consist of an operating loan and a 364-day revolving loan. Advances under the credit facilities or letters of credit can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance rates plus applicable margins or LIBOR rates plus applicable margins. The syndicated credit facilities were increased from $370.0 million to $485.0 million in June 2008. The facilities are subject to semi-annual review and are secured by a floating charge over all of Baytex’s assets. The credit facilities mature on July 1, 2009 if they are not extended. Subsequent to the end of the first quarter, we have reached agreement with our lenders to increase the amount of the facilities from $485.0 million to $515.0 million effective July 1, 2009, and extend the maturity of the facilities to July 1, 2010.

Baytex’s credit facilities were arranged pursuant to an agreement with a syndicate of nine financial institutions. A copy our credit agreement and the first amendment is accessible on the SEDAR website at www.sedar.com (filed on March 28, 2008 and September 15, 2008).

Baytex has US$179.7 million of 9.625% senior subordinated notes due July 15, 2010 and US$0.2 million of 10.5% senior subordinated notes due February 15, 2011. These notes are unsecured and are subordinate to Baytex’s bank credit facilities.

Pursuant to various agreements with Baytex’s creditors, we are restricted from making distributions to unitholders if the distribution would or could have a material adverse effect on the Trust or its subsidiaries’ ability to fulfill its obligations under Baytex’s credit facilities or the senior subordinated notes.

The Trust believes that cash flow generated from operations, together with the existing bank facilities, will be sufficient to finance current operations, distributions to the unitholders and planned capital expenditures for the ensuing year. The timing of most of the capital expenditures is discretionary and there are no material long-term capital expenditure commitments. The level of distribution is also discretionary, and the Trust has the ability to modify distribution levels should cash flow from operations be negatively impacted by reduction in commodity prices.

The Trust has a number of financial obligations in the ordinary course of business. These obligations are of a recurring nature and impact the Trust’s cash flows in an ongoing manner. A significant portion of these obligations

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will be funded through operating cash flow. These obligations as of March 31, 2009, and the expected timing of funding of these obligations are noted in the table below.

($ thousands)	Total	1 year	2-3 years	4-5 years	Beyond 5 years
Accounts payable and accrued liabilities	140,994	140,994	–	–	–
Distributions payable to unitholders	11,817	11,817	–	–	–
Bank loan(1)	272,421	272,421	–	–	–
Long-term debt(2)	226,768	–	226,768	–	–
Convertible debentures(2)	10,398	–	10,398	–	–
Deferred obligations	63	46	14	3	–
Operating leases	41,817	2,886	7,462	7,740	23,729
Processing and transportation agreements	20,589	8,406	11,978	205	–
Total	724,867	436,570	256,620	7,948	23,729

(1) The bank loan is a 364-day revolving loan with the ability to extend the term. The Trust has reached agreement with our lending syndicate to extend the maturity of our facility to July 1, 2010.

(2) Principal amount of instruments.

The Trust is authorized to issue an unlimited number of trust units. As at May 8, 2009, the Trust had 106,561,868 trust units issued and outstanding.

At May 8, 2009, the Trust had $10.4 million convertible unsecured subordinated debentures outstanding which are convertible at the option of the holder at any time into fully paid trust units at a conversion price of $14.75 per unit.

Capital Expenditures

Capital expenditures for the three months ended March 31, 2009 and 2008 are summarized as follows:

	Three Months Ended
($ thousands)	March 31, 2009			March 31, 2008
Land		1,400			1,160
Seismic		316			301
Drilling and completion		36,360			41,751
Equipment		9,011			6,754
Other		577			1,037
Total exploration and development		47,664			51,003
Property acquisitions		–			641
Property dispositions		(16	)		(60	)
Total capital expenditures		47,648			51,584

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 its 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 credit risk by entering into sales contracts with creditworthy entities and reviewing its exposure to individual entities on a regular basis.

Details of the risk management contracts in place as at March 31, 2009, and the accounting for the Trust’s financial instruments are disclosed in note 13 to the consolidated financial statements.

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Selected Quarterly Financial Information

	2009			2008					2007
($ thousands, except per unit amounts)		Q1			Q4	Q3	Q2	Q1		Q4	Q3	Q2
Petroleum and natural gas sales		150,943			199,890	363,044	332,336	264,448		233,856	193,784	156,670
Net income (loss)		(8,490	)		52,401	137,228	34,417	35,848		41,353	36,674	31,050
Net income (loss) per unit – basic		(0.09	)		0.54	1.44	0.39	0.42		0.49	0.44	0.41
Net income (loss) per unit – diluted		(0.09	)		0.53	1.39	0.38	0.41		0.46	0.43	0.39

Changes in Accounting Policies

Effective January 1, 2009, the Trust adopted the Canadian Institute of Chartered Accountants (“CICA”) accounting standards Section 3064 “Goodwill and Intangible Assets”, which replaced Section 3062 “Goodwill and Other Intangible Assets” and Section 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 adoption of this new standard did not have a material impact on the consolidated financial statements of the Trust.

Effective January 1, 2009 the Trust adopted the CICA issued EIC-173 “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. The EIC provides guidance on how to take into account the credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. This did not have a material impact on the consolidated financial statements of the Trust.

The Trust’s foreign operations are considered to be “self-sustaining operations”, financially and operationally independent, as of January 1, 2009. As a result, the accounts of the self-sustaining foreign operations are translated using the current rate method whereby assets and liabilities are translated using the exchange rate in effect at the balance sheet date, while revenues and expenses are translated using the average exchange rate for the period. Translation gains and losses are deferred and included in other comprehensive income in unitholders’ equity.

Previously, foreign operations were considered to be integrated and were translated using the temporal method. Under the temporal method, monetary assets and liabilities were translated at the period end exchange rate while other assets and liabilities were translated at the historical rate. Revenues and expenses were translated at the average monthly rate except for depletion, depreciation and accretion, which were translated on the same basis as the assets to which they relate. Translation gains and losses were included in the determination of net income for the period.

This change was adopted prospectively on January 1, 2009 and resulted in a currency translation adjustment of $15.4 million with a corresponding increase in petroleum and natural gas properties.

Future Accounting Changes

In April 2008, the CICA published the exposure draft “Adopting IFRS in Canada”. The exposure draft proposes to incorporate International Financial Reporting Standards (“IFRS”) into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS. The Trust is currently reviewing the standards to determine the potential impact on its consolidated financial statements. The Trust has appointed internal staff to lead the conversion project along with sponsorship from the senior leadership team. In addition, an external advisor has been retained to assist the Trust in scoping its conversion project. The Trust has performed a diagnostic analysis that identifies differences between the Trust’s current accounting policies and IFRS. At this time, the Trust is evaluating the impact of these differences and assessing the need for amendments to existing accounting policies in order to comply with IFRS.

In January 2009, the CICA issued Section 1582 “Business Combinations” which establishes principles and requirements of the acquisition method for business combinations and related disclosures. The purchase price is to be based on trading data at the closing date of the acquisition, not the announcement date of the acquisition, and most acquisition costs are to be expensed as incurred. This standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning

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on or after January 1, 2011 with earlier application permitted. The Trust plans to adopt this standard prospectively effective January 1, 2011. The adoption of this standard may have an impact on the accounting of future business combinations.

In January 2009, the CICA issued Section 1601 which establishes standards for the preparation of consolidated financial statements and Section 1602 which provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The Trust plans to adopt this standard prospectively effective January 1, 2011. The adoption of this standard may have an impact on the accounting of future business combinations.

Disclosure Controls and Procedures

Anthony Marino, the President and 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. They have designed such disclosure controls and procedures, or caused them to be designed under their supervision, to provide reasonable assurance that all material or potentially material information about the activities of Baytex is made known to them by others within Baytex.

It should be noted that while the 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 Control over Financial Reporting

Under the supervision and with participation of the Disclosure Officers, we conducted an evaluation of the design and effectiveness of our internal control over financial reporting as of December 31, 2008 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, 2008, Baytex did maintain effective internal control over financial reporting.

There were no changes in our internal control over financial reporting during the three months ended March 31, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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: funding sources for our cash distributions and capital program; the sufficiency of our capital resources to meet our ongoing short, medium and long-term commitments; the financial capacity of counterparties to honor outstanding obligations to us in the normal course of business; the timing of funding our financial obligations; 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

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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 that 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, 2008, 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.

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CONSOLIDATED BALANCE SHEETS

(thousands of Canadian dollars) (unaudited)	March 31, 2009			December 31, 2008
ASSETS
Current assets
Cash	$	687		$	–
Accounts receivable		98,292			87,551
Crude oil inventory		1,301			332
Financial instruments (note 13)		61,522			85,678
		161,802			173,561
Future tax asset		420			–
Petroleum and natural gas properties		1,613,499			1,601,017
Goodwill		37,755			37,755
	$	1,813,476		$	1,812,333
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	140,994		$	164,279
Distributions payable to unitholders		11,817			17,583
Bank loan		272,421			208,482
Future tax liability		18,180			25,358
		443,412			415,702
Long-term debt (note 3)		224,004			217,273
Convertible debentures (note 4)		10,219			10,195
Asset retirement obligations (note 5)		50,270			49,351
Deferred obligations		63			74
Future tax liability		177,781			192,411
Financial instruments (note 13)		1,420			–
		907,169			885,006
UNITHOLDERS’ EQUITY
Unitholders’ capital (note 6)		1,138,974			1,129,909
Conversion feature of debentures (note 4)		498			498
Contributed surplus (note 8)		22,120			21,234
Accumulated other comprehensive income (note 2)		18,751			–
Deficit		(274,036	)		(224,314	)
		906,307			927,327
	$	1,813,476		$	1,812,333

Commitments and contingencies (note 14)

See accompanying notes to the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF INCOME AND

COMPREHENSIVE INCOME

	Three Months Ended March 31
(thousands of Canadian dollars) (unaudited)	2009			2008
Revenue
Petroleum and natural gas	$	150,943		$	264,448
Royalties		(21,728	)		(44,987	)
Loss on financial instruments (note 13)		(2,920	)		(17,719	)
		126,295			201,742
Expenses
Operating		39,160			37,744
Transportation and blending		37,842			51,070
General and administrative		8,734			7,151
Unit-based compensation (note 8)		1,688			2,082
Interest (note 11)		8,124			8,720
Foreign exchange loss (note 12)		3,999			7,518
Depletion, depreciation and accretion		55,204			50,458
		154,751			164,743
Income (loss) before taxes and non-controlling interest		(28,456	)		36,999
Tax expense (recovery) (note 10)
Current expense		2,189			2,514
Future recovery		(22,155	)		(2,478	)
		(19,966	)		36
Income (loss) before non-controlling interest		(8,490	)		36,963
Non-controlling interest (note 7)		–			(1,115	)
Net income (loss)	$	(8,490	)	$	35,848
Other comprehensive income
Foreign currency translation adjustment (note 2)		18,751			–
Comprehensive income	$	10,261		$	35,848
Net income (loss) per trust unit (note 9)
Basic	$	(0.09	)	$	0.42
Diluted	$	(0.09	)	$	0.41
Weighted average trust units (note 9)
Basic		98,066			85,254
Diluted		98,066			90,693

CONSOLIDATED STATEMENTS OF DEFICIT

	Three Months Ended March 31
(thousands of Canadian dollars, except per unit amounts) (unaudited)	2009			2008
Deficit, beginning of period	$	(224,314	)	$	(239,727	)
Net income (loss)		(8,490	)		35,848
Distributions to unitholders		(41,232	)		(47,857	)
Deficit, end of period	$	(274,036	)	$	(251,736	)

See accompanying notes to the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31
(thousands of Canadian dollars) (unaudited)	2009			2008
CASH PROVIDED BY (USED IN):
Operating activities
Net income (loss)	$	(8,490	)	$	35,848
Items not affecting cash:
Unit-based compensation (note 8)		1,688			2,082
Unrealized foreign exchange loss (note 12)		4,622			7,010
Depletion, depreciation and accretion		55,204			50,458
Accretion on debentures and notes (notes 3 & 4)		434			364
Unrealized loss on financial instruments (note 13)		28,069			7,171
Future tax (recovery)		(22,155	)		(2,478	)
Non-controlling interest (note 7)		–			1,115
		59,372			101,570
Change in non-cash working capital		(22,854	)		19,779
Asset retirement expenditures		(451	)		(394	)
Decrease in deferred obligations		(11	)		(10	)
		36,056			120,945
Financing activities
Increase (decrease) in bank loan		63,145			(43,702	)
Payments of distributions		(39,438	)		(37,280	)
Issue of trust units, net of issuance costs (note 6)		702			3,791
		24,409			(77,191	)
Investing activities
Petroleum and natural gas property expenditures		(47,664	)		(51,003	)
Disposition of petroleum and natural gas properties		16			(581	)
Change in non-cash working capital		(12,087	)		7,830
		(59,735	)		(43,754	)
Impact of foreign exchange on cash balances (note 2)		(43	)		–
Change in cash		687			–
Cash, beginning of period		–			–
Cash, end of period	$	687		$	–

See accompanying notes to the consolidated financial statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

THREE MONTHS ENDED MARCH 31, 2009 AND 2008

(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. Pursuant to the Plan of Arrangement, the Company became 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 annual consolidated financial statements of the Trust as at December 31, 2008, 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 annual consolidated financial statements and notes thereto for the year ended December 31, 2008.

2. CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2009, the Trust adopted the following new accounting standards that were issued by the Canadian Institute of Chartered Accountants (“CICA”): Section 3064 “Goodwill and Intangible Assets” and EIC-173 “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities”. These standards were adopted prospectively.

Goodwill and Intangible Assets

Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062.

Credit risk and the fair value of financial assets and liabilities

EIC-173 provides guidance on how to take into account credit the credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. The adoption of the EIC had no impact on the consolidated financial statements of the Trust.

Change in currency translation

The Trust’s foreign operations are considered to be “self-sustaining operations”, financially and operationally independent, as of January 1, 2009. As a result, the accounts of the self-sustaining foreign operations are translated using the current rate method whereby assets and liabilities are translated using the exchange rate in effect at the balance sheet date (1.2602), while revenues and expenses are translated using the average exchange rate for the period (1.2456). Translation gains and losses are deferred and included in other comprehensive income in unitholders’ equity.

Previously, foreign operations were considered to be integrated and were translated using the temporal method. Under the temporal method, monetary assets and liabilities were translated at the period end exchange rate while other assets and liabilities were translated at the historical rate. Revenues and expenses were translated at the average monthly rate except for depletion, depreciation and accretion, which were translated on the same basis as

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the assets to which they relate. Translation gains and losses were included in the determination of net income for the period.

This change was adopted prospectively on January 1, 2009 resulting in a currency translation adjustment of $15.4 million upon adoption with a corresponding increase in petroleum and natural gas properties. An additional $3.4 million was recognized in the first quarter of 2009, resulting in a balance of $18.8 million in accumulated other comprehensive income.

Future Accounting Pronouncements

Business Combinations

Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. The purchase price is to be based on trading data at the closing date of the acquisition, not the announcement date of the acquisition, and most acquisition costs are to be expensed as incurred. This standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 1, 2011 with earlier application permitted. The Trust plans to adopt this standard prospectively effective January 1, 2011. The impact from adoption of this standard on the Trust’s accounting of future business combinations has not yet been determined.

Consolidated Financial Statements

Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The Trust plans to adopt this standard prospectively effective January 1, 2011. The impact from adoption of this standard on the Trust’s accounting of future business combinations has not yet been determined.

International Financial Reporting Standards (“IFRS”)

In April 2008, the CICA published the exposure draft “Adopting IFRS in Canada”. The exposure draft proposes to incorporate IFRS into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS. The Trust has performed a diagnostic analysis that identifies differences between the Trust’s current accounting policies and IFRS. At this time, the Trust is evaluating the impact of these differences to determine the potential impact on its consolidated financial statements and assessing the need for amendments to existing accounting policies in order to comply with IFRS.

3. LONG-TERM DEBT

	March 31, 2009			December 31, 2008
10.5% senior subordinated notes (US$247)	$	311		$	303
9.625% senior subordinated notes (US$179,699)		226,457			220,059
		226,768			220,362
Discontinued fair value hedge		(2,764	)		(3,089	)
	$	224,004		$	217,273

The Company has US$0.2 million 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

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Company’s option, in whole or in part, with not less than 30 nor more than 60 days’ notice at the redemption prices (expressed as percentage of the principal amount of the notes) of 100% for 2009 and thereafter. These notes are carried at amortized cost net of a discontinued fair value hedge of $6.0 million recorded on adoption of CICA Handbook Section 3865 “Hedges”. The notes will accrete up to the principal balance at maturity using the effective interest method. Accretion expense of $0.4 million had been recorded for the first quarter of 2009 ($0.3 million in the first quarter of 2008). The effective interest rate is 10.6%.

4. CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES

In June 2005, the Trust issued $100.0 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 7.6%. 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 Debentures			Convertible Debentures			Conversion Feature of Debentures
Balance, December 31, 2007		16,620		$	16,150		$	796
Conversion		(6,222	)		(6,052	)		(298	)
Accretion		–			97			–
Balance, December 31, 2008		10,398		$	10,195		$	498
Conversion		–			–			–
Accretion		–			24			–
Balance, March 31, 2009		10,398		$	10,219		$	498

5. ASSET RETIREMENT OBLIGATIONS

	March 31, 2009			December 31, 2008
Balance, beginning of period	$	49,351		$	45,113
Liabilities incurred		214			871
Liabilities settled		(451	)		(1,443	)
Acquisition of liabilities		–			1,536
Disposition of liabilities		(101	)		(904	)
Accretion		989			3,802
Change in estimate(1)		266			376
Foreign exchange		2			–
Balance, end of period	$	50,270		$	49,351

(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 50 years. The undiscounted amount of estimated cash flow required to settle the retirement obligations at March 31, 2009 is

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$269.5 million. Estimated cash flow has been discounted at a credit-adjusted risk free rate of 8.0 percent and an estimated annual inflation rate of 2.0 percent.

6. UNITHOLDERS’ CAPITAL

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

	Number of Units		Amount
Balance, December 31, 2007		84,540	$	821,624
Issued on conversion of debentures		422		6,350
Issued on conversion of exchangeable shares		2,787		86,888
Issued on exercise of trust unit rights		1,386		10,653
Transfer from contributed surplus on exercise of trust unit rights		–		5,105
Issued on acquisition of Burmis Energy Inc. net of issuance costs		6,383		151,903
Issued pursuant to distribution reinvestment plan		2,167		47,386
Balance, December 31, 2008		97,685	$	1,129,909
Issued on exercise of trust unit rights		220		702
Transfer from contributed surplus on exercise of trust unit rights		–		802
Issued pursuant to distribution reinvestment plan		574		7,561
Balance, March 31, 2009		98,479	$	1,138,974

7. NON-CONTROLLING INTEREST

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, 2007		1,566		$	21,235
Exchanged for trust units		(1,566	)		(24,593	)
Non-controlling interest in net income		–			3,358
Balance, December 31, 2008		–		$	–
Balance, March 31, 2009		–		$	–

On May 30, 2008, the Trust announced that the Company had elected to redeem all of its exchangeable shares outstanding on August 29, 2008. In connection with this redemption, Baytex ExchangeCo Ltd. exercised its overriding “redemption call right” to purchase such exchangeable shares from holders of record. Each exchangeable share was exchanged for units of the Trust in accordance with the exchange ratio in effect at August 28, 2008. As at March 31, 2009 and December 31, 2008, there were no exchangeable shares outstanding.

8. 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 10.0% 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 to account for future distributions, subject to certain performance criteria.

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The Trust recorded compensation expense of $1.7 million for the three months ended March 31, 2009 ($2.1 million in the first quarter of 2008) related to the rights granted under the Plan.

The Trust uses the binomial-lattice model to calculate the estimated weighted average fair value of $1.64 per unit for rights issued during the three months ended March 31, 2009 ($3.23 per unit in the first quarter of 2008). The following assumptions were used to arrive at the estimate of fair values:

	Three Months Ended March 31,
	2009			2008
Expected annual exercise price reduction	$	1.50		$	2.36
Expected volatility		39% – 43	%		28	%
Risk-free interest rate		1.88% – 2.60	%		3.78% – 4.17	%
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:

	Number of rights			Weighted average exercise price(1)
Balance, December 31, 2007		7,662		$	14.67
Granted		2,838		$	19.27
Exercised		(1,386	)	$	7.69
Cancelled		(665	)	$	21.79
Balance, December 31, 2008		8,449		$	14.58
Granted		303		$	13.43
Exercised		(220	)	$	3.19
Cancelled		(13	)	$	17.28
Balance, March 31, 2009		8,519		$	14.47

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

The following table summarizes information about the unit rights outstanding at March 31, 2009:

Range of Exercise Prices	Number Outstanding at March 31, 2009	Weighted Average Remaining Term	Weighted Average Exercise Price	Number Exercisable at March 31, 2009	Weighted Average Exercise Price
		(years)
$1.00 to $6.00	535	0.8	$3.77	535	$3.77
$6.01 to $11.00	1,304	1.6	$7.97	1,304	$7.97
$11.01 to $16.00	727	3.7	$14.76	234	$14.71
$16.01 to $21.00	5,908	3.7	$16.76	1,631	$16.63
$21.01 to $26.03	45	4.1	$25.51	–	$–
$1.00 to $26.03	8,519	3.2	$14.47	3,704	$11.60

The following table summarizes the changes in contributed surplus:

Balance, December 31, 2007	$	18,527
Compensation expense		7,812
Transfer from contributed surplus on exercise of trust unit rights(1)		(5,105	)
Balance, December 31, 2008	$	21,234
Compensation expense		1,688
Transfer from contributed surplus on exercise of trust unit rights(1)		(802	)
Balance, March 31, 2009	$	22,120

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

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9. NET INCOME (LOSS) 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 March 31,
	2009								2008
	Net (Loss)			Trust Units		Net (Loss) per Unit			Net Income		Trust Units		Net Income per Unit
Net income (loss) per basic unit	$	(8,490	)		98,066	$	(0.09	)	$	35,848		85,254	$	0.42
Dilutive effect of trust unit rights		–			–					–		1,634
Conversion of convertible debentures		–			–					206		1,106
Exchange of exchangeable shares		–			–					1,115		2,699
Net income (loss) per diluted unit	$	(8,490	)		98,066	$	(0.09	)	$	37,169		90,693	$	0.41

For the quarter ended March 31, 2009, 7.6 million trust unit rights (first quarter of 2008 – 3.9 million) and 0.7 million units (first quarter of 2008 – nil) that would be issued on the conversion of the convertible debentures were excluded in calculating the weighted average number of diluted trust units outstanding as they were anti-dilutive.

10. TAX EXPENSE (RECOVERY)

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

	Three Months Ended March 31,
	2009			2008
Income (loss) before taxes and non-controlling interest	$	(28,456	)	$	36,999
Expected taxes at the statutory rate of 29.60% (2008 – 30.90%)		(8,423	)		11,432
Increase (decrease) in taxes resulting from:
Net earnings of the Trust		(13,306	)		(15,763	)
Non-taxable portion of foreign exchange loss		1,177			1,060
Effect of change in tax rate		(166	)		(191	)
Effect of change in opening tax pool balances		2,956			–
Effect of change in valuation allowance		(4,967	)		–
Unit-based compensation		500			643
Other		74			341
Future tax (recovery)		(22,155	)		(2,478	)
Current tax expense		2,189			2,514
Total tax (recovery) expense	$	(19,966	)	$	36

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11. INTEREST EXPENSE

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

	Three Months Ended March 31,
	2009		2008
Bank loan and other	$	2,552	$	3,743
Convertible debentures		177		298
Long-term debt		5,395		4,679
Total interest	$	8,124	$	8,720

12. SUPPLEMENTAL INFORMATION

	Three Months Ended March 31,
	2009		2008
Interest paid	$	12,133	$	12,395
Current income taxes	$	2,939	$	439

	Three Months Ended  March 31,
	2009			2008
Unrealized foreign exchange loss	$	4,622		$	7,010
Realized foreign exchange (gain) loss		(623	)		508
Total foreign exchange loss	$	3,999		$	7,518

13. 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 instruments, 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 five categories: held-for-trading, held to maturity, loans and receivables, available-for-sale and other

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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:

	March 31, 2009						December 31, 2008
	Carrying Value			Fair Value			Carrying Value			Fair Value
Financial Assets
Held for trading
Cash	$	687		$	687		$	–		$	–
Derivatives designated as held for trading		61,522			61,522			85,678			85,678
Total held for trading	$	62,209		$	62,209		$	85,678		$	85,678
Loans and receivables
Accounts receivable	$	98,292		$	98,292		$	87,551		$	87,551
Total loans and receivables	$	98,292		$	98,292		$	87,551		$	87,551
Financial Liabilities
Held for trading
Derivatives designated as held for trading	$	(1,420	)	$	(1,420	)		–			–
Total held for trading	$	(1,420	)	$	(1,420	)		–			–
Other financial liabilities
Accounts payable and accrued liabilities	$	(140,994	)	$	(140,994	)	$	(164,279	)	$	(164,279	)
Distributions payable to unitholders		(11,817	)		(11,817	)		(17,583	)		(17,583	)
Bank loan		(272,421	)		(272,421	)		(208,482	)		(208,482	)
Long-term debt		(224,004	)		(220,823	)		(217,273	)		(200,557	)
Convertible debentures		(10,219	)		(10,918	)		(10,195	)		(9,837	)
Deferred obligations		(63	)		(63	)		(74	)		(74	)
Total other financial liabilities	$	(659,518	)	$	(657,036	)	$	(617,886	)	$	(600,812	)

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 based on the lower of trading value and 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.

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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.

To manage the impact of currency rate fluctuations, the Trust may enter into agreements to fix the Canada – U.S. exchange rate.

At March 31, 2009, the Trust had in place the following currency swaps:

	Period	Amount	Swap Price(1)
Swap	January 1, 2009 to December 31, 2009	USD 10.0 million per month	CAD/USD 1.2386
Swap	January 1, 2010 to December 31, 2010	USD 5.0 million per month	CAD/USD 1.2300

(1) Exchange rate is weighted average

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 March 31, 2009.

	$0.10 Increase/Decrease in CAD/USD Exchange Rate
Gain/loss on currency swap	$	253
Gain/loss on other monetary assets/liabilities		13,964
Impact on income before taxes and non-controlling interest	$	14,217

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

	Assets		Liabilities
	March 31, 2009	December 31, 2008	March 31, 2009	December 31, 2008
U.S. dollar denominated	USD 65,388	USD 84,070	USD 207,558	USD 191,571

Subsequent to March 31, 2009, the Trust added the following currency swap:

	Period	Amount	Swap Price
Swap	January 1, 2010 to December 31, 2010	USD 3.0 million per month	CAD/USD 1.2030

Interest rate risk

The Trust’s interest rate risk arises from its floating rate bank loan. As at March 31, 2009, $272.4 million of the Trust’s total debt is subject to movements in floating interest rates. An increase or decrease of 100 basis points in interest rates would impact cash flow for the three months ended March 31, 2009 by approximately $0.7 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 addition to the unrealized loss in the first quarter of 2009 of $8.4 million relating to the financial

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derivative instruments outstanding as at March 31, 2009, while a 10% decrease could have resulted in a reduction to the loss of $8.6 million.

At March 31, 2009, the Trust had the following commodity derivative contracts:

Oil	Period	Volume	Price	Index
Price collar	Calendar 2009	2,000 bbl/d	USD 90.00 – 136.40	WTI
Price collar	Calendar 2009	2,000 bbl/d	USD 110.00 – 172.70	WTI

Gas	Period	Volume	Price	Index
Price collar	April 1, 2009 to December 31, 2010	5,000 GJ/d	CAD 5.00 - 6.30	AECO

The commodity derivative contracts are marked to market at the end of each reporting period, with the following reflected in the income statement:

	Three Months Ended March 31,
	2009			2008
Realized gain (loss) on financial instruments	$	25,149		$	(10,548	)
Unrealized (loss) on financial instruments		(28,069	)		(7,171	)
Loss on financial instruments	$	(2,920	)	$	(17,719	)

Subsequent to March 31, 2009, the Trust added the following commodity derivative contract:

Oil	Period	Volume	Price	Index
Fixed	Calendar 2010	575 bbl/d	USD 64.00	WTI

Physical contracts

At March 31, 2009, the Trust had the following crude oil supply contracts:

Heavy Oil

	Period	Volume	Price(1)
Price Swap – WCS Blend	Calendar 2009	10,340 bbl/d	WTI × 67.0%
Price Swap – WCS Blend	April 1, 2009 to August 30, 2009	775 bbl/d	WTI × 80.0%
Price Swap – WCS Blend	April 1, 2009 to August 30, 2009	775 bbl/d	WTI less US$10

(1) Price is weighted average

Subsequent to March 31, 2009, the Trust added the following physical crude oil supply contracts:

Heavy Oil

	Period	Volume	Price
Price Swap – WCS Blend	January 1, 2010 to December 31, 2010	2,500 bbl/d	US$51.04
Price Swap – Condensate	January 1, 2010 to December 31, 2010	575 bbl/d	WTI plus US$2.25 – $2.60

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At March 31, 2009, the Trust had the following natural gas physical sales contract:

Gas

	Period	Volume	Price/GJ
Price Collar	Calendar 2009	5,000 GJ/d	$	7.00 – $7.95

Subsequent to March 31, 2009, the Trust added the following physical gas sales contract:

Gas

	Period	Volume	Price/GJ
Price Collar	Calendar 2010	5,000 GJ/d	$	5.00 – $6.28

At March 31, 2009, the Trust had the following power contracts:

Power

	Period	Volume	Price/MWh
Fixed	October 1, 2008 to December 31, 2009	0.6 MW/hr	$	78.61
Fixed	October 1, 2008 to December 31, 2009	0.6 MW/hr	$	79.92
Fixed	March 1, 2009 to June 30, 2010	0.6 MW/hr	$	76.89

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 March 31, 2009, the Trust had available unused bank credit facilities in the amount of $160 million. The Trust believes it has sufficient funding capacity through its credit facilities to meet foreseeable borrowing requirements.

The timing of cash outflows (excluding interest) 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		140,994		140,994		–		–		–
Distributions payable to unitholders		11,817		11,817		–		–		–
Bank loan(1)		272,421		272,421		–		–		–
Long-term debt(2)		226,768		–		226,768		–		–
Convertible debentures(2)		10,398		–		10,398		–		–
Deferred obligations		63		46		14		3		–
		662,461		425,278		237,180		3		–

(1) The bank loan is a 364-day revolving loan with the ability to extend the term. In May 2009, the Trust reached agreement with its lending syndicate to extend the maturity of our loan to June 30, 2010.

(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 creditworthy entities and reviewing its

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

As at March 31, 2009, accounts receivable include a $10.2 million balance over 90 days (December 31, 2008 – $9.9 million). A balance of $2.4 million (December 31, 2008 – $2.4 million) has been set up as allowance for doubtful accounts.

14. COMMITMENTS AND CONTINGENCIES

At March 31, 2009, the Trust had operating lease and transportation obligations as summarized below:

			Payments Due Within										Beyond
	Total		1 year		2 years		3 years		4 years		5 years		5 years
Operating leases	$	41,817	$	2,886	$	3,594	$	3,868	$	3,749	$	3,991	$	23,729
Processing and transportation agreements		20,589		8,406		7,320		4,658		164		41		–
Total	$	62,406	$	11,292	$	10,914	$	8,526	$	3,913	$	4,032	$	23,729

Other

At March 31, 2009, there were outstanding letters of credit aggregating $2.3 million (December 31, 2008 – $2.3 million) issued as security for performance under certain contracts.

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 March 31, 2009, additional payments totaling $5.3 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.

15. 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

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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 from operations 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. 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.

On December 4, 2008, the Minister of Finance announced changes to the Guidelines to allow an income trust to accelerate the utilization of the safe harbour amounts for each of 2009 and 2010 so that the safe harbour amounts for 2009 and 2010 are available on and after December 4, 2008. This change does not alter the maximum permitted expansion threshold for an income trust, but it allows an income trust to use its safe harbour amount remaining as of December 4, 2008 in a single year, rather than staging a portion of the safe harbour amount over the 2009 and 2010 years.

Subsequent to the year end, the Federal Government introduced draft tax legislation which included the above mentioned changes to the Guidelines as part of Canada’s Economic Action Plan. This legislation received Royal Assent on March 12, 2009, and was therefore passed into law. The Trust continues to review the impact of the future taxation of distributions on its business strategy but at this time has made no decision as to the ultimate legal form under which it will operate post 2010.

For the Trust, the safe harbour amounts were approximately $730 million for 2006/2007 and approximately $365 million for each of the subsequent three years with any unused amount carrying forward to the next year. The Trust did not issue equity in excess of its safe harbour amounts during 2006/2007 or 2008 or the first quarter of 2009. As at December 31, 2008, the Trust had an unused safe harbour amount of $596.6 million that was carried forward, resulting in a safe harbour amount of $1,317.5 million for 2009/2010. As at March 31, 2009, the Trust had not exceeded its safe harbour amounts. Subsequent to the end of the first quarter, The Trust issued $115 million in equity as discussed below in subsequent events (note 16).

16. SUBSEQUENT EVENTS

On April 14, 2009, the Trust closed its bought deal equity financing resulting in the issuance of 7,935,000 trust units (including 1,035,000 trust units issued pursuant to the exercise in full of the over-allotment option granted to the underwriters) at $14.50 per trust unit for total gross proceeds of $115,057,500. The net proceeds of the offering will initially be used by the Trust for general working capital purposes, which may ultimately be used to fund its capital expenditure program or to retire or repay outstanding indebtedness.

In May 2009, the Company reached agreement with its lending syndicate to increase the amount of its credit facilities from $485.0 million to $515.0 million effective July 1, 2009, and extend the maturity of the facilities to June 30, 2010.

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ABBREVIATIONS

bbl	barrel	Mcf	thousand cubic feet
bbl/d	barrel per day	Mcf/d	thousand cubic feet per day
Bcf	billion cubic feet	MMbbl	million barrels
boe	barrels of oil equivalent	MMboe	million barrels of oil equivalent
boe/d	barrels of oil equivalent per day	MMcf	million cubic feet
Mbbl	thousand barrels	MMcf/d	million cubic feet per day
Mboe	thousand barrels of oil equivalent	NGL	natural gas liquids

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CORPORATE INFORMATION

BOARD OF DIRECTORS Raymond T. Chan Executive Chairman   John A. Brussa (2)(3)(4) Partner Burnet, Duckworth & Palmer LLP   Edward Chwyl (2)(3)(4) Lead Independent Director Independent Businessman   Naveen Dargan (1)(2)(4) Independent Businessman   R. E. T. (Rusty) Goepel (1) Senior Vice President Raymond James Ltd.   Anthony W. Marino President & Chief Executive Officer Baytex Energy Ltd.   Gregory K. Melchin (1) Independent Businessman   Dale O. Shwed (3) President and CEO Crew Energy Inc.   (1) Member of the Audit Committee (2) Member of the Compensation Committee (3) Member of the Reserves Committee (4) Member of the Nominating and Governance Committee   HEAD OFFICE Suite 2200, Bow Valley Square II 205 – 5th Avenue S.W. Calgary, Alberta T2P 2V7 T 403-269-4282 F 403-205-3845 Toll-free: 1-800-524-5521 www.baytex.ab.ca   AUDITORS Deloitte & Touche LLP   BANKERS The Toronto-Dominion Bank Bank of Nova Scotia BNP Paribas (Canada) Canadian Imperial Bank of Commerce Fortis Capital (Canada) Ltd. National Bank of Canada Royal Bank of Canada Société Générale Union Bank of California   LEGAL COUNSEL Burnet, Duckworth & Palmer LLP   OFFICERS Raymond T. Chan Executive Chairman   Anthony W. Marino President & Chief Executive Officer   W. Derek Aylesworth Chief Financial Officer   Marty L. Proctor Chief Operating Officer   Randal J. Best Senior Vice President, Corporate Development   Stephen Brownridge Vice President, Heavy Oil   Brett J. McDonald Vice President, Land   Timothy R. Morris Vice President, U.S. Business Development   R. Shaun Paterson Vice President, Marketing   Mark F. Smith Vice President, Conventional Oil & Gas   Shannon M. Gangl Corporate Secretary Partner, Burnet, Duckworth & Palmer LLP   RESERVES ENGINEERS Sproule Associates Limited   TRANSFER AGENT Valiant Trust Company   EXCHANGE LISTING Toronto Stock Exchange Symbol: BTE.UN   New York Stock Exchange Symbol: BTE            

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