ex99_1.htm

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.

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”.

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.

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 23,432 bbl/d from 22,484 bbl/d a year ago due to development drilling over the past year in the Seal and

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

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.

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 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 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 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 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.

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 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.

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 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.

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 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 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.

		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 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.

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.

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.

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 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

	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

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.

($ thousands, except per unit amounts)	2009				2008				2007
		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

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.

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 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.

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.

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.

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 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.