6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

of the Securities Exchange Act of 1934

For the month of July 2009

BAYTEX ENERGY TRUST

(Translation of registrant's name into English)

2200, 205 – 5TH AVENUE S.W.

CALGARY, ALBERTA, CANADA

T2P 2V7

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

 Form 20-F   o  Form 40-F   x

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

 Yes   o  No   x

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82- ________

The Press Release attached as an exhibit hereto is incorporated by reference herein.

EXHIBIT LIST

Exhibit	Description
99.1	Supplemental note to audited comparative consolidated financial statements as at and for the year ended December 31, 2008 titled "Supplemental U.S. GAAP Disclosures", together with the auditors' report thereon
99.2	Supplemental Disclosures about Oil and Gas Producing Activities prepared in accordance with SFAS No. 69 – "Disclosure about Oil and Gas Producing Activities"(unaudited)
99.3	Material Change Report dated March 26, 2009

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BAYTEX ENERGY TRUST (Registrant) By: Baytex Energy Ltd., as administrator
Date: July 16, 2009	By:	/s/ W. Derek Aylesworth
		Name: W. Derek Aylesworth
		Title: Chief Financial Officer

EX-99.1

Exhibit 99.1

Baytex Energy Trust

Supplemental U.S. GAAP Disclosures

December 31, 2008

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors of Baytex Energy Ltd. and

Unitholders of Baytex Energy Trust:

We have audited the consolidated financial statements of Baytex Energy Trust and subsidiaries (the “Trust”) as at December 31, 2008 and 2007 and for the years then ended and have issued our reports thereon dated March 16, 2009 (which audit report expresses an unqualified opinion and includes an explanatory paragraph relating to the separate issuance of financial statements prepared in accordance with Canadian generally accepted accounting principles and includes a separate report titled Comments by Independent Registered Chartered Accountants on Canada-United States of America Reporting Differences relating to changes in accounting principles) and such financial statements and reports are included in Amendment No. 1  to Form 40-F for the year ended December 31, 2008. We have also audited the following Supplemental U.S. GAAP Disclosures of the Trust as at December 31, 2008 and 2007 and for the years then ended which were prepared to comply with the requirements of Item 18 of Form 20-F.  This supplemental disclosure is the responsibility of the Trust’s management. Our responsibility is to express an opinion based on our audits. In our opinion, the Supplemental U.S. GAAP Disclosures as at December 31, 2008 and 2007 and for the years then ended, when considered in relation to the 2008 and 2007 basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants

Calgary, Alberta, Canada

July 16, 2009

Baytex Energy Trust

Supplemental U.S. GAAP Disclosures

December 31, 2008

(All tabular amounts in thousands of Canadian dollars, except per unit amounts)

This information should be read in conjunction with the audited annual consolidated financial statements of Baytex Energy Trust (“Baytex” or the “Trust”) as at and for the years ended December 31, 2008 and 2007.  The Trust’s consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).  Significant differences between Canadian and United States generally accepted accounting principles (“U.S. GAAP”) are described in note 19 of the December 31, 2008 consolidated financial statements.  In addition to the significant differences described in note 19, presentation of the following additional disclosures are required under U.S. GAAP and Regulation S-X of the United States Securities and Exchange Commission as specified in Item 18 of the Form 20-F.

1. Full Cost Accounting

Under U.S. GAAP, for determining the limitation of capitalized costs, the carrying value of a cost center’s oil and gas properties cannot exceed the future net cash flows, discounted at 10%, of its proved reserves using period-end oil and gas prices and costs plus (i) the costs of properties that have been excluded from the depletion calculation and (ii) the lower of cost or estimated fair value of unproved properties included in the depletion calculation less (iii) income tax effects related to differences between the book and tax basis of the properties.  The amount of the impairment expense is recognized as a charge to the results of operations and a reduction in the net carrying amount of a cost center’s oil and gas properties.

For Canadian GAAP, the carrying value includes all capitalized costs for each cost center, including costs associated with asset retirement net of estimated salvage values, unproved properties and major development projects, less accumulated depletion and ceiling test impairments. This is essentially the same definition according to U.S. GAAP, under Regulation S-X, except that the carrying value of assets should be net of deferred income taxes and costs of major development projects are to be considered separately for purposes of the ceiling test calculation.

Under U.S. GAAP, the capitalized costs of unproved properties and major development costs, which have been excluded from the depletion and ceiling test calculations, are required to be disclosed on the face of the balance sheet.  Capitalized costs of $121.2 million relating to unproved properties were included in the petroleum and natural gas properties on the balance sheet.  This is amortized into the depletion base over five years.  There were no major development projects that were excluded from the capitalized costs being amortized.

2. Full Cost Accounting

i. The components of accounts payable and accrued liabilities are as follows:

	As at December 31
	2008		2007
Trade payables	$	64,067	$	46,965
Joint venture		25,670		8,508
Oil & gas accrued liabilities		66,361		39,450
Other		8,181		9,395
	$	164,279	$	104,318

ii. The components of inventory are as follows:

	As at December 31
	2008		2007
Oil and condensates	$	260	$	5,585
Other		72		412
	$	332	$	5,997

3. Deferred Charges

As described under “Financial Instruments and Risk Management” in note 16 of the December 31, 2008 consolidated financial statements, deferred charges or transaction costs are recorded as a reduction from the related liability and accounted for using the effective interest method.  For U.S. GAAP purposes, these costs are classified as deferred charges and amortized using the effective interest method over the expected term of the financial liability.

Baytex Energy Trust

Supplemental U.S. GAAP Disclosures

December 31, 2008

(All tabular amounts in thousands of Canadian dollars, except per unit amounts)

4. Bank Loan and Credit Facilities

The weighted average interest rate on short-term borrowings for the year ended December 31, 2008 was 5.39% (2007 – 6.91%).

5. Unitholders’ Capital

Distributions declared for the year ended December 31, 2008 were $2.64 per unit (2007 – $2.16 per unit).  The number of trust units outstanding as at December 31, 2008 was 97,685,333 (2007 – 84,539,945).  Under U.S. GAAP, the number of trust units issued and outstanding is required to be disclosed on the face of the balance sheet.

Costs related to the issuance of trust units for the year ended December 31, 2008 of $0.2 million (2007 - $7.7 million) were netted against unitholders’ capital.  Under U.S. GAAP, in the consolidated statement of cash flows, these amounts would be presented on a gross basis, whereas under Canadian GAAP, they have been netted against the proceeds from the issuance of trust units.

6. Trust Unit Rights Incentive Plan

The Trust has a Trust Units Rights Incentive Plan (the “Plan”) established in 2003.  As the exercise price of the unit rights granted under the plan is subject to downward revisions in future periods by a portion of the future distributions, subject to certain performance criteria, the Plan is a variable compensation plan under U.S. GAAP.  Effective January 1, 2006, the Trust adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payments” (“SFAS 123R”).

SFAS 123R requires that all unit-based payments to employees, including grants of unit rights, be recognized in the financial statements based on their fair values. Liability classified awards, such as the Trust’s unit rights are re-measured to fair value at each consolidated balance sheet date until the award is settled rather than being treated as an equity classified award on the grant date as required under Canadian GAAP.  Baytex has adopted this standard by applying the modified prospective method.   The fair value of the unit rights has been determined using a binomial-lattice model.  Under U.S. GAAP, changes in fair values between reporting periods are charged or credited to earnings with a corresponding change to current liabilities.  The accounting for compensation expense for the Plan results in a difference between Canadian GAAP and U.S. GAAP, as the Trust classifies the Plan as equity awards and uses the grant date fair value method to account for its unit compensation expense under Canadian GAAP.

Under U.S. GAAP, compensation expense was increased by $1.2 million in 2008 ($3.1 million reduction to compensation expense in 2007).  The Trust recorded compensation expense of $9.0 million for the year ended December 31, 2008 ($4.9 million in 2007) related to the unit rights granted under the Plan.

The Trust used the binomial-lattice model to calculate the estimated weighted average grant date fair value of $2.42 per unit for unit rights issued during 2008 ($3.87 per unit in 2007).  The following assumptions were used to arrive at the estimate of fair values:

	2008			2007
Expected annual exercise price reduction	$	2.64		$	2.16
Expected volatility		28% - 39	%		28	%
Risk-free interest rate		2.98% - 4.17	%		3.77% - 4.50	%
Forfeiture rate		10	%		10	%
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.

Baytex Energy Trust

Supplemental U.S. GAAP Disclosures

December 31, 2008

(All tabular amounts in thousands of Canadian dollars, except per unit amounts)

The following table is a summary of the status of the unvested unit rights as of December 31, 2008 and 2007 and changes during the years then ended:

	Number of unvested rights			Weighted average grant date fair value
Unvested, December 31, 2006		4,293		$	4.06
Granted		2,642		$	3.87
Vested		(1,736	)	$	3.95
Forfeited		(554	)	$	4.10
Unvested, December 31, 2007		4,645		$	3.99
Granted		2,838		$	2.42
Vested		(2,149	)	$	3.96
Forfeited		(665	)	$	4.12
Unvested, December 31, 2008		4,669		$	3.03

As of December 31, 2008, there was $4.7 million of total unrecognized compensation cost related to unvested unit rights; the cost is expected to be recognized over a weighted average period of 1.4 years.  The total fair value of unit rights vested during the year ended December 31, 2008 was $8.3 million ($13.9 million in 2007).

The intrinsic value of a unit right is the amount by which the current market value of the underlying trust unit exceeds the exercise price of the unit right.

The following table summarizes information related to unit rights activity during the years ended December 31, 2008 and 2007:

	Number of rights			Weighted average exercise price (1)		Weighted average contract life (years)		Aggregate intrinsic value
Outstanding, December 31, 2007		7,662		$	14.67		3.4	$	35,553
Granted		2,838		$	19.27		4.7		-
Exercised		(1,386	)	$	7.69		1.1		23,109
Forfeited		(665	)	$	21.79		4.1		1,836
Outstanding, December 31, 2008		8,449		$	14.58		3.3	$	16,277
Exercisable, December 31, 2008		3,780		$	11.52		2.3	$	15,858
Expected to vest		4,201		$	17.07		4.1	$	377

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

	Number of rights			Weighted average exercise price (1)		Weighted average contract life (years)		Aggregate intrinsic value
Outstanding, December 31, 2006		6,313		$	14.00		3.7	$	52,396
Granted		2,642		$	19.85		4.7		248
Exercised		(739	)	$	7.42		1.7		9,685
Forfeited		(554	)	$	16.91		3.5		2,103
Outstanding, December 31, 2007		7,662		$	14.67		3.4	$	35,553
Exercisable, December 31, 2007		3,017		$	9.89		2.4	$	28,012
Expected to vest		4,180		$	17.78		4.1	$	6,787

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

7. Petroleum and Natural Gas Revenues

Under U.S. GAAP, petroleum and natural gas revenues are required to be presented net of royalties, excise and sales taxes to governments and other mineral interest owners.

Baytex Energy Trust

Supplemental U.S. GAAP Disclosures

December 31, 2008

(All tabular amounts in thousands of Canadian dollars, except per unit amounts)

8. Interest

Under U.S. GAAP, interest income should be disclosed separately from interest expense on the face of the income statement.  For the year ended December 31, 2008, interest income netted against the interest expense was $0.2 million (2007 - $0.8 million).

9. Income Taxes

On January 1, 2007, Baytex adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes" ("FIN 48"), an interpretation of FASB Statement No. 109, ”Accounting for Income Taxes."  FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  The interpretation requires that Baytex recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the technical merits of the position.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, and accounting in interim periods and disclosure.  In accordance with the provisions of FIN 48, any cumulative effect resulting from the change in accounting principle is to be recorded as an adjustment to the opening deficit balance.  Baytex has applied similar guidance in assessing its uncertain tax positions under Canadian GAAP.

The implementation of FIN 48 did not result in any adjustment to the beginning tax positions of the Trust.   The unrecognized tax benefits of the Trust are disclosed below.

Unrecognized tax benefits, January 1, 2007	$	3,071
Gross decrease for tax positions taken during a prior period		(130	)
Gross decrease for tax positions taken during the current period		(710	)
Gross increase for tax positions taken during the current period		2,896
Reductions due to lapse of applicable statute of limitations		(877	)
Unrecognized tax benefits, December 31, 2007	$	4,250
Gross increase for tax positions taken during a prior period		98
Gross decrease for tax positions taken during a prior period		(195	)
Gross increase for tax positions taken during the current period		447
Reductions due to lapse of applicable statute of limitations		(1,000	)
Unrecognized tax benefits, December 31, 2008	$	3,600

All of the Trust’s unrecognized tax benefits at December 31, 2008, if recognized, would affect the Trust’s effective income tax rate.  The Trust does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its consolidated financial statements.

The Trust recognizes interest and penalties related to uncertain tax positions in a component of interest expense.  During each of the years ended December 31, 2008 and 2007, interest expense includes $0.3 million of interest related to taxation amounts.  There are no accruals of interest and penalties as at December 31, 2008 on the balance sheet ($0.1 million accrued at December 31, 2007).

Baytex and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax, or the relevant income tax in other international jurisdictions.  Baytex may be subject to a reassessment of federal and provincial income taxes by Canadian tax authorities for a period of four years from the date of mailing of the original notice of assessment in respect of any particular taxation year.  For the Canadian federal and provincial income tax matters, the open taxation years range from 2005 to 2008.   The U.S. federal statute of limitations for assessment of income tax is generally closed for the taxation years through 2004.   In certain circumstances, the U.S. federal statute of limitations can reach beyond the standard three year period.  U.S. state statutes of limitations for income tax assessment vary from state to state.   The tax authorities have not audited any of the income tax returns of Baytex or its subsidiaries for the open taxation years noted above.

Baytex Energy Trust

Supplemental U.S. GAAP Disclosures

December 31, 2008

(All tabular amounts in thousands of Canadian dollars, except per unit amounts)

10. Financial Instruments and Risk Management

In September 2006, the FASB issued SFAS No. 157, “Fair value measurements” (“SFAS 157”).  This statement defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and expands disclosure about fair value measurements.  The Trust adopted the provisions of SFAS 157 effective January 1, 2008.  The implementation did not have a material impact on the consolidated financial statements as the current policy on accounting for fair value measurements is consistent with this guidance.  The Trust has, however, provided additional prescribed disclosures not required under Canadian GAAP.

SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  The three levels of the fair value hierarchy are described below:

· Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

· Level 2:  Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

· Level 3:  Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

As required by SFAS 157 when the inputs used to measure fair value fall within different levels of the hierarchy, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measure in its entirety.

The following table presents the Trust’s fair value hierarchy for those assets and liabilities measured at fair value on a recurring basis as of December 31, 2008.  The fair value measurement of financial instruments related to the Trust’s foreign currency swaps and commodity price collars are considered Level 2.

As at December 31, 2008	Level 1	Level 2	Level 3	Total
Derivatives designated as held for trading	-	$   85,678	-	$    85,678

11. Commitments and Contingencies

For the year ended December 31, 2008, the Trust recorded an expense for operating leases of $2.8 million (2007 – $2.0 million).  The operating leases have expiration dates ranging from April 2010 to April 2020.

12. Supplemental Information

Change in Non-Cash Working Capital Items

For years ended December 31,	2008		2007
Operating activities
Accounts receivable	$	29,795	$	(27,231	)
Crude oil inventory		5,665		3,612
Accounts payable and accrued liabilities		3,436		28,759
		38,896		5,140
Investing activities
Accounts payable and accrued liabilities		19,874		4,060
	$	58,770	$	9,200

EX-99.2

Exhibit 99.2

Baytex Energy Trust

Supplemental Disclosures about Oil and Gas Producing Activities (unaudited)

December 31, 2008

The following disclosures have been prepared by Baytex Energy Trust (“Baytex” or the “Trust”) in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”):

Oil and Gas Reserve Information

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids (“NGL”) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

Reserves are estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations, from a given date forward, by known technology, under existing operating conditions and prices in effect at year end.  Estimates of oil and gas reserves are subject to uncertainty and will change as additional information regarding the producing fields and technology becomes available and as future economic conditions change.  Reserves presented in this section represent the Trust’s share of reserves, excluding royalty interests of others.  Net after royalty reserves are the Trust’s working interest and overriding royalty share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties.  Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.

The changes in the Trust’s net proved oil and gas reserves under constant prices and costs for the two-year period ended December 31, 2008 were as follows:

	Canada					United States						Total
	Crude Oil & NGL		Natural Gas			Crude Oil & NGL			Natural Gas			Crude Oil & NGL			Natural Gas
	(Mbbl)		(MMcf)			(Mbbl)			(MMcf)			(Mbbl)			(Mmcf)
Net proved reserves
December 31, 2006	74,790			88,560			-			-			74,790			88,560
Revisions of previous estimates	3,955			(2,267	)		-			-			3,955			(2,267	)
Improved recovery	246			-			-			-			246			-
Purchases	7,792			8,657			-			-			7,792			8,657
Extensions and discoveries	7,428			4,802			-			-			7,428			4,802
Production	(8,315	)		(14,849	)		-			-			(8,315	)		(14,849	)
December 31, 2007	85,896			84,903			-			-			85,896			84,903
Revisions of previous estimates	3,130			(547	)		-			-			3,130			(547	)
Improved recovery	-			-			-			78			-			78
Purchases	1,102			22,671			3,281			1,580			4,383			24,251
Extensions and discoveries	402			183			-			-			402			183
Production	(9,166	)		(14,992	)		(57	)		(13	)		(9,223	)		(15,005	)
December 31, 2008	81,364			92,218			3,224			1,645			84,588			93,863
Net proved developed reserves
End of year 2006	45,958			75,679			-			-			45,958			75,679
End of year 2007	48,052			72,372			-			-			48,052			72,372
End of year 2008	45,384			80,916			1,161			330			46,545			81,246

1

Baytex Energy Trust

Supplemental Disclosures about Oil and Gas Producing Activities (unaudited)

December 31, 2008

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by SFAS 69 and based on crude oil and natural gas reserve and production volumes estimated by Baytex’s independent engineering evaluators, Sproule Associates Limited. In calculating the standardized measure of discounted future net cash flows, year-end constant prices and cost assumptions were applied to Baytex’s annual future production from proved reserves to determine cash inflows.  Future production and development costs are based on constant price assumptions and assume the continuation of existing economic, operating, and regulatory conditions.  Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The Trust is currently not taxable.  A 10 percent discount factor was applied to the future net cash flows.

The information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the fair market value of Baytex’s oil and gas properties. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The prescribed discount rate of 10 percent may not appropriately reflect interest rates.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2008 was based on the year-end AECO-C spot price for natural gas of $6.34/mmbtu (2007 - $6.52/mmbtu) and on crude oil prices computed with reference to the year-end Edmonton Par spot price of $45.51/bbl (2007 - $93.44/bbl).

The standardized measure of discounted future net cash flows relating to net proved oil and gas reserves are as follows:

	Canada						United States					Total
(thousands of Canadian dollars)	2008			2007			2008			2007		2008			2007
Future cash inflows	$	2,548,386		$	4,239,971		$	161,982		$	-	$	2,710,368		$	4,239,971
Future production costs		(1,324,077	)		(1,503,820	)		(66,397	)		-		(1,390,474	)		(1,503,820	)
Future development costs		(411,306	)		(428,574	)		(57,124	)		-		(468,430	)		(428,574	)
Future income taxes (1)		-			(80,005	)		(6,304	)		-		(6,304	)		(80,005	)
Future net cash flows		813,003			2,227,572			32,157			-		845,160			2,227,572
Deduct: 10% annual discount factor		(251,348	)		(788,772	)		(35,994	)		-		(287,342	)		(788,772	)
Standardized measure	$	561,655		$	1,438,800		$	(3,837	)	$	-	$	557,818		$	1,438,800

(1) Not expected to be taxable in Canada.

2

Baytex Energy Trust

Supplemental Disclosures about Oil and Gas Producing Activities (unaudited)

December 31, 2008

Reconciliation of Changes in Standardized Measure of Future Net Cash Flows Discounted at 10% per Year Relating to Proved Oil and Gas Reserves

As at December 31, 2008 (thousands of Canadian dollars)	Canada			United States			Total
Balance, beginning of year	$	1,438,800		$	-		$	1,438,800
Sales, net of production costs		(776,491	)		(3,234	)		(779,725	)
Net change in prices and production costs related to future production		(273,125	)		-			(273,125	)
Changes in previously estimated production costs incurred during the period		(162,473	)		(62,390	)		(224,863	)
Extensions, discoveries and improved recovery,     net of related costs		5,426			280			5,706
Revisions of previous quantity estimates		35,199			-			35,199
Purchases of reserves in place		119,553			62,209			181,762
Accretion of discount		159,586			-			159,586
Net change in income taxes		15,180			(702	)		14,478
Balance, end of year	$	561,655		$	(3,837	)	$	557,818

As at December 31, 2007 (thousands of Canadian dollars)	Canada			United States		Total
Balance, beginning of year	$	1,227,079		$	-	$	1,227,079
Sales, net of production costs		(508,384	)		-		(508,384	)
Net change in prices and production costs related to future production		209,794			-		209,794
Changes in previously estimated production costs incurred during the period		(120,870	)		-		(120,870	)
Extensions, discoveries and improved recovery,     net of related costs		193,199			-		193,199
Revisions of previous quantity estimates		82,630			-		82,630
Purchases of reserves in place		283,831			-		283,831
Accretion of discount		96,740			-		96,740
Net change in income taxes		(25,219	)		-		(25,219	)
Balance, end of year	$	1,438,800		$	-	$	1,438,800

Capitalized Costs Relating to Oil and Gas Producing Activities

As at December 31, 2008 (thousands of Canadian dollars)	Canada			United States			Total
Proved properties	$	3,377,726		$	49,282		$	3,427,008
Unproved properties		63,587			57,629			121,216
Total capital costs		3,441,313			106,911			3,548,224
Accumulated depletion and depreciation		(2,795,663	)		(49,285	)		(2,844,948	)
Net capitalized costs	$	645,650		$	57,626		$	703,276

As at December 31, 2007 (thousands of Canadian dollars)	Canada			United States		Total
Proved properties	$	2,993,179		$	-	$	2,993,179
Unproved properties		64,984			-		64,984
Total capital costs		3,058,163			-		3,058,163
Accumulated depletion and depreciation		(1,929,982	)		-		(1,929,982	)
Net capitalized costs	$	1,128,181		$	-	$	1,128,181

3

Baytex Energy Trust

Supplemental Disclosures about Oil and Gas Producing Activities (unaudited)

December 31, 2008

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

For years ended December 31, 2008 (thousands of Canadian dollars)	Canada		United States		Total
Property acquisition costs (1)
Proved properties	$	190,471	$	12,299	$	202,770
Unproved properties		4,700		57,629		62,329
Development costs (2)		140,887		36,892		177,779
Exploration costs (3)		6,026		1,278		7,304
Total	$	342,084	$	108,098	$	450,182

For years ended December 31, 2007 (thousands of Canadian dollars)	Canada		United States		Total
Property acquisition costs (1)
Proved properties	$	245,000	$	-	$	245,000
Unproved properties		6,530		-		6,530
Development costs (2)		130,400		-		130,400
Exploration costs (3)		12,266		-		12,266
Total	$	394,196	$	-	$	394,196

(1) Acquisitions are net of disposition of properties.

(2) Development and facilities capital expenditures.

(3) Cost of geological and geophysical capital expenditures and drilling costs for exploratory wells drilled.

Results of Operations for Producing Activities

For years ended December 31, 2008 (thousands of Canadian dollars except per boe amounts)	Canada			United States			Total
Oil and gas revenues, net of royalties	$	946,772		$	4,213		$	950,985
Less:
Operating costs, production and mineral taxes		182,431			980			183,411
Transportation costs		218,706			-			218,706
Depreciation, depletion and accretion		870,928			48,687			919,615
Operating income (loss)		(325,293	)		(45,454	)		(370,747	)
Income taxes (1)		-			-			-
Results of operations (2)	$	(325,293	)	$	(45,454	)	$	(370,747	)
Depletion rate per net boe (3)		74.66			822.88			78.44

For years ended December 31, 2007 (thousands of Canadian dollars except per boe amounts)	Canada		United States		Total
Oil and gas revenues, net of royalties	$	640,430	$	-	$	640,430
Less:
Operating costs, production and mineral taxes		139,763		-		139,763
Transportation costs		155,754		-		155,754
Depreciation, depletion and accretion		154,771		-		154,771
Operating income		190,142		-		190,142
Income taxes (1)		-		-		-
Results of operations (2)	$	190,142	$	-	$	190,142
Depletion rate per net boe		14.34		-		14.34

(1) Baytex is currently not taxable.

 (2) Excludes corporate overhead and interest costs.

 (3) Includes impairment write-down of $799.1 million ($752.1 million – Canada; $47.0 million – United States).

4

EX-99.3

Exhibit 99.3

MATERIAL CHANGE REPORT

1. Name and Address of Reporting Issuer:

Baytex Energy Trust ("Baytex")

Suite 2200, 205 – 5th Avenue S.W.

Calgary, Alberta T2P 2V7

2. Date of Material Change:

March 23, 2009

3. News Release:

A press release was issued by Baytex on March 23, 2009 and disseminated through the facilities of Marketwire and would have been received by the securities commissions where Baytex is a reporting issuer in the normal course of its dissemination.

4. Summary of Material Change:

Baytex announced that it has entered into a bought deal financing agreement with a syndicate of underwriters pursuant to which the syndicate has agreed to purchase 6,900,000 trust units at $14.50 per unit for total gross proceeds of $100,050,000.  Baytex has granted the underwriters an option, exercisable, in whole or in part, at any time on or within 30 days after closing, to purchase an additional 1,035,000 trust units at the same offering price which, if exercised, would increase the total gross proceeds to $115,057,500.

5. Full Description of Material Change:

5.1           Full Description of Material Change

Baytex announced that it has entered into a bought deal financing agreement with a syndicate of underwriters pursuant to which the syndicate has agreed to purchase 6,900,000 trust units at $14.50 per unit for total gross proceeds of $100,050,000.  The syndicate is led by TD Securities Inc. and includes CIBC World Markets Inc., National Bank Financial Inc., RBC Capital Markets, Scotia Capital Inc., Canaccord Capital Corporation, FirstEnergy Capital Corp., Raymond James Ltd., Peters & Co. Limited, Tristone Capital Inc., UBS Securities Canada Inc., Cormark Securities Inc. and Dundee Securities Corporation. Baytex has granted the underwriters an option, exercisable, in whole or in part, at any time on or within 30 days after closing, to purchase an additional 1,035,000 trust units at the same offering price which, if exercised, would increase the total gross proceeds to $115,057,500.  The net proceeds of the offering will be used for general corporate purposes.

The offering will be made in all provinces of Canada by way of a short form prospectus.  This offering is subject to customary regulatory approvals and is expected to close on or about April 14, 2009.  Purchasers of trust units under the offering who continue to hold such units, will be eligible to receive the distribution to be paid on May 15, 2009 to holders of record on April 30, 2009.

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 material change report 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").  Specifically, this material change report contains forward-looking statements relating to the use of the net proceeds of the offering, the filing of the short form prospectus, the closing date of the offering and the first distribution that purchasers of the trust units will be eligible to receive.    The forward-looking statements contained in this material change report speak only as of its date and are expressly qualified by this cautionary statement.

These forward-looking statements are based on certain key assumptions regarding, among other things, the timing of obtaining regulatory approvals.  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 which are discussed in Baytex's Annual Information Form and Management's Discussion and Analysis for the year ended December 31, 2008, as filed with Canadian securities regulatory authorities.

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.

5.2          Disclosure for Restructuring Transactions

Not Applicable.

6. Reliance on subsection 7.1(2) of National Instrument 51-102:

Not Applicable.

7. Omitted Information:

Not Applicable.

8. Executive Officer:

Derek Aylesworth, Chief Financial Officer of Baytex Energy Ltd., the administrator of Baytex.

Telephone:  (403) 538-3639

Facsimile:   (403) 205-3845

9. Date of Report

March 26, 2009.