Operations

Baytex’s year-end 2010 reserves are evaluated by Sproule Associates Limited (“Sproule”), the independent reserves evaluator for all of Baytex’s oil and gas properties, in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2010, which will be filed in late March 2011. The December 31, 2010 reserve disclosure herein excludes the 2011 Heavy Oil Acquisition.

Highlights of the 2010 reserve report include:

• Total proved reserves increased 8% to 140 million boe, while total proved plus probable reserves increased 16% to 229 million boe;
• Inclusive of acquisitions, replaced 297% of production, with finding, development and acquisition costs (“FD&A”) of $13.17 per boe for proved plus probable reserves including changes in FDC. Three-year average (2008 – 2010) FD&A costs are $15.92 per boe for proved plus probable reserves including changes in FDC;
• FD&A costs of $5.90 per boe for proved plus probable reserves excluding changes in FDC. Three-year average FD&A costs are $9.54 per boe for proved plus probable reserves excluding changes in FDC;
• Replaced 271% of production through exploration and development (“E&D”) activities alone, while reinvesting only approximately 52% of FFO into E&D;
• Reserve life index is 13.2 years for proved plus probable reserves and 8.1 years for proved reserves, based on year-end reserves and the mid-point of our 2011 production guidance as at December 31, 2010 of 47,500 boe/d;
• Year-end 2010 reserves are comprised of 91% oil (including NGLs) on a proved plus probable basis, and 90% oil (including NGLs) on a proved basis;
• Generated a recycle ratio (operating netback divided by FD&A costs) based on proved plus probable reserves (including changes in FDC) of 2.5x in 2010 and 2.0x for the three-year average; and
• Generated a recycle ratio based on proved plus probable reserves (excluding changes in FDC) of 5.6x in 2010 and 3.3x for the three-year average.
• Capital expenditures in 2010 totaled $284 million, with $237 million spent on exploration and development activities, and $47 million spent on property acquisitions (net of proceeds of disposition).

Heavy Oil

Year-end 2010 reserves reflect continued growth of our heavy oil reserves to 167 million barrels of proved plus probable reserves, an increase of 15% over 2009, and 105 million barrels of proved reserves, an increase of 8% over 2009.

At Seal, year-end 2010 proved reserves increased 44% to 45.0 million barrels and proved plus probable reserves increased 56% to 83.9 million barrels. Proved reserves consist of 39.9 million barrels of primary (cold) reserves and 5.1 million barrels of reserves from thermally-enhanced oil recovery (“TEOR”). There were no proved reserves from TEOR booked at Seal at year-end 2009. The proved plus probable reserves consist of 53.6 million barrels of primary (cold) reserves and 30.3 million barrels of reserves from TEOR. There were 8.2 million barrels of proved plus probable reserves from TEOR booked at Seal at year-end 2009. The steady reserve growth we have recorded since beginning development in 2005 is consistent with our view that this property holds significant long-term growth potential. At year-end 2010, primary (cold) reserves were included on only 21 of our 105 sections of oil sands leasehold at Seal, and thermal reserves were included on only 1.5 sections. The table below summarizes the steady reserve growth we have realized at Seal.

Seal Reserve Growth

	Dec 31 2005	Dec 31 2006	Dec 31 2007	Dec 31 2008	Dec 31 2009	Dec 31 2010
Reserves (MMbbl)
Total Proved	2.2	8.5	20.2	27.0	31.2	45.0
Proved plus Probable	4.0	13.0	28.7	39.2	54.7	83.9
Land Assigned Reserves
Sections (640 acres)	4	8	12	15	20	23

We will continue to focus on development of this potential at Seal, and note that Seal will attract a larger percentage of our 2011 capital budget than any other project in our asset portfolio. In 2011, we expect to drill approximately 20 horizontal wells at Seal, largely comprised of multi-lateral wells. In addition, we intend to re-enter several existing single-leg horizontal wells and drill additional horizontal legs at closer inter-well spacing to increase recovery from these older wells. We also intend to complete our first 10-well module of CSS development at Seal during 2011.

Light Oil and Natural Gas Liquids

In combination, our proved plus probable light oil and NGL reserves increased by approximately six million barrels, or 39%, to 40 million barrels at year-end 2010.

In our light oil resource plays, the year-end 2010 reserves report reflects a 78% increase in proved plus probable reserves to 22.0 million boe for our Bakken/Three Forks development in North Dakota and a 92% increase in proved plus probable reserves to 4.2 million boe for our Viking development project in southeastern Alberta. Our year-end 2010 report includes 2.5 million boe of proved plus probable reserves for our southwest Saskatchewan Viking oil resource play. There were no undeveloped reserves booked for the Viking in southwest Saskatchewan at year-end 2009.

Natural Gas

Natural gas reserves declined year-over-year by eight Bcf, or 6%, to 126 Bcf on a proved plus probable basis. During 2010, we directed our efforts and capital toward oil development, and our reduced natural gas weighting and reserves reflect this focus.

Petroleum and Natural Gas Reserves as at December 31, 2010

	Based on Forecast Prices and Costs
	Light Oil & NGLs		Heavy Oil		Natural Gas		Oil Equivalent
Reserve Category	Gross (mbbl)	Net (mbbl)	Gross (mbbl)	Net (mbbl)	Gross (bcf)	Net (bcf)	Gross (mboe)	Net (mboe)
Proved
Developed Producing	9,068	7,225	35,751	29,030	62.2	52.5	55,184	45,007
Developed Non-Producing	971	756	14,610	12,281	7.9	6.7	16,900	14,152
Undeveloped	11,201	9,369	54,618	46,073	13.7	11.1	68,106	57,290
Total Proved	21,241	17,350	104,978	87,384	83.8	70.3	140,190	116,449
Probable	19,158	15,820	62,435	51,284	43.5	36.1	88,835	73,118
Total Proved Plus Probable	40,399	33,170	167,414	138,668	127.3	106.4	229,025	189,567
Notes: "Gross" reserves means the total working and royalty interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others. "Net" reserves means Baytex's gross reserves less all royalties payable to others. Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

Reserve Reconciliation  

	Reconciliation of Gross Company Interest Reserves(1)(2) By Principal Product Type Forecast Prices and Costs
	Light and Medium Crude Oil			Heavy Oil
Reserve Category	Proved (mbbl)	Probable (mbbl)	Proved + Probable (mbbl)	Proved (mbbl)	Probable (mbbl)	Proved + Probable (mbbl)
December 31, 2009	14,568	10,233	24,801	97,054	48,542	145,596
Extensions	4,931	9,073	14,004	14,142	2,533	16,675
Discoveries	-	-	-	93	38	131
Improved Recoveries	-	-	-	1,641	19,058	20,699
Technical Revisions	(219)	(2,764)	(2,983)	1,314	(8,252)	(6,938)
Acquisitions	754	1,381	2,135	1,483	772	2,255
Dispositions	-	-	-	(102)	(34)	(136)
Economic Factors	43	19	62	(213)	(222)	(435)
Production	(1,660)	-	(1,660)	(10,434)	-	(10,434)
December 31, 2010	18,417	17,942	36,359	104,978	62,435	167,413

	Natural Gas Liquids			Natural Gas including solution gas
Reserve Category	Proved (mbbl)	Probable (mbbl)	Proved + Probable (mbbl)	Proved (mmcf)	Probable (mmcf)	Proved + Probable (mmcf)
December 31, 2009	2,817	1,501	4,318	89,659	44,090	133,748
Extensions	253	143	396	7,278	9,247	16,525
Discoveries	-	-	-	-	-	-
Improved Recoveries	-	-	-	-	-	-
Technical Revisions	554	(396)	158	11,088	(8,439)	2,648
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Economic Factors	(74)	(32)	(106)	(4,015)	(1,445)	(5,460)
Production	(726)	-	(726)	(20,185)	-	(20,185)
December 31, 2010	2,824	1,216	4,040	83,825	43,453	127,278

	Oil Equivalent (3)
Reserve Category	Proved (mboe)	Probable (mboe)	Proved + Probable (mboe)
December 31, 2009	129,382	67,624	197,007
Extensions	20,539	13,290	33,829
Discoveries	93	38	131
Improved Recoveries	1,641	19,058	20,699
Technical Revisions	3,497	(12,819)	(9,322)
Acquisitions	2,237	2,153	4,390
Dispositions	(102)	(34)	(136)
Economic Factors	(913)	(476)	(1,389)
Production	(16,184)	-	(16,184)
December 31, 2010	140,190	88,835	229,025

Notes:
(1)	Gross Company interest reserves include solution gas but do not include royalty interests.
(2)	Reserve information as at December 31, 2010 and 2009 is prepared in accordance with NI 51-101.
(3)	Oil equivalent 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 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Summary of 2010 Net Present Values of Future Net Revenue

	Reserve Value (C$Millions) Before Tax and discounted at (%/year):
Reserve Category	0%	5%	10%	15%	20%
Proved
Developed Producing	2,037	1,684	1,461	1,305	1,188
Developed Non-Producing	617	453	347	274	223
Undeveloped	2,299	1,599	1,173	897	709
Total Proved	4,953	3,736	2,980	2,476	2,120
Probable	3,245	1,836	1,195	851	643
Total Proved Plus Probable	8,197	5,572	4,175	3,327	2,763
Notes: Reserve value at December 31, 2010, as evaluated by Sproule Associates Limited. The net present values noted in the table above do not include any value for future net revenue which may ultimately be generated from the contingent resources discussed later in this press release.

Capital Efficiencies

	2010	2009	2008	3 Year Average 2008 - 2010
Excluding Future Development Costs
FD&A costs - Proved ($/boe)
Exploration and development	$9.54	$12.54	$14.26	$11.50
Acquisitions (net of dispositions)	21.84	21.27	22.99	22.32
Total	$10.52	$15.45	$18.37	$14.57
FD&A costs – Proved plus Probable ($/boe)
Exploration and development	$5.41	$9.25	$10.53	$7.39
Acquisitions (net of dispositions)	10.96	16.70	15.83	15.35
Total	$5.90	$11.63	$13.11	$9.54
Operating netback per boe	$32.79	$27.64	$33.76	$31.42
Recycle ratio based on operating netback
Proved plus Probable	5.6	2.4	2.6	3.3
Reserve replacement ratio
Proved plus Probable	165%	233%	274%	222%
Including Future Development Costs
FD&A costs – Proved ($/boe)
Exploration and development	$15.22	$22.96	$11.01	$16.06
Acquisitions (net of dispositions)	32.71	28.28	27.87	28.52
Total	$16.61	$24.73	$18.95	$19.59
FD&A costs – Proved plus Probable ($/boe)
Exploration and development	$12.44	$20.01	$12.09	$14.00
Acquisitions (net of dispositions)	20.68	23.12	20.23	21.09
Total	$13.17	$21.00	$16.06	$15.92
Recycle ratio based on operating netback
Proved plus probable	2.5	1.3	2.1	2.0
Notes: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. Recycle ratio is calculated as operating netback divided by FD&A costs (prove plus probable excluding FDC). Operating netback is calculated as revenue minus royalties, operating expenses and transportation expenses. Reserve replacement ratio is calculated as total reserves added in the year divided by production for the same year.

Reserve Life Index

	2011	Reserve Life Index (years)
	Production Target	Total Proved	Proved Plus Probable
Oil and NGL (bbl/d)	39,500	8.8	14.4
Natural Gas (mmcf/d)	48.0	4.8	7.3
Oil Equivalent (boe/d)	47,500	8.1	13.2

Please refer to our 2010 Annual Information Form which will be filed on SEDAR by the end of March for complete reserves disclosure.

Sproule December 31, 2010 Forecast Prices  

Year	WTI Cushing US$/bbl	Edmonton Par Price C$/bbl	Hardisty Heavy 12 API C$/bbl	AECO C-Spot C$/MMbtu	Inflation Rate %/Yr	Exchange Rate $US/$Cdn
2010 act.	79.43	77.81	62.29	4.16	1.5%	0.97
2011	88.40	93.08	74.46	4.04	1.5%	0.93
2012	89.14	93.85	75.08	4.66	1.5%	0.93
2013	88.77	93.43	72.87	4.99	1.5%	0.93
2014	88.88	93.54	71.09	6.58	1.5%	0.93
2015	90.22	94.95	72.16	6.69	1.5%	0.93
2016	91.57	96.38	73.25	6.80	1.5%	0.93
2017	92.94	97.84	74.36	6.91	1.5%	0.93
2018	94.34	99.32	75.48	7.02	1.5%	0.93
2019	95.75	100.81	76.62	7.14	1.5%	0.93
2020	97.19	102.34	77.78	7.26	1.5%	0.93

Future Development Costs  

Year	Proved Reserves ($000s)	Proved Plus Probable Reserves ($000s)
2011	255,592	327,459
2012	194,056	282,761
2013	103,985	200,014
2014	75,809	150,146
2015	54,939	152,561
Remaining	95,550	107,349
Total (Undiscounted)	779,931	1,220,290

Year-End Reserves and Reserve Life Index Pro Forma 2011 Heavy Oil Acquisition

On February 3, 2011, Baytex completed an acquisition of heavy oil assets located in the Seal area of northern Alberta and the Lloydminster area of western Saskatchewan. The assets were acquired through a combination of a corporate acquisition of a private company and an asset acquisition. The reserves attributed to the 2011 Heavy Oil Acquisition have been evaluated by Sproule effective January 1, 2011. The following tables highlight Baytex’s reserves pro forma the 2011 Heavy Oil acquisition.
	Baytex Reserves Pro forma 2011 Heavy Acquisition Forecast Prices and Costs
Reserve Category	Baytex	Acquisition	Pro forma
Heavy Oil (mbbl)
Proved	104,978	6,201	111,179
Proved Plus Probable	167,414	10,501	177,915
Light Oil and Natural Gas Liquids (mbbl)
Proved	21,241	-	21,241
Proved Plus Probable	40,399	-	40,339
Natural Gas (mmcf)
Proved	83,865	-	83,825
Proved Plus Probable	127,278	-	127,278
Oil Equivalent (mboe)
Proved	140,189	6,201	146,390
Proved Plus Probable	229,025	10,501	239,506

The following table sets forth our reserve life index based on pro forma total proved and pro forma proved plus probable reserves and the mid-point of our 2011 production guidance of 49,500 boe/d, as it was updated following the 2011 Heavy Oil Acquisition.
	Reserve Life Index (years)
	2011 Production Target	Total Proved	Proved Plus Probable
Oil and NGL (bbl/d) Natural	41,500	8.7	14.4
Gas (mmcf/d)	48.0	4.8	7.3
Oil Equivalent (boe/d)	49,500	8.1	13.3