ex99_1.htm

EX-99.1 2 ex99_1.htm THIRD QUARTER REPORT 2011 ex99_1.htm

Exhibit 99.1

SUMMARY

●

Produced record quarterly production of 52,625 boe/d in Q3/2011 (an increase of 10% over Q2/2011 and 17% over Q3/2010);

●

Generated funds from operations (“FFO”) of $144.8 million ($1.24 per basic share) in Q3/2011, the second highest level of quarterly FFO in the history of Baytex, and an increase of 5% over Q2/2011 and 31% over Q3/2010;

●

Generated net income of $52 million ($0.45 per basic share) in Q3/2011;

●

Maintained a cash payout ratio in Q3/2011 of 35% net of dividend reinvestment plan (“DRIP”) participation;

●

Closed a previously announced natural gas acquisition in west-central Alberta to consolidate non-operated interests at attractive acquisition metrics; and

●

Subsequent to the end of the third quarter, entered into definitive agreements to sell certain primarily-undeveloped lands in Alberta and Saskatchewan for $47.1 million.

	Three Months Ended								Nine Months Ended
	September 30, 2011		June 30, 2011			September 30, 2010			September 30, 2011		September 30, 2010
FINANCIAL (thousands of Canadian dollars, except per common share or unit amounts)
Petroleum and natural gas sales		313,787		336,899			238,276			941,001		741,639
Funds from operations(1)		144,825		138,233			110,954			392,510		324,494
Per share or unit – basic		1.24		1.20			0.99			3.40		2.93
Per share or unit – diluted		1.22		1.17			0.96			3.31		2.83
Cash dividends or distributions declared(2)		50,270		52,764			45,795			155,035		141,698
Cash dividends or distributions declared per share or unit		0.60		0.60			0.54			1.80		1.62
Net income		51,839		106,863			23,319			159,652		210,260
Per share or unit – basic		0.45		0.92			0.21			1.38		1.90
Per share or unit – diluted		0.44		0.90			0.20			1.35		1.84
Exploration and development		100,368		108,453			59,559			295,835		172,269
Property acquisitions		28,502		(185	)		11,452			65,835		19,316
Corporate acquisition		22		1,325			–			118,693		40,314
Proceeds from divestitures		–		–			(18,137	)		–		(18,137	)
Total oil and natural gas capital expenditures		128,892		109,593			52,874			480,363		213,762
Bank loan		368,184		315,073			314,567			368,184		314,567
Convertible debentures		–		–			5,057			–		5,057
Long-term debt		305,835		294,645			150,000			305,835		150,000
Working capital deficiency		65,180		72,621			72,616			65,180		72,616
Total monetary debt(3)		739,199		682,339			542,240			739,199		542,240

Notes:

(1)

Funds from operations is a non-GAAP measure that represents cash generated from operating activities adjusted for finance costs, changes in non-cash operating working capital and other operating items. Baytex’s funds from operations may not be comparable to other issuers. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends and capital investments. For a reconciliation of funds from operations to cash flow from operating activities, see Management’s Discussion and Analysis of the operating and financial results for the three months and nine months ended September 30, 2011.

(2)	Cash dividends or distributions declared are net of DRIP participation.

(3)

Total monetary debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred income tax assets or liabilities and unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and the balance sheet amount of any convertible debentures and long-term bank loans.

	Three Months Ended						Nine Months Ended
	September 30, 2011		June 30, 2011		September 30, 2010		September 30, 2011		September 30, 2010
OPERATING
Daily production
Light oil and NGL (bbl/d)		7,170		6,055		6,600		6,612		6,567
Heavy oil (bbl/d)		37,280		33,839		28,959		34,324		28,172
Total oil and NGL (bbl/d)		44,450		39,894		35,559		40,936		34,739
Natural gas (mmcf/d)		49.0		47.8		55.4		49.3		56.2
Oil equivalent (boe/d @ 6:1)(1)		52,625		47,853		44,799		49,147		44,113
Average prices (before hedging)
WTI oil (US$/bbl)		89.76		102.56		76.20		95.48		77.65
Edmonton par oil ($/bbl)		92.45		102.63		74.43		94.85		76.73
BTE light oil and NGL ($/bbl)		80.48		89.11		63.13		81.53		65.18
BTE heavy oil ($/bbl)(2)		59.92		71.02		57.97		63.45		59.15
BTE total oil and NGL ($/bbl)		63.26		73.78		58.93		66.45		60.29
BTE natural gas ($/mcf)		4.20		4.36		3.89		4.25		4.47
BTE oil equivalent ($/boe)		57.31		65.84		51.59		59.61		53.18
USD/CAD noon rate at period end		0.9626		1.0370		0.9711		0.9626		0.9711
USD/CAD average rate for period		1.0220		1.0334		0.9624		1.0231		0.9654
COMMON SHARE OR TRUST UNIT INFORMATION
TSX
Share or Unit price (Cdn$)
High	$	55.93	$	58.76	$	37.86	$	58.76	$	37.86
Low	$	41.71	$	47.59	$	31.27	$	41.71	$	27.72
Close	$	43.81	$	52.72	$	37.27	$	43.81	$	37.27
Volume traded (thousands)		27,710		22,857		21,917		84,765		72,806
NYSE
Share or Unit price (US$)
High	$	59.04	$	61.95	$	36.90	$	61.95	$	36.90
Low	$	40.31	$	48.63	$	25.64	$	40.31	$	25.64
Close	$	41.67	$	54.44	$	36.33	$	41.67	$	36.33
Volume traded (thousands)		11,771		9,851		4,514		29,806		16,258
Common shares or trust units outstanding (thousands)		116,755		116,004		112,333		116,755		112,333

Notes:

(1)

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. The use of boe amounts 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.

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

Forward-Looking Statements

This report contains forward-looking statements relating to: our average production rate for 2011; our product mix for 2011; our exploration and development capital expenditures for 2011; initial production rates from wells drilled; development plans for our properties, including the number of wells to be drilled in the fourth quarter of 2011; our Cliffdale cyclic steam stimulation project at Seal, including our assessment of the results of the third steam injection cycle for our pilot well, the steam-oil ratio for the third steam injection cycle and the completion of a 10-well commercial module of CSS development, including the commencement of steam injection into four additional wells and the drilling of five additional CSS wells; our Kerrobert steam- assisted gravity drainage project, including the steam-oil ratio, our ability to optimize the placement of SAGD well pairs by drilling stratigraphic test wells and the expansion of the steam plant; the natural gas-weighted acquisition in west-central Alberta, including the 2011 net operating income from the acquired assets and the remaining proved plus probable reserves attributable to the acquired assets; the completion of the disposition of assets in the Dodsland area of Saskatchewan; the demand for Canadian heavy oil by U.S. refiners; the outlook for the pricing differential between Canadian heavy oil and West Texas Intermediate; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; the amount of our undrawn credit facilities at September 30, 2011; our debt to FFO ratio; our liquidity and financial capacity; and the sufficiency of our financial resources to fund our operations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. The level of future cash dividends will depend on the amount of funds from operations generated by our operations and our prevailing financial circumstances at the time. We refer you to the end of the Management’s Discussion and Analysis section of this report for our advisory on forward-looking statements.

Non-GAAP Financial Measures

In this report we refer to certain measures that are commonly used in the oil and gas industry but are not based on generally accepted accounting principles in Canada, such as funds from operations and total monetary debt. For a description of these measures, we refer you to “Non-GAAP Financial Measures” in the Management’s Discussion and Analysis section of this report.

All amounts in this report are stated in Canadian dollars unless otherwise noted.

MESSAGE TO SHAREHOLDERS

Operations Review

Production averaged 52,625 boe/d during the third quarter of 2011, as compared to 44,799 boe/d in the third quarter of 2010 and 47,853 boe/d in the second quarter of 2011. Oil-equivalent production increased by 17% from the third quarter of 2010, with oil and natural gas liquids (“NGL”) production 25% higher and natural gas production 12% lower. Oil equivalent production increased by 10% from the second quarter of 2011, with oil and NGL production 11% higher and natural gas production 3% higher.

Capital expenditures for exploration and development activities totaled $100.4 million for the third quarter of 2011. During the third quarter, Baytex participated in the drilling of 48 (39.4 net) wells, resulting in 46 (37.4 net) oil wells and two (2.0 net) service wells for a 100% success rate.

In our Lloydminster heavy oil area, we drilled 19 (19.0 net) oil wells and two (2.0 net) service wells. In our Seal heavy oil area, we drilled seven (7.0 net) horizontal cold production wells. In our light oil and gas areas in western Canada, we drilled 15 (9.9 net) oil wells. We drilled five (1.5 net) oil wells in our Bakken/Three Forks play in North Dakota.

Our previous production guidance for 2011 was a range of 49,500 to 50,500 boe/d. Based on production performance for the first nine months of 2011, we can now narrow our full-year 2011 guidance to a range of 50,000 to 50,500 boe/d. We continue to project that our production mix will be comprised of approximately 70% heavy oil, 14% light oil and NGL and 16% natural gas. Our exploration and development capital budget for 2011 remains at $355 million. We plan to provide production and capital budget guidance for 2012 on or about December 6, 2011, following approval of our 2012 development plan by our Board of Directors.

Heavy Oil

In the third quarter of 2011, heavy oil production averaged 37,280 bbl/d, an increase of 29% over the third quarter of 2010 and 10% over the second quarter of 2011. During the third quarter of 2011, we drilled 26 (26.0 net) oil wells and two (2.0 net) service wells on our heavy oil properties for a success rate of 100%.

Production from our Seal properties averaged approximately 17,800 bbl/d, an increase of 24% from the second quarter of 2011. In the third quarter of 2011, we drilled seven (7.0 net) cold horizontal producers at Seal, including our first drilling on the Reno-area properties acquired earlier this year. Our most common multi-lateral well design includes eight approximately 1,400 meter-long laterals, which are often augmented with several shorter “stubby” laterals to drain the region around the intermediate casing point to the starting point of the 1,400 meter-long laterals. Three of the wells drilled in the third quarter and two of the wells drilled in the second quarter established average 30-day peak production rates of approximately 340 bbl/d per well. Although we have not yet recorded a 30-day peak production rate on any wells drilled on the lands acquired at Reno earlier this year, the first two wells drilled have initial production rates averaging approximately 375 bbl/d per well, based on the first two weeks of production. The two Reno wells had an average of six full-length horizontal laterals per well, plus an average of four “stubbies” per well. During the remainder of 2011, we plan to drill approximately five additional multi-lateral cold horizontal wells at Seal.

In our Cliffdale cyclic steam stimulation (“CSS”) project at Seal, we continued production operations during the pilot well’s third cycle. Consistent with our numerical reservoir simulation, we project a steam-oil ratio (“SOR”) of approximately 1.9 for this cycle. Four additional CSS-project wells drilled in the first quarter continued pre-steam cold production in the third quarter at rates of approximately 20 bbl/d per well, while awaiting completion of our steam generation facility. We have now received regulatory approvals to install oil and water handling facilities and steam distribution piping at our Cliffdale facility. Construction has commenced, and we expect to begin steam injection late in the fourth quarter of 2011. To complete our first 10-well commercial CSS module, we also plan to drill an additional five horizontal CSS wells in the fourth quarter of 2011.

At our Kerrobert steam-assisted gravity drainage (“SAGD”) project, the well pair which commenced production in October 2010 continues to operate at oil rates in excess of 800 bbl/d. Two additional SAGD well pairs were drilled during the second quarter and placed on production in the third quarter at average rates of approximately 950 bbl/d per well. Current SOR for the Kerrobert SAGD project is 2.4. We drilled two stratigraphic test wells in the third quarter and plan to drill two additional stratigraphic test wells in the fourth quarter to optimize the placement of future SAGD well pairs. Design work is being conducted for steam plant expansion to allow the drilling of additional SAGD well pairs.

Light Oil & Natural Gas

During the third quarter of 2011, light oil, NGL and natural gas production averaged 15,345 boe/d, which was comprised of 7,170 bbl/d of light oil and NGL and 49.0 mmcf/d of natural gas. Compared to the third quarter of 2010, light oil and NGL production increased by 9% and natural gas production declined by 12%. Compared to the second quarter of 2011, light oil and NGL production increased by 18% and natural gas production increased by 3%.

In the third quarter of 2011, we drilled five (4.0 net) Viking multi-lateral wells in eastern Alberta. Two of the wells drilled in the third quarter and two of the wells drilled in the second quarter established average 30-day peak rates of approximately 120 bbl/d per well. We plan to drill two more Viking light oil horizontal wells in eastern Alberta in the fourth quarter of 2011.

We drilled three Viking light oil horizontal wells in Saskatchewan in the third quarter, two of which were fracture-stimulated and commenced production early in the fourth quarter but have not yet established 30-day peak rates. One of the Saskatchewan Viking wells was an unstimulated five-lateral well which had a 30-day peak production rate of approximately 20 bbl/d.

We participated in seven (2.9 net) Cardium light oil horizontal wells in the third quarter, two of which were operated. The operated wells will be fracture-stimulated and put on production in the fourth quarter.

In our Bakken/Three Forks play in North Dakota, in the third quarter we participated in the drilling of five (1.5 net) horizontal oil wells, four of which were Baytex-operated, and the fracture-stimulation of six wells. During the third quarter, three operated 640-acre spacing wells established average 30-day peak production rates of 350 bbl/d per well and one operated 1,280-acre spacing well established an average 30-day peak production rate of 430 bbl/d. We plan to participate in the drilling of approximately seven (2.0 net) additional Bakken/Three Forks wells in the fourth quarter.

Acquisition and Divestiture Activity

As previously announced, in the third quarter we closed the acquisition of predominantly natural gas assets located in the Brewster area of west-central Alberta. Prior to the acquisition, we had non-operated interests in most of these assets. As a result of the acquisition, we are now the operator of all of the acquired assets. The total consideration for the acquisition (net of adjustments) was $22.4 million, which was funded by drawing on our credit facilities. The purchase price is a multiple of approximately three times projected net operating income from the acquired properties for 2011. The acquired assets are producing approximately 800 boe/d of production (80% natural gas). We estimate remaining proved plus probable reserves to be approximately 2.5 million boe. The acquired assets include 72,000 net acres of undeveloped land, a 64 kilometer gathering system and two compressor stations.

Subsequent to the end of the third quarter, we entered into and closed the sale of six sections of leasehold, including five sections with Duvernay rights, in the Kaybob South area of west central Alberta for $11.1 million. Five of the six sections faced lease expiry within the next year. There is no production on the divested lands.

Subsequent to the end of the third quarter, we entered into a definitive agreement to sell approximately 32,600 net acres of leasehold in the “halo” of the Dodsland field in southwest Saskatchewan for $36 million. As at December 31, 2010, the properties had booked proved plus probable reserves of approximately 1.5 million boe (9% proved developed producing). Current production from the lands is approximately 60 bbls/day. This disposition is expected to close on or about November 25, 2011. After the sale, we will continue to hold significant undeveloped land for Viking light oil development in the Kerrobert and Whiteside areas of southwest Saskatchewan.

Financial Review

The financial statements for the third quarter of 2011 have been prepared in accordance with International Financial Reporting Standards (“IFRS”). Comparative periods in 2010 have been restated to conform to IFRS presentation. Reconciliations from IFRS to the previously reported financial results are shown in the notes to our interim condensed consolidated financial statements. The adoption of IFRS did not have a material impact on the amounts reported as FFO.

We generated FFO of $145 million ($1.24 per basic share) in the third quarter of 2011, an increase of 31% compared to the third quarter of 2010, and an increase of 5% compared to the second quarter of 2011. The increase in FFO relative to the second quarter of 2011 is primarily the result of increased sales volumes which more than offset the lower commodity prices realized in the third quarter. Consistent with our practice prior to the adoption of IFRS, FFO is presented net of financing costs, which totaled $10.4 million in the third quarter.

The average WTI price for the third quarter of 2011 was US$89.76/bbl, an 18% increase from the third quarter of 2010, and a 12% decrease from the second quarter of 2011. We received an average oil and NGL price of $63.26/bbl in the third quarter of 2011 (inclusive of our physical hedging gains), up from $58.93/bbl for the third quarter of 2010 and down from $73.78/bbl for the second quarter of 2011. We received an average natural gas price of $4.20/mcf in the third quarter of 2011, a modest decrease from the second quarter of 2011.

The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 19.6% for the third quarter of 2011, as compared to 20.6% in the third quarter of 2010 and 17.2% in the second quarter of 2011. Looking forward, demand for Canadian heavy oil by US refiners in the midcontinent region is expected to increase in late 2011 through 2013 with the commissioning of heavy oil refining projects in the region. The impact of those refining projects is already being noted in the market, as the current heavy oil differential is approximately 12% of WTI, and the forward markets are suggesting similar levels for the first half of 2012.

Baytex continues to actively hedge its exposure to commodity prices, heavy oil differentials and interest and foreign exchange rates with the objective of reducing the volatility of its funds from operations, which are used to finance capital expenditures and dividend payments. Contracts currently in place have locked in pricing on approximately 24% of our 2012 WTI price, 22% of our heavy oil differential exposure, 32% of our natural gas price exposure, and 19% of our exposure to currency movements between the Canadian and US dollar. Details of those contracts are contained in the notes to our interim condensed consolidated financial statements. We continue to monitor the markets for opportunities to add to this hedging program for 2012 and later years.

At the end of the third quarter of 2011, total monetary debt was $739 million and undrawn credit facilities were $332 million. This level of debt represents a debt-to-FFO ratio of 1.4 times, based on trailing twelve months FFO. This level of debt and undrawn credit facilities are within our leverage and liquidity targets, and provide ample capacity to finance our operations.

Conclusion

We continued to execute our sustainable growth-and-income model in the third quarter of 2011.

We maintained our record of continuous production growth that has been in place since the beginning of 2009. Oil production was particularly strong, with a 10% increase over the second quarter of 2011 and a 17% increase over the third quarter of 2010. Together with the monthly income provided by our dividends, we think that our oil growth can be a meaningful contributor to our total return to shareholders.

We announced two minor divestitures of largely undeveloped land, one of which has already closed. These divestitures, coupled with occasional acquisitions, reflect our practice of continuously evaluating and improving the suitability and quality of our asset portfolio. The proceeds from these divestitures will reduce our leverage ratios, helping to maintain our conservative financial structure.

With respect to mid-stream infrastructure, although a decision by the U.S. Government regarding TransCanada’s Keystone XL Pipeline has been delayed, there are competing proposals that have the potential to move Canadian heavy oil into the U.S. Gulf Coast market. While we await these longer-term pipeline projects, new initiatives in the form of rail and pipeline reversals are helping to maintain a positive outlook for heavy oil differentials.

It remains an honour to serve you, and we want to express our appreciation for your continued support as we move forward in executing our plan for long-term value creation.

Anthony W. Marino

President and Chief Executive Officer

November 10, 2011

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months and nine months ended September 30, 2011. This information is provided as of November 9, 2011. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The third quarter results have been compared with the corresponding period in 2010. This MD&A should be read in conjunction with the Company’s condensed interim unaudited consolidated financial statements (“consolidated financial statements”) for the three months and nine months ended September 30, 2011 and 2010, and its audited consolidated comparative financial statements for the years ended December 31, 2010 and 2009, together with accompanying notes, and the Annual Information Form for the year ended December 31, 2010. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com. The consolidated financial statements for the third quarter of 2011 are prepared in accordance with International Financial Reporting Standards (“IFRS”). Comparative periods in 2010 have been restated to conform to IFRS presentation. Reconciliations from IFRS to Canadian general accepted accounting principles (“previous GAAP”) are shown in the notes to our consolidated financial statements. The adoption of IFRS did not have a material impact on the amounts reported as funds from operations. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share or per trust unit amounts or as otherwise noted.

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.

Corporate Conversion

At year end 2010, Baytex Energy Trust (the “Trust”) completed a plan of arrangement under the Business Corporations Act (Alberta) pursuant to which it converted its legal structure from an income trust to a corporation (the “Corporate Conversion”). Pursuant to the Corporate Conversion: (i) on December 31, 2010, holders of trust units of the Trust exchanged their trust units for our common shares on a one-for-one basis; and (ii) on January 1, 2011, the Trust was dissolved and terminated, with the result that we became the successor to the Trust. The reorganization into a corporation has been accounted for on a continuity of interest basis, and accordingly, the consolidated financial statements reflect the financial position, results of operations and cash flows as if the Company had always carried on the business formerly carried on by the Trust.

Despite the change in legal structure from a trust to a corporation, the Company’s business objectives and strategies remain unchanged and the officers and directors remained the same. Baytex’s business objectives are directed towards growing its production and asset base through internal property development and acquisitions with the objectives of providing monthly income to its shareholders and creating long-term value for its shareholders. To achieve these objectives, Baytex intends to invest capital to enhance the value of its assets, operate its producing petroleum and natural gas properties in a low cost manner while maximizing the recovery of reserves, and pay monthly dividends to shareholders.

Baytex will continue to direct its efforts to increase the value of its assets through development drilling and associated development activities and enhanced oil recovery activities. Baytex will also seek to acquire undeveloped and producing petroleum and natural gas properties and primarily participate in development activities that are generally considered to be lower risk. Also, a minor percentage of each year’s capital budget will be devoted to moderate risk development and lower risk exploration opportunities on its properties.

The common shares of Baytex trade on the Toronto Stock Exchange and the New York Stock Exchange under the trading symbol BTE. Beginning with the January 31, 2011 record date, shareholders of Baytex will receive payments in the form of dividends. Prior to the Corporate Conversion on December 31, 2010, unitholders of the Trust received payments in the form of distributions.

Non-GAAP Financial Measures

In this MD&A, we refer to certain financial measures (such as funds from operations, payout ratio, total monetary debt and operating netback) which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada (“GAAP”). While funds from operations, payout ratio and operating netback are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures for other issuers.

Funds from Operations

We define funds from operations as cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. However, funds from operations should not be construed as an alternative to traditional performance measures determined in accordance with IFRS or previous GAAP, such as cash flow from operating activities and net income. For a reconciliation of funds from operations to cash flow from operating activities, see “Funds from Operations, Payout Ratio and Dividends or Distributions”.

Payout Ratio

We define payout ratio as cash dividends (net of participation in our dividend reinvestment plan) divided by funds from operations. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to Shareholders and capital investments.

Total Monetary Debt

We define total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred income tax assets or liabilities and unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and the balance sheet amount of any convertible debentures and long-term bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

Operating Netback

We define operating netback as product revenue less royalties, operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. We believe that this measure assists in evaluating the specific operating performance by product.

RESULTS OF OPERATIONS

Production

	Three Months Ended September 30									Nine Months Ended September 30
	2011			2010			Change			2011			2010			Change
Daily Production
Light oil and NGL (bbl/d)		7,170			6,600			9	%		6,612			6,567			1	%
Heavy oil (bbl/d)(1)		37,280			28,959			29	%		34,324			28,172			22	%
Natural gas (mmcf/d)		49.0			55.4			(12	%)		49.3			56.2			(12	%)
Total production (boe/d)		52,625			44,799			17	%		49,147			44,113			11	%
Production Mix
Light oil and NGL		14	%		15	%		–			13	%		15	%		–
Heavy oil		71	%		65	%		–			70	%		64	%		–
Natural gas		15	%		20	%		–			17	%		21	%		–

(1)

Heavy oil sales volumes may differ from reported production volumes due to changes to Baytex’s heavy oil inventory. For the three months ended September 30, 2011, heavy oil sales volumes were 369 bbl/d lower than production volumes (three months ended September 30, 2010 – 10 bbl/d lower). For the nine months ended September 30, 2011, heavy oil sales volumes were 89 bbl/d higher than production volumes (nine months ended September 30, 2010 – 75 bbl/d higher).

Production for the three months ended September 30, 2011 averaged 52,625 boe/d, as compared to 44,799 boe/d for the same period in 2010. Light oil and natural gas liquids (“NGL”) production for the third quarter of 2011 increased by 9% to 7,170 bbl/d from 6,600 bbl/d due to development activities in the US, which increased production by 95%, as compared to the same quarter in 2010. Heavy oil production for the third quarter of 2011 increased by 29% to 37,280 bbl/d from 28,959 bbl/d a year ago primarily due to development activities and the acquisition of producing assets in the first quarter of 2011. Natural gas production decreased by 12% to 49.0 mmcf/d for the third quarter of 2011, as compared to 55.4 mmcf/d for the same period last year primarily due to natural declines as we focused our drilling effort on our oil portfolio, partially offset by a natural gas-weighted acquisition that closed in the third quarter of 2011.

Production for the nine months ended September 30, 2011 averaged 49,147 boe/d, as compared to 44,113 boe/d for the same period in 2010. Light oil and NGL production for the nine months ended September 30, 2011 increased by 1% to 6,612 bbl/d from 6,567 bbl/d a year earlier due to development activities in the US, which increased US production by 75%, as compared to the same period in 2010. This increase was partially offset by second quarter production interruptions in North Dakota, Alberta and British Columbia. Heavy oil production for the nine months ended September 30, 2011 increased by 22% to 34,324 bbl/d from 28,172 bbl/d a year ago primarily due to development activities and the acquisition of producing assets in the first quarter of 2011. Natural gas production decreased by 12% to 49.3 mmcf/d for the nine months ended September 30, 2011, as compared to 56.2 mmcf/d for the same period last year primarily due to natural declines as we focused our drilling effort on our oil portfolio, partially offset by a natural gas-weighted acquisition that closed in the third quarter of 2011.

Commodity Prices

Crude Oil

For the first nine months of 2011, the prompt price of WTI fluctuated between a low of US$79.20/bbl and a high of US$113.93/bbl. This was a period of significant volatility, as oil prices reacted to rapidly changing macroeconomic issues and uncertainty, political and social unrest, and underlying energy market fundamentals. After rallying early in the third quarter of 2011, the WTI price declined on renewed macroeconomic concerns, a US budget stalemate and the release of 60 million barrels of oil from emergency stock by the International Energy Agency. During the third quarter of 2011, the prompt WTI price ranged from a high of US$99.87/bbl to a low of US$79.20/bbl at September 30, 2011. The average WTI price in the third quarter of 2011 was US$89.76/bbl, compared to the second quarter of 2011 average price of US$102.56/bbl. Also during the third quarter of 2011, the discount for WTI crude to Brent crude continued to widen, at times exceeding US$25/bbl, due to market expectations of an increasing transportation bottleneck out of Cushing, Oklahoma.

The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged nearly 20% in third quarter of 2011, compared to 17% for second quarter of 2011. This increase in WCS differentials from second quarter levels was largely due to the effect of declining WTI prices. As the WCS differential is set a month prior to the delivery of heavy crude, a decline in the WTI price after the WCS differential is set results in a wider percentage differential of WCS to WTI. During the nine months ended September 30, 2011, the WCS heavy oil price differential was 20% as compared to 17% in the first nine months of 2010.

Natural Gas

For the three months ended September 30, 2011, AECO natural gas prices averaged $3.72/mcf, unchanged from the same period of 2010. After rallying early in the third quarter, natural gas prices trended lower over the remainder of the third quarter due to increasing US gas production and expectations of higher gas storage levels. For the nine months ended September 30, 2011, the average AECO natural gas price was $3.75/mcf, as compared to $4.31/mcf in the same period last year.

	Three Months Ended September 30									Nine Months Ended September 30
	2011			2010			Change			2011			2010			Change
Benchmark Averages
WTI oil (US$/bbl)(1)	$	89.76		$	76.20			18	%	$	95.48		$	77.65			23	%
WCS heavy oil (US$/bbl)(2)	$	72.14		$	60.55			19	%	$	76.10		$	64.72			18	%
Heavy oil differential(3)		(20	%)		(21	%)		–			(20	%)		(17	%)		–
USD/CAD average exchange rate		1.0220			0.9624			6	%		1.0231			0.9654			6	%
Edmonton par oil ($/bbl)	$	92.45		$	74.43			24	%	$	94.85		$	76.73			24	%
AECO natural gas price ($/mcf)(4)	$	3.72		$	3.72			–	%	$	3.75		$	4.31			(13	%)
Baytex Average Sales Prices
Light oil and NGL ($/bbl)	$	80.48		$	63.13			27	%	$	81.53		$	65.18			25	%
Heavy oil ($/bbl)(5)	$	59.12		$	57.59			3	%	$	62.53		$	60.28			4	%
Physical forward sales contracts gain (loss) ($/bbl)		0.80			0.38						1.01			(1.13	)
Heavy oil, net ($/bbl)	$	59.92		$	57.97			3	%	$	63.54		$	59.15			7	%
Total oil and NGL, net ($/bbl)	$	63.26		$	58.93			7	%	$	66.45		$	60.29			10	%
Natural gas ($/mcf)(6)	$	3.89		$	3.76			3	%	$	3.95		$	4.38			(10	%)
Physical forward sales contracts gain ($/mcf)		0.31			0.13						0.30			0.09
Natural gas, net ($/mcf)	$	4.20		$	3.89			8	%	$	4.25		$	4.47			(5	%)
Summary
Weighted average ($/boe)(6)	$	56.32		$	51.11			10	%	$	58.45		$	53.90			8	%
Physical forward sales contracts gain (loss) ($/boe)		0.99			0.48						1.16			(0.72	)
Weighted average, net ($/boe)	$	57.31		$	51.59			11	%	$	59.61		$	53.18			12	%

(1)	WTI refers to the calendar monthly average based on NYMEX prompt month WTI.

(2)	WCS refers to the average posting price for the benchmark WCS heavy oil.

(3)	Heavy oil differential refers to the WCS discount to WTI.

(4)	AECO refers to the AECO monthly index price published by the Canadian Gas Price Reporter.

(5)	Baytex’s realized heavy oil prices are calculated based on sales volumes, net of blending costs.

(6)

Baytex’s risk management strategy employs both oil and natural gas financial and physical forward contracts (fixed price forward sales and collars) and heavy oil differential physical delivery contracts (fixed price and percentage of WTI). The above pricing information in the table excludes the impact of financial derivatives.

During the third quarter of 2011, Baytex’s average sales price for light oil and NGL was $80.48/bbl, up 27% from $63.13/bbl in the third quarter of 2010. Baytex’s realized heavy oil price during the third quarter of 2011, prior to physical forward sales contracts, was $59.12/bbl, or 84% of WCS. This compares to a realized heavy oil price in the third quarter of 2010, prior to physical forward sales contracts, of $57.59/bbl, or 92% of WCS. The differential to WCS largely reflects the cost of blending Baytex’s heavy oil with diluent to meet pipeline specifications. Net of physical forward sales contracts, Baytex’s realized heavy oil price during the third quarter of 2011 was $59.92/bbl, up 3% from $57.97/bbl in the third quarter of 2010. Baytex’s realized natural gas price for the three months ended September 30, 2011 was $3.89/mcf prior to physical forward sales contracts and $4.20/mcf inclusive of physical forward sales contracts (three months ended September 30, 2010 – $3.76/mcf prior to physical forward sales contracts and $3.89/mcf inclusive of physical forward sales contracts).

For the first nine months of 2011, Baytex’s average sales price for light oil and NGL was $81.53/bbl, up 25% from $65.18/bbl in the first nine months of 2010. Baytex’s realized heavy oil price during the first nine months of 2011, prior to physical forward sales contracts, was $62.53/bbl, or 84% of WCS. This compares to a realized heavy oil price in the first nine months of 2010, prior to physical forward sales contracts, of $60.28/bbl, or 90% of WCS. The differential to WCS largely reflects the cost of blending Baytex’s heavy oil with diluent to meet pipeline specifications. Net of physical forward sales contracts, Baytex’s realized heavy oil price during the first nine months of 2011 was $63.54/bbl, up 7% from $59.15/bbl in the first nine months of 2010. Baytex’s realized natural gas price for the nine months ended September 30, 2011 was $3.95/mcf prior to physical forward sales contracts and $4.25/mcf inclusive of physical forward sales contracts (nine months ended September 30, 2010 – $4.38/mcf prior to physical forward sales contracts and $4.47/mcf inclusive of physical forward sales contracts).

Gross Revenues

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for %)	2011		2010		Change			2011		2010		Change
Oil revenue
Light oil and NGL	$	53,808	$	38,632		39	%	$	147,899	$	117,164		26	%
Heavy oil		203,486		154,381		32	%		595,838		456,162		31	%
Total oil revenue		257,294		193,013		33	%		743,737		573,326		30	%
Natural gas revenue		18,962		19,830		(4	%)		57,155		68,561		(17	%)
Total oil and natural gas revenue		276,256		212,843		30	%		800,892		641,887		25	%
Sales of heavy oil blending diluent		37,531		25,433		48	%		140,109		99,752		40	%
Total petroleum and natural gas sales	$	313,787	$	238,276		32	%	$	941,001	$	741,639		27	%

Petroleum and natural gas sales increased 32% to $313.8 million for the three months ended September 30, 2011 from $238.3 million for the same period in 2010. During this period, the change was driven by heavy oil revenues which increased by 32% due to a 3% increase in realized price and a 29% increase in sales volume compared to the three months ended September 30, 2010.

For the nine months ended September 30, 2011, petroleum and natural gas sales increased 27% to $941.0 million from $741.6 million for the same period in 2010. During this period, the change was driven by heavy oil revenues which increased by 31% due to a 7% increase in realized price and an 22% increase in sales volume compared to the nine months ended September 30, 2010.

Royalties

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for % and per boe)	2011			2010			Change			2011			2010			Change
Royalties	$	50,656		$	42,750			18	%	$	150,617		$	135,797			11	%
Royalty rates:
Light oil, NGL and natural gas		20.8	%		17.3	%		–			18.9	%		21.0	%		–
Heavy oil		17.6	%		21.1	%		–			18.8	%		21.2	%		–
Average royalty rates(1)		18.4	%		20.1	%		–			18.8	%		21.2	%		–
Royalty expenses per boe	$	10.54		$	10.37			2	%	$	11.22		$	11.26			–	%

(1)	Average royalty rate excludes sales of heavy oil blending diluents and the effects of financial derivatives.

Total royalties for the third quarter of 2011 increased to $50.7 million from $42.8 million in the third quarter of 2010. Total royalties for the third quarter of 2011 were 18.4% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 20.1% for the same period in 2010. Royalty rates for light oil, NGL and natural gas increased from 17.3% in the three months ended September 30, 2010 to 20.8% in the three months ended September 30, 2011 due to the increase in reference pricing for light oil and NGL, partially offset by reductions in conventional oil royalty rates on new wells. Royalty rates for heavy oil decreased from 21.1% in the three months ended September 30, 2010 to 17.6% in the three months ended September 30, 2011 due to lower royalty rates at Seal and Kerrobert.

Total royalties for the nine months ended September 30, 2011 increased to $150.6 million from $135.8 million in the nine months ended September 30, 2010. Total royalties for the first nine months of 2011 were 18.8% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 21.2% for the same period in 2010. Royalty rates for light oil, NGL and natural gas decreased from 21.0% in the nine months ended September 30, 2010 to 18.9% in the nine months ended September 30, 2011 due to royalty incentives on new wells realized in the period. Royalty rates for heavy oil decreased from 21.2% in the nine months ended September 30, 2010 to 18.8% in the nine months ended September 30, 2011 due to lower royalty rates at Seal and Kerrobert, in addition to a $1.0 million Alberta Royalty Tax Credit reassessment related to 2004 and 2005 periods received in the first quarter of 2011.

Certain additional credits earned under the Alberta Royalty Drilling Credit program, which are based on drilling activity and drilling depths, are recorded as a reduction to capital expenditures, rather than as a reduction to royalties.

Financial Derivatives

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2011			2010			Change			2011			2010			Change
Realized gain (loss) on financial derivatives(1)
Crude oil	$	3,114		$	4,501		$	(1,387	)	$	(14,355	)	$	8,409		$	(22,764	)
Natural gas		102			3,620			(3,518	)		59			7,665			(7,606	)
Foreign currency		2,907			6,553			(3,646	)		13,701			19,660			(5,959	)
Interest rate		104			567			(463	)		32			1,079			(1,047	)
Total	$	6,227		$	15,241		$	(9,014	)	$	(563	)	$	36,813		$	(37,376	)
Unrealized gain (loss) on financial derivatives(2)
Crude oil	$	58,710		$	(9,932	)	$	68,642		$	62,303		$	6,171		$	56,132
Natural gas		2,287			(643	)		2,930			3,792			3,545			247
Foreign currency		(23,372	)		4,361			(27,733	)		(26,069	)		(13,123	)		(12,946	)
Interest rate		(6,609	)		(6,243	)		(366	)		(5,878	)		(15,706	)		9,828
Total	$	31,016		$	(12,457	)	$	43,473		$	34,148		$	(19,113	)	$	53,261
Total gain (loss) on financial derivatives
Crude oil	$	61,824		$	(5,431	)	$	67,255		$	47,948		$	14,580		$	33,368
Natural gas		2,389			2,977			(588	)		3,851			11,210			(7,359	)
Foreign currency		(20,465	)		10,914			(31,379	)		(12,368	)		6,537			(18,905	)
Interest rate		(6,505	)		(5,676	)		(829	)		(5,846	)		(14,627	)		8,781
Total	$	37,243		$	2,784		$	34,459		$	33,585		$	17,700		$	15,885

(1)	Realized gain (loss) on financial derivatives represents actual cash settlement or receipts under the financial derivatives.

(2)	Unrealized gain (loss) on financial derivatives represents the change in fair value of the financial derivatives during the period.

The total gain on financial derivatives for the three months ended September 30, 2011 was $37.2 million, as compared to a gain of $2.8 million for the same period in 2010. This includes a realized gain of $6.2 million and an unrealized mark-to-market gain of $31.0 million for the third quarter of 2011, as compared to $15.2 million in realized gains and $12.5 million in unrealized losses for the third quarter of 2010. The realized gain of $6.2 million for the three months ended September 30, 2011 relates to the realization of gains on commodity contracts due to lower oil prices and gains on foreign currency contracts. The unrealized mark-to-market gain of $31.0 million for the three months ended September 30, 2011 relates to lower oil prices at September 30, 2011, as compared to June 30, 2011, partially offset by a strengthening US dollar against the Canadian dollar.

The total gain on financial derivatives for the nine months ended September 30, 2011 was $33.6 million, as compared to a gain of $17.7 million for the same period in 2010. This includes a realized loss of $0.6 million and an unrealized mark-to-market gain of $34.1 million for the first nine months of 2011, as compared to $36.8 million in realized gains and $19.1 million in unrealized losses for the same period in 2010. The realized loss of $0.6 million for the nine months ended September 30, 2011 relates to the realization of losses on commodity contracts due to higher oil prices in the first seven months of the year offset by gains on foreign currency contracts. The unrealized gain of $34.1 million for the nine months ended September 30, 2011, is mainly due to lower commodity prices at September 30, 2011, as compared to December 31, 2010, offset by a strengthening US dollar against the Canadian dollar.

A summary of the risk management contracts in place as at September 30, 2011 and the accounting treatment of the Company’s financial instruments are disclosed in note 22 to the consolidated financial statements as at and for the three months and nine months ended September 30, 2011.

Evaluation and Exploration Expense

Evaluation and exploration expense for the three months and nine months ended September 30, 2011 decreased to $3.3 million and $10.1 million respectively, as compared to $6.2 million and $18.2 million for the same periods of 2010, due to a decrease in lease expiries of undeveloped land during 2011.

Production and Operating Expenses

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for % and per boe)	2011		2010		Change			2011		2010		Change
Production and operating expenses	$	55,936	$	43,890		27	%	$	153,601	$	128,511		20	%
Production and operating expenses per boe	$	11.64	$	10.65		9	%	$	11.44	$	10.65		7	%

Production and operating expenses for the three months ended September 30, 2011 increased to $55.9 million from $43.9 million for the same period of 2010 due to increases in total production volumes from development activities, the cost of energy inputs and the number of turnarounds conducted at Baytex operated and non-operated oil and natural gas processing facilities. Production and operating expenses were $11.64 per boe for the three months ended September 30, 2011, as compared to $10.65 per boe for the same period in 2010. For the three months ended September 30, 2011, production and operating expenses were $12.98 per boe of light oil, NGL and natural gas and $11.08 per barrel of heavy oil, as compared to $10.62 and $10.67, respectively, for the same period in 2010.

Production and operating expenses for the nine months ended September 30, 2011 increased to $153.6 million from $128.5 million for the same period of 2010 due to an increase in total production volumes from development activities and difficult year-to-date weather conditions. In the winter months, Baytex experienced increased costs for energy inputs and snow removal. In the spring months, Baytex experienced increased costs due to forest fires in northern Alberta and extremely wet ground conditions in North Dakota. In the summer months, production and operating expenses increased due to the increased cost of energy inputs and number of turnarounds conducted at Baytex operated and non-operated oil and natural gas processing facilities. Production and operating expenses were $11.44 per boe for the nine months ended September 30, 2011, as compared to $10.65 per boe for the same period in 2010. For the nine months ended September 30, 2011, production and operating expenses were $12.14 per boe of light oil, NGL and natural gas and $11.14 per barrel of heavy oil, as compared to $10.92 and $10.50, respectively, for the same period in 2010.

Transportation and Blending Expenses

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for % and per boe)	2011		2010		Change			2011		2010		Change
Blending expenses	$	37,531	$	25,433		48	%	$	140,109	$	99,752		40	%
Transportation expenses(1)		16,528		12,122		36	%		45,628		35,759		28	%
Total transportation and blending expenses	$	54,059	$	37,555		44	%	$	185,737	$	135,511		37	%
Transportation expense per boe(1)	$	3.44	$	2.94		17	%	$	3.40	$	2.96		15	%

(1)	Transportation expenses per boe are before the purchase of blending diluent.

Transportation and blending expenses for the third quarter of 2011 were $54.1 million, as compared to $37.6 million for the third quarter of 2010. Transportation and blending expenses for the first nine months of 2011 were $185.7 million, as compared to $135.5 million for the first nine months of 2010.

The heavy oil produced by Baytex requires blending to reduce its viscosity in order to meet pipeline specifications. Baytex mainly purchases condensate from industry producers as the blending diluent to facilitate the marketing of its heavy oil. In the third quarter of 2011, blending expenses were $37.5 million for the purchase of 4,287 bbl/d of condensate at $95.16 per barrel, as compared to $25.4 million for the purchase of 3,411 bbl/d at $81.03 per barrel for the same period last year. In the nine months ended September 30, 2011, blending expenses were $140.1 million for the purchase of 5,116 bbl/d of condensate at $100.32 per barrel, as compared to $99.8 million for the purchase of 4,331 bbl/d at $84.36 per barrel for the same period last year. The cost of blending diluent is effectively recovered in the sale price of a blended product.

Transportation expenses were $3.44 per boe for the three months ended September 30, 2011, as compared to $2.94 per boe for the same period of 2010. Transportation expenses were $0.85 per boe of light oil, NGL and natural gas and $4.51 per barrel of heavy oil in the third quarter of 2011, as compared to $0.82 and $4.10 per barrel, respectively, for the same period in 2010. The increase in transportation expenses per barrel of heavy oil is primarily due to a larger portion of our heavy oil production coming from Seal, which requires long-haul trucking, and increased fuel prices.

Transportation expenses were $3.40 per boe for the nine months ended September 30, 2011, as compared to $2.96 per boe for the same period of 2010. Transportation expenses were $0.81 per boe of light oil, NGL and natural gas and $4.52 per barrel of heavy oil in the first nine months of 2011, as compared to $0.86 and $4.15 per barrel, respectively, for the same period in 2010. The increase in transportation expenses per barrel of heavy oil is primarily due to a larger portion of our heavy oil production coming from Seal, which requires long-haul trucking, and increased fuel prices.

Operating Netback

	Three Months Ended September 30							Nine Months Ended September 30
($ per boe except for % and volume)	2011		2010		Change			2011			2010		Change
Sales volume (boe/d)		52,256		44,789		17	%		49,171			44,188		11	%
Operating netback(1):
Sales price(2)	$	57.31	$	51.59		11	%	$	59.61		$	53.18		12	%
Less:
Royalties		10.54		10.37		2	%		11.22			11.26		–	%
Operating expenses		11.64		10.65		9	%		11.44			10.65		7	%
Transportation expenses		3.44		2.94		17	%		3.40			2.96		15	%
Operating netback before financial derivatives	$	31.69	$	27.63		15	%	$	33.55		$	28.31		19	%
Financial derivatives gain (loss)(3)		1.30		3.70		(65	%)		(0.04	)		3.05		(101	%)
Operating netback after financial derivatives (loss) gain	$	32.99	$	31.33		5	%	$	33.51		$	31.36		7	%

(1)	Operating netback table includes revenues and costs associated with sulphur production.

(2)	Sales price is shown net of blending costs and gains (losses) on physical delivery contracts.

(3)	Financial derivatives reflect realized gains (losses) only.

General and Administrative Expenses

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for % and per boe)	2011		2010		Change			2011		2010		Change
General and administrative expenses	$	9,604	$	8,606		12	%	$	29,423	$	29,628		(1	%)
General and administrative expenses per boe	$	2.00	$	2.09		(4	%)	$	2.19	$	2.46		(11	%)

General and administrative expenses for the third quarter of 2011 increased to $9.6 million from $8.6 million for the comparable period in 2010. The increase is a result of higher general office and salary costs, partially offset by higher capital overhead recoveries from increased capital expenditures.

General and administrative expenses for the nine months ended September 30, 2011 decreased slightly to $29.4 million from $29.6 million for the same period in 2010. This decrease is a result of higher capital overhead recoveries from increased capital expenditures and lower consulting expenses, partially offset by increases in rent and independent reserves evaluator fees.

Share-based Compensation Expense

Compensation expense related to the Common Share Rights Incentive Plan (the “Share Rights Plan”) was $3.9 million for the three months ended September 30, 2011, as compared to a $35.0 million expense related to the Trust Unit Rights Incentive Plan of the Trust (the “Unit Rights Plan”) for the same period in 2010. For the nine months ended September 30, 2011, the compensation expense was $13.7 million, as compared to $63.1 million for the same period in 2010. The significant decrease in compensation expense is primarily due to the change in classification of the plans. Under IFRS, prior to our conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability is re-measured at each reporting date and at settlement date. Any changes in fair value are recognized in net income for the period. Upon conversion to a corporation, the outstanding Unit Rights Plan was modified to become the new Share Rights Plan, effectively changing the related classification from liability-settled to equity-settled. The expense recognized from the date of the plan modification over the remainder of the vesting period is determined based on the fair value of the reclassified unit rights at the date of the modification.

On January 1, 2011, the Company adopted a full-value award plan (the “Share Award Incentive Plan”) pursuant to which restricted awards and performance awards may be granted to directors, officers and employees of the Company and its subsidiaries. During the three months and nine months ended September 30, 2011, the Company recorded $5.9 million and $11.5 million, respectively, related to the share awards ($nil for the three months and nine months ended September 30, 2010). This increase is the result of the compensation expense related to share awards granted in 2011.

Compensation expense associated with the Share Rights Plan and the Share Award Incentive Plan are recognized in income over the vesting period of the share rights or share awards with a corresponding increase in contributed surplus. The issuance of common shares upon the exercise of share rights or settlement of share awards is recorded as an increase in shareholders’ capital with a corresponding reduction in contributed surplus.

Financing Costs

	Three Months Ended September 30								Nine Months Ended September 30
($ thousands except for %)	2011		2010			Change			2011		2010		Change
Bank loan and other	$	2,583	$	3,616			(29	%)	$	9,389	$	9,213		2	%
Long-term debt		6,088		3,823			(59	%)		16,793		10,763		56	%
Accretion on asset retirement obligations		1,558		1,473			6	%		4,558		4,331		5	%
Convertible debentures		–		(93	)		(100	%)		–		155		(100	%)
Debt financing costs		154		11			1,300	%		2,998		1,425		110	%
Financing costs	$	10,383	$	8,830			18	%	$	33,738	$	25,887		30	%

Financing costs for the three months ended September 30, 2011 increased to $10.4 million, as compared to $8.8 million in the third quarter of 2010. The increase in financing costs was primarily attributable to the interest on the US$150.0 million principal amount of 6.75% Series B senior unsecured debentures issued on February 17, 2011, higher fees paid in 2011 associated with our revolving credit facilities, offset by lower borrowing rates on the US$180.0 million portion of bank loan.

Financing costs for the nine months ended September 30, 2011 increased to $33.7 million, as compared to $25.9 million in the nine months ended September 30, 2010. The increase in financing costs was primarily attributable to the interest on the US$150.0 million principal amount of 6.75% Series B senior unsecured debentures issued on February 17, 2011 and higher debt financing costs related to the issuance of these debentures.

Foreign Exchange

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for %)	2011			2010			Change			2011			2010			Change
Unrealized foreign exchange loss (gain)	$	24,257		$	(5,321	)		(556	%)	$	14,655		$	(2,824	)		(619	%)
Realized foreign exchange (gain) loss		(4,418	)		903			(589	%)		(2,752	)		(1,186	)		132	%
Total loss (gain)	$	19,839		$	(4,418	)		(549	%)	$	11,903		$	(4,010	)		(397	%)

The foreign exchange loss for the three months ended September 30, 2011 was $19.8 million, as compared to a gain of $4.4 million for the three months ended September 30, 2010. This loss was comprised of an unrealized foreign exchange loss of $24.3 million and a realized foreign exchange gain of $4.4 million. The third quarter of 2011 unrealized loss of $24.3 million, as compared to a gain of $5.3 million for the third quarter of 2010, was due to the translation of the US$180 million portion of the bank loan and US$150 million Series B senior unsecured debentures as the USD/CAD foreign exchange rates strengthened at September 30, 2011 (as compared to June 30, 2011) and weakened at September 30, 2010 (as compared to June 30, 2010). The current quarter realized gain was related to day-to-day US dollar denominated transactions.

The foreign exchange loss for the nine months ended September 30, 2011 was $11.9 million, as compared to a gain of $4.0 million for the nine months ended September 30, 2010. This gain was comprised of an unrealized foreign exchange loss of $14.7 million and a realized foreign exchange gain of $2.8 million. The nine months ended September 30, 2011 unrealized loss of $14.7 million, as compared to a gain of $2.8 million for the same period in 2010, was due to the translation of the US$180 million portion of the bank loan as the USD/CAD foreign exchange rates strengthened at September 30, 2011 (as compared to December 31, 2010) and strengthened at September 30, 2010 (as compared to December 31, 2009). In addition, the translation of the US$150 million Series B senior unsecured debentures issued on February 17, 2011 contributed to the year to date unrealized foreign exchange loss as the USD/CAD foreign exchange rate strengthened from the issue date of the debentures to September 30, 2011. The realized gain for the nine months ended September 30, 2011 was related to day-to-day US dollar denominated transactions.

Depletion and Depreciation

Depletion and depreciation for the three months ended September 30, 2011 increased to $63.4 million from $50.9 million for the same period in 2010. On a sales-unit basis, the provision for the current quarter was $12.56 per boe, as compared to $11.67 per boe for the same quarter in 2010.

Depletion and depreciation for the nine months ended September 30, 2011 increased to $176.5 million from $147.7 million for the same period in 2010. On a sales-unit basis, the provision for the first nine months of 2011 was $13.15 per boe, as compared to $12.24 per boe for the same period in 2010.

Income Taxes

For the nine months ended September 30, 2011, deferred income tax expense totaled $39.7 million, as compared to a recovery of $114.9 million for the nine months ended September 30, 2010. The decrease in the deferred income tax recovery is primarily due to the $109.8 million recovery in the second quarter of 2010 related to the difference between the deferred income tax asset and the cash paid for the acquisition of private entities.

As at September 30, 2011, net deferred income tax liability was $70.5 million (December 31, 2010 – $6.5 million). The increase relates to the additional liability recognized in the corporate acquisition in the current year of $24.5 million and the impact of accounting income net of adjustments due to decrease in rates and adjustments to opening tax pool balances.

Tax Pools

During 2010 and prior years, Baytex was organized as a mutual fund trust for Canadian income tax purposes. Partially as a result of tax deductions taken for distributions paid to unitholders in 2010 and prior years, no material Canadian cash tax was payable by the Trust, other than the Saskatchewan resource surcharge which is classified as a royalty expense under IFRS.

Following the conversion from a trust structure to a corporate legal form on December 31, 2010, Baytex will not be entitled to a deduction from Canadian taxable income for its distributions, nor will a deduction be available for future dividends. As such, it is likely that cash income tax expense attributable to our Canadian operations will be higher in future. Baytex has accumulated the Canadian and US tax pools as noted in the table below, which will be available to reduce the future taxable income. Our cash income tax liability is dependant upon many factors, including the prices at which we sell our production, available income tax deductions and the legislative environment in place during the taxation year. Based upon the current forward commodity price outlook, projected production and cost levels, and the proposed legislation on partnership deferral, Baytex expects to become liable for Canadian income taxes between 2012 and 2013. The income tax pools detailed below are deductible at various rates as prescribed by law.

($ thousands)	September 30, 2011		December 31, 2010
Canadian Tax Pools
Canadian oil and natural gas property expenditures	$	330,224	$	271,741
Canadian development expenditures		332,132		292,500
Canadian exploration expenditures		17,483		11,757
Undepreciated capital costs		261,142		184,586
Non-capital losses		769,922		775,727
Financing costs and other		8,966		10,334
Total Canadian tax pools	$	1,719,869	$	1,546,645
US Tax Pools
Taxable depletion	$	172,367	$	125,628
Intangible drilling costs		12,932		35,000
Tangibles		12,434		3,634
Non-capital losses		84,501		66,530
Total US tax pools	$	282,234	$	230,792

Net Income

Net income for the three months ended September 30, 2011 was $51.8 million, as compared to $23.3 million for the same period in 2010. The increase in net income was primarily the result of a decrease in share-based compensation, an increase in gain on financial derivative and an increase in production volume coupled with a higher operating netback for the current period. This was partially offset by an increase in foreign exchange loss and increase in depletion and depreciation.

Net income for the nine months ended 2011 was $159.7 million, as compared to $210.3 million for the same period in 2010. The decrease in net income was primarily the result of a $109.8 million deferred income tax recovery in 2010 relating to the acquisition of private entities, which was partially mitigated by an increase in production volume coupled with a higher operating netback and lower share-based compensation expense for the current period.

Other Comprehensive Income

Revenues and expenses of foreign operations are translated to Canadian dollars using average foreign currency exchange rates for the period. Monetary assets and liabilities that form part of the net investment in the foreign operation are translated at the period-end foreign currency exchange rate. Gains or losses resulting from the translation are included in accumulated other comprehensive income (loss) in shareholders’/unitholders’ equity and are recognized in net income when there has been a disposal or partial disposal of the foreign operation.

Under IFRS, the Company has elected to deem cumulative currency translation differences as $nil at January 1, 2010. The $2.5 million balance of accumulated other comprehensive income at September 30, 2011 is the sum of a $10.3 million foreign currency translation loss incurred in 2010 and a $12.8 million foreign currency translation gain for the nine months ended September 30, 2011 as USD/CAD foreign exchange rates strengthened at September 30, 2011.

FUNDS FROM OPERATIONS, PAYOUT RATIO AND DIVIDENDS OR DISTRIBUTIONS

Funds from operations and payout ratio are non-GAAP measures. Funds from operations represents cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Payout ratio is calculated as cash dividends/distributions (net of participation in the Dividend Reinvestment Plan (“DRIP”)) divided by funds from operations. Baytex considers these to be key measures of performance as they demonstrate its ability to generate the cash flow necessary to fund dividends and capital investments.

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

	Three Months Ended									Nine Months Ended						Year Ended
($ thousands except for %)	September 30, 2011			June 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010			December 31, 2010
Cash flow from operating activities	$	148,678		$	146,199		$	137,142		$	414,777		$	353,112		$	459,732
Change in non-cash working capital		1,758			2,206			(19,627	)		1,553			(9,424	)		13,399
Asset retirement expenditures		3,064			959			683			4,942			2,027			2,829
Financing costs		(10,383	)		(12,793	)		(8,830	)		(33,738	)		(25,887	)		(34,570	)
Accretion on asset retirement obligations		1,558			1,516			1,473			4,558			4,331			5,862
Accretion on debentures and long-term debt		150			146			113			418			335			426
Funds from operations	$	144,825		$	138,233		$	110,954		$	392,510		$	324,494		$	447,678
Cash distributions declared, net of DRIP	$	50,270		$	52,764		$	45,795		$	155,035		$	141,698		$	189,824
Payout ratio		35	%		38	%		41	%		39	%		44	%		42	%

Baytex does not deduct capital expenditures when calculating the payout ratio. Due to the depleting nature of petroleum and natural gas assets, certain levels of capital expenditures are required to minimize production declines. In the petroleum and natural 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 petroleum and natural gas assets increase significantly, it is possible that Baytex would be required to reduce or eliminate its dividends in order to fund capital expenditures. There can be no certainty that Baytex will be able to maintain current production levels in future periods. Cash dividends declared, net of DRIP participation, of $50.3 million for the third quarter of 2011 were funded through funds from operations of $144.8 million.

The following table compares cash dividends or distributions declared (net of DRIP participation) to cash flow from operating activities and net income:

	Three Months Ended							Nine Months Ended				Year Ended
($ thousands)	September 30, 2011		June 31, 2011		September 30, 2010			September 30, 2011		September 30, 2010		December 31, 2010
Cash flow from operating activities	$	148,678	$	146,199	$	137,142		$	414,777	$	353,112	$	459,732
Cash dividends or distributions declared, net of DRIP		50,270		52,764		45,795			155,035		141,698		189,824
Excess of cash flow from operating activities over cash dividends or distributions declared, net of DRIP	$	98,408	$	93,435	$	91,347		$	259,742	$	211,414	$	269,908
Net income	$	51,839	$	106,863	$	23,319		$	159,652	$	210,260	$	231,615
Cash dividends or distributions declared, net of DRIP		50,270		52,764		45,795			155,035		141,698		189,824
Excess (shortfall) of earnings over cash dividends or distributions declared, net of DRIP	$	1,569	$	54,099	$	(22,476	)	$	4,617	$	68,562	$	41,791

It is Baytex’s long-term operating objective to substantially fund cash dividends and capital expenditures for exploration and development activities through funds 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 dividends. During periods of lower commodity prices or periods of higher capital spending, it is possible that funds from operations will not be sufficient to fund both cash dividends and capital spending. In these instances, the cash shortfall may be funded through a combination of equity and debt financing.

For the three months ended September 30, 2011, the Company’s net income was in excess of cash dividends declared (net of DRIP participation) by $1.6 million, with net income reduced by $96.8 million for non-cash items. For the nine months ended September 30, 2011, the Company’s net income was in excess of cash dividends declared (net of DRIP participation) by $4.6 million, with net income reduced by $255.1 million for non-cash items. Non-cash items such as depletion and depreciation may not be 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.

LIQUIDITY AND CAPITAL RESOURCES

We regularly review our liquidity sources as well as our exposure to counterparties, and have concluded that our capital resources are sufficient to meet our on-going short, medium and long-term commitments. Specifically, we believe that our internally generated funds 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. We periodically review the financial capacity of our counterparties and, in certain circumstances, we will seek enhanced credit protection from a counterparty.

($ thousands)	September 30, 2011		December 31, 2010
Bank loan	$	368,184	$	303,773
Long-term debt(1)		305,835		150,000
Working capital deficiency		65,180		52,462
Total monetary debt	$	739,199	$	506,235

(1)	Principal amount of long-term debt.

At September 30, 2011, total monetary debt was $739.2 million, as compared to $506.2 million at December 31, 2010. Bank borrowings at September 30, 2011 were $368.2 million, as compared to total credit facilities of $700.0 million. Subsequent to the end of the third quarter, we entered into definitive agreements to sell certain primarily-undeveloped lands in Alberta and Saskatchewan for $47.1 million. The proceeds from these dispositions will be used to reduce the amount drawn on the credit facilities.

Our wholly-owned subsidiary, Baytex Energy Ltd. (“Baytex Energy”), has established credit facilities with a syndicate of chartered banks. On June 14, 2011, Baytex Energy reached agreement with its lending syndicate to amend the credit facilities to (i) increase the amount available under the facilities to $700 million (from $650 million), (ii) extend the revolving period from 364 days (with a one-year term out following the revolving period) to three years, which is extendible annually for a 1, 2 or 3 year period (subject to a maximum three-year term at any time), and (iii) change the structure of the facilities from reserves-based to covenant- based (with standard commercial covenants for facilities of this nature). The credit facilities do not require any mandatory principal payments during the three-year term. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or US funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offer Rates, plus applicable margins. The credit facilities are secured by a floating charge over all of Baytex Energy’s assets and are guaranteed by us and certain of our material subsidiaries. The credit facilities do not include a term-out feature or a borrowing base restriction. In the event that Baytex Energy does not comply with covenants under the credit facilities, our ability to pay dividends to shareholders may be restricted. A copy of the amended and restated credit agreement which establishes the credit facilities is accessible on the SEDAR website at www.sedar.com (filed under the category “Material Document” on July 22, 2011).

Financing costs for the nine months ended September 30, 2011 include facility amendment fees of $2.2 million ($1.4 million for nine months ended September 30, 2010). The weighted average interest rate on the bank loan for nine months ended September 30, 2011 was 3.45% (3.94% for the year ended December 31, 2010 and 3.91% for the nine months ended September 30, 2010).

On February 17, 2011, Baytex issued US$150.0 million principal amount of Series B senior unsecured debentures bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. Net proceeds of this issue were used to repay a portion of the amount drawn in Canadian currency on Baytex Energy’s credit facilities. These debentures are unsecured and are subordinate to Baytex Energy’s credit facilities.

Pursuant to various agreements with our lenders, we are restricted from paying dividends to shareholders where the dividend would or could have a material adverse effect on us or our subsidiaries’ ability to fulfill our respective obligations under the Series A or Series B senior unsecured debentures and Baytex Energy’s credit facilities.

Baytex believes that funds from operations, together with the existing credit facilities, will be sufficient to finance current operations, dividends to the shareholders 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 dividend is also discretionary, and the Company has the ability to modify dividend levels should funds from operations be negatively impacted by factors such as reductions in commodity prices or production volumes.

Capital Expenditures

Capital expenditures are summarized as follows:

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2011			2010			2011			2010
Land	$	(463	)	$	(1,115	)	$	4,088		$	9,656
Seismic		211			263			379			66
Drilling and completion		67,042			42,568			203,981			115,752
Equipment		33,632			17,841			87,404			46,822
Other		(54	)		2			(17	)		(27	)
Total exploration and development	$	100,368		$	59,559		$	295,835		$	172,269
Acquisitions – Corporate		22			–			118,693			40,314
Acquisitions – Properties		28,502			11,452			65,835			19,316
Proceeds from divestitures		–			(18,137	)		–			(18,137	)
Total Acquisitions and divestitures		28,524			(6,685	)		184,528			41,493
Total oil and natural gas expenditures		128,892			52,874			480,363			213,762
Other plant and equipment, net		591			6,715			1,416			13,447
Total capital expenditures	$	129,483		$	59,589		$	481,779		$	227,209

Shareholders’ Capital

On December 31, 2010, all of the outstanding trust units of the Trust were exchanged for common shares of Baytex on a one-for-one basis in connection with the Corporate Conversion.

Baytex is authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. Baytex establishes the rights and terms of preferred shares upon issuance. As at November 4, 2011, the Company had 117,342,527 common shares and no preferred shares issued and outstanding.

Contractual Obligations

Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s funds from operations on an ongoing manner. A significant portion of these obligations will be funded through funds from operations. These obligations as of September 30, 2011, and the expected timing of funding of these obligations, are noted in the table below.

($ thousands)	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	221,960	$	221,960	$	–	$	–	$	–
Dividends payable to shareholders		23,351		23,351		–		–		–
Bank loan(1)		368,184		–		368,184		–		–
Long-term debt(2)		305,835		–		–		150,000		155,835
Operating leases		51,581		5,774		12,311		11,766		21,730
Processing and transportation agreements		2,206		1,610		594		2		–
Total	$	973,117	$	252,695	$	381,089	$	161,768	$	177,565

(1)	The bank loan is a three-year covenant-based revolving loan that is extendible annually for a one, two or three year period (subject to a maximum three-year term at any time). Unless extended, the revolving period will end on June 14, 2014 with all amounts to be re-paid on such date.

(2)	Principal amount of instruments.

Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives. Programs to abandon and reclaim them are undertaken regularly in accordance with applicable legislative requirements.

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Baytex is exposed to a number of financial risks, including market risk, liquidity risk and credit 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 foreign currency risk, interest rate risk and commodity price risk. Market risk is managed by Baytex through a series of derivative contracts intended to manage the volatility of its operating cash flow. Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Baytex 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 Company incurring a loss. Baytex manages credit risk by entering into sales contracts with creditworthy entities and reviewing its exposure to individual entities on a regular basis.

QUARTERLY FINANCIAL INFORMATION(1)

	2011				2010					2009
($ thousands, except per common share or trust unit amounts)		Q3	Q2	Q1		Q4	Q3	Q2	Q1		Q4
Gross revenues		313,787	336,899	290,315		263,497	238,276	241,581	261,782		237,962
Net income		51,839	106,863	950		21,356	23,319	157,440	29,501		27,956
Per common share or trust unit – basic		0.45	0.92	0.01		0.19	0.21	1.42	0.27		0.26
Per common share or trust unit – diluted		0.44	0.90	0.01		0.18	0.20	1.38	0.26		0.25

(1)	Financial information for 2011 and 2010 has been prepared in accordance with IFRS and financial information for 2009 has been prepared in accordance with the previous GAAP.

CHANGES IN ACCOUNTING POLICIES

Adoption of International Financial Reporting Standards

IFRS replaces GAAP in Canada for financial periods beginning on January 1, 2011. At the transition date, publicly accountable enterprises are required to prepare financial statements in accordance with IFRS. The adoption date of January 1, 2011 requires the restatement, for comparative purposes, of 2010 amounts reported by Baytex, including the opening statement of financial position as at January 1, 2010.

Our IFRS financial statements for the year ending December 31, 2011 must use the standards that are in effect on December 31, 2011, and therefore our consolidated financial statements have been prepared using the standards expected to be effective at the end of 2011. IFRS accounting policies will only be finalized when our first annual IFRS financial statements are prepared for the year ending December 31, 2011 and as a result, our consolidated financial statements for the three months and nine months ended September 30, 2011 are subject to change. Reconciliations to IFRS from the previously published consolidated financial statements, prepared in accordance with previous GAAP are shown in note 25 to the consolidated financial statements. The accounting policies described in note 3 to the consolidated financial statements set out those policies that have been applied retrospectively and consistently in preparing the consolidated financial statements, except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1 (as disclosed in note 25 to the consolidated financial statements).

The following table reconciles Baytex’s 2010 previous GAAP results to IFRS for the three months and nine months ended September 30, 2010.

	2010
($ thousands)	Three months ended September 30			Nine months ended September 30
Net income – Previous GAAP	$	35,061		$	120,042
Exploration and evaluation		(6,158	)		(18,163	)
Depletion and depreciation		17,169			51,558
Gain on oil and gas properties		16,209			16,209
Accretion on asset retirement obligation		(320	)		(970	)
Unit-based compensation		(33,121	)		(56,335	)
Conversion feature of convertible debentures		(1,622	)		(3,866	)
Deferred income tax		(3,528	)		102,490
Other		(371	)		(705	)
Net income – IFRS	$	23,319		$	210,260

	2010
($ thousands)	Three months ended September 30			Nine months ended September 30
Funds from operations – Previous GAAP	$	112,786		$	329,407
Exploration and evaluation		(1,615	)		(4,476	)
Other		(217	)		(437	)
Funds from operations – IFRS	$	110,954		$	324,494

Listed below is a summary of the significant effects of the transition from previous GAAP to IFRS:

Exploration and Evaluation

Under previous GAAP, petroleum and natural gas properties included certain exploration and evaluation expenditures incurred within a country-by-country cost centre. Under IFRS, such exploration and evaluation expenditures are recognized as tangible or intangible based on their nature and subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are expensed.

During the three months ended September 30, 2010, Baytex expensed $4.6 million of exploration and evaluation assets related to lease expiries and $1.6 million in direct exploration costs. For the nine months ended September 30, 2010, Baytex had exploration and evaluation capital expenditures of $30.0 million, corporate acquisitions of $2.5 million, transfers to oil and gas properties of $22.0 million, transfers to expense related to lease expiries of $13.7 million and a decrease due to foreign currency translation of $1.1 million. For the nine months ended September 30, 2010, Baytex expensed $13.7 million of exploration and evaluation assets related to lease expiries and $4.5 million in direct exploration costs.

Depletion

Upon transition to IFRS, the Company adopted a policy of depleting oil and natural gas properties on a “units of production” basis over proved plus probable reserves on an area basis rather than a cost pool basis under previous GAAP. The depletion policy under previous GAAP was units of production over proved reserves on a country basis.

There is no impact to depletion on transition to IFRS at January 1, 2010. For the three months ended September 30, 2010, this change to IFRS resulted in a decrease in depletion expense of $18.0 million with a corresponding increase in oil and natural gas properties. For the nine months ended September 30, 2010, this change to IFRS resulted in a decrease in depletion expense of $54.3 million with a corresponding increase in oil and natural gas properties.

Divestiture of Oil and Gas Assets

Previous GAAP utilized the full cost accounting, whereby gains and losses were not recognized upon the divestiture of oil and gas assets unless such a divestiture would alter the rate of depletion by 20% or more. Under IFRS, gains and losses are recognized based on the difference between the net proceeds from the divestiture and the carrying value of the asset disposed. For the three months and nine months ended September 30, 2010, a gain of $16.2 million was recognized relating to a divestiture of oil and gas assets.

Impairment of Property, Plant and Equipment (“PP&E”) Assets

Under IFRS, impairment of PP&E must be calculated at a more detailed level than what was required under previous GAAP. Impairment calculations are performed at the cash generating unit (“CGU”) level using the higher of its fair value less costs to sell and its value in use. Baytex uses discounted estimated cash flows from proved plus probable reserves for impairment tests of PP&E. Under previous GAAP, estimated future net cash flows used to assess impairments were not discounted. As such, impairment losses may be recognized earlier under IFRS than under previous GAAP. Impairment losses are reversed under IFRS when there is an increase in the recoverable amount.

Baytex has allocated the PP&E amount recognized under previous GAAP as at January 1, 2010 to the assets at a CGU level using reserve values calculated using the discounted net cash flows. There is no change in the overall net book value of our PP&E as there were no impairments upon transition to IFRS at January 1, 2010.

Asset Retirement Obligations

Under IFRS, Baytex uses a risk free interest rate to discount the estimated fair value of its asset retirement obligations associated with the related oil and natural gas properties. Under previous GAAP, the Company used a credit-adjusted risk free interest rate. A lower discount rate under IFRS will increase the asset retirement obligations. In addition, under IFRS the asset retirement obligations are measured using the best estimate of the expenditure to be incurred and current discount rates at each remeasurement date with the corresponding adjustment to the cost of the related oil and natural gas properties. Existing liabilities under previous GAAP are not remeasured using current discount rates.

For the three months ended September 30, 2010, the $1.2 million accretion expense on asset retirement obligations under previous GAAP was reclassified to finance costs and an additional accretion expense on asset retirement obligations of $0.3 million has been recognized in net income under IFRS. For the nine months ended September 30, 2010, $3.4 million was reclassified to finance costs and an additional accretion expense of $1.0 million has been recognized.

Unit-based Compensation

Under previous GAAP, the obligation associated with the Unit Rights Plan is considered to be equity-based and the related unit-based compensation was calculated using the binomial-lattice model to estimate the fair value of the outstanding unit rights at grant date. The exercise of unit rights was recorded as an increase in unitholders’ capital with a corresponding reduction in contributed surplus.

Under IFRS, prior to the conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability is remeasured at each reporting date and at settlement date. Any changes in fair value are recognized in net income for the period. For periods prior to the conversion to a corporation, remeasuring the fair value of the obligation each reporting period will increase or decrease the unit-based payment liability, unitholders’ capital and compensation expense recognized. Upon conversion to a corporation, the outstanding Unit Rights Plan was modified to become the new Share Rights Plan, effectively changing the related classification from liability-settled to equity-settled. The expense recognized from the date of the plan modification over the remainder of the vesting period is determined based on the fair value of the reclassified unit rights at the date of the modification. Upon transition of IFRS at January 1, 2010, an additional unit-based payment liability of $91.6 million and a decrease of $20.4 million in contributed surplus resulted in a corresponding $71.2 million charge to deficit.

Under IFRS, in addition to the January 1, 2010 adjustments discussed above, at September 30, 2010 the remeasurement of the liability at reporting date and at settlement date resulted in the recognition of an additional unit-based compensation expense of $56.3 million, with a corresponding decrease of $0.6 million in contributed surplus, an increase of $30.3 million in shareholders’/unitholders’ equity and an increase of $26.6 million in unit-based payment liability (three months ended September 30, 2010 – $33.1 million additional unit-based compensation expense).

Conversion Feature of Convertible Debentures

Under previous GAAP, the convertible debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders’ or shareholders’ equity. The debt portion accreted up to the principal balance at maturity. If the debentures were converted to trust units, a portion of the value of the conversion feature under unitholders’ equity was reclassified to unitholders’ capital along with principal amounts converted.

Under IFRS, the conversion feature of the convertible debentures has been classified as a financial derivative liability. The financial derivative liability requires a fair value method of accounting and changes in the fair value of the derivative liability are recognized in the statements of income and comprehensive income. If the debentures were converted to trust units, the fair value of the conversion feature under financial derivative liability was reclassified to unitholders’/shareholders’ capital along with the principal amounts converted. The impact on adoption to IFRS at January 1, 2010 was an additional liability of $7.4 million, an increase of $33.4 million in unitholders’ capital with a corresponding $40.4 million charge to deficit and a decrease of $0.4 million in the conversion feature of convertible debentures.

Under IFRS, for the nine months ended September 30, 2010, the increase in unitholders’/shareholders’ equity of $3.3 million and the increase of $0.1 million in conversion feature of convertible debentures had a corresponding increase in the $0.4 million liability recorded at January 1, 2010 and a $3.8 million decrease in gain on financial derivatives in net income (three months ended September 30, 2010 – $1.6 million decrease in gain on financial derivatives in net income).

Accumulated Other Comprehensive Loss

Under previous GAAP, amounts are composed entirely of currency translation adjustments on self-sustaining foreign operations. Under IFRS, the Company has elected to deem cumulative currency translation differences as $nil at January 1, 2010. At January 1, 2010, this has resulted in an decrease in accumulated other comprehensive loss with a corresponding increase in deficit of $3.9 million.

Deferred Income Taxes

Under IFRS, deferred income taxes are required to be presented as non-current. Upon transition to IFRS, the Company recognized a $27.6 million reduction in the net deferred income tax liability entirely resulting from the tax impact of the adjustments from previous GAAP to IFRS with a decrease to deficit of $25.8 million and a decrease to unitholders’ capital of $1.8 million.

In May 2010, Baytex acquired several private entities to be used in its internal financing structure. Under previous GAAP, the excess of amounts assigned to the acquired assets over the consideration paid is classified as a deferred credit. Under IFRS, the deferred credit is derecognized through net income as a deferred income tax recovery. For the nine months ended September 30, 2010, deferred income tax recovery of $109.8 million was recorded in net income for amounts previously recognized as a deferred credit (three months ended September 30, 2010, $nil was recorded in net income for amounts previously recognized as a deferred credit).

For the three months ended September 30, 2010, the application of the IFRS adjustments resulted in a $3.6 million increase to the Company’s deferred income tax expense. For the nine months ended September 30, 2010, the transition to IFRS resulted in a $102.5 million increase to the Company’s deferred income tax recovery. The increase in deferred income tax recovery is due to the deferred credit derecognized through net income under IFRS.

Under IFRS, taxable and deductible temporary differences related to the legal entity of the Trust must be measured using the highest marginal personal tax rate of 39%, as opposed to the corporate tax rates used under previous GAAP, resulting in an increase to the deferred income tax asset of $5.1 million at January 1, 2010. Upon conversion to a dividend paying corporation on December 31, 2010, the total deferred income tax asset related to the Trust was adjusted to the corporate tax rate of approximately 25% and derecognized through net income on December 31, 2010.

FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management’s assessment of the Company’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: crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; our business strategies, plans and objectives; our ability to fund our capital expenditures and dividends on our common shares from funds from operations; our ability to utilize our tax pools to reduce or potentially eliminate our taxable income for the initial period post-conversion; the timing of payment of Canadian income taxes; the sufficiency of our capital resources to meet our on-going short, medium and long-term commitments; the financial capacity of counterparties to honor outstanding obligations to us in the normal course of business; funding sources for our cash dividends and capital program; the timing of funding our financial obligations; the existence, operation, and strategy of our risk management program; the impact of the adoption of new accounting standards on our financial results; and the impact of the adoption of IFRS on our financial position and results of operations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum 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 dividends 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: fluctuations in market prices for petroleum and natural gas; fluctuations in foreign exchange or interest rates; general economic, market and business conditions; stock market volatility and market valuations; changes in income tax laws; industry capacity; geological, technical, drilling and processing problems and other difficulties in producing petroleum and natural gas reserves; uncertainties associated with estimating petroleum and natural gas reserves; liabilities inherent in oil and natural gas operations; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; risks associated with oil and natural gas operations; changes in royalty rates and incentive programs relating to the oil and natural gas industry; changes in environmental and other regulations; incorrect assessments of the value of acquisitions; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management’s Discussion and Analysis for the year ended December 31, 2010, 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.

CONDENSED CONSOLIDATED STATEMENTS

OF FINANCIAL POSITION

As at (thousands of Canadian dollars) (unaudited)	September 30, 2011			December 31, 2010			January 1, 2010
ASSETS
Current assets
Cash	$	–		$	–		$	10,177
Trade and other receivables (note 6)		179,368			151,792			137,154
Crude oil inventory		763			1,802			1,384
Financial derivatives (note 22)		46,659			13,921			29,453
		226,790			167,515			178,168
Non-current assets
Deferred income tax asset (note 18)		8,392			7,870			1,789
Financial derivatives (note 22)		8,812			2,622			2,541
Exploration and evaluation assets (note 7)		126,703			113,082			124,621
Oil and gas properties (note 8)		1,993,976			1,624,629			1,512,035
Other plant and equipment (note 9)		26,333			27,550			27,096
Goodwill		37,755			37,755			37,755
	$	2,428,761		$	1,981,023		$	1,884,005
LIABILITIES
Current liabilities
Trade and other payables (note 11)	$	221,960		$	183,314		$	186,516
Dividends or distributions payable to shareholders/unitholders		23,351			22,742			19,674
Bank loan (note 10)		–			–			265,088
Convertible debentures (note 13)		–			–			7,736
Financial derivatives (note 22)		11,922			20,312			12,004
		257,233			226,368			491,018
Non-current liabilities
Bank loan (note 10)		368,184			303,773			–
Long-term debt (note 12)		300,815			146,893			146,498
Asset retirement obligations (note 14)		216,929			169,611			141,869
Unit-based payment liability (note 16)		–			–			91,559
Deferred income tax liability (note 18)		78,872			14,383			160,719
Financial derivatives (note 22)		21,025			8,859			1,418
		1,243,058			869,887			1,033,081
SHAREHOLDERS’/UNITHOLDERS’ EQUITY
Shareholders’ capital (note 15)		1,627,889			1,484,335			–
Unitholders’ capital (note 15)		–			–			1,331,161
Contributed surplus		95,848			129,129			–
Accumulated other comprehensive income (loss)		2,454			(10,323	)		–
Deficit		(540,488	)		(492,005	)		(480,237	)
		1,185,703			1,111,136			850,924
	$	2,428,761		$	1,981,023		$	1,884,005

Subsequent events (note 24).

See accompanying notes to the condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Three Months Ended September 30						Nine Months Ended September 30
(thousands of Canadian dollars, except per common share and per trust unit amounts) (unaudited)	2011			2010			2011			2010
Revenues, net of royalties (note 19)	$	263,131		$	195,526		$	790,384		$	605,842
Expenses
Exploration and evaluation		3,285			6,158			10,102			18,163
Production and operating		55,936			43,890			153,601			128,511
Transportation and blending		54,059			37,555			185,737			135,511
General and administrative		9,604			8,606			29,423			29,628
Share-based or unit-based compensation (note 16)		9,841			35,009			25,177			63,069
Financing costs (note 20)		10,383			8,830			33,738			25,887
Gain on oil and gas properties		(1,603	)		(16,227	)		(1,603	)		(16,227	)
Gain on financial derivatives (note 22)		(37,243	)		(2,784	)		(33,585	)		(17,700	)
Foreign exchange loss (gain) (note 21)		19,839			(4,418	)		11,903			(4,010	)
Depletion and depreciation		63,406			50,947			176,519			147,693
		187,507			167,566			591,012			510,525
Net income before income taxes		75,624			27,960			199,372			95,317
Deferred income tax expense (recovery) (note 18)		23,785			4,641			39,720			(114,943	)
Net income attributable to shareholders/unitholders	$	51,839		$	23,319		$	159,652		$	210,260
Other comprehensive income (loss)
Foreign currency translation adjustment		19,425			(5,533	)		12,777			(3,204	)
Comprehensive income	$	71,264		$	17,786		$	172,429		$	207,056
Net income per common share or trust unit (note 17)
Basic	$	0.45		$	0.21		$	1.38		$	1.90
Diluted	$	0.44		$	0.20		$	1.35		$	1.84
Weighted average common shares or trust units (note 17)
Basic		116,404			111,710			115,477			110,926
Diluted		118,918			115,053			118,478			114,460

See accompanying notes to the condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES

IN EQUITY

(thousands of Canadian dollars) (unaudited)	Shareholders’ capital		Unitholders’ capital		Contributed surplus			Accumulated other comprehensive income (loss)			Deficit			Total equity
Balance at January 1, 2010	$	–	$	1,331,161	$	–		$	–		$	(480,237	)	$	850,924
Distributions to unitholders		–		–		–			–			(179,970	)		(179,970	)
Issued on conversion of debentures		–		6,154		–			–			–			6,154
Exercise of unit rights		–		54,593		–			–			–			54,593
Issued pursuant to distribution reinvestment plan		–		36,938		–			–			–			36,938
Comprehensive income (loss) for the period		–		–		–			(3,204	)		210,260			207,056
Balance at September 30, 2010	$	–	$	1,428,846	$	–		$	(3,204	)	$	(449,947	)	$	975,695
Balance at December 31, 2010	$	1,484,335	$	–	$	129,129		$	(10,323	)	$	(492,005	)	$	1,111,136
Dividends to shareholders		–		–		–			–			(208,135	)		(208,135	)
Exercise of share rights		92,084		–		(58,458	)		–			–			33,626
Share-based compensation		–		–		25,177			–			–			25,177
Issued pursuant to dividend reinvestment plan		51,470		–		–			–			–			51,470
Comprehensive income for the period		–		–		–			12,777			159,652			172,429
Balance at September 30, 2011	$	1,627,889	$	–	$	95,848		$	2,454		$	(540,488	)	$	1,185,703

See accompanying notes to the condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended September 30						Nine Months Ended September 30
(thousands of Canadian dollars) (unaudited)	2011			2010			2011			2010
CASH PROVIDED BY (USED IN):
Operating activities
Net income for the period	$	51,839		$	23,319		$	159,652		$	210,260
Adjustments for:
Share-based or unit-based compensation (note 16)		9,841			35,009			25,177			63,069
Unrealized foreign exchange loss (gain) (note 21)		24,257			(5,321	)		14,655			(2,824	)
Exploration and evaluation		2,608			4,543			7,562			13,687
Depletion and depreciation		63,406			50,947			176,519			147,693
Unrealized (gain) loss on financial derivatives (note 22)		(31,016	)		12,457			(34,148	)		19,113
Gain on oil and gas properties		(1,603	)		(16,227	)		(1,603	)		(16,227	)
Deferred income tax expense (recovery) (note 18)		23,785			4,641			39,720			(114,943	)
Financing costs (note 20)		10,383			8,830			33,738			25,887
Change in non-cash working capital (note 21)		(1,758	)		19,627			(1,553	)		9,424
Asset retirement expenditures (note 14)		(3,064	)		(683	)		(4,942	)		(2,027	)
		148,678			137,142			414,777			353,112
Financing activities
Payments of dividends or distributions		(52,037	)		(46,078	)		(156,056	)		(142,486	)
Increase (decrease) in bank loan		39,694			(21,808	)		56,448			52,503
Proceeds from issuance of long-term debt (note 12)		–			–			145,810			–
Issuance of common shares or trust units (note 15)		5,148			6,520			33,626			18,167
Interest paid		(14,982	)		(13,018	)		(31,370	)		(26,494	)
		(22,177	)		(74,384	)		48,458			(98,310	)
Investing activities
Additions to exploration and evaluation assets (note 7)		(566	)		(15,206	)		(8,010	)		(30,055	)
Additions to oil and gas properties		(99,802	)		(44,353	)		(287,825	)		(142,214	)
Property acquisitions		(28,502	)		(11,452	)		(65,835	)		(19,316	)
Corporate acquisitions (note 5)		(22	)		–			(118,693	)		(40,314	)
Proceeds from divestitures		–			18,137			–			18,137
Additions to other plant and equipment, net of disposals (note 9)		(591	)		(6,715	)		(1,416	)		(13,447	)
Acquisition of financing entities		–			–			–			(38,000	)
Change in non-cash working capital (note 21)		1,260			(4,877	)		18,577			1,784
		(128,223	)		(64,466	)		(463,202	)		(263,425	)
Impact of foreign currency translation on cash balances		(337	)		(140	)		(33	)		(386	)
Change in cash		(2,059	)		(1,848	)		–			(9,009	)
Cash, beginning of period		2,059			3,016			–			10,177
Cash, end of period	$	–		$	1,168		$	–		$	1,168

See accompanying notes to the condensed consolidated financial statements.

NOTES TO THE CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS

As at September 30, 2011, December 31, 2010 and January 1, 2010 and for the three months and nine months ended September 30, 2011 and 2010

(all tabular amounts in thousands of Canadian dollars, except per common share and per trust unit amounts) (unaudited)

1.	REPORTING ENTITY

Baytex Energy Corp. (the “Company” or “Baytex”) is an oil and gas corporation engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and the United States. The Company’s common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 - 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 - 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

Baytex Energy Trust (the “Trust”) completed the conversion of its legal structure from an income trust to a corporation at year-end 2010 pursuant to a Plan of Arrangement under the Business Corporations Act (Alberta) (the “Arrangement”). Pursuant to the Arrangement, (i) on December 31, 2010, the trust units of the Trust were exchanged for common shares of Baytex on a one-for-one basis and (ii) on January 1, 2011, the Trust was dissolved and terminated, with Baytex being the successor to the Trust. The reorganization into a corporation has been accounted for on a continuity of interest basis, and accordingly, the condensed consolidated financial statements reflect the financial position, results of operations and cash flows as if the Company had always carried on the business formerly carried on by the Trust.

2.	BASIS OF PRESENTATION

The condensed interim unaudited consolidated financial statements (“consolidated financial statements”) have been prepared in accordance with International Accounting Standard (“IAS”) 34, Interim Financial Reporting. Canadian generally accepted accounting principles have been revised to incorporate International Financial Reporting Standards (“IFRS”) and publicly accountable enterprises are required to apply such standards for years beginning on or after January 1, 2011. Accordingly, these consolidated financial statements were prepared in accordance with IFRS 1, First-time Adoption of IFRS. The significant accounting policies set out below were consistently applied to all the periods presented. These consolidated financial statements do not include all the necessary annual disclosures in accordance with IFRS.

In these financial statements, the term “previous GAAP” refers to Canadian generally accepted accounting principles prior to the adoption of IFRS. Previous GAAP differs in some areas from IFRS. In preparing these consolidated financial statements, management has amended certain accounting, valuation and consolidation methods previously applied in the previous GAAP financial statements to comply with IFRS. The comparative figures for 2010 were restated to reflect these adjustments. The date of transition to IFRS was January 1, 2010. Reconciliations and descriptions of the effect of the transition from previous GAAP to IFRS on equity, net income and comprehensive income are included in note 25.

The consolidated financial statements were approved and authorized by the Board of Directors on November 9, 2011.

The consolidated financial statements have been prepared on the historical cost basis, except derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is rounded to the nearest thousand, except per share or per trust unit amounts and when otherwise indicated. Certain prior period balances have been reclassified for presentation purposes.

3.	SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries from the respective dates of acquisition of the subsidiary companies. The date of acquisition is the date on which the Company obtains control and the subsidiary companies continue to be consolidated until the date such control ceases. Control exists when the Company has the ability to direct the activities of an entity to generate returns from its activities. Inter-company transactions and balances are eliminated upon consolidation. A portion of the Company’s exploration, development and production activities is conducted jointly with others and involve jointly controlled assets. These jointly controlled assets are accounted for using the proportionate consolidation method whereby the consolidated financial statements reflect only the Company’s proportionate interest.

Operating Segments Reporting

Baytex’s operations are grouped into one operating segment for reporting consistent with the internal reporting provided to the chief operating decision- maker of the Company.

Measurement Uncertainty and Judgements

The preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenue and expenses during the reporting period. Actual results can differ from those estimates.

In particular, amounts recorded for depletion of oil and gas properties are based on a unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account the level of development required to produce the reserves. The Company’s total proved plus probable reserves are estimated annually using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate a 50 percent or greater statistical probability of being recovered. Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates of reserves are inherently imprecise, require the application of judgement and are subject to change as additional information becomes available. The impact of future changes to estimates on the consolidated financial statements of subsequent periods could be material.

Amounts recorded for depreciation are based on estimated useful lives of depreciable assets; management reviews these estimates at each reporting date.

The Company’s capital assets are aggregated into cash-generating units based on their ability to generate largely independent cash flows and are used for impairment testing. The definition of the Company’s cash-generating units is subject to Management’s judgement.

Impairment of assets and group of assets are based on the higher of calculations of value-in-use calculations and fair value less costs to sell. These calculations require the use of estimates and assumptions on highly uncertain matters such as future commodity prices, effects of inflation and technology improvements on operating expenses, production profiles and the outlook of market supply-and-demand conditions for oil and gas products. Any changes to these estimates and assumptions could impact the carrying value of assets. The Company assesses internal and external indicators of impairment in determining whether the carrying values of the assets may not be recoverable.

Fair value of financial instruments, where active market quotes are not available are estimated using the Company’s assessment of available market inputs and are described in note 22. These estimates may vary from the actual prices that will be achieved upon settlement of the financial instruments.

Fair values of share-based compensation are measured at the later of grant date or December 31, 2010, taking into consideration management’s best estimate of the number of shares that will vest. Fair values of unit-based compensation were remeasured at each reporting date until the December 31, 2010 corporate conversion using a binomial-lattice pricing model, taking into consideration management’s best estimate of the expected volatility, expected life of the option and estimated number of units that will vest.

The amounts recorded for asset retirement costs are estimated based on the Company’s net ownership interest in all wells and facilities, estimated 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. Any changes to these estimates could change the amount recorded for asset retirement obligations and may materially impact the consolidated financial statements of future periods.

The Company is engaged in litigation and claims arising in the normal course of operations where the actual outcome may vary from the amount recognized in the consolidated financial statements. None of these claims could reasonably be expected to materially affect the Company’s financial position or reported results of operations.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting. The cost of an acquisition is measured as cash paid and the fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and liabilities assumed, including contingent liabilities are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair value of the net identifiable assets acquired is recognized as goodwill. Any deficiency of the cost of acquisition below the fair values of the identifiable net assets acquired is credited to net income in the statements of income and comprehensive income in the period of acquisition. Associated transaction costs are expensed when incurred.

Crude Oil Inventory

Crude oil inventory, consisting of production in transit in pipelines at the reporting date, is valued at the lower of cost, using the weighted average cost method, or net realizable value. Costs include direct and indirect expenditures incurred in bringing the crude oil to its existing condition and location.

Exploration and Evaluation Assets, Oil and Gas Properties and Other Plant and Equipment

a)	Pre-license Costs

Pre-license costs are costs incurred before the legal rights to explore a specific area have been obtained. These costs are expensed in the period in which they are incurred.

b)	Exploration and Evaluation (“E&E”) Costs

Once the legal right to explore has been acquired, costs directly associated with an exploration well are capitalized as an intangible asset until the drilling of the well program/project is complete and the results have been evaluated. Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing. E&E costs are not depleted and are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determined. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when proved and/or probable reserves are determined to exist. All such carried costs are subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the impairment costs are charged to exploration and evaluation expense. Upon determination of proven and/or probable reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified to oil and gas properties.

c)	Development Costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as oil and gas properties only when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves and are accumulated on a geotechnical area basis.

Major maintenance and repairs consist of the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and has been completely written off is replaced and it is probable that there are future economic benefits associated with the item, the expenditure is capitalized. The costs of the day-to-day servicing of property, plant and equipment are recognized in net income as incurred.

The carrying amount of any replaced or sold component of an oil and gas property is derecognized and included in net income in the period in which the item is derecognized.

d)	Borrowing Costs and Other Capitalized Costs

Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset form part of the cost of that asset. A qualifying asset is an asset that requires a period of one year or greater to get ready for its intended use or sale. Baytex has had no qualifying assets that would allow for borrowing costs to be capitalized to the asset. All such borrowing costs are expensed as incurred.

No general and administrative expenses have been capitalized since Baytex’s inception.

e)	Depletion and Depreciation

The net carrying value of oil and gas properties is depleted using the units of production method using estimated proved and probable petroleum and natural gas reserves, by reference to the ratio of production in the year to the related proven and probable reserves at forecast prices, taking into account estimated future development costs necessary to bring those reserves into production. For purposes of this calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil. Future development costs are estimated as the costs of development required to produce the reserves. These estimates are prepared by independent reserve engineers at least annually.

The depreciation methods and estimated useful lives for other assets for other plant and equipment are as follows:

Classification	Method	Rate or period
Motor Vehicles	Diminishing balance		15	%
Office Equipment	Diminishing balance		20	%
Computer Hardware	Diminishing balance		30	%
Furniture and Fixtures	Diminishing balance		10	%
Leasehold Improvements	Straight-line over life of the lease	Various
Other Assets	Diminishing balance	Various

The expected lives of other plant and equipment are reviewed on an annual basis and, if necessary, changes in expected useful lives are accounted for prospectively.

Impairment of Non-financial Assets

The goodwill balance is assessed for impairment at least annually at year end or more frequently if events or changes in circumstances indicate that the asset may be impaired. E&E assets are assessed for impairment when they are reclassified to oil and gas properties and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The Company assesses other assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable.

Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets (the “cash-generating unit” or “CGU”). Goodwill acquired is allocated to CGUs expected to benefit from synergies of the related business combination.

If any such indication of impairment exists or when annual impairment testing for a CGU is required, the Company makes an estimate of its recoverable amount. A CGU’s recoverable amount is the higher of its fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the CGU and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment amount reduces first the carrying amount of any goodwill allocated to the CGU. Any remaining impairment is allocated to the individual assets in the CGU on a pro rata basis. Impairment is charged to net income in the period in which it occurs.

For all assets excluding goodwill, an assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depletion and depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in net income. After such a reversal, the depletion or depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life. Impairment losses recognized in relation to goodwill are not reversed for subsequent increases in its recoverable amount.

Asset Retirement Obligations

The Company recognizes a liability at the discounted value for the future asset retirement costs associated with its oil and gas properties using the risk free interest rate. The present value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The discount in the liability unwinds until the date of expected settlement of the retirement obligations and is recognized as a finance cost in the statements of income and comprehensive income. The liability will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations to the extent that the liability exists on the statements of financial position.

Foreign Currency Translation

Transactions completed in foreign currencies are reflected in Canadian dollars at the foreign currency exchange rates prevailing at the time of the transactions. Monetary assets and liabilities denominated in foreign currencies are reflected in the statements of financial position at the Canadian equivalent at the foreign currency exchange rates prevailing at the reporting date. Foreign exchange gains and losses are included in net income.

Revenue Recognition

Revenue associated with sales of petroleum and natural gas is recognized when title passes to the purchaser at the pipeline delivery point. Revenue is measured net of discounts, customs duties and royalties. With respect to royalties, the Company is acting as a collection agent on behalf of the Crown and other royalty interest holders.

Revenue from the production of oil in which the Company has an interest with other producers is recognized based on the Company’s working interest and the terms of the relevant joint venture agreements.

Financial Instruments

Financial instruments are measured at fair value on initial recognition of the instrument and are classified into one of the following five categories: fair value through profit or loss (“FVTPL”), loans and receivables, held-to-maturity investments, available-for-sale financial assets or other financial liabilities.

Subsequent measurement of financial instruments is based on their initial classification. FVTPL financial assets are measured at fair value and changes in fair value are recognized in net income. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income (loss) until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest rate method.

All risk management contracts are recorded in the statements of financial position at fair value unless they were entered into and continue to be held in accordance with the Company’s expected purchase, sale and usage requirements. All changes in their fair value are recorded in net income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income until the underlying hedged transaction is recognized in net income. The Company has elected not to use cash flow hedge accounting on its risk management contracts with financial counterparties resulting in all changes in fair value being recorded in net income.

Cash is classified as FVTPL. Trade and other receivables are classified as loans and receivables, which are measured at amortized cost. Trade and other payables and the bank loan are classified as other financial liabilities, which are measured at amortized cost.

The convertible debentures have been classified as liabilities, net of the fair value of the conversion feature which has been classified as a financial derivative liability. The financial derivative liability requires a fair value method of accounting and changes in the fair value of the instrument are recognized in the net income. The liability component is classified as other financial liabilities. The liability component will accrete up to the principal balance at maturity. The accretion and the interest paid are reported as finance expense in the condensed consolidated statements of income and comprehensive income (loss). If the debentures are converted to trust units, the fair value of the conversion feature will be reclassified to unitholders’ capital along with the principal amounts converted.

An embedded derivative is a component of a contract that affects the terms of another factor. These hybrid contracts are considered to consist of a host contract plus an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative. The Company has no material embedded derivatives.

The transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability classified at FVTPL are expensed immediately. For a financial asset or financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to or deducted from the fair value on initial recognition and amortized through net income over the term of the financial instrument.

The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered into by the Company are related to underlying financial instruments or future petroleum and natural gas production. The Company does not use financial derivatives for trading or speculative purposes. These instruments are classified as FVTPL unless designated for hedge accounting. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting. As a result, for all derivative instruments, the Company applies the fair value method of accounting by recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in the statements of income and comprehensive income for the current period. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income when incurred.

The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statements of financial position. Settlements on these physical sales contracts are recognized in revenue in the period of settlement.

Income Taxes

Current and deferred income taxes are recognized in net income, except when they relate to items that are recognized directly in equity. Where current and deferred income taxes are recognized directly in equity when current income tax or deferred income tax arises from the initial accounting for a business combination, the tax effect is included in the accounting for the business combination.

Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted or substantively enacted at the end of the reporting period.

The Company follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all temporary differences deductible to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.

Share Rights Plan and Share Award Incentive Plan

The Trust’s Trust Unit Rights Incentive Plan (the “Unit Rights Plan”), which was superseded by the Company’s Common Share Rights Incentive Plan (the “Share Rights Plan”), is described in note 16. The exercise price of the share rights under the Share Rights Plan may be reduced in future periods in accordance with the terms of the Share Rights Plan.

Prior to the conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability was re-measured at each reporting date and at settlement date. Any changes in fair value were recognized in net income for the period. The conversion of the outstanding unit rights to share rights in connection with the Arrangement effectively changed the related classification from a liability plan to an equity-settled plan. The expense recognized from the date of modification over the remainder of the vesting period was determined based on the fair value of the reclassified equity awards at the date of the modification using a binomial- lattice pricing model.

Baytex’s Share Award Incentive Plan is described in note 16.

4.	CHANGES IN ACCOUNTING POLICIES

Future Accounting Pronouncements

Financial Instruments

IASB published IFRS 9, “Financial Instruments” and replaces IAS 39 “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classifications: at amortized cost or fair value.

IFRS 9 is effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. The adoption of this standard may have an impact on the Company’s accounting for financial assets and financial liabilities.

Consolidation, Joint Ventures and Disclosures

In May 2011, the IASB issued new standards, IFRS 10, “Consolidated Financial Statements”, IFRS 11, “Joint Arrangements” and IFRS 12, “Disclosure of Interests in Other Entities”. IAS 27, “Separate Financial Statements” and IAS 28, “Investments in Associates and Joint Ventures” were amended for replaced and conforming changes based on the issuance of IFRS 10, IFRS 11 and IFRS 12. Each of the new and revised standards is effective for annual periods beginning on or after January 1, 2013, with earlier application permitted. The adoption of these standards may have an impact on the Company’s accounting.

Consolidated Financial Statements

IFRS 10, “Consolidated Financial Statements” replaces the consolidation guidance in IAS 27, “Consolidated and Separate Financial Statements” by introducing a single consolidation model for all entities based on control, irrespective of the nature of the investee. Under IFRS 10, control is based on whether an investor has 1) power over the investee; 2) exposure, or rights, to variable returns from its involvement with the investee; and 3) the ability to use its power over the investee to affect the amount of the returns.

Joint Arrangements

IFRS 11, “Joint Arrangements” replaces IAS 31, “Interest in Joint Ventures”. The new standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted.

Disclosure of Interests in Other Entities

IFRS 12, “Disclosure of Interests in Other Entities”, requires enhanced disclosures about both consolidated entities and unconsolidated entities in which an entity has involvement. The objective of IFRS 12 is to require information so that financial statement users may evaluate the basis of control, any restrictions on consolidated assets and liabilities, risk exposures arising from involvements with unconsolidated structured entities and non-controlling interest holders’ involvement in the activities of consolidated entities.

Fair Value Measurement

In May 2011, the IASB issued IFRS 13, “Fair Value Measurement” which replaces the guidance on fair value measurement in existing IFRS accounting literature with a single standard. IFRS 13 is effective for annual periods beginning on or after January 1, 2013 with early application permitted. The adoption of this standard may have an impact on the Company’s accounting.

Presentation of Financial Statements

In June 2011, the IASB amended IAS 1, “Presentation of Financial Statements” to require companies preparing financial statements in accordance with IFRSs to group together items within OCI that may be reclassified to the net income section of the income statement. The amendments also reaffirm existing requirements that items in OCI and profit or loss should be presented as either a single statement or two consecutive statements. The amendment to IAS 1 is effective for annual periods beginning on or after July 1, 2012 with earlier application permitted. The adoption of this amended standard is not expected to have a material impact on the consolidated financial statements of the Company.

5.	BUSINESS COMBINATIONS

2011 Corporate Acquisition

On February 3, 2011, Baytex acquired all the issued and outstanding shares of a private company, which was a junior heavy oil producer with operational focus in the Seal area of northern Alberta and the Lloydminster area of western Saskatchewan, for total consideration of $119.7 million (net of cash acquired). The acquisition has been accounted for as a business combination with the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:

Consideration for the acquisition:
Cash paid for exploration and evaluation assets and oil and gas properties	$	118,693
Cash paid for working capital (net of cash acquired)		979
Total consideration	$	119,672
Recognized amounts of identifiable assets acquired and liabilities assumed:
Trade and other receivables	$	1,637
Exploration and evaluation assets		14,944
Oil and gas properties		130,322
Trade and other payables		(658	)
Asset retirement obligations		(2,031	)
Deferred income tax liability		(24,542	)
Total net assets acquired	$	119,672

For the period from February 3, 2011 to September 30, 2011, the acquired properties contributed revenue of $29.5 million to Baytex’s operations. If the acquisition had occurred on January 1, 2011, management estimates that the acquired properties would have generated revenue of $32.6 million for the nine month period ended September 30, 2011. It is not possible to determine the amount of contributed net income from the acquired properties.

The fair values of assets and liabilities recognized are estimates due to the uncertainty of provisional amounts recognized. Amendments may be made to the purchase equation as the cost estimates and balances are finalized.

2011 Property Acquisition

On February 3, 2011, Baytex acquired heavy oil properties in the Seal area of northern Alberta and the Lloydminster area of western Saskatchewan, for total consideration of $37.4 million. The acquisition has been accounted for as a business combination with the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:

Consideration for the acquisition:
Cash paid	$	37,416
Total consideration	$	37,416
Recognized amounts of identifiable assets acquired and liabilities assumed:
Exploration and evaluation assets	$	1,700
Oil and gas properties		36,224
Asset retirement obligations		(508	)
Total net assets acquired	$	37,416

For the period from February 3, 2011 to September 30, 2011, the acquired properties contributed revenue of $7.4 million to Baytex’s operations. If the acquisition had occurred on January 1, 2011, management estimates that the acquired properties would have generated revenue of $8.2 million for the nine month period ended September 30, 2011. It is not possible to determine the amount of contributed net income from the acquired properties.

2010 Corporate Acquisition

On May 26, 2010, Baytex acquired all the issued and outstanding shares of a private company, which was a junior heavy oil producer with operational focus in east central Alberta through to west central Saskatchewan, for total consideration of $40.3 million (net of cash acquired). The acquisition has been accounted for as a business combination with the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:

Consideration for the acquisition:
Cash paid (net of cash acquired)	$	40,314
Total consideration	$	40,314
Recognized amounts of identifiable assets acquired and liabilities assumed:
Trade and other receivables	$	1,722
Exploration and evaluation assets		2,534
Oil and gas properties		48,313
Trade and other payables		(1,436	)
Asset retirement obligations		(2,207	)
Deferred income tax liability		(8,612	)
Total net assets acquired	$	40,314

For the period from May 26, 2010 to December 31, 2010, the acquired properties contributed revenue of $8.7 million to Baytex’s operations. If the acquisition had occurred on January 1, 2010, management estimates that the acquired properties would have generated revenue of $14.9 million for the year ended December 31, 2010. It is not possible to determine the amount of contributed net income from the acquired properties.

6.	TRADE AND OTHER RECEIVABLES

As at	September 30, 2011			December 31, 2010			January 1, 2010
Petroleum and natural gas sales and accrual	$	133,064		$	119,827		$	107,657
Joint venture		39,944			30,536			28,581
Prepaid, deposits and other		7,368			3,282			3,252
Allowance for doubtful accounts		(1,008	)		(1,853	)		(2,336	)
	$	179,368		$	151,792		$	137,154

7.	EXPLORATION AND EVALUATION ASSETS

Cost
As at January 1, 2010	$	124,621
Capital expenditures		37,411
Corporate acquisition		2,534
Exploration and evaluation expense		(18,913	)
Transfer to oil and gas properties		(29,116	)
Divestitures		(113	)
Foreign currency translation		(3,342	)
As at December 31, 2010	$	113,082
Capital expenditures		8,010
Corporate acquisition		14,944
Property acquisition		8,764
Exploration and evaluation expense		(7,562	)
Transfer to oil and gas properties		(12,949	)
Foreign currency translation		2,414
As at September 30, 2011	$	126,703

8.	OIL AND GAS PROPERTIES

Cost
As at January 1, 2010	$	1,512,035
Capital expenditures		218,651
Corporate acquisition		48,313
Transferred from exploration and evaluation assets		29,116
Change in asset retirement obligations		21,766
Divestitures		(4,072	)
Foreign currency translation		(6,458	)
As at December 31, 2010	$	1,819,351
Capital expenditures		292,523
Corporate acquisition		130,322
Property acquisitions		59,936
Transferred from exploration and evaluation assets		12,949
Change in asset retirement obligations		38,035
Foreign currency translation		10,027
As at September 30, 2011	$	2,363,143

Accumulated depletion
As at January 1, 2010	$	–
Depletion for the period		195,015
Divestitures		(107	)
Foreign currency translation		(186	)
As at December 31, 2010	$	194,722
Depletion for the period		173,872
Foreign currency translation		573
As at September 30, 2011	$	369,167

Carrying value
As at January 1, 2010	$	1,512,035
As at December 31, 2010	$	1,624,629
As at September 30, 2011	$	1,993,976

9.	OTHER PLANT AND EQUIPMENT

Cost
As at January 1, 2010	$	49,341
Capital expenditures		8,473
Disposals		(236	)
Foreign currency translation		(54	)
As at December 31, 2010	$	57,524
Capital expenditures		1,416
Foreign currency translation		49
As at September 30, 2011	$	58,989

Accumulated depreciation
As at January 1, 2010	$	22,245
Depreciation		7,781
Disposals		(26	)
Foreign currency translation		(26	)
As at December 31, 2010	$	29,974
Depreciation		2,647
Foreign currency translation		35
As at September 30, 2011	$	32,656

Carrying value
As at January 1, 2010	$	27,096
As at December 31, 2010	$	27,550
As at September 30, 2011	$	26,333

Field inventory held is valued at the lower of cost, using the weighted average cost method, or net realizable value and is not depreciated.

10.

BANK LOAN

As at		September 30, 2011				December 31, 2010				January 1, 2010
Bank loan		$	368,184			$	303,773			$	265,088

Baytex Energy Ltd. (“Baytex Energy”), a wholly-owned subsidiary of Baytex, has established credit facilities with a syndicate of chartered banks. On June 14, 2011, Baytex Energy reached agreement with its lending syndicate to amend the credit facilities to (i) increase the amount available under the facilities to $700 million (from $650 million), (ii) extend the revolving period from 364 days (with a one-year term out following the revolving period) to three years, which is extendible annually for a 1, 2 or 3 year period (subject to a maximum three-year term at any time), and (iii) change the structure of the facilities from reserves-based to covenant- based (with standard commercial covenants for facilities of this nature). The credit facilities do not require any mandatory principal payments during the three-year term. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offer Rates, plus applicable margins. The credit facilities are secured by a floating charge over all of Baytex Energy’s assets and are guaranteed by us and certain of our material subsidiaries. The credit facilities do not include a term-out feature or a borrowing base restriction. In the event that we do not comply with covenants under the credit facilities, our ability to pay dividends to shareholders may be restricted.

11.	TRADE AND OTHER PAYABLES

As at	September 30, 2011		December 31, 2010		January 1, 2010
Trade payables	$	101,081	$	79,841	$	79,150
Joint venture		16,397		12,284		14,924
Capital and operating expense accruals		96,550		77,656		75,471
Other		7,932		13,533		16,971
	$	221,960	$	183,314	$	186,516

12.	LONG-TERM DEBT

As at	September 30, 2011		December 31, 2010		January 1, 2010
9.15% senior unsecured debentures (Cdn$150,000 – principal)	$	147,216	$	146,893	$	146,498
6.75% senior unsecured debentures (US$150,000 – principal)		153,599		–		–
	$	300,815	$	146,893	$	146,498

On August 26, 2009, the Trust issued $150.0 million principal amount of Series A senior unsecured debentures bearing interest at 9.15% payable semi-annually with principal repayable on August 26, 2016. As a result of the Arrangement, Baytex assumed all of the rights and obligations of the Trust under the Series A senior unsecured debentures effective January 1, 2011. These debentures are subordinate to Baytex Energy’s bank credit facilities. After August 26 of each of the following years, these debentures are redeemable at the Company’s option, in whole or in part, with not less than 30 nor more than 60 days’ notice at the following redemption prices (expressed as a percentage of the principal amount of the debentures): 2012 at 104.575%, 2013 at 103.05%, 2014 at 101.525%, and 2015 at 100%. These notes are carried at amortized cost, net of a $3.6 million transaction cost. The notes accrete up to the principal balance at maturity using the effective interest rate of 9.6%.

On February 17, 2011, Baytex issued US$150.0 million principal amount of Series B senior unsecured debentures bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. These debentures are subordinate to Baytex Energy’s bank credit facilities. After February 17 of each of the following years, these debentures are redeemable at the Company’s option, in whole or in part, with not less than 30 nor more than 60 days’ notice at the following redemption prices (expressed as a percentage of the principal amount of the debentures): 2016 at 103.375%, 2017 at 102.25%, 2018 at 101.525%, and 2019 at 100%. These notes are carried at amortized cost, net of a $2.2 million transaction cost. These notes accrete up to the principal balance at maturity using the effective interest rate of 7.0%.

Accretion expense on debentures of $0.1 million has been recorded for the three months ended September 30, 2011 (three months ended September 30, 2010 – $0.1 million) and $0.4 million for the nine months ended September 30, 2011 (nine months ended September 30, 2010 – $0.3 million).

13.	CONVERTIBLE DEBENTURES

	Number of Convertible Debentures			Convertible Debentures			Conversion Feature of Debentures
Balance, January 1, 2010		7,815		$	7,736		$	7,354
Conversion		(7,474	)		(7,426	)		(12,473	)
Accretion		–			31			–
Loss on financial derivative		–			–			5,119
Repayment on maturity		(341	)		(341	)		–
Balance, December 31, 2010 and September 30, 2011		–		$	–		$	–

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 paid interest semi-annually and were 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. On the December 31, 2010 maturity date, the outstanding $0.3 million principal amount was repaid at par value.

The debentures were classified as debt net of the fair value of the conversion feature which was classified as a financial derivative liability. This resulted in $95.2 million being classified as debt and $4.8 million being initially classified as a financial derivative liability. The debt portion accreted up to the principal balance at maturity, using the effective interest rate of 7.6%. The accretion and the interest paid were expensed as a finance expense in the condensed consolidated statements of income and comprehensive income. When debentures were converted to trust units, the fair value of the conversion feature under financial derivative liability was reclassified to unitholders’ capital along with the principal amounts converted.

14.	ASSET RETIREMENT OBLIGATIONS

	September 30, 2011			December 31, 2010
Balance, beginning of period	$	169,611		$	141,869
Liabilities incurred		4,697			2,030
Liabilities settled		(4,942	)		(2,829	)
Liabilities acquired		5,003			2,207
Liabilities divested		(108	)		(1,254	)
Accretion		4,558			5,862
Change in estimate(1)		38,035			21,766
Foreign currency translation		75			(40	)
Balance, end of period	$	216,929		$	169,611

(1)	Changes in the status of wells, changes in discount rates and changes in the estimated costs of abandonment and reclamation are factors resulting in a change in estimate.

The Company’s asset retirement obligations are based on its net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities using existing technology and the estimated time period during which these costs will be incurred in the future. These costs are expected to be incurred over the next 52 years. The undiscounted amount of estimated cash flow required to settle the asset retirement obligations using an estimated annual inflation rate of 2.0% at September 30, 2011 is $312.5 million (December 31, 2010 – $288.8 million, January 1, 2010 – $279.3 million). The amount of estimated cash flow required to settle the asset retirement obligations using an estimated annual inflation rate of 2.0% and discounted at a risk free rate of 3.0% at September 30, 2011 (December 31, 2010 – 3.5% and January 1, 2010 – 4.0%) is $216.9 million (December 31, 2010 – $169.6 million and January 1, 2010 – $141.9 million).

15.	SHAREHOLDERS’/UNITHOLDERS’ CAPITAL

Unitholders’ Capital

	Number of Trust Units			Amount
Balance, January 1, 2010		109,299		$	1,331,161
Issued on conversion of debentures		507			19,897
Issued on exercise of unit rights		2,337			26,021
Transfer from unit-based payment liability on exercise of unit rights		–			56,628
Issued pursuant to distribution reinvestment plan		1,569			51,699
Change in effective tax rate on issue costs		–			(1,071	)
Exchanged for shares, pursuant to the Arrangement		(113,712	)		(1,484,335	)
Balance, December 31, 2010 and September 30, 2011		–		$	–

Shareholders’ Capital

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10,000,000 preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at September 30, 2011, no preferred shares have been issued by the Company and all common shares issued were fully paid.

	Number of Common Shares		Amount
Balance, January 1, 2010		–	$	–
Issued for units, pursuant to the Arrangement		113,712		1,484,335
Balance, December 31, 2010		113,712	$	1,484,335
Issued on exercise of share rights		1,982		33,626
Transfer from contributed surplus on exercise of share rights		–		58,458
Issued pursuant to dividend reinvestment plan		1,061		51,470
Balance, September 30, 2011		116,755	$	1,627,889

Baytex has a Dividend Reinvestment Plan (the “DRIP”) that allows eligible holders in Canada and the United States to reinvest their monthly cash dividends to acquire additional common shares. At the discretion of Baytex, common shares will either be issued from treasury or acquired in the open market at prevailing market prices. Pursuant to the terms of the DRIP, common shares issued from treasury are currently issued at a five percent discount to the arithmetic average of the daily volume weighted average trading prices of the common shares on the Toronto Stock Exchange (in respect of participants resident in Canada or any jurisdiction other than the United States) or the New York Stock Exchange (in respect of participants resident in the United States) for the period commencing on the second business day after the dividend record date and ending on the second business day immediately prior to the dividend payment date. Baytex reserves the right at any time to change or eliminate the discount on common shares acquired through the DRIP from treasury.

The holders of common shares or trust units may receive dividends or distributions as declared from time to time and are entitled to one vote per share or trust unit at any meetings of the holders of common shares or trust units. All common shares rank among themselves equally and with regard to the Company’s net assets in the event of termination or winding-up of the Company.

Dividends of $0.20 per common share per month were declared by the Company during the three months and nine months ended September 30, 2011. Total dividends declared were $69.9 million for the three months ended September 30, 2011, and $208.1 million for the nine months ended September 30, 2011. Distributions of $0.20 per trust unit in December 2010 and $0.18 per trust unit for each of the previous eleven months were declared by the Trust during the year ended December 31, 2010 for total distributions declared of $243.4 million.

Subsequent to September 30, 2011, the Company announced that a dividend in respect of October 2011 operations of $0.20 per common share ($23.5 million) would be paid on November 15, 2011 to shareholders of record on October 31, 2011.

16.	EQUITY BASED PLANS

Share Rights Plan

The Trust had a Unit Rights Plan pursuant to which rights to acquire trust units (“unit rights”) were granted to eligible directors, officers and employees of the Trust and its subsidiaries. The maximum number of trust units issuable pursuant to the Unit Rights Plan was a “rolling” maximum equal to 10% of the outstanding trust units plus the number of trust units which were issuable on the exchange of outstanding exchangeable shares. Any increase in the issued and outstanding trust units resulted in an increase in the number of trust units available for issuance under the Unit Rights Plan, and any exercises of unit rights made new grants available under the Unit Rights Plan, effectively resulting in a re-loading of the number of unit rights available to grant under the Unit Rights Plan. Under the Unit Rights Plan, unit rights had a maximum term of five years and vested and became exercisable as to one-third on each of the first, second and third anniversaries of the grant date.

The Unit Rights Plan provided that the exercise price of the unit rights may be reduced to account for future distributions, subject to certain performance criteria. Effective November 16, 2009, the Unit Rights Plan was amended to (i) base the exercise price of unit rights on the closing price of the trust units on the trading day prior to the date of grant (previously based on a five-day volume weighted average trading price) and (ii) permit the granting of unit rights with a fixed exercise price. Effective October 25, 2010, the Unit Rights Plan was amended to provide holders of unit rights who are not subject to taxation in the United States with the ability to elect at the time of exercise to pay an exercise price per unit right equal to (i) the original exercise price reduced for distributions paid subsequent to grant date or (ii) the original exercise price.

Pursuant to the terms of the Unit Rights Plan, the Arrangement (as described in note 1) constituted a capital reorganization which resulted in each holder of unit rights exchanging such rights for equivalent rights to acquire common shares of Baytex (“share rights”) on a one-for-one basis on December 31, 2010. The share rights are subject to the terms of the Share Rights Plan. The Share Rights Plan is substantially similar to the Unit Rights Plan other than amendments necessary to reflect:

●

The entitlement of holders to receive common shares instead of trust units;

●

The exercise price, as calculated for unit rights outstanding at the effective time of the Arrangement, will be carried forward under the Share Rights Plan and, if applicable, future adjustments to the exercise price after the completion of the Arrangement will be based on dividends paid on the common shares of Baytex rather than distributions paid on the trust units of the Trust; and

●

The administration of the Share Rights Plan will be carried out by Baytex as opposed to Baytex Energy.

As a result of the adoption of the Share Award Incentive Plan (as described below), no further grants will be made under the Share Rights Plan effective January 1, 2011.

Baytex recorded compensation expense of $3.9 million for the three months ended September 30, 2011 (three months ended September 30, 2010 – $35.0 million) and $13.7 million for the nine month ended September 30, 2011 (nine months ended September 30, 2010 – $63.1 million) related to the share rights under the Share Rights Plan or the unit rights under the Unit Rights Plan.

Baytex uses a binomial-lattice pricing model to calculate the estimated weighted average fair value of the share rights and unit rights. The following assumptions were used to arrive at the estimate of fair values at each reporting date, with the expense recognized from the December 31, 2010 date of modification over the remainder of the vesting period determined based on the fair value of the reclassified unit rights at the date of the modification:

As at	December 31, 2010			January 1, 2010
Expected annual exercise price reduction (on unit rights or share rights with declining exercise price)	Various			$2.16
Share or unit price	$46.61			$29.70
Expected volatility(1)		43.8	%		43.4	%
Risk free interest rate		1.99	%		2.57	%
Forfeiture rate		4.6	%		4.6	%

(1)	Expected volatility is estimated by considering the historical average price volatility of the common shares/trust units commensurate with the term of the right.

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

	Number of share or unit rights (000’s)			Weighted average exercise price(1)
Balance, January 1, 2010		8,120		$	16.68
Granted(2)		190			32.71
Exercised		(2,337	)		11.13
Forfeited		(212	)		20.35
Balance, December 31, 2010		5,761		$	17.02
Granted		–			–
Exercised		(1,982	)		16.97
Forfeited		(74	)		22.63
Balance, September 30, 2011		3,705		$	16.84

(1)	Weighted average exercise price reflects the grant price less the reduction in exercise price.

(2)	Weighted average exercise price of rights granted is based on the exercise price at the date of grant.

The following table summarizes information about the share rights outstanding at September 30, 2011:

		Exercise Prices Applying Original Grant Price										Exercise Prices Applying Original Grant Price Reduced for Dividends and Distributions Subsequent to Grant Date
PRICE RANGE		Number Outstanding at September 30, 2011 (000’s)		Weighted Average Grant Price		Weighted Average Remaining Term (years)		Number Exercisable at September 30, 2011 (000’s)		Weighted Average Exercise Price		Number Outstanding at September 30, 2011 (000’s)		Weighted Average Exercise Price		Weighted Average Remaining Term (years)		Number Exercisable at September 30, 2011 (000’s)		Weighted Average Exercise Price
$	5.08 to $12.00		–	$	–		–		–	$	–		1,931	$	11.47		1.7		1,299	$	11.39
$	12.01 to $19.00		1,437		17.69		2.1		667		17.77		417		16.76		2.2		222		16.32
$	19.01 to $26.00		987		20.29		1.3		919		20.15		1,045		23.23		3.0		342		22.65
$	26.01 to $33.00		1,229		27.94		3.2		348		27.93		280		27.97		3.3		77		28.05
$	33.01 to $40.00		49		35.71		3.9		8		34.60		29		34.95		3.9		2		34.56
$	40.01 to $47.72		3		44.96		4.2		–		–		3		43.03		4.2		–		–
$	5.08 to $47.72		3,705	$	22.04		2.2		1,942	$	20.78		3,705	$	16.84		2.2		1,942	$	14.62

Share Award Incentive Plan

In connection with the Arrangement, the unitholders of the Trust approved, at a special meeting held on December 9, 2010, the adoption by the Company effective January 1, 2011 of a full-value award plan (the “Share Award Incentive Plan”) pursuant to which restricted awards and performance awards (collectively, “share awards”) may be granted to the directors, officers and employees of the Company and its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plan of the Company, including the Share Rights Plan) shall not at any time exceed 10% of the then issued and outstanding common shares.

Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents as described below) with such common shares to be issued as to one-third on each of the first, second and third anniversary dates of the date of grant. Each performance award entitles the holder to be issued as to one-third on each of the first, second and third anniversary dates of the date of grant the number of common shares designated in the performance award (plus dividend equivalents as described below) multiplied by a payout multiplier. The payout multiplier is dependent on the performance of the Company relative to pre-defined corporate performance measures for a particular period. In the case of both restricted and performance awards, the number of common shares to be issued on the applicable issue date is adjusted to account for the payment of dividends from the grant date to the applicable issue date.

The Company recorded compensation expense of $5.9 million for the three months ended September 30, 2011 and $11.5 million for the nine months ended September 30, 2011 related to the share awards ($nil for the three months and nine months ended September 30, 2010).

The fair value of share awards is determined at the date of grant using the closing price of the common shares and, for performance awards, an estimated payout multiplier. The amount of compensation expense is reduced by an estimated forfeiture rate, which has been estimated at 4.6% of outstanding awards. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. The estimated weighted average fair value for share awards is $50.71 per restricted award and $83.04 per performance award issued during the nine months ended September 30, 2011 (no share awards were issued during the three months and nine months ended September 30, 2010).

The number of share awards outstanding is detailed below:

	Number of restricted awards (000’s)			Number of performance awards (000’s)			Number of share awards (000’s)
Balance, January 1, 2010 and December 31, 2010		–			–			–
Granted		370			235			605
Forfeited		(10	)		(3	)		(13	)
Balance, September 30, 2011		360			232			592

Under the terms of the Share Award Incentive Plan, the Compensation Committee of the Board of Directors of Baytex has the authority to approve the granting of share awards. The Compensation Committee’s historical practice is to split the share award into two equal amounts, with 50% granted immediately and 50% granted six months subsequent to the initial grant date (with such grant being conditional on the grantee continuing to be employed by the Company or its subsidiaries on such date).

17.	NET INCOME PER SHARE AND PER TRUST UNIT

Baytex calculates basic income per share and per trust unit based on the net income attributable to shareholders or unitholders and a weighted average number of shares or units outstanding during the period. Diluted income per share or trust unit amounts reflect the potential dilution that could occur if share rights or unit rights were exercised, share awards were converted and convertible debentures were converted. The treasury stock method is used to determine the dilutive effect of share rights or unit rights whereby any proceeds from the exercise of share rights or unit rights or other dilutive instruments and the amount of compensation expense, if any, attributed to future services not yet recognized are assumed to be used to purchase common shares or trust units at the average market price during the periods.

	Three Months Ended September 30, 2011						Three Months Ended September 30, 2010
	Net income		Common Shares (000’s)		Net income per share		Net income		Trust units (000’s)		Net income per unit
Net income – basic	$	51,839		116,404	$	0.45	$	23,319		111,710	$	0.21
Dilutive effect of share rights or unit rights		–		2,303				–		2,962
Dilutive effect of share awards		–		211				–		–
Conversion of convertible debentures		–		–				74		381
Net income – diluted	$	51,839		118,918	$	0.44	$	23,393		115,053	$	0.20

For the three months ended September 30, 2011, nil share rights (three months ended September 30, 2010 – 0.3 million unit rights) were excluded in calculating the weighted average number of diluted common shares outstanding as they were anti-dilutive.

	Nine Months Ended September 30, 2011						Nine Months Ended September 30, 2010
	Net income		Common Shares (000’s)		Net income per share		Net income		Trust units (000’s)		Net income per unit
Net income – basic	$	159,652		115,477	$	1.38	$	210,260		110,926	$	1.90
Dilutive effect of share rights or unit rights		–		2,808				–		3,104
Dilutive effect of share awards		–		193				–		–
Conversion of convertible debentures		–		–				252		430
Net income – diluted	$	159,652		118,478	$	1.35	$	210,512		114,460	$	1.84

For the nine months ended September 30, 2011, nil share rights (nine months ended September 30, 2010 – 1.3 million unit rights) were excluded in calculating the weighted average number of diluted common shares outstanding as they were anti-dilutive.

18.	INCOME TAXES

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

	Nine Months Ended September 30
	2011			2010
Net income before income taxes	$	199,372		$	95,317
Expected income taxes at the statutory rate of 26.97% (2010 – 28.49%)		53,771			27,156
Increase (decrease) in income taxes resulting from:
Net income of the Trust prior to the Arrangement		–			(38,156	)
Non-taxable portion of foreign exchange loss (gain)		2,105			(431	)
Non-deductible (taxable) items		113			(3,426	)
Share-based or unit-based compensation		6,790			17,969
Effect of change in income tax rates		(4,629	)		2,002
Effect of rate adjustments for foreign jurisdictions		(2,489	)		(2,808	)
Effect of change in opening tax pool balances		(14,817	)		(7,500	)
Effect of change in valuation allowance		(1,558	)		–
Deferred credit(1)		–			(109,800	)
Other		434			51
Deferred income tax expense (recovery)	$	39,720		$	(114,943	)

(1)

In May 2010, Baytex acquired a number of private entities for use in its internal financing structure for approximately $38.0 million. The transaction resulted in the recognition of a future income tax asset of approximately $147.8 million with a corresponding deferred credit of $109.8 million recognized under previous GAAP, reflecting the difference between the future income tax asset recognized on the transaction and the cash paid. Under IFRS, the deferred credit is derecognized through net income as a deferred income tax recovery.

The components of the net deferred income tax liability are as follows:

As at	September 30, 2011			December 31, 2010			January 1, 2010
Deferred income tax liabilities:
Petroleum and natural gas properties	$	(271,030	)	$	(224,923	)	$	(196,118	)
Financial derivatives		(14,128	)		(4,463	)		(9,432	)
Partnership deferral		(82,767	)		(52,327	)		(2,921	)
Other		(2,654	)		(5,025	)		(3,875	)
Deferred income tax assets:
Asset retirement obligations		56,541			43,339			36,446
Financial derivatives		8,392			7,870			1,789
Non-capital losses		232,903			227,149			13,185
Finance costs		2,263			1,867			1,996
Net deferred income tax liability(1)	$	(70,480	)	$	(6,513	)	$	(158,930	)

(1)	Non-capital loss carry-forwards totaled $854.4 million (December 31, 2010 – $842.3 million, January 1, 2010 – $48.4 million) and expire from 2014 to 2031.

19.

REVENUES

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Petroleum and natural gas revenues	$	313,247		$	237,695		$	938,850		$	740,159
Royalty charges		(50,656	)		(42,750	)		(150,617	)		(135,797	)
Royalty income		540			581			2,151			1,480
Revenues, net of royalties	$	263,131		$	195,526		$	790,384		$	605,842

20.	FINANCING COSTS

Baytex incurred financing costs on its outstanding liabilities as follows:

	Three Months Ended September 30					Nine Months Ended September 30
	2011		2010			2011		2010
Bank loan and other	$	2,583	$	3,616		$	9,389	$	9,213
Long-term debt		6,088		3,823			16,793		10,763
Accretion on asset retirement obligations		1,558		1,473			4,558		4,331
Convertible debentures		–		(93	)		–		155
Debt financing costs		154		11			2,998		1,425
Financing costs	$	10,383	$	8,830		$	33,738	$	25,887

21.	SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Trade and other receivables	$	12,373		$	17,270		$	(27,577	)	$	2,799
Crude oil inventory		(763	)		101			1,039			912
Trade and other payables		(13,361	)		(2,384	)		42,865			7,883
Foreign exchange		1,253			(237	)		697			(386	)
	$	(498	)	$	14,750		$	17,024		$	11,208
Changes in non-cash working capital related to:
Operating activities	$	(1,758	)	$	19,627		$	(1,553	)	$	9,424
Investing activities		1,260			(4,877	)		18,577			1,784
	$	(498	)	$	14,750		$	17,024		$	11,208

Foreign Exchange

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Unrealized foreign exchange loss (gain)	$	24,257		$	(5,321	)	$	14,655		$	(2,824	)
Realized foreign exchange (gain) loss		(4,418	)		903			(2,752	)		(1,186	)
Foreign exchange loss (gain)	$	19,839		$	(4,418	)	$	11,903		$	(4,010	)

22.	FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Company’s financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, dividends or distributions payable to shareholders or unitholders, bank loan, financial derivatives, long-term debt and convertible debentures.

Categories of Financial Instruments

The estimated fair values of the financial instruments have been determined based on the Company’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 debt, are equal to their carrying amounts due to the short-term maturity of these instruments. The fair value of the bank loan approximates its carrying value as it is at a market rate of interest. The fair value of the long-term debt is based on the lower of trading value and the present value of future cash flows associated with the debentures.

Fair Value of Financial Instruments

Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments:

●

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.

The carrying value and fair value of the Company’s financial instruments on the condensed consolidated statements of financial position are classified into the following categories:

As at	September 30, 2011						December 31, 2010						January 1, 2010
	Carrying Value			Fair Value			Carrying Value			Fair Value			Carrying Value			Fair Value			Fair Value Measurement Hierarchy
Financial Assets
FVTPL
Cash	$	–		$	–		$	–		$	–		$	10,177		$	10,177		Level 1
Derivatives		55,471			55,471			16,543			16,543			31,994			31,994		Level 2
Total FVTPL	$	55,471		$	55,471		$	16,543		$	16,543		$	42,171		$	42,171
Loans and receivables
Trade and other receivables	$	179,368		$	179,368		$	151,792		$	151,792		$	137,154		$	137,154			–
Total loans and receivables	$	179,368		$	179,368		$	151,792		$	151,792		$	137,154		$	137,154
Financial Liabilities
FVTPL
Derivatives	$	(32,947	)	$	(32,947	)	$	(29,171	)	$	(29,171	)	$	(13,422	)	$	(13,422	)	Level 2
Total FVTPL	$	(32,947	)	$	(32,947	)	$	(29,171	)	$	(29,171	)	$	(13,422	)	$	(13,422	)
Other financial liabilities
Trade and other payables	$	(221,960	)	$	(221,960	)	$	(183,314	)	$	(183,314	)	$	(186,516	)	$	(186,516	)		–
Dividends or distributions payable to shareholders/unitholders		(23,351	)		(23,351	)		(22,742	)		(22,742	)		(19,674	)		(19,674	)		–
Bank loan		(368,184	)		(368,184	)		(303,773	)		(303,773	)		(265,088	)		(265,088	)		–
Convertible debentures		–			–			–			–			(7,736	)		(7,736	)		–
Long-term debt		(300,815	)		(315,585	)		(146,893	)		(163,875	)		(146,498	)		(162,750	)	Level 1
Total other financial liabilities	$	(914,310	)	$	(929,080	)	$	(656,722	)	$	(673,704	)	$	(625,512	)	$	(641,764	)

Financial Risk

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

Market Risk

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

Foreign currency risk

Baytex is exposed to fluctuations in foreign currency as a result of the U.S. dollar portion of its bank loan, its Series B senior unsecured debentures, crude oil sales based on U.S. dollar indices and commodity contracts that are settled in U.S. dollars. The Company’s net income and cash flow will therefore be impacted by fluctuations in foreign exchange rates.

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

At September 30, 2011, the Company had in place the following currency derivative contracts:

Type	Period	Amount per month	Sales Price		Reference
Monthly forward spot sale	January 2010 to December 2011	US$20.00 million		1.0204		(1	)
Monthly forward spot sale	June 2010 to June 2012	US$1.00 million		1.0250		(2	)
Monthly forward spot sale	January 2011 to June 2012	US$3.00 million		1.0622		(2	)
Monthly forward spot sale	January 2011 to August 2012	US$1.00 million		1.0565		(2	)
Monthly forward spot sale	January 2011 to September 2012	US$1.50 million		1.0553		(2	)
Monthly forward spot sale	November 2011 to October 2013	US$1.00 million		1.0433		(2	)
Monthly forward spot sale	Calendar 2012	US$4.50 million		0.9940		(3	)
Monthly average rate forward	Calendar 2012	US$1.25 million		1.0209		(3	)
Monthly spot collar	Calendar 2012	US$0.75 million		0.9524 - 1.0503		(2	)
Monthly spot collar	Calendar 2012	US$0.25 million		1.0200 - 1.0700		(2	)
Monthly average collar	Calendar 2012	US$0.25 million		0.9700 - 1.0310		(2	)
Monthly average collar	Calendar 2012	US$0.50 million		0.9750 - 1.0305		(2	)
Monthly average collar	Calendar 2012	US$0.75 million		1.0225 - 1.0425		(2	)
Monthly average collar	Calendar 2012	US$0.25 million		1.0295 - 1.0545		(2	)
Monthly forward spot sale	Calendar 2013	US$4.50 million		1.0007		(3	)
Monthly average rate forward	Calendar 2013	US$0.25 million		1.0023		(2	)
Monthly average collar	Calendar 2013	US$0.25 million		0.9700 - 1.0310		(2	)

(1)	Based on the weighted average rate on the remaining life of 20 contracts (CAD/USD).

(2)	Actual contract rate (CAD/USD).

(3)	Based on the weighted average contract rates (CAD/USD).

The following table demonstrates the effect of movements in the Canada – United States exchange rate on net income before income taxes and comprehensive income due to changes in the fair value of the currency swaps as well as gains and losses on the revaluation of U.S. dollar denominated monetary assets and liabilities at September 30, 2011.

$0.01 Increase (Decrease) in CAD/USD Exchange Rate
Loss (gain) on currency derivative contracts	$	3,048
Loss (gain) on other monetary assets/liabilities		2,498
Impact on net income before income taxes and comprehensive income	$	5,546

The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities at the reporting date are as follows:

	Assets			Liabilities
	September 30, 2011	December 31, 2010	January 1, 2010	September 30, 2011	December 31, 2010	January 1, 2010
U.S. dollar denominated	US$125,972	US$72,663	US$67,389	US$389,714	US$230,878	US$198,690

Interest rate risk

The Company’s interest rate risk arises from its floating rate bank credit facilities. As at September 30, 2011, $368.2 million of the Company’s total debt is subject to movements in floating interest rates. A change of 100 basis points in interest rates would impact net income before taxes for the nine months ended September 30, 2011 by approximately $1.9 million. Baytex uses a combination of short-term and long-term debt to finance operations. The bank loan is typically at floating rates of interest and long-term debt is typically at fixed rates of interest.

As at September 30, 2011, Baytex had the following interest rate swap financial derivative contracts:

Type	Period	Notional Principal Amount	Fixed interest rate			Floating rate index
Swap – pay fixed, receive floating	September 27, 2011 to September 27, 2014	US$90.0 million		4.06	%	3-month LIBOR
Swap – pay fixed, received floating	September 25, 2012 to September 25, 2014	US$90.0 million		4.39	%	3-month LIBOR

When assessing the potential impact of forward interest rate changes on financial derivative contracts outstanding as at September 30, 2011, an increase or decrease of 100 basis points would result in an increase or decrease, respectively, to the unrealized gain in nine months ended September 30, 2011 by approximately $4.6 million.

Commodity Price Risk

Baytex monitors and, when appropriate, utilizes financial derivative contracts or 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 Baytex. Under the Company’s risk management policy, financial derivatives are not to be used for speculative purposes.

When assessing the potential impact of oil price changes on the financial derivative contracts outstanding as at September 30, 2011, a 10% increase would decrease the unrealized gain at September 30, 2011 by $29.3 million, while a 10% decrease would increase the unrealized gain at September 30, 2011 by $29.9 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at September 30, 2011, a 10% increase would decrease the unrealized gain at September 30, 2011 by $2.5 million, while a 10% decrease would increase the unrealized gain at September 30, 2011 by $2.2 million.

Financial Derivative Contracts

At September 30, 2011, Baytex had the following financial derivative contracts:

Oil	Period	Volume	Price/Unit(1)	Index
Fixed – Sell	February 2011 to December 2012	500 bbl/d	US$98.33	WTI
Fixed – Sell	October to December 2011	9,300 bbl/d	US$90.88	WTI
Price collar	March to December 2011	250 bbl/d	US$95.00 - 107.20	WTI
Price collar	March to December 2011	200 bbl/d	US$100.00 - 112.60	WTI
Time spread	March to December 2011	500 bbl/d	Dec 2013 plus US$1.40	WTI
Price collar	April to December 2011	100 bbl/d	US$100.00 - 117.00	WTI
Price collar	July to December 2011	500 bbl/d	US$90.00 - 95.00	WTI
Price collar	Calendar 2011	500 bbl/d	US$85.00 - 90.00	WTI
Price collar	Calendar 2011	500 bbl/d	US$85.00 - 92.50	WTI
Price collar	Calendar 2011	500 bbl/d	US$87.50 - 92.00	WTI
Price collar	Calendar 2011	500 bbl/d	US$89.00 - 92.20	WTI
Price collar	Calendar 2011	500 bbl/d	US$89.00 - 92.30	WTI
Price collar	Calendar 2011	1,000 bbl/d	US$90.00 - 98.00	WTI
Price collar	Calendar 2011	300 bbl/d	US$91.00 - 97.60	WTI
Price collar	Calendar 2011	200 bbl/d	US$91.50 - 94.85	WTI
Price collar	Calendar 2011	200 bbl/d	US$92.50 - 96.65	WTI
Fixed – Sell	Calendar 2012	5,400 bbl/d	US$91.92	WTI
Price collar	Calendar 2012	400 bbl/d	US$98.00 - 104.52	WTI
Price collar	Calendar 2012	300 bbl/d	US$100.00 - 104.90	WTI
Price collar	Calendar 2012	200 bbl/d	US$97.50 - 104.25	WTI
Price collar	Calendar 2012	300 bbl/d	US$100.00 - 105.92	WTI
Fixed – Buy	Calendar 2012	200 bbl/d	US$102.50	WTI
Fixed – Buy	January to June 2013	250 bbl/d	US$102.07	WTI
Fixed – Buy	July to December 2013	350 bbl/d	US$101.70	WTI
Fixed – Buy	Calendar 2014	380 bbl/d	US$101.06	WTI

(1)	Based on the weighted average price/unit for the remainder of the contract.

Natural Gas	Period	Volume	Price/Unit(1)	Index
Sold call	July to December 2011	3,000 mmBtu/d	US$6.25	NYMEX
Sold call	July to December 2011	3,000 mmBtu/d	US$5.00	NYMEX
Fixed – Sell	July to December 2011	6,000 mmBtu/d	US$4.61	NYMEX
Basis swap	Calendar 2011	4,000 mmBtu/d	NYMEX less US$0.615	AECO
Basis swap	Calendar 2011	2,000 mmBtu/d	NYMEX less US$0.490	AECO
Basis swap	Calendar 2012	1,500 mmBtu/d	NYMEX less US$0.490	AECO
Basis swap	Calendar 2012	1,000 mmBtu/d	NYMEX less US$0.515	AECO
Basis swap	Calendar 2012	2,000 mmBtu/d	NYMEX less US$0.520	AECO
Basis swap	Calendar 2012	2,500 mmBtu/d	NYMEX less US$0.530	AECO
Sold call	Calendar 2012	6,000 mmBtu/d	US$5.25	NYMEX
Fixed – Sell	Calendar 2012	7,000 mmBtu/d	US$5.07	NYMEX

(1)	Based on the weighted average price/unit for the remainder of the contract.

Financial derivatives are marked-to-market at the end of each reporting period, with the following reflected in the condensed consolidated statements of income and comprehensive income:

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Realized (gain) loss on financial derivatives	$	(6,227	)	$	(15,241	)	$	563		$	(36,813	)
Unrealized (gain) loss on financial derivatives		(31,016	)		12,457			(34,148	)		19,113
Gain on financial derivatives	$	(37,243	)	$	(2,784	)	$	(33,585	)	$	(17,700	)

Included in unrealized gain on financial derivatives is a loss of $1.6 million and $3.9 million for the three and nine months ended September 30, 2010, respectively ($nil for three and nine months ended September 30, 2011) relating to the conversion feature of the convertible debentures.

Subsequent to September 30, 2011, Baytex added the following financial derivative contracts:

Oil	Period	Volume	Price/Unit(1)	Index
Fixed – Sell	November to December 2011	500 bbl/d	US$92.00	WTI
Fixed – Sell	January to March 2012	1,000 bbl/d	US$91.16	WTI
Fixed – Sell	January to December 2012	300 bbl/d	US$94.15	WTI
Time Spread	January to December 2012	500 bbl/d	Dec 2014 plus US$0.65	WTI
Time Spread	January to December 2012	500 bbl/d	Dec 2014 plus US$3.25	WTI

(1)	Based on the weighted average price/unit for the remainder of the contract.

Natural Gas	Period	Volume	Price/Unit(1)	Index
Basis swap	Calendar 2012	1,000 mmBtu/d	NYMEX less US$0.450	AECO
Basis swap	Calendar 2012	1,000 mmBtu/d	NYMEX less US$0.430	AECO
Basis swap	Calendar 2012	1,000 mmBtu/d	NYMEX less US$0.410	AECO

(1)	Based on the weighted average price/unit for the remainder of the contract.

Physical Delivery Contracts

At September 30, 2011, the following physical delivery contracts were entered into and continue to be held for the purpose of delivery of non-financial items in accordance with the Company’s expected sale requirements. Physical delivery contracts are not considered financial instruments; therefore, no asset or liability has been recognized in the consolidated financial statements.

Heavy Oil	Period	Volume	Weighted Average Price/Unit(1)
WCS Blend	October to December 2011	5,000 bbl/d	WTI × 81.50%
WCS Blend	October to December 2011	5,500 bbl/d	WTI less US$15.64
WCS Blend	October 2011 to December 2014	2,000 bbl/d	WTI × 81.00%
WCS Blend	January to March 2012	1,000 bbl/d	WTI less US$13.75
WCS Blend	Calendar 2012	4,000 bbl/d	WTI less US$18.13
WCS Blend	January to June 2013	1,250 bbl/d	WTI × 80.00%
WCS Blend	January to June 2013	4,250 bbl/d	WTI less US$18.18
WCS Blend	July to December 2013	2,750 bbl/d	WTI × 80.00%
WCS Blend	July to December 2013	2,750 bbl/d	WTI less US$21.00

(1)	Based on the weighted average price/unit for the remainder of the contract.

Natural Gas	Period	Volume	Price/Unit(1)
Fixed – Sell	February to November 2011	2,500 GJ/d	AECO Cdn$5.03
Price collar	Calendar 2011	2,500 GJ/d	AECO Cdn$5.50 - 7.10
Fixed – Sell	Calendar 2011	5,000 GJ/d	AECO Cdn$4.84

(1)	Based on the weighted average price/unit for the remainder of the contract.

Subsequent to September 30, 2011, Baytex added the following physical delivery contracts:

Heavy Oil	Period	Volume	Price/Unit(1)
WCS Blend	January to March 2012	2,000 bbl/d	WTI less US$10.91
WCS Blend	April to June 2012	1,000 bbl/d	WTI less US$13.50

(1)	Based on the weighted average price/unit for the remainder of the contract.

Liquidity Risk

Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include continuously monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements and opportunities to issue additional common shares. As at September 30, 2011, Baytex had available unused bank credit facilities in the amount of $331.8 million.

The timing of cash outflows (excluding interest) relating to financial liabilities is outlined in the table below:

	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	221,960	$	221,960	$	–	$	–	$	–
Dividends payable to shareholders		23,351		23,351		–		–		–
Bank loan(1)		368,184		–		368,184		–		–
Long-term debt(2)		305,835		–		–		150,000		155,835
	$	919,330	$	245,311	$	368,184	$	150,000	$	155,835

(1)	The bank loan is a three-year covenant-based revolving loan that is extendible annually, for a one, two or three year period (subject to a maximum three-year term at any time). Unless extended, the revolving period will end on June 14, 2014 with all amounts to be re-paid on such date.

(2)	Principal amount of instruments.

Credit Risk

Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. Most of the Company’s trade and other receivables relate to petroleum and natural gas sales and are exposed to typical industry credit risks. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts with only creditworthy entities. Letters of credit and/or parental guarantees may be obtained prior to the commencement of business with certain counterparties. 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 Company considers that all financial assets that are not impaired or past due for each of the reporting dates under review are of good credit quality. None of the Company’s financial assets are secured by collateral.

Should Baytex determine that the ultimate collection of a receivable is in doubt based on the processes for managing credit risk, 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. If the Company subsequently determines that an account is uncollectible, the account is written-off with a corresponding change to allowance for doubtful accounts.

23.	CAPITAL DISCLOSURES

The Company’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.

Baytex considers its capital structure to include total monetary debt and shareholders’/unitholders’ equity. Total monetary debt is a non-GAAP measure which is the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as deferred tax assets or liabilities and unrealized gains or losses on financial derivative contracts)) and the principal amount of long-term debt. At September 30, 2011, total monetary debt was $739.2 million.

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

Baytex monitors capital based on the current and projected ratio of total monetary debt to funds from operations and the current and projected level of its undrawn bank credit facilities. Funds from operations is not a measurement based on GAAP, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash flow from operating activities before changes in non-cash working capital and other operating items. The Company’s objectives are to maintain a total monetary debt to funds 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 funds 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 funds from operations ratio and the level of undrawn bank credit facilities, the Company continuously monitors its funds from operations and evaluates its dividend policy and capital spending plans.

Although Baytex has changed its legal form to a corporation, the Company’s financial objectives and strategy over the last two completed fiscal years as described above have remained substantially unchanged. These objectives and strategy are reviewed on an annual basis and Baytex believes its financial metrics are within acceptable limits pursuant to its capital management objectives.

Baytex is subject to financial covenants relating to its senior unsecured debentures and the credit facilities of Baytex Energy. Baytex is in compliance with all financial covenants.

24.	SUBSEQUENT EVENTS

Subsequent to the end of the third quarter, Baytex Energy entered into definitive agreements to sell certain primarily-undeveloped lands in Alberta and Saskatchewan for $47.1 million.

25.	FIRST-TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

For all periods up to and including the year ended December 31, 2010, the Company prepared its financial statements in accordance with previous GAAP. The Accounting Standards Board confirmed that IFRS will replace previous GAAP for financial periods beginning January 1, 2011 with restatement required for comparative purposes of amounts reported for year ended December 31, 2010, including the opening statement of financial position as at January 1, 2010.

The Company has prepared financial statements which comply with IFRS applicable for periods beginning on or after January 1, 2011 and the significant accounting policies meeting those requirements are described in note 3.

The general principle that should be applied on first-time adoption of IFRS is that standards in force at the first reporting date should be applied retrospectively. However, IFRS 1, “First-Time Adoption of International Financial Reporting Standards”, provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas. The Company has taken all mandatory exceptions and the following optional exemptions:

●

IFRS 2, “Share-based Payment”, has not been applied to any liabilities arising from share-based payment transactions that settled before January 1, 2010.

●

Deemed costs of oil and gas assets are based on exploration and evaluation assets at the amount determined under previous GAAP and assets in the development or production phases at the amount determined for the cost centre under previous GAAP, allocated to the cost centres’ underlying assets pro rata using reserve values as of January 1, 2010.

●

IFRS Interpretations Committee (“IFRIC”) 1, “Determining whether an Arrangement contains a Lease”, transition rules have been applied that allow determination of whether any existing arrangement at January 1, 2010 contains a lease on the basis of the facts and circumstances existing at that date.

●

IFRS 3, “Business Combinations”, has not been applied to acquisitions of subsidiaries or of interests in associates and joint ventures that occurred before January 1, 2010, the Company’s date of transition.

●

Cumulative translation differences are deemed to be $nil at January 1, 2010 and deficit adjusted by the same amount.

●

Asset retirement liabilities included in the cost of property, plant and equipment are measured as at January 1, 2010 in accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”, and the difference between that amount and the carrying amount of those liabilities at January 1, 2010 determined under previous GAAP are recognized directly in deficit.

●

IAS 23, “Borrowing Costs”, transition rules have been applied that allow application of the standard to borrowing costs related to qualifying assets for which the commencement date for capitalization is on or after the effective date, January 1, 2010.

CONDENSED CONSOLIDATED STATEMENTS

OF INCOME AND COMPREHENSIVE INCOME – IFRS

			Three Months Ended September 30, 2010									Nine Months Ended September 30, 2010
(thousands of Canadian dollars) (unaudited)	Note		Previous GAAP			Effect of transition to IFRS			IFRS			Previous GAAP			Effect of transition to IFRS			IFRS
Revenues
Petroleum and natural gas		N	$	238,293		$	(42,767	)	$	195,526		$	741,639		$	(135,797	)	$	605,842
Royalties		F,N		(39,615	)		39,615			–			(125,577	)		125,577			–
Gain on financial derivatives				4,406			(4,406	)		–			21,567			(21,567	)		–
				203,084			(7,558	)		195,526			637,629			(31,787	)		605,842
Expenses
Exploration and evaluation		B		–			6,158			6,158			–			18,163			18,163
Production and operating				43,618			272			43,890			128,680			(169	)		128,511
Transportation and blending				37,555			–			37,555			135,511			–			135,511
General and administrative				8,605			1			8,606			29,027			601			29,628
Unit-based compensation		J		1,888			33,121			35,009			6,734			56,335			63,069
Financing costs		H, I		7,257			1,573			8,830			21,263			4,624			25,887
Gain on oil and gas properties		C		–			(16,227	)		(16,227	)		–			(16,227	)		(16,227	)
Gain on financial derivatives		G		–			(2,784	)		(2,784	)		–			(17,700	)		(17,700	)
Foreign exchange loss				(4,418	)		–			(4,418	)		(4,010	)		–			(4,010	)
Depletion and depreciation		D		69,270			(18,323	)		50,947			202,614			(54,921	)		147,693
				163,775			3,791			167,566			519,819			(9,294	)		510,525
Net income before income taxes				39,309			(11,349	)		27,960			117,810			(22,493	)		95,317
Income tax expense (recovery)
Current		F		3,208			(3,208	)		–			10,215			(10,215	)		–
Deferred		L, M		1,040			3,601			4,641			(12,447	)		(102,496	)		(114,943	)
				4,248			393			4,641			(2,232	)		(112,711	)		(114,943	)
Net income attributable to unitholders			$	35,061		$	(11,742	)	$	23,319		$	120,042		$	90,218		$	210,260
Other comprehensive income (loss)
Foreign currency translation adjustment				(5,740	)		207			(5,533	)		(3,274	)		70			(3,204	)
Comprehensive income			$	29,321		$	(11,535	)	$	17,786		$	116,768		$	90,288		$	207,056

CONDENSED CONSOLIDATED STATEMENTS

OF FINANCIAL POSITION – IFRS

As at			December 31, 2010									September 30, 2010									January 1, 2010
(thousands of Canadian dollars) (unaudited)	Note		Previous GAAP			Effect of transition to IFRS			IFRS			Previous GAAP			Effect of transition to IFRS			IFRS			Previous GAAP			Effect of transition to IFRS			IFRS
Assets
Current assets
Cash		O	$	–		$	–		$	–		$	1,168		$	–		$	1,168		$	10,177		$	–		$	10,177
Trade and other receivables		A		151,792			–			151,792			134,355			–			134,355			137,154			–			137,154
Crude oil inventory				1,802			–			1,802			472			–			472			1,384			–			1,384
Future income tax asset		A,M		5,480			(5,480	)		–			281			(281	)		–			1,371			(1,371	)		–
Financial derivatives				13,921			–			13,921			21,116			–			21,116			29,453			–			29,453
				172,995			(5,480	)		167,515			157,392			(281	)		157,111			179,539			(1,371	)		178,168
Non-current assets
Deferred income tax asset		A,M		150,190			(142,320	)		7,870			151,201			(147,520	)		3,681			418			1,371			1,789
Financial derivatives				2,622			–			2,622			2,285			–			2,285			2,541			–			2,541
Exploration and evaluation assets		B		–			113,082			113,082			–			120,327			120,327			–			124,621			124,621
Oil and gas properties		A,C,D,I		1,683,650			(59,021	)		1,624,629			1,703,644			(76,733	)		1,626,911			1,663,752			(151,717	)		1,512,035
Other plant and equipment		E		–			27,550			27,550			–			34,817			34,817			–			27,096			27,096
Goodwill				37,755			–			37,755			37,755			–			37,755			37,755			–			37,755
			$	2,047,212		$	(66,189	)	$	1,981,023		$	2,052,277		$	(69,390	)	$	1,982,887		$	1,884,005		$	–		$	1,884,005
Liabilities
Current liabilities
Trade and other payables		A	$	179,269		$	4,045		$	183,314		$	182,371		$	6,020		$	188,391		$	180,493		$	6,023		$	186,516
Distributions payable to unitholders				22,742			–			22,742			20,220			–			20,220			19,674			–			19,674
Bank loan				–			–			–			–			–			–			265,088			–			265,088
Convertible debentures				–			–			–			5,057			–			5,057			7,736			–			7,736
Future income tax liability		A,M		3,756			(3,756	)		–			6,016			(6,016	)		–			8,683			(8,683	)		–
Financial derivatives		G		20,312			–			20,312			985			7,795			8,780			4,650			7,354			12,004
				226,079			289			226,368			214,649			7,799			222,448			486,324			4,694			491,018
Non-current liabilities
Bank loan				303,773			–			303,773			314,567			–			314,567			–						–
Long-term debt		H		150,000			(3,107	)		146,893			150,000			(3,209	)		146,791			150,000			(3,502	)		146,498
Deferred credit		L		109,800			(109,800	)		–			109,800			(109,800	)		–			–			–			–
Asset retirement obligations		I		52,373			117,238			169,611			57,619			117,377			174,996			54,593			87,276			141,869
Unit-based payment liability		J		–			–			–			–			118,202			118,202			–			91,559			91,559
Deferred income tax liability		A,M		167,302			(152,919	)		14,383			180,351			(162,099	)		18,252			179,673			(18,954	)		160,719
Financial derivatives				8,859			–			8,859			11,936			–			11,936			1,418			–			1,418
				1,018,186			(148,299	)		869,887			1,038,922			(31,730	)		1,007,192			872,008			161,073			1,033,081
Shareholders’/Unitholders’ Equity
Shareholders’ capital		J		1,390,034			94,301			1,484,335			–			–			–			–			–			–
Unitholders’ capital		G,J		–			–			–			1,360,050			68,796			1,428,846			1,295,931			35,230			1,331,161
Conversion feature of convertible debentures		G		–			–			–			243			(243	)		–			374			(374	)		–
Contributed surplus		J		20,131			108,998			129,129			20,943			(20,943	)		–			20,371			(20,371	)		–
Accumulated other comprehensive (loss) income		K		(14,607	)		4,284			(10,323	)		(7,173	)		3,969			(3,204	)		(3,899	)		3,899			–
Deficit				(366,532	)		(125,473	)		(492,005	)		(360,708	)		(89,239	)		(449,947	)		(300,780	)		(179,457	)		(480,237	)
				1,029,026			82,110			1,111,136			1,013,355			(37,660	)		975,695			1,011,997			(161,073	)		850,924
			$	2,047,212		$	(66,189	)	$	1,981,023		$	2,052,277		$	(69,390	)	$	1,982,887		$	1,884,005		$	–		$	1,884,005

A)	Presentation Differences

Certain presentation differences between previous GAAP and IFRS have no impact on reported comprehensive income or total equity.

Some line items are described differently (renamed) under IFRS compared to previous GAAP. These line items are as follows (with previous GAAP descriptions in brackets):

●

Trade and other receivables (Accounts receivable)

●

Oil and gas properties (Petroleum and natural gas properties)

●

Deferred income tax asset/liability (Future income tax asset/liability)

●

Trade and other payables (Accounts payable and accrued liabilities)

B)	Exploration and Evaluation

Exploration and evaluation assets at January 1, 2010 were deemed to be $124.6 million, being the amount recorded as the undeveloped land balance under previous GAAP. This has resulted in the reclassification from property, plant and equipment to intangible exploration assets of $124.6 million in the opening IFRS statement of financial position. For the twelve months ended December 31, 2010, Baytex had exploration and evaluation capital expenditures of $37.4 million, corporate acquisitions of $2.5 million, transfer to oil and gas properties of $29.1 million, transfers of $18.9 million to expense related to lease expiries and a decrease due to foreign currency translation of $3.3 million.

C)	Oil and Gas Properties

IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at its time of adoption, to measure exploration and evaluation assets at the amount determined under the entity’s previous GAAP and to measure oil and gas assets in the development and production phases by allocating the amount determined under the entity’s previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date. The Company has allocated the amount recognized under previous GAAP as at January 1, 2010 using reserve values to the assets at an area level. This has resulted in oil and gas properties of $1,512.0 million in the opening IFRS statement of financial position.

Previous GAAP utilized full cost accounting whereby gains and losses were not recognized upon the divestiture of oil and gas assets unless such a divestiture would alter the rate of depletion by 20% or more. Under IFRS, gains and losses are recognized based on the difference between the net proceeds from the divestiture and the carrying value of the asset disposed. For the three months and nine months ended September 30, 2010, a gain of $16.2 million was recognized relating to a divestiture of oil and gas assets.

Depletion

Upon transition to IFRS, the Company adopted a policy of depleting oil and gas properties on a “units of production” basis over proved plus probable reserves on an area basis rather than a cost pool basis under previous GAAP. The depletion policy under previous GAAP was units of production over proved reserves on a country basis.

There is no impact to depletion on transition to IFRS at January 1, 2010. For the three months ended September 30, 2010, this change resulted in a decrease in depletion expense of $18.0 million with a corresponding increase in oil and gas properties. For the nine months ended September 30, 2010, this change resulted in a decrease in depletion expense of $54.3 million with a corresponding increase in oil and gas properties.

E)	Other Plant and Equipment

Contains amounts previously grouped within petroleum and natural gas properties.

F)	Current Income Tax Expense

Under previous GAAP, Saskatchewan resource surcharge expense was classified as current income tax. Under IFRS, Saskatchewan resource surcharge is considered a royalty and is netted against petroleum and natural gas revenues. Saskatchewan resource surcharge for the three months ended September 30, 2010 netted in revenues is $3.2 million. For the nine months ended September 30, 2010 netted in revenues is $10.2 million.

G)	Conversion Feature of Convertible Debentures

H)	Long-term Debt

Under previous GAAP, the Company’s policy was to immediately expense transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability. Under IFRS, the transaction costs for financial instruments carried at amortized cost are included in the calculation of the effective interest rate and effectively amortized through net income over the term of the instrument. Baytex’s $150.0 million principal amount of Series A senior unsecured debentures are classified as other financial liabilities. Under IFRS, the senior unsecured debentures are carried at amortized cost, net of the associated $3.6 million transaction costs, which will accrete up to the principal balance at maturity using the effective interest rate. Under IFRS, a reduction in the long-term debt liability of $3.5 million had a corresponding decrease in deficit at January 1, 2010. Accretion expense included in finance costs for the three months ended September 30, 2010 is $0.1 million. Accretion expense included in finance costs for the nine months ended September 30, 2010 is $0.3 million.

I)	Asset Retirement Obligations

Under IFRS, Baytex uses a risk free interest rate to discount the estimated fair value of its asset retirement obligations associated with the related oil and gas properties. Under previous GAAP, the Company used a credit-adjusted risk free interest rate. A lower discount rate under IFRS increases the asset retirement obligations. In addition, under IFRS the asset retirement obligations are measured using the best estimate of the expenditures to be incurred and current discount rates at each remeasurement date with the corresponding adjustment to the cost of the related oil and gas properties. Existing liabilities under previous GAAP are not remeasured using current discount rates.

Under previous GAAP, the Company’s asset retirement obligations were recorded using the credit-adjusted risk free rate of 8.0%. Under IFRS, the Company’s asset retirement obligations are recorded using the risk free rate of 3.5% at December 31, 2010 (4.0% at January 1, 2010 and 3.5% at September 30, 2010). Under IFRS, an additional liability of $87.3 million was charged to deficit at January 1, 2010. At September 30, 2010, excluding the January 1, 2010 adjustment, the lower discount rates used resulted in an additional liability of $30.1 million and a resulting $29.2 million increase to the related oil and gas properties. At December 31, 2010, excluding the January 1, 2010 adjustment, the lower discount rates used resulted in an additional liability of $30.0 million and a resulting $28.7 million increase to the related oil and gas properties.

J)	Unit-based Compensation

Under IFRS, prior to the conversion to a corporation, the obligation associated with the Unit Rights Plan was considered a liability and the fair value of the liability is remeasured at each reporting date and at settlement date. Any changes in fair value are recognized in net income for the period. For periods prior to the conversion to a corporation remeasuring the fair value of the obligation each reporting period will increase or decrease the unit-based payment liability, unitholders’ capital and compensation expense recognized. Upon conversion to a corporation, the outstanding Unit Rights Plan was modified to become the new Share Rights Plan, effectively changing the related classification from liability-settled to equity-settled. The expense recognized from the date of the plan modification over the remainder of the vesting period is determined based on the fair value of the reclassified unit rights at the date of the modification. Upon transition of IFRS at January 1, 2010, an additional unit-based payment liability of $91.6 million and a decrease of $20.4 million in contributed surplus resulted in a corresponding $71.2 million charge to deficit.

K)	Accumulated Other Comprehensive Loss

Under previous GAAP, amounts are composed entirely of currency translation adjustments on self-sustaining foreign operations. Under IFRS, the Company has elected to deem cumulative currency translation differences as $nil at January 1, 2010. At January 1, 2010, this has resulted in a decrease in accumulated other comprehensive loss with a corresponding increase in deficit of $3.9 million.

L)	Deferred Credit

Baytex acquired several private entities to be used in its internal financing structure. Under previous GAAP, the excess of amounts assigned to the acquired assets over the consideration paid is classified as a deferred credit. Under IFRS, the deferred credit is derecognized through net income as a deferred income tax recovery. For the nine months ended September 30, 2010, a deferred income tax recovery of $109.8 million was recorded in net income for amounts previously recognized as a deferred credit (three months ended September 30, 2010, $nil was recorded in net income for amounts previously recognized as a deferred credit).

M)	Deferred Income Taxes

Royalties

Under previous GAAP, gross petroleum and natural gas revenues and royalties were presented separately. Under IFRS, petroleum and natural gas revenues are presented net of crown, third-party, gross overriding royalties and production taxes.

O)	Statements of Cash Flows

The transition from previous GAAP to IFRS had no material effect on the reported cash flows generated by the Company.

26.	CONSOLIDATING FINANCIAL INFORMATION – BASE SHELF PROSPECTUS

On August 4, 2011, Baytex filed a Short Form Base Shelf Prospectus with the securities regulatory authorities in each of the provinces of Canada (other than Québec) and a Registration Statement with the United States Securities and Exchange Commission (collectively, the “Shelf Prospectus”). The Shelf Prospectus allows Baytex to offer and issue common shares, subscription receipts, warrants, options and debt securities by way of one or more prospectus supplements at any time during the 25-month period that the Shelf Prospectus remains in place. The securities may be issued from time to time, at the discretion of Baytex, with an aggregate offering amount not to exceed $500 million (Canadian).

Any debt securities issued by Baytex pursuant to the Shelf Prospectus will be guaranteed by all of its direct and indirect wholly-owned material subsidiaries (the “Guarantor Subsidiaries”). The guarantees of the Guarantor Subsidiaries are full and unconditional and joint and several. These guarantees may in turn be guaranteed by Baytex. Other than investments in its subsidiaries, Baytex has no independent assets or operations.

Pursuant to the credit agreement governing Baytex Energy’s credit facilities, Baytex Energy and its subsidiaries are prohibited from paying dividends to their shareholders that would have, or would reasonably be expected to have, a material adverse effect or would adversely affect or impair the ability or capacity of Baytex Energy to pay or fulfill any of its obligations under the credit agreement. In addition, Baytex Energy may not permit any of its subsidiaries to pay any dividends during the continuance of a default or event of default under the credit agreement.

The following tables present condensed interim unaudited consolidating financial information as at September 30, 2011 and December 31, 2010 and for the three months and nine months ended September 30, 2011 and 2010 for: 1) Baytex, on a stand-alone basis, 2) Guarantor subsidiaries, on a stand- alone basis, 3) non-guarantor subsidiaries, on a stand-alone basis and 4) Baytex, on a consolidated basis.

(thousands of Canadian dollars)	Baytex		Guarantor Subsidiaries			Non-guarantor Subsidiaries		Consolidation Adjustments			Total Consolidated
As at September 30, 2011
Current assets	$	71	$	226,422		$	297	$	–		$	226,790
Intercompany advances and investments		1,765,800		(533,796	)		78,338		(1,310,342	)		–
Non-current assets		2,435		2,199,536			–		–			2,201,971
Current liabilities		25,937		231,222			74		–			257,233
Bank loan and long-term debt		300,815		368,184			–		–			668,999
Asset retirement obligation and other non-current liabilities	$	–	$	316,826		$	–	$	–		$	316,826

As at December 31, 2010
Current assets	$	15	$	167,473		$	27	$	–		$	167,515
Intercompany advances and investments		1,687,861		(456,094	)		72,318		(1,304,085	)		–
Non-current assets		1,138		1,812,370			–		–			1,813,508
Current liabilities		27,539		198,788			41		–			226,368
Bank loan and long-term debt		146,893		303,773			–		–			450,666
Asset retirement obligation and other non-current liabilities	$	–	$	192,853		$	–	$	–		$	192,853

For nine months ended September 30, 2011
Revenues, net of royalties	$	16,059		$	791,767	$	6,335		$	(23,777	)	$	790,384
Production, operation and exploration		–			163,703		–			–			163,703
Transportation and blending		–			185,737		–			–			185,737
General, administrative and share-based compensation		1,206			54,393		126			(1,125	)		54,600
Financing, derivatives, foreign exchange and other gains/losses		24,597			8,556		(48	)		(22,652	)		10,453
Depletion and depreciation		–			176,519		–			–			176,519
Deferred income tax (recovery) expense		(1,298	)		41,018		–			–			39,720
Net income (loss)	$	(8,446	)	$	161,841	$	6,257		$	–		$	159,652

For three months ended September 30, 2011
Revenues, net of royalties	$	5,878		$	263,506		$	2,602		$	(8,855	)	$	263,131
Production, operation and exploration		–			59,221			–			–			59,221
Transportation and blending		–			54,059			–			–			54,059
General, administrative and share-based compensation		437			19,373			10			(375	)		19,445
Financing, derivatives, foreign exchange and other gains/losses		17,226			(17,360	)		(10	)		(8,480	)		(8,624	)
Depletion and depreciation		–			63,406			–			–			63,406
Deferred income tax (recovery) expense		(1,362	)		25,147			–			–			23,785
Net income (loss)	$	(10,423	)	$	59,660		$	2,602		$	–		$	51,839

For nine months ended September 30, 2010
Revenues, net of royalties	$	148,292	$	606,967		$	4,190		$	(153,607	)	$	605,842
Production, operation and exploration		–		146,674			–			–			146,674
Transportation and blending		–		135,511			–			–			135,511
General, administrative and unit-based compensation		1,125		92,418			279			(1,125	)		92,697
Financing, derivatives, foreign exchange and other gains/losses		14,784		125,649			(1	)		(152,482	)		(12,050	)
Depletion and depreciation		3,940		143,753			–			–			147,693
Deferred income tax expense (recovery)		4		(114,968	)		21			–			(114,943	)
Net income	$	128,439	$	77,930		$	3,891		$	–		$	210,260

For three months ended September 30, 2010
Revenues, net of royalties	$	32,852		$	195,901		$	1,440	$	(34,667	)	$	195,526
Production, operation and exploration		–			50,048			–		–			50,048
Transportation and blending		–			37,555			–		–			37,555
General, administrative and unit-based compensation		375			43,523			92		(375	)		43,615
Financing, derivatives, foreign exchange and other gains/losses		5,353			14,339			1		(34,292	)		(14,599	)
Depletion and depreciation		1,306			49,641			–		–			50,947
Deferred income tax (recovery) expense		(1,641	)		6,278			4		–			4,641
Net income (loss)	$	27,459		$	(5,483	)	$	1,343	$	–		$	23,319

For nine months ended September 30, 2011
Cash provided by (used in):
Operating activities	$	195,502		$	218,854		$	421		$	–		$	414,777
Payment of dividends		(156,056	)		258			(258	)		–			(156,056	)
Increase in bank loan		–			56,448			–			–			56,448
Increase (decrease) in intercompany loans		(193,414	)		248,826			(55,412	)		–			–
Proceeds from issuance of long-term debt		145,810			–			–			–			145,810
Increase in investments					(55,249	)					55,249			–
Increase in equity		33,626			–			55,249			(55,249	)		33,626
Interest paid		(25,468	)		(5,902	)		–			–			(31,370	)
Financing activities		(195,502	)		244,381			(421	)		–			48,458
Additions to exploration and evaluation assets		–			(8,010	)		–			–			(8,010	)
Additions to oil and gas properties		–			(287,825	)		–			–			(287,825	)
Property acquisitions		–			(65,835	)		–			–			(65,835	)
Corporate acquisitions		–			(118,693	)		–			–			(118,693	)
Additions to other plant and equipment, net of disposals		–			(1,416	)		–			–			(1,416	)
Acquisitions of financing entities		–			–			–			–			–
Change in non-cash working capital		–			18,577			–			–			18,577
Investing activities		–			(463,202	)		–			–			(463,202	)
Impact of foreign currency translation on cash balances	$	–		$	(33	)	$	–		$	–		$	(33	)

For nine months ended September 30, 2010
Cash provided by (used in):
Operating activities	$	154,841		$	198,621		$	(350	)	$	–		$	353,112
Payment of distributions		(142,486	)		787			(787	)		–			(142,486	)
Increase in bank loan		–			52,503			–			–			52,503
Increase (decrease) in intercompany loans		(16,660	)		21,129			(4,469	)		–			–
Increase in investments		–			(2,653	)		–			2,653			–
Increase in equity		18,167			–			2,653			(2,653	)		18,167
Interest paid		(14,227	)		(15,072	)		2,805			–			(26,494	)
Financing activities		(155,206	)		56,694			202			–			(98,310	)
Additions to exploration and evaluation assets		–			(30,055	)		–			–			(30,055	)
Additions to oil and gas properties		–			(142,214	)		–			–			(142,214	)
Property acquisitions		–			(19,316	)		–			–			(19,316	)
Corporate acquisitions		–			(40,314	)		–			–			(40,314	)
Proceeds from divestitures		–			18,137									18,137
Additions to other plant and equipment, net of disposals		–			(13,447	)		–			–			(13,447	)
Acquisitions of financing entities		–			(38,000	)		–			–			(38,000	)
Change in non-cash working capital		–			1,784			–			–			1,784
Investing activities		–			(263,425	)		–			–			(263,425	)
Impact of foreign currency translation on cash balances	$	–		$	(386	)	$	–		$	–		$	(386	)

ABBREVIATIONS

AcSB	Accounting Standards Board
AECO	the natural gas storage facility located at Suffield, Alberta
ASC	Accounting Standards Codification
bbl	barrel
bbl/d	barrel per day
bcf	billion cubic feet
boe*	barrels of oil equivalent
boe/d*	barrels of oil equivalent per day
COSO	Committee of Sponsoring Organizations of the Treadway Commission
DRIP	Dividend Reinvestment Plan
GAAP	generally accepted accounting principles
GJ	gigajoule
GJ/d	gigajoule per day
IAS	International Accounting Standard
IASB	International Accounting Standards Board
IFRS	International Financial Reporting Standards
LIBOR	London Interbank Offered Rate
LLB	Lloyd Light Blend
LLK	Lloyd Kerrobert
mbbl	thousand barrels
mboe*	thousand barrels of oil equivalent
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmbbl	million barrels
mmboe*	million barrels of oil equivalent
mmBtu	million British Thermal Units
mmBtu/d	million British Thermal Units per day
mmcf	million cubic feet
mmcf/d	million cubic feet per day
MW	Megawatt
NGL	natural gas liquids
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
TSX	Toronto Stock Exchange
WCS	Western Canadian Select
WTI	West Texas Intermediate

BOEs may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CORPORATE INFORMATION

BOARD OF DIRECTORS	OFFICERS
Raymond T. Chan	Raymond T. Chan
Executive Chairman	Executive Chairman
Baytex Energy Corp.	Anthony W. Marino
John A. Brussa (2)(3)(4)	President & Chief Executive Officer
Partner	W. Derek Aylesworth
Burnet, Duckworth & Palmer LLP	Chief Financial Officer
Edward Chwyl (2)(3)(4)	Marty L. Proctor
Lead Independent Director	Chief Operating Officer
Independent Businessman	Daniel G. Anderson
Naveen Dargan (1)(2)(4)	Vice President, U.S. Business Unit
Independent Businessman	Randal J. Best
R. E. T. (Rusty) Goepel (1)	Senior Vice President,
Senior Vice President	Corporate Development
Raymond James Ltd.	Stephen Brownridge
Anthony W. Marino	Vice President, Exploration
President & Chief Executive Officer	Geoffrey J. Darcy
Baytex Energy Corp.	Vice President, Marketing
Gregory K. Melchin (1)	Murray J. Desrosiers
Independent Businessman	Vice President,
Dale O. Shwed (3)	General Counsel and Corporate Secretary
President & Chief Executive Officer	Brian G. Ector
Crew Energy Inc.	Vice President, Investor Relations
(1) Member of the Audit Committee	Michael S. Kaluza
(2) Member of the Compensation Committee	Vice President, Planning
(3) Member of the Reserves Committee	Brett J. McDonald
(4) Member of the Nominating and Governance Committee	Vice President, Land
HEAD OFFICE	Timothy R. Morris
Centennial Place, East Tower	Vice President, U.S. Business Development
Suite 2800, 520 – 3rd Avenue S.W.	Richard P. Ramsay
Calgary, Alberta T2P 0R3	Vice President, Heavy Oil
T 587-952-3000	Mark F. Smith
F 587-952-3001	Vice President, Conventional Oil & Gas
Toll-free: 1-800-524-5521	LEGAL COUNSEL
www.baytex.ab.ca	Burnet, Duckworth & Palmer LLP
AUDITORS	RESERVES ENGINEERS
Deloitte & Touche LLP	Sproule Associates Limited
BANKERS	TRANSFER AGENT
The Toronto-Dominion Bank	Valiant Trust Company
Alberta Treasury Branches	EXCHANGE LISTINGS
Bank of America	Toronto Stock Exchange
Bank of Montreal	New York Stock Exchange
Bank of Nova Scotia	Symbol: BTE
Barclays Bank PLC
BNP Paribas (Canada)
Canadian Imperial Bank of Commerce
Caisse Centrale Desjardins
Credit Suisse AG
National Bank of Canada
Royal Bank of Canada
Société Générale
Union Bank of California