EX-99.1 2 a2208421zex-99_1.htm EXHIBIT 99.1

Exhibit 99.1

ANNUAL REPORT 2011

CALGARY Heavy Oil Areas Light Oil and Natural Gas Areas Baytex Properties Corporate Headquarters USA DIVIDE LLOYD MINSTER SEAL PEMBINA BON ACCORD STODDART WILLIAMS KERROBERT CANADA ALBERTA SASKATCHEWAN BRITISH COLUMBIA MONTANA NORTH DAKOTA OPERATING AREAS 4 Message to Shareholders 8 Management’s Discussion and Analysis 32 Management’s Report 33 Auditors’ Report 35 Consolidated Financial Statements 80 Reserves Information CONTENTS

SUMMARY

		Three Months Ended					Years Ended

		December 31, 2011		September 30, 2011	December 31, 2010		December 31, 2011		December 31, 2010

FINANCIAL (thousands of Canadian dollars, except per common share or unit amounts)
Petroleum and natural gas sales		367,813		313,787	263,497		1,308,814		1,005,136
Funds from operations⁽¹⁾		162,973		144,825	123,162		555,483		447,657
	Per share or unit – basic	1.39		1.24	1.09		4.79		4.02
	Per share or unit – diluted	1.36		1.22	1.06		4.67		3.89
Cash dividends or distributions declared⁽²⁾		50,925		50,270	48,126		205,960		189,824
Cash dividends or distributions declared per share or unit		0.62		0.60	0.56		2.42		2.18
Net income		57,780		51,839	21,355		217,432		231,615
	Per share or unit – basic	0.49		0.45	0.19		1.88		2.08
	Per share or unit – diluted	0.48		0.44	0.18		1.83		2.01
Exploration and development		72,013		100,368	59,350		367,848		231,619
Property acquisitions		10,329		28,502	3,096		76,164		22,412
Corporate acquisition		1,313		22	–		120,006		40,314
Proceeds from divestitures		(47,396	)	–	(896	)	(47,396	)	(19,033	)

Total oil and natural gas capital expenditures		36,259		128,892	61,550		516,622		275,312
Bank loan		311,960		368,184	303,773		311,960		303,773
Long-term debt		302,550		305,835	150,000		302,550		150,000
Working capital deficiency		36,071		65,180	52,462		36,071		52,462

Total monetary debt⁽³⁾		650,581		739,199	506,235		650,581		506,235

(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 year ended December 31, 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 long-term bank loans.

Baytex Energy Corp. 2011 Annual Report 1

			Three Months Ended						Years Ended

			December 31, 2011		September 30, 2011		December 31, 2010		December 31, 2011		December 31, 2010

OPERATING
Daily production
	Light oil and NGL (bbl/d)		7,232		7,170		6,457		6,769		6,539
	Heavy oil (bbl/d)		38,006		37,280		29,808		35,252		28,585
	Total oil and NGL (bbl/d)		45,238		44,450		36,265		42,021		35,124
	Natural gas (mmcf/d)		46.9		49.0		52.5		48.7		55.3
	Oil equivalent (boe/d @ 6:1)⁽¹⁾		53,054		52,625		45,015		50,132		44,341
Average prices (before hedging)
	WTI oil (US$/bbl)		94.06		89.76		85.17		95.12		79.53
	Edmonton par oil ($/bbl)		97.87		92.45		80.73		95.56		77.81
	BTE light oil and NGL ($/bbl)		85.09		80.48		68.07		82.49		65.90
	BTE heavy oil ($/bbl)⁽²⁾		70.85		59.92		60.10		65.53		59.40
	BTE total oil and NGL ($/bbl)		73.13		63.26		61.53		68.26		60.61
	BTE natural gas ($/mcf)		3.91		4.20		3.84		4.17		4.32
	BTE oil equivalent ($/boe)		65.81		57.31		53.99		61.26		53.39
	USD/CAD noon rate at period end		0.9833		0.9626		1.0054		0.9833		1.0054
	USD/CAD average rate for period		0.9774		1.0220		0.9873		1.0114		0.9708
COMMON SHARE OR TRUST UNIT INFORMATION
TSX
Share or Unit price (Cdn$)
	High	$	57.26	$	55.93	$	48.15	$	58.76	$	48.15
	Low	$	39.18	$	41.71	$	37.12	$	39.18	$	27.72
	Close	$	56.97	$	43.81	$	46.61	$	56.97	$	46.61
Volume traded (thousands)			26,471		27,710		32,579		111,236		105,385
NYSE
Share or Unit price (US$)
	High	$	56.33	$	59.04	$	47.82	$	61.95	$	47.82
	Low	$	36.39	$	40.31	$	35.96	$	36.89	$	25.64
	Close	$	55.89	$	41.67	$	45.82	$	55.89	$	46.82
Volume traded (thousands)			7,579		11,771		5,231		37,384		21,489
Common shares or trust units outstanding (thousands)			117,893		116,755		113,712		117,893		113,712

(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.

2 Baytex Energy Corp. 2011 Annual Report

Advisory Regarding Forward-Looking Statements

This report contains forward-looking statements relating to: our business strategies, plans and objectives; our ability to grow our reserve base and add to production levels through exploration and development activities complemented by strategic acquisitions; reserves and contingent resource estimates and the assumptions relating thereto; our reserves life index; development plans for our properties; our heavy oil resource play at Seal, including the development of a new 15-well thermal module; our Bakken/Three Forks and Viking light oil resource plays, including their resource potential and their potential to grow our light oil production and reserves; our exploration and development capital expenditures for 2012; our average production rate for 2012; the outlook for Canadian heavy oil prices and the pricing differential between Canadian heavy and West Texas Intermediate crude oils; the alleviation of pipeline constraints through the addition of incremental transportation capacity; the completion of refinery turnarounds; the demand for Canadian heavy oil by U.S. refiners; our ability to mitigate our exposure to heavy oil price differentials by transporting our crude oil to market by railways; the volume of heavy oil to be transported to market on railways in 2012; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; our dividend policy and level; our debt-to-funds from operations 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. In establishing the level of cash dividends, our Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures 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 information and statements.

Contingent Resource

This report contains estimates of contingent resource. Contingent resource is not, and should not be confused with, petroleum and natural gas reserves. Contingent resource is defined in the Canadian Oil and Gas Evaluation Handbook as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resource the estimated discovered recoverable quantities associated with a project in the early evaluation stage." For additional information on contingent resource, we refer you to the end of this report for our advisory on oil and gas information.

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.

Baytex Energy Corp. 2011 Annual Report 3

MESSAGE TO SHAREHOLDERS

We are pleased to report our 2011 results to our shareholders. In 2011, we achieved record levels of production, reserves and funds from operations. Operationally, we continued to advance several key projects that we expect to provide reliable and diversified growth in the coming years. We also recorded another year in which we replaced more than 100% of our annual production with reserves developed by our organic exploration and development ("E&D") investment activities. Finally, we continue to be conservatively financed, maintaining low levels of debt relative to our cash-generating capability.

Our capital markets model is to provide a combination of growth and income within a framework of internal capital discipline. Our view is that the distinguishing feature of the oil and gas industry is its inherent capital intensity, and therefore, that no oil and gas company can distinguish itself without achieving high capital efficiencies. Thus far, our disciplined approach has proved successful.

In each of 2009 and 2010, we were fortunate to deliver the highest total return as compared to our former peer group of energy trusts. Last year was our first in our new corporate legal structure following our conversion from an income trust on December 31, 2010. Now that we have converted to a corporation, we compete against a much larger group of energy companies that have a range of capital markets strategies along the income-to-growth continuum. During our new corporate era, as measured from January 1, 2011 to February 29, 2012, we delivered the second highest total market return performance among the 39 companies in the S&P/TSX Composite Oil & Gas Exploration & Production Index. This market recognition leaves us honored, and also determined to continue to focus on delivering sustainable income and growth to our shareholders.

Operations Review

Oil-equivalent production averaged 53,054 boe/d in the fourth quarter of 2011, and 50,132 boe/d for the full year, a 13% increase over 2010. Production increased each quarter during 2011, with the fourth quarter marking our twelfth consecutive quarter of production growth. Oil production growth was even more dramatic, increasing 20% from 2010 levels. With respect to product mix, Baytex is one of the most oil-weighted entities in the North American energy industry, with 85% of our production and 92% of our reserves represented by heavy oil, light oil and natural gas liquids.

Capital investment into E&D activities totaled $368 million, with the majority directed toward heavy oil projects. During the year, Baytex participated in the drilling of 198 gross (157.3 net) wells on our heavy oil, light oil and natural gas properties, generating a 99% success rate.

Our total capital program for 2011, including acquisitions (net of dispositions), amounted to $518 million. We only pursue acquisitions that meet three criteria: value accretion for our existing shareholders, growth potential from the acquired assets, and operating control and capability by Baytex. As a result of these restrictive criteria, we are not a frequent acquirer, but nonetheless, we did complete two acquisitions in 2011. In February 2011, we acquired heavy oil assets in the Reno area of northern Alberta and in the Lloydminster area of western Saskatchewan for $159 million. The acquisition consisted of approximately 2,600 bbl/d of production (100% heavy oil) and 95,600 net acres of undeveloped land in close proximity to our existing lands at Seal. Our second acquisition, in August 2011, was a $22 million purchase of predominantly natural gas assets in the Brewster area of west-central Alberta where we already had a significant non-operated interest. As a result, we are now the operator of all of the acquired assets, which consisted of approximately 800 boe/d of production (80% natural gas), 72,000 net acres of undeveloped land, a 64 kilometre gathering system and two compressor stations.

During the fourth quarter of 2011, we completed two property dispositions. The first included the sale of six sections of leasehold, including five sections with Duvernay rights, in the Kaybob South area of west-central Alberta for $11 million. Five of the six sections faced lease expiry within the next year and there was no production on the divested lands. The second disposition included the sale of approximately 32,600 net acres of leasehold in the "halo" of the Dodsland field in southwest Saskatchewan for $36 million. Production from the Dodsland lands at the time of sale was approximately 60 bbl/d. These dispositions were part of our continuous program of asset portfolio

4 Baytex Energy Corp. 2011 Annual Report

evaluation and high-grading. Through this program, we seek to divest assets that are not consistent with our low-risk, high capital efficiency model, or have market values that exceed our view of their intrinsic worth.

This capital program allowed Baytex to increase its reserve base in both proved and probable reserve categories for the eighth consecutive year. At year-end 2011, our proved plus probable reserves, as evaluated by Sproule Associates Limited ("Sproule"), reached 252 million boe, a 10% increase over year-end 2010. This reserve total represents a 13.0 year reserve life index based on our fourth quarter 2011 production of 53,054 boe/d.

We commissioned Sproule to conduct a contingent resource assessment on three of our oil resource plays: the Bluesky in the Seal area of Alberta, the Bakken/Three Forks in North Dakota and the Viking in the Redwater area of Alberta and the Kerrobert and Whiteside areas of Saskatchewan. We also commissioned McDaniel & Associates Consultants Ltd. ("McDaniel") to conduct a contingent resource assessment on certain heavy oil properties in the Lloydminster area of northeast Alberta. For the total of these four plays, Sproule and McDaniel's estimate of contingent resource as of December 31, 2011 ranges from 560 million boe in the "low estimate" (C1) to 1.2 billion boe in the "high estimate" (C3), with a "best estimate" (C2) of 783 million boe. Contingent resources are in addition to currently booked reserves.

Baytex continued to record strong capital efficiencies in 2011. Finding, development and acquisition costs were $12.46/boe on a proved plus probable basis (excluding changes in future development costs), resulting in a recycle ratio of 2.8 times. Our capital efficiency is further demonstrated by replacement of 164% of the year's production through E&D activities, while reinvesting only 66% of funds from operations ("FFO"). Including acquisitions (net of dispositions), we replaced 227% of our 2011 production while reinvesting 93% of FFO. These results are consistent with our long-term performance in capital efficiency. On a proved plus probable basis, our five-year average finding, development and acquisition cost of $10.46/boe (excluding changes in future development costs), recycle ratio of 3.1 times and reserve replacement ratio of 239% all rank strongly within our industry.

In the Peace River oil sands region, we drilled 27 new cold horizontal producers, including two wells at our Reno lands which were acquired in 2011. We continued our record of 100% drilling success and increased production from this important growth property to approximately 17,500 bbl/d by the end of 2011. During 2011, we also began operating our first commercial cyclic steam stimulation project at Seal. Subject to receipt of regulatory approvals, we plan to initiate development of a new 15-well thermal module during the fourth quarter of 2012. We also drilled six stratigraphic test wells to further delineate our land base for future cold and thermal development.

Production from our Lloydminster heavy oil area increased to 20,930 boe/d in 2011, as new drilling, recompletion of existing wells and our February 2011 acquisition more than offset natural production declines. In addition to our traditional cold primary activities, we also expanded our thermal operations in Lloydminster, including the drilling and completion of two additional steam-assisted gravity drainage well pairs at Kerrobert.

We continued to pursue several light oil growth projects of long-term importance. The Bakken-Three Forks play in North Dakota and the Viking play in Alberta and Saskatchewan utilize horizontal wells, most often with multiple hydraulic fracture stimulations, to induce light oil production from low permeability reservoirs. These plays contain very large volumes of light oil resource in place and have the potential, over time, to generate significant increases in Baytex's light oil production and reserves.

In our Bakken-Three Forks play in Divide and Williams Counties, North Dakota, our land base totals approximately 116,000 net acres. Production from this play has organically grown to approximately 5% of our company's total production rate. Since our original land acquisition in North Dakota in 2008, we have increased the length of our horizontal laterals and the number of hydraulic fracturing stages used in our wells. During 2012, we will focus on drilling two-mile long horizontal wells completed with up to 30 hydraulic fracturing stages per well.

In our Viking play in southeast Alberta, we drilled eleven successful multi-lateral horizontal wells in 2011. During 2012, we plan to continue multi-lateral horizontal drilling in the Viking in Alberta, potentially augmented with single-lateral horizontal drilling accompanied by hydraulic fracturing in southwest Saskatchewan.

In 2012, our capital budget of $400 million for E&D activities is designed to generate average production of 54,000 to 55,000 boe/d, an increase of approximately 9% over 2011.

Baytex Energy Corp. 2011 Annual Report 5

We are encouraged by our operating results and capital expenditure efficiencies, and it is through these measures that we seek to differentiate ourselves from our competitors. Our success in these areas has allowed us to execute our growth-and-income model in a variety of commodity price environments.

Commodity Price Review

Oil prices experienced significant volatility last year, in reaction to rapidly changing economic fundamentals, geopolitical uncertainty and debt crises. The West Texas Intermediate ("WTI") benchmark price for 2011 averaged US$95.12/bbl, an increase of 20% from the average for 2010. We received an average oil and NGL price of $68.26/bbl in 2011, up 13% from $60.61/bbl in 2010.

Natural gas prices remained depressed during 2011 due to significant additions to supply in the United States. The average price for natural gas at the AECO hub was $3.68 /mcf, as compared to $4.13 /mcf in 2010. With only 7% of our revenue coming from natural gas in 2011, fluctuations in natural gas prices had a relatively minor impact on our FFO.

We are particularly weighted to heavy oil. The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 18% in 2011, which was unchanged from 2010.

In the first quarter of 2012, heavy oil differentials widened as a result of both unplanned refinery outages and seasonal refinery turnarounds. The combination of reduced refinery demand and increased crude oil supply from several sources, including the Williston Basin in the U.S., created logistical difficulties as transport systems struggled to move crude oil out of the U.S. midwest. Consequently, at the time of this writing, the prompt WCS differential to WTI has increased to approximately 30%.

As we look forward, incremental transportation capacity from the reversal of the Seaway pipeline near the end of the second quarter of 2012 may alleviate some crude oil backlogs, and completion of refinery turnarounds may support tighter heavy oil differentials. Nonetheless, in a closely balanced market, heavy oil differentials have the potential to remain volatile for the balance of 2012. Over the longer term, we continue to believe that transportation solutions to allow Canadian crudes to access additional markets will proceed, and that the prices for Canadian crudes will more closely match those of worldwide quality peers.

We are mitigating our exposure to heavy oil differential volatility in several ways. First, at the time of this writing, we have established hedges on 25% of our heavy oil production for 2012. Based on the forward strip for WTI, our WCS contracts for 2012 translate to approximately a 17% differential to WTI. We have additional contracts for smaller volumes in place for 2013 and 2014 at approximately 19% differentials to WTI. Second, we are bypassing weaker crude oil markets in the U.S. midwest by railing crude to higher value markets. We have contracted to deliver approximately 15% of our heavy oil production for March to market by rail and expect railed volumes to increase during the remainder of 2012. Finally, as part of our long-term transportation portfolio, we have submitted a nomination for a ten-year open-season pipeline commitment which, if accepted, would enable us to access the U.S. Gulf Coast markets for approximately 12% of our heavy oil production (based on current production rates) starting in mid-2014.

We also continue to actively hedge our exposure to other commodity prices and foreign exchange rates. At the time of this writing, we have established forward contacts for 2012 on approximately 39% of our WTI price exposure, 18% of our natural gas price exposure (excluding covered call options that we have sold on natural gas), and 28% of our exposure to currency movements between the Canadian and U.S. dollars. We continue to monitor the markets for opportunities to add to our hedge positions.

Financial Review

FFO for 2011 was our highest ever at $555 million, an increase of 24% from 2010. Despite fluctuations in commodity prices during the year, FFO increased each quarter during 2011, from a low of $109 million in the first quarter to a high of $163 million in the fourth quarter. As is the case with production, FFO has grown for twelve consecutive quarters.

As a result of the improvement in commodity prices and our strong operating results, we increased our monthly dividend from $0.20 to $0.22 per share in December 2011. We have now increased our dividends for three

6 Baytex Energy Corp. 2011 Annual Report

consecutive years. Cash dividends for 2011 were $206 million, bringing our cumulative cash dividends and distributions to $1.3 billion since we introduced a monthly income payout in 2003. Our payout ratio for 2011 averaged 37% (net of participation in our dividend reinvestment program).

Total monetary debt at year-end 2011 was $651 million and undrawn credit facilities were $388 million. This level of debt represents a debt-to-FFO ratio of 1.2 times, based on FFO over the trailing twelve months. These levels of debt and undrawn credit facilities are within our leverage and liquidity targets and provide ample capacity to finance our operations. We are pleased to note that our banking syndicate increased the size of our credit facility from $650 million to $700 million in June 2011.

Conclusion

Internally within Baytex, we intend to keep our organization as technically-focused and as non-bureaucratic as possible. In terms of external communication, we pledge to continue to communicate with our shareholders in a complete and forthright manner. As in the past, we will emphasize organic growth, occasionally augmented by accretive acquisitions that enhance our organic growth profile.

We remain committed to providing a combination of growth and income to the owners of our company. We are sometimes asked why a company with high-return projects chooses to pay a dividend. It is our view that the income component of our total return has several advantages for our shareholders. We believe that a dividend-paying stock reduces investment risk by stabilizing a portion of total return. Our market assessment is that dividends meet the income needs of many investors and are, as a result, desired by a large segment of the equity market. We believe that a combination of income and growth will offer the most reliable path to long-term total return. Finally, as we learned in the trust era, returning a portion of our cash flow stream to investors instills discipline in capital investment decisions — a critical element of success in a capital-intensive business like oil and gas. The market rewarded our disciplined approach with a total market return of 28% during 2011, including both appreciation of our share price and reinvestment of dividends.

I can assure you that Baytex's management and staff, led by our Board of Directors, will continue to work hard on behalf of our shareholders. It remains an honor 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.

Finally, I would like to note a recent example of Baytex's commitment to the communities in which we operate. On March 18, I was honored to attend a ceremony with the residents of Peace River, Alberta to celebrate our sponsorship of the community arena. The Baytex Energy Centre is the primary ice arena in Peace River, which is the nearest town to our Seal operation. We take great pride in having the Baytex name on this facility, and we are delighted to support minor hockey and other sports and cultural activities in Peace River and our other operating areas.

On behalf of the Board of Directors,

Anthony Marino
President and Chief Executive Officer
March 13, 2012

Baytex Energy Corp. 2011 Annual Report 7

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 year ended December 31, 2011. This information is provided as of March 13, 2012. 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. This MD&A should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2011 and 2010 (the "consolidated financial statements"), together with accompanying notes, and the Annual Information Form for the year ended December 31, 2011. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com. The consolidated financial statements for the year ended December 31, 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.

2011 OVERVIEW

We are a conventional oil and gas corporation with our head office in Calgary, Alberta. Through our subsidiaries, we are engaged in the business of acquiring, developing, exploiting and holding interests in petroleum and natural gas properties and related assets in Canada (primarily in the provinces of British Columbia, Alberta and Saskatchewan) and in the United States (primarily in the states of North Dakota and Wyoming). We act as the primary financing vehicle for our subsidiaries by providing access to debt and equity capital markets.

During 2011, we executed a successful capital program, resulting in the replacement of 156% of production (on a proved plus probable basis) by reinvesting approximately 66% of funds from operations into exploration and development activities. Including acquisitions (net of proceeds of disposition), our capital program replaced 227% of production while reinvesting approximately 93% of funds from operations.

On February 3, 2011, we completed the acquisition of heavy oil assets located in the Reno area of northern Alberta and the Lloydminster area of western Saskatchewan. The total consideration for the acquisition of $159.3 million (net of adjustments) was funded by drawing on our revolving credit facilities.

On February 17, 2011, we completed a private placement of US$150 million principal amount of 6.75% Series B senior unsecured debentures due February 17, 2021. The net proceeds of the offering were used to repay existing indebtedness under the credit facilities and for general corporate purposes.

On August 9, 2011, we completed the acquisition of natural gas assets located in the Brewster area of west central Alberta. The total consideration for the acquisition of $22.4 million (net of adjustments) was funded by drawing on our revolving credit facilities.

In the fourth quarter of 2011, we completed two dispositions of primarily undeveloped lands for $47.4 million. In the Kaybob South area of west central Alberta, we sold six sections of leasehold, including five sections with Duvernay

8 Baytex Energy Corp. 2011 Annual Report

rights, for $11.1 million. In the Dodsland area in southwest Saskatchewan, we sold 32,600 net acres of leasehold in the "halo" of the field for $36.3 million.

As at December 31, 2011, our total proved reserves increased 12% to 157 million boe and our total proved plus probable reserves increased 10% to 252 million boe. During the year ended December 31, 2011, our production averaged 50,132 boe/d, primarily from our properties in Canada.

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 activities are directed towards increasing oil production through organic property development and acquisitions, with the objectives of providing monthly income and long-term value creation for its 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. Baytex will primarily participate in development activities that are 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 have received 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".

Baytex Energy Corp. 2011 Annual Report 9

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 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, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

RESULTS OF OPERATIONS

Production

	Years Ended December 31

	2011	2010	Change

Daily Production

Light oil and NGL (bbl/d)	6,769	6,539	4%
Heavy oil (bbl/d)⁽¹⁾	35,252	28,585	23%
Natural gas (mmcf/d)	48.7	55.3	(12%	)

Total production (boe/d)	50,132	44,341	13%
Production Mix
Light oil and NGL	14%	15%	–
Heavy oil	70%	64%	–
Natural gas	16%	21%	–

(1): Heavy oil sales volumes may differ from reported production volumes due to changes to Baytex's heavy oil inventory. For the year ended December 31, 2011, heavy oil sales volumes were 72 bbl/d higher than production volumes (year ended December 31, 2010 – 36 bbl/d lower).

Production for the year ended December 31, 2011 averaged 50,132 boe/d, as compared to 44,341 boe/d for the same period in 2010. Light oil and NGL production for the year ended December 31, 2011 increased by 4% to 6,769 bbl/d from 6,539 bbl/d a year earlier due to development activities in the US, which increased US production by 81%, as compared to the same period in 2010, partially offset by second quarter production interruptions in North Dakota, Alberta and British Columbia. Heavy oil production for the year ended December 31, 2011 increased by 23% to 35,252 bbl/d from 28,585 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 48.7 mmcf/d for the year ended December 31, 2011, as compared to 55.3 mmcf/d for the same period. The decrease in natural gas production was primarily due to natural declines as we focused our drilling effort on our oil portfolio and, to a lesser extent, to pipeline constraints in west central Alberta partially offset by a natural gas-weighted acquisition that closed in the third quarter of 2011.

10 Baytex Energy Corp. 2011 Annual Report

Commodity Prices

Crude Oil

For the year ended December 31, 2011, the price of West Texas Intermediate ("WTI") fluctuated from a low of US$75.67/bbl to a high of US$113.93/bbl. The average prompt WTI price for the year ended December 31, 2011 was US$95.12/bbl, or 20% higher than the corresponding 2010 price of US$79.53/bbl. 2011 was a year of significant volatility, as oil prices reacted to rapidly changing macroeconomic issues and uncertainty, political and social unrest, and underlying energy market fundamentals. Global oil demand growth from emerging market countries, including China, and several smaller oil supply disruptions, have helped support oil prices over the past year. By the end of 2011, oil markets appeared to focus on signs of improving economic activity in the United States and growing tensions over Iran's nuclear program, both of which contributing to rising oil prices.

The Western Canadian Select ("WCS") price differential to WTI, averaged 18% in the year ended December 31, 2011, unchanged from 2010. The volatility of the heavy oil differential in 2011 was marked by periodic transportation disruptions increasing differentials, which was offset by a combination of high refinery runs in the mid-continent region of the United States and new heavy oil refinery capacity in late 2011 supporting heavy oil demand and lower heavy oil differentials.

Natural Gas

For the year ended December 31, 2011, AECO natural gas prices averaged $3.68/mcf, as compared to $4.13/mcf in 2010. Natural gas prices have remained at depressed levels during 2011 due to significant natural gas production capacity additions in the United States, which have exceeded gas demand growth, and a warm start to the winter of 2011-2012 resulting in low demand.

			Years Ended December 31

			2011			2010		Change

Benchmark Averages
	WTI oil (US$/bbl)⁽¹⁾	$	95.12		$	79.53		20%
	WCS heavy oil (US$/bbl)⁽²⁾	$	77.97		$	65.30		19%
	Heavy oil differential⁽³⁾		(18%	)		(18%	)	–%
	USD/CAD average exchange rate		1.0114			0.9708		4%
	Edmonton par oil ($/bbl)	$	95.56		$	77.81		23%
	AECO natural gas price ($/mcf)⁽⁴⁾	$	3.68		$	4.13		(11%	)
Baytex Average Sales Prices
	Light oil and NGL ($/bbl)	$	82.49		$	65.90		25%
	Heavy oil ($/bbl)⁽⁵⁾	$	65.36		$	60.08		9%
	Physical forward sales contracts gain (loss) ($/bbl)		0.17			(0.68	)

	Heavy oil, net ($/bbl)	$	65.53		$	59.40		10%

	Total oil and NGL, net ($/bbl)	$	68.26		$	60.61		13%

	Natural gas ($/mcf)⁽⁶⁾	$	3.86		$	4.22		(9%	)
	Physical forward sales contracts gain ($/mcf)		0.31			0.10

	Natural gas, net ($/mcf)	$	4.17		$	4.32		(3%	)
Summary
	Weighted average ($/boe)⁽⁶⁾	$	60.78		$	53.75		13%
	Physical forward sales contracts gain (loss) ($/boe)		0.48			(0.36	)

	Weighted average, net ($/boe)	$	61.26		$	53.39		15%

(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.

Baytex Energy Corp. 2011 Annual Report 11

For the year ended December 31, 2011, Baytex's average sales price for light oil and NGL was $82.49/bbl, up 25% from $65.90/bbl in the same period in 2010. Baytex's realized heavy oil price during the year ended December 31, 2011, prior to physical forward sales contracts, was $65.36/bbl, or 85% of WCS. This compares to a realized heavy oil price in the same period of 2010, prior to physical forward sales contracts, of $60.08/bbl, or 89% 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 year ended December 31, 2011 was $65.53/bbl, up 10% from $59.40/bbl in the same period in 2010. Baytex's realized natural gas price for the year ended December 31, 2011 was $3.86/mcf prior to physical forward sales contracts and $4.17/mcf inclusive of physical forward sales contracts (year ended December 31, 2010 – $4.22/mcf prior to physical forward sales contracts and $4.32/mcf inclusive of physical forward sales contracts).

Gross Revenues

			Years Ended December 31

($ thousands except for %)			2011		2010	Change

Oil revenue
	Light oil and NGL	$	204,513	$	157,603	30%
	Heavy oil		843,707		618,969	36%

	Total oil revenue		1,048,220		776,572	35%
Natural gas revenue			74,018		87,116	(15%	)

Total oil and natural gas revenue			1,122,238		863,688	30%

Sales of heavy oil blending diluent			186,576		141,448	32%

Total petroleum and natural gas sales		$	1,308,814	$	1,005,136	30%

For the year ended December 31, 2011, petroleum and natural gas sales increased 30% to $1,308.8 million from $1,005.1 million for the same period in 2010. During this period, the change was driven by heavy oil revenues which increased by 36% due to a 9% increase in realized price and an 23% increase in sales volume compared to the year ended December 31, 2010.

Royalties

			Years Ended December 31

($ thousands except for % and per boe)			2011		2010	Change

Royalties		$	212,172	$	170,844	24%
Royalty rates:
	Light oil, NGL and natural gas		18.7%		20.5%	–
	Heavy oil		19.0%		19.5%	–

Average royalty rates⁽¹⁾			18.9%		19.8%	–
Royalty expenses per boe		$	11.59	$	10.56	10%

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

Total royalties for the year ended December 31, 2011 increased to $212.2 million from $170.8 million in the year ended December 31, 2010. Total royalties for the year ended December 31, 2011 were 18.9% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 19.8% for the same period in 2010. Royalty rates for light oil, NGL and natural gas decreased from 20.5% in the year ended December 31, 2010 to 18.7% in the year ended December 31, 2011 due to conventional oil royalty rate incentives on new wells, partially offset by higher royalty rates for properties acquired in August 2011. Royalty rates for heavy oil decreased from 19.5% in the year ended December 31, 2010 to 19.0% in the year ended December 31, 2011 due to royalty rate incentives on new wells at Seal and Kerrobert. In addition, Baytex received a positive $1.0 million Alberta Royalty

12 Baytex Energy Corp. 2011 Annual Report

Tax Credit reassessment related to 2004 and 2005 periods. This increased credit was received in the first quarter of 2011, which decreased our reported royalty rate for 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

			Years Ended December 31

($ thousands)			2011			2010			Change

Realized gain (loss) on financial derivatives⁽¹⁾
	Crude oil	$	(17,641	)	$	7,609		$	(25,250	)
	Natural gas		431			11,322			(10,891	)
	Foreign currency		15,230			28,119			(12,889	)
	Interest rate		116			1,079			(963	)

	Total	$	(1,864	)	$	48,129		$	(49,993	)

Unrealized gain (loss) on financial derivatives⁽²⁾
	Crude oil	$	1,237		$	(17,546	)	$	18,783
	Natural gas		6,004			(641	)		6,645
	Foreign currency		(17,542	)		(9,261	)		(8,281	)
	Interest rate		(5,865	)		(15,864	)		9,999

	Total	$	(16,166	)	$	(43,312	)	$	27,146

Total gain (loss) on financial derivatives
	Crude oil	$	(16,404	)	$	(9,937	)	$	(6,467	)
	Natural gas		6,435			10,681			(4,246	)
	Foreign currency		(2,312	)		18,858			(21,170	)
	Interest rate		(5,749	)		(14,785	)		9,036

	Total	$	(18,030	)	$	4,817		$	(22,847	)

(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 loss on financial derivatives for the year ended December 31, 2011 was $18.0 million, as compared to a gain of $4.8 million for the same period in 2010. This includes a realized loss of $1.9 million and an unrealized mark-to-market loss of $16.2 million for the year ended December 31, 2011, as compared to $48.1 million in realized gains and $43.3 million in unrealized losses for the same period in 2010. The realized loss of $1.9 million for the year ended December 31, 2011 relates to the realization of losses on commodity contracts due to higher oil prices offset by gains on foreign currency contracts. The unrealized loss of $16.2 million for the year ended December 31, 2011, is mainly due to the reversal of previously recorded unrealized gains on foreign currency contracts as they are settled upon maturity and a decrease in floating 3-month London Interbank Offer Rates offset by lower natural gas price.

A summary of the risk management contracts in place as at December 31, 2011 and the accounting treatment of the Company's financial instruments are disclosed in note 23 to the consolidated financial statements as at and for the year ended December 31, 2011.

Evaluation and Exploration Expense

Evaluation and exploration expense for the year ended December 31, 2011 decreased to $13.9 million, as compared and $24.5 million for the year ended December 31, 2010, due to a decrease in the expiration of undeveloped land leases during 2011.

Baytex Energy Corp. 2011 Annual Report 13

Production and Operating Expenses

		Years Ended December 31

($ thousands except for % and per boe)		2011		2010	Change

Production and operating expenses	$	209,177	$	171,704	22%
Production and operating expenses per boe	$	11.43	$	10.62	8%

Production and operating expenses for the year ended December 31, 2011 increased to $209.2 million from $171.7 million for the same period of 2010 due to an increase in total production volumes from development activities and difficult 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 a number of turnarounds conducted at operated and non-operated oil and natural gas processing facilities. Production and operating expenses were $11.43 per boe for the year ended December 31, 2011, as compared to $10.62 per boe for the same period in 2010. For the year ended December 31, 2011, production and operating expenses were $12.21 per boe of light oil, NGL and natural gas and $11.09 per barrel of heavy oil, as compared to $10.64 per boe and $10.60 per barrel, respectively, for the same period in 2010.

Transportation and Blending Expenses

		Years Ended December 31

($ thousands except for % and per boe)		2011		2010	Change

Blending expenses	$	186,576	$	141,448	32%
Transportation expenses⁽¹⁾		63,274		47,143	34%

Total transportation and blending expenses	$	249,850	$	188,591	32%

Transportation expense per boe⁽¹⁾	$	3.46	$	2.92	18%

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

Transportation and blending expenses for the year ended December 31, 2011 were $249.9 million, as compared to $188.6 million for the year ended 2010.

The heavy oil produced by Baytex requires blending to reduce its viscosity in order to meet pipeline specifications. In most cases, Baytex purchases condensate from industry producers as the blending diluent to facilitate the marketing of its heavy oil. In the year ended December 31, 2011, blending expenses were $186.6 million for the purchase of 5,031 bbl/d of condensate at $101.60 per barrel, as compared to $141.4 million for the purchase of 4,557 bbl/d at $85.05 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 $3.46 per boe for the year ended December 31, 2011, as compared to $2.92 per boe for the same period of 2010. Transportation expenses were $0.79 per boe of light oil, NGL and natural gas and $4.58 per barrel of heavy oil in the year ended December 31, 2011, as compared to $0.85 and $4.05 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 utilizes long-haul trucking to ship a portion of production volumes, and higher fuel prices.

14 Baytex Energy Corp. 2011 Annual Report

Operating Netback

			Years Ended December 31

($ per boe except for % and volume)			2011			2010	Change

Sales volume (boe/d)			50,154			44,305	13%
Operating netback⁽¹⁾:
Sales price⁽²⁾		$	61.26		$	53.39	15%
Less:
	Royalties		11.59			10.56	10%
	Operating expenses		11.43			10.62	8%
	Transportation expenses		3.46			2.92	18%

Operating netback before financial derivatives		$	34.78		$	29.29	19%

Financial derivatives gain (loss)⁽³⁾			(0.10	)		2.98	(103%	)

Operating netback after financial derivatives gain (loss)		$	34.68		$	32.27	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

		Years Ended December 31

($ thousands except for % and per boe)		2011		2010	Change

General and administrative expenses	$	39,335	$	40,747	(3%	)
General and administrative expenses per boe	$	2.15	$	2.52	(15%	)

General and administrative expenses for the year ended December 31, 2011 decreased to $39.3 million from $40.7 million for the year ended December 31, 2010. This decrease is a result of lower non-recurring consulting fees, including fees relating to our corporate conversion at year-end 2010, and higher capital overhead recoveries from increased capital expenditures, 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 $15.6 million for the year ended December 31, 2011, as compared to a $94.2 million expense related to the Trust Unit Rights Incentive Plan of the Trust (the "Unit Rights Plan") 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 year ended December 31, 2011, the Company recorded $18.2 million related to the share awards (December 31, 2010 – $nil). 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 is recognized in income over the vesting period of the share rights or share awards with a corresponding increase in contributed

Baytex Energy Corp. 2011 Annual Report 15

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

		Years Ended December 31

($ thousands except for %)		2011		2010	Change

Bank loan and other	$	12,489	$	12,547	–%
Long-term debt		22,935		14,198	62%
Accretion on asset retirement obligations		6,185		5,862	6%
Convertible debentures		–		320	(100%	)
Debt financing costs		3,002		1,643	83%

Financing costs	$	44,611	$	34,570	29%

Financing costs for the year ended December 31, 2011 increased to $44.6 million, as compared to $34.6 million for the year ended December 31, 2010. The increase in financing costs was primarily attributable to the higher levels of outstanding debt, interest on the US$150.0 million principal amount of 6.75% Series B senior unsecured debentures issued on February 17, 2011 and higher fees for our revolving credit facilities.

Foreign Exchange

		Years Ended December 31

($ thousands except for % and exchange rates)		2011			2010		Change

Unrealized foreign exchange loss (gain)	$	8,490		$	(8,999	)	194%
Realized foreign exchange gain		(656	)		(149	)	(340%	)

Total loss (gain)	$	7,834		$	(9,148	)	186%

USD/CAD exchange rates:
At beginning of period		1.0054			0.9555
At end of period		0.9833			1.0054

The foreign exchange loss for the year ended December 31, 2011 was $7.8 million, as compared to a gain of $9.1 million for the year ended December 31, 2010. This loss was comprised of an unrealized foreign exchange loss of $8.5 million and a realized foreign exchange gain of $0.7 million. The year ended December 31, 2011 unrealized loss of $8.5 million, as compared to a gain of $9.0 million for the same period in 2010, was due to the translation of the US$180.0 million portion of the bank loan as the USD/CAD foreign exchange rates strengthened (as compared to December 31, 2010) and weakened at December 31, 2010 (as compared to December 31, 2009). In addition, the translation of the US$150.0 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 December 31, 2011. The realized gains for the year ended December 31, 2011 and 2010 were due to day-to-day US dollar denominated transactions.

Depletion and Depreciation

Depletion and depreciation for the year ended December 31, 2011 increased to $248.5 million from $202.8 million for the same period in 2010. On a sales-unit basis, the provision for the year ended December 31, 2011 was $13.57 per boe, as compared to $12.54 per boe for the same period in 2010 due to the increase in future development costs resulting in a higher depletable base.

16 Baytex Energy Corp. 2011 Annual Report

Income Taxes

For the year ended December 31, 2011, deferred income tax expense totaled $52.1 million, as compared to a recovery of $124.2 million for the year ended December 31, 2010. Prior to its conversion from a mutual fund trust to a corporation on December 31, 2010, Baytex sheltered a portion of its income from income taxes by deducting distributions payable to unitholders. Subsequent to conversion, the Company's earnings have been entirely sheltered from current income taxes by a drawdown of tax pools. An increase in deferred income tax expense in 2011 compared to 2010 reflects the cost of consuming these pools. In addition, $109.8 million of the $124.2 million recovery for the year ended December 31, 2010 recovery for the year ended December 31, 2011 relates to the difference between the deferred income tax asset and the cash paid for the acquisition of private entities during the second quarter of 2010.

As at December 31, 2011, net deferred income tax liability was $83.1 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.

As a result of the conversion from a trust structure to a corporate legal form on December 31, 2010, Baytex is no longer 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 the future. We have accumulated the Canadian and US tax pools as noted in the table below, which will be available to reduce 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 existing legislation, we expect to become liable for Canadian income taxes in 2013.

The income tax pools detailed below are deductible at various rates as prescribed by law:

($ thousands)		December 31, 2011		December 31, 2010

Canadian Tax Pools

Canadian oil and natural gas property expenditures	$	264,503	$	271,741
Canadian development expenditures		328,006		292,500
Canadian exploration expenditures		4,253		11,757
Undepreciated capital costs		266,105		184,586
Non-capital losses		712,288		775,727
Financing costs and other		9,824		10,334

Total Canadian tax pools	$	1,584,979	$	1,546,645

US Tax Pools

Taxable depletion	$	92,871	$	125,628
Intangible drilling costs		87,039		35,000
Tangibles		21,835		3,634
Non-capital losses		90,828		66,530

Total US tax pools	$	292,573	$	230,792

Baytex Energy Corp. 2011 Annual Report 17

Net Income

Net income for the year ended 2011 was $217.4 million, as compared to $231.6 million for the same period in 2010. This decrease in net income was primarily the result of higher deferred income tax expense, financial derivative losses and depletion and depreciation. This was partially offset by a decrease in share-based compensation and larger gains realized on sale of oil and gas properties compared to 2010.

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 $3.6 million balance of accumulated other comprehensive loss at December 31, 2011 is the sum of a $10.3 million foreign currency translation loss incurred in 2010 and a $6.8 million foreign currency translation gain for the year ended December 31, 2011 as USD/CAD foreign exchange rates strengthened at December 31, 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):

		Years Ended

($ thousands except for %)		December 31, 2011			December 31, 2010

Cash flow from operating activities	$	571,860		$	461,406
Change in non-cash working capital		10,889			11,704
Asset retirement expenditures		10,588			2,829
Financing costs		(44,611	)		(34,570	)
Accretion on asset retirement obligations		6,185			5,862
Accretion on debentures and long-term debt		572			426

Funds from operations	$	555,483		$	447,657

Cash dividends/distributions declared	$	281,047		$	243,382
Reinvested dividends/distributions		75,087			53,558

Cash dividends/distributions declared (net of DRIP)	$	205,960		$	189,824

Payout ratio		51%			54%
Payout ratio (net of DRIP)		37%			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

18 Baytex Energy Corp. 2011 Annual Report

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 $206.0 million for the year ended December 31, 2011 were funded through funds from operations of $555.5 million.

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

		Years Ended

($ thousands)		December 31, 2011		December 31, 2010

Cash flow from operating activities	$	571,860	$	461,406
Cash dividends/distributions declared (net of DRIP)		205,960		189,824

Excess of cash flow from operating activities over cash dividends/distributions declared (net of DRIP)	$	365,900	$	271,582

Net income	$	217,432	$	231,615
Cash dividends/distributions declared (net of DRIP)		205,960		189,824

Excess (shortfall) of earnings over cash dividends/distributions declared (net of DRIP)	$	11,472	$	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 year ended December 31, 2011, the Company's net income was in excess of cash dividends declared (net of DRIP participation) by $11.5 million, with net income reduced by $354.4 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)		December 31, 2011		December 31, 2010

Bank loan	$	311,960	$	303,773
Long-term debt⁽¹⁾		302,550		150,000
Working capital deficiency		36,071		52,462

Total monetary debt	$	650,581	$	506,235

(1): Principal amount of instruments.

At December 31, 2011, total monetary debt was $650.6 million, as compared to $506.2 million at December 31, 2010. Bank borrowings at December 31, 2011 were $312.0 million, as compared to total credit facilities of $700.0 million.

Baytex Energy Corp. 2011 Annual Report 19

Our wholly-owned subsidiary, Baytex Energy Ltd., 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 $700.0 million (from $650.0 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). Baytex is in compliance with all financial covenants. 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 year ended December 31, 2011 include credit facility amendment fees of $2.3 million ($1.4 million for year ended December 31, 2010). The weighted average interest rate on the bank loan for year ended December 31, 2011 was 3.69% (3.94% for the year ended December 31, 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:

		Years Ended December 31

($ thousands)		2011			2010

Land	$	5,219		$	12,774
Seismic		1,042			186
Drilling and completion		245,093			157,568
Equipment		116,513			61,211
Other		(19	)		(120	)

Total exploration and development	$	367,848		$	231,619

Acquisitions – Corporate		120,006			40,314
Acquisitions – Properties		76,164			22,412
Proceeds from divestitures		(47,396	)		(19,033	)

Total acquisitions and divestitures		148,774			43,693

Total oil and natural gas expenditures		516,622			275,312

Other plant and equipment, net		1,252			8,237

Total capital expenditures	$	517,874		$	283,549

20 Baytex Energy Corp. 2011 Annual Report

For the year ended December 31, 2011, Baytex disposed of assets in Kaybob and Dodsland areas which consisted of $9.0 million of oil and gas properties and $2.1 million of exploration and evaluation assets for net cash proceeds of $47.4 million. Gains totaling $36.3 million were recognized in the statements of income and comprehensive income.

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 March 8, 2012, the Company had 118,755,036 common shares and no preferred shares issued and outstanding.

Off Balance Sheet Arrangements

Baytex is not party to any contractual arrangement under which a non-consolidated entity may have any obligation under certain guarantee contracts, a retained or contingent interest in assets transferred to a non-consolidated entity or similar arrangement that serves as credit, liquidity or market risk support to that entity for such assets. Baytex has no obligation under financial instruments or a material variable interest in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.

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 with funds from operations. These obligations as of December 31, 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	$	225,831	$	225,831	$	–	$	–	$	–
Dividends payable to shareholders		25,936		25,936		–		–		–
Bank loan⁽¹⁾		311,960		–		311,960		–		–
Long-term debt⁽²⁾		302,550		–		–		150,000		152,550
Operating leases		50,117		5,753		11,884		12,228		20,252
Processing and transportation agreements		5,198		3,238		1,960		–		–

Total	$	921,592	$	260,758	$	325,804	$	162,228	$	172,802

(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.

Baytex Energy Corp. 2011 Annual Report 21

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.

The exploration for and the development, production and marketing of petroleum and natural gas involves a wide range of business and financial risks, some of which are beyond the Company's control. Included in these risks are the uncertainty of finding new reserves, fluctuations in commodity prices, the volatile nature of interest and foreign exchange rates, and the possibility of changes to royalty, tax and environmental regulations. The petroleum industry is highly competitive and Baytex competes with a number of other entities, many of which have greater financial and operating resources.

The business risks facing Baytex are mitigated in a number of ways. Geological, geophysical, engineering, environmental and financial analyses are performed on new exploration prospects, development projects and potential acquisitions to ensure a balance between risk and reward. Baytex's ability to increase its production, revenues and funds from operations depends on its success in not only developing its existing properties but also in acquiring, exploring for and developing new reserves and production and managing those assets in an efficient manner.

Despite best practice analysis being conducted on all projects, there are numerous uncertainties inherent in estimating quantities of petroleum and natural gas reserves, including future petroleum and natural gas prices, engineering data, projected future rates of production and the timing of future expenditures. The process of estimating petroleum and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. An independent engineering firm evaluates the Company's properties annually to determine a fair estimate of reserves. The Reserves Committee, consisting of members of the Board of Directors of Baytex (the "Board"), assists the Board in their annual review of the reserve estimates.

The provision for depletion and depreciation in the financial statements and the impairment test are based on proved plus probable reserve estimates. Any future significant revisions could result in a write-down or material changes to the annual rate of depletion and depreciation.

The financial risks that Baytex is exposed to as part of the normal course of its business are managed, in part, with various financial derivative instruments, in addition to physical delivery contracts. The use of derivative instruments is governed under formal internal policies and subject to limits established by the Board. Derivative instruments are not used for speculative or trading purposes.

The Company's financial results can be significantly affected by the prices received for petroleum and natural gas production as commodity prices fluctuate in response to changing market forces. This pricing volatility is expected to continue. As a result, Baytex has a risk management program that may be used to protect the prices of oil and natural gas on a portion of the total expected production. The objective of the risk management program is to decrease exposure to market volatility and ensure the Company's ability to finance its dividends and capital program.

Baytex's financial results are also impacted by fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Crude oil and, to a large extent, natural gas prices are based on reference prices denominated in U.S. dollars, while the majority of expenses are denominated in Canadian dollars. The exchange rate also impacts the valuation of the U.S. dollar borrowings. The related foreign exchange gains and losses are included in net income.

22 Baytex Energy Corp. 2011 Annual Report

Baytex is exposed to changes in interest rates as advances under Baytex Energy's credit facilities are based on the agent bank's prime lending rate, bankers' acceptance discount rates or London Interbank Offer Rates plus applicable margins.

CRITICAL ACCOUNTING ESTIMATES

A summary of Baytex's significant accounting policies can be found in notes 2 and 3 to the consolidated financial statements. The preparation of the consolidated financial statements in accordance with GAAP requires management to make judgments and estimates that affect the financial results of the Company. The financial and operating results of Baytex incorporate certain estimates including:

•: estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;
•: estimated capital expenditures on projects that are in progress;
•: estimated depletion and depreciation that are based on estimates of petroleum and natural gas reserves that Baytex expects to recover in the future;
•: estimated fair values of financial derivative contracts that are subject to fluctuation depending upon the underlying commodity prices, interest rates and foreign exchange rates;
•: estimated value of asset retirement obligations that are dependant upon estimates of future costs and timing of expenditures; and
•: estimated future recoverable value of petroleum and natural gas properties and goodwill.

Baytex has hired individuals who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.

CHANGES IN ACCOUNTING POLICIES

Current Changes in Accounting Policies

Adoption of International Financial Reporting Standards

IFRS replaced previous GAAP in Canada for financial periods beginning on January 1, 2011. At the transition date, publicly accountable enterprises were 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.

Reconciliations to IFRS from the previously published consolidated financial statements, prepared in accordance with previous GAAP are shown in note 29 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 29 to the consolidated financial statements).

Baytex Energy Corp. 2011 Annual Report 23

The following table reconciles Baytex's 2010 previous GAAP results to IFRS for the year ended December 31, 2010:

($ thousands)

Net income – Previous GAAP		$	177,631
	Exploration and evaluation		(24,502	)
	Depletion and depreciation		63,731
	Gain on oil and gas properties		16,227
	Accretion on asset retirement obligation		(1,348	)
	Unit-based compensation		(85,855	)
	Conversion feature of convertible debentures		(5,118	)
	Deferred income tax		92,180
	Other		(1,331	)

Net income – IFRS		$	231,615

($ thousands)

Funds from operations – Previous GAAP		$	454,183
	Exploration and evaluation		(5,610	)
	Other		(916	)

Funds from operations – IFRS		$	447,657

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.

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 year ended December 31, 2010, Baytex had exploration and evaluation capital expenditures of $37.4 million, corporate acquisitions of $2.5 million, divestitures of $0.1 million, transfers to oil and gas properties of $29.1 million, transfers to expense related to lease expiries of $18.9 million and a decrease due to foreign currency translation of $3.3 million. For the year ended December 31, 2010, Baytex expensed $18.9 million of exploration and evaluation assets related to lease expiries and $5.6 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 was no impact to depletion on transition to IFRS at January 1, 2010. Upon adoption of IFRS, for the year ended December 31, 2010, the change in accounting policy resulted in a decrease in depletion expense of $67.4 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

24 Baytex Energy Corp. 2011 Annual Report

value of the asset disposed. For the year ended December 31, 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 re-measured 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). Under IFRS, an additional liability of $87.3 million was charged to deficit at January 1, 2010.

For the year ended December 31, 2010, $4.5 million was reclassified to finance costs and an additional accretion expense of $1.4 million on asset retirement has been recognized in net income under IFRS.

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 December 31, 2010 (immediately prior to the conversion to a corporation) the remeasurement of the liability at reporting date and at settlement date resulted in the recognition of additional unit-based compensation expense of $85.9 million, with a corresponding

Baytex Energy Corp. 2011 Annual Report 25

decrease of $0.3 million in contributed surplus, an increase of $48.0 million in shareholders'/unitholders' equity and an increase of $37.6 million in unit-based payment liability.

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 year ended December 31, 2010, the increase in unitholders'/shareholders' equity of $12.1 million and the increase of $0.4 million in conversion feature of convertible debentures had a corresponding decrease in the $7.4 million liability recorded at January 1, 2010 and a $5.1 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 year ended December 31, 2010, deferred income tax recovery of $109.8 million was recorded in net income for amounts previously recognized as a deferred credit.

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.

26 Baytex Energy Corp. 2011 Annual Report

Future Changes in Accounting Policies

Financial Instruments

The International Accounting Standards Board (the "IASB") published IFRS 9, "Financial Instruments" which 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 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 consolidated financial statements of the Company.

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 consolidated financial statements of the Company.

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 IFRS to group together items within other comprehensive income that may be reclassified to the net income section of the income statement. The amendments also reaffirm existing requirements that items in other comprehensive income 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

Baytex Energy Corp. 2011 Annual Report 27

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.

SELECTED ANNUAL INFORMATION

($ thousands, except per common share or trust unit amounts)			2011		2010

Petroleum and natural gas sales		$	1,305,814	$	1,003,295
Net income⁽¹⁾		$	217,432	$	231,615
	Per common share or trust unit – basic⁽¹⁾	$	1.88	$	2.08
	Per common share or trust unit – diluted⁽¹⁾	$	1.83	$	2.01
Total assets		$	2,461,810	$	1,981,023
Total other long-term financial liabilities		$	609,691	$	450,666
Cash dividends or distributions declared per common share or trust unit		$	2.42	$	2.18
Average wellhead prices, net of blending costs		$	61.26	$	53.39
Total production (boe/d)			50,132		44,341

(1): Net income and net income per common share or trust unit is after non-controlling interest related to exchangeable shares.

FOURTH QUARTER OF 2011

For a discussion and analysis of our operating and financial results for the three months ended December 31, 2011, please see our Management's Discussion and Analysis for the three months and year ended December 31, 2011 dated March 13, 2012, which is incorporated by reference into this MD&A and is accessible on SEDAR at www.sedar.com.

2012 GUIDANCE

We have set a 2012 exploration and development capital budget of $400 million, which is designed to generate production levels at an average annual rate of 54,000 to 55,000 boe/d.

We view 2011 as the year in which we completed our shift from a predominantly income-focused model as a trust to a growth-and-income model in our new corporate era. Our 2012 capital program reflects the continuation and advancement of the growth-and-income model. Based on the mid-point of the production guidance ranges for 2011 and 2012, our 2012 plan reflects an organic production growth rate of 8% based on oil-equivalent production, and 11% for oil production. Our 2012 production mix is forecast to be approximately 69% heavy oil, 16% light oil and natural gas liquids and 15% natural gas, based on a 6:1 natural gas-to-oil equivalency.

Approximately 60% of our 2012 capital budget will be invested in our heavy oil operations, with the majority being directed to cold primary horizontal well development at Seal in the Peace River Oil Sands. This budget also includes funding to begin drilling and facility construction on a second module of commercial thermal development at Seal. The second thermal module is planned as a 15-well cyclic steam stimulation (CSS) project. Subject to receipt of regulatory approvals, we expect to commence development of this project in the fourth quarter of 2012 and be completed in the first quarter of 2013. Our capital budget for the Lloydminster area is directed primarily at cold drilling, with horizontal wells comprising the majority of drilling capital. The balance of our capital program will be directed primarily towards light oil development, with the two largest projects being the Bakken/Three Forks in North Dakota and the Viking in southeast Alberta.

ENVIRONMENTAL REGULATION AND RISK

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities.

28 Baytex Energy Corp. 2011 Annual Report

Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties. Further, environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.

Climate Change Regulation

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"), which requires a reduction in greenhouse gas ("GHG") emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005, although on December 12, 2011 Canada formally withdrew from the Kyoto Protocol. In December 2009, government leaders and representatives met in Copenhagen, Denmark and agreed to the Copenhagen Accord, which reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate change. Another meeting of government leaders and representatives in 2010 resulted in the Cancun Agreements wherein developed countries committed to additional measures to help developing countries deal with climate change. Neither the Copenhagen Accord nor the Cancun Agreements establish binding GHG emissions reduction targets. In response to the Copenhagen Accord, the Government of Canada indicated that it will seek to achieve a 17% reduction in GHG emissions from 2005 levels by 2020.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both GHG emissions and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets. Although draft regulations for the implementation of the Updated Action Plan were intended to become binding on January 1, 2010, only draft regulations pertaining to carbon dioxide emissions from coal-fired generation of electricity have been proposed to date. Further, representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. In January 2012, representatives from the Government of Canada indicated that flexibility may be introduced into the proposed regulations which would allow for Provinces to set their own emissions targets, as long as they have rules in place that would achieve equivalent reductions. As a result of ensuring consistency with the United States and the possibility that emissions targets will be Province specific, it is unclear to what extent, if any, the proposals contained in the Updated Action Plan will be implemented.

In addition to federal commitments and legislation, Province specific legislation also imposes GHG emission standards and regulations which may impact Baytex and its operations and financial condition. The implementation of strategies for reducing GHG, whether to meet the goals of the Copenhagen Accord, the Cancun Agreements, federal or provincial regulations, or otherwise, could have a material impact on the nature of oil and natural gas operations, including those of Baytex. Given the evolving nature of the debate related to climate changes and the regulation of GHG, it is not possible to predict the impact of those requirements, or future requirements, on Baytex and its operations and financial condition.

Further information regarding environmental and climate change regulation is contained in our Annual Information Form for the year ended December 31, 2011 under the "Industry Conditions – Climate Change Regulation" section.

DISCLOSURE CONTROL AND PROCEDURES

As of December 31, 2011, an evaluation was conducted of the effectiveness of the Baytex's "disclosure controls and procedures" (as defined in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act") and in Canada by National Instrument 52-109, Certification of Disclosure in

Baytex Energy Corp. 2011 Annual Report 29

Issuers' Annual and Interim Filings ("NI 52-109")) under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the Baytex's disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that the Baytex files or submits under the Exchange Act or under Canadian securities legislation is (i) recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms and (ii) accumulated and communicated to the Company's management, including the President and Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding the required disclosure.

It should be noted that while the President and Chief Executive Officer and the Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Baytex's disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Baytex. "Internal control over financial reporting" (as defined in the United States by Rules 13a-15(f) and 15d-15(f) under the Exchange Act and in Canada by NI 52-109) is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of Baytex's financial statements for external reporting purposes in accordance with Canadian GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Additionally, projections of any evaluations of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with Baytex's policies and procedures. Management has assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2011 based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2011. The effectiveness of the Baytex's internal control over financial reporting as of December 31, 2011 has been audited by Deloitte & Touche LLP, as reflected in their report for 2011.

No changes were made to our internal control over financial reporting during the year ended December 31, 2011.

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

30 Baytex Energy Corp. 2011 Annual Report

adoption of new accounting standards on our financial results; our exploration and development capital expenditures for 2012; our average production rate for 2012; our production growth rates for 2012; our production mix for 2012; the allocation of our exploration and development capital expenditures for 2012; our heavy oil resource play at Seal, including the timing of completing a 15-well cyclic steam stimulation project; and the impact of new environmental and climate change regulations on 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. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time.

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 receipt, in a timely manner, of regulatory and other required approvals; 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; the failure to obtain the necessary regulatory and other approvals on planned timelines; 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, 2011, 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.

Baytex Energy Corp. 2011 Annual Report 31

MANAGEMENT'S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

The management of Baytex Energy Corp. is responsible for establishing and maintaining adequate internal control over financial reporting over the Company. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2011, our internal control over financial reporting was effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2011 has been audited by Deloitte & Touche LLP, the Company's Independent Registered Chartered Accountants, who also audited the Company's Consolidated Financial Statements for the year ended December 31, 2011.

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

Management, in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board, has prepared the accompanying consolidated financial statements of Baytex Energy Corp. Financial and operating information presented throughout this Annual Report is consistent with that shown in the consolidated financial statements.

Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.

Deloitte & Touche LLP were appointed by the Company's shareholders to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with IFRS.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board exercises this responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our petroleum and natural gas reserves. The Audit Committee meets regularly with management and the Independent Registered Chartered Accountants to ensure that management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of Deloitte & Touche LLP and reviews their fees. The Independent Registered Chartered Accountants have access to the Audit Committee without the presence of management.


Anthony W. Marino President and Chief Executive Officer Baytex Energy Corp.		W. Derek Aylesworth Chief Financial Officer Baytex Energy Corp.

March 13, 2012

32 Baytex Energy Corp. 2011 Annual Report

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Baytex Energy Corp.

We have audited the accompanying consolidated financial statements of Baytex Energy Corp. and subsidiaries (the "Company"), which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, and the consolidated statements of income and comprehensive income, statements of changes in equity, and statements of cash flows for the years ended December 31, 2011 and December 31, 2010, and the notes to the consolidated financial statements.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Baytex Energy Corp. and subsidiaries as at December 31, 2011, December 31, 2010 and January 1, 2010 and their financial performance and cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 13, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

Calgary, Canada
March 13, 2012		Independent Registered Chartered Accountants

Baytex Energy Corp. 2011 Annual Report 33

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Baytex Energy Corp.

We have audited the internal control over financial reporting of Baytex Energy Corp. and subsidiaries (the "Company") as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the Company and our report dated March 13, 2012 expressed an unqualified opinion on those financial statements.

Calgary, Canada
March 13, 2012		Independent Registered Chartered Accountants

34 Baytex Energy Corp. 2011 Annual Report

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

As at			December 31, 2011			December 31, 2010			January 1, 2010

(thousands of Canadian dollars)
ASSETS
Current assets
Cash		$	7,847		$	–		$	10,177
Trade and other receivables (note 6)			206,951			151,792			137,154
Crude oil inventory			898			1,802			1,384
Financial derivatives (note 23)			10,879			13,921			29,453

			226,575			167,515			178,168
Non-current assets
	Deferred income tax asset (note 19)		10,133			7,870			1,789
	Financial derivatives (note 23)		180			2,622			2,541
	Exploration and evaluation asset (note 7)		129,774			113,082			124,621
	Oil and gas properties (note 8)		2,032,160			1,624,629			1,512,035
	Other plant and equipment (note 9)		25,233			27,550			27,096
	Goodwill (note 10)		37,755			37,755			37,755

		$	2,461,810		$	1,981,023		$	1,884,005

LIABILITIES
Current liabilities
	Trade and other payables (note 12)	$	225,831		$	183,314		$	186,516
	Dividends or distributions payable to shareholders/unitholders		25,936			22,742			19,674
	Bank loan (note 11)		–			–			265,088
	Convertible debentures (note 14)		–			–			7,736
	Financial derivatives (note 23)		25,205			20,312			12,004

			276,972			226,368			491,018
Non-current liabilities
	Bank loan (note 11)		311,960			303,773			–
	Long-term debt (note 13)		297,731			146,893			146,498
	Asset retirement obligations (note 15)		260,411			169,611			141,869
	Unit-based payment liability (note 17)		–			–			91,559
	Deferred income tax liability (note 19)		93,217			14,383			160,719
	Financial derivatives (note 23)		14,785			8,859			1,418

			1,255,076			869,887			1,033,081

SHAREHOLDERS'/UNITHOLDERS' EQUITY
Shareholders' capital (note 16)			1,680,184			1,484,335			–
Unitholders' capital (note 16)			–			–			1,331,161
Contributed surplus			85,716			129,129			–
Accumulated other comprehensive loss			(3,546	)		(10,323	)		–
Deficit			(555,620	)		(492,005	)		(480,237	)

			1,206,734			1,111,136			850,924

		$	2,461,810		$	1,981,023		$	1,884,005

Commitments and contingencies (note 26)

See accompanying notes to the consolidated financial statements.

On behalf of the Board


Naveen Dargan		Gregory K. Melchin
Director, Baytex Energy Corp.		Director, Baytex Energy Corp.

Baytex Energy Corp. 2011 Annual Report 35

CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME

Years Ended December 31		2011			2010

(thousands of Canadian dollars, except per common share and per trust unit amounts)
Revenues, net of royalties (note 20)	$	1,096,642		$	834,292
Expenses
Exploration and evaluation		13,865			24,502
Production and operating		209,177			171,704
Transportation and blending		249,850			188,591
General and administrative		39,335			40,747
Share-based or unit-based compensation (note 17)		33,845			94,199
Financing costs (note 21)		44,611			34,570
Gain on divestitures of oil and gas properties		(37,946	)		(16,227	)
Loss (gain) on financial derivatives (note 23)		18,030			(4,817	)
Foreign exchange loss (gain) (note 22)		7,834			(9,148	)
Depletion and depreciation (note 8 & 9)		248,468			202,796

		827,069			726,917

Net income before income taxes		269,573			107,375
Deferred income tax expense (recovery) (note 19)		52,141			(124,240	)

Net income attributable to shareholders/unitholders	$	217,432		$	231,615

Other comprehensive income (loss)
Foreign currency translation adjustment		6,777			(10,323	)

Comprehensive income attributable to shareholders/unitholders	$	224,209		$	221,292

Net income per common share or trust unit (note 18)
Basic	$	1.88		$	2.08
Diluted	$	1.83		$	2.01
Weighted average common shares or trust units (note 18)
Basic		115,960			111,450
Diluted		118,921			115,151

See accompanying notes to the consolidated financial statements.

36 Baytex Energy Corp. 2011 Annual Report

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

		Shareholders' capital		Unitholders' capital			Contributed surplus			Accumulated other comprehensive income (loss)			Deficit			Total equity

(thousands of Canadian dollars)
Balance at January 1, 2010	$	–	$	1,331,161		$	–		$	–		$	(480,237	)	$	850,924
Distributions to unitholders		–		–			–			–			(243,383	)		(243,383	)
Issued on conversion of debentures		–		19,897			–			–			–			19,897
Exercise of unit rights		–		82,649			–			–			–			82,649
Issued pursuant to distribution reinvestment plan		–		51,699			–			–			–			51,699
Comprehensive income (loss) for the period		–		–			–			(10,323	)		231,615			221,292
Change in effective tax rate on issue costs		–		(1,071	)		–			–			–			(1,071	)
Exchanged for shares, pursuant to the Arrangement		1,484,335		(1,484,335	)		129,129			–			–			129,129

Balance at December 31, 2010	$	1,484,335	$	–		$	129,129		$	(10,323	)	$	(492,005	)	$	1,111,136

Dividends to shareholders		–		–			–			–			(281,047	)		(281,047	)
Exercise of share rights		122,306		–			(77,258	)		–			–			45,048
Share-based compensation		–		–			33,845			–			–			33,845
Issued pursuant to dividend reinvestment plan		73,543		–			–			–			–			73,543
Comprehensive income for the period		–		–			–			6,777			217,432			224,209

Balance at December 31, 2011	$	1,680,184	$	–		$	85,716		$	(3,546	)	$	(555,620	)	$	1,206,734

See accompanying notes to the consolidated financial statements.

Baytex Energy Corp. 2011 Annual Report 37

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31			2011			2010

(thousands of Canadian dollars)
CASH PROVIDED BY (USED IN):
Operating activities
Net income for the year		$	217,432		$	231,615
Adjustments for:
	Share-based or unit-based compensation (note 17)		33,845			94,199
	Unrealized foreign exchange loss (gain) (note 22)		8,490			(8,999	)
	Exploration and evaluation		10,130			18,913
	Depletion and depreciation		248,468			202,796
	Unrealized loss on financial derivatives (note 23)		16,166			43,312
	Gain on divestitures of oil and gas properties		(37,946	)		(16,227	)
	Deferred income tax expense (recovery) (note 19)		52,141			(124,240	)
	Financing costs (note 21)		44,611			34,570
	Change in non-cash working capital (note 22)		(10,889	)		(11,704	)
	Asset retirement expenditures (note 15)		(10,588	)		(2,829	)

			571,860			461,406

Financing activities
Payments of dividends or distributions			(204,308	)		(188,615	)
Increase in bank loan			4,290			48,045
Proceeds from issuance of long-term debt (note 13)			145,810			–
Repayment of convertible debentures (note 14)			–			(341	)
Issuance of common shares or trust units (note 16)			45,048			26,021
Interest paid			(34,730	)		(28,499	)

			(43,890	)		(143,389	)

Investing activities
Additions to exploration and evaluation assets (note 7)			(9,104	)		(37,411	)
Additions to oil and gas properties			(358,744	)		(194,208	)
Property acquisitions			(76,164	)		(22,412	)
Corporate acquisitions (note 5)			(120,006	)		(40,314	)
Proceeds from divestitures			47,396			19,033
Additions to other plant and equipment, net of disposals (note 9)			(1,252	)		(8,237	)
Acquisition of financing entities (note 19)			–			(38,000	)
Change in non-cash working capital (note 22)			(2,553	)		(5,956	)

			(520,427	)		(327,505	)
Impact of foreign currency translation on cash balances			304			(689	)

Change in cash			7,847			(10,177	)
Cash, beginning of year			–			10,177

Cash, end of year		$	7,847		$	–

See accompanying notes to the consolidated financial statements.

38 Baytex Energy Corp. 2011 Annual Report

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
AS AT DECEMBER 31, 2011, DECEMBER 31, 2010 AND JANUARY 1, 2010
AND FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010
(all tabular amounts in thousands of Canadian dollars, except per common share and per trust unit amounts)

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 - 3^rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 - 8^th 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 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 consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. Canadian generally accepted accounting principles have been revised to incorporate 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.

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 applied in the previous GAAP financial statements to comply with IFRS. The date of transition to IFRS was January 1, 2010 and the comparative figures for 2010 were restated to reflect these adjustments. 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 29.

The consolidated financial statements were approved and authorized by the Board of Directors on March 13, 2012.

The consolidated financial statements have been prepared on the historical cost basis, except for 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.

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

Baytex Energy Corp. 2011 Annual Report 39

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 calculated based on the higher 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 natural 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 23. 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 obligations 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, the estimated time period during which these costs will be incurred in the future and the discount and inflation rates. Any changes

40 Baytex Energy Corp. 2011 Annual Report

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 quarterly 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

Baytex Energy Corp. 2011 Annual Report 41

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

42 Baytex Energy Corp. 2011 Annual Report

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 depleted 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.

Baytex Energy Corp. 2011 Annual Report 43

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 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 consolidated statements of income and comprehensive income (loss). If the debentures were converted to trust units, the fair value of the conversion feature would be reclassified to unitholders' capital along with the principal amounts converted.

An embedded derivative is a component of a contract that modifies the cash flows of the contract. 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.

44 Baytex Energy Corp. 2011 Annual Report

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 balance sheet 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 17. 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 17.

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, 2015, 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

Baytex Energy Corp. 2011 Annual Report 45

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 consolidated financial statements of the Company.

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

Disclosure of Interests in Other Entities

Fair Value Measurement

Presentation of Financial Statements

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 $120.9 million (net of cash acquired). This acquisition provides additional development opportunities in the Seal area where Baytex already possesses significant leasehold and

46 Baytex Energy Corp. 2011 Annual Report

operating infrastructure. The acquisition has been accounted for as a business combination with the 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	$	120,006
Cash paid for working capital (net of cash acquired)		869

Total consideration	$	120,875

Recognized amounts of identifiable assets acquired and liabilities assumed:
Trade and other receivables	$	1,664
Exploration and evaluation assets		14,944
Oil and gas properties		131,635
Trade and other payables		(795	)
Asset retirement obligations		(2,031	)
Deferred income tax liability		(24,542	)

Total net assets acquired	$	120,875

Acquisition-related costs totaling $0.3 million have been excluded from the consideration transferred and have been recognized as an expense in the year ended December 31, 2011, within the "general and administrative" line item in the consolidated statements of income and comprehensive income. The fair value of the acquired trade and other receivables approximates the carrying value due to their short term nature.

From the period of February 3, 2011 to December 31, 2011, the acquired properties contributed revenues, net of royalties, of $38.3 million and revenues, net of royalties, production and operating expenses ("operating income") of $25.5 million to Baytex's operations. If the acquisition had occurred on January 1, 2011, management estimates its pro forma revenues, net of royalties and operating income would have been approximately $41.4 million and $27.9 million, respectively, for the year ended December 31, 2011. It is impracticable to derive all amounts necessary to determine contributed net income from the acquired properties as operations were immediately merged with Baytex's operations to realize synergies.

The fair values of assets and liabilities recognized are estimates due to the uncertainty of provisional amounts recognized.

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 $38.4 million. This acquisition provides additional development opportunities in the Seal area where Baytex already possesses significant leasehold and operating infrastructure. The acquisition has been accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized below:


Consideration for the acquisition:
Cash paid	$	38,439

Total consideration	$	38,439

Recognized amounts of identifiable assets acquired and liabilities assumed:
Exploration and evaluation assets	$	1,700
Oil and gas properties		37,247
Asset retirement obligations		(508	)

Total net assets acquired	$	38,439

Acquisition-related costs totaling $0.1 million have been excluded from the consideration transferred and have been recognized as an expense in the year ended December 31, 2011, within the "General and administrative" line item in the consolidated statements of income and comprehensive income.

Baytex Energy Corp. 2011 Annual Report 47

From the period of February 3, 2011 to December 31, 2011, the acquired properties contributed revenues, net of royalties, of $9.6 million and operating income of $6.4 million to Baytex's operations. If the acquisition had occurred on January 1, 2011, management estimates its pro forma revenues, net of royalties and operating income would have been approximately $10.4 million and $7.0 million, respectively, for the year ended December 31, 2011. It is impracticable to derive all amounts necessary to determine contributed net income from the acquired properties as operations were immediately merged with Baytex's operations to realize synergies.

The fair values of assets and liabilities recognized are estimates due to the uncertainty of provisional amounts recognized.

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 acquired assets provide a number of cold heavy oil development opportunities and were readily integrated into Baytex's existing producing infrastructure in the Lloydminster area. The acquisition has been accounted for as a business combination with the 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

Acquisition-related costs totaling $0.6 million have been excluded from the consideration transferred and have been recognized as an expense in the year ended December 31, 2010, within the "general and administrative" line item in the consolidated statements of income and comprehensive income. The fair value of the acquired trade and other receivables approximates the carrying value due to their short term nature.

From the period of May 26, 2010 to December 31, 2010, the acquired properties contributed revenues, net of royalties, of $8.7 million and operating income of $3.9 million to Baytex's operations. If the acquisition had occurred on January 1, 2010, management estimates its pro forma revenues, net of royalties and operating income would have been approximately $14.9 million and $3.6 million, respectively, for the year ended December 31, 2010. It is impracticable to derive all amounts necessary to determine contributed net income from the acquired properties as operations were immediately merged with Baytex's operations to realize synergies.

6. TRADE AND OTHER RECEIVABLES

As at		December 31, 2011			December 31, 2010			January 1, 2010

Petroleum and natural gas sales and accrual	$	161,567		$	119,827		$	107,657
Joint venture		42,928			30,536			28,581
Prepaid, deposits and other		3,415			3,282			3,252
Allowance for doubtful accounts		(959	)		(1,853	)		(2,336	)

	$	206,951		$	151,792		$	137,154

48 Baytex Energy Corp. 2011 Annual Report

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		9,104
	Corporate acquisition		14,944
	Property acquisition		18,013
	Exploration and evaluation expense		(10,130	)
	Transfer to oil and gas properties		(14,398	)
	Divestitures		(2,058	)
	Foreign currency translation		1,217

As at December 31, 2011		$	129,774

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		364,578
	Corporate acquisition		131,635
	Property acquisitions		61,137
	Transferred from exploration and evaluation assets		14,398
	Change in asset retirement obligations		84,879
	Divestitures		(10,233	)
	Foreign currency translation		5,674

As at December 31, 2011		$	2,471,419

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		244,893
	Divestitures		(667	)
	Foreign currency translation		311

As at December 31, 2011		$	439,259

Carrying value

As at January 1, 2010	$	1,512,035

As at December 31, 2010	$	1,624,629

As at December 31, 2011	$	2,032,160

Baytex Energy Corp. 2011 Annual Report 49

The carrying value of petroleum and natural gas properties are subject to impairment tests, which were calculated at December 31, 2011 using the following benchmark reference prices for the years 2012 to 2016 adjusted for commodity differentials specific to the Company:

	2012	2013	2014	2015	2016

WTI crude oil (US$/bbl)	98.07	94.90	92.00	97.42	99.37
AECO natural gas ($/MMBtu)	3.16	3.78	4.13	5.53	5.65
Exchange rate (USD/CAD)	1.01	1.01	1.01	1.01	1.01

Oil and natural gas prices reflect the NYMEX futures market for the period ending 2012. This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2016 have been adjusted for estimated inflation at an estimated annual rate of 2 percent. Based on the impairment test calculations, the Company's estimated discounted future net cash flows associated with proved and probable reserves exceeded the net book value of the oil and gas properties.

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		1,252
	Foreign currency translation		25

As at December 31, 2011		$	58,801

Accumulated depletion

As at January 1, 2010		$	22,245
	Depreciation		7,781
	Disposals		(26	)
	Foreign currency translation		(26	)

As at December 31, 2010		$	29,974

	Depreciation		3,575
	Foreign currency translation		19

As at December 31, 2011		$	33,568

Carrying value

As at January 1, 2010	$	27,096

As at December 31, 2010	$	27,550

As at December 31, 2011	$	25,233

50 Baytex Energy Corp. 2011 Annual Report

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. GOODWILL

As at		December 31, 2011		December 31, 2010		January 1, 2010

Cost	$	37,755	$	37,755	$	37,755
Impairment		–		–		–

Carrying value	$	37,755	$	37,755	$	37,755

The carrying value, calculated based on the higher of value-in-use (as compared to fair value less cost to sell), of the CGU was determined to be lower than its recoverable amount and no impairment loss was recognized.

The Company estimates value-in-use by using a discounted cash flow model using a pre-tax discount rate. The reserve reports generated by an external party and approved by senior management on an annual basis is the source for information for the determination of the value-in-use value assigned. The reserve reports are based on a remaining reserve life of 50 years. The forecasted cash flows include reserves where there is at least a 50% probability that the estimated proved plus probable reserves will be recovered. Value-in-use, related to this goodwill impairment test, was determined by discounting the future cash flows generated from the CGU using key assumptions as noted in note 8 "Oil and Gas Properties".

11. BANK LOAN

As at		December 31, 2011		December 31, 2010		January 1, 2010

Bank loan	$	311,960	$	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 Baytex and certain of its 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, Baytex's ability to pay dividends to its shareholders may be restricted.

Financing costs for the year ended December 31, 2011 includes facility amendment fees of $2.3 million ($1.4 million for year ended December 31, 2010). The weighted average interest rate on the bank loan for the year ended December 31, 2011 was 3.69% (3.94% for the year ended December 31, 2010).

Baytex Energy Corp. 2011 Annual Report 51

12. TRADE AND OTHER PAYABLES

As at		December 31, 2011		December 31, 2010		January 1, 2010

Trade payables	$	120,717	$	79,841	$	79,150
Joint venture		17,457		12,284		14,924
Capital and operating expense accruals		74,673		77,656		75,471
Other		12,984		13,533		16,971

	$	225,831	$	183,314	$	186,516

13. LONG-TERM DEBT

As at		December 31, 2011		December 31, 2010		January 1, 2010

9.15% senior unsecured debentures (Cdn$150,000 – principal)	$	147,328	$	146,893	$	146,498
6.75% senior unsecured debentures (US$150,000 – principal)		150,403		–		–

	$	297,731	$	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 $0.2 million has been recorded for the year ended December 31, 2011 (year ended December 31, 2010 – $0.3 million).

52 Baytex Energy Corp. 2011 Annual Report

14. 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 December 31, 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 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.

15. ASSET RETIREMENT OBLIGATIONS

		December 31, 2011			December 31, 2010

Balance, beginning of year	$	169,611		$	141,869
Liabilities incurred		5,834			2,030
Liabilities settled		(10,588	)		(2,829	)
Liabilities acquired		5,003			2,207
Liabilities divested		(556	)		(1,254	)
Accretion		6,185			5,862
Change in estimate⁽¹⁾		84,879			21,766
Foreign currency translation		43			(40	)

Balance, end of year	$	260,411		$	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 December 31, 2011 is $315.9 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 2.5% at December 31, 2011 (December 31, 2010 – 3.5% and January 1, 2010 – 4.0%) is $260.4 million (December 31, 2010 – $169.6 million and January 1, 2010 – $141.9 million).

Baytex Energy Corp. 2011 Annual Report 53

16. 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 December 31, 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 December 31, 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	2,665		45,048
Transfer from contributed surplus on exercise of share rights	–		77,258
Issued pursuant to dividend reinvestment plan	1,516		73,543

Balance, December 31, 2011	117,893	$	1,680,184

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 were issued from treasury 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. Commencing with the dividends declared on December 15, 2011, the discount was reduced to three percent. 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.

Monthly dividends of $0.22 per common share in December 2011 and $0.20 per month for each of the previous eleven months were declared by the Company during the year ended December 31, 2011 for total dividends declared of $281.0 million. Monthly 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.

54 Baytex Energy Corp. 2011 Annual Report

Subsequent to December 31, 2011, the Company announced that monthly dividends in respect of January and February 2012 operations of $0.22 per common share totaling $26.1 million each month will be payable on February 15, 2012 and March 15, 2012 to shareholders of record at January 31, 2012 and February 29, 2012, respectively.

17. 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 $15.6 million for the year ended December 31, 2011 (year ended December 31, 2010 – $94.2 million) related to the share rights under the Share Rights Plan or the unit rights under the Unit Rights Plan.

Baytex used 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

Baytex Energy Corp. 2011 Annual Report 55

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

Balance, January 1, 2010	8,120		$	16.68
Granted⁽²⁾	190			32.71
Exercised⁽¹⁾	(2,337	)		11.13
Forfeited⁽¹⁾	(212	)		20.35

Balance, December 31, 2010	5,761		$	17.02

Granted	–			–
Exercised⁽¹⁾	(2,665	)		16.92
Forfeited⁽¹⁾	(125	)		23.05

Balance, December 31, 2011	2,971		$	16.98

(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 December 31, 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 December 31, 2011 (000's)	Weighted Average Grant Price	Weighted Average Remaining Term (years)	Number Exercisable at December 31, 2011 (000's)	Weighted Average Exercise Price	Number Outstanding at December 31, 2011 (000's)	Weighted Average Exercise Price	Weighted Average Remaining Term (years)	Number Exercisable at December 31, 2011 (000's)	Weighted Average Exercise Price

$5.08 to $12.00	–	$ –	–	–	$ –	1,385	$10.88	1.5	1,305	$10.97
$12.01 to $19.00	1,174	17.63	1.8	1,067	17.85	369	17.01	2.1	285	17.28
$19.01 to $26.00	648	20.23	1.2	584	20.01	1,014	22.85	2.8	616	22.85
$26.01 to $33.00	1,105	27.94	2.9	648	27.79	177	28.45	3.1	96	27.94
$33.01 to $40.00	41	35.60	3.6	7	35.35	24	34.78	3.6	4	35.29
$40.01 to $47.72	3	44.96	4.0	1	44.35	2	43.29	4.0	1	42.63

$5.08 to $47.72	2,971	$22.30	2.1	2,307	$21.25	2,971	$16.98	2.1	2,307	$15.60

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

56 Baytex Energy Corp. 2011 Annual Report

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 $18.2 million for the year ended December 31, 2011 and related to the share awards (year ended December 31, 2010 – $nil).

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 $50.27 per restricted award and performance award granted during the year ended December 31, 2011 (no share awards were granted during the year ended December 31, 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	389		243		632
Forfeited	(24	)	(14	)	(38	)

Balance, December 31, 2011	365		229		594

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).

18. 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

Baytex Energy Corp. 2011 Annual Report 57

services not yet recognized are assumed to be used to purchase common shares or trust units at the average market price during the periods.

		Years Ended December 31

		2011					2010

		Net income	Common shares (000's)		Net income per share		Net income	Trust units (000's)		Net income per unit

Net income – basic	$	217,432	115,960	$	1.88	$	231,615	111,450	$	2.08
Dilutive effect of share rights or unit rights		–	2,643				–	3,304
Dilutive effect of share awards		–	318				–	–
Conversion of convertible debentures		–	–				297	397

Net income – diluted	$	217,432	118,921	$	1.83	$	231,912	115,151	$	2.01

For the year ended December 31, 2011, nil share rights (year ended December 31, 2010 – 0.1 million unit rights) were excluded in calculating the weighted average number of diluted common shares outstanding as they were anti-dilutive.

19. INCOME TAXES

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

			Years Ended December 31

			2011			2010

Net income before income taxes		$	269,573		$	107,375
Expected income taxes at the statutory rate of 26.95% (2010 – 28.49%)⁽¹⁾			72,650			30,591
Increase (decrease) in income taxes resulting from:
	Net income of the Trust prior to the Arrangement		–			(69,342	)
	Non-taxable portion of foreign exchange loss (gain)		1,580			(1,333	)
	Non-deductible (taxable) items		–			(2,854	)
	Share-based or unit-based compensation		9,120			26,838
	Effect of change in income tax rates		(9,902	)		11,132
	Effect of rate adjustments for foreign jurisdictions		(3,464	)		(3,730	)
	Effect of change in opening tax pool balances		(14,740	)		(5,740	)
	Effect of change in valuation allowance		(1,770	)		–
	Deferred credit⁽²⁾		–			(109,800	)
	Other		(1,333	)		(2	)

Deferred income tax expense (recovery)		$	52,141		$	(124,240	)

(1): The change in statutory rate is related to a legislated reduction in the Canadian Federal corporate income tax rate and changes in the provincial apportionment of income.
(2): 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.

58 Baytex Energy Corp. 2011 Annual Report

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

As at			December 31, 2011			December 31, 2010			January 1, 2010

Deferred income tax liabilities:
	Petroleum and natural gas properties	$	(280,118	)	$	(224,923	)	$	(196,118	)
	Financial derivatives		–			(4,463	)		(9,432	)
	Partnership deferral		(86,019	)		(52,327	)		(2,921	)
	Other		(2,700	)		(5,025	)		(3,875	)
Deferred income tax assets:
	Asset retirement obligations		55,038			43,339			36,446
	Financial derivatives		7,362			7,870			1,789
	Non-capital losses		219,874			227,149			13,185
	Finance costs		3,479			1,867			1,996

Net deferred income tax liability⁽¹⁾⁽²⁾		$	(83,084	)	$	(6,513	)	$	(158,930	)

(1): Non-capital loss carry-forwards totaled $803.1 million (December 31, 2010 – $842.3 million, January 1, 2010 – $48.4 million) and expire from 2014 to 2031.
(2): Baytex has recognized a net deferred tax asset of $10.3M relating to its US subsidiary. The Company has reviewed the reserves report, undeveloped land holdings and budget forecasts for this subsidiary and has determined that it is probable that future taxable profits will be sufficient to utilize the deductible temporary differences.

A continuity of the net deferred income tax liability is detailed in the following tables:

As at			January 1, 2010			Recognized in Net Income			Acquired in Business Combination			Other			December 31, 2010

Deferred income tax liabilities:
	Petroleum and natural gas properties	$	(196,118	)	$	(19,641	)	$	(9,164	)	$	–		$	(224,923	)
	Financial derivatives		(9,432	)		4,969			–			–			(4,463	)
	Partnership deferral		(2,921	)		(49,406	)		–			–			(52,327	)
	Other		(3,875	)		(1,009	)		–			(141	)		(5,025	)
Deferred income tax assets:
	Asset retirement obligations		36,446			6,341			552			–			43,339
	Financial derivatives		1,789			6,081			–			–			7,870
	Non-capital losses		13,185			175,964			38,000			–			227,149
	Finance costs		1,996			941			–			(1,070	)		1,867

Net deferred income tax liability		$	(158,930	)	$	124,240		$	29,388		$	(1,211	)	$	(6,513	)

As at			January 1, 2011			Recognized in Net Income			Acquired in Business Combination			Other		December 31, 2011

Deferred income tax liabilities:
	Petroleum and natural gas properties	$	(224,923	)	$	(25,724	)	$	(25,059	)	$	–	$	(275,706	)
	Financial derivatives		(4,463	)		4,463			–			–		–
	Partnership deferral		(52,327	)		(33,692	)		–			–		(86,019	)
	Other		(5,025	)		2,213			–			112		(2,700	)
Deferred income tax assets:
	Asset retirement obligations		43,339			11,182			517			–		55,038
	Financial derivatives		7,870			(508	)		–			–		7,362
	Non-capital losses		227,149			(11,687	)		–			–		215,462
	Finance costs		1,867			1,612			–			–		3,479

Net deferred income tax liability		$	(6,513	)	$	(52,141	)	$	(24,542	)	$	112	$	(83,084	)

Baytex Energy Corp. 2011 Annual Report 59

20. REVENUES

		Years Ended December 31

		2011			2010

Petroleum and natural gas revenues	$	1,305,814		$	1,003,295
Royalty charges		(212,172	)		(170,844	)
Royalty income		3,000			1,841

Revenues, net of royalties	$	1,096,642		$	834,292

21. FINANCING COSTS

Baytex incurred financing costs on its outstanding liabilities as follows:

		Years Ended December 31

		2011		2010

Bank loan and other	$	12,489	$	12,547
Long-term debt		22,935		14,198
Accretion on asset retirement obligations		6,185		5,862
Convertible debentures		–		320
Debt financing costs		3,002		1,643

Financing costs	$	44,611	$	34,570

22. SUPPLEMENTAL INFORMATION

Change in Non-Cash Working Capital Items

			Years Ended December 31

			2011			2010

Trade and other receivables		$	(55,159	)	$	(14,638	)
Crude oil inventory			905			(418	)
Trade and other payables			40,992			(2,678	)
Foreign exchange			(180	)		74

		$	(13,442	)	$	(17,660	)

Changes in non-cash working capital related to:
	Operating activities	$	(10,889	)	$	(11,704	)
	Investing activities		(2,553	)		(5,956	)

		$	(13,442	)	$	(17,660	)

Foreign Exchange

		Years Ended December 31

		2011			2010

Unrealized foreign exchange loss (gain)	$	8,490		$	(8,999	)
Realized foreign exchange gain		(656	)		(149	)

Foreign exchange loss (gain)	$	7,834		$	(9,148	)

60 Baytex Energy Corp. 2011 Annual Report

Income Statement Presentation

The following table details the amount of total employee compensation costs included in the production and operating expense and general and administrative expense.

		Years Ended December 31

		2011		2010

Production and operating	$	6,457	$	5,675
General and administrative		25,529		24,400

Total employee compensation costs	$	31,986	$	30,075

23. 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 trading value of 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.

Baytex Energy Corp. 2011 Annual Report 61

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

			December 31, 2011						December 31, 2010						January 1, 2010

As at			Carrying Value			Fair Value			Carrying Value			Fair Value			Carrying Value			Fair Value		Fair Value Measurement Hierarchy

Financial Assets
FVTPL
	Cash	$	7,847		$	7,847		$	–		$	–		$	10,177		$	10,177		Level 1
	Derivatives		11,059			11,059			16,543			16,543			31,994			31,994		Level 2

Total FVTPL		$	18,906		$	18,906		$	16,543		$	16,543		$	42,171		$	42,171

Loans and receivables
	Trade and other receivables	$	206,951		$	206,951		$	151,792		$	151,792		$	137,154		$	137,154		–

Total loans and receivables		$	206,951		$	206,951		$	151,792		$	151,792		$	137,154		$	137,154

Financial Liabilities
FVTPL
	Derivatives	$	(39,990	)	$	(39,990	)	$	(29,171	)	$	(29,171	)	$	(13,422	)	$	(13,422	)	Level 2

Total FVTPL		$	(39,990	)	$	(39,990	)	$	(29,171	)	$	(29,171	)	$	(13,422	)	$	(13,422	)

Other financial liabilities
	Trade and other payables	$	(225,831	)	$	(225,831	)	$	(183,314	)	$	(183,314	)	$	(186,516	)	$	(186,516	)	–
	Dividends or distributions payable to shareholders / unitholders		(25,936	)		(25,936	)		(22,742	)		(22,742	)		(19,674	)		(19,674	)	–
	Bank loan		(311,960	)		(311,960	)		(303,773	)		(303,773	)		(265,088	)		(265,088	)	–
	Convertible debentures		–			–			–			–			(7,736	)		(7,736	)	–
	Long-term debt		(297,731	)		(314,201	)		(146,893	)		(163,875	)		(146,498	)		(162,750	)	–

Total other financial liabilities		$	(861,458	)	$	(877,928	)	$	(656,722	)	$	(673,704	)	$	(625,512	)	$	(641,764	)

There were no transfers between Level 1 and 2 in the period.

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.

62 Baytex Energy Corp. 2011 Annual Report

At December 31, 2011, the Company had in place the following currency derivative contracts:

Type	Period	Amount per month	Sales Price	Reference

Monthly forward spot sale	June 2010 to June 2012	US$1.00 million	1.0250	(1	)
Monthly forward spot sale	January 2011 to June 2012	US$3.00 million	1.0622	(1	)
Monthly forward spot sale	January 2011 to August 2012	US$1.00 million	1.0565	(1	)
Monthly forward spot sale	January 2011 to September 2012	US$1.50 million	1.0553	(1	)
Monthly forward spot sale	November 2011 to October 2013	US$1.00 million	1.0433	(1	)
Monthly forward spot sale	Calendar 2012	US$6.25 million	1.0084	(2	)
Monthly average rate forward	Calendar 2012	US$1.25 million	1.0209	(2	)
Monthly spot collar	Calendar 2012	US$0.75 million	0.9524 - 1.0503	(1	)
Monthly spot collar	Calendar 2012	US$0.25 million	1.0200 - 1.0700	(1	)
Monthly average collar	Calendar 2012	US$0.25 million	0.9700 - 1.0310	(1	)
Monthly average collar	Calendar 2012	US$0.50 million	0.9750 - 1.0305	(1	)
Monthly average collar	Calendar 2012	US$0.75 million	1.0225 - 1.0425	(1	)
Monthly average collar	Calendar 2012	US$0.25 million	1.0295 - 1.0545	(1	)
Monthly forward spot sale	Calendar 2013	US$4.50 million	1.0007	(2	)
Monthly average rate forward	Calendar 2013	US$0.25 million	1.0023	(1	)
Monthly average collar	Calendar 2013	US$0.25 million	0.9700 - 1.0310	(1	)

(1): Actual contract rate (CAD/USD).
(2): Based on the weighted average contract rates (CAD/USD).

The following table demonstrates the effect of movements in the Canadian – 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 December 31, 2011.

$0.01 Increase (Decrease) in CAD/USD
		Exchange Rate

Loss (gain) on currency derivative contracts	$	1,648
Loss (gain) on other monetary assets/liabilities		2,954

Impact on net income before income taxes and comprehensive income	$	4,602

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

Assets

Liabilities

December 31,
2011

December 31,
2010

January 1,
2010

December 31,
2011

December 31,
2010

January 1,
2010

U.S. dollar denominated

US$107,138

US$72,663

US$67,389

US$402,979

US$230,878

US$198,690

Subsequent to December 31, 2011, Baytex added the following currency contracts:

Type	Period	Amount per month	Sales Price	Reference

Monthly spot collar	Calendar 2012	US$1.00 million	0.9800 - 1.0722	(1)
Monthly spot collar	Calendar 2012	US$1.00 million	0.9900 - 1.0720	(1)
Monthly spot collar	Calendar 2012	US$0.50 million	0.9900 - 1.0785	(1)
Monthly spot collar	June 2012 to December 2012	US$1.00 million	0.9800 - 1.0720	(1)
Monthly average rate forward	January 2012 to June 2012	US$1.00 million	1.0500	(1)(2)

(1): Actual contract rate (CAD/USD).
(2): Counterparty has the option to extend the term of the contract for an additional six months.

Interest rate risk

The Company's interest rate risk arises from its floating rate bank credit facilities. As at December 31, 2011, $312.0 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 year ended December 31, 2011 by

Baytex Energy Corp. 2011 Annual Report 63

approximately $3.4 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 December 31, 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 December 31, 2011, an increase of 100 basis points would decrease the unrealized loss at December 31, 2011 by $4.2 million, while a decrease of 100 basis points would increase the unrealized loss at December 31, 2011 by $3.3 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 December 31, 2011, a 10% increase would increase the unrealized loss at December 31, 2011 by $43.2 million, while a 10% decrease would decrease the unrealized loss at December 31, 2011 by $43.2 million.

When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at December 31, 2011, a 10% increase would increase the unrealized loss at December 31, 2011 by $1.1 million, while a 10% decrease would decrease the unrealized loss at December 31, 2011 by $1.0 million.

Financial Derivative Contracts

At December 31, 2011, Baytex had the following financial derivative contracts:

Oil	Period	Volume	Price/Unit⁽¹⁾	Index

Fixed – Sell	January to March 2012	1,750 bbl/d	US$93.83	WTI
Fixed – Sell	January to June 2012	3,600 bbl/d	US$100.59	WTI
Time Spread	January to December 2012	500 bbl/d	Dec 2014 plus US$3.25	WTI
Time Spread	January to December 2012	500 bbl/d	Dec 2014 plus US$0.65	WTI
Fixed – Sell	Calendar 2012	7,450 bbl/d	US$93.44	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.

64 Baytex Energy Corp. 2011 Annual Report

Natural Gas	Period	Volume	Price/Unit⁽¹⁾	Index

Basis swap	January to June 2012	1,000 mmBtu/d	NYMEX less US$0.328	AECO
Basis swap	Calendar 2012	1,000 mmBtu/d	NYMEX less US$0.390	AECO
Basis swap	Calendar 2012	1,000 mmBtu/d	NYMEX less US$0.370	AECO
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
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 consolidated statements of income and comprehensive income:

		Years Ended December 31

		2011		2010

Realized loss (gain) on financial derivatives	$	1,864	$	(48,129	)
Unrealized loss on financial derivatives		16,166		43,312

Loss (gain) on financial derivatives	$	18,030	$	(4,817	)

Included in unrealized gain on financial derivatives is a loss of $5.1 million for the year ended December 31, 2010, respectively ($nil for year ended December 31, 2011) relating to the conversion feature of the convertible debentures.

Subsequent to December 31, 2011, Baytex added the following financial derivative contracts:

Oil	Period	Volume	Price/Unit⁽¹⁾	Index

Fixed – Sell	January to June 2012⁽²⁾	500 bbl/d	US$108.00	WTI
Fixed – Sell	January to June 2012⁽²⁾	500 bbl/d	US$108.45	WTI
Fixed – Sell	January to December 2012	500 bbl/d	US$101.70	WTI
Fixed – Sell	March 2012	2,500 bbl/d	US$108.30	WTI
Fixed – Sell	March to December 2012	200 bbl/d	US$97.00-US$117.60	WTI
Fixed – Sell	March to December 2012	300 bbl/d	US$97.00-US$116.60	WTI
Fixed – Sell	April to June 2012	1,200 bbl/d	US$105.23	WTI
Fixed – Sell	April to June 2012⁽³⁾	500 bbl/d	US$107.70	WTI
Fixed – Sell	July to September 2012	300 bbl/d	US$107.38	WTI
Fixed – Sell	July to December 2012⁽²⁾	500 bbl/d	US$107.30	WTI
Fixed – Sell	July to December 2012⁽⁴⁾	500 bbl/d	US$108.80	WTI
Fixed – Sell	July to December 2012⁽⁴⁾	500 bbl/d	US$108.65	WTI
Fixed – Sell	July to December 2012⁽⁴⁾	500 bbl/d	US$107.80	WTI
Fixed – Sell	July to December 2012⁽⁴⁾	500 bbl/d	US$109.25	WTI

(1): Based on the weighted average price/unit for the remainder of the contract.
(2): Counterparty has the option to extend the term of the contract for an additional six months.
(3): Counterparty has the option to extend the term of the contract for an additional six months on 250 bbl/d.
(4): Counterparty has the option to increase the volume on the contract to 1,000 bbl/d.

Baytex Energy Corp. 2011 Annual Report 65

Physical Delivery Contracts

At December 31, 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 2011 to December 2014	2,000 bbl/d	WTI × 81.00%
WCS Blend	January to March 2012	4,000 bbl/d	WTI less US$11.78
WCS Blend	April to June 2012	1,500 bbl/d	WTI less US$13.42
WCS Blend	July to September 2012	500 bbl/d	WTI less US$15.00
WCS Blend	October to December 2012	500 bbl/d	WTI less US$18.00
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.

Subsequent to December 31, 2011, Baytex added the following physical purchase 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 December 31, 2011, Baytex had available unused bank credit facilities in the amount of $388.0 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	$	225,831	$	225,831	$	–	$	–	$	–
Dividends payable to shareholders		25,936		25,936		–		–		–
Bank loan⁽¹⁾		311,960		–		311,960		–		–
Long-term debt⁽²⁾		302,550		–		–		150,000		152,550

	$	866,277	$	251,767	$	311,960	$	150,000	$	152,550

(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

66 Baytex Energy Corp. 2011 Annual Report

obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. Due to the short term nature of accounts receivable, 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.

Baytex considers all amounts greater than 90 days as past due. The average collection on petroleum and natural gas sales is 30 to 60 days from the date of the invoice. 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. For the year ended December 31, 2011, $0.9 million was written-off in relation to balances already previously provided for (year ended December 31, 2010 – $0.5 million write-off).

Movements in allowance for doubtful accounts were as follows:


At January 1, 2010	$	(2,336	)
Foreign currency translation		4
Charge for the period		–
Amounts written off		479
Unused amounts reversed		–

At December 31, 2010	$	(1,853	)
Foreign currency translation		(2	)
Charge for the period		–
Amounts written off		896
Unused amounts reversed		–

At December 31, 2011	$	(959	)

Included in the allowance for doubtful accounts are individually impaired trade receivables of $0.3 million (December 31, 2010 – $0.2 million). As at December 31, 2011, accounts receivable that Baytex has deemed past due but not impaired is $4.5 million (December 31, 2010 – $4.6 million).

24. OPERATING LEASES

At December 31, 2011, the future minimum lease payments under non-cancellable operating lease rentals are payable as follows:

		Total			Less than 1 year			1-5 years			Beyond 5 years

Gross operating leases	$	50,984		$	6,286		$	24,446		$	20,252
Operating subleases		(867	)		(533	)		(334	)		–

Net operating leases	$	50,117		$	5,753		$	24,112		$	20,252

Operating lease and sublease payments recognized as an expense during the year ended December 31, 2011 was $5.5 million (December 31, 2010 – $4.8 million).

Baytex has entered into operating leases on office buildings in the ordinary course of business. The Company's operating lease agreements do not contain any contingent rent clauses. The Company has renewal options to extend its lease at the option of the lessee at lease payments based on market prices on one of its leased office buildings. None of the operating lease agreements contain purchase options or escalation clauses or any restrictions regarding dividends, further leases or additional debt.

Baytex Energy Corp. 2011 Annual Report 67

25. RELATED PARTIES

Balances and transactions between the Company and its subsidiaries, which are related parties of the Company, have been eliminated on consolidation and are not disclosed separately in this note.

Transaction with key management personnel (including directors):

		December 31, 2011		December 31, 2010

Short-term employee benefits	$	8,585	$	7,550
Share-based compensation		14,271		47,876

Total compensation for key management personnel	$	22,856	$	55,426

26. COMMITMENTS AND CONTINGENCIES

At December 31, 2011 Baytex had processing and transportation obligations as summarized below:

		Total		Less than 1 year		1-2 years		2-3 years		3-4 years		4-5 years		Beyond 5 years

Processing and transportation agreements	$	5,198	$	3,238	$	1,881	$	79	$	–	$	–	$	–

At December 31, 2011 Baytex has $0.4 million of outstanding letters of credit ($nil – December 31, 2010 and January 1, 2010).

Baytex is engaged in litigation and claims arising in the normal course of operations, none of which could reasonably be expected to materially affect the Company's financial position or reported results of operations.

27. GEOGRAPHIC INFORMATION

Baytex has operations principally in Canada and the United States. Baytex's entire operating activities are related to the acquisition, development and production of oil and natural gas. The following geographic information has been prepared by segregating the results into the geographic areas in which Baytex operates.

		Canada						United States						Total

		2011			2010			2011			2010			2011			2010

Years ended December 31
Gross revenues to external customers	$	1,267,589		$	986,041		$	41,225		$	19,095		$	1,308,814		$	1,005,136
Royalties		(200,786	)		(165,631	)		(11,386	)		(5,213	)		(212,172	)		(170,844	)

Revenue, net of royalties to external customers	$	1,066,803		$	820,410		$	29,839		$	13,882		$	1,096,642		$	834,292

As at December 31
Exploration and evaluation assets	$	76,592		$	58,233		$	53,182		$	54,849		$	129,774		$	113,082
Oil and gas properties		1,812,206			1,484,463			219,954			140,166			2,032,160			1,624,629
Other plant and equipment		24,965			27,270			268			280			25,233			27,550
Goodwill		37,755			37,755			–			–			37,755			37,755
Total non current assets	$	1,963,727		$	1,621,554		$	271,508		$	191,954		$	2,235,235		$	1,813,508

28. 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.

68 Baytex Energy Corp. 2011 Annual Report

Baytex considers its capital structure to include total monetary debt and shareholders'/unitholders' equity. Total monetary debt 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 December 31, 2011, total monetary debt was $650.6 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. Baytex is in compliance with all financial covenants relating to its senior unsecured debentures and the credit facilities of Baytex Energy. 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 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.

29. FIRST-TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

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") 4, "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.

Baytex Energy Corp. 2011 Annual Report 69

Baytex Energy Corp.
Consolidated Statements of Income and Comprehensive Income – IFRS
(thousands of Canadian dollars)

			Year Ended December 31, 2010

	Note		Previous GAAP			Effect of transition to IFRS			IFRS

Revenues
Petroleum and natural gas	F, N	$	1,005,136		$	(170,844	)	$	834,292
Royalties	N		(162,332	)		162,332			–
Gain on financial derivatives			9,935			(9,935	)		–

			852,739			(18,447	)		834,292

Expenses
Exploration and evaluation	B		–			24,502			24,502
Production and operating			171,740			(36	)		171,704
Transportation and blending			188,591			–			188,591
General and administrative			39,774			973			40,747
Unit-based compensation	J		8,344			85,855			94,199
Financing costs	H, I		32,828			1,742			34,570
Gain on divestitures of oil and gas properties	C		–			(16,227	)		(16,227	)
Gain on financial derivatives	G		–			(4,817	)		(4,817	)
Foreign exchange gain			(9,148	)		–			(9,148	)
Depletion and depreciation	D		266,527			(63,731	)		202,796

			698,656			28,261			726,917

Net income before income taxes			154,083			(46,708	)		107,375

Income tax expense (recovery)
Current	F		8,512			(8,512	)		–
Deferred	L, M		(32,060	)		(92,180	)		(124,240	)

			(23,548	)		(100,692	)		(124,240	)

Net income attributable to unitholders		$	177,631		$	53,984		$	231,615

Other comprehensive income (loss)
Foreign currency translation adjustment			(10,708	)		385			(10,323	)

Comprehensive income		$	166,923		$	54,369		$	221,292

70 Baytex Energy Corp. 2011 Annual Report

Baytex Energy Corp.
Consolidated Statements of Financial Position – IFRS
(thousands of Canadian dollars) (unaudited)

As at				December 31, 2010									January 1, 2010

		Note		Previous GAAP			Effect of transition to IFRS			IFRS			Previous GAAP			Effect of transition to IFRS			IFRS

Assets
Current assets
	Cash	O	$	–		$	–		$	–		$	10,177		$	–		$	10,177
	Trade and other receivables	A		151,792			–			151,792			137,154			–			137,154
	Crude oil inventory			1,802			–			1,802			1,384			–			1,384
	Future income tax asset	A,M		5,480			(5,480	)		–			1,371			(1,371	)		–
	Financial derivatives			13,921			–			13,921			29,453			–			29,453

				172,995			(5,480	)		167,515			179,539			(1,371	)		178,168
Non-current assets
	Deferred income tax asset	A,M		150,190			(142,320	)		7,870			418			1,371			1,789
	Financial derivatives			2,622			–			2,622			2,541			–			2,541
	Exploration and evaluation assets	B		–			113,082			113,082			–			124,621			124,621
	Oil and gas properties	A,C,D,I		1,683,650			(59,021	)		1,624,629			1,663,752			(151,717	)		1,512,035
	Other plant and equipment	E		–			27,550			27,550			–			27,096			27,096
	Goodwill			37,755			–			37,755			37,755			–			37,755

			$	2,047,212		$	(66,189	)	$	1,981,023		$	1,884,005		$	–		$	1,884,005

Liabilities
Current liabilities
	Trade and other payables	A	$	179,269		$	4,045		$	183,314		$	180,493		$	6,023		$	186,516
	Distributions payable to unitholders			22,742			–			22,742			19,674			–			19,674
	Bank loan			–			–			–			265,088			–			265,088
	Convertible debentures			–			–			–			7,736			–			7,736
	Future income tax liability	A,M		3,756			(3,756	)		–			8,683			(8,683	)		–
	Financial derivatives	G		20,312			–			20,312			4,650			7,354			12,004

				226,079			289			226,368			486,324			4,694			491,018
Non-current liabilities
	Bank loan			303,773			–			303,773			–			–			–
	Long-term debt	H		150,000			(3,107	)		146,893			150,000			(3,502	)		146,498
	Deferred credit	L		109,800			(109,800	)		–			–			–			–
	Asset retirement obligations	I		52,373			117,238			169,611			54,593			87,276			141,869
	Unit-based payment liability	J		–			–			–			–			91,559			91,559
	Deferred income tax liability	A,M		167,302			(152,919	)		14,383			179,673			(18,954	)		160,719
	Financial derivatives			8,859			–			8,859			1,418			–			1,418

				1,018,186			(148,299	)		869,887			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		–			–			–			1,295,931			35,230			1,331,161
Conversion feature of convertible debentures		G		–			–			–			374			(374	)		–
Contributed surplus		J		20,131			108,998			129,129			20,371			(20,371	)		–
Accumulated other comprehensive (loss) income		K		(14,607	)		4,284			(10,323	)		(3,899	)		3,899			–
Deficit				(366,532	)		(125,473	)		(492,005	)		(300,780	)		(179,457	)		(480,237	)

				1,029,026			82,110			1,111,136			1,011,997			(161,073	)		850,924

			$	2,047,212		$	(66,189	)	$	1,981,023		$	1,884,005		$	–		$	1,884,005

Baytex Energy Corp. 2011 Annual Report 71

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

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 quarterly 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 year ended December 31, 2010, Baytex expensed $18.9 million of exploration and evaluation assets related to lease expiries and $5.6 million in direct exploration costs. For the year ended December 31, 2010, Baytex had exploration and evaluation capital expenditures of $37.4 million, corporate acquisitions of $2.5 million, divestitures of $0.1 million, transfers to oil and gas properties of $29.1 million, transfers to expense related to lease expiries of $18.9 million 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 year ended December 31, 2010, a gain of $16.2 million was recognized relating to a divestiture of oil and gas assets.

D) 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 year ended December 31, 2010, this change resulted in a decrease in depletion expense of $67.4 million with a corresponding increase in oil and gas properties.

72 Baytex Energy Corp. 2011 Annual Report

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 year ended December 31, 2010 netted in revenues is $8.5 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 year ended December 31, 2010 is $0.4 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 December 31, 2010). Under IFRS, an additional liability

Baytex Energy Corp. 2011 Annual Report 73

of $87.3 million was charged to deficit at January 1, 2010. At December 31, 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.

For the year ended December 31, 2010, the $4.5 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 $1.4 million has been recognized in net income under IFRS.

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.

Under IFRS, in addition to the January 1, 2010 adjustments discussed above, at December 31, 2010 immediately prior to the conversion to a corporation, the remeasurement of the liability at reporting date and at settlement date resulted in the recognition of an additional unit-based compensation expense of $85.9 million, with a corresponding decrease of $0.3 million in contributed surplus, an increase of $48.0 million in shareholders'/unitholders' equity and an increase of $37.6 million in unit-based payment liability.

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 year ended December 31, 2010, a deferred income tax recovery of $109.8 million was recorded in net income for amounts previously recognized as a deferred credit.

M) Deferred Income Taxes

74 Baytex Energy Corp. 2011 Annual Report

For the year ended December 31, 2010, the application of the IFRS adjustments resulted in a $92.2 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.

N) 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

With the exception of a $28.5 million interest paid reclass from operating activities to financing activities for the year ended December 31, 2010, the transition from previous GAAP to IFRS had no material effect on the reported cash flows generated by the Company.

30. 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 consolidating financial information as at December 31, 2011, December 31, 2010 and January 1, 2010 and for the years ended December 31, 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.

Baytex Energy Corp. 2011 Annual Report 75

(thousands of Canadian dollars)		Baytex		Guarantor Subsidiaries			Non-guarantor Subsidiaries		Consolidation Adjustments			Total Consolidated

As at December 31, 2011
Current assets	$	351	$	225,850		$	374	$	–		$	226,575
Intercompany advances and investments		1,753,047		(515,492	)		72,787		(1,310,342	)		–
Non-current assets		2,435		2,232,800			–		–			2,235,235
Current liabilities		34,502		242,303			167		–			276,972
Bank loan and long-term debt		297,731		311,960			–		–			609,691
Asset retirement obligation and other non-current liabilities	$	–	$	368,413		$	–	$	–		$	368,413

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

As at January 1, 2010
Current assets	$	412	$	177,608		$	148	$	–		$	178,168
Intercompany advances and investments		1,522,661		(1,522,596	)		63,892		(63,957	)		–
Non-current assets		42,515		1,663,322			–		–			1,705,837
Current liabilities		39,577		451,357			84		–			491,018
Bank loan and long-term debt		146,498		–			–		–			146,498
Asset retirement obligation and other non-current liabilities	$	–	$	395,565		$	–	$	–		$	395,565

76 Baytex Energy Corp. 2011 Annual Report

(thousands of Canadian dollars)		Baytex			Guarantor Subsidiaries		Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated

Year ended December 31, 2011
Revenues, net of royalties	$	22,012		$	1,098,415	$	9,649		$	(33,434	)	$	1,096,642
Production, operation and exploration		–			223,042		–			–			223,042
Transportation and blending		–			249,850		–			–			249,850
General, administrative and share-based compensation		1,596			72,842		257			(1,515	)		73,180
Financing, derivatives, foreign exchange and other gains/losses		27,497			36,999		(48	)		(31,919	)		32,529
Depletion and depreciation		–			248,468		–			–			248,468
Deferred income tax (recovery) expense		(1,298	)		53,439		–			–			52,141

Net (loss) income	$	(5,783	)	$	213,775	$	9,440		$	–		$	217,432

(thousands of Canadian dollars)		Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries		Consolidation Adjustments			Total Consolidated

Year ended December 31, 2010
Revenues, net of royalties	$	262,138		$	800,887		$	10,537	$	(239,270	)	$	834,292
Production, operation and exploration		–			196,206			–		–			196,206
Transportation and blending		–			188,591			–		–			188,591
General, administrative and unit-based compensation		1,500			134,598			348		(1,500	)		134,946
Financing, derivatives, foreign exchange and other gains/losses		(15,270	)		257,405			13		(237,770	)		4,378
Depletion and depreciation		4,811			197,985			–		–			202,796
Deferred income tax expense (recovery)		13,495			(137,739	)		4		–			(124,240	)

Net income (loss)	$	257,602		$	(36,159	)	$	10,172	$	–		$	231,615

Baytex Energy Corp. 2011 Annual Report 77

(thousands of Canadian dollars)		Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated

Year ended December 31, 2011
Cash provided by (used in):
Operating activities	$	56,926		$	514,581		$	353		$	–		$	571,860
Payment of dividends		(204,308	)		9,004			(9,004	)		–			(204,308	)
Increase in bank loan		–			4,290			–			–			4,290
Increase (decrease) in intercompany loans		(18,008	)		110,041			(92,033	)		–			–
Proceeds from issuance of long-term debt		145,810			–			–			–			145,810
Increase in investments					(90,649	)					90,649			–
Increase in equity		45,048			–			90,649			(90,649	)		45,048
Interest paid		(25,468	)		(19,297	)		10,035			–			(34,730	)

Financing activities		(56,926	)		13,389			(353	)		–			(43,890	)
Additions to exploration and evaluation assets		–			(9,104	)		–			–			(9,104	)
Additions to oil and gas properties		–			(358,744	)		–			–			(358,744	)
Property acquisitions		–			(76,164	)		–			–			(76,164	)
Corporate acquisitions		–			(120,006	)		–			–			(120,006	)
Proceeds from divestitures		–			47,396			–			–			47,396
Additions to other plant and equipment, net of disposals		–			(1,252	)		–			–			(1,252	)
Acquisitions of financing entities		–			–			–			–			–
Change in non-cash working capital		–			(2,553	)		–			–			(2,553	)

Investing activities		–			(520,427	)		–			–			(520,427	)
Impact of foreign currency translation on cash balances	$	–		$	304		$	–		$	–		$	304

78 Baytex Energy Corp. 2011 Annual Report

(thousands of Canadian dollars)		Baytex			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidation Adjustments			Total Consolidated

Year ended December 31, 2010
Cash provided by (used in):
Operating activities	$	227,665		$	224,483		$	9,258		$	–		$	461,406
Payment of distributions		(188,615	)		10,455			(10,455	)		–			(188,615	)
Increase in bank loan		–			48,045			–			–			48,045
Increase (decrease) in intercompany loans		(50,915	)		55,324			(4,409	)		–			–
Increase in investments		–			(2,653	)		–			2,653			–
Repayment of convertible debentures		(341	)		–			–			–			(341	)
Increase in equity		26,021			–			2,653			(2,653	)		26,021
Interest paid		(14,180	)		(17,124	)		2,805			–			(28,499	)

Financing activities		(228,030	)		94,047			(9,406	)		–			(143,389	)
Additions to exploration and evaluation assets		–			(37,411	)		–			–			(37,411	)
Additions to oil and gas properties		–			(194,208	)		–			–			(194,208	)
Property acquisitions		–			(22,412	)		–			–			(22,412	)
Corporate acquisitions		–			(40,314	)		–			–			(40,314	)
Proceeds from divestitures		–			19,033									19,033
Additions to other plant and equipment, net of disposals		–			(8,237	)		–			–			(8,237	)
Acquisitions of financing entities		–			(38,000	)		–			–			(38,000	)
Change in non-cash working capital		–			(5,956	)		–			–			(5,956	)

Investing activities		–			(327,505	)		–			–			(327,505	)
Impact of foreign currency translation on cash balances	$	–		$	(689	)	$	–		$	–		$	(689	)

Baytex Energy Corp. 2011 Annual Report 79

Petroleum and Natural Gas Reserves as at December 31, 2011⁽¹⁾

		Forecast Prices and Costs

		Light and Medium Crude Oil		Heavy Oil		Natural Gas Liquids
Reserve Category		Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾

		(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mbbl)
PROVED
	Developed Producing	8,419	6,955	41,740	34,949	1,845	1,322
	Developed Non-Producing	806	664	12,356	10,329	110	77
	Undeveloped	18,999	16,092	53,998	46,471	3,811	3,132

TOTAL PROVED		28,224	23,711	108,094	91,749	5,766	4,531
PROBABLE		15,010	12,656	71,150	59,169	2,857	2,226

TOTAL PROVED PLUS PROBABLE		43,234	36,367	179,244	150,918	8,623	6,757

		Forecast Prices and Costs

		Natural Gas		Oil Equivalent⁽³⁾
Reserve Category		Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾

		(bcf)	(bcf)	(mboe)	(mboe)
PROVED
	Developed Producing	55.3	47.8	61,224	51,194
	Developed Non-Producing	3.4	2.9	13,844	11,552
	Undeveloped	28.2	22.8	81,494	69,500

TOTAL PROVED		86.9	73.5	156,562	132,246
PROBABLE		39.5	32.8	95,613	79,508

TOTAL PROVED PLUS PROBABLE		126.4	106.3	252,175	211,754

(1): Reserves are evaluated by Sproule Associates Limited ("Sproule"), the independent reserves evaluator for all of our oil and gas properties, in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101").
(2): "Gross" reserves means the total working and royalty interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(3): "Net" reserves means Baytex's gross reserves less all royalties payable to others.
(4): Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 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.

80 Baytex Energy Corp. 2011 Annual Report

Reserve Reconciliation
Reconciliation of Gross Company Interest Reserves⁽¹⁾⁽²⁾
By Principal Product Type (Forecast Prices and Costs)

	Light and Medium Crude Oil						Heavy Oil
	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable

	(mbbl)		(mbbl)		(mbbl)		(mbbl)		(mbbl)		(mbbl)
December 31, 2010	18,416		17,943		36,359		104,978		62,435		167,413
Extensions	8,762		5,299		14,061		9,477		7,929		17,406
Discoveries	–		–		–		51		17		68
Improved Recoveries	–		–		–		3,191		3,409		6,600
Technical Revisions	3,498		(7,348	)	(3,850	)	(2,873	)	(6,701	)	(9,574	)
Acquisitions	–		–		–		6,222		4,031		10,252
Dispositions	(548	)	(864	)	(1,412	)	–		–		–
Economic Factors	(38	)	(20	)	(58	)	(86	)	30		(56	)
Production	(1,866	)	–		(1,866	)	(12,867	)	–		(12,867	)

December 31, 2011	28,224		15,010		43,234		108,094		71,151		179,244

	Natural Gas Liquids						Natural Gas including solution gas
	Proved		Probable		Proved + Probable		Proved		Probable		Proved + Probable

	(mbbl)		(mbbl)		(mbbl)		(mmcf)		(mmcf)		(mmcf)
December 31, 2010	2,825		1,215		4,040		83,825		43,453		127,278
Extensions	797		585		1,382		12,522		6,580		19,102
Discoveries	–		–		–		–		–		–
Improved Recoveries	–		–		–		21		5		26
Technical Revisions	2,367		902		3,269		4,461		(12,871	)	(8,410	)
Acquisitions	458		173		631		8,565		3,348		11,913
Dispositions	–		–		–		(240	)	(13	)	(253	)
Economic Factors	(77	)	(18	)	(95	)	(4,520	)	(930	)	(5,450	)
Production	(604	)	–		(604	)	(17,764	)	–		(17,764	)

December 31, 2011	5,766		2,857		8,623		86,870		39,572		126,442

	Oil Equivalent⁽³⁾

	Proved		Probable		Proved + Probable

	(mboe)		(mboe)		(mboe)
December 31, 2010	140,190		88,835		229,025
Extensions	21,123		14,910		36,033
Discoveries	51		17		68
Improved Recoveries	3,194		3,410		6,604
Technical Revisions	3,736		(15,291	)	(11,555	)
Acquisitions	8,107		4,762		12,869
Dispositions	(588	)	(866	)	(1,454	)
Economic Factors	(953	)	(164	)	(1,117	)
Production	(18,298	)	–		(18,298	)

December 31, 2011	156,562		95,613		252,174

(1): Gross Company interest reserves include solution gas but do not include royalty interests.
(2): Reserve information as at December 31, 2011 and 2010 is prepared in accordance with NI 51-101.
(3): Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Baytex Energy Corp. 2011 Annual Report 81

Reserve Life Index

The following table sets forth our reserve life index based on total proved and proved plus probable reserves and the actual Q4/2011 production level of 53,054 boe/d.

		Reserve Life Index (years)

	Q4/2011 Production	Total Proved	Proved Plus Probable

Oil and NGL (bbl/d)	45,238	8.6	14.0
Natural Gas (mmcf/d)	46.8	5.1	7.4

Oil Equivalent (boe/d)	53,054	8.1	13.0

Net Present Value of Reserves (Using Forecast Prices and Costs and Before Income Taxes)

		Summary of Net Present Value of Future Net Revenue As at December 31, 2011 Before Income Taxes and Discounted at (%/year)

Reserve Category		0%	5%	10%	15%	20%

		($000s)	($000s)	($000s)	($000s)	($000s)
Proved
	Developed Producing	2,245,149	1,886,065	1,646,807	1,474,966	1,344,829
	Developed Non-Producing	511,190	388,377	304,848	245,749	202,561
	Undeveloped	2,706,576	1,804,291	1,274,225	939,406	714,592

Total Proved		5,462,915	4,078,732	3,225,881	2,660,121	2,261,982
Probable		3,884,906	2,343,263	1,590,382	1,158,294	885,369

Total Proved Plus Probable		9,347,822	6,421,995	4,816,263	3,818,415	3,147,351

The net present values noted in the table above do not include any value for future net revenue which may ultimately be generated from the contingent resources discussed below.

Sproule December 31, 2011 Forecast Prices

Year	WTI Cushing US$/bbl	Edmonton Par Price C$/bbl	Hardisty Lloydblend 20.5° API C$/bbl	AECO C-Spot C$/mmBtu	Inflation Rate %/Yr	Exchange Rate $US/$Cdn

2011 act.	95.00	95.16	77.09	3.72	1.5	1.01

2012	98.07	96.87	82.34	3.16	2.0	1.01

2013	94.90	93.75	79.69	3.78	2.0	1.01

2014	92.00	90.89	77.25	4.13	2.0	1.01

2015	97.42	96.23	81.80	5.53	2.0	1.01

2016	99.37	98.16	83.44	5.65	2.0	1.01

2017	101.35	100.12	85.10	5.77	2.0	1.01

2018	103.38	102.12	86.81	5.89	2.0	1.01

2019	105.45	104.17	88.54	6.01	2.0	1.01

2020	107.56	106.25	90.31	6.14	2.0	1.01

2021	109.71	108.38	92.12	6.27	2.0	1.01

Thereafter	Escalation Rate of 2%

82 Baytex Energy Corp. 2011 Annual Report

Capital Program Efficiency

Based on the evaluation of our petroleum and natural gas reserves prepared in accordance with NI 51-101 by our independent reserve evaluator, Sproule, the efficiency of our capital programs, as measured by finding, development and acquisition ("FD&A") costs, operating netback per boe and recycle ratio, are summarized as follows:

			2011		2010		2009		Three Year Average 2009 - 2011

Excluding Future Development Costs
FD&A costs – Proved ($/boe)
	Exploration and development⁽¹⁾	$	13.55	$	9.54	$	12.54	$	11.81
	Acquisitions (net of dispositions)		19.79		21.84		21.27		20.64

	Total	$	14.90	$	10.52	$	15.45	$	13.56

FD&A costs – Proved plus probable ($/boe)
	Exploration and development⁽¹⁾	$	12.25	$	5.41	$	9.25	$	8.39
	Acquisitions (net of dispositions)		13.03		10.96		16.70		13.90

	Total	$	12.46	$	5.90	$	11.63	$	9.52

Operating netback per boe⁽²⁾		$	34.68	$	32.27	$	27.64	$	31.95

Recycle ratio⁽²⁾
	Proved plus probable		2.8		5.5		2.4		3.4

Including Future Development Costs
FD&A costs – Proved ($/boe)
	Exploration and development⁽¹⁾	$	23.66	$	15.22	$	22.96	$	20.27
	Acquisitions (net of dispositions)		25.22		32.71		28.28		27.43

	Total	$	24.00	$	16.61	$	24.73	$	21.69

FD&A costs – Proved plus probable ($/boe)
	Exploration and development⁽¹⁾	$	19.02	$	12.44	$	20.01	$	16.03
	Acquisitions (net of dispositions)		17.39		20.68		23.12		19.91

	Total	$	18.57	$	13.17	$	21.00	$	16.83

Recycle ratio⁽²⁾
	Proved plus probable		1.9		2.5		1.3		1.9

(1): The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
(2): Recycle ratio is calculated as operating netback divided by FD&A costs (proved plus probable). Operating netback is calculated as revenue (including realized hedging gains and losses) less royalties, operating expenses and transportation expenses.

Baytex Energy Corp. 2011 Annual Report 83

Contingent Resource Assessment

	Summary of Contingent Resources⁽¹⁾ As of December 31, 2011

		Contingent Resources (gross)⁽⁵⁾ As at Dec. 31, 2011

(millions of barrels of oil equivalent and bitumen)⁽³⁾	Proved plus Probable Gross Reserves⁽⁴⁾ As at Dec. 31, 2011	Low⁽⁶⁾	Best⁽⁷⁾	High⁽⁸⁾

Bluesky – Seal, Alberta	92.9	438.8	531.0	776.9
Mannville Group – Northeast Alberta	4.0	69.6	130.1	201.8
Bakken/Three Forks – North Dakota, USA	32.4	47.3	110.5	204.9
Viking – Redwater, Alberta	3.6	4.2	9.3	18.0
Viking – Kerrobert/Whiteside, Saskatchewan	4.2	0.6	1.9	10.1

Total	137.1	560.4	782.9	1,211.7

Percent oil and bitumen		99%	99%	98%

		Summary of Net Present Values of Future Net Revenues from Contingent Resources As of December 31, 2011 Forecast Prices and Costs⁽²⁾ Before income taxes discounted at (%/year)⁽⁹⁾

		0%		5%		8%		10%

		($ millions)
Low estimate (C1)⁽⁶⁾
	Bluesky – Seal, Alberta	13,596.8		6,021.3		3,855.0		2,905.8
	Mannville Group – Northeast Alberta	1,365.9		640.3		430.0		333.6
	Bakken/Three Forks – North Dakota, USA	1,150.9		370.5		189.3		119.8
	Viking – Redwater, Alberta	26.6		(0.1	)	(9.1	)	(13.2	)
	Viking – Kerrobert/Whiteside, Saskatchewan	(26.2	)	(19.7	)	(16.7	)	(15.0	)

Total		16,113.9		7,012.2		4,448.5		3,331.0

Best estimate (C2)⁽⁷⁾
	Bluesky – Seal, Alberta	17,810.2		7,757.3		4,927.1		3,697.2
	Mannville Group – Northeast Alberta	3,365.4		1,348.7		856.8		648.8
	Bakken/Three Forks – North Dakota, USA	5,650.3		1,821.3		1,014.6		708.6
	Viking – Redwater, Alberta	421.5		260.5		200.0		169.1
	Viking – Kerrobert/Whiteside, Saskatchewan	31.3		16.3		10.7		7.9

Total		27,278.8		11,240.1		7,009.2		5,231.6

High estimate (C3)⁽⁸⁾
	Bluesky – Seal, Alberta	29,738.4		12,092.3		7,434.6		5,476.0
	Mannville Group – Northeast Alberta	6,088.5		2,265.1		1,404.7		1,053.9
	Bakken/Three Forks – North Dakota, USA	13,540.2		3,874.9		2,093.7		1,450.7
	Viking – Redwater, Alberta	1,083.3		666.5		518.4		444.2
	Viking – Kerrobert/Whiteside, Saskatchewan	464.9		264.4		191.4		155.4
Total		50,915.4		19,163.2		11,642.8		8,580.2

84 Baytex Energy Corp. 2011 Annual Report

(1): The contingent resource assessments were prepared by Sproule (in the case of all properties except Northeast Alberta) and McDaniel & Associates Consultants Ltd. ("McDaniel") (in the case of Northeast Alberta) in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101. Contingent resource is defined in the Canadian Oil and Gas Evaluation Handbook as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets.
(2): The forecast price and cost assumptions utilized in the year-end 2011 reserves report were also utilized by Sproule and McDaniel in preparing the contingent resource assessments. See "Sproule December 31, 2011 Forecast Prices" above.
(3): Under NI 51-101, naturally occurring hydrocarbons with a viscosity greater than 10,000 centipoise are classed as bitumen. The majority of the contingent resource at Seal that will be recovered by thermal processes has a viscosity greater than this value; therefore, this component of the contingent resource is classified as bitumen under NI 51-101.
(4): Proved plus probable gross reserve volumes are based on the year-end 2011 reserves report prepared by Sproule.
(5): Sproule and McDaniel prepared the estimates of contingent resource shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. Gross means the company's working interest share in the contingent resource before deducting royalties.
(6): Low estimate (C1) is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at the low end of the estimate range have the highest degree of certainty – a 90% confidence level – that the actual quantities recovered will be equal or exceed the estimate.
(7): Best estimate (C2) is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will be equal or exceed the estimate.
(8): High estimate (C3) is considered to be an optimistic estimate of the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the high end of the estimate range have a lower degree of certainty – a 10% confidence level – that the actual quantities recovered will equal or exceed the estimate.
(9): The net present value of future net revenue attributable to the contingent resource does not necessarily represent the fair market value of the contingent resource. Estimated abandonment and reclamation costs have been included in the evaluation.

Baytex Energy Corp. 2011 Annual Report 85

Advisory Regarding Oil and Gas Information

The reserves information contained in this report has been prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators. Complete NI 51-101 reserves disclosure is included in our Annual Information Form for the year ended December 31, 2011. Listed below are cautionary statements that are specifically required by NI 51-101:

•: Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of 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.
•: This report contains reserves estimates for our Seal (Bluesky), North Dakota (Bakken/Three Forks), Redwater (Viking), Kerrobert/Whiteside (Viking) and Northeast Alberta (Mannville) properties. Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.
•: With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
•: This report contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves.

This report contains estimates as of December 31, 2011 of the volumes of, and the net present value of the future net revenue from, the "contingent resource" for four of our oil resource plays: the Bluesky in the Seal area of Alberta; the Bakken/Three Forks in North Dakota; the Viking in southeast Alberta; and the Mannville in northeast Alberta. These estimates were prepared by independent qualified reserves evaluators.

"Contingent resource" is not, and should not be confused with, petroleum and natural gas reserves. "Contingent resource" is defined in the Canadian Oil and Gas Evaluation Handbook as: "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resource the estimated discovered recoverable quantities associated with a project in the early evaluation stage."

The primary contingencies which currently prevent the classification of the contingent resource as reserves consist of: preparation of firm development plans, including determination of the specific scope and timing of the project; project sanction; access to capital markets; stakeholder and regulatory approvals; access to required services and field development infrastructure; oil prices; demonstration of economic viability; future drilling program and testing results; further reservoir delineation and studies; facility design work; limitations to development based on adverse topography or other surface restrictions; and the uncertainty regarding marketing and transportation of petroleum from development areas.

There is no certainty that it will be commercially viable to produce any portion of the contingent resource or that we will produce any portion of the volumes currently classified as contingent resource. The estimates of contingent resource involve implied assessment, based on certain estimates and assumptions, that the resource described exists in the quantities predicted or estimated and that the resource can be profitably produced in the future. The net present value of the future net revenue from the contingent resource does not necessarily represent the fair market value of the contingent resource.

The recovery and resource estimates provided herein are estimates only. Actual contingent resource (and any volumes that may be reclassified as reserves) and future production from such contingent resource may be greater than or less than the estimates provided herein.

86 Baytex Energy Corp. 2011 Annual Report

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.

Baytex Energy Corp. 2011 Annual Report 87

CORPORATE INFORMATION DIRECTORS Raymond T. Chan Executive Chairman Baytex Energy Corp. John A. Brussa 2,3,4 Partner Burnet, Duckworth & Palmer LLP Edward Chwyl 2,3,4 Lead Independent Director Independent Businessman Naveen Dargan 1,2,4 Independent Businessman R.E.T (Rusty) Goepel 1 Senior Vice President Raymond James Ltd. Anthony W. Marino President & Chief Executive Officer Baytex Energy Corp. Gregory K. Melchin 1 Independent Businessman Dale O. Shwed 3 President & Chief Executive Officer Crew Energy Inc. 1 Member of the Audit Committee 2 Member of the Compensation Committee 3 Member of the Reserves Committee 4 Member of the Nominating and Governance Committee HEAD OFFICE Baytex Energy Corp. Centennial Place, East Tower 2800, 520 - 3rd Avenue SW Calgary, Alberta T2P 0R3 Toll-free: 1-800-524-5521 T: 587-952-3000 F: 587-952-3001 www.baytex.ab.ca OFFICERS Raymond T. Chan Executive Chairman Anthony W. Marino President & Chief Executive Officer W. Derek Aylesworth Chief Financial Officer Marty L. Proctor Chief Operating Officer Daniel G. Anderson Vice President, U.S. Business Unit Kendall D. Arthur Vice President, Saskatchewan Business Unit Stephen Brownridge Vice President, Exploration Geoffrey J. Darcy Vice President, Marketing Murray J. Desrosiers Vice President, General Counsel and Corporate Secretary Brian G. Ector Vice President, Investor Relations Michael S. Kaluza Vice President, Corporate Development and Planning Brett J. McDonald Vice President, Land Timothy R. Morris Vice President, U.S. Business Development Richard P. Ramsay Vice President, Alberta/B.C. Business Unit AUDITORS Deloitte & Touche LLP BANKERS The Toronto-Dominion Bank Alberta Treasury Branches Bank of America Bank of Montreal Bank of Nova Scotia 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 LEGAL COUNSEL Burnet, Duckworth & Palmer LLP RESERVES EVALUATOR Sproule Associates Limited TRANSFER AGENT Valiant Trust Company EXCHANGE LISTINGS Toronto Stock Exchange New York Stock Exchange Symbol: BTE

Condensate (diluent)

Price/Unit

Condensate

April 2012 to March 2013

WTI plus US$6.70