ex99_2.htm

Exhibit 99.2

Baytex Energy Corp.

Q1 2012 MD&A

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three months ended March 31, 2012 and 2011

Dated May 9, 2012

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2012. This information is provided as of May 9, 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. The first quarter results have been compared with the corresponding period in 2011. This MD&A should be read in conjunction with the Company’s condensed interim unaudited consolidated financial statements (“consolidated financial statements”) for the three months ended March 31, 2012 and 2011, its audited consolidated comparative financial statements for the years ended December 31, 2011 and 2010, together with accompanying notes, and its Revised 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. 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 amounts 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.

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 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".

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.

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Baytex Energy Corp.

Q1 2012 MD&A

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

	Three Months Ended March 31
Daily Production	2012			2011			Change
Light oil and NGL (bbl/d)		7,565			6,606			15	%
Heavy oil (bbl/d) (1)		38,353			31,792			21	%
Natural gas (mmcf/d)		45.1			51.0			(12	%)
Total production (boe/d)		53,433			46,902			14	%

Production Mix
Light oil and NGL		14	%		14	%		-
Heavy oil		72	%		68	%		-
Natural gas		14	%		18	%		-

(1)	Heavy oil sales volumes may differ from reported production volumes due to changes to Baytex's heavy oil inventory. For the three months ended March 31, 2012, heavy oil sales volumes were 91 bbl/d higher than production volumes (three months ended March 31, 2011 – 576 bbl/d higher).

Production for the three months ended March 31, 2012 averaged 53,433 boe/d, compared to 46,902 boe/d for the same period in 2011. Light oil and natural gas liquids (“NGL”) production for the first quarter of 2012 increased by 15% to 7,565 bbl/d from 6,606 bbl/d due to development activities in the U.S., which increased production by 183%, as compared to the same quarter in 2011. Heavy oil production for the first quarter of 2012 increased by 21% to 38,353 bbl/d from 31,792 bbl/d primarily due to successful development of our existing heavy oil assets and the acquisition of producing assets in the first quarter of 2011. Natural gas production decreased by 12% to 45.1 mmcf/d for the first quarter of 2012, as compared to 51.0 mmcf/d for the same period in 2011. The decrease in natural gas production was primarily due to natural declines as we focused our drilling effort on our oil portfolio.

Commodity Prices

Crude Oil

During the three months ended March 31, 2012, the prompt daily close price of West Texas Intermediate (“WTI”) fluctuated from a low of US$96.36/bbl to a high of US$109.77/bbl. The average WTI price in the first quarter of 2012 was US$102.93/bbl, or 9% higher than the US$94.10/bbl average in the first quarter of 2011. WTI continued its upward trend during much of the first quarter of 2012 due to several factors including the rising concerns about a confrontation with Iran over its nuclear program, an agreement on a bailout plan for Greece and signs of continued improvement in the U.S. economy. These last two factors were reflected in rising equity markets, particularly in the U.S., which consequently added support for oil prices on expectations of improving demand for oil.

The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 21% in the first quarter of 2012, compared to 11% in the fourth quarter of 2011 and 24% in the first quarter of 2011. The wider WCS differentials seen in the first quarter of 2012, as compared to the fourth quarter of 2011, was due to planned and unplanned refinery maintenance in the Midwest U.S. in March 2012 resulting in short term outages on crude export pipelines to those markets, thus reducing demand for Canadian heavy oil. These factors, together with incremental Canadian heavy oil production growth, resulted in logistical bottlenecks and higher discounts for Canadian heavy oil.

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Baytex Energy Corp.

Q1 2012 MD&A

Natural Gas

For the three months ended March 31, 2012, the AECO natural gas price averaged $2.52/mcf, as compared to $3.77/mcf in the same period of 2011. In the first quarter of 2012, continued U.S. natural gas production growth and unseasonably warm winter weather over much of North America resulted in historically high natural gas storage levels and lower natural gas prices.

	Three Months Ended March 31
	2012		2011		Change
Benchmark Averages
WTI oil (US$/bbl) (1)	$	102.93	$	94.10		9	%
WCS heavy oil (US$/bbl) (2)	$	81.51	$	71.24		14	%
Heavy oil differential (3)		(21%)		(24%)		-
USD/CAD average exchange rate		0.9998		1.0142		(1	%)
Edmonton par oil ($/bbl)	$	92.81	$	88.45		5	%
AECO natural gas ($/mcf) (4)	$	2.52	$	3.77		(33	%)

Baytex Average Sales Prices
Light oil and NGL ($/bbl)	$	81.99	$	75.68		8	%
Heavy oil ($/bbl) (5)	$	64.44	$	57.83		11	%
Physical forward sales contracts gain ($/bbl)		1.45		2.06
Heavy oil, net ($/bbl)	$	65.89	$	59.89		10	%
Total oil and NGL, net ($/bbl)	$	68.54	$	62.57		10	%
Natural gas ($/mcf) (6)	$	2.46	$	3.92		(37	%)
Physical forward sales contracts gain ($/mcf)		-		0.27
Natural gas, net ($/mcf)	$	2.46	$	4.19		(41	%)

Summary
Weighted average ($/boe) (6)	$	59.77	$	53.90		11	%
Physical forward sales contracts gain ($/boe)		1.21		1.96
Weighted average, net ($/boe)	$	60.98	$	55.86		9	%

(1) WTI refers to the arithmetic 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 arithmetic average monthly index price published by the Canadian Gas Price Reporter.

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

(6)

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

During the first quarter of 2012, Baytex’s average sales price for light oil and NGL was $81.99 bbl, up 8% from $75.68/bbl in the first quarter of 2011. Baytex’s realized heavy oil price during the first quarter of 2012, prior to physical forward sales contracts, was $64.44/bbl, or 79% of WCS. This compares to a realized heavy oil price in the first quarter of 2011, prior to physical forward sales contracts, of $57.83/bbl, or 82% of WCS. The differential to WCS largely reflects the cost of blending Baytex’s heavy oil with diluent to meet pipeline specifications. Net of physical forward sales contracts, Baytex’s realized heavy oil price during the first quarter of 2012 was $65.89/bbl, up 10% from $59.89/bbl in the first quarter of 2011. Baytex’s realized natural gas price for the three months ended March 31, 2012 was $2.46/mcf with no applicable physical forward sales contracts (three months ended March 31, 2011 - $3.92/mcf prior to physical forward sales contracts and $4.19/mcf inclusive of physical forward sales contracts).

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Baytex Energy Corp.

Q1 2012 MD&A

Gross Revenues

	Three Months Ended March 31
($ thousands except for %)	2012		2011		Change
Oil revenue
Light oil and NGL	$	56,443	$	44,994		25	%
Heavy oil		230,506		174,470		32	%
Total oil revenue		286,949		219,464		31	%
Natural gas revenue		10,075		19,236		(48	%)
Total oil and natural gas revenue		297,024		238,700		24	%
Sales of heavy oil blending diluent		46,331		51,615		(10	%)
Total petroleum and natural gas sales	$	343,355	$	290,315		18	%

Petroleum and natural gas sales increased 18% to $343.4 million for the three months ended March 31, 2012 from $290.3 million for the same period in 2011. During this period, the change primarily resulted from heavy oil revenues which increased by 32% due to a 10% increase in realized price and a 19% increase in sales volume compared to the three months ended March 31, 2011.

Royalties

	Three Months Ended March 31
($ thousands except for % and per boe)	2012			2011			Change
Royalties	$	52,994		$	48,802			9	%
Royalty rates:
Light oil, NGL and natural gas		18.5	%		18.9	%		-
Heavy oil		17.7	%		20.9	%		-
Average royalty rates (1)		17.8	%		20.3	%		-
Royalty expenses per boe	$	10.88		$	11.42			(5	%)

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

Royalties include Crown, freehold, overriding royalties and mineral taxes. Total royalties for the first quarter of 2012 increased to $53.0 million from $48.8 million in the first quarter of 2011. Total royalties for the first quarter of 2012 were 17.8% of petroleum and natural gas revenue (excluding sales of heavy oil blending diluent), as compared to 20.3% for the same period in 2011.

Royalty rates for light oil, NGL and natural gas decreased from 18.9% in the three months ended March 31, 2011 to 18.5% in the three months ended March 31, 2012 due to a 41% decrease in the realized natural gas price and from conventional oil royalty rate incentives on new wells. Royalty rates for heavy oil decreased from 20.9% in the three months ended March 31, 2011 to 17.7% due to royalty incentives on new wells at Seal and Kerrobert. In Seal, the royalty framework levies a flat 5% royalty rate on horizontal wells for the first 50,000 to 100,000 barrels of production, depending on well depth. In Kerrobert, our Steam Assisted Gravity Drainage projects also merit favourable royalty rate incentives for Baytex.

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.

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Baytex Energy Corp.

Q1 2012 MD&A

Financial Derivatives

	Three Months Ended March 31
($ thousands)	2012			2011			Change
Realized gain (loss) on financial derivatives (1)
Crude oil	$	(8,553	)	$	(4,433	)	$	(4,120	)
Natural gas		1,225			(10	)		1,235
Foreign currency		1,881			6,102			(4,221	)
Interest rate		(1,693	)		(72	)		(1,621	)
Total	$	(7,140	)	$	1,587		$	(8,727	)

Unrealized gain (loss) on financial derivatives (2)
Crude oil	$	(8,918	)	$	(48,791	)	$	39,873
Natural gas		368			408			(40	)
Foreign currency		3,312			1,380			1,932
Interest rate		1,036			533			503
Total	$	(4,202	)	$	(46,470	)	$	42,268

Total gain (loss) on financial derivatives
Crude oil	$	(17,471	)	$	(53,224	)	$	35,753
Natural gas		1,593			398			1,195
Foreign currency		5,193			7,482			(2,289	)
Interest rate		(657	)		461			(1,118	)
Total	$	(11,342	)	$	(44,883	)	$	33,541

(1) Realized gain (loss) on financial derivatives represents actual cash settlement or receipts for 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 three months ended March 31, 2012 was $11.3 million, as compared to a loss of $44.9 million for the same period in 2011. This includes a realized loss of $7.1 million and an unrealized mark-to-market loss of $4.2 million for the first quarter of 2012, as compared to $1.6 million in realized gains and $46.5 million in unrealized losses for the first quarter of 2011. The realized loss of $7.1 million for the three months ended March 31, 2012 relates to the settlement at maturity of losses incurred on derivative contracts due to higher oil prices and lower floating interest rates, partially offset by gains on natural gas and foreign currency contracts. The unrealized mark-to-market loss of $4.2 million for the three months ended March 31, 2012 relates to higher oil prices at March 31, 2012, as compared to December 31, 2011, partially offset by a strengthening Canadian dollar against the U.S. dollar.

A summary of the risk management contracts in place as at March 31, 2012 and the accounting treatment of the Company’s financial instruments are disclosed in note 15 to the consolidated financial statements as at and for the three months ended March 31, 2012.

Evaluation and Exploration Expense

Evaluation and exploration expense for the three months ended March 31, 2012 decreased to $2.5 million, as compared to $3.5 million for the same period of 2011, due to a decrease in the expiration of undeveloped land leases during 2012.

Production and Operating Expenses

	Three Months Ended March 31
($ thousands except for % and per boe)	2012		2011		Change
Production and operating expenses	$	58,287	$	47,476		23	%
Production and operating expenses per boe	$	11.97	$	11.11		8	%

Production and operating expenses for the three months ended March 31, 2012 increased to $58.3 million from $47.5 million due to increased production volumes attributable to the development of existing assets in Canada and the U.S. and the Reno and Brewster acquisitions. Production and operating expenses were $11.97 per boe for the three months ended March 31, 2012, as compared to $11.11 per boe for the same period in 2011. For the three

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Baytex Energy Corp.

Q1 2012 MD&A

months ended March 31, 2012, production and operating expenses were $14.28 per boe of light oil, NGL and natural gas and $11.06 per barrel of heavy oil, as compared to $11.28 per boe and $11.03 per barrel, respectively, for the same period in 2011. Total production and operating expenses increased by 8% and light oil and natural gas production and operating expenses increased by 27% for the three months ended March 31, 2012 as compared to the same period of 2011 due to higher than normal workover expenses, Stoddart compressor turnaround costs, and increases in labour rates.

Transportation and Blending Expenses

	Three Months Ended March 31
($ thousands except for % and per boe)	2012		2011		Change
Blending expenses	$	46,331	$	51,615		(10	%)
Transportation expenses		15,406		12,545		23	%
Total transportation and blending expenses	$	61,737	$	64,160		(4	%)
Transportation expenses per boe (1)	$	3.16	$	2.94		7	%

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

Transportation and blending expenses for the first quarter of 2012 were $61.7 million, as compared to $64.2 million for the first quarter of 2011.

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 first quarter of 2012, blending expenses were $46.3 million for the purchase of 4,620 bbl/d of condensate at $110.19 per barrel, as compared to $51.6 million for the purchase of 5,870 bbl/d at $97.71 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 $3.16 per boe for the three months ended March 31, 2012, as compared to $2.94 per boe for the same period of 2011. Transportation expenses were $0.70 per boe of light oil, NGL and natural gas and $4.13 per barrel of heavy oil in the first quarter of 2012, as compared to $0.73 and $3.97 per barrel, respectively, for the same period in 2011. The increase in transportation expenses per barrel of heavy oil is primarily driven by a larger portion of our heavy oil production coming from our Seal and Reno areas which utilizes long-haul trucking to ship a portion of production volumes.

Operating Netback

	Three Months Ended March 31
($ per boe except for % and volume)	2012			2011		Change
Sales volume (boe/d)		53,524			47,478		13	%
Operating netback (1):
Sales price (2)	$	60.98		$	55.86		9	%
Less:
Royalties		10.88			11.42		(5	%)
Operating expenses		11.97			11.11		8	%
Transportation expenses		3.16			2.94		7	%
Operating netback before financial derivatives	$	34.97		$	30.39		15	%
Financial derivatives gain (loss) (3)		(1.47	)		0.37		(497	%)
Operating netback after financial derivatives gain (loss)	$	33.50		$	30.76		9	%

(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.

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Baytex Energy Corp.

Q1 2012 MD&A

General and Administrative Expenses

	Three Months Ended March 31
($ thousands except for % and per boe)	2012		2011		Change
General and administrative expenses	$	11,188	$	11,130		1	%
General and administrative expenses per boe	$	2.30	$	2.60		(12	%)

General and administrative expenses for the first quarter of 2012 at $11.2 million were comparable to the $11.1 million for the same period in 2011. On a per boe basis, general and administrative expenses decreased by 12% from $2.60 in the first quarter of 2011 to $2.30 in the first quarter of 2012 due to increase in production.

Share-based Compensation Expense

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. Concurrent with the adoption of the Share Award Incentive Plan, no further grants were made under the Common Share Rights Incentive Plan (the “Share Rights Plan).

Compensation expense related to the Share Rights Plan decreased to $0.4 million in the first quarter of 2012 (three months ended March 31, 2011 - $5.3 million) while compensation expense related to the Share Award Incentive Plan increased to $6.5 million for the three months ended March 31, 2012 (three months ended March 31, 2011 - $2.7 million). The overall decrease in compensation expense of $1.1 million is mainly resulting from increased forfeitures during the three months ended March 31, 2012 compared to the same period of 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 surplus. The issuance of common shares upon the exercise of share rights or release of share awards is recorded as an increase in shareholders’ capital with a corresponding reduction in contributed surplus.

Financing Costs

	Three Months Ended March 31
($ thousands except for %)	2012		2011		Change
Bank loan and other	$	2,540	$	3,721		(32	%)
Long-term debt		6,112		4,696		30	%
Accretion on asset retirement obligations		1,627		1,484		10	%
Debt financing costs		20		661		(97	%)
Financing costs	$	10,299	$	10,562		(2	%)

Financing costs for the three months ended March 31, 2012 decreased to $10.3 million, as compared to $10.6 million in the first quarter of 2011. The decrease was primarily attributable to lower average borrowing on bank loans coupled with lower interest rates, offset by interest on the US$150.0 million principal amount of 6.75% Series B senior unsecured debentures issued on February 17, 2011.

Foreign Exchange

	Three Months Ended March 31
($ thousands except for % and exchange rates)	2012			2011			Change
Unrealized foreign exchange gain	$	(5,993	)	$	(4,856	)		23	%
Realized foreign exchange loss		1,125			926			21	%
Total gain	$	(4,868	)	$	(3,930	)		24	%
USD/CAD exchange rates:
At beginning of period		0.9833			1.0054
At end of period		1.0009			1.0290

The foreign exchange gain for the three months ended March 31, 2012 was $4.9 million and comprised of an unrealized foreign exchange gain of $6.0 million and a realized foreign exchange loss of $1.1 million. The foreign exchange gain for the three months ended March 31, 2011 was $3.9 million and comprised of an unrealized foreign exchange gain of $4.9 million and a realized foreign exchange loss of $0.9 million. The first quarter of 2012 unrealized

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Baytex Energy Corp.

Q1 2012 MD&A

gain of $6.0 million, as compared to a gain of $4.9 million for the first quarter of 2011, was due to the translation of the US$180.0 million portion of the bank loan and US$150.0 million Series B senior unsecured debentures as the USD/CAD foreign exchange rates strengthened at March 31, 2012 (as compared to December 31, 2011) and strengthened at March 31, 2011 (as compared to December 31, 2010). The current quarter realized losses were due to day-to-day U.S. dollar denominated transactions.

Depletion and Depreciation

Depletion and depreciation for the three months ended March 31, 2012 increased to $72.3 million from $56.6 million for the same period in 2011. On a sales-unit basis, the provision for the current quarter was $14.85 per boe, as compared to $13.26 per boe for the same quarter in 2011 due to the increase in future development costs resulting in a higher depletable base.

Income Taxes

For the three months ended March 31, 2012, deferred income tax expense totaled $17.8 million, as compared to an expense of $1.8 million for the three months ended March 31, 2011. The Company’s earnings are sheltered from current income taxes by applying tax pools. Earnings were higher for the three months ended March 31, 2012 compared to the same period in 2011 and the increase in deferred income tax expense reflects the cost of drawing down tax pools to shelter that increased income.

As at March 31, 2012, net deferred income tax liability was $101.1 million (December 31, 2011 - $83.1 million). The increase relates to the deferred tax expense associated with earnings over the period.

Net Income

Net income for the three months ended March 31, 2012 was $43.0 million, as compared to $1.0 million for the same period in 2011. The increase in net income was primarily the result of a decrease in unrealized loss on financial derivative contracts and an increase in production volume coupled with a higher operating netback for the current period. This was partially offset by an increase in financial derivative loss and higher depletion and depreciation.

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’ equity and are recognized in net income when there has been a disposal or partial disposal of the foreign operation.

The $8.9 million balance of accumulated other comprehensive loss at March 31, 2012 is the sum of a $3.5 million foreign currency translation loss incurred as at December 31, 2011 and a $5.4 million foreign currency translation loss related to the three months ended March 31, 2012, due to the strengthening USD/CAD foreign exchange rates at March 31, 2012 compared to December 31, 2011.

FUNDS FROM OPERATIONS, PAYOUT RATIO AND DIVIDENDS

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 (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.

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Baytex Energy Corp.

Q1 2012 MD&A

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

	Three Months Ended											Year Ended
($ thousands except for %)	March 31, 2012			December 31, 2011				March 31, 2011			December 31, 2011
Cash flow from operating activities	$	151,361			$	157,083		$	119,899			$	571,860
Change in non-cash working capital		(1,881	)			9,336			(2,392	)			10,889
Asset retirement expenditures		771				5,646			919				10,588
Financing costs		(10,299	)			(10,873	)		(10,562	)			(44,611	)
Accretion on asset retirement obligations		1,627				1,627			1,484				6,185
Accretion on debentures and long-term debt		157				154			122				572
Funds from operations	$	141,736			$	162,973		$	109,470			$	555,483
Cash dividends declared	$	78,365			$	72,912		$	68,794			$	281,047
Reinvested dividends		22,806				21,987			16,792				75,087
Cash dividends declared (net of DRIP)	$	55,559			$	50,925		$	52,002			$	205,960
Payout ratio		55%				45%			63%				51%
Payout ratio (net of DRIP)		39%				31%			48%				37%	%

Baytex does not deduct capital expenditures when calculating the payout ratio. Due to the depleting nature of petroleum and natural gas assets, certain levels of capital expenditures are required to minimize production declines. In the petroleum and natural gas industry, due to the nature of reserve reporting, natural production declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Should the costs to explore for, develop or acquire petroleum and natural gas assets increase significantly, it is possible that Baytex would be required to reduce or eliminate its dividends in order to fund capital expenditures. There can be no certainty that Baytex will be able to maintain current production levels in future periods. Cash dividends declared, net of DRIP participation, of $55.6 million for the first quarter of 2012 were funded through funds from operations of $141.7 million.

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)	March 31, 2012			December 31, 2011
Bank loan		$	326,889		$	311,960
Long-term debt (1)			299,865			302,550
Working capital deficiency			63,988			36,071
Total monetary debt		$	690,742		$	650,581

(1) Principal amount of instruments.

At March 31, 2012, total monetary debt was $690.7 million, as compared to $650.6 million at December 31, 2011. Bank borrowings at March 31, 2012 were $326.9 million, as compared to total credit facilities of $700.0 million.

Our wholly-owned subsidiary, Baytex Energy Ltd. ("Baytex Energy"), has established a $40 million extendible operating loan facility with a chartered bank and a $660 million extendible syndicated loan facility with a syndicate of chartered banks, each of which constitute a revolving credit facility for a three-year term (to June 14, 2014), which is extendible annually for a 1, 2 or 3 year period (subject to a maximum three-year term at any time). The Credit Facilities contain standard commercial covenants for facilities of this nature. Baytex Energy is in compliance with all such 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 U.S. funds and bear interest at

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Baytex Energy Corp.

Q1 2012 MD&A

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 the 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).

The weighted average interest rate on the bank loan for three months ended March 31, 2012 was 3.59% (3.69% for year ended December 31, 2011 and 3.84% for the three months ended March 31, 2011).

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.

Subsequent to the end of the first quarter, we entered into an agreement to sell the non-operated portion of our North Dakota assets for gross proceeds of US$311 million. The proceeds from this disposition maybe used to reduce net debt or redeployed into other oil and gas assets.

Capital Expenditures

Capital expenditures are summarized as follows:

	Three Months Ended March 31
($ thousands)	2012			2011
Land	$	2,592		$	2,225
Seismic		848			123
Drilling and completion		95,335			63,195
Equipment		37,055			21,431
Other		88			40
Total exploration and development	$	135,918		$	87,014
Acquisitions - Corporate		-			117,346
Acquisitions - Properties		2,336			37,518
Proceeds from divestitures		(3,568	)		-
Total acquisitions and divestitures	$	(1,232	)	$	154,864
Total oil and natural gas expenditures	$	134,686		$	241,878
Other plant and equipment, net		5,044			(275	)
Total capital expenditures	$	139,730		$	241,603

Shareholders’ Capital

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 May 8, 2012, the Company had 119,087,393 common shares and no preferred shares issued and outstanding.

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Baytex Energy Corp.

Q1 2012 MD&A

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 March 31, 2012, and the expected timing of funding of these obligations, are noted in the table below.

($ thousands)	Total		Less than 1 year			1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	221,799		$	221,799	$	-	$	-		$	-
Dividends payable to shareholders		26,159			26,159		-		-			-
Bank loan (1)		326,889			-		326,889		-			-
Long-term debt (2)		299,865			-		-		150,000			149,865
Operating leases		48,656			5,734		11,962		12,186			18,774
Processing agreements		69,457			2,474		11,231		11,105			44,647
Transportation agreements		67,252			1,651		7,303		16,871			41,427
Total	$	1,060,077		$	257,817	$	357,385	$	190,162		$	254,713

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

(2)	Principal amount of instruments.

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

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

QUARTERLY FINANCIAL INFORMATION

	2012	2011				2010
($ thousands, except per common share or trust unit amounts)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Gross revenues	343,355	367,813	313,787	336,899	290,315	263,497	238,276	241,581
Net income	42,958	57,780	51,839	106,863	950	21,356	23,319	157,440
Per common share or trust unit - basic	0.36	0.49	0.45	0.92	0.01	0.19	0.21	1.42
Per common share or trust unit - diluted	0.36	0.48	0.44	0.90	0.01	0.18	0.20	1.38

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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; and the existence, operation and strategy of our risk management program. 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; failure to obtain the necessary regulatory and other approvals on the 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.

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