2014 Q2 MD&A

EX-99.2 3 a2014q2mda.htm MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30 2014 Q2 MD&A

Baytex Energy Corp.

Q2 2014 MD&A Page 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and six months ended June 30, 2014 and 2013

Dated July 30, 2014

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended June 30, 2014. This information is provided as of July 30, 2014. 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 second quarter results have been compared with the corresponding period in 2013. This MD&A should be read in conjunction with the Company’s condensed interim unaudited consolidated financial statements (“consolidated financial statements”) for the three and six months ended June 30, 2014, its audited comparative consolidated financial statements for the years ended December 31, 2013 and 2012, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2013. 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 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.

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 by 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 ("DRIP")) 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 unrealized gains or losses on financial derivatives, assets held for sale and liabilities related to assets held for sale)), 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. See "Liquidity and Capital Resources" for a description of Total Monetary Debt.

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. As sales volumes are not materially different than production volumes, we believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

Baytex Energy Corp.

Q2 2014 MD&A Page 2

SECOND QUARTER HIGHLIGHTS

The second quarter was a busy quarter for the Company as we set the stage for future growth. We closed the acquisition of Aurora Oil & Gas Limited ("Aurora") in June 2014 which resulted in an immediate increase in production. The new Eagle Ford assets added 6,106 boe/d of production and about $47.5 million of revenue in the period after closing. Production in our heavy oil properties increased by 8% for the second quarter of 2014 as compared to the same period in 2013, as we continued to have success in our drilling and development program, especially in the Peace River area. Oil prices were 24% higher this year compared to last year as the price for West Texas Intermediate crude oil ("WTI") increased, the discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, decreased and the Canadian dollar weakened against the U.S. dollar. We benefited from our rail transportation strategy which allowed us to access higher value markets for our heavy oil. We also completed a swap of assets, exiting mature properties in Saskatchewan and acquiring additional properties in the Peace River area. Funds from operations for the second quarter was $165.5 million ($202.5 million excluding acquisition-related costs of $37.0 million). We generated net income of $36.8 million in the second quarter which was similar to the net income in the same period last year, despite the acquisition-related costs.

BUSINESS COMBINATION

On June 11, 2014, we acquired all of the ordinary shares of Aurora for $4.20 (Australian dollars) per share by way of a scheme of arrangement under the Corporations Act 2001 (Australia) (the "Arrangement"). The total purchase price for Aurora was approximately $2.8 billion, including the assumption of $955 million of indebtedness and $54.6 million of cash. Aurora’s primary asset consists of 22,200 net contiguous acres in the Sugarkane Field located in South Texas in the core of the liquids-rich Eagle Ford shale. The Sugarkane Field has been largely delineated with infrastructure in place which is expected to facilitate future annual production growth. The acquisition adds an estimated 166.6 Mboe of proved and probable reserves. In addition, these assets have future reserves upside potential from well downspacing, improving completion techniques and new development targets in additional zones.

To finance the acquisition of Aurora, we completed the issuance of 38,433,000 subscription receipts at $38.90 each on February 24, 2014, raising gross proceeds of approximately $1.5 billion. The subscription receipts were converted to common shares on June 11, 2014. We also entered into an agreement with a Canadian chartered bank for the provision of new unsecured revolving credit facilities of approximately $1.2 billion (to replace the $850 million revolving credit facilities of Baytex Energy Ltd.), and a new two-year $200 million unsecured loan. The new facilities became available upon closing of the Arrangement and were used to finance a portion of the purchase price.

In anticipation of closing the Arrangement, we made tender offers for the US$665 million principal value of outstanding senior notes of Aurora USA Oil & Gas, Inc, a wholly-owned subsidiary of Aurora. Approximately 98% of the outstanding notes with a principal value totaling US$650.7 million were tendered in response to our offer resulting in US$745.6 million being paid to the former holders of the notes. In order to finance the tender offers, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 and US$400 million of 5.625% notes due June 1, 2024.

The Results of Operations include the results of Aurora from June 11, 2014. Total production from the date of acquisition to June 30, 2014 was 555,667 boe (27,783 boe/d), equivalent to 6,106 boe/d for the three months ended June 30, 2014 and 3,070 boe/d for the six months ended June 30, 2014. Revenue for the period, since June 11, was $47.5 million, or $85.47/boe, which generated a netback on the Aurora operations of $53.97/boe.

RESULTS OF OPERATIONS

Production



	Three Months Ended June 30						Six Months Ended June 30
Daily Production	2014		2013		Change		2014		2013		Change
Light oil and NGL (bbl/d)	12,340		8,202		50	%	9,912		8,062		23	%
Heavy oil (bbl/d)⁽¹⁾	45,986		42,510		8	%	45,611		40,012		14	%
Natural gas (mcf/d)	51,645		45,148		14	%	46,295		42,243		10	%
Total production (boe/d)	66,934		58,236		15	%	63,239		55,115		15	%

Production Mix
Light oil and NGL	18	%	14	%			16	%	14	%
Heavy oil	69	%	73	%			72	%	73	%
Natural gas	13	%	13	%			12	%	13	%

(1) Heavy oil sales volumes may differ from reported production volumes due to changes in our heavy oil inventory. For the three months ended June 30, 2014, heavy oil sales volumes were 257 bbl/d higher than production volumes (three months ended June 30, 2013 – 204 bbl/d higher). For the six months ended June 30, 2014, heavy oil sales volumes were 101 bbl/d higher than production volumes (six months ended June 30, 2013 - 97 bbl/d higher).

Baytex Energy Corp.

Q2 2014 MD&A Page 3

Production for the three months ended June 30, 2014 averaged 66,934 boe/d, an increase of 15% compared to 58,236 boe/d for the same period in 2013. Light oil and natural gas liquids (“NGL”) production in the second quarter of 2014 increased by 50% to 12,340 bbl/d, as compared to 8,202 bbl/d in the second quarter of 2013, primarily due to the Aurora acquisition which increased production by 5,032 bbl/d, partially offset by natural declines. Heavy oil production for the second quarter of 2014 increased by 8% to 45,986 bbl/d from 42,510 bbl/d in the second quarter of 2013, primarily due to successful development activities in the Peace River area. Natural gas production increased by 14% to 51.6 mmcf/d for the second quarter of 2014, as compared to 45.1 mmcf/d for the same period in 2013, mainly due to the addition of 6.4 mmcf/d from the acquisition of Aurora.

Production for the six months ended June 30, 2014 averaged 63,239 boe/d, an increase of 15% compared to 55,115 boe/d for the same period in 2013. Light oil and NGL production in the first six months of 2014 increased by 23% to 9,912 bbl/d, as compared to 8,062 bbl/d in the first six months of 2013, primarily due to the Aurora acquisition which increased production by 2,530 bbl/d, partially offset by natural declines. Heavy oil production for the six months ended June 30, 2014 increased by 14% to 45,611 bbl/d from 40,012 bbl/d for the same period in 2013, primarily due to successful development activities in the Peace River area. Natural gas production increased by 10% to 46.3 mmcf/d for the first six months of 2014, as compared to 42.2 mmcf/d for the same period in 2013, mainly due to the addition of 3.2 mmcf/d from the Aurora acquisition.

Commodity Prices

The prices received for our crude oil and natural gas production directly impact our earnings, funds from operations and our financial position. The following tables compare selected benchmark prices and our average realized selling prices for the current quarter and year to date against the same periods last year.



	Three Months Ended June 30								Six Months Ended June 30
	2014			2013			Change		2014			2013			Change
Benchmark Averages
WTI oil (US$/bbl)⁽¹⁾	$	102.99		$	94.22		9	%	$	100.84		$	94.30		7	%
WCS heavy oil (US$/bbl)⁽²⁾	$	82.95		$	75.07		10	%	$	79.25		$	68.75		15	%
Heavy oil differential⁽³⁾	19		%	20		%			22		%	27		%
CAD/USD average exchange rate	1.0894			1.0231			6	%	1.0964			1.0159			8	%
Edmonton par oil ($/bbl)	$	106.68		$	92.94		15	%	$	103.43		$	90.77		14	%
LLS oil (US$/bbl)⁽⁴⁾	$	105.55		$	104.81		1	%	$	104.96		$	109.37		(4	)%
AECO natural gas price ($/mcf)⁽⁵⁾	$	4.68		$	3.46		35	%	$	4.72		$	3.27		44	%

Average Sales Prices
Heavy oil ($/bbl)⁽⁶⁾	$	79.17		$	63.92		24	%	$	75.08		$	57.82		30	%
Physical forward sales contracts gain($/bbl)	$	0.09		$	—				$	0.18		$	1.25
Heavy oil, net ($/bbl)	$	79.26		$	63.92		24	%	$	75.26		$	59.07		27	%
Light oil and NGL ($/bbl)⁽⁷⁾	$	91.03		$	77.85		17	%	$	88.84		$	77.30		15	%
Total oil and NGL, net ($/bbl)	$	81.74		$	66.17		24	%	$	77.68		$	62.12		25	%
Natural gas ($/mcf)	$	4.84		$	3.59		35	%	$	5.01		$	3.53		42	%

Summary
Weighted average ($/boe)⁽⁷⁾	$	75.00		$	60.42		24	%	$	71.79		$	55.99		28	%
Physical forward sales contracts gain ($/boe)	0.06			—					0.13			0.91
Weighted average, net ($/boe)	$	75.06		$	60.42		24	%	$	71.92		$	56.90		26	%


(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 on a monthly weighted average basis.


(4)	Louisiana Light Sweet ("LLS") refers to the monthly arithmetic average for Argus LLS front month.


(5)	AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter.


(6)	Realized heavy oil prices are calculated based on sales volumes, net of blending costs.


(7)	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 pricing information in the table excludes the impact of financial derivatives.

Baytex Energy Corp.

Q2 2014 MD&A Page 4

Crude Oil

For the three months ended June 30, 2014, the WTI oil prompt price averaged US$102.99/bbl, a 9% increase from the average WTI price of US$94.22/bbl in the second quarter of 2013. In the three months ended June 30, 2014, prices benefited from a steady decline in crude oil inventories at Cushing, Oklahoma, heightened global geopolitical risk and bullish sentiment from speculative traders.

For the six months ended June 30, 2014, the WTI oil prompt price averaged US$100.84/bbl, a 7% increase from the average WTI price of US$94.30/bbl in the first half of 2013. In the first six months of 2014, prices benefited from increased pipeline connectivity between Cushing, Oklahoma and the U.S. Gulf Coast, resulting in a more narrow spread between WTI and globally priced crude oil.

The discount for Canadian heavy oil, as measured by the WCS price differential to WTI, averaged 19% for the three months ended June 30, 2014 compared to 20% for the same period in 2013. WCS differentials improved throughout the second quarter of 2014 compared to the first quarter of 2014, due to increased heavy oil demand stemming from the continued ramp up of BP Whiting’s refinery modernization project and normal seasonality.

For the six months ended June 30, 2014, the WCS heavy oil differential averaged 22% compared to 27% in the first half of 2013. In the first six months of 2014, the differential narrowed due to an increase in crude caused by supply issues in the first quarter of 2014, low inventory levels and increasing take-away capacity out of Western Canada.

Natural Gas

For the three months ended June 30, 2014 the AECO natural gas price averaged $4.68/mcf, a 35% increase compared to $3.46/mcf in the same period of 2013. The increase in natural gas price for the three months ended June 30, 2014 compared to the same period in 2013 is a result of below average North American natural gas storage levels after a prolonged and colder than normal winter.

For the six months ended June, 30, 2014 the AECO natural gas price averaged $4.72/mcf, a 44% increase compared to $3.27/mcf in the same period of 2013. In the first six months of 2014, prices benefited from a weaker Canadian dollar and a colder than normal winter.

Average Sales Prices

Our realized heavy oil price during the second quarter of 2014 was $79.26/bbl, or 88% of WCS, compared to $63.92/bbl, or 83% of WCS in the second quarter of 2013. The realized price during the second quarter of 2014 increased due to the decline in the Canadian dollar compared to the second quarter of 2013, an increase in WTI coupled with a decrease in the WCS differential. We also increased our use of rail which helped to optimize our realized price. During the second quarter of 2014, our average sales price for light oil and NGL was $91.03/bbl, up 17% from $77.85/bbl in the second quarter of 2013, which is in line with the increase in the Edmonton par oil benchmark price over the same period. Our realized natural gas price for the three months ended June 30, 2014 was $4.84/mcf, up from $3.59/mcf in the second quarter of 2013. The increase is is in line with the increase in the AECO benchmark applicable to the Canadian production and in line with expected prices for the Aurora production over the same period.

Our realized heavy oil price for the six months ended June 30, 2014 was $75.26/bbl, or 87% of WCS, compared to $59.07/bbl, or 85% of WCS in the second quarter of 2013. The realized price during the first six months of 2014 increased due to the decline in the Canadian dollar compared to the same period in 2013, as well as an increase in the benchmark prices. During the first six months of 2014, our average sales price for light oil and NGL was $88.84/bbl, up 15% from $77.30/bbl in the first six months of 2013, in line with the increase in the Edmonton par oil benchmark price over the same period. Our realized natural gas price for the six months ended June 30, 2014 was $5.01/mcf, up from $3.53/mcf in the second quarter of 2013, largely in line with increase in the AECO benchmark and the US natural gas benchmarks.

Financial Derivatives

As part of normal operations in the upstream oil and gas industry, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize a series of financial derivative contracts which are intended to reduce some of the volatility in our operating cash flow. The following table summarizes the results of our financial derivative contracts for the three and six months ended June 30, 2014 and 2013.

Baytex Energy Corp.

Q2 2014 MD&A Page 5



	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2014			2013			Change			2014			2013			Change
Realized (loss) gain on financial derivatives⁽¹⁾
Crude oil	$	(12,054	)	$	8,748		$	(20,802	)	$	(10,441	)	$	15,609		$	(26,050	)
Natural gas	(629		)	(264		)	(365		)	(1,816		)	79			(1,895		)
Foreign currency	(1,231		)	147			(1,378		)	(3,266		)	813			(4,079		)
Interest	117			137			(20		)	(4,021		)	(3,605		)	(416		)
Total	$	(13,797	)	$	8,768		$	(22,565	)	$	(19,544	)	$	12,896		$	(32,440	)

Unrealized (loss) gain on financial derivatives⁽²⁾
Crude oil	$	(33,034	)	$	5,226		$	(38,260	)	$	(42,346	)	$	(5,074	)	$	(37,272	)
Natural gas	795			3,037			(2,242		)	(2,241		)	650			(2,891		)
Foreign currency	(15,043		)	(8,539		)	(6,504		)	6,118			(11,476		)	17,594
Interest⁽³⁾	11,956			(175		)	12,131			15,968			3,554			12,414
Total	$	(35,326	)	$	(451	)	$	(34,875	)	$	(22,501	)	$	(12,346	)	$	(10,155	)

Total (loss) gain on financial derivatives
Crude oil	$	(45,088	)	$	13,974		$	(59,062	)	$	(52,787	)	$	10,535		$	(63,322	)
Natural gas	166			2,773			(2,607		)	(4,057		)	729			(4,786		)
Foreign currency	(16,274		)	(8,392		)	(7,882		)	2,852			(10,663		)	13,515
Interest⁽³⁾	12,073			(38		)	12,111			11,947			(51		)	11,998
Total	$	(49,123	)	$	8,317		$	(57,440	)	$	(42,045	)	$	550		$	(42,595	)


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


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


(3)	Unrealized gain on interest rate derivatives includes the change in fair value of the call options embedded in our senior unsecured notes.

Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price on the date the contract matures. As the forward markets for commodities and currencies fluctuate and as new contracts are executed, changes in the fair value are reported as unrealized gains or losses in the period. Contracts in place at the beginning of the period which settle during the period will give rise to the reversal of the unrealized gain or loss recorded at the beginning of the period.

The realized loss of $13.8 million for the three months ended June 30, 2014 on derivative contracts is mainly due to crude oil prices exceeding our fixed price contracts during the quarter. The unrealized mark-to-market loss of $35.3 million for the three months ended June 30, 2014 mainly relates to higher forward crude oil prices at June 30, 2014 as compared to March 31, 2014, partially offset by the fair value gain of $12.1 million on the call options embedded within the senior unsecured notes and the strengthening Canadian dollar against the US dollar at June 30, 2014 as compared to March 31, 2014. The unrealized loss also includes the reversal of the unrealized gain of $31.6 million reported at March 31, 2014 on the Australian dollar contracts put in place to mitigate currency risk on the purchase price of Aurora.

The realized loss of $19.5 million for the six months ended June 30, 2014 on derivative contracts relates to crude oil rising to levels above our fixed price contracts and losses on the interest rate swaps as LIBOR remained low, as well as the weakening Canadian dollar against the U.S. dollar compared to December 31, 2013. The unrealized mark-to-market loss of $22.5 million for the six months ended June 30, 2014 is mainly due to higher forward commodity prices at June 30, 2014, as compared to December 31, 2013, partially offset by the fair value gain of $12.1 million on the call options embedded within the senior unsecured notes, addition of favourable foreign currency contracts and settlement of previously unrecorded unrealized losses on interest rate contracts.

A summary of the financial derivative contracts in place as at June 30, 2014 and the accounting treatment thereof are disclosed in note 18 to the consolidated financial statements.

Baytex Energy Corp.

Q2 2014 MD&A Page 6

Gross Revenues



	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for %)	2014		2013		Change		2014		2013		Change
Oil revenue
Light oil and NGL	$	102,226	$	58,106	76	%	$	159,392	$	112,794	41	%
Heavy oil	333,518		248,458		34	%	622,730		428,818		45	%
Total oil revenue	435,744		306,564		42	%	782,122		541,612		44	%
Natural gas revenue	22,764		14,730		55	%	41,959		26,962		56	%
Total oil and natural gas revenue	458,508		321,294		43	%	824,081		568,574		45	%
Other income	415		—		100	%	415		—		100	%
Heavy oil blending revenue	17,481		19,717		(11	)%	37,717		45,382		(17	)%
Total petroleum and natural gas revenues	$	476,404	$	341,011	40	%	$	862,213	$	613,956	40	%

Petroleum and natural gas revenues increased 40% to $476.4 million for the three months ended June 30, 2014 from $341.0 million for the same period in 2013. The growth in revenues for the three months ended June 30, 2014 is the result of both higher production volumes and higher commodity prices compared to the second quarter of 2013. Heavy oil blending revenue was down 11% for the three months ended June 30, 2014 due to the decrease in contracted volumes of heavy oil requiring blending diluent. Unlike transportation through oil pipelines, transportation of heavy oil by rail does not require blending diluent. The decrease in heavy oil blending revenue is offset by a corresponding decrease in heavy oil blending costs.

Petroleum and natural gas revenues increased 40% to $862.2 million for the six months ended June 30, 2014 from $614.0 million for the same period in 2013. The increase in revenues is a result of higher realized pricing on all product lines, combined with increased production. Blending revenue is 17% lower for the six months ended June 30, 2014 compared to the same period last year due to an increase in contracted volumes of heavy oil being transported by rail.

The assets acquired from Aurora contributed $47.5 million of petroleum and natural gas revenue for the three and six months ended June 30, 2014.

Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Royalties are calculated based on gross revenues and are generally expressed as a percentage of gross revenue. The actual royalty rates can vary for a number of reasons including commodity produced, commodity price, royalty incentives, the producing formation and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and six months ended June 30, 2014 and 2013:



	Three Months Ended June 30								Six Months Ended June 30
($ thousands except for % and per boe)	2014			2013			Change		2014			2013			Change
Royalties	$	112,282		$	62,010		81	%	$	187,162		$	107,288		74	%
Royalty rates:
Light oil, NGL and natural gas	23.9		%	18.3		%			22.3		%	21.7		%
Heavy oil	24.7		%	19.6		%			22.8		%	18.0		%
Average royalty rates⁽¹⁾	24.5		%	19.3		%			22.7		%	18.9		%
Royalty expenses per boe	$	18.36		$	11.66		57	%	$	16.33		$	10.74		52	%


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

Royalty rates in the three months ended June 30, 2014 for light oil, NGL and natural gas were 23.9%, up from 18.3% in the three months ended June 30, 2013 as the Aurora assets have an expected royalty rate of 29%. Excluding the Aurora assets, the royalty rate for light oil, NGL and natural gas would have been 20.7%, largely in line with expectations. Royalty rates for heavy oil increased to 24.7% in the three months ended June 30, 2014 compared to 19.6% in the three months ended June 30, 2013, primarily due to higher royalty rates imposed by the Crown, a reduction in the royalty incentive volumes in Peace River and $2.8 million of adjustments applied by the Crown related to prior periods. Crown heavy oil royalty rates utilize a sliding scale based on commodity price and therefore have increased as WTI prices increased.

Royalty rates for light oil, NGL and natural gas increased from 21.7% in the six months ended June 30, 2013 to 22.3% in the six months ended June 30, 2014, primarily due to inclusion of the Aurora assets. Royalty rates for heavy oil increased from 18.0% in the six months ended June 30, 2013 to 22.8% in the six months ended June 30, 2014 primarily due to increased royalty rates imposed by the Crown based on higher commodity prices.

Production and Operating Expenses



	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for % and per boe)	2014		2013		Change		2014		2013		Change
Production and operating expenses	$	75,343	$	68,999	9	%	$	144,178	$	134,215	7	%
Production and operating expenses per boe:
Heavy oil	$	12.28	$	12.74	(4	)%	$	12.07	$	13.30	(9	)%
Light oil, NGL and natural gas	$	12.42	$	13.61	(9	)%	$	13.89	$	13.78	1	%
Total	$	12.32	$	12.97	(5	)%	$	12.58	$	13.43	(6	)%

Production and operating expenses for the three months ended June 30, 2014 increased to $75.3 million from $69.0 million for the same period in 2013. This increase is due to higher production volumes offset by lower costs per unit of production. Production and operating expenses decreased to $12.32/boe for the three months ended June 30, 2014 compared to $12.97/boe for the same period in 2013, primarily due to the inclusion of the Aurora assets which had production and operating expenses of $4.65/boe in the period since acquisition, lowering the total average cost by $0.77/boe. This was offset by higher fuel and electricity costs due to increasing prices for natural gas.

Production and operating expenses for the six months ended June 30, 2014 increased to $144.2 million from $134.2 million for the same period in 2013. This increase is due to higher production volumes offset by lower costs per unit of production. Production and operating expenses decreased to $12.58/boe for the six months ended June 30, 2014 compared to $13.43/boe for the same period in 2013, primarily due to the acquisition of Aurora which decreased overall production and operating expenses by $0.22/boe, as well as decreased repairs and maintenance and fluid hauling costs, partially offset by higher fuel and electricity costs. Repairs and maintenance costs and fluid hauling costs have decreased, in part, due to capital investments made in the U.S. and Peace River areas in 2013.

Transportation and Blending Expenses

Transportation expenses include the costs to move the production from the field to the sales point. The largest component of transportation expense relates to the movement of heavy oil to pipeline and rail delivery terminals. The heavy oil produced by Baytex requires blending to reduce its viscosity in order to meet pipeline specifications and to facilitate its marketing. The cost of blending diluent is recovered in the sale price of the blended product. Product transported by rail does not require blending diluent.

The following table compares our blending and transportation expenses for the three and six months ended June 30, 2014 and 2013, expressed in dollars and per BOE:



	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for % and per boe)	2014		2013		Change		2014		2013		Change
Blending expenses	$	17,481	$	19,717	(11	)%	$	37,717	$	45,382	(17	)%
Transportation expenses	22,256		21,723		2	%	46,923		42,194		11	%
Total transportation and blending expenses	$	39,737	$	41,440	(4	)%	$	84,640	$	87,576	(3	)%
Transportation expenses per boe⁽¹⁾:
Heavy oil	$	4.77	$	5.32	(10	)%	$	5.30	$	5.56	(5	)%
Light oil, NGL and natural gas	$	1.14	$	0.74	54	%	$	0.96	$	0.68	41	%
Total	$	3.64	$	4.08	(11	)%	$	4.09	$	4.22	(3	)%


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

Blending expenses for the three months ended June 30, 2014 decreased 11% from the same period in 2013 due to lower volumes of condensate being required due to increased rail volumes, partially offset by higher per barrel costs of condensate. In the second quarter of 2014, blending expenses were $17.5 million for the purchase of 1,679 bbl/d of condensate at $114.45/bbl, compared to $19.7 million for the purchase of 2,128 bbl/d at $101.82/bbl for the same period last year. In the first six months of 2014, blending expenses were $37.7 million for the purchase of 1,851 bbl/d of condensate at $112.58/bbl, compared to $45.4 million for the purchase of 2,403 bbl/d at $104.34/bbl for the same period last year. The decrease in blending expenses for the three and six months ended June 30, 2014, as compared to the same period in 2013, is due to higher volumes of heavy oil being transported by rail.

Transportation expenses increased by 2% and 11% for the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013, due to higher sales volumes offset by lower average per unit transportation expense. For the three and six months ended June 30, 2014, transportation expenses per boe decreased 11% and 3% to $3.64/boe and $4.09/boe, respectively,

Baytex Energy Corp.

Q2 2014 MD&A Page 7

compared to $4.08/boe and $4.22/boe for the three and six month periods ended June 30, 2013, mainly due to shorter distance hauls and decreased wait times at the rail terminals.

Operating Netback



	Three Months Ended June 30							Six Months Ended June 30
($ per boe except for % and volume)	2014			2013		Change		2014			2013		Change
Sales volume (boe/d)	67,191			58,440		15	%	63,340			55,212		15	%
Operating netback⁽¹⁾:
Sales price	$	75.06		$	60.42	24	%	$	71.92		$	56.90	26	%
Less:
Royalties	18.36			11.66		57	%	16.33			10.74		52	%
Production and operating expenses	12.32			12.97		(5	)%	12.58			13.43		(6	)%
Transportation expenses	3.64			4.08		(11	)%	4.09			4.22		(3	)%
Operating netback before financial derivatives	$	40.74		$	31.71	28	%	$	38.92		$	28.51	37	%
Financial derivatives (loss) gain⁽²⁾	(2.28		)	1.62				(1.35		)	1.65
Operating netback after financial derivatives (loss) gain	$	38.46		$	33.33	15	%	$	37.57		$	30.16	25	%


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


(2)	Financial derivatives reflect realized gains on commodity related contracts only and exclude the impact of interest rate swaps.

Evaluation and Exploration Expense

Evaluation and exploration expense includes the write off of undeveloped lands and assets.

Evaluation and exploration expense for the three months ended June 30, 2014 increased to $3.9 million from $2.0 million for the same period in 2013 due to an increase in the expiration of undeveloped land leases.

Evaluation and exploration expense for the six months ended June 30, 2014 increased to $14.5 million from $5.6 million for the same period in 2013 due to both an increase in the expiration of undeveloped land leases and the impairment of evaluation and exploration assets that will not be developed.

Depletion and Depreciation

Depletion and depreciation for the three and six months ended June 30, 2014 increased to $99.6 million and $188.2 million, respectively, from $86.5 million and $165.1 million for the same periods in 2013 due to overall higher production volumes. On a sales-unit basis, the provisions for the three and six months ended June 30, 2014 were $16.56/boe and $16.41/boe, respectively, compared to $16.29/boe and $16.52/boe for the same periods in 2013. The provision related to Aurora for the second quarter of 2014 was $26.23/boe reflecting the inclusion of the fair value of the acquired assets in the depletable pool. On a sales-unit basis, the provisions excluding Aurora, for the three and six months ended June 30, 2014 were $15.29/boe and $15.91/boe, respectively, compared to $16.29/boe and $16.52/boe for the same periods in 2013. The decrease for both the three month and six month periods ended June 30, 2014 was primarily due to properties with higher depletion rates being disposed of in the second quarter of 2014, as well as the increase in the 2014 opening reserves compared to 2013 opening reserves.

General and Administrative Expenses



	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for % and per boe)	2014		2013		Change		2014		2013		Change
General and administrative expenses	$	14,309	$	10,540	36	%	$	26,208	$	22,090	19	%
General and administrative expenses per boe	$	2.34	$	1.98	18	%	$	2.29	$	2.21	4	%

General and administrative expenses for the three months ended June 30, 2014 increased to $14.3 million, as compared to $10.5 million in the second quarter of 2013, due to higher salaries and increased head count, lower capital recoveries consistent with lower capital spending and the addition of Aurora's general and administrative expenses, which contributed $0.8 million subsequent to the acquisition date. General and administrative expenses per boe increased to $2.34/boe in the second quarter of 2014, from $1.98/boe in the second quarter of 2013.

General and administrative expenses for the six months ended June 30, 2014 increased to $26.2 million, as compared to $22.1 million in the first half of 2013, mainly due to higher salaries and increased head count and lower capital recoveries consistent with lower

Baytex Energy Corp.

Q2 2014 MD&A Page 8

capital spending. General and administrative expenses per boe increased to $2.29/boe in the first half of 2014, from $2.21/boe in the first half of 2013.

Acquisition-related Costs

During the three and six months ended June 30, 2014, acquisition-related costs for the Aurora acquisition were $37.0 million, including legal, regulatory and advisory fees along with premiums paid on foreign currency hedges.

Share-based Compensation Expense

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

Compensation expense related to the Share Award Incentive Plan decreased to $8.2 million and $16.1 million for the three and six months ended June 30, 2013, respectively, from $9.8 million and $18.6 million in the three and six months ended June 30, 2013. This was mainly due to an increase in both actual forfeitures and the estimated future forfeiture rate on outstanding awards, as well as a decrease in the estimated payout multiplier.

Financing Costs

Financing costs include interest on bank loans and long-term debt, as well as non-cash charges related to accretion of asset retirement obligations and the amortization of financing expenses and debt issuance costs.



	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for %)	2014		2013		Change		2014		2013		Change
Bank loan and other	$	4,509	$	2,865	57	%	$	10,601	$	4,480	137	%
Long-term debt	11,252		7,732		46	%	16,008		15,394		4	%
Accretion on asset retirement obligations	1,779		1,690		5	%	3,520		3,350		5	%
Debt financing costs	57		2,117		(97	)%	57		2,156		(97	)%
Financing costs	$	17,597	$	14,404	22	%	$	30,186	$	25,380	19	%

Financing costs for the three months ended June 30, 2014 increased to $17.6 million from $14.4 million in the second quarter of 2013. Financing costs for the six months ended June 30, 2014 increased to $30.2 million from $25.4 million in the same period in 2013. The increases in financing costs for the three and six months ended June 30, 2014 were primarily due to higher outstanding debt levels compared to the same periods in 2013, partially offset by no amendment fees being incurred in 2014 on the credit facilities of Baytex Energy Ltd.

Foreign Exchange

Unrealized foreign exchange gains and losses are due to translation of the U.S. dollar denominated long-term debt and bank loans caused by the movement of the Canadian dollar against the U.S. dollar during the period. Realized foreign exchange gains and losses are due to our day-to-day U.S. dollar denominated transactions.



	Three Months Ended June 30								Six Months Ended June 30
($ thousands except for % and exchange rates)	2014			2013			Change		2014			2013			Change
Unrealized foreign exchange (gain) loss	$	(21,379	)	$	4,919		(535	)%	$	(14,923	)	$	8,736		(271	)%
Realized foreign exchange loss (gain)	2,924			(1,565		)	(287	)%	986			(3,601		)	(127	)%
Foreign exchange (gain) loss	$	(18,455	)	$	3,354		(650	)%	$	(13,937	)	$	5,135		(371	)%
CAD/USD exchange rates:
At beginning of period	1.1053			1.0156					1.0636			0.9949
At end of period	1.0676			1.0512					1.0676			1.0512

The unrealized foreign exchange gains of $21.4 and $14.9 million for the three and six months ended June 30, 2014, respectively, were mainly the result of the stronger Canadian dollar against the U.S. dollar at June 30, 2014 as compared to the issue date of the US$800 million notes.

Baytex Energy Corp.

Q2 2014 MD&A Page 9

Income Taxes

For the three and six months ended June 30, 2014, deferred income tax expense was $19.7 million and $40.1 million, respectively, as compared to $14.0 million and $17.8 million for the three and six months ended June 30, 2013.

When compared to the prior period, the increase in deferred income tax expense is primarily the result of an increase in the amount of tax pool claims required to shelter the increased taxable income in the six months ended June 30, 2014 compared to same period in 2013.

Net Income

Net income for the three months ended June 30, 2014 was $36.8 million, compared to net income of $36.2 million for the same period in 2013. The increase in net income was due to higher operating netbacks, higher foreign exchange gains, gains on dispositions in the current quarter and lower share-based compensation, partially offset by costs incurred related to the acquisition, higher depletion expense, financial derivative losses and higher income taxes.

Net income for the six months ended June 30, 2014 was $84.6 million, compared to net income of $46.3 million for the same period in 2013. The increase in net income was due to higher operating netbacks and lower share-based compensation, partially offset by costs incurred related to the acquisition of Aurora, the loss on financial derivative contracts and higher depletion and deferred income tax expenses.

Other Comprehensive Income

Other comprehensive income is comprised of the foreign currency translation adjustment on U.S. operations not recognized in profit or loss. The $45.6 million balance of accumulated other comprehensive income at June 30, 2014 relates to a $1.5 million foreign currency translation gain accumulated to December 31, 2013 combined with a $47.1 million foreign currency translation loss related to the six months ended June 30, 2014. The increased translation gain is primarily due to the strengthening of the Canadian dollar against the U.S. dollar at June 30, 2014, compared to closing date of the acquisition of Aurora on June 11, 2014.

Capital Expenditures

Capital expenditures for the three and six months ended June 30, 2014 and 2013 are summarized as follows:



	Three Months Ended June 30					Six Months Ended June 30
($ thousands)	2014		2013			2014		2013
Land	$	1,822	$	2,415		$	3,212	$	5,400
Seismic	774		208			1,166		766
Drilling and completion	90,559		122,425			224,017		241,170
Equipment	55,761		52,786			92,946		96,992
Other	—		—			—		28
Total exploration and development	$	148,916	$	177,834		$	321,341	$	344,356
Total acquisitions, net of divestitures	2,920,845		(1,796		)	2,921,518		(23,227		)
Total oil and natural gas expenditures	3,069,761		176,038			3,242,859		321,129
Other plant and equipment, net	5,313		1,350			6,070		4,720
Total capital expenditures	$	3,075,074	$	177,388		$	3,248,929	$	325,849

During the three months ended June 30, 2014, we drilled 28.3 net wells, compared to 25.8 net wells in the three months ended June 30, 2013. During the six months ended June 30, 2014, we drilled 147.4 net wells, compared to 135.6 net wells in the six months ended June 30, 2013. In 2014, capital investment activity has progressed as planned in our key development areas. 90% of the wells drilled were heavy oil focused.

In the second quarter, we completed the swap of assets on a non-cash basis by disposing of assets in the Saskatchewan heavy oil area in exchange for acquired assets in the Peace River area. The assets exchanged were comparable in terms of value and current production volumes. A gain of $18.7 million was recognized in the three and six months ended June 30, 2014 in respect of the disposed assets.

Total acquisitions, net of divestitures of $2.9 million for the three months ended June 30, 2014 include the acquisition of Aurora for approximately $2.8 billion which closed in the quarter. See "Business Combination" for further details on the acquisition. The acquisition is reported at estimated fair value of the assets acquired.

Baytex Energy Corp.

Q2 2014 MD&A Page 10

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 DRIP) divided by funds from operations. Baytex considers these to be key measures of performance as they demonstrate our ability to generate the cash flow necessary to fund dividends and capital investments.

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



	Three Months Ended						Six Months Ended
($ thousands except for %)	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Cash flow from operating activities	$	152,087		$	160,306		$	273,696		$	255,480
Change in non-cash working capital	25,960			6,776			81,938			19,558
Asset retirement expenditures	2,992			1,273			6,888			4,246
Financing costs	(17,597		)	(14,404		)	(30,186		)	(25,380		)
Accretion on asset retirement obligations	1,779			1,690			3,520			3,350
Accretion on notes and long-term debt	281			163			456			322
Funds from operations	$	165,502		$	155,804		$	336,312		$	257,576
Dividends declared	$	95,467		$	81,432		$	178,724		$	162,391
Reinvested dividends	(20,070		)	(21,106		)	(39,886		)	(45,616		)
Cash dividends declared (net of DRIP)	$	75,397		$	60,326		$	138,838		$	116,775
Payout ratio⁽¹⁾	58		%	52		%	53		%	63		%
Payout ratio (net of DRIP)⁽¹⁾	46		%	39		%	41		%	45		%

(1) Payout ratio, excluding acquisition related costs was 47% (37% net of DRIP) for the three months ended June 30, 2014 and 48% (37% net of DRIP) for the six months ended June 30, 2014.

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 maintain production. Due to the nature of reserve reporting, natural production declines and the risks involved in capital investment, we are unable 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 we would be required to reduce or eliminate dividends on our common shares in order to fund capital expenditures. There can be no certainty that we will be able to maintain current production levels in future periods. Cash dividends declared, net of DRIP participation, of $75.4 million and $138.8 million for the three and six months ended June 30, 2014 were funded by funds from operations of $165.5 million and $336.3 million respectively.

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.



($ thousands)	June 30, 2014		December 31, 2013
Bank loan	$	952,402	$	223,371
Long-term debt⁽¹⁾	1,329,487		459,540
Working capital deficiency⁽²⁾	178,517		79,151
Total monetary debt	$	2,460,406	$	762,062


(1)	Principal amount of instruments.


(2)	Working capital is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives, assets held for sale, and liabilities related to assets held for sale).

At June 30, 2014, total monetary debt was $2,460.4 million, as compared to $762.1 million at December 31, 2013. The increase in monetary debt at June 30, 2014 as compared to December 31, 2013 was primarily due to the acquisition of Aurora and exploration and development expenditures exceeding cash flow from operations during the first six months of the year.

Effective June 4, 2014 Baytex reached agreement with its bank lending syndicate to establish credit facilities for approximately $1.4 billion consisting of the following: (i) revolving extendible unsecured credit facilities consisting of a $50 million operating loan and a $950 million syndicated loan for Baytex and a US$200 million syndicated loan for our wholly-owned subsidiary, Baytex USA Oil & Gas, Inc., both of which have a four-year term (collectively, the "Revolving Facilities"); and (ii) a $200 million non-revolving unsecured syndicated loan with a two-year term (the "Non-Revolving Facility" and, together with the Revolving Facilities, the "Unsecured Facilities"). The Unsecured Facilities contain standard commercial covenants for facilities of this nature and the Revolving Facilities do not require any mandatory principal payments prior to maturity. At June 30, 2014, $952.4 million has been drawn on these Unsecured Facilities with $461.1 million remaining available. A copy of the credit agreement is accessible on the SEDAR website at www.sedar.com (filed under the category "Material Document" on June 11, 2014).

The following table lists the financial covenants under the Unsecured Facilities and the senior unsecured notes, and the compliance therewith as at June 30, 2014.



Covenant Description	Maximum Ratio	Position at June 30, 2014
Bank loan
Senior debt to capitalization^{(1) (2)}	0.50:1.00	0.46:1.00
Senior debt to Adjusted income^{(1) (5) (6)}	3.00:1.00	1.96:1.00
Debt to Adjusted income^{(3) (5) (6)}	4.00:1.00	1.98:1.00
Long-term debt
Fixed charge coverage^{(4) (5) (6)}	2:00:1.00	0.10:1.00


(1)	"Senior debt" is defined as the sum of our bank loan and principal amount of long-term debt.


(2)	"Capitalization" is defined as the sum of our bank loan, principal amount of long-term debt and shareholders' equity.


(3)	"Debt" is defined as the sum of our bank loan, the principal amount of long-term debt, and certain other liabilities identified in the credit agreement.


(4)	Fixed charge coverage is computed as the ratio of financing cost to trailing twelve month Adjusted income.


(5)	For purposes of the covenant calculations, Aurora's Adjusted income for the trailing twelve months has been included, in accordance with the terms of the credit agreements.


(6)	"Adjusted income" is calculated based on terms and definitions set out in the banking agreements which adjusts net income for financing costs, certain specific unrealized and non-cash transactions, acquisition and disposition activity and is calculated based on a trailing twelve month basis.

Adjusted income for the trailing twelve months ended June 30, 2014 was $1.16 billion.

In the event of a material acquisition, certain of the financial covenants are relaxed for up to two quarter ends following the closing of such material acquisition, provided that in each quarter: (i) the senior debt to capitalization ratio shall not exceed 0.55:1.00; (ii) the senior debt to Adjusted Income ratio shall not exceed 3.50:1.00; and (iii) the sole cause of such ratios exceeding the levels set forth above is due to the material acquisition. If we exceed any of the covenants under the Unsecured Facilities, we would be required to repay, refinance or renegotiate the loan terms and conditions which may restrict our ability to pay dividends to our shareholders.

The weighted average interest rate on the bank loan for the three and six months ended June 30, 2014 was 3.73% and 3.92%, respectively (three and six months ended June 30, 2013 - 5.09% and 5.31%, respectively).

On July 19, 2012, we issued $300 million principal amount of senior unsecured notes bearing interest at 6.625% payable semi-annually with principal repayable on July 19, 2022. On February 17, 2011, we issued US$150 million principal amount of senior unsecured notes bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021.

Pursuant to the acquisition of Aurora, Baytex assumed US$365 million of 9.875% senior unsecured notes due February 15, 2017 (the "2017 Notes") and US$300 million of 7.500% senior unsecured notes due April 1, 2020 (the "2020 Notes" and, together with the 2017 Notes, the "Notes").

On April 22, 2014, Baytex commenced a cash tender offer and consent solicitation for the Notes at a price (per $1,000 of principal amount) of US$1,107.34 for the 2017 Notes and US$1,138.97 for the 2020 Notes. Upon closing of the tender offers on June 11, 2014, Baytex purchased US$357.1 million (97.8% of total outstanding) of the 2017 Notes and US$293.6 million (97.9% of total outstanding) of the 2020 Notes, which have been cancelled. The remaining Notes are redeemable at the Company's option, in whole or in part, commencing on February 15, 2015 (in the case of the 2017 Notes) and April 1, 2016 (in the case of the 2020 Notes) at specified redemption prices.

On June 6, 2014, Baytex issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the "2021 Notes") and US$400 million of 5.625% notes due June 1, 2024 (the "2024 Notes"). The 2021 Notes and the 2024 Notes pay interest semi-annually and are redeemable at the Company's option, in whole or in part, commencing on June 1, 2017 (in the case of the 2021 Notes) and June 1, 2019 (in the case of the 2024 Notes) at specified redemption prices.

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 our senior unsecured notes and credit facilities.

We believe that our funds from operations, together with the existing credit facilities, will be sufficient to finance current operations, dividends to the shareholders and planned capital expenditures in 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 Event

On July 29, 2014, the Company signed an agreement with an oil and gas company to sell the North Dakota assets for approximately$357 million, effective July 1, 2014. We expect the net after-tax proceeds of approximately $275 million to be applied first to the Non-Revolving Facility in accordance with certain banking agreements and then to outstanding bank indebtedness. Production for the six months ended June 30, 2014 was 3,200 boe/d and proved and probable reserves at December 31, 2013 were estimated to be 53.5 million boe. The transaction is subject to standard terms and conditions and is expected to close near the end of the third quarter of 2014.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. The rights and terms of preferred shares are determined upon issuance. As at July 28, 2014, we had 166,068,926 common shares and no preferred shares issued and outstanding. During the second quarter of 2014, we converted 38,433,000 subscription receipts issued in February 2014 into 38,433,000 common shares upon closing of the acquisition of Aurora.

Contractual Obligations

We have 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 in an ongoing manner. A significant portion of these obligations will be funded by funds from operations. These obligations as of June 30, 2014 and the expected timing for funding these obligations is noted in the table below.



Operating leases	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	446,543	$	446,543	$	—	$	—	$	—
Dividends payable to shareholders	39,701		39,701		—		—		—
Bank loan⁽¹⁾	952,402		—		200,000		752,402		—
Long-term debt⁽²⁾	1,329,487		—		8,434		—		1,321,053
Operating leases	46,318		8,061		16,160		15,845		6,252
Processing agreements	92,259		10,663		21,808		13,795		45,993
Transportation agreements	73,116		11,233		19,858		18,005		24,020
Total	$	2,979,826	$	516,201	$	266,260	$	800,047	$	1,397,318


(1)	The bank loan is a covenant-based loan with a revolving portion that is extendible annually for up to a four year period and a non-revolving portion which matures on June 3, 2016. Unless extended, the revolving period will end on June 3, 2018, with all amounts to be re-paid on such date.


(2)	Principal amount of instruments.

We also have 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

Our normal operations expose us to a number of financial risks, including liquidity risk, credit risk and market risk. Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. We manage 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. Credit risk is managed by entering into sales contracts with creditworthy entities and reviewing our exposure to individual entities on a regular basis. 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 partially mitigated through a series of derivative contracts intended to reduce some of the volatility of our operating cash flow.

A summary of the risk management contracts in place as at June 30, 2014 and the accounting treatment thereof is disclosed in note 18 to the consolidated financial statements.

Baytex Energy Corp.

Q2 2014 MD&A Page 11

QUARTERLY FINANCIAL INFORMATION



	2014		2013				2012
($ thousands, except per common share amounts)	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Gross revenues	476,404	385,809	330,712	422,791	341,011	272,945	292,095	299,786
Net income	36,799	47,841	31,173	87,331	36,192	10,149	31,620	26,773
Per common share - basic	0.27	0.38	0.26	0.70	0.29	0.08	0.26	0.22
Per common share - diluted	0.27	0.38	0.25	0.70	0.29	0.08	0.26	0.22

Baytex Energy Corp.

Q2 2014 MD&A Page 12

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 but not limited to: the anticipated benefits from the acquisition of Aurora; our expectations that the Aurora assets have infrastructure in place that support future annual production growth; our expectations regarding the effect of well downspacing, improving completion techniques and new development targets on the reserves potential of the Aurora assets; crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; the royalty rate for the Aurora assets; 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; our business strategies, plans and objectives; our ability to fund our capital expenditures and dividends on our common shares from funds from operations; funding sources for our cash dividends and capital program; the timing of closing of the asset disposition; the estimated proceeds from the asset disposition; the intended use of proceeds from the asset disposition; 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: our ability to execute and realize on the anticipated benefits of the acquisition of Aurora; 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 for our operating activities; 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; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved 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: failure to realize the anticipated benefits of the acquisition of Aurora; declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; access to external sources of capital; third party credit risk; a downgrade of our credit ratings; risks associated with the exploitation of our properties and our ability to acquire reserves; increases in operating costs; changes in government regulations that affect the oil and gas industry; changes to royalty or mineral/severance tax regimes; risks relating to hydraulic fracturing; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; expansion of our operations; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the activities of our operating entities and their key personnel and information systems; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonal weather patterns; our permitted investments; access to technological advances; changes in the demand for oil and natural gas products; involvement in legal, regulatory and tax proceedings; the failure of third parties to comply with confidentiality agreements; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond the control of Baytex. These and additional 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, 2013, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

Baytex Energy Corp.

Q2 2014 MD&A Page 13

The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.

There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements 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.