Baytex Energy 6K Condensed Consolidated Statements of Financial Position | BTE 2 Nov 18

Baytex Energy Corp.

Q3 2018 MD&A Page 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2018 and 2017

Dated November 1, 2018

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for

the three and nine months ended September 30, 2018. This information is provided as of November 1, 2018. 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 results for the three and nine months ended September 30, 2018 ("Q3/2018" and "YTD 2018") have been compared with the results for the three and nine months ended September 30, 2017 ("Q3/2017" and "YTD 2017"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim unaudited financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 2018, its audited comparative consolidated financial statements for the years ended December 31, 2017 and 2016, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2017. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated.

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 along with certain measures which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). We refer you to the advisory on forward-looking information and statements and a summary of our non-GAAP measures at the end of our MD&A.

THIRD QUARTER HIGHLIGHTS

Business combination

On August 22, 2018, Baytex and Raging River Exploration Inc. ("Raging River") completed the strategic combination of the two companies (the "Strategic Combination") by way of a plan of arrangement whereby Baytex acquired all of the issued and outstanding common shares of Raging River. The Strategic Combination increases our light oil exposure while improving our leverage ratios and increasing operational control of our properties. Production from Raging River's properties is approximately 90% weighted towards high netback light oil. The Strategic Combination has also strengthened our balance sheet and resulted in a decrease in our net debt to Bank EBITDA ratio to 2.3 for Q3/2018 compared to a ratio of 4.4 in Q2/2018. The addition of the primarily operated assets to our portfolio increases our inventory of drilling prospects and increases our ability to effectively allocate capital.

Operating and financial results include Raging River operations from the closing date of August 22, 2018. Production from the properties averaged approximately 23,750 boe/d between closing and September 30, 2018 which contributed 10,300 boe/d and 3,500 boe/d of average daily production to Q3/2018 and YTD 2018, respectively. The Companies began integration in Q3/2018 and operations have continued in-line with expectations for both the legacy Baytex and Raging River assets. Baytex issued 315.3 million common shares and assumed Raging River's net debt of approximately $363.6 million million at closing of the transaction.

Third quarter operating and financial results

Baytex delivered strong operating and financial results during Q3/2018. We generated adjusted funds flow of $171.2 million which exceeded our investment on exploration and development activities of $139.2 million by $32.0 million. Average daily production of 82,412 boe/d was 17% higher compared to 70,664 boe/d for Q2/2018 and 19% higher than 69,310 boe/d reported for Q3/2017. The increase reflects the production contribution from the Strategic Combination along with strong well performance in both our legacy Canadian and U.S operations.

We invested $94.5 million on exploration and development activities in Canada during Q3/2018 compared to $30.6 million in Q2/2018 and $14.5 million in Q3/2017. We had an active capital program in Canada which was focused on our heavy oil properties at Peace River and Lloydminster along with our Viking and Duvernay light oil properties. The production contribution from the Strategic Combination combined with strong well performance resulted in average production of 45,214 boe/d during Q3/2018 which is 33% higher than 34,042 boe/d for Q2/2018 and 31% higher than 34,560 boe/d for Q3/2017.

In the U.S., we invested $44.7 million on exploration and development activity during Q3/2018 and drilled 29 (8.0 net) wells and commenced production from 26 (4.9 net) wells. We continue to see strong well performance from enhanced completions techniques utilizing higher proppant loading and increased frac stages in 2018 compared to 2017. Wells that commenced production during Q3/2018 have established 30-day initial gross production rates of approximately 1,600 boe/d per well. U.S production of 37,198 boe/

Baytex Energy Corp.

Q3 2018 MD&A Page 2

d for Q3/2018 increased from 36,622 boe/d for Q2/2018 and 34,750 boe/d for Q3/2017 due to strong well performance for wells brought online during YTD 2018.

During 2018, strong global oil demand along with ongoing production curtailments by the Organization of Petroleum Exporting Countries ("OPEC") resulted in further reductions in global crude oil inventories. The West Texas Intermediate ("WTI") benchmark oil price averaged US$69.50/bbl for Q3/2018 which is an increase of 44% from US$48.20/bbl for Q3/2017. The LLS benchmark price continued to improve relative to WTI a result of higher global crude oil pricing and traded at a US$5.75/bbl premium to WTI in Q3/2018 compared to a US$2.07/bbl premium in Q3/2017. The improvement in WTI market prices was partially offset by wider light and heavy oil differentials in Canada and resulted in a 45% increase in our realized sales price to $55.03/boe in Q3/2018 from $38.04/boe in Q3/2017. The ongoing lack of takeaway capacity for light and heavy grades of Canadian crude oil combined with increasing crude oil production in Western Canada resulted in a widening of the price differential for Canadian oil relative to WTI. The Edmonton par oil price traded at a US$6.82/boe discount to WTI during Q3/2018 compared to a discount of US$2.89/bbl during Q3/2017 while the Canadian heavy oil price differential to WTI widened to US$22.25/bbl in Q3/2018 from US$9.94/bbl in Q3/2017.

We generated adjusted funds flow of $171.2 million for Q3/2018, an increase of $93.8 million from adjusted funds flow of $77.3 million reported for Q3/2017. Stronger realized pricing combined with the increase in average daily production resulted in an operating netback of $238.1 million for Q3/2018 which was $124.4 million higher than Q3/2017. Higher realized prices and production resulted in a $174.7 million increase in total sales, net of blending and other expense, relative to Q3/2017. This was offset by $50.3 million from higher royalties with increased revenue and by higher operating and transportation expense from increased production. The increase in operating netback was offset by realized hedging losses of $30.9 million in Q3/2018 as compared to gains of $2.8 million for Q3/2017. Net income was $27.4 million for Q3/2018 reflecting our strong operating and financial results for the quarter.

At September 30, 2018, net debt was $2,112.1 million, an increase of $377.8 million from $1,734.3 million at December 31, 2017. The increase is primarily due to the $363.6 million of net debt assumed on closing of the Strategic Combination in Q3/2018. Despite the increase in net debt, our net debt to Bank EBITDA ratio has decreased to 2.3 due to the Strategic Combination and the inclusion of the Raging River EBITDA on a trailing basis.

Baytex Energy Corp.

Q3 2018 MD&A Page 3

RESULTS OF OPERATIONS

The Canadian operating segment includes our light oil assets in Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford assets in Texas.

Production



	Three Months Ended September 30
	2018						2017
Daily Production	Canada		U.S.		Total		Canada		U.S.		Total
Liquids (bbl/d)
Light oil and condensate	9,894		19,837		29,731		1,245		18,796		20,041
Heavy oil	27,036		—		27,036		26,161		—		26,161
Natural Gas Liquids (NGL)	1,096		8,980		10,076		1,126		7,814		8,940
Total liquids (bbl/d)	38,026		28,817		66,843		28,532		26,610		55,142
Natural gas (mcf/d)	43,127		50,287		93,414		36,164		48,842		85,006
Total production (boe/d)	45,214		37,198		82,412		34,560		34,750		69,310

Production Mix
Light oil and condensate	22	%	53	%	36	%	4	%	54	%	29	%
Heavy oil	60	%	—	%	33	%	76	%	—	%	38	%
NGL	2	%	24	%	12	%	3	%	23	%	13	%
Natural gas	16	%	23	%	19	%	17	%	23	%	20	%



	Nine Months Ended September 30
	2018						2017
Daily Production	Canada		U.S.		Total		Canada		U.S.		Total
Liquids (bbl/d)
Light oil and condensate	3,898		20,067		23,965		1,258		20,085		21,343
Heavy oil	25,824		—		25,824		25,454		—		25,454
Natural Gas Liquids	1,202		8,347		9,549		1,063		7,919		8,982
Total liquids (bbl/d)	30,924		28,414		59,338		27,775		28,004		55,779
Natural gas (mcf/d)	40,232		49,217		89,449		37,502		50,664		88,166
Total production (boe/d)	37,629		36,617		74,246		34,025		36,448		70,473

Production Mix
Light oil and condensate	10	%	55	%	32	%	4	%	55	%	30	%
Heavy oil	69	%	—	%	35	%	75	%	—	%	36	%
NGL	3	%	23	%	13	%	3	%	22	%	13	%
Natural gas	18	%	22	%	20	%	18	%	23	%	21	%

We reported average production of 82,412 boe/d for Q3/2018 and 74,246 boe/d for YTD 2018 compared to 69,310 boe/d in Q3/2017 and 70,473 boe/d in YTD 2017. The increase in production for Q3/2018 and YTD 2018 compared to the same periods of 2017 is primarily due to the Strategic Combination which closed on August 22, 2018 and added approximately 10,300 boe/d to Q3/2018 production and 3,500 boe/d to YTD 2018 production.

Average daily production in Canada was 45,214 boe/d for Q3/2018 and 37,629 boe/d for YTD 2018 compared to 34,560 boe/d in Q3/2017 and 34,025 boe/d for YTD 2017. The increase in production in 2018 relative to 2017 is primarily due to the production contribution from the Strategic Combination. Production from our Viking and Duvernay properties consists of approximately 90% light oil which resulted in a higher portion of our Canadian production being comprised of light oil in 2018 relative to 2017. Canadian results, excluding the Strategic Combination, for Q3/2018 and YTD 2018 were in line with expectations and relatively consistent with the same periods of 2017.

Baytex Energy Corp.

Q3 2018 MD&A Page 4

In the U.S., production averaged 37,198 boe/d for Q3/2018 and 36,617 boe/d for YTD 2018. Strong well performance from 85 (17.9 net) wells that commenced production during YTD 2018 resulted in average daily production that was consistent with 36,448 boe/d in YTD 2017 when 90 (23.3 net) wells were brought on production. Improved well productivity contributed to the increase in daily production to 37,198 boe/d for Q3/2018 compared to 34,750 boe/d for Q3/2017 which was also impacted by an estimated 1,500 boe/d of downtime associated with Hurricane Harvey.

Our production of 74,246 boe/d for YTD 2018 increased from 70,473 boe/d reported for YTD 2017 primarily from the Strategic Combination. We expect our annual production for 2018 to be in line with our updated annual guidance range of 79,000 to 80,000 boe/d.

Commodity Prices

The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and our financial position.

Crude Oil

Global benchmark prices for crude oil continued to strengthen into Q3/2018 as robust global demand and ongoing OPEC production curtailments continue to reduce global inventory levels. We compare our liquids pricing to the WTI benchmark oil price which is the representative index for inland North American light oil at Cushing, Oklahoma. The WTI benchmark price averaged US$69.50/bbl during Q3/2018, representing an increase of 44% compared to Q3/2017 when the benchmark price averaged US$48.20/bbl. During YTD 2018, the WTI benchmark price averaged US$66.75/bbl representing a 35% increase relative to an average of US$49.46/bbl during the same period of 2017.

Our U.S. crude oil production is primarily priced off the Louisiana Light Sweet ("LLS") stream at St. James, Louisiana, which is the representative benchmark for light oil pricing at the U.S. Gulf coast. The LLS benchmark price remained strong during Q3/2018 averaging US$75.25/bbl which is 50% higher than US$50.27/bbl during Q3/2017. The LLS benchmark price continued to improve relative to WTI during YTD 2018 as a result of higher global crude oil pricing. During YTD 2018, LLS averaged US$71.24/bbl, which is a premium of US$4.49/bbl relative to WTI, compared to US$50.82/bbl or a US$1.36/bbl premium to WTI for the same period of 2017.

Benchmark prices for Canadian light and heavy grades of crude oil improved in 2018 relative to 2017 but traded at a wider discount to WTI due to ongoing pipeline capacity constraints, a lack of rail transport capacity and increasing Western Canadian crude oil production. We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $81.92/bbl in Q3/2018 and $78.19/bbl for YTD 2018 compared to $56.74/bbl in Q3/2017 and $60.87/bbl for YTD 2017. During YTD 2018, Edmonton par traded at a US$6.03/bbl discount to WTI compared to a US$2.88/boe discount for the same period of 2017. The price received for our heavy oil production in Canada is based on the Western Canadian Select ("WCS") benchmark price which is the representative benchmark for heavy grades of crude oil in Western Canada. The WCS heavy oil differential to WTI averaged US$22.25/bbl in Q3/2018 and US$21.93/bbl in YTD 2018 as compared to US$9.94/bbl and US$11.87/bbl for the same periods of 2017.

Natural Gas

North American natural gas prices were lower during YTD 2018 relative to YTD 2017 as natural gas supply growth outpaced growth in demand. Canadian natural gas prices remained challenged during YTD 2018 as a lack of egress in Western Canada continues to impact natural gas prices in the region. Increasing supply from U.S. shale production has resulted in a decline in U.S. natural gas benchmark prices during YTD 2018 as compared to YTD 2017.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. During Q3/2018 and YTD 2018, the NYMEX natural gas benchmark averaged US$2.90/mmbtu representing a 3% and 9% decrease from the same periods in 2017.

In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a significant discount to NYMEX as a result of increasing supply and limited market access for Canadian natural gas production. The benchmark averaged $1.35/mcf during Q3/2018 and $1.41/mcf during YTD 2018 which is 34% and 45% lower than the benchmark averages of $2.04/mcf and $2.58/mcf during the comparative periods in 2017.

Baytex Energy Corp.

Q3 2018 MD&A Page 5

The following tables compare selected benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30						Nine Months Ended September 30
	2018		2017		Change		2018		2017		Change
Benchmark Averages
WTI oil (US$/bbl)⁽¹⁾	69.50		48.20		44	%	66.75		49.46		35	%
WTI oil (CAD$/bbl)	90.84		60.37		50	%	85.96		64.63		33	%
WCS heavy oil differential (US$/bbl)	(22.25	)	(9.94	)	124	%	(21.93	)	(11.87	)	85	%
WCS heavy oil differential (CAD$/bbl)	(29.08	)	(12.45	)	134	%	(28.25	)	(15.52	)	82	%
WCS heavy oil (US$/bbl)⁽²⁾	47.25		38.26		23	%	44.82		37.59		19	%
WCS heavy oil (CAD$/bbl)	61.76		47.92		29	%	57.71		49.11		18	%
LLS oil (US$/bbl)⁽³⁾	75.25		50.27		50	%	71.24		50.82		40	%
LLS oil (CAD$/bbl)	98.35		62.96		56	%	91.74		66.41		38	%
CAD/USD average exchange rate	1.3070		1.2524		4	%	1.2877		1.3067		(1	)%
Edmonton par oil ($/bbl)	81.92		56.74		44	%	78.19		60.87		28	%
AECO natural gas price ($/mcf)⁽⁴⁾	1.35		2.04		(34	)%	1.41		2.58		(45	)%
NYMEX natural gas price (US$/mmbtu)⁽⁵⁾	2.90		3.00		(3	)%	2.90		3.17		(9	)%


(1)	WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.


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


(3)	LLS refers to the Argus trade month average for Louisiana Light Sweet oil.


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


(5)	NYMEX refers to the NYMEX last day average index price as published by the CGPR.



	Three Months Ended September 30
	2018						2017
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices⁽¹⁾
Light oil and condensate ($/bbl)	$	76.42	$	93.37	$	87.73	$	52.57	$	58.59	$	58.22
Heavy oil ($/bbl)⁽²⁾	48.15		—		48.15		38.18		—		38.18
NGL ($/bbl)	41.11		36.93		37.38		25.06		25.20		25.18
Natural gas ($/mcf)	1.21		3.90		2.66		1.72		3.76		2.89
Weighted average ($/boe)⁽²⁾	$	47.66	$	63.98	$	55.03	$	33.41	$	42.64	$	38.04



	Nine Months Ended September 30
	2018						2017
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices⁽¹⁾
Light oil and condensate ($/bbl)	$	75.08	$	86.90	$	84.98	$	54.77	$	61.13	$	60.75
Heavy oil ($/bbl)⁽²⁾	43.95		—		43.95		37.29		—		37.29
NGL ($/bbl)	35.33		31.37		31.87		27.70		24.24		24.65
Natural gas ($/mcf)	1.39		3.80		2.72		2.35		4.09		3.35
Weighted average ($/boe)⁽²⁾	$	40.56	$	59.89	$	50.09	$	33.37	$	44.64	$	39.20


(1)	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 this table excludes the impact of financial derivatives.


(2)	Realized heavy oil prices are calculated based on sales volumes and sales dollars, net of blending and other expense.

Baytex Energy Corp.

Q3 2018 MD&A Page 6

Average Realized Sales Prices

Our weighted average sales price was $50.09/boe for YTD 2018, up $10.89/boe from $39.20/boe for the first nine months of 2017. The increase is primarily a result of higher crude oil pricing in 2018 relative to 2017 which helped to increase the weighted average sales price for our production in the U.S. and Canada. Our realized pricing has also improved following the Strategic Combination which resulted in a higher proportion of our Canadian production being higher value light oil from our Viking and Duvernay properties.

In Canada, our realized light oil and condensate price of $76.42/bbl for Q3/2018 and $75.08/bbl for YTD 2018 increased from $52.57/bbl for Q3/2017 and $54.77/bbl for YTD 2017, due to the increase in market prices for crude oil over the same periods. The increase in our realized light oil pricing for Q3/2018 and YTD 2018 also reflects light oil production from our Viking and Duvernay properties which produce a higher quality light oil and achieves stronger price realizations than our pre-existing Canadian properties. As a result, the increase in our realized light oil and condensate price for Q3/2018 and YTD 2018 was higher than the increase in Edmonton par pricing relative to the same periods of 2017.

Our realized Canadian heavy oil sales price, net of blending and other expense, averaged $48.15/bbl for Q3/2018 and $43.95/bbl for YTD 2018 which is $9.97/bbl and $6.66/bbl higher than realized pricing of $38.18/bbl for Q3/2017 and $37.29/bbl for YTD 2017. Our Canadian heavy oil production is blended with diluent in order to meet pipeline transportation specifications. The price received for the blended product is recorded as heavy oil sales revenue while the cost of blending diluent is recorded as blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark. The increase in our realized heavy oil sale price, net of blending and other expense, is primarily due to the $13.84/bbl and $8.60/bbl increase in the WCS benchmark in Q3/2018 and YTD 2018 relative to the same periods of 2017. Our realized heavy oil price in 2018 did not increase as much as the WCS benchmark price as the cost of blending diluent has increased more than the increase in the benchmark price.

In the U.S., our realized light oil and condensate price was $93.37/bbl for Q3/2018 and $86.90/bbl for YTD 2018 compared to $58.59/bbl for Q3/2017 and $61.13/bbl for YTD 2017. The $34.78/bbl and $25.77/bbl increase in our realized light oil and condensate pricing for Q3/2018 and YTD 2018 was consistent with the increase in the LLS benchmark price (expressed in Canadian dollars) of $35.39/bbl and $25.33/bbl since the same periods of 2017.

For Q3/2018, our realized NGL price was $37.38/bbl or 41% of WTI (expressed in Canadian dollars) compared to $25.18/bbl or 41% of WTI in Q3/2017. Our realized NGL price for YTD 2018 was $31.87/bbl or 35% of WTI (expressed in Canadian dollars) relative to $24.65/bbl or 38% of WTI for YTD 2017. Our realized price as a percentage of WTI can vary from period to period based on the product mix of our NGL volumes and changes in the market prices of the underlying products.

Our realized natural gas price in Canada was $1.21/mcf for Q3/2018 and $1.39/mcf for YTD 2018 compared to realized pricing of $1.72/mcf in Q3/2017 and $2.35/mcf in YTD 2017. The decrease is primarily due to lower AECO benchmark pricing in Q3/2018 and YTD 2018 relative to the comparative periods. A portion of our Canadian natural gas sales are referenced to the AECO daily index which was higher throughout YTD 2018 relative to the AECO monthly average index. Accordingly, our realized sales price for Q3/2018 and YTD 2018 decreased by $0.51/mcf and $0.96/mcf relative to a $0.69/mcf and $1.17/mcf decrease in the AECO monthly average relative to the same periods of 2017.

Our U.S. realized natural gas price was $3.90/mcf in Q3/2018 and $3.80/mcf for YTD 2018 compared to $3.76/mcf for Q3/2017 and $4.09/mcf for YTD 2017. The change in our realized pricing reflects changes in the NYMEX natural gas benchmark (expressed in Canadian dollars) which was was $0.03/mcf higher in Q3/2018 relative to Q3/2017 and $0.41/mcf lower in YTD 2018 relative to YTD 2017.

Petroleum and Natural Gas Sales



	Three Months Ended September 30
	2018								2017
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	69,557		$	170,402	$	239,959		$	6,024		$	101,320	$	107,344
Heavy oil	139,305			—		139,305			107,972			—		107,972
NGL	4,147			30,508		34,655			2,596			18,116		20,712
Total liquids sales	213,009			200,910		413,919			116,592			119,436		236,028
Natural gas sales	4,796			18,046		22,842			5,715			16,877		22,592
Total petroleum and natural gas sales	217,805			218,956		436,761			122,307			136,313		258,620
Blending and other expense	(19,548		)	—		(19,548		)	(16,069		)	—		(16,069		)
Total sales, net of blending and other expense	$	198,257		$	218,956	$	417,213		$	106,238		$	136,313	$	242,551

Baytex Energy Corp.

Q3 2018 MD&A Page 7



	Nine Months Ended September 30
	2018								2017
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	79,894		$	476,086	$	555,980		$	18,808		$	335,190	$	353,998
Heavy oil	364,957			—		364,957			301,663			—		301,663
NGL	11,595			71,480		83,075			8,040			52,395		60,435
Total liquids sales	456,446			547,566		1,004,012			328,511			387,585		716,096
Natural gas sales	15,296			51,125		66,421			24,011			56,599		80,610
Total petroleum and natural gas sales	471,742			598,691		1,070,433			352,522			444,184		796,706
Blending and other expense	(55,077		)	—		(55,077		)	(42,554		)	—		(42,554		)
Total sales, net of blending and other expense	$	416,665		$	598,691	$	1,015,356		$	309,968		$	444,184	$	754,152

Total sales, net of blending and other expense, was $417.2 million for Q3/2018 which is an increase of $174.7 million or 72% from $242.6 million reported for Q3/2017. Higher average daily production in Q3/2018 was primarily a result of the incremental production from the Strategic Combination which increased sales by $67.0 million relative to Q3/2017. Improved commodity prices combined with a higher weighting of light oil production resulted in stronger realized pricing in Q3/2018 and increased sales by $107.7 million relative to the same period of 2017.

In Canada, total sales, net of blending and other expense, were $198.3 million for Q3/2018, up $92.0 million or 87% from $106.2 million in the same period of 2017. Average daily production in Canada was approximately 10,700 boe/d or 31% higher in Q3/2018 compared to the same quarter of 2017. The majority of the increase can be attributed to the 10,300 boe/d of incremental production associated with the Strategic Combination. A higher proportion of our Canadian production mix was light oil in Q3/2018 relative to Q3/2017 and, combined with the improvement in benchmark pricing, contributed to the $14.25/boe or 42% increase in our weighted average realized price.

Petroleum and natural gas sales of $219.0 million during Q3/2018 in the U.S. increased 61% or $82.6 million from $136.3 million reported for Q3/2017. The increase was driven by higher benchmark pricing which resulted in a $21.34/boe or 50% increase in our weighted average realized price for Q3/2018 compared to Q3/2017. Average daily production in the U.S. was also up approximately 2,400 boe/d or 7% in Q3/2018 due to strong well performance and the impact of Hurricane Harvey which reduced production for Q3/2017 by an estimated 1,500 boe/d.

Total sales, net of blending and other expense, of $1,015.4 million for YTD 2018 were $261.2 million or 35% higher than $754.2 million reported for the first nine months of 2017. Benchmark prices for crude oil have been higher during YTD 2018 which resulted in a 28% increase in our weighted averaged realized price and a $209.6 million increase in total sales, net of blending and other expense, relative to YTD 2017. Average daily production of 74,246 boe/d for YTD 2018 was higher compared to 70,473 boe/d for YTD 2017 primarily due to the 3,500 boe/d of incremental production from the Strategic Combination and resulted in a $51.6 million increase in total sales, net of blending and other expense.

Royalties

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects, and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30
	2018									2017
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	26,139		$	65,806		$	91,945		$	14,973		$	40,203		$	55,176
Average royalty rate⁽¹⁾	13.2		%	30.1		%	22.0		%	14.1		%	29.5		%	22.7		%
Royalty rate per boe	$	6.28		$	19.23		$	12.13		$	4.71		$	12.58		$	8.65


(1)	Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.



	Nine Months Ended September 30
	2018									2017
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	55,471		$	178,518		$	233,989		$	41,725		$	130,642		$	172,367
Average royalty rate⁽¹⁾	13.3		%	29.8		%	23.0		%	13.5		%	29.4		%	22.9		%
Royalty rate per boe	$	5.40		$	17.86		$	11.54		$	4.49		$	13.13		$	8.96


(1)	Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.

Total royalties for Q3/2018 were $91.9 million and averaged 22.0% of total sales, net of blending and other expense, which is higher than $55.2 million or 22.7% for Q3/2017. Total royalties were $234.0 million for YTD 2018 and averaged 23.0% of total sales, net of blending and other expense, as compared to $172.4 million and 22.9% reported for YTD 2017. Royalty expense is higher in 2018 due to higher total sales, net of blending and other expense, in Canada and the U.S. relative to 2017. The average royalty rate in Canada was lower following the Strategic Combination as the royalty rate on our Viking properties was approximately 9.6% for Q3/2018, resulting in a lower average royalty rate in Canada compared to Q3/2017. In the U.S., royalties for Q3/2018 and YTD 2018 averaged 30.1% and 29.8% of total petroleum and natural gas sales respectively, which is consistent with the comparative periods of 2017 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage. Our average royalty rate of 23.0% for YTD 2018 is slightly higher than our 2018 annual guidance of approximately 22.0%. We are maintaining annual guidance of approximately 22.0% for 2018 as we expect the lower royalty rate on production from the Strategic Combination to reduce our corporate average royalty rate through the remainder of 2018.

Operating Expense



	Three Months Ended September 30
	2018						2017
($ thousands except for per boe)	Canada		U.S.⁽¹⁾		Total		Canada		U.S.⁽¹⁾		Total
Operating expense	$	54,710	$	22,988	$	77,698	$	43,525	$	20,866	$	64,391
Operating expense per boe	$	13.15	$	6.72	$	10.25	$	13.69	$	6.53	$	10.10



	Nine Months Ended September 30
	2018						2017
($ thousands except for per boe)	Canada		U.S.⁽¹⁾		Total		Canada		U.S.⁽¹⁾		Total
Operating expense	$	147,054	$	66,681	$	213,735	$	132,908	$	66,538	$	199,446
Operating expense per boe	$	14.31	$	6.67	$	10.54	$	14.31	$	6.69	$	10.37


(1)	Operating expense related to the Eagle Ford assets includes transportation expense.

Operating expense of $10.25/boe for Q3/2018 and $10.54/boe for YTD 2018 is consistent with the low end our annual guidance range of $10.50 - $10.75/boe. Total operating expense was $77.7 million ($10.25/boe) for Q3/2018 and $213.7 million ($10.54/boe) for YTD 2018 compared to $64.4 million ($10.10/boe) for Q3/2017 and $199.4 million ($10.37/boe) for YTD 2017.

In Canada, operating expense was $54.7 million ($13.15/boe) for Q3/2018 and $147 million ($14.31/boe) for YTD 2018 compared to $43.5 million ($13.69/boe) for Q3/2017 and $132.9 million ($14.31/boe) for YTD 2017. Total operating expense in Canada has increased following the closing of the Strategic Combination as these properties contributed approximately $11.1 million of operating expense in Q3/2018. Per unit operating expense in Canada was slightly lower in Q3/2018 compared to Q3/2017 as per unit operating costs on our Viking and Duvernay properties are lower relative to our other Canadian properties. Total operating expense in Canada is higher in YTD 2018 compared to YTD 2017 due to costs incurred to support higher average daily production in YTD 2018 and operating expenses associated with our Viking and Duvernay properties.

U.S. operating expense of $23.0 million ($6.72/boe) for Q3/2018 and $66.7 million ($6.67/boe) for YTD 2018 was relatively consistent with $20.9 million ($6.53/boe) for Q3/2017 and $66.5 million ($6.69/boe) for YTD. The reported amount of our U.S. operating expense expressed in Canadian dollars changes with fluctuations in the CAD/USD exchange rate which was 1.2877 CAD/USD in YTD 2018 as compared to 1.3067 CAD/USD in YTD 2017. Expressed in U.S. dollars, operating expense for our U.S. properties was US$5.14/boe in Q3/2018 and US$5.18/boe during YTD 2018 which is fairly consistent with US$5.21/boe for Q3/2017 and US$5.12/boe in YTD 2017.

Baytex Energy Corp.

Q3 2018 MD&A Page 8

Transportation Expense

Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices and trucking rates. The following table compares our transportation expense for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30
	2018						2017
($ thousands except for per boe)	Canada		U.S.⁽¹⁾		Total		Canada		U.S.⁽¹⁾		Total
Transportation expense	$	9,520	$	—	$	9,520	$	9,312	$	—	$	9,312
Transportation expense per boe	$	2.29	$	—	$	1.26	$	2.93	$	—	$	1.46



	Nine Months Ended September 30
	2018						2017
($ thousands except for per boe)	Canada		U.S.⁽¹⁾		Total		Canada		U.S.⁽¹⁾		Total
Transportation expense	$	25,875	$	—	$	25,875	$	26,327	$	—	$	26,327
Transportation expense per boe	$	2.52	$	—	$	1.28	$	2.83	$	—	$	1.37


(1)	Transportation expense related to the Eagle Ford assets is included in operating expenses.

Transportation expense was $9.5 million ($1.26/boe) for Q3/2018 and $25.9 million ($1.28/boe) for YTD 2018 compared to $9.3 million ($1.46/boe) for Q3/2017 and $26.3 million ($1.37/boe) for YTD 2017. Gas transportation costs were slightly lower for YTD 2018 relative to YTD 2017 as a result of a change in certain marketing arrangements. The decrease in gas transportation costs for YTD 2018 was partially offset by higher oil trucking costs of approximately $1.5 million ($1.58/boe) associated with the Strategic Combination. Per unit transportation expense $1.28/boe is slightly below our annual guidance range of $1.35 - $1.45/boe for 2018 due to additional production associated with the Strategic Combination.

Blending and Other Expense

Blending and other expense primarily includes the cost of blending diluent purchased in order to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications. The purchased diluent is recorded as blending and other expense. The price received for the blended product is recorded as heavy oil sales revenue. We net blending and other expense against heavy oil sales to compare the realized price on our produced volumes to benchmark pricing. Accordingly, our heavy oil sales price realization can fluctuate depending on the quantity and price of blending diluent required to meet pipeline specifications.

Blending and other expense was $19.5 million for Q3/2018 and $55.1 million for YTD 2018 compared to $16.1 million for Q3/2017 and $42.6 million for the first nine months of 2017. The increase in blending and other expense during Q3/2018 and YTD 2018 is due to higher diluent prices combined with an increase in the quantity of diluent required to meet pipeline specifications relative to the same periods of 2017. The density of blending diluent available in YTD 2018 was heavier relative to YTD 2017 which resulted in higher purchases of blending diluent in order to meet pipeline specifications.

Baytex Energy Corp.

Q3 2018 MD&A Page 9

Financial Derivatives

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2018			2017			Change			2018			2017		Change
Realized financial derivatives gain (loss)
Crude oil	$	(31,704	)	$	972		$	(32,676	)	$	(72,529	)	$	4,828	$	(77,357	)
Natural gas	872			1,823			(951		)	2,448			891		1,557
Interest and financing	(22		)	—			(22		)	(22		)	—		(22		)
Total	$	(30,854	)	$	2,795		$	(33,649	)	$	(70,103	)	$	5,719	$	(75,822	)
Unrealized financial derivatives gain (loss)
Crude oil	$	4		$	(21,912	)	$	21,916		$	(63,454	)	$	13,936	$	(77,390	)
Natural gas	(1,027		)	767			(1,794		)	(2,663		)	13,762		(16,425		)
Interest and financing	977			—			977			977			—		977
Total	$	(46	)	$	(21,145	)	$	21,099		$	(65,140	)	$	27,698	$	(92,838	)
Total financial derivatives gain (loss)
Crude oil	$	(31,700	)	$	(20,940	)	$	(10,760	)	$	(135,983	)	$	18,764	$	(154,747	)
Natural gas	(155		)	2,590			(2,745		)	(215		)	14,653		(14,868		)
Interest and financing	955			—			955			955			—		955
Total	$	(30,900	)	$	(18,350	)	$	(12,550	)	$	(135,243	)	$	33,417	$	(168,660	)

Realized financial derivatives losses of $30.9 million for Q3/2018 and $70.1 million for YTD 2018 are primarily a result of the market prices for crude oil settling at levels above those set in our derivative contracts.

Our realized crude oil losses of $72.5 million for YTD 2018 were driven by $71.5 million of losses on our WTI swap contracts and $16.1 million of losses on our Brent swap contracts as the market price of WTI and Brent settled above our contract prices. We also recorded $4.8 million of realized losses on our 3-way option contract as the market price of WTI settled above the sold call price during YTD 2018. Losses on WTI and Brent contracts were partially offset by gains of $19.9 million on our WCS differential contracts as the index was wider than the differentials set in our contracts throughout the first nine months of 2018.

We recorded realized gains of $2.4 million on our natural gas financial derivatives during YTD 2018. These gains were primarily a result of the AECO price index for the first nine months of 2018 averaging less than the average fixed price on AECO contracts in place for YTD 2018.

At September 30, 2018, the fair value of our financial derivative contracts represent a net liability of $102.3 million compared to a net liability of $31.6 million at December 31, 2017. The net liability of $102.3 million as at September 30, 2018 is primarily a result of futures pricing for WTI and Brent crude oil indices being higher than the prices in our crude oil financial derivatives in place for the remainder of 2018 and 2019.

Baytex Energy Corp.

Q3 2018 MD&A Page 10

We had the following commodity financial derivative contracts as at November 1, 2018.



	Period	Volume	Price/Unit⁽¹⁾		Index
Oil
Basis swap	Oct 2018 to Dec 2018	6,000 bbl/d	WTI less US$14.24/bbl		WCS
3-way option⁽²⁾	Oct 2018 to Dec 2018	2,000 bbl/d	US$60.00/US$54.40/US$40.00		WTI
Fixed - Sell	Oct 2018 to Dec 2018	16,500 bbl/d	US$52.28/bbl		WTI
Fixed - Sell	Oct 2018 to Dec 2018	4,000 bbl/d	US$61.31/bbl		Brent
Fixed - Sell	Jan 2019 to Jun 2019	2,000 bbl/d	US$62.85/bbl		WTI
Fixed - Sell	Jan 2019 to Dec 2019	2,000 bbl/d	US$61.70/bbl		WTI
Swaption⁽³⁾	Jan 2019 to Dec 2019	2,000 bbl/d	US$61.70/bbl		WTI
Swaption⁽³⁾	Jan 2019 to Dec 2019	2,000 bbl/d	US$59.60/bbl		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	2,000 bbl/d	US$70.00/US$60.00/US$50.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$72.60/US$65.00/US$55.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$72.50/US$66.00/US$56.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$73.00/US$66.00/US$56.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	2,000 bbl/d	US$73.00/US$67.00/US$57.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	2,000 bbl/d	US$74.00/US$68.00/US$58.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$75.00/US$69.90/US$60.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$76.00/US$71.00/US$61.00		WTI
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$75.50/US$65.50/US$55.50		Brent
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$77.55/US$70.00/US$60.00		Brent
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$83.00/US$73.00/US$63.00		Brent
3-way option⁽²⁾	Jan 2019 to Dec 2019	1,000 bbl/d	US$78.00/US$73.00/US$63.00		WTI

Natural Gas
Fixed - Sell	Oct 2018 to Dec 2018	15,000 mmbtu/d		US$3.01	NYMEX
Fixed - Sell	Oct 2018 to Dec 2018	5,000 GJ/d		$2.67	AECO
Fixed - Sell	Nov 2018 to Mar 2019	5,000 GJ/d		$2.25	AECO


(1)	Based on the weighted average price per unit for the period.

(2)

Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$70/US$60/US$50 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$50/bbl; Baytex receives US$60.00/bbl when WTI is between US$50/bbl and US$60/bbl; Baytex receives the market price when WTI is between US$60/bbl and US$70/bbl; and Baytex receives US$70/bbl when WTI is above US$70/bbl.


(3)	For these contracts, the counterparty has the right, if exercised on December 31, 2018, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

Physical Delivery Contracts

The following physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with the Company's expected sale requirements. Physical delivery contracts are not considered financial instruments, and as a result no asset or liability has been recognized in the consolidated statements of financial position.

As at November 1, 2018, Baytex had committed to deliver the following volumes of raw bitumen to market on rail:



Period		Volume
Oct 2018 to Dec 2018		8,340 bbl/d
Nov 2018 to Oct 2019		1,000 bbl/d
Oct 2018 to Dec 2019		2,500 bbl/d
Jan 2019 to Dec 2019		2,500 bbl/d
Jan 2019 to Dec 2020		5,000 bbl/d

Baytex Energy Corp.

Q3 2018 MD&A Page 11

Operating Netback

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30
	2018							2017
($ per boe except for volume)	Canada		U.S.		Total			Canada		U.S.		Total
Total production (boe/d)	45,214		37,198		82,412			34,560		34,750		69,310
Operating netback:
Total sales, net of blending and other expense	$	47.66	$	63.98	$	55.03		$	33.41	$	42.64	$	38.04
Less:
Royalties	6.28		19.23		12.13			4.71		12.58		8.65
Operating expense	13.15		6.72		10.25			13.69		6.53		10.10
Transportation expense	2.29		—		1.26			2.93		—		1.46
Operating netback	$	25.94	$	38.03	$	31.39		$	12.08	$	23.53	$	17.83
Realized financial derivatives (loss) gain	—		—		(4.07		)	—		—		0.44
Operating netback after financial derivatives	$	25.94	$	38.03	$	27.32		$	12.08	$	23.53	$	18.27



	Nine Months Ended September 30
	2018							2017
($ per boe except for volume)	Canada		U.S.		Total			Canada		U.S.		Total
Total production (boe/d)	37,629		36,617		74,246			34,025		36,448		70,473
Operating netback:
Total sales, net of blending and other expense	$	40.56	$	59.89	$	50.09		$	33.37	$	44.64	$	39.20
Less:
Royalties	5.40		17.86		11.54			4.49		13.13		8.96
Operating expense	14.31		6.67		10.54			14.31		6.69		10.37
Transportation expense	2.52		—		1.28			2.83		—		1.37
Operating netback	$	18.33	$	35.36	$	26.73		$	11.74	$	24.82	$	18.50
Realized financial derivatives (loss) gain	—		—		(3.46		)	—		—		0.30
Operating netback after financial derivatives	$	18.33	$	35.36	$	23.27		$	11.74	$	24.82	$	18.80

Operating netback after financial derivatives of $27.32/boe for Q3/2018 and $23.27/boe for YTD 2018 increased 50% from $18.27/boe for Q3/2017 and 24% from $18.80/boe for YTD 2017. The increase in our realized sales price per boe during Q3/2018 and YTD 2018 resulting from higher oil prices was partially offset by higher royalties and slightly higher operating expenses compared the to same periods of 2017. The increase in royalty expense per boe is primarily due to higher realized prices in Q3/2018 and YTD 2018. Operating expense per boe was slightly higher in Q3/2018 and YTD 2018 due to a higher proportion of our production coming from Canada which has higher costs than the U.S. We recorded realized losses on financial derivatives of $4.07/boe in Q3/2018 and $3.46/boe in YTD 2018 as losses recorded on our WTI and Brent contracts were partially offset by gains recorded on our WCS differential and natural gas contracts.

Exploration and Evaluation Expense

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the derecognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of lease expiries, the accumulated costs of expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $0.5 million for Q3/2018 and $3.9 million for YTD 2018 compared to $0.5 million for Q3/2017 and $5.5 million for YTD 2017.

Baytex Energy Corp.

Q3 2018 MD&A Page 12

Depletion and Depreciation

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30
	2018						2017
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Depletion and depreciation⁽¹⁾	$	77,671	$	66,830	$	144,501	$	51,635	$	66,035	$	117,670
Depletion and depreciation per boe	$	18.67	$	19.53	$	19.06	$	16.24	$	20.66	$	18.45



	Nine Months Ended September 30
	2018						2017
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Depletion and depreciation⁽¹⁾	$	172,442	$	192,212	$	364,654	$	155,153	$	216,003	$	371,156
Depletion and depreciation per boe	$	16.79	$	19.23	$	17.99	$	16.70	$	21.71	$	19.29


(1)	Canada includes corporate depreciation.

Depletion and depreciation expense was $144.5 million ($19.06/boe) for Q3/2018 and $364.7 million ($17.99/boe) for YTD 2018 compared to $117.7 million ($18.45/boe) for Q3/2017 and $371.2 million ($19.29/boe) for YTD 2017. In Canada, the depletion rate for YTD 2018 was consistent with YTD 2017. Total depletion expense and the depletion rate in Canada increased in Q3/2018 following closing of the Strategic Combination as the depletion rate on our Viking properties is higher than our other Canadian properties. The U.S. depletion rate for 2018 is lower than 2017 primarily due to an increase in proved plus probable reserve volumes recorded in Q4/2017.

General and Administrative Expense

General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating capital and production activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated capital and production activity during the period.

The following table summarizes our G&A expense for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for per boe)	2018		2017		Change			2018		2017		Change
General and administrative expense	$	10,158	$	11,074	$	(916	)	$	31,729	$	37,672	$	(5,943	)
General and administrative expense per boe	$	1.34	$	1.74	$	(0.40	)	$	1.57	$	1.96	$	(0.39	)

G&A expense of $31.7 million ($1.57/boe) for YTD 2018 is consistent with our expectation. Our annual guidance of approximately $45 million ($1.55/boe) includes additional G&A in Q4/2018 from higher staffing and additional costs associated with the Strategic Combination.

We reported G&A expense of $10.2 million ($1.34/boe) for Q3/2018 and $31.7 million ($1.57/boe) for YTD 2018 compared to $11.1 million ($1.74/boe) for Q3/2017 and $37.7 million ($1.96/boe) for YTD 2017. G&A expense was lower in Q3/2018 as the impact of higher staffing levels following closing of the Strategic Combination was more than offset by an increase in recoveries associated with a more active capital program in Canada during Q3/2018 relative to Q3/2017. The decrease in G&A expense for YTD 2018 compared to YTD 2017 reflects lower personnel costs following a reduction in staffing levels in Q2/2017 along with higher recoveries associated with higher capital activity in Canada relative to YTD 2017.

Share-Based Compensation Expense

Share-based compensation ("SBC") expense associated with the Share Award Incentive Plan is recognized in net income or loss over the vesting period of the share awards with a corresponding increase in contributed surplus. The issuance of common shares upon the conversion of share awards is recorded as an increase in shareholders' capital with a corresponding reduction in contributed surplus. SBC expense varies with the quantity of unvested share awards outstanding and the grant date fair value assigned to the share awards.

Baytex Energy Corp.

Q3 2018 MD&A Page 13

We recorded SBC expense of $7.2 million for Q3/2018 and $15.0 million for YTD 2018 compared to $2.5 million for Q3/2017 and $12.6 million for YTD 2017. Q3/2018 SBC expense increased approximately $2.6 million as a result of the Strategic Combination. SBC expense is higher in YTD 2018 due to a higher value of share awards granted in YTD 2018 compared to YTD 2017 and additional expense recorded in Q3/2018 related to the Strategic Combination.

Financing and Interest Expense

Financing and interest expense includes interest on our bank loan and long-term notes, non-cash financing costs and the accretion on our asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period and the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.

Financing and interest expense was $30.0 million for Q3/2018 and $86.8 million for YTD 2018 compared to $27.5 million reported for Q2/2017 and $85.3 million for YTD 2017. Cash interest on long-term notes of $66.1 million for YTD 2018 was slightly lower than $67.1 million for the same period of 2017 as a result of a stronger Canadian dollar during YTD 2018 which reduced the reported amount of U.S. dollar interest in Canadian dollars. The increase in cash interest on our bank loan in YTD 2018 compared to YTD 2017 is a result of higher levels of bank debt outstanding during YTD 2018 due to the assumption of $316.8 million of outstanding debt as part of the Strategic Combination. Cash interest of $76.4 million ($3.77/boe) for the first nine months of 2018 is consistent with our full year guidance of approximately $104 million and $3.58/boe.

Foreign Exchange

Unrealized foreign exchange gains and losses represent the change in value of the long-term notes and bank loan denominated in U.S. dollars. The long-term notes and bank loan are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate. When the Canadian dollar strengthens against the U.S. dollar at the end of the current period compared to the previous period an unrealized gain is recorded and conversely when the Canadian dollar weakens at the end of the current period compared to the previous period an unrealized loss is recorded. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian operations.



	Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for exchange rates)	2018			2017			Change			2018		2017			Change
Unrealized foreign exchange loss (gain)	$	(20,583	)	$	(44,006	)	$	23,423		$	38,136	$	(87,389	)	$	125,525
Realized foreign exchange loss (gain)	(360		)	1,531			(1,891		)	1,887		1,373			514
Foreign exchange loss (gain)	$	(20,943	)	$	(42,475	)	$	21,532		$	40,023	$	(86,016	)	$	126,039
CAD/USD exchange rates:
At beginning of period	1.3142			1.2983						1.2518		1.3427
At end of period	1.2924			1.2510						1.2924		1.2510

We recorded an unrealized foreign exchange gain of $20.6 million for Q3/2018 and a loss of $38.1 million for YTD 2018 as the Canadian dollar strengthened relative to the U.S. dollar during Q3/2018 and weakened relative to the U.S. dollar during YTD 2018. The CAD/USD exchange rate was 1.2924 as at September 30, 2018 compared to 1.3142 as at June 30, 2018 and 1.2518 as at December 31, 2017.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss of $1.9 million for the first nine months of 2018 compared to a loss of $1.4 million for the same period of 2017.

Income Taxes



	Three Months Ended September 30								Nine Months Ended September 30
($ thousands)	2018			2017			Change		2018			2017			Change
Current income tax expense (recovery)	$	—		$	(48	)	$	48	$	(71	)	$	(1,489	)	$	1,418
Deferred income tax expense (recovery)	(4,427		)	(18,486		)	14,059		(51,905		)	(54,226		)	2,321
Total income tax recovery	$	(4,427	)	$	(18,534	)	$	14,107	$	(51,976	)	$	(55,715	)	$	3,739

Current income taxes were nominal for the three and nine months ended September 30, 2018 and 2017. During all of these periods, tax pool claims were sufficient to shelter the income associated with our adjusted funds flow.

We recorded a deferred income tax recovery of $4.4 million for Q3/2018 and $51.9 million for YTD 2018 compared to $18.5 million for Q3/2017 and $54.2 million for YTD 2017. The decrease in the deferred income tax recovery in 2018 compared to 2017 is primarily

Baytex Energy Corp.

Q3 2018 MD&A Page 14

the result of higher adjusted funds flow in the U.S. which resulted in greater use of available tax pool shelter. During YTD 2018, we recorded unrealized losses on financial derivatives which offset the impact of higher adjusted funds flow relative to YTD 2017.

In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the "CRA”) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. These reassessments followed a previously disclosed letter which we received in November 2014 from the CRA, proposing to issue such reassessments.

We remain confident that the tax filings of the affected entities are correct and are defending our tax filing positions. The reassessments do not require us to pay any amounts in order to participate in the appeals process.

In September 2016, we filed a notice of objection for each notice of reassessment received which will be reviewed by the Appeals Division of the CRA. An Appeals Officer was assigned to our file in July 2018 and we estimate the appeals process could take up to one year. If the Appeals Division upholds the notices of reassessment, we have the right to appeal to the Tax Court of Canada; a process that we estimate could take a further two years. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591 million (the “Losses”). The Losses were subsequently used to reduce the taxable income of those trusts. The reassessments disallow the deduction of the Losses under the general anti-avoidance rule of the Income Tax Act (Canada). If, after exhausting available appeals, the deduction of Losses continues to be disallowed, we will owe cash taxes for the years 2012 through 2015 and an additional amount for late payment interest. The amount of cash taxes owing and the late payment interest are dependent upon the amount of unused tax shelter available to offset the reassessed income, including tax shelter from future years available to recover taxes paid in the years 2012 through 2015.

Baytex Energy Corp.

Q3 2018 MD&A Page 15

Net Income (Loss) and Adjusted Funds Flow

The components of adjusted funds flow and net income or loss for the three and nine months ended September 30, 2018 and 2017 are set forth in the following table.



	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2018			2017			Change			2018			2017			Change
Petroleum and natural gas sales	$	436,761		$	258,620		$	178,141		$	1,070,433		$	796,706		$	273,727
Royalties	(91,945		)	(55,176		)	(36,769		)	(233,989		)	(172,367		)	(61,622		)
Revenue, net of royalties	344,816			203,444			141,372			836,444			624,339			212,105

Expenses
Operating	(77,698		)	(64,391		)	(13,307		)	(213,735		)	(199,446		)	(14,289		)
Transportation	(9,520		)	(9,312		)	(208		)	(25,875		)	(26,327		)	452
Blending and other	(19,548		)	(16,069		)	(3,479		)	(55,077		)	(42,554		)	(12,523		)
Operating netback	$	238,050		$	113,672		$	124,378		$	541,757		$	356,012		$	185,745
General and administrative	(10,158		)	(11,074		)	916			(31,729		)	(37,672		)	5,943
Cash financing and interest	(26,343		)	(24,526		)	(1,817		)	(76,384		)	(75,632		)	(752		)
Realized financial derivatives (loss) gain	(30,854		)	2,795			(33,649		)	(70,103		)	5,719			(75,822		)
Realized foreign exchange gain (loss)	360			(1,531		)	1,891			(1,887		)	(1,373		)	(514		)
Other income (expense)	302			(283		)	585			869			(1,192		)	2,061
Current income tax recovery (expense)	—			48			(48		)	71			1,489			(1,418		)
Payments on onerous contracts	(147		)	(1,761		)	1,614			(439		)	(5,506		)	5,067
Adjusted funds flow	$	171,210		$	77,340		$	93,870		$	362,155		$	241,845		$	120,310
Acquisition costs	(13,066		)	—			(13,066		)	(13,066		)	—			(13,066		)
Exploration and evaluation	(510		)	(497		)	(13		)	(3,887		)	(5,505		)	1,618
Depletion and depreciation	(144,501		)	(117,670		)	(26,831		)	(364,654		)	(371,156		)	6,502
Share based compensation	(7,180		)	(2,469		)	(4,711		)	(15,010		)	(12,611		)	(2,399		)
Non-cash financing and accretion	(3,686		)	(2,972		)	(714		)	(10,441		)	(9,664		)	(777		)
Unrealized financial derivatives (loss) gain	(46		)	(21,145		)	21,099			(65,140		)	27,698			(92,838		)
Unrealized foreign exchange gain (loss)	20,583			44,006			(23,423		)	(38,136		)	87,389			(125,525		)
Gain (loss) on disposition of oil and gas properties	34			(6,068		)	6,102			1,764			(6,592		)	8,356
Deferred income tax recovery (expense)	4,427			18,486			(14,059		)	51,905			54,226			(2,321		)
Payments on onerous contracts	147			1,761			(1,614		)	439			5,506			(5,067		)
Net income (loss) for the period	$	27,412		$	(9,228	)	$	36,640		$	(94,071	)	$	11,136		$	(105,207	)

We generated adjusted funds flow of $171.2 million for Q3/2018, an increase of $93.9 million from adjusted funds flow of $77.3 million reported for Q3/2017. The increase in adjusted funds flow in the third quarter of 2018 was primarily due to a higher operating netback which increased by $124.4 million from the same period in 2017. The increase in operating netback was due to higher commodity prices and average daily production from the Strategic Combination which increased revenues. This was partially offset by higher royalties in Q3/2018 as compared to Q3/2017 along with a $33.6 million increase in realized hedging losses.

In Q3/2018, we recorded net income of $27.4 million compared to a net loss of $9.2 million for the same period of 2017. The increase in net income was driven by the $93.9 million increase in adjusted funds flow. This was offset by higher depletion of $26.8 million and $13.1 million of acquisition costs from the Strategic Combination and a lower deferred tax recovery in Q3/2018.

Adjusted funds flow of $362.2 million for YTD 2018 was $120.3 million higher than $241.8 million for YTD 2017. The increase in adjusted funds flow for YTD 2018 was driven by higher commodity prices and average daily production which resulted in a $212.1 million increase in revenue, net of royalties as compared to YTD 2017. Operating netback for YTD 2018 was $185.7 million higher than YTD 2017 as the increase in revenue, net of royalties, was partially offset by a $12.5 million increase in blending and other expense along with an increase in operating expenses associated with the Strategic Combination. We recorded realized financial derivative losses of $70.1 million in YTD 2018 as compared to gains of $5.7 million for YTD 2017 which offset the increase in operating netbacks by $75.8 million.

We recorded a net loss of $94.1 million for YTD 2018 as compared to net income of $11.1 million reported for the same period of 2017. The change in net income was primarily a result of strengthening commodity prices which increased our adjusted funds flow by $120.3 million but also increased our unrealized loss on financial derivatives for YTD 2018 by $92.8 million as we recorded a loss of $65.1 million in YTD 2018 compared to a $27.7 million gain for YTD 2017. We also recorded an unrealized foreign exchange loss

Baytex Energy Corp.

Q3 2018 MD&A Page 16

of $38.1 million related to the weakening of the Canadian dollar during YTD 2018 which impacted the carrying value of our long-term notes. This resulted in a $125.5 million change in net income compared to YTD 2017 when we recorded an unrealized foreign exchange gain of $87.4 million. These factors combined to more than offset the increase in adjusted funds flow and resulted in a $105.2 million change in net income (loss) reported for YTD 2018 as compared to YTD 2017.

Other Comprehensive Income (Loss)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets not recognized in profit or loss. The $77.1 million foreign currency translation gain for the nine months ended September 30, 2018 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the weakening of the Canadian dollar against the U.S. dollar over the same period. The CAD/USD exchange rate was 1.2924 as at September 30, 2018 compared to 1.2518 as at December 31, 2017.

Capital Expenditures

Capital expenditures for the three and nine months ended September 30, 2018 and 2017 are summarized as follows.



	Three Months Ended September 30
	2018								2017
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Land and seismic	$	1,364		$	—	$	1,364		$	664		$	1,143	$	1,807
Drilling, completion and equipping	80,244			42,352		122,596			7,921			44,563		52,484
Facilities	14,106			2,204		16,310			5,902			1,351		7,253
Other	(1,237		)	162		(1,075		)	—			—		—
Total exploration and development	$	94,477		$	44,718	$	139,195		$	14,487		$	47,057	$	61,544
Total acquisitions, net of proceeds from divestitures	46			—		46			(7,436		)	—		(7,436		)
Total oil and natural gas expenditures	$	94,523		$	44,718	$	139,241		$	7,051		$	47,057	$	54,108



	Nine Months Ended September 30
	2018								2017
($ thousands)	Canada			U.S.		Total			Canada		U.S.		Total
Land and seismic	$	4,699		$	—	$	4,699		$	3,475	$	1,143	$	4,618
Drilling, completion and equipping	122,980			123,468		246,448			56,032		154,623		210,655
Facilities	46,474			11,217		57,691			11,901		8,936		20,837
Other	2,457			264		2,721			—		—		—
Total exploration and development	$	176,610		$	134,949	$	311,559		$	71,408	$	164,702	$	236,110
Total acquisitions, net of proceeds from divestitures	(2,001		)	—		(2,001		)	63,794		—		63,794
Total oil and natural gas expenditures	$	174,609		$	134,949	$	309,558		$	135,202	$	164,702	$	299,904

Exploration and development expenditures were $139.2 million for Q3/2018 and $311.6 million for YTD 2018 compared to $61.5 million for Q3/2017 and $236.1 million for YTD 2017. Our Q3/2018 and YTD 2018 capital program includes $40.4 million of exploration and development expenditures for our Viking and Duvernay light oil properties subsequent to closing of the Strategic Combination.

Total exploration and development expenditures in Canada were $94.5 million in Q3/2018 compared to $14.5 million in Q3/2017. We drilled 87 (66.8 net) wells and spent $80.2 million on drilling, completion and equipping costs during Q3/2018 compared to drilling 20 (7.4 net) wells during Q3/2017 for $7.9 million. YTD 2018 drilling, completion and equipping costs of $123.0 million were $66.9 million higher than $56.0 million for YTD 2017 primarily due to $40.4 million invested on light oil exploration and development at our Viking and Duvernay properties during Q3/2018. During YTD 2018 we invested $46.5 million on facilities in Canada including construction of a gas plant and strategic infrastructure projects which is up $34.6 million from $11.9 million during the YTD 2017.

In the U.S., exploration and development expenditures for Q3/2018 and YTD 2018 were $44.7 million and $134.9 million respectively, both lower than the $47.1 million and $164.7 million for the comparative periods in 2017. We participated in the drilling of 29 (8.0 net) wells and initiated production from 26 (4.9 net) wells during Q3/2018 compared to 30 (7.9 net) wells drilled and 22 (5.8 net) wells on production in Q3/2017. Lower drilling and completion activity on our lands in YTD 2018 resulted in lower total exploration and development expenditures relative to YTD 2017. We drilled 72 (17.5 net) wells and initiated production from 85 (18.0 net) wells during

Baytex Energy Corp.

Q3 2018 MD&A Page 17

YTD 2018 as compared to 104 (25.7 net) wells drilled and 90 (23.3 net) wells brought on production during YTD 2017. Wells on production during YTD 2018 had longer completed lengths and increased proppant concentration which resulted in a slight increase in average well costs relative to YTD 2017.

We completed minor property acquisition and disposition activity in YTD 2018 for net proceeds of $2.0 million compared to YTD 2017 when our property acquisition and disposition activities were primarily comprised of the Peace River property acquisition which totaled $66.1 million.

CAPITAL RESOURCES AND LIQUIDITY

Our objective for capital management involves maintaining a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions and the risk characteristics of our oil and gas properties. At September 30, 2018, our capital structure was comprised of shareholders' capital, long-term debt, working capital and our bank loan.

The capital intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing exploration and development. Our capital resources consist primarily of adjusted funds flow, available credit facilities and proceeds received from the divestiture of oil and gas properties. We believe that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures. Our adjusted funds flow is dependent on a number of factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange rates. In order to manage our capital structure and liquidity, we may from time to time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

Management of debt levels is a priority for Baytex in order to sustain operations and support our plans for long-term growth. At September 30, 2018, net debt was $2,112.1 million, an increase of $377.8 million from $1,734.3 million at December 31, 2017. The increase in net debt is primarily due to $363.6 million of net debt assumed in conjunction with the Strategic Combination on August 22, 2018.

We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a twelve month trailing basis. At September 30, 2018, our net debt to adjusted funds flow ratio was 2.6, after adjustment for the Strategic Combination as if the transaction had occurred on the first day of the relevant period, compared to a ratio of 5.0 as at December 31, 2017. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2017 is attributed to higher adjusted funds flow from higher commodity prices combined with the increase in average daily production. The effect of higher adjusted funds flow more than offset the impact of the increase in net debt as at September 30, 2018 which was primarily due to $363.6 million of net debt assumed in conjunction with the Strategic Combination.

Bank Loan

At September 30, 2018, the principal amount of bank loan outstanding was $490.6 million and we had approximately $552.6 million of undrawn capacity under our credit facilities that total approximately $1.04 billion. Our facilities include US$575 of revolving credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving term loan (the "Term Loan").

On August 22, 2018, Baytex amended its credit facilities to facilitate the Strategic Combination and the debt assumed from Raging River. The Revolving Facilities are secured and are comprised of a US$35 million operating loan, a US$340 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. and matures on June 4, 2020. The Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership and matures on June 4, 2020.

The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity on June 4, 2020 which could be extended upon our request. Advances (including letters of credit) under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates, plus applicable margins. In the event that Baytex exceeds any of the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders.

The agreements and associated amending agreements relating to the credit facilities are accessible on the SEDAR website at www.sedar.com (filed under the category "Material contracts" on April 13, 2016, May 2, 2018, and October 12, 2018).

The weighted average interest rate on the credit facilities for Q3/2018 was 4.1% as compared to 4.0% for Q3/2017.

Financial Covenants

The following table summarizes the financial covenants applicable to the Revolving Facilities and our compliance therewith at September 30, 2018.



Covenant Description	Position as at September 30, 2018	Covenant
Senior Secured Debt⁽¹⁾ to Bank EBITDA⁽²⁾(Maximum Ratio)	0.55:1.00	3.50:1.00
Interest Coverage⁽³⁾ (Minimum Ratio)	9.00:1.00	2.00:1.00


(1)	Senior Secured Debt is defined as the principal amount of the bank loan and $15.0 million of letters of credit identified as other secured obligations in the credit agreements. As at September 30, 2018, the Company's Senior Secured Debt totaled $505.6 million.

(2)

Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, unrealized gains and losses on financial derivatives, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended September 30, 2018 was $911.1 million.


(3)	Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended September 30, 2018 were $101.2 million.

Long-Term Notes

We have four series of long-term notes outstanding that total $1.53 billion as at September 30, 2018. The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts our ability to raise additional debt beyond existing credit facilities and long-term notes unless we maintain a minimum fixed charge coverage ratio (computed as the ratio of Bank EBITDA to financing and interest expenses on a trailing twelve month basis) of 2.50:1.00. As at September 30, 2018, the fixed charge coverage ratio was 9.00:1.00.

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. As of February 17, 2016, these notes are redeemable at our option, in whole or in part, at specified redemption prices.

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. As of July 19, 2017, these notes are redeemable at our option, in whole or in part, at specified redemption prices.

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the "5.125% Notes") and US$400 million of 5.625% notes due June 1, 2024 (the "5.625% Notes"). The 5.125% Notes and the 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. As of June 1, 2017, the 5.125% Notes are redeemable at our option, in whole or in part, at specified redemption prices. The 5.625% Notes will be redeemable at our option, in whole or in part, commencing on June 1, 2019 at specified redemption prices.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the nine months ended September 30, 2018, we issued 3.2 million common shares pursuant to our share-based compensation program and 315.3 million common shares on closing of the Strategic Combination. As at November 1, 2018, we had 554.0 million common shares issued and outstanding and no preferred shares issued and outstanding.

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 our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of September 30, 2018 and the expected timing for funding 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	$	317,118	$	317,118	$	—	$	—	$	—
Bank loan^{(1) (2)}	490,565		—		490,565		—		—
Long-term notes⁽²⁾	1,527,733		—		710,793		300,000		516,940
Interest on long-term notes⁽³⁾	342,401		88,531		160,322		74,110		19,438
Operating leases	24,697		7,758		12,628		4,286		25
Processing agreements	51,340		11,983		16,947		9,090		13,320
Transportation agreements	118,590		13,861		43,359		21,933		39,437
Total	$	2,872,444	$	439,251	$	1,434,614	$	409,419	$	589,160


(1)	The bank loan matures on June 4, 2020 unless maturity is extended at our request.


(2)	Principal amount of instruments.


(3)	Excludes interest on bank loan as interest payments on bank loans fluctuate based on interest rate and bank loan balance.

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

Baytex Energy Corp.

Q3 2018 MD&A Page 18

QUARTERLY FINANCIAL INFORMATION



	2018						2017						2016
($ thousands, except per common share amounts)	Q3		Q2		Q1		Q4		Q3		Q2	Q1	Q4
Petroleum and natural gas sales	436,761		347,605		286,067		303,163		258,620		277,536	260,549	233,116
Net income (loss)	27,412		(58,761	)	(62,722	)	76,038		(9,228	)	9,268	11,096	(359,424	)
Per common share - basic	0.07		(0.25	)	(0.27	)	0.32		(0.04	)	0.04	0.05	(1.66	)
Per common share - diluted	0.07		(0.25	)	(0.27	)	0.32		(0.04	)	0.04	0.05	(1.66	)
Adjusted funds flow	171,210		106,690		84,255		105,796		77,340		83,136	81,369	77,239
Per common share - basic	0.46		0.45		0.36		0.45		0.33		0.35	0.35	0.36
Per common share - diluted	0.45		0.45		0.36		0.44		0.33		0.35	0.34	0.36
Exploration and development	139,195		78,830		93,534		90,156		61,544		78,007	96,559	68,029
Canada	94,477		30,608		51,525		41,864		14,487		18,439	38,484	12,151
U.S.	44,718		48,222		42,009		48,292		47,057		59,568	58,075	55,878
Acquisitions, net of divestitures	46		(21	)	(2,026	)	(3,937	)	(7,436	)	5,226	66,004	(322	)
Net debt	2,112,090		1,784,835		1,783,379		1,734,284		1,748,805		1,819,387	1,850,909	1,773,541
Total assets	6,491,303		4,476,906		4,433,074		4,372,111		4,353,637		4,582,049	4,702,423	4,594,085
Common shares outstanding	553,950		236,662		236,578		235,451		235,451		234,204	234,203	233,449

Daily production
Total production (boe/d)	82,412		70,664		69,522		69,556		69,310		72,812	69,298	65,136
Canada (boe/d)	45,214		34,042		33,505		32,194		34,560		34,284	33,217	31,704
U.S. (boe/d)	37,198		36,622		36,017		37,362		34,750		38,528	36,081	33,432

Benchmark prices
WTI oil (US$/bbl)	69.50		67.88		62.87		55.40		48.20		48.28	51.91	49.29
WCS heavy (US$/bbl)	47.25		48.61		38.59		43.14		38.26		37.16	37.34	34.97
CAD/USD avg exchange rate	1.3070		1.2911		1.2651		1.2717		1.2524		1.3447	1.3229	1.3339
AECO gas ($/mcf)	1.35		1.03		1.85		1.96		2.04		2.77	2.94	2.81
NYMEX gas (US$/mmbtu)	2.90		2.80		3.00		2.93		3.00		3.18	3.32	2.98

Sales price ($/boe)	55.03		51.22		42.96		44.75		38.04		39.41	40.16	38.16
Royalties ($/boe)	12.13		12.01		10.36		10.86		8.65		9.06	9.17	9.28
Operating expense ($/boe)	10.25		10.91		10.53		10.91		10.10		10.70	10.28	9.96
Transportation expense ($/boe)	1.26		1.22		1.36		1.20		1.46		1.35	1.29	1.30
Operating netback ($/boe)	31.39		27.08		20.71		21.78		17.83		18.30	19.42	17.62
Financial derivatives (loss) gain ($/boe)	(4.07	)	(4.57	)	(1.57	)	0.30		0.44		0.40	0.04	1.62
Operating netback after financial derivatives ($/boe)	27.32		22.51		19.14		22.08		18.27		18.70	19.46	19.24

Our operating and financial results have improved as oil prices continue to recover from the multi-year lows experienced in 2016. Compliance with OPEC's production quotas and increased global demand for crude oil have resulted in the WTI benchmark gradually increasing from US$49.29/bbl in Q4/2016 to US$69.50/bbl during Q3/2018. Improved well productivity from enhanced completion techniques contributed to the increase in daily production in the U.S. with a reduction in quarterly exploration and development expenditures. In Canada, exploration and development activity increased in 2017 after deferring operated heavy oil drilling during the first three quarters of 2016 in response to low heavy oil prices. The increased level of activity along with the Strategic Combination in Q3/2018 has increased production from Q4/2016 into Q3/2018. Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow improved in late 2017 as commodity prices recovered and our daily production increased from 2016.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt has increased from $1,773.5 million at Q4/2016 to $2,112.1 million at Q3/2018 primarily due to the additional net debt assumed in conjunction with the Strategic Combination in Q3/2018.

Baytex Energy Corp.

Q3 2018 MD&A Page 19

2018 GUIDANCE

The following table compares our 2018 annual guidance to our YTD 2018 results.



	Original Guidance ⁽¹⁾	Current Guidance ⁽²⁾	YTD 2018
Exploration and development capital	$450 - $500 million	$450 - $500 million	$311.6 million
Production (boe/d)	79,000 to 81,000	79,000 to 80,000	74,246

Expenses:
Royalty rate	~ 21.0%	~ 22.0%	23.0	%
Operating	$10.75 - $11.25/boe	$10.50 - $10.75/boe	$10.54/boe
Transportation	$1.35 - $1.45/boe	$1.25 - $1.30/boe	$1.28/boe
General and administrative	~ $48 million ($1.64/boe)	~ $45 million ($1.55/boe)	$31.7 million ($1.57/boe)
Interest	~ $105 million ($3.60/boe)	~ $104 million ($3.58/boe)	$76.4 million ($3.77/boe)


(1)	As announced on August 22, 2018 to include Raging River from the closing date of the Strategic Combination.


(2)	Updated as at November 2, 2018.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at September 30, 2018, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the nine months ended September 30, 2018. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2017.

CHANGES IN ACCOUNTING STANDARDS

Revenue Recognition

Baytex adopted IFRS 15 Revenue from Contracts with Customers with a date of initial application of January 1, 2018. For the year ended December 31, 2017, $8.3 million of commodity purchases related to heavy oil sales have been reclassified from petroleum and natural gas sales to blending and other expense to conform with the requirements of IFRS 15. There were no adjustments made to the January 1, 2018 opening statement of financial position on adoption. The additional disclosures required by IFRS 15 are provided in note 12 to the consolidated financial statements.

The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis if Baytex acts in the capacity of an agent rather than as a principal.

Revenue from the sale of heavy oil, light oil and condensate, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue when control of the product transfers to the customer and collection is reasonably assured. The amount of revenue recognized is based on the consideration specified in the contract. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon and collection is reasonably assured.

The transaction price for variable price contracts in the Canada and U.S. segments is based on a representative commodity price index, and may be adjusted for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.

Tariffs, tolls and fees charged to other entities for use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.

Baytex Energy Corp.

Q3 2018 MD&A Page 20

Financial Instruments

Baytex adopted IFRS 9 Financial Instruments, on January 1, 2018 using the retrospective method. The adoption of this standard did not result in a change in the recognition or measurement of any of the Company's financial instruments on transition.

IFRS 9 contains three principal classification categories for initial classification of financial assets: measured at amortized cost; fair value through other comprehensive income (“FVOCI”); or fair value through profit or loss (“FVTPL”). The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are eliminated. Financial assets are categorized based on the Company’s objective for the asset and the contractual cash flows. A financial asset is classified as amortized cost if the asset is held with the objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the financial asset. All other financial assets are measured at FVTPL. Financial assets are assessed for impairment using an expected credit loss model. Trade and other receivables are classified and measured at amortized cost.

The initial classification of financial liabilities under IFRS 9 is fundamentally unchanged from the requirements under IAS 39. A financial liability is measured at amortized cost or FVTPL. A financial liability is measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL at initial recognition. For liabilities measured at FVTPL, any change in value resulting from a change in Baytex’s credit-risk is recorded through other comprehensive income or loss rather than net income or loss. Trade and other payables, bank loan and long-term notes are classified and measured at amortized cost.

Future accounting pronouncements

A description of accounting standards that will be effective in the future is included in the notes to the consolidated financial statements.

NON-GAAP AND CAPITAL MEASUREMENT MEASURES

In this MD&A, we refer to certain measures (such as adjusted funds flow, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by GAAP. While adjusted funds flow, net debt, operating netback and Bank EBITDA are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. We believe that inclusion of these non-GAAP measures provides useful information to investors and shareholders when evaluating the financial results of the Company.

Adjusted Funds Flow

We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate funds for capital investments, debt repayment, settlement of our abandonment obligations and potential future dividends. In addition, we use a ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate changes in non-cash working capital and settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed within our capital budgeting process which considers available adjusted funds flow. In addition, we have removed transaction costs from the Strategic Combination as we consider the costs non-recurring and not reflective of our ongoing ability to generate adjusted funds flow. Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income or loss.

The following table reconciles cash flow from operating activities to adjusted funds flow.



	Three Months Ended September 30					Nine Months Ended September 30
($ thousands)	2018		2017			2018		2017
Cash flow from operating activities	$	154,091	$	77,912		$	316,241	$	228,885
Change in non-cash working capital	1,025		(2,326		)	23,633		3,311
Asset retirement obligations settled	3,028		1,754			9,215		9,649
Transaction costs	13,066		—			13,066		—
Adjusted funds flow	$	171,210	$	77,340		$	362,155	$	241,845

Baytex Energy Corp.

Q3 2018 MD&A Page 21

Net Debt

We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure to assess our liquidity.

The following table summarizes our calculation of net debt.



($ thousands)	September 30, 2018		December 31, 2017
Bank loan⁽¹⁾	$	490,565	$	213,376
Long-term notes⁽¹⁾	1,527,733		1,489,210
Working capital (surplus) deficiency⁽²⁾	93,792		31,698
Net debt	$	2,112,090	$	1,734,284


(1)	Principal amount of instruments expressed in Canadian dollars.


(2)	Working capital is calculated as current assets less current liabilities (excluding current financial derivatives and onerous contracts).

Operating Netback

We define operating netback as petroleum and natural gas sales, less blending and other expense, royalties, operating expense and transportation expense. Operating netback per boe is the operating netback divided by barrels of oil equivalent production volume for the applicable period. We believe that this measure assists in assessing our ability to generate cash margin on a unit of production basis.



	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2018			2017			2018			2017
Petroleum and natural gas sales	$	436,761		$	258,620		$	1,070,433		$	796,706
Blending and other expense	(19,548		)	(16,069		)	(55,077		)	(42,554		)
Total sales, net of blending and other expense	417,213			242,551			1,015,356			754,152
Less:
Royalties	91,945			55,176			233,989			172,367
Operating expense	77,698			64,391			213,735			199,446
Transportation expense	9,520			9,312			25,875			26,327
Operating netback	238,050			113,672			541,757			356,012
Realized financial derivative gain (loss)	(30,854		)	2,795			(70,103		)	5,719
Operating netback after realized financial derivatives gain (loss)	$	207,196		$	116,467		$	471,654		$	361,731

Baytex Energy Corp.

Q3 2018 MD&A Page 22

Bank EBITDA

Bank EBITDA is used to assess compliance with certain financial covenants. The following table reconciles net income or loss to Bank EBITDA.



	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2018			2017			2018			2017
Net income (loss)	$	27,412		$	(9,228	)	$	(94,071	)	$	11,136
Plus:
Financing and interest	30,029			27,498			86,825			85,296
Unrealized foreign exchange (gain) loss	(20,583		)	(44,006		)	38,136			(87,389		)
Unrealized financial derivatives (gain) loss	46			21,145			65,140			(27,698		)
Current income tax expense (recovery)	—			(48		)	(71		)	(1,489		)
Deferred income tax recovery	(4,427		)	(18,486		)	(51,905		)	(54,226		)
Depletion and depreciation	144,501			117,670			364,654			371,156
(Gain) loss on disposition of oil and gas properties	(34		)	6,068			(1,764		)	6,592
Transaction costs	13,066			—			13,066			—
Non-cash items⁽¹⁾	7,690			2,966			18,897			18,116
Strategic combination adjustment ⁽²⁾	96,736			—			255,800			—
Bank EBITDA	$	294,436		$	103,579		$	694,707		$	321,494


(1)	Non-cash items include share-based compensation, exploration and evaluation expense and non-cash other expense.


(2)	In accordance with the credit facilities agreements, the calculation of Bank EBITDA is adjusted to reflect the impact of material acquisitions as if the transaction had occurred on the first day of the relevant period.

INTERNAL CONTROL OVER FINANCIAL REPORTING

We are required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our interim MD&A any weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses were identified in, or changes were made to, internal controls over financial reporting during the three months ended September 30, 2018, except for the matter described below.

On August 22, 2018, Baytex completed the acquisition of Raging River, a publicly traded oil and gas company that was listed on the Toronto Stock Exchange. Raging River's operations have been included in the consolidated financial statements of Baytex since August 22, 2018. However, Baytex has not had sufficient time to appropriately assess the disclosure controls and procedures and internal controls over financial reporting previously used by Raging River and integrate them with those of Baytex. In addition, Raging River was not subject to the Sarbanes-Oxley Act of 2002 and, therefore, was not required to have its external auditors audit the effectiveness of its internal control over financial reporting. As a result, the certifying officers have limited the scope of their design of disclosure controls and procedures and internal controls over financial reporting to exclude controls, policies and procedures of Raging River (as permitted by applicable securities laws in Canada and the U.S.). Baytex has a program in place to complete its assessment of the controls, policies and procedures of the acquired operations by August 22, 2019.

During the three months ended September 30, 2018, the assets previously held by Raging River contributed revenues net of royalties of $60.6 million (representing 18% of total revenues, net of royalties) and operating income (revenues, net of royalties, less operating, transportation and blending and other expenses) of $48.0 million (representing 20% of total operating income). At September 30, 2018, current assets of $58.2 million, non-current assets of $2.0 billion, current liabilities of $148.7 million and non-current liabilities of $673.3 million were associated with acquired entity.

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", "plan", "project", "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: our business strategies, plans and objectives; our corporate royalty rate for 2018; the existence, operation and strategy of our risk management program; the

Baytex Energy Corp.

Q3 2018 MD&A Page 23

reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; the length of time it would take to resolve the reassessments; that we would owe cash taxes and late payment interest if the reassessment is successful; that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures; that a significant portion of our financial obligations will be funded by adjusted funds flow; our capital budget and expected average daily production for 2018; and our expected royalty rate and operating, transportation, general and administrative and interest expenses for 2018. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

These forward-looking statements are based on certain key assumptions regarding, among other things: the timing of receipt of regulatory and shareholder approvals for the Transaction; the ability of the combined company to realize the anticipated benefits of the Transaction; 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; our ability to borrow under our credit agreements; 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; 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: completion of the Transaction could be delayed if parties are unable to obtain the necessary regulatory, stock exchange, shareholder and court approvals on the timeline planned; the Transaction will not be completed if all of these approvals are not obtained or some other condition of closing is not satisfied; the volatility of oil and natural gas prices; a decline or an extended period of the currently low oil and natural gas prices; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; availability and cost of gathering, processing and pipeline systems; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; we may lose access to our information technology systems; risks associated with the ownership of our securities, including 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 our control. 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, 2017, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

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.

Baytex Energy (BTE) 6-KCondensed Consolidated Statements of Financial Position