Exhibit

EX-99.2 3 a992-q32019mda.htm EXHIBIT 99.2 Exhibit

Baytex Energy Corp.

Q3 2019 MD&A Page 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2019 and 2018

Dated October 31, 2019

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, 2019. This information is provided as of October 31, 2019. 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, 2019 ("Q3/2019" and "YTD 2019") have been compared with the results for the three and nine months ended September 30, 2018 ("Q3/2018" and "YTD 2018"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 2019, its audited comparative consolidated financial statements for the years ended December 31, 2018 and 2017, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2018. 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"). The terms "adjusted funds flow", "operating netback", "exploration and development expenditures", "net debt", and "Bank EBITDA" do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to our advisory on forward-looking information and statements and a summary of our non-GAAP measures at the end of the MD&A.

BAYTEX ENERGY CORP.

Baytex Energy Corp. is a North American focused oil and gas company based in Calgary, Alberta. The company has oil and gas operations in Canada and the United States. The Canadian operating segment includes our light oil assets in the 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.

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 increased our light oil exposure and operational control of our properties while improving our leverage ratios. Production from Raging River's properties is approximately 90% light oil from the Viking and Duvernay. The addition of the primarily operated assets to our portfolio increased our inventory of drilling prospects and enhanced our ability to effectively allocate capital.

THIRD QUARTER HIGHLIGHTS

Baytex delivered solid operating and financial results for Q3/2019. We reported adjusted funds flow of $213.4 million which exceeded exploration and development expenditures of $139.1 million for Q3/2019. Production of 94,927 boe/d was in line with expectations after strong operational performance during the first half of 2019 and a reduction in exploration and development activity in Q2/2019 and Q3/2019. We completed the early redemption of our US$150 million 6.75% senior unsecured notes on September 13, 2019 using the liquidity generated by adjusted funds flow of $670.3 million which exceeded exploration and development expenditures of $399.2 million for YTD 2019.

In Canada, production was 58,134 boe/d for Q3/2019 and 58,904 boe/d for YTD 2019 which was 29% and 57% higher than the comparative periods of 2018 which reflects the impact of the Strategic Combination. Exploration and development expenditures of $96.8 million in Q3/2019 were primarily focused on our Viking light oil property along with additional heavy oil development at Peace River and Lloydminster. Exploration and development expenditures included costs associated with drilling 82 (72.5 net) light oil wells in the Viking and 20 (20.0 net) heavy oil wells during Q3/2019.

In the U.S., we continue to observe strong performance from wells brought on stream during Q3/2019 which resulted in production of 36,793 boe/d compared to 37,198 boe/d for Q3/2018. Production for Q3/2019 was in line with expectations after strong operational performance during the first half of 2019 and the timing of completion activity during YTD 2019 resulted in production of 39,822 boe/d in Q2/2019. We invested $42.3 million on exploration and development activity during Q3/2019 and drilled 22 (5.3 net) wells and commenced production from 20 (4.6 net) wells.

Baytex Energy Corp.

Q3 2019 MD&A Page 2

We continue to benefit from a narrowing Canadian light and heavy oil differentials after production curtailments mandated by the Government of Alberta came into effect in January 2019. The Edmonton par light oil benchmark averaged $68.41/bbl in Q3/2019 which represents a differential of US$4.66/bbl to the West Texas Intermediate ("WTI") benchmark price as compared to a US$26.51 differential in Q4/2018 and a US$6.82/bbl differential in Q3/2018. The Western Canadian Select ("WCS") heavy oil differential averaged US$12.24/bbl in Q3/2019 relative to a differential of US$39.42/bbl in Q4/2018 and US$22.25/bbl in Q3/2018. Stronger Canadian oil differentials helped to mitigate the impact of a lower WTI benchmark price of US$56.45/bbl for Q3/2019 compared to US$69.50/bbl during Q3/2018.

Adjusted funds flow of $213.4 million in Q3/2019 was $42.2 million higher than $171.2 million for Q3/2018 due to higher production from the Strategic Combination along with $20.9 million of realized hedging gains that more than offset the $8.7 million decrease in operating netback due to lower benchmark pricing.

We redeemed our US$150 million 6.75% senior unsecured notes on September 13, 2019 using adjusted funds flow generated during YTD 2019. At September 30, 2019, net debt was $1,971.3 million, a $293.9 million decrease from $2,265.2 million at December 31, 2018. Net debt has decreased as adjusted funds flow has exceeded exploration and development expenditures for YTD 2019 by $271.1 million and the Canadian dollar strengthened at September 30, 2019 which reduced the reported amount of our US denominated long-term notes by $32.2 million.

2019 GUIDANCE

The following table compares our 2019 annual guidance to our YTD 2019 results. As a result of our strong operational performance in YTD 2019 we now expect to exceed our 2019 annual production guidance of approximately 97,000 boe/d with exploration and development expenditures of approximately $560 million.



	Previous Annual Guidance ⁽¹⁾	Revised Annual Guidance	YTD 2019
Exploration and development capital	$550 - 600 million	~ $560 million	$399.2 million
Production (boe/d)	96,000 - 97,000	~ 97,000	98,125

Expenses:
Royalty rate	~ 19.0%	No change	19.0	%
Operating	$10.75 - $11.25/boe	No change	$11.13/boe
Transportation	$1.25 - $1.35/boe	No change	$1.31/boe
General and administrative	~ $46 million ($1.30/boe)	No change	$35.6 million ($1.33/boe)
Cash interest	~ $112 million ($3.23/boe)	No change	$83.0 million ($3.10/boe)

(1) As announced on August 1, 2019.

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Q3 2019 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
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	22,493		20,336		42,829		9,894		19,837		29,731
Heavy oil	25,712		—		25,712		27,036		—		27,036
Natural Gas Liquids (NGL)	1,575		7,968		9,543		1,096		8,980		10,076
Total liquids (bbl/d)	49,780		28,304		78,084		38,026		28,817		66,843
Natural gas (mcf/d)	50,122		50,932		101,054		43,127		50,287		93,414
Total production (boe/d)	58,134		36,793		94,927		45,214		37,198		82,412

Production Mix
Light oil and condensate	39	%	55	%	45	%	22	%	53	%	36	%
Heavy oil	44	%	—	%	27	%	60	%	—	%	33	%
NGL	3	%	22	%	10	%	2	%	24	%	12	%
Natural gas	14	%	23	%	18	%	16	%	23	%	19	%

	Nine Months Ended September 30
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	22,636		20,843		43,479		3,898		20,067		23,965
Heavy oil	26,637		—		26,637		25,824		—		25,824
Natural Gas Liquids (NGL)	1,430		9,315		10,745		1,202		8,347		9,549
Total liquids (bbl/d)	50,703		30,158		80,861		30,924		28,414		59,338
Natural gas (mcf/d)	49,207		54,380		103,587		40,232		49,217		89,449
Total production (boe/d)	58,904		39,221		98,125		37,629		36,617		74,246

Production Mix
Light oil and condensate	39	%	53	%	44	%	10	%	55	%	32	%
Heavy oil	45	%	—	%	27	%	69	%	—	%	35	%
NGL	2	%	24	%	11	%	3	%	23	%	13	%
Natural gas	14	%	23	%	18	%	18	%	22	%	20	%

After strong operational performance and production of 98,125 boe/d in YTD 2019 we expect to exceed our annual production guidance for 2019 of approximately 97,000 boe/d which represents the top end of our previous range of 96,000 to 97,000 boe/d.

Production averaged 94,927 boe/d for Q3/2019 and 98,125 boe/d for YTD 2019 compared to annual guidance of approximately 97,000 boe/d. Production in 2019 is higher than 2018 due to the Strategic Combination along with production related to our exploration and development program. As expected, our production declined in Q3/2019 following strong operational performance during the first six months of 2019 and a reduction in exploration and development expenditures on our U.S. properties during Q2/2019.

In Canada, production was 58,134 boe/d for Q3/2019 and 58,904 boe/d for YTD 2019 compared to 45,214 boe/d in Q3/2018 and 37,629 boe/d in YTD 2018. The increase in production in 2019 relative to 2018 is primarily due to the production contribution from the Strategic Combination along with strong well performance from our exploration and development program. Production from our Viking and Duvernay properties consists of approximately 90% light oil which resulted in a higher proportion of our Canadian production being comprised of light oil in both periods of 2019 relative to 2018.

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Q3 2019 MD&A Page 4

Production in the U.S. averaged 36,793 boe/d for Q3/2019 and 39,221 boe/d in YTD 2019 compared to 37,198 boe/d for Q3/2018 and 36,617 boe/d in YTD 2018. U.S. production of 36,793 boe/d for Q3/2019 is slightly lower than 37,198 boe/d for Q3/2018 due to lower completion activity on our lands during Q2/2019 and Q3/2019. We initiated production from 20 (4.6 net) wells during Q3/2019 compared to 26 (4.9 net) wells in Q3/2018. We continue to see strong initial production results from wells brought on stream in 2019 which resulted in production for YTD 2019 that was 2,604 boe/d higher than 36,617 boe/d in YTD 2018 with only a slight increase in completion activity. During YTD 2019 we commenced production from 85 (18.6 net) wells compared to YTD 2018 when 85 (17.9 net) wells were brought on production.

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 declined during Q3/2019 as forecast demand levels were impacted by the ongoing trade dispute between the U.S. and China which more than offset the effect of compliance with OPEC production curtailments along with U.S. imposed sanctions on Iran and Venezuela. North American benchmark prices for Q3/2019 and YTD 2019 were lower than the same periods of 2018 as a result of increasing supply from U.S. production along with uncertainty around global crude oil demand. Canadian oil differentials remained strong in Q3/2019 and YTD 2019 compared to Q3/2018 and YTD 2018 due to the Government of Alberta's production curtailments which came into effect in January of 2019. While our YTD 2019 production levels were not significantly impacted by the Government of Alberta's curtailment program we have benefited from narrower differentials for our light and heavy oil production in Q3/2019 and YTD 2019.

We compare the price received for our U.S. crude oil production to the Louisiana Light Sweet ("LLS") stream at St. James, Louisiana, which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The LLS benchmark averaged US$61.88/bbl during Q3/2019 and US$63.54/bbl during YTD 2019 which is a premium to WTI of US$5.43/bbl in Q3/2019 and US$6.48/bbl in YTD 2019. The LLS benchmark averaged US$75.25/bbl or a premium to WTI of US$5.75/bbl in Q3/2018 and US$71.24/bbl or a premium of US$4.49/bbl in YTD 2018.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $68.41/bbl for Q3/2019 and $69.59/bbl for YTD 2019 compared to $81.92/bbl for Q3/2018 and $78.19/bbl for YTD 2018. Production curtailments mandated by the Government of Alberta have narrowed the Edmonton par differential to WTI in 2019. Edmonton par traded at a US$4.66/bbl discount to WTI in Q3/2019 and a discount of US$4.70/bbl in YTD 2019 compared to a US$6.82/bbl discount in Q3/2018 and a US$6.03/bbl discount in YTD 2018.

The price received for our heavy oil production in Canada is based on the WCS benchmark price which is the representative benchmark for heavy grades of crude oil in Western Canada. We continue to benefit from a narrowing of the WCS heavy oil differential due to the Government of Alberta production curtailments which came into effect in January of 2019. The WCS heavy oil differential to WTI averaged US$12.24/bbl in Q3/2019 and US$11.74/bbl in YTD 2019 as compared to US$22.25/bbl for Q3/2018 and US$21.93 for YTD 2018. As a result, the WCS heavy oil benchmark price of $60.24/bbl in YTD 2019 increased $2.53/bbl from $57.71/bbl in YTD 2018 despite a $10.12/bbl decrease in WTI (expressed in Canadian dollars) over the same periods.

Natural Gas

North American natural gas prices for Q3/2019 and YTD 2019 were lower than Q3/2018 and YTD 2018 as significant growth in North American natural gas production outpaced growth in natural gas demand. Canadian natural gas prices remained challenged during Q3/2019 and YTD 2019 as a lack of egress from Western Canada continues to impact natural gas prices in the region.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$2.23/mmbtu in Q3/2019 and US$2.67/mmbtu in YTD 2019 which is lower compared to US$2.90/mmbtu in both periods of 2018. Record natural gas production levels in the U.S. have resulted in an oversupplied North American market and lower natural gas prices in 2019 relative to 2018.

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 AECO benchmark averaged $1.04/mcf during Q3/2019 and $1.39/mcf in YTD 2019 which is lower than $1.35/mcf for Q3/2018 and $1.41/mcf in YTD 2018.

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Q3 2019 MD&A Page 5

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2019 and 2018.



	Three Months Ended September 30						Nine Months Ended September 30
	2019		2018		Change		2019		2018		Change
Benchmark Averages
WTI oil (US$/bbl)⁽¹⁾	56.45		69.50		(13.05	)	57.06		66.75		(9.69	)
LLS oil (US$/bbl)⁽²⁾	61.88		75.25		(13.37	)	63.54		71.24		(7.70	)
LLS oil differential to WTI (US$/bbl)	5.43		5.75		(0.32	)	6.48		4.49		1.99
Edmonton par oil ($/bbl)	68.41		81.92		(13.51	)	69.59		78.19		(8.60	)
Edmonton par oil differential to WTI (US$/bbl)	(4.66	)	(6.82	)	2.16		(4.70	)	(6.03	)	1.33
WCS heavy oil ($/bbl)⁽³⁾	58.39		61.76		(3.37	)	60.24		57.71		2.53
WCS heavy oil differential to WTI (US$/bbl)	(12.24	)	(22.25	)	10.01		(11.74	)	(21.93	)	10.19
AECO natural gas price ($/mcf)⁽⁴⁾	1.04		1.35		(0.31	)	1.39		1.41		(0.02	)
NYMEX natural gas price (US$/mmbtu)⁽⁵⁾	2.23		2.90		(0.67	)	2.67		2.90		(0.23	)
CAD/USD average exchange rate	1.3207		1.3070		0.0137		1.3292		1.2877		0.0415


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


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


(3)	WCS refers to the average posting price for the benchmark WCS heavy 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
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices⁽¹⁾
Light oil and condensate ($/bbl)	$	65.20	$	75.01	$	69.86	$	76.42	$	93.37	$	87.73
Heavy oil ($/bbl)⁽²⁾	44.39		—		44.39		48.15		—		48.15
NGL ($/bbl)	10.26		15.07		14.27		41.11		36.93		37.38
Natural gas ($/mcf)	0.95		3.08		2.03		1.21		3.90		2.66
Weighted average ($/boe)⁽²⁾	$	45.96	$	48.99	$	47.14	$	47.66	$	63.98	$	55.03

	Nine Months Ended September 30
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices⁽¹⁾
Light oil and condensate ($/bbl)	$	66.20	$	77.81	$	71.77	$	75.08	$	86.90	$	84.98
Heavy oil ($/bbl)⁽²⁾	45.53		—		45.53		43.95		—		43.95
NGL ($/bbl)	17.12		18.74		18.52		35.33		31.37		31.87
Natural gas ($/mcf)	1.49		3.51		2.55		1.39		3.80		2.72
Weighted average ($/boe)⁽²⁾	$	47.69	$	50.67	$	48.88	$	40.56	$	59.89	$	50.09


(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.

Average Realized Sales Prices

Our weighted average sales price was $47.14/boe for Q3/2019 and $48.88/boe for YTD 2019 compared to $55.03/boe for Q3/2018 and $50.09/boe in YTD 2018. Our realized price in the U.S. was $48.99/boe in Q3/2019 which is $14.99/boe lower than $63.98/boe in Q3/2018 due to the decrease in U.S. crude oil benchmark prices. In Canada, our realized price of $45.96/boe for Q3/2019 was $1.70/boe lower than $47.66/boe for Q3/2018 as the decline in benchmark prices was partially offset by a higher weighting of light oil in our Canadian production over the same periods.

Baytex Energy Corp.

Q3 2019 MD&A Page 6

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $65.20/bbl in Q3/2019 and $66.20/bbl in YTD 2019 compared to $76.42/bbl in Q3/2018 and $75.08/bbl in YTD 2018. Our realized light oil and condensate price for Q3/2019 and YTD 2019 represents a discount of $3.21/bbl and $3.39/bbl to the Edmonton par price for the same periods. Our Canadian light oil price realizations have improved following the acquisition of our Viking and Duvernay light oil properties in Q3/2018 which receive higher pricing than our legacy light oil properties in Canada which reported a $9.14/bbl discount to the Edmonton par benchmark for the first six months of 2018.

We compare the price received for our U.S. light oil and condensate production to the LLS benchmark. Our realized light oil and condensate price averaged $75.01/bbl for Q3/2019 and $77.81/bbl for YTD 2019 compared to $93.37/bbl for Q3/2018 and $86.90/bbl in YTD 2018. Expressed in U.S. dollars, our realized light oil and condensate price of US$56.80/bbl for Q3/2019 and US$58.54/bbl for YTD 2019. Our realized light oil and condensate pricing reflects a change in certain marketing contracts to be based on the Magellan East Houston ("MEH") benchmark which is representative pricing at the Magellan East crude oil terminal in Houston, Texas. This change in marketing contracts during Q1/2019 resulted in a US$5.08/bbl discount to the LLS benchmark for Q3/2019 and a US$5.00/bbl discount for YTD 2019 relative to a discount of US$3.81/bbl and US$3.76/bbl for the same periods of 2018.

Our realized heavy oil price, net of blending and other expense averaged $44.39/bbl in Q3/2019 and $45.53/bbl for YTD 2019 compared to $48.15/bbl in Q3/2018 and $43.95/bbl in YTD 2018. Our realized heavy oil price for Q3/2019 was $3.76/bbl lower in Q3/2018 which is relatively consistent with the $3.37/bbl decrease in the WCS benchmark over the same period. The increase in our realized heavy oil price for YTD 2019 was $1.58/bbl which is slightly lower than the $2.53/bbl increase in the WCS benchmark compared to YTD 2018. While our realized heavy oil price has improved in 2019 it did not increase as much as the WCS benchmark due to certain WTI based heavy oil marketing contracts that were entered into prior to the Government of Alberta's decision to curtail production which resulted in a narrowing of the WCS differential.

Our realized NGL 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 for the underlying products. Our realized NGL price was $14.27/bbl in Q3/2019 or 19% of WTI (expressed in Canadian dollars) compared to $37.38/bbl or 41% of WTI (expressed in Canadian dollars) in Q3/2018. Our YTD 2019 realized NGL price was $18.52/bbl or 24% of WTI (expressed in Canadian dollars) compared to $31.87/bbl or 37% of WTI (expressed in Canadian dollars) for YTD 2018. The decrease in our realized NGL price for Q3/2019 and YTD 2019 reflects higher production and NGL supply in North America which resulted in lower market prices for propane and butane relative to Q3/2018 and YTD 2018.

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $0.95/mcf for Q3/2019 and $1.49/mcf for YTD 2019 compared to $1.21/mcf in Q3/2018 and $1.39/mcf in YTD 2018. The change in our realized natural gas prices in both periods of 2019 is relatively consistent with the change in the AECO natural gas price over the same periods of 2018. In the U.S., our realized natural gas price was US$2.33/mcf for Q3/2019 and US$2.64/mcf for YTD 2019 compared to US$2.98/mcf in Q3/2018 and US$2.95/mcf in YTD 2018. Our realized natural gas price in the U.S. is relatively consistent with the NYMEX benchmark in both periods of 2019 and 2018.

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Q3 2019 MD&A Page 7

Petroleum and Natural Gas Sales



	Three Months Ended September 30
	2019								2018
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	134,921		$	140,344	$	275,265		$	69,557		$	170,402	$	239,959
Heavy oil	117,961			—		117,961			139,305			—		139,305
NGL	1,486			11,045		12,531			4,147			30,508		34,655
Total oil sales	254,368			151,389		405,757			213,009			200,910		413,919
Natural gas sales	4,401			14,442		18,843			4,796			18,046		22,842
Total petroleum and natural gas sales	258,769			165,831		424,600			217,805			218,956		436,761
Blending and other expense	(12,950		)	—		(12,950		)	(19,548		)	—		(19,548		)
Total sales, net of blending and other expense	$	245,819		$	165,831	$	411,650		$	198,257		$	218,956	$	417,213

	Nine Months Ended September 30
	2019								2018
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	409,117		$	442,763	$	851,880		$	79,894		$	476,086	$	555,980
Heavy oil	381,684			—		381,684			364,957			—		364,957
NGL	6,684			47,656		54,340			11,595			71,480		83,075
Total oil sales	797,485			490,419		1,287,904			456,446			547,566		1,004,012
Natural gas sales	20,021			52,099		72,120			15,296			51,125		66,421
Total petroleum and natural gas sales	817,506			542,518		1,360,024			471,742			598,691		1,070,433
Blending and other expense	(50,628		)	—		(50,628		)	(55,077		)	—		(55,077		)
Total sales, net of blending and other expense	$	766,878		$	542,518	$	1,309,396		$	416,665		$	598,691	$	1,015,356

Total sales, net of blending and other expense, of $411.7 million for Q3/2019 decreased $5.6 million from $417.2 million reported for Q3/2018 while total sales, net of blending and other expense, of $1,309.4 million for YTD 2019 was $294.0 million higher than $1,015.4 million in YTD 2018. Production for Q3/2019 and YTD 2019 was 12,515 boe/d and 23,879 boe/d higher than the same periods of 2018 due to the Strategic Combination along with our exploration and development programs. The increase in total sales from higher production in Q3/2019 and YTD 2019 was offset by lower realized pricing relative to the same periods of 2018.

In Canada, total sales, net of blending and other expense, was $245.8 million for Q3/2019 which is an increase of $47.6 million from Q3/2018. Total petroleum and natural gas sales increased with production due to the Strategic Combination and our exploration and development programs. Production in Canada was 12,920 boe/d higher in Q3/2019 which resulted in a $56.7 million increase in total sales, net of blending and other expense relative to Q3/2018. Our average realized price of $45.96/boe for Q3/2019 was slightly lower than $47.66/boe for Q3/2018 due to the decrease in benchmark pricing for our production in Canada and resulted in a $9.1 million decrease in total sales, net of blending and other expense. Higher production and stronger realized pricing resulted in our total sales, net of blending and other expense, increasing to $766.9 million in YTD 2019 from $416.7 million in YTD 2018.

In the U.S., petroleum and natural gas sales were $165.8 million for Q3/2019 and decreased $53.1 million from $219.0 million reported for Q3/2018. The decrease in total sales was primarily from lower realized pricing for Q3/2019 which decreased $14.99/boe from Q3/2018 and resulted in a $50.7 million decrease in total petroleum and natural gas sales. Lower realized pricing in YTD 2019 resulted in petroleum and natural gas sales of $542.5 million which was $56.2 million lower than $598.7 million for YTD 2018 despite a 2,604 boe/d increase in production over the same period.

Baytex Energy Corp.

Q3 2019 MD&A Page 8

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, 2019 and 2018.



	Three Months Ended September 30
	2019									2018
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	26,193		$	48,824		$	75,017		$	26,139		$	65,806		$	91,945
Average royalty rate⁽¹⁾	10.7		%	29.4		%	18.2		%	13.2		%	30.1		%	22.0		%
Royalties per boe	$	4.90		$	14.42		$	8.59		$	6.28		$	19.23		$	12.13

	Nine Months Ended September 30
	2019									2018
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	82,313		$	160,646		$	242,959		$	55,471		$	178,518		$	233,989
Average royalty rate⁽¹⁾	10.7		%	29.6		%	18.6		%	13.3		%	29.8		%	23.0		%
Royalties per boe	$	5.12		$	15.00		$	9.07		$	5.40		$	17.86		$	11.54


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

Total royalties in YTD 2019 were $243.0 million or 18.6% of total sales, net of blending and other expense compared to $234.0 million or 23.0% in YTD 2018. Our average royalty rate was 18.6% for YTD 2019 which is consistent with our annual guidance of approximately 19.0% for 2019.

Royalties for Q3/2019 were $75.0 million and averaged 18.2% of total sales, net of blending and other expense, compared to $91.9 million or 22.0% for Q3/2018. Total royalty expense is lower in Q3/2019 due to the decrease in petroleum and natural gas sales in the U.S. relative to Q3/2018 combined with a decrease in our total royalty rate due to the Strategic Combination. The increase in total sales, net of blending and other expense for YTD 2019 resulted in higher total royalties relative to YTD 2018 which was partially offset by the decrease in our total royalty rate over the same periods.

Our Canadian royalty rate of 10.7% for Q3/2019 and YTD 2019 was lower than 13.2% for Q3/2018 and 13.3% for YTD 2018 due to the lower royalty rate on our Viking light oil properties which were acquired in the Strategic Combination. In the U.S., royalties for Q3/2019 and YTD 2019 averaged 29.4% and 29.6% of total petroleum and natural gas sales which is consistent with the same periods of 2018 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

Operating Expense



	Three Months Ended September 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	73,701	$	23,676	$	97,377	$	54,710	$	22,988	$	77,698
Operating expense per boe	$	13.78	$	6.99	$	11.15	$	13.15	$	6.72	$	10.25

	Nine Months Ended September 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	221,680	$	76,463	$	298,143	$	147,054	$	66,681	$	213,735
Operating expense per boe	$	13.79	$	7.14	$	11.13	$	14.31	$	6.67	$	10.54

Operating expense of $11.15/boe for Q3/2019 and $11.13/boe for YTD 2019 is consistent with expectations and our 2019 annual guidance range of $10.75 - $11.25/boe.

Operating expense was $97.4 million ($11.15/boe) for Q3/2019 and $298.1 million ($11.13/boe) for YTD 2019 compared to $77.7 million ($10.25/boe) in Q3/2018 and $213.7 million ($10.54/boe) in YTD 2018. The increase in total operating expense is from higher production in Q3/2019 and YTD 2019 relative to Q3/2018 and YTD 2018 along with a slight increase in per unit operating expense.

Baytex Energy Corp.

Q3 2019 MD&A Page 9

In Canada, operating expense was $73.7 million ($13.78/boe) for Q3/2019 and $221.7 million ($13.79/boe) for YTD 2019 compared to $54.7 million ($13.15/boe) for Q3/2018 and $147.1 million ($14.31/boe) for YTD 2018. Total operating expense in Canada has increased with higher production following the Strategic Combination. Per unit operating costs of $13.78/boe for Q3/2019 and $13.79/boe in YTD 2019 were consistent with $13.15/boe in Q3/2018 and lower than $14.31/boe in YTD 2018 as our Viking and Duvernay properties have lower per unit operating expense relative to our other Canadian properties which resulted in lower per unit operating expense in Canada following the Strategic Combination.

U.S. operating expense was $23.7 million ($6.99/boe) for Q3/2019 and $76.5 million ($7.14/boe) for YTD 2019 compared to $23.0 million ($6.72/boe) for Q3/2018 and $66.7 million ($6.67/boe) for YTD 2018. The increase in total operating expense reflects higher U.S. production combined with a weaker Canadian dollar in Q3/2019 and YTD 2019 compared to Q3/2018 and YTD 2018. Expressed in U.S. dollars, per boe operating expense for our U.S. properties have been fairly consistent and were US$5.29/boe in Q3/2019 and US$5.37/boe in YTD 2019 compared to US$5.14/boe for Q3/2018 and US$5.18/boe in YTD 2018.

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, 2019 and 2018.



	Three Months Ended September 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	9,903	$	—	$	9,903	$	9,520	$	—	$	9,520
Transportation expense per boe	$	1.85	$	—	$	1.13	$	2.29	$	—	$	1.26

	Nine Months Ended September 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	35,102	$	—	$	35,102	$	25,875	$	—	$	25,875
Transportation expense per boe	$	2.18	$	—	$	1.31	$	2.52	$	—	$	1.28

We reported transportation expense of $1.31/boe for YTD 2019 which is in line with expectations and our guidance range of $1.25 - $1.35/boe for 2019. Transportation expense was $9.9 million ($1.13/boe) for Q3/2019 and $35.1 million ($1.31/boe) for YTD 2019 compared to $9.5 million ($1.26/boe) for Q3/2018 and $25.9 million ($1.28/boe) for YTD 2018. The increase in transportation expense for 2019 reflects additional oil trucking and transportation costs associated with our Viking and Duvernay light oil properties acquired as part of the Strategic Combination.

Blending and Other Expense

Blending and other expense primarily includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines in order 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.

Blending and other expense was $13.0 million for Q3/2019 and $50.6 million for YTD 2019 which is relatively consistent with $19.5 million for Q3/2018 and $55.1 million for YTD 2018. The decrease in blending and other expense in both periods of 2019 was primarily a result of a decrease in the cost of blending diluent relative to the same periods of 2018.

Baytex Energy Corp.

Q3 2019 MD&A Page 10

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, 2019 and 2018.



	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2019			2018			Change			2019			2018			Change
Realized financial derivatives gain (loss)
Crude oil	$	19,631		$	(31,704	)	$	51,335		$	49,944		$	(72,529	)	$	122,473
Natural gas	1,243			872			371			2,713			2,448			265
Interest and financing	(17		)	(22		)	5			7			(22		)	29
Total	$	20,857		$	(30,854	)	$	51,711		$	52,664		$	(70,103	)	$	122,767
Unrealized financial derivatives gain (loss)
Crude oil	$	8,559		$	4		$	8,555		$	(29,083	)	$	(63,454	)	$	34,371
Natural gas	(1,041		)	(1,027		)	(14		)	(1,391		)	(2,663		)	1,272
Interest and financing	148			977			(829		)	(448		)	977			(1,425		)
Total	$	7,666		$	(46	)	$	7,712		$	(30,922	)	$	(65,140	)	$	34,218
Total financial derivatives gain (loss)
Crude oil	$	28,190		$	(31,700	)	$	59,890		$	20,861		$	(135,983	)	$	156,844
Natural gas	202			(155		)	357			1,322			(215		)	1,537
Interest and financing	131			955			(824		)	(441		)	955			(1,396		)
Total	$	28,523		$	(30,900	)	$	59,423		$	21,742		$	(135,243	)	$	156,985

We recorded total financial derivative gains of $28.5 million for Q3/2019 and $21.7 million for YTD 2019. Realized financial derivatives gains of $20.9 million for Q3/2019 and $52.7 million for YTD 2019 are primarily a result of the market prices for crude oil settling at levels below those set in our derivative contracts. The unrealized gain of $7.7 million for Q3/2019 and unrealized loss of $30.9 million for YTD 2019 is primarily a result of fluctuations in the futures prices for crude oil which impacts the fair value of our contracts in place at September 30, 2019.

Realized gains on crude oil financial derivatives of $19.6 million in Q3/2019 and $49.9 million for YTD 2019 are primarily a result of market prices for Brent and WTI settling at levels below the prices set in our contracts outstanding during the periods. Our natural gas financial derivatives generated gains of $1.2 million in Q3/2019 and $2.7 million for YTD 2019. These gains were primarily a result of the NYMEX index for Q3/2019 and YTD 2019 averaging less than the fixed price on our NYMEX contracts in place for both periods.

We recorded unrealized gains of $7.7 million in Q3/2019 and unrealized losses of $30.9 million in YTD 2019 due to fluctuations in the futures prices for crude oil along with additional notional volumes associated with financial derivative contracts entered for 2020. The fair value of our financial derivative contracts was a net asset of $48.7 million at September 30, 2019 compared to a net asset of $41.0 million at June 30, 2019 and a net asset of $79.6 million at December 31, 2018.

Baytex Energy Corp.

Q3 2019 MD&A Page 11

We had the following commodity financial derivative contracts as at October 31, 2019.



	Period	Volume	Price/Unit ⁽¹⁾		Index
Oil
Basis Swap	Oct 2019 to Dec 2019	7,000 bbl/d	WTI less US$17.59/bbl		WCS
Basis Swap	Oct 2019 to Dec 2019	4,000 bbl/d	WTI less US$8.00/bbl		MSW
Basis Swap	Jan 2020 to Dec 2020	2,500 bbl/d	WTI less US$16.10/bbl		WCS
Fixed - Sell	Oct 2019 to Dec 2019	12,000 bbl/d	US$62.35/bbl		WTI
Fixed - Sell	Oct 2019 to Dec 2019	2,000 bbl/d	US$65.50/bbl		Brent
Fixed - Sell ⁽⁵⁾	Jan 2020 to Mar 2020	4,000 bbl/d	US$55.90/bbl		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	2,000 bbl/d	US$49.00/US$61.70/US$75.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	2,000 bbl/d	US$50.00/US$60.00/US$70.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$55.00/US$65.00/US$72.60		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$56.00/US$66.00/US$72.50		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$56.00/US$66.00/US$73.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	2,000 bbl/d	US$57.00/US$67.00/US$73.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	2,000 bbl/d	US$58.00/US$68.00/US$74.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$60.00/US$69.90/US$75.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$61.00/US$71.00/US$76.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$63.00/US$73.00/US$78.00		WTI
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$55.50/US$65.50/US$75.50		Brent
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$60.00/US$70.00/US$77.55		Brent
3-way option⁽²⁾	Oct 2019 to Dec 2019	1,000 bbl/d	US$63.00/US$73.00/US$83.00		Brent
3-way option⁽²⁾	Jan 2020 to Dec 2020	3,000 bbl/d	US$50.00/US$56.00/US$61.35		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	3,000 bbl/d	US$50.00/US$57.00/US$60.00		WTI
3-way option⁽²⁾⁽⁵⁾	Jan 2020 to Dec 2020	3,000 bbl/d	US$50.00/US$57.00/US$62.00		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	1,500 bbl/d	US$51.00/US$59.00/US$65.60		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	1,500 bbl/d	US$51.00/US$59.00/US$66.00		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$59.50/US$66.15		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$60.00/US$65.60		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$60.00/US$66.00		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$60.00/US$66.05		WTI
3-way option⁽²⁾	Jan 2020 to Dec 2020	2,000 bbl/d	US$51.00/US$60.00/US$66.70		WTI
Swaption⁽³⁾	Jan 2020 to Dec 2020	1,000 bbl/d	US$62.50/bbl		WTI
Swaption⁽³⁾	Jan 2020 to Dec 2020	1,000 bbl/d	US$63.20/bbl		WTI
Swaption⁽⁴⁾	Jan 2021 to Dec 2021	3,000 bbl/d	US$60.75/bbl		WTI
Swaption⁽⁴⁾⁽⁵⁾	Jan 2021 to Dec 2021	3,000 bbl/d	US$70.00/bbl		Brent

Natural Gas
Fixed - Sell	Oct 2019 to Dec 2019	15,000 mmbtu/d		US$2.97	NYMEX


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

(2)

Producer 3-way option consists of a sold put, a bought put and a sold call. To illustrate, in a US$50/US$60/US$70 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, 2019, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.


(4)	For these contracts, the counterparty has the right, if exercised on December 30, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.


(5)	Contracts entered subsequent to September 30, 2019.

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.

Baytex Energy Corp.

Q3 2019 MD&A Page 12

As at October 31, 2019, Baytex had committed to deliver the following volumes of raw bitumen to market on rail.



Period	Volume
Oct 2019	1,000 bbl/d
Oct 2019 to Dec 2019	11,000 bbl/d
Jan 2020 to Dec 2020	7,500 bbl/d

Baytex Energy Corp.

Q3 2019 MD&A Page 13

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, 2019 and 2018.



	Three Months Ended September 30
	2019									2018
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)	58,134			36,793			94,927			45,214			37,198			82,412
Operating netback:
Total sales, net of blending and other expense	$	45.96		$	48.99		$	47.14		$	47.66		$	63.98		$	55.03
Less:
Royalties	(4.90		)	(14.42		)	(8.59		)	(6.28		)	(19.23		)	(12.13		)
Operating expense	(13.78		)	(6.99		)	(11.15		)	(13.15		)	(6.72		)	(10.25		)
Transportation expense	(1.85		)	—			(1.13		)	(2.29		)	—			(1.26		)
Operating netback	$	25.43		$	27.58		$	26.27		$	25.94		$	38.03		$	31.39
Realized financial derivatives gain (loss)	—			—			2.39			—			—			(4.07		)
Operating netback after financial derivatives	$	25.43		$	27.58		$	28.66		$	25.94		$	38.03		$	27.32

	Nine Months Ended September 30
	2019									2018
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)	58,904			39,221			98,125			37,629			36,617			74,246
Operating netback:
Total sales, net of blending and other expense	$	47.69		$	50.67		$	48.88		$	40.56		$	59.89		$	50.09
Less:
Royalties	(5.12		)	(15.00		)	(9.07		)	(5.40		)	(17.86		)	(11.54		)
Operating expense	(13.79		)	(7.14		)	(11.13		)	(14.31		)	(6.67		)	(10.54		)
Transportation expense	(2.18		)	—			(1.31		)	(2.52		)	—			(1.28		)
Operating netback	$	26.60		$	28.53		$	27.37		$	18.33		$	35.36		$	26.73
Realized financial derivatives gain (loss)	—			—			1.97			—			—			(3.46		)
Operating netback after financial derivatives	$	26.60		$	28.53		$	29.34		$	18.33		$	35.36		$	23.27

Our operating netback after financial derivatives was $28.66/boe for Q3/2019 which was $1.34/boe higher than $27.32/boe for Q3/2018. Operating netback after financial derivatives of $29.34/boe for YTD 2019 was $6.07/boe higher than $23.27/boe for the same period of 2018. Operating netback of $26.27/boe in Q3/2019 was lower than $31.39/boe in Q3/2018 due to the decrease in benchmark pricing which resulted in lower per unit sales net of royalties. This was more than offset by the difference on financial derivatives of $6.46/boe in Q3/2019 as we recorded realized gains of $2.39/boe in Q3/2019 compared to realized losses of $4.07/boe in Q3/2018. Our operating netback was $27.37/boe for YTD 2019 compared to YTD 2018 when our operating netback was $26.73/boe as the decrease in our royalty rate more than offset the impact of lower benchmark pricing. We recorded realized gains on financial derivatives of $1.97/boe in YTD 2019 which also contributed to the increase in operating netback after financial derivatives compared YTD 2018 when we recorded realized losses of $3.46/boe.

In Canada, our operating netback was $25.43/boe in Q3/2019 and $26.60/boe in YTD 2019 compared to $25.94/boe in Q3/2018 and $18.33/boe in YTD 2018. Lower benchmark pricing in Q3/2019 resulted in a decrease in our operating netback relative to Q3/2018 despite improved price realizations and a lower royalty rate following the Strategic Combination. The increase in our netback in YTD 2019 was primarily from an increase in our realized sales price per boe as a higher portion of our production was from light oil after the Strategic Combination along with narrower Canadian oil differentials. Our operating netback in the U.S. of $27.58/boe in Q3/2019 and $28.53/boe in YTD 2019 was lower than $38.03/boe in Q3/2018 and $35.36/boe in YTD 2018 as our realized sales price decreased with lower benchmark pricing in both periods of 2019 relative to 2018.

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 exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.

Baytex Energy Corp.

Q3 2019 MD&A Page 14

The following table summarizes our G&A expense for the three and nine months ended September 30, 2019 and 2018.



	Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for per boe)	2019			2018			Change			2019			2018			Change
Gross general and administrative expense	$	11,633		$	13,016		$	(1,383	)	$	39,907		$	38,338		$	1,569
Overhead recoveries	(1,699		)	(2,858		)	1,159			(4,331		)	(6,609		)	2,278
General and administrative expense	$	9,934		$	10,158		$	(224	)	$	35,576		$	31,729		$	3,847
General and administrative expense per boe	$	1.14		$	1.34		$	(0.20	)	$	1.33		$	1.57		$	(0.24	)

We reported G&A expense of $35.6 million ($1.33/boe) for YTD 2019 which is in line with expectations and is consistent with our annual guidance of approximately $46 million ($1.30/boe). We expected G&A expense to decrease during the second half of 2019 as we continue to optimize our business following the Strategic Combination. G&A expense was $9.9 million ($1.14/boe) for Q3/2019 compared to $10.2 million ($1.34/boe) for Q3/2018 which only includes the additional staff and costs associated with the Strategic Combination following closing on August 22, 2018. G&A expense of $35.6 million for YTD 2019 was higher relative to $31.7 million for YTD 2018 due to the additional staff and costs required to integrate the two organizations following the Strategic Combination in Q3/2018. The decrease in G&A expense per boe in Q3/2019 and YTD 2019 relative to the same periods of 2018 reflects the efficiencies we were able to realize by combining the two organizations.

Financing and Interest Expense

Financing and interest expense includes interest on our bank loan, long-term notes and lease obligations as well as non-cash financing costs and the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, 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.

The following table summarizes our financing and interest expense for the three and nine months ended September 30, 2019 and 2018.



	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for per boe)	2019		2018		Change			2019		2018		Change
Interest on bank loan	$	4,650	$	4,108	$	542		$	15,171	$	10,297	$	4,874
Interest on long-term notes	21,955		22,235		(280		)	67,382		66,087		1,295
Interest on lease obligations	147		—		147			475		—		475
Cash interest	$	26,752	$	26,343	$	409		$	83,028	$	76,384	$	6,644
Accretion of debt issue costs	1,607		866		741			3,753		2,991		762
Accretion of asset retirement obligations	3,407		2,820		587			10,268		7,450		2,818
Financing and interest expense	$	31,766	$	30,029	$	1,737		$	97,049	$	86,825	$	10,224
Cash interest per boe	$	3.06	$	3.47	$	(0.41	)	$	3.10	$	3.77	$	(0.67	)
Financing and interest expense per boe	$	3.64	$	3.96	$	(0.32	)	$	3.62	$	4.28	$	(0.66	)

Cash interest expense of $83.0 million or $3.10/boe for YTD 2019 was in line with expectations and our 2019 annual guidance of approximately $112 million or $3.23/boe.

Financing and interest expense was $31.8 million in Q3/2019 and $97.0 million for YTD 2019 compared to $30.0 million in Q3/2018 and $86.8 million in YTD 2018. Interest on our bank loan of $4.7 million in Q3/2019 and $15.2 million in YTD 2019 was higher than $4.1 million in Q3/2018 and $10.3 million in YTD 2018 primarily due to the assumption of net debt associated with the Strategic Combination. The weighted average interest rate on our bank loan was 4.3% in YTD 2019 compared to 4.5% in YTD 2018. Interest on our long-term notes was $22.0 million for Q3/2019 and $67.4 million for YTD 2019 compared to $22.2 million for Q3/2018 and $66.1 million for YTD 2018. We redeemed the US$150 million principal amount of 6.75% senior unsecured notes on September 13, 2019 which resulted in slightly lower interest on our long-term notes in Q3/2019 relative to the same period of 2018. The reported amount of interest on our long-term notes was higher in YTD 2019 due to an increase in the exchange rate used to convert the interest on our U.S. dollar denominated long-term notes relative to YTD 2018. Accretion of our asset retirement obligations was higher in Q3/2019 and YTD 2019 as our asset retirement obligation increased with the Strategic Combination.

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Q3 2019 MD&A Page 15

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 of $2.1 million for Q3/2019 and $8.7 million for YTD 2019 is higher than $0.5 million for Q3/2018 and $3.9 million for YTD 2018 primarily due to a higher amount of acreage expiring in 2019 relative to 2018.

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, 2019 and 2018.



	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2019		2018		Change		2019		2018		Change
Depletion	$	178,364	$	143,913	$	34,451	$	547,345	$	362,726	$	184,619
Depreciation	2,058		588		1,470		4,203		1,928		2,275
Depletion and depreciation	$	180,422	$	144,501	$	35,921	$	551,548	$	364,654	$	186,894
Depletion and depreciation per boe	$	20.66	$	19.06	$	1.60	$	20.59	$	17.99	$	2.60

Depletion and depreciation expense was $180.4 million ($20.66/boe) for Q3/2019 and $551.5 million ($20.59/boe) for YTD 2019 compared to $144.5 million ($19.06/boe) for Q3/2018 and $364.7 million ($17.99/boe) for YTD 2018. Total depletion and depreciation expense was higher in both periods of 2019 due to the Strategic Combination which resulted in a higher depletable base and production relative to the comparative periods of 2018. The depletion rate per boe increased following the Strategic Combination due to the addition of proved plus probable reserves at a higher cost than our historic base.

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.

We recorded SBC expense of $3.4 million for Q3/2019 and $14.2 million for YTD 2019 compared to $7.2 million for Q3/2018 and $15.0 million for YTD 2018. SBC expense is lower in both periods of 2019 due to the lower total value of awards granted in YTD 2019 compared to YTD 2018 which included additional SBC expense in Q3/2018 associated with the Strategic Combination.

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 functional currency entities.

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Q3 2019 MD&A Page 16



	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for exchange rates)	2019		2018			Change		2019			2018		Change
Unrealized foreign exchange loss (gain)	$	13,855	$	(20,583	)	$	34,438	$	(38,404	)	$	38,136	$	(76,540	)
Realized foreign exchange loss (gain)	382		(360		)	742		426			1,887		(1,461		)
Foreign exchange loss (gain)	$	14,237	$	(20,943	)	$	35,180	$	(37,978	)	$	40,023	$	(78,001	)
CAD/USD exchange rates:
At beginning of period	1.3091		1.3142					1.3646			1.2518
At end of period	1.3244		1.2924					1.3244			1.2924

We recorded an unrealized foreign exchange loss of $13.9 million for Q3/2019 due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2019 compared to June 30, 2019. This compares to an unrealized foreign exchange gain of $20.6 million in Q3/2018 due to the strengthening of the Canadian dollar relative to the U.S. dollar over Q3/2018.

We recorded an unrealized foreign exchange gain of $38.4 million for YTD 2019 due to the strengthening of the Canadian dollar relative to the U.S. dollar at September 30, 2019 compared to December 31, 2018. This compares to an unrealized foreign exchange loss of $38.1 million for YTD 2018 due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2018 compared to 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 $0.4 million for Q3/2019 and YTD 2019 compared to a gain of $0.4 million for Q3/2018 and a loss of $1.9 million for YTD 2018.

Income Taxes



	Three Months Ended September 30							Nine Months Ended September 30
($ thousands)	2019		2018			Change		2019			2018			Change
Current income tax expense (recovery)	$	501	$	—		$	501	$	1,591		$	(71	)	$	1,662
Deferred income tax expense (recovery)	1,082		(4,427		)	5,509		(14,958		)	(51,905		)	36,947
Total income tax expense (recovery)	$	1,583	$	(4,427	)	$	6,010	$	(13,367	)	$	(51,976	)	$	38,609

Current income tax expense was $0.5 million for Q3/2019 and $1.6 million for YTD 2019 compared to the nominal amounts recorded for Q3/2018 and YTD 2018. The current income tax expense for Q3/2019 and YTD 2019 reflects state taxes owing on our U.S. operations.

We recorded deferred income tax expense of $1.1 million for Q3/2019 and a recovery of $15.0 million for YTD 2019 as compared to a recovery of $4.4 million for Q3/2018 and $51.9 million for YTD 2018. Our deferred income tax recovery for YTD 2019 was lower due to higher adjusted funds flow relative to YTD 2018. The deferred income tax recovery for YTD 2019 includes a $10.6 million recovery associated with the Alberta tax rate reduction.

As disclosed in the 2018 annual financial statements, Baytex received several reassessments from the Canada Revenue Agency (the “CRA”) in June 2016 which denied $591 million of non-capital loss deductions that Baytex had previously claimed. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to our file in July 2018. Baytex remains confident that its original tax filings are correct and intends to defend those tax filings through the appeals process.

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Q3 2019 MD&A Page 17

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, 2019 and 2018 are set forth in the following table.



	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2019			2018			Change			2019			2018			Change
Petroleum and natural gas sales	$	424,600		$	436,761		$	(12,161	)	$	1,360,024		$	1,070,433		$	289,591
Royalties	(75,017		)	(91,945		)	16,928			(242,959		)	(233,989		)	(8,970		)
Revenue, net of royalties	349,583			344,816			4,767			1,117,065			836,444			280,621

Expenses
Operating	(97,377		)	(77,698		)	(19,679		)	(298,143		)	(213,735		)	(84,408		)
Transportation	(9,903		)	(9,520		)	(383		)	(35,102		)	(25,875		)	(9,227		)
Blending and other	(12,950		)	(19,548		)	6,598			(50,628		)	(55,077		)	4,449
Operating netback	$	229,353		$	238,050		$	(8,697	)	$	733,192		$	541,757		$	191,435
General and administrative	(9,934		)	(10,158		)	224			(35,576		)	(31,729		)	(3,847		)
Cash financing and interest	(26,752		)	(26,343		)	(409		)	(83,028		)	(76,384		)	(6,644		)
Realized financial derivatives gain (loss)	20,857			(30,854		)	51,711			52,664			(70,103		)	122,767
Realized foreign exchange (loss) gain	(382		)	360			(742		)	(426		)	(1,887		)	1,461
Other income	738			302			436			5,044			869			4,175
Current income tax (expense) recovery	(501		)	—			(501		)	(1,591		)	71			(1,662		)
Payments on onerous contracts	—			(147		)	147			—			(439		)	439
Adjusted funds flow	$	213,379		$	171,210		$	42,169		$	670,279		$	362,155		$	308,124
Transaction costs	—			(13,066		)	13,066			—			(13,066		)	13,066
Exploration and evaluation	(2,138		)	(510		)	(1,628		)	(8,667		)	(3,887		)	(4,780		)
Depletion and depreciation	(180,422		)	(144,501		)	(35,921		)	(551,548		)	(364,654		)	(186,894		)
Share based compensation	(3,401		)	(7,180		)	3,779			(14,245		)	(15,010		)	765
Non-cash financing and accretion	(5,014		)	(3,686		)	(1,328		)	(14,021		)	(10,441		)	(3,580		)
Unrealized financial derivatives gain (loss)	7,666			(46		)	7,712			(30,922		)	(65,140		)	34,218
Unrealized foreign exchange (loss) gain	(13,855		)	20,583			(34,438		)	38,404			(38,136		)	76,540
Gain on dispositions	18			34			(16		)	1,075			1,764			(689		)
Deferred income tax (expense) recovery	(1,082		)	4,427			(5,509		)	14,958			51,905			(36,947		)
Payments on onerous contracts	—			147			(147		)	—			439			(439		)
Net income (loss) for the period	$	15,151		$	27,412		$	(12,261	)	$	105,313		$	(94,071	)	$	199,384

We generated adjusted funds flow of $213.4 million for Q3/2019 and $670.3 million for YTD 2019 which is an increase of $42.2 million and $308.1 million from the comparative periods of 2018. Realized gains on financial derivatives of $20.9 million for Q3/2019 more than offset the $8.7 million decrease in operating netback due to the decline in oil and natural gas benchmark prices relative to Q3/2018 when we recorded losses on financial derivatives of $30.9 million. Operating netback for YTD 2019 was $191.4 million higher than YTD 2018 due to increased production along with improved light oil price realizations in Canada and a decrease in our average royalty rate as a result of the Strategic Combination. We recorded realized hedging gains $52.7 million in YTD 2019 compared to realized losses of $70.1 million in the same period in 2018 which also contributed to the $308.1 million increase in adjusted funds flow.

In Q3/2019 we reported net income of $15.2 million compared to $27.4 million in Q3/2018. The $42.2 million increase in adjusted funds flow in Q3/2019 compared to Q3/2018 was offset by a $35.9 million increase in depletion and depreciation expense in Q3/2019 along with an unrealized foreign exchange loss that exceeded gains by $34.4 million relative to Q3/2018. Net income was $105.3 million for YTD 2019 compared to a net loss of $94.1 million in YTD 2018. The increase in net income was driven by the $308.1 million increase in adjusted funds flow and by unrealized losses on financial derivatives and foreign exchange gains which increased net income $110.8 million in YTD 2019 compared to YTD 2018. These increases to net income were offset by an increase in depletion and depreciation expense of $186.9 million along with our deferred tax recovery which was $36.9 million lower in YTD 2019 relative to YTD 2018. Net income for Q3/2018 and YTD 2018 include transaction costs of $13.1 million associated with the Strategic Combination.

Other Comprehensive Income (Loss)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in profit or loss. The foreign currency translation gain of $25.3 million for Q3/2019 relates to the change in value of our

Baytex Energy Corp.

Q3 2019 MD&A Page 18

U.S. net assets expressed in Canadian dollars and is due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2019 compared to June 30, 2019. We recorded a foreign currency translation loss of $67.8 million for YTD 2019 due to the strengthening of the Canadian dollar against the U.S. dollar at September 30, 2019 compared to December 31, 2018. The CAD/USD exchange rate was 1.3244 CAD/USD as at September 30, 2019 compared to 1.3091 CAD/USD at June 30, 2019 and 1.3646 CAD/USD as at December 31, 2018.

Capital Expenditures

Capital expenditures for the three and nine months ended September 30, 2019 and 2018 are summarized as follows.



	Three Months Ended September 30
	2019								2018
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Drilling, completion and equipping	$	85,633		$	38,731	$	124,364		$	80,244		$	42,352	$	122,596
Facilities	9,934			2,991		12,925			14,106			2,204		16,310
Land, seismic and other	1,207			589		1,796			127			162		289
Total exploration and development	$	96,774		$	42,311	$	139,085		$	94,477		$	44,718	$	139,195
Total acquisitions and property swaps, net of proceeds from divestitures	$	(30	)	$	—	$	(30	)	$	—		$	—	$	—

	Nine Months Ended September 30
	2019								2018
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Drilling, completion and equipping	$	228,570		$	120,716	$	349,286		$	122,980		$	123,468	$	246,448
Facilities	31,401			7,573		38,974			46,474			11,217		57,691
Land, seismic and other	9,932			982		10,914			7,156			264		7,420
Total exploration and development	$	269,903		$	129,271	$	399,174		$	176,610		$	134,949	$	311,559
Total acquisitions and property swaps, net of proceeds from divestitures	$	1,617		$	—	$	1,617		$	(2,047	)	$	—	$	(2,047	)

Exploration and development expenditures were $139.1 million for Q3/2019 and $399.2 million for YTD 2019 compared to $139.2 million for Q3/2018 and $311.6 million for YTD 2018. Higher exploration and development expenditures in YTD 2019 relative to the same periods of 2018 reflects the additional activity associated with our Viking and Duvernay light oil properties which were acquired during Q3/2018 as part of the Strategic Combination.

In Canada, we invested $96.8 million on exploration and development activities in Q3/2019 which is $2.3 million higher than $94.5 million in Q3/2018. Activity levels were lower in Q3/2019 relative to Q3/2018 which only included investment on exploration and development activities for our Viking and Duvernay light oil properties subsequent to acquisition on August 22, 2018. Exploration and development expenditures for Q3/2019 included costs associated with drilling 82 (72.5 net) light oil wells, 20 (20.0 net) heavy oil wells and investing $9.9 million on facilities. Exploration and development expenditures for Q3/2018 included $80.2 million of costs associated with 87 (66.8 net) wells drilled. Exploration and development expenditures of $269.9 million for YTD 2019 included costs associated with drilling 223 (193.7 net) light oil wells, 25 (25.0 net) heavy oil wells and 4 (4.0 net) stratigraphic exploration wells along with $31.4 million of associated facility expenditures. Total exploration and development costs for YTD 2019 were $93.3 million higher than the same period of 2018 primarily due to the investment on our Viking and Duvernay light oil properties which were acquired in Q3/2018.

Total U.S. exploration and development expenditures were $42.3 million for Q3/2019 which is similar to $44.7 million for Q3/2018. During Q3/2019 we participated in the drilling of 22 (5.3 net) wells and commenced production from 20 (4.6 net) wells compared to 29 (8.0 net) wells drilled and 26 (4.9 net) wells on production during Q3/2018. Exploration and development expenditures of $129.3 million for YTD 2019 include costs associated with drilling 65 (14.5 net) wells and bringing 85 (18.5 net) wells on production which is slightly lower than exploration and development expenditures of $134.9 million in YTD 2018 when we drilled 72 (17.5 net) well and commenced production from 85 (18.0 net) wells.

We completed minor acquisition and disposition activity, including property swaps, in YTD 2019 for net consideration of $1.6 million compared to net proceeds of $2.0 million in YTD 2018.

We are forecasting exploration and development expenditures of approximately $560 million for 2019.

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Q3 2019 MD&A Page 19

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, 2019, our capital structure was comprised of shareholders' capital, long-term notes, 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. Adjusted funds flow depends 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 value creation. At September 30, 2019, net debt was $1,971.3 million, a decrease of $293.9 million from net debt of $2,265.2 million at December 31, 2018. The decrease in net debt is primarily a result of adjusted funds flow exceeding exploration and development expenditures for YTD 2019 by $271.1 million. Net debt was also lower at September 30, 2019 due to a strengthening of the Canadian dollar which resulted in a $32.2 million decrease in the reported principal amount of our U.S. dollar denominated long-term notes relative to December 31, 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, 2019, our net debt to adjusted funds flow ratio was 2.5 compared to a ratio of 3.1 as at December 31, 2018. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2018 is attributed to higher adjusted funds flow due to the increase in production in YTD 2019 combined with a $293.9 million decrease in net debt at September 30, 2019.

Bank Loan

At September 30, 2019, the principal amount of bank loan and letters of credit outstanding was $586.2 million and we had approximately $475.3 million of undrawn capacity under our credit facilities that total approximately $1.06 billion. Our credit facilities include US$575 million of revolving credit facilities (the "Revolving Facilities") and a $300 million non-revolving term loan (the "Term Loan").

On May 2, 2019, we amended our credit facilities to extend maturity of the Revolving Facilities and the Term Loan from June 4, 2020 to April 2, 2021. The credit facilities will automatically be extended to June 4, 2021 providing we have either refinanced, or have the ability to repay, the outstanding 2021 long-term notes with existing credit capacity as of April 1, 2021.

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 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 or will be accessible on the SEDAR website at www.sedar.com (filed under the category "Material contracts" on April 13, 2016, May 2, 2018, October 12, 2018 and May 16, 2019).

The weighted average interest rate on the credit facilities was 4.0% for Q3/2019 and 4.3% for YTD 2019 compared to 4.5% for Q3/2018 and YTD 2018.

Financial Covenants

The following table summarizes the financial covenants applicable to the Revolving Facilities and our compliance therewith at September 30, 2019.



Covenant Description	Position as at September 30, 2019	Covenant
Senior Secured Debt⁽¹⁾ to Bank EBITDA⁽²⁾(Maximum Ratio)	0.66:1.00	3.50:1.00
Interest Coverage⁽³⁾ (Minimum Ratio)	8.02:1.00	2.00:1.00


(1)	"Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at September 30, 2019, the Company's Senior Secured Debt totaled $586.2 million which includes $570.8 million of principal amounts outstanding and $15.4 million of letters of credit.

(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, payments on lease obligations, 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, 2019 was $889.4 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, 2019 were $111.0 million.

Long-Term Notes

On September 13, 2019, we completed the early redemption of the US$150 million principal amount of 6.75% senior unsecured notes which were issued on February 17, 2011. Redemption of these notes was completed at par plus accrued interest at September 13, 2019.

We have three series of long-term notes outstanding that total $1.36 billion as at September 30, 2019. 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. The fixed charge coverage ratio was 8.02:1.00 as at September 30, 2019.

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 and will be redeemable at par from July 19, 2020 to maturity.

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. The 5.125% Notes are redeemable at our option, in whole or in part, at par anytime prior to maturity. As of June 1, 2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified redemption prices and will be redeemable at par from June 1, 2022 to maturity.

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, 2019, we issued 3.9 million common shares pursuant to our share-based compensation program. As at October 31, 2019, we had 558.0 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, 2019 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	$	212,404	$	212,404	$	—	$	—	$	—
Bank loan^{(1) (2)}	570,792		—		570,792		—		—
Long-term notes⁽²⁾	1,359,480		—		829,740		529,740		—
Interest on long-term notes⁽³⁾	240,189		76,822		113,649		49,718		—
Lease agreements	14,815		6,102		8,517		196		—
Processing agreements	43,049		11,541		11,810		8,950		10,748
Transportation agreements	119,908		10,791		39,643		39,553		29,921
Total	$	2,560,637	$	317,660	$	1,574,151	$	628,157	$	40,669


(1)	The bank loan matures on April 2, 2021. Maturity will automatically be extended to June 4, 2021 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2021 long-term notes with existing credit capacity as of April 1, 2021.


(2)	Principal amount of instruments.


(3)	Excludes interest on our bank loan as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances.

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.

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Q3 2019 MD&A Page 20

QUARTERLY FINANCIAL INFORMATION



	2019						2018								2017
($ thousands, except per common share amounts)	Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4
Petroleum and natural gas sales	424,600		482,000		453,424		358,437		436,761		347,605		286,067		303,163
Net income (loss)	15,151		78,826		11,336		(231,238	)	27,412		(58,761	)	(62,722	)	76,038
Per common share - basic	0.03		0.14		0.02		(0.42	)	0.07		(0.25	)	(0.27	)	0.32
Per common share - diluted	0.03		0.14		0.02		(0.42	)	0.07		(0.25	)	(0.27	)	0.32
Adjusted funds flow	213,379		236,130		220,770		110,828		171,210		106,690		84,255		105,796
Per common share - basic	0.38		0.42		0.40		0.20		0.46		0.45		0.36		0.45
Per common share - diluted	0.38		0.42		0.40		0.20		0.45		0.45		0.36		0.44
Exploration and development	139,085		106,246		153,843		184,162		139,195		78,830		93,534		90,156
Canada	96,774		68,259		104,870		125,507		94,477		30,608		51,525		41,864
U.S.	42,311		37,987		48,973		58,655		44,718		48,222		42,009		48,292
Acquisitions, net of divestitures	(30	)	1,647		—		229		—		(21	)	(2,026	)	(3,937	)
Net debt	1,971,339		2,028,686		2,175,241		2,265,167		2,112,090		1,784,835		1,783,379		1,734,284
Total assets	6,233,875		6,222,190		6,359,157		6,377,198		6,491,303		4,476,906		4,433,074		4,372,111
Common shares outstanding	557,972		556,798		555,872		554,060		553,950		236,662		236,578		235,451

Daily production
Total production (boe/d)	94,927		98,402		101,115		98,890		82,412		70,664		69,522		69,556
Canada (boe/d)	58,134		58,580		60,018		60,453		45,214		34,042		33,505		32,194
U.S. (boe/d)	36,793		39,822		41,097		38,437		37,198		36,622		36,017		37,362

Benchmark prices
WTI oil (US$/bbl)	56.45		59.81		54.90		58.81		69.50		67.88		62.87		55.40
WCS heavy (US$/bbl)	44.21		49.14		42.61		19.39		47.25		48.61		38.59		43.14
CAD/USD avg exchange rate	1.3207		1.3376		1.3293		1.3215		1.3070		1.2911		1.2651		1.2717
AECO gas ($/mcf)	1.04		1.17		1.94		1.94		1.35		1.03		1.85		1.96
NYMEX gas (US$/mmbtu)	2.23		2.64		3.15		3.64		2.90		2.80		3.00		2.93

Sales price ($/boe)	47.14		51.49		47.98		37.89		55.03		51.22		42.96		44.75
Royalties ($/boe)	(8.59	)	(9.67	)	(8.94	)	(8.77	)	(12.13	)	(12.01	)	(10.36	)	(10.86	)
Operating expense ($/boe)	(11.15	)	(11.22	)	(11.02	)	(10.76	)	(10.25	)	(10.91	)	(10.53	)	(10.91	)
Transportation expense ($/boe)	(1.13	)	(1.33	)	(1.46	)	(1.21	)	(1.26	)	(1.22	)	(1.36	)	(1.20	)
Operating netback ($/boe)	26.27		29.27		26.56		17.15		31.39		27.08		20.71		21.78
Financial derivatives gain (loss) ($/boe)	2.39		1.45		2.07		(0.34	)	(4.07	)	(4.57	)	(1.57	)	0.30
Operating netback after financial derivatives ($/boe)	28.66		30.72		28.63		16.81		27.32		22.51		19.14		22.08

In Q3/2019 we delivered our fourth consecutive quarter of strong operating and financial results following closing of the Strategic Combination in Q3/2018. Production has increased from 69,556 boe/d during Q4/2017 to a high of 101,115 boe/d during Q1/2019 as a result of the Strategic Combination along with our successful development programs in the U.S. and Canada. As planned, production has decreased to 94,927 boe/d in Q3/2019 as a result of decreased capital spending in Q2/2019 and Q3/2019. Improved well productivity from enhanced completion techniques resulted in relatively consistent average daily production in the U.S. despite lower quarterly exploration and development expenditures. In Canada, our exploration and development program was focused on our heavy oil properties at Peace River and Lloydminster. Exploration and development activity in Canada increased following the Strategic Combination with the addition of our light oil Viking and Duvernay properties.

Global benchmark prices for crude oil have fluctuated as attempts to balance the market with production cuts have been mitigated by geopolitical factors and increasing production in North America. Our realized pricing in Canada improved in 2019 after a narrowing of light and heavy oil differentials along with a higher weighting of light oil production following the Strategic Combination. The WCS benchmark averaged US$44.21/bbl in Q3/2019 compared to US$19.39/bbl in Q4/2018 and US$43.14/bbl in Q4/2017.

Baytex Energy Corp.

Q3 2019 MD&A Page 21

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 began to improve in late 2017 as commodity prices recovered. Adjusted funds flow continued to improve through Q3/2019 following the Strategic Combination due to increased production and higher realizations associated with the higher weighting of light oil production, as well as strong well performance. The increase in production and operating netback after financial derivatives resulted in adjusted funds flow of $213.4 million in Q3/2019 which is higher than $105.8 million reported in Q4/2017.

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 $1,734.3 million at Q4/2017 to $1,971.3 million at Q3/2019 primarily due to $363.6 million of net debt assumed in conjunction with the Strategic Combination in Q3/2018 combined with an increase in the CAD/USD exchange rate used to translate our U.S. dollar denominated debt from 1.2518 CAD/USD at Q4/2017 to 1.3244 CAD/USD at Q3/2019. The increase in net debt due to the Strategic Combination and a weakening of the Canadian dollar relative to the U.S. dollar was partially offset by adjusted funds flow that exceeded exploration and development expenditures by $264.0 million over the last eight quarters.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at September 30, 2019, 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, 2019 except for the adoption of IFRS 16 as discussed below. 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, 2018.

CHANGES IN ACCOUNTING STANDARDS

Leases

Baytex adopted IFRS 16 Leases on January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of comparative financial information as it recognizes the cumulative effect on transition as an adjustment to opening retained earnings and applies the standard prospectively. Comparative information in the Company's consolidated statements of financial position, consolidated statements of income (loss) and comprehensive income (loss), consolidated statements of changes in equity, and consolidated statements of cash flows has not been restated.

The cumulative effect of initial application of the standard was to recognize an $18.0 million increase to right-of-use assets ("lease assets"), a $2.0 million reduction of onerous contracts and a $18.0 million increase to lease obligations. Initial measurement of the lease obligation was determined based on the remaining lease payments at January 1, 2019 using a weighted averaged incremental borrowing rate of approximately 3.9%. The lease assets were initially recognized at an amount equal to the lease obligations. The lease assets and lease obligations recognized largely relate to the Company's head office lease in Calgary.

The adoption of IFRS 16 using the modified retrospective approach allowed the Company to use the following practical expedients in determining the opening transition adjustment:


•	The weighted average incremental borrowing rate in effect at January 1, 2019 was used as opposed to the rate in effect at inception of the lease;


•	Leases with a remaining term of less than 12 months as at January 1, 2019 were accounted for as short-term leases;


•	Leases with an underlying asset of low value are recorded as an expense and not recognized as a lease asset;


•	Leases with similar characteristics were accounted for as a portfolio using a single discount rate; and


•	The Company's previous assessment under IAS 37, "Provisions, Contingent Liabilities and Contingent Assets' was used for onerous contracts instead of reassessing the lease assets for impairment at January 1, 2019.

The Company's accounting policy for leases effective January 1, 2019 is set forth below. The Company applied IFRS 16 using the modified retrospective approach. Comparative information continues to be accounted for in accordance with the Company's previous accounting policy found in the 2018 annual financial statements.

Leases

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. A lease obligation and corresponding right-of-use asset ("lease asset") are recognized at the commencement of the lease. The present value of the lease obligation is based on the future lease payments and is discounted using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with similar characteristics. The lease asset is recognized at the amount of the lease obligation,

Baytex Energy Corp.

Q3 2019 MD&A Page 22

adjusted for lease incentives received and initial direct costs, on commencement of the lease. Depreciation is recognized on the lease asset over the shorter of the estimated useful life of the asset or the lease term.

Lease payments are allocated between the liability and interest expense. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation.

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates, and assumptions that affect the reported amount of assets, liabilities, income, and expenses. Actual results could differ significantly from these estimates. Management has made the following judgments, estimates, and assumptions related to the accounting for leases.

The carrying amounts of the right-of-use assets, lease obligations, and the resulting interest and depletion and depreciation expense are based on the implicit interest rate within the lease arrangement or, if this information is unavailable, the incremental borrowing rate. Incremental borrowing rates are based on judgments including economic environment, term, and the underlying risk inherent to the asset.

NON-GAAP AND CAPITAL MEASUREMENT MEASURES

In this MD&A, we refer to certain capital management measures (such as adjusted funds flow, exploration and development expenditures, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). While adjusted funds flow, exploration and development expenditures, 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 financial measures provide 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 exploration and development expenditures, debt repayment, payments on our lease obligations, 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 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 with our capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our operations on a continuing basis. In addition, we have removed transaction costs associated with the Strategic Combination as we consider the costs non-recurring and are not reflective of our ability to generate adjusted funds flow on an ongoing basis.

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



	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2019		2018		2019		2018
Cash flow from operating activities	$	194,970	$	154,091	$	599,920	$	316,241
Change in non-cash working capital	17,275		1,025		59,499		23,633
Asset retirement obligations settled	1,134		3,028		10,860		9,215
Transaction costs	—		13,066		—		13,066
Adjusted funds flow	$	213,379	$	171,210	$	670,279	$	362,155

Exploration and Development Expenditures

We use exploration and development expenditures to measure and evaluate the performance of our capital programs. The total amount of exploration and development expenditures is managed as part of our budgeting process and can vary from period to period depending on the availability of adjusted funds flow and other sources of liquidity. We eliminate changes in non-cash working capital, acquisition and dispositions, and additions to other plant and equipment from investing activities as these amounts are generated by activities outside of our programs to explore and develop our existing properties.

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Q3 2019 MD&A Page 23

Changes in non-cash working capital are eliminated in the determination of exploration and development expenditures as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our exploration and development activity on a continuing basis. Our capital budgeting process is focused on programs to explore and develop our existing properties, accordingly, cash flows arising from acquisition and disposition activities are eliminated as we analyze these activities on a transaction by transaction basis separately from our analysis of the performance of our capital programs. Additions to other plant and equipment is primarily comprised of expenditures on corporate assets which do not generate incremental oil and natural gas production and is therefore analyzed separately from our evaluation of the performance of our exploration and development programs.

The following table reconciles cash flow used in investing activities to exploration and development expenditures.



	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2019			2018			2019			2018
Cash flow used in investing activities	$	150,651		$	70,194		$	447,835		$	227,301
Change in non-cash working capital	(11,577		)	70,396			(46,646		)	84,113
Proceeds from dispositions	150			—			1,100			2,234
Property acquisitions	(120		)	—			(2,193		)	(187		)
Property swaps	—			—			(524		)	—
Additions to other plant and equipment	(19		)	(1,395		)	(398		)	(1,902		)
Exploration and development expenditures	$	139,085		$	139,195		$	399,174		$	311,559

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. We calculate net debt based on the principal amounts of our bank loan and long-term notes outstanding, including trade and other receivables and trade and other payables. We use the principal amounts of the bank loan and long-term notes outstanding in the calculation of net debt as these amounts represent our final repayment obligation at maturity. The carrying amount of debt issue costs associated with the bank loan and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of capital or repayment obligation.

The following table summarizes our calculation of net debt.



($ thousands)	September 30, 2019			December 31, 2018
Bank loan⁽¹⁾	$	570,792		$	522,294
Long-term notes⁽¹⁾	1,359,480			1,596,323
Trade and other payables	212,404			258,114
Trade and other receivables	(171,337		)	(111,564		)
Net debt	$	1,971,339		$	2,265,167

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

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Q3 2019 MD&A Page 24

Operating Netback

We define operating netback as petroleum and natural gas sales, less blending 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 and is a key measure used to evaluate our operating performance.

The following table summarizes our calculation of operating netback.



	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2019			2018			2019			2018
Petroleum and natural gas sales	$	424,600		$	436,761		$	1,360,024		$	1,070,433
Blending and other expense	(12,950		)	(19,548		)	(50,628		)	(55,077		)
Total sales, net of blending and other expense	411,650			417,213			1,309,396			1,015,356
Royalties	(75,017		)	(91,945		)	(242,959		)	(233,989		)
Operating expense	(97,377		)	(77,698		)	(298,143		)	(213,735		)
Transportation expense	(9,903		)	(9,520		)	(35,102		)	(25,875		)
Operating netback	229,353			238,050			733,192			541,757
Realized financial derivative gain (loss)	20,857			(30,854		)	52,664			(70,103		)
Operating netback after realized financial derivatives	$	250,210		$	207,196		$	785,856		$	471,654

Bank EBITDA

Bank EBITDA is used to assess compliance with certain financial covenants contained in our credit facility agreements. Net income is adjusted for the items set forth in the table below as prescribed by the credit facility agreements. The following table reconciles net income or loss to Bank EBITDA.



	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2019			2018			2019			2018
Net income (loss)	$	15,151		$	27,412		$	105,313		$	(94,071	)
Plus:
Financing and interest	31,766			30,029			97,049			86,825
Unrealized foreign exchange (gain) loss	13,855			(20,583		)	(38,404		)	38,136
Unrealized financial derivatives (gain) loss	(7,666		)	46			30,922			65,140
Current income tax expense (recovery)	501			—			1,591			(71		)
Deferred income tax expense (recovery)	1,082			(4,427		)	(14,958		)	(51,905		)
Depletion and depreciation	180,422			144,501			551,548			364,654
Gain on dispositions	(18		)	(34		)	(1,075		)	(1,764		)
Transaction costs	—			13,066			—			13,066
Payments on lease obligations	(1,390		)	—			(4,402		)	—
Non-cash items⁽¹⁾	5,539			7,690			22,912			18,897
Adjustment for Strategic Combination⁽²⁾	—			96,736			—			255,800
Bank EBITDA	$	239,242		$	294,436		$	750,496		$	694,707


(1)	Non-cash items include share-based compensation and exploration and evaluation 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, 2019, except for the matter described below.

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Q3 2019 MD&A Page 25

Baytex previously excluded business processes acquired through the Strategic Combination on August 22, 2018, from the Company's evaluation of internal control over financial reporting as permitted by applicable securities laws in Canada and the U.S. We completed the evaluation and integration of internal controls over financial reporting of Raging River during Q3/2019.

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 capital budget and expected average daily production for 2019; that we expect to exceed our 2019 production guidance; and our expected royalty rate and operating, transportation, general and administrative and interest expenses for 2019; the existence, operation and strategy of our risk management program; that management of our debt levels is a priority; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; 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.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; 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: the volatility of oil and natural gas prices and price differentials; availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil 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; alternatives to and changing demand for petroleum products; risks associated with our use of 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 nonresidents 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, 2018, 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.