Baytex Energy 6K Condensed Consolidated Statements of Financial Position | BTE 1 Aug 19

Baytex Energy Corp.

Q2 2019 MD&A Page 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and six months ended June 30, 2019 and 2018

Dated July 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 six months ended June 30, 2019. This information is provided as of July 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 six months ended June 30, 2019 ("Q2/2019" and "YTD 2019") have been compared with the results for the three and six months ended June 30, 2018 ("Q2/2018" 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 six months ended June 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 increased our ability to effectively allocate capital.

SECOND QUARTER HIGHLIGHTS

Baytex delivered solid operating and financial results in Q2/2019, generating adjusted funds flow of $236.1 million which exceeded exploration and development expenditures of $106.2 million and contributed to a $146.6 million reduction in net debt from Q1/2019. Strong well performance in the U.S. and Canada resulted in production of 98,402 boe/d which exceeds the high end of our revised annual guidance range of 96,000 to 97,000 boe/d.

In the U.S., production was 39,822 boe/d for Q2/2019 which was consistent with our expectations and slightly lower than 41,097 boe/d in Q1/2019 and 9% higher than 36,622 boe/d for Q2/2018. Strong well performance has increased our production from 2018, while lower activity in Q2/2019 from Q1/2019 resulted in the moderate decrease in production relative to Q1/2019. We invested $38.0 million on exploration and development activities during Q2/2019 and drilled 20 (5.1 net) wells and commenced production from 29 (5.0 net) wells. Lower completion activity in Q2/2019 resulted in exploration and development expenditures that were $10.2 million lower than Q2/2018 when we invested $48.2 million and drilled 18 (2.6 net) wells and commenced production from 32 (7.6 net) wells.

In Canada, production was 58,580 boe/d for Q2/2019 which was slightly lower than 60,018 boe/d in Q1/2019 but 72% higher than 34,042 boe/d in Q2/2018 which reflects the impact of the Strategic Combination along with an increase in heavy oil production from our development program. Production of 59,296 boe/d for YTD 2019 is relatively consistent with 60,453 boe/d for Q4/2018 despite production curtailments mandated by the Government of Alberta which became effective in January 2019. Exploration and development expenditures of $68.3 million in Q2/2019 were focused on our Viking and Duvernay light oil properties. Exploration and development expenditures included costs associated with drilling 43 (42.9 net) light oil wells and 4 (4.0 net) heavy oil wells during Q2/2019.

Baytex Energy Corp.

Q2 2019 MD&A Page 2

The West Texas Intermediate ("WTI") benchmark price for crude oil was lower in Q2/2019 compared to Q2/2018. The WTI oil price averaged US$59.81/bbl in Q2/2019 which was down US$8.07/bbl from US$67.88/bbl in Q2/2018 and up US$4.91/bbl from US$54.90/bbl in Q1/2019. In 2018, light and heavy oil differentials in Canada were impacted by increasing oil production and a lack of egress in Western Canada and traded at wider differentials to WTI relative to previous years. Production curtailments mandated by the Government of Alberta came into effect in January of 2019 and have helped narrow Canadian light and heavy oil differentials in YTD 2019. The Edmonton par light oil benchmark averaged $73.84/bbl in Q2/2019 which represents a differential of US$4.61/bbl to WTI as compared to a US$26.51 differential in Q4/2018 and a US$5.47/bbl differential in Q2/2018. The Western Canadian Select ("WCS") heavy oil differential averaged US$10.68/bbl in Q2/2019 relative to a differential of US$39.42/bbl in Q4/2018 and US$19.28/bbl in Q2/2018.

Adjusted funds flow of $236.1 million in Q2/2019 was $129.4 million higher than $106.7 million for Q2/2018 due to stronger price realizations in Canada along with 39% increase in production for Q2/2019 relative to Q2/2018. Our realized price of $51.49/boe for Q2/2019 is consistent with $51.22/boe for Q2/2018 and reflects stronger pricing received on our Canadian light oil production and narrower WCS differentials which was offset by lower realized pricing on our U.S. production with lower WTI pricing. Increased production from the Strategic Combination and stronger price realizations in Canada resulted in a $131.7 million increase in total sales, net of blending and other expense, for Q2/2019 relative to Q2/2018. This was offset by a $43.8 million increase in royalties, operating and transportation expense associated with the increase in production resulting in a $88.0 million increase in operating netback in Q2/2019 relative to Q2/2018. Realized hedging gains of $13.0 million contributed to the increase in adjusted funds flow relative to Q2/2018 when we recorded realized hedging losses of $29.4 million.

In Q2/2019 we reported net income of $78.8 million compared to a net loss of $58.8 million in Q2/2018. In addition to the $129.4 million increase in adjusted funds flow in Q2/2019 compared to Q2/2018, unrealized gains on finance derivatives and foreign exchange exceeded losses in Q2/2018 by $110.0 million. This was offset by depletion and depreciation expense that was $73.9 million higher in Q2/2019 compared to Q2/2018. Our deferred tax recovery of $1.6 million for Q2/2019 was $23.0 million lower than $24.6 million for Q2/2018 due to higher net income before income tax which was partially offset by a $10.6 million recovery associated with a reduction in future tax rates in Alberta.

At June 30, 2019, net debt was $2,028.7 million, a $236.5 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 $196.8 million and the Canadian dollar strengthened at June 30, 2019 which reduced the reported amount of our US denominated long-term notes by $52.7 million. The change in net debt also reflects $9.7 million of asset retirement obligations settled and $3.0 million of lease payments for YTD 2019.

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 are tightening our 2019 production guidance range to 96,000 to 97,000 boe/d with exploration and development expenditures of $550 to $600 million. We are also reducing our expected royalty rate for 2019 from approximately 20.0% to 19.0%.



	Previous Annual Guidance ⁽¹⁾	Revised Annual Guidance	YTD 2019
Exploration and development capital	$575 - 625 million	$550 - 600 million	$260.1 million
Production (boe/d)	95,000 - 97,000	96,000 to 97,000	99,751

Expenses:
Royalty rate	~ 20.0%	~ 19.0%	18.7	%
Operating	$10.75 - $11.25/boe	No change	$11.12/boe
Transportation	$1.25 - $1.35/boe	No change	$1.40/boe
General and administrative	~ $46 million ($1.30/boe)	No change	$25.6 million ($1.42/boe)
Cash interest	~ $112 million ($3.23/boe)	No change	$56.3 million ($3.12/boe)

(1) As announced on May 2, 2019.

Baytex Energy Corp.

Q2 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 June 30
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	22,130		20,455		42,585		842		20,258		21,100
Heavy oil	27,320		—		27,320		25,544		—		25,544
Natural Gas Liquids (NGL)	1,106		9,880		10,986		1,214		8,205		9,419
Total liquids (bbl/d)	50,556		30,335		80,891		27,600		28,463		56,063
Natural gas (mcf/d)	48,145		56,920		105,065		38,650		48,955		87,605
Total production (boe/d)	58,580		39,822		98,402		34,042		36,622		70,664

Production Mix
Light oil and condensate	38	%	51	%	43	%	2	%	56	%	30	%
Heavy oil	47	%	—	%	28	%	75	%	—	%	36	%
NGL	2	%	25	%	11	%	4	%	22	%	13	%
Natural gas	13	%	24	%	18	%	19	%	22	%	21	%

	Six Months Ended June 30
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	22,709		21,100		43,809		850		20,184		21,034
Heavy oil	27,107		—		27,107		25,208		—		25,208
Natural Gas Liquids (NGL)	1,356		10,000		11,356		1,256		8,025		9,281
Total liquids (bbl/d)	51,172		31,100		82,272		27,314		28,209		55,523
Natural gas (mcf/d)	48,742		56,132		104,874		38,761		48,673		87,434
Total production (boe/d)	59,296		40,455		99,751		33,774		36,321		70,095

Production Mix
Light oil and condensate	38	%	52	%	44	%	3	%	56	%	30	%
Heavy oil	46	%	—	%	27	%	75	%	—	%	36	%
NGL	2	%	25	%	11	%	4	%	22	%	13	%
Natural gas	14	%	23	%	18	%	18	%	22	%	21	%

Production averaged 98,402 boe/d for Q2/2019 and 99,751 for YTD 2019 which exceeds the high end of our revised annual guidance range of 96,000 to 97,000 boe/d. Production in 2019 is higher than 2018 due to the Strategic Combination, increased U.S. production from strong well results along with additional production related to our development program.

In Canada, production was 58,580 boe/d for Q2/2019 and 59,296 boe/d for YTD 2019 compared to 34,042 boe/d in Q2/2018 and 33,774 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 production results 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.

Baytex Energy Corp.

Q2 2019 MD&A Page 4

Production in the U.S. averaged 39,822 boe/d for Q2/2019 and 40,455 boe/d in YTD 2019 compared to 36,622 boe/d for Q2/2018 and 36,321 boe/d in YTD 2018. Strong well performance from wells that commenced production during Q2/2019 contributed to the increase in production relative to Q2/2018. Average daily production for YTD 2019 was 4,134 boe/d higher than 36,321 boe/d in YTD 2018 due to the timing of completion activity and strong well performance. During YTD 2019 we commenced production from 65 (14.0 net) wells compared to YTD 2018 when 59 (13.1 net) wells were brought on production.

We have narrowed our annual production guidance range for 2019 from 95,000 to 97,000 to 96,000 to 97,000 boe/d, increasing the midpoint of our range by 500 boe/d reflecting the positive performance in YTD 2019. Lower exploration and development expenditures during Q2/2019 are expected to result in lower production levels during Q3/2019.

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 have improved in 2019 from Q4/2018 when increasing production and geopolitical factors contributed to a sharp decline in global oil prices but have decreased from Q2/2018 when OPEC production curtailments and global inventory levels supported higher prices. The WTI benchmark price averaged US$59.81/bbl during Q2/2019 and US$57.36/bbl in YTD 2019, representing a decrease of US$8.07/bbl and US$8.01/bbl compared to US$67.88/bbl in Q2/2018 and US$65.37/bbl in YTD 2018.

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. LLS averaged US$67.15/bbl during Q2/2019 and US$64.37/bbl during YTD 2019 compared to US$71.37/bbl in Q2/2018 and US$69.24/bbl in YTD 2018. The LLS premium to WTI of US$7.34/bbl and US$7.01/bbl for Q2/2019 and YTD 2019, respectively, has been higher than US$3.49 and US$3.87 for the same periods in 2018 which has slightly offset the decrease in WTI pricing during 2019.

Ongoing pipeline capacity constraints, a lack of rail transport capacity and increasing Western Canadian crude oil production resulted in the WCS and Edmonton benchmark prices trading at wide discounts to WTI in late 2018. Production curtailments mandated by the Government of Alberta have narrowed the Canadian oil differentials in YTD 2019 and resulted in the WCS heavy differential averaging US$11.48/bbl and the Edmonton par differential averaging US$4.72/bbl for YTD 2019.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $73.84/bbl for Q2/2019 and $70.19/bbl for YTD 2019 compared to $80.58/bbl for Q2/2018 and $76.32/bbl for YTD 2018. Edmonton par traded at a US$4.61/bbl discount to WTI in Q2/2019 and a discount of US$4.72/bbl in YTD 2019 compared to a US$5.47/bbl discount in Q2/2018 and a US$5.66/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. The WCS heavy oil differential to WTI averaged US$10.68/bbl in Q2/2019 and US$11.48/bbl in YTD 2019 as compared to US$19.28/bbl for Q2/2018 and US$21.77 for YTD 2018. As a result, the WCS heavy oil benchmark price of $61.17/bbl in YTD 2019 increased $5.44/bbl from $55.73/bbl in YTD 2018 despite a $7.08/bbl decrease in WTI (expressed in Canadian dollars) over the same periods.

Natural Gas

North American natural gas prices for Q2/2019 and YTD 2019 were fairly consistent with Q2/2018 and YTD 2018 as increased demand due to cold weather in 2019 mitigated the impact of significant North American natural gas supply growth. Canadian natural gas prices remained challenged during YTD 2019 as a lack of egress in 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$2.64/mmbtu in Q2/2019 and US$2.89/mmbtu in YTD 2019 which is slightly lower in the quarter and relatively consistent year-to-date with US$2.80/mmbtu and US$2.90/mmbtu for the same periods of 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 $1.17/mcf during Q2/2019 and $1.56/mcf in YTD 2019 which is slightly higher than $1.03/mcf for Q2/2018 and $1.44/mcf in YTD 2018.

Baytex Energy Corp.

Q2 2019 MD&A Page 5

The following tables compare selected benchmark prices and our average realized selling prices for the three and six months ended June 30, 2019 and 2018.



	Three Months Ended June 30						Six Months Ended June 30
	2019		2018		Change		2019		2018		Change
Benchmark Averages
WTI oil (US$/bbl)⁽¹⁾	59.81		67.88		(8.07	)	57.36		65.37		(8.01	)
LLS oil (US$/bbl)⁽²⁾	67.15		71.37		(4.22	)	64.37		69.24		(4.87	)
LLS oil differential to WTI (US$/bbl)	7.34		3.49		3.85		7.01		3.87		3.14
Edmonton par oil ($/bbl)	73.84		80.58		(6.74	)	70.19		76.32		(6.13	)
Edmonton par oil differential to WTI (US$/bbl)	(4.61	)	(5.47	)	0.86		(4.72	)	(5.66	)	0.94
WCS heavy oil ($/bbl)⁽³⁾	65.73		62.75		2.98		61.17		55.73		5.44
WCS heavy oil differential to WTI (US$/bbl)	(10.68	)	(19.28	)	8.60		(11.48	)	(21.77	)	10.29
AECO natural gas price ($/mcf)⁽⁴⁾	1.17		1.03		0.14		1.56		1.44		0.12
NYMEX natural gas price (US$/mmbtu)⁽⁵⁾	2.64		2.80		(0.16	)	2.89		2.90		(0.01	)
CAD/USD average exchange rate	1.3376		1.2911		0.0465		1.3334		1.2781		0.0553


(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 June 30
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices⁽¹⁾
Light oil and condensate ($/bbl)	$	70.43	$	82.47	$	76.21	$	71.61	$	87.38	$	86.75
Heavy oil ($/bbl)⁽²⁾	50.34		—		50.34		49.70		—		49.70
NGL ($/bbl)	17.46		17.58		17.57		37.05		30.53		31.37
Natural gas ($/mcf)	1.16		3.47		2.41		1.07		3.73		2.56
Weighted average ($/boe)⁽²⁾	$	51.36	$	51.69	$	51.49	$	41.61	$	60.16	$	51.22

	Six Months Ended June 30
	2019						2018
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices⁽¹⁾
Light oil and condensate ($/bbl)	$	66.71	$	79.19	$	72.72	$	67.18	$	83.68	$	83.01
Heavy oil ($/bbl)⁽²⁾	46.07		—		46.07		41.67		—		41.67
NGL ($/bbl)	21.18		20.23		20.34		32.76		28.21		28.82
Natural gas ($/mcf)	1.77		3.71		2.81		1.50		3.75		2.75
Weighted average ($/boe)⁽²⁾	$	48.55	$	51.44	$	49.72	$	35.73	$	57.76	$	47.15


(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 $51.49/boe for Q2/2019 and $49.72/boe for YTD 2019 compared to $51.22/boe for Q2/2018 and $47.15/boe in YTD 2018. Our realized price in the U.S. was $51.69/boe in Q2/2019 which is $8.47/boe lower than $60.16/boe in Q2/2018 due to the decrease in U.S. crude oil benchmark prices. In Canada, our realized price of $51.36/boe for Q2/2019 was $9.75/boe higher than $41.61/boe for Q2/2018 due to a narrowing of Canadian light and heavy oil differentials combined with an improvement in our realized pricing following the Strategic Combination.

Baytex Energy Corp.

Q2 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 $70.43/bbl in Q2/2019 and $66.71/bbl in YTD 2019 compared to $71.61/bbl in Q2/2018 and $67.18/bbl in YTD 2018. Our realized light oil and condensate price for Q2/2019 and YTD 2019 represents a discount of $3.41/bbl and $3.48/bbl to the Edmonton par price compared to a discount of $8.97/bbl in Q2/2018 and $9.14/bbl in YTD 2018. The improvement in our Canadian light oil price realizations can be attributed to our Viking and Duvernay light oil properties acquired in Q3/2018 which receive higher pricing than our legacy light oil properties in Canada.

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 $82.47/bbl for Q2/2019 and $79.19/bbl for YTD 2019 compared to $87.38/bbl for Q2/2018 and $83.68/bbl in YTD 2018. Expressed in U.S. dollars, our realized light oil and condensate price of US$61.66/bbl for Q2/2019 and US$59.39/bbl for YTD 2019 represents a US$5.49/bbl discount to the LLS benchmark for Q2/2019 and a US$4.98/bbl discount for YTD 2019. Our light oil and condensate pricing in the U.S. was impacted by a change in reference price on certain marketing contracts in Q1/2019 which resulted in lower price realizations relative to Q2/2018 and YTD 2018 when our realized price expressed in U.S. dollars was a US$3.69/bbl and US$3.77/bbl discount to the LLS benchmark.

Our realized heavy oil price, net of blending and other expense averaged $50.34/bbl in Q2/2019 and $46.07/bbl for YTD 2019 compared to $49.70/bbl in Q2/2018 and $41.67/bbl in YTD 2018. Our realized heavy oil price for Q2/2019 and YTD 2019 was $0.64/bbl and $4.40/bbl higher relative to Q2/2018 and YTD 2018 compared to a $2.98/bbl and $5.44/bbl increase in the WCS benchmark over the same periods. 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 of the underlying products. Our realized NGL price was $17.57/bbl in Q2/2019 or 22% of WTI (expressed in Canadian dollars) compared to $31.37/bbl or 36% of WTI (expressed in Canadian dollars) in Q2/2018. Our YTD 2019 realized NGL price was $20.34/bbl or 27% of WTI (expressed in Canadian dollars) compared to $28.82/bbl or 34% of WTI (expressed in Canadian dollars) for YTD 2018. The decrease in our realized NGL price for Q2/2019 and YTD 2019 is a result in the decline in market prices for propane and butane relative to Q2/2018 and YTD 2018.

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $1.16/mcf for Q2/2019 and $1.77/mcf for YTD 2019 compared to $1.07/mcf in Q2/2018 and $1.50/mcf in YTD 2018. The increase in our realized natural gas prices in 2019 compared to 2018 is relatively consistent with the change in the AECO natural gas price over the same periods. In the U.S., our realized natural gas price was US$2.59/mmbtu for Q2/2019 and US$2.78/mmbtu for YTD 2019 compared to US$2.89/mmbtu in Q2/2018 and US$2.93/mmbtu 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.

Baytex Energy Corp.

Q2 2019 MD&A Page 7

Petroleum and Natural Gas Sales



	Three Months Ended June 30
	2019								2018
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	141,827		$	153,504	$	295,331		$	5,484		$	161,078	$	166,562
Heavy oil	146,038			—		146,038			133,768			—		133,768
NGL	1,757			15,808		17,565			4,092			22,794		26,886
Total oil sales	289,622			169,312		458,934			143,344			183,872		327,216
Natural gas sales	5,076			17,990		23,066			3,778			16,611		20,389
Total petroleum and natural gas sales	294,698			187,302		482,000			147,122			200,483		347,605
Blending and other expense	(20,890		)	—		(20,890		)	(18,239		)	—		(18,239		)
Total sales, net of blending and other expense	$	273,808		$	187,302	$	461,110		$	128,883		$	200,483	$	329,366

	Six Months Ended June 30
	2019								2018
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	274,195		$	302,419	$	576,614		$	10,336		$	305,684	$	316,020
Heavy oil	263,724			—		263,724			225,651			—		225,651
NGL	5,198			36,610		41,808			7,448			40,972		48,420
Total oil sales	543,117			339,029		882,146			243,435			346,656		590,091
Natural gas sales	15,620			37,658		53,278			10,502			33,079		43,581
Total petroleum and natural gas sales	558,737			376,687		935,424			253,937			379,735		633,672
Blending and other expense	(37,678		)	—		(37,678		)	(35,529		)	—		(35,529		)
Total sales, net of blending and other expense	$	521,059		$	376,687	$	897,746		$	218,408		$	379,735	$	598,143

Total sales, net of blending and other expense, of $461.1 million for Q2/2019 increased $131.7 million from $329.4 million reported for Q2/2018 while total sales, net of blending and other expense, of $897.7 million for YTD 2019 was $299.6 million higher than $598.1 million in YTD 2018. The increase in Q2/2019 and YTD 2019 is primarily a result of higher production from the Strategic Combination. Stronger realized pricing in Canada from the narrowing of Canadian oil differentials and a higher weighting of light oil production was offset by lower realized pricing in the U.S. relative to the same periods of 2018.

In Canada, total sales, net of blending and other expense, was $273.8 million for Q2/2019 which is an increase of $144.9 million from Q2/2018. Total petroleum and natural gas sales increased with production due to the Strategic Combination and our oil exploration and development programs. The increase in our average realized price to $51.36/boe for Q2/2019 also contributed to higher total sales, net of blending and other expense, compared to Q2/2018 when our average realized price was $41.61/boe. Higher production and stronger realized pricing resulted in our total sales, net of blending and other expense, increasing to $521.1 million in YTD 2019 from $218.4 million in YTD 2018.

In the U.S., petroleum and natural gas sales were $187.3 million for Q2/2019 and decreased $13.2 million from $200.5 million reported for Q2/2018. Production for Q2/2019 was 3,200 boe/d higher relative to Q2/2018 and increased total sales by $15.1 million. This was offset by lower realized prices which were $8.47/boe lower in Q2/2019 compared to Q2/2018 and decreased total sales by $28.3 million. Lower realized pricing in YTD 2019 resulted in petroleum and natural gas sales of $376.7 million which was $3.0 million lower than $379.7 million for YTD 2018 despite a 4,134 boe/d increase in production over the same period.

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Q2 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 six months ended June 30, 2019 and 2018.



	Three Months Ended June 30
	2019									2018
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	30,936		$	55,681		$	86,617		$	17,998		$	59,207		$	77,205
Average royalty rate⁽¹⁾	11.3		%	29.7		%	18.8		%	14.0		%	29.5		%	23.4		%
Royalty rate per boe	$	5.80		$	15.37		$	9.67		$	5.81		$	17.77		$	12.01

	Six Months Ended June 30
	2019									2018
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	56,120		$	111,822		$	167,942		$	29,332		$	112,712		$	142,044
Average royalty rate⁽¹⁾	10.8		%	29.7		%	18.7		%	13.4		%	29.7		%	23.7		%
Royalty rate per boe	$	5.23		$	15.27		$	9.30		$	4.80		$	17.14		$	11.20


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

Royalties for Q2/2019 were $86.6 million and averaged 18.8% of total sales, net of blending and other expense, compared to $77.2 million or 23.4% for Q2/2018. Total royalties in YTD 2019 were $167.9 million or 18.7% of total sales, net of blending and other expenses compared to $142.0 million or 23.7% in YTD 2018. Total royalty expense is higher in Q2/2019 and YTD 2019 due to higher total sales, net of blending and other expense, relative to the same periods of 2018. Our Canadian royalty rate of 11.3% for Q2/2019 and 10.8% for YTD 2019 was lower than 14.0% for Q2/2018 and 13.4% 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 Q2/2019 and YTD 2019 averaged 29.7% 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.

Our average royalty rate was 18.7% for YTD 2019. We have reduced our annual royalty rate guidance for 2019 from approximately 20.0% to approximately 19.0% as our Canadian sales, which have a lower royalty rate, represented a higher percentage of total sales due to narrower light and heavy oil differentials than originally budgeted.

Operating Expense



	Three Months Ended June 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	73,877	$	26,597	$	100,474	$	46,924	$	23,225	$	70,149
Operating expense per boe	$	13.86	$	7.34	$	11.22	$	15.15	$	6.97	$	10.91

	Six Months Ended June 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	147,979	$	52,787	$	200,766	$	92,344	$	43,693	$	136,037
Operating expense per boe	$	13.79	$	7.21	$	11.12	$	15.11	$	6.65	$	10.72

Operating expense was $100.5 million ($11.22/boe) for Q2/2019 and $200.8 million ($11.12/boe) for YTD 2019 compared to $70.1 million ($10.91/boe) in Q2/2018 and $136.0 million ($10.72/boe) in YTD 2018. The increase in total operating expense is from higher production in Q2/2019 and YTD 2019 relative to Q2/2018 and YTD 2018 along with a slight increase in per unit operating expense.

In Canada, operating expense was $73.9 million ($13.86/boe) for Q2/2019 and $148.0 million ($13.79/boe) for YTD 2019 compared to $46.9 million ($15.15/boe) for Q2/2018 and $92.3 million ($15.11/boe) for YTD 2018. Total operating expense in Canada has increased with higher production following the Strategic Combination. Per unit operating costs of $13.86/boe for Q2/2019 and $13.79/boe in YTD 2019 decreased from $15.15/boe in Q2/2018 and $15.11/boe in YTD 2018 as our Viking and Duvernay properties have

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Q2 2019 MD&A Page 9

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 $26.6 million ($7.34/boe) for Q2/2019 and $52.8 million ($7.21/boe) for YTD 2019 compared to $23.2 million ($6.97/boe) for Q2/2018 and $43.7 million ($6.65/boe) for YTD 2018. The increase in total operating expense reflects higher U.S. production combined with a weaker Canadian dollar in Q2/2019 and YTD 2019 compared to Q2/2018 and YTD 2018. Expressed in U.S. dollars, per boe operating expense for our U.S. properties have been fairly consistent and were US$5.49/boe in Q2/2019 and US$5.41/boe in YTD 2019 compared to US$5.40/boe for Q2/2018 and US$5.20/boe in YTD 2018.

Operating expense of $11.12/boe for YTD 2019 is consistent with expectations and we are maintaining our 2019 annual guidance range of $10.75 - $11.25/boe.

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 six months ended June 30, 2019 and 2018.



	Three Months Ended June 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	11,869	$	—	$	11,869	$	7,836	$	—	$	7,836
Transportation expense per boe	$	2.23	$	—	$	1.33	$	2.53	$	—	$	1.22

	Six Months Ended June 30
	2019						2018
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	25,199	$	—	$	25,199	$	16,355	$	—	$	16,355
Transportation expense per boe	$	2.35	$	—	$	1.40	$	2.68	$	—	$	1.29

Transportation expense was $11.9 million ($1.33/boe) for Q2/2019 and $25.2 million ($1.40/boe) for YTD 2019 compared to $7.8 million ($1.22/boe) for Q2/2018 and $16.4 million ($1.29/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. Per unit transportation costs of $1.40/boe for YTD 2019 were in line with expectations and we are maintaining our annual guidance range of $1.25 - $1.35/boe for 2019.

Blending and Other Expense

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

Blending and other expense was $20.9 million for Q2/2019 and $37.7 million for YTD 2019 which is relatively consistent with $18.2 million for Q2/2018 and $35.5 million for YTD 2018.

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Q2 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 six months ended June 30, 2019 and 2018.



	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2019			2018			Change			2019			2018			Change
Realized financial derivatives gain (loss)
Crude oil	$	12,501		$	(30,558	)	$	43,059		$	30,313		$	(40,824	)	$	71,137
Natural gas	504			1,150			(646		)	1,470			1,575			(105		)
Interest and financing	(12		)	—			(12		)	24			—			24
Total	$	12,993		$	(29,408	)	$	42,401		$	31,807		$	(39,249	)	$	71,056
Unrealized financial derivatives gain (loss)
Crude oil	$	13,524		$	(45,800	)	$	59,324		$	(37,642	)	$	(63,459	)	$	25,817
Natural gas	1,230			(1,585		)	2,815			(350		)	(1,635		)	1,285
Interest and financing	(81		)	—			(81		)	(596		)	—			(596		)
Total	$	14,673		$	(47,385	)	$	62,058		$	(38,588	)	$	(65,094	)	$	26,506
Total financial derivatives gain (loss)
Crude oil	$	26,025		$	(76,358	)	$	102,383		$	(7,329	)	$	(104,283	)	$	96,954
Natural gas	1,734			(435		)	2,169			1,120			(60		)	1,180
Interest and financing	(93		)	—			(93		)	(572		)	—			(572		)
Total	$	27,666		$	(76,793	)	$	104,459		$	(6,781	)	$	(104,343	)	$	97,562

We recorded total financial derivative gains of $27.7 million for Q2/2019 and losses of $6.8 million for YTD 2019. Realized financial derivatives gains of $13.0 million for Q2/2019 and $31.8 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 $14.7 million for Q2/2019 and unrealized loss of $38.6 million for YTD 2019 is primarily a result of fluctuations in the futures prices for WTI which impacts the fair value of our contracts in place at June 30, 2019.

Realized gains on crude oil financial derivatives of $12.5 million in Q2/2019 and $30.3 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 $0.5 million in Q2/2019 and $1.5 million for YTD 2019. These gains were primarily a result of the NYMEX index for Q2/2019 and YTD 2019 averaging less than the fixed price on our NYMEX contracts in place for both periods.

During Q2/2019 we recorded unrealized gains of $14.7 million as the fair value of our financial derivative contracts at June 30, 2019 increased from a net asset of $26.3 million at March 31, 2019 to a net asset of $41.0 million at June 30, 2019. The increase in the fair value of our financial derivatives during Q2/2019 is a result of a decline in the futures pricing for WTI and Brent at June 30, 2019 relative to March 31, 2019. We recorded an unrealized loss on financial derivatives of $38.6 million for YTD 2019 due to improved futures pricing at June 30, 2019 relative to December 31, 2018 when the fair value of our financial derivatives was a net asset of $79.6 million.

Baytex Energy Corp.

Q2 2019 MD&A Page 11

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



	Period	Volume	Price/Unit⁽¹⁾		Index
Oil
Basis Swap	Jul 2019 to Sep 2019	4,000 bbl/d	WTI less US$17.38/bbl		WCS
Basis Swap	Oct 2019 to Dec 2019	4,000 bbl/d	WTI less US$20.88/bbl		WCS
Basis Swap	Jul 2019 to Dec 2019	4,000 bbl/d	WTI less US$8.00/bbl		MSW
Fixed - Sell	Jul 2019 to Dec 2019	10,000 bbl/d	US$62.82/bbl		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	2,000 bbl/d	US$49.00/US$61.70/US$75.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	2,000 bbl/d	US$50.00/US$60.00/US$70.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$55.00/US$65.00/US$72.60		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$56.00/US$66.00/US$72.50		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$56.00/US$66.00/US$73.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	2,000 bbl/d	US$57.00/US$67.00/US$73.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	2,000 bbl/d	US$58.00/US$68.00/US$74.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$60.00/US$69.90/US$75.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$61.00/US$71.00/US$76.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$63.00/US$73.00/US$78.00		WTI
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$55.50/US$65.50/US$75.50		Brent
3-way option⁽²⁾	Jul 2019 to Dec 2019	1,000 bbl/d	US$60.00/US$70.00/US$77.55		Brent
3-way option⁽²⁾	Jul 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	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$66.00		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$66.05		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

Natural Gas
Fixed - Sell	Jul 2019 to Dec 2019	5,000 mmbtu/d		US$3.15	NYMEX
Fixed - Sell	Jul 2019 to Sep 2019	10,000 mmbtu/d		US$2.79	NYMEX
Fixed - Sell	Oct 2019 to Dec 2019	10,000 mmbtu/d		US$2.88	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.

Physical Delivery Contracts

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

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



Period	Volume
Jul 2019 to Oct 2019	1,000 bbl/d
Jul 2019 to Dec 2019	10,000 bbl/d
Jan 2020 to Dec 2020	7,500 bbl/d

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Q2 2019 MD&A Page 12

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 six months ended June 30, 2019 and 2018.



	Three Months Ended June 30
	2019									2018
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)	58,580			39,822			98,402			34,042			36,622			70,664
Operating netback:
Total sales, net of blending and other expense	$	51.36		$	51.69		$	51.49		$	41.61		$	60.16		$	51.22
Less:
Royalties	(5.80		)	(15.37		)	(9.67		)	(5.81		)	(17.77		)	(12.01		)
Operating expense	(13.86		)	(7.34		)	(11.22		)	(15.15		)	(6.97		)	(10.91		)
Transportation expense	(2.23		)	—			(1.33		)	(2.53		)	—			(1.22		)
Operating netback	$	29.47		$	28.98		$	29.27		$	18.12		$	35.42		$	27.08
Realized financial derivatives gain (loss)	—			—			1.45			—			—			(4.57		)
Operating netback after financial derivatives	$	29.47		$	28.98		$	30.72		$	18.12		$	35.42		$	22.51

	Six Months Ended June 30
	2019									2018
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)	59,296			40,455			99,751			33,774			36,321			70,095
Operating netback:
Total sales, net of blending and other expense	$	48.55		$	51.44		$	49.72		$	35.73		$	57.76		$	47.15
Less:
Royalties	(5.23		)	(15.27		)	(9.30		)	(4.80		)	(17.14		)	(11.20		)
Operating expense	(13.79		)	(7.21		)	(11.12		)	(15.11		)	(6.65		)	(10.72		)
Transportation expense	(2.35		)	—			(1.40		)	(2.68		)	—			(1.29		)
Operating netback	$	27.18		$	28.96		$	27.90		$	13.14		$	33.97		$	23.94
Realized financial derivatives gain (loss)	—			—			1.76			—			—			(3.09		)
Operating netback after financial derivatives	$	27.18		$	28.96		$	29.66		$	13.14		$	33.97		$	20.85

Our operating netback after financial derivatives was $30.72/boe for Q2/2019 which was $8.21/boe higher than $22.51/boe for Q2/2018. Operating netback after financial derivatives of $29.66 for YTD 2019 was $8.81/boe higher than $20.85/boe for the same period of 2018. The increase in both periods of 2019 was driven by higher realized pricing in Canada which was slightly offset by lower pricing in our U.S operations relative to the same periods of 2018. We recorded realized gains on financial derivatives of $1.45/boe in Q2/2019 and $1.76/boe in YTD 2019 which increased our operating netback after financial derivatives compared Q2/2018 and YTD 2018 when we recorded realized losses of $4.57/boe and $3.09/boe.

In Canada, our operating netback increased to $29.47/boe in Q2/2019 and $27.18/boe in YTD 2019 from $18.12/boe in Q2/2018 and $13.14/boe in YTD 2018. The increase in our netback was primarily from an increase in our realized sales price per boe during Q2/2019 and YTD 2019 which was driven by a higher portion of our production coming from light oil after the Strategic Combination along with narrower Canadian oil differentials. Our operating netback in the U.S. of $28.98/boe in Q2/2019 and $28.96/boe in YTD 2019 was lower than $35.42/boe in Q2/2018 and $33.97/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 capital on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated capital activity during the period.

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Q2 2019 MD&A Page 13

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



	Three Months Ended June 30									Six Months Ended June 30
($ thousands except for per boe)	2019			2018			Change			2019			2018			Change
Gross general and administrative expense	$	12,655		$	12,286		$	369		$	28,274		$	25,322		$	2,952
Overhead recoveries	(1,149		)	(1,723		)	574			(2,632		)	$	(3,751	)	1,119
General and administrative expense	$	11,506		$	10,563		$	943		$	25,642		$	21,571		$	4,071
General and administrative expense per boe	$	1.28		$	1.64		$	(0.36	)	$	1.42		$	1.70		$	(0.28	)

We reported G&A expense of $11.5 million ($1.28/boe) for Q2/2019 and $25.6 million ($1.42/boe) for YTD 2019 compared to $10.6 million ($1.64/boe) for Q2/2018 and $21.6 million ($1.70/boe) for YTD 2018. The increase in G&A expense can be attributed to the additional costs and staff associated with the Strategic Combination. A change in accounting for lease contracts resulted in a $1.4 million reduction in G&A in YTD 2019 relative to YTD 2018. Per unit G&A expense was lower in Q2/2019 and YTD 2019 relative to the same periods of 2018 as we were able to realize efficiencies by combining the two organizations.

G&A expense for YTD 2019 is slightly higher than our expectation due to severance costs associated with a reduction in staffing levels. We expect G&A expense for 2019 to be in line with our annual guidance of approximately $46 million ($1.30/boe).

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 six months ended June 30, 2019 and 2018.



	Three Months Ended June 30							Six Months Ended June 30
($ thousands except for per boe)	2019		2018		Change			2019		2018		Change
Interest on bank loan	$	5,109	$	3,260	$	1,849		$	10,521	$	6,189	$	4,332
Interest on long-term notes	22,825		22,270		555			45,427		43,852		1,575
Interest on lease obligations	158		—		158			328		—		328
Cash interest	28,092		25,530		2,562			56,276		50,041		6,235
Accretion of debt issue costs	1,051		934		117			2,146		2,125		21
Accretion of asset retirement obligations	3,398		2,322		1,076			6,861		4,630		2,231
Financing and interest expense	$	32,541	$	28,786	$	3,755		$	65,283	$	56,796	$	8,487
Cash interest per boe	$	3.14	$	3.97	$	(0.83	)	$	3.12	$	3.94	$	(0.82	)
Financing and interest expense per boe	$	3.63	$	4.48	$	(0.85	)	$	3.62	$	4.48	$	(0.86	)

Financing and interest expense was $32.5 million in Q2/2019 and $65.3 million for YTD 2019 compared to $28.8 million in Q2/2018 and $56.8 million in YTD 2018. Interest on our bank loan of $5.1 million in Q2/2019 and $10.5 million in YTD 2019 was higher than $3.3 million in Q2/2018 and $6.2 million in YTD 2019 due to the increase in loan balances following the assumption of net debt associated with the Strategic Combination. The weighted average interest rate on our bank loan was 3.6% in YTD 2019 compared to 4.5% in YTD 2018. The reported amount of interest on our long-term notes was higher in both periods of 2019 as the exchange rate used to convert the interest on our U.S. dollar denominated long-term notes was higher relative to the comparative periods of 2018. Accretion of our asset retirement obligations was higher in Q2/2019 and YTD 2019 as our asset retirement obligation increased with the Strategic Combination. Cash interest expense of $56.3 million or $3.12/boe for YTD 2019 was in line with expectations and we are maintaining our 2019 annual guidance of approximately $112 million or $3.23/boe.

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 $4.7 million for Q2/2019 and $6.5 million for YTD 2019 is higher than $1.4 million for Q2/2018 and $3.4 million for YTD 2018 primarily due to a higher amount of acreage expiring in Q2/2019 relative to the same period of 2018.

Baytex Energy Corp.

Q2 2019 MD&A Page 14

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 six months ended June 30, 2019 and 2018.



	Three Months Ended June 30							Six Months Ended June 30
($ thousands except for per boe)	2019		2018		Change			2019		2018		Change
Depletion	$	185,232	$	111,035	$	74,197		$	370,076	$	218,813	$	151,263
Depreciation	540		829		(289		)	1,050		1,340		(290		)
Depletion and depreciation	$	185,772	$	111,864	$	73,908		$	371,126	$	220,153	$	150,973
Depletion and depreciation per boe	$	20.75	$	17.40	$	3.35		$	20.56	$	17.35	$	3.21

Depletion and depreciation expense was $185.8 million ($20.75/boe) for Q2/2019 and $371.1 million ($20.56/boe) for YTD 2019 compared to $111.9 million ($17.40/boe) for Q2/2018 and $220.2 million ($17.35/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 and resulted in the depletion rate of $20.75/boe for Q2/2019 and $20.56/boe for YTD 2019 which was higher than $17.40/boe for Q2/2018 and $17.35/boe for YTD 2018.

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 $5.0 million for Q2/2019 and $10.8 million for YTD 2019 compared to $3.9 million for Q2/2018 and $7.8 million for YTD 2018. SBC expense is higher in 2019 relative to 2018 due to the additional expense 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.



	Three Months Ended June 30								Six Months Ended June 30
($ thousands except for exchange rates)	2019			2018		Change			2019			2018		Change
Unrealized foreign exchange (gain) loss	$	(25,318	)	$	22,673	$	(47,991	)	$	(52,259	)	$	58,719	$	(110,978	)
Realized foreign exchange loss	639			2,076		(1,437		)	44			2,247		(2,203		)
Foreign exchange (gain) loss	$	(24,679	)	$	24,749	$	(49,428	)	$	(52,215	)	$	60,966	$	(113,181	)
CAD/USD exchange rates:
At beginning of period	1.3360			1.2901					1.3646			1.2518
At end of period	1.3091			1.3142					1.3091			1.3142

We recorded an unrealized foreign exchange gain of $25.3 million for Q2/2019 and $52.3 million for YTD 2019 due to a strengthening of the Canadian dollar relative to the U.S. dollar. The CAD/USD exchange rate was 1.3091 CAD/USD at June 30, 2019 compared to 1.3360 CAD/USD at March 31, 2019 and 1.3646 CAD/USD at December 31, 2018. We recorded an unrealized foreign exchange loss of $22.7 million in Q2/2018 and $58.7 million in YTD 2018 as the CAD/USD exchange rate weakened to 1.3142 CAD/USD at June 30, 2018 from 1.2901 CAD/USD at March 31, 2018 and 1.2518 CAD/USD at December 31, 2017.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss of $0.6 million for Q2/2019 and $0.04 million for YTD 2019 compared to a loss of $2.1 million for Q2/2018 and $2.2 million for YTD 2018.

Baytex Energy Corp.

Q2 2019 MD&A Page 15

Income Taxes



	Three Months Ended June 30								Six Months Ended June 30
($ thousands)	2019			2018			Change		2019			2018			Change
Current income tax expense (recovery)	$	495		$	2		$	493	$	1,090		$	(71	)	$	1,161
Deferred income tax recovery	(1,555		)	(24,561		)	23,006		(16,040		)	(47,478		)	31,438
Total income tax recovery	$	(1,060	)	$	(24,559	)	$	23,499	$	(14,950	)	$	(47,549	)	$	32,599

Current income tax expense was $0.5 million for Q2/2019 and $1.1 million for YTD 2019 compared to the nominal amounts recorded for Q2/2018 and YTD 2018. The current income tax expense for Q2/2019 and YTD 2019 reflects state taxes owing on our U.S. operations.

We recorded a deferred income tax recovery of $1.6 million for Q2/2019 and $16.0 million for YTD 2019 as compared to $24.6 million for Q2/2018 and $47.5 million for YTD 2018. The deferred income tax recoveries in both periods decreased because the effect of the Alberta tax rate reduction was more than offset by the increase in adjusted funds flow and the decrease in unrealized financial derivative losses.

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.

Net Income (Loss) and Adjusted Funds Flow

The components of adjusted funds flow and net income or loss for the three and six months ended June 30, 2019 and 2018 are set forth in the following table.



	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2019			2018			Change			2019			2018			Change
Petroleum and natural gas sales	$	482,000		$	347,605		$	134,395		$	935,424		$	633,672		$	301,752
Royalties	(86,617		)	(77,205		)	(9,412		)	(167,942		)	(142,044		)	(25,898		)
Revenue, net of royalties	395,383			270,400			124,983			767,482			491,628			275,854

Expenses
Operating	(100,474		)	(70,149		)	(30,325		)	(200,766		)	(136,037		)	(64,729		)
Transportation	(11,869		)	(7,836		)	(4,033		)	(25,199		)	(16,355		)	(8,844		)
Blending and other	(20,890		)	(18,239		)	(2,651		)	(37,678		)	(35,529		)	(2,149		)
Operating netback	$	262,150		$	174,176		$	87,974		$	503,839		$	303,707		$	200,132
General and administrative	(11,506		)	(10,563		)	(943		)	(25,642		)	(21,571		)	(4,071		)
Cash financing and interest	(28,092		)	(25,530		)	(2,562		)	(56,276		)	(50,041		)	(6,235		)
Realized financial derivatives gain (loss)	12,993			(29,408		)	42,401			31,807			(39,249		)	71,056
Realized foreign exchange (loss) gain	(639		)	(2,076		)	1,437			(44		)	(2,247		)	2,203
Other income	1,719			288			1,431			4,306			567			3,739
Current income tax (expense) recovery	(495		)	(2		)	(493		)	(1,090		)	71			(1,161		)
Payments on onerous contracts	—			(195		)	195			—			(292		)	292
Adjusted funds flow	$	236,130		$	106,690		$	129,440		$	456,900		$	190,945		$	265,955
Exploration and evaluation	(4,685		)	(1,358		)	(3,327		)	(6,529		)	(3,377		)	(3,152		)
Depletion and depreciation	(185,772		)	(111,864		)	(73,908		)	(371,126		)	(220,153		)	(150,973		)
Share based compensation	(5,001		)	(3,915		)	(1,086		)	(10,844		)	(7,830		)	(3,014		)
Non-cash financing and accretion	(4,449		)	(3,256		)	(1,193		)	(9,007		)	(6,755		)	(2,252		)
Unrealized financial derivatives gain (loss)	14,673			(47,385		)	62,058			(38,588		)	(65,094		)	26,506
Unrealized foreign exchange gain (loss)	25,318			(22,673		)	47,991			52,259			(58,719		)	110,978
Gain on disposition of oil and gas properties	1,057			244			813			1,057			1,730			(673		)
Deferred income tax recovery	1,555			24,561			(23,006		)	16,040			47,478			(31,438		)
Payments on onerous contracts	—			195			(195		)	—			292			(292		)
Net income (loss) for the period	$	78,826		$	(58,761	)	$	137,587		$	90,162		$	(121,483	)	$	211,645

Baytex Energy Corp.

Q2 2019 MD&A Page 16

We generated adjusted funds flow of $236.1 million for Q2/2019 and $456.9 million for YTD 2019 which is an increase of $129.4 million and $266.0 million from the comparative periods of 2018. The increase in adjusted funds flow was primarily due to higher operating netback which was $88.0 million higher in Q2/2019 and $200.1 million higher in YTD 2019 relative to the same periods of 2018. The increase in operating netback was driven by increased production as a result of the Strategic Combination. We recorded realized hedging gains of $13.0 million in Q2/2019 and $31.8 million in YTD 2019 compared to realized losses of $29.4 million and $39.2 million in the same periods in 2018 which also contributed to the increase in adjusted funds flow.

In Q2/2019 we reported net income of $78.8 million compared to a net loss of $58.8 million in Q2/2018. In addition to the $129.4 million increase in adjusted funds flow in Q2/2019 compared to Q2/2018, unrealized gains on financial derivatives and foreign exchange exceeded losses in Q2/2018 by $110.0 million. This was offset by depletion and depreciation expense that was $73.9 million higher in Q2/2019 compared to Q2/2018. Our deferred tax recovery of $1.6 million for Q2/2019 was $23.0 million lower than $24.6 million for Q2/2018 due to higher net income before income tax which was partially offset by a $10.6 million recovery associated with a reduction in future tax rates in Alberta.

For YTD 2019 we reported net income of $90.2 million compared to a net loss of $121.5 million in YTD 2018. The increase in net income was driven by the $266.0 million increase in adjusted funds flow and by unrealized gains and losses on financial derivatives and foreign exchange which increased net income $137.5 million in YTD 2019 compared to YTD 2018. These increases to net income were offset by an increase in depletion and depreciation expense of $151.0 million. Our deferred tax recovery was $31.4 million lower in YTD 2019 relative to YTD 2018 due to the increase in net income before income tax which was partially offset by a $10.6 million recovery associated with a reduction in future tax rates in Alberta.

Other Comprehensive Income (Loss)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets not recognized in profit or loss. The foreign currency translation loss of $45.4 million for Q2/2019 and $93.2 million for YTD 2019 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the strengthening of the Canadian dollar against the U.S. dollar over both periods. The CAD/USD exchange rate was 1.3091 CAD/USD as at June 30, 2019 compared to 1.3360 CAD/USD at March 31, 2019 and 1.3646 CAD/USD as at December 31, 2018.

Capital Expenditures

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



	Three Months Ended June 30
	2019						2018
($ thousands)	Canada		U.S.		Total		Canada			U.S.		Total
Drilling, completion and equipping	$	54,056	$	35,926	$	89,982	$	9,193		$	45,945	$	55,138
Facilities	8,527		1,920		10,447		19,378			2,175		21,553
Land, seismic and other	5,676		141		5,817		2,037			102		2,139
Total exploration and development	$	68,259	$	37,987	$	106,246	$	30,608		$	48,222	$	78,830
Total acquisitions and property swaps, net of proceeds from divestitures	$	1,647	$	—	$	1,647	$	(21	)	$	—	$	(21	)

	Six Months Ended June 30
	2019						2018
($ thousands)	Canada		U.S.		Total		Canada			U.S.		Total
Drilling, completion and equipping	142,937		81,985		224,922		42,736			81,116		123,852
Facilities	21,467		4,582		26,049		32,368			9,013		41,381
Land, seismic and other	8,725		393		9,118		7,029			102		7,131
Total exploration and development	$	173,129	$	86,960	$	260,089	$	82,133		$	90,231	$	172,364
Total acquisitions and property swaps, net of proceeds from divestitures	$	1,647	$	—	$	1,647	$	(2,047	)			$	(2,047	)

Exploration and development expenditures were $106.2 million for Q2/2019 and $260.1 million for YTD 2019 compared to $78.8 million for Q2/2018 and $172.4 million for YTD 2018. Higher exploration and development expenditures in Q2/2019 and 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.

Baytex Energy Corp.

Q2 2019 MD&A Page 17

In Canada, we invested $68.3 million on exploration and development activities in Q2/2019 which is $37.7 million higher than $30.6 million in Q2/2018. Exploration and development expenditures for Q2/2019 included costs associated with drilling 43 (42.9 net) light oil wells, 4 (4.0 net) heavy oil wells and investing $8.5 million on facilities. Exploration and development expenditures of $173.1 million for YTD 2019 included costs associated with drilling 141 (121.2 net) light oil wells, 5 (5.0 net) heavy oil wells and 4 (4.0 net) stratigraphic exploration wells along with $21.5 million of associated facility expenditures. Total exploration and development costs for YTD 2019 were $91.0 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 $38.0 million for Q2/2019, $10.2 million lower than $48.2 million for Q2/2018. The decrease in Q2/2019 is primarily a result of lower completion activity on our lands relative to Q2/2018. During Q2/2019 we participated in the drilling of 20 (5.1 net) wells and commenced production from 29 (5.0 net) wells compared to 18 (2.6 net) wells drilled and 32 (7.6 net) wells on production during Q2/2018. Exploration and development expenditures of $87.0 million for YTD 2019 include costs associated with drilling 43 (9.2 net) wells and bringing 65 (13.9 net) wells on production which is slightly lower than exploration and development expenditures of $90.2 million in YTD 2018 when we drilled 43 (9.5 net) well and commenced production from 59 (13.1 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 have narrowed our 2019 annual guidance range and we expect to invest between $550 million and $600 million on exploration and development activities during 2019.

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 June 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 growth. At June 30, 2019, net debt was $2,028.7 million, a decrease of $236.5 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 $196.8 million. Net debt was also lower at June 30, 2019 due to a strengthening of the Canadian dollar which resulted in a $52.7 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 June 30, 2019, our net debt to adjusted funds flow ratio was 2.3, after adjustment for the Strategic Combination as if the transaction had occurred on the first day of the relevant period, compared to a ratio of 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 commodity prices and production combined with net debt that was $236.5 million lower at June 30, 2019.

On July 31, 2019, the Board of Directors approved the early redemption of the US $150 million principal amount of 6.75% senior unsecured notes which were issued on February 17, 2011. We will provide notice to the bondholders and expect to redeem the notes in September 2019.

Bank Loan

At June 30, 2019, the principal amount of bank loan and letters of credit outstanding was $429.9 million and we had approximately $622.8 million of undrawn capacity under our credit facilities that total approximately $1.05 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, Baytex amended its 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 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.

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 for Q2/2019 was 3.5% and 3.6% for YTD 2019 compared to 4.1% for Q2/2018 and 4.5% for YTD 2018.

Financial Covenants

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



Covenant Description	Position as at June 30, 2019	Covenant
Senior Secured Debt⁽¹⁾ to Bank EBITDA⁽²⁾(Maximum Ratio)	0.47:1.00	3.50:1.00
Interest Coverage⁽³⁾ (Minimum Ratio)	8.24:1.00	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 June 30, 2019, the Company's Senior Secured Debt totaled $429.9 million which includes $414.7 million of principal amounts outstanding and $15.2 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 June 30, 2019 was $911.1 million.


(3)	Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended June 30, 2019 were $110.6 million.

Long-Term Notes

We have four series of long-term notes outstanding that total $1.54 billion as at June 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 8.24:1.00 as at June 30, 2019.

On February 17, 2011, we issued US$150 million principal amount of senior unsecured notes bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. These notes are redeemable at our option, in whole or in part, at par anytime prior to maturity. On July 31, 2019, the Board of Directors approved the early redemption of these notes. We will provide notice to the bondholders and expect to redeem the notes in September 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 six months ended June 30, 2019, we issued 2.7 million common shares pursuant to our share-based compensation program. As at July 31, 2019, we had 557.9 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 June 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	$	227,717	$	227,717	$	—	$	—	$	—
Bank loan^{(1) (2)}	414,691		—		414,691		—		—
Long-term notes⁽²⁾	1,543,645		—		720,005		823,640		—
Interest on long-term notes⁽³⁾	278,978		89,421		131,899		57,658		—
Lease agreements	15,938		6,108		9,549		281		—
Processing agreements	46,408		12,269		13,271		9,052		11,816
Transportation agreements	103,327		17,603		37,312		17,621		30,791
Total	$	2,630,704	$	353,118	$	1,326,727	$	908,252	$	42,607


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

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

Baytex Energy Corp.

Q2 2019 MD&A Page 18

QUARTERLY FINANCIAL INFORMATION



	2019				2018								2017
($ thousands, except per common share amounts)	Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3
Petroleum and natural gas sales	482,000		453,424		358,437		436,761		347,605		286,067		303,163		258,620
Net income (loss)	78,826		11,336		(231,238	)	27,412		(58,761	)	(62,722	)	76,038		(9,228	)
Per common share - basic	0.14		0.02		(0.42	)	0.07		(0.25	)	(0.27	)	0.32		(0.04	)
Per common share - diluted	0.14		0.02		(0.42	)	0.07		(0.25	)	(0.27	)	0.32		(0.04	)
Adjusted funds flow	236,130		220,770		110,828		171,210		106,690		84,255		105,796		77,340
Per common share - basic	0.42		0.40		0.20		0.46		0.45		0.36		0.45		0.33
Per common share - diluted	0.42		0.40		0.20		0.45		0.45		0.36		0.44		0.33
Exploration and development	106,246		153,843		184,162		139,195		78,830		93,534		90,156		61,544
Canada	68,259		104,870		125,507		94,477		30,608		51,525		41,864		14,487
U.S.	37,987		48,973		58,655		44,718		48,222		42,009		48,292		47,057
Acquisitions, net of divestitures	1,647		—		183		46		(21	)	(2,026	)	(3,937	)	(7,436	)
Net debt	2,028,686		2,175,241		2,265,167		2,112,090		1,784,835		1,783,379		1,734,284		1,748,805
Total assets	6,222,190		6,359,157		6,377,198		6,491,303		4,476,906		4,433,074		4,372,111		4,353,637
Common shares outstanding	556,798		555,872		554,060		553,950		236,662		236,578		235,451		235,451

Daily production
Total production (boe/d)	98,402		101,115		98,890		82,412		70,664		69,522		69,556		69,310
Canada (boe/d)	58,580		60,018		60,453		45,214		34,042		33,505		32,194		34,560
U.S. (boe/d)	39,822		41,097		38,437		37,198		36,622		36,017		37,362		34,750

Benchmark prices
WTI oil (US$/bbl)	59.81		54.90		58.81		69.50		67.88		62.87		55.40		48.20
WCS heavy (US$/bbl)	49.14		42.61		19.39		47.25		48.61		38.59		43.14		38.26
CAD/USD avg exchange rate	1.3376		1.3293		1.3215		1.307		1.2911		1.2651		1.2717		1.2524
AECO gas ($/mcf)	1.17		1.94		1.94		1.35		1.03		1.85		1.96		2.04
NYMEX gas (US$/mmbtu)	2.64		3.15		3.64		2.90		2.80		3.00		2.93		3.00

Sales price ($/boe)	51.49		47.98		37.89		55.03		51.22		42.96		44.75		38.04
Royalties ($/boe)	(9.67	)	(8.94	)	(8.77	)	(12.13	)	(12.01	)	(10.36	)	(10.86	)	(8.65	)
Operating expense ($/boe)	(11.22	)	(11.02	)	(10.76	)	(10.25	)	(10.91	)	(10.53	)	(10.91	)	(10.10	)
Transportation expense ($/boe)	(1.33	)	(1.46	)	(1.21	)	(1.26	)	(1.22	)	(1.36	)	(1.20	)	(1.46	)
Operating netback ($/boe)	29.27		26.56		17.15		31.39		27.08		20.71		21.78		17.83
Financial derivatives gain (loss) ($/boe)	1.45		2.07		(0.34	)	(4.07	)	(4.57	)	(1.57	)	0.30		0.44
Operating netback after financial derivatives ($/boe)	30.72		28.63		16.81		27.32		22.51		19.14		22.08		18.27

In Q2/2019 we delivered our third consecutive quarter of strong operating and financial results following closing of the Strategic Combination in Q3/2018. Over the last eight quarters, production has increased from 69,310 boe/d during Q3/2017 to 98,402 boe/d in Q2/2019 as a result of the Strategic Combination along with our successful development programs in the U.S. and Canada. Improved well productivity from enhanced completion techniques contributed to the increase in daily production in the U.S. 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 and increased demand have been mitigated by geopolitical factors and increasing production in North America. We received the strongest realized pricing in our Canadian operations for the eight most recent quarters after a narrowing of light and heavy oil differentials and a higher weighting of light oil production following the Strategic Combination. The WCS benchmark averaged US$49.14/bbl in Q2/2019 compared to US$19.39/bbl in Q4/2018 and US$38.26/bbl in Q3/2017.

Baytex Energy Corp.

Q2 2019 MD&A Page 19

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 and increased through Q2/2019 with higher production due to strong well performance along with the Strategic Combination. The increase in production and operating netback after financial derivatives resulted in adjusted funds flow of $236.1 million in Q2/2019 which is higher than $77.3 million reported in Q3/2017.

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 $1,748.8 million at Q3/2017 to $2,028.7 million at Q2/2019 primarily due to the additional net debt of $363.6 million assumed in conjunction with the Strategic Combination in Q3/2018.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at June 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 six months ended June 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 a $18.0 million increase to right-of-use assets ("lease assets"), a $2.0 million reduction of onerous contracts and an $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 lease with similar characteristics. The lease asset is recognized at the amount of the lease obligation, 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.

Baytex Energy Corp.

Q2 2019 MD&A Page 20

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.

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



	Three Months Ended June 30					Six Months Ended June 30
($ thousands)	2019			2018		2019		2018
Cash flow from operating activities	$	247,585		$	74,538	$	404,950	$	162,150
Change in non-cash working capital	(16,253		)	29,228		42,224		22,608
Asset retirement obligations settled	4,798			2,924		9,726		6,187
Adjusted funds flow	$	236,130		$	106,690	$	456,900	$	190,945

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.

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.

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Q2 2019 MD&A Page 21

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



	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2019			2018			2019			2018
Cash flow used in investing activities	$	109,596		$	73,411		$	297,184		$	157,107
Change in non-cash working capital	(1,389		)	5,905			(35,069		)	13,717
Proceeds from disposition of oil an gas properties	950			21			950			2,234
Property acquisitions	(2,073		)	—			(2,073		)	(187		)
Property swaps	(524		)	—			(524		)	—
Additions to other plant and equipment	(314		)	(507		)	(379		)	(507		)
Exploration and development expenditures	$	106,246		$	78,830		$	260,089		$	172,364

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 ultimate 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 liquidity or repayment obligation.

The following table summarizes our calculation of net debt.



($ thousands)	June 30, 2019			December 31, 2018
Bank loan⁽¹⁾	$	414,691		$	522,294
Long-term notes⁽¹⁾	1,543,645			1,596,323
Trade and other payables	227,717			258,114
Trade and other receivables	(157,367		)	(111,564		)
Net debt	$	2,028,686		$	2,265,167


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

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 June 30						Six Months Ended June 30
($ thousands)	2019			2018			2019			2018
Petroleum and natural gas sales	$	482,000		$	347,605		$	935,424		$	633,672
Blending and other expense	(20,890		)	(18,239		)	(37,678		)	(35,529		)
Total sales, net of blending and other expense	461,110			329,366			897,746			598,143
Royalties	(86,617		)	(77,205		)	(167,942		)	(142,044		)
Operating expense	(100,474		)	(70,149		)	(200,766		)	(136,037		)
Transportation expense	(11,869		)	(7,836		)	(25,199		)	(16,355		)
Operating netback	262,150			174,176			503,839			303,707
Realized financial derivative gain (loss)	12,993			(29,408		)	31,807			(39,249		)
Operating netback after realized financial derivatives	$	275,143		$	144,768		$	535,646		$	264,458

Baytex Energy Corp.

Q2 2019 MD&A Page 22

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 June 30						Six Months Ended June 30
($ thousands)	2019			2018			2019			2018
Net income (loss)	$	78,826		$	(58,761	)	$	90,162		$	(121,483	)
Plus:
Financing and interest	32,541			28,786			65,283			56,796
Unrealized foreign exchange (gain) loss	(25,318		)	22,673			(52,259		)	58,719
Unrealized financial derivatives (gain) loss	(14,673		)	47,385			38,588			65,094
Current income tax expense (recovery)	495			2			1,090			(71		)
Deferred income tax recovery	(1,555		)	(24,561		)	(16,040		)	(47,478		)
Depletion and depreciation	185,772			111,864			371,126			220,153
Gain on disposition of oil and gas properties	(1,057		)	(244		)	(1,057		)	(1,730		)
Payments on lease obligations	(1,623		)	—			(3,012		)	—
Non-cash items⁽¹⁾	9,686			5,273			17,373			11,207
Bank EBITDA	$	263,094		$	132,417		$	511,254		$	241,207


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

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 June 30, 2019, except for the matter described below.

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

The assets previously held by Raging River contributed revenues net of royalties of $127.6 million for Q2/2019 and $251.1 million for YTD 2019. At June 30, 2019, total assets of $2.1 billion were associated with the acquired entity.

FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "plan", "project", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; our business strategies, plans and objectives; our capital budget and expected average daily production for 2019; 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; that we intend to redeem the US$150 million principal amount of 6.75% notes in September 2019; 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

Baytex Energy Corp.

Q2 2019 MD&A Page 23

significant portion of our financial obligations will be funded by adjusted funds flow and our plan to complete an assessment of the controls, policies and procedures associated with Raging River by August 22, 2019.

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.

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