Form 6-K BAYTEX ENERGY CORP. For: Aug 09

Form 6-K BAYTEX ENERGY CORP. For: Aug 09

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August 9, 2016 5:00 PM EDT

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 Under the
Securities Exchange Act of 1934

For the month of August 2016

Commission File Number: 1-32754

BAYTEX ENERGY CORP.
(Exact name of registrant as specified in its charter)

2800, 520 – 3^rd AVENUE S.W.
CALGARY, ALBERTA, CANADA
T2P 0R3
(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F o Form 40-F ý

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes o No ý

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

The following document attached as an exhibit hereto is incorporated by reference herein:

Exhibit No.			Document

	99.1		Second Quarter Report 2016

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		BAYTEX ENERGY CORP.
		/s/ Rodney D. Gray Name: Rodney D. Gray Title: Chief Financial Officer
Dated: August 9, 2016

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SIGNATURES

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Exhibit 99.1

SUMMARY

•: Generated production of 70,031 boe/d (77% oil and NGL) in Q2/2016;
•: Delivered funds from operations ("FFO") of $81.3 million ($0.39 per share) in Q2/2016;
•: Reduced net debt by $39 million in Q2/2016 as funds from operations exceeded capital expenditures;
•: Realized an operating netback (sales price less royalties, operating and transportation expenses) in Q2/2016 of $14.39/boe ($18.13/boe including financial derivatives gain);
•: Reinitiated production from heavy oil wells shut-in during the first quarter due to low oil prices; at June 30, approximately 6,500 boe/d of the 7,500 boe/d previously shut-in had been re-started;
•: Reduced operating expenses by 12% to $9.42/boe in the first half of 2016, as compared to $10.70/boe in the first half of 2015;
•: Maintained strong levels of financial liquidity with a Senior Secured Debt to Bank EBITDA ratio of 0.86:1.00; and
•: Entered into an agreement to dispose of our operated assets in the Eagle Ford for approximately $55 million.

			Three Months Ended									Six Months Ended

			June 30, 2016			March 31, 2016			June 30, 2015			June 30, 2016			June 30, 2015

FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales		$	195,733		$	153,598		$	342,803		$	349,331		$	626,186
Funds from operations⁽¹⁾			81,261			45,645			158,050			126,906			318,270
	Per share – basic		0.39			0.22			0.77			0.60			1.70
	Per share – diluted		0.39			0.22			0.77			0.60			1.70
Net income (loss)			(86,937	)		607			(26,955	)		(86,330	)		(202,871	)
	Per share – basic		(0.41	)		0.00			(0.13	)		(0.41	)		(1.08	)
	Per share – diluted		(0.41	)		0.00			(0.13	)		(0.41	)		(1.08	)
Exploration and development			35,490			81,685			106,010			117,175			253,439
Acquisitions, net of divestitures			(37	)		(9	)		1,170			(46	)		2,720

Total oil and natural gas capital expenditures		$	35,453		$	81,676		$	107,180		$	117,129		$	256,159

Bank loan⁽²⁾		$	347,083		$	290,465		$	192,255		$	347,083		$	192,255
Long-term notes⁽²⁾			1,544,181			1,540,546			1,493,013			1,544,181			1,493,013

Long-term debt			1,891,264			1,831,011			1,685,268			1,891,264			1,685,268
Working capital deficiency			51,274			150,332			137,243			51,274			137,243

Net debt⁽³⁾		$	1,942,538		$	1,981,343		$	1,822,511		$	1,942,538		$	1,822,511

Baytex Energy Corp. Second Quarter Report 2016 1

		Three Months Ended			Six Months Ended

		June 30, 2016	March 31, 2016	June 30, 2015	June 30, 2016	June 30, 2015

OPERATING
Daily production
	Heavy oil (bbl/d)	22,423	24,807	35,397	23,615	37,302
	Light oil and condensate (bbl/d)	21,894	24,489	25,899	23,191	26,971
	NGL (bbl/d)	9,834	10,109	8,232	9,971	8,228
	Total oil and NGL (bbl/d)	54,151	59,405	69,528	56,777	72,501
	Natural gas (mcf/d)	95,281	98,220	91,456	96,750	91,234
	Oil equivalent (boe/d @ 6:1)⁽⁴⁾	70,031	75,776	84,770	72,902	87,707
Benchmark prices
	WTI oil (US$/bbl)	45.60	33.45	57.94	39.53	53.29
	WCS heavy oil (US$/bbl)	32.29	19.22	46.35	25.76	40.14
	Edmonton par oil ($/bbl)	54.78	40.80	67.72	47.80	59.84
	LLS oil (US$/bbl)	46.20	33.24	62.38	39.73	56.47
Baytex average prices (before hedging)
	Heavy oil ($/bbl)⁽⁵⁾	30.09	12.54	44.59	20.87	36.21
	Light oil and condensate ($/bbl)	52.42	37.97	65.11	44.79	58.50
	NGL ($/bbl)	13.28	18.38	15.78	15.86	17.55
	Total oil and NGL ($/bbl)	36.07	24.02	48.82	29.76	42.39
	Natural gas ($/mcf)	1.94	2.40	3.06	2.17	3.14
	Oil equivalent ($/boe)	30.52	21.93	43.34	26.06	38.30
CAD/USD noon rate at period end		1.3009	1.2971	1.2474	1.3009	1.2474
CAD/USD average rate for period		1.2885	1.3748	1.2294	1.3317	1.2353

COMMON SHARE INFORMATION
TSX
Share price (Cdn$)
	High	9.04	5.39	24.14	9.04	24.87
	Low	4.85	1.57	19.24	1.57	16.03
	Close	7.50	5.13	19.43	7.50	20.03
	Volume traded (thousands)	466,201	483,311	80,572	949,511	202,752
NYSE
Share price (US$)
	High	7.14	4.15	20.10	7.14	19.99
	Low	3.67	1.08	15.42	1.08	13.14
	Close	5.79	3.97	15.58	5.79	15.80
	Volume traded (thousands)	198,514	154,052	44,497	352,567	68,710
Common shares outstanding (thousands)		210,715	210,689	206,193	210,715	206,193

Notes:

(1): Funds from operations is not a measurement based on generally accepted accounting principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. We define funds from operations as cash flow from operating activities adjusted for changes in non-cash operating working capital and other operating items. Baytex's funds from operations may not be comparable to other issuers. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund capital investments and potential future dividends. For a reconciliation of funds from operations to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three and six months ended June 30, 2016.
(2): Principal amount of instruments.
(3): Net debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives and assets held for sale)) and the principal amount of both the long-term notes and the bank loan.
(4): 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. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(5): Heavy oil prices exclude condensate blending.

2 Baytex Energy Corp. Second Quarter Report 2016

Advisory Regarding Forward-Looking Statements

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

Specifically, this press release contains forward-looking statements relating to but not limited to: our business plan, strategies and objectives, including to deploy capital efficiently, maintain strong levels of financial liquidity and emphasize cost reductions; that we are well positioned to benefit from a continued oil price recovery and that our three core plays provide strong capital efficiencies; our target for 2016 capital expenditures to approximate funds from operations in order to minimize additional bank borrowings; our Eagle Ford shale play, including our assessment of the performance of wells drilled in Q2/2016, our plan to monitor and evaluate the multi-zone potential of our acreage, and the cost to drill, complete and equip a well; our ability to partially reduce the volatility in our funds from operations by utilizing financial derivative contracts for commodity prices, heavy oil differentials and interest and foreign exchange rates; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in reducing the volatility in our funds from operations; our anticipated disposition of assets in Canada; that we expect funds from operations to exceed capital expenditures in 2016; and our expectations for exploration and development capital expenditures and annual average production rate for 2016 and the impact that the spending reduction will have on our annual average production rate for 2016. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

These forward-looking statements are based on certain key assumptions regarding, among other things: 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; further declines or an extended period of the currently low oil and natural gas prices; failure to comply with the covenants in our debt agreements; that our credit facilities may not provide sufficient liquidity or may not be renewed; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; risks associated with the ownership of our securities, including changes in market-based factors and the discretionary nature of dividend payments; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2015, 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.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.

Baytex Energy Corp. Second Quarter Report 2016 3

Non-GAAP Financial Measures

Funds from operations is not a measurement based on Generally Accepted Accounting Principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash generated from operating activities adjusted for changes in non-cash operating working capital and other operating items. Baytex's determination of funds from operations may not be comparable with the calculation of similar measures for other entities. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund capital investments and potential future dividends to shareholders. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.

Net debt is not a measurement based on GAAP in Canada. We define net debt as the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives)) and the principal amount of both the long-term notes and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

Bank EBITDA is not a measurement based on GAAP in Canada. We define Bank EBITDA as our consolidated net income attributable to shareholders before interest, taxes, depletion and depreciation, and certain other non-cash items as set out in the credit agreement governing our revolving credit facilities. This measure is used to measure compliance with certain financial covenants.

Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to product revenue less royalties, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. Our determination of operating netback may not be comparable with the calculation of similar measures for other entities. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

4 Baytex Energy Corp. Second Quarter Report 2016

MESSAGE TO SHAREHOLDERS

Second Quarter Results

As we entered 2016, we laid out certain strategic objectives to help guide us through the commodity price downturn, which included deploying capital efficiently, maintaining strong levels of financial liquidity and continuing to emphasize cost reductions across all facets of our organization. Our second quarter results were reflective of these strategic objectives and we remain well positioned to benefit from a continued recovery in crude oil prices. We highlight below some of the results achieved to-date from the execution of these initiatives.

Capital Deployment

Our emphasis on deploying capital efficiently was evident during the second quarter as we continued to defer investments in our heavy oil operations in Canada and reduced the pace of development in the Eagle Ford. As a result, we significantly curtailed our level of capital spending, focusing all development activity in the Eagle Ford, our highest rate of return and highest netback asset. In Q2/2016, our exploration and development expenditures totaled $35.5 million, down from $81.7 million in Q1/2016 and $140.8 million in Q4/2015.

During the second quarter, we participated in the drilling of 38 gross (11.3 net) wells in the Eagle Ford and commenced production from 20 gross (5.7 net) wells. This compares to Q1/2016 when we commenced production from 34 gross (10.2 net) wells. Of the 20 wells that commenced production during the second quarter, all have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,300 boe/d. We currently have three drilling rigs operating on our lands, as compared to six drilling rigs in Q1/2016. We continue to monitor and evaluate the multi-zone development potential of our acreage, which sees us targeting the Lower Eagle Ford, Upper Eagle Ford and Austin Chalk formations.

In addition to a reduced pace of development, in Canada we shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production during the first quarter of 2016. As crude oil prices recovered from the lows experienced earlier this year, we reinitiated production from the majority of these wells in May and June. By the end of June, approximately 6,500 boe/d of the 7,500 boe/d previously shut-in had been re-started. We expect to resume production from the remaining 1,000 boe/d in the second half of 2016.

Production averaged 70,031 boe/d (77% oil and NGL) in Q2/2016 as compared to 75,776 boe/d in Q1/2016, reflecting both the reduced pace of development and the impact of the shut-in heavy oil volumes.

Financial Liquidity

On March 31, 2016, we amended our credit facilities to provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million, granting our banking syndicate first priority security over our assets and restructuring our financial covenants. The revolving facilities, which currently mature in June 2019, are not borrowing base facilities and do not require annual or semi-annual reviews. Our Senior Secured Debt to Bank EBITDA ratio as at June 30, 2016 was 0.86:1.00 (maximum permitted ratio of 5.00:1.00) and our interest coverage ratio was 4.05:1.00 (minimum permitted ratio of 1.25:1.00).

In addition to amending our credit facilities, we have targeted our capital expenditures to approximate our funds from operations in order to minimize additional bank borrowings. In Q2/2016, our funds from operations totaled $81.3 million, as compared to capital expenditures of $35.5 million, and in the first six months of 2016, our funds from operations totaled $126.9 million, as compared to capital expenditures of $117.1 million.

Our net debt (bank loan, long-term notes and working capital deficiency) has decreased to $1.94 billion at June 30, 2016 from $2.05 billion at December 31, 2015.

Baytex Energy Corp. Second Quarter Report 2016 5

Cost Reductions

We continue to have success in reducing our cost structure while maintaining efficiency in our operations and the safety of our employees.

Costs in the Eagle Ford have continued to decrease with wells now being drilled, completed and equipped for approximately US$5.4 million, as compared to US$8.2 million in late 2014. Despite achieving cost reductions of approximately 20% in Canada during 2015, the prevailing commodity prices have not supported additional drilling on our Canadian assets.

Operating expenses have been reduced by 12% to $9.42/boe in the first half of 2016, as compared to $10.70/boe in the first half of 2015. These cost reductions reflect a combination of a lower overall cost structure in Canada and our lower cost Eagle Ford assets representing a larger percentage of our total production. Transportation expenses are also down, averaging $0.90/boe through the first six months of 2016, as compared to $1.94/boe in 2015.

General and administrative expenses for the three and six months ended June 30, 2016 of $12.2 million and $26.4 million, respectively, have decreased from $15.6 million and $32.6 million for the same periods in 2015. The decrease is attributable to reductions in staffing levels commensurate with lower activity levels combined with a reduction in discretionary spending and supplier's costs. As a continued cost control measure, all full-time employee salaries and all annual retainers paid to our directors were reduced by 10% effective March 1, 2016.

Operating Netback

During the second quarter, our operating netback improved by 147% as compared to Q1/2016 as crude oil prices strengthened from the lows of the first quarter and heavy oil differentials tightened as a result of supply disruptions associated with the forest fires near Fort McMurray. In Q2/2016, the price for West Texas Intermediate light oil ("WTI") averaged US$45.60/bbl, as compared to US$33.45/bbl in Q1/2016, while the discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, averaged US$13.31/bbl in Q2/2016, as compared to US$14.23/bbl in Q1/2016.

We generated an operating netback in Q2/2016 of $14.39/boe ($18.13/boe including financial derivatives gain), up from $5.82/boe ($12.29/boe including financial derivatives gain) in Q1/2016. The Eagle Ford generated an operating netback of $17.66/boe ($11.41/boe in Q1/2016) while our Canadian operations generated an operating netback of $10.44/boe (loss of $0.77/boe in Q1/2016).

The following table provides a summary of our operating netbacks for the periods noted.

			Three Months Ended June 30

			2016						2015

($ per boe except for volume)			Canada		U.S.		Total		Canada		U.S.		Total

Sales volume (boe/d)			31,722		38,309		70,031		45,222		39,548		84,770
Oil and natural gas revenues		$	25.80	$	34.43	$	30.52	$	40.43	$	46.67	$	43.34
Less:
	Royalties		2.74		9.89		6.65		6.87		13.79		10.10
	Operating expenses		10.84		6.88		8.67		13.45		7.43		10.64
	Transportation expenses		1.78		–		0.81		3.63		–		1.94

Operating netback		$	10.44	$	17.66	$	14.39	$	16.48	$	25.45	$	20.66
	Financial derivatives gain		–		–		3.74		–		–		5.19

Operating netback after financial derivatives		$	10.44	$	17.66	$	18.13	$	16.48	$	25.45	$	25.85

6 Baytex Energy Corp. Second Quarter Report 2016

Risk Management

For the second half of 2016, we have entered into hedges on approximately 46% of our net WTI exposure with 15% fixed at US$63.79/bbl and 31% hedged utilizing a 3-way option structure. We have also entered into hedges on approximately 35% of our net WCS differential exposure and 67% of our net natural gas exposure.

For 2017, we have entered into hedges on approximately 31% of our net WTI exposure utilizing a 3-way option structure. We have also entered into hedges on approximately 23% of our net WCS differential exposure and 44% of our net natural gas exposure.

A complete listing of our financial derivative contracts can be found in Note 15 to our Q2/2016 financial statements.

Disposition Activity

In Q2/2016, we entered into an agreement to dispose of our operated assets in the Eagle Ford for approximately $55 million. Production from these assets is currently 1,000 boe/d and the disposition includes reserves of approximately 1.26 million boe on a proved plus probable basis (as evaluated by Ryder Scott Company, L.P. at December 31, 2015). This production has a lower netback than our other Eagle Ford barrels due to small economies of scale. The Eagle Ford transaction closed on July 27, 2016. In addition, we anticipate closing dispositions relating to an additional 1,250 boe/d of certain non-core assets in Canada. These transactions are expected to close during the third quarter.

2016 Guidance

As a result of continued depressed crude oil prices, our development activity in the Eagle Ford has been reduced. We currently have three drilling rigs operating on our lands, as compared to six drilling rigs in Q1/2016.

Given the reduced pace of development anticipated for the second half of 2016, we are now forecasting full-year 2016 exploration and development capital expenditures of $200 to $225 million, down from previous expectations of $225 to $265 million.

Taking into account the above noted disposition activity and the reduced spending profile, we now anticipate full year 2016 production of 67,000 to 69,000 boe/d (previously 68,000 to 72,000 boe/d). Excluding the impact of disposition activity, the approximate 13% reduction in planned spending impacts our 2016 production forecast by only 1%. Our 2016 program will remain flexible and allows for adjustments to spending based on changes in the commodity price environment.

At this level of spending and based on the forward strip for crude oil and natural gas, we expect our funds from operations to exceed capital expenditures in 2016.

Board Appointment

The Board of Directors is pleased to announce the appointment of Trudy M. Curran as a director of Baytex. Ms. Curran holds a Bachelor of Arts degree in English and a Bachelor of Laws degree (both with distinction) from the University of Saskatchewan and the ICD.D designation from the Institute of Corporate Directors. She is a retired businesswoman with extensive experience in executive compensation, mergers and acquisitions, financing and governance. She served as an officer of Canadian Oil Sands Limited from September 2002 to the time of its sale in February 2016. As Senior Vice President, General Counsel & Corporate Secretary of Canadian Oil Sands Limited, she was responsible for legal, human resources and administration and a member of the executive team focused on strategy and risk management. From 2003 to 2016, she was a director of Syncrude Canada Ltd., where she served

Baytex Energy Corp. Second Quarter Report 2016 7

as chair of the Human Resources and Compensation Committee and as a member of the Pension Committee. She serves on the Executive Committee of the Calgary chapter of the Institute of Corporate Directors and is a member of the board and the Finance and Audit Committee of Kids Cancer Care Foundation of Alberta.

Conclusion

Our operating results for the second quarter were consistent with our expectations and demonstrate the commitment we have made during this downturn to deploy capital efficiently, maintain strong levels of financial liquidity and reduce costs in all facets of our business. Importantly, our funds from operations exceeded capital expenditures during both the second quarter and first half resulting in a reduction in net debt. We remain well positioned to benefit from a rising oil price environment with strong capital efficiencies across our three core resource plays.

We look forward to executing our plans for 2016 for the ongoing benefit of all stakeholders and we thank you for your continued support.

On behalf of the Board of Directors,

James L. Bowzer
President and Chief Executive Officer
July 28, 2016

8 Baytex Energy Corp. Second Quarter Report 2016

MANAGEMENT'S DISCUSSION AND ANALYSIS

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, 2016. This information is provided as of July 27, 2016. 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 six months ended June 30, 2016 ("YTD 2016") have been compared with the results for the six months ended June 30, 2015 ("YTD 2015") and the results for the three months ended June 30, 2016 ("Q2/2016") have been compared with the results for the three months ended June 30, 2015 ("Q2/2015"). This MD&A should be read in conjunction with the Company's condensed interim unaudited consolidated financial statements ("consolidated financial statements") for the three and six months ended June 30, 2016, its audited comparative consolidated financial statements for the years ended December 31, 2015 and 2014, together with the accompanying notes and its Annual Information Form for the year ended December 31, 2015. 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, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

In this MD&A, barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

This MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our advisory on forward-looking information and statements.

NON-GAAP FINANCIAL MEASURES

In this MD&A, we refer to certain financial measures (such as funds from operations, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada ("GAAP"). While funds from operations, net debt and operating netback are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures by other issuers.

Funds from Operations

We consider funds from operations ("FFO") a key measure that provides a more complete understanding of our results of operations and financial performance, including our ability to generate funds for capital investments, debt repayment and potential dividends. However, funds from operations should not be construed as an alternative to performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income (loss).

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

		Three Months Ended June 30				Six Months Ended June 30

($ thousands)		2016		2015		2016		2015

Cash flow from operating activities	$	54,961	$	137,848	$	119,314	$	325,748
Change in non-cash working capital		25,592		17,042		5,183		(15,084	)
Asset retirement expenditures		708		3,160		2,409		7,606

Funds from operations	$	81,261	$	158,050	$	126,906	$	318,270

Baytex Energy Corp. Second Quarter Report 2016 9

Net Debt

We believe that net debt assists in providing a more complete understanding of our financial position.

The following table summarizes our net debt at June 30, 2016 and December 31, 2015.

($ thousands)		June 30, 2016		December 31, 2015

Bank loan⁽¹⁾	$	347,083	$	256,749
Long-term notes⁽¹⁾		1,544,181		1,623,658
Working capital deficiency⁽²⁾⁽³⁾		51,274		169,498

Net debt	$	1,942,538	$	2,049,905

(1): Principal amount of instruments.
(2): Working capital is current assets less current liabilities (excluding current financial derivatives and assets held for sale).
(3): In the oil and gas industry, it is not unusual to have a working capital deficiency as accounts receivable arising from sales of production are usually settled within one or two months but accounts payable related to capital and operating expenditures are usually settled over a longer time span (often two to four months) due to vendor billing cycles and internal approval processes.

Operating Netback

We define operating netback as oil and natural gas revenue, less royalties, operating expenses and transportation expenses. 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.

Bank EBITDA

Bank EBITDA is used to assess compliance with certain financial covenants.

The following table reconciles net income (loss) (a GAAP measure) to Bank EBITDA (a non-GAAP measure).

		Three Months Ended June 30						Six Months Ended June 30

($ thousands)		2016			2015			2016			2015

Net income (loss)	$	(86,937	)	$	(26,955	)	$	(86,330	)	$	(202,871	)
Plus:
Financing and interest		27,888			26,772			56,941			56,182
Unrealized foreign exchange loss (gain)		3,548			(18,349	)		(83,252	)		82,967
Unrealized financial derivatives loss		80,564			41,739			110,687			129,911
Current income tax (recovery) expense		(2,284	)		(553	)		(3,726	)		16,382
Deferred income tax (recovery)		(46,783	)		(12,313	)		(94,905	)		(53,995	)
Depletion and depreciation		121,940			161,476			263,611			335,603
Non-cash items⁽¹⁾		5,829			10,400			11,754			22,609

Bank EBITDA	$	103,765		$	182,217		$	174,780		$	386,788

(1): Non-cash items include share-based compensation, exploration and evaluation expense and gain (loss) on divestiture of oil and gas properties.

SECOND QUARTER HIGHLIGHTS

In Q2/2016, commodity prices improved from Q1/2016 and our funds from operations increased 78% with higher realized pricing and lower operating costs. We continue to prudently manage our capital program with funds from operations exceeding capital expenditures for both Q2/2016 and YTD 2016.

10 Baytex Energy Corp. Second Quarter Report 2016

The price of West Texas Intermediate light oil ("WTI") ranged from a low of US$26.21/bbl in February 2016 to a high of US$51.23/bbl in June 2016. WTI averaged US$45.60/bbl in Q2/2016 up from US$33.45/bbl in Q1/2016 but was still down from US$57.94/bbl in Q2/2015. With improved commodity prices, FFO increased 78% from Q1/2016 to $81.3 million in Q2/2016. Our average sales price increased 39% to $30.52/boe in Q2/2016 compared to $21.93/boe in Q1/2016. WTI has averaged US$39.53/bbl during 2016, a decrease of 26% as compared to the first six months of 2015.

Production averaged 70,031 boe/d during Q2/2016, a decrease of 8% from Q1/2016. This decrease is a result of reduced capital spending combined with low or negative margin production that was shut-in during the first half of the quarter. Canadian production averaged 31,722 boe/d for Q2/2016, a decrease of 9% from Q1/2016. With improved pricing, 6,500 boe/d of previously shut-in production was brought back on during the second half of Q2/2016. The Company still has approximately 1,000 boe/d of production in Canada shut-in. U.S. production averaged 38,309 boe/d for Q2/2016 which was down approximately 7% from 41,067 boe/d in Q1/2016. This decrease was largely anticipated due to a reduction in the rigs and completion crews on our Eagle Ford lands during 2016 in response to the lower commodity prices. Production averaged 72,902 boe/d during YTD 2016 down 17% as compared to YTD 2015. The decrease from 2015 is mainly attributed to the limited amount of capital spending in Canada over the last 18 months combined with low or negative margin production that was shut in. The reduced capital spending in the Eagle Ford is also contributing to the decrease from the prior year.

Funds from operations for Q2/2016 was $81.3 million ($0.39 per basic and diluted share) compared to $45.6 million ($0.22 per basic and diluted share) in Q1/2016. The 78% increase in FFO is attributable to higher commodity prices and lower operating costs in the quarter which was partially offset by lower hedging gains. FFO for YTD 2016 of $126.9 million is down 60% from YTD 2015 and is directly attributable to lower commodity prices, lower production volumes in Canada and lower realized financial derivatives gain.

Capital activity in the current quarter slowed from Q1/2016 with capital expenditures totaling $35.5 million, a decrease of $46.2 million from Q1/2016 and $71.7 million from Q2/2015. Despite lower activity levels in Q2/2016, 92% of total capital spending was focused on our Eagle Ford assets. Capital spending in the Eagle Ford totaled $32.7 million in Q2/2016 where we drilled 11.3 net wells, completed 7.2 net wells and brought 5.7 net wells on-stream. There was very limited activity in Canada in Q2/2016 with total capital spending of $2.7 million as compared to $7.7 million in Q2/2015.

With reduced capital spending and higher commodity prices, our net debt decreased to $1.94 billion at June 30, 2016 from $2.05 billion at December 31, 2015. At June 30, 2016, we were in compliance with all of our financial covenants with approximately $410 million in undrawn credit capacity.

Baytex Energy Corp. Second Quarter Report 2016 11

RESULTS OF OPERATIONS

The Canadian division includes the heavy oil assets in Peace River and Lloydminster and the conventional oil and natural gas assets in Western Canada. The U.S. division includes the Eagle Ford assets in Texas.

Production

Three Months Ended June 30

2016

2015

Daily Production

Canada

U.S.

Total

Canada

U.S.

Total

Liquids (bbl/d)

Heavy oil

22,423

–

22,423

35,397

–

35,397

Light oil and condensate

1,461

20,433

21,894

1,900

23,999

25,899

NGL

1,268

8,566

9,834

1,085

7,147

8,232

Total liquids (bbl/d)

25,152

28,999

54,151

38,382

31,146

69,528

Natural gas (mcf/d)

39,422

55,859

95,281

41,042

50,414

91,456

Total production (boe/d)

31,722

38,309

70,031

45,222

39,548

84,770

Production Mix

Heavy oil

71%

–%

32%

78%

–%

41%

Light oil and condensate

54%

31%

61%

31%

NGL

22%

14%

18%

10%

Natural gas

20%

24%

23%

15%

21%

18%

Six Months Ended June 30

2016

2015

Daily Production

Canada

U.S.

Total

Canada

U.S.

Total

Liquids (bbl/d)

Heavy oil

23,615

–

23,615

37,302

–

37,302

Light oil and condensate

1,513

21,678

23,191

1,995

24,976

26,971

NGL

1,301

8,670

9,971

1,162

7,066

8,228

Total liquids (bbl/d)

26,429

30,348

56,777

40,459

32,042

72,501

Natural gas (mcf/d)

40,712

56,038

96,750

41,645

49,589

91,234

Total production (boe/d)

33,214

39,688

72,902

47,400

40,307

87,707

Production Mix

Heavy oil

71%

–%

32%

79%

–%

43%

Light oil and condensate

55%

32%

62%

31%

NGL

22%

14%

18%

Natural gas

20%

23%

22%

15%

20%

17%

Production for Q2/2016 averaged 70,031 boe/d, a 17% decrease from Q2/2015. U.S. production averaged 38,309 boe/d in Q2/2016 which was a slight decrease from Q2/2015 with less capital spending in Q2/2016 and fewer wells coming on production. Production in Canada averaged 31,722 boe/d, a 30% decrease from Q2/2015. Production has decreased with natural declines as there has been minimal capital spending in Canada over the last 18 months along with 7,500 boe/d of low or negative margin production that was shut-in. With increased commodity prices approximately 6,500 boe/d of the shut-in production was brought back on by the end of June 2016. The shut-in volumes reduced average production in Q2/2016 by approximately 4,250 boe/d.

12 Baytex Energy Corp. Second Quarter Report 2016

Production for YTD 2016 averaged 72,902 boe/d, a 17% decrease from YTD 2015. U.S. production averaged 39,688 boe/d in YTD 2016 and was relatively unchanged from YTD 2015 with continued capital investment in the Eagle Ford offsetting the production declines. Canadian production of 33,214 boe/d decreased 30%, or 14,186 boe/d, from YTD 2015 due to minimal capital investment along with low or negative margin production that was shut-in. The shut-in volumes reduced average production in YTD 2016 by approximately 4,600 boe/d.

Commodity Prices

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

Crude Oil

For Q2/2016, the WTI oil prompt averaged US$45.60/bbl, a 21% decrease from the average WTI price of US$57.94/bbl in Q2/2015. For YTD 2016, the WTI oil prompt averaged US$39.53/bbl, a 26% decrease from the average WTI price of US$53.29/bbl for YTD 2015. The low prices experienced during 2016, as compared to 2015, were due to the continued global oversupply of crude oil and on-going concerns due to the high levels of inventory in storage.

The discount for Canadian heavy oil is measured by the Western Canadian Select ("WCS") price differential to WTI. For the three and six months ended June 30, 2016, the WCS heavy oil differential averaged US$13.31/bbl and US$13.77/bbl, respectively, compared to US$11.59/bbl and US$13.15/bbl for the same periods in 2015. Over the past year, increased pipeline capacity from Canada to the U.S. Gulf Coast has allowed WCS pricing to achieve pipeline equivalency with the large waterborne Gulf Coast refinery market.

Natural Gas

For the three and six months ended June 30, 2016, the AECO natural gas prices averaged $1.25/mcf and $1.68/mcf, respectively, a decrease compared to $2.67/mcf and $2.81/mcf for the same periods in 2015. For the three and six months ended June 30, 2016, the NYMEX natural gas price averaged US$1.95/mmbtu and US$2.02/mmbtu, respectively, a decrease compared to US$2.64/mmbtu and US$2.81/mmbtu for the same periods in 2015. The decrease in natural gas prices on both indices during 2016 was driven by historically high production levels and extremely weak weather related demand compared to 2015.

The following table compares selected benchmark prices and our average realized selling prices for the three and six months ended June 30, 2016.

		Three Months Ended June 30				Six Months Ended June 30

		2016	2015	Change		2016	2015	Change

Benchmark Averages
	WTI oil (US$/bbl)⁽¹⁾	45.60	57.94	(21%	)	39.53	53.29	(26%	)
	WCS heavy oil (US$/bbl)⁽²⁾	32.29	46.35	(30%	)	25.76	40.14	(36%	)
	WCS heavy oil (CAD$/bbl)	41.61	56.98	(27%	)	34.31	49.59	(31%	)
	LLS oil (US$/bbl)⁽³⁾	46.20	62.38	(26%	)	39.73	56.47	(30%	)
	CAD/USD average exchange rate	1.2885	1.2294	5%		1.3317	1.2353	8%
	Edmonton par oil ($/bbl)	54.78	67.72	(19%	)	47.80	59.84	(20%	)
	AECO natural gas price ($/mcf)⁽⁴⁾	1.25	2.67	(53%	)	1.68	2.81	(40%	)
	NYMEX natural gas price (US$/mmbtu)⁽⁵⁾	1.95	2.64	(26%	)	2.02	2.81	(28%	)

(1): WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2): WCS refers to the average posting price for the benchmark WCS heavy oil.
(3): LLS refers to the Argus trade month average for Louisiana Light Sweet oil.
(4): AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(5): NYMEX refers to the NYMEX last day average index price as published by the CGPR.

Baytex Energy Corp. Second Quarter Report 2016 13

		Three Months Ended June 30

		2016						2015

		Canada		U.S.		Total		Canada		U.S.		Total

Average Sales Prices⁽¹⁾
Canadian heavy oil ($/bbl)⁽²⁾	$	30.09	$	–	$	30.09	$	44.59	$	–	$	44.59
Light oil and condensate ($/bbl)		47.24		52.79		52.42		62.20		65.34		65.11
NGL ($/bbl)		18.56		12.50		13.28		23.05		14.67		15.78
Natural gas ($/mcf)		1.30		2.39		1.94		2.61		3.43		3.06

Weighted average ($/boe)⁽²⁾	$	25.80	$	34.43	$	30.52	$	40.43	$	46.67	$	43.34

		Six Months Ended June 30

		2016						2015

		Canada		U.S.		Total		Canada		U.S.		Total

Average Sales Prices⁽¹⁾
Canadian heavy oil ($/bbl)⁽²⁾	$	20.87	$	–	$	20.87	$	36.21	$	–	$	36.21
Light oil and condensate ($/bbl)		41.37		45.03		44.79		54.72		58.81		58.50
NGL ($/bbl)		17.72		15.59		15.86		23.65		16.55		17.55
Natural gas ($/mcf)		1.62		2.57		2.17		2.64		3.56		3.14

Weighted average ($/boe)⁽²⁾	$	19.40	$	31.63	$	26.06	$	33.70	$	43.71	$	38.30

(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 the table excludes the impact of financial derivatives.
(2): Realized heavy oil prices are calculated based on sales volumes, net of blending costs.

Average Realized Sales Prices

U.S. light oil and condensate pricing for Q2/2016 was $52.79/bbl, down 19% from $65.34/bbl in Q2/2015, which is slightly less than the 22% decrease in the LLS benchmark (expressed in Canadian dollars). U.S. light oil and condensate pricing for YTD 2016 was $45.03/bbl, down 23% from $58.81/bbl in YTD 2015 also slightly less than the 24% decrease in the LLS benchmark (expressed in Canadian dollars). Reduced supply along with increased pipeline capacity have tightened the pricing differential between our U.S. light oil and condensate to LLS during 2016.

During Q2/2016, our Canadian average sales price for light oil and condensate was $47.24/bbl, down 24% from $62.20/bbl in Q2/2015, as compared to a 19% decrease in the benchmark Edmonton par price. Canadian light oil and condensate pricing was $41.37/bbl for YTD 2016 compared to $54.72/bbl for YTD 2015, a 24% decrease compared to a 20% decrease in the benchmark Edmonton par price. Our Canadian realized price decreased slightly more than the benchmark when comparing 2016 to 2015 as a higher percentage of our Canadian light oil production in 2016 is comprised of medium grade crude which has a higher discount to the benchmark price.

Our realized heavy oil price for Q2/2016 was $30.09/bbl, a $14.50/bbl decrease from Q2/2015. YTD 2016, our realized heavy oil price was $20.87/bbl, a $15.34/bbl decrease from YTD 2015. The decrease in our realized heavy oil price during 2016 generally coincides with the decrease in the WCS benchmark price (expressed in Canadian dollars) which decreased from 2015 by $15.37/bbl for Q2/2016 and by $15.28/bbl for YTD 2016 as our heavy oil is generally sold at a fixed dollar differential to the benchmark. Our price decreased slightly less than the benchmark during 2016 as the volumes shut-in have a higher discount to the benchmark price resulting in better price realizations in 2016.

Our Canadian average realized natural gas price for the three and six months ended June 30, 2016 was $1.30/mcf and $1.62/mcf, respectively, down 50% and 38% from the same periods in 2015. The decrease in our realized price was consistent with the decrease in the AECO benchmarks for the three and six months ended June 30, 2016 of 53% and 40% from the same periods in 2015.

Our U.S. average realized natural gas price for the three and six months ended June 30, 2016 was $2.39/mcf and $2.57/mcf, respectively, down 30% and 28% from the same periods of 2015. The decrease in the U.S. average

14 Baytex Energy Corp. Second Quarter Report 2016

realized natural gas price was consistent with the decrease in the NYMEX benchmark for the three and six months ended June 30, 2016 of 26% and 28% for the same periods of 2015.

Our realized NGL price was $13.28/bbl or 23% of WTI (expressed in Canadian dollars) in Q2/2016 compared to $15.78/bbl or 22% of WTI (expressed in Canadian dollars) in Q2/2015. For YTD 2016, our realized NGL price was 30% of WTI (expressed in Canadian dollars) which is slightly higher than 27% of WTI in YTD 2015. In Q2/2016, the operator of our Eagle Ford assets reversed the changes to certain post-production NGL processing arrangements that were recorded in Q1/2016 which reduced NGL revenues and operating expenses in Q2/2016 but have no impact on YTD 2016.

Gross Revenues

			Three Months Ended June 30

			2016						2015

($ thousands)			Canada		U.S.		Total		Canada		U.S.		Total

Oil revenue
	Heavy oil	$	61,396	$	–	$	61,396	$	143,626	$	–	$	143,626
	Light oil and condensate		6,279		98,162		104,441		10,752		142,686		153,438
	NGL		2,141		9,744		11,885		2,276		9,542		11,818

Total liquids revenue			69,816		107,906		177,722		156,654		152,228		308,882
Natural gas revenue			4,673		12,131		16,804		9,736		15,723		25,459

Total oil and natural gas revenue			74,489		120,037		194,526		166,390		167,951		334,341
Heavy oil blending revenue			1,207		–		1,207		8,462		–		8,462

Total petroleum and natural gas revenues		$	75,696	$	120,037	$	195,733	$	174,852	$	167,951	$	342,803

			Six Months Ended June 30

			2016						2015

($ thousands)			Canada		U.S.		Total		Canada		U.S.		Total

Oil revenue
	Heavy oil	$	89,703	$	–	$	89,703	$	244,482	$	–	$	244,482
	Light oil and condensate		11,393		177,667		189,060		19,752		265,843		285,595
	NGL		4,196		24,593		28,789		4,972		21,167		26,139

Total liquids revenue			105,292		202,260		307,552		269,206		287,010		556,216
Natural gas revenue			11,986		26,227		38,213		19,922		31,912		51,834

Total oil and natural gas revenue			117,278		228,487		345,765		289,128		318,922		608,050
Heavy oil blending revenue			3,566		–		3,566		18,136		–		18,136

Total petroleum and natural gas revenues		$	120,844	$	228,487	$	349,331	$	307,264	$	318,922	$	626,186

Total petroleum and natural gas revenues for Q2/2016 of $195.7 million decreased $147.1 million from Q2/2015 with lower commodity prices contributing $82.1 million of the decrease and the remaining $65.0 million from lower production volumes. Petroleum and natural gas revenues of $120.0 million in the U.S. decreased $47.9 million from Q2/2015 due to a decrease in realized prices on all products.

In Canada, petroleum and natural gas revenues for Q2/2016 totaled $75.7 million, a $99.2 million decrease compared to Q2/2015 due to lower realized prices and lower production volumes.

Baytex Energy Corp. Second Quarter Report 2016 15

Total petroleum and natural gas revenues for YTD 2016 of $349.3 million decreased $276.9 million from YTD 2015 with lower commodity prices contributing $163.3 million of the decrease and the remaining $113.6 million from lower production volumes. Petroleum and natural gas revenues of $228.5 million in the U.S. decreased $90.4 million from YTD 2015 mainly due to a decrease in realized prices on all products. In Canada, petroleum and natural gas revenues for YTD 2016 totaled $120.8 million, a $186.4 million decrease compared to YTD 2015 due to lower realized prices and lower production volumes.

Heavy oil blending revenue of $1.2 million and $3.6 million for the three and six months ended June 30, 2016, respectively, decreased $7.3 million and $14.6 million compared to the same periods in 2015. Heavy oil blending revenue decreased in 2016 as the Company sold less diluent with the decrease in heavy oil production in Canada. Heavy oil transported through pipelines requires blending to reduce its viscosity in order to meet pipeline specifications. The cost of blending diluent is recovered in the sale price of the blended product. Our heavy oil transported by rail does not require blending diluent. The purchases and sales of blending diluent are recorded as heavy oil blending expense and revenue, respectively.

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 gross revenue. 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, 2016 and 2015.

		Three Months Ended June 30

		2016						2015

($ thousands except for % and per boe)		Canada		U.S.		Total		Canada		U.S.		Total

Royalties	$	7,920	$	34,466	$	42,386	$	28,258	$	49,628	$	77,886
Average royalty rate⁽¹⁾		10.6%		28.7%		21.8%		17.0%		29.5%		23.3%
Royalty rate per boe	$	2.74	$	9.89	$	6.65	$	6.87	$	13.79	$	10.10

		Six Months Ended June 30

		2016						2015

($ thousands except for % and per boe)		Canada		U.S.		Total		Canada		U.S.		Total

Royalties	$	11,755	$	65,213	$	76,968	$	41,677	$	92,916	$	134,593
Average royalty rate⁽¹⁾		10.0%		28.5%		22.3%		14.4%		29.1%		22.1%
Royalty rate per boe	$	1.94	$	9.03	$	5.80	$	4.86	$	12.74	$	8.48

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

Total royalties for Q2/2016 of $42.4 million decreased 46%, or $35.5 million, from Q2/2015, due to the decline in gross revenues. The overall royalty rate in Q2/2016 of 21.8% was slightly lower than 23.3% in Q2/2015. The royalty rate decreased slightly as the royalty rate in Canada was lower in Q2/2016 as a result of lower prices. Canadian royalties decreased to 10.6% of revenue for Q2/2016, compared to 17.0% of revenue in Q2/2015. Canadian crown royalty rates are partially based on price and with the lower commodity prices experienced during Q2/2016, the Company recorded lower crown royalty rates compared to Q2/2015. The royalty percentage on our U.S. assets does not vary with price and as a result the U.S. royalty rate in Q2/2016 of 28.7% has remained fairly consistent with the Q2/2015 rate of 29.5% and overall royalties have decreased with the decrease in gross revenues.

Total royalties for YTD 2016 of $77.0 million decreased 43%, or $57.6 million, from YTD 2015, due to the decline in gross revenues. The overall royalty rate in YTD 2016 of 22.3% was consistent with 22.1% in YTD 2015. The Canadian royalty rate decreased, but a higher proportion of our revenue came from the U.S. in YTD 2016 which has higher royalty rates offsetting the impact of the decrease in the Canadian rate on the overall royalty rate. Canadian royalties decreased to 10.0% of revenue for YTD 2016, compared to 14.4% of revenue in YTD 2015 due to lower commodity prices. The royalty percentage on our U.S. assets does not vary with price and as a result the YTD 2016 U.S. royalty rate of 28.5% has remained consistent with the YTD 2015 rate of 29.1% and overall royalties have decreased with the decrease in gross revenues.

16 Baytex Energy Corp. Second Quarter Report 2016

Operating Expenses

		Three Months Ended June 30

		2016						2015

($ thousands except for per boe)		Canada		U.S.(1)		Total		Canada		U.S.(1)		Total

Operating expenses	$	31,280	$	23,995	$	55,275	$	55,341	$	26,739	$	82,080
Operating expenses per boe	$	10.84	$	6.88	$	8.67	$	13.45	$	7.43	$	10.64

		Six Months Ended June 30

		2016						2015

($ thousands except for per boe)		Canada		U.S.(1)		Total		Canada		U.S.(1)		Total

Operating expenses	$	65,925	$	59,030	$	124,955	$	115,915	$	53,920	$	169,835
Operating expenses per boe	$	10.91	$	8.17	$	9.42	$	13.51	$	7.39	$	10.70

(1): Operating expenses related to the Eagle Ford assets include transportation expenses.

Operating expenses of $55.3 million and $125.0 million for the three and six months ended June 30, 2016, respectively, decreased by $26.8 million and $44.9 million compared to the same periods in 2015. Overall operating costs are down as production has decreased in 2016 compared to 2015. Operating expenses are also down on a unit of production basis with operating costs decreasing to $8.67/boe and $9.42/boe for the three and six months ended June 30, 2016, respectively, compared to $10.64/boe and $10.70/boe for the same periods in 2015. The lower cost Eagle Ford assets comprise a larger proportion of our overall volumes which is helping to reduce our overall operating costs per boe. In Canada, we are also seeing the impacts of our cost savings initiatives along with the benefit of shutting-in higher cost properties as our operating expenses per unit of production were lower in the three and six months ended June 30, 2016 compared to same periods in 2015.

U.S. operating expenses of $24.0 million for Q2/2016 decreased $2.7 million compared to Q2/2015. In Q1/2016, the operator of the Eagle Ford property changed certain post-production processing arrangements which increased operating expenses and revenues. In Q2/2016, this change was reversed by the operator resulting in a decrease to operating expenses and revenues. The reversal of the post production processing arrangement reduced operating costs by approximately $1.00/boe in Q2/2016 with no impact on the YTD 2016. On a unit of production basis, YTD 2016 operating expenses were $8.17/boe compared to $7.39/boe in YTD 2015 representing an increase of $0.78/boe. This increase in per unit costs in the U.S is primarily a result of the weaker Canadian dollar against the U.S. dollar. Operating expenses per boe in U.S. dollars for YTD 2016 have averaged US$6.17/boe which is comparable to YTD 2015 costs of US$5.98/boe.

Canadian operating expenses of $31.3 million and $65.9 million for the three and six months ended June 30, 2016, respectively, decreased $24.1 million and $50.0 million compared to the same periods in 2015. The decrease is a result of lower production volumes and realized cost savings across all of our operations. On a per boe basis, Canadian operating expenses were $10.84/boe and $10.91/boe for the three and six months ended June 30, 2016, respectively, compared to $13.45/boe and $13.51/boe for the same periods in 2015 reflecting the cost savings initiatives during 2016 and the impact of high cost production being shut-in for part of YTD 2016. As commodity prices improve and the higher cost shut-in volumes are restored, we expect Canadian operating expenses, on a unit of production basis, to increase.

Baytex Energy Corp. Second Quarter Report 2016 17

Transportation Expenses

Transportation expenses include the costs to move production from the field to the sales point. The largest component of transportation expenses relates to the trucking of heavy oil to pipeline and rail terminals. The following table compares our transportation expenses for the three and six months ended June 30, 2016 and 2015.

		Three Months Ended June 30

		2016						2015

($ thousands except for per boe)		Canada		U.S.(1)		Total		Canada		U.S.(1)		Total

Transportation expenses	$	5,146	$	–	$	5,146	$	14,928	$	–	$	14,928
Transportation expense per boe	$	1.78	$	–	$	0.81	$	3.63	$	–	$	1.94

		Six Months Ended June 30

		2016						2015

($ thousands except for per boe)		Canada		U.S.(1)		Total		Canada		U.S.(1)		Total

Transportation expenses	$	11,921	$	–	$	11,921	$	30,876	$	–	$	30,876
Transportation expense per boe	$	1.97	$	–	$	0.90	$	3.60	$	–	$	1.94

(1): Transportation expenses related to the Eagle Ford assets have been included in operating expenses.

Transportation expenses for the three and six months ended June 30, 2016 totaled $5.1 million and $11.9 million, respectively, a decrease of 66% and 61% from the same periods in 2015. The decrease is due to lower heavy oil volumes being transported to the sales point, decreased fuel costs and the increased use of lower cost internal trucking. On a per unit basis, costs have decreased as a large portion of the shut-in volumes were subject to higher transportation charges.

Blending Expenses

Blending expenses for the three and six months ended June 30, 2016 of $1.2 million and $3.6 million, respectively, have decreased compared to $8.5 million and $18.1 million for the same periods of 2015. Consistent with the decrease in heavy oil blending revenue, blending expenses decreased due to a decrease in both the volume of blending diluent required and the price of blending diluent.

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 funds from operations. Financial derivatives are managed at the corporate level and are not allocated between divisions. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price. Changes in the fair value of contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as

18 Baytex Energy Corp. Second Quarter Report 2016

new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and six months ended June 30, 2016 and 2015.

			Three Months Ended June 30									Six Months Ended June 30

($ thousands)			2016			2015			Change			2016			2015			Change

Realized financial derivatives gain (loss)
	Crude oil	$	18,778		$	48,784		$	(30,006	)	$	60,270		$	156,811		$	(96,541	)
	Natural gas		5,038			309			4,729			8,172			6,037			2,135
	Foreign currency		–			(9,021	)		9,021			–			(20,942	)		20,942

	Total	$	23,816		$	40,072		$	(16,256	)	$	68,442		$	141,906		$	(73,464	)

Unrealized financial derivatives gain (loss)
	Crude oil	$	(64,539	)	$	(59,545	)	$	(4,994	)	$	(99,526	)	$	(129,124	)	$	29,598
	Natural gas		(16,025	)		351			(16,376	)		(11,161	)		(4,647	)		(6,514	)
	Foreign currency		–			14,036			(14,036	)		–			(1,420	)		1,420
	Interest and financing⁽¹⁾		–			3,419			(3,419	)		–			5,280			(5,280	)

	Total	$	(80,564	)	$	(41,739	)	$	(38,825	)	$	(110,687	)	$	(129,911	)	$	19,224

Total financial derivatives gain (loss)
	Crude oil	$	(45,761	)	$	(10,761	)	$	(35,000	)	$	(39,256	)	$	27,687		$	(66,943	)
	Natural gas		(10,987	)		660			(11,647	)		(2,989	)		1,390			(4,379	)
	Foreign currency		–			5,015			(5,015	)		–			(22,362	)		22,362
	Interest and financing		–			3,419			(3,419	)		–			5,280			(5,280	)

	Total	$	(56,748	)	$	(1,667	)	$	(55,081	)	$	(42,245	)	$	11,995		$	(54,240	)

(1): Unrealized interest and financing derivatives gain (loss) includes the change in fair value of the call options embedded in our long-term notes.

The realized financial derivatives gain of $23.8 million and $68.4 million for three and six months ended June 30, 2016, respectively, relate mainly to crude oil prices being at levels below those set in our fixed price contracts.

The unrealized financial derivatives loss of $80.6 million for Q2/2016 is due to the increase in WTI price at June 30, 2016 as compared to March 31, 2016 and the realization, or reversal, of previous unrealized gains recorded at March 31, 2016. The unrealized financial derivatives loss of $110.7 million for YTD 2016 is due to the increase in WTI price at June 30, 2016 as compared to December 31, 2015 and the realization, or reversal, of previous unrealized gains recorded at December 31, 2015.

A summary of the financial derivative contracts in place as at June 30, 2016 and the accounting treatment thereof are disclosed in note 15 to the consolidated financial statements.

Baytex Energy Corp. Second Quarter Report 2016 19

Operating Netback

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the periods indicated:

			Three Months Ended June 30

			2016						2015

($ per boe except for volume)			Canada		U.S.		Total		Canada		U.S.		Total

Sales volume (boe/d)			31,722		38,309		70,031		45,222		39,548		84,770
Operating netback:
Oil and natural gas revenues		$	25.80	$	34.43	$	30.52	$	40.43	$	46.67	$	43.34
Less:
	Royalties		2.74		9.89		6.65		6.87		13.79		10.10
	Operating expenses		10.84		6.88		8.67		13.45		7.43		10.64
	Transportation expenses		1.78		–		0.81		3.63		–		1.94

Operating netback		$	10.44	$	17.66	$	14.39	$	16.48	$	25.45	$	20.66

Realized financial derivatives gain			–		–		3.74		–		–		5.19

Operating netback after financial derivatives		$	10.44	$	17.66	$	18.13	$	16.48	$	25.45	$	25.85

			Six Months Ended June 30

			2016						2015

($ per boe except for volume)			Canada		U.S.		Total		Canada		U.S.		Total

Sales volume (boe/d)			33,214		39,688		72,902		47,400		40,307		87,707
Operating netback:
Oil and natural gas revenues		$	19.40	$	31.63	$	26.06	$	33.70	$	43.71	$	38.30
Less:
	Royalties		1.94		9.03		5.80		4.86		12.74		8.48
	Operating expenses		10.91		8.17		9.42		13.51		7.39		10.70
	Transportation expenses		1.97		–		0.90		3.60		–		1.94

Operating netback		$	4.58	$	14.43	$	9.94	$	11.73	$	23.58	$	17.18

Realized financial derivatives gain			–		–		5.16		–		–		8.94

Operating netback after financial derivatives		$	4.58	$	14.43	$	15.10	$	11.73	$	23.58	$	26.12

Exploration and Evaluation Expense

Exploration and evaluation expense includes the derecognition of exploration and evaluation assets and will vary from period to period depending on the expiry of leases and assessment of our exploration programs and assets.

Exploration and evaluation expense decreased to $1.9 million for Q2/2016 from $2.2 million in Q2/2015. Exploration and evaluation expense decreased to $3.4 million for YTD 2016 from $4.5 million for YTD 2015. The decrease is due to lower expiries of undeveloped land.

20 Baytex Energy Corp. Second Quarter Report 2016

Depletion and Depreciation

		Three Months Ended June 30

		2016						2015

($ thousands except for per boe)		Canada		U.S.		Total		Canada		U.S.		Total

Depletion and depreciation⁽¹⁾	$	46,843	$	74,470	$	121,940	$	67,711	$	92,820	$	161,476
Depletion and depreciation per boe	$	16.23	$	21.36	$	19.13	$	16.45	$	25.79	$	20.93

		Six Months Ended June 30

		2016						2015

($ thousands except for per boe)		Canada		U.S.		Total		Canada		U.S.		Total

Depletion and depreciation⁽¹⁾	$	101,628	$	160,609	$	263,611	$	142,828	$	191,204	$	335,603
Depletion and depreciation per boe	$	16.81	$	22.24	$	19.87	$	16.65	$	26.21	$	21.14

(1): Total includes corporate depreciation.

Depletion and depreciation expense of $121.9 million and $263.6 million for the three and six months ended June 30, 2016, respectively, decreased by $39.5 million and $72.0 million from the same periods in 2015. On a per boe basis, depletion and depreciation expense for the three and six months ended June 30, 2016 of $19.13/boe and $19.87/boe, respectively, decreased from $20.93/boe and $21.14/boe for the same periods in 2015. The depletion rate decreased during 2016 as we recorded $755.6 million of impairments on U.S. oil and gas properties in 2015 which reduced the depletable base and the depletion rate for 2016.

General and Administrative Expenses

		Three Months Ended June 30						Six Months Ended June 30

($ thousands except for % and per boe)		2016		2015	Change			2016		2015	Change

General and administrative expenses	$	12,233	$	15,557	(21%	)	$	26,402	$	32,612	(19%	)
General and administrative expenses per boe	$	1.92	$	2.02	(5%	)	$	1.99	$	2.05	(3%	)

General and administrative expenses for the three and six months ended June 30, 2016 of $12.2 million and $26.4 million, respectively, decreased from $15.6 million and $32.6 million for the same periods in 2015. The decreases are attributable to reductions in staffing levels commensurate with lower activity levels combined with a reduction in discretionary spending.

Share-Based Compensation Expense

Compensation expense associated with the Share Award Incentive Plan is recognized in net income (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.

Compensation expense related to the Share Award Incentive Plan was $3.9 million and $8.4 million for the three and six months ended June 30, 2016, respectively, compared to $8.2 million and $16.2 million for the same periods in 2015. The decrease in share-based compensation expense for both periods is a result of a lower fair value of share awards granted due to a reduction in the Company's share price at grant date for new grants in 2016.

Baytex Energy Corp. Second Quarter Report 2016 21

Financing and Interest Expenses

Financing and interest expenses include interest on bank loan and long-term notes, non-cash financing costs and accretion on asset retirement obligations.

Financing and interest expenses increased $1.1 million to $27.9 million for Q2/2016, compared to $26.8 million in Q2/2015. The Canadian dollar was weaker in Q2/2016 compared to Q2/2015 which increased our interest expense on our long-term notes as the majority of our long-term notes are denominated in U.S. dollars.

Financing and interest expenses increased slightly to $56.9 million for YTD 2016, compared to $56.2 million in YTD 2015. Interest on long-term notes increased to $45.3 million during YTD 2016 compared to $43.4 million in YTD 2015 as the Canadian dollar was weaker against the U.S. dollar in YTD 2016 compared to YTD 2015 which increased our interest expense as a majority of our long-term notes are denominated in U.S. dollars. This was offset by lower interest charges on our bank loan in 2016 as compared to 2015 as we had larger bank loans in 2015 before the proceeds from the equity financing on April 2, 2015, were used to reduce bank indebtedness.

Foreign Exchange

Unrealized foreign exchange gains and losses are recognized with the change in the 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 and a strengthening Canadian dollar against the U.S. dollar from current period to previous period will result in unrealized gains and a weakening Canadian dollar will result in unrealized losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in the Canadian operations.

		Three Months Ended June 30								Six Months Ended June 30

($ thousands except for % and exchange rates)		2016			2015		Change			2016			2015	Change

Unrealized foreign exchange loss (gain)	$	3,549		$	(18,349	)	(119%	)	$	(83,252	)	$	82,967	(200%	)
Realized foreign exchange (gain) loss		(222	)		4,374		(105%	)		(764	)		113	(776%	)

Foreign exchange loss (gain)	$	3,327		$	(13,975	)	(124%	)	$	(84,016	)	$	83,080	(201%	)

CAD/USD exchange rates:
At beginning of period		1.2971			1.2683					1.3840			1.1601
At end of period		1.3009			1.2474					1.3009			1.2474

The Company recorded unrealized foreign exchange loss of $3.5 million for Q2/2016 as the Canadian dollar weakened against the U.S. dollar at June 30, 2016 as compared to March 31, 2016. The Company recorded unrealized foreign exchange gain of $83.3 million for YTD 2016 as the Canadian dollar strengthened against the U.S. dollar at June 30, 2016 as compared to December 31, 2015.

The Company realizes foreign exchange gains and losses from day-to-day U.S. dollar denominated transactions in its Canadian entities. For the three and six months ended June 30, 2016, the Company recorded realized foreign exchange gains of $0.2 million and $0.8 million, respectively.

22 Baytex Energy Corp. Second Quarter Report 2016

Income Taxes

		Three Months Ended June 30									Six Months Ended June 30

($ thousands)		2016			2015			Change			2016			2015			Change

Current income tax (recovery) expense	$	(2,284	)	$	(553	)	$	(1,731	)	$	(3,726	)	$	16,382		$	(20,108	)
Deferred income tax (recovery)		(46,783	)		(12,313	)		(34,470	)		(94,905	)		(53,995	)		(40,910	)

Total income tax (recovery)	$	(49,067	)	$	(12,866	)	$	(36,201	)	$	(98,631	)	$	(37,613	)	$	(61,018	)

In 2016, available tax deductions exceeded taxable income which allowed the Company to recover a portion of the prior year current income tax expense. For Q2/2016, this resulted in a current income tax recovery of $2.3 million, an increase of $1.7 million over the current income tax recovery of $0.6 million in Q2/2015. For YTD 2016, this resulted in a current income tax recovery of $3.7 million, an increase of $20.1 million over the current income tax expense of $16.4 million in YTD 2015.

The deferred income tax recovery of $46.8 million for Q2/2016 increased $34.5 million from $12.3 million for Q2/2015. The deferred income tax recovery of $94.9 million for YTD 2016 increased $40.9 million from $54.0 million for YTD 2015. The increase for both periods is primarily the result of a decrease in the amount of tax pool claims required to shelter the lower taxable income.

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

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

We will file a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of the CRA; a process that we estimate could take up to two years. If the Appeals Division upholds the notices of reassessment, we have the right to appeal to the Tax Court of Canada; a process that we estimate could take a further two years. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

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

Net Income (Loss) and Funds from Operations

Net loss for Q2/2016 totaled $86.9 million ($0.41 per basic and diluted share) compared to net loss of $27.0 million ($0.13 per basic and diluted share) for Q2/2015. Net loss for YTD 2016 totaled $86.3 million ($0.41 per basic and diluted share) compared to net loss of $202.9 million ($1.08 per basic and diluted share) for YTD 2015. Funds from operations for Q2/2016 totaled $81.3 million ($0.39 per basic and diluted share) as compared to $158.1 million ($0.60 per basic and diluted share) for Q2/2015. Funds from operations for YTD 2016 totaled $126.9 million ($0.60 per basic and diluted share) as compared to $318.3 million ($1.70 per basic and diluted share) for YTD 2015. The

Baytex Energy Corp. Second Quarter Report 2016 23

components of the change in net income (loss) and funds from operations from Q2/2015 to Q2/2016 and YTD 2015 to YTD 2016 are detailed in the following table:

			Three Months Ended June 30						Six Months Ended June 30

($ thousands)			Net income (loss)			Funds from operations			Net income (loss)			Funds from operations

2015		$	(26,955	)	$	158,050		$	(202,871	)	$	318,270
Increase (decrease) in revenues
	Revenue, net of royalties		(111,570	)		(111,570	)		(219,230	)		(219,230	)
(Increase) decrease in expenses
	Operating		26,805			26,805			44,880			44,880
	Transportation		9,782			9,782			18,955			18,955
	Blending		7,255			7,255			14,570			14,570
	General and administrative		3,324			3,324			6,210			6,210
	Exploration and evaluation		299			–			1,187			–
	Depletion and depreciation		39,536			–			71,992			–
	Share-based compensation		4,296			–			7,860			–
	Financing and interest		(1,116	)		(69	)		(759	)		536
	Financial derivatives		(55,081	)		(16,256	)		(54,240	)		(73,464	)
	Foreign exchange		(17,302	)		4,596			167,096			877
	Other⁽¹⁾⁽²⁾		(2,411	)		(2,387	)		(2,998	)		(4,806	)
	Current income tax		1,731			1,731			20,108			20,108
	Deferred income tax		34,470			–			40,910			–

2016		$	(86,937	)	$	81,261		$	(86,330	)	$	126,906

(1): For net income (loss), other includes gain (loss) on disposition and other expense.
(2): For funds from operations, other includes other expense.

Dividends

In 2015, we declared monthly dividends of $0.10 per common share for January to June totaling $0.60 per common share. The Company paid $83.2 million in cash dividends in YTD 2015, and $25.5 million of dividends declared were settled by issuing 1,262,000 common shares under the Company's dividend reinvestment plan. In response to the prolonged low price commodity environment and in an effort to preserve liquidity, Baytex suspended the monthly dividend effective September 2015.

Other Comprehensive Income (Loss)

Other comprehensive income (loss) is comprised of the foreign currency translation adjustment on U.S. net assets not recognized in profit or loss. The $6.1 million foreign currency translation gain for Q2/2016 is due to a slight weakening of the Canadian dollar against the U.S. dollar at June 30, 2016 as compared to March 31, 2016. The $152.6 million foreign currency translation loss for YTD 2016 is due to the strengthening of the Canadian dollar against the U.S. dollar at June 30, 2016 as compared to December 31, 2015.

24 Baytex Energy Corp. Second Quarter Report 2016

Capital Expenditures

Capital expenditures for the three and six months ended June 30, 2016 and 2015 are summarized as follows:

		Three Months Ended June 30

		2016								2015

($ thousands except for # of wells drilled)		Canada			U.S.		Total			Canada			U.S.			Total

Land	$	1,374		$	6,097	$	7,471		$	(656	)	$	(156	)	$	(812	)
Seismic		58			–		58			73			–			73
Drilling, completion and equipping		378			26,285		26,663			4,299			82,255			86,554
Facilities		937			361		1,298			3,974			16,221			20,195

Total exploration and development	$	2,747		$	32,743	$	35,490		$	7,690		$	98,320		$	106,010
Total acquisitions, net of divestitures		(37	)		–		(37	)		1,410			(240	)		1,170

Total oil and natural gas expenditures	$	2,710		$	32,743	$	35,453		$	9,100		$	98,080		$	107,180

Wells drilled (net)		–			11.3		11.3			2.0			13.2			15.2

		Six Months Ended June 30

		2016								2015

($ thousands except for # of wells drilled)		Canada			U.S.		Total			Canada		U.S.			Total

Land	$	2,237		$	6,097	$	8,334		$	2,800	$	(3	)	$	2,797
Seismic		113			–		113			132		–			132
Drilling, completion and equipping		3,810			95,966		99,776			15,525		203,252			218,777
Facilities		1,445			7,507		8,952			10,505		21,228			31,733

Total exploration and development	$	7,605		$	109,570	$	117,175		$	28,962	$	224,477		$	253,439
Total acquisitions, net of divestitures		(46	)		–		(46	)		2,821		(101	)		2,720

Total oil and natural gas expenditures	$	7,559		$	109,570	$	117,129		$	31,783	$	224,376		$	256,159

Wells drilled (net)		1.0			23.8		24.8			11.1		29.1			40.2

YTD 2016 capital expenditures totaled $117.1 million as compared to $256.2 million in YTD 2015. Capital spending has been focused on our Eagle Ford assets with YTD 2016 capital spending of $109.6 million down from $224.4 million for YTD 2015. The decrease in spending is from lower activity levels with lower commodity prices and from significant cost savings achieved on our Eagle Ford program. Total costs in the Eagle Ford have continued to decrease with wells now being drilled, completed and equipped for approximately US$5.4 million as compared to US$8.2 million in 2014. We also recognized additional savings on drilling, completion and equipping expenditures in Q2/2016 as actual costs incurred were less than previously estimated. In Canada, we have drilled one well in YTD 2016 and have spent $7.6 million compared to YTD 2015 where we drilled 11.1 net wells and spent $29.0 million. Despite achieving cost reductions of approximately 20% in Canada during 2015, the prevailing commodity prices have not supported additional drilling on our Canadian assets.

In Q2/2016, our capital expenditures totaled $35.5 million compared to $107.2 million in Q2/2015 and were focused on our Eagle Ford assets with 92% of the total capital being spent in the U.S. The significant reduction year over year is due to reduced activity levels in Canada and the Eagle Ford and from cost savings on the Eagle Ford program that were recognized in Q2/2016 as actual costs incurred were less than previously estimated. We did not drill any wells in Canada and spent $2.7 million in Q2/2016 as compared to 2.0 net wells and $7.7 million in Q2/2015.

Subsequent to the end of the quarter, we closed the sale of our operated assets in the Eagle Ford on July 27, 2016 for approximately $55 million.

Baytex Energy Corp. Second Quarter Report 2016 25

LIQUIDITY, CAPITAL RESOURCES AND RISK MANAGEMENT

We regularly review our capital structure and liquidity sources to ensure that our capital resources will be sufficient to meet our on-going short, medium and long-term commitments. Specifically, we believe that our internally generated funds from operations and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures.

We regularly review our exposure to counterparties to ensure they have the financial capacity to honor outstanding obligations to us in the normal course of business. We periodically review the financial capacity of our counterparties and, in certain circumstances, we will seek enhanced credit protection.

The current commodity price environment has reduced our internally generated funds from operations. As a result, we have taken several steps to protect our liquidity, which included reducing our 2016 capital program by approximately 33% from our initial plans and working with our lending syndicate to secure our bank credit facilities. We also shut-in low or negative margin production for part of 2016.

If the current commodity price environment continues, or if prices decline further, we may need to make additional changes to our capital program. A sustained low price environment could lead to a default of certain financial covenants, which could impact our ability to borrow under existing credit facilities or obtain new financing. It could also restrict our ability to pay future dividends or sell assets and may result in our debt becoming immediately due and payable. Should our internally generated funds from operations be insufficient to fund the capital expenditures required to maintain operations, we may draw additional funds from our current credit facilities or we may consider seeking additional capital in the form of debt or equity. There is also no certainty that any of the additional sources of capital would be available when required.

At June 30, 2016, net debt was $1,942.5 million, as compared to $2,049.9 million at December 31, 2015, representing a decrease of $107.4 million. This decrease is mainly due to the strengthening of the Canadian dollar against the U.S. dollar which reduced the carrying value of our U.S. dollar denominated long-term notes and bank loans at June 30, 2016. Funds from operations exceeded capital spending by $9.7 million for YTD 2016 further reducing net debt.

Bank Loan

On March 31, 2016, we amended our credit facilities to provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million, granting our banking syndicate first priority security over our assets and restructuring our financial covenants. The amended revolving extendible secured credit facilities are comprised of a US$25 million operating loan and a US$350 million syndicated loan and a US$200 million syndicated loan for our wholly-owned subsidiary, Baytex Energy USA, Inc. (collectively, the "Revolving Facilities").

The Revolving Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The facilities contain standard commercial covenants as detailed below and do not require any mandatory principal payments prior to maturity on June 4, 2019. Baytex may request an extension under the Revolving Facilities which could extend the revolving period for up to four years (subject to a maximum four-year term at any time). The agreement relating to the Revolving Facilities is accessible on the SEDAR website at www.sedar.com (filed under the category "Material contracts – Credit agreements" on April 13, 2016).

The weighted average interest rates on the credit facilities for the three and six months ended June 30, 2016 were 3.5%, as compared to 4.0% and 3.1%, respectively, for the same periods in 2015.

26 Baytex Energy Corp. Second Quarter Report 2016

Covenants

On March 31, 2016, we reached an agreement with the lending syndicate to restructure the financial covenants applicable to the Revolving Facilities. The following table summarizes the financial covenants contained in the amended credit agreement and our compliance therewith as at June 30, 2016.

	Ratio for the Quarter(s) ending:

Covenant Description	Position as at June 30, 2016	June 30, 2016 to June 30, 2018	June 30, 2018 to September 30, 2018	December 31, 2018	Thereafter

Senior Secured Debt⁽¹⁾ to Bank EBITDA⁽²⁾ (Maximum Ratio)	0.86:1.00	5.00:1.00	4.50:1.00	4.00:1.00	3.50:1.00
Interest Coverage⁽³⁾ (Minimum Ratio)	4.05:1.00	1.25:1.00	1.50:1.00	1.75:1.00	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, 2016, our Senior Secured Debt totaled $359 million.
(2): Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income (loss) for financing and interest expenses, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange and stock based compensation) and is calculated based on a trailing twelve month basis. Bank EBITDA for the twelve months ended June 30, 2016 was $417 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, 2016 were $103 million.

If we exceed or breach any of the covenants under the Revolving Facilities or our long-term notes, we may be required to repay, refinance or renegotiate the loan terms and may be restricted from paying dividends to our shareholders or taking on further debt.

Long-Term Notes

Baytex has five series of long-term notes outstanding that total $1.54 billion as at June 30, 2016. 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 our existing credit facilities and long-term notes unless we maintain a minimum fixed charge coverage ratio (computed as the ratio of EBITDA to financing and interest expenses on a trailing twelve month basis) of 2.5:1. As at June 30, 2016, the fixed charge coverage ratio was 4.05:1.

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

On July 19, 2012, we issued $300 million principal amount of senior unsecured notes bearing interest at 6.625% payable semi-annually with principal repayable on July 19, 2022. These notes are redeemable at our option, in whole or in part, commencing on July 19, 2017 at specified redemption prices.

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

Pursuant to the acquisition of Aurora Oil & Gas Limited ("Aurora"), on June 11, 2014, we assumed all of Aurora's existing senior unsecured notes and then purchased and cancelled approximately 98% of the outstanding notes. On February 27, 2015, we redeemed one tranche of the remaining Aurora notes at a price of US$8.3 million plus

Baytex Energy Corp. Second Quarter Report 2016 27

accrued interest. The remaining Aurora notes (US$6.4 million principal amount) are redeemable at our option, in whole or in part, as of April 1, 2016 at specified redemption prices.

Financial Instruments

As part of our normal operations, we are exposed to a number of financial risks, including liquidity risk, credit risk and market risk. Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. We manage liquidity risk through cash and debt management. Credit risk is the risk that a counterparty to a financial asset will default, resulting in the Company incurring a loss. Credit risk is managed by entering into sales contracts with creditworthy entities and reviewing our exposure to individual entities on a regular basis. Market risk is the risk that the fair value of future cash flows will fluctuate due to movements in market prices, and is comprised of foreign currency risk, interest rate risk and commodity price risk. Market risk is partially mitigated through a series of derivative contracts intended to reduce some of the volatility of our funds from operations.

A summary of the risk management contracts in place as at June 30, 2016 and the accounting treatment thereof is disclosed in note 15 to the consolidated financial statements.

Shareholders' Capital

We are authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. The rights and terms of preferred shares are determined upon issuance. As at July 27, 2016, we had 211,541,490 common shares and no preferred shares issued and outstanding. During the three and six months ended June 30, 2016, we issued 25,916 and 131,798 common shares, respectively, pursuant to our share-based compensation program.

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company's funds from operations in an ongoing manner. A significant portion of these obligations will be funded by funds from operations. These obligations as of June 30, 2016 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	$	139,694	$	139,694	$	–	$	–	$	–
Bank loan⁽¹⁾⁽²⁾		347,083		–		347,083		–		–
Long-term notes⁽²⁾		1,544,181		–		–		723,821		820,360
Interest on long-term notes		420,062		62,941		125,883		124,789		106,449
Operating leases		47,985		8,009		16,404		15,212		8,360
Processing agreements		50,011		9,017		9,521		9,043		22,430
Transportation agreements		68,130		13,152		22,972		21,969		10,037

Total	$	2,617,146	$	232,813	$	521,863	$	894,834	$	967,636

(1): The bank loan is covenant-based with a revolving period that is extendible annually for up to a four-year term. Unless extended, the revolving period will end on June 4, 2019, with all amounts to be repaid on such date.
(2): Principal amount of instruments.

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

28 Baytex Energy Corp. Second Quarter Report 2016

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at June 30, 2016, 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, 2016. Further information on our critical accounting policies and estimates can be found in the notes to the annual consolidated financial statements and MD&A for the year ended December 31, 2015.

CHANGES IN ACCOUNTING STANDARDS

We did not adopt any new accounting standards for the six months ended June 30, 2016. A description of accounting standards that will be effective in the future is included in the notes to the audited consolidated financial statements and MD&A for the year ended December 31, 2015.

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 and six months ended June 30, 2016.

QUARTERLY FINANCIAL INFORMATION

		2016			2015								2014

($ thousands, except per common share amounts)		Q2		Q1	Q4		Q3		Q2		Q1		Q4		Q3

Gross revenues		195,733		153,598	229,361		265,898		342,792		283,384		465,917		634,400
Net income (loss)		(86,937	)	607	(412,924	)	(517,856	)	(26,955	)	(175,916	)	(361,816	)	144,369
	Per common share – basic	(0.41	)	0.00	(1.96	)	(2.49	)	(0.13	)	(1.04	)	(2.16	)	0.87
	Per common share – diluted	(0.41	)	0.00	(1.96	)	(2.49	)	(0.13	)	(1.04	)	(2.16	)	0.86

FORWARD-LOOKING STATEMENTS

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

Specifically, this document contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; our expectation for Canadian operating expenses for the remainder of 2016; our ability to reduce the volatility in our funds from operations by utilizing financial derivative contracts; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing

Baytex Energy Corp. Second Quarter Report 2016 29

position; the length of time it would take to resolve the reassessments; that we would owe cash taxes and late payment interest if the reassessment is successful; the cost to drill, complete and equip a well in the Eagle Ford; the sufficiency of our capital resources to meet our on-going short, medium and long-term commitments; the financial capacity of counterparties to honor outstanding obligations to us in the normal course of business; our belief that the amended credit facilities provide increased financial flexibility; and the existence, operation and strategy of our risk management program. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

30 Baytex Energy Corp. Second Quarter Report 2016

CONDENSED CONSOLIDATED STATEMENTS
OF FINANCIAL POSITION

As at (thousands of Canadian dollars) (unaudited)			June 30, 2016			December 31, 2015

ASSETS
Current assets
	Cash	$	419		$	247
	Trade and other receivables		88,001			98,093
	Financial derivatives		24,006			106,573
	Assets held for sale (note 16)		14,005			–

			126,431			204,913
Non-current assets
	Financial derivatives		878			4,417
	Exploration and evaluation assets (note 4)		545,318			578,969
	Oil and gas properties (note 5)		4,391,750			4,674,175
	Other plant and equipment		24,903			26,024

		$	5,089,280		$	5,488,498

LIABILITIES
Current liabilities
	Trade and other payables	$	139,694		$	267,838
	Financial derivatives		11,813			–

			151,507			267,838
Non-current liabilities
	Bank loan (note 6)		342,754			252,172
	Long-term notes (note 7)		1,525,394			1,602,757
	Asset retirement obligations (note 8)		336,393			296,002
	Deferred income tax liability		536,593			655,255
	Financial derivatives		12,769			–

			2,905,410			3,074,024

SHAREHOLDERS' EQUITY
Shareholders' capital (note 9)			4,299,969			4,296,831
Contributed surplus			9,810			4,575
Accumulated other comprehensive income			552,735			705,382
Deficit			(2,678,644	)		(2,592,314	)

			2,183,870			2,414,474

		$	5,089,280		$	5,488,498

Subsequent event (note 16)

See accompanying notes to the condensed interim consolidated financial statements.

Baytex Energy Corp. Second Quarter Report 2016 31

CONDENSED CONSOLIDATED STATEMENTS
OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

			Three Months Ended June 30						Six Months Ended June 30

(thousands of Canadian dollars, except per common share amounts) (unaudited)			2016			2015			2016			2015

Revenue, net of royalties
Petroleum and natural gas sales		$	195,733		$	342,803		$	349,331		$	626,186
Royalties			(42,386	)		(77,886	)		(76,968	)		(134,593	)

			153,347			264,917			272,363			491,593
Expenses
Operating			55,275			82,080			124,955			169,835
Transportation			5,146			14,928			11,921			30,876
Blending			1,207			8,462			3,566			18,136
General and administrative			12,233			15,557			26,402			32,612
Exploration and evaluation (note 4)			1,896			2,195			3,359			4,546
Depletion and depreciation			121,940			161,476			263,611			335,603
Share-based compensation (note 10)			3,933			8,229			8,373			16,233
Financing and interest (note 13)			27,888			26,772			56,941			56,182
Financial derivatives loss (gain) (note 15)			56,748			1,667			42,245			(11,995	)
Foreign exchange loss (gain) (note 14)			3,327			(13,975	)		(84,016	)		83,080
Disposition of oil and gas properties loss (gain)			–			(24	)		22			1,830
Other (income)			(242	)		(2,629	)		(55	)		(4,861	)

			289,351			304,738			457,324			732,077

Net income (loss) before income taxes			(136,004	)		(39,821	)		(184,961	)		(240,484	)

Income tax (recovery) expense (note 12)
Current income tax (recovery) expense			(2,284	)		(553	)		(3,726	)		16,382
Deferred income tax (recovery)			(46,783	)		(12,313	)		(94,905	)		(53,995	)

			(49,067	)		(12,866	)		(98,631	)		(37,613	)

Net income (loss) attributable to shareholders		$	(86,937	)	$	(26,955	)	$	(86,330	)	$	(202,871	)

Other comprehensive income (loss)
Foreign currency translation adjustment			6,062			(41,665	)		(152,647	)		199,253

Comprehensive income (loss)		$	(80,875	)	$	(68,620	)	$	(238,977	)	$	(3,618	)

Net income (loss) per common share (note 11)
	Basic	$	(0.41	)	$	(0.13	)	$	(0.41	)	$	(1.08	)
	Diluted	$	(0.41	)	$	(0.13	)	$	(0.41	)	$	(1.08	)
Weighted average common shares (note 11)
	Basic		210,749			205,896			210,687			187,106
	Diluted		210,749			205,896			210,687			187,106

See accompanying notes to the condensed interim consolidated financial statements.

32 Baytex Energy Corp. Second Quarter Report 2016

CONDENSED CONSOLIDATED STATEMENTS
OF CHANGES IN EQUITY

(thousands of Canadian dollars) (unaudited)		Shareholders' capital			Contributed surplus			Accumulated other comprehensive income (loss)			Deficit			Total equity

Balance at December 31, 2014	$	3,580,825		$	31,067		$	199,575		$	(1,304,690	)	$	2,506,777
Dividends to shareholders		–			–			–			(112,423	)		(112,423	)
Vesting of share awards		15,392			(15,392	)		–			–			–
Share-based compensation		–			16,233			–			–			16,233
Issued for cash		632,494			–			–			–			632,494
Issuance costs, net of tax		(19,301	)		–			–			–			(19,301	)
Issued pursuant to dividend reinvestment plan		25,463			–			–			–			25,463
Comprehensive income (loss) for the period		–			–			199,253			(202,871	)		(3,618	)

Balance at June 30, 2015	$	4,234,873		$	31,908		$	398,828		$	(1,619,984	)	$	3,045,625

Balance at December 31, 2015		4,296,831			4,575			705,382			(2,592,314	)		2,414,474
Vesting of share awards		3,138			(3,138	)		–			–			–
Share-based compensation		–			8,373			–			–			8,373
Comprehensive income (loss) for the period		–			–			(152,647	)		(86,330	)		(238,977	)

Balance at June 30, 2016	$	4,299,969		$	9,810		$	552,735		$	(2,678,644	)	$	2,183,870

See accompanying notes to the condensed interim consolidated financial statements.

Baytex Energy Corp. Second Quarter Report 2016 33

CONDENSED CONSOLIDATED STATEMENTS
OF CASH FLOWS

			Three Months Ended June 30						Six Months Ended June 30

(thousands of Canadian dollars) (unaudited)			2016			2015			2016			2015

CASH PROVIDED BY (USED IN):
Operating activities
Net income (loss) for the period		$	(86,937	)	$	(26,955	)	$	(86,330	)	$	(202,871	)
Adjustments for:
	Share-based compensation (note 10)		3,933			8,229			8,373			16,233
	Unrealized foreign exchange loss (gain) (note 14)		3,549			(18,349	)		(83,252	)		82,967
	Exploration and evaluation (note 4)		1,896			2,195			3,359			4,546
	Depletion and depreciation		121,940			161,476			263,611			335,603
	Non-cash financing and interest (note 13)		3,099			2,052			5,341			4,046
	Unrealized financial derivatives loss (note 15)		80,564			41,739			110,687			129,911
	Disposition of oil and gas properties loss (gain)		–			(24	)		22			1,830
	Deferred income tax (recovery)		(46,783	)		(12,313	)		(94,905	)		(53,995	)
	Change in non-cash working capital		(25,592	)		(17,042	)		(5,183	)		15,084
	Asset retirement obligations settled (note 8)		(708	)		(3,160	)		(2,409	)		(7,606	)

			54,961			137,848			119,314			325,748

Financing activities
Payment of dividends			–			(43,136	)		–			(83,151	)
Increase (decrease) in bank loan			53,864			(581,653	)		104,607			(482,582	)
Tenders of long-term notes			–			–			–			(10,372	)
Issuance of common shares, net of issuance costs			–			606,095			–			606,095

			53,864			(18,694	)		104,607			29,990

Investing activities
Additions to exploration and evaluation assets (note 4)			(1,508	)		(1,655	)		(2,573	)		(3,698	)
Additions to oil and gas properties (note 5)			(33,982	)		(104,355	)		(114,602	)		(249,741	)
Property acquisitions, net of divestitures			37			(1,170	)		46			(2,720	)
Current income tax paid on dispositions			–			–			–			(8,181	)
Additions to other plant and equipment, net of disposals			(52	)		336			(374	)		4,706
Change in non-cash working capital			(73,083	)		(16,848	)		(104,318	)		(97,807	)

			(108,588	)		(123,692	)		(221,821	)		(357,441	)
Impact of foreign currency translation on cash balances			(270	)		(150	)		(1,928	)		835

Change in cash			(33	)		(4,688	)		172			(868	)
Cash, beginning of period			452			4,962			247			1,142

Cash, end of period		$	419		$	274		$	419		$	274

Supplementary information
Interest paid		$	30,222		$	28,760		$	51,876		$	50,350
Income taxes paid		$	–		$	–		$	5,138		$	8,181

See accompanying notes to the condensed interim consolidated financial statements.

34 Baytex Energy Corp. Second Quarter Report 2016

NOTES TO THE CONDENSED CONSOLIDATED
INTERIM FINANCIAL STATEMENTS
For the three and six months ended June 30, 2016 and 2015
(all tabular amounts in thousands of Canadian dollars, except per common share amounts) (unaudited)

1. REPORTING ENTITY

Baytex Energy Corp. (the "Company" or "Baytex") is an oil and gas corporation engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and the United States. The Company's common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company's head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

The audited consolidated financial statements of the Company as at and for the year ended December 31, 2015 are available through our filings on SEDAR at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov.

2. BASIS OF PRESENTATION

The condensed interim unaudited consolidated financial statements ("consolidated financial statements") have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, as issued by the International Accounting Standards Board. These consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements as of December 31, 2015. The Company's accounting policies are unchanged compared to December 31, 2015. The use of estimates and judgments is also consistent with the December 31, 2015 financial statements.

The consolidated financial statements were approved by the Board of Directors of Baytex on July 27, 2016.

The consolidated financial statements have been prepared on a historical cost basis, except for derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency. All financial information is rounded to the nearest thousand, except per share amounts and when otherwise indicated. Prior period financial statement amounts have been reclassified to conform with current period presentation.

Baytex Energy Corp. Second Quarter Report 2016 35

3. SEGMENTED FINANCIAL INFORMATION

Baytex's reportable segments are determined based on the Company's geographic locations.

•: Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada.
•: U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the USA.
•: Corporate includes corporate activities and items not allocated between operating segments.

		Canada						U.S.						Corporate						Consolidated

Three Months Ended June 30		2016			2015			2016			2015			2016			2015			2016			2015

Revenue, net of royalties
Petroleum and natural gas sales	$	75,696		$	174,852		$	120,037		$	167,951		$	–		$	–		$	195,733		$	342,803
Royalties		(7,920	)		(28,258	)		(34,466	)		(49,628	)		–			–			(42,386	)		(77,886	)

		67,776			146,594			85,571			118,323			–			–			153,347			264,917
Expenses
Operating		31,280			55,341			23,995			26,739			–			–			55,275			82,080
Transportation		5,146			14,928			–			–			–			–			5,146			14,928
Blending		1,207			8,462			–			–			–			–			1,207			8,462
General and administrative		–			–			–			–			12,233			15,557			12,233			15,557
Exploration and evaluation		1,896			2,195			–			–			–			–			1,896			2,195
Depletion and depreciation		46,843			67,711			74,470			92,820			627			945			121,940			161,476
Share-based compensation		–			–			–			–			3,933			8,229			3,933			8,229
Financing and interest		–			–			–			–			27,888			26,772			27,888			26,772
Financial derivatives loss		–			–			–			–			56,748			1,667			56,748			1,667
Foreign exchange loss (gain)		–			–			–			–			3,327			(13,975	)		3,327			(13,975	)
Disposition of oil and gas properties loss (gain)		–			–			–			(24	)		–			–			–			(24	)
Other (income)		–			–			–			–			(242	)		(2,629	)		(242	)		(2,629	)

		86,372			148,637			98,465			119,535			104,514			36,566			289,351			304,738

Net income (loss) before income taxes		(18,596	)		(2,043	)		(12,894	)		(1,212	)		(104,514	)		(36,566	)		(136,004	)		(39,821	)

Income tax (recovery) expense
Current income tax (recovery) expense		(1,958	)		(2,410	)		–			1,857			(326	)		–			(2,284	)		(553	)
Deferred income tax (recovery) expense		(3,814	)		28,676			(16,928	)		(18,261	)		(26,041	)		(22,728	)		(46,783	)		(12,313	)

		(5,772	)		26,266			(16,928	)		(16,404	)		(26,367	)		(22,728	)		(49,067	)		(12,866	)

Net income (loss)	$	(12,824	)	$	(28,309	)	$	4,034		$	15,192		$	(78,147	)	$	(13,838	)	$	(86,937	)	$	(26,955	)

Total oil and natural gas capital expenditures(1)	$	2,710		$	9,100		$	32,743		$	98,080		$	–		$	–		$	35,453		$	107,180

(1): Includes acquisitions and divestitures.

36 Baytex Energy Corp. Second Quarter Report 2016

		Canada						U.S.						Corporate						Consolidated

Six Months Ended June 30		2016			2015			2016			2015			2016			2015			2016			2015

Revenue, net of royalties
Petroleum and natural gas sales	$	120,844		$	307,264		$	228,487		$	318,922		$	–		$	–		$	349,331		$	626,186
Royalties		(11,755	)		(41,677	)		(65,213	)		(92,916	)		–			–			(76,968	)		(134,593	)

		109,089			265,587			163,274			226,006			–			–			272,363			491,593
Expenses
Operating		65,925			115,915			59,030			53,920			–			–			124,955			169,835
Transportation		11,921			30,876			–			–			–			–			11,921			30,876
Blending		3,566			18,136			–			–			–			–			3,566			18,136
General and administrative		–			–			–			–			26,402			32,612			26,402			32,612
Exploration and evaluation		3,359			4,546			–			–			–			–			3,359			4,546
Depletion and depreciation		101,628			142,828			160,609			191,204			1,374			1,571			263,611			335,603
Share-based compensation		–			–			–			–			8,373			16,233			8,373			16,233
Financing and interest		–			–			–			–			56,941			56,182			56,941			56,182
Financial derivatives loss (gain)		–			–			–			–			42,245			(11,995	)		42,245			(11,995	)
Foreign exchange (gain) loss		–			–			–			–			(84,016	)		83,080			(84,016	)		83,080
Disposition of oil and gas properties loss (gain)		–			2,074			–			(244	)		22			–			22			1,830
Other (income)		–			–			–			–			(55	)		(4,861	)		(55	)		(4,861	)

		186,399			314,375			219,639			244,880			51,286			172,822			457,324			732,077

Net income (loss) before income taxes		(77,310	)		(48,788	)		(56,365	)		(18,874	)		(51,286	)		(172,822	)		(184,961	)		(240,484	)

Income tax (recovery) expense
Current income tax (recovery) expense		(3,400	)		14,525			–			1,857			(326	)		–			(3,726	)		16,382
Deferred income tax (recovery) expense		(18,548	)		(96,799	)		(45,328	)		(18,261	)		(31,029	)		61,065			(94,905	)		(53,995	)

		(21,948	)		(82,274	)		(45,328	)		(16,404	)		(31,355	)		61,065			(98,631	)		(37,613	)

Net income (loss)	$	(55,362	)	$	33,486		$	(11,037	)	$	(2,470	)	$	(19,931	)	$	(233,887	)	$	(86,330	)	$	(202,871	)

Total oil and natural gas capital expenditures(1)	$	7,559		$	31,783		$	109,570		$	224,376		$	–		$	–		$	117,129		$	256,159

(1): Includes acquisitions and divestitures.

As at		June 30, 2016		December 31, 2015

Canadian assets	$	1,987,665	$	2,059,903
U.S. assets		3,064,685		3,304,647
Corporate assets		36,930		123,948

Total consolidated assets	$	5,089,280	$	5,488,498

Baytex Energy Corp. Second Quarter Report 2016 37

4. EXPLORATION AND EVALUATION ASSETS

As at			June 30, 2016			December 31, 2015

Balance, beginning of period		$	578,969		$	542,040
	Capital expenditures		2,573			5,642
	Property acquisitions, net of divestitures		(65	)		1,813
	Exploration and evaluation expense		(3,359	)		(8,775	)
	Transfer to oil and gas properties		(2,871	)		(38,062	)
	Divestitures		–			(1,588	)
	Assets held for sale (note 16)		(2,338	)		–
	Foreign currency translation		(27,591	)		77,899

Balance, end of period		$	545,318		$	578,969

5. OIL AND GAS PROPERTIES

			Cost			Accumulated depletion			Net book value

Balance, December 31, 2014		$	6,431,760		$	(1,447,844	)	$	4,983,916
	Capital expenditures		515,397			–			515,397
	Property acquisitions		551			–			551
	Transferred from exploration and evaluation assets		38,062			–			38,062
	Change in asset retirement obligations		10,722			–			10,722
	Divestitures		(20,096	)		19,449			(647	)
	Impairment		–			(755,613	)		(755,613	)
	Foreign currency translation		607,885			(68,509	)		539,376
	Depletion		–			(657,589	)		(657,589	)

Balance, December 31, 2015		$	7,584,281		$	(2,910,106	)	$	4,674,175
	Capital expenditures		114,602			–			114,602
	Property acquisitions, net of divestitures		(3	)		–			(3	)
	Transferred from exploration and evaluation assets		2,871			–			2,871
	Change in asset retirement obligations		41,885			–			41,885
	Assets held for sale (note 16)		(15,055	)		3,388			(11,667	)
	Foreign currency translation		(210,121	)		42,130			(167,991	)
	Depletion		–			(262,122	)		(262,122	)

Balance, June 30, 2016		$	7,518,460		$	(3,126,710	)	$	4,391,750

6. BANK LOAN

		June 30, 2016			December 31, 2015

Bank loan – U.S. dollar denominated	$	347,083		$	237,861
Bank loan – Canadian dollar denominated		–			18,888

Bank loan – principal		347,083			256,749
Unamortized debt issuance costs		(4,329	)		(4,577	)

Bank loan	$	342,754		$	252,172

On March 31, 2016, Baytex amended the credit facilities with its banking syndicate to grant the banking syndicate first priority security over its assets. The amended revolving extendible secured credit facilities are comprised of a US$25 million operating loan and a US$350 million syndicated loan for Baytex and a US$200 million syndicated loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. (collectively, the "Revolving Facilities").

38 Baytex Energy Corp. Second Quarter Report 2016

The Revolving Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The facilities contain standard commercial covenants and do not require any mandatory principal payments prior to maturity on June 4, 2019. Baytex may request an extension under the Revolving Facilities which could extend the revolving period for up to four years (subject to a maximum four-year period at any time). Advances (including letters of credit) under the Revolving 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 Revolving Facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from paying dividends to shareholders or taking on further debt.

At June 30, 2016, Baytex was in compliance with all of the covenants contained in the Revolving Facilities. The following table summarizes the financial covenants contained in the Revolving Facilities and our compliance therewith as at June 30, 2016.

	Ratio for the Quarter(s) ending:

Covenant Description	Position as at June 30, 2016	June 30, 2016 to June 30, 2018	June 30, 2018 to September 30, 2018	December 31, 2018	Thereafter

Senior Secured Debt⁽¹⁾ to Bank EBITDA⁽²⁾ (Maximum Ratio)	0.86:1.00	5.00:1.00	4.50:1.00	4.00:1.00	3.50:1.00
Interest Coverage⁽³⁾ (Minimum Ratio)	4.05:1.00	1.25:1.00	1.50:1.00	1.75:1.00	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, 2016, our Senior Secured Debt totaled $359 million.
(2): Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income (loss) for financing and interest expenses, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange and stock based compensation) and is calculated based on a trailing twelve month basis. Bank EBITDA for the twelve months ended June 30, 2016 was $417 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, 2016 were $103 million.

7. LONG-TERM NOTES

		June 30, 2016			December 31, 2015

7.5% notes (US$6,400 – principal) due April 1, 2020	$	8,326		$	8,858
6.75% notes (US$150,000 – principal) due February 17, 2021		195,135			207,600
5.125% notes (US$400,000 – principal) due June 1, 2021		520,360			553,600
6.625% notes (Cdn$300,000 – principal) due July 19, 2022		300,000			300,000
5.625% notes (US$400,000 – principal) due June 1, 2024		520,360			553,600

Total long-term notes – principal		1,544,181			1,623,658
Unamortized debt issuance costs		(18,787	)		(20,901	)

Total long-term notes – net of unamortized debt issuance costs	$	1,525,394		$	1,602,757

Baytex Energy Corp. Second Quarter Report 2016 39

8. ASSET RETIREMENT OBLIGATIONS

			June 30, 2016			December 31, 2015

Balance, beginning of period		$	296,002		$	286,032
	Liabilities incurred		2,915			4,964
	Liabilities settled		(2,409	)		(10,888	)
	Liabilities acquired		–			593
	Liabilities divested		(350	)		(10,578	)
	Accretion		3,230			6,262
	Change in estimate⁽¹⁾		(1,617	)		33,266
	Changes in discount rates and inflation rates		40,936			(17,523	)
	Foreign currency translation		(2,314	)		3,874

Balance, end of period		$	336,393		$	296,002

(1): Changes in the estimated costs, the timing of abandonment and reclamation and the status of wells are factors resulting in a change in estimate.

9. SHAREHOLDERS' CAPITAL

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10,000,000 preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at June 30, 2016, no preferred shares have been issued by the Company and all common shares issued were fully paid.

		Number of Common Shares (000s)		Amount

Balance, December 31, 2014		168,107	$	3,580,825
	Transfer from contributed surplus on vesting and conversion of share awards	1,092		41,836
	Issued for cash	36,455		632,494
	Issuance costs, net of tax	–		(19,301	)
	Issued pursuant to dividend reinvestment plan	4,929		60,977

Balance, December 31, 2015		210,583	$	4,296,831

	Transfer from contributed surplus on vesting and conversion of share awards	132		3,138

Balance, June 30, 2016		210,715	$	4,299,969

10. SHARE AWARD INCENTIVE PLAN

The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "share awards") may be granted to the directors, officers and employees of the Company and its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not at any time exceed 3.8% of the then-issued and outstanding common shares.

Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the performance award (plus dividend equivalents) multiplied by a payout multiplier. Both awards are expensed over the vesting period.

The Company recorded compensation expense related to the share awards of $3.9 million for the three months ended June 30, 2016 ($8.2 million for the three months ended June 30, 2015) and $8.4 million for the six months ended June 30, 2016 ($16.2 million for the six months ended June 30, 2015).

40 Baytex Energy Corp. Second Quarter Report 2016

The weighted average fair value of share awards granted during the six months ended June 30, 2016 was $2.75 per restricted and performance award (for the six months ended June 30, 2015, $17.11 per restricted and performance award).

The number of share awards outstanding is detailed below:

(000s)		Number of restricted awards		Number of performance awards(1)		Total number of share awards

Balance, December 31, 2014		747		615		1,362
	Granted	615		503		1,118
	Vested and converted to common shares	(432	)	(382	)	(814	)
	Forfeited	(201	)	(123	)	(324	)

Balance, December 31, 2015		729		613		1,342

	Granted	1,259		1,371		2,630
	Vested and converted to common shares	(62	)	(30	)	(92	)
	Forfeited	(20	)	(28	)	(48	)

Balance, June 30, 2016		1,906		1,926		3,832

(1): Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.

11. NET INCOME (LOSS) PER SHARE

		Three Months Ended June 30

		2016							2015

		Net loss		Common shares *(000s)*		Net loss per share			Net loss		Common shares (000s)		Net loss per share

Net income (loss) – basic	$	(86,937	)	210,749	$	(0.41	)	$	(26,955	)	205,896	$	(0.13	)
Dilutive effect of share awards		–		–		–			–		–		–

Net income (loss) – diluted	$	(86,937	)	210,749	$	(0.41	)	$	(26,955	)	205,896	$	(0.13	)

		Six Months Ended June 30

		2016							2015

		Net loss		Common shares *(000s)*		Net loss per share			Net loss		Common shares (000s)		Net loss per share

Net income (loss) – basic	$	(86,330	)	210,687	$	(0.41	)	$	(202,871	)	187,106	$	(1.08	)
Dilutive effect of share awards		–		–		–			–		–		–

Net income (loss) – diluted	$	(86,330	)	210,687	$	(0.41	)	$	(202,871	)	187,106	$	(1.08	)

For the three months ended June 30, 2016, 3.8 million share awards were anti-dilutive (June 30, 2015 – 3.9 million share awards). For the six months ended June 30, 2016, 3.8 million share awards were anti-dilutive (June 30, 2015 – 1.1 million share awards).

Baytex Energy Corp. Second Quarter Report 2016 41

12. INCOME TAXES

The provision for income taxes has been computed as follows:

			Six Months Ended June 30

			2016			2015

Net income (loss) before income taxes		$	(184,961	)	$	(240,484	)
Expected income taxes at the statutory rate of 27.00% (2015 – 25.47%)⁽¹⁾			(49,939	)		(63,079	)
Increase (decrease) in income tax recovery resulting from:
	Share-based compensation		2,195			4,258
	Non-taxable portion of foreign exchange (gain) loss		(10,655	)		10,877
	Effect of change in income tax rates		–			10,984
	Effect of rate adjustments for foreign jurisdictions		(28,624	)		(23,296	)
	Effect of change in deferred tax benefit not recognized⁽²⁾		(10,655	)		22,620
	Other		(953	)		23

Income tax (recovery)		$	(98,631	)	$	(37,613	)

(1): Expected income tax rate increased due to an increase in the corporate income tax rate in Alberta (from 10% to 12%), offset by a decrease in the Texas franchise tax rate (from 1.00% to 0.75%).
(2): A deferred income tax asset has not been recognized for allowable capital losses of $109 million related to the unrealized foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes ($149 million as at December 31, 2015).

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

Baytex remains confident that the tax filings of the affected entities are correct and will file a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of CRA; a process that Baytex estimates could take up to two years. If the Appeals Division upholds the notices of reassessment Baytex has the right to appeal to the Tax Court of Canada; a process that Baytex estimates could take a further two years. Should Baytex be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that Baytex estimates could take another two years and potentially longer. The reassessments do not require Baytex to pay any amounts in order to participate in the appeals process.

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

13. FINANCING AND INTEREST

		Three Months Ended June 30				Six Months Ended June 30

		2016		2015		2016		2015

Interest on bank loan	$	2,690	$	3,345	$	6,301	$	8,763
Interest on long-term notes		22,099		21,375		45,299		43,373
Non-cash financing		1,531		504		2,111		880
Accretion on asset retirement obligations		1,568		1,548		3,230		3,166

Financing and interest	$	27,888	$	26,772	$	56,941	$	56,182

42 Baytex Energy Corp. Second Quarter Report 2016

14. FOREIGN EXCHANGE

		Three Months Ended June 30						Six Months Ended June 30

		2016			2015			2016			2015

Unrealized foreign exchange loss (gain)	$	3,549		$	(18,349	)	$	(83,252	)	$	82,967
Realized foreign exchange (gain) loss		(222	)		4,374			(764	)		113

Foreign exchange loss (gain)	$	3,327		$	(13,975	)	$	(84,016	)	$	83,080

15. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The carrying amounts of the Company's U.S. dollar denominated monetary assets and liabilities at the reporting date are as follows:

	Assets		Liabilities

	June 30, 2016	December 31, 2015	June 30, 2016	December 31, 2015

U.S. dollar denominated	US$58,422	US$124,218	US$1,293,729	US$1,240,308

Financial Derivative Contracts

Baytex had the following financial derivative contracts:

Oil	Period	Volume	Price/Unit(1)	Index

Fixed – Sell	July 2016 to December 2016	5,000 bbl/d	US$63.79	WTI
Producer 3-way option(2)	July 2016 to December 2016	10,000 bbl/d	US$59.85/US$49.75/US$39.75	WTI
Producer 3-way option(2)	January 2017 to December 2017	10,000 bbl/d	US$58.53/US$45.90/US$36.00	WTI
Basis swap	July 2016 to September 2016	500 bbl/d	WTI less US$12.30	WCS
Basis swap	July 2016 to December 2016	4,500 bbl/d	WTI less US$13.27	WCS
Basis swap	October 2016 to December 2016	500 bbl/d	WTI less US$13.45	WCS
Basis swap	January 2017 to December 2017	1,500 bbl/d	WTI less US$13.42	WCS
Sold call option(3)	October 2016 to December 2016	1,000 bbl/d	US$52.05	WTI
Sold call option(3)(4)	January 2017 to December 2017	5,000 bbl/d	US$53.67	WTI

(1): Based on the weighted average price/unit for the remainder of the contract.
(2): Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a $60/$50/$40 contract, Baytex receives WTI + US$10/bbl when WTI is at or below US$40/bbl; Baytex receives US$50/bbl when WTI is between US$40/bbl and US$50/bbl; Baytex receives WTI when WTI is between US$50/bbl and US$60/bbl; and Baytex receives US$60/bbl when WTI is above US$60/bbl.
(3): Counterparty has the option to enter into a fixed sell for the periods, volumes and prices noted.
(4): The Company restructured the sold call options subsequent to June 30, 2016. At June 30, 2016 the price was US$49.57/bbl.

Natural Gas	Period	Volume	Price/Unit(1)	Index

Fixed – Sell	July 2016 to December 2016	15,000 mmBtu/d	US$2.98	NYMEX
Fixed – Sell	January 2017 to December 2017	17,500 mmBtu/d	US$2.83	NYMEX
Fixed – Sell	January 2018 to December 2018	7,500 mmBtu/d	US$3.00	NYMEX
Fixed – Sell	July 2016 to December 2016	32,500 GJ/d	$2.39	AECO
Fixed – Sell	January 2017 to December 2017	12,500 GJ/d	$2.65	AECO
Fixed – Sell	January 2018 to December 2018	5,000 GJ/d	$2.67	AECO

(1): Based on the weighted average price/unit for the remainder of the contract.

Baytex Energy Corp. Second Quarter Report 2016 43

Financial derivatives are marked-to-market at the end of each reporting period, with the following reflected in the consolidated statements of income (loss) and comprehensive income (loss):

		Three Months Ended June 30						Six Months Ended June 30

		2016			2015			2016			2015

Realized financial derivatives (gain)	$	(23,816	)	$	(40,072	)	$	(68,442	)	$	(141,906	)
Unrealized financial derivatives loss – commodity		80,564			45,158			110,687			135,191
Unrealized financial derivatives (gain) – redemption feature on long-term notes		–			(3,419	)		–			(5,280	)

Financial derivatives loss (gain)	$	56,748		$	1,667		$	42,245		$	(11,995	)

Physical Delivery Contracts

As at June 30, 2016, 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; therefore, no asset or liability has been recognized in the consolidated financial statements.

(1): Based on the weighted average price/unit for the remainder of the contract.

As at June 30, 2016, Baytex had committed at fixed price to deliver the volumes of raw bitumen as noted below to market on rail:

	Period	Term volume

Raw bitumen	July 2016 to December 2016	7,400 bbl/d
Raw bitumen	January 2017 to December 2017	5,000 bbl/d

16. SUBSEQUENT EVENT

On July 27, 2016, Baytex disposed of its operated interest in certain Eagle Ford properties, which consisted of oil and gas properties and exploration and evaluations assets, for approximately $55 million. At June 30, 2016, $2.3 million of exploration and evaluation assets and $11.7 million of oil and gas properties relating to the disposition were reclassified to assets held for sale.

44 Baytex Energy Corp. Second Quarter Report 2016

ABBREVIATIONS

AECO		the natural gas storage facility located at Suffield, Alberta
bbl		barrel
bbl/d		barrel per day
boe*		barrels of oil equivalent
boe/d		barrels of oil equivalent per day
GAAP		Generally Accepted Accounting Principles
GJ		gigajoule
GJ/d		gigajoule per day
IFRS		International Financial Reporting Standards
LIBOR		London Interbank Offered Rate
LLS		Louisiana Light Sweet
mbbl		thousand barrels
mboe*		thousand barrels of oil equivalent
mcf		thousand cubic feet
mcf/d		thousand cubic feet per day
mmbtu		million British Thermal Units
mmbtu/d		million British Thermal Units per day
mmcf		million cubic feet
mmcf/d		million cubic feet per day
NGL		natural gas liquids
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
TSX		Toronto Stock Exchange
WCS		Western Canadian Select
WTI		West Texas Intermediate

*: Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Baytex Energy Corp. Second Quarter Report 2016 45

CORPORATE INFORMATION

BOARD OF DIRECTORS

Raymond T. Chan
Chairman of the Board
Baytex Energy Corp.

James L. Bowzer
Chief Executive Officer
Baytex Energy Corp.

John A. Brussa ⁽³⁾⁽⁴⁾
Vice Chairman
Burnet, Duckworth & Palmer LLP

Edward Chwyl ⁽²⁾⁽³⁾⁽⁴⁾
Lead Independent Director
Baytex Energy Corp.
Independent Businessman

Trudy M. Curran ⁽¹⁾⁽⁴⁾
Independent Businesswoman

Naveen Dargan ⁽¹⁾⁽²⁾
Independent Businessman

R. E. T. (Rusty) Goepel ⁽⁴⁾
Senior Vice President
Raymond James Ltd.

Gregory K. Melchin ⁽¹⁾
Independent Businessman

Mary Ellen Peters ⁽¹⁾⁽²⁾
Independent Businesswoman

Dale O. Shwed ⁽³⁾
President & Chief Executive Officer
Crew Energy Inc.

(1)   Member of the Audit Committee
(2)   Member of the Compensation Committee
(3)   Member of the Reserves Committee
(4)   Member of the Nominating and Governance Committee

HEAD OFFICE

Baytex Energy Corp.
Centennial Place, East Tower
2800, 520 – 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll-free: 1-800-524-5521
T: 587-952-3000
F: 587-952-3001
www.baytexenergy.com

BANKERS

Bank of Nova Scotia
Alberta Treasury Branches
Bank of America
Bank of Montreal
Barclays Bank plc
Canadian Imperial Bank of Commerce
Caisse Centrale Desjardins
National Bank of Canada
Royal Bank of Canada
Société Générale
The Toronto-Dominion Bank
Union Bank
Wells Fargo Bank

OFFICERS

James L. Bowzer
Chief Executive Officer

Edward D. LaFehr
President

Rodney D. Gray
Chief Financial Officer

Richard P. Ramsay
Chief Operating Officer

Geoffrey J. Darcy
Senior Vice President, Marketing

Brian G. Ector
Senior Vice President, Capital Markets
and Public Affairs

Kendall D. Arthur
Vice President,
Lloydminster Business Unit

Murray J. Desrosiers
Vice President, General Counsel
and Corporate Secretary

Cameron A. Hercus
Vice President, Corporate Development

Ryan M. Johnson
Vice President, Central Business Unit

Chad L. Kalmakoff
Vice President, Finance

Gregory A. Sawchenko
Vice President, Land

Gregory M. Zimmerman
Vice President, U.S. Business Unit

AUDITORS

KPMG LLP

LEGAL COUNSEL

Burnet, Duckworth & Palmer LLP

RESERVES ENGINEERS

Sproule Unconventional Limited
Ryder Scott Company L.P.

TRANSFER AGENT

Computershare Trust Company of Canada

EXCHANGE LISTINGS

Toronto Stock Exchange
New York Stock Exchange
Symbol: BTE

QuickLinks

Exhibit 99.1

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Price/Unit⁽¹⁾

July 2016 to December 2016

2,000 bbl/d

WTI less US$13.68