Bank of America Merrill Lynch 2016 Energy Credit Conference

Bank of America Merrill Lynch 2016 Energy Credit Conference New York, New York, June 8, 2016 Rod Gray Chief Financial Officer

Advisory 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 made by the presenter and contained in these presentation materials (collectively, this "presentation") 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"). The forward-looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement. The information contained in this presentation does not purport to be all-inclusive or to contain all information that potential investors may require. Specifically, this presentation contains forward-looking statements relating, but not limited, to: our business strategies, plans and objectives; our focus on per share growth in production, cash flow and reserves; our target to fund our capital program from internally generated funds from operations; our ability to mitigate the volatility in Western Canadian Select price differentials by transporting our crude oil to market using railways; our annual average production rate and capital budget for 2016; our plans to develop our three key resource plays (Eagle Ford, Peace River and Lloydminster), including the number of wells to be brought on production in the Eagle Ford in 2016; the proportion of our expenditures to be made in the Eagle Ford; our drilling plans in the Eagle Ford, Peace River and Lloydminster; the number of drilling rigs and frac crews working on our Eagle Ford lands in 2016; our plan to bring shut-in production back on line; our expectation that we will realize further improvements in capital efficiencies through cost reductions; our target for all-in capital efficiencies; the rate of return for an individual well in the Eagle Ford, Peace River and Lloydminster under various pricing assumptions for West Texas Intermediate light oil ( WTI ) and the oil price at which the wells break-even; our expectation that our development opportunities will provide attractive returns; for individual wells in the Eagle Ford, Peace River and Lloydminster, the cost to drill, complete and equip a well, initial production rates, liquids weighting, estimated ultimate recoveries (EUR) and single well economics (including internal rate of return, net present value, payout and capital efficiency); our Eagle Ford shale play, including the growth potential of the assets, initial production rates from new wells, our plans to use stack and frac pilots to target three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation, our assessment of the results of the stack and frac pilots, individual well economics, cumulative recoveries, drilling efficiency and the pricing benchmarks used for our liquids production; our Peace River heavy oil resource play, including years of drilling inventory remaining, reservoir characteristics, individual well economics for multi-lateral horizontal wells (including well design, drilling and completion costs, initial production rates, capital efficiency ratio, internal rate of return and estimated ultimate recoveries (EUR)); our Lloydminster heavy oil property, including years of drilling inventory remaining, the impact of drilling horizontal wells and individual well economics for horizontal wells (including drilling and completion costs, initial production rates, capital efficiency ratio internal rate of return and estimated ultimate recoveries (EUR) and our expectation that multi-lateral drilling will result in improvements in capital efficiencies); that we retain significant leverage to increases in crude oil prices, have a significant inventory of development projects and have strong levels of financial liquidity; and the sensitivity of our 2016 funds from operations to changes in WTI prices, heavy oil differentials, natural gas prices and Canada-United States foreign exchange rates. 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. Although Baytex believes that the expectations and assumptions upon which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Baytex can give no assurance that they will prove to be correct. These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; 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. 2

Advisory (Cont.) 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 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. Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. The above summary of assumptions and risks related to forward-looking statements in this presentation has been provided in order to provide potential investors with a more complete perspective of our current and future operations and as such information may be not 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. Oil and Gas Information This presentation contains estimates, as at December 31, 2015, of the volume of our petroleum and natural gas reserves as prepared by our independent qualified reserves evaluators, Sproule Unconventional Limited ("Sproule") for our Canadian properties and Ryder Scott Company, L.P. for our United States properties. These estimates have been prepared in accordance with Canadian reserves disclosure standards and definitions as set forth in National Instrument 51-101 Standards of Disclosure for Oil and Natural Gas Activities of the Canadian Securities Administrators ( NI 51-101 ). The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts, including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods, is required to properly use and apply reserves definitions. The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves and future production from such reserves may be greater or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. For complete NI 51-101 reserves disclosure, please see our Annual Information Form for the year end December 31, 2015. References herein to initial test production rates, 30-day IP rates and other short-term production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the acquired assets. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary. When converting volumes of natural gas to oil equivalent amounts, Baytex has adopted a conversion factor of six million cubic feet of natural gas being equivalent to one barrel of oil, 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. Oil equivalent amounts may be misleading, particularly if used in isolation. 3

Advisory (Cont.) Non-GAAP Financial Measures This presentation refers to 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"). We define funds from operations ("FFO") as cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund potential future dividends to shareholders and capital investments. However, funds from operations should not be construed as an alternative to traditional performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income. Please refer to our most recent management's discussion and analysis of financial condition and results of operations for a reconciliation of funds from operations to cash flow from operating activities. We define net debt as the sum of monetary working capital (which is current assets less current liabilities (excluding current losses on financial derivatives)), and the principal amount of both long-term notes and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities. We define operating netback as product sales price 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 by other entities. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis. Bank EBITDA is calculated based on terms and definitions set out in the agreement governing our revolving credit facilities. It is calculated by adjusting net income for financing costs, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, amortization, impairment, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange, and sharebased compensation) and acquisition and disposition activity and is calculated based on a trailing twelve month basis. Bank EBITDA is used by our lenders to monitor compliance with financial covenants. 4

Baytex Key Attributes Making the Right Choices In a Low Oil Price Environment Pro-actively worked with our bank lending syndicate to provide increased financial flexibility; targeting capital expenditures to approximate FFO Maintained Financial Liquidity Reduced Cost Structure Cost reduction focus across all facets of our organization while maintaining efficiency in our operations and the safety of our employees Strong capital efficiencies across three core resource plays; retain a significant inventory of development prospects Retained Leverage to Rising Crude Environment Deployed Capital Efficiently Capital expenditures directed to the Eagle Ford, which generates the highest netback and highest rate of return in our portfolio 5

Corporate Profile Market Summary Ticker Symbol TSX / NYSE: BTE Average Daily Volume (1) CAN: 10,200,000 / US: 2,800,000 Shares Outstanding 210.7 million Market Capitalization / Enterprise Value $1.3 billion / $3.3 billion Net Debt (2) $2.0 billion Corporate Summary Production (3) Production Mix E&D Capital (3) Reserves 2P Gross (4) 68,000 72,000 boe/d 77% oil and liquids $225-$265 million 417 mmboe (1) Average daily trading volumes for May 2016. Volumes are a composite of all exchanges in Canada and the U.S. (2) Net debt is the principal amount of long-term debt and bank loan and includes working capital. As at March 31, 2016. (3) Production and exploration and development capital represents our 2016 guidance range. (4) Gross reserves are per NI 51-101 as at December 31, 2015. See Advisory Oil and Gas Information for more information. 6

Three Key Resource Plays Texas Eagle Ford 34% Q1/16 production of 41,100 boe/d Expect to bring ~ 30 net wells on production in 2016 Actively developing the Lower Eagle Ford formation in the core of the play Significant advancements were made in the last twelve months to delineate the multi-zone potential of our Sugarkane acreage 13 multi-zone projects in various stages of execution and production Western Canada 66% Texas 34% Texas 34% Gas 14% NGLs 17% Peace River Q1/16 production of 14,200 boe/d Heavy Oil 51% Light Oil Developed via multi-lateral 22% horizontal wells 2016 development deferred and ~ 6,000 bbl/d of heavy oil proactively shut-in due to low margins in Q1/2016 Texas 34% Lloydminster Q1/16 production of 11,500 boe/d Conventional heavy oil targeting multiple stacked pay formations North Dakota 4% Lloydminster Peace River Heavy Oil 36% Western Heavy Canada Oil 36% Western Canada 66% 63% Gas 10% Light Oil 18% 2016 development deferred and ~ 1,000 bbl/d of heavy oil proactively shut-in due to low margins in Q1/2016 7

2016 Capital Budget Summary of 2016 Expectations Exploration and Development Capital Production $225-$265 million 68,000 72,000 boe/d We are targeting capital expenditures to approximate funds from operations in order to minimize additional bank borrowings. Approximately 95% of planned expenditures will be in the Eagle Ford. In the Eagle Ford, we anticipate a reduced pace of development with four to five drilling rigs and one to two frac crews working on our lands. We anticipate bringing approximately 30 net wells on production. Production by Region 2016 Guidance We do not plan to execute our heavy oil development program this year. We proactively shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production. United States 55% Canada 45% 8

Balance Sheet / Debt Composition At March 31, 2016, long-term debt (bank loan and long-term notes) totaled $1.8 billion and we were 39% drawn on our credit facilities. Credit Capacity $2.3 Billion Long-Term Notes Maturity Schedule ($ Millions) Debt composition as at March 31, 2016. We have secured revolving credit facilities totaling US$575 million that mature June 2019. The revolving credit facilities do not require any mandatory principal payments prior to maturity and can be further extended beyond June 2019 with the consent of the lenders. 9

Financial Covenant Flexibility Baytex Position as at March 31, 2016 Senior Secured Debt (1) to Bank EBITDA (2) 0.61 : 1.00 Interest Coverage (3) 4.82 : 1.00 March 31, 2016 to March 31, 2018 Ratio for the Quarter(s) ending: June 30, 2018 to September 30, 2018 December 31, 2018 Thereafter Senior Secured Debt (1) to Bank EBITDA (2) 5.00 : 1.00 4.50 : 1.00 4.00 : 1.00 3.50 : 1.00 (Maximum Ratio) Interest Coverage (3) (Minimum Ratio) 1.25 : 1.00 1.50 : 1.00 1.75 : 1.00 2.00 : 1.00 Notes: (1) Senior Secured Debt is defined as the principal amount of our bank loan and other secured obligations under the credit facilities. At March 31, 2016, our Senior Secured Debt totaled C$303 million. (2) Bank EBITDA is calculated based on terms and conditions set out in the credit agreement which adjusts net income for interest expense, income taxes, certain non-cash items and acquisition and disposition activity. Bank EBITDA is calculated based on a trailing twelve month basis and was C$495 million for the twelve months ended March 31, 2016. (3) Interest Coverage is computed as the ratio of Bank EBITDA to interest expense on our Senior Secured Debt and long-term notes. Interest expense for the trailing twelve months ended March 31, 2016 was C$103 million. 10

Crude Oil Hedge Portfolio Q2/2016 Q3/2016 Q4/2016 Balance of 2016 Full-Year 2017 WTI Fixed Hedges Volumes (bbl/d) 8,000 5,000 5,000 6,000 --- Fixed Price (US$/bbl) $59.84 $63.79 $63.79 $62.03 --- WTI 3-Way Option Volumes (bbl/d) 9,500 10,000 10,000 9,833 10,000 Average Ceiling/Floor/Sold Floor $60/$50/$40 $60/$50/$40 $60/$50/$40 $60/$50/$40 $59/$46/$36 (US$/bbl) (2) Total WTI Hedge Volumes (bbl/d) 17,500 15,000 15,000 15,833 10,000 Hedge (%) (1) 49% 42% 42% 44% 28% WCS Differential Hedges Volumes (bbl/d) 8,000 7,000 7,000 7,333 1,500 WCS Price Relative to WTI (US$/bbl) ($13.26) ($13.32) ($13.40) ($13.32) ($13.42) Hedge (%) (1) 42% 37% 37% 38% 8% (1) Percentage of hedged volumes are based on the mid-point of 2016 production guidance (excluding NGL), net of royalties. (2) WTI 3-way option consists of a sold call, a bought put and a sold put. In a $60/$50/$40 example, 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 $50/bbl and $60/bbl; and Baytex receives $60/bbl when WTI is above US$60/bbl. 11

Cost Reduction Focus Baytex continues to take active measures to reduce costs where possible while maintaining efficiency in our operations and the safety of our employees and contractors. Drilling costs reduced 27% in the Eagle Ford Operating expenses reduced 18% from budget; transportation expenses reduced 20% from budget Realized Over $150 Million in Efficiencies in 2015 Optimization of operational practices - Trucking and fluid hauling - Well servicing - Facility rationalization Further reductions through fuel savings, reduced repairs and maintenance, and workovers General & Administration expenses reduced 22% from budget 12

Attractive Rates of Return 175% (1) (2) (3) Rate of Return 150% 125% 100% 75% Eagle Ford - US$5.6M/well Peace River - C$2.8M/well Lloydminster - C$750K/well Break-Even WTI (4) 50% 25% 0% $45 $50 $55 $60 $65 $70 WTI (US$/bbl) (1) Individual well economics are based on constant pricing and costs. Pricing assumptions: NYMEX gas = US$2.75/mcf, WCS differential = US$13.50/bbl, FX Rate (US$/C$) = 1.3. (2) Type curve assumptions: Eagle Ford: 30-day IP rate ~ 1,000 boe/d, EUR ~ 800 mboe. Peace River multi-lateral well: 30-day IP rate ~ 400 boe/d, EUR ~ 300 mboe. Lloydminster: for a single lined horizontal well: 30-day IP rate ~ 70 boe/d, EUR ~ 70 mboe. Baytex internal estimates. (3) Internal rate of return ( IRR ) is a rate of return measure used to compare the profitability of an investment and represents the discount rate at which the net present value of costs equals the net present value of the benefits. The higher a project s IRR, the more desirable the project. (4) Break even price represents the constant oil price (WTI) at which the net present value of the average type well is zero using a 10% discount rate. 13

Q1 2016 Highlights Generated production of 75,800 boe/d (78% oil and NGL) Continued to Meet the Challenges of Low Oil Prices Directed 96% of exploration and development spending to the Eagle Ford which generates the highest rates of return and highest netbacks in our portfolio Pro-actively shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production Amended bank credit facilities and restructured financial covenants Continued focus on cost reduction initiatives Advanced multi-zone development potential of Eagle Ford acreage Targeting up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk Produced 41,100 boe/d, an increase of 2% from Q4/2015 and 5% from Q3/2015 To-date, achieved a 32% reduction in well costs, with wells now being drilled, completed and equipped for approximately US$5.6 million, as compared to US$8.2 million in 2014 14

2016 Funds from Operations Sensitivities Sensitivities Estimated Effect on Annual Funds from Operations ($ Millions) Excluding Hedges Including Hedges Change of US$1.00/bbl WTI crude oil $17.8 $15.1 Change of US$1.00/bbl WCS heavy oil differential $9.7 $7.4 Change of US$0.25/mcf NYMEX natural gas $7.5 $2.7 Change of $0.01 in the C$/US$ exchange rate $4.6 $4.9 FFO sensitivities represent the remainder of 2016 (Q2 thru Q4) annualized. Price Assumptions: WTI crude oil - US$50/bbl, WCS heavy oil differential - US$14/bbl, NYMEX natural gas - US$2.10/mcf, Exchange Rate (C$/US$) 1.31. 15

The Eagle Ford

Baytex Acreage Position The Eagle Ford Provides Baytex With Exposure to a World Class Oil Resource Play Overview of Acreage 23,000 net contiguous acres in the Sugarkane Field in the core of the liquids-rich Eagle Ford shale The Sugarkane Field has been largely delineated which is expected to facilitate future production growth Extensive infrastructure in place across the acreage position, including centralized processing facilities, disposal wells and infield gathering systems 97% of acreage is held by production 17

Eagle Ford Development Significant advancements have been made to delineate the multi-zone development potential of our Sugarkane acreage Commenced production from 34 wells in Q1/2016 (47% Upper Eagle Ford, 35% Lower Eagle Ford, 18% Austin Chalk) A total of 19 wells established 30-day IP rates in Q1/2016 ~ 1,300 boe/d A recent five-well pad targeting the Austin Chalk and Upper Eagle Ford formations delivered an average 30-day IP rate per well of approximately 1,350 boe/d As at March 31, 2016, there are 74 producing Austin Chalk wells on our lands with an average 30-day IP rate per well of approximately 1,000 boe/d 18

Eagle Ford Performance Increasing Performance and Efficiency Improvements in drilling and completion design have increased 30-day IP rates by approximately 106% since Q4/2011 with 180-day cumulative recovery increasing 74% over the same time period Drilling times have decreased by 60% since Q4/2011 resulting in reduced completed well costs Production (30 Day IP, boe/d) Cumulative Recovery (mboe) Drilling Efficiency (Spud to TD) 74% Days on Production 19

Completion Improvements Increasing Lateral Length, Frac Stages and Proppant Lateral Length and Total Depth Per Well Frac Stages and Proppant Per Well 20

Heavy Oil Overview 21

Peace River Oil Sands Multi-Lateral Drilling Drives Strong Capital Efficiencies Area Statistics Land Holdings Production (Q1/2016) 2P Reserves (YE15) (1) Drilling Inventory (2) 338 net sections 14,200 boe/d 73.6 mmboe 7.5 years (1) In addition, we have 18.2 mmbbl of bitumen reserves related to our thermal operations. (2) Drilling inventory in years based on identified drilling locations (risked) and a normalized pace of ~ 25 wells per year. 22

Lloydminster Heavy Oil Lloydminster Heavy Oil Shift to Horizontal Drilling Expands Inventory Area Statistics Land Position Production (Q1/2015) 2P Reserves (YE15) (1) Drilling Inventory (2) 652 net sections 11,500 boe/d 33.2 mmboe ~ 7.5 years (1) In addition, we have 43.4 mmbbl of bitumen reserves related to our SAGD project at Gemini and 8.1 mmbbl of bitumen reserves related to our SAGD project at Kerrobert. (2) Drilling inventory in years based on identified drilling locations (risked) and a normalized pace of 70 to 80 wells per year. 23

Summary We are well positioned to benefit from an oil price recovery Retain significant leverage to a rising crude oil price environment Exceptional asset base focused on crude oil & liquids Significant inventory of development projects Advancing multi-zone potential of Eagle Ford acreage Focused on driving our cost structure lower Realized over $150 million in efficiencies in 2015 Maintain strong levels of financial liquidity Amended credit facilities and restructured financial covenants Senior Secured Debt to Bank EBITDA ratio of 0.61:1.00 $456 million of undrawn capacity on credit facilities 24

Contact Information Suite 2800, Centennial Place 520 3rd Avenue S.W. Calgary, Alberta T2P 0R3 T: (587) 952-3000 1-800-524-5521 www.baytexenergy.com James L. Bowzer President & Chief Executive Officer (587) 952-3000 Rodney D. Gray Chief Financial Officer (587) 952-3160 Brian G. Ector Senior Vice President, Capital Markets and Public Affairs (587) 952-3237 25