Investor Presentation June 2020 Advisory Forward Looking - - PowerPoint PPT Presentation

Investor Presentation

June 2020

2 Forward Looking Statements Any “financial outlook” or “future oriented financial information” in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial

• utlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are

cautioned that reliance on such information may not be appropriate for other circumstances. In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of future plans and operations, certain statements in 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"). 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 presentation peak only as of the date hereof and are expressly qualified by this cautionary statement. Specifically, this presentation contains forward-looking statements relating to but not limited to: that we have 10+ years of inventory in core areas, strong capital efficiencies and flexibility on discretionary capital; the percentage of our net crude oil exposure that is hedged and the expected gain on our 2020 financial contracts; that we have a consistent approach to risk management and are committed to strong ESG performance; our GHG emissions intensity reduction target; expectations for 2020 as to Baytex’s production on a boe/d basis, percentage of production that will be liquids, exploration and development expenditures, production by area and commodity; we are focused on protecting the health and safety of personnel while maintaining

• peartions; our 2020 outlook, including: to maintain financial liquidity, minimize capital outlays and emphasize cost reductions, our expectations with respect to activity in the eagle Ford and

shut-in volumes, planned net wells and exploration and development expenditures by operating area and $135 million of expected type and impact of cost reductions for 2020; the sensitivity of

• ur expected 2020 adjusted funds flow to changes in WTI prices, WCS and MSW differentials, natural gas prices and the Canada-United States foreign exchange rate; for the Eagle Ford that

enhanced completions continue to drive step change in performance, we expect to bring 16-18 wells on production in 2020 and stable production and deep inventory drive asset level free cash flow; for the Viking that we have meaningful extended reach inventory, additional EOR potential and that 2020 program is suspended pending recovery in oil prices; in Heavy Oil, that low decline production provides capital allocation flexibility, innovative multi-lateral horizontal drilling generates strong capital efficiencies and activity is planned on Peavine lands in 2021; for the Pembina Area Duvernay that completion activity for Q1/2020 wells is deferred indefinitely; the expected drilling and completion well costs, reserves and drilling inventory for our Eagle Ford, Peace River, Lloydminster, Viking and Pembina Area Duvernay assets; that we are committed to corporate sustainability and the components of our GHG emissions reduction strategy; and

• ur 2020 guidance for exploration and development expenditures, production, royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures

and asset retirement obligations. 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 they can be profitably produced in the future. 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 they 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; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow under credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for 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; the ability to develop crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect. Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions

• r costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; changes in income tax or other laws or

government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects;

Advisory

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Advisory (Cont.)

alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to 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, 2019, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings. 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. The future oriented financial information and forward-looking statements are made as of May 7, 2020 and Baytex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. Non-GAAP Financial and Capital Management Measures This presentation contains certain financial measures that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered non-GAAP measures. These non-GAAP measures may not be comparable to similar measures presented by other issuers. The following terms are not recognized measures under IFRS, but are presented in this presentation. “Adjusted funds flow” is defined as cash flow from operating activities adjusted for changes in non-cash operating working capital, asset retirement obligations settled and transaction costs. Management of Baytex consider adjusted funds flow a key measure of performance as it demonstrates the combined entity’s ability to generate the cash flow necessary to fund capital investments, debt repayment, settlement of abandonment obligations and potential future dividends. In addition, the ratio of net debt to adjusted funds flow is used to manage Baytex’s capital structure. “Asset Level Free Cash Flow” is defined as field level operating netback less exploration and development expenditures. “Bank EBITDA” is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning

• f the twelve month period. Bank EBITDA for the twelve months ended March 31, 2020 was $923.8 million.

“Capital Efficiency” is defined as the cost to drill, complete, equip and tie-in a well divided by the initial production rate of the well on a boe basis over its initial 365 days of production. “Exploration and development expenditures” is defined as expenditures related to drilling, completing and equipping, facilities, land, seismic and other. Exploration and development expenditures includes additions to exploration and evaluation assets along with additions to oil and gas properties. “Free cash flow” is defined as adjusted funds flow less exploration and development expenditures, payments on lease obligations and asset retirement obligations settled. “Interest coverage” is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended March 31, 2020 were $107.2 million. “Net debt” is defined as the sum of monetary working capital (which is current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term notes of Baytex and the bank loans of Baytex. Management of Baytex believe that net debt assists in providing a more complete understanding of Baytex’s cash liabilities. “Operating netback” is defined as petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense divided by barrels of oil equivalent sales volume for the applicable period. Management of Baytex believe that operating netback assists in characterizing Baytex’s ability to generate cash margin on a unit of production basis. "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at March 31, 2020, the Company's Senior Secured Debt totaled $694.9 million which includes $678.7 million of principal amounts outstanding and $16.2 million of letters of credit.

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Advisory (Cont.)

Advisory Regarding Oil and Gas Information The reserves information contained in this presentation has been prepared in accordance with National Instrument 51-101 -Standards of Disclosure for Oil and 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. Complete NI 51-101 reserves disclosure for year-end 2019 is included in our Annual Information Form for the year ended December 31, 2019, which has been filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission. This presentation discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex’s total proved, probable and unbooked locations. Proved locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed

• reserves. Unbooked locations are farther away from existing wells and, therefore, there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty

whether such wells will result in additional oil and gas reserves, resources or production. In the Eagle Ford, Baytex’s net drilling locations include 140 proved and 83 probable locations as at December 31, 2019 and 52 unbooked locations. In the Viking, Baytex’s net drilling locations include 1,080 proved and 319 probable locations as at December 31, 2019 and 636 unbooked

• locations. In Peace River, Baytex’s net drilling locations include 77 proved and 75 probable locations as at December 31, 2019 and 100 unbooked locations. In Lloydminster, Baytex’s net

drilling locations include 178 proved and 63 probable locations as at December 31, 2019 and 361 unbooked locations. In the Duvernay , Baytex’s net drilling locations include 11 proved and 10 probable locations as at December 31, 2019 and 295 unbooked locations. References herein to average 30-day initial production 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 assets for which such rates are provided. 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. Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs 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.

Notice to United States Readers

The petroleum and natural gas reserves contained in this presentation have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" (as defined in SEC rules). Canadian securities laws require oil and gas issuers disclose their reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves". Additionally, NI 51-101 defines "proved reserves“ and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in this presentation may not be comparable to United States standards. Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments. Moreover, in this presentation future net revenue from its reserves has been determined and disclosed estimated using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting

• period. As a consequence of the foregoing, the reserve estimates and production volumes in this presentation may not be comparable to those made by companies utilizing United States

reporting and disclosure standards. All amounts in this presentation are stated in Canadian dollars unless otherwise specified.

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▪ ~ 10 or more years of projected drilling inventory in each of our core areas (Viking, Eagle Ford and Canadian heavy oil) ▪ Strong capital efficiencies and flexibility on discretionary capital

Investment Highlights

High Quality and Diversified Oil Portfolio Across Multiple Plays Track Record of Substantial Free Cash Flow Generation Consistent Approach to Risk Management Financial Liquidity and No Near-Term Maturities

▪ Exploration and development expenditures represents 84% of adjusted funds flow over the last five years (2015 to 2019) ▪ Free cash flow of $329 million generated in 2019 ▪ Credit facilities ~ 35% undrawn and liquidity of ~ $300 million (1) ▪ First long-term note maturity is not until June 2024 ▪ Proven commitment to environmental, social and governance (“ESG”) objectives ▪ Established target to reduce GHG emissions intensity by 30% by 2021

Committed to ESG

▪ Utilize financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow ▪ Majority of net crude oil exposure hedged for 2020

(1) Undrawn credit facilities of $417 million and liquidity (net working capital) of $315 million, as at March 31, 2020.

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EAGLE FORD VIKING LLOYDMINSTER PEACE RIVER DUVERNAY

(1) Average daily trading volumes for June 1 to June 25, 2020. Volumes are a composite of all exchanges in Canada and the U.S. (2) Enterprise value based on closing share price on the Toronto Stock Exchange on June 25, 2020 and shares outstanding and net debt as at March 31, 2020. (3) Production, production mix, and exploration and development (“E&D”) expenditures represents 2020 guidance. (4) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd. (5) Production (Gross W.I.) composition based on 2020 guidance. Heavy oil includes Peace River and Lloydminster. (6) Revenue by commodity composition based on 2019 actuals.

Production by Core Area (5)

Heavy Oil Light Oil NGLs Natural Gas

Corporate Profile

Market Summary Ticker Symbol TSX / NYSE: BTE Average Daily Volume (1) CAN: 22 million / US: 5 million Shares Outstanding (2) 560 million Market Capitalization / Enterprise Value (2) $358 million / $2,410 million Operating Statistics Production (Gross W.I.) (3) 78,000 - 82,000 boe/d Production Mix (3) 83% liquids E&D Expenditures (3) $260 to $290 million Reserves – 2P Gross (4) 529 mmboe

Heavy Oil Light Oil NGLs Natural Gas Eagle Ford Viking Heavy Oil Other

Production by Commodity (5) Revenue by Commodity (6)

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ESG Highlights

GHG Emission Reduction Safety Established target to reduce GHG emissions intensity by 30% by 2021 55% reduction in lost time incident frequency in 5 years Gas Conservation Indigenous Relations 99.1% routine gas conservation in Peace River $32 million in contracts awarded in 2017-2018 Spill Volumes Gender Diversity 76% reduction in spill volumes over 5 years 25% women Board members

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Q1 2020 Highlights

• Generated production of 98,452 boe/d (83% oil and NGL)
• Delivered adjusted funds flow of $133 million ($0.24 per basic share)
• Issued US$500 million principal amount of 8.75% senior unsecured notes

due April 2027

• Redeemed two series of senior unsecured notes - US$400 million due 2021

and $300 million due 2022

• Extended the maturity of our credit facilities to April 2024
• Maintained undrawn credit capacity of $417 million and liquidity, net of

working capital, of $315 million

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Responding Decisively to COVID-19

• The oil and gas industry is facing an unprecedented challenge due to

significant degradation and volatility in global crude oil prices

• We are focused on protecting the health and safety of our personnel while

maintaining our operations

• We have implemented a number of measures to foster resilience through

these unpredictable times, including a work-from-home program and altering shifts in the field

• We have aggressively shifted our operating and capital activities to:
• Maintain financial liquidity
• Minimize capital outlays
• Emphasize cost reductions

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Maintain Financial Liquidity

C$548 Undrawn

C$300 US$400 US$400

(1) Balance sheet as at March 31, 2020. Revolving credit facilities mature April 2024 and are comprised of a US$575 million facility and a $300 million term loan facility. (2) S&P corporate rating “B” and senior unsecured debt rating “B+” ; Fitch corporate rating and senior unsecured debt rating “B”; Moody’s corporate rating “B2” and senior unsecured debt rating “B3”. (3) See advisory for definitions of Non-GAAP Financial and Capital Management Measures

• n page 4 of this presentation.

Long-Term Notes Maturity Schedule (2) ($ millions)

• Credit Facilities ~ 35%

Undrawn

• $417 million of undrawn

capacity on credit facilities and $315 million of liquidity net of working capital

• Enhanced long-term note

maturity profile

• First long-term note maturity

not until 2024

• Extended maturity of credit

facilities to 2024

• Credit facilities are not

borrowing base facilities and do not require annual or semi- annual reviews

Balance Sheet (1) $ millions Bank loan $679 Long-term notes $1,271 Long-term debt $1,950 Working Capital deficiency $102 Net Debt $2,052 2020 2021 2022 2023 2024 2025 2026 2027

US$500

Financial Covenants (3) Position as at March 31, 2020 Covenant Senior Secured Debt to Bank EBITDA (maximum ratio) 0.8:1.00 3.50:1.00 Interest Coverage (minimum ratio) 8.6:1.00 2.00:1.00

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Minimize Capital Outlays

2020 Guidance (1) E&D CapEx $260 - 290 million Production 78,000 - 82,000 boe/d Oil and NGLs 83%

• 50% reduction in capital spending
• $260 to $290 million, from $500 to

$575 million, previously

• Drilling operations in Canada

suspended

• Moderated pace of activity in the

Eagle Ford with 16-18 net wells brought on production (previously 22 net wells)

• Voluntarily shut-in production
• 25,000 boe/d shut-in for April and

May (80% heavy oil)

• ~ 80% of shut-in volumes re-started

in June, which will have a positive impact on our adjusted funds flow

Operating Area Net Wells CapEx ($MM) (2) Eagle Ford 17 $135 Viking 69 $80 Heavy Oil 33 $50 Pembina Duvernay 2 $10 Total $275

(1) Production guidance assumes approximately 20,000 boe/d of production shut-in for H2/2020. We have the operational flexibility to adjust spending plans based on changes in commodity prices. (2) Represents mid-point of 2020 guidance range.

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Emphasize Cost Reductions

• Intensely focused on driving

further efficiencies to capture or sustain cost reductions previously identified

• ~ $92 million of cost reductions

for 2020

• No change to per-unit operating

expense guidance despite lower volumes

• 30% reduction in transportation

expense

• G&A expenses reduced 14% to

$38 million (down 20% in last 18 months)

Operating Expenses Transportation Marketing G&A

Total Cost Reductions of ~ $92 million

Fee renegotiations and reduced tolls Discretionary spending eliminated; reduced salaries and annual retainers paid to Board of Directors Reduction in production; deferral of activity; reduced trucking costs Deferral of activity Reduced production associated with shut-in volumes Workforce optimization

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(1) WTI and Brent 3-way options consist of a sold put, a bought put and a sold call. In a $50/$58/$63 example, Baytex receives WTI+$8/bbl when WTI is at or below $50/bbl; Baytex receives $58/bbl when WTI is between $50/bbl and $58/bbl; Baytex receives WTI when WTI is between $58/bbl and $63/bbl; and Baytex receives $63/bbl when WTI is above $63/bbl.

Crude Oil Hedge Portfolio

Q2/2020 Q3/2020 Q4/2020 Balance

• f Year

WTI Fixed Hedges

Volumes (bbl/d) 16,683 23,732 8,000 16,138 Fixed Price (US$/bbl) $31.03 $36.41 $42.78 $35.61

WTI 3-Way Option

Volumes (bbl/d) 24,500 24,500 24,500 24,500 Average Sold Put / Put / Sold Call (US$/bbl) (1)

$50/$58/$63 $50/$58/$63 $50/$58/$63 $50/$58/$63

Total Hedge Volumes (bbl/d) 41,183 48,232 32,500 40,638

Basis Differential Financial Swaps

WCS Volumes (bbl/d) 6,500 10,833 6,500 7,944 WCS Price Relative to WTI (US$/bbl) ($16.27) ($13.55) ($16.27) ($15.03) MSW Volume (bbl/d) 5,267 8,898 5,000 6,388 MSW Price Relative to WTI (US$/bbl) ($6.07) ($5.76) ($6.15) ($5.95)

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2020E Adjusted Funds Flow Sensitivities

Sensitivities Estimated Effect on Annual Adjusted Funds Flow ($MM) (1) (2) Excluding Hedges Including Hedges (3) Change of US$1.00/bbl WTI crude oil $24.3 $15.9 Change of US$1.00/bbl WCS heavy oil differential $7.1 $3.4 Change of US$1.00/bbl MSW light oil differential $7.3 $3.9 Change of US$0.25/mcf NYMEX natural gas $7.7 $5.3 Change of $0.01 in the C$/US$ exchange rate $4.4 $4.4

(1) Adjusted funds flow sensitivities are based on the following full-year 2020 pricing assumptions: WTI - US$37/bbl; WCS differential - US$14/bbl; MSW differential – US$6/bbl, NYMEX Gas - US$1.95/mcf; AECO Gas - $2.00/mcf and Exchange Rate (CAD/USD) - 1.36. (2) Includes impact of reduced volumes associated with voluntarily shutting-in production. (3) Our adjusted funds flow sensitivities (including hedges ) will vary depending on where WTI prices trade, relative to the bands established within our 3-way option contracts. The sensitivity to a change of US$1/bbl WTI crude oil in the table above reflects a WTI price of less than US$50/bbl.

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$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 $45,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 BTE 22 23 24 25 26 27 28

Top Quartile Capital Efficiencies

Source: Scotiabank Global Banking and Markets – May 2019. Comparative group includes AAV, ARX, BIR, BNE, BNP, BXE, CJ, CPG, CR, DEE, ECA, ERF, FRU, KEL, NVA, OBE, PEY, PMT, PONY, POU, PSK, SGY, TOG, TOU, VET, VII, WCP.

Oil Gas (< 33% Liquids) Mixed (<67% Liquids) 2018 All-In Capital Efficiencies, excl. A&D ($/boe/d) Weighted Average ($/boe/d) Oil $25,000 Gas $12,800 Mixed $21,600 All $19,500

Asset Overview

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Asset Highlights

Geographic and play diversification with ~ 10 or more years drilling inventory in each core area

Eagle Ford Viking Heavy Oil Pembina Duvernay Production

(Gross; Q1/2020)

36,190 boe/d 24,696 boe/d 31,211 boe/d 1,799 boe/d Oil and NGLs

(Gross; Q1/2020)

77% 92% 93% 81% 2P Reserves (1)

(Gross)

229 mmboe 98 mmboe 103 mmboe 14 mmboe Asset Highlights ▪ 19,851 net acres in the core of Karnes county with world class partner, and operator in Marathon ▪ Stable production base with low sustaining capital has driven ~ $724 million of asset level free cash flow since 2016 (2) ▪ Enhanced completions continue to drive step change in performance ▪ 419,615 net acres of land in the Viking play ▪ Shallow, light oil, strong netback asset with “manufacturing” development ▪ $83 million of asset level free cash flow in 2019 (2) ▪ Meaningful extended reach inventory (~ 10 years) with additional EOR potential ▪ Dominant land position

• f 672,640 net acres

▪ Low decline production provides capital allocation flexibility ▪ Innovative multi-lateral horizontal drilling generates top tier capital efficiencies ▪ 176,000 acres of 100% W.I. lands in the Pembina area ▪ Offset development and 9 wells drilled to-date have delineated ~ 40%

• f acreage position

▪ Measured delineation planned

(1) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd. See “Advisories”. (2) The term “asset level free cash flow” is a non-GAAP measure. See slide 3 for more information.

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Eagle Ford: Core of Karnes County

LONGHORN

Wilson

Atascosa Karnes Live Oak

EXCELSIOR SUGARLOAF IPANEMA

Bee

Oil Condensate Dry Gas

• 19,900 net acres in the

core of the Eagle Ford shale in south Texas

• Four AMI’s (Longhorn,

Sugarloaf, Ipanema and Excelsior) with average 25% W.I.

• Q1/2020 production of

36,200 boe/d (77% liquids)

• 30 gross (6.1 net) wells in

Q1/2020 established average 30-day IP rates of ~ 1,875 boe/d per well

• Expect to bring 16 to 18

net wells on production in 2020

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$42 $138 $285 $238 $21

2016 2017 2018 2019 Q1 2020 36.6 36.7 37.1 39.1 36.2 2016 2017 2018 2019 Q1 2020

Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory

50 100 150 200 250 300 2020 Program Remaining Undrilled Inventory

Drilling Inventory (2) (net locations) > 10 year inventory at current pace

16-18 net wells

• n- stream

> 250 net locations

(1) Asset level free cash flow represents field level operating netback less exploration and development capital. For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary. (2) Net locations includes 223 proved plus probable undeveloped reserves locations at year-end 2019 and 52 unbooked future locations. See “Advisories”

Asset Level Free Cash Flow (1) (C$ millions) ~ $724MM cumulative asset level free cash flow since 2016 Production (mboe/d) Stable production and deep inventory drives asset level free cash flow

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25 50 75 100 125 150 175

1 2 3 4 5 6 Cumulative Production (mboe) Months

17% increase 2019 over 2017 5% increase 2019 over 2018

Enhanced Completions Drive Step Change in Well Performance

2017 2016

180 Day Cumulative Well Production

Hz Length (ft) Proppant (lbs/ft) Stage Spacing (ft) # of Stages Q1 2020 6,000 2,700 226 26 2019 6,300 2,300 225 28 2018 6,000 2,000 215 28 2017 5,900 1,800 217 27 2016 5,500 1,600 221 25

Completion Activity

2019 2018

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Viking Light Oil: 460 Highly Prospective Sections

Baytex Lands

Esther/Hoosier Kerrobert Plenty Greater Gleneath Lucky Hills/Whiteside Dodsland Mantario (Laporte) Plato

• Shallow (700 m), light oil

(36° API) resource play with strong netbacks

• Produced a record

24,700 boe/d (92% oil) in Q1/2020

• Added 229 net unbooked

drilling opportunities in 2019 through multiple deals and asset swaps

• Steady pace of

development in Q1/2020 with 4 drilling rigs and 2 frac crews running

• Remainder of 2020

program suspended pending recovery in oil prices

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10 20 30 40 50 60 70 80

• 5,000

10,000 15,000 20,000 25,000 Oil Rate (bbl/d) Cum Oil (bbl) 2019 Wells 2018 Wells 2017 Wells 2016 Wells 2015 Wells 2014 Wells 2013 Wells 2012 Wells

Technical Advancements Drive Productivity Improvement

Viking Wells by Vintage

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 50 100 150 200 250 300 350 400 2012 2013 2014 2015 2016 2017 2018 2019 Net Wells Onstream (Left Axis) ERH (%) (Right Axis)

Shift to ERH(1) Wells Drives Productivity Improvements 95%+ of Viking Development now ERH Wells

(1) Extended Reach Horizontal (“ERH) wells are ¾ to 1 mile long laterals drilled to a depth of approximately 700 metres.

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Peace River: Innovative Multi-Lateral Development

Performance Drivers

• Produced 16,100 boe/d in

Q1/2020 (87% oil)

• Dominant 560 net sections
• Strong capital efficiencies

Baytex Lands

Seal Harmon Valley Reno Golden Peavine

Peavine Lands

• Q1/2020 strategic agreement

with Peavine Metis settlement

• 60 sections of land
• Early stage exploratory play

targeting Spirit River formation, a Clearwater formation equivalent

• First activity planned for 2021

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Lloydminster: Significant Land Position and Drilling Inventory

Performance Drivers

• Produced 15,100 boe/d in

Q1/2020 (99% oil)

• Strong capital efficiencies
• Applying multi-lateral

horizontal drilling and production techniques

• Ramp-up of Kerrobert

thermal project occurred in Q4/2019 with peak production of ~ 3,500 bbl/d

Baytex Lands

ALBERTA SASKATCHEWAN

Kerrobert Lloydminster Soda Lake Tangleflags Ardmore/Cold Lake Lindbergh

25

Heavy Oil Innovation

Peace River Multi-Lateral Horizontal Lloydminster Horizontal

26

Pembina Area Duvernay Light Oil: Emerging Resource Play

Baytex Lands

Pembina Duvernay

• 275 sections of 100% WI lands
• Nine wells drilled to date have

delineated a minimum of 100- 125 sections

• Produced 1,800 boe/d (81%

liquids) in Q1/2020

• Two wells on-stream in 2019

generated average 30-day IP rate of ~ 1,050 boe/d (75% liquids)

• D&C costs of ~ $7.0 million

represent an ~ 20% reduction from previous wells

• Completion activities for two

wells drilled in Q1/2020 deferred

Producing Pads (7 wells) Rimbey Leduc Reef Liquids Rich Gas Liquids Rich Gas Volatile Oil Black Oil 2020 DUC’s (2 wells)

27

Eagle Ford Viking Peace River (1) Lloydminster (1) Pembina Duvernay

Formation Lower Eagle Ford Viking Bluesky Mannville Group Duvernay Upper Eagle Ford Austin Chalk Depth (metres) 3,300-3,900 700 600 350-800 2,200-2,400 Oil API Oil: 40-45° 36° 11° 10-16° 42-44° Condensate: 44-55° Porosity 4.6% - 9% 23% 28% 30% 3% - 6% Permeability 0.33 - 0.41 millidarcies 0.5 - 50 millidarcies 1 - 5 darcies 0.5 - 5 darcies 10 nanodarcy Completion Plug and perf Pin point coil Open hole multi-lateral Horizontal slotted liner /

• pen-hole multi-lateral

Plug and perf Expected Well Costs (drill, complete, equip and tie-in) US$5.6 million $1.0 million $2.5 million $0.8 million $7.0 million 6,000 foot lateral Land - gross (net) sections 122 (31) 763 (656) 562 (560) 637 (491) 275 (275) Pembina area Reserves at YE 2019 (mmboe) Proved developed producing 71 29 21 13 2 Proved 163 65 32 28 7 Proved plus probable 229 98 59 44 14 Drilling inventory (risked) – net locations (booked/unbooked) 223 / 52 1,399 / 636 152 / 100 241 / 361 21 / 295

(1) Figures do not incorporate thermal assets at Cliffdale (Peace River) or Gemini (Lloydminster)

High Quality Oil Development

Corporate Sustainability

29

Corporate Sustainability

At Baytex, we believe that commitment to corporate responsibility is just as important as delivering financial and operational targets. We publish a biennial Corporate Sustainability Report which provides transparent reporting and clear goals on the topics that matter:

Safety Environment Communities and Stakeholders Business Practice and Compliance

For more information and to view our most recent report, visit http://www.baytexenergy.com

Commitment to the health and safety of our employees, contractors and communities. Commitment to minimizing our impact on air, water, land and life in the areas we operate. Commitment to provide social and economic benefits to the communities in which we

• perate and to hear the

voices and concerns of our stakeholders. Commitment to governance, ethical business conduct, and regulatory compliance. Baytex was recognized by Corporate Knights in 2018 as one of Canada’s Top Sustainability Performers.

30

GHG Emissions Reduction

Target to reduce GHG emission intensity (tonnes of CO2 per boe) by 30% by 2021. Our emissions reduction strategy includes:

• Increasing gas conservation
• Reusing associated gas as fuel for

field activities

• Reducing emissions from storage

tanks

• Monitoring and preventing fugitive

emissions

31

A Culture of Commitment

Objective What we’ve done Result How it contributes to value creation ENVIRONMENT

Responsibly develop

• ur assets

Ensure our employees and contractors uphold our procedures for spill prevention, response and cleanup 76% reduction in corporate spill volumes, over 5 years Reduces costs and maintains social license Exceed regulatory

• bligations

Invested more than $100 million in gas conservation activities in Peace River in the last 5 years 99.1% routine gas conservation in Peace River Helps to build trust with regulators and stakeholders

SOCIAL

Create a culture of safety Tie safety targets to annual performance incentive program 55% reduction in employee +contractor LTIF in 5 years Supports the consistent and safe execution of our business plan Be a good neighbour Build mutually beneficial relationships based on trust $32 million awarded in contracts to Indigenous contractors/companies in 2017- 2018 Maintain social license and enables growth in our

• perations by reducing non-

technical project delays

GOVERNANCE

Ensure effective Board leadership Ensure our Board is comprised of dedicated Directors who are invested in our success 100% Board meeting attendance and 25% women Board members as

• f Sep. 2019

Sets strategic direction and improves decision making Be transparent and accountable Communicate our ESG impacts by publishing biennial sustainability reports since 2012 Recognized by Corporate Knights as Future 40 Responsible Corporate Leaders in 2018 Enables shareholders and stakeholders to make informed decisions

Source: 2018 Sustainability Report – September 2019

Supplementary Information

33

Summary of Operating and Financial Metrics

Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Benchmark Prices WTI crude oil (US$/bbl) $62.87 $67.88 $69.50 $58.81 $64.77 $54.90 $59.81 $56.45 $56.96 $57.03 $46.17 NYMEX natural gas (US$/mcf) $3.00 $2.80 $2.90 $3.64 $3.09 $3.15 $2.64 $2.23 $2.50 $2.63 $1.95 Production Crude oil (bbl/d) 45,835 46,644 56,767 71,326 55,218 71,939 69,905 68,541 70,956 70,328 74,571 Natural gas liquids (bbl/d) 9,143 9,419 10,076 10,327 9,745 11,729 10,986 9,543 8,699 10,229 7,822 Natural gas (mcf/d) 87,261 87,605 93,414 103,424 92,971 104,682 105,065 101,054 100,236 102,742 96,356 Oil equivalent (boe/d) (1) 69,522 70,664 82,412 98,890 80,458 101,115 98,402 94,927 96,360 97,680 98,452 % Liquids 79% 79% 81% 83% 81% 83% 82% 82% 83% 82% 83% Netback ($/boe) Total sales, net of blending and other expenses (2) $42.96 $51.22 $55.03 $37.89 $46.31 $47.98 $51.49 $47.14 $48.25 $48.72 $35.19 Royalties (10.36) (12.01) (12.13) (8.77) (10.68) (8.94) (9.67) (8.59) (8.72) (8.98) (6.33) Operating expense (10.53) (10.91) (10.25) (10.76) (10.61) (11.02) (11.22) (11.15) (11.23) (11.16) (11.66) Transportation expense (1.36) (1.22) (1.26) (1.21) (1.26) (1.46) (1.33) (1.13) (1.00) (1.23) (1.15) Operating Netback (4) $20.71 $27.08 $31.39 $17.15 $23.76 $26.56 $29.27 $26.27 $27.30 $27.35 $16.05 General and administrative (1.76) (1.64) (1.34) (1.55) (1.56) (1.55) (1.28) (1.14) (1.12) (1.28) (1.09) Cash financing and interest (3.92) (3.97) (3.47) (3.07) (3.55) (3.10) (3.14) (3.06) (2.75) (3.01) (3.19) Realized financial derivative gain (loss) (1.57) (4.57) (4.07) (0.34) (2.49) 2.07 1.45 2.39 2.59 2.12 3.00 Other (3) 0.01 (0.31) 0.07 (0.02) (0.05) 0.28 0.07 (0.03) 0.16 0.13 0.07 Adjusted funds flow (4) $13.47 $16.59 $22.58 $12.17 $16.11 $24.26 $26.37 $24.43 $26.19 $25.31 $14.84

(1) 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. (2) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark. (3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q3/2019 MD&A for further information on these amounts. (4) The terms “adjusted funds flow” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures on slide 3 of this presentation.

34

Reserves Summary (Gross)

Category (1) Eagle Ford Viking Heavy Oil Pembina Duvernay Other Total Proved Developed Producing 71 29 34 2 6 142 Total Proved 163 65 68 7 11 314 Total Proved Plus Probable 229 98 163 14 25 529

2P Reserves by Asset 2P Reserves Breakdown 2P Reserves by Commodity

Light Oil + NGL Heavy Oil Natural Gas Probable PDNP + PUD PDP

(1) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd.

Eagle Ford Viking Heavy Oil Pembina Duvernay Other

35

2020 Guidance and Cost Assumptions

Exploration and development expenditures ($ millions) $260 - $290 Production (boe/d) 78,000 - 82,000 Expenses: Royalty rate (%) 18.5% Operating ($/boe) $11.75 - $12.50 Transportation ($/boe) $0.95 - $1.05 General and administrative ($ millions) $38 ($1.30/boe) Interest ($ millions) $112 ($3.84/boe) Leasing expenditures ($ millions) $7 Asset retirement obligations ($ millions) $10

Edward D. LaFehr

President and Chief Executive Officer 587.952.3000

Rodney D. Gray

Executive Vice President and Chief Financial Officer 587.952.3160

Brian G. Ector

Vice President, Capital Markets 587.952.3237

Baytex Energy Corp.

Suite 2800, Centennial Place 520 – 3rd Avenue S.W. Calgary, Alberta T2P 0R3 T 587.952.3000 Toll Free 1.800.524.5521

www.baytexenergy.com

Contact Information