Investor Presentation - October 2021 - Baytex Energy Corp.

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Investor Presentation - October 2021 - Baytex Energy Corp.
Investor
Presentation
 October 2021
Investor Presentation - October 2021 - Baytex Energy Corp.
Advisory

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 outlook
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 drilling inventory in core areas, strong capital efficiencies and flexibility
on discretionary capital; we have potential to deliver more than $350 million of free cash flow ($0.62 per share) in 2021; we use derivate contract and crude-by-rail to reduce volatility in adjusted
funds flow; that approximately 45% of our net crude oil exposure is hedged for H2/2021; our GHG emissions intensity reduction target; expectations for 2021 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; that our 2021 capital program is fully funded at
US$35/bbl WTI, will have capital efficiencies of ~$12,000 boe/d, 75% will be directed to high netback light oil assets, intend to implement a heavy oil program with 35 net wells in H2/2021
including 7 net clearwater equivalent wells and have the potential to further advance Pembina Duvernay; the expected number of wells onstream and total capex for 2021 in pour Viking, Eagle
Ford, Heavy Oil, East Duvernay and other Operating Areas; that our 5-year plan at $55 WTI will: target capital spending at $1 billion of free cash flow, has a target net debt of $1 to $1.2 billion and a target net debt to bank EBITDA ratio of
120 sections prospective for Sprit River (clearwater equivalent), the play aligns with our core competencies, that we have de-risked 20 sections and believe the play holds the potential for
>200 locations, preparing for two additional clearwater wells in 2021 and 12 to 18 in 2022; ~22 net wells planned for H2/2021 in Lloydminster; in Pembina Area Duvernay, measured delineation is
planned, two wells drilled in 2020 demonstrate repeatability of 11-30 pad completed in 2019 and 2 wells planned for H2/2021; the expected individual well payout, IRR, recycle ratio and
breakeven WTI price for wells in the Eagle Ford, Viking, Peace River, Clearwater and Lloydminster areas; the expected drill, complete, equip and tie-in well costs, reserves and drilling inventory
for our Eagle Ford, Peace River, Lloydminster, Viking and Pembina Duvernay assets; our aspiration, visions and approach to ESG; that we are committed to corporate sustainability; the
components of our GHG emissions reduction strategy; our new ESG targets: reducing our GHG emissions intensity by 65% by 2025 from our 2018 baseline, reduce our end of life well inventory
to zero by 2040, by 2022 evaluate and test new methods to reduce freshwater intensity and by 2022 expand our baseline to include multiple dimensions of diversity and enhance our processes
to measure employee engagement; and our 2021 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.
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.

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Investor Presentation - October 2021 - Baytex Energy Corp.
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 oil and natural gas prices and price differentials (including the impacts of Covid-19); the availability and cost of capital or borrowing; risks associated with our ability to exploit our
properties and add reserves; availability and cost of gathering, processing and pipeline systems; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply
with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; public perception and its influence on the regulatory regime; restrictions or costs
imposed by climate change initiatives and the physical risks of climate change; 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; costs to develop and operate our properties;
variations in interest rates and foreign exchange rates; risks associated with our hedging activities; retaining or replacing our leadership and key personnel; 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 related to our
thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; results of litigation; risks associated with
large projects; 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, 2020, 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 October 1, 2021 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 expense, income tax, non-recurring losses,
certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expense, impairment, deferred income tax expense or recovery, unrealized gains
and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if
they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2020 was $414.9 million.
“Capital Efficiency” is defined as exploration and development expenditures divided by the expected aggregate IP365 rate (boe/d) for all wells coming on production in the year, normalized to a
January 1 start-date.“
“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.
“Internal rate of return” of “IRR” is a rate of return measure (before tax) 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.
“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 credit facilities 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.

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Investor Presentation - October 2021 - Baytex Energy Corp.
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 2020 is included in our Annual Information Form for the year ended December 31,
2020, which will be filed on or before March 31, 2021 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 135 proved and 75 probable locations as at
December 31, 2020 and 38 unbooked locations. In the Viking, Baytex’s net drilling locations include 985 proved and 283 probable locations as at December 31, 2020 and 443 unbooked
locations. In Peace River, Baytex’s net drilling locations include 17 proved and 48 probable locations as at December 31, 2020 and 163 unbooked locations. In Lloydminster, Baytex’s net drilling
locations include 99 proved and 74 probable locations as at December 31, 2020 and 417 unbooked locations. In the Duvernay, Baytex’s net drilling locations include 13 proved and 12 probable
locations as at December 31, 2020 and 278 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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Investor Presentation - October 2021 - Baytex Energy Corp.
Investment Highlights

    High Quality and              ~ 10 or more years of projected drilling inventory in each of our
 Diversified Oil Portfolio         core areas (Viking, Eagle Ford and Canadian heavy oil)
  Across Multiple Plays           Strong capital efficiencies and flexibility on discretionary capital

                                  Exploration and development expenditures represents 81% of
    Track Record of                adjusted funds flow over the last five years (2016 to 2020)
  Substantial Free Cash
                                  Potential to deliver > $350 million ($0.62 per share) of free cash
    Flow Generation                flow in 2021 (1)

  Financial Liquidity and          Credit facilities ~ 50% undrawn and liquidity ~ $500 million (2)
 No Near-Term Maturities           First long-term note maturity not until June 2024

                                   Utilize financial derivative contracts and crude-by-rail to reduce the
 Consistent Approach to             volatility in our adjusted funds flow
   Risk Management                 ~ 45% of net crude oil exposure hedged for H2/2021

                                   Proven commitment to environmental, social and governance
                                    (“ESG”) objectives
   Committed to ESG
                                   Established target to reduce GHG emissions intensity by 65% by
                                    2025, relative to 2018 baseline
                             (1)   2021 full-year pricing assumptions: WTI - US$64/bbl; WCS differential - US$13/bbl; MSW differential – US$4/bbl; NYMEX Gas -
                                   US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26.
                             (2)   As at June 30, 2021.
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Investor Presentation - October 2021 - Baytex Energy Corp.
Corporate Profile

                                                                                      Market Summary
                                                                                       Ticker Symbol                                                                   TSX: BTE
                                                                                        Average Daily Volume              (1)                                          12.9 million
                                                                                       Shares      Outstanding (2)                                                     564 million
                                                                                       Market Capitalization / Enterprise                Value (2)                     $1.95 billion / $3.58 billion

                                                                                    Operating Statistics
                                                                                       Production (Gross W.I.) (3)                                                     79,000 – 80,000 boe/d
                                                                                       Production Mix            (3)                                                   81% liquids
                                  PEACE RIVER

                                 DUVERNAY
                                       LLOYDMINSTER
                                                                                       E&D Expenditures (3)                                                            $285 to $315 million
                                                VIKING                                 Reserves – 2P Gross (4)                                                         462 mmboe

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

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

(1)   Average daily trading volumes for September 2021. Volumes are a composite of all exchanges in Canada.
(2)   Enterprise value based on closing share price on the Toronto Stock Exchange on September 30, 2021 and shares outstanding and net debt as at June 30, 2021.
(3)   Production, production mix, and exploration and development (“E&D”) expenditures represents 2021 guidance.
(4)   Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd.
(5)   Production (Gross W.I.) composition based on 2021 guidance. Heavy oil includes Peace River and Lloydminster.
(6)   Revenue by commodity composition based on 2020 actuals.                                                                                                                                               6
Investor Presentation - October 2021 - Baytex Energy Corp.
Q2 2021 Highlights

Operational Execution
   •   Production of 81,200 boe/d, up 3% from Q1/2021
   •   E&D capital of $61 million, consistent with full-year plan
   •   Continue to advance our Peace River Clearwater play with 5 wells on production

Free Cash Flow Generation
   •   Adjusted funds flow of $176 million ($0.31 per basic share), a 12% increase over
       Q1/2021
   •   Substantial free cash flow of $112 million ($0.20 per basic share)

Strengthened Balance Sheet
   •   Reduced net debt by $129 million through a combination of free cash flow and the
       Canadian dollar strengthening relative to the U.S. dollar
   •   Increased undrawn capacity to $511 million (50% undrawn on our $1 billion credit
       facilities)
   •   Repurchased and cancelled US$106 million of our outstanding long-term notes
       due 2024 during and subsequent to the quarter

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Investor Presentation - October 2021 - Baytex Energy Corp.
ESG Highlights

GHG Emission Reduction                     Safety
          46% reduction in GHG                       25% reduction in total
          emissions intensity through                recordable injury frequency in
          2020, relative to 2018                     5 years
          baseline; 65% target in place

Gas Conservation                           Indigenous Relations
          97% routine gas conservation               Recent agreements with
          in Peace River in 2020                     Woodland Cree First Nation
                                                     and Peavine Métis Settlement

Spill Volumes                              Gender Diversity
          59% reduction in reportable                25% women Board members
          spill volumes over 5 years                 as of April 2021

Abandonment & Reclamation                  Water
          Reduce inactive well inventory             Initiate water recycle projects
          of ~ 4,500 wells to zero by                in Kerrobert, Viking and
          2040                                       Duvernay
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Investor Presentation - October 2021 - Baytex Energy Corp.
2021 Capital Program

•   Cash neutrality (capital program fully         2021 Guidance (1)
    funded) at US$35/bbl WTI
                                                   E&D CapEx                                                      $285 - 315 million

•   Capital efficiencies of approximately          Production                                              79,000 - 80,000 boe/d
    $12,000 per boe/d across the                   Oil and NGLs                                                                         81%
    portfolio
                                                                                           Net Wells
•   75% directed to our high netback           Operating Area                              Onstream                 CapEx ($MM) (2)
    light oil assets in the Eagle Ford and
                                               Viking                                                 120                               $115
    Viking
                                               Eagle Ford                                               22                              $110
•   Heavy oil program kicked off in June       Heavy Oil                                                35                                $45
    – 35 net wells planned for the year,
    including up to 7 net Clearwater           East Duvernay                                              2                               $20
    equivalent wells                           Other                                                      4                               $10
                                               Total                                                                                    $300
•   Further advancing our Pembina
    Duvernay development with two well       (1)    2021 capital spending is 52% weighted to the second half of the year. Eagle Ford

    program in H2/2021                              development includes 14 net wells drilled and 22 net wells on production. Other development
                                                    includes 2 net natural gas wells drilled and 4 net natural gas wells on production.
                                             (2)    Represents mid-point of 2021 guidance range.

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Investor Presentation - October 2021 - Baytex Energy Corp.
5-Year Plan (2021 to 2025) at US$55 WTI

1. Disciplined and Returns Based Capital Allocation
                •        Target capital spending at < 70% of adjusted funds flow
                •        Optimize production in the 80,000 to 85,000 boe/d range
                •        Capital efficiencies during the plan period of $15,000 to $16,000 per boe/d

2. Maximize Free Cash Flow
                •        Generate > $1 billion of free cash flow during the plan period

3. Improve Leverage Ratios
                •        Target net debt of $1.0 to $1.2 billion and net debt to bank EBITDA ratio of
                         < 1.5x at US$55 WTI

4. Enhance Shareholder Returns (2022-2025)
                •        Consider introduction of share buy-back, dividend and/or reinvestment for
                         organic growth
Notes:
(1)      For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary.
(2)      Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. Year one of the 5-year plan (2021) based on H1/2021 actual results and the forward strip for the
         balance of the year. Full year 2021 pricing assumptions:: WTI - US$64/bbl; WCS differential - US$13/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26
         Years two through five of the five-year plan (2022 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf;
         AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28.
(3)      Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at each year-end and forecast Bank EBITDA for that particular year. See advisory for definitions of Non-GAAP Financial and Capital Management Measures
         on page 3 of this presentation.

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5-Year Plan Generates > $1 Billion Cumulative Free Cash Flow

                     90,000
                                                                                                                                                                                                          > $1 Billion Cumulative Free Cash Flow
                     80,000                                                                                                                                                                     $1,400

                     70,000

                                                                                                                                                       Cumulative Free Cash Flow ($ millions)
                                                                                                                                                                                                $1,200
                     60,000
                                                                                                                                                                                                $1,000
Production (boe/d)

                     50,000
                                                                                                                                                                                                 $800
                     40,000
                                                                                                                                                                                                 $600
                     30,000

                                                                                                                                                                                                 $400
                     20,000

                     10,000                                                                                                                                                                      $200

                           0                                                                                                                                                                       $0
                            2021                     2022                    2023                     2024                     2025                                                                         2021          2022      2023      2024     2025
                                         Eagle Ford          Viking       Heavy Oil        Duvernay          Conventional

                                                                                                      Adjusted                           Adjusted                                                             Capital
                                                                    Production                                                                                                                                                    Free Cash    Ending Net Debt
                                                                                                    Funds Flow                        Funds Flow                                                         Expenditures
                                                                       (boe/d)                                                                                                                                                   Flow ($MM)             ($MM)
                                                                                                        ($ MM)                       ($ per share)                                                             ($MM)
             2021                                                            79,500                              $675                             $1.20                                                            $300                $360             $1,480
             2022                                                            79,900                              $591                             $1.04                                                            $366                $200             $1,280
             2023                                                            81,500                              $615                             $1.08                                                            $410                $180             $1,100
             2024                                                            83,000                              $648                             $1.14                                                            $410                $213               $887
             2025                                                            83,900                              $666                             $1.16                                                            $410                $231               $656
     Notes:
     (1)             For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary.
     (2)             Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. Year one of the 5-year plan (2021) based on H1/2021 actual results and the forward strip for the balance
                     of the year. Full year 2021 pricing assumptions:: WTI - US$64/bbl; WCS differential - US$13/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26.
     (3)             Years two through five of the five-year plan (2022 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf;
                     AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28.

                                                                                                                                                                                                                                                              11
5-Year Plan with Upside WTI Scenario’s

                                                               US$55 WTI                                  US$65 WTI                                               US$75 WTI
                                                              ~ $1.2 Billion                             ~ $2.0 Billion                                          ~ $2.6 Billion
                                                             Cumulative FCF                             Cumulative FCF                                          Cumulative FCF

                                                   $700                                                                                                                                                      2.0x

                                                                                                                                                                                                             1.8x
                                                   $600
                                                                                                                                                                                                             1.6x

                                                                                                                                                                                                                     Net Debt to Bank EBITDA ratio
                     Free Cash Flow ($ millions)

                                                   $500                                                                                                                                                      1.4x

                                                                                                                                                                                                             1.2x
                                                   $400
                                                                                                                                                                                                             1.0x
                                                   $300
                                                                                                                                                                                                             0.8x

                                                   $200                                                                                                                                                      0.6x

                                                                                                                                                                                                             0.4x
                                                   $100
                                                                                                                                                                                                             0.2x

                                                     $0                                                                                                                                                      0.0x
                                                          2021 2022 2023 2024 2025               2021 2022 2023 2024 2025                                  2021 2022 2023 2024 2025
                                                                    US$55/bbl                                        US$65/bbl                                                 US$75/bbl

                                                                                         Free Cash Flow               Net Debt to Bank EBITDA
Notes:
(1)      For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary. Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including
         prior year’s results.
(2)      2021 (year one of the base case and the upside WTI scenarios) is based on H1/2021 actual results and the forward strip for the balance of the year. Full year 2021 pricing assumptions: WTI - US$64/bbl; WCS differential -
         US$13/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26
(3)      Years two through five of the base case (2022 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf;
         AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28. In the upside WTI scenarios, all other pricing assumptions are held constant
(4)      Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at each year-end and forecast Bank EBITDA for that particular year. Free cash flow is utilized to reduce net debt. See advisory for definitions of Non-GAAP
         Financial and Capital Management Measures on page 3 of this presentation.

                                                                                                                                                                                                                                                     12
Financial Liquidity

• Credit Facilities ~ 50%                                                                            Balance Sheet (1)                                       $ millions
  Undrawn                                                                                            Credit facilities                                             $487

           •       $511 million of undrawn credit                                                    Long-term notes                                              $1,109
                   capacity and liquidity, net of                                                    Long-term debt                                               $1,596
                   working capital, of $477 million                                                  Working Capital deficiency                                     $34
                                                                                                     Net Debt                                                     $1,630
• First long-term note maturity
                    C$548
  not until 2024   Undrawn

• Repurchased and cancelled
  US$106 million of 2024 long-                                                                                US$400
                                                                                                            Long-Term Notes Maturity Schedule (2) ($ millions)
  term notes in 2021

                                                                                                             Repurchased and
                                                                                                             cancelled in 2021    US$106

                                                                                                                                                         US$500
(1)   Balance sheet as at June 30, 2021. Revolving credit facilities mature April 2024 and are
      comprised of a US$575 million facility and a $300 million term loan facility. Revolving                 Principal amount
      credit facilities are not borrowing base facilities and do not require annual or semi-annual       outstanding as of July
                                                                                                                                  US$294
      reviews.                                                                                                            2021
(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”.                                                                    2021       2022     2023     2024     2025   2026   2027      2028

                                                                                                                                                                      13
Crude Oil Hedge Portfolio

                                                                                                                        Q3/2021                Q4/2021                 H2/2021                   2022
      WTI Fixed Hedges (1)
       Volumes (bbl/d)                                                                                                     4,000                  4,000                   4,000                 10,000
       Fixed Price (US$/bbl)                                                                                              $45.00                 $45.00                  $45.00                 $53.50
      WTI 3-Way Option                (2)

       Volumes (bbl/d)                                                                                                    17,500                 17,500                  17,500                 10,500

       Average Sold Put / Put / Sold Call (US$/bbl)                                                                    $35/$45/$52            $35/$45/$52            $35/$45/$52            $48/$58/$68

  Total Hedge Volumes (bbl/d)                                                                                               21,500                21,500                21,500                 20,500

  Hedge (%) (3)                                                                                                               45%                   45%                   45%                    42%

  Basis Differential Hedges
       WCS Volumes (bbl/d)                                                                                                 11,000                 11,000                 11,000                12,000
       WCS Price Relative to WTI (US$/bbl)                                                                                ($13.23)               ($13.23)              ($13.23)               ($12.40)
       MSW Volume (bbl/d)                                                                                                   7,500                  7,500                 7,500                  4,000
       MSW Price Relative to WTI (US$/bbl)                                                                                 ($5.03)                ($5.03)               ($5.03)                ($4.43)

(1)    WTI fixed hedges for 2022 include 10,000 bbl/d of swaptions where the counterparty has the right, if exercised on December 31, 2021, to enter into a swap transaction for the volumes and price indicated.
(2)    WTI 3-way options consist of a sold put, a bought put and a sold call. In a $48/$58/$68 example, Baytex receives WTI+$10/bbl when WTI is at or below $48/bbl; Baytex receives $58/bbl when WTI is
       between $48/bbl and $58/bbl; Baytex receives WTI when WTI is between $58/bbl and $68/bbl; and Baytex receives $68/bbl when WTI is above $68/bbl.
(3)    Percentage of hedged volumes are based on 2021 annual production guidance (excluding NGL), net of royalties

                                                                                                                                                                                                            14
2021E Adjusted Funds Flow Sensitivities

                                                   Estimated Effect on Annual Adjusted Funds Flow ($MM)
Sensitivities
                                                       Excluding Hedges             Including Hedges

Change of US$1.00/bbl WTI crude oil                          $22.7                       $13.0

Change of US$1.00/bbl WCS heavy oil differential              $7.1                        $3.2

Change of US$1.00/bbl MSW light oil differential              $6.9                        $4.2
Change of US$0.25/mcf NYMEX natural gas                       $8.7                        $5.0

Change of $0.01 in the C$/US$ exchange rate                   $5.1                        $5.1

                                                                                                          15
Asset Overview
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                                   30,400 boe/d                               17,800 boe/d                    23,800 boe/d            1,900 boe/d
      (Gross; H1 2021)

      Oil and NGLs                                              79%                                        90%                        91%                   82%
      (Gross; H1 2021)

  2P Reserves (1)                                    215 mmboe                                    85 mmboe                     123 mmboe               17 mmboe
          (Gross)

                              19,851 net acres in the                   419,615 net acres of        Dominant land position  148,480 net acres of
                               core of Karnes county                      land in the Viking play      of 672,640 net acres         100% W.I. lands in the
                               with outstanding                          Shallow, light oil, strong  Low decline production       Pembina area
                               operating partner,                         netback asset with           provides capital            Offset development and
                               Marathon.                                  “manufacturing”              allocation flexibility       9 wells drilled to-date
                              Stable production base                     development                 Innovative multi-lateral     have de-risked ~ 40% of
                               with low sustaining                       Technical                    horizontal drilling          acreage position
         Asset                 capital has driven ~                       advancements drive           generates top tier capital  Measured delineation
       Highlights              $923 million of asset                      productivity                 efficiencies                 planned
                               level free cash flow                       improvements
                               since 2016 (2)
                              Enhanced completions
                               continue to drive step
                               change in performance

(1)    Baytex reserves as at December 31, 2020 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.

                                                                                                                                                                17
Eagle Ford: Core of Karnes County

                                                                               •   19,900 net acres in the
                                                                                   core of the Eagle Ford
                                                                                   shale in south Texas
                   Wilson
                                                                               •   Four AMI’s (Longhorn,
                                                                                   Sugarloaf, Ipanema and
                                                                                   Excelsior) with average
                                                                                   25% W.I.
                                          Karnes
                                                                               •   H1/2021 production of
                                                       LONGHORN                    30,400 boe/d (79%
                                                                                   liquids)
  Atascosa

                                                                               •   H1/2021 - 62 gross (17.2
                                                   SUGARLOAF
                                                                                   net) wells established
                                                                                   average 30-day IP rates of
                                                           IPANEMA
                     EXCELSIOR                                                     ~ 1,600 boe/d per well

                                                                               •   Expect to bring ~ 22 net
                                                                                   wells on production in
                      Live Oak                                                     2021
                                                                         Bee

             Oil             Condensate                        Dry Gas

                                                                                                              18
Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory

                                                                                                                                            > 10 year drilling inventory (2)
        Asset Level Free Cash Flow (1) (C$ millions)                                                                               300                                                ~ 250 net
                                                                                                                                                                                       locations
                        $923 million cumulative asset level                                                                        250

                             free cash flow since 2016                                                                             200
                                                                                                                                   150
                                                                                                                                                        ~ 22
                                                                                                                                   100
                                                                                                        $124                                         net wells
                                                                                                                                    50             on- stream
                                                                                        $96
                                                                                                                                      0
                                                                                                                                                 2021 Program                 Remaining Undrilled
                                                                                                                                                                                  Inventory
                                                                    $238

                                                                                                                                                      Well Economics (3)

                                                  $285                                                                             WTI Oil Price                       $50/bbl                 $60/bbl
                                                                                                                                   Payout:                            0.9 years               0.6 years
                                                                                                                                   IRR:                                  101%                    203%
                                $138
                                                                                                                                   Recycle Ratio:                         3.2x                    4.0x
               $42
                                                                                                                                   Breakeven:
                                                                                                                                                                                 US$30/bbl
              2016              2017              2018              2019              2020           H1 2021                       (10% IRR)

(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 210 proved plus probable undeveloped reserves locations at year-end 2020 and 38 unbooked future locations. See “Advisories”
(3)   Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type curve that uses the following assumptions: well cost US$5 million (6,000 foot
      lateral); IP365 - 700 boe/d; EUR – 800 mboe).

                                                                                                                                                                                                              19
Viking Light Oil: 460 Highly Prospective Sections

                                                                                  •   Shallow (700 m), light oil
                                                                                      (36° API) resource play
                                                                                      with strong netbacks

                                                                                  •   Produced 17,800 boe/d
                                                                                      (90% oil) in H1/2021

                                                                                  •   Drilling activity resumed
                                                                                      in December with two
                                                                                      rigs mobilized
                                           Kerrobert
                                                                      Plenty
                    Esther/Hoosier

                                                       Greater Gleneath
                                                                                  •   Capital reduction effort
                                        Lucky Hills/Whiteside        Dodsland
                                                                                      and operational
                                                                                      efficiencies drive costs
                                                                                      down ~ 10%
                                     Mantario (Laporte)

                                                                          Plato
                                                                                  •   Expect to bring ~ 120 net
                                                                                      wells on production in
                                                                                      2021
   Baytex Lands

                                                                                                                 20
Technical Advancements Drive Productivity Improvement

  Shift to ERH(1) Wells Drives Productivity                                                                                            95%+ of Viking Development now
  Improvements                                                                                                                         ERH Wells
                                                                                                                                       400                                                           100%

                                                       Viking Wells by Vintage                                                         350
                                                                                                                                                                                                     90%

                         80                                                                                                                                                                          80%
                                                                                                                                       300
                                                                                                                                                                                                     70%
                         70                                                                                                            250
                                                                                                                                                                                                     60%
                         60                                                                                                            200                                                           50%
      Oil Rate (bbl/d)

                         50                                                                                                                                                                          40%
                                                                                                                                       150
                                                                                                                                                                                                     30%
                         40                                                                                                            100
                                                                                                                                                                                                     20%
                         30                                                                                                             50
                                                                                                                                                                                                     10%

                         20                                                                                                              0                                                           0%
                                                                                                                                             2012 2013 2014 2015 2016 2017 2018 2019 2020

                         10                                                                                                                     Net Wells Onstream (Left Axis)      ERH (%) (Right Axis)

                          0
                              -                5,000            10,000              15,000              20,000               25,000    Well Economics (2)
                                                                   Cum Oil (bbl)                                                         WTI Oil Price                 $50/bbl            $60/bbl

                                  2020 Wells       2019 Wells             2018 Wells              2017 Wells             2016 Wells      Payout:                      1.8 years          1.1 years

                                  2015 Wells       2014 Wells             2013 Wells             2012 Wells                              IRR:                            33%                 77%
                                                                                                                                         Recycle Ratio:                  1.5x                1.9x
(1)             Extended Reach Horizontal (“ERH) wells are ¾ to 1 mile long laterals drilled to a depth of approximately 700 metres.
(2)             Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type       Breakeven:
                                                                                                                                                                                 US$42/bbl
                curve that uses the following assumptions: well cost - $950,000; IP 365 - 50 boe/d; EUR - 40 mboe. MSW differential      (10% IRR)
                assumption US$4/bbl.

                                                                                                                                                                                                     21
Peace River: Innovative Multi-Lateral Development

                                                     Performance Drivers

                                                     • Produced 13,700 boe/d in
                                                       H1/2021 (86% oil)
                                  Golden             • Dominant 560 net sections
                                                     • Three net Bluesky multi-lateral
                                                       wells planned for H2/2021

                                           Seal      Peavine Lands
                        Harmon Valley
                                                     • Strategic agreements with
                                                       Peavine Métis Settlement cover
                                                       80 contiguous sections
                                                     • Early stage exploratory play
                                                       targeting Spirit River formation,
                                                       a Clearwater formation
                 Reno                                  equivalent
                                           Peavine   • Five net wells on production -
                                                       two successful appraisal wells
                                                       (2-laterals each); three
  Baytex Lands
                                                       additional wells (8-laterals each)
                                                       on production
                                                                                           22
Northwest Clearwater: Extending the Trend

                                                                                                 Peavine

                                                                                                 14-36 Pad
                                                                                                           7
                                                                  5-33 Pad                                 5
                                                                                  4                        6
                                                                                  1
                                                                                  2
                                                                                  3

•   > 500 net sections in the NW
    Clearwater fairway with > 120
    prospective for Spirit River
    (Clearwater equivalent)

•   Executed second strategic land
    agreement with the Peavine Métis
    Settlement; increased land position
    by a further 20 sections to 80
    contiguous sections                                                                                                                                30-Day IP Rate
                                                               Well                  Spud               Rig Release          # of Laterals                  (bbl/d) (1)
                                                1         100/04-34              January 7               January 15                      2                        175
•   Aligns strongly with our core               2         102/04-34                June 15                  June 21                      2                        175
    competencies with over a decade of          3         100/13-27                June 22                    July 6                     8                        695
    experience in heavy oil exploration         4         100/05-34                  July 8                  July 18                     8                        412
    and multi-lateral development               5         102/11-31                 July 20                August 4                      8                        930
                                                6         100/06-31                     Q4                        Q4                     8                           ---
                                                7         100/14-31                     Q4                        Q4                     8                           ---
                                          (1)   30-Day Initial Production Rate (bbl/d) is defined as the average oil rate over the first 720 hours of production   23
                                                following drilling fluid recovery.
Northwest Clearwater – Promising Early Results with Strong Economics

Operations Update                                   Top 10 Clearwater Wells (1)
 •   Five producing wells
                                                                                                                                    Peak Calendar Rate
                                                           No.                     UWI                    Current Operator
 •   Production increased from zero at the                                                                                              (bbl/day)
     beginning of the year to > 2,300 bbl/d                 1       102/11-31-078-15W5/00                      BAYTEX                        896
                                                            2       100/13-27-078-16W5/00                      BAYTEX                        844
 •   Two Baytex 8-lateral wells rank as the top
                                                            3       102/12-34-074-25W4/00                    HWX (CVE)                       733
     Clearwater wells drilled to-date; both are             4                                                HWX (CVE)                       670
                                                                    100/16-35-074-25W4/00
     outperforming Baytex type curve                        5       100/16-26-074-25W4/02                       HWX                          670
     assumptions                                            6       102/12-31-074-24W4/06                    HWX (CVE)                       634
                                                            7       100/13-34-074-25W4/00                    HWX (CVE)                       617
                                                            8       100/01-11-074-25W4/00                   DELTASTREAM                      589
Q4/2021 Activity                                            9       104/05-17-073-24W4/08                       CNRL                         584
                                                            10      102/01-14-074-25W4/00                   DELTASTREAM                      575
 •   Drilling two wells on the 14-36 pad adjacent
     to the highest rate well drilled to-date        Well Economics (2)
 •   Construction of access roads and surface
     pad locations for 2022 development activity          WTI Oil Price                     $50/bbl                $60/bbl
                                                          Payout:                         0.9 years              0.5 years
Preliminary 2022 Plan                                     IRR:                               108%                   335%
                                                          Recycle Ratio:                      2.2x                   3.4x
 •   Expect to execute an expanded program of
     12 to 18 wells in 2022                               Breakeven:
                                                                                                     US$33/bbl
                                                          (10% IRR)
 •   20 sections de-risked with potential for
     greater than 200 locations pending further     (1)    Public data obtained from GeoScout. Baytex well results represent an estimate of the calendar
     success                                               rate for the month of September.
                                                    (2)    Individual well economics based on constant pricing and costs, and Baytex’s assumptions
                                                           regarding an expected type curve that uses the following assumptions: development well cost -
                                                           $1.4 million; IP30 - 335 bbl/d, IP 365 - 180 bbl/d; EUR – 170 mboe; WCS differential assumption
                                                           US$12/bbl.

                                                                                                                                                       24
Lloydminster: Significant Land Position and Drilling Inventory

                                                          Performance Drivers

                                                          •   Produced 10,100 boe/d in
                                                              H1/2021 (98% oil)

                   Ardmore/Cold Lake                      •   Strong capital efficiencies

                                                          •   Applying multi-lateral
                                                              horizontal drilling and
                      Lindbergh
                                                              production techniques
                            Lloydminster    Tangleflags

                                                          •   ~ 22 net wells planned for
                                           Soda Lake
                                                              H2/2021

                                           Kerrobert

                        ALBERTA            SASKATCHEWAN

    Baytex Lands

                                                                                            25
Heavy Oil Innovation

Peace River                                                                                                                Lloydminster
Multi-Lateral Horizontal                                                                                                   Horizontal

  Well Economics (1)
      WTI Oil Price                    $50/bbl               $60/bbl                                                         WTI Oil Price                     $50/bbl                $60/bbl
      Payout:                        1.7 years              0.9 years                                                        Payout:                          1.4 years             0.9 years
      IRR:                               51%                  129%                                                           IRR:                                62%                   136%
      Recycle Ratio:                     2.5x                  3.8x                                                          Recycle Ratio:                      2.0x                   2.9x
      Breakeven:                                                                                                             Breakeven:
                                                US$42/bbl                                                                                                               US$42/bbl
      (10% IRR)                                                                                                              (10% IRR)

(1)     Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type curve that uses the following assumptions: Peace River (Bluesky development)
        well cost - $2.5 million; IP 365 - 215 boe/d; EUR – 300 mboe; Lloydminster well cost - $0.8 million ; IP 365 - 50 boe/d; EUR – 60 mboe. WCS differential assumption US$12/bbl.

                                                                                                                                                                                                     26
Pembina Area Duvernay Light Oil: Emerging Resource Play

                                                                                                           Pembina Duvernay
                                                                                                           •   232 sections of 100% WI lands

                                                                                                           •   Nine wells drilled to date have
                                                                                                               delineated a minimum of 100-
                                                                                                               125 sections

                                                                                                           •   Produced 1,900 boe/d (82%
                                                                                                               liquids) in H1/2021

                                                                                                           •   Two wells drilled in 2020
                                                                  Black Oil                                    demonstrate repeatability of 11-
                                                                                                               30 pad completed in 2019

                                                               Volatile
                                                                                                           •   10-16 generated a 30-day IP
                                            Liquids Rich Gas     Oil                                           rate of 1,300 boe/d (69% oil);
                                                                                                               11-16 generated a facility
                                                                                                               constrained 30-day IP rate of
                                                                                                               900 boe/d (68% oil)
 Baytex Lands

  Rimbey Leduc Reef
                                  Liquids                                                                  •   Two wells to be drilled and
                                 Rich Gas
                                                                                                               completed in Q3/2021
                      Producing Pads (7 wells)      Two wells (10-16, 11-16)   Two wells (06-08, 07-08)
                      pre-2020                      onstream November 2020     expected onstream Q3 2021

                                                                                                                                                 27
High Quality Oil Development

                                         Eagle Ford                 Viking               Peace River               Lloydminster               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

                                                                                                                 Horizontal slotted liner /
Completion                                     Plug and perf            Pin point coil Open hole multi-lateral    open-hole multi-lateral            Plug and perf

Expected Well Costs
(drill, complete, equip and tie-in)             US$5 million               $950,000               $2.5 million                  $800,000              $7.0 million
                                            6,000 foot lateral

Land - gross (net) sections                          122 (31)              763 (656)                562 (560)                   637 (491)              232 (232)
                                                                                                                                                    Pembina area

Reserves at YE 2020 (mmboe)
 Proved developed producing                               68                       22                      15                            8                      3
 Proved                                                  153                       57                      19                           25                      8
 Proved plus probable                                    215                       85                      39                           84                     17

Drilling inventory (risked) at
YE 2020 – net locations
(booked/unbooked)                                    210 / 38            1,268 / 443                 65 / 163                   173 / 417                 25 / 278

                                                                                                                                                               28
Environment, Social and Governance (ESG)
ESG at Baytex

As a responsible energy company, we take a sustainable approach to managing and
developing our business into the future. We aspire to create an organization that future
generations will be proud to be a part of.

                                                                                           30
How Focusing on ESG Creates Value

By incorporating
environmental, social
and governance
factors into our
business and reporting
on our performance,
we create value for
shareholders and
remain focused on
advancing a
responsible energy
future.

                                    31
Our ESG Targets

                  32
Supplementary Information
Summary of Operating and Financial Metrics

                                                     Q1 2019 Q2 2019 Q3 2019 Q4 2019                       2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020                         2020     Q1 2021       Q2 2021

Benchmark Prices
 WTI crude oil (US$/bbl)                               $54.90      $59.81      $56.45      $56.96       $57.03      $46.17      $27.85      $40.93      $42.66        $39.40       $57.84        $66.07
 NYMEX natural gas (US$/mcf)                            $3.15       $2.64       $2.23       $2.50        $2.63       $1.95       $1.72       $1.98       $2.66         $2.08        $2.69         $2.83

Production
 Crude oil (bbl/d)                                    71,939 69,905 68,541 70,956                       70,328      74,571      50,783      56,239      51,293        58,198       57,419        58,403
 Natural gas liquids (bbl/d)                          11,729 10,986    9,543   8,699                    10,229       7,822       7,634       7,417       6,495         7,340        6,238         7,563
 Natural gas (mcf/d)                                 104,682 105,065 101,054 100,236                   102,742      96,356      84,546      84,945      76,116        85,464       90,739        91,172
 Oil equivalent (boe/d) (1)                          101,115 98,402 94,927 96,360                       97,680      98,452      72,508      77,814      70,475        79,781       78,780        81,162
 % Liquids                                              83%     82%     82%     83%                       82%         83%         81%         82%         82%           82%          81%           81%

Netback ($/boe)
 Total sales, net of blending and other
 expenses (2)                                         $47.98      $51.49      $47.14      $48.25        $48.72      $35.19      $22.31      $33.79      $34.35       $31.75        $51.84        $57.19
 Royalties                                             (8.94)      (9.67)      (8.59)      (8.72)        (8.98)      (6.33)      (4.42)      (5.59)      (5.83)       (5.61)        (9.44)       (11.04)
 Operating expense                                    (11.02)     (11.22)     (11.15)     (11.23)       (11.16)     (11.66)     (11.17)     (10.26)     (12.30)      (11.35)       (11.36)       (11.22)
 Transportation expense                                (1.46)      (1.33)      (1.13)      (1.00)        (1.23)      (1.15)      (0.76)      (0.89)      (1.03)       (0.97)        (1.24)        (1.01)
 Operating Netback (4)                                $26.56      $29.27      $26.27      $27.30        $27.35      $16.05        $5.96     $17.05      $15.19       $13.82        $29.80        $33.92
 General and administrative                            (1.55)      (1.28)      (1.14)      (1.12)        (1.28)      (1.09)      (1.13)      (1.08)      (1.44)       (1.17)        (1.23)        (1.44)
 Cash financing and interest                           (3.10)      (3.14)      (3.06)      (2.75)        (3.01)      (3.19)      (4.15)      (3.55)      (3.89)       (3.65)        (3.44)        (3.19)
 Realized financial derivative gain (loss)               2.07        1.45        2.39        2.59          2.12        3.00        2.06      (1.36)        2.64         1.64        (2.93)        (5.28)
 Other (3)                                               0.28        0.07      (0.03)        0.16          0.13        0.07      (0.03)      (0.09)        0.17         0.03        (0.12)        (0.20)
 Adjusted funds flow (4)                              $24.26      $26.37      $24.43      $26.19        $25.31      $14.84        $2.71     $10.97      $12.67       $10.67        $22.08        $23.81

 (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 share based compensation. Refer to the Q2 2021 MD&A for further
       information on these amounts.
 (4)   The terms “operating netback” and “adjusted funds flow” 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
2021 Guidance and Cost Assumptions

Exploration and development expenditures ($ millions)      $285 - $315
Production (boe/d)                                      79,000 – 80,000
Expenses:

 Royalty rate (%)                                          18% - 18.5%

 Operating ($/boe)                                      $11.25 - $12.00
 Transportation ($/boe)                                   $1.15 - $1.25
 General and administrative ($ millions)                $42 ($1.45/boe)
 Interest ($ millions)                                  $95 ($3.27/boe)
Leasing expenditures ($ millions)                                   $4
Asset retirement obligations ($ millions)                           $6

                                                                          35
Contact Information

Baytex Energy Corp.            Edward D. LaFehr
                               President and Chief Executive Officer
Suite 2800, Centennial Place   587.952.3000
520 – 3rd Avenue S.W.
Calgary, Alberta T2P 0R3       Rodney D. Gray
T        587.952.3000          Executive Vice President & Chief Financial Officer
Toll Free 1.800.524.5521       587.952.3160

                               Brian G. Ector
www.baytexenergy.com           Vice President, Capital Markets
                               587.952.3237
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