Baytex Energy : Investor Presentation - August 2021

Investor

Presentation

August 2021

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 <70% of adjusted funds flow, optimize production in the 80,000 to 85,000 boe/d range, have capital efficiencies of $15,000 to $16,000, generate >$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 <1.5x and allow consideration of share buy-back, dividend and/or organic growth; for our 5-year plan: expected production from each of our assets and for each year expected average daily production, adjusted funds flow, adjusted funds flow per share, capital expenditures, free cash flow and ending net debt; for our 5-year plan expected free flow at certain WTI prices, our anticipated cumulative free cash flow, expected financial liquidity and net debt to EBITDA ratio at year end; the sensitivity of our expected 2021 adjusted funds flow to changes in WTI prices, WCS and MSW differentials, natural gas prices and the Canada-United States foreign exchange rate; for the Eagle Ford that enhanced completions continue to drive step change in performance, we expect to bring 22 net wells on production in 2021 and stable production and deep inventory drive asset level free cash flow; for the Viking that we have meaningful extended reach inventory, technical advancements drive productivity improvements, and we expect to bring ~120 wells online in 2021; in Heavy Oil, that low decline production provides capital allocation flexibility, innovative multi-lateral horizontal drilling generates strong capital efficiencies, 3 bluesky multilateral wells planned for H2/2021 in Peace River, >100 sections prospective for Sprit River (clearwater equivalent), 2021 plan includes up to 7 clearwater wells with 5 wells at Peavine; ~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 (excluding 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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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 July 28 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 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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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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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

Track Record of

Substantial Free Cash

Flow Generation

• Exploration and development expenditures represents 81% of adjusted funds flow over the last five years (2016 to 2020)
• Potential to deliver > $350 million ($0.62 per share) of free cash 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
Consistent Approach to	▪ Utilize financial derivative contracts and crude-by-rail to reduce the
	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

Committed to ESG	("ESG") objectives
▪ 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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