investor presentation - baytex energy

Investor Presentation

January 2021

2

Forward Looking Statements

Any “financial outlook” or “future oriented financial information” in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial 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; that approximately 50% of our net crude oil exposure that is hedged for 2021; that we have a consistent approach to risk management and are committed to strong ESG

performance; 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 we have an active hedge strategy to preserve adjusted funds flow; that our production base is ~75,000 boe/d; that we are

poised to deliver free cash flow at US$40-$45 WTI; that we expect to have positive free cash flow in H2 2020; are expected daily production rate for H2 2020; that our 2021 priorities are to invest

at sustaining capital levels of $335 to $275 million, deliver stable production of 73,000 to 77,000 boe/d and maximize free flow and focus on continued deleveraging; our 2021 free cash flow

profile at certain price assumption; that improved capital efficiencies and high graded inventory increase sustainability at lower prices; the number of economic drilling locations we have at

various oil prices and the expected capital efficiency of our capital spending in 2021; that our business will deliver free cash flow in a US$40-$45 WTI environment; that our 2021 capital program

is fully funded at US$36/bbl WTI, 90% will be directed to high netback light oil assets, will generate capital efficiencies of ~$12,000 and that we retain significant flexibility to implement a heavy oil

program in H2/2021 and further advance Pembina Duvernay; for 2021: our capital budget, our estimated boe/d production, the percentage of our production expected to be oil and NGLs, our

capital allocation plans by area and number of wells we expect to bring on stream; 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 18 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 and have additional EOR

potential and we are executing a 30 well drilling program in Q4/2020; in Heavy Oil, that low decline production provides capital allocation flexibility, innovative multi-lateral horizontal drilling

generates strong capital efficiencies and first activity on Peavine lands is planned for 2021; 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; that we are committed to corporate sustainability and the components of our GHG emissions reduction strategy; 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. In addition, information and statements

relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in

quantities predicted or estimated, and that they can be profitably produced in the future.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil

prices; well production rates and reserve volumes; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow under

credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for operating activities; the availability and cost of labour and other industry services; interest and

foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the ability to develop crude oil and natural gas properties in the manner

currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are

cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not

limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); availability and cost of gathering, processing and pipeline systems; failure to

comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks

associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our

properties and our ability to acquire reserves; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and

gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions or

Advisory

3

Advisory (Cont.)

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

incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring,

developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; alternatives to and changing

demand for petroleum products; risks associated with our use of information technology systems; risks associated with the ownership of our securities, including changes in market-based factors;

risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to

non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report

on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2019, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange

Commission and in our other public filings.

The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on

Baytex’s current and future operations and such information may not be appropriate for other purposes.

There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements. The future oriented financial information

and forward-looking statements are made as of January 4, 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 September 30, 2020 was $566.1 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.

“Interest coverage” is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a

trailing twelve month basis. Financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended September 30, 2020 was $105.2

million.

“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.

“Senior secured debt” is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at September 30, 2020, the Company's Senior

Secured Debt totaled $640.3 million which includes $624.8 million of principal amounts outstanding and $15.5 million of letters of credit.

4

Advisory (Cont.)

Advisory Regarding Oil and Gas Information

The reserves information contained in this presentation has been prepared in accordance with National Instrument 51-101 -Standards of Disclosure for Oil and Gas Activities of the Canadian

Securities Administrators ("NI 51-101"). The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of

proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of

reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been

satisfied. Knowledge of concepts, including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods, is required to properly use and apply reserves

definitions.

The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves and future production from

such reserves may be greater or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves

for all properties, due to the effects of aggregation. Complete NI 51-101 reserves disclosure for year-end 2019 is included in our Annual Information Form for the year ended December 31,

2019, which has been filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

This presentation discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex’s total proved, probable and unbooked locations. Proved

locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our

prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed

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

whether such wells will result in additional oil and gas reserves, resources or production. In the Eagle Ford, Baytex’s net drilling locations include 140 proved and 83 probable locations as at

December 31, 2019 and 52 unbooked locations. In the Viking, Baytex’s net drilling locations include 1,080 proved and 319 probable locations as at December 31, 2019 and 636 unbooked

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

drilling locations include 178 proved and 63 probable locations as at December 31, 2019 and 361 unbooked locations. In the Duvernay , Baytex’s net drilling locations include 11 proved and 10

probable locations as at December 31, 2019 and 295 unbooked locations.

References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not

determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging,

readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test

interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.

Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if

used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip

and does not represent a value equivalency at the wellhead.

Notice to United States Readers

The petroleum and natural gas reserves contained in this presentation have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all

respects to United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings

with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" (as defined in SEC rules). Canadian securities laws require oil and gas issuers

disclose their reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves". Additionally, NI 51-101 defines "proved reserves“

and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in this presentation may not be comparable to United States standards. Probable

reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves.

In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and

similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments.

Moreover, in this presentation future net revenue from its reserves has been determined and disclosed estimated using forecast prices and costs, whereas the SEC rules require that reserves

be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting

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

reporting and disclosure standards.

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

5

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

▪ Strong capital efficiencies and flexibility on discretionary capital

Investment Highlights

High Quality and

Diversified Oil Portfolio

Across Multiple Plays

Track Record of

Substantial Free Cash

Flow Generation

Consistent Approach to

Risk Management

Financial Liquidity and

No Near-Term Maturities

▪ Exploration and development expenditures represents 84% of adjusted funds flow over the last five years (2015 to 2019)

▪ Free cash flow of $329 million generated in 2019

▪ Credit facilities ~ 40% undrawn and liquidity > $300 million (1)

▪ First long-term note maturity is not until June 2024

▪ Proven commitment to environmental, social and governance (“ESG”) objectives

▪ Established target to reduce GHG emissions intensity by 30% by 2021

Committed to ESG

▪ Utilize financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow

▪ ~ 50% of net crude oil exposure hedged for 2021

(1) As at September 30, 2020.

6

EAGLE FORD

VIKING

LLOYDMINSTER

PEACE RIVER

DUVERNAY

(1) Average daily trading volumes for December 2020. Volumes are a composite of all exchanges in Canada.

(2) Enterprise value based on closing share price on the Toronto Stock Exchange on December 31, 2020 and shares outstanding and net debt as at September 30, 2020.

(3) Production, production mix, and exploration and development (“E&D”) expenditures represents 2021 guidance.

(4) Baytex reserves as at December 31, 2019 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 9 month 2020 actuals.

Production by

Core Area (5)

Heavy Oil

Light Oil

NGLs

Natural Gas

Corporate Profile

Market Summary

Ticker Symbol TSX: BTE

Average Daily Volume (1) 8.5 million (Canada)

Shares Outstanding (2) 561 million

Market Capitalization / Enterprise Value (2) $387 million / $2,294 million

Operating Statistics

Production (Gross W.I.) (3) 73,000 – 77,000 boe/d

Production Mix (3) 81% liquids

E&D Expenditures (3) $225 to $275 million

Reserves – 2P Gross (4) 529 mmboe

Heavy Oil

Light Oil

NGLs

Natural Gas

Eagle Ford

Viking

Heavy Oil

Other

Production by

Commodity (5)

Revenue by

Commodity (6)

7

ESG Highlights

GHG Emission Reduction Safety

15% reduction in GHG

emissions intensity in 2019;

target 30% by 2021

41% reduction in lost time

incident frequency in 5

years

Gas Conservation Indigenous Relations

99.5% routine gas

conservation in Peace River

in 2019

Recent agreements with

Woodland Cree First

Nation and Peavine Métis

Settlement

Spill Volumes Gender Diversity

42% reduction in spill

volumes over 5 years

> 20% women Board

members

8

Action 2020 Highlights

Negotiated bank credit facility

extension and refinanced long-term

notes

• Extended maturity of credit facilities to April 2024

• Issued US$500 million principal amount of long-term notes due April 2027

• Redeemed two series of senior unsecured notes - US$400 million due 2021 and $300 million due 2022

Dynamic response to oil price collapse

• Identified cost savings of ~$100 million, capital budget reduced by ~ 50%

• Maintained liquidity of > $300 million

• Maintained strong operating efficiency

• Active hedge strategy implemented to preserve adjusted funds flow

• Accessed available government assistance

High graded portfolio and economic

inventory

• Capital reduction has re-set production base to ~ 75,000 boe/d

• Improved capital efficiencies and moderated production decline rate

• Poised to deliver free cash flow in a US$40 to $45/bbl WTI environment

Established Covid-19 task force and

flexible working team

• Effective response to Covid-19 with on-going training, communication and work strategies

2020 Highlights

We have re-set our business in the face of extremely volatile crude oil markets

9

H1 2020 H2 2020 (implied)

2020 Capital and Production

Capex reduction

expected to lead to

positive free cashflow in

H2 2020

2020 Capital Spending ($ millions)

Annual Guidance $260-$290

$187

$88

2020 Production (boe/d)

Annual Guidance ~ 80,000

H1 2020 H2 2020 (implied)

85,500

74,500

Production base re-set following

limited investment

Capital outlays minimized to preserve financial liquidity

(1) H2 2020 implied represents to the mid-point of annual guidance range.

10

2021 Priorities and Free Cash Flow Profile

(1) For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary.

(2) Pricing assumptions: WCS differential - US$13.50/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$2.75/mcf; AECO Gas - $2.75/mcf; Exchange Rate (CAD/USD) - 1.32.

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

US$40 US$45 US$50

$ m

illio

ns

Adjusted Funds Flow Capital Spending Free Cash Flow

Free Cash Flow Profile (1) (2)

Invest at sustaining capital levels

of $225 to $275 million

Deliver stable production of

73,000 to 77,000 boe/d

Maximize free cash flow and focus

on continued de-leveraging

2021 Priorities

11

High Graded Portfolio with Strong Capital Efficiencies

Improved capital efficiencies and high graded inventory increases sustainability at lower prices

(1) Economic drilling locations are defined as individual well locations generating an internal rate of return of > 20% and a payout of < 24 months under flat WTI pricing assumptions. Economic drilling locations include both booked and

un-booked locations, see slide 4 for a description of our booked and un-booked locations as at December 31, 2019.

(2) See advisory for definitions of Non-GAAP Financial and Capital Management Measures on page 3 of this presentation.

Capital Efficiency (2)Economic Drilling Locations (1)

0

500

1,000

1,500

2,000

2,500

3,000

US$40 US$45 US$50 US$55

Net W

ells

EagleFord Viking Heavy Oil Duvernay

$17,000per boe/d

$12,000per boe/d

2020 Budget 2021 Budget

12

2021 Capital Program

2021 Guidance (1)

E&D CapEx $225 - 275 million

Production 73,000 - 77,000 boe/d

Oil and NGLs 81%

We have reset our business to deliver free cash flow in a US$40 to US$45 WTI environment

• Cash neutrality (capital program fully funded) at US$35/bbl WTI

• 85% directed to our high netback light oil assets in the Eagle Ford and Viking

• Capital efficiencies of approximately $12,000 per boe/d across the portfolio

• Retain significant flexibility to implement a heavy oil program in H2/2021 and further advance our Pembina Duvernay development

Operating Area

Net Wells

Onstream CapEx ($MM) (2)

Viking 120 $110

Eagle Ford 18 $100

Heavy Oil 28 $25

East Duvernay 2 $15

Total $250

(1) 2021 capital spending is approximately 50% weighted to the first half of the year. Eagle Ford

development includes 10 net wells drilled and 18 net wells on production. Heavy oil (up to 36

net wells) and Duvernay (up to 4 net wells) are scheduled for H2/2021 and dependent on

crude oil prices.

(2) Represents mid-point of 2021 guidance range.

Capital Budget CapEx ($MM) (2)

Drill, complete and equip $235

Facilities $10

Land and seismic $5

Total $250

13

Financial Liquidity

C$548

Undrawn

C$300US$400

US$400

(1) Balance sheet as at September 30, 2020. Revolving credit facilities mature April 2024

and are comprised of a US$575 million facility and a $300 million term loan facility.

Revolving credit facilities are not borrowing base facilities and do not require annual or

semi-annual reviews.

(2) S&P corporate rating “B” and senior unsecured debt rating “B+” ; Fitch corporate rating

and senior unsecured debt rating “B”; Moody’s corporate rating “B2” and senior

unsecured debt rating “B3”.

(3) See advisory for definitions of Non-GAAP Financial and Capital Management Measures

on page 3 of this presentation.

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

• Credit Facilities ~ 40% Undrawn

• $426 million of undrawn credit capacity and liquidity, net of working capital, of $344 million

• Enhanced long-term note maturity profile

• First long-term note maturity not until 2024

• Strong compliance with financial covenants

• Expect to remain onside with financial covenants and maintain liquidity

Balance Sheet (1) $ millions

Credit facilities $625

Long-term notes $1,199

Long-term debt $1,824

Working Capital deficiency $82

Net Debt $1,907

2020 2021 2022 2023 2024 2025 2026 2027

US$500

Financial Covenants (3) Position as at

September 30, 2020Covenant

Senior Secured Debt to

Bank EBITDA (maximum

ratio)

1.1:1.00 3.50:1.00

Interest Coverage

(minimum ratio)5.4:1.00 2.00:1.00

14

(1) WTI 3-way options consist of a sold put, a bought put and a sold call. In a $35/$45/$52 example, Baytex receives WTI+$10/bbl when WTI is at or below $35/bbl; Baytex receives $45/bbl when WTI is

between $35/bbl and $45/bbl; Baytex receives WTI when WTI is between $45/bbl and $52/bbl; and Baytex receives $52/bbl when WTI is above $52/bbl.

(2) Percentage of hedged volumes are based on 2021 annual production guidance (excluding NGL), net of royalties

Crude Oil Hedge Portfolio

Q4/2020 H1/2021 H2/2021Full-Year

2021

WTI Fixed Hedges

Volumes (bbl/d) 8,000 4,000 4,000 4,000

Fixed Price (US$/bbl) $42.78 $45.00 $45.00 $45.00

WTI 3-Way Option

Volumes (bbl/d) 24,500 17,500 17,500 17,500

Average Sold Put / Put / Sold Call (US$/bbl) (1) $50/$58/$63 $35/$45/$52 $35/$45/$52 $35/$45/$52

Total Hedge Volumes (bbl/d) 32,500 21,500 21,500 21,500

Basis Differential Hedges

WCS Volumes (bbl/d) 6,500 11,000 9,000 10,000

WCS Price Relative to WTI (US$/bbl) ($16.27) ($13.60) ($13.57) ($13.59)

MSW Volume (bbl/d) 5,000 6,000 6,000 6,000

MSW Price Relative to WTI (US$/bbl) ($6.15) ($5.17) ($5.17) ($5.17)

Hedge (%) (2) 70% 48% 48% 48%

15

2021E Adjusted Funds Flow Sensitivities

Sensitivities

Estimated Effect on Annual Adjusted Funds Flow ($MM) (1)

Excluding Hedges

Including

Hedges when

WTI is between

US$35/bbl and

US$45/bbl

Including

Hedges when

WTI is between

US$45/bbl and

US$52/bbl

Change of US$1.00/bbl WTI crude oil $22.7 $12.8 $20.7

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

Change of US$1.00/bbl MSW light oil differential $6.9 $4.2 $4.2

Change of US$0.25/mcf NYMEX natural gas $8.7 $5.0 $5.0

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

Asset Overview

17

Asset Highlights

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

Eagle Ford Viking Heavy Oil Pembina Duvernay

Production(Gross; Q3 2020)

28,650 boe/d 18,774 boe/d 24,791 boe/d 1,474 boe/d

Oil and NGLs(Gross; Q3 2020)

77% 91% 89% 79%

2P Reserves (1)

(Gross)229 mmboe 98 mmboe 103 mmboe 14 mmboe

Asset

Highlights

▪ 19,851 net acres in the core of Karnes county with world class partner, and operator in Marathon

▪ Stable production base with low sustaining capital has driven ~$787 million of asset level free cash flow since 2016 (2)

▪ Enhanced completions continue to drive step change in performance

▪ 419,615 net acres of land in the Viking play

▪ Shallow, light oil, strong netback asset with “manufacturing” development

▪ $83 million of asset level free cash flow in 2019 (2)

▪ Meaningful extended reach inventory (~ 10 years) and additional EOR potential

▪ Dominant land position of 672,640 net acres

▪ Low decline production provides capital allocation flexibility

▪ Innovative multi-lateral horizontal drilling generates top tier capital efficiencies

▪ 148,480 acres of 100% W.I. lands in the Pembina area

▪ Offset development and 9 wells drilled to-date have delineated ~ 40% of acreage position

▪ Measured delineation planned

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

(2) The term “asset level free cash flow” is a non-GAAP measure. See slide 3 for more information.

18

Eagle Ford: Core of Karnes County

LONGHORN

Wilson

Atascosa

Karnes

Live Oak

EXCELSIOR

SUGARLOAF

IPANEMA

Bee

Oil Condensate Dry Gas

• 19,900 net acres in the

core of the Eagle Ford

shale in south Texas

• Four AMI’s (Longhorn,

Sugarloaf, Ipanema and

Excelsior) with average

25% W.I.

• Q3/2020 production of

28,650 boe/d (77%

liquids)

• YTD 2020 - 53 gross (11.5

net) wells established

average 30-day IP rates of

~ 1,750 boe/d per well

• Expect to bring ~ 18 net

wells on production in

2021

19

$42

$138

$285

$238

$84

2016 2017 2018 2019 9 Mths 2020

Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory

0

50

100

150

200

250

300

2021 Program Remaining UndrilledInventory

> 10 year drilling inventory (2)

~ 18

net wells

on- stream

> 250 net locations

(1) Asset level free cash flow represents field level operating netback less exploration and development capital. For illustrative purposes only and should not be relied upon as indicative of future results.

Baytex’s actual results may vary.

(2) Net locations includes 223 proved plus probable undeveloped reserves locations at year-end 2019 and 52 unbooked future locations. See “Advisories”

(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).

Asset Level Free Cash Flow (1) (C$ millions)

$787MM cumulative asset level free cash flow

since 2016

WTI Oil Price $45/bbl $50/bbl

Payout: 1.3 years 0.9 years

IRR: 72% 106%

Recycle Ratio: 2.8x 3.2x

Breakeven:

(10% IRR)US$30/bbl

Well Economics (3)

20

Viking Light Oil: 460 Highly Prospective Sections

Baytex Lands

Esther/Hoosier

Kerrobert

Plenty

Greater Gleneath

Lucky Hills/Whiteside Dodsland

Mantario (Laporte)

Plato

• Shallow (700 m), light oil

(36° API) resource play

with strong netbacks

• Produced 18,800 boe/d

(91% oil) in Q3/2020

• Added 229 net unbooked

drilling opportunities in

2019 through multiple

deals and asset swaps

• Q1/2020 saw an active

pace of development

with 4 drilling rigs and 2

frac crews running

• Executing 30-well drilling

program in Q4/2020

21

Technical Advancements Drive Productivity Improvement

Viking Wells by Vintage

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

50

100

150

200

250

300

350

400

2012 2013 2014 2015 2016 2017 2018 2019 2020

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

Shift to ERH(1) Wells Drives Productivity

Improvements

95%+ of Viking Development now

ERH Wells

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

(2) 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 - $950,000; IP 365 - 50 boe/d; EUR - 40 mboe. MSW differential

assumption US$5/bbl.

Well Economics (2)



IRR: 18% 36%


Breakeven:

(10% IRR)US$42/bbl

0

10

20

30

40

50

60

70

80

- 5,000 10,000 15,000 20,000 25,000

Oil R

ate

(b

bl/d

)

Cum Oil (bbl)

2020 Wells 2019 Wells 2018 Wells 2017 Wells 2016 Wells

2015 Wells 2014 Wells 2013 Wells 2012 Wells

22

Peace River: Innovative Multi-Lateral Development

Performance Drivers

• Produced 12,100 boe/d in

Q3/2020 (80% oil)

• Dominant 560 net sections

• Strong capital efficiencies

Baytex Lands

Seal

Harmon Valley

Reno

Golden

Peavine

Peavine Lands

• Q1/2020 strategic agreement

with Peavine Metis settlement

• 60 sections of land

• Early stage exploratory play

targeting Spirit River formation,

a Clearwater formation

equivalent

• First activity planned for 2021

23

Lloydminster: Significant Land Position and Drilling Inventory

Performance Drivers

• Produced 12,700 boe/d in

Q3/2020 (98% oil)

• Strong capital efficiencies

• Applying multi-lateral

horizontal drilling and

production techniques

• Ramp-up of Kerrobert

thermal project occurred in

Q4/2019 with peak

production of ~ 3,500 bbl/d

Baytex Lands

ALBERTA SASKATCHEWAN

Kerrobert

Lloydminster

Soda Lake

Tangleflags

Ardmore/Cold Lake

Lindbergh

24

Heavy Oil Innovation

Peace River

Multi-Lateral Horizontal

Lloydminster

Horizontal

Well Economics (1)



IRR: 31% 61%


Breakeven:

(10% IRR)US$42/bbl



IRR: 22% 48%


Breakeven:

(10% IRR)US$43/bbl

(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 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$13.50/bbl.

25

Pembina Area Duvernay Light Oil: Emerging Resource Play

Baytex Lands

Pembina Duvernay

• 232 sections of 100% WI lands

• Nine wells drilled to date have

delineated a minimum of 100-

125 sections

• Produced 1,500 boe/d (79%

liquids) in Q3/2020

• Two wells on-stream in 2019

generated average 30-day IP

rate of ~ 1,050 boe/d (75%

liquids)

• Two wells drilled in Q1/2020

fracture stimulated in October;

initial flow back rates are very

encouraging - first well (10-16)

on-stream November 2; second

well (11-16) on-stream

November 17

Producing Pads (7 wells)

Rimbey Leduc Reef

Liquids Rich Gas

Liquids

Rich Gas

Volatile

Oil

Black Oil

2020 Drills (2 wells)

26

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

Formation Lower Eagle Ford Viking Bluesky Mannville Group Duvernay

Upper Eagle Ford

Austin Chalk

Depth (metres) 3,300-3,900 700 600 350-800 2,200-2,400

Oil API Oil: 40-45° 36° 11° 10-16° 42-44°

Condensate: 44-55°

Porosity 4.6% - 9% 23% 28% 30% 3% - 6%

Permeability 0.33 - 0.41 millidarcies 0.5 - 50 millidarcies 1 - 5 darcies 0.5 - 5 darcies 10 nanodarcy

Completion Plug and perf Pin point coil Open hole multi-lateral

Horizontal slotted liner /

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 2019 (mmboe)

Proved developed producing 71 29 21 13 2

Proved 163 65 32 28 7

Proved plus probable 229 98 59 44 14

Drilling inventory (risked) – net

locations (booked/unbooked) 223 / 52 1,399 / 636 152 / 100 241 / 361 21 / 295

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

High Quality Oil Development

Corporate Sustainability

28

Corporate Sustainability

At Baytex, we believe that commitment to corporate responsibility is just as important as

delivering financial and operational targets. We publish a biennial Corporate Sustainability

Report which provides transparent reporting and clear goals on the topics that matter:

Safety Environment

Communities and

StakeholdersBusiness Practice

and Compliance

For more information and to view our most recent report, visit

http://www.baytexenergy.com

Commitment to the health

and safety of our

employees, contractors and

communities.

Commitment to

minimizing our impact on

air, water, land and life in

the areas we operate.

Commitment to provide social

and economic benefits to the

communities in which we

operate and to hear the

voices and concerns of our

stakeholders.

Commitment to

governance, ethical

business conduct, and

regulatory compliance.

Baytex was recognized by Corporate Knights in 2018 as one of Canada’s

Top Sustainability Performers.

29

GHG Emissions Reduction

Target to reduce GHG emission

intensity (tonnes of CO2 per boe)

by 30% by 2021.

Our emissions reduction strategy

includes:

• Increased gas conservation

• Reusing associated gas as fuel

for field activities

• Increased combustion and

reduced emissions from storage

tanks

• Monitoring and preventing

fugitive emissions

0.112 0.095 0.08 0.07 -

0.040

0.080

0.120

Baseline 2018 2019A 2020E Target 2021

Tonnes o

f C

O2

per

boe

30%reduction

from baseline

GHG Intensity Target

30

A Culture of Commitment

Objective What we’ve done ResultHow it contributes to

value creation

EN

VIR

ON

ME

NT

Responsibly develop

our assets

Ensure our employees and

contractors uphold our procedures

for spill prevention, response and

cleanup

42% reduction in corporate spill

volumes, over 5 yearsReduces costs and maintains

social license

Exceed regulatory

obligations

Invested more than $100 million in

gas conservation activities in Peace

River in the last 5 years

99.5% routine gas conservation in

Peace River in 2019Helps to build trust with

regulators and stakeholders

SO

CIA

L

Create a culture of

safety

Tie safety targets to annual

performance incentive program

41% reduction in employee

+contractor LTIF in 5 years

Supports the consistent and

safe execution of our business

plan

Be a good neighbour

Build mutually beneficial

relationships based on trust

Entered into support and

development agreement with the

Peavine Métis Settlement in 2020

Maintain social license and

enables growth in our

operations by reducing non-

technical project delays

GO

VE

RN

AN

CE Ensure effective

Board leadership

Ensure our Board is comprised of

dedicated Directors who are

invested in our success

100% Board meeting attendance

and

25% women Board members as

of Sep. 2019

Sets strategic direction and

improves decision making

Be transparent and

accountable

Communicate our ESG impacts by

publishing biennial sustainability

reports since 2012

Recognized by Corporate Knights

as Future 40 Responsible

Corporate Leaders in 2018

Enables shareholders and

stakeholders to make informed

decisions

Supplementary Information

32

Summary of Operating and Financial Metrics

Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020

Benchmark Prices

WTI crude oil (US$/bbl) $62.87 $67.88 $69.50 $58.81 $64.77 $54.90 $59.81 $56.45 $56.96 $57.03 $46.17 $27.85 $40.93

NYMEX natural gas (US$/mcf) $3.00 $2.80 $2.90 $3.64 $3.09 $3.15 $2.64 $2.23 $2.50 $2.63 $1.95 $1.72 $1.98

Production

Crude oil (bbl/d) 45,835 46,644 56,767 71,326 55,218 71,939 69,905 68,541 70,956 70,328 74,571 50,783 56,239

Natural gas liquids (bbl/d) 9,143 9,419 10,076 10,327 9,745 11,729 10,986 9,543 8,699 10,229 7,822 7,634 7,417

Natural gas (mcf/d) 87,261 87,605 93,414 103,424 92,971 104,682 105,065 101,054 100,236 102,742 96,356 84,546 84,945

Oil equivalent (boe/d) (1) 69,522 70,664 82,412 98,890 80,458 101,115 98,402 94,927 96,360 97,680 98,452 72,508 77,814

% Liquids 79% 79% 81% 83% 81% 83% 82% 82% 83% 82% 83% 81% 82%

Netback ($/boe)

Total sales, net of blending and other

expenses (2) $42.96 $51.22 $55.03 $37.89 $46.31 $47.98 $51.49 $47.14 $48.25 $48.72 $35.19 $22.31 $33.79

Royalties (10.36) (12.01) (12.13) (8.77) (10.68) (8.94) (9.67) (8.59) (8.72) (8.98) (6.33) (4.42) (5.59)

Operating expense (10.53) (10.91) (10.25) (10.76) (10.61) (11.02) (11.22) (11.15) (11.23) (11.16) (11.66) (11.17) (10.26)

Transportation expense (1.36) (1.22) (1.26) (1.21) (1.26) (1.46) (1.33) (1.13) (1.00) (1.23) (1.15) (0.76) (0.89)

Operating Netback (4) $20.71 $27.08 $31.39 $17.15 $23.76 $26.56 $29.27 $26.27 $27.30 $27.35 $16.05 $5.96 $17.05

General and administrative (1.76) (1.64) (1.34) (1.55) (1.56) (1.55) (1.28) (1.14) (1.12) (1.28) (1.09) (1.13) (1.08)

Cash financing and interest (3.92) (3.97) (3.47) (3.07) (3.55) (3.10) (3.14) (3.06) (2.75) (3.01) (3.19) (4.15) (3.55)

Realized financial derivative gain (loss) (1.57) (4.57) (4.07) (0.34) (2.49) 2.07 1.45 2.39 2.59 2.12 3.00 2.06 (1.36)

Other (3) 0.01 (0.31) 0.07 (0.02) (0.05) 0.28 0.07 (0.03) 0.16 0.13 0.07 (0.03) (0.09)

Adjusted funds flow (4) $13.47 $16.59 $22.58 $12.17 $16.11 $24.26 $26.37 $24.43 $26.19 $25.31 $14.84 $2.71 $10.97

(1) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly

if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does

not represent a value equivalency at the wellhead.

(2) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the

realized pricing on our produced volumes to the WCS benchmark.

(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q3/2020 MD&A for

further information on these amounts.

(4) The terms “adjusted funds flow” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be

comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures on slide 3 of this presentation.

33

Reserves Summary (Gross)

Category (1) Eagle Ford Viking Heavy OilPembina

DuvernayOther Total

Proved Developed Producing 71 29 34 2 6 142

Total Proved 163 65 68 7 11 314

Total Proved Plus Probable 229 98 163 14 25 529

2P Reserves by Asset2P Reserves Breakdown 2P Reserves by Commodity

Light Oil + NGLHeavy

Oil

Natural Gas

Probable

PDNP + PUD

PDP

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

Eagle Ford

Viking

Heavy Oil

PembinaDuvernay

Other

34

2021 Guidance and Cost Assumptions

Exploration and development expenditures ($ millions) $225 - $275

Production (boe/d) 73,000 – 77,000

Expenses:

Royalty rate (%) 18% - 18.5%

Operating ($/boe) $11.50 - $12.25

Transportation ($/boe) $1.00 - $1.10

General and administrative ($ millions) $42 ($1.53/boe)

Interest ($ millions) $105 ($3.84/boe)

Leasing expenditures ($ millions) $4

Asset retirement obligations ($ millions) $6

35

Notes

Edward D. LaFehrPresident and Chief Executive Officer

587.952.3000

Rodney D. GrayExecutive Vice President and Chief Financial Officer

587.952.3160

Brian G. EctorVice President, Capital Markets

587.952.3237

Baytex Energy Corp.

Suite 2800, Centennial Place

520 – 3rd Avenue S.W.

Calgary, Alberta T2P 0R3

T 587.952.3000

Toll Free 1.800.524.5521

www.baytexenergy.com

Contact Information

investor presentation - baytex energy

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