Investor Presentation

April 2020

2

Forward Looking Statements

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

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 inventory in core areas, strong capital efficiencies and flexibility on

discretionary capital; the percentage of our net crude oil exposure that is hedged; that we have a consistent approach to risk management and are committed to strong ESG performance; our

GHG emissions intensity reduction target; expectations for 2020 as to Baytex’s production on a boe/d basis , production mix, exploration and development expenditures, production by area

and commodity; our 2020 outlook, including: that our capital program is designed to preserve financial liquidity, the amount of production we will shut-in, planned net wells and exploration and

development expenditures by operating area; the percentage of Baytex’s net exposure to oil prices that is hedged for Q1 and full year 2020; the sensitivity of our expected 2020 adjusted funds

flow to changes in WTI prices, WCS and MSW differentials, natural gas prices and the Canada-United States foreign exchange rate; that crude by rail is an effective tool for managing

differential exposure and provides greater operating netback certainty; our estimated crude oil and NGL sales portfolio for 2020 and our estimated 2020 WTI, WCS and MSW prices and Baytex

price realizations; for the Eagle Ford that enhanced completions continue to drive step change in performance; for the Viking that we have a steady pace of development in Q1/2020; in Peace

River and Lloydminster, that low decline production provides capital allocation flexibility, that innovative multi-lateral horizontal drilling generates strong capital efficiencies; for the East

Duvernay that we have measured delineation planned; the expected drilling and completion well costs, reserves and drilling inventory for our Eagle Ford, Peace River, Lloydminster, Viking and

East Duvernay assets; that we are committed to corporate sustainability and the components of our GHG emissions reduction strategy; and our revised 2020 guidance for exploration and

development expenditures, production, royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures and asset retirement obligations. In

addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that

the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future. In addition, information and statements relating to reserves are deemed

to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and

that they can be profitably produced in the future.

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

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

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

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

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

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

Advisory

3

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); 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 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 March 18, 2020 and Baytex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result

of new information, future events or results or otherwise, other than as required by applicable securities laws.

Non-GAAP Financial and Capital Management Measures

This presentation contains certain financial measures that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered

non-GAAP measures. These non-GAAP measures may not be comparable to similar measures presented by other issuers. The following terms are not recognized measures under IFRS, but

are presented in this presentation.

“Adjusted funds flow” is defined as cash flow from operating activities adjusted for changes in non-cash operating working capital, asset retirement obligations settled and transaction costs.

Management of Baytex consider adjusted funds flow a key measure of performance as it demonstrates the combined entity’s ability to generate the cash flow necessary to fund capital

investments, debt repayment, settlement of abandonment obligations and potential future dividends. In addition, the ratio of net debt to adjusted funds flow is used to manage Baytex’s capital

structure.

“Asset Level Free Cash Flow” is defined as field level operating netback less exploration and development expenditures.

“Capital Efficiency” is defined as the cost to drill, complete, equip and tie-in a well divided by the initial production rate of the well on a boe basis over its initial 365 days of production.

“Exploration and development expenditures” is defined as expenditures related to drilling, completing and equipping, facilities, land, seismic and other. Exploration and development

expenditures includes additions to exploration and evaluation assets along with additions to oil and gas properties.

“Free cash flow” is defined as adjusted funds flow less exploration and development expenditures, payments on lease obligations and asset retirement obligations settled.

“Net debt” is defined as the sum of monetary working capital (which is current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the

long-term notes of Baytex and the bank loans of Baytex. Management of Baytex believe that net debt assists in providing a more complete understanding of Baytex’s cash liabilities.

“Operating netback” is defined as petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense divided by barrels of oil

equivalent sales volume for the applicable period. Management of Baytex believe that operating netback assists in characterizing Baytex’s ability to generate cash margin on a unit of

production basis.

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 ~ 33% undrawn and liquidity of ~ $300 million (1)

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

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

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

Committed to Strong

ESG Performance

▪ ~ 53% of net crude oil exposure hedged for 2020, largely utilizing a 3-way option structure

▪ WTI hedge contracts - mark-to-market value of ~ $110 million (2)

(1) Undrawn credit facilities and liquidity position as at December 31, 2019 and pro forma the issuance of a US$500 million note

due 2027 (closed February 5, 2020) and the redemption of a US$400 million note due 2021 (occurred February 20, 2020) and a

$300 million note due 2022 (occurred March 6, 2020).

(2) As at March 17, 2020.

6

EAGLE FORD

VIKING

LLOYDMINSTER

PEACE RIVER

DUVERNAY

(1) Average daily trading volumes for March 2020. Volumes are a composite of all exchanges in Canada and the U.S.

(2) Enterprise value based on closing share price on the Toronto Stock Exchange on March 31, 2020 and shares outstanding and net debt as at December 31, 2019.

(3) Production, production mix, and exploration and development (“E&D”) expenditures represents 2020 guidance.

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

(5) Production (Gross W.I.) composition based on 2020 guidance. Heavy oil includes Peace River and Lloydminster.

(6) Revenue by commodity composition based on 2019 actuals.

Production by

Core Area (5)

Heavy Oil

Light Oil

NGLs

Natural Gas

Corporate Profile

Market Summary

Ticker Symbol TSX / NYSE: BTE

Average Daily Volume (1) CAN: 15.4 million / US: 2.6 million

Shares Outstanding (2) 558 million

Market Capitalization / Enterprise Value (2) $187 million / $2,074 million

Operating Statistics

Production (Gross W.I.) (3) 85,000 - 89,000 boe/d

Production Mix (3) 83% liquids

E&D Expenditures (3) $260 to $290 million

Reserves – 2P Gross (4) 529 mmboe

Heavy Oil

Light Oil

NGLs

Natural Gas

Eagle Ford

Viking

Heavy Oil

Other

Production by

Commodity (5)

Revenue by

Commodity (6)

7

ESG Highlights

GHG Emission Reduction Safety

Established target to

reduce GHG emissions

intensity by 30% by 2021

55% reduction in lost

time incident frequency

in 5 years

Gas Conservation Indigenous Relations

99.1% routine gas

conservation in Peace

River

$32 million in contracts

awarded in 2017-2018

Spill Volumes Gender Diversity

76% reduction in spill

volumes over 5 years

25% women Board

members

8

▪ Exploration and development expenditures of $552 million, which is the low end of original guidance

▪ Generated production of 97,680 boe/d, exceeding the high end of original guidance

2019 Highlights

Delivered on our

Operating Plan

Generated Free

Cash Flow

Sustainability

Improved our

Financial Position

▪ Free cash flow of $329 million generated in 2019

▪ Eagle Ford, Viking and Heavy Oil all generated positive asset level free cash flow

▪ Net debt reduced by 17% ($393 million) in 2019

▪ Redeemed US$150 million of notes in September 2019 that were not due until 2021

▪ Shareholder outreach program

▪ Published fourth corporate sustainability report

▪ Established GHG emission reduction target of 30%

Committed to Strong

ESG Performance

▪ PDP reserves increased 5% to 142 mmboe

▪ Replaced 112% of production from development activities

▪ Delivered strong F&D and recycle ratios (PDP - $13.04/boe, 2.3x)

9

2020 Outlook

2020 Guidance (1)

E&D CapEx $260 - 290 million

Production 85,000 - 89,000 boe/d

Oil and NGLs 83%

Revised capital program designed to preserve financial liquidity

• 50% reduction in capital spending announced on March 18

• Drilling operations in Canada have been suspended. We will forgo drilling 43 net heavy oil wells and 151 net light oil wells over the balance of 2020

• Expect a moderated pace of activity in the Eagle Ford with 16-18 net wells brought on production (previously 22 net wells)

• Proactively shutting-in approximately ~ 3,500 boe/d of heavy oil production in order optimize the value of our resource base

Operating Area Net Wells CapEx ($MM) (2)

Eagle Ford 17 $135

Viking 69 $80

Heavy Oil 33 $50

East Duvernay 2 $10

Total $275

(1) We have the operational flexibility to adjust spending plans based on changes in commodity prices.

(2) Represents mid-point of 2020 guidance range.

10

Balance Sheet and Liquidity

C$548

Undrawn

C$300US$400 US$400

(1) Balance sheet and long-term notes maturity schedule as at December 31,

2019 and pro forma the issuance of a US$500 million note due 2027 (closed

February 5, 2020) and the redemption of a US$400 million note due 2021

(occurred February 20, 2020) and a $300 million note due 2022 (occurred

March 6, 2020).

(2) Revolving credit facilities mature April 2024 and are comprised of a US$575

million facility and a $300 million term loan facility.

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

corporate rating “B+” and senior unsecured debt rating “BB-”; Moody’s

corporate rating “B2” and senior unsecured debt rating “B3”.

(4) Net debt to adjusted funds flow ratio based on trailing 12-month adjusted

funds flow.

Long-Term Notes Maturity Schedule (1)(3) ($ millions)

• Strong financial liquidity

• Credit facilities ~ one-third undrawn

• ~ $300 million of liquidity

• Enhanced maturity profile with first long-term note maturity not until 2024

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

Balance Sheet (1) $ millions

Bank loan (2) $692

Long-term notes (3) $1,167

Long-term debt $1,859

Working Capital deficiency $28

Net Debt $1,887

2020 2021 2022 2023 2024 2025 2026 2027

0x

1x

2x

3x

4x

5x

6x

7x

2012 2013 2014 2015 2016 2017 2018 2019

Net Debt to Adjusted Funds Flow Ratio (4)

US$500

11

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

WTI is between $50/bbl and $58/bbl; Baytex receives WTI when WTI is between $58/bbl and $63/bbl; and Baytex receives $63/bbl when WTI is above $63/bbl.

(2) Percentage of hedged volumes are based on 2020 annual production guidance (excluding NGL), net of royalties

Crude Oil Hedge Portfolio

Q1/2020 Q2/2020 Q3/2020 Q4/2020 2020

WTI Fixed Hedges

Volumes (bbl/d) 8,000 2,000 2,000 2,000 3,500

Fixed Price (US$/bbl) $56.95 $58.00 $58.00 $58.00 $57.40

WTI 3-Way Option

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

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

Total Hedge Volumes (bbl/d) 32,500 26,500 26,500 26,500 28,000

Hedge (%) (2) 52% 50% 54% 59% 53%

Basis Differential Financial Swaps

WCS Volumes (bbl/d) 2,500 6,500 6,500 6,500 5,500

WCS Price Relative to WTI (US$/bbl) ($16.10) ($16.27) ($16.27) ($16.27) ($16.25)

MSW Volume (bbl/d) 2,000 5,000 5,000 5,000 4,250

MSW Price Relative to WTI (US$/bbl) ($6.50) ($6.15) ($6.15) ($6.15) ($6.19)

12

2020E Adjusted Funds Flow Sensitivities

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

Excluding Hedges Including Hedges (2)

Change of US$1.00/bbl WTI crude oil $27.3 $26.0

Change of US$1.00/bbl WCS heavy oil differential $11.2 $8.1

Change of US$1.00/bbl MSW light oil differential $8.4 $7.8

Change of US$0.25/mcf NYMEX natural gas $8.4 $7.8

Change of $0.01 in the C$/US$ exchange rate $3.2 $3.2

(1) Adjusted funds flow sensitivities are based on the following full-year 2020 pricing assumptions: WTI - US$38/bbl; LLS - US$41/bbl; WCS differential - US$16/bbl; MSW differential – US$5.50/bbl,

NYMEX Gas - US$2.20/mcf; AECO Gas - $2.05/mcf and Exchange Rate (CAD/USD) - 1.39.

(2) Our adjusted funds flow sensitivities (including hedges ) will vary depending on where WTI prices trade, relative to the bands established within our 3-way option contracts. The sensitivity to a

change of US$1/bbl WTI crude oil in the table above reflects a WTI price of less than US$50/bbl.

13

Diversified Crude Oil Marketing Portfolio

Viking Light Oil

• 36° API light oil contributes to top quartile field netbacks

• Priced off Canadian Mixed Sweet (“MSW”) blend

LLS / Brent Exposure

• Eagle Ford is proximal to Gulf Coast markets; receives premium pricing

• Light oil and condensate priced off LLS crude oil benchmark, which is a function of the Brent price

Crude by Rail

• 11,500 bbl/d (~ 45%) of heavy oil contracted for 2020

• Effective tool for management of differentials

• Reduces price volatility and provides greater operating netback certainty

Crude Oil and NGL Sales Portfolio (1)

Benchmark

2020

Index (2)

Baytex Price

Realization (3)

Viking light oil MSW WTI less

US$9/bbl

MSW less

$3.50/bbl

Eagle Ford

light oil and

condensate LLS

WTI plus

US$3/bbl

LLS less

US$3.50/bbl

Peace River /

Lloydminster

heavy oil WCS

WTI less

US$17/bbl

WCS less

$14/bbl

(1) Based on 2020 guidance.

(2) 2020 Index based on the forward strip as at March 30, 2020.

(3) 2020 estimate

WTI / MSW 27%

Brent / LLS28%

WCS18%

Crude by Rail 16%

NGLs

11%

14

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

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

Top Quartile Capital Efficiencies

Source: Scotiabank Global Banking and Markets – May 2019.

Comparative group includes AAV, ARX, BIR, BNE, BNP, BXE, CJ, CPG, CR, DEE, ECA, ERF, FRU, KEL, NVA, OBE, PEY, PMT, PONY, POU, PSK, SGY, TOG, TOU, VET, VII, WCP.

Oil Gas (< 33% Liquids) Mixed (<67% Liquids)

2018 A

ll-I

n C

ap

ital E

ffic

ien

cie

s, excl. A

&D

($/b

oe/d

)

Weighted Average ($/boe/d)

Oil $25,000

Gas $12,800

Mixed $21,600

All $19,500

Asset Overview

16

Asset Highlights

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

Eagle Ford Viking Heavy Oil East Duvernay

Production(Gross; FY 2019)

39,055 boe/d 22,546 boe/d 29,377 boe/d 1,688 boe/d

Oil and NGLs(Gross; FY 2019)

77% 92% 91% 84%

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 ~$703 million of asset level free cash flow since 2016 (2)

▪ Enhanced completions continue to drive step change in performance

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

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

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

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

▪ Dominant land position of 786,939 net acres

▪ Low decline production provides capital allocation flexibility

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

▪ 176,000 acres of 100% W.I. lands in the Pembina area

▪ Offset development and 7 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.

17

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.

• 2019 production of 39,100

boe/d (77% liquids)

• Achieved record

production rates from new

wells in 2019

• 109 gross wells in 2019

established average 30-

day IP rates of ~ 1,900

boe/d per well

18

Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory

$42

$138

$285

$238

2016 2017 2018 2019

Asset Level Free Cash

Flow (1) (C$ millions)

~ $703MM cumulative free

cash flow since 2016

0

50

100

150

200

250

300

2020 Program RemainingUndrilledInventory

Drilling Inventory (2)

(net locations)

> 10 year inventory at

current pace

16-18

net wells

on- stream

> 250 net

locations

36.6 36.7 37.1

39.1

2016 2017 2018 2019

Production

(mboe/d)

Stable production and

deep inventory drives free

cash flow

(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”

19

0

25

50

75

100

125

150

175

0 1 2 3 4 5 6

Cu

mu

lati

ve

Pro

du

cti

on

(m

bo

e)

Months

17% increase 2019 over 2017

5% increase 2019 over 2018

Enhanced Completions Drive Step Change in Well Performance

2017

2016

180 Day Cumulative Well Production

Hz Length

(ft)

Proppant

(lbs/ft)

Stage

Spacing

(ft)

# of

Stages

2019 6,300 2,300 225 28

2018 6,000 2,000 215 28

2017 5,900 1,800 217 27

2016 5,500 1,600 221 25

Completion Activity

2019

2018

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 22,500 boe/d

(92% oil) in 2019

• Added 229 net unbooked

drilling opportunities in

2019 through multiple

deals and asset swaps

• Steady pace of

development in Q1/2020

with 4 drilling rigs and 2

frac crews executing our

program

• Revised 2020 guidance -

69 net wells

21

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)

2019 Wells 2018 Wells 2017 Wells 2016 Wells

2015 Wells 2014 Wells 2013 Wells 2012 Wells

Technical Advancements Drive Productivity Improvement

Viking Wells by Vintage

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

50

100

150

200

250

300

350

400

2012 2013 2014 2015 2016 2017 2018 2019

Net Wells Onstream (Left Axis)

ERH (%) (Right Axis)

Shift to ERH(1) Wells Drives Productivity

Improvements

95%+ of Viking Development now

ERH Wells

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

22

Peace River: Driving Production Growth and Cost Reductions

Performance Drivers

• Produced 16,800 boe/d in 2019

(86% oil)

• Dominant 738 net sections

• Innovative multi-lateral horizontal

drilling generate strong capital

efficiencies

• Revised 2020 guidance - 4 net

wells

Baytex Lands

Seal

Harmon Valley

Reno

North Seal Development

• 2018/2019 program (10 multi-

lateral horizontal wells)

generated 30-day IP rates of ~

700 boe/d per well

23

Lloydminster: Significant Land Position and Drilling Inventory

Performance Drivers

• Produced 12,600 boe/d in

2019 (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

• Revised 2020 guidance - 29

net wells

Baytex Lands

ALBERTA SASKATCHEWAN

Kerrobert

Lloydminster

Soda Lake

Tangleflags

Ardmore/Cold Lake

Lindbergh

24

Heavy Oil Innovation

Peace River

Multi-Lateral Horizontal

Lloydminster

Horizontal

25

East Duvernay Shale Light Oil: Emerging Resource Play

Baytex Lands

Pembina Region

• 275 sections of 100% WI lands

• Seven wells drilled to date have

delineated a minimum of 100-

125 sections

• Produced 1,700 boe/d (84%

liquids) in 2019

• Two wells on-stream in 2019

generated average 30-day IP

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

liquids)

• D&C costs of ~ $7.0 million

represent an ~ 20% reduction

from previous wells

• Two most recent completions

utilize fracture diversion

technology

Pembina

Ferrybank

Gilby

Q4/2018 Completions

(4 wells)

14-36 Initial Pembina

Discovery (Q1/2018)Q3/2019 Completions

2 wells (14-31, 3-19)

26

Eagle Ford Viking Peace River (1) Lloydminster (1) East 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 0 millidarcies

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$5.6 million $1.0 million $2.5 million $0.8 million $7.0 million

6,000 foot lateral

Land - gross (net) sections 122 (31) 763 (656) 748 (738) 637 (491) 275 (275)

Pembina area

Reserves at YE 2019 (mmboe)

Proved developed producing 71 29 21 13 2

Proved 163 65 32 28 7

Proved plus probable 229 98 59 44 14

Drilling inventory (risked) – net

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

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

High Quality Oil Development

Corporate Sustainability

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:

• Increasing gas conservation

• Reusing associated gas as fuel for

field activities

• Reducing emissions from storage

tanks

• Monitoring and preventing fugitive

emissions

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

76% 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

99.1% routine gas conservation in

Peace RiverHelps to build trust with

regulators and stakeholders

SO

CIA

L

Create a culture of

safety

Tie safety targets to annual

performance incentive program

55% reduction in employee

+contractor LTIF in 5 years

Supports the consistent and

safe execution of our business

plan

Be a good neighbour

Build mutually beneficial

relationships based on trust

$32 million awarded in contracts

to Indigenous

contractors/companies in 2017-

2018

Maintain social license and

enables growth in our

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

Source: 2018 Sustainability Report – September 2019

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

not represent a value equivalency at the wellhead.

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

realized pricing on our produced volumes to the WCS benchmark.

(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q3/2019 MD&A for

further information on these amounts.

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

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

33

Reserves Summary (Gross)

Eagle Ford

Viking

Heavy Oil

East Duvernay

Other

Category (1) Eagle Ford Viking Heavy Oil East Duvernay Other Total

Proved Developed Producing 71 29 34 2 6 142

Total Proved 163 65 68 7 11 314

Total Proved Plus Probable 229 98 163 14 25 529

2P Reserves by 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.

34

2020 Guidance and Cost Assumptions

Exploration and development expenditures ($ millions) $260 - $290

Production (boe/d) 85,000 - 89,000

Expenses:

Royalty rate (%) 19.0% - 19.5%

Operating ($/boe) $11.75 - $12.50

Transportation ($/boe) $1.10 - $1.20

General and administrative ($ millions) $45 ($1.42/boe)

Interest ($ millions) $115 ($3.62/boe)

Leasing expenditures ($ millions) $7

Asset retirement obligations ($ millions) $10

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