Investor Presentation - Baytex Energy · 2021. 5. 3. · 2 Forward Looking Statements Any “financialoutlook”or “futureoriented financial information”in this presentation as

Investor Presentation

May 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; we have potential to deliver more than $250 million of free cash flow ($0.45 per share) in 2021; we use derivate contract and crude-by-rail to reduce volatility in adjusted

funds flow; that approximately 50% of our net crude oil exposure is hedged for 2021; that we 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 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 and have the potential to further advance Pembina Duvernay; 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 to bank EBITDA ratio of

<1.5x and will all consideration of share buy-back, dividend 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 close and ending net debt; for our 5-year plan expected free flow at certain WTI prices; our

expected financial liquidity and net debt to EBITDA ratio at year end 2021; 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 20 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, ~4 net wells planned for H2/2021 in Peace River, >100 sections prospective for Sprit River (clearwater equivalent), H2/2021 plan included up to 6

clearwater wells; ~31 (23 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; that we are committed to corporate sustainability; 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.

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); 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

Advisory

3

Advisory (Cont.)

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 April 29, 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.

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 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.

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 81% of adjusted funds flow over the last five years (2016 to 2020)

▪ Potential to deliver > $250 million ($0.45 per share) of free cash flow in 2021 (1)

▪ Credit facilities ~ 40% undrawn and liquidity > $350 million (2)

▪ First long-term note maturity not until June 2024

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

▪ Established target to reduce GHG emissions intensity by 65% by 2025, relative to 2018 baseline

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) 2021 full-year pricing assumptions: WTI - US$60/bbl; WCS differential - US$12/bbl; MSW differential – US$4.5/bbl; NYMEX Gas

- US$2.80/mcf; AECO Gas - $2.80/mcf and Exchange Rate (CAD/USD) - 1.25.

(2) As at March 31, 2021.

6

EAGLE FORD

VIKING

LLOYDMINSTER

PEACE RIVER

DUVERNAY

(1) Average daily trading volumes for April 2021. Volumes are a composite of all exchanges in Canada.

(2) Enterprise value based on closing share price on the Toronto Stock Exchange on April 30, 2021 and shares outstanding and net debt as at March 31, 2021.

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

(4) Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd.

(5) Production (Gross W.I.) composition based on 2021 guidance. Heavy oil includes Peace River and Lloydminster.

(6) Revenue by commodity composition based on 2020 actuals.

Production by

Core Area (5)

Heavy Oil

Light Oil

NGLs

Natural Gas

Corporate Profile

Market Summary

Ticker Symbol TSX: BTE

Average Daily Volume (1) 5.4 million

Shares Outstanding (2) 564 million

Market Capitalization / Enterprise Value (2) $823 million / $2,582 million

Operating Statistics

Production (Gross W.I.) (3) 77,000 – 79,000 boe/d

Production Mix (3) 81% liquids

E&D Expenditures (3) $285 to $315 million

Reserves – 2P Gross (4) 462 mmboe

Heavy Oil

Light Oil

NGLs

Natural Gas

Eagle Ford

Viking

Heavy Oil

Other

Production by

Commodity (5)

Revenue by

Commodity (6)

7

Q1 2021 Highlights

Operational Execution

• Production of 78,800 boe/d, up 12% from Q4/2020

• E&D capital of $84 million, consistent with full-year plan

• Successful exploration well on our Peace River Clearwater play

Free Cash Flow Generation

• Adjusted funds flow of $157 million ($0.28 per basic share), a 91% increase over Q4/2020

• Free cash flow of $70 million ($0.13 per basic share)

Strengthened Balance Sheet

• Reduced net debt by $89 million through a combination of free cash flow and the Canadian dollar strengthening relative to the U.S. dollar

• Increased undrawn credit capacity to $401 million and liquidity, net of working capital, to $381 million

8

ESG Highlights

GHG Emission Reduction Safety

46% reduction in GHG

emissions intensity through

year-end 2020, relative to

2018 baseline

25% reduction in total

recordable injury

frequency in 5 years

Gas Conservation Indigenous Relations

97% routine gas

conservation in Peace River

in 2020

Recent agreements with

Woodland Cree First

Nation and Peavine Métis

Settlement

Spill Volumes Gender Diversity

59% reduction in reportable

spill volumes over 5 years

25% women Board

members as of April 2021

9

2021 Capital Program

2021 Guidance (1)

E&D CapEx $285 - 315 million

Production 77,000 - 79,000 boe/d

Oil and NGLs 81%

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

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

• 75% directed to our high netback light oil assets in the Eagle Ford and Viking

• Heavy oil program kicks off in July –35 net wells planned for the year, including up to 6 net Clearwater equivalent wells

• Further advancing our Pembina Duvernay development with two well program in H2/2021

Operating Area

Net Wells

Onstream CapEx ($MM) (2)

Viking 120 $115

Eagle Ford 20 $110

Heavy Oil 35 $45

East Duvernay 2 $20

Other 4 $10

Total $300

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

development includes 14 net wells drilled and 20 net wells on production. Other development

includes 2 net natural gas wells drilled and 4 net natural gas wells on production.

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

10

5-Year Plan (2021 to 2025) at US$55 WTI

1. Disciplined and Returns Based Capital Allocation

• Target capital spending at < 70% of adjusted funds flow

• Optimize production in the 80,000 to 85,000 boe/d range

• Capital efficiencies during the plan period of $15,000 to $16,000 per boe/d

2. Maximize Free Cash Flow

• Generate > $1 billion of free cash flow during the plan period

3. Improve Leverage Ratios

• Target net debt to bank EBITDA ratio of < 1.5x

4. Enhance Shareholder Returns (2022-2025)

• Consider introduction of share buy-back, dividend and/or reinvestment for organic growth

Notes:

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

(2) Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. 5-year plan (2021 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl;

WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf; AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28.

(3) Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at each year-end and forecast Bank EBITDA for that particular year. See advisory for definitions of Non-GAAP Financial and Capital Management Measures

on page 3 of this presentation.

11

Notes:


(2) Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. 5-year plan (2021 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS

differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf; AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28.

Production

(boe/d)

Adjusted

Funds Flow

($ MM)

Adjusted

Funds Flow

($ per share)

Capital

Expenditures

($MM)

Free Cash

Flow ($MM)

Ending Net Debt

($MM)

2021 78,000 $537 $0.95 $300 $220 $1,633

2022 79,900 $591 $1.04 $366 $200 $1,431

2023 81,500 $615 $1.08 $410 $180 $1,249

2024 83,000 $648 $1.14 $410 $213 $1,035

2025 83,900 $666 $1.16 $410 $231 $802

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

2021 2022 2023 2024 2025

Pro

du

ctio

n (b

oe

/d)

Eagle Ford Viking Heavy Oil Duvernay Conventional

$1 Billion Cumulative Free Cash Flow

$0

$200

$400

$600

$800

$1,000

$1,200

2021 2022 2023 2024 2025

Cu

mu

lati

ve F

ree

Cas

h F

low

($

mill

ion

s)

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

12

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

2021 2022 2023 2024 2025 2021 2022 2023 2024 2025 2021 2022 2023 2024 2025

Net

Deb

t to

Ban

k EB

ITD

A r

atio

Free

Cas

h F

low

($

mill

ion

s)

Free Cash Flow Net Debt to Bank EBITDA

5-Year Plan with Upside WTI Scenario’s

Base Case

US$55/bbl US$60/bbl US$65/bbl

Notes:


(2) Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. 5-year plan (2021 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl;

WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf; AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28. In the upside WTI scenarios, all other pricing assumptions are held

constant.

(3) Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at each year-end and forecast Bank EBITDA for that particular year. Free cash flow is utilized to reduce net debt. See advisory for definitions of Non-GAAP

Financial and Capital Management Measures on page 3 of this presentation.

Significant Free Cash Flow and Accelerated De-leveraging

Upside WTI Scenario’s

13

Financial Liquidity

C$548

Undrawn

C$300US$400US$400

(1) 2021 pricing assumptions: WTI - US$60/bbl; WCS differential - US$12/bbl; MSW

differential – US$4.5/bbl, NYMEX Gas - US$2.80/mcf; AECO Gas - $2.80/mcf and

Exchange Rate (CAD/USD) - 1.25.

(2) Balance sheet as at March 31, 2021. 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.

(3) 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”.

(4) Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at year-end 2021

and forecast 2021 Bank EBITDA. See advisory for definitions of Non-GAAP Financial and

Capital Management Measures on page 3 of this presentation.

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

• Credit Facilities ~ 40% Undrawn

• $401 million of undrawn credit capacity and liquidity, net of working capital, of $381 million

• Financial liquidity expected to increase to > $550 million in 2021(1)

• First long-term note maturity not until 2024

• 2021E Net Debt to EBITDA ratio < 2.5x (1)

Balance Sheet (2) $ millions

Credit facilities $607

Long-term notes $1,131

Long-term debt $1,738

Working Capital deficiency $21

Net Debt $1,759

2021 2022 2023 2024 2025 2026 2027 2028

US$500

3.0x2.5x

2.2x1.9x

US$50 US$55 US$60 US$65

WTI (US$/bbl)

2021E Net Debt to Bank EBITDA Ratio (4)

14

(1) WTI fixed hedges for 2022 include 10,000 bbl/d of swaptions where the counterparty has the right, if exercised on December 31, 2021, to enter into a swap transaction for the volumes and price indicated.

(2) WTI 3-way options consist of a sold put, a bought put and a sold call. In a $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.

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

Crude Oil Hedge Portfolio

Q2/2021 Q3/2021 Q4/20219 Months

20212022

WTI Fixed Hedges (1)

Volumes (bbl/d) 4,000 4,000 4,000 4,000 10,000

Fixed Price (US$/bbl) $45.00 $45.00 $45.00 $45.00 $53.50

WTI 3-Way Option (2)

Volumes (bbl/d) 17,500 17,500 17,500 17,500 6,000

Average Sold Put / Put / Sold Call (US$/bbl) $35/$45/$52 $35/$45/$52 $35/$45/$52 $35/$45/$52 $45/$55/$65

Total Hedge Volumes (bbl/d) 21,500 21,500 21,500 21,500 16,000

Basis Differential Hedges

WCS Volumes (bbl/d) 13,000 11,000 11,000 11,667 9,000

WCS Price Relative to WTI (US$/bbl) ($13.31) ($13.23) ($13.23) ($13.26) ($12.47)

MSW Volume (bbl/d) 7,500 7,500 7,500 7,500 ---

MSW Price Relative to WTI (US$/bbl) ($5.03) ($5.03) ($5.03) ($5.03) ---

Hedge (%) (3) 47% 47% 47% 47% 33%

15

2021E Adjusted Funds Flow Sensitivities

SensitivitiesEstimated Effect on Annual Adjusted Funds Flow ($MM)

Excluding Hedges Including Hedges

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

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

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

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

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

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; Q1 2021)

26,740 boe/d 19,400 boe/d 24,400 boe/d 2,100 boe/d

Oil and NGLs(Gross; Q1 2021)

77% 91% 90% 84%

2P Reserves (1)

(Gross)215 mmboe 85 mmboe 123 mmboe 17 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 ~$833 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

▪ Technical advancements drive productivity improvements

▪ 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, 2020 as evaluated by McDaniel & Associates Consultants Ltd. See “Advisories”.

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

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.

• Q1/2021 production of

26,740 boe/d (77%

liquids)

• Q1/2021 - 24 gross (7.0

net) wells established

average 30-day IP rates of

~ 1,600 boe/d per well

• Expect to bring ~ 20 net

wells on production in

2021

19

$42

$138

$285

$238

$96

$43

2016 2017 2018 2019 2020 Q1 2021

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

onstream

~ 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 210 proved plus probable undeveloped reserves locations at year-end 2020 and 38 unbooked future locations. See “Advisories”

(3) Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type curve that uses the following assumptions: well cost US$5 million (6,000 foot

lateral); IP365 - 700 boe/d; EUR – 800 mboe).

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

$842 million cumulative asset level

free cash flow since 2016

WTI Oil Price $50/bbl $60/bbl

Payout: 0.9 years 0.6 years

IRR: 101% 203%

Recycle Ratio: 3.2x 4.0x

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 19,400 boe/d

(91% oil) in Q1/2021

• Drilling activity resumed

in December with two

rigs mobilized

• Capital reduction effort

and operational

efficiencies drive costs

down ~ 10%

• Expect to bring ~ 120 net

wells on production in

2021

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$4/bbl.

Well Economics (2)



IRR: 33% 77%


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 14,300 boe/d in

Q1/2021 (85% oil)

• Dominant 560 net sections

• ~ 4 net wells planned for H2/2021

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 exploration well in Q1/2021

23

Northwest Clearwater: Extending the Trend

• > 500 net sections in the NW Clearwater fairway with > 100 prospective for Spirit River (Clearwater equivalent)

• Promising exploration well result with 30-day initial production rate of 175 bbl/d (from two laterals)

• H2/2021 plans include up to 6 additional Clearwater multi-lateral wells

• With over a decade of experience in heavy oil exploration and multi-lateral development, this play type aligns strongly with our core competencies

• >3 million meters and >2,400 legs drilled in the region since 2005

Peavine

24

Lloydminster: Significant Land Position and Drilling Inventory

Performance Drivers

• Produced 10,100 boe/d in

Q1/2021 (97% oil)

• Strong capital efficiencies

• Applying multi-lateral

horizontal drilling and

production techniques

• ~ 31 (23 net) wells planned

for H2/2021

Baytex Lands

ALBERTA SASKATCHEWAN

Kerrobert

Lloydminster

Soda Lake

Tangleflags

Ardmore/Cold Lake

Lindbergh

25

Heavy Oil Innovation

Peace River

Multi-Lateral Horizontal

Lloydminster

Horizontal

Well Economics (1)



IRR: 62% 136%


Breakeven:

(10% IRR)US$42/bbl



IRR: 51% 129%


Breakeven:

(10% IRR)US$42/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$12/bbl.

26

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 2,100 boe/d (84%

liquids) in Q1/2021

• Two wells drilled in 2020

demonstrate repeatability of 11-

30 pad completed in 2019

• 10-16 generated a 30-day IP

rate of 1,300 boe/d (69% oil);

11-16 generated a facility

constrained 30-day IP rate of

900 boe/d (68% oil)

• Two wells planned for H2/2021

Producing Pads (7 wells)

Rimbey Leduc Reef

Liquids Rich Gas

Liquids

Rich Gas

Volatile

Oil

Black Oil

Two wells (10-16, 11-16)

onstream November 2020

27

Eagle Ford Viking Peace River Lloydminster Pembina Duvernay

Formation Lower Eagle Ford Viking Bluesky Mannville Group Duvernay

Upper Eagle Ford

Austin Chalk

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

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

Condensate: 44-55°

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

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

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 2020 (mmboe)

Proved developed producing 68 22 15 8 3

Proved 153 57 19 25 8

Proved plus probable 215 85 39 84 17

Drilling inventory (risked) – net

locations (booked/unbooked) 210 / 38 1,268 / 443 65 / 163 173 / 417 25 / 278

High Quality Oil Development

Corporate Sustainability

29

Corporate Sustainability

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

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

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

Safety Environment

Communities and

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.

30

GHG Emissions Reduction

Target to reduce GHG emission

intensity (tonnes of CO2 per boe)

by 65% by 2025.

Our emissions reduction strategy

includes:

• Increased gas conservation and

combustion

• Reusing associated gas as fuel

for field activities

• Reduced emissions from storage

tanks

• Monitoring and preventing

fugitive emissions

0.112 0.095 0.061 0.041 -

0.040

0.080

0.120

Baseline 2018 2019 2020 Target 2025

Tonnes o

f C

O2

per

boe

65%reduction

from baseline

GHG Intensity Improvement and Target

31

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

59% reduction in reportable 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

97% routine gas conservation in

Peace River in 2020Helps to build trust with

regulators and stakeholders

SO

CIA

L

Create a culture of

safety

Tie safety targets to annual

performance incentive program

25% reduction in total recordable

injury frequency in 5 yearsSupports 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 April 2021

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

33

Summary of Operating and Financial Metrics

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

Benchmark Prices

WTI crude oil (US$/bbl) $54.90 $59.81 $56.45 $56.96 $57.03 $46.17 $27.85 $40.93 $42.66 $39.40 $57.84

NYMEX natural gas (US$/mcf) $3.15 $2.64 $2.23 $2.50 $2.63 $1.95 $1.72 $1.98 $2.66 $2.08 $2.69

Production

Crude oil (bbl/d) 71,939 69,905 68,541 70,956 70,328 74,571 50,783 56,239 51,293 58,198 57,419

Natural gas liquids (bbl/d) 11,729 10,986 9,543 8,699 10,229 7,822 7,634 7,417 6,495 7,340 6,238

Natural gas (mcf/d) 104,682 105,065 101,054 100,236 102,742 96,356 84,546 84,945 76,116 85,464 90,739

Oil equivalent (boe/d) (1) 101,115 98,402 94,927 96,360 97,680 98,452 72,508 77,814 70,475 79,781 78,780

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

Netback ($/boe)

Total sales, net of blending and other

expenses (2) $47.98 $51.49 $47.14 $48.25 $48.72 $35.19 $22.31 $33.79 $34.35 $31.75 $51.84

Royalties (8.94) (9.67) (8.59) (8.72) (8.98) (6.33) (4.42) (5.59) (5.83) (5.61) (9.44)

Operating expense (11.02) (11.22) (11.15) (11.23) (11.16) (11.66) (11.17) (10.26) (12.30) (11.35) (11.36)

Transportation expense (1.46) (1.33) (1.13) (1.00) (1.23) (1.15) (0.76) (0.89) (1.03) (0.97) (1.24)

Operating Netback (4) $26.56 $29.27 $26.27 $27.30 $27.35 $16.05 $5.96 $17.05 $15.19 $13.82 $29.80

General and administrative (1.55) (1.28) (1.14) (1.12) (1.28) (1.09) (1.13) (1.08) (1.44) (1.17) (1.23)

Cash financing and interest (3.10) (3.14) (3.06) (2.75) (3.01) (3.19) (4.15) (3.55) (3.89) (3.65) (3.44)

Realized financial derivative gain (loss) 2.07 1.45 2.39 2.59 2.12 3.00 2.06 (1.36) 2.64 1.64 (2.93)

Other (3) 0.28 0.07 (0.03) 0.16 0.13 0.07 (0.03) (0.09) 0.17 0.03 (0.12)

Adjusted funds flow (4) $24.26 $26.37 $24.43 $26.19 $25.31 $14.84 $2.71 $10.97 $12.67 $10.67 $22.08

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

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

burner tip and does not represent a value equivalency at the wellhead.

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

realized pricing on our produced volumes to the WCS benchmark.

(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share based compensation. Refer to the Q1 2021 MD&A for further

information on these amounts.

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

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

34

Reserves Summary (Gross)

Category (1) Eagle Ford Viking Heavy OilPembina

DuvernayOther Total

Proved Developed Producing 68 22 23 3 4 120

Total Proved 153 57 44 8 9 271

Total Proved Plus Probable 215 85 123 17 22 462

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

(1) Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd.

Probable

PDNP + PUD

PDP

Eagle Ford

Viking

Heavy Oil

Pembina Duvernay

Other

Light Oil & NGLHeavy

Oil

Natural Gas

35

2021 Guidance and Cost Assumptions

Exploration and development expenditures ($ millions) $285 - $315

Production (boe/d) 77,000 – 79,000

Expenses:

Royalty rate (%) 18% - 18.5%

Operating ($/boe) $11.25 - $12.00

Transportation ($/boe) $1.15 - $1.25

General and administrative ($ millions) $42 ($1.48/boe)

Interest ($ millions) $98 ($3.46/boe)

Leasing expenditures ($ millions) $4

Asset retirement obligations ($ millions) $6

Contact Information

Edward D. LaFehrPresident and Chief Executive Officer

587.952.3000

Rodney D. GrayExecutive Vice President & 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

Documents

Investor Presentation - Baytex Energy · 2021. 5. 3. · 2 Forward Looking Statements Any “financialoutlook”or “futureoriented financial information”in this presentation as