Investor Presentation - October 2021 - Baytex Energy Corp.
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Investor Presentation October 2021
Advisory
Forward Looking Statements
Any “financial outlook” or “future oriented financial information” in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial outlook
or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that
reliance on such information may not be appropriate for other circumstances.
In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of future plans and operations, certain
statements in this presentation are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within
the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as
"anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar
words suggesting future outcomes, events or performance. The forward-looking statements contained in this presentation peak only as of the date hereof and are expressly qualified by this
cautionary statement.
Specifically, this presentation contains forward-looking statements relating to but not limited to: that we have 10+ years of drilling inventory in core areas, strong capital efficiencies and flexibility
on discretionary capital; we have potential to deliver more than $350 million of free cash flow ($0.62 per share) in 2021; we use derivate contract and crude-by-rail to reduce volatility in adjusted
funds flow; that approximately 45% of our net crude oil exposure is hedged for H2/2021; our GHG emissions intensity reduction target; expectations for 2021 as to Baytex’s production on a
boe/d basis, percentage of production that will be liquids, exploration and development expenditures, production by area and commodity; that our 2021 capital program is fully funded at
US$35/bbl WTI, will have capital efficiencies of ~$12,000 boe/d, 75% will be directed to high netback light oil assets, intend to implement a heavy oil program with 35 net wells in H2/2021
including 7 net clearwater equivalent wells and have the potential to further advance Pembina Duvernay; the expected number of wells onstream and total capex for 2021 in pour Viking, Eagle
Ford, Heavy Oil, East Duvernay and other Operating Areas; that our 5-year plan at $55 WTI will: target capital spending at $1 billion of free cash flow, has a target net debt of $1 to $1.2 billion and a target net debt to bank EBITDA ratio of
120 sections prospective for Sprit River (clearwater equivalent), the play aligns with our core competencies, that we have de-risked 20 sections and believe the play holds the potential for
>200 locations, preparing for two additional clearwater wells in 2021 and 12 to 18 in 2022; ~22 net wells planned for H2/2021 in Lloydminster; in Pembina Area Duvernay, measured delineation is
planned, two wells drilled in 2020 demonstrate repeatability of 11-30 pad completed in 2019 and 2 wells planned for H2/2021; the expected individual well payout, IRR, recycle ratio and
breakeven WTI price for wells in the Eagle Ford, Viking, Peace River, Clearwater and Lloydminster areas; the expected drill, complete, equip and tie-in well costs, reserves and drilling inventory
for our Eagle Ford, Peace River, Lloydminster, Viking and Pembina Duvernay assets; our aspiration, visions and approach to ESG; that we are committed to corporate sustainability; the
components of our GHG emissions reduction strategy; our new ESG targets: reducing our GHG emissions intensity by 65% by 2025 from our 2018 baseline, reduce our end of life well inventory
to zero by 2040, by 2022 evaluate and test new methods to reduce freshwater intensity and by 2022 expand our baseline to include multiple dimensions of diversity and enhance our processes
to measure employee engagement; and our 2021 guidance for exploration and development expenditures, production, royalty rate, operating, transportation, general and administration and
interest expense and leasing expenditures and asset retirement obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they
involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the
future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil
prices; well production rates and reserve volumes; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow under
credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for operating activities; the availability and cost of labour and other industry services; interest and
foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the ability to develop crude oil and natural gas properties in the manner
currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are
cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
2
Advisory (Cont.)
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited
to: the volatility of oil and natural gas prices and price differentials (including the impacts of Covid-19); the availability and cost of capital or borrowing; risks associated with our ability to exploit our
properties and add reserves; availability and cost of gathering, processing and pipeline systems; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply
with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; public perception and its influence on the regulatory regime; restrictions or costs
imposed by climate change initiatives and the physical risks of climate change; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government
regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; costs to develop and operate our properties;
variations in interest rates and foreign exchange rates; risks associated with our hedging activities; retaining or replacing our leadership and key personnel; changes in income tax or other laws or
government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks related to our
thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; results of litigation; risks associated with
large projects; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to
enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are
beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended
December 31, 2020, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings.
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on
Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements. The future oriented financial information
and forward-looking statements are made as of October 1, 2021 and Baytex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new
information, future events or results or otherwise, other than as required by applicable securities laws.
Non-GAAP Financial and Capital Management Measures
This presentation contains certain financial measures that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered non-
GAAP measures. These non-GAAP measures may not be comparable to similar measures presented by other issuers. The following terms are not recognized measures under IFRS, but are
presented in this presentation.
“Adjusted funds flow” is defined as cash flow from operating activities adjusted for changes in non-cash operating working capital, asset retirement obligations settled and transaction costs.
Management of Baytex consider adjusted funds flow a key measure of performance as it demonstrates the combined entity’s ability to generate the cash flow necessary to fund capital investments,
debt repayment, settlement of abandonment obligations and potential future dividends. In addition, the ratio of net debt to adjusted funds flow is used to manage Baytex’s capital structure.
“Asset level free cash flow” is defined as field level operating netback less exploration and development expenditures.
“Bank EBITDA” is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expense, income tax, non-recurring losses,
certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expense, impairment, deferred income tax expense or recovery, unrealized gains
and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if
they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2020 was $414.9 million.
“Capital Efficiency” is defined as exploration and development expenditures divided by the expected aggregate IP365 rate (boe/d) for all wells coming on production in the year, normalized to a
January 1 start-date.“
“Exploration and development expenditures” is defined as expenditures related to drilling, completing and equipping, facilities, land, seismic and other. Exploration and development expenditures
includes additions to exploration and evaluation assets along with additions to oil and gas properties.
“Free cash flow” is defined as adjusted funds flow less exploration and development expenditures, payments on lease obligations and asset retirement obligations settled.
“Internal rate of return” of “IRR” is a rate of return measure (before tax) used to compare the profitability of an investment and represents the discount rate at which the net present value of costs
equals the net present value of the benefits. The higher a project’s IRR, the more desirable the project.
“Net debt” is defined as the sum of monetary working capital (which is current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term
notes of Baytex and the credit facilities of Baytex. Management of Baytex believe that net debt assists in providing a more complete understanding of Baytex’s cash liabilities.
“Operating netback” is defined as petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense divided by barrels of oil equivalent
sales volume for the applicable period. Management of Baytex believe that operating netback assists in characterizing Baytex’s ability to generate cash margin on a unit of production basis.
3
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.
4
Investment Highlights
High Quality and ~ 10 or more years of projected drilling inventory in each of our
Diversified Oil Portfolio core areas (Viking, Eagle Ford and Canadian heavy oil)
Across Multiple Plays Strong capital efficiencies and flexibility on discretionary capital
Exploration and development expenditures represents 81% of
Track Record of adjusted funds flow over the last five years (2016 to 2020)
Substantial Free Cash
Potential to deliver > $350 million ($0.62 per share) of free cash
Flow Generation flow in 2021 (1)
Financial Liquidity and Credit facilities ~ 50% undrawn and liquidity ~ $500 million (2)
No Near-Term Maturities First long-term note maturity not until June 2024
Utilize financial derivative contracts and crude-by-rail to reduce the
Consistent Approach to volatility in our adjusted funds flow
Risk Management ~ 45% of net crude oil exposure hedged for H2/2021
Proven commitment to environmental, social and governance
(“ESG”) objectives
Committed to ESG
Established target to reduce GHG emissions intensity by 65% by
2025, relative to 2018 baseline
(1) 2021 full-year pricing assumptions: WTI - US$64/bbl; WCS differential - US$13/bbl; MSW differential – US$4/bbl; NYMEX Gas -
US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26.
(2) As at June 30, 2021.
5
Corporate Profile
Market Summary
Ticker Symbol TSX: BTE
Average Daily Volume (1) 12.9 million
Shares Outstanding (2) 564 million
Market Capitalization / Enterprise Value (2) $1.95 billion / $3.58 billion
Operating Statistics
Production (Gross W.I.) (3) 79,000 – 80,000 boe/d
Production Mix (3) 81% liquids
PEACE RIVER
DUVERNAY
LLOYDMINSTER
E&D Expenditures (3) $285 to $315 million
VIKING Reserves – 2P Gross (4) 462 mmboe
Production by Production by Revenue by
Core Area (5) Commodity (5) Commodity (6)
Natural
Other
Natural NGLs Gas Heavy
Gas Heavy Oil
Eagle Oil
Ford NGLs
Heavy
Oil
Light
EAGLE FORD
Viking Light Oil
Oil
(1) Average daily trading volumes for September 2021. Volumes are a composite of all exchanges in Canada.
(2) Enterprise value based on closing share price on the Toronto Stock Exchange on September 30, 2021 and shares outstanding and net debt as at June 30, 2021.
(3) Production, production mix, and exploration and development (“E&D”) expenditures represents 2021 guidance.
(4) Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd.
(5) Production (Gross W.I.) composition based on 2021 guidance. Heavy oil includes Peace River and Lloydminster.
(6) Revenue by commodity composition based on 2020 actuals. 6
Q2 2021 Highlights
Operational Execution
• Production of 81,200 boe/d, up 3% from Q1/2021
• E&D capital of $61 million, consistent with full-year plan
• Continue to advance our Peace River Clearwater play with 5 wells on production
Free Cash Flow Generation
• Adjusted funds flow of $176 million ($0.31 per basic share), a 12% increase over
Q1/2021
• Substantial free cash flow of $112 million ($0.20 per basic share)
Strengthened Balance Sheet
• Reduced net debt by $129 million through a combination of free cash flow and the
Canadian dollar strengthening relative to the U.S. dollar
• Increased undrawn capacity to $511 million (50% undrawn on our $1 billion credit
facilities)
• Repurchased and cancelled US$106 million of our outstanding long-term notes
due 2024 during and subsequent to the quarter
7
ESG Highlights
GHG Emission Reduction Safety
46% reduction in GHG 25% reduction in total
emissions intensity through recordable injury frequency in
2020, relative to 2018 5 years
baseline; 65% target in place
Gas Conservation Indigenous Relations
97% routine gas conservation Recent agreements with
in Peace River in 2020 Woodland Cree First Nation
and Peavine Métis Settlement
Spill Volumes Gender Diversity
59% reduction in reportable 25% women Board members
spill volumes over 5 years as of April 2021
Abandonment & Reclamation Water
Reduce inactive well inventory Initiate water recycle projects
of ~ 4,500 wells to zero by in Kerrobert, Viking and
2040 Duvernay
8
2021 Capital Program
• Cash neutrality (capital program fully 2021 Guidance (1)
funded) at US$35/bbl WTI
E&D CapEx $285 - 315 million
• Capital efficiencies of approximately Production 79,000 - 80,000 boe/d
$12,000 per boe/d across the Oil and NGLs 81%
portfolio
Net Wells
• 75% directed to our high netback Operating Area Onstream CapEx ($MM) (2)
light oil assets in the Eagle Ford and
Viking 120 $115
Viking
Eagle Ford 22 $110
• Heavy oil program kicked off in June Heavy Oil 35 $45
– 35 net wells planned for the year,
including up to 7 net Clearwater East Duvernay 2 $20
equivalent wells Other 4 $10
Total $300
• Further advancing our Pembina
Duvernay development with two well (1) 2021 capital spending is 52% weighted to the second half of the year. Eagle Ford
program in H2/2021 development includes 14 net wells drilled and 22 net wells on production. Other development
includes 2 net natural gas wells drilled and 4 net natural gas wells on production.
(2) Represents mid-point of 2021 guidance range.
9
5-Year Plan (2021 to 2025) at US$55 WTI
1. Disciplined and Returns Based Capital Allocation
• Target capital spending at < 70% of adjusted funds flow
• Optimize production in the 80,000 to 85,000 boe/d range
• Capital efficiencies during the plan period of $15,000 to $16,000 per boe/d
2. Maximize Free Cash Flow
• Generate > $1 billion of free cash flow during the plan period
3. Improve Leverage Ratios
• Target net debt of $1.0 to $1.2 billion and net debt to bank EBITDA ratio of
< 1.5x at US$55 WTI
4. Enhance Shareholder Returns (2022-2025)
• Consider introduction of share buy-back, dividend and/or reinvestment for
organic growth
Notes:
(1) For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary.
(2) Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. Year one of the 5-year plan (2021) based on H1/2021 actual results and the forward strip for the
balance of the year. Full year 2021 pricing assumptions:: WTI - US$64/bbl; WCS differential - US$13/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26
Years two through five of the five-year plan (2022 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf;
AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28.
(3) Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at each year-end and forecast Bank EBITDA for that particular year. See advisory for definitions of Non-GAAP Financial and Capital Management Measures
on page 3 of this presentation.
105-Year Plan Generates > $1 Billion Cumulative Free Cash Flow
90,000
> $1 Billion Cumulative Free Cash Flow
80,000 $1,400
70,000
Cumulative Free Cash Flow ($ millions)
$1,200
60,000
$1,000
Production (boe/d)
50,000
$800
40,000
$600
30,000
$400
20,000
10,000 $200
0 $0
2021 2022 2023 2024 2025 2021 2022 2023 2024 2025
Eagle Ford Viking Heavy Oil Duvernay Conventional
Adjusted Adjusted Capital
Production Free Cash Ending Net Debt
Funds Flow Funds Flow Expenditures
(boe/d) Flow ($MM) ($MM)
($ MM) ($ per share) ($MM)
2021 79,500 $675 $1.20 $300 $360 $1,480
2022 79,900 $591 $1.04 $366 $200 $1,280
2023 81,500 $615 $1.08 $410 $180 $1,100
2024 83,000 $648 $1.14 $410 $213 $887
2025 83,900 $666 $1.16 $410 $231 $656
Notes:
(1) For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary.
(2) Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including prior year’s results. Year one of the 5-year plan (2021) based on H1/2021 actual results and the forward strip for the balance
of the year. Full year 2021 pricing assumptions:: WTI - US$64/bbl; WCS differential - US$13/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26.
(3) Years two through five of the five-year plan (2022 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf;
AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28.
115-Year Plan with Upside WTI Scenario’s
US$55 WTI US$65 WTI US$75 WTI
~ $1.2 Billion ~ $2.0 Billion ~ $2.6 Billion
Cumulative FCF Cumulative FCF Cumulative FCF
$700 2.0x
1.8x
$600
1.6x
Net Debt to Bank EBITDA ratio
Free Cash Flow ($ millions)
$500 1.4x
1.2x
$400
1.0x
$300
0.8x
$200 0.6x
0.4x
$100
0.2x
$0 0.0x
2021 2022 2023 2024 2025 2021 2022 2023 2024 2025 2021 2022 2023 2024 2025
US$55/bbl US$65/bbl US$75/bbl
Free Cash Flow Net Debt to Bank EBITDA
Notes:
(1) For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary. Budget and forecast beyond 2021 have not been finalized and are subject to a variety of factors including
prior year’s results.
(2) 2021 (year one of the base case and the upside WTI scenarios) is based on H1/2021 actual results and the forward strip for the balance of the year. Full year 2021 pricing assumptions: WTI - US$64/bbl; WCS differential -
US$13/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) - 1.26
(3) Years two through five of the base case (2022 to 2025) based on the following commodity price assumptions: WTI - US$55/bbl; WCS differential - US$12.50/bbl; MSW differential – US$5.50/bbl, NYMEX Gas - US$2.75/mcf;
AECO Gas - $2.75/mcf and Exchange Rate (CAD/USD) - 1.28. In the upside WTI scenarios, all other pricing assumptions are held constant
(4) Net Debt to Bank EBITDA ratio calculation is based on forecast net debt at each year-end and forecast Bank EBITDA for that particular year. Free cash flow is utilized to reduce net debt. See advisory for definitions of Non-GAAP
Financial and Capital Management Measures on page 3 of this presentation.
12Financial Liquidity
• Credit Facilities ~ 50% Balance Sheet (1) $ millions
Undrawn Credit facilities $487
• $511 million of undrawn credit Long-term notes $1,109
capacity and liquidity, net of Long-term debt $1,596
working capital, of $477 million Working Capital deficiency $34
Net Debt $1,630
• First long-term note maturity
C$548
not until 2024 Undrawn
• Repurchased and cancelled
US$106 million of 2024 long- US$400
Long-Term Notes Maturity Schedule (2) ($ millions)
term notes in 2021
Repurchased and
cancelled in 2021 US$106
US$500
(1) Balance sheet as at June 30, 2021. Revolving credit facilities mature April 2024 and are
comprised of a US$575 million facility and a $300 million term loan facility. Revolving Principal amount
credit facilities are not borrowing base facilities and do not require annual or semi-annual outstanding as of July
US$294
reviews. 2021
(2) S&P corporate rating “B” and senior unsecured debt rating “B+” ; Fitch corporate rating
and senior unsecured debt rating “B”; Moody’s corporate rating “B2” and senior
unsecured debt rating “B3”. 2021 2022 2023 2024 2025 2026 2027 2028
13Crude Oil Hedge Portfolio
Q3/2021 Q4/2021 H2/2021 2022
WTI Fixed Hedges (1)
Volumes (bbl/d) 4,000 4,000 4,000 10,000
Fixed Price (US$/bbl) $45.00 $45.00 $45.00 $53.50
WTI 3-Way Option (2)
Volumes (bbl/d) 17,500 17,500 17,500 10,500
Average Sold Put / Put / Sold Call (US$/bbl) $35/$45/$52 $35/$45/$52 $35/$45/$52 $48/$58/$68
Total Hedge Volumes (bbl/d) 21,500 21,500 21,500 20,500
Hedge (%) (3) 45% 45% 45% 42%
Basis Differential Hedges
WCS Volumes (bbl/d) 11,000 11,000 11,000 12,000
WCS Price Relative to WTI (US$/bbl) ($13.23) ($13.23) ($13.23) ($12.40)
MSW Volume (bbl/d) 7,500 7,500 7,500 4,000
MSW Price Relative to WTI (US$/bbl) ($5.03) ($5.03) ($5.03) ($4.43)
(1) WTI fixed hedges for 2022 include 10,000 bbl/d of swaptions where the counterparty has the right, if exercised on December 31, 2021, to enter into a swap transaction for the volumes and price indicated.
(2) WTI 3-way options consist of a sold put, a bought put and a sold call. In a $48/$58/$68 example, Baytex receives WTI+$10/bbl when WTI is at or below $48/bbl; Baytex receives $58/bbl when WTI is
between $48/bbl and $58/bbl; Baytex receives WTI when WTI is between $58/bbl and $68/bbl; and Baytex receives $68/bbl when WTI is above $68/bbl.
(3) Percentage of hedged volumes are based on 2021 annual production guidance (excluding NGL), net of royalties
142021E Adjusted Funds Flow Sensitivities
Estimated Effect on Annual Adjusted Funds Flow ($MM)
Sensitivities
Excluding Hedges Including Hedges
Change of US$1.00/bbl WTI crude oil $22.7 $13.0
Change of US$1.00/bbl WCS heavy oil differential $7.1 $3.2
Change of US$1.00/bbl MSW light oil differential $6.9 $4.2
Change of US$0.25/mcf NYMEX natural gas $8.7 $5.0
Change of $0.01 in the C$/US$ exchange rate $5.1 $5.1
15Asset Overview
Asset Highlights
Geographic and play diversification with ~ 10 or more years drilling inventory in each core area
Eagle Ford Viking Heavy Oil Pembina Duvernay
Production 30,400 boe/d 17,800 boe/d 23,800 boe/d 1,900 boe/d
(Gross; H1 2021)
Oil and NGLs 79% 90% 91% 82%
(Gross; H1 2021)
2P Reserves (1) 215 mmboe 85 mmboe 123 mmboe 17 mmboe
(Gross)
19,851 net acres in the 419,615 net acres of Dominant land position 148,480 net acres of
core of Karnes county land in the Viking play of 672,640 net acres 100% W.I. lands in the
with outstanding Shallow, light oil, strong Low decline production Pembina area
operating partner, netback asset with provides capital Offset development and
Marathon. “manufacturing” allocation flexibility 9 wells drilled to-date
Stable production base development Innovative multi-lateral have de-risked ~ 40% of
with low sustaining Technical horizontal drilling acreage position
Asset capital has driven ~ advancements drive generates top tier capital Measured delineation
Highlights $923 million of asset productivity efficiencies planned
level free cash flow improvements
since 2016 (2)
Enhanced completions
continue to drive step
change in performance
(1) Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd. See “Advisories”.
(2) The term “asset level free cash flow” is a non-GAAP measure. See slide 3 for more information.
17Eagle Ford: Core of Karnes County
• 19,900 net acres in the
core of the Eagle Ford
shale in south Texas
Wilson
• Four AMI’s (Longhorn,
Sugarloaf, Ipanema and
Excelsior) with average
25% W.I.
Karnes
• H1/2021 production of
LONGHORN 30,400 boe/d (79%
liquids)
Atascosa
• H1/2021 - 62 gross (17.2
SUGARLOAF
net) wells established
average 30-day IP rates of
IPANEMA
EXCELSIOR ~ 1,600 boe/d per well
• Expect to bring ~ 22 net
wells on production in
Live Oak 2021
Bee
Oil Condensate Dry Gas
18Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory
> 10 year drilling inventory (2)
Asset Level Free Cash Flow (1) (C$ millions) 300 ~ 250 net
locations
$923 million cumulative asset level 250
free cash flow since 2016 200
150
~ 22
100
$124 net wells
50 on- stream
$96
0
2021 Program Remaining Undrilled
Inventory
$238
Well Economics (3)
$285 WTI Oil Price $50/bbl $60/bbl
Payout: 0.9 years 0.6 years
IRR: 101% 203%
$138
Recycle Ratio: 3.2x 4.0x
$42
Breakeven:
US$30/bbl
2016 2017 2018 2019 2020 H1 2021 (10% IRR)
(1) Asset level free cash flow represents field level operating netback less exploration and development capital. For illustrative purposes only and should not be relied upon as indicative of future results.
Baytex’s actual results may vary.
(2) Net locations includes 210 proved plus probable undeveloped reserves locations at year-end 2020 and 38 unbooked future locations. See “Advisories”
(3) Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type curve that uses the following assumptions: well cost US$5 million (6,000 foot
lateral); IP365 - 700 boe/d; EUR – 800 mboe).
19Viking Light Oil: 460 Highly Prospective Sections
• Shallow (700 m), light oil
(36° API) resource play
with strong netbacks
• Produced 17,800 boe/d
(90% oil) in H1/2021
• Drilling activity resumed
in December with two
rigs mobilized
Kerrobert
Plenty
Esther/Hoosier
Greater Gleneath
• Capital reduction effort
Lucky Hills/Whiteside Dodsland
and operational
efficiencies drive costs
down ~ 10%
Mantario (Laporte)
Plato
• Expect to bring ~ 120 net
wells on production in
2021
Baytex Lands
20Technical Advancements Drive Productivity Improvement
Shift to ERH(1) Wells Drives Productivity 95%+ of Viking Development now
Improvements ERH Wells
400 100%
Viking Wells by Vintage 350
90%
80 80%
300
70%
70 250
60%
60 200 50%
Oil Rate (bbl/d)
50 40%
150
30%
40 100
20%
30 50
10%
20 0 0%
2012 2013 2014 2015 2016 2017 2018 2019 2020
10 Net Wells Onstream (Left Axis) ERH (%) (Right Axis)
0
- 5,000 10,000 15,000 20,000 25,000 Well Economics (2)
Cum Oil (bbl) WTI Oil Price $50/bbl $60/bbl
2020 Wells 2019 Wells 2018 Wells 2017 Wells 2016 Wells Payout: 1.8 years 1.1 years
2015 Wells 2014 Wells 2013 Wells 2012 Wells IRR: 33% 77%
Recycle Ratio: 1.5x 1.9x
(1) Extended Reach Horizontal (“ERH) wells are ¾ to 1 mile long laterals drilled to a depth of approximately 700 metres.
(2) Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type Breakeven:
US$42/bbl
curve that uses the following assumptions: well cost - $950,000; IP 365 - 50 boe/d; EUR - 40 mboe. MSW differential (10% IRR)
assumption US$4/bbl.
21Peace River: Innovative Multi-Lateral Development
Performance Drivers
• Produced 13,700 boe/d in
H1/2021 (86% oil)
Golden • Dominant 560 net sections
• Three net Bluesky multi-lateral
wells planned for H2/2021
Seal Peavine Lands
Harmon Valley
• Strategic agreements with
Peavine Métis Settlement cover
80 contiguous sections
• Early stage exploratory play
targeting Spirit River formation,
a Clearwater formation
Reno equivalent
Peavine • Five net wells on production -
two successful appraisal wells
(2-laterals each); three
Baytex Lands
additional wells (8-laterals each)
on production
22Northwest Clearwater: Extending the Trend
Peavine
14-36 Pad
7
5-33 Pad 5
4 6
1
2
3
• > 500 net sections in the NW
Clearwater fairway with > 120
prospective for Spirit River
(Clearwater equivalent)
• Executed second strategic land
agreement with the Peavine Métis
Settlement; increased land position
by a further 20 sections to 80
contiguous sections 30-Day IP Rate
Well Spud Rig Release # of Laterals (bbl/d) (1)
1 100/04-34 January 7 January 15 2 175
• Aligns strongly with our core 2 102/04-34 June 15 June 21 2 175
competencies with over a decade of 3 100/13-27 June 22 July 6 8 695
experience in heavy oil exploration 4 100/05-34 July 8 July 18 8 412
and multi-lateral development 5 102/11-31 July 20 August 4 8 930
6 100/06-31 Q4 Q4 8 ---
7 100/14-31 Q4 Q4 8 ---
(1) 30-Day Initial Production Rate (bbl/d) is defined as the average oil rate over the first 720 hours of production 23
following drilling fluid recovery.Northwest Clearwater – Promising Early Results with Strong Economics
Operations Update Top 10 Clearwater Wells (1)
• Five producing wells
Peak Calendar Rate
No. UWI Current Operator
• Production increased from zero at the (bbl/day)
beginning of the year to > 2,300 bbl/d 1 102/11-31-078-15W5/00 BAYTEX 896
2 100/13-27-078-16W5/00 BAYTEX 844
• Two Baytex 8-lateral wells rank as the top
3 102/12-34-074-25W4/00 HWX (CVE) 733
Clearwater wells drilled to-date; both are 4 HWX (CVE) 670
100/16-35-074-25W4/00
outperforming Baytex type curve 5 100/16-26-074-25W4/02 HWX 670
assumptions 6 102/12-31-074-24W4/06 HWX (CVE) 634
7 100/13-34-074-25W4/00 HWX (CVE) 617
8 100/01-11-074-25W4/00 DELTASTREAM 589
Q4/2021 Activity 9 104/05-17-073-24W4/08 CNRL 584
10 102/01-14-074-25W4/00 DELTASTREAM 575
• Drilling two wells on the 14-36 pad adjacent
to the highest rate well drilled to-date Well Economics (2)
• Construction of access roads and surface
pad locations for 2022 development activity WTI Oil Price $50/bbl $60/bbl
Payout: 0.9 years 0.5 years
Preliminary 2022 Plan IRR: 108% 335%
Recycle Ratio: 2.2x 3.4x
• Expect to execute an expanded program of
12 to 18 wells in 2022 Breakeven:
US$33/bbl
(10% IRR)
• 20 sections de-risked with potential for
greater than 200 locations pending further (1) Public data obtained from GeoScout. Baytex well results represent an estimate of the calendar
success rate for the month of September.
(2) Individual well economics based on constant pricing and costs, and Baytex’s assumptions
regarding an expected type curve that uses the following assumptions: development well cost -
$1.4 million; IP30 - 335 bbl/d, IP 365 - 180 bbl/d; EUR – 170 mboe; WCS differential assumption
US$12/bbl.
24Lloydminster: Significant Land Position and Drilling Inventory
Performance Drivers
• Produced 10,100 boe/d in
H1/2021 (98% oil)
Ardmore/Cold Lake • Strong capital efficiencies
• Applying multi-lateral
horizontal drilling and
Lindbergh
production techniques
Lloydminster Tangleflags
• ~ 22 net wells planned for
Soda Lake
H2/2021
Kerrobert
ALBERTA SASKATCHEWAN
Baytex Lands
25Heavy Oil Innovation
Peace River Lloydminster
Multi-Lateral Horizontal Horizontal
Well Economics (1)
WTI Oil Price $50/bbl $60/bbl WTI Oil Price $50/bbl $60/bbl
Payout: 1.7 years 0.9 years Payout: 1.4 years 0.9 years
IRR: 51% 129% IRR: 62% 136%
Recycle Ratio: 2.5x 3.8x Recycle Ratio: 2.0x 2.9x
Breakeven: Breakeven:
US$42/bbl US$42/bbl
(10% IRR) (10% IRR)
(1) Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type curve that uses the following assumptions: Peace River (Bluesky development)
well cost - $2.5 million; IP 365 - 215 boe/d; EUR – 300 mboe; Lloydminster well cost - $0.8 million ; IP 365 - 50 boe/d; EUR – 60 mboe. WCS differential assumption US$12/bbl.
26Pembina Area Duvernay Light Oil: Emerging Resource Play
Pembina Duvernay
• 232 sections of 100% WI lands
• Nine wells drilled to date have
delineated a minimum of 100-
125 sections
• Produced 1,900 boe/d (82%
liquids) in H1/2021
• Two wells drilled in 2020
Black Oil demonstrate repeatability of 11-
30 pad completed in 2019
Volatile
• 10-16 generated a 30-day IP
Liquids Rich Gas Oil rate of 1,300 boe/d (69% oil);
11-16 generated a facility
constrained 30-day IP rate of
900 boe/d (68% oil)
Baytex Lands
Rimbey Leduc Reef
Liquids • Two wells to be drilled and
Rich Gas
completed in Q3/2021
Producing Pads (7 wells) Two wells (10-16, 11-16) Two wells (06-08, 07-08)
pre-2020 onstream November 2020 expected onstream Q3 2021
27High Quality Oil Development
Eagle Ford Viking Peace River Lloydminster Pembina Duvernay
Formation Lower Eagle Ford Viking Bluesky Mannville Group Duvernay
Upper Eagle Ford
Austin Chalk
Depth (metres) 3,300-3,900 700 600 350-800 2,200-2,400
Oil API Oil: 40-45° 36° 11° 10-16° 42-44°
Condensate: 44-55°
Porosity 4.6% - 9% 23% 28% 30% 3% - 6%
Permeability 0.33 - 0.41 millidarcies 0.5 - 50 millidarcies 1 - 5 darcies 0.5 - 5 darcies 10 nanodarcy
Horizontal slotted liner /
Completion Plug and perf Pin point coil Open hole multi-lateral open-hole multi-lateral Plug and perf
Expected Well Costs
(drill, complete, equip and tie-in) US$5 million $950,000 $2.5 million $800,000 $7.0 million
6,000 foot lateral
Land - gross (net) sections 122 (31) 763 (656) 562 (560) 637 (491) 232 (232)
Pembina area
Reserves at YE 2020 (mmboe)
Proved developed producing 68 22 15 8 3
Proved 153 57 19 25 8
Proved plus probable 215 85 39 84 17
Drilling inventory (risked) at
YE 2020 – net locations
(booked/unbooked) 210 / 38 1,268 / 443 65 / 163 173 / 417 25 / 278
28Environment, Social and Governance (ESG)
ESG at Baytex
As a responsible energy company, we take a sustainable approach to managing and
developing our business into the future. We aspire to create an organization that future
generations will be proud to be a part of.
30How Focusing on ESG Creates Value
By incorporating
environmental, social
and governance
factors into our
business and reporting
on our performance,
we create value for
shareholders and
remain focused on
advancing a
responsible energy
future.
31Our ESG Targets
32Supplementary Information
Summary of Operating and Financial Metrics
Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 2020 Q1 2021 Q2 2021
Benchmark Prices
WTI crude oil (US$/bbl) $54.90 $59.81 $56.45 $56.96 $57.03 $46.17 $27.85 $40.93 $42.66 $39.40 $57.84 $66.07
NYMEX natural gas (US$/mcf) $3.15 $2.64 $2.23 $2.50 $2.63 $1.95 $1.72 $1.98 $2.66 $2.08 $2.69 $2.83
Production
Crude oil (bbl/d) 71,939 69,905 68,541 70,956 70,328 74,571 50,783 56,239 51,293 58,198 57,419 58,403
Natural gas liquids (bbl/d) 11,729 10,986 9,543 8,699 10,229 7,822 7,634 7,417 6,495 7,340 6,238 7,563
Natural gas (mcf/d) 104,682 105,065 101,054 100,236 102,742 96,356 84,546 84,945 76,116 85,464 90,739 91,172
Oil equivalent (boe/d) (1) 101,115 98,402 94,927 96,360 97,680 98,452 72,508 77,814 70,475 79,781 78,780 81,162
% Liquids 83% 82% 82% 83% 82% 83% 81% 82% 82% 82% 81% 81%
Netback ($/boe)
Total sales, net of blending and other
expenses (2) $47.98 $51.49 $47.14 $48.25 $48.72 $35.19 $22.31 $33.79 $34.35 $31.75 $51.84 $57.19
Royalties (8.94) (9.67) (8.59) (8.72) (8.98) (6.33) (4.42) (5.59) (5.83) (5.61) (9.44) (11.04)
Operating expense (11.02) (11.22) (11.15) (11.23) (11.16) (11.66) (11.17) (10.26) (12.30) (11.35) (11.36) (11.22)
Transportation expense (1.46) (1.33) (1.13) (1.00) (1.23) (1.15) (0.76) (0.89) (1.03) (0.97) (1.24) (1.01)
Operating Netback (4) $26.56 $29.27 $26.27 $27.30 $27.35 $16.05 $5.96 $17.05 $15.19 $13.82 $29.80 $33.92
General and administrative (1.55) (1.28) (1.14) (1.12) (1.28) (1.09) (1.13) (1.08) (1.44) (1.17) (1.23) (1.44)
Cash financing and interest (3.10) (3.14) (3.06) (2.75) (3.01) (3.19) (4.15) (3.55) (3.89) (3.65) (3.44) (3.19)
Realized financial derivative gain (loss) 2.07 1.45 2.39 2.59 2.12 3.00 2.06 (1.36) 2.64 1.64 (2.93) (5.28)
Other (3) 0.28 0.07 (0.03) 0.16 0.13 0.07 (0.03) (0.09) 0.17 0.03 (0.12) (0.20)
Adjusted funds flow (4) $24.26 $26.37 $24.43 $26.19 $25.31 $14.84 $2.71 $10.97 $12.67 $10.67 $22.08 $23.81
(1) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
(2) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the
realized pricing on our produced volumes to the WCS benchmark.
(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share based compensation. Refer to the Q2 2021 MD&A for further
information on these amounts.
(4) The terms “operating netback” and “adjusted funds flow” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not
be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures on slide 3 of this presentation.
342021 Guidance and Cost Assumptions
Exploration and development expenditures ($ millions) $285 - $315
Production (boe/d) 79,000 – 80,000
Expenses:
Royalty rate (%) 18% - 18.5%
Operating ($/boe) $11.25 - $12.00
Transportation ($/boe) $1.15 - $1.25
General and administrative ($ millions) $42 ($1.45/boe)
Interest ($ millions) $95 ($3.27/boe)
Leasing expenditures ($ millions) $4
Asset retirement obligations ($ millions) $6
35Contact Information
Baytex Energy Corp. Edward D. LaFehr
President and Chief Executive Officer
Suite 2800, Centennial Place 587.952.3000
520 – 3rd Avenue S.W.
Calgary, Alberta T2P 0R3 Rodney D. Gray
T 587.952.3000 Executive Vice President & Chief Financial Officer
Toll Free 1.800.524.5521 587.952.3160
Brian G. Ector
www.baytexenergy.com Vice President, Capital Markets
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