Investor Presentation - February 2021 - Baytex Energy Corp.
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Investor Presentation February 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 $250 million of free cash flow ($0.45 per share) in 2022; 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 weare 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 priorities are to invest at sustaining capital levels of $225 to $275 million, deliver stable production of 73,000 to 77,000 boe/d and maximize free flow and focus on continued
deleveraging; our 2021 free cash flow profile at certain price assumption; that improved capital efficiencies and high graded inventory increase sustainability at lower prices; the number of
economic drilling locations we have at various oil prices and the expected capital efficiency of our capital spending in 2021; that our 2021 capital program is fully funded at US$35/bbl WTI, 85%
will be directed to high netback light oil assets, we will generate capital efficiencies of ~$12,000, intend to implement a heavy oil program with 36 net wells in H2/2021 and have the potential to
further advance Pembina Duvernay; for 2021: our capital budget, our estimated boe/d production, the percentage of our production expected to be oil and NGLs, our capital allocation plans by
area and number of wells we expect to bring on stream; in 2021, that we expect to have > $550 million of liquidity and an estimated Net Debt to EBITDA ratio of less than 2.5x; our expected
2021 Net Debt to Bank EBITDA ratios at certain WTI oil prices; the sensitivity of our expected 2021 adjusted funds flow to changes in WTI prices, WCS and MSW differentials, natural gas prices
and the Canada-United States foreign exchange rate; for the Eagle Ford that enhanced completions continue to drive step change in performance, we expect to bring 18 net wells on production
in 2021 and stable production and deep inventory drive asset level free cash flow; for the Viking that we have meaningful extended reach inventory, 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, ~6 net wells planned for H2/2021 in Peace River, first activity on Peavine lands is planned for 2021; ~30 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 up to 4 wells planned for H@/2021; the expected drill,
complete, equip and tie-in well costs, reserves and drilling inventory for our Eagle Ford, Peace River, Lloydminster, Viking and Pembina Duvernay assets; that we are committed to corporate
sustainability; 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
2
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, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission not later than March 31, 2021 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 February 24, 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.
“Senior secured debt” is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at December 31, 30, 2020, the Company's Senior
Secured Debt totaled $666.2 million which includes $651.2 million of principal amounts outstanding and $15.0 million of letters of credit.
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 > $250 million ($0.45 per share) of free cash
Flow Generation flow in 2021 (1)
Financial Liquidity and ▪ Credit facilities ~ 35% undrawn and liquidity > $300 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 ▪ ~ 50% of net crude oil exposure hedged for 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 pricing assumptions: WTI - US$58/bbl; WCS differential - US$12/bbl; MSW differential – US$4/bbl, NYMEX Gas -
US$3.00/mcf; AECO Gas - $3.05/mcf and Exchange Rate (CAD/USD) - 1.27.
(2) As at December 31, 2020.
5
Corporate Profile
Market Summary
Ticker Symbol TSX: BTE
Average Daily Volume (1) 8.4 million
Shares Outstanding (2) 561 million
Market Capitalization / Enterprise Value (2) $628 million / $2,476 million
Operating Statistics
Production (Gross W.I.) (3) 73,000 – 77,000 boe/d
Production Mix (3) 81% liquids
PEACE RIVER
DUVERNAY
LLOYDMINSTER
E&D Expenditures (3) $225 to $275 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
Oil
Eagle
Heavy Ford
Oil NGLs
Light
EAGLE FORD
Viking Light Oil
Oil
(1) Average daily trading volumes for January 2021. Volumes are a composite of all exchanges in Canada.
(2) Enterprise value based on closing share price on the Toronto Stock Exchange on February 23, 2021 and shares outstanding and net debt as at December 31, 2020.
(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
ESG Highlights
GHG Emission Reduction Safety
46% reduction in GHG 41% reduction in lost time
emissions intensity through incident frequency in 5
year-end 2020, relative to years
2018 baseline
Gas Conservation Indigenous Relations
99.5% routine gas Recent agreements with
conservation in Peace River Woodland Cree First
in 2019 Nation and Peavine Métis
Settlement
Spill Volumes Gender Diversity
42% reduction in spill 25% women Board
volumes over 5 years members as of April 2021
7
2020 Highlights
We responded aggressively to the downturn brought on by Covid-19, improved our
cost structure and capital efficiencies, and enhanced our overall sustainability
Action 2020 Highlights
• Extended maturity of credit facilities to April 2024
Negotiated bank credit facility
extension and refinanced long-term • Issued US$500 million principal amount of long-term notes due April 2027
notes • Redeemed two series of senior unsecured notes - US$400 million due
2021 and $300 million due 2022
• Identified cost savings of ~$100 million, capital budget reduced by ~ 50%
Delivered on our commitment to • Maintained strong operating efficiency with production and capital
preserve financial Liquidity, capture spending in line with guidance
cost savings and generate free cash
• Generated $18 million of free cash flow in 2020
flow
• Maintained liquidity of > $300 million
• Capital reduction re-set production base to ~ 75,000 boe/d
High graded portfolio and economic • Improved capital efficiencies and moderated production decline rate
inventory
• Ability to generate free cash flow in a US$40 to $45/bbl WTI environment
Established Covid-19 task force and • Effective response to Covid-19 with on-going training, communication and
flexible working team work strategies
8
2021 Priorities and Free Cash Flow Profile
2021 Priorities
Free Cash Flow Profile (1) (2)
Invest at sustaining capital levels $700
of $225 to $275 million
$600
$500
Deliver stable production of $400
$ millions
73,000 to 77,000 boe/d
$300
$200
Maximize free cash flow and focus
$100
on continued de-leveraging
$0
US$50 US$55 US$60 US$65
Adjusted Funds Flow Capital Spending Free Cash Flow
(1) For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary.
(2) Pricing assumptions: WCS differential - US$12/bbl; MSW differential – US$4/bbl, NYMEX Gas - US$3.00/mcf; AECO Gas - $3.05/mcf; Exchange Rate (CAD/USD) - 1.27.
9
High Graded Portfolio with Strong Capital Efficiencies
Improved capital efficiencies and high graded inventory increases
sustainability at lower prices
Economic Drilling Locations (1)
Capital Efficiency (2)
3,000
$17,000
2,500 per boe/d
Net Wells
2,000
$12,000
1,500 per boe/d
1,000
500
0
US$50 US$55 US$60 US$65 2020 Budget 2021 Budget
Viking Eagle Ford Heavy Oil Duvernay
(1) Economic drilling locations are defined as individual well locations generating an internal rate of return of > 20% and a payout of < 24 months under flat WTI pricing assumptions. Economic drilling locations include both booked and
un-booked locations, see slide 4 for a description of our booked and un-booked locations as at December 31, 2020.
(2) See advisory for definitions of Non-GAAP Financial and Capital Management Measures on page 3 of this presentation.
102021 Capital Program
2021 Guidance (1)
• Cash neutrality (capital program fully
funded) at US$35/bbl WTI E&D CapEx $225 - 275 million
Production 73,000 - 77,000 boe/d
• Capital efficiencies of approximately Oil and NGLs 81%
$12,000 per boe/d across the
portfolio Capital Budget CapEx ($MM) (2)
Drill, complete and equip $235
• 85% directed to our high netback Facilities $10
light oil assets in the Eagle Ford and
Viking Land and seismic $5
Total $250
• Intend to implement a heavy oil
program in H2/2021 Net Wells
Operating Area Onstream CapEx ($MM) (2)
• Potential to further advance our Viking 120 $110
Pembina Duvernay development Eagle Ford 18 $100
Heavy Oil 28 $25
East Duvernay 2 $15
Total $250
(1) 2021 capital spending is approximately 50% weighted to the first half of the year. Eagle Ford
development includes 10 net wells drilled and 18 net wells on production. Heavy oil (up to 36
net wells) and Duvernay (up to 4 net wells) are scheduled for H2/2021 and dependent on
crude oil prices.
(2) Represents mid-point of 2021 guidance range.
11Financial Liquidity
Balance Sheet (2) $ millions
• Credit Facilities ~ 35% Credit facilities $651
Undrawn
Long-term notes $1,148
• $367 million of undrawn credit Long-term debt $1,799
capacity and liquidity, net of Working Capital deficiency $48
working capital, of $319 million
Net Debt $1,848
• Financial liquidity expected to
increase to > $550 million in Long-Term Notes Maturity Schedule (3) ($ millions)
2021(1)
C$548
Undrawn
• First long-term note maturity
not until 2024 US$400 US$500
US$400 C$300
• 2021E Net Debt to EBITDA
2021 2022 2023 2024 2025 2026 2027 2028
ratio < 2.5x (1)
2021E Net Debt to Bank EBITDA Ratio (4)
(1) 2021 pricing assumptions: WTI - US$58/bbl; WCS differential - US$12/bbl; MSW
differential – US$4/bbl, NYMEX Gas - US$3.00/mcf; AECO Gas - $3.05/mcf and 3.0x
Exchange Rate (CAD/USD) - 1.27.
2.5x
(2) Balance sheet as at December 31, 2020. Revolving credit facilities mature April 2024 and 2.2x
are comprised of a US$575 million facility and a $300 million term loan facility. Revolving 1.9x
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 US$50 US$55 US$60 US$65
Capital Management Measures on page 3 of this presentation.
WTI (US$/bbl)
12Crude Oil Hedge Portfolio
Full-Year
H1/2021 H2/2021
2021
WTI Fixed Hedges
Volumes (bbl/d) 4,000 4,000 4,000
Fixed Price (US$/bbl) $45.00 $45.00 $45.00
WTI 3-Way Option
Volumes (bbl/d) 17,500 17,500 17,500
Average Sold Put / Put / Sold Call (US$/bbl) (1) $35/$45/$52 $35/$45/$52 $35/$45/$52
Total Hedge Volumes (bbl/d) 21,500 21,500 21,500
Hedge (%) (2) 48% 48% 48%
Basis Differential Hedges
WCS Volumes (bbl/d) 12,500 11,000 11,750
WCS Price Relative to WTI (US$/bbl) ($13.38) ($13.23) ($13.31)
MSW Volume (bbl/d) 7,000 7,500 7,250
MSW Price Relative to WTI (US$/bbl) ($5.07) ($5.03) ($5.05)
(1) WTI 3-way options consist of a sold put, a bought put and a sold call. In a $35/$45/$52 example, Baytex receives WTI+$10/bbl when WTI is at or below $35/bbl; Baytex receives $45/bbl when WTI is
between $35/bbl and $45/bbl; Baytex receives WTI when WTI is between $45/bbl and $52/bbl; and Baytex receives $52/bbl when WTI is above $52/bbl.
(2) Percentage of hedged volumes are based on 2021 annual production guidance (excluding NGL), net of royalties
132021E Adjusted Funds Flow Sensitivities
Estimated Effect on Annual Adjusted Funds Flow ($MM) (1)
Including
Including
Sensitivities Hedges when
Excluding Hedges when
WTI is between
Hedges WTI is >
US$45/bbl and
US$52.40/bbl
US$52.40/bbl
Change of US$1.00/bbl WTI crude oil $22.7 $20.7 $13.0
Change of US$1.00/bbl WCS heavy oil differential $7.1 $3.2 $3.2
Change of US$1.00/bbl MSW light oil differential $6.9 $4.2 $4.2
Change of US$0.25/mcf NYMEX natural gas $8.7 $5.0 $5.0
Change of $0.01 in the C$/US$ exchange rate $5.1 $5.1 $5.1
14Asset 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 31,200 boe/d 19,600 boe/d 23,300 boe/d 1,500 boe/d
(Gross; 2020)
Oil and NGLs 77% 91% 91% 82%
(Gross; 2020)
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 acres of 100%
core of Karnes county land in the Viking play of 672,640 net acres W.I. lands in the
with world class partner, ▪ Shallow, light oil, strong ▪ Low decline production Pembina area
and operator in 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 delineated ~ 40%
with low sustaining ▪ Technical horizontal drilling of acreage position
Asset capital has driven ~ advancements drive generates top tier capital ▪ Measured delineation
Highlights $800 million of asset productivity efficiencies planned
level free cash flow improvements
since 2016 (2)
▪ Enhanced completions
continue to drive step
change in performance
(1) Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd. See “Advisories”.
(2) The term “asset level free cash flow” is a non-GAAP measure. See slide 3 for more information.
16Eagle Ford: Core of Karnes County
• 19,900 net acres in the
core of the Eagle Ford
shale in south Texas
Wilson
• Four AMI’s (Longhorn,
Sugarloaf, Ipanema and
Excelsior) with average
25% W.I.
Karnes
• 2020 production of 31,179
LONGHORN boe/d (77% liquids)
Atascosa
• 2020 - 62 gross (14.1 net)
wells established average
SUGARLOAF
30-day IP rates of ~ 1,650
boe/d per well
IPANEMA
EXCELSIOR
• Expect to bring ~ 18 net
wells on production in
2021
Live Oak
Bee
Oil Condensate Dry Gas
17Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory
> 10 year drilling inventory (2)
Asset Level Free Cash Flow (1) (C$ millions) 300 ~ 250 net
locations
$800 million cumulative asset level 250
free cash flow since 2016 200
150
~ 18
100
net wells
$96
50 on- stream
0
2021 Program Remaining Undrilled
$238
Inventory
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 (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).
18Viking Light Oil: 460 Highly Prospective Sections
• Shallow (700 m), light oil
(36° API) resource play
with strong netbacks
• Produced 19,600 boe/d
(91% oil) in 2020
• 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
19Technical 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.
20Peace River: Innovative Multi-Lateral Development
Performance Drivers
• Produced 11,800 boe/d in 2020
(84% oil)
Golden
• Dominant 560 net sections
• ~ 6 net wells planned for H2/2021
Seal
Harmon Valley
Peavine Lands
• Q1/2020 strategic agreement
with Peavine Metis settlement
• 60 sections of land
• Early stage exploratory play
Reno targeting Spirit River formation,
a Clearwater formation
Peavine
equivalent
• First activity planned for 2021
Baytex Lands
21Lloydminster: Significant Land Position and Drilling Inventory
Performance Drivers
• Produced 11,500 boe/d in
2020 (98% oil)
Ardmore/Cold Lake • Strong capital efficiencies
• Applying multi-lateral
horizontal drilling and
Lindbergh
production techniques
Lloydminster Tangleflags
• ~ 30 net wells planned for
Soda Lake
H2/2021
Kerrobert
ALBERTA SASKATCHEWAN
Baytex Lands
22Heavy Oil Innovation
Lloydminster
Peace River
Horizontal
Multi-Lateral 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 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.
23Pembina 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 1,500 boe/d (82%
liquids) in 2020
• 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 • Up to four wells planned for
Rich Gas
H2/2021
Producing Pads (7 wells) Two wells (10-16, 11-16)
onstream November 2020
24High 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) – net
locations (booked/unbooked) 210 / 38 1,268 / 443 65 / 163 173 / 417 25 / 278
25Corporate Sustainability
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
Commitment to the health Commitment to
and safety of our minimizing our impact on
employees, contractors and air, water, land and life in
communities. the areas we operate.
Communities and Business Practice
Stakeholders and Compliance
Commitment to provide social Commitment to
and economic benefits to the governance, ethical
communities in which we business conduct, and
operate and to hear the regulatory compliance.
voices and concerns of our
stakeholders.
Baytex was recognized by Corporate Knights in 2018 as one of Canada’s
Top Sustainability Performers.
For more information and to view our most recent report, visit
http://www.baytexenergy.com
27GHG Emissions Reduction
Target to reduce GHG emission
intensity (tonnes of CO2 per boe)
by 65% by 2025. GHG Intensity Improvement and Target
0.120
65%
reduction
Our emissions reduction strategy
Tonnes of CO2 per boe
from baseline
includes: 0.080
• Increased gas conservation and
combustion
0.040
• Reusing associated gas as fuel
for field activities
• Reduced emissions from storage 0.112 0.095 0.061 0.041
-
tanks Baseline 2018 2019 2020 Target 2025
• Monitoring and preventing
fugitive emissions
28A Culture of Commitment
How it contributes to
Objective What we’ve done Result
value creation
Ensure our employees and 42% reduction in corporate spill
ENVIRONMENT
Reduces costs and maintains
Responsibly develop contractors uphold our procedures volumes, over 5 years
social license
our assets for spill prevention, response and
cleanup
Invested more than $100 million in 99.5% routine gas conservation in
Exceed regulatory Helps to build trust with
gas conservation activities in Peace Peace River in 2019
obligations regulators and stakeholders
River in the last 5 years
Tie safety targets to annual 41% reduction in employee Supports the consistent and
Create a culture of
performance incentive program +contractor LTIF in 5 years safe execution of our business
safety
plan
SOCIAL
Build mutually beneficial Entered into support and Maintain social license and
Be a good neighbour relationships based on trust development agreement with the enables growth in our
Peavine Métis Settlement in 2020 operations by reducing non-
technical project delays
Ensure our Board is comprised of 100% Board meeting attendance
GOVERNANCE
Ensure effective dedicated Directors who are and Sets strategic direction and
Board leadership invested in our success 25% women Board members as improves decision making
of April 2021
Communicate our ESG impacts by Recognized by Corporate Knights Enables shareholders and
Be transparent and publishing biennial sustainability as Future 40 Responsible stakeholders to make informed
accountable reports since 2012 Corporate Leaders in 2018 decisions
29Supplementary Information
Summary of Operating and Financial Metrics
Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 2020
Benchmark Prices
WTI crude oil (US$/bbl) $54.90 $59.81 $56.45 $56.96 $57.03 $46.17 $27.85 $40.93 $42.66 $39.40
NYMEX natural gas (US$/mcf) $3.15 $2.64 $2.23 $2.50 $2.63 $1.95 $1.72 $1.98 $2.66 $2.08
Production
Crude oil (bbl/d) 71,939 69,905 68,541 70,956 70,328 74,571 50,783 56,239 51,293 58,198
Natural gas liquids (bbl/d) 11,729 10,986 9,543 8,699 10,229 7,822 7,634 7,417 6,495 7,340
Natural gas (mcf/d) 104,682 105,065 101,054 100,236 102,742 96,356 84,546 84,945 76,116 85,464
Oil equivalent (boe/d) (1) 101,115 98,402 94,927 96,360 97,680 98,452 72,508 77,814 70,475 79,781
% Liquids 83% 82% 82% 83% 82% 83% 81% 82% 82% 82%
Netback ($/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
Royalties (8.94) (9.67) (8.59) (8.72) (8.98) (6.33) (4.42) (5.59) (5.83) (5.61)
Operating expense (11.02) (11.22) (11.15) (11.23) (11.16) (11.66) (11.17) (10.26) (12.30) (11.35)
Transportation expense (1.46) (1.33) (1.13) (1.00) (1.23) (1.15) (0.76) (0.89) (1.03) (0.97)
Operating Netback (4) $26.56 $29.27 $26.27 $27.30 $27.35 $16.05 $5.96 $17.05 $15.19 $13.82
General and administrative (1.55) (1.28) (1.14) (1.12) (1.28) (1.09) (1.13) (1.08) (1.44) (1.17)
Cash financing and interest (3.10) (3.14) (3.06) (2.75) (3.01) (3.19) (4.15) (3.55) (3.89) (3.65)
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
Other (3) 0.28 0.07 (0.03) 0.16 0.13 0.07 (0.03) (0.09) 0.17 0.03
Adjusted funds flow (4) $24.26 $26.37 $24.43 $26.19 $25.31 $14.84 $2.71 $10.97 $12.67 $10.67
(1) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
(2) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the
realized pricing on our produced volumes to the WCS benchmark.
(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share based compensation. Refer to the 2020 MD&A for further
information on these amounts.
(4) The terms “operating netback” and “adjusted funds flow” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not
be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures on slide 3 of this presentation.
31Reserves Summary (Gross)
2P Reserves Breakdown 2P Reserves by Asset 2P Reserves by Commodity
Pembina
Other
Duvernay
Natural
Gas
PDP
Probable Eagle
Heavy Oil
Ford Light Oil
Heavy & NGL
Oil
PDNP +
PUD
Viking
Pembina
Category (1) Eagle Ford Viking Heavy Oil Other Total
Duvernay
Proved Developed Producing 68 22 23 3 4 120
Total Proved 153 57 44 8 9 271
Total Proved Plus Probable 215 85 123 17 22 462
(1) Baytex reserves as at December 31, 2020 as evaluated by McDaniel & Associates Consultants Ltd.
322021 Guidance and Cost Assumptions
Exploration and development expenditures ($ millions) $225 - $275
Production (boe/d) 73,000 – 77,000
Expenses:
Royalty rate (%) 18% - 18.5%
Operating ($/boe) $11.50 - $12.25
Transportation ($/boe) $1.00 - $1.10
General and administrative ($ millions) $42 ($1.53/boe)
Interest ($ millions) $105 ($3.84/boe)
Leasing expenditures ($ millions) $4
Asset retirement obligations ($ millions) $6
33Notes
34Contact 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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