Investor Presentation · 2020-06-30 · 2 Forward Looking Statements Any “financialoutlook”or...
Transcript of Investor Presentation · 2020-06-30 · 2 Forward Looking Statements Any “financialoutlook”or...
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Investor Presentation
July 2020
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Forward Looking Statements
Any “financial outlook” or “future oriented financial information” in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial
outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are
cautioned that reliance on such information may not be appropriate for other circumstances.
In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of future plans and operations, certain
statements in this presentation are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information"
within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as
"anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or
similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this presentation peak only as of the date hereof and are expressly qualified by
this cautionary statement.
Specifically, this presentation contains forward-looking statements relating to but not limited to: that we have 10+ years of inventory in core areas, strong capital efficiencies and flexibility on
discretionary capital; the percentage of our net crude oil exposure that is hedged and the expected gain on our 2020 financial contracts; that we have a consistent approach to risk
management and are committed to strong ESG performance; our GHG emissions intensity reduction target; expectations for 2020 as to Baytex’s production on a boe/d basis, percentage of
production that will be liquids, exploration and development expenditures, production by area and commodity; we are focused on protecting the health and safety of personnel while maintaining
opeartions; our 2020 outlook, including: to maintain financial liquidity, minimize capital outlays and emphasize cost reductions, our expectations with respect to activity in the eagle Ford and
shut-in volumes, planned net wells and exploration and development expenditures by operating area and $135 million of expected type and impact of cost reductions for 2020; the sensitivity of
our expected 2020 adjusted funds flow to changes in WTI prices, WCS and MSW differentials, natural gas prices and the Canada-United States foreign exchange rate; for the Eagle Ford that
enhanced completions continue to drive step change in performance, we expect to bring 16-18 wells on production in 2020 and stable production and deep inventory drive asset level free cash
flow; for the Viking that we have meaningful extended reach inventory, additional EOR potential and that 2020 program is suspended pending recovery in oil prices; in Heavy Oil, that low
decline production provides capital allocation flexibility, innovative multi-lateral horizontal drilling generates strong capital efficiencies and activity is planned on Peavine lands in 2021; for the
Pembina Area Duvernay that completion activity for Q1/2020 wells is deferred indefinitely; the expected drilling and completion well costs, reserves and drilling inventory for our Eagle Ford,
Peace River, Lloydminster, Viking and Pembina Area Duvernay assets; that we are committed to corporate sustainability and the components of our GHG emissions reduction strategy; and
our 2020 guidance for exploration and development expenditures, production, royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures
and asset retirement obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on
certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future. In addition, information and
statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described
exist in quantities predicted or estimated, and that they can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil
prices; well production rates and reserve volumes; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow
under credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for operating activities; the availability and cost of labour and other industry services;
interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the ability to develop crude oil and natural gas properties in
the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated).
Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not
limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); availability and cost of gathering, processing and pipeline systems; failure to
comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks
associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our
properties and our ability to acquire reserves; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil
and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions
or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; changes in income tax or other laws or
government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated
with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects;
Advisory
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Advisory (Cont.)
alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; risks associated with the ownership of our securities, including
changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and
production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed
in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2019, filed with Canadian securities regulatory
authorities and the U.S. Securities and Exchange Commission and in our other public filings.
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete
perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements. The future oriented financial
information and forward-looking statements are made as of May 7, 2020 and Baytex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of
new information, future events or results or otherwise, other than as required by applicable securities laws.
Non-GAAP Financial and Capital Management Measures
This presentation contains certain financial measures that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered
non-GAAP measures. These non-GAAP measures may not be comparable to similar measures presented by other issuers. The following terms are not recognized measures under IFRS, but
are presented in this presentation.
“Adjusted funds flow” is defined as cash flow from operating activities adjusted for changes in non-cash operating working capital, asset retirement obligations settled and transaction costs.
Management of Baytex consider adjusted funds flow a key measure of performance as it demonstrates the combined entity’s ability to generate the cash flow necessary to fund capital
investments, debt repayment, settlement of abandonment obligations and potential future dividends. In addition, the ratio of net debt to adjusted funds flow is used to manage Baytex’s capital
structure.
“Asset Level Free Cash Flow” is defined as field level operating netback less exploration and development expenditures.
“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 expenses, income tax, non-recurring
losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, 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 March 31, 2020 was $923.8 million.
“Capital Efficiency” is defined as the cost to drill, complete, equip and tie-in a well divided by the initial production rate of the well on a boe basis over its initial 365 days of production.
“Exploration and development expenditures” is defined as expenditures related to drilling, completing and equipping, facilities, land, seismic and other. Exploration and development
expenditures includes additions to exploration and evaluation assets along with additions to oil and gas properties.
“Free cash flow” is defined as adjusted funds flow less exploration and development expenditures, payments on lease obligations and asset retirement obligations settled.
“Interest coverage” is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a
trailing twelve month basis. Financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended March 31, 2020 were
$107.2 million.
“Net debt” is defined as the sum of monetary working capital (which is current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the
long-term notes of Baytex and the bank loans of Baytex. Management of Baytex believe that net debt assists in providing a more complete understanding of Baytex’s cash liabilities.
“Operating netback” is defined as petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense divided by barrels of oil
equivalent sales volume for the applicable period. Management of Baytex believe that operating netback assists in characterizing Baytex’s ability to generate cash margin on a unit of
production basis.
"Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at March 31, 2020, the Company's Senior
Secured Debt totaled $694.9 million which includes $678.7 million of principal amounts outstanding and $16.2 million of letters of credit.
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Advisory (Cont.)
Advisory Regarding Oil and Gas Information
The reserves information contained in this presentation has been prepared in accordance with National Instrument 51-101 -Standards of Disclosure for Oil and Gas Activities of the Canadian
Securities Administrators ("NI 51-101"). The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of
proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of
reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been
satisfied. Knowledge of concepts, including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods, is required to properly use and apply reserves
definitions.
The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves and future production from
such reserves may be greater or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves
for all properties, due to the effects of aggregation. Complete NI 51-101 reserves disclosure for year-end 2019 is included in our Annual Information Form for the year ended December 31,
2019, which has been filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
This presentation discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex’s total proved, probable and unbooked locations. Proved
locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our
prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed
reserves. Unbooked locations are farther away from existing wells and, therefore, there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty
whether such wells will result in additional oil and gas reserves, resources or production. In the Eagle Ford, Baytex’s net drilling locations include 140 proved and 83 probable locations as at
December 31, 2019 and 52 unbooked locations. In the Viking, Baytex’s net drilling locations include 1,080 proved and 319 probable locations as at December 31, 2019 and 636 unbooked
locations. In Peace River, Baytex’s net drilling locations include 77 proved and 75 probable locations as at December 31, 2019 and 100 unbooked locations. In Lloydminster, Baytex’s net
drilling locations include 178 proved and 63 probable locations as at December 31, 2019 and 361 unbooked locations. In the Duvernay , Baytex’s net drilling locations include 11 proved and 10
probable locations as at December 31, 2019 and 295 unbooked locations.
References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not
determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging,
readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test
interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.
Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if
used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
Notice to United States Readers
The petroleum and natural gas reserves contained in this presentation have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all
respects to United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings
with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" (as defined in SEC rules). Canadian securities laws require oil and gas issuers
disclose their reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves". Additionally, NI 51-101 defines "proved reserves“
and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in this presentation may not be comparable to United States standards. Probable
reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves.
In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and
similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments.
Moreover, in this presentation future net revenue from its reserves has been determined and disclosed estimated using forecast prices and costs, whereas the SEC rules require that reserves
be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting
period. As a consequence of the foregoing, the reserve estimates and production volumes in this presentation may not be comparable to those made by companies utilizing United States
reporting and disclosure standards.
All amounts in this presentation are stated in Canadian dollars unless otherwise specified.
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▪ ~ 10 or more years of projected drilling inventory in each of our core areas (Viking, Eagle Ford and Canadian heavy oil)
▪ Strong capital efficiencies and flexibility on discretionary capital
Investment Highlights
High Quality and
Diversified Oil Portfolio
Across Multiple Plays
Track Record of
Substantial Free Cash
Flow Generation
Consistent Approach to
Risk Management
Financial Liquidity and
No Near-Term Maturities
▪ Exploration and development expenditures represents 84% of adjusted funds flow over the last five years (2015 to 2019)
▪ Free cash flow of $329 million generated in 2019
▪ Credit facilities ~ 35% undrawn and liquidity of ~ $300 million (1)
▪ First long-term note maturity is not until June 2024
▪ Proven commitment to environmental, social and governance (“ESG”) objectives
▪ Established target to reduce GHG emissions intensity by 30% by 2021
Committed to ESG
▪ Utilize financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow
▪ Majority of net crude oil exposure hedged for 2020
(1) Undrawn credit facilities of $417 million and liquidity (net working capital) of $315 million, as at March 31, 2020.
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EAGLE FORD
VIKING
LLOYDMINSTER
PEACE RIVER
DUVERNAY
(1) Average daily trading volumes for June 1 to June 25, 2020. Volumes are a composite of all exchanges in Canada and the U.S.
(2) Enterprise value based on closing share price on the Toronto Stock Exchange on June 25, 2020 and shares outstanding and net debt as at March 31, 2020.
(3) Production, production mix, and exploration and development (“E&D”) expenditures represents 2020 guidance.
(4) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd.
(5) Production (Gross W.I.) composition based on 2020 guidance. Heavy oil includes Peace River and Lloydminster.
(6) Revenue by commodity composition based on 2019 actuals.
Production by
Core Area (5)
Heavy Oil
Light Oil
NGLs
Natural Gas
Corporate Profile
Market Summary
Ticker Symbol TSX / NYSE: BTE
Average Daily Volume (1) CAN: 22 million / US: 5 million
Shares Outstanding (2) 560 million
Market Capitalization / Enterprise Value (2) $358 million / $2,410 million
Operating Statistics
Production (Gross W.I.) (3) 78,000 - 82,000 boe/d
Production Mix (3) 83% liquids
E&D Expenditures (3) $260 to $290 million
Reserves – 2P Gross (4) 529 mmboe
Heavy Oil
Light Oil
NGLs
Natural Gas
Eagle Ford
Viking
Heavy Oil
Other
Production by
Commodity (5)
Revenue by
Commodity (6)
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ESG Highlights
GHG Emission Reduction Safety
Established target to
reduce GHG emissions
intensity by 30% by 2021
55% reduction in lost
time incident frequency
in 5 years
Gas Conservation Indigenous Relations
99.1% routine gas
conservation in Peace
River
$32 million in contracts
awarded in 2017-2018
Spill Volumes Gender Diversity
76% reduction in spill
volumes over 5 years
25% women Board
members
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Q1 2020 Highlights
• Generated production of 98,452 boe/d (83% oil and NGL)
• Delivered adjusted funds flow of $133 million ($0.24 per basic share)
• Issued US$500 million principal amount of 8.75% senior unsecured notes due April 2027
• Redeemed two series of senior unsecured notes - US$400 million due 2021 and $300 million due 2022
• Extended the maturity of our credit facilities to April 2024
• Maintained undrawn credit capacity of $417 million and liquidity, net of working capital, of $315 million
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Responding Decisively to COVID-19
• The oil and gas industry is facing an unprecedented challenge due to significant degradation and volatility in global crude oil prices
• We are focused on protecting the health and safety of our personnel while maintaining our operations
• We have implemented a number of measures to foster resilience through these unpredictable times, including a work-from-home program and altering shifts in the field
• We have aggressively shifted our operating and capital activities to:
• Maintain financial liquidity
• Minimize capital outlays
• Emphasize cost reductions
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Maintain Financial Liquidity
C$548
Undrawn
C$300US$400
US$400
(1) Balance sheet as at March 31, 2020. Revolving credit facilities mature April 2024 and are
comprised of a US$575 million facility and a $300 million term loan facility.
(2) S&P corporate rating “B” and senior unsecured debt rating “B+” ; Fitch corporate rating
and senior unsecured debt rating “B”; Moody’s corporate rating “B2” and senior
unsecured debt rating “B3”.
(3) See advisory for definitions of Non-GAAP Financial and Capital Management Measures
on page 4 of this presentation.
Long-Term Notes Maturity Schedule (2) ($ millions)
• Credit Facilities ~ 35% Undrawn
• $417 million of undrawn capacity on credit facilities and $315 million of liquidity net of working capital
• Enhanced long-term note maturity profile
• First long-term note maturity not until 2024
• Extended maturity of credit facilities to 2024
• Credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews
Balance Sheet (1) $ millions
Bank loan $679
Long-term notes $1,271
Long-term debt $1,950
Working Capital deficiency $102
Net Debt $2,052
2020 2021 2022 2023 2024 2025 2026 2027
US$500
Financial Covenants (3) Position as at
March 31, 2020Covenant
Senior Secured Debt to Bank
EBITDA (maximum ratio)0.8:1.00 3.50:1.00
Interest Coverage
(minimum ratio)8.6:1.00 2.00:1.00
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Minimize Capital Outlays
2020 Guidance (1)
E&D CapEx $260 - 290 million
Production 78,000 - 82,000 boe/d
Oil and NGLs 83%
• 50% reduction in capital spending
• $260 to $290 million, from $500 to $575 million, previously
• Drilling operations in Canada suspended
• Moderated pace of activity in the Eagle Ford with 16-18 net wells brought on production (previously 22 net wells)
• Voluntarily shut-in production
• 25,000 boe/d shut-in for April and May (80% heavy oil)
• ~ 80% of shut-in volumes re-started in June, which will have a positive impact on our adjusted funds flow
Operating Area Net Wells CapEx ($MM) (2)
Eagle Ford 17 $135
Viking 69 $80
Heavy Oil 33 $50
Pembina Duvernay 2 $10
Total $275
(1) Production guidance assumes approximately 20,000 boe/d of production shut-in for H2/2020. We
have the operational flexibility to adjust spending plans based on changes in commodity prices.
(2) Represents mid-point of 2020 guidance range.
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Emphasize Cost Reductions
• Intensely focused on driving further efficiencies to capture or sustain cost reductions previously identified
• ~ $92 million of cost reductions for 2020
• No change to per-unit operating expense guidance despite lower volumes
• 30% reduction in transportation expense
• G&A expenses reduced 14% to $38 million (down 20% in last 18 months) Operating
Expenses
Transportation
Marketing
G&A
Total Cost Reductions of ~ $92 million
Fee renegotiations and reduced tolls
Discretionary spending eliminated; reduced salaries and annual retainers paid to Board of Directors
Reduction in production; deferral of activity; reduced trucking costs
Deferral of activity
Reduced production associated with shut-in volumes
Workforce optimization
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(1) WTI and Brent 3-way options consist of a sold put, a bought put and a sold call. In a $50/$58/$63 example, Baytex receives WTI+$8/bbl when WTI is at or below $50/bbl; Baytex receives $58/bbl when
WTI is between $50/bbl and $58/bbl; Baytex receives WTI when WTI is between $58/bbl and $63/bbl; and Baytex receives $63/bbl when WTI is above $63/bbl.
Crude Oil Hedge Portfolio
Q2/2020 Q3/2020 Q4/2020Balance
of Year
WTI Fixed Hedges
Volumes (bbl/d) 16,683 23,732 8,000 16,138
Fixed Price (US$/bbl) $31.03 $36.41 $42.78 $35.61
WTI 3-Way Option
Volumes (bbl/d) 24,500 24,500 24,500 24,500
Average Sold Put / Put / Sold Call (US$/bbl) (1) $50/$58/$63 $50/$58/$63 $50/$58/$63 $50/$58/$63
Total Hedge Volumes (bbl/d) 41,183 48,232 32,500 40,638
Basis Differential Financial Swaps
WCS Volumes (bbl/d) 6,500 10,833 6,500 7,944
WCS Price Relative to WTI (US$/bbl) ($16.27) ($13.55) ($16.27) ($15.03)
MSW Volume (bbl/d) 5,267 8,898 5,000 6,388
MSW Price Relative to WTI (US$/bbl) ($6.07) ($5.76) ($6.15) ($5.95)
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2020E Adjusted Funds Flow Sensitivities
SensitivitiesEstimated Effect on Annual Adjusted Funds Flow ($MM) (1) (2)
Excluding Hedges Including Hedges (3)
Change of US$1.00/bbl WTI crude oil $24.3 $15.9
Change of US$1.00/bbl WCS heavy oil differential $7.1 $3.4
Change of US$1.00/bbl MSW light oil differential $7.3 $3.9
Change of US$0.25/mcf NYMEX natural gas $7.7 $5.3
Change of $0.01 in the C$/US$ exchange rate $4.4 $4.4
(1) Adjusted funds flow sensitivities are based on the following full-year 2020 pricing assumptions: WTI - US$37/bbl; WCS differential - US$14/bbl; MSW differential – US$6/bbl, NYMEX Gas -
US$1.95/mcf; AECO Gas - $2.00/mcf and Exchange Rate (CAD/USD) - 1.36.
(2) Includes impact of reduced volumes associated with voluntarily shutting-in production.
(3) Our adjusted funds flow sensitivities (including hedges ) will vary depending on where WTI prices trade, relative to the bands established within our 3-way option contracts. The sensitivity to a
change of US$1/bbl WTI crude oil in the table above reflects a WTI price of less than US$50/bbl.
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$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
$40,000
$45,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 BTE 22 23 24 25 26 27 28
Top Quartile Capital Efficiencies
Source: Scotiabank Global Banking and Markets – May 2019.
Comparative group includes AAV, ARX, BIR, BNE, BNP, BXE, CJ, CPG, CR, DEE, ECA, ERF, FRU, KEL, NVA, OBE, PEY, PMT, PONY, POU, PSK, SGY, TOG, TOU, VET, VII, WCP.
Oil Gas (< 33% Liquids) Mixed (<67% Liquids)
2018 A
ll-I
n C
ap
ital E
ffic
ien
cie
s, excl. A
&D
($/b
oe/d
)
Weighted Average ($/boe/d)
Oil $25,000
Gas $12,800
Mixed $21,600
All $19,500
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Asset Overview
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17
Asset Highlights
Geographic and play diversification with ~ 10 or more years drilling inventory in each core area
Eagle Ford Viking Heavy Oil Pembina Duvernay
Production(Gross; Q1/2020)
36,190 boe/d 24,696 boe/d 31,211 boe/d 1,799 boe/d
Oil and NGLs(Gross; Q1/2020)
77% 92% 93% 81%
2P Reserves (1)
(Gross)229 mmboe 98 mmboe 103 mmboe 14 mmboe
Asset
Highlights
▪ 19,851 net acres in the core of Karnes county with world class partner, and operator in Marathon
▪ Stable production base with low sustaining capital has driven ~$724 million of asset level free cash flow since 2016 (2)
▪ Enhanced completions continue to drive step change in performance
▪ 419,615 net acres of land in the Viking play
▪ Shallow, light oil, strong netback asset with “manufacturing” development
▪ $83 million of asset level free cash flow in 2019 (2)
▪ Meaningful extended reach inventory (~ 10 years) with additional EOR potential
▪ Dominant land position of 672,640 net acres
▪ Low decline production provides capital allocation flexibility
▪ Innovative multi-lateral horizontal drilling generates top tier capital efficiencies
▪ 176,000 acres of 100% W.I. lands in the Pembina area
▪ Offset development and 9 wells drilled to-date have delineated ~ 40% of acreage position
▪ Measured delineation planned
(1) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd. See “Advisories”.
(2) The term “asset level free cash flow” is a non-GAAP measure. See slide 3 for more information.
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18
Eagle Ford: Core of Karnes County
LONGHORN
Wilson
Atascosa
Karnes
Live Oak
EXCELSIOR
SUGARLOAF
IPANEMA
Bee
Oil Condensate Dry Gas
• 19,900 net acres in the
core of the Eagle Ford
shale in south Texas
• Four AMI’s (Longhorn,
Sugarloaf, Ipanema and
Excelsior) with average
25% W.I.
• Q1/2020 production of
36,200 boe/d (77%
liquids)
• 30 gross (6.1 net) wells in
Q1/2020 established
average 30-day IP rates of
~ 1,875 boe/d per well
• Expect to bring 16 to 18
net wells on production in
2020
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19
$42
$138
$285
$238
$21
2016 2017 2018 2019 Q12020
36.6 36.7 37.1
39.1
36.2
2016 2017 2018 2019 Q12020
Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory
0
50
100
150
200
250
300
2020 Program RemainingUndrilledInventory
Drilling Inventory (2)
(net locations)
> 10 year inventory at
current pace
16-18
net wells
on- stream
> 250 net
locations
(1) Asset level free cash flow represents field level operating netback less exploration and development capital. For illustrative purposes only and should not be relied upon as indicative of future results.
Baytex’s actual results may vary.
(2) Net locations includes 223 proved plus probable undeveloped reserves locations at year-end 2019 and 52 unbooked future locations. See “Advisories”
Asset Level Free Cash
Flow (1) (C$ millions)
~ $724MM cumulative
asset level free cash flow
since 2016
Production
(mboe/d)
Stable production and
deep inventory drives
asset level free cash flow
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20
0
25
50
75
100
125
150
175
0 1 2 3 4 5 6
Cu
mu
lati
ve
Pro
du
cti
on
(m
bo
e)
Months
17% increase 2019 over 2017
5% increase 2019 over 2018
Enhanced Completions Drive Step Change in Well Performance
2017
2016
180 Day Cumulative Well Production
Hz Length
(ft)
Proppant
(lbs/ft)
Stage
Spacing
(ft)
# of
Stages
Q1
20206,000 2,700 226 26
2019 6,300 2,300 225 28
2018 6,000 2,000 215 28
2017 5,900 1,800 217 27
2016 5,500 1,600 221 25
Completion Activity
2019
2018
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21
Viking Light Oil: 460 Highly Prospective Sections
Baytex Lands
Esther/Hoosier
Kerrobert
Plenty
Greater Gleneath
Lucky Hills/Whiteside Dodsland
Mantario (Laporte)
Plato
• Shallow (700 m), light oil
(36° API) resource play
with strong netbacks
• Produced a record
24,700 boe/d (92% oil) in
Q1/2020
• Added 229 net unbooked
drilling opportunities in
2019 through multiple
deals and asset swaps
• Steady pace of
development in Q1/2020
with 4 drilling rigs and 2
frac crews running
• Remainder of 2020
program suspended
pending recovery in oil
prices
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22
0
10
20
30
40
50
60
70
80
- 5,000 10,000 15,000 20,000 25,000
Oil R
ate
(b
bl/d
)
Cum Oil (bbl)
2019 Wells 2018 Wells 2017 Wells 2016 Wells
2015 Wells 2014 Wells 2013 Wells 2012 Wells
Technical Advancements Drive Productivity Improvement
Viking Wells by Vintage
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0
50
100
150
200
250
300
350
400
2012 2013 2014 2015 2016 2017 2018 2019
Net Wells Onstream (Left Axis)
ERH (%) (Right Axis)
Shift to ERH(1) Wells Drives Productivity
Improvements
95%+ of Viking Development now
ERH Wells
(1) Extended Reach Horizontal (“ERH) wells are ¾ to 1 mile long laterals drilled to a depth of approximately 700 metres.
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23
Peace River: Innovative Multi-Lateral Development
Performance Drivers
• Produced 16,100 boe/d in
Q1/2020 (87% oil)
• Dominant 560 net sections
• Strong capital efficiencies
Baytex Lands
Seal
Harmon Valley
Reno
Golden
Peavine
Peavine Lands
• Q1/2020 strategic agreement
with Peavine Metis settlement
• 60 sections of land
• Early stage exploratory play
targeting Spirit River formation,
a Clearwater formation
equivalent
• First activity planned for 2021
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24
Lloydminster: Significant Land Position and Drilling Inventory
Performance Drivers
• Produced 15,100 boe/d in
Q1/2020 (99% oil)
• Strong capital efficiencies
• Applying multi-lateral
horizontal drilling and
production techniques
• Ramp-up of Kerrobert
thermal project occurred in
Q4/2019 with peak
production of ~ 3,500 bbl/d
Baytex Lands
ALBERTA SASKATCHEWAN
Kerrobert
Lloydminster
Soda Lake
Tangleflags
Ardmore/Cold Lake
Lindbergh
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25
Heavy Oil Innovation
Peace River
Multi-Lateral Horizontal
Lloydminster
Horizontal
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26
Pembina Area Duvernay Light Oil: Emerging Resource Play
Baytex Lands
Pembina Duvernay
• 275 sections of 100% WI lands
• Nine wells drilled to date have
delineated a minimum of 100-
125 sections
• Produced 1,800 boe/d (81%
liquids) in Q1/2020
• Two wells on-stream in 2019
generated average 30-day IP
rate of ~ 1,050 boe/d (75%
liquids)
• D&C costs of ~ $7.0 million
represent an ~ 20% reduction
from previous wells
• Completion activities for two
wells drilled in Q1/2020
deferredProducing Pads (7 wells)
Rimbey Leduc Reef
Liquids Rich Gas
Liquids
Rich Gas
Volatile
Oil
Black Oil
2020 DUC’s (2 wells)
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Eagle Ford Viking Peace River (1) Lloydminster (1) Pembina Duvernay
Formation Lower Eagle Ford Viking Bluesky Mannville Group Duvernay
Upper Eagle Ford
Austin Chalk
Depth (metres) 3,300-3,900 700 600 350-800 2,200-2,400
Oil API Oil: 40-45° 36° 11° 10-16° 42-44°
Condensate: 44-55°
Porosity 4.6% - 9% 23% 28% 30% 3% - 6%
Permeability 0.33 - 0.41 millidarcies 0.5 - 50 millidarcies 1 - 5 darcies 0.5 - 5 darcies 10 nanodarcy
Completion Plug and perf Pin point coil Open hole multi-lateral
Horizontal slotted liner /
open-hole multi-lateral Plug and perf
Expected Well Costs
(drill, complete, equip and tie-in) US$5.6 million $1.0 million $2.5 million $0.8 million $7.0 million
6,000 foot lateral
Land - gross (net) sections 122 (31) 763 (656) 562 (560) 637 (491) 275 (275)
Pembina area
Reserves at YE 2019 (mmboe)
Proved developed producing 71 29 21 13 2
Proved 163 65 32 28 7
Proved plus probable 229 98 59 44 14
Drilling inventory (risked) – net
locations (booked/unbooked) 223 / 52 1,399 / 636 152 / 100 241 / 361 21 / 295
(1) Figures do not incorporate thermal assets at Cliffdale (Peace River) or Gemini (Lloydminster)
High Quality Oil Development
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Corporate Sustainability
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29
Corporate Sustainability
At Baytex, we believe that commitment to corporate responsibility is just as important as
delivering financial and operational targets. We publish a biennial Corporate Sustainability
Report which provides transparent reporting and clear goals on the topics that matter:
Safety Environment
Communities and
StakeholdersBusiness Practice
and Compliance
For more information and to view our most recent report, visit
http://www.baytexenergy.com
Commitment to the health
and safety of our
employees, contractors and
communities.
Commitment to
minimizing our impact on
air, water, land and life in
the areas we operate.
Commitment to provide social
and economic benefits to the
communities in which we
operate and to hear the
voices and concerns of our
stakeholders.
Commitment to
governance, ethical
business conduct, and
regulatory compliance.
Baytex was recognized by Corporate Knights in 2018 as one of Canada’s
Top Sustainability Performers.
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30
GHG Emissions Reduction
Target to reduce GHG emission
intensity (tonnes of CO2 per boe)
by 30% by 2021.
Our emissions reduction strategy
includes:
• Increasing gas conservation
• Reusing associated gas as fuel for
field activities
• Reducing emissions from storage
tanks
• Monitoring and preventing fugitive
emissions
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31
A Culture of Commitment
Objective What we’ve done ResultHow it contributes to
value creation
EN
VIR
ON
ME
NT
Responsibly develop
our assets
Ensure our employees and
contractors uphold our procedures
for spill prevention, response and
cleanup
76% reduction in corporate spill
volumes, over 5 yearsReduces costs and maintains
social license
Exceed regulatory
obligations
Invested more than $100 million in
gas conservation activities in Peace
River in the last 5 years
99.1% routine gas conservation in
Peace RiverHelps to build trust with
regulators and stakeholders
SO
CIA
L
Create a culture of
safety
Tie safety targets to annual
performance incentive program
55% reduction in employee
+contractor LTIF in 5 years
Supports the consistent and
safe execution of our business
plan
Be a good neighbour
Build mutually beneficial
relationships based on trust
$32 million awarded in contracts
to Indigenous
contractors/companies in 2017-
2018
Maintain social license and
enables growth in our
operations by reducing non-
technical project delays
GO
VE
RN
AN
CE Ensure effective
Board leadership
Ensure our Board is comprised of
dedicated Directors who are
invested in our success
100% Board meeting attendance
and
25% women Board members as
of Sep. 2019
Sets strategic direction and
improves decision making
Be transparent and
accountable
Communicate our ESG impacts by
publishing biennial sustainability
reports since 2012
Recognized by Corporate Knights
as Future 40 Responsible
Corporate Leaders in 2018
Enables shareholders and
stakeholders to make informed
decisions
Source: 2018 Sustainability Report – September 2019
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Supplementary Information
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33
Summary of Operating and Financial Metrics
Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020
Benchmark Prices
WTI crude oil (US$/bbl) $62.87 $67.88 $69.50 $58.81 $64.77 $54.90 $59.81 $56.45 $56.96 $57.03 $46.17
NYMEX natural gas (US$/mcf) $3.00 $2.80 $2.90 $3.64 $3.09 $3.15 $2.64 $2.23 $2.50 $2.63 $1.95
Production
Crude oil (bbl/d) 45,835 46,644 56,767 71,326 55,218 71,939 69,905 68,541 70,956 70,328 74,571
Natural gas liquids (bbl/d) 9,143 9,419 10,076 10,327 9,745 11,729 10,986 9,543 8,699 10,229 7,822
Natural gas (mcf/d) 87,261 87,605 93,414 103,424 92,971 104,682 105,065 101,054 100,236 102,742 96,356
Oil equivalent (boe/d) (1) 69,522 70,664 82,412 98,890 80,458 101,115 98,402 94,927 96,360 97,680 98,452
% Liquids 79% 79% 81% 83% 81% 83% 82% 82% 83% 82% 83%
Netback ($/boe)
Total sales, net of blending and other
expenses (2) $42.96 $51.22 $55.03 $37.89 $46.31 $47.98 $51.49 $47.14 $48.25 $48.72 $35.19
Royalties (10.36) (12.01) (12.13) (8.77) (10.68) (8.94) (9.67) (8.59) (8.72) (8.98) (6.33)
Operating expense (10.53) (10.91) (10.25) (10.76) (10.61) (11.02) (11.22) (11.15) (11.23) (11.16) (11.66)
Transportation expense (1.36) (1.22) (1.26) (1.21) (1.26) (1.46) (1.33) (1.13) (1.00) (1.23) (1.15)
Operating Netback (4) $20.71 $27.08 $31.39 $17.15 $23.76 $26.56 $29.27 $26.27 $27.30 $27.35 $16.05
General and administrative (1.76) (1.64) (1.34) (1.55) (1.56) (1.55) (1.28) (1.14) (1.12) (1.28) (1.09)
Cash financing and interest (3.92) (3.97) (3.47) (3.07) (3.55) (3.10) (3.14) (3.06) (2.75) (3.01) (3.19)
Realized financial derivative gain (loss) (1.57) (4.57) (4.07) (0.34) (2.49) 2.07 1.45 2.39 2.59 2.12 3.00
Other (3) 0.01 (0.31) 0.07 (0.02) (0.05) 0.28 0.07 (0.03) 0.16 0.13 0.07
Adjusted funds flow (4) $13.47 $16.59 $22.58 $12.17 $16.11 $24.26 $26.37 $24.43 $26.19 $25.31 $14.84
(1) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly
if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
(2) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the
realized pricing on our produced volumes to the WCS benchmark.
(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q3/2019 MD&A for
further information on these amounts.
(4) The terms “adjusted funds flow” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be
comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures on slide 3 of this presentation.
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Reserves Summary (Gross)
Category (1) Eagle Ford Viking Heavy OilPembina
DuvernayOther Total
Proved Developed Producing 71 29 34 2 6 142
Total Proved 163 65 68 7 11 314
Total Proved Plus Probable 229 98 163 14 25 529
2P Reserves by Asset2P Reserves Breakdown 2P Reserves by Commodity
Light Oil + NGLHeavy
Oil
Natural Gas
Probable
PDNP + PUD
PDP
(1) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd.
Eagle Ford
Viking
Heavy Oil
PembinaDuvernay
Other
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35
2020 Guidance and Cost Assumptions
Exploration and development expenditures ($ millions) $260 - $290
Production (boe/d) 78,000 - 82,000
Expenses:
Royalty rate (%) 18.5%
Operating ($/boe) $11.75 - $12.50
Transportation ($/boe) $0.95 - $1.05
General and administrative ($ millions) $38 ($1.30/boe)
Interest ($ millions) $112 ($3.84/boe)
Leasing expenditures ($ millions) $7
Asset retirement obligations ($ millions) $10
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Edward D. LaFehrPresident and Chief Executive Officer
587.952.3000
Rodney D. GrayExecutive Vice President and Chief Financial Officer
587.952.3160
Brian G. EctorVice President, Capital Markets
587.952.3237
Baytex Energy Corp.
Suite 2800, Centennial Place
520 – 3rd Avenue S.W.
Calgary, Alberta T2P 0R3
T 587.952.3000
Toll Free 1.800.524.5521
www.baytexenergy.com
Contact Information