investor presentation - baytex energy · this presentation are "forward-looking...
TRANSCRIPT
Investor Presentation
February 2020
2
Forward Looking Statements
Any “financial outlook” or “future oriented financial information” in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial outlook or future
oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such
information may not be appropriate for other circumstances.
In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of future plans and operations, certain statements in
this presentation are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of
applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe",
"continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future
outcomes, events or performance. The forward-looking statements contained in this presentation peak only as of the date hereof and are expressly qualified by this cautionary statement.
Specifically, this presentation contains forward-looking statements relating to but not limited to: Baytex’s strategy for value creation including its vision is to be a top tier north American oil producer
targeting 10-15% annual shareholder returns, that we have a self-funded business model with attractive valuation, expect to be free cash flow positive >$50/bbbl WTI, and a target of $100+ million of free
cash flow in 2020; that we have high return light oil assets with heavy oil torque, 10+ year inventory in core areas, that a $540 million capital program drives stable production in 2020 and 80% of our
capital is directed to high netback light oil; expectations for 2020 as to Baytex’s production by area and commodity; our 2020 outlook, including: that our capital program will deliver stable production and
maximize free cash flow, the capital program is fully funded at US$50/bbl WTI, that we will continue to advance the East Duvernay light oil play, further deleveraging is a top priority and adjusted funds
flow in excess of capital expenditures, lease payments and asset retirement expenditures will be allocated to debt repayment; our 2020 guidance for annual production, production mix and exploration and
development capital; for 2020: our capital allocation plans by activity type and area and number of net wells we expect to bring on stream; our estimated adjusted funds flow for 2020 at certain WTI, WCS
and MSW prices; that we expect our US$400 million 2021 Notes and $300 million 2022 Notes to be redeemed in Q1 2020; our net debt to adjusted funds flow target; the percentage of Baytex’s net
exposure to oil prices that is hedged for Q1 and full year 2020; the sensitivity of our expected 2020 adjusted funds flow to changes in WTI prices, WCS and MSW differentials, natural gas prices and the
Canada-United States foreign exchange rate; that crude by rail is an effective tool for managing differential exposure and provides greater operating netback certainty; our estimated crude oil and NGL
sales portfolio for 2020 and our estimated 2020 WTI, WCS and MSW prices and Baytex price realizations; that the Eagle Ford has strong asset level free cash flow and the amount of remaining undrilled
inventory; the time to payout, internal rate of return, recycle ratio and WTI break-even price for our type wells in the Eagle Ford; for the Viking that, 460 sections are highly prospective, extended reach
horizontal wells are enhancing returns, we have a steady pace of development and we expect to bring 220 net wells on stream in 2020; that the Viking has strong price realizations and low cost structure,
its asset level free cash flow contribution at US$55/bbl WTI and US$60/bbl WTI and the amount of remaining drilling inventory; the time to payout, internal rate of return, recycle ratio and WTI break-even
price for our type wells in the Viking; in Peace River, that innovative multi-lateral horizontal drilling generates strong capital efficiencies and the number of net wells we plan to bring on-stream in 2020; In
Lloydminster, that we have strong capital efficiencies and economics at current oil prices, that we are applying multi-lateral drilling at Soda Lake, and the number of net wells we plan to bring on-stream in
2020; In Peace River and Lloydminster, our capital efficiencies, asset level free cash flow expectations at US$55/bbl WTI and US$60/bbl WTI and drilling inventory; the time to payout, internal rate of
return, recycle ratio and WTI break-even price for our type wells in Peace River and Lloyminster; that we have delineated a minimum of 100-125 sections; the expected drilling and completion well costs,
reserves and drilling inventory for our Eagle Ford, Peace River, Lloydminster, Viking and East Duvernay assets; that we are committed to corporate sustainability; and our GHG emissions reduction
target. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that
the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future. In addition, information and statements relating to reserves are deemed to be
forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be
profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices;
well production rates and reserve volumes; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow under credit
agreements; the receipt, in a timely manner, of regulatory and other required approvals for operating activities; the availability and cost of labour and other industry services; interest and foreign exchange
rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the ability to develop crude oil and natural gas properties in the manner currently contemplated; and
current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions,
although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Advisory
3
Advisory (Cont.)
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to:
the volatility of oil and natural gas prices and price differentials; availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the
availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our Eagle Ford properties; the
cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; new regulations on hydraulic fracturing;
restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and
safety regulations; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks
associated with our hedging activities; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully
insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large
projects; risks related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; risks associated
with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing
practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional
risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2018, which was filed with
Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission on March 12, 2019 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.
Baytex has included certain type curves and well economics in this presentation. The type curves presented are primarily based on expectations regarding future drilling results. As such, there is no
certainty that such results will be achieved or that Baytex will be able to optimize such drilling results to achieve the type curves, well economics and estimated ultimate recoverable volumes described.
Such type curves and well economics are useful in understanding management's assumptions for determining the success of the performance of future wells; however, such type curves and well
economics are not necessarily determinative of the production rates and performance of existing and future wells and such type curves do not reflect the type curves used by our independent qualified
reserves evaluator in estimating our reserves volumes.
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 5, 2020 and Baytex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information,
future events or results or otherwise, other than as required by applicable securities laws.
Non-GAAP Financial and Capital Management Measures
This presentation contains certain financial measures that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered non-
GAAP measures. These non-GAAP measures may not be comparable to similar measures presented by other issuers. The following terms are not recognized measures under IFRS, but are presented
in this presentation.
“Adjusted funds flow” is defined as cash flow from operating activities adjusted for changes in non-cash operating working capital, asset retirement obligations settled and transaction costs. Management
of Baytex consider adjusted funds flow a key measure of performance as it demonstrates the combined entity’s ability to generate the cash flow necessary to fund capital investments, debt repayment,
settlement of abandonment obligations and potential future dividends. In addition, the ratio of net debt to adjusted funds flow is used to manage Baytex’s capital structure.
“Asset Level Free Cash Flow” is defined as field level operating netback less exploration and development expenditures.
“Capital Efficiency” is defined as the cost to drill, complete, equip and tie-in a well divided by the initial production rate of the well on a boe basis over its initial 365 days of production.
“Debt adjusted production per share growth” is defined as growth in production from December 31, 2018 to December 31, 2019 on a per share basis with the number of shares adjusted based on debt
outstanding. Debt-adjusted share count is calculated as total shares outstanding plus incremental shares issued at current market price ($1.87) to eliminate net debt (i.e. full equitization of net debt).
Management of Baytex believes that debt adjusted production per share growth is useful in determining the production growth on a per share basis as if all debt was extinguished by the issuance of
shares.
“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.
4
Advisory (Cont.)
“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.
“Payout” is defined as the point at which the cost to drill, complete, equip and tie-in a well has been recovered, being the point in time when the cumulative operating netback is equal to the cost of
the well.
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. Selected NI 51-101 reserves disclosure was included in our press release dated January 20, 2020. Complete NI 51-101 reserves disclosure for year-
end 2019 will be included in our Annual Information Form for the year ended December 31, 2019, which we expect to file no later than March 30, 2020 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.
5
Advisory (Cont.)
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.
6
Our Strategy for Value Creation
▪ Reduced net debt by $394 million in 2019
▪ Enhanced long-term note maturity schedule with first note not due until 2024
▪ 2019 year-end net debt to adjusted funds flow ratio of 2.1x Financial
Liquidity
▪ High return light oil assets with heavy oil torque
▪ 10+ year development inventory in core areas
▪ $540 million capital program in 2020 drives stable production
▪ 80% of capital program to high netback light oil
▪ Self funded business model with attractive valuation
▪ Free cash flow positive > US$50/bbl WTI
▪ 10% debt-adjusted production per share growth (exit 2018 to exit 2019)
▪ Target $100+ million of free cash flow in 2020
▪ Relentless focus on driving cost and capital efficiencies in our business
▪ Competitive cost structure enhances operating netback
▪ G&A reduced 15% to ~ $1.30/boeCompetitive
Cost Structure
Deploy Capital
Effectively
Creating Shareholder
Value
Vision: Top Tier North American Oil Producer Targeting 10-15% Annual Shareholder Returns
7
EAGLE FORD
VIKING
LLOYDMINSTER
PEACE RIVER
DUVERNAY
(1) Average daily trading volumes for January 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 January 31, 2020 and shares outstanding and net debt as at December 31, 2019.
(3) Production, production mix, and exploration and development (“E&D”) expenditures represents 2020 guidance.
(4) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd.
(5) Production (Gross W.I.) composition based on 2020 guidance. Heavy oil includes Peace River and Lloydminster.
(6) Revenue by commodity composition based on 2019 actuals.
Production by
Core Area (5)
Heavy Oil
Light Oil
NGLs
Natural Gas
Corporate Profile
Market Summary
Ticker Symbol TSX / NYSE: BTE
Average Daily Volume (1) CAN: 10.7 million / US: 2.2 million
Shares Outstanding (2) 558 million
Market Capitalization / Enterprise Value (2) $804 million / $2,691 million
Operating Statistics
Production (Gross W.I.) (3) 93,000 - 97,000 boe/d
Production Mix (3) 84% liquids
E&D Expenditures (3) $500 to $575 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)
8
▪ Capital expenditures of $552 million, which is the low end of original guidance
▪ Generated production of 97,680 boe/d, exceeding the high end of original guidance
2019 Highlights
Delivering on our
Operating Plan
Generating Free
Cash Flow
Sustainability
Improving our
Financial Position
▪ Free cash flow of $329 million generated in 2019
▪ Eagle Ford, Viking and Heavy Oil all generated positive asset level free cash flow
▪ Net debt reduced by 17% ($394 million) in 2019
▪ Redeemed US$150 million of notes in September 2019 that were not due until 2021
▪ Shareholder outreach program
▪ Published fourth corporate sustainability report
▪ Established GHG emission reduction target of 30%
Committed to Strong
ESG Performance
▪ PDP reserves increased 5% to 142 mmboe
▪ Replaced 112% of production from development activities
▪ Delivered strong F&D and recycle ratios (PDP - $13.04/boe, 2.3x)
9
2020 Outlook
2020 Guidance (1)
E&D CapEx $500 - 575 million
Production 93,000 - 97,000 boe/d
Oil and NGLs 84%
2020 capital program designed to deliver stable production and maximize free cash flow
• Cash neutrality (capital program fully funded) at US$50/bbl WTI
• 80% directed to our high netback light oil assets in the Eagle Ford and Viking
• Continue to advance East DuvernayShale light oil exploration play
Further deleveraging remains a top priority
• Adjusted funds flow in excess of capital expenditures, lease payments and asset retirement expenditures will be allocated to debt repayment
Operating Area Net Wells CapEx ($MM) (2)
Viking 220 $255
Eagle Ford 22 $165
Heavy Oil 76 $100
East Duvernay 2-4 $20
Total $540
(1) 2020 capital spending is approximately 50% weighted to the first half of the year. We have
the operational flexibility to adjust spending plans based on changes in commodity prices.
(2) Represents mid-point of 2020 guidance range.
Capital Budget CapEx ($MM) (2)
Drill, complete and equip $470
Facilities $45
Gas conservation $20
Land and seismic $5
Total $540
10
2020E Adjusted Funds Flow Matrix
Adjusted Funds Flow
($ millions) (1)
WTI (US$/bbl)
$50 $55 $60 $65
WC
S /
MS
W (
2)
Dif
fere
nti
al
(US
$/b
bl)
$14 / $4 $660 $756 $867 $985
$16 / $6 $620 $716 $827 $946
$18 / $8 $580 $676 $788 $906
$20 / $10 $540 $636 $748 $866
(1) Adjusted funds flow matrix based on mid-point of 2020 guidance and includes the impact of hedging. For illustrative purposes only and should not be relied upon as indicative of future results.
Baytex’s actual results may vary. Pricing assumptions - LLS – WTI+US$3/bbl; NYMEX Gas - US$2.35/mcf; AECO Gas - $1.90/mcf and Exchange Rate (CAD/USD) - 1.33.
(2) Western Canadian Select (“WCS”) is the benchmark heavy oil price (~ 21° API) in western Canada. The WCS differential is quoted in U.S. dollars relative to WTI. The five-year average WCS
differential to WTI (2015-2019) is US$16/bbl. Mixed Sweet Blend (“MSW”) is the benchmark light oil price (~ 41°API) in western Canada and is often referenced as Edmonton Par. The MSW
differential is quoted in U.S. dollars relative to WTI. The five-year average MSW differential to WTI (2015-2019) is US$5/bbl.
(3) 2020 forward strip pricing assumptions: WTI - US$51/bbl; LLS - US$55/bbl; WCS differential - US$19/bbl; MSW differential – US$7/bbl, NYMEX Gas - US$2.15/mcf; AECO Gas - $1.80/mcf and
Exchange Rate (CAD/USD) - 1.325.
High netback light oil drives 2020 adjusted funds flow
Adjusted funds
flow at the
forward strip (3)
$610
11
Balance Sheet and Liquidity
C$548
Undrawn
C$300US$400 US$400
(1) Balance sheet as at December 31, 2019 and pro forma US$500 million note
due 2027 (closed February 5, 2020) and redemption of US$400 million due
2021 and $300 million due 2022 (both scheduled to occur in Q1/2020).
(2) Revolving credit facilities mature April 2021 and are comprised of a US$575
million facility and a $300 million term loan facility that is secured by the
assets of Raging River.
(3) S&P corporate and senior unsecured debt rating - “BB,”; Fitch corporate
rating – “B+: and senior unsecured debt rating – “BB-”; Moody’s corporate
rating - “B1” and senior unsecured debt rating - “B2”.
(4) Net debt to adjusted funds flow ratio based on trailing 12-month adjusted
funds flow.
Long-Term Notes Maturity Schedule (3) ($ millions)
• Strong financial liquidity
• Credit facilities ~ one-third undrawn
• > $300 million of liquidity
• Enhanced maturity profile with first long-term note maturity not until 2024 (1)
• Credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews
Balance Sheet (1) $ millions
Bank loan (2) $692
Long-term notes (3) $1,167
Long-term debt $1,859
Working Capital deficiency $28
Net Debt $1,887
2020 2021 2022 2023 2024 2025 2026 2027
0x
1x
2x
3x
4x
5x
6x
7x
2012 2013 2014 2015 2016 2017 2018 2019
Net Debt to Adjusted Funds Flow Ratio (4)
Target
1.5x
US$500
To be Redeemed in
Q1/2020
12
(1) WTI and Brent 3-way options consist of a sold put, a bought put and a sold call. In a $50/$58/$63 example, Baytex receives WTI+$8/bbl when WTI is at or below $50/bbl; Baytex receives $58/bbl when
WTI is between $50/bbl and $58/bbl; Baytex receives WTI when WTI is between $58/bbl and $63/bbl; and Baytex receives $63/bbl when WTI is above $63/bbl.
(2) Percentage of hedged volumes are based on 2020 annual production guidance (excluding NGL), net of royalties
Crude Oil Hedge Portfolio
Q1/2020 2020
WTI Fixed Hedges
Volumes (bbl/d) 8,000 3,500
Fixed Price (US$/bbl) $56.95 $57.40
WTI 3-Way Option
Volumes (bbl/d) 24,500 24,500
Average Sold Put / Put / Sold Call (US$/bbl) (1) $50/$58/$63 $50/$58/$63
Total Hedge Volumes (bbl/d) 32,500 28,000
Hedge (%) (2) 55% 48%
Basis Differential Financial Swaps
WCS Volumes (bbl/d) 2,500 2,500
WCS Price Relative to WTI (US$/bbl) ($16.10) ($16.10)
MSW Volume (bbl/d) 2,000 2,000
MSW Price Relative to WTI (US$/bbl) ($6.50) ($6.50)
13
2020E Adjusted Funds Flow Sensitivities
SensitivitiesEstimated Effect on Annual Adjusted Funds Flow ($MM) (1)
Excluding Hedges Including Hedges
Change of US$1.00/bbl WTI crude oil $29.1 $21.6
Change of US$1.00/bbl WCS heavy oil differential $12.4 $11.2
Change of US$1.00/bbl MSW light oil differential $9.4 $8.5
Change of US$0.25/mcf NYMEX natural gas $8.9 $8.3
Change of $0.01 in the C$/US$ exchange rate $9.9 $9.9
14
Diversified Crude Oil Marketing Portfolio
Viking Light Oil
• 36° API light oil contributes to top quartile field netbacks
• Priced off Canadian Mixed Sweet (“MSW”) blend
LLS / Brent Exposure
• Eagle Ford is proximal to Gulf Coast markets; receives premium pricing
• Light oil and condensate priced off LLS crude oil benchmark, which is a function of the Brent price
Crude by Rail
• 11,500 bbl/d (~ 40%) of heavy oil contracted for 2020
• Effective tool for management of differentials
• Reduces price volatility and provides greater operating netback certainty
Crude Oil and NGL Sales Portfolio (1)
Benchmark
2020
Index (2)
Baytex Price
Realization (3)
Viking light oil MSW WTI less
US$7/bbl
MSW less
$3.50/bbl
Eagle Ford
light oil and
condensate LLS
WTI plus
US$3.50/bbl
LLS less
US$4.50/bbl
Peace River /
Lloydminster
heavy oil WCS
WTI less
US$19/bbl
WCS less
$12.50/bbl
(1) Based on 2020 guidance.
(2) 2020 Index based on the forward strip as at February 3, 2020.
(3) 2020 estimate
WTI / MSW 28%
Brent / LLS24%
WCS23%
Crude by Rail 14%
NGLs
11%
15
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
$40,000
$45,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 BTE 22 23 24 25 26 27 28
Top Quartile Capital Efficiencies
Source: Scotiabank Global Banking and Markets – May 2019.
Comparative group includes AAV, ARX, BIR, BNE, BNP, BXE, CJ, CPG, CR, DEE, ECA, ERF, FRU, KEL, NVA, OBE, PEY, PMT, PONY, POU, PSK, SGY, TOG, TOU, VET, VII, WCP.
Oil Gas (< 33% Liquids) Mixed (<67% Liquids)
20
18
All
-In
Cap
ita
l E
ffic
ien
cie
s, e
xc
l. A
&D
($
/bo
e/d
)
Weighted Average ($/boe/d)
Oil $25,000
Gas $12,800
Mixed $21,600
All $19,500
Asset Overview
17
Asset Highlights
Geographic and play diversification with ~ 10 or more years drilling inventory in each core area
Eagle Ford Viking Heavy Oil East Duvernay
Free Cash Flow
Light Oil
Free Cash Flow
Light Oil
Low Decline
Heavy Oil
Early Stage Light
Oil Growth
Production(Gross; FY 2019)
39,056 boe/d 22,545 boe/d 29,378 boe/d 1,688 boe/d
Oil and NGLs(Gross; FY 2019)
77% 92% 91% 84%
2P Reserves (1)
(Gross)229 mmboe 98 mmboe 103 mmboe 14 mmboe
Asset
Highlights
▪ 19,851 net acres in the core of Karnes county with world class partner, and operator in Marathon
▪ Stable production base with low sustaining capital has driven ~$703 million of asset level free cash flow since 2016 (2)
▪ Enhanced completions continue to drive step change in performance
▪ 419,615 net acres of land in the Viking play
▪ Shallow, light oil, strong netback asset with “manufacturing” development
▪ Shifting from growth to sustainable free cash flow; ~ $83 million of asset level free cash flow in 2019 (2)
▪ Meaningful extended reach inventory (~ 10 years) with additional EOR potential
▪ Dominant land position of 786,939 net acres
▪ Low decline production provides capital allocation flexibility
▪ Innovative multi-lateral horizontal drilling generates top tier capital efficiencies
▪ Strong economics with significant torque above US$55/bbl; marketing approach insulates against differentials
▪ 176,000 acres of 100% W.I. lands in the Pembina area
▪ Offset development and 7 wells drilled to-date have delineated ~ 40% of acreage position
▪ Measured delineation planned under current commodity price backdrop
(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.
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.
• 2019 production of 39,100
boe/d (77% liquids)
• Achieved record
production rates from new
wells in 2019
• YTD 2019 – 85 gross
wells established average
30-day IP rates of ~ 1,870
boe/d per well
19
Eagle Ford: Strong Free Cash Flow and Deep Drilling Inventory
$42
$138
$285
$238
2016 2017 2018 2019
Asset Level Free Cash
Flow (1) (C$ millions)
~ $703MM cumulative free
cash flow since 2016
0
50
100
150
200
250
300
2020 Program RemainingUndrilledInventory
Drilling Inventory (2)
(net locations)
> 10 year inventory at
current pace
~ 22 net
wells
on- stream
> 250 net
locations
36.6 36.7 37.1
39.1
2016 2017 2018 2019
Production
(mboe/d)
Stable production and
deep inventory drives free
cash flow
(1) Asset level free cash flow represents field level operating netback less exploration and development capital. For illustrative purposes only and should not be relied upon as indicative of future results.
Baytex’s actual results may vary.
(2) Net locations includes 223 proved plus probable undeveloped reserves locations at year-end 2019 and 52 unbooked future locations. See “Advisories”
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
9 Mths 2019 6,500 2,400 216 30
2018 6,000 2,000 215 28
2017 5,900 1,800 217 27
2016 5,500 1,600 221 25
Completion Activity
2019
2018WTI Oil Price $55/bbl $60/bbl
Payout: 1.4 years 1.1 years
IRR: 56% 77%
Recycle Ratio: 2.6x 2.9x
Breakeven:
(10% IRR)US$35/bbl
Well Economics (1)
(1) 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$5.6 million (6,000 foot
lateral); IP365 - 625 boe/d; EUR – 700 mboe).
21
Viking Light Oil: 460 Highly Prospective Sections
Baytex Lands
Esther/Hoosier
Kerrobert
Plenty
Greater Gleneath
Lucky Hills/Whiteside Dodsland
Mantario (Laporte)
Plato
• Shallow (700 m), light oil
(36° API) resource play
with strong netbacks
• Extended Reach
Horizontals are
enhancing returns
• Produced 22,500 boe/d
(92% oil) in 2019
• Added 229 net unbooked
drilling opportunities in
2019 through multiple
deals and asset swaps
• Steady pace of
development with 3
drilling rigs and 2 frac
crews executing our
program
• 2020 budget - 220 net
wells on-stream
22
Viking – Shifting from Growth to Sustainable Free Cash Flow
0
5,000
10,000
15,000
20,000
25,000
Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19
2012 2013 2014 2015 2016 2017 2018 2019
Successful Transition from Organic Growth to Stable Production
and Free Cash Flow Generation in 2019
Viking Oil Production (bbl/d)
23
0
500
1,000
1,500
2,000
2,500
2020 Program RemainingUndrilled Inventory
High Netback Light Oil with Significant Running Room
High Netback Light Oil
($/boe)
Strong Price Realizations
and Low Cost Structure
$0
$10
$20
$30
$40
$50
$60
$70
US$55/bbl US$60/bbl
Royalties
Operating
Transportation
OperatingNetback
$0
$20
$40
$60
$80
$100
$120
$140
US$55/bbl US$60/bbl
Asset Level Free Cash
Flow (1) ($ millions)
~ $80 million Free Cash
Flow at US$55/bbl WTI
Drilling Inventory (2)
(Net locations)
~ 10 year inventory at
current pace
220 net wells
on-stream
> 2,000 net
locations
(1) Asset level free cash flow represents field level operating netback less exploration and development capital. MSW differential assumption US$5/bbl. 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 1,399 proved plus probable undeveloped reserves locations as at December 31, 2019 and 636 unbooked future locations. See “Advisories”
24
0
10
20
30
40
50
60
70
80
- 5,000 10,000 15,000 20,000 25,000
Oil
Rate
(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
Well Economics (2)
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.
(2) Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected
type curve that uses the following assumptions: well cost - $1 million; IP 365 - 44 boe/d; EUR - 48 mboe. MSW
differential assumption US$5/bbl.
WTI Oil Price $55/bbl $60/bbl
Payout: 2.2 years 1.7 years
IRR: 33% 49%
Recycle Ratio: 1.7x 2.0x
Breakeven:
(10% IRR)US$46/bbl
25
Peace River: Driving Production Growth and Cost Reductions
Performance Drivers
• Produced 16,800 boe/d in 2019
(86% oil)
• Dominant 738 net sections
• Innovative multi-lateral horizontal
drilling generate strong capital
efficiencies
• 2020 budget – 16 net wells
on-stream
Baytex Lands
Seal
Harmon Valley
Reno
North Seal Development
• 2018/2019 program (10 multi-
lateral horizontal wells)
generated 30-day IP rates of ~
700 boe/d per well
26
Lloydminster: Significant Land Position and Drilling Inventory
Performance Drivers
• Produced 12,600 boe/d in
2019 (98% oil)
• Strong capital efficiencies
and economics at current oil
prices
• Applying multi-lateral
horizontal drilling and
production techniques
• Ramp-up of Kerrobert
thermal project occurred in
Q4/2019 with peak
production of ~ 3,500 bbl/d
• 2020 budget – 60 net wells
on-stream
Baytex Lands
ALBERTA SASKATCHEWAN
Kerrobert
Lloydminster
Soda Lake
Tangleflags
Ardmore/Cold Lake
Lindbergh
27
0
100
200
300
400
500
600
700
2020Program
RemainingUndrilledInventory
2020Program
RemainingUndrilledInventory
Strong Capital Efficiencies and Significant Torq to Higher Oil Prices
Strong Capital Efficiencies (1)
($/boe/d)
Ability to Add Production
Cost Efficiently
Asset Level Free Cash
Flow (2) (C$ millions)
Significant Torq Above
US$50/bbl
$0
$20
$40
$60
$80
$100
$120
US$55/bbl US$60/bblPeace River Lloydminster
(1) Capital efficiency based on individual well costs (DCET) and IP365 using a Peace River multi-lateral horizontal well and a Lloydminster single-lined horizontal well.
(2) Asset level free cash flow represents field level operating netback less exploration and development capital. WCS differential assumption US$17.50/bbl. For illustrative purposes only and should not
be relied upon as indicative of future results. Baytex’s actual results may vary.
(3) Net locations for Peace River includes 152 proved plus probable undeveloped reserves locations as at December 31, 2019 and 100 unbooked future locations. Net locations for Lloydminster
includes 241 proved plus probable undeveloped reserves locations as at December 31, 2019 and 361 unbooked future locations. See “Advisories”
$12,000
per
boe/d
$13,000
per
boe/d
Drilling Inventory (3)
(Net locations)
> 10 year inventory
Peace River Lloydminster
28
Heavy Oil: Innovation Enhances Economic Returns
Peace River
Multi-Lateral Horizontal
Lloydminster
Horizontal
Well Economics (1)
WTI Oil Price $55/bbl $60/bbl
Payout: 1.6 years 1.2 years
IRR: 47% 83%
Recycle Ratio: 1.7x 2.2x
Breakeven:
(10% IRR)US$49/bbl
WTI Oil Price $55/bbl $60/bbl
Payout: 1.9 years 1.2 years
IRR: 35% 73%
Recycle Ratio: 1.3x 1.9x
Breakeven:
(10% IRR)US$52/bbl
(1) Individual well economics based on constant pricing and costs, and Baytex’s assumptions regarding an expected type curve that uses the following assumptions: Peace River well cost - $2.5
million; IP 365 - 209 boe/d; EUR - 250 mboe; Lloydminster well cost - $0.8 million ; IP 365 - 60 boe/d; EUR – 64 mboe. WCS differential assumption US$17.50/bbl.
29
East Duvernay Shale Light Oil: Emerging Resource Play
Baytex Lands
Pembina Region
• 275 sections of 100% WI lands
• Seven wells drilled to date have
delineated a minimum of 100-
125 sections
• Produced 1,700 boe/d (84%
liquids) in 2019
• Two wells on-stream in 2019
generated average 30-day IP
rate of ~ 1,050 boe/d (75%
liquids)
• D&C costs of ~ $7.0 million
represent an ~ 20% reduction
from previous wells
• Two most recent completions
utilize fracture diversion
technology
Pembina
Ferrybank
Gilby
Q4/2018 Completions
(4 wells)
14-36 Initial Pembina
Discovery (Q1/2018)Q3/2019 Completions
2 wells (14-31, 3-19)
30
Eagle Ford Viking Peace River (1) Lloydminster (1) East Duvernay
Formation Lower Eagle Ford Viking Bluesky Mannville Group Duvernay
Upper Eagle Ford
Austin Chalk
Depth (metres) 3,300-3,900 700 600 350-800 2,200-2,400
Oil API Oil: 40-45° 36° 11° 10-16° 42-44°
Condensate: 44-55°
Porosity 4.6% - 9% 23% 28% 30% 3% - 6%
Permeability 0.33 - 0.41 millidarcies 0.5 - 50 millidarcies 1 - 5 darcies 0.5 - 5 darcies 0 millidarcies
Completion Plug and perf Pin point coil Open hole multi-lateral
Horizontal slotted liner /
open-hole multi-lateral Plug and perf
Expected Well Costs
(drill, complete, equip and tie-in) US$5.6 million $1.0 million $2.5 million $0.8 million $7.0 million
6,000 foot lateral
Land - gross (net) sections 122 (31) 763 (656) 748 (738) 637 (491) 275 (275)
Pembina area
Reserves at YE 2019 (mmboe)
Proved developed producing 71 29 21 13 2
Proved 163 65 32 28 7
Proved plus probable 229 98 59 44 14
Drilling inventory (risked) – net
locations (booked/unbooked) 223 / 52 1,399 / 636 152 / 100 241 / 361 21 / 295
(1) Figures do not incorporate thermal assets at Cliffdale (Peace River) or Gemini (Lloydminster)
High Quality Oil Development
Corporate Sustainability
32
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.
33
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
34
A Culture of Commitment
Objective What we’ve done ResultHow it contributes to
value creation
EN
VIR
ON
ME
NT
Responsibly develop
our assets
Ensure our employees and
contractors uphold our procedures
for spill prevention, response and
cleanup
76% reduction in corporate spill
volumes, over 5 yearsReduces costs and maintains
social license
Exceed regulatory
obligations
Invested more than $100 million in
gas conservation activities in Peace
River in the last 5 years
99.1% routine gas conservation in
Peace RiverHelps to build trust with
regulators and stakeholders
SO
CIA
L
Create a culture of
safety
Tie safety targets to annual
performance incentive program
55% reduction in employee
+contractor LTIF in 5 years
Supports the consistent and
safe execution of our business
plan
Be a good neighbour
Build mutually beneficial
relationships based on trust
$32 million awarded in contracts
to Indigenous
contractors/companies in 2017-
2018
Maintain social license and
enables growth in our
operations by reducing non-
technical project delays
GO
VE
RN
AN
CE Ensure effective
Board leadership
Ensure our Board is comprised of
dedicated Directors who are
invested in our success
100% Board meeting attendance
and
25% women Board members as
of Sep. 2019
Sets strategic direction and
improves decision making
Be transparent and
accountable
Communicate our ESG impacts by
publishing biennial sustainability
reports since 2012
Recognized by Corporate Knights
as Future 40 Responsible
Corporate Leaders in 2018
Enables shareholders and
stakeholders to make informed
decisions
Source: 2018 Sustainability Report – September 2019
Supplementary Information
36
Summary of Operating and Financial Metrics
Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019
Benchmark Prices
WTI crude oil (US$/bbl) $62.87 $67.88 $69.50 $58.81 $64.77 $54.90 $59.81 $56.45 $56.96 $57.03
NYMEX natural gas (US$/mcf) $3.00 $2.80 $2.90 $3.64 $3.09 $3.15 $2.64 $2.23 $2.50 $2.63
Production
Crude oil (bbl/d) 45,835 46,644 56,767 71,326 55,218 71,939 69,905 68,541 70,956 70,328
Natural gas liquids (bbl/d) 9,143 9,419 10,076 10,327 9,745 11,729 10,986 9,543 8,699 10,229
Natural gas (mcf/d) 87,261 87,605 93,414 103,424 92,971 104,682 105,065 101,054 100,236 102,742
Oil equivalent (boe/d) (1) 69,522 70,664 82,412 98,890 80,458 101,115 98,402 94,927 96,360 97,680
% Liquids 79% 79% 81% 83% 81% 83% 82% 82% 83% 82%
Netback ($/boe)
Total sales, net of blending and other expenses (2) $42.96 $51.22 $55.03 $37.89 $46.31 $47.98 $51.49 $47.14 $48.25 $48.72
Royalties (10.36) (12.01) (12.13) (8.77) (10.68) (8.94) (9.67) (8.59) (8.72) (8.98)
Operating expense (10.53) (10.91) (10.25) (10.76) (10.61) (11.02) (11.22) (11.15) (11.23) (11.16)
Transportation expense (1.36) (1.22) (1.26) (1.21) (1.26) (1.46) (1.33) (1.13) (1.00) (1.23)
Operating Netback (4) $20.71 $27.08 $31.39 $17.15 $23.76 $26.56 $29.27 $26.27 $27.30 $27.35
General and administrative (1.76) (1.64) (1.34) (1.55) (1.56) (1.55) (1.28) (1.14) (1.12) (1.28)
Cash financing and interest (3.92) (3.97) (3.47) (3.07) (3.55) (3.10) (3.14) (3.06) (2.75) (3.01)
Realized financial derivative gain (loss) (1.57) (4.57) (4.07) (0.34) (2.49) 2.07 1.45 2.39 2.59 2.12
Other (3) 0.01 (0.31) 0.07 (0.02) (0.05) 0.28 0.07 (0.03) 0.16 0.13
Adjusted funds flow (4) $13.47 $16.59 $22.58 $12.17 $16.11 $24.26 $26.37 $24.43 $26.19 $25.31
(1) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly
if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
(2) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the
realized pricing on our produced volumes to the WCS benchmark.
(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q3/2019 MD&A for
further information on these amounts.
(4) The terms “adjusted funds flow” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be
comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures on slide 3 of this presentation.
37
Reserves Summary (Gross)
Eagle Ford
Viking
Heavy Oil
East Duvernay
Other
Category (1) Eagle Ford Viking Heavy OilEast
DuvernayOther Total
BT NPV-10
($MM)
Total Debt
Coverage (2)
Proved Developed Producing 71 29 34 2 6 142 $2,211 1.2x
Total Proved 163 65 68 7 11 314 $3,710 2.0x
Total Proved Plus Probable 229 98 163 14 25 529 $5,600 3.0x
2P Reserves by Asset2P Reserves Breakdown 2P Reserves by Commodity
Light Oil + NGLHeavy
Oil
Natural Gas
Probable
PDNP + PUD
PDP
(1) Baytex reserves as at December 31, 2019 as evaluated by McDaniel & Associates Consultants Ltd.
(2) Total Debt Coverage calculated as Total Debt as at December 31, 2019, divided by BT NPV-10.
38
2020 Guidance and Cost Assumptions
Exploration and development expenditures ($ millions) $500 - $575
Production (boe/d) 93,000 - 97,000
Expenses:
Royalty rate (%) 18.0% - 18.5%
Operating ($/boe) $11.25 - $12.00
Transportation ($/boe) $1.20 - $1.30
General and administrative ($ millions) $45 ($1.30/boe)
Interest ($ millions) $112 ($3.23/boe)
Leasing expenditures ($ millions) $7
Asset retirement obligations ($ millions) $19
39
Notes
Edward D. LaFehrPresident and Chief Executive Officer
587.952.3000
Rodney D. GrayExecutive Vice President and Chief Financial Officer
587.952.3160
Brian G. EctorVice President, Capital Markets
587.952.3237
Baytex Energy Corp.
Suite 2800, Centennial Place
520 – 3rd Avenue S.W.
Calgary, Alberta T2P 0R3
T 587.952.3000
Toll Free 1.800.524.5521
www.baytexenergy.com
Contact Information