Investor Presentation. August 2018

Transcription

1 Investor Presentation August 2018

2 Advisory Forward Looking Statements Any financial outlook or future oriented financial information in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other circumstances. In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of future plans and operations, certain statements in this presentation are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this presentation peak only as of the date hereof and are expressly qualified by this cautionary statement. Specifically, this presentation contains forward-looking statements relating to but not limited to: the vision for Baytex, including that: it will be a top tier North American oil producer focused on per share value creation; have disciplined growth and return of capital to shareholders, be a self-funded business model, target 10-15% annual total return to shareholders, will consider share buybacks and/or reinstating a dividend at the appropriate time, have strong asset quality, be more than 80% liquids-weighted and more than 80% operated, have a long term decline rate of less than 30%, target accretive acquisitions, focus on next play capture; target a net debt to adjusted funds flow ratio of less than 1.5; the outlook for production volumes, adjusted funds flow and net debt to adjusted funds flow ratio from now until year-end 2023; that Baytex will have world class assets, an attractive growth and free cash flow profile, high return oil-weighted assets, a superior capability to optimize capital allocation, a strong balance sheet and a top tier management team; expectations for Baytex, including: forecast 2019 average annual production; ratio of net debt to adjusted funds flow; sustaining capital and free cash flow yield, 2019 free cash flow above growth capital of $200 million and the resulting rate of debt adjusted growth per share and the estimated 2019 operating netback; estimated 2019 adjusted funds flow and free cash flow; expected internal rates of return, undiscounted payout range, capital efficiencies and drilling inventory; that Baytex as an enhanced platform for growth, will build on strong operational momentum and drive further operational excellence and shareholder returns; Baytex s estimates of reserves; expectations as to Baytex s annual production growth rate, forecast 2019 average annual production, adjusted funds flow, sustaining capital, growth capital, debt repayment, development activity (net wells and capital expenditures) by area; 2019 preliminary guidance for exploration and development capital expenditures, production, adjusted funds flow, operating netback, year-end net debt, year-end net debt to adjusted funds flow ratio; expectations as to Baytex s production, operating cash flow, capital allocation and free cash flow by core area for 2019; the impact of changes to the price of WTI on Baytex s 2019 free cash flow and net debt to adjusted funds flow ratio; the IRR for individual wells at certain WTI prices for the Eagle Ford, Peace River, Lloydminster, Viking and East Duvernay; for the Eagle Ford, expectations as to Northern Austin Chalk drilling activity for 2018; for the Duvernay, that required infrastructure spending is minimal, the potential drilling inventory and planned well completion activity; for the Viking, that extended reach horizontal wells will enhance returns and extend the runway and for individual wells: the drill, complete and equip cost, expected 30-day IP rate and the estimated ultimate recovery; for Peace River and Lloydminster, expectations as to number of wells and rigs to be used in 2018 and 2019, the IRR of the wells and for individual wells: the drill, complete and equip cost, expected 30-day IP rate and the estimated ultimate recovery; the sensitivity of our adjusted funds flow to changes in WTI prices, heavy oil differentials, natural gas prices and Canada-United States foreign exchange rates; and the percentage of Baytex s net exposure to oil prices, heavy oil differentials and natural gas prices that is hedged for 2018 and 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: the ability of Baytex to realize the anticipated benefits of the strategic combination with Raging River; 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. Baytex has disclosed certain expected details relating to Baytex's 2019 capital program and expected guidance; however, the board of directors of Baytex has not approved a budget for 2019 and as such the details relating to the 2019 capital program and guidance are intended only to illustrate Baytex's current expectations based on information and conditions known as of the date hereof. Baytex's actual 2019 capital budget once approved may differ from the details disclosed herein for a variety of reasons including as a result of any change in conditions and information known to Baytex prior to the date the 2019 budget is approved and/or as a result of Baytex's management and board of directors allocating capital differently than currently expected. The actual 2019 capital budget will impact the 2019 guidance provided herein as well. The actual 2019 capital program and the guidance set out herein may also differ from the expectations as set out herein due to the other risk factors identified herein. 2

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; the availability and cost of capital or borrowing; that credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in debt agreements; risks associated with a third-party operating our Eagle Ford properties; availability and cost of gathering, processing and pipeline systems; public perception and its influence on the regulatory regime; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with hedging activities; the cost of developing and operating assets; depletion of reserves; risks associated with the exploitation of properties and ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; 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 operations; risks associated with large projects; risks related to thermal heavy oil projects; risks associated with use of information technology systems; risks associated with the ownership of Baytex, 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 control. These and additional risk factors are discussed in Baytex's Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2017, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission. 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 and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be 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. adjusted funds flow, bank EBITDA, debt adjusted production per share growth, free cash flow, internal rate of return, net debt and operating netback 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 and asset retirement obligations settled. 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. Bank EBITDA is defined as consolidated net income attributable to shareholders before interest, taxes, depletion and depreciation, and certain other non-cash items as set out in the credit agreement governing Baytex s revolving credit facilities. Management of Baytex use Bank EBITDA to measure compliance with certain financial covenants in Baytex s credit agreement. Debt adjusted production per share growth is defined as growth in production over the period on a per share basis with the number of shares adjusted based on debt outstanding. Baytex s 2019 debt adjusted production per share growth is calculated based on the forecast of 2019 production per debt-adjusted share divided by the combined production of Baytex and Raging River for Q2/2018 per debt-adjusted share as at closing of the transaction. Debt-adjusted share count is calculated as total shares outstanding plus incremental shares issued at current market price ($3.91) 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. Free cash flow is defined as adjusted funds flow less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset production declines on an annual basis and maintain flat production volumes. Internal rate of return of IRR is a rate of return measure used to compare the profitability of an investment and represents the discount rate at which the net present value of costs equals the net present value of the benefits. The higher a project s IRR, the more desirable the project. Net debt is defined as the sum of monetary working capital (which is current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term notes of Baytex and the 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. 3

4 Advisory (Cont.) Advisory Regarding Oil and Gas Information The reserves information contained in this presentation has been prepared in accordance with National Instrument Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators ("NI "). 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. For complete NI reserves disclosure, please the Annual Information Forms for the year end December 31, 2017 for Baytex and Raging River respectively. 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 187 proved, 69 probable and 263 unbooked locations. In the Viking, Baytex s net drilling locations include 1,109 proved, 51 probable and 1,340 unbooked locations. In Peace River, Baytex s net drilling locations include 73 proved, 91 probable and 204 unbooked locations. In Lloydminster, Baytex s net drilling locations include 213 proved, 47 probable and 690 unbooked locations. In the Duvernay, Baytex s net drilling locations include 2 proved, 2 probable and 746 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" and "possible reserves" (each as defined in SEC rules). Canadian securities laws require oil and gas issuers disclose their reserves in accordance with NI , which requires disclosure of not only "proved reserves" but also "probable reserves" and permits the optional disclosure of "possible reserves". Additionally, NI defines "proved reserves", "probable reserves" and "possible reserves" differently from the SEC rules. Accordingly, proved, probable and possible 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. Possible reserves are higher risk than probable reserves and are generally believed to be less likely to be accurately estimated or recovered than probable 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 press release are stated in Canadian dollars unless otherwise specified. 4

5 Vision A Top Tier North American Oil Producer Focused on Per Share Value Creation Disciplined growth and return of capital to shareholders Target 10-15% annual total return to shareholders Self funded business model focused on per share growth Target net debt to adjusted funds flow ratio of < 1.5x Consider share buyback and/or reinstating dividend at the appropriate time Production (Mboe/d) Production Growth Pro forma Build on strong asset quality Adjusted Funds Flow Liquids weighting > 80% Operated production > 80% Long-term decline rate < 30% Target accretive acquisitions Focus on next play capture Adjusted Funds Flow ($MM) $1,600 $1,400 $1,200 $1,000 $800 Pro forma Adjusted Funds Flow Net Debt to Adjusted Funds Flow x 2.0x 1.5x 1.0x 0.5x Net Debt to Adjusted Funds Flow (x) 5

6 Corporate Profile Market Summary Ticker Symbol TSX / NYSE: BTE Average Daily Volume (1) CAN: 7,000,000/ US: 1,900,000 Shares Outstanding 555 million Market Capitalization / Enterprise Value $2.2 billion / $4.3 billion Net Debt (2) $2.1 billion Corporate Summary Production (3) Production Mix E&D Capital (3) Reserves 2P Gross (4) 100, ,000 boe/d 85% oil and liquids $750 - $850 million 539 mmboe (1) Average daily trading volumes for July Volumes are a composite of all exchanges in Canada and the U.S. (2) Net debt is the principal amount of long-term notes and bank loan and includes working capital, pro forma Raging River combination as at August 22, (3) Production and exploration and development capital represents 2019 preliminary guidance range. (4) Gross reserves are based on Baytex gross reserves as at December 31, 2017 as evaluated by Sproule Unconventional Limited and Ryder Scott Company L.P., and Raging River gross reserves as at December 31, 2017 as evaluated by Sproule Associates Limited and GLJ Petroleum Consultants Ltd.. 6

7 Creating a Top-Tier Oil Producer With Exceptional Assets Enterprise value $4.3 billion Four high quality crude oil assets World Class Asset Base (1) > 100,000 boe/d (2019E) 2P Reserves 539 mmboe Leading oil plays in the best High Return Oil Weighted Assets High margins and capital efficiencies IRRs of 50%-110% and payouts jurisdictions of 6-18 months at US$65/bbl WTI Attractive Growth and Free Cash Flow (2)(3)(4) 5% -10% annual production growth ~ $900 million adjusted funds flow and $325 million free cash flow Superior Capability to Optimize Capital Allocation Well defined 10+ year drilling inventory Strong oil price diversification Positioned to develop East Duvernay Shale oil play Strong Balance Sheet (2)(3) 2.2x net debt to adjusted funds flow Strong financial liquidity No long-term debt maturities until 2021 Top Tier Team with Focus On Operational Excellence Enhanced platform for growth Build on strong operational momentum Drive further operational excellence and shareholder returns (1) Reserves based on Baytex gross reserves as at December 31, 2017 as evaluated by Sproule Unconventional Limited and Ryder Scott Company, L.P., and Raging River gross reserves as at December 31, 2017 as evaluated by Sproule Associates Limited and GLJ Petroleum Consultants Ltd. (2) Based on 2019 preliminary guidance (3) Based on forward strip commodity prices for 2019 (as at August 20, 2018); WTI - US$63/bbl; LLS - US$67/bbl, WCS differential - US$23/bbl; MSW Differential US$7/bbl; NYMEX Gas - US$2.80/mcf; Exchange Rate (CAD/USD) (4) Free Cash Flow is defined as adjusted funds flow less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset production declines on an annual basis and maintain flat production. Pro forma sustaining capital is estimated at $575 million. 7

8 World Class Asset Base Production by Core Area (1) Operating Cash Flow (2) Other Other Lloyd. PEACE RIVER Lloyd. Peace River Viking Eagle Ford Peace River Viking Eagle Ford DUVERNAY LLOYDMINSTER VIKING 2019E Capital Allocation Free Cash Flow (2)(3) EAGLE FORD Lloyd. Peace River Viking Eagle Ford Peace River Other Lloyd. Viking Eagle Ford (1) Production composition based on 2019 preliminary guidance. (2) Pricing assumptions: WTI - US$65/bbl, LLS - US$69/bbl, WCS differential - US$20/bbl, NYMEX gas - US$2.75/mcf, FX Rate (C$/US$) (3) Free Cash Flow is defined as adjusted funds flow less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset production declines on an annual basis and maintain flat production. Pro forma sustaining capital is estimated at $575 million. 8

9 Company Highlights: 2019 Annual Estimates Average annual production of 100,000 to 105,000 boe/d (85% oil and NGL) with an exploration and development capital program of $750 to $850 million, Debt adjusted production per share growth of approximately 12% Adjusted funds flow of approximately $900 million Net debt to adjusted funds flow of 2.2x Sustaining capital of $575 million Strong operating netback of approximately $28/boe across portfolio Approximately 275,000 acres in the East Duvernay Shale oil play with recent exploration success validating the prospectivity of the lands Notes: (1) Debt-Adjusted Production Per Share Growth calculated as 2019E production per debt-adjusted share divided by pro forma Q production per debt-adjusted share. Debt-adjusted share count calculated as total shares outstanding plus incremental shares issued at current market price to eliminate net debt (i.e., full equitization of net debt). (2) Based on forward strip commodity prices for 2019 (as at August 20, 2018); WTI - US$63/bbl; LLS - US$67/bbl, WCS differential - US$23/bbl; MSW Differential US$7/bbl; NYMEX Gas - US$2.80/mcf; Exchange Rate (CAD/USD) (3) Net debt to adjusted funds flow ratio based on forecast net debt at year-end 2019 and forecast 2019 adjusted funds flow. (4) Certain terms referenced above are non-gaap measures. See advisory regarding Non-GAAP Financial and Capital Management Measures. 9

10 Preliminary 2019 Plans 2019 annual average production of 100,000 to 105,000 boe/d 2019 Preliminary Plans E&D CapEx $750 - $850 million ~ 8% production growth over 2018 pro forma average annual production Adjusted funds flow of ~ $900 million Sustaining capital: $575 million Growth capital: $225 million Debt repayment: $100 million Production 100, ,000 boe/d Oil and NGLs 85% Operating Netback (1) $28/boe Adjusted Funds Flow (1) $900 million Adjusted Funds Flow per Share (2) $1.60 Development Activity Net debt (year-end) $2.0 billion Area Net Wells CapEx ($MM) Net Debt to Adjusted Funds Flow (3) 2.2x Viking 275 $250 Eagle Ford 30 $230 East Duvernay $110 Peace River 32 $100 Lloydminster 100 $90 Notes: (1) Based on forward strip commodity prices for 2019 (as at August 20, 2018); WTI - US$63/bbl; LLS - US$67/bbl, WCS differential - US$23/bbl; MSW Differential US$7/bbl; NYMEX Gas - US$2.80/mcf; Exchange Rate (CAD/USD) (2) Based on 555 million common shares outstanding. (3) Net debt ratios based on forecast net debt at year-end 2019 and forecast 2019 adjusted funds flow. Other $20 Total $800 10

11 Significant Free Cash Flow Profile Significant free cash flow to pursue organic growth, reduce debt, pursue strategic acquisitions and/or reinstate a dividend (1)(2) $900 (3) Free Cash Flow Net Debt / Adjusted Funds Flow (4) 3.5x Free Cash Flow ($MM) $800 $700 $600 $500 $400 $300 $ x 2.5x 2.0x 1.5x 1.0x Net Debt / Adjusted Funds Flow (x) $ x $55 $60 $65 $70 $75 $80 WTI (US$/bbl) Notes: (1) Pro forma production is based on preliminary 2019 guidance of 100,000 to 105,000 boe/d. (2) Price Assumptions: LLS WTI + US$4/bbl; NYMEX gas - US$2.75/mcf; WCS heavy oil differential - US$20/bbl; Exchange Rate (C$/US$) (3) Free Cash Flow is defined as adjusted funds flow less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset production declines on an annual basis and maintain flat production. Pro forma sustaining capital is estimated at $575 million. (4) Net debt to adjusted funds flow is calculated based on forecast year-end 2019 net debt to projected 2019 adjusted funds flow. Excess cash flow above 2019 capital spending guidance is utilized to reduce net debt. 11

12 High Rate of Return Oil Development 200% High quality oil assets Internal Rate of Return (1)(2)(3) 175% 150% 125% 100% 75% 50% Eagle Ford Peace River Lloydminster Viking East Duvernay Superior capability to optimize capital allocation Strong oil price diversification Well defined low-risk inventory that represents over 10 years of development opportunities 25% 0% $55 $60 $65 $70 $75 $80 Payouts ranging from 6-18 months at constant US$65/bbl WTI WTI (US$/bbl) Notes: (1) Individual well economics for the chart based on constant pricing and costs. Pricing assumptions: NYMEX gas = US$2.75/mcf, WCS differential = US$20/bbl, FX Rate (C$/US$) = (2) Type curve assumptions: Eagle Ford: well cost US$5.6 million (normalized 5,500 foot lateral), 30-day IP rate ~ 1,350 boe/d, EUR ~ 800 mboe. Peace River: well cost $2.6 million (multi-lateral horizontal), 30-day IP rate ~ 350 boe/d, EUR ~ 250 mboe. Lloydminster: well cost $750,000 (single lined horizontal), 30-day IP rate ~ 60 boe/d, EUR ~ 70 mboe. Viking: well cost $900,000 (extended reach horizontal), 30-day IP rate 90 boe/d, EUR ~ 55 mboe, East Duvernay Shale: well cost $6.5 million, 30-day IP rate ~ 380 boe/d, EUR ~ 427 mboe. Baytex internal estimates. (3) Internal rate of return ( 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. 12

13 High Return Oil Development Inventory 10+ years drilling inventory in each core area Viking Light Oil Eagle Ford Light Oil Peace River Heavy Oil Lloydminster Heavy Oil East Duvernay Light Oil Self-Funding Light Oil Growth Free Cash Flow Light Oil Self-Funding Heavy Oil Growth Self-Funding Heavy Oil Growth Early Stage Light Oil Growth Production 21,000 boe/d 36,000 boe/d 16,500 boe/d 11,000 boe/d 500 boe/d Oil and NGLs 93% 78% 91% 99% 90% Op. Netback $46/boe $36/boe $18/boe $18/boe $46/boe DCET Well Cost $900,000 US$5.6 million $2.6 million $750,000 $6.5 million IRR (2) % % 50-75% % 80% Payout (2) 6-15 months 9-12 months months months 24 months Capital Efficiency $21,000 boe/d $11,000 boe/d $12,000 boe/d $13,000 boe/d $25,000 boe/d Dominant position with over 460 net sections Top decile returns and netbacks Excellent position (Karnes County) in the heart of play Receives LLS pricing (premium to WTI) Dominant 725 net section land position Innovative, multi-lateral Hz drilling Multiple stacked pay formations at shallow depths Vertical, Hz, and SAGD opportunities 430 net sections Top decile netbacks Strong growth potential (1) Production from the five areas represents approximately 90% of pro forma production. (2) Pricing assumptions: WTI - US$65/bbl; LLS - US$69/bbl; WCS differential - US$20/bbl; NYMEX Gas - US$2.75/mcf; and Exchange Rate (CAD/USD)

14 Leverage Profile Bank Debt Covenants Covenant Pro Forma Senior Secured Debt (1) / Bank EBITDA (2) Max 3.5:1 0.5x (2019E) Interest Coverage (3) Min 2:1 9.2x (2019E) Debt Maturities $ in millions Revolving Credit Facilities Long-term Notes C$500 Undrawn US$ % Pro forma net debt $2.1 billion C$550 Drawn US$ % C$ % US$ % (1) Senior Secured Debt is defined as the principal amount of our bank loan and other secured obligations under the credit facilities.. (2) Bank EBITDA is calculated based on terms and conditions set out in the credit agreement which adjusts net income for interest expense, income taxes, certain non-cash items and acquisition and disposition activity. Bank EBITDA is calculated based on a trailing twelve month basis. (3) Interest Coverage is computed as the ratio of Bank EBITDA to financing and interest expense on our Senior Secured Debt and long-term notes. 14

15 Asset Overview

16 Eagle Ford: Step Change in Well Performance Enhanced completions drive improved well performance Increased lateral length, proppant loading and frac stages Q2/2018 Development Achieved record production rates from new wells 32 gross wells established average 30 day IP rates of 1,850 boe/d per well 25% improvement over wells brought on production in 2017 Northern Austin Chalk Two wells in Austin Chalk fracture trend demonstrated 30-day IP rates of ~2,400 boe/d per well 5-6 gross wells planned for 2018 Cumulative Production (mboe) Day Cumulative Well Production ~20% increase at 180 days 2016 vs Months Completion Activity Hz Length (ft) Proppant (lbs/ft) Stage Spacing (ft) # of Stages H1/2018 6,100 2, ,900 1, ,500 1, ,200 1, ,400 1, , , ,

17 Eagle Ford: Strong Q2/2018 Karnes and Atascosa Drilling Results Franke May B 3 well pad 80% oil Average 30-day IP: 1,600 boe/d Best Well: 1,800 boe/d Coy City Ranch 4 well pad 80% oil Average 30-day IP: 1,200 boe/d Best Well: 1,400 boe/d Turnbull B-C 6 well pad 70% oil Average 30-day IP: 1,900 boe/d Best Well: 2,300 boe/d Wilson Karnes LONGHORN Atascosa SUGARLOAF EXCELSIOR IPANEMA Live Oak Bee Oil Condensate Dry Gas Karnes City NE 6 well pad 74% oil Average 30-day IP: 2,100 boe/d Best Well: 3,300 boe/d Egbert Miller 3 well pad 70% oil Average 30-day IP: 1,850 boe/d Best Well: 2,300 boe/d May 1 4 well pad 55% oil Average 30-day IP: 2,100 boe/d Best Well: 2,500 boe/d Franke Johnson 6 well pad 50% oil Average 30-day IP: 1,700 boe/d Best Well: 2,300 boe/d 17

18 Viking Light Oil: 460 Highly Prospective Sections Shallow (700 m), Light oil (36 API) resource play Strong netback estimate $46/boe field netback at US$65/bbl Esther/Hoosier Kerrobert Plenty Greater Gleneath Lucky Hills/Whiteside Dodsland Short cycle, fast payouts spud to producing oil ~ 20 days 250 to 275 net wells planned for 2019, 3 to 4 drilling rigs Mantario (Laporte) Plato Forgan Wells generate IRRs of % at US$65/bbl Baytex Lands Extended Reach Horizontals are enhancing returns and extending the runway 18

19 Viking Light Oil Development Reservoir Characteristics (1) Formation Viking Formation Depth 700 metres Completion Pin point coil Frac Oil Quality API Average Porosity 23% Permeability millidarcies Oil Saturation 65% Individual Wells (1) DCET Well Cost $900, day IP boe/d EUR mboe (1) Baytex internal estimates. 19

20 Peace River: Driving Production Growth and Cost Reductions North Seal Development First three wells on acquired lands generated 30-day IP rates of ~ 800 boe/d per well Nine wells to be drilled in the area in 2018 Harmon Valley Seal Performance Drivers Dominant 725 net sections Reno Increased 2 rig drilling program to continue through 2019 ~ 18 net wells planned for 2018; 32 net wells for 2019 Baytex Lands Wells generate IRRs of 50% to 75% at US$65/bbl 20

21 Peace River: Multi-Lateral Horizontal Wells Reservoir Characteristics (1) Formation Bluesky Depth ~ 600 metres Completion Open Hole Oil Quality 11 API Average Porosity 28% Permeability 1-5 darcies Oil Saturation 70% Recovery Factor 5-7% Individual Wells (1) DCET Well Cost 30-day IP EUR $2.6 million boe/d mboe (1) Baytex internal estimates. 21

22 Lloydminster: Significant Land Position and Drilling Inventory Ardmore/Cold Lake Performance Drivers Lindbergh Lloydminster Tangleflags Soda Lake Increased 2 rig drilling program to continue through 2019 ~ 100 net wells per year Kerrobert Applying multi-lateral horizontal drilling and production techniques in the Soda Lake area (~ 20 net wells in 2018) Baytex Lands ALBERTA SASKATCHEWAN Wells generate IRRs of 50% to 110% at US$65/bbl 22

23 Lloydminster Development Reservoir Characteristics (1) Formation Depth Mannville Group metres Completion Horizontal Slotted Liner / Vertical Stacked Pays Oil Quality API Average Porosity 30% Permeability darcies Oil Saturation 70% Individual Wells (1) DCET Well Cost $750, day IP boe/d EUR mboe (1) Baytex internal estimates. 23

24 East Duvernay Shale Light Oil: Emerging Resource Play Early stage, high netback light oil resource play 430 net sections (275,000 acres) within the Duvernay Oil window, ~57% Crown FOX CREEK WEST SHALE BASIN Moderate drilling depths ~ 2,200 to 2,400 metres tvd Significant resource potential of 8 to > 25 MMbbls OOIP per section Minimal and manageable infrastructure spending required to develop the play Significant cost and technology improvements to date but still early in the play evolution Baytex Focus Areas RED DEER Large drilling inventory potential for 750 horizontal light oil locations 24

25 East Duvernay Shale Light Oil: Emerging Resource Play Duvernay Well Significant Q1, 2018 light oil discovery (42 API) On production March 23, 2018 Average production rate in June boe/d (86% light oil and NGLs) 4-11 Duvernay Well Initial Q4/2017 light oil discovery (38 API) On production November 6, 2017 Cumulative oil to date 34 mstb (35.5 mboe) 2-20 Duvernay Well Drilled and cased in Q1/ mile lateral Successful completion in Q2/2018 and placed on-stream. Results expected Q3/ Duvernay Well 6-12 wells planned for H2/2018 through Q2/2019 Drilled and cased in Q1/2018 Successful completion in Q2/2018 and placed on-stream. Results expected Q3/2018. Baytex Lands 25

26 Supplementary Information

27 Board of Directors Kevin Olson (1) (2) Edward D. LaFehr President and Chief Executive Officer Neil Roszell Chairman Raymond T. Chan (2) (3) Lead Independent Director Dave Pearce (3) (4) Gregory K. Melchin (1) (4) Gary Bugeaud (2) (4) Trudy M. Curran (2) (4) Mark R. Bly (1) (3) Naveen Dargan (1) (3) (1) Member of the Audit Committee (2) Member of the Human Resources and Compensation Committee (3) Member of the Reserves Committee (4) Member of the Nominating and Governance Committee 27

28 Baytex Leadership Team Edward LaFehr President & CEO Mr. LaFehr joined Baytex as President on July 18, 2016 and was appointed Chief Executive Officer on May 4, Mr. LaFehr has nearly 35 years of experience in the oil and gas industry working with Amoco, BP, Talisman and the Abu Dhabi National Energy Company ("TAQA") in various geographies. Before joining Baytex, Mr. LaFehr was President of TAQA's North American oil and gas business which led to his subsequent role as Chief Operating Officer of TAQA, globally. Prior to this, he served as Senior Vice President for Talisman Energy, accountable for its Canadian business. Mr. LaFehr has a long track record of success in the oil and gas industry leading organizations, growing assets and joint ventures, and driving capital and cost efficiencies. Mr. LaFehr holds Masters degrees in geophysics and mineral economics from Stanford University and the Colorado School of Mines, respectively. Bruce Beynon EVP, Exploration & Corporate Development Mr. Beynon joined Baytex as Executive Vice President, Exploration and Corporate Development on August 22, Mr. Beynon is a professional geologist with 30 years of industry experience. Previously, he was President of Raging River Exploration Inc. from June 2017 until August 2018, Executive Vice President from December 2015 until June 2017 and Vice President, Exploration from March 2012 until December From October 2010 to February 2012, Mr. Beynon was the Vice President, Exploration with Compass Petroleum Partnership. Prior to Compass, from February, 2006 to June, 2010, Mr. Beynon was the President and CEO of Peloton Exploration Corp. From 2003 to 2006, Mr. Beynon was the President and CEO of Espoir Exploration Corp. From 1999 to 2003, Mr. Beynon was Vice President, Exploration for KeyWest Energy Inc. Mr. Beynon graduated with a Masters of Science degree in Geology in Rodney Gray EVP, Chief Financial Officer Mr. Gray was appointed Executive Vice President and Chief Financial Officer of Baytex on August 22, He joined Baytex on April 7, 2014 and served as Chief Financial Officer from April 2014 to August Mr. Gray has over twenty years experience in the oil and gas industry. Prior to joining Baytex, Mr. Gray held the position of Chief Financial Officer for CEDA International. Prior thereto, he spent eleven years with Enerplus Corporation, the last eight of which as Vice President, Finance, where areas of responsibility included corporate reporting, treasury and capital markets, operational accounting, business analysis, risk management and insurance. Mr. Gray is a Chartered Accountant and has a Bachelor of Commerce degree with Honours from Queen's University. He is very active in the community having been involved with several charitable organizations. 28

29 Baytex Leadership Team Richard Ramsay EVP, Chief Operating Officer Mr. Ramsay was appointed Executive Vice President and Chief Operating Officer of Baytex on August 22, He originally joined Baytex in January 2010 and has held the following positions: Vice President, Heavy Oil from January 2010 to January 2012, Vice President, Alberta/B.C. Business Unit from January 2012 to May 2014 and Chief Operating Officer from May 2014 to August Mr. Ramsay has over 25 years of experience in the Canadian oil and gas industry and was formerly Chief Operating Officer of TAQA North Ltd. He previously held a variety of technical and management positions with Northrock Resources Ltd., Fletcher Challenge Energy Canada Inc., Amoco Canada Petroleum Ltd. and Dome Petroleum Ltd. Mr. Ramsay has a Bachelor of Science degree with Distinction in Mechanical Engineering from the University of Saskatchewan and is a practicing member of the Association of Professional Engineers, Geologists and Geophysists of Alberta. Jason Jaskela VP, Duvernay and EagleFord Shale Mr. Jaskela joined Baytex as Vice President, Duvernay and Eagle Ford Business Units on August 22, Mr. Jaskela is a professional engineer with 18 years of industry experience. Previously, Mr. Jaskela was Chief Operating Officer of Raging River Exploration Inc. from March 2014 until August 2018 and the Vice President, Production from March 2012 until March From October 2009 to April 2010 he held the position of Manager Engineering with Wild Stream Exploration Inc. and was the Vice President, Production from April 2010 until March Prior to Wild Stream, Mr. Jaskela held senior engineering roles with Encana Corporation (May 2000 to May 2006) and Mahalo Energy Ltd. (May 2006 to October 2009). Mr. Jaskela graduated with a Bachelor of Science degree in Engineering in Brian Ector VP, Capital Markets Mr. Ector is Vice President, Capital Markets of Baytex and is responsible for Baytex's equity capital markets, investor relations and public affairs functions. He joined Baytex in November Prior to joining Baytex, Mr. Ector spent 15 years as a sell-side research analyst covering both energy trusts and exploration and production corporations. He spent the last seven years with Scotia Capital where he was consistently ranked as one of the top rated analysts in Canada. Mr. Ector received a Bachelor of Commerce degree with a concentration in finance from the University of Calgary and received his Chartered Financial Analyst designation in He is a national board member of the Canadian Investor Relations Institute as well as a member of the National Investor Relations Institute, the CFA Institute and the Calgary CFA Society. 29

30 Q Results: Delivering on our Operational and Financial Targets Production of 70,664 boe/d in line with guidance 80,000 Production Growth Adjusted funds flow of $107 million exceeded capital expenditures by $28 million Operational Momentum Executed Q2/2018 drilling program in Canada with strong results at Peace River and Lloydminster Established average 30-day IP rates of ~1,850 boe/d per well in the Eagle Ford, representing a 25% improvement over wells brought on production in Realized an operating netback of $35.42/boe in the Eagle Ford, the strongest since Q3/2014. Expanded our crude by rail volumes to 8,300 bbl/d (33% of our heavy oil production). Boe/d 70,000 60,000 50,000 40,000 30,000 20,000 10,000 Notes: 0 Q116 Q216 Q316 Q416 Q117 Q217 Q317 Q417 Q118 Q218 H Scorecard (1) As announced on December 7, Annual H Guidance (1) Results Canada U.S. E&D CapEx ($ millions) Production (boe/d) 68,000-72,000 70,095 Operating Expense ($/boe) G&A Expense ($/boe)

31 2019E Adjusted Funds Flow Sensitivities Sensitivities Estimated Effect on Annual Adjusted Funds Flow ($MM) (1) Excluding Hedges Including Hedges Change of US$1.00/bbl WTI crude oil $28.1 $25.8 Change of US$1.00/bbl WCS heavy oil differential $13.3 $13.3 Change of US$0.25/mcf NYMEX natural gas $8.3 $8.3 Change of $0.01 in the C$/US$ exchange rate $12.8 $12.8 (1) Price Assumptions: WTI - US$63/bbl. LLS US$67/bbl; NYMEX gas - US$2.80/mcf; WCS heavy oil differential - US$23/bbl; MSW differential US$7/bbl; Exchange Rate (C$/US$)

32 Crude Oil Hedge Portfolio Q3/18 Q4/ WTI Fixed Hedges Volumes (bbl/d) 14,833 16,500 7,000 (1) Fixed Price (US$/bbl) $52.30 $52.27 $61.22 WTI 3-Way Option Volumes (bbl/d) 2,000 2,000 2,000 Average Ceiling/Floor/Sold Floor (US$/bbl) (2) $60/$54/$40 $60/$54/$40 $70/$60/$50 Brent Hedges Volumes (bbl/d) 4,000 4,000 3,000 Fixed Price (US$/bbl) / 3-Way Option (US$/bbl) $61.31 $61.31 $78.68/$69.50/$59.50 Total Hedge Volumes (bbl/d) 20,833 22,500 12,000 Hedge (%) (4) 47% 37% 19% WCS Differential Hedges Volumes (bbl/d) 8,667 8, WCS Price Relative to WTI(US$/bbl) ($14.45) ($14.18) --- Hedge (%) (3) 34% 27% --- (1) Includes WTI swaptions assumed to be exercised on December 31, 2018 (2) WTI 3-way option consists of a sold call, a bought put and a sold put. in a $70/$60/$50 example, Baytex receives WTI+$10/bbl when WTI is at or below $50/bbl; Baytex receives $60/bbl when WTI is between $50/bbl and $60/bbl; Baytex receives WTI when WTI is between $60/bbl and $70/bbl; and Baytex receives $70/bbl when WTI is above $70/bbl. (3) Percentage of hedged volumes are based on 2018 and 2019 annual production guidance (excluding NGL), net of royalties. 32

33 Natural Gas Hedge Portfolio Q3/18 Q4/ AECO Fixed Hedges Volumes (GJ/day) 5,000 5, Price (C$/GJ) $2.67 $ NYMEX Fixed Hedges Volumes (mmbtu/d) 15,000 15, Price (US$/mmbtu) $3.01 $ Total Hedge Volume (mmbtu/d) 19,739 19, Hedge (%) (1) 30% 29% --- (1) Percentage of hedged volumes are based on 2018 and 2019 annual production guidance, net of royalties and fuel purchases. 33

34 Contact Information Baytex Energy Corp. Suite 2800, Centennial Place 520 3rd Avenue S.W. Calgary, Alberta T2P 0R3 T Toll Free Edward D. LaFehr President and Chief Executive Officer Rodney D. Gray Executive Vice President and Chief Financial Officer Brian G. Ector Vice President, Capital Markets