Investor Presentation November 2018 Advisory Forward Looking - - PowerPoint PPT Presentation

Investor Presentation

November 2018

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

• n 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, target 10-15% annual total return to shareholders, be a self-funded business model, target net debt to adjusted funds flow ratio of <1.5x, 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 and focus on “next play” capture; the outlook for production volumes, adjusted funds flow and net debt to adjusted funds flow ratio from now until year-end 2023; Baytex’s estimates of reserves; 2019 preliminary guidance for annual production, production mix and exploration and development capital; that Baytex will have world class assets, high return light oil assets, an attractive growth and free cash flow, a superior capability to optimize capital allocation, a strong balance sheet and a top tier management team; expectations for Baytex, including: 5-10% annual production growth, 2019 adjusted funds flow and free cash flow, that there is 10+ years of inventory, the ratio of net debt to adjusted funds flow; that Baytex has an enhanced platform for growth, will build on strong operational momentum and drive further operational excellence and shareholder returns; expectations as to Baytex’s production and operating cash flow by area and production and revenue by commodity for 2019; our reduced guidance for 2018 operating and general and administrative expenses; the impact of our heavy oil optimization strategy; our plans to optimize heavy oil prices, including: the volume of oil we expect to deliver to market by rail and the percentage of our rail commitments exposed to WCS pricing; that our top priority is disciplined capital allocation to drive meaningful free cash flow; our expected adjusted funds flow in excess of exploration and development capital expenditures; that we are targeting debt adjusted production per share growth of approximately 10%; 2019 preliminary guidance for exploration and development capital expenditures, production, percentage of production that will be Oil and NGLs, operating netback, adjusted funds flow, adjusted funds flow by share, year-end net debt, year-end net debt to adjusted funds flow ratio; 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 operating netback and DCET costs for wells in the Eagle Ford, Peace River, Lloydminster, Viking and East Duvernay; the percentage of Baytex’s net exposure to oil prices that is hedged for 2018 and 2019; for the Eagle Ford, expectations as to Northern Austin Chalk drilling activity for 2018; for the Viking, that extended reach horizontal wells will enhance returns, that in takes 20 days from well spud to production, the estimated field netback at US $70/bbl 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, plans to optimize operations in Q4/2018 and for individual wells: the drill, complete and equip cost, expected 30-day IP rate and the estimated ultimate recovery; for the Duvernay, the resource potential per section, that the infrastructure spending will be minimal and manageable, the drilling inventory and planned well completion activity for 2018; the sensitivity of our expected 2019 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 natural gas prices that is hedged for 2018 and 2019. 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

• perating 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.

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; 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

• bligation 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”, “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. “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 ($2.77) 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.

“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

• f 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.

4

Advisory (Cont.)

Advisory Regarding Oil and Gas Information The reserves information contained in this presentation has been prepared in accordance with National Instrument 51-101 -Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators ("NI 51-101"). The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts, including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods, is required to properly use and apply reserves definitions. The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves and future production from such reserves may be greater or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. For complete NI 51-101 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

• f 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 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves" and permits the optional disclosure of "possible reserves". Additionally, NI 51-101 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.

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

Build on strong asset quality

• Liquids weighting > 80%
• Operated production > 80%
• Long-term decline rate < 30%
• Target accretive acquisitions
• Focus on “next play” capture

Production Growth Adjusted Funds Flow

0.5x 1.0x 1.5x 2.0x 2.5x $800 $1,000 $1,200 $1,400 $1,600 Pro forma 2019 2020 2021 2022 2023 Net Debt to Adjusted Funds Flow (x) Adjusted Funds Flow ($MM) Adjusted Funds Flow Net Debt to Adjusted Funds Flow 80 90 100 110 120 130 140 150 160 Pro forma 2019 2020 2021 2022 2023 Production (Mboe/d)

6

Corporate Profile

Market Summary Ticker Symbol TSX / NYSE: BTE Average Daily Volume (1) CAN: 13,300,000/ US: 2,800,000 Shares Outstanding 555 million Market Capitalization / Enterprise Value $1.5 billion / $3.6 billion Net Debt (2) $2.1 billion Corporate Summary Production (3) 95,000 – 100,000 boe/d Production Mix 85% oil and liquids E&D Capital (3) $650 - $750 million Reserves – 2P Gross (4) 539 mmboe

(1) Average daily trading volumes for October 2018. 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, as at September 30, 2018. (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.

7

Creating a Top-Tier Oil Producer With Exceptional Assets

World Class Asset Base (1) Attractive Growth and Free Cash Flow (2)(3)(4) Strong Balance Sheet (2)(3) High Return Light Oil Assets Top Tier Team with Focus On Operational Excellence Superior Capability to Optimize Capital Allocation

• Enterprise value $3.6 billion
• ~ 97,000 boe/d (Oct. 2018)
• 2P Reserves 539 mmboe
• Leading oil plays in the best

jurisdictions

• Capability to deliver 5%-10%

annual production growth

• ~ $900 million adjusted

funds flow and $325 million free cash flow

• 2.1x net debt to adjusted

funds flow

• Strong financial liquidity
• No long-term debt

maturities until 2021

• Strong oil price diversification
• 80% of operating netback derived

from high margin, light oil assets in the Viking and Eagle Ford

• Well defined 10+ year drilling

inventory

• Strong oil price diversification
• Positioned to develop East

Duvernay Shale oil play

(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) Commodity price assumptions: WTI - US$70/bbl; LLS - US$75/bbl, WCS differential - US$30/bbl; MSW Differential – US$15/bbl; NYMEX Gas - US$2.90/mcf; Exchange Rate (CAD/USD) - 1.30 (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. Sustaining capital is estimated at $575 million.

• Enhanced platform for growth
• Build on strong operational

momentum

• Drive further operational excellence

and shareholder returns

8

EAGLE FORD VIKING LLOYDMINSTER PEACE RIVER DUVERNAY

Production by Core Area (1) Operating Cash Flow (2) Production by Commodity (1) Revenue by Commodity (2)

Eagle Ford Viking Peace River Lloyd. Other Heavy Oil Light Oil NGLs Natural Gas Eagle Ford Viking Peace River Lloyd. Other Heavy Oil Light Oil NGLs Natural Gas

World Class Asset Base

(1) Production composition based on 2019 preliminary guidance. (2) Pricing assumptions: WTI - US$70/bbl, LLS - US$75/bbl, WCS differential - US$30/bbl, MSW Differential – US$15/bbl, NYMEX gas - US$2.90/mcf, FX Rate (C$/US$) - 1.3.

9

 Completed the strategic combination with Raging River on August 22, 2018. Q3/2018 results reflect a 40 day contribution from the Raging River assets  Generated adjusted funds flow of $171 million ($0.46 per basic share), $32 million in excess of exploration and development capital expenditures of $139 million  Reduced annual guidance for operating expenses by 4% (at mid-point) to $10.50- $10.75/boe, reflecting strong performance year-to-date of $10.54/boe  Continued to drive efficiency across our business with a 5% reduction in forecast 2018 general and administrative expenses to $1.55/boe  Maintained strong financial liquidity with our credit facilities approximately 50% undrawn and our first long-term note maturity not until 2021. Net debt totaled $2.1 billion at September 30, 2018  Generated an operating netback (excluding realized financial derivatives gains and losses) of $31.39/boe in Q3/2018, a 76% improvement compared to $17.83/boe in Q3/2017

Q3 2018 Financial Highlights

10

 Delivered production of 82,412 boe/d (81% oil and NGL) during Q3/2018

• Raging River averaged 23,750 boe/d (Q3/2018 impact of 10,327 boe/d)
• Legacy Baytex production averaged 72,085 boe/d
• October production averaged approximately 97,000 boe/d

 Completed two (2.0 net) significant light oil discovery wells in the Pembina area of the East Duvernay Shale.

• 30-day initial production rate of approximately 750 boe/d per well (88% oil and NGLs)

 Implemented plans to optimize our heavy oil production

• Q4/2018 heavy oil volumes reduced by approximately 5,000 boe/d (5% of our total

production) and given current pricing, will have a minimal impact on our adjusted funds flow

 Secured additional rail capacity, which increases our crude oil volumes delivered to market by rail to 11,000 bbl/d (approximately 40% of our heavy oil production) through 2019.

• Commencing January 1, 2019, approximately 70% of our crude by rail commitments are WTI

based contracts with no WCS pricing exposure

Q3 2018 Operating Highlights

11

Preliminary 2019 Plans

Notes: (1) Commodity price assumptions: WTI - US$70/bbl; LLS - US$75/bbl, WCS differential - US$30/bbl; MSW Differential – US$15bbl; NYMEX Gas - US$2.90/mcf; Exchange Rate (CAD/USD) - 1.30 (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.

2019 Preliminary Plans E&D CapEx $650 - $750 million Production 95,000 - 100,000 boe/d Oil and NGLs 85% Operating Netback (1) $31/boe Adjusted Funds Flow (1) $900 million Adjusted Funds Flow per Share (2) $1.60 Net debt (year-end) $1.9 billion

Net Debt to Adjusted Funds Flow (3) 2.1x

Our top priority will be disciplined

capital allocation to drive meaningful

free cash flow and a strengthened

balance sheet With a diversified asset base and high

netback light oil production, we

have the capability to optimize capital allocation based on commodity prices and economic returns by area We expect to generate $200 million of

adjusted funds flow in excess of

exploration and development capital expenditures We are targeting debt adjusted

production per share growth of

approximately 10%

12

– 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x – $100 $200 $300 $400 $500 $600 $60 $65 $70 $75 $80 Net Debt / Adjusted Funds Flow (x) Free Cash Flow ($MM) WTI (US$/bbl) Free Cash Flow Net Debt / Adjusted Funds Flow

(4)

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)

Notes: (1) Production is based on preliminary 2019 guidance of 95,000 to 100,000 boe/d. (2) Price Assumptions: LLS – WTI + US$5/bbl; NYMEX gas - US$2.90/mcf; WCS differential - US$30/bbl; MSW differential – US$15/bbl; Exchange Rate (C$/US$) - 1.3. (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

• n 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.

(3)

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High Quality Oil Development Inventory

Viking Light Oil Eagle Ford Light Oil Peace River Heavy Oil Lloydminster Heavy Oil East Duvernay Light Oil

Free Cash Flow Light Oil Free Cash Flow Light Oil Self-Funding Heavy Oil Growth Self-Funding Heavy Oil Growth Early Stage Light Oil Growth Production (1) 22,000 boe/d 37,000 boe/d 18,000 boe/d 11,500 boe/d 650 boe/d Oil and NGLs 94% 78% 89% 99% 90%

• Op. Netback (2)

$44/boe $39/boe $16/boe $16/boe $40/boe DCET Well Cost (3) $900,000 US$5.6 million $2.6 million $750,000 $6.5 million

• Dominant

position with

• ver 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

• pportunities
• 430 net

sections

• Top decile

netbacks

• Strong growth

potential

(1) Production (Q3/2018) from the five areas represents approximately 92% of total Baytex volumes. Viking and Duvernay production reflects period August 22 to September 30. (2) Pricing assumptions: WTI - US$70/bbl; LLS - US$75/bbl; WCS differential - US$30/bbl; MSW differential – US$15/bbl; NYMEX Gas - US$2.75/mcf; and Exchange Rate (CAD/USD) - 1.275. (3) East Duvernay light oil DCET (drill, complete, equip and tie-in) well cost reflects anticipated efficiencies to be gained through continuous development.

10+ years drilling inventory in each core area

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

• f the Brent price

Crude by Rail

• ~ 40% of heavy oil production
• Effective tool for management of

differentials

• Reduces price volatility and provides

greater netback certainty

• ~70% of our crude by rail commitments

commencing January 1, 2019 are WTI based contracts with no WCS exposure

Crude Oil and NGL Sales Portfolio (1)

Benchmark 2019 Index (2) Baytex Price Realization (3) Viking light oil MSW WTI less US$15/bbl MSW less $5/bbl Eagle Ford light oil and condensate LLS WTI plus US$5/bbl LLS less US$4/bbl Peace River / Lloydminster heavy oil WCS WTI less US$30/bbl WCS less $14/bbl

(1) Based on preliminary 2019 plans. (2) 2019 Index based on the forward strip as at November 1, 2018. (3) Baytex price realization reflects Q3/2018 actual discounts to the index price.

WTI / MSW 30% Brent / LLS 25% WCS 18% Crude by Rail 13% NGLs 13%

15

(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.

Crude Oil Hedges

Q4/18 Q1/19 Q2/19 Q3/19 Q4/19

WTI Fixed Hedges

Volumes (bbl/d) (1) 16,500 8,000 8,000 6,000 6,000 Fixed Price (US$/bbl) $52.28 $61.50 $61.50 $61.00 $61.00

WTI 3-Way Option

Volumes (bbl/d) 2,000 12,000 12,000 12,000 12,000

Average Ceiling/Floor/Sold Floor (US$/bbl) (2) $60/$54/$40 $73/$67/$57 $73/$67/$57 $73/$67/$57 $73/$67/$57

Brent Hedges

Volumes (bbl/d) 4,000 3,000 3,000 3,000 3,000 Fixed Price (US$/bbl) / 3-Way Option (US$/bbl) $61.31

$79/$70/60 $79/$70/ $60 $79/$70/ $60 $79/$70/ $60

Total Hedge Volumes (bbl/d) 22,500 23,000 23,000 21,000 21,000 Hedge (%) (3) 36% 37% 37% 34% 34%

16

Leverage Profile

Debt Maturities

$ in millions

US$150 6.75% C$550 Undrawn

2018 2019 2020 2021 2022 2023 2024 2025

C$300 6.625% US$400 5.125% US$400 5.625% C$490 Drawn

(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. (4) Revolving credit facilities mature June 2020 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, (5) S&P corporate and senior unsecured debt rating - “BB,”; Moody’s corporate rating - “B1” and senior unsecured debt rating - “B2”.

Revolving Credit Facilities (4) Long-term Notes (5)

Bank Debt Covenants Covenant Current Senior Secured Debt (1) / Bank EBITDA (2) Max 3.5:1 0.55x Interest Coverage (3) Min 2:1 9.00x

Net debt totals $2.1 billion as at September 30, 2018

Asset Overview

18

Eagle Ford: Step Change in Well Performance

Enhanced completions drive improved well performance

Increased lateral length, proppant loading and frac stages

YTD 2018 Development

Achieved record production rates from new wells 85 gross wells established average 30 day IP rates of 1,750 boe/d per well 20% improvement over wells brought on production in 2017

Northern Austin Chalk

Two wells in Austin Chalk fracture trend demonstrated 30-day IP rates

• f ~2,400 boe/d per well

5-6 gross wells planned for 2018

25 50 75 100 125 150 1 2 3 4 5 6 Cumulative Production (mboe) Months

2017 2016 2014 2015 2011 2012 2013

180 Day Cumulative Well Production

Hz Length (ft) Proppant (lbs/ft) Stage Spacing (ft) # of Stages YTD 2018 6,100 2,000 215 29 2017 5,900 1,800 217 27 2016 5,500 1,600 221 25 2015 5,200 1,100 229 23 2014 5,400 1,000 239 23 2013 5,400 700 315 17 2012 5,100 800 325 16 2011 4,600 800 297 16

Completion Activity

~20% increase at 180 days 2016 vs. 2017

19

Eagle Ford: Strong Q3/2018 Drilling Results

Wilhelm Smith B

3 well pad Average 30-day IP: 1,250 boe/d Best Well: 1,375 boe/d

Henke Wilhelm A

4 well pad Average 30-day IP: 1,000 boe/d Best Well: 1,250 boe/d

May B

4 well pad Average 30-day IP: 1,775 boe/d Best Well: 2,060 boe/d

Davilla

3 well pad Average 30-day IP: 2,215 boe/d Best Well: 2,620 boe/d

Hollman

4 well pad Average 30-day IP: 1,130 boe/d Best Well: 1,165 boe/d

LONGHORN

Wilson

Atascosa Karnes Live Oak

EXCELSIOR SUGARLOAF IPANEMA

Bee

K-Laubach / M-Witte

4 well pad Average 30-day IP: 1,700 boe/d Best Well: 2,060 boe/d

Oil Condensate Dry Gas

20

Viking Light Oil: 460 Highly Prospective Sections

Baytex Lands

Esther/Hoosier Kerrobert Plenty Greater Gleneath Lucky Hills/Whiteside Dodsland Mantario (Laporte) Plato Forgan

• Shallow (700 m), Light
• il (36° API) resource

play

• Extended Reach

Horizontals are enhancing returns and extending the runway

• Short cycle, fast pay-
• uts – spud to producing
• il ~ 20 days
• Strong netback –

estimate $44/boe field netback at US$70/bbl

• Produced 22,000 boe/d

in Q3/2018

• Currently 5 drilling rigs

and 1.5 frac crews executing development program

21

Viking Light Oil Development

(1) Baytex internal estimates.

Reservoir Characteristics (1) Formation Viking Formation Depth 700 metres Completion Pin point coil Frac Oil Quality 34-36°API Average Porosity 23% Permeability 0.5 – 50 millidarcies Oil Saturation 65% Individual Wells (1) DCET Well Cost $900,000 30-day IP 60-90 boe/d EUR 40-60 mboe

22

Peace River: Driving Production Growth and Cost Reductions

Performance Drivers

• Dominant 725 net sections
• Innovative multi-lateral

horizontal drilling techniques

• Produced 18,000 boe/d in

Q3/2018 (89% oil)

• In Q4/2018, implemented

plans to optimize operations

Baytex Lands

Seal Harmon Valley Reno

North Seal Development

• First six wells on acquired

lands generated 30-day IP rates of ~ 700 boe/d per well

• Deferred three Q4/2018

completions due to low heavy

• il prices

23

Peace River: Multi-Lateral Horizontal Wells

(1) Baytex internal estimates.

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 $2.6 million 30-day IP 300-400 boe/d EUR 220-330 mboe

24

Lloydminster: Significant Land Position and Drilling Inventory

Performance Drivers

• Produced 11,500 boe/d in

Q3/2018 (99% oil)

• Applying multi-lateral

horizontal drilling and production techniques at Soda Lake

• Completed expansion of

Kerrobert thermal project in Q3/2018, increasing productive capacity to ~ 2,000 bbl/d

• In Q4/2018, implemented

plans to optimize operations

Baytex Lands

ALBERTA SASKATCHEWAN

Kerrobert Lloydminster Soda Lake Tangleflags Ardmore/Cold Lake Lindbergh

25

Lloydminster Development

(1) Baytex internal estimates.

Reservoir Characteristics (1) Formation Mannville Group Depth 350 – 800 metres Completion Horizontal Slotted Liner / Vertical Stacked Pays Oil Quality 10 – 16 °API Average Porosity 30% Permeability 0.5 – 5.0 darcies Oil Saturation 70% Individual Wells (1) DCET Well Cost $750,000 30-day IP 75-150 boe/d EUR 60-80 mboe

26

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

• 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

• Large drilling inventory – potential for

750 horizontal light oil locations

RED DEER FOX CREEK

WEST SHALE BASIN Baytex Focus Areas

27

East Duvernay Shale Light Oil: Emerging Resource Play

Baytex Lands

Pembina Region

• 256 sections of 100% WI lands
• Focus for 2019 development

and delineation drilling Q4/2018 Activity

• Four wells on flow-back in

Q4/2018

• Drilled and completed two

significant light oil discovery wells in October with average 30-day IP rates of ~750 boe/d per well (88% light oil and NGL)

• Drilling operations completed
• n two additional wells from
• riginal 14-36 surface pad with

completion activities to start mid-November

Duvernay Producers

Pembina Ferrybank Gilby

Q4/2018 Completions (4 wells) 14-36 Initial Pembina Discovery (Q1/2018)

Supplementary Information

29

Raymond T. Chan (2) (3) Lead Independent Director Edward D. LaFehr President and Chief Executive Officer Mark R. Bly (1) (3) Trudy M. Curran (2) (4) Naveen Dargan (1) (3) Gregory K. Melchin (1) (4)

Board of Directors

Gary Bugeaud (2) (4) Neil Roszell Chairman Dave Pearce (3) (4) Kevin Olson (1) (2)

(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

30

Rodney Gray EVP, Chief Financial Officer

Baytex Leadership Team

Bruce Beynon EVP, Corporate Development Edward LaFehr President & CEO

• Mr. LaFehr joined Baytex as President on July 18, 2016 and was appointed Chief Executive Officer on

May 4, 2017. 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.

• Mr. Beynon joined Baytex as Executive Vice President, Corporate Development on August 22, 2018. 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 2015. 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 1991.

• Mr. Gray was appointed Executive Vice President and Chief Financial Officer of Baytex on August 22,
• 2018. He joined Baytex on April 7, 2014 and served as Chief Financial Officer from April 2014 to August
• 2018. 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.

31

Richard Ramsay EVP, Chief Operating Officer

Baytex Leadership Team

Jason Jaskela VP, Duvernay and EagleFord Shale Brian Ector VP, Capital Markets

• Mr. Ramsay was appointed Executive Vice President and Chief Operating Officer of Baytex on August

22, 2018. 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 2018. 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.

• Mr. Jaskela joined Baytex as Vice President, Duvernay and Eagle Ford Business Units on August 22,
• 2018. 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 2014. 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 2012. 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 2000.

• Mr. Ector is Vice President, Capital Markets of Baytex and is responsible for Baytex's equity capital

markets and investor relations functions. He joined Baytex in November 2009. 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 1996. 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.

32

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 $26.0 $20.4 Change of US$1.00/bbl WCS heavy oil differential $7.5 $7.5 Change of US$1.00/bbl MSW light oil differential 10.1 10.1 Change of US$0.25/mcf NYMEX natural gas $8.5 $8.3 Change of $0.01 in the C$/US$ exchange rate $11.2 $11.1

(1) Price Assumptions: WTI - US$70/bbl. LLS – US$75/bbl; NYMEX gas - US$2.90/mcf; WCS heavy oil differential - US$30/bbl; MSW differential – US$15/bbl; Exchange Rate (C$/US$) - 1.30.

33

Natural Gas Hedge Portfolio

Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 AECO Fixed Hedges Volumes (GJ/day) 8,333 5,000

• Price (C$/GJ)

$2.50 $2.25

• NYMEX Fixed Hedges

Volumes (mmbtu/d) 15,000

• Price (US$/mmbtu)

$3.01

• (1)

Percentage of hedged volumes are based on 2018 and 2019 annual production guidance, net of royalties and fuel purchases.

Total Hedge Volume (mmbtu/d) 22,898 4,739

• Hedge (%) (1)

29% 7%

Edward D. LaFehr

President and Chief Executive Officer 587.952.3000

Rodney D. Gray

Executive Vice President and Chief Financial Officer 587.952.3160

Brian G. Ector

Vice 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