Barclays CEO Energy-Power Conference September 7, 2016 New York, New York James Bowzer Chief Executive Officer Ed LaFehr President Brian Ector Senior Vice President, Capital Markets & Public Affairs

2

Forward-Looking Statements In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements made by the presenter and contained in these presentation materials (collectively, 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"). The forward-looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement. The information contained in this presentation does not purport to be all-inclusive or to contain all information that potential investors may require. Specifically, this presentation contains forward-looking statements relating, but not limited, to: our business strategies, plans and objectives; our key attributes, including: maintaining strong levels of financial liquidity, targeting capital expenditures to approximate funds from operations, a cost reduction focus across our organization, efficient deployment of capital; that capital directed to the Eagle Ford generates the highest netback and rate of return in our portfolio; that we retain leverage to a rising crude environment, that our three core plays provide strong capital efficiencies and that we have a significant inventory of development prospects; the rate of return, net present value, payout and profit to investment ratio for wells in the Eagle Ford, Peace River and Lloydminster under various pricing assumptions for West Texas Intermediate light oil (“WTI”) and the oil price at which the wells break-even; that cost reductions will make our Peace River and Lloydminster wells competitive with the Eagle Ford at US $50-$55 WTI; that production from our Eagle Ford play receives a pricing premium to WTI; our Peace River heavy oil resource play, including our belief that there are strong capital efficiencies, the years of drilling inventory remaining, reservoir characteristics, individual well economics for multi-lateral horizontal wells (including well design, drilling and completion costs, initial production rates, capital efficiency ratio, internal rate of return and estimated ultimate recoveries (EUR)); our Lloydminster heavy oil property, including that horizontal drilling has expanded inventory, the years of drilling inventory remaining, the impact of drilling horizontal wells and individual well economics for horizontal wells (including drilling and completion costs, initial production rates, capital efficiency ratio internal rate of return and estimated ultimate recoveries (EUR) and our expectation that multi-lateral drilling will result in improvements in capital efficiencies); our free cash flow at certain WTI pricing scenarios; that as funds from operations increase we will spend capital to offset production declines, invest in organic growth and may repay debt; that cost targets will drive return improvements in Canada; and the sensitivity of our 2016 funds from operations to changes in WTI prices, heavy oil differentials, natural gas prices and Canada-United States foreign exchange rates. 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 the reserves can be profitably produced in the future. Although Baytex believes that the expectations and assumptions upon which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Baytex can give no assurance that they will prove to be correct. These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our 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; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect. Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of natural gas prices; further declines or an extended period of the currently low oil and natural gas prices; failure to comply with the covenants in our debt agreements; that our credit facilities may not provide sufficient liquidity or may not be renewed; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; 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 our hedging activities; the cost of developing and operating our assets; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; risks associated with the ownership of our securities, including changes in market-based factors and the discretionary nature of dividend payments; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2015, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

Advisory

3

Advisory (Cont.)

Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. The above summary of assumptions and risks related to forward-looking statements in this presentation has been provided in order to provide potential investors with a more complete perspective of our current and future operations and as such information may be not 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 law. Oil and Gas Information This presentation contains estimates, as at December 31, 2015, of the volume of our petroleum and natural gas reserves as prepared by our independent qualified reserves evaluators, Sproule Unconventional Limited ("Sproule") for our Canadian properties and Ryder Scott Company, L.P. for our United States properties. These estimates have been prepared in accordance with Canadian reserves disclosure standards and definitions as set forth in National Instrument 51-101 “Standards of Disclosure for Oil and Natural 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 see our Annual Information Form for the year end December 31, 2015. References herein to initial test production rates, 30-day IP 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 acquired assets. 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. When converting volumes of natural gas to oil equivalent amounts, Baytex has adopted a conversion factor of six million cubic feet of natural gas being equivalent to one barrel of oil, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Oil equivalent amounts may be misleading, particularly if used in isolation.

4

Advisory (Cont.)

Non-GAAP Financial Measures This presentation refers to funds from operations, net debt, free cash flow, sustaining capital, operating netback and Bank EBITDA, which do not have any standardized meaning prescribed by generally accepted accounting principles in Canada ("GAAP"). We define funds from operations ("FFO") as cash flow from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. We believe that this measures assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future capital investments. However, funds from operations should not be construed as an alternative to traditional performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income. Please refer to our most recent management's discussion and analysis of financial condition and results of operations for a reconciliation of funds from operations to cash flow from operating activities. We define net debt as the sum of monetary working capital (which is current assets less current liabilities (excluding current losses on financial derivatives)), and the principal amount of both long-term notes and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities. We define free cash flow as funds from operations less sustaining capital and 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. We define operating netback as product sales price less royalties, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. Our determination of operating netback may not be comparable with the calculation of similar measures by other entities. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis. Bank EBITDA is calculated based on terms and definitions set out in the agreement governing our revolving credit facilities. It is calculated by adjusting net income for financing costs, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, amortization, impairment, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange, and share-based compensation) and acquisition and disposition activity and is calculated based on a trailing twelve month basis. Bank EBITDA is used by our lenders to monitor compliance with financial covenants.

5 5

Baytex Key Attributes

Capital expenditures directed to the Eagle Ford, which generates the highest netback and highest rate of return in our portfolio

Strong capital efficiencies across three core resource plays; retain a significant inventory of development prospects

Cost reduction focus across all facets of our organization while maintaining efficiency in our operations and the safety of our employees

Pro-actively worked with our bank lending syndicate to provide increased financial flexibility; targeting capital expenditures to approximate FFO

Maintained Financial Liquidity

Reduced Cost Structure

Deployed Capital

Efficiently

Retained Leverage to Rising Crude Environment

Making the Right Choices In a Low Oil Price Environment

6

Ticker Symbol TSX / NYSE: BTE Average Daily Volume (1) CAN: 9,500,000 / US: 2,400,000 Shares Outstanding 211.5 million Market Capitalization / Enterprise Value $1.3 billion / $3.2 billion Net Debt (2) $1.9 billion

Production (3) 67,000 – 69,000 boe/d Production Mix 77% oil and liquids E&D Capital (3) $200-$225 million Reserves – 2P Gross (4) 417 mmboe

(1) Average daily trading volumes for August 2016. Volumes are a composite of all exchanges in Canada and the U.S. (2) Net debt is the principal amount of long-term debt and bank loan and includes working capital. As at June 30, 2016. (3) Production and exploration and development capital represents our 2016 guidance range. (4) Gross reserves are per NI 51-101 as at December 31, 2015. See “Advisory – Oil and Gas Information” for more information.

Corporate Profile

Market Summary

Corporate Summary

7

First call on capital

Highest rate of return asset at current prices

Highest netback asset in our portfolio

Represents ~ 90% of 2016 budgeted E&D spending

Currently targeting the Lower Eagle Ford, Upper Eagle Ford and Austin Chalk formations

Texas 34%

Capital Deployment Opportunities

Lloydminster Heavy Oil 36%

Light Oil 18% Gas 10%

Western Canada 63%

Heavy Oil 51%

Light Oil 22%

NGLs 17% Gas

14%

Texas 34%

Eagle Ford Texas 34%

Peace River / Lloydminster

2016 multi-lateral development at Peace River and conventional development at Lloydminster deferred

No heavy oil development in either play since mid-2015

Currently targeting a further 10% reduction in capital costs

Competitive rates of return at US$50-US55/bbl with further cost reductions

Texas 34%

8 8

H1 2016 Highlights

Generated production of 72,902 boe/d (78% oil and NGL)

Curtailed capital spending, focusing all development activity in the Eagle Ford, our highest rate of return and highest netback asset

Reinitiated production from heavy oil wells shut-in during the first quarter of 2016 due to low oil prices

Reduced net debt (bank loan, long-term notes and working capital deficiency) by

5% to $1.9 billion

Maintained strong levels of financial liquidity with a Senior Secured Debt to Bank EBITDA ratio of 0.86:1.00

Continued to emphasize cost reductions across all facets of our organization

Disposed of our operated portion of the Eagle Ford for approximately $55 million

9

Balance Sheet / Debt Composition

Debt Composition(1) and Unutilized Capacity Long-Term Notes Maturity Schedule ($ Millions)

(1) Debt composition as at June 30, 2016. We have secured revolving credit facilities totaling US$575 million that mature June 2019. The revolving credit facilities do not require any mandatory principal payments prior to maturity and can be further extended beyond June 2019 with the consent of the lenders.

(2) “Senior Secured Debt” is defined as the principal amount of our bank loan and other secured obligations under the credit facilities. At June 30, 2016, our Senior Secured Debt totaled C$359 million.

(3) “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 and was C$417 million for the twelve months ended June 30, 2016.

(4) “Interest Coverage” is computed as the ratio of Bank EBITDA to interest expense on our Senior Secured Debt and long-term notes. Interest expense for the trailing twelve months ended June 30, 2016 was C$103 million.

Senior Secured Debt (2) to Bank EBITDA (3) 0.86x (maximum 5.0x through March 2018)

Interest Coverage (4) 4.05x (minimum 1.25x through March 2018)

Significant Liquidity, No Near-Term Maturities and Financial Covenant Flexibility

10

Crude Oil Hedge Portfolio

Q3/2016 Q4/2016 H2 2016 2017 2018 WTI Fixed Hedges

Volumes (bbl/d) 5,000 5,000 5,000 --- ---

Fixed Price (US$/bbl) $63.79 $63.79 $63.79 --- ---

WTI 3-Way Option

Volumes (bbl/d) 10,000 10,000 10,000 12,000 ---

Average Ceiling/Floor/Sold Floor (US$/bbl) (2) $60/$50/$40 $60/$50/$40 $60/$50/$40 $59/$46/$37 ---

Total WTI Hedge Volumes (bbl/d) 15,000 15,000 15,000 12,000 ---

Hedge (%) (1) 43% 45% 44% 36% ---

(1) Percentage of hedged volumes are based on the mid-point of 2016 production guidance (excluding NGL), net of royalties. (2) WTI 3-way option consists of a sold call, a bought put and a sold put. In a $60/$50/$40 example, Baytex receives WTI + US$10/bbl when WTI is at or below US$40/bbl; Baytex receives

US$50/bbl when WTI is between US$40/bbl and US$50/bbl; Baytex receives WTI when WTI is between $50/bbl and $60/bbl; and Baytex receives $60/bbl when WTI is above US$60/bbl.

WCS Differential Hedges

Volumes (bbl/d) 7,000 7,500 7,250 4,500 ---

WCS Price Relative to WTI (US$/bbl) ($13.32) ($13.47) ($13.40) ($14.14) ---

Hedge (%) (1) 33% 38% 36% 24% ---

11

0%

25%

50%

75%

100%

125%

150%

175%

$45 $50 $55 $60 $65 $70

Eagle Ford - US$5.2M/wellPeace River - C$2.8M/wellLloydminster - C$750K/well

WTI (US$/bbl)

Rat

e of

Ret

urn

Eagle Ford Provides Highest Rate of Return at Current Commodity Prices

Break-Even WTI (4)

(1) Individual well economics are based on constant pricing and costs. Pricing assumptions: NYMEX gas = US$2.75/mcf, WCS differential = US$13.50/bbl, FX Rate (US$/C$) = 1.3. (2) Type curve assumptions: Eagle Ford: 30-day IP rate ~ 1,000 boe/d, EUR ~ 800 mboe. Peace River multi-lateral well: 30-day IP rate ~ 400 boe/d, EUR ~ 300 mboe. Lloydminster: for a single

lined horizontal well: 30-day IP rate ~ 70 boe/d, EUR ~ 70 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. (4) Break even price represents the constant oil price (WTI) at which the net present value of the average type well is zero using a 10% discount rate.

Well costs reflect the most recent results achieved. No

heavy oil wells have been drilled at Peace River and Lloydminster

since mid-2015.

12

0%

25%

50%

75%

100%

125%

150%

175%

$45 $50 $55 $60 $65 $70

Eagle Ford - US$5.2M/wellPeace River - C$2.8M/wellPeace River - C$2.5M/wellLloydminster - C$750K/wellLloydminster - C$700K/well

WTI (US$/bbl)

Rat

e of

Ret

urn

At US$50/bbl, all three assets would generate IRR’s ≥ 50%

Cost Targets Drive Return Improvement in Canada

(1) Individual well economics are based on constant pricing and costs. Pricing assumptions: NYMEX gas = US$2.75/mcf, WCS differential = US$13.50/bbl, FX Rate (US$/C$) = 1.3. (2) Type curve assumptions: Eagle Ford: 30-day IP rate ~ 1,000 boe/d, EUR ~ 800 mboe. Peace River multi-lateral well: 30-day IP rate ~ 400 boe/d, EUR ~ 300 mboe. Lloydminster: for a single

lined horizontal well: 30-day IP rate ~ 70 boe/d, EUR ~ 70 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.

With further cost savings in Canada, heavy oil economics are competitive with the Eagle

Ford at US$50-US$55/bbl

13

Individual Well Economics – Sensitivity to WTI

IRR (3)

Eagle Ford Peace River Lloydminster

US$45 53% 25% 35%

US$50 69% 50% 67%

US$55 88% 79% 105%

US$60 110% 115% 150%

(1) DC&E costs – Eagle Ford – US$5.2 million, Peace River - $2.5 million, Lloydminster - $700,000 (2) Individual well economics based on constant pricing and costs. Pricing assumptions: NYMEX gas = US$2.75/mcf, WCS differential US$13.50/bbl, FX Rate (C$/C$) = 1.3. (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. (4) Profit to Investment Ratio (P/IR) is the net present value of future cash flows discounted at 10% divided by the initial investment.

NPV (C$000s) – 10% discount rate

Eagle Ford Peace River Lloydminster

US$45 $5,688 $716 $262

US$50 $7,247 $1,611 $581

US$55 $8,806 $2,459 $900

US$60 $10,365 $3,277 $1,220

Payout (years)

Eagle Ford Peace River Lloydminster

US$45 1.9 2.7 2.0

US$50 1.6 1.6 1.4

US$55 1.4 1.2 1.1

US$60 1.2 0.9 0.9

Profit to Investment (P/I) Ratio (4)

Eagle Ford Peace River Lloydminster

US$45 0.86 0.29 0.35

US$50 1.09 0.65 0.78

US$55 1.33 0.99 1.21

US$60 1.56 1.32 1.63

The Eagle Ford

Eagle Ford Development

Advancements Since Late 2014

Significant advancements have been made to delineate the multi-zone potential of our Sugarkane acreage

DC&E costs reduced by ~ 35% 30-day IP rates increased ~ 20% Drilling efficiency improved ~ 40% Adopted tighter frac stage spacing

and higher proppant intensity Currently three rigs and two frac

crews working on our lands

Concentrated Land Positon in Core of the Eagle Ford

16

Improved Performance and Efficiency Improvements in drilling and completion design have increased 30-day IP rates by

approximately 100% since Q4/2011 with 180-day cumulative recovery increasing 74% over the same time period

Drilling times have decreased by 63% since Q4/2011 resulting in reduced completed well costs

Eagle Ford Performance

Production (30 Day IP, boe/d) Cumulative Recovery (mboe) Drilling Efficiency (Spud to TD)

Days on Production

74%

17

Lateral Length and Total Depth Per Well Frac Stages and Proppant Per Well

Completion Improvements

Increasing Lateral Length, Frac Stages and Proppant

18 18 (1) Based on 2016E liquids revenues

Pricing Exposure

H1/2016 Operating Netback

$/boe Canada Eagle Ford Total

WTI (US$/bbl) $39.53

Sales Price $19.40 $31.63 $26.06 Royalties (1.94) (9.03) (5.80) Operating Costs (10.91) (8.17) (9.42) Transportation (1.97) --- (0.90) Operating Netback $4.58 $14.43 $9.94

Our light oil and condensate production in the Eagle Ford is priced primarily off a Louisiana Light Sweet (LLS) benchmark, which typically trades at a premium to WTI.

Strong waterborne pricing, combined with low cash costs, contributes positively to our operating netback.

The Eagle Ford Significantly Enhances Our Operating Netback

Product Pricing Exposure (1)

Eagle Ford Light Oil

Other Oil & NGLs

Canada Heavy Oil

WCS Benchmark

28%

LLS Benchmark

60%

WTI Benchmark

12%

19

Heavy Oil Overview

20

Peace River Oil Sands

Multi-Lateral Drilling Drives Strong Capital Efficiencies

Land Holdings 338 net sections

Production (Q2/2016) 13,100 boe/d

2P Reserves (YE15) (1) 73.6 mmboe

Drilling Inventory (2) 7.5 years

Area Statistics

(1) In addition, we have 18.2 mmbbl of bitumen reserves related to our thermal operations.

(2) Drilling inventory in years based on identified drilling locations (risked) and a normalized pace of ~ 25 wells per year.

21

Multi-Lateral Cold 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%

(1) Baytex internal estimates.

Well Economics (1)

Well Design ~ 12 laterals

Completed Well Cost ~ $2.8 MM

Production (IP30) 300-500 boe/d

Capital Efficiency (based on IP365)

$13,000 per boe/d

22

Lloydminster Heavy Oil

Lloydminster Heavy Oil

Area Statistics

Land Position 652 net sections

Production (Q2/2016) 10,200 boe/d

2P Reserves (YE15) (1) 33.2 mmboe

Drilling Inventory (2) ~ 7.5 years

(1) In addition, we have 43.4 mmbbl of bitumen reserves related to our SAGD project at Gemini and 8.1 mmbbl of bitumen reserves related to our SAGD project at Kerrobert.

(2) Drilling inventory in years based on identified drilling locations (risked) and a normalized pace of 70 to 80 wells per year.

Shift to Horizontal Drilling Expands Inventory

23

Lloydminster Development

Horizontal Well Economics (1)

Completed Well Cost ~ $750,000

Production (IP30) 70-80 bbl/d

Capital Efficiency (based on IP365)

$14,000 per bbl/d

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%

Increased Multi-Lateral Drilling at Lloydminster is Leading to an ~ 20% Improvement in Capital Efficiencies

(1) Baytex internal estimates.

24

Free Cash Flow Scenarios

Notes: (1) Free Cash Flow is defined as funds from operations less sustaining capital. (2) 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. (3) Pricing assumptions: NYMEX gas = US$2.75/mcf, WCS differential = US$13.50/bbl, FX Rate (US$/C$) = 1.3.

Sustaining Capital (2) ~ $300 million

Base Assumptions

Production 63,000 boe/d

Corporate Decline Rate ~ 32%

Capital Efficiency ($/boe/d) ~ $15,000/boe/d

Free Cash Flow(1) Positive at US$55/bbl As funds from operations increase: E&D capital deployed to offset

production declines

Invest in organic growth once free cash flow positive

Potential for debt repayment

-$250

-$150

-$50

$50

$150

$250

$40 $45 $50 $55 $60 $65

$ M

illio

ns

WTI (US$/bbl)

25

Summary

We are well positioned to benefit from an oil price recovery First call on capital – the Eagle Ford

Cost targets drive return improvements in Canada

Retain significant leverage to a rising crude oil price environment

Exceptional asset base focused on crude oil & liquids Significant inventory of development projects Advancing multi-zone potential of Eagle Ford acreage

Maintain strong levels of financial liquidity

Net debt in H1/2016 reduced by 5% to $1.9 billion Senior Secured Debt to Bank EBITDA ratio of 0.86:1.00 Further debt reduction in Q3/16 through minor non-core asset sales

26 26

James L. Bowzer Chief Executive Officer (587) 952-3000 Rodney D. Gray Chief Financial Officer (587) 952-3160 Brian G. Ector Senior Vice President, Capital Markets and Public Affairs (587) 952-3237

Suite 2800, Centennial Place 520 – 3rd Avenue S.W. Calgary, Alberta T2P 0R3 T: (587) 952-3000 1-800-524-5521 www.baytexenergy.com

Contact Information