January Presentation

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 to, but not limited to: our business strategies, plans and objectives; our target to fund our capital program and cash dividends from internally generated funds from operations; our ability to mitigate the volatility in Western Canadian Select price differentials by transporting our crude oil to market using railways; our annual average production rate for 2016; our production mix for 2016; our capital budget for 2016; our plans to develop our three key resource plays (Eagle Ford, Peace River and Lloydminster), including the number and type of wells to be drilled in 2016 on each play; the upside potential of the Eagle Ford assets; the sustainability of our business; our liquidity and financial capacity; our target of funding our capital expenditures with funds from operations to minimize additional bank borrowings; the timing of our capital spending in Canada; the decline rate of our Canadian assets; the amount of our senior debt, our senior debt to Bank EBITDA ratio and the amount drawn on our revolving credit facilities all at year-end 2015; the estimated amount of cost reductions for 2015 and the breakdown of the reductions by spending category; our target for the cost to drill, complete and equip a well in the Eagle Ford, Peace River and Lloydminster; reductions in operating and general and administrative expenses relative to our budget and our intent to seek further reductions; our expectation that we will realize further improvements in capital efficiencies through cost reductions; our estimate of current individual well capital efficiencies; our target for all-in capital efficiencies; the rate of return for an individual well 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; our expectation that our development opportunities will provide attractive returns; for individual wells in the Eagle Ford, Peace River and Lloydminster, the cost to drill, complete and equip a well, initial production rates, liquids weighting, estimated ultimate recoveries (EUR) and single well economics (including internal rate of return, net present value, payout and capital efficiency); our Eagle Ford shale play, including the growth potential of the assets, initial production rates from new wells, our plans to use “stack and frac” pilots to target three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation, our assessment of the results of the “stack and frac” pilots, individual well economics, cumulative recoveries and drilling efficiency; our expectation regarding the effect of well downspacing, improvements in completion techniques and new development targets on initial production rates and the reserves potential of the assets; the pricing benchmarks used for our liquids production; our Peace River heavy oil resource play, including development and operational plans, years of drilling inventory remaining, the number and type of wells to be drilled in 2015, 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 development and operational plans, years of drilling inventory remaining, the number and type of wells to be drilled in 2015, 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 expected oil and natural gas production for 2015 and 2016; reserves and reserves life index; 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; the existence, operation and strategy of our risk management program, including the portion of future exposures that have been hedged; our ability to optimize the price received for our oil production and to manage our exposure to heavy oil price differentials by transporting our crude oil to market using trucks and railways; our belief that our ability to sell undiluted heavy oil provides us with a sustainable competitive advantage; the ability to ship and the portion of heavy oil sales to be transported via pipeline and railway in Q4 2015. 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. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time. 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: our ability to execute and realize on the anticipated benefits of the acquisition of the Eagle Ford assets; 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; 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; the amount of future cash dividends that we intend to pay; 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.

Advisory

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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: declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; a downgrade of our credit ratings; risks associated with properties operated by third parties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; 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; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; the implementation of strategies for reducing greenhouse gases; depletion of our reserves; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2014, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission. 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, 2014, 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, 2014 dated March 9, 2015. This presentation contains estimates of the volumes of the "contingent resources" for our oil resource plays in the Bluesky in the Peace River area of Alberta, the Mannville group in northeast Alberta and for the Gemini SAGD project at Angling Lake (Cold Lake), Alberta, as of December 31, 2014. These estimates were prepared by our independent qualified reserves evaluators, Sproule and McDaniel & Associates Consultants Ltd. ("McDaniel"). "Contingent resources" are not, and should not be confused with, petroleum and natural gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook as: "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.” The outstanding contingencies applicable to our disclosed contingent resources do not include economic contingencies. Economic contingent resources are those resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The assigned contingent resources are categorized as economically recoverable based on economics completed at year-end 2012.

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Advisory (Cont.)

A range of contingent resources estimates (low, best and high) were prepared by Sproule and McDaniel. A low estimate (C1) is considered to be a conservative estimate of the quantity of the resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources in the low estimate have the highest degree of certainty (a 90% confidence level) that the actual quantities recovered will equal or exceed the estimate. A best estimate (C2) is considered to be the best estimate of the quantity of the resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources in the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. A high estimate (C3) is considered to be an optimistic estimate of the quantity of the resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will equal or exceed the high estimate. Those resources in the high estimate have a lower degree of certainty (a 10% confidence level) that the actual quantities recovered will equal or exceed the estimate.

The primary contingencies which currently prevent the classification of the contingent resources as reserves consist of: preparation of firm development plans, including determination of the specific scope and timing of the project; project sanction; stakeholder and regulatory approvals; access to required services and field development infrastructure; oil prices and price differentials between light, medium and heavy gravity crude oils; future drilling program and testing results; further reservoir delineation and studies; facility design work; limitations to development based on adverse topography or other surface restrictions; and the uncertainty regarding marketing and transportation of petroleum from development areas. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that we will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated and that the resources can be profitably produced in the future.

The recovery and resources estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein.

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. Non-GAAP Financial Measures This presentation refers to funds from operations, total monetary debt, 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 measure 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 dividends to shareholders and 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 total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and long-term bank loans. We believe that this measure assists in providing a more complete understanding of its cash liabilities.

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 extendible unsecured 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

Focus on per share growth in production, cash flow and reserves Production growth focused on crude oil and liquids Significant inventory of development prospects

North American Oil Focused Producer Operating for Over 20 Years

Sector Leading Capital Efficiencies

Sustainable Business Model

Active Risk Management

Exceptional Growth Platform

Sector leading efficiencies in three core resource plays: Eagle Ford, Peace River and Lloydminster

Strong capital efficiencies result in low sustaining capital; provides flexibility on discretionary capital

Target to fund capital program and cash dividends from internally generated funds from operations

No near-term maturities on long-term debt; significant undrawn capacity on existing credit facilities

Risk management policy allows hedging of up to 60% of financial exposure

Mitigate the volatility in WCS price differentials by transporting crude oil to higher value markets by rail

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Ticker Symbol TSX / NYSE: BTE Average Daily Volume (1) CAN: 6,800,000 / US: 2,200,000 Shares Outstanding 210.3 million Market Capitalization / Enterprise Value $1.0 billion / $2.9 billion Total Monetary Debt (2) $1.9 billion

Production (3) 74,000 – 78,000 boe/d Production Mix 78% oil and liquids E&D Capital (3) $325-400 million Reserves – 2P Gross (4) 432 mmboe

(1) Average daily trading volumes for December 2015. Volumes are a composite of all exchanges in Canada and the U.S. (2) Total monetary debt includes working capital and the principal amount of both the long-term debt and bank loan. As at September 30, 2015. (3) Production and exploration and development capital represents our 2016 guidance range. (4) Gross reserves are per NI 51-101 as at December 31, 2014. See “Advisory – Oil and Gas Information” for more information.

Corporate Profile

Market Summary

Corporate Summary

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Texas 34%

Three Key Resource Plays

Lloydminster Heavy Oil 36%

Peace River Heavy Oil 36%

Light Oil 18% Gas 10%

Western Canada 63%

North Dakota 4%

Heavy Oil 51%

Light Oil 22%

NGLs 17% Gas

14%

Western Canada 66%

Texas 34% Eagle Ford

Q3/15 production of 39,000 boe/d

Expect to bring 35-40 net wells on production in 2016

Actively developing the Lower Eagle Ford formation in the core of the play

Significant upside potential via further delineation of Austin Chalk/Upper Eagle Ford, ongoing completion design optimization and down-spacing

Texas 34%

Peace River

Western Canada 66%

Q3/15 production of 21,200 boe/d

12 net wells planned for 2016

Developed via multi-lateral horizontal wells

Strong capital efficiencies

Texas 34%

Q3/15 production of 13,800 boe/d

24 net wells planned for 2016

Conventional heavy oil targeting multiple stacked pay formations

Expanding use of multi-lateral drilling techniques with encouraging initial results

Lloydminster

8 8

YTD 2015 Highlights

Generated production of 85,800 boe/d (9 months actual), up 16% year-over-year

Advanced multi-zone development potential of Eagle Ford acreage

13 multi-zone projects in various stages of execution and production

Continued to focus on cost reduction initiatives

Drilling costs have been reduced by ~ 27% in the Eagle Ford and by ~ 20% in Canada Operating costs have been reduced by 15% vs. budget G&A expenses have been reduced by 18% vs. budget

Maintained strong levels of financial liquidity

Completed equity financing in April 2015 Extended maturity of unsecured revolving credit facilities by one year to June 2019 Enhanced liquidity through a reduced capital program and suspension of dividend Obtained covenant relaxation on our credit facility through 2017

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Commentary:

- Our 2016 capital budget has been structured to ensure maximum flexibility with respect to both the timing and level of spend.

- We are targeting capital expenditures to approximate funds from operations in order to minimize additional bank borrowings.

- For the full-year, approximately 80%-90% of our planned capital expenditures will be directed to our Eagle Ford operations, which at current commodity prices represent the highest individual well economics and highest rates of return in our portfolio.

- We anticipate ramping up activity in Canada in the second half of 2016, with the pace being dependent on crude oil prices and project economics.

2016 Capital Budget & Commentary

Summary of 2016 Expectations Exploration and Development Capital $325-$400 million

Production 74,000 – 78,000 boe/d

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Balance Sheet / Debt Composition

Anticipate exiting 2015 with senior debt (bank debt and long-term notes) of $1.8 billion - $1.9 billion

Senior debt to Bank EBITDA ratio (twelve-month trailing) of approximately 3.0x at year-end

2015, compared to a permitted ratio of 5.25x to the end of 2017.

Approximately 25% drawn on our revolving credit facilities at year-end 2015 (total credit facility of ~ $1,060 million).

Credit Capacity $2.6 Billion Long-Term Debt Maturity Schedule ($ Millions)

Debt composition as at September 30, 2015. We have unsecured revolving credit facilities consisting of an $800 million Canadian facility and a US$200 million U.S. facility 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.

Long Term Debt $1,581

Bank Debt $208

Unutilized Capacity $850

$0 $0 $0 $0 $9

$737

$300

$0

$536

2016 2017 2018 2019 2020 2021 2022 2023 2024

11 11

Cost Reduction Focus

We are focused on cost reduction initiatives through all facets of our business

Capital spending Operating Costs General & Administration

Anticipated cost reductions in 2015 total

~ $135 million

G&A 9%

Operating Costs 44%

E&D CapEx 47%

Baytex continues to take active measures to reduce costs where possible while maintaining efficiency in our operations and the

safety of our employees and contractors.

Cost Reduction Initiatives Total ~$135M

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$3.4M

$2.8M

2014 Target

Cost Reduction Initiatives – Drilling

Eagle Ford (US$) (1)

$8.2M

$6.0M

2014 Target

Peace River (C$) (1)

Lloydminster (C$) (1)

(1) Drill, complete, and equip cost per well

$950K $750K

2014 Target

Four recently drilled wells estimated DC&E of $2.7 million In Q3/2015, we set a record drilling rate of up to 1,250 metres

per day Focused on reducing construction and equip costs Reduced day rate on drilling rig

Seven recent single-lined Hz wells estimated DC&E of $750K Cost reductions through negotiated savings with service

providers

High graded best drilling rigs and completion crews Reduced drilling days despite longer well laterals Recent drill achieved a record of 6.5 days spud to total depth Increased efficiency on completions (reduced frac times) Recent AFE’s of $6.2M are prior to a further $0.2M of

anticipated cost savings

13 13

Cost Reduction Initiatives – Operating and G&A

Operating expenses reduced 15% vs. 2015 budget

On a per-boe basis, down 14% vs. budget (YTD 2015 actual = $10.55/boe) Optimization of operational practices

Trucking and fluid hauling Well servicing Facility rationalization

Shut-in of uneconomic production with high operating costs

Shut-in volumes ~ 2,400 boe/d

Further reductions through fuel savings, reduced repairs and maintenance, and workovers

General & administrative expenses reduced 18% vs. 2015 budget

YTD 2015 actual = $1.99/boe We continue to seek further spending reductions across all categories

14

$0

$5,000

$10,000

$15,000

$20,000

2014

Cur

rent

2014

Cur

rent

2014

Cur

rent

$ pe

r boe

/d

$0

$10,000

$20,000

$30,000

$40,000

2012

2013

2014

Targ

et

Bay

tex

Indu

stry

Ave

rage

$ pe

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/d

Strong Capital Efficiencies – Driving Down Costs

Capital efficiency improvement in 2014 driven by portfolio enhancements, including:

Addition of the Eagle Ford Divestiture of North Dakota and other non-core assets Reduced thermal expenditures

We anticipate further improvements as we drive our costs down

Individual Well Capital Efficiencies(1)

(1) Individual well capital efficiencies represent the cost to drill, complete and equip divided by the average first year production rate. (2) All-in capital efficiencies calculated at a corporate level include the cost of land, infrastructure, and drilling and completion. (3) Source: Scotiabank “The Statsbook: Taking a Closer Look: May 2015,

All-In Capital Efficiencies(2)

3-Year Average (3)

(2012-2014)

Eagle Ford Peace River

Lloydminster

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Attractive Rates of Return

0%

25%

50%

75%

100%

125%

150%

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

Eagle Ford - US$6.0M/wellPeace River - C$2.8M/wellLloydminster - C$750K/well

WTI (US$/bbl)

Inte

rnal

Rat

e of

Ret

urn

(1) (

2) (3

)

Break-Even WTI (4)

(1) Individual well economics are based on constant pricing and costs. Pricing assumptions: NYMEX gas = US$3.15/mcf, WCS differential = US$14/bbl, FX Rate (US$/C$) = 1.25. (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.

16

High Quality Investment Opportunities

Single Well Economics

Eagle Ford Peace River Lloydminster

Well Costs – DC&E (1) ($ millions) US$6.0 $2.8 $0.75

Production (boe/d)

IP30 1,000 - 1,200 300 - 500 70 - 80

% Liquids 60% - 70% 100% 100%

EUR (2) (mboe) 800 300 70

Single Well Economics @ US$50/bbl (constant oil price) (3)

Internal Rate of Return (4) 38% 19% 42%

Net Present Value (10% pre-tax) ($ millions) $4.6 $0.5 $0.36

Payout (years) 2.2 3.3 1.9

Capital Efficiency (IP365) ($/boe/d) $13,000 $13,000 $14,500

(1) DC&E – Drill, complete and equip (2) EUR or estimated ultimate recovery represents the amount of oil and gas expected to be economically recovered from a reservoir by the end of its producing life. Baytex internal estimate. (3) Constant pricing assumptions: WTI US$50/bbl, WCS differential US$14/bbl, LLS premium to WTI US$3/bbl, FX rate (C$/US$) = 1.25. (4) 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.

The Eagle Ford

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Baytex Acreage Position

Overview of Acreage

- 23,000 net contiguous acres in the Sugarkane Field in the core of the liquids-rich Eagle Ford shale

- The Sugarkane Field has been largely delineated which is expected to facilitate future production growth

- Extensive infrastructure in place across the acreage position, including centralized processing facilities, disposal wells and infield gathering systems

- 97% of acreage is held by production

The Eagle Ford Provides Baytex With Exposure to a World Class Oil Resource Play

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Eagle Ford Development

Development to-date has targeted the Lower Eagle Ford

Development occurring at 40-acre and 60-acre spacing

We are seeing an approximate 28% improvement in 30-day IP rates since acquisition

Extending Lower Eagle Ford Success

Austin Chalk now delineated on over 50% of our acreage

As at September 30, 2015, there are 45

producing Austin Chalk wells on our lands with 30-day IP rates of approximately 1,000 boe/d

Stack and Frac pilots to include Austin Chalk, Upper Eagle Ford and Lower Eagle Ford formations

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Urrutia

Eagle Ford “Stack and Frac” Highlights

Four well pad on production February 14, 2015 Four zones targeted: Lower EF, Upper-Lower

EF, Upper EF, Austin Chalk Average 30-day IP rate ~1,450 boe/d Average lateral length 5,466 feet

Sienkiewicz

Urrutia

Four Tier “Stack and Frac” Development

Three Tier “Stack and Frac” Development

Co-development with Murphy Sinclair unit Three wells on production May 31, 2015 Two zones targeted: Lower EF, Austin Chalk Average 30-day IP rate ~ 1,200 boe/d Average lateral length 6,175 feet

Five-well pad on production April 30, 2015 Three zones targeted: Lower EF, Upper EF,

Austin Chalk Average 30-day IP rate ~1,575 boe/d Average lateral length 4,570 feet

Murphy Sinclair

Co-Development

Murphy Sinclair

Sienkiewicz

San Christoval Ranch

San Christoval Ranch

Six well pad on production July 19, 2015 Four zones targeted: Lower EF, Upper-Lower

EF, Upper EF, Austin Chalk Average 30-day IP rate 700 – 1,480 boe/d Average lateral length 7,583 feet

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

approximately 84% since Q4/2011 with 180-day cumulative recovery increasing 69% over the same time period

- Drilling times have decreased by 64% since Q4/2011 resulting in reduced completed well costs

- In Q2/2015, a new record of 6.5 days was set on a 19,000 foot well

Eagle Ford Performance

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

Days on Production

69%

22

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

Completion Improvements

Increasing Lateral Length, Frac Stages and Proppant - Since 2011, the average lateral length per well has increased 18% to approximately

5,700 feet, the number of frac stages per well has increased 44% to 23 stages and the amount of total proppant per well has increased 40% to 5.0 million pounds.

23 23 (1) Based on 2015E liquids revenues

Pricing Exposure

2015 YTD Operating Netback (2)

$/boe Canada Eagle Ford Total

WTI (US$/bbl) $51.00

Sales Price $32.83 $42.73 $37.42 Royalties (4.55) (12.41) (8.20) Operating Costs (13.13) (7.58) (10.55) Transportation (3.37) --- (1.81) Operating Netback $11.78 $22.74 $16.86

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

43%

LLS Benchmark

49%

WTI Benchmark

8%

(2) Nine months ended September 30, 2015

24

Heavy Oil Overview

25

Peace River Oil Sands

Multi-Lateral Drilling Drives Strong Capital Efficiencies

Land Holdings 310 net sections

Production (Q3/2015) 21,200 boe/d

2P Reserves (YE14) (1) 72.6 mmboe

Drilling Inventory (2) 6.5 years

Area Statistics

2016 Development

~12 multi-lateral horizontal wells

~6 stratigraphic and service wells

(1) In addition, we have 38 mmbbl of bitumen reserves related to our thermal operations.

(2) Drilling inventory in years based on identified drilling locations (cold horizontal multi-lateral wells) and 2014 drilling activity.

26

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

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Lloydminster Heavy Oil

Lloydminster Heavy Oil

Area Statistics

2016 Development

Land Position 652 net sections

Production (Q3/2015) 13,800 boe/d

2P Reserves (YE14) (1) 49.5 mmboe

Drilling Inventory (2) ~ 6.5 years

Drilling ~24 net wells

% Horizontal/Vertical 70% / 30%

(1) In addition, we have 43.4 mmbbl of bitumen reserves related to our SAGD project at Gemini and 10 mmbbl of bitumen reserves related to our SAGD project at Kerrobert.

(2) Drilling inventory in years based on identified drilling locations and 2014 drilling activity.

Shift to Horizontal Drilling Expands Inventory

28

Lloydminster Development

Horizontal Well Economics (1)

Completed Well Cost ~ $750,000

Production (IP30) 70-80 bbl/d

Capital Efficiency (based on IP365)

$14,500 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.

29 29

The Value Proposition

We have recalibrated our business to the current oil price environment

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

Focused on driving our cost structure lower

Drilling costs have been reduced by ~ 27% in the Eagle Ford Operating costs have been reduced by 15% vs. budget G&A expenses have been reduced by 18% vs. budget

Maintain strong levels of financial liquidity

Extended maturity of unsecured revolving credit facilities by one year to June 2019 $850 million of undrawn capacity on credit facilities

Currently trade at a discount to our peer group

30

Supplementary Information

31

Production Growth

Production Breakdown 2016 Guidance

87% Oil (%) 88% 86% 81% 78%

Production by Region 2016 Guidance

78%

Heavy Oil 34% Gas

22%

NGLs 12% Light Oil

32%

5 Year Production CAGR = 9%

United States 53%

Canada 47%

32

Reserves Growth / Contingent Resources

Gas 15%

Heavy Oil 53%

Light Oil 16%

Gas 14%

NGLs 17%

(1) See “Advisory – Oil and Gas Information” for more information on contingent resources. (2) Reserve Life Index (RLI) is based on year end reserves (prepared by our independent reserves evaluator) divided by Q4 production rate for each year.

Heavy Oil 53%

Light Oil 16%

Gas 14%

NGLs 17%

Heavy Oil 53% Light Oil

16%

NGLs 17%

Natural Gas 16%

Economic Contingent Resources (1)

(Millions of barrels of bitumen)

Best Estimate

Peace River, Alberta 555

Northeast Alberta 118

Cold Lake, Alberta 74

Total 747

5 Year Reserve CAGR = 17% (per share CAGR = 7%)

91% Oil (%) 92% 93% 90% 84%

13.9 RLI (yrs) (2) 13.0 14.5 14.9 13.0

2P Gross Reserves Breakdown

Company Total = 432 MMboe

12.6

89%

Heavy Oil 48%

NGLs 22%

Natural Gas 16%

Light Oil 14%

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2016 Funds from Operations Sensitivities

Sensitivities (excludes effect of hedging)

Estimated Effect on Annual Funds from

Operations ($ Millions)

Estimated Effect on Annual Funds from

Operations (Per Share)

Change of US$1.00/bbl WTI crude oil $18.0 $0.09

Change of US$1.00/bbl WCS heavy oil differential $8.2 $0.04

Change of US$0.25/mcf NYMEX natural gas $6.2 $0.03

Change of $0.01 in the US$/C$ exchange rate $5.3 $0.03

Note: Based on the forward strip as at December 1, 2015.

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Crude Oil Hedge Portfolio

Q4/2015 2016 2017 Fixed Hedges

Volumes (bbl/d) 9,667 6,250 ---

Hedge (%) (1) 20% 16% ---

Fixed Price (US$/bbl) $76.37 $63.64 ---

3-Way Option

Volumes (bbl/d) 1,000 9,500 2,000

Hedge (%) (1) 2% 24% 5%

Average Ceiling/Floor/Sold Floor (US$/bbl) (2) $62.50/$50/$40 $60/$50/$40 $60/$50/$40

Total Hedged Volumes (bbl/d) 10,667 15,750 2,000

Total Hedged Volumes (%) (1) 22% 40% 5%

(1) Percentage of hedged volumes are based on 2016 production guidance, net of royalties. (2) Producer 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.

35

Natural Gas / Foreign Exchange Hedge Coverage

Q4/15 2016 2017

Natural Gas AECO Volumes Hedged (GJ/day) 20,000 15,000 ---

% of Volumes Hedged at Fixed Price (1) 25% 18% ---

Average AECO Swap Price (C$/GJ) $2.88 $2.96 ---

NYMEX Volumes Hedged (mmbtu/day) 15,000 10,000 ---

% of Volumes Hedged at Fixed Price (1) 20% 12% ---

Average NYMEX Swap Price (US$/mmbtu) $3.06 $3.19 ---

Foreign Exchange

Hedged Amount (US$ millions) $58.5 --- ---

Average Hedged Price (CAD per USD) 1.11 --- ---

(1) Percentage of hedged volumes are based on 2016 production guidance, net of royalties.

36

Marketing - Crude by Rail

Rail a Key Component of Market Access

- Trucking flexibility helps optimize value of production

- Rail has become an effective vehicle for management of heavy oil differentials

- Undiluted heavy oil sales provide Baytex with a sustainable competitive advantage

Baytex Heavy Oil Volumes on Rail (bbl/d) Q4 2015 Heavy Oil Sales Portfolio

Rail 40%

Pipeline 60%

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Baytex shareholder base, estimated as at December 2015. Sources: IPREO and Baytex internal data.

Share Ownership Breakdown

Institutional 60%

Retail 40%

100%

Canada 67%

U.S. 29%

Europe/Asia 4%

100%

Ownership Breakdown

Institutional - U.S. 15%

Institutional - Europe / Asia

4%

Institutional - Canada

41%

Retail - U.S. 14%

Retail - Canada 26%

38

(1) Includes Change in Future Development Costs. (2) Calculated as total reserve additions (including acquisitions and divestitures) divided by annual average production. (3) Calculated as operating netback (excluding hedging gains/losses) divided by F&D costs.

Capital Program Efficiency

2012 2013 2014 3-Year

Average 2012-14

Capital Expenditures ($millions) Exploration and development 418.6 550.9 766.1 1,735.6

Acquisitions (net of dispositions) (170.9) (39.1) 2,545.1 2,335.1

Total 247.7 511.8 3,311.2 4,070.7

Proved plus Probable Reserve Additions (mboe)

Exploration and development 33,659 48,396 33,598 116,193

Acquisitions (net of dispositions) 25,523 (1,540) 108,515 132,498

Total 59,182 47,396 142,113 248,691

Finding & Development (F&D) Costs ($/boe) (1) 19.69 19.30 19.77 19.55

Finding, Development & Acquisition (FD&A) Costs ($/boe) (1) 11.51 18.28 31.10 23.99

Ratios – Proved plus Probable Reserves

Production Replacement Ratio (2) 300% 227% 497% 359%

Recycle Ratio (3) 1.6x 1.7x 1.8x 1.7x

39 39

James L. Bowzer President & 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