2 Advisory Baytex Energy Corp. (“Baytex”) announced on February 28, 2023 that it has entered into a definitive agreement (the ‘”Agreement”) to acquire Ranger Oil Corporation (“Ranger”), a pure play Eagle Ford company (the “Acquisition”). In this presentation, we refer to certain specified financial measures which do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”). While these measures are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This presentation also contains oil and gas disclosures, various industry terms, and forward-looking statements, including various assumptions on which such forward-looking statements are based and related risk factors. Please see the Company’s disclosures located at the end of this presentation for further details regarding these matters. All slides in this presentation should be read in conjunction with “Forward Looking Statements Advisory”, “Specified Financial Measures Advisory”, “Capital Management Measures Advisory” and “Advisory Regarding Oil and Gas Information”. This presentation should be read in conjunction with the Company’s consolidated audited financial statements and Management’s Discussion and Analysis (“MD&A”) for the period ended December 31, 2022. There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements. The future oriented financial information and forward-looking statements are made as of February 28, 2023 and Baytex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. All dollar amounts in this presentation are stated in Canadian dollars unless otherwise specified. The CAD/USD exchange rate used in this presentation is 1.35.

3 Quality Scale and Resiliency “Baytex has a high quality and diversified oil portfolio in both Canada and the Eagle Ford in Texas. With more than 10 years of projected development inventory in each of our core areas, our objective is to deliver modest and reliable annual production growth organically and generate meaningful free cash flow while maintaining reasonable financial leverage. We are committed to building an even stronger and more resilient business over time to increase shareholder value and enhance direct shareholder returns on a per-share basis. We view our extensive position in Canada and the Eagle Ford as core to our ongoing business. We are building an even stronger Canadian energy company with a high-quality diversified oil-weighted portfolio across the Western Canadian Sedimentary Basin and the Eagle Ford.” “The Ranger acquisition is strategic. We are acquiring a strong operating capability in the Eagle Ford, on-trend with our non-operated position in the Karnes Trough and driving meaningful per-share accretion on all metrics. The transaction more than doubles our EBITDA and nearly doubles our free cash flow. The Ranger inventory immediately competes for capital in our portfolio and brings 12-15 years of quality oil-weighted drilling opportunities. We are building quality scale and a more durable business with a lower break-even WTI price. We are committed to enhancing direct shareholder returns, and through this transaction, we are returning more value to our shareholders on a per-share basis. Upon closing of this transaction, we intend to initiate a dividend, which will be a key means of delivering reliable value to shareholders going forward.” “I couldn’t be more proud of the Ranger team and the company we’ve built together. We expect that combining with the balance sheet strength, deep asset base, and operational excellence of Baytex will create a unique company of scale which will deliver sustained free cash flow growth and differentiated shareholder returns. We look forward to bringing together our complementary teams and assets to realize the long-term value of this combination for our shareholders.” “This transaction represents a leap forward in shareholder value creation potential and accelerates both companies’ shareholder return strategies. We expect this combination will create a company that is exceptionally positioned for sustained shareholder returns.” Eric T. Greager President and Chief Executive Officer, Baytex Energy Darrin Henke Chief Executive Officer, Ranger Oil Edward Geiser Chairman, Ranger Oil Board of Directors Managing Partner, Juniper Capital

4 EAGLE FORD VIKING LLOYDMINSTER PEACE RIVER/ PEAVINE DUVERNAY (1) Enterprise value is calculated as market capitalization plus net debt and is used to assess the valuation of the Company. (2) Calculated in accordance with the credit facilities agreement which is available on SEDAR at www.sedar.com. (3) Capital management measure. Refer to the Capital Management Measures section in this presentation for further information. (4) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this presentation for further information. Baytex + Ranger - A Diversified North American E&P Operator Pro forma Market Summary Ticker Symbol TSX & NYSE | BTE Shares Outstanding 864 million Market Capitalization / Enterprise Value(1) $5.0 billion / $7.6 billion Pro forma Metrics Production (working interest) 155 – 160 Mboe/d Production Mix 85% liquids Reserves – 2P (working interest) 696 MMboe Net Acres 1.7 million EBITDA(2) $2.4 billion Adjusted Funds Flow(3) $2.2 billion Free Cash Flow(4) $1.0 billion Total debt to EBITDA(4) 1.0x Acquisition Overview 70% Stock 30% Cash Assumed Debt In this presentation we reference financial metrics for Ranger and Baytex (pro forma for the Acquisition), including EBITDA, adjusted funds flow and free cash flow. We also reference accretion on a per-share basis for adjusted funds flow, free cash flow and production. Financial metrics and financial accretion assume the Acquisition closes at the end of Q2/2023, is based on the 12-month period from closing, July 1, 2023 to June 30, 2024, and the following commodity prices: WTI - US$75/bbl; MEH premium to WTI - US$2/bbl; WCS differential to WTI – US$17.50/bbl, NYMEX Gas - US$3.50/MMbtu; Exchange Rate (CAD/USD) - 1.35. Production and production accretion (boe/d per thousand share) based on the 12-month period from closing, July 1, 2023 to June 30, 2024, and includes: (i) Baytex production of 88-90 Mboe/d (working interest); and (ii) Baytex’s internal estimate for Ranger production of 67-70 MBoe/d (working interest). Reserves based on (i) Baytex reserves as at December 31, 2022 prepared by McDaniel & Associates Consultants Ltd, (“McDaniel”), an independent qualified reserves evaluator in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”); and (ii) Ranger’s year-end 2022 reserves were evaluated by McDaniel in accordance with NI 51-101. Market capitalization, enterprise value and dividend yield based on Baytex closing share price on the Toronto Stock Exchange on February 24, 2023 of $5.74. Total debt is based on estimated total debt for Baytex and Ranger on closing of the Acquisition, including estimated transaction costs. These assumptions apply throughout this presentation.

5 ▪ Materially increases Eagle Ford scale ▪ Creates a quality operating platform in a capital efficient basin ▪ 67-70 Mboe/d (87% liquids), 43° API crude oil Compelling Strategic Rationale Immediately Accretive on all Metrics(1) Creating a More Resilient Business Enhances Inventory ▪ 162k net acres, 96% operated ▪ ~ 741 net drilling locations and 12-15 years of sustaining inventory that immediately competes for capital in the Baytex portfolio ▪ Strong economics with Lower Eagle Ford locations generating IRRs > 75% and payouts < 18 months at US$75 WTI ▪ Asset level free cash flow break-even price(3) improves US$7/bbl to US$41/bbl WTI ▪ Lowers cash cost structure, improves operating netback and margin ▪ Increased exposure to premium light oil U.S. Gulf Coast pricing ▪ Lowers average GHG emissions intensity by 16% ▪ Shareholder returns increase to 50% of free cash flow on closing ▪ Anticipate introducing quarterly dividend of $0.0225 per share ($0.09 per share annualized, or ~1.6% annual dividend yield) ▪ Total debt to EBITDA(5) ratio(3) 1.0x expected at closing Enhancing Direct Shareholder Returns Building Quality Scale ▪ 24% accretion to adjusted funds flow per share(2) ▪ 20% accretion to free cash flow per share(3) ▪ 20% accretion to return of capital per share(4) ▪ 12% accretion to production per share 1. See note regarding assumptions on Slide 4. 2. Capital management measure. Refer to the Capital Management Measures section in this presentation for further information. 3. Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this presentation for further information. 4. Return of capital per share is calculated as the dollar value of dividends and common shares repurchased and cancelled divided by average common shares outstanding for the applicable period. 5. Calculated in accordance with the credit facilities agreement which is available on SEDAR at www.sedar.com.

6 Acquisition Overview ▪ Ranger Oil is listed on the NASDAQ exchange (“ROCC”) ▪ 42.5 million fully diluted shares outstanding ▪ Total transaction value of ~ US$2.5 billion (C$3.4 billion), including net debt(4) of ~ US$650 million(5) ▪ Ranger shareholders will receive 7.49 Baytex common shares plus US$13.31 per share cash, for total consideration of approximately US$44.36 per share ▪ Represents a 7.6% premium to the closing price on February 24, 2023 (1) See note regarding assumptions on Slide 4. Transaction value based on the trailing 5-day volume weighted average price as of February 24, 2023 for Baytex trading on all Canadian exchanges. (2) Calculated in accordance with the credit facilities agreement which is available on SEDAR at www.sedar.com. (3) Enterprise value is calculated as market capitalization plus net debt and is used to assess the valuation of the Company. (4) Capital management measure. Refer to the Capital Management Measures section in this presentation for further information. (5) Estimated as at closing. ▪ Closing of the transaction anticipated late Q2/2023 ▪ Acquisition to be completed by way of a merger agreement ▪ Respective shareholder votes for Baytex and Ranger expected in Q2/2023 ▪ Combined organization to be led by Eric T. Greager, President and Chief Executive Officer of Baytex and the Baytex leadership team, with the addition of key senior operational leadership from Ranger ▪ Baytex intends to appoint two independent directors from the Ranger Board to the Baytex board of directors ▪ Affiliates of Juniper Capital Advisors own approximately 54% of Ranger’s shares and have agreed to vote in favour of the transaction and have entered into a hold period agreement with respect to the Baytex shares to be issued to Juniper Transaction Size and Value(1) Canadian $ U.S. $ Transaction Value $3.4 billion US$2.5 billion Production (boe/d) 67-70 Mboe/d (working interest) 52-54 Mboe/d (net revenue interest) 2P Reserves 258 MMboe 258 MMboe EBITDA(2) $1.2 billion US$900 million EV(3) / Production $50 kboe/d US$48 kboe/d EV / EBITDA 2.86x 2.86x

7 Building a Strong Operating Platform in the Eagle Ford Materially Increases Eagle Ford Scale while Building a Quality Operating Platform in a Premier Basin ▪ Located primarily in Gonzales, Lavaca, Fayette and Dewitt counties, in the oil windows of the Eagle Ford shale ▪ Large contiguous position, on-trend with Baytex’s non-operated position in the Karnes Trough ▪ High working interest and largely operated provides operational control & opportunity ▪ 86% working interest ▪ 96% operated ▪ 96% held by production Eagle Ford Metrics Baytex Ranger Pro Forma Gross Acreage 78,212 188,900 267,112 Working interest, % 25% 86% 68% Production (boe/d) 27,000 68,500 95,500 % Operated 0% 96% 70% % Crude Oil 59% 72% 68% % Liquids 77% 87% 84%

8 Deep, High-Quality Inventory ▪ 741 net undrilled locations ▪ 523 quality Lower Eagle Ford opportunities ▪ 218 additional Upper Eagle Ford and Austin Chalk opportunities ▪ 12-15 years of sustaining development ▪ Inventory immediately competes for capital ▪ Attractive well economics ▪ 2 rig program (50-55 net wells to sales per year) to generate modest production growth (1) Individual well economics based on the following commodity prices (constant): WTI - US$75/bbl; MEH premium to WTI - US$2/bbl; NYMEX Gas - US$3.50 MMbtu. Lower Eagle Ford Inventory Depth and Economics(1) Thermal Maturity Windows Net Well Count (1) IP365 (boe/d) EUR (Mboe) Oil Weighting Liquids Weighting IRR Payout (years) NPV10 Btax (US$MM) Black Oil 290 410 489 83% 92% 79% 1.4 $6.8 Volatile Oil 90 674 654 59% 81% 89% 1.1 $7.2 Condensate 60 922 856 38% 71% 94% 1.1 $7.7 Redevelopment 83 396 397 67% 85% 43% 1.8 $3.4

9 Consistent Performance Improvement & Strength Relative to Local Peers - 50,000 100,000 150,000 200,000 250,000 0 6 12 18 24 30 Cumulative 2 Phase Production (Mboe) Months Cumulative Well Production by Year (2) 2020 2019 2018 2017 2016 2021 2022 2023 Ganymede Pad 6-Month Cumulative Productivity (2) (boe/foot) 11.2 11.4 11.6 11.8 12.0 12.2 12.4 12.6 12.8 2011-2014 2015-2019 2020-2021 2022 Competitive Performance Across the Oil Window since 2020 Relative to Large Peers(1)(2) on Immediately Adjacent Acreage - 50,000 100,000 150,000 200,000 250,000 16 month 18 month 24 month Cumulative boe per 8,000ft (15:1 gas) (1) MRO data set includes all 27 wells since 1/1/2020, EOG data set includes all 143 wells since 1/1/2020, ROCC data set includes all 106 wells since 1/1/2020 (2) Source: Enverus ROCC ROCC ROCC

10 ▪ Baytex’s asset level free cash flow break-even price(1) improves US$7/bbl to US$41/bbl WTI ▪ Provides increased flexibility for capital allocation across portfolio ▪ Defensive inventory at lower WTI pricing ▪ Operated production increases to 82% (70% previously) ▪ Eagle Ford light oil production increases to 42% of pro forma production (18% previously) ▪ Operating netback(1)(2) increases 12% ▪ Increased exposure to premium Gulf Coast pricing ▪ Eagle Ford light oil (43° API crude oil) receives a premium to WTI ▪ Substantial infrastructure in place with low operating and transportation costs 1. Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this presentation for further information. 2. See note regarding assumptions on Slide 4. 3. Revenue per boe is calculated as petroleum and natural gas sales divided by barrels of oil equivalent production volume for the applicable period. 4. Cash costs per boe include operating expense and transportation expense. Portfolio at US$75 WTI and 2P Reserves Portfolio at US$55 WTI and 2P Reserves Creating a More Resilient and Sustainable Business Revenue per boe (2)(3) 7% Cash Costs per boe(1)(4) 14% Operating Netback per boe(1) 12% - 50 100 150 200 250 300 350 400 450 Relative IRRs 2P Undeveloped Booked Volume (MMboe) Baytex Ranger - Eagle Ford - 50 100 150 200 250 300 350 400 450 Relative IRRs 2P Undeveloped Booked Volume (MMboe) Baytex Ranger - Eagle Ford Peavine Clearwater Eagle Ford Heavy Oil Duvernay Duvernay Viking Heavy Oil Eagle Ford Eagle Ford Heavy Oil Viking Peavine Clearwater Eagle Ford Eagle Ford Duvernay Duvernay Eagle Ford Viking Eagle Ford Heavy Oil Heavy Oil Viking Heavy Oil

11 Enhances Free Cash Flow and Shareholder Returns ▪ Increasing per-share value directly to our shareholders ▪ 20% accretion to free cash flow per share(1) ▪ 20% accretion to return of capital per share(2) ▪ Direct shareholder return expected to increase to 50% of free cash flow on closing ▪ Combination of increased share buybacks and introduction of a quarterly dividend ▪ Increases to 75% of free cash flow upon reaching $1.5 billion total debt target(1) ▪ ~ $1 billion of pro forma annual free cash flow(1) at US$75/bbl WTI ▪ Anticipate introducing a quarterly dividend of $0.0225 per share ▪ $0.09 per share annualized ▪ ~ 1.6% annual dividend yield(3) ▪ Initial dividend expected to be paid in October 2023 ▪ Represents 4% of adjusted funds flow(4) and 8% of free cash flow at US$75/bbl WTI ▪ Dividend fully funded to US$47/bbl WTI 1. Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this presentation for further information. 2. Return of capital per share is calculated as the common shares repurchased and cancelled or issued divided by average common shares outstanding for the applicable period. 3. See note regarding assumptions on Slide 4. 4. Capital management measure. Refer to the Capital Management Measures section in this presentation for further information. Free Cash Flow Accretion(3) Baytex Stand-Alone Pro forma Ranger Accretion Free Cash Flow $538 million $1.0 billion FCF Per Share $1.04 $1.25 20%

12 Free Cash Flow Accretion to 5-Year Plan ▪ In addition to near-term value accretion, the Ranger acquisition is 23% accretive to free cash flow per share during our 5-year plan period(1) ▪ Cumulative free cash flow(2) of $5.00 per share (2023-2026) at US$75/bbl WTI $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 2022 2023 2024 2025 2026 Cumulative Free Cash Flow ($ millions) Baytex Free Cash Flow Profile (2023-2026) at US$75/bbl WTI Baytex Stand-Alone (1) Baytex’s current five-year plan is for the period 2022-2026 and will be updated upon closing of the Acquisition and rolled forward to include 2027. Baytex generated free cash flow of $622 million ($1.11 per share) in 2022. To illustrate the long-term accretion of the Acquisition, the period 2023-2026 is referenced. (2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this presentation for further information (3) For illustrative purposes only and should not be relied upon as indicative of future results. Baytex’s actual results may vary. Budget and forecast beyond 2023 has not been finalized and are subject to a variety of factors including prior year’s results. (4) Baytex pro forma free cash flow profile assumes closing of the Acquisition at the end of Q2/2023. (5) In both scenarios, exploration and development expenditures represent approximately 50-55% of adjusted funds flow. (6) Based on the following long-term pricing assumptions: WTI - US$75/bbl; MEH premium to WTI - US$2/bbl; WCS differential to WTI – US$17.50/bbl, NYMEX Gas - US$3.50/MMbtu; Exchange Rate (CAD/USD) - 1.35. (7) See note regarding assumptions on Slide 4. $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 2022 2023 2024 2025 2026 Cumulative Free Cash Flow ($ millions) Baytex Pro Forma 2023 – 2026 Cumulative Free Cash Flow: $1.9 billion, $4.07 per Share 2023 – 2026 Cumulative Free Cash Flow: $3.6 billion, $5.00 per Share

13 Maintaining Financial Strength Pro forma Net Debt US$MM C$MM Credit Facilities $659 $890 Term Loan $250 $337 Bridge Loan $500 $675 Long-Term Notes $409 $552 Total Debt(1) $1,818 $2,454 Working Capital $165 $223 Net Debt(2) $1,983 $2,677 Credit Facility Capacity $1,000 $1,350 % Unutilized 35% Total Debt to EBITDA(3) Ratio(1) 1.0x (1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this presentation for further information. (2) Capital management measure. Refer to the Capital Management Measures section in this presentation for further information. (3) Calculated in accordance with the credit facilities agreement which is available on SEDAR at www.sedar.com. On a pro forma basis: ▪ Maintaining strong liquidity ▪ Total debt to EBITDA ratio 1.0x ▪ Revolving credit facilities increase to US$1 billion (US$850 million, previously) ▪ US$250 million 2-year term loan ▪ Expect to pursue a financing structure which will include senior notes ▪ Intend to hedge ~ 40% of pro forma net oil exposure On closing: ▪ Baytex’s balance sheet will remain a priority with 50% of free cash flow allocated to debt repayment upon closing and a newly established total debt target of $1.5 billion (represents 1x total debt to EBITDA at US$50 WTI)

14 Improves GHG Intensity Metrics ▪ We are committed to monitoring greenhouse gas (“GHG”) emissions from our operations, setting targets to reduce our GHG emissions intensity, and pursuing cost-effective strategies to produce energy for society with a lower carbon intensity ▪ The Ranger acquisition reduces our average GHG intensity by 16% (based on 2021 published data for both companies) GHG Emissions Intensity (2021 Data) Baytex Ranger Combined % Change GHG Emissions, Scope 1 and 2 (CO2e tonnes) 1,173,678 602,687 1,776,365 Intensity, Scope 1 and 2 (kg CO2e/boe) 54 28 45 -16%

15 Pro forma Adjusted Funds Flow Sensitivities Sensitivities Estimated Effect on Annual Adjusted Funds Flow(1) ($MM) Change of US$5.00/bbl WTI crude oil $218 Change of US$1.00/bbl WCS heavy oil differential $17 Change of US$0.50/MMbtu NYMEX natural gas $15 Change of $0.01 in the C$/US$ exchange rate $22 1. Capital management measure. Refer to the Capital Management Measures in this presentation for further information.

Supplementary Information

17 Market Capitalization Baytex Industry Ranking by Market Capitalization and Production Production - Working interest(2) (1) Source: Factset, CIBC World Markets. See note regarding assumptions on page 4. (2) Working interest production shown for comparability. U.S peers’ production converted at a 23% royalty rate. (3) U.S. Peers: Callon, Chord Energy, Civitas Resources, Earthstone, HighPeak, Energy, Magnolia, Matador Resources, PDC Energy, Permian Resources, SM Energy, Vital Energy. (4) Canadian Peers: Crescent Point Energy, Enerplus Resources, Tamarack Valley Energy, Vermilion Energy, Whitecap Resources. $8.9 $8.4 $8.4 $8.0 $7.7 $6.5 $6.5 $5.3 $5.0 $5.0 $4.9 $4.2 $3.3 $3.2 $3.1 $2.6 $2.4 $1.2 – $2.0 $4.0 $6.0 $8.0 $10.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Baytex Pro Forma Peer 10 Peer 11 Peer 12 Peer 13 Baytex Peer 14 Peer 15 Peer 16 C$B 335 219 216 208 194 167 162 158 140 138 132 109 100 97 90 89 70 66 0 50 100 150 200 250 300 350 400 Peer 2 Peer 5 Peer 4 Peer 3 Peer 9 Peer 1 Peer 7 Baytex Pro Forma Peer 8 Peer 12 Peer 14 Peer 6 Peer 16 Peer 10 Peer 13 Baytex Peer 15 Peer 11 Mboe/d

18 Baytex Stand-Alone(1) Pro Forma Production and Reserves Baytex Pro Forma Ranger(1) Production: 88-90 Mboe/d 2P Reserves (YE 2022): 438 MMboe Production: 155-160 Mboe/d 2P Reserves (YE 2022): 696 MMboe (1) See note regarding assumptions on Slide 4. Eagle Ford Light Oil Canada Light Oil Canada Heavy Oil NGLs Natural Gas Eagle Ford Light Oil Canada Light Oil Canada Heavy Oil NGLs Natural Gas Eagle Ford Light Oil Canada Light Oil Canada Heavy Oil NGLs Natural Gas Eagle Ford Light Oil Canada Light Oil Canada Heavy Oil NGLs Natural Gas

19 Eric T. Greager President and CEO Mark R. Bly Chair of the Board Trudy M. Curran Steve D.L. Reynish Gregory K. Melchin Board of Directors Dave L. Pearce Jennifer A. Maki • Adding two independent board members (Jeffrey Wojahn + one additional) from Ranger’s Board • Mr. Gregory Melchin not standing for election at the Baytex 2023 Annual Meeting of Shareholders • On closing of acquisition, 10 board members, 9 of which will be independent Don G. Hrap Angela Lekatsas Efficient and Independent Board with Complementary Skills Suited to Govern the Combined Business Jeffrey E, Wojahn, Ranger Oil

20 Eric T. Greager President and CEO M. Scott Lovett Vice President Corporate Development Kendall D. Arthur Vice President Heavy Oil Leadership Team James R. Maclean Vice President General Counsel and Corporate Secretary Brian G. Ector Vice President Capital Markets Nicole Frechette Vice President Light Oil A Passionate, Shareholder-Aligned Leadership Team Committed to Creating Value Chad E. Lundberg Chief Operating and Sustainability Officer Chad L. Kalmakoff Chief Financial Officer • Baytex intends to add one senior operational leader (Julia Gwaltney) to the Baytex leadership team and retain the Ranger teams, operating in Houston Julia Gwaltney Senior Vice President and Chief Operating Officer, Ranger Oil

21 Any “financial outlook” or “future oriented financial information” in this presentation as defined by applicable securities laws, has been approved by management of Baytex. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other circumstances. In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of future plans and operations, certain statements in this presentation are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this presentation peak only as of the date hereof and are expressly qualified by this cautionary statement. Specifically, this presentation contains forward-looking statements relating to but not limited to: the Acquisition, the expected closing of the Acquisition and the timing thereof; the expected financial effects of the Acquisition, including the expected accretion to adjusted funds flow, free cash flow and production, the expected impact on break-even price, our debt levels and leverage ratio, the expected impact on EBITDA and expected single-well IRRs and paybacks; the expected operational impacts of the Acquisition, including the number of locations to be drilled and the level of oil and natural gas production from wells on the acquired acreage; and expected plans as a result of the transaction, including increasing direct shareholder returns to 50% of free cash flow, instituting a dividend, maintaining or increasing share buybacks and anticipated changes to our management team and Board of Directors. 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. Forward Looking Statements Advisory

22 Forward Looking Statements Advisory (Cont.) These forward-looking statements are based on certain key assumptions regarding, among other things: the consummation and success of the Acquisition and our ability to successfully integrate the acquired business into our existing operations; petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow under credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the ability to develop crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect. 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 (including the impacts of rising macroeconomic uncertainties and geopolitical tensions, including Russia’s invasion of Ukraine, and Covid-19); restrictions or costs imposed by climate change initiatives and the physical risks of climate change; risks associated with our ability to develop our properties and add reserves; the impact of an energy transition on demand for petroleum productions; changes in income tax or other laws or government incentive programs; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; the availability and cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; risks associated with large projects; costs to develop and operate our properties; public perception and its influence on the regulatory regime; current or future control, legislation or regulations; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; regulations regarding the disposal of fluids; risks associated with our hedging activities; the impact of elevated levels of inflation and government policies aimed at reducing them, such as increasing interest rates; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; additional risks associated with our thermal heavy oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; results of litigation; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks of counterparty default; the impact of Indigenous claims; risks associated with expansion into new activities; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for year ended December 31, 2022, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings. The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes. We have not risked potential drilling locations, and actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been identified. Factors affecting ultimate recovery include the scope of our on‐going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of reserves, type/decline curves, EURs, per‐well economics, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, internal rates of return disclosed in this presentation are calculated solely based on drilling and completion costs per well and lease operating expenses and do not include other costs such as land acquisition costs, general and administrative expenses, or other costs and expenses. Additionally, initial production rates are subject to decline over time and should not be reflective of sustained production levels.

23 Specified Financial Measures Advisory In this presentation, we refer to certain specified financial measures (such as free cash flow, operating netback, operating netback per boe, total debt, total debt to EBITDA ratio and asset level free cash flow break-even price) which do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”). While these measures are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. There are no significant differences in the calculations between historical and forward-looking specified financial measures. Non-GAAP Financial Measures Free cash flow Free cash flow referred to in this presentation is a forward-looking non-GAAP measure that is calculated consistently with the measures disclosed in the Company’s MD&A. The most directly comparable financial measure for free cash flow disclosed in the Company's primary financial statements is cash flow from operating activities. For the year-ended December 31, 2022, cash flow from operating activities and free cash flow were $1.1 billion and $621.5 million, respectively. For information on the composition of free cash flow and how the Company uses this measure, refer to the “Specified Financial Measures” section of the MD&A for the period ended December 31, 2022, which section is incorporated herein by reference, and available on SEDAR at www.sedar.com. Operating netback Operating netback and operating netback per boe referred to in this presentation are forward-looking non-GAAP financial measures and ratios that are calculated consistently with the measures disclosed in the Company’s MD&A. The most directly comparable financial measure for operating netback disclosed in the Company's primary financial statements is petroleum and natural gas sales. For the year-ended December 31, 2022, petroleum and natural gas sales and operating netback were $2.9 billion and $1.7 billion, respectively. For information on the composition of operating netback and operating netback per boe and how the Company uses these measures, refer to the “Specified Financial Measures” section of the MD&A for the period ended December 31, 2022, which section is incorporated herein by reference, and available on SEDAR at www.sedar.com. Total debt Total debt is used to assess the Company’s liquidity position at a point in time. Total debt is comprised of the credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs. The following table summarizes our calculation of total debt. 1) Unamortized debt issuance costs were obtained from Note 7 Credit Facilities and Note 8 Long-term Notes from the Consolidated Financial Statements for the year ended December 31, 2022. ($ millions) December 31, 2022 Credit facilities $383 Unamortized debt issuance costs – Credit facilities(1) 2 Long-term notes 548 Unamortized debt issuance costs – Long-term notes(1) 7 Total Debt $940

24 Specified Financial Measures Advisory (Cont.) Non-GAAP Financial Measures (Cont.) Cash costs Cash costs are used to monitor the Company's operating and transportation costs for an applicable period and is calculated by adding together operating and transportation expenses per the primary financial statements. The following table summarizes our calculation of cash costs Non-GAAP Financial Ratios Total debt to EBITDA ratio Total debt to EBITDA ratio is used to monitor future liquidity requirements and is calculated as total debt divided by EBITDA. EBITDA is calculated in accordance with the terms of the credit facilities agreement. Asset level free cash flow break-even price Asset level free cash flow break-even price represents the benchmark WTI price ($US/bbl) required to generate free cash flows equal to zero and is used by management to assess the financial flexibility for capital allocation. Cash costs per boe Cash costs per boe is calculated as operating and transportation expenses divided by barrels of oil equivalent production volume for the applicable period and is used to measure cost synergies on a per boe basis. ($ millions) December 31, 2022 Operating expense $423 Transportation expense 49 Cash costs $472

25 Capital Management Measures Advisory This presentation contains the terms "adjusted funds flow“ and "net debt”, which are capital management measures. We believe that the inclusion of these capital management measures provides useful information to financial statement users when evaluating the financial results of Baytex. Net debt and adjusted funds flow are calculated consistently with the measures disclosed in the Company’s MD&A. The most directly comparable financial measures for net debt and adjusted funds flow disclosed in the Company's primary financial statements are credit facilities and cash flow from operating activities, respectively. For the year-ended December 31, 2022, credit facilities and cash flow from operating activities were $383.0 million and $1.1 billion, respectively. For the year-ended December 31, 2022, net debt and adjusted funds flow were $987.4 million and $1.2 billion, respectively. For information on the composition of these measures and how the Company uses them, refer to the “Specified Financial Measures” section of the MD&A for the period ended December 31, 2022, which section is incorporated herein by reference, and available on SEDAR at www.sedar.com.

26 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. Complete NI 51-101 reserves disclosure for year-end 2021 is included in our Annual Information Form for the year ended December 31, 2021 which will be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission no later than March 31, 2022. 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 129 proved and 58 probable locations as at December 31, 2021 and 37 unbooked locations. In the Viking, Baytex’s net drilling locations include 936 proved and 222 probable locations as at December 31, 2021 and 490 unbooked locations. In Peace River (including Clearwater), Baytex’s net drilling locations include 61 proved and 37 probable locations as at December 31, 2021 and 334 unbooked locations. In Lloydminster, Baytex’s net drilling locations include 82 proved and 63 probable locations as at December 31, 2021 and 423 unbooked locations. In the Duvernay, Baytex’s net drilling locations include 17 proved and 12 probable locations as at December 31, 2021 and 231 unbooked locations. References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary. Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Notice to United States Readers The petroleum and natural gas reserves contained in this presentation have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" (as defined in SEC rules). Canadian securities laws require oil and gas issuers disclose their reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves". Additionally, NI 51-101 defines "proved reserves“ and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in this presentation may not be comparable to United States standards. Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments. Moreover, in this presentation future net revenue from its reserves has been determined and disclosed estimated using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. As a consequence of the foregoing, the reserve estimates and production volumes in this presentation may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

27 Important Information for Shareholders and Where to Find It No Offer or Solicitation This communication relates to the proposed merger transaction between Baytex Energy Corp. (“Baytex”) and Ranger Oil Corporation (“Ranger” and such transactions, collectively, the “Transaction”). This communication is not intended to and does not constitute an offer to sell or the solicitation of an offer to subscribe for or buy any securities or a solicitation of any vote or approval with respect to the Transaction or otherwise, nor shall there be any offer, solicitation or sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offer of securities in the United States shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933. Important Additional Information and Where to Find It In connection with the proposed Transaction, Baytex intends to file with the U.S. Securities and Exchange Commission (the “SEC”) a registration statement on Form F-4 (the “Registration Statement”) to register the Baytex securities to be issued in connection with the proposed Transaction (including a prospectus therefor). Baytex and Ranger also plan to file other documents with the SEC regarding the proposed Transaction. This communication is not a substitute for the Registration Statement or the prospectus or for any other document that Baytex or Ranger may file with the SEC in connection with the Transaction. U.S. INVESTORS AND U.S. HOLDERS OF BAYTEX AND RANGER SECURITIES ARE URGED TO READ THE REGISTRATION STATEMENT AND OTHER DOCUMENTS RELATING TO THE PROPOSED TRANSACTION (INCLUDING ALL AMENDMENTS AND SUPPLEMENTS TO THOSE DOCUMENTS) THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT BAYTEX, RANGER AND THE PROPOSED TRANSACTION. Shareholders will be able to obtain free copies of the Registration Statement, proxy statement/prospectus and other documents containing important information about Baytex and Ranger once such documents are filed with the SEC, through the website maintained by the SEC at http://www.sec.gov. Copies of such documents may also be obtained from Baytex and Ranger without charge. Participants in the Solicitation Baytex, Ranger and certain of their respective directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies from the Baytex's shareholders and the solicitation of proxies from Ranger's shareholders, in each case with respect to the Acquisition. Information about Baytex's directors and executive officers is available in the Annual Information Form published February 23, 2023 and in the proxy statement/prospectus (when available). Information about the Ranger's directors and executive officers is available in its definitive proxy statement for its 2022 annual meeting filed with the SEC on April 1, 2022, and in the proxy statement/prospectus (when available). Other information regarding the participants in the solicitations and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the Registration Statement, the proxy statement/prospectus and other relevant materials to be filed with the SEC regarding the Acquisitions when they become available. Shareholders, potential investors and other readers should read the proxy statement/prospectus carefully when it becomes available before making any voting or investment decisions.

Contact Information Eric T. Greager President and Chief Executive Officer Chad L. Kalmakoff Chief Financial Officer Chad E. Lundberg Chief Operating and Sustainability Officer 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 Toll Free 1.800.524.5521 www.baytexenergy.com