Exhibit 99.1 Magnolia Oil & Gas Corporation Investor Presentation – January 2019Exhibit 99.1 Magnolia Oil & Gas Corporation Investor Presentation – January 2019

Disclaimer FORWARD LOOKING STATEMENTS The information in this presentation and the oral statements made in connection therewith include “forward‐looking statements” within the  meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and  Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of present or historical fact  included in this presentation, regarding Magnolia Oil & Gas Corporation’s (“Magnolia,” “we,” “us,”  “our” or the “Company”) financial and production guidance, strategy, future operations, financial position, estimated revenues, and losses,  projected costs, prospects, plans and objectives of management are forward‐looking  statements. When used in this presentation, including any oral statements made in connection therewith, the words “could,” “should,”  “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” the negative of  such terms and other similar expressions are intended to identify forward‐looking statements, although not all forward‐looking statements contain  such identifying words. These forward‐looking statements are based on  management’s current expectations and assumptions about future events. Except as otherwise required by applicable law, Magnolia disclaims any duty  to update any forward‐looking statements, all of which are expressly qualified by  the statements in this section, to reflect events or circumstances after the date of this presentation. Magnolia cautions you that these forward‐looking statements are subject to all of the risks and uncertainties, most of which are  difficult to predict and many of which are beyond the control of Magnolia, incident to the development, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity  price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of  drilling and production equipment, supplies, services and qualified personnel, processing  volumes and pipeline throughput, and certificates related to new technologies, geographical concentration of operations, environmental risks, weather risks,  security risks, drilling and other operating risks, regulatory changes, the  uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, Magnolia’s ability to satisfy future cash obligations, restrictions in existing or  future debt agreements, the timing of development expenditures, managing growth and integration of acquisitions, failure to realize expected value  creation from property acquisitions, and the defects and limited control over non‐ operated properties. Should one or more of the risks or uncertainties described in this presentation and the oral statements made in  connection therewith occur, or should underlying assumptions prove incorrect, actual results and  plans could different materially from those expressed in any forward‐looking statements. Additional information concerning these and other factors that may impact Magnolia's operations and projections can be found in its filings  with the Securities and Exchange Commission (the  SEC ), including its Annual Report on Form 10‐K for the fiscal year ended December 31, 2017 and its definitive proxy statement regarding  filed with the SEC on July 2, 2018.  Magnolia’s SEC filings are available publicly on the SEC’s website at www.sec.gov.  PRO FORMA FINANCIAL INFORMATION The pro forma financial information set forth in this presentation gives pro forma effect to the EnerVest Business Combination as if it  occurred on January 1, 2017.  The Predecessor’s acquisition of the GulfTex assets on March 1, 2018  are included in the Company’s pro forma results.  Pro forma financial and operating data in this presentation is calculated in  accordance with Accounting Standards Codification (ASC) 805. NON‐GAAP FINANCIAL MEASURES This presentation includes non‐GAAP financial measures, including pro forma EBITDAX and adjusted operating margin. Magnolia believes these metrics  are useful because they allow Magnolia to more effectively evaluate its operating  performance and compare the results of its operations from period to period and against its peers without regard to financing methods or capital structure. Magnolia does not consider these non‐GAAP measures in isolation or as an  alternative to similar financial measures determined in accordance with GAAP. The computations of these non‐GAAP measures may not be comparable  to other similarly titled measures of other companies. Magnolia excludes certain items from net income in arriving at adjusted operating margin because these amounts can vary substantially from  company to company within its industry depending upon accounting methods, book values  of assets and the method by which the assets were acquired. Pro forma EBITDAX and adjusted operating margin should not be considered  as alternatives to, or more meaningful than, net income as determined in accordance with  GAAP.  Certain items excluded from pro forma EBITDAX and adjusted operating margin are significant components in understanding and assessing a  company’s financial performance, and should not be construed as an inference that  its results will be unaffected by unusual or non‐recurring terms.  In this presentation, we refer to adjusted operating margin per Boe and pro forma EBITDAX, both are supplemental non‐GAAP financial  measures that are used by management. We define adjusted operating margin per Boe as total  revenues per Boe less operating expenses per Boe adjusted for certain unusual or non‐recurring items per Boe that management does not  consider to be representative of the Company's on‐going business operations. We define pro  forma EBITDAX as pro forma net income before interest expense, income taxes, depreciation, depletion and amortization and accretion of asset  retirement obligations, and exploration costs. Management believes these metrics  provide relevant and useful information, which is used by management in assessing the Company’s profitability and comparability of results to  our peers. We believe pro forma EBIDTAX is an important supplemental measure of  operating performance for this period because it combines the operations of both the Karnes County and Giddings Field Assets and eliminates items that have less bearing on combined operating performance and so highlights trends  in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities  analysts, investors and other interested parties may use pro forma EBITDAX in the evaluation of  our Company. As performance measures, adjusted operating margin and pro forma EBITDAX may be useful to investors in facilitating comparisons to others in  the Company’s industry because certain items can vary substantially in the oil and gas  industry from company to company depending upon accounting methods, book value of assets, and capital structure, among other factors. Management  believes excluding these items facilitates investors and analysts in evaluating  and comparing the underlying operating and financial performance of our business from period to period by eliminating differences caused by the  existence and timing of certain expense and income items that would not otherwise be  apparent on a GAAP basis. However, our presentation of adjusted operating margin, adjusted operating margin per Boe, and pro forma EBITDAX  may not be comparable to similar measures of other companies in our industry. An  adjusted operating margin per Boe reconciliation is shown on page 15 of the presentation and an EBITDAX reconciliation is shown on page  25 of the presentation. INDUSTRY AND MARKET DATA This presentation has been prepared by Magnolia and includes market data and other statistical information from sources believed by Magnolia to be reliable, including independent industry publications, governmental publications or  other published independent sources. Some data is also based on the good faith estimates of Magnolia, which are derived from its review of internal sources as well as the independent sources described above. Although Magnolia  believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. 2Disclaimer FORWARD LOOKING STATEMENTS The information in this presentation and the oral statements made in connection therewith include “forward‐looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of present or historical fact included in this presentation, regarding Magnolia Oil & Gas Corporation’s (“Magnolia,” “we,” “us,” “our” or the “Company”) financial and production guidance, strategy, future operations, financial position, estimated revenues, and losses, projected costs, prospects, plans and objectives of management are forward‐looking statements. When used in this presentation, including any oral statements made in connection therewith, the words “could,” “should,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” the negative of such terms and other similar expressions are intended to identify forward‐looking statements, although not all forward‐looking statements contain such identifying words. These forward‐looking statements are based on management’s current expectations and assumptions about future events. Except as otherwise required by applicable law, Magnolia disclaims any duty to update any forward‐looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation. Magnolia cautions you that these forward‐looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the control of Magnolia, incident to the development, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, processing volumes and pipeline throughput, and certificates related to new technologies, geographical concentration of operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, Magnolia’s ability to satisfy future cash obligations, restrictions in existing or future debt agreements, the timing of development expenditures, managing growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, and the defects and limited control over non‐ operated properties. Should one or more of the risks or uncertainties described in this presentation and the oral statements made in connection therewith occur, or should underlying assumptions prove incorrect, actual results and plans could different materially from those expressed in any forward‐looking statements. Additional information concerning these and other factors that may impact Magnolia's operations and projections can be found in its filings with the Securities and Exchange Commission (the SEC ), including its Annual Report on Form 10‐K for the fiscal year ended December 31, 2017 and its definitive proxy statement regarding filed with the SEC on July 2, 2018. Magnolia’s SEC filings are available publicly on the SEC’s website at www.sec.gov. PRO FORMA FINANCIAL INFORMATION The pro forma financial information set forth in this presentation gives pro forma effect to the EnerVest Business Combination as if it occurred on January 1, 2017. The Predecessor’s acquisition of the GulfTex assets on March 1, 2018 are included in the Company’s pro forma results. Pro forma financial and operating data in this presentation is calculated in accordance with Accounting Standards Codification (ASC) 805. NON‐GAAP FINANCIAL MEASURES This presentation includes non‐GAAP financial measures, including pro forma EBITDAX and adjusted operating margin. Magnolia believes these metrics are useful because they allow Magnolia to more effectively evaluate its operating performance and compare the results of its operations from period to period and against its peers without regard to financing methods or capital structure. Magnolia does not consider these non‐GAAP measures in isolation or as an alternative to similar financial measures determined in accordance with GAAP. The computations of these non‐GAAP measures may not be comparable to other similarly titled measures of other companies. Magnolia excludes certain items from net income in arriving at adjusted operating margin because these amounts can vary substantially from company to company within its industry depending upon accounting methods, book values of assets and the method by which the assets were acquired. Pro forma EBITDAX and adjusted operating margin should not be considered as alternatives to, or more meaningful than, net income as determined in accordance with GAAP. Certain items excluded from pro forma EBITDAX and adjusted operating margin are significant components in understanding and assessing a company’s financial performance, and should not be construed as an inference that its results will be unaffected by unusual or non‐recurring terms. In this presentation, we refer to adjusted operating margin per Boe and pro forma EBITDAX, both are supplemental non‐GAAP financial measures that are used by management. We define adjusted operating margin per Boe as total revenues per Boe less operating expenses per Boe adjusted for certain unusual or non‐recurring items per Boe that management does not consider to be representative of the Company's on‐going business operations. We define pro forma EBITDAX as pro forma net income before interest expense, income taxes, depreciation, depletion and amortization and accretion of asset retirement obligations, and exploration costs. Management believes these metrics provide relevant and useful information, which is used by management in assessing the Company’s profitability and comparability of results to our peers. We believe pro forma EBIDTAX is an important supplemental measure of operating performance for this period because it combines the operations of both the Karnes County and Giddings Field Assets and eliminates items that have less bearing on combined operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties may use pro forma EBITDAX in the evaluation of our Company. As performance measures, adjusted operating margin and pro forma EBITDAX may be useful to investors in facilitating comparisons to others in the Company’s industry because certain items can vary substantially in the oil and gas industry from company to company depending upon accounting methods, book value of assets, and capital structure, among other factors. Management believes excluding these items facilitates investors and analysts in evaluating and comparing the underlying operating and financial performance of our business from period to period by eliminating differences caused by the existence and timing of certain expense and income items that would not otherwise be apparent on a GAAP basis. However, our presentation of adjusted operating margin, adjusted operating margin per Boe, and pro forma EBITDAX may not be comparable to similar measures of other companies in our industry. An adjusted operating margin per Boe reconciliation is shown on page 15 of the presentation and an EBITDAX reconciliation is shown on page 25 of the presentation. INDUSTRY AND MARKET DATA This presentation has been prepared by Magnolia and includes market data and other statistical information from sources believed by Magnolia to be reliable, including independent industry publications, governmental publications or other published independent sources. Some data is also based on the good faith estimates of Magnolia, which are derived from its review of internal sources as well as the independent sources described above. Although Magnolia believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. 2

Magnolia Oil & Gas – Overview ~475,000 Net Acre Position Targeting Two of the Top  • High‐quality, low‐risk pure‐play South Texas operator with a core  Eagle Ford and Austin Chalk position acquired at an attractive entry  Oil Plays in the U.S. multiple • Significant scale and PDP base generates material free cash flow,  Giddings Field reduces development risk and increases optionality • Asset Overview: – ~16,500 net acres in a well‐delineated, low‐risk position in the  core of Karnes County, representing some of the most prolific  acreage in the United States with industry leading breakevens – ~460,000 net acres in the Giddings Field, a re‐emerging oil play  with significant upside and substantial running room for  development Karnes County – Both assets expected to remain self funding and within cash flow Market Statistics Trading Symbol (NYSE) MGY Share Price as of 1/2/2019 $11.29 (1) Common Shares Outstanding  249.7 million Source: IHS Performance Evaluator. Market Capitalization $2.8 billion Industry Leading Breakevens ($/Bbl WTI) Long‐term Debt ‐ Principal $400 million (2) $45  Total Enterprise Value  $3.2 billion $39  $39  $38  $35  $34  $32  $28  Operating Statistics Karnes Giddings Total Net Acreage 16,454 458,989 475,443 Karnes Austin Karnes Lower Midland Delaware DJ Basin Eagle Ford STACK Bakken Pro Forma Q3 Net Production (Mboe/d)  41.4 13.8 55.2 Chalk Eagle Ford Source: RSEG. (1) Common Stock outstanding includes Class A and Class B Stock and does not give effect to the exercise of any warrants. (2) Total enterprise value does not include noncontrolling interest due to inclusion of Class B Stock in the market capitalization. 3Magnolia Oil & Gas – Overview ~475,000 Net Acre Position Targeting Two of the Top • High‐quality, low‐risk pure‐play South Texas operator with a core Eagle Ford and Austin Chalk position acquired at an attractive entry Oil Plays in the U.S. multiple • Significant scale and PDP base generates material free cash flow, Giddings Field reduces development risk and increases optionality • Asset Overview: – ~16,500 net acres in a well‐delineated, low‐risk position in the core of Karnes County, representing some of the most prolific acreage in the United States with industry leading breakevens – ~460,000 net acres in the Giddings Field, a re‐emerging oil play with significant upside and substantial running room for development Karnes County – Both assets expected to remain self funding and within cash flow Market Statistics Trading Symbol (NYSE) MGY Share Price as of 1/2/2019 $11.29 (1) Common Shares Outstanding 249.7 million Source: IHS Performance Evaluator. Market Capitalization $2.8 billion Industry Leading Breakevens ($/Bbl WTI) Long‐term Debt ‐ Principal $400 million (2) $45 Total Enterprise Value $3.2 billion $39 $39 $38 $35 $34 $32 $28 Operating Statistics Karnes Giddings Total Net Acreage 16,454 458,989 475,443 Karnes Austin Karnes Lower Midland Delaware DJ Basin Eagle Ford STACK Bakken Pro Forma Q3 Net Production (Mboe/d) 41.4 13.8 55.2 Chalk Eagle Ford Source: RSEG. (1) Common Stock outstanding includes Class A and Class B Stock and does not give effect to the exercise of any warrants. (2) Total enterprise value does not include noncontrolling interest due to inclusion of Class B Stock in the market capitalization. 3

Corporate Execution of Business Model and Strategy (1) Magnolia Value Creation Strategy YTD and Q3 Achievements  Organic production growth of 7% Q/Q and  1 Consistent organic production growth 59% YoY (excludes Harvest acquisition) 2 High full‐cycle operating margins Continue to target full cycle margins of 50% $400 million of principal debt outstanding,  3 Conservative leverage profile representing ~0.5x third quarter  annualized pro forma EBITDAX YTD D&C capex at 50% of EBITDAX,  Significant free cash flow after capital  4 providing significant free cash flow with  expenditures moderate organic growth  Q3 Harvest acquisition accretive to  5 Effective reinvestment of free cash flow Magnolia value per share (1) YTD represents 9 months ended 9/30/2018. 4Corporate Execution of Business Model and Strategy (1) Magnolia Value Creation Strategy YTD and Q3 Achievements Organic production growth of 7% Q/Q and 1 Consistent organic production growth 59% YoY (excludes Harvest acquisition) 2 High full‐cycle operating margins Continue to target full cycle margins of 50% $400 million of principal debt outstanding, 3 Conservative leverage profile representing ~0.5x third quarter annualized pro forma EBITDAX YTD D&C capex at 50% of EBITDAX, Significant free cash flow after capital 4 providing significant free cash flow with expenditures moderate organic growth Q3 Harvest acquisition accretive to 5 Effective reinvestment of free cash flow Magnolia value per share (1) YTD represents 9 months ended 9/30/2018. 4

Magnolia Oil & Gas – Free Cash Flow Model • Our objective is to manage the business to generate meaningful free cash flow while providing moderate production  growth • D&C capex spend is planned within 60% of EBITDAX, irrespective of commodity price ‒ Year to date, we have invested ~50% of our EBITDAX on D&C operations • Discretionary cash flow will be used for: ‒ Accretive bolt‐on acquisitions ‒ Debt reduction ‒ Share repurchases (2) D&C Capex vs Pro Forma  EBITDAX ($MM)  $216  $179  $159  $112  $91  $82  (1) (1) Q1 2018 Q2 2018 Q3 2018 D&C Capex Pro forma EBITDAX (1) Q1 and Q2 represent revenue less direct expense less estimated G&A expense of $201 million, $32 million and $10.6 million for the three months ended March 31,  2018 and $229 million, $40 million and $10.6 million for the three months ended June 30, 2018. 5 (2) EBITDAX is a non‐GAAP measure. See the Appendix for Non‐GAAP reconciliation.Magnolia Oil & Gas – Free Cash Flow Model • Our objective is to manage the business to generate meaningful free cash flow while providing moderate production growth • D&C capex spend is planned within 60% of EBITDAX, irrespective of commodity price ‒ Year to date, we have invested ~50% of our EBITDAX on D&C operations • Discretionary cash flow will be used for: ‒ Accretive bolt‐on acquisitions ‒ Debt reduction ‒ Share repurchases (2) D&C Capex vs Pro Forma EBITDAX ($MM) $216 $179 $159 $112 $91 $82 (1) (1) Q1 2018 Q2 2018 Q3 2018 D&C Capex Pro forma EBITDAX (1) Q1 and Q2 represent revenue less direct expense less estimated G&A expense of $201 million, $32 million and $10.6 million for the three months ended March 31, 2018 and $229 million, $40 million and $10.6 million for the three months ended June 30, 2018. 5 (2) EBITDAX is a non‐GAAP measure. See the Appendix for Non‐GAAP reconciliation.

Q3 Financials Adjusted for Current Price Environment Q3 2018 Pro Forma Actuals Q3 2018 @ Current Pricing Adjusting only the commodity prices  from the Q3 2018 Pro Forma Actuals to  Net Production reflect the current price environment  Oil (Mbopd) 32.8 32.8 still results in positive net income and  Gas (MMcfpd) 76.5 76.5 free cash flow. NGLs (Mbopd) 9.6 9.6 Daily (Mboepd) 55.2 55.2 Commodity Price Deck WTI ($ / bbl) $69.02 $45.00 Henry Hub ($ / MMBtu) $2.86 $3.00 Realized Pricing We expect every $1 / Bbl change in  Oil ($ / bbl) $72.55 $48.53 oil pricing to result in a $12 million  Gas ($ / Mcf) $2.88 $3.02 change in annualized oil revenue NGL ($ / bbl) $32.15 $20.96 Cash Flows ($MM) Oil Revenue 219.0 146.5 We expect every $0.10 / Mcf change  Gas Revenue 20.3 21.3 in gas pricing to result in a $3 million  NGL Revenue 28.5 18.6 change in annualized gas revenue Total Revenue $267.7 $186.3 (1) Total Cash Operating Expenses (51.4) (47.7) (2) EBITDAX $216.3 $138.6 Book DD&A (90.8) (90.8) Other (0.9) (0.9) EBIT $124.6 $46.9 Net Income $101.0 $34.0 Capital Expenditures (113.4) (113.4) EBITDAX Less Capex $102.9 $25.2 Annualized EBITDAX $865.2 $554.4 (1) The change in Total Cash Operating Expenses is entirely attributable to production taxes as a result of the change in the commodity  prices from $69.02 and $2.86 to  $45.00 and $3.00.  6 (2) EBITDAX is a non‐GAAP measure. See the Appendix for Non‐GAAP reconciliation.Q3 Financials Adjusted for Current Price Environment Q3 2018 Pro Forma Actuals Q3 2018 @ Current Pricing Adjusting only the commodity prices from the Q3 2018 Pro Forma Actuals to Net Production reflect the current price environment Oil (Mbopd) 32.8 32.8 still results in positive net income and Gas (MMcfpd) 76.5 76.5 free cash flow. NGLs (Mbopd) 9.6 9.6 Daily (Mboepd) 55.2 55.2 Commodity Price Deck WTI ($ / bbl) $69.02 $45.00 Henry Hub ($ / MMBtu) $2.86 $3.00 Realized Pricing We expect every $1 / Bbl change in Oil ($ / bbl) $72.55 $48.53 oil pricing to result in a $12 million Gas ($ / Mcf) $2.88 $3.02 change in annualized oil revenue NGL ($ / bbl) $32.15 $20.96 Cash Flows ($MM) Oil Revenue 219.0 146.5 We expect every $0.10 / Mcf change Gas Revenue 20.3 21.3 in gas pricing to result in a $3 million NGL Revenue 28.5 18.6 change in annualized gas revenue Total Revenue $267.7 $186.3 (1) Total Cash Operating Expenses (51.4) (47.7) (2) EBITDAX $216.3 $138.6 Book DD&A (90.8) (90.8) Other (0.9) (0.9) EBIT $124.6 $46.9 Net Income $101.0 $34.0 Capital Expenditures (113.4) (113.4) EBITDAX Less Capex $102.9 $25.2 Annualized EBITDAX $865.2 $554.4 (1) The change in Total Cash Operating Expenses is entirely attributable to production taxes as a result of the change in the commodity prices from $69.02 and $2.86 to $45.00 and $3.00. 6 (2) EBITDAX is a non‐GAAP measure. See the Appendix for Non‐GAAP reconciliation.

Asset OverviewAsset Overview

Karnes County – Core Eagle Ford and Austin Chalk Key Asset Highlights Premier Position in the Core of the Eagle Ford • World‐class acreage footprint located in the core of the  Eagle Ford, substantially de‐risked ‒ 16,454 net acres (31,043 gross acres), 69% operated,  90% HBP, 41.4 Mboe/d Q3 2018 production (69% oil,  84% liquids) ‒ EOG represents ~85% of non‐operated activity • Steady production growth while generating substantial free  cash flow ‒ Full field development allows for operational efficiencies  and improved performance • Well known, repeatable acreage position targeting multiple  benches and represents some of the best economics in  Source: IHS Performance Evaluator. North America (1) Industry Leading Breakevens ($/Bbl WTI) ‒ Breakevens between $28 ‐ $32 per barrel  $45  ‒ Magnolia Eagle Ford Type Curve IP30/IP90: 400/285  $39  $39  $38  $34  $35  $32  $28  boe/d / 1,000’ LL (88/85% Oil) ‒ Magnolia Austin Chalk Type Curve IP30/IP90: 465/400  Karnes Austin Karnes Lower Midland Delaware DJ Basin Eagle Ford STACK Bakken boe/d / 1,000’ LL (80/77% Oil) Chalk Eagle Ford Source: RSEG. (1) Source: RSEG 8Karnes County – Core Eagle Ford and Austin Chalk Key Asset Highlights Premier Position in the Core of the Eagle Ford • World‐class acreage footprint located in the core of the Eagle Ford, substantially de‐risked ‒ 16,454 net acres (31,043 gross acres), 69% operated, 90% HBP, 41.4 Mboe/d Q3 2018 production (69% oil, 84% liquids) ‒ EOG represents ~85% of non‐operated activity • Steady production growth while generating substantial free cash flow ‒ Full field development allows for operational efficiencies and improved performance • Well known, repeatable acreage position targeting multiple benches and represents some of the best economics in Source: IHS Performance Evaluator. North America (1) Industry Leading Breakevens ($/Bbl WTI) ‒ Breakevens between $28 ‐ $32 per barrel $45 ‒ Magnolia Eagle Ford Type Curve IP30/IP90: 400/285 $39 $39 $38 $34 $35 $32 $28 boe/d / 1,000’ LL (88/85% Oil) ‒ Magnolia Austin Chalk Type Curve IP30/IP90: 465/400 Karnes Austin Karnes Lower Midland Delaware DJ Basin Eagle Ford STACK Bakken boe/d / 1,000’ LL (80/77% Oil) Chalk Eagle Ford Source: RSEG. (1) Source: RSEG 8

Located in an Attractive Neighborhood BP Core position in Karnes County Oil Window adjacent to EOG and Marathon with $28 to $32/barrel  (1) breakevens and less than 1‐year new well paybacks (1) Source: RSEG 9Located in an Attractive Neighborhood BP Core position in Karnes County Oil Window adjacent to EOG and Marathon with $28 to $32/barrel (1) breakevens and less than 1‐year new well paybacks (1) Source: RSEG 9

Karnes County Results Show Superior Economics • Results in Karnes County are some the best in North America • Karnes Eagle Ford and Austin Chalk type curves produce 216,000 and 332,000 barrels of oil, respectively, in their first 12 months of  production supporting paybacks in less than 6 months (2) • Liquids heavy commodity mix with Eagle Ford wells producing 74% oil (86% liquids) and Austin Chalk wells producing 63% oil (80%  (2) liquids) …with significant early cumulative  Karnes has some of the highest U.S. IPs… …resulting in best in class paybacks production… 3,000 800 $15 2,500 $10 600 5‐Month  (3) Payout 2,000 $5 1,500 400 6‐Month  (3) Payout $0 1,000 10 200 (2) (2) Oil Liquids ($5) 19‐Month  500 MGY LEF 74% 86% (3) Payout MGY AC 63% 80% RSEG WC 46% 73% 0 0 ($10) 0 4 8 12 16 20 24 0 4 8 12 16 20 24 0 4 8 121620 24 Months Months Months (1) MGY Lower EF MGY Austin Chalk RSEG Delaware Wolfcamp Note: Magnolia type curves normalized to 5,000’ laterals. Projections based on flat $58 WTI and $2.75 Henry Hub pricing.  (1) Source: RSEG, Delaware North Reeves Wolfcamp A curve. 10 (2) Commodity percentage splits represent first 24 months of production. (3) All payout figures include assumed 2‐month spud to sales delay. Daily Production (Boe/d) Cum. Production (Mboe) Cum. Cash Flow ($MM)Karnes County Results Show Superior Economics • Results in Karnes County are some the best in North America • Karnes Eagle Ford and Austin Chalk type curves produce 216,000 and 332,000 barrels of oil, respectively, in their first 12 months of production supporting paybacks in less than 6 months (2) • Liquids heavy commodity mix with Eagle Ford wells producing 74% oil (86% liquids) and Austin Chalk wells producing 63% oil (80% (2) liquids) …with significant early cumulative Karnes has some of the highest U.S. IPs… …resulting in best in class paybacks production… 3,000 800 $15 2,500 $10 600 5‐Month (3) Payout 2,000 $5 1,500 400 6‐Month (3) Payout $0 1,000 10 200 (2) (2) Oil Liquids ($5) 19‐Month 500 MGY LEF 74% 86% (3) Payout MGY AC 63% 80% RSEG WC 46% 73% 0 0 ($10) 0 4 8 12 16 20 24 0 4 8 12 16 20 24 0 4 8 121620 24 Months Months Months (1) MGY Lower EF MGY Austin Chalk RSEG Delaware Wolfcamp Note: Magnolia type curves normalized to 5,000’ laterals. Projections based on flat $58 WTI and $2.75 Henry Hub pricing. (1) Source: RSEG, Delaware North Reeves Wolfcamp A curve. 10 (2) Commodity percentage splits represent first 24 months of production. (3) All payout figures include assumed 2‐month spud to sales delay. Daily Production (Boe/d) Cum. Production (Mboe) Cum. Cash Flow ($MM)

Giddings Field – Redeveloping as an Emerging Play Giddings Asset Overview Lease Map • Emerging, high‐growth asset with extensive inventory potential  and significant development flexibility  ‒ ~458,989 net acres, 99%+ HBP and ~87% operated, 13.8  Mboe/d Q3 2018 production (30% oil, 57% liquids) • HBP nature of asset allows for systematic delineation and  optimization of play while staying within asset cash flow 4 • Modern high‐intensity completions have resulted in a step‐ 5 1 2 change improvement in well performance 3 ‒ The first four wells have had average IP30s of 1,596 boe/d  and average IP90s of 1,827 boe/d • At least 1,000 locations based on conservative spacing  8 6 assumptions 9 7 (1)  (2) Actual Well Payouts  (Months) Selected Recent Well Results  WELL NAM E OPERATOR FIRST PROD LAT LENGTH IP30 (BOE/ D) % OIL IP30/ 1,00 0 1 Winkelman 1H WILDHORSE Q4 2017 4,765 1,863 32% 391 9 8 2 Broussard-Liebscher 1H M AGNOLIA Q1 2018 5,243 1,776 57% 339 3 Lili M arlene 2H M AGNOLIA Q1 2018 5,355 1,789 66% 334 4 Neva 2 MAGNOLIA Q3 2017 4,715 1,439 31% 305 4 4 McMahan 2 MAGNOLIA Q4 2017 4,774 1,381 33% 293 5 6 Breitkruez 1H GEOSOUTHERN Q4 2017 5,604 765 71% 137 7 Freis 1H GEOSOUTHERN Q1 2018 5,940 781 61% 132 8 Kristoff 1H GEOSOUTHERN Q4 2017 6,084 603 57% 99 Lili Marlene 2H Broussard-Liebscher McMahan 2 Neva 2 9 Loughnane 1H GEOSOUTHERN Q2 2017 5,646 463 68% 82 1H With significant scale and HBP position, Giddings offers a unique opportunity to develop an emerging play while  remaining within cash flow (1) Payout from first production. (2) Recent Giddings area Austin Chalk well results with >30% oil cut. 11Giddings Field – Redeveloping as an Emerging Play Giddings Asset Overview Lease Map • Emerging, high‐growth asset with extensive inventory potential and significant development flexibility ‒ ~458,989 net acres, 99%+ HBP and ~87% operated, 13.8 Mboe/d Q3 2018 production (30% oil, 57% liquids) • HBP nature of asset allows for systematic delineation and optimization of play while staying within asset cash flow 4 • Modern high‐intensity completions have resulted in a step‐ 5 1 2 change improvement in well performance 3 ‒ The first four wells have had average IP30s of 1,596 boe/d and average IP90s of 1,827 boe/d • At least 1,000 locations based on conservative spacing 8 6 assumptions 9 7 (1) (2) Actual Well Payouts (Months) Selected Recent Well Results WELL NAM E OPERATOR FIRST PROD LAT LENGTH IP30 (BOE/ D) % OIL IP30/ 1,00 0 1 Winkelman 1H WILDHORSE Q4 2017 4,765 1,863 32% 391 9 8 2 Broussard-Liebscher 1H M AGNOLIA Q1 2018 5,243 1,776 57% 339 3 Lili M arlene 2H M AGNOLIA Q1 2018 5,355 1,789 66% 334 4 Neva 2 MAGNOLIA Q3 2017 4,715 1,439 31% 305 4 4 McMahan 2 MAGNOLIA Q4 2017 4,774 1,381 33% 293 5 6 Breitkruez 1H GEOSOUTHERN Q4 2017 5,604 765 71% 137 7 Freis 1H GEOSOUTHERN Q1 2018 5,940 781 61% 132 8 Kristoff 1H GEOSOUTHERN Q4 2017 6,084 603 57% 99 Lili Marlene 2H Broussard-Liebscher McMahan 2 Neva 2 9 Loughnane 1H GEOSOUTHERN Q2 2017 5,646 463 68% 82 1H With significant scale and HBP position, Giddings offers a unique opportunity to develop an emerging play while remaining within cash flow (1) Payout from first production. (2) Recent Giddings area Austin Chalk well results with >30% oil cut. 11

Financial OverviewFinancial Overview

Magnolia Oil & Gas – Financial Policy Capital Spending Plan Targeted at 50 ‐ Conservative Financial Statements with  60% of annual EBITDAX Low Financial Leverage  (Plan expected to deliver 10%+ of annual  production growth and consistently generate  (<= 1.0x EBITDAX) free cash flow) Acquisitions generally expected to be  smaller bolt‐ons in the vicinity of  No Commodity Hedging current assets and with similar financial  characteristics Return‐focused, long‐term value creation through execution on (i) debt reduction,  (ii) accretive bolt‐on acquisitions, and (iii) share repurchases. 13Magnolia Oil & Gas – Financial Policy Capital Spending Plan Targeted at 50 ‐ Conservative Financial Statements with 60% of annual EBITDAX Low Financial Leverage (Plan expected to deliver 10%+ of annual production growth and consistently generate (<= 1.0x EBITDAX) free cash flow) Acquisitions generally expected to be smaller bolt‐ons in the vicinity of No Commodity Hedging current assets and with similar financial characteristics Return‐focused, long‐term value creation through execution on (i) debt reduction, (ii) accretive bolt‐on acquisitions, and (iii) share repurchases. 13

Business Risks Adequately Managed Level of Risk Generally Acceptable to Magnolia Low Fully Exposed Risk Factor Moderate Geologic/Exploratory Political Cost Risk Reinvestment Commodity Financial 14Business Risks Adequately Managed Level of Risk Generally Acceptable to Magnolia Low Fully Exposed Risk Factor Moderate Geologic/Exploratory Political Cost Risk Reinvestment Commodity Financial 14

Magnolia Oil & Gas – Focus on High Margins Successor $ / Boe, unless otherwise noted July 31, 2018 through September 30, 2018 Revenue ($MM) $179  Revenue $50.93  Less: Lease Operating Expenses (3.14) Less: Gathering, Transportation & Processing (1.64) Less: Taxes Other Than Income (2.67) Less: Exploration Expense (3.20) Less: G&A (2.94) Less: Transaction Related Expense (6.38) Cash Operating Margin $30.96  Margin % 61% Less: Depreciation, Depletion, and Amortization (19.25) Less: Asset Retirement Obligations Accretion (0.11) Operating Margin  $11.60  Margin % 23% Plus: Exploration Expense Related to Seismic License Continuation 3.14  Plus: Transaction Related Expense 6.38  (1) Adjusted Operating Margin  $21.12  Margin % 41% (1) Adjusted Operating Margin is a non‐GAAP measure. For reasons management believes this is useful to investors, refer to slide 2  “Non‐GAAP Reconciliations.” 15Magnolia Oil & Gas – Focus on High Margins Successor $ / Boe, unless otherwise noted July 31, 2018 through September 30, 2018 Revenue ($MM) $179 Revenue $50.93 Less: Lease Operating Expenses (3.14) Less: Gathering, Transportation & Processing (1.64) Less: Taxes Other Than Income (2.67) Less: Exploration Expense (3.20) Less: G&A (2.94) Less: Transaction Related Expense (6.38) Cash Operating Margin $30.96 Margin % 61% Less: Depreciation, Depletion, and Amortization (19.25) Less: Asset Retirement Obligations Accretion (0.11) Operating Margin $11.60 Margin % 23% Plus: Exploration Expense Related to Seismic License Continuation 3.14 Plus: Transaction Related Expense 6.38 (1) Adjusted Operating Margin $21.12 Margin % 41% (1) Adjusted Operating Margin is a non‐GAAP measure. For reasons management believes this is useful to investors, refer to slide 2 “Non‐GAAP Reconciliations.” 15

Q3 2018 Capital Structure and Liquidity Overview Capital Structure Overview Capitalization & Liquidity ($MM) • Maintaining low financial leverage profile Capitalization Summary As of 9/30/2018 ‒ Net Debt / Total Book Capitalization of 12% Cash and Cash Equivalents $37  ‒ Net Debt / Q3 annualized EBITDAX of 0.4x Revolving Credit Facility $0  (1) • Liquidity as of 9/30/2018 of $587MM, including fully undrawn credit facility  6.00% Senior Notes Due 2026 ‐ Principal $400  • No debt maturities until 2026 Senior Unsecured Notes Total Debt Outstanding $400  Debt Maturity Schedule ($MM) (2) Total Shareholder's Equity  $2,643  $550 6.00% Senior  Net Debt / Q3 Annualized EBITDAX 0.4x Borrowing  Unsecured  Base Notes Net Debt / Total Book Capitalization 12% $400 Liquidity Summary As of 9/30/2018 Cash and Cash Equivalents $37  Credit Facility  Borrowings  Credit Facility Availability $550  (as of 9/30/18) $0 (1) Liquidity  $587  2018 2019 2020 2021 2022 2023 2024 2025 2026 (1) Liquidity defined as cash and cash equivalents plus availability on revolving credit facility. (2) Total Shareholders’ Equity includes noncontrolling interest.  16Q3 2018 Capital Structure and Liquidity Overview Capital Structure Overview Capitalization & Liquidity ($MM) • Maintaining low financial leverage profile Capitalization Summary As of 9/30/2018 ‒ Net Debt / Total Book Capitalization of 12% Cash and Cash Equivalents $37 ‒ Net Debt / Q3 annualized EBITDAX of 0.4x Revolving Credit Facility $0 (1) • Liquidity as of 9/30/2018 of $587MM, including fully undrawn credit facility 6.00% Senior Notes Due 2026 ‐ Principal $400 • No debt maturities until 2026 Senior Unsecured Notes Total Debt Outstanding $400 Debt Maturity Schedule ($MM) (2) Total Shareholder's Equity $2,643 $550 6.00% Senior Net Debt / Q3 Annualized EBITDAX 0.4x Borrowing Unsecured Base Notes Net Debt / Total Book Capitalization 12% $400 Liquidity Summary As of 9/30/2018 Cash and Cash Equivalents $37 Credit Facility Borrowings Credit Facility Availability $550 (as of 9/30/18) $0 (1) Liquidity $587 2018 2019 2020 2021 2022 2023 2024 2025 2026 (1) Liquidity defined as cash and cash equivalents plus availability on revolving credit facility. (2) Total Shareholders’ Equity includes noncontrolling interest. 16

Cash Flow Priorities to Maximize Shareholder Returns Accretive  Bolt‐On  Acquisitions Debt  Share  Reduction Repurchases Return‐ focused  Value  Creation With a targeted goal of always being free cash flow positive, Magnolia intends to be a prudent  steward of shareholder’s capital 17Cash Flow Priorities to Maximize Shareholder Returns Accretive Bolt‐On Acquisitions Debt Share Reduction Repurchases Return‐ focused Value Creation With a targeted goal of always being free cash flow positive, Magnolia intends to be a prudent steward of shareholder’s capital 17

Summary Investment Highlights High Quality Assets Positioned for Success (1) • Coveted position in core of Karnes County with industry leading breakevens between $28 - $32 per barrel • Emerging position in the Giddings Field with results that continue to improve and substantial running room Positive Free Cash Flow and Peer Leading Margins • One of the select upstream independents generating substantial free cash flow after capital expenditures • Peer leading free cash flow yield at a wide range of commodity prices Multiple Levers of Growth • Steady organic growth through proven drilling program while remaining well within cash flow • Clean balance sheet and strong free cash flow enables Magnolia to pursue accretive acquisitions Strong Balance Sheet, Financial Flexibility & Conservative Financial Policy (2) • Conservative leverage profile with only $400 million of principal total debt outstanding (2) • Substantial liquidity of $587 million (1) Source: RSEG. (2) Debt and liquidity as of 9/30/2018. 18Summary Investment Highlights High Quality Assets Positioned for Success (1) • Coveted position in core of Karnes County with industry leading breakevens between $28 - $32 per barrel • Emerging position in the Giddings Field with results that continue to improve and substantial running room Positive Free Cash Flow and Peer Leading Margins • One of the select upstream independents generating substantial free cash flow after capital expenditures • Peer leading free cash flow yield at a wide range of commodity prices Multiple Levers of Growth • Steady organic growth through proven drilling program while remaining well within cash flow • Clean balance sheet and strong free cash flow enables Magnolia to pursue accretive acquisitions Strong Balance Sheet, Financial Flexibility & Conservative Financial Policy (2) • Conservative leverage profile with only $400 million of principal total debt outstanding (2) • Substantial liquidity of $587 million (1) Source: RSEG. (2) Debt and liquidity as of 9/30/2018. 18

AppendixAppendix

Magnolia Oil & Gas – Q3 2018 Key Metrics Q3 2018 Earnings Q3 2018 Pro Forma Total Production  Q4 2018 Estimated Production $6.7 Million (GAAP) 55.2 Mboe/d 59 Mboe/d $58 Million (Pro Forma) (1) (1) Q3 2018 Pro Forma D&C Capex Q3 2018 Pro Forma EBITDAX  Adjusted Operating Margin ($/Boe, %)  $21.12 / 41% $216 Million $112 Million (1) Adjusted operating margin and pro forma EBITDAX are non‐GAAP measures. Adjusted operating margin based on Successor period only. 20Magnolia Oil & Gas – Q3 2018 Key Metrics Q3 2018 Earnings Q3 2018 Pro Forma Total Production Q4 2018 Estimated Production $6.7 Million (GAAP) 55.2 Mboe/d 59 Mboe/d $58 Million (Pro Forma) (1) (1) Q3 2018 Pro Forma D&C Capex Q3 2018 Pro Forma EBITDAX Adjusted Operating Margin ($/Boe, %) $21.12 / 41% $216 Million $112 Million (1) Adjusted operating margin and pro forma EBITDAX are non‐GAAP measures. Adjusted operating margin based on Successor period only. 20

Revised Production Guidance Original 2018 Production Guidance Revised 2018 Production Guidance 45.6 Mboe/d 50.0 Mboe/d Transaction Announcement – 3/20/2018 Q2 Earnings Release – 8/14/2018 10% Increase over Original Further Revised 2018 Production Guidance Q4 2018 Production Guidance 53.0 Mboe/d 59.0 Mboe/d Q3 Earnings Release – 11/13/2018 Q3 Earnings Release – 11/13/2018 16% Increase over Original 7% Sequential Growth 6% Increase over Revised 21Revised Production Guidance Original 2018 Production Guidance Revised 2018 Production Guidance 45.6 Mboe/d 50.0 Mboe/d Transaction Announcement – 3/20/2018 Q2 Earnings Release – 8/14/2018 10% Increase over Original Further Revised 2018 Production Guidance Q4 2018 Production Guidance 53.0 Mboe/d 59.0 Mboe/d Q3 Earnings Release – 11/13/2018 Q3 Earnings Release – 11/13/2018 16% Increase over Original 7% Sequential Growth 6% Increase over Revised 21

Harvest Acquisition Overview st • On August 31 , closed acquisition of substantially all of the South Texas Assets of Harvest Oil & Gas Corporation for  ~$193 million in cash and stock ‒ Transaction consideration of $133 million cash and 4.2MM newly issues shares of Magnolia ‒ Cash consideration funded by cash on balance sheet and free cash flow generated by the business ‒ Transaction effective date of July 1, 2018 • Acquisition Adds: ‒ Undivided working interest across a portion of our existing Karnes County assets and all of our Giddings Field assets ‒ Approximately 114,000 net acres to our Giddings Field position ‒ Approximately 15 net undrilled locations to our core Karnes County inventory ‒ Pro forma, Magnolia holds over 470,000 net acres in the Eagle Ford • Harvest South Texas Assets 1H 2018 Results: ‒ Produced approximately 4,800 boe/d with 1,400 boe/d in Karnes County (69% oil, 83% liquids) and 3,400 boe/d in  Giddings Field (27% oil, 53% liquids) ‒ Generated revenues less direct operating expenses of approximately $25 million ‒ Incurred capital expenditures of approximately $13 million • Magnolia acquisition strategy: ‒ Continue to evaluate M&A opportunities that are consistent with existing business model – high margin, free cash  flow positive assets acquired at accretive cash flow multiples with meaningful upside ‒ Karnes acquisitions likely to be bolt‐on/tuck‐in acquisitions surrounding current high quality inventory ‒ Giddings acquisitions likely to focus on undrilled lease opportunities 22Harvest Acquisition Overview st • On August 31 , closed acquisition of substantially all of the South Texas Assets of Harvest Oil & Gas Corporation for ~$193 million in cash and stock ‒ Transaction consideration of $133 million cash and 4.2MM newly issues shares of Magnolia ‒ Cash consideration funded by cash on balance sheet and free cash flow generated by the business ‒ Transaction effective date of July 1, 2018 • Acquisition Adds: ‒ Undivided working interest across a portion of our existing Karnes County assets and all of our Giddings Field assets ‒ Approximately 114,000 net acres to our Giddings Field position ‒ Approximately 15 net undrilled locations to our core Karnes County inventory ‒ Pro forma, Magnolia holds over 470,000 net acres in the Eagle Ford • Harvest South Texas Assets 1H 2018 Results: ‒ Produced approximately 4,800 boe/d with 1,400 boe/d in Karnes County (69% oil, 83% liquids) and 3,400 boe/d in Giddings Field (27% oil, 53% liquids) ‒ Generated revenues less direct operating expenses of approximately $25 million ‒ Incurred capital expenditures of approximately $13 million • Magnolia acquisition strategy: ‒ Continue to evaluate M&A opportunities that are consistent with existing business model – high margin, free cash flow positive assets acquired at accretive cash flow multiples with meaningful upside ‒ Karnes acquisitions likely to be bolt‐on/tuck‐in acquisitions surrounding current high quality inventory ‒ Giddings acquisitions likely to focus on undrilled lease opportunities 22

Q3 2018 Operating Highlights Successor Predecessor Pro Forma July 31, 2018 through  July 1, 2018 through  Three Months Ended  September 30, 2018 July 30, 2018 September 30, 2018 Production: Oil (MBbls) 2,023  897  3,018  Natural Gas (MMcf) 5,047  1,153  7,036  NGLs (MBbls) 642  160  885  Total (Mboe) 3,506  1,249  5,076  Revenues (in thousands): Oil Sales $143,202  $68,487  $218,951  Natural Gas Sales 14,201  3,646  20,253  NGL Sales 21,153  4,754  28,455  Total Revenues $178,556  $76,887  $267,659  Average Sales Price: Oil (per Bbl) $70.79  $76.35  $72.55  Natural Gas (per Mcf) 2.81  3.16  2.88  NGL (per Bbl) 32.95  29.71  32.15  Total (per Boe) $50.93  $61.56  $52.73  NYMEX WTI ($/Bbl) $68.46  $70.11  $69.02  NYMEX Henry Hub ($/Mcf) 2.90  2.78  2.86  (1) Realization to benchmark: Oil (per Bbl) 103% 109% 105% Natural Gas (per Mcf) 97% 114% 101% Operating Expenses (in thousands): Lease Operating Expenses $11,016  $3,681  $17,538  Taxes Other Than Income 9,351  2,087  12,162  Gathering, Transportation and Processing 5,746  2,240  8,355  Depreciation, Depletion and Amortization 67,478  23,157  90,831  Operating Costs (per Boe): Lease Operating Expenses $3.14  $2.95  $3.46  Taxes Other Than Income 2.67  1.67  2.40  Gathering, Transportation and Processing 1.64  1.79  1.65  Depreciation, Depletion and Amortization 19.25  18.54  17.89  (1) Benchmarks are the NYMEX WTI and NYMEX HH average prices for oil and natural gas, respectively. 23Q3 2018 Operating Highlights Successor Predecessor Pro Forma July 31, 2018 through July 1, 2018 through Three Months Ended September 30, 2018 July 30, 2018 September 30, 2018 Production: Oil (MBbls) 2,023 897 3,018 Natural Gas (MMcf) 5,047 1,153 7,036 NGLs (MBbls) 642 160 885 Total (Mboe) 3,506 1,249 5,076 Revenues (in thousands): Oil Sales $143,202 $68,487 $218,951 Natural Gas Sales 14,201 3,646 20,253 NGL Sales 21,153 4,754 28,455 Total Revenues $178,556 $76,887 $267,659 Average Sales Price: Oil (per Bbl) $70.79 $76.35 $72.55 Natural Gas (per Mcf) 2.81 3.16 2.88 NGL (per Bbl) 32.95 29.71 32.15 Total (per Boe) $50.93 $61.56 $52.73 NYMEX WTI ($/Bbl) $68.46 $70.11 $69.02 NYMEX Henry Hub ($/Mcf) 2.90 2.78 2.86 (1) Realization to benchmark: Oil (per Bbl) 103% 109% 105% Natural Gas (per Mcf) 97% 114% 101% Operating Expenses (in thousands): Lease Operating Expenses $11,016 $3,681 $17,538 Taxes Other Than Income 9,351 2,087 12,162 Gathering, Transportation and Processing 5,746 2,240 8,355 Depreciation, Depletion and Amortization 67,478 23,157 90,831 Operating Costs (per Boe): Lease Operating Expenses $3.14 $2.95 $3.46 Taxes Other Than Income 2.67 1.67 2.40 Gathering, Transportation and Processing 1.64 1.79 1.65 Depreciation, Depletion and Amortization 19.25 18.54 17.89 (1) Benchmarks are the NYMEX WTI and NYMEX HH average prices for oil and natural gas, respectively. 23

Magnolia Oil & Gas – Summary Balance Sheet (in thousands) Successor Predecessor September 30, 2018 December 31, 2017  Cash $36,715  $ ‐ Other current assets 174,998  114,536  Property, plant and equipment, net 3,016,671  1,565,537  Other assets 71,713  8,901  Total assets $3,300,097  $1,688,974  Current liabilities $178,072  $81,300  Long‐term debt, net 388,343  ‐ Other long‐term liabilities 90,673  9,836  Stockholders' equity Noncontrolling interests 991,959  ‐ Common stock 25  ‐ Additional paid in capital 1,647,905  ‐ Retained earnings 3,120  ‐ Parents' net investment ‐ 1,597,838  Total liabilities and equity $3,300,097  $1,688,974  24Magnolia Oil & Gas – Summary Balance Sheet (in thousands) Successor Predecessor September 30, 2018 December 31, 2017 Cash $36,715 $ ‐ Other current assets 174,998 114,536 Property, plant and equipment, net 3,016,671 1,565,537 Other assets 71,713 8,901 Total assets $3,300,097 $1,688,974 Current liabilities $178,072 $81,300 Long‐term debt, net 388,343 ‐ Other long‐term liabilities 90,673 9,836 Stockholders' equity Noncontrolling interests 991,959 ‐ Common stock 25 ‐ Additional paid in capital 1,647,905 ‐ Retained earnings 3,120 ‐ Parents' net investment ‐ 1,597,838 Total liabilities and equity $3,300,097 $1,688,974 24

Reconciliation of Net Income to EBITDAX (in thousands) Pro Forma Three Months Ended  Nine Months Ended  EBITDAX reconciliation to net income: (1) September 30, 2018 September 30, 2018  Net income attributable to Class A Common Stock $57,891  $151,316  Net income attributable to noncontrolling interest 43,138  112,753  Income tax expense 16,138  42,183  Interest expense 7,385  22,527  Depreciation, depletion and amortization 90,831  243,262  Exploration expense 322  917  Asset retirement obligation accretion 587  1,762  (2) EBITDAX  $216,292  $574,720  (1) Includes revenue less direct expense attributable to the Subsequent GulfTex assets of $22.0 million. (2) Pro forma EBITDAX is a non‐GAAP measure. For reasons management believes this is useful to investors, refer to slide 2 “Non‐GAAP Reconciliations.” 25Reconciliation of Net Income to EBITDAX (in thousands) Pro Forma Three Months Ended Nine Months Ended EBITDAX reconciliation to net income: (1) September 30, 2018 September 30, 2018 Net income attributable to Class A Common Stock $57,891 $151,316 Net income attributable to noncontrolling interest 43,138 112,753 Income tax expense 16,138 42,183 Interest expense 7,385 22,527 Depreciation, depletion and amortization 90,831 243,262 Exploration expense 322 917 Asset retirement obligation accretion 587 1,762 (2) EBITDAX $216,292 $574,720 (1) Includes revenue less direct expense attributable to the Subsequent GulfTex assets of $22.0 million. (2) Pro forma EBITDAX is a non‐GAAP measure. For reasons management believes this is useful to investors, refer to slide 2 “Non‐GAAP Reconciliations.” 25