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Second Quarter 2019

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Second Quarter 2019 Second Quarter 2019 Financial and Operational Review August 7, 2019 Forward-Looking Statements and Other Matters This presentation (and oral statements made regarding the subjects of this presentation) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including, without limitation: the Company's 2019 capital budget and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production, guidance, cash margins, asset sales and acquisitions, oil growth, cost and expense estimates, cash flows, uses of excess cash, return of cash to shareholders, returns, including CROIC and CFPDAS, and EG EBITDAX, asset sales and acquisitions, leasing and exploration activities, future financial position, tax rates and other plans and objectives for future operations. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “future”, “guidance,” “intend,” “may,” “outlook”, “plan,” “project,” “seek,” “should,” “target,” “will,” “would,” or similar words may be used to identify forward- looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While the Company believes its assumptions concerning future events are reasonable, a number of factors could cause actual results to differ materially from those projected, including, without limitation: conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the jurisdictions in which the Company operates, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; capital available for exploration and development; risks related to our hedging activities; well production timing; drilling and operating risks; availability of drilling rigs, materials and labor, including the costs associated therewith; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions; acts of war or terrorism, and the governmental or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company’s 2018 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.Marathonoil.com. Except as required by law, the Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise. This presentation includes non-GAAP financial measures, including organic free cash flow and E.G. EBITDAX. Reconciliations of the differences between non-GAAP financial measures used in this presentation and their most directly comparable GAAP financial measures are available at www.Marathonoil.com in the 2Q19 Investor Packet. 2 Framework for Success Our working definition of capital discipline Committed to our Framework • Portfolio transformation and focused capital allocation drive multi-year Corporate Returns corporate returns improvement through capital efficient oil growth Free Cash Flow • Sustainable free cash flow at conservative pricing • Return incremental capital to shareholders in addition to peer Return of Capital competitive dividend; funded through free cash flow, not dispositions • Continuous improvement in capital efficiency and operating costs Differentiated Execution while enhancing our resource base; delivering on our commitments Powered by our Foundation • Capital allocation flexibility, broad market access, supplier diversification, Multi-Basin Portfolio rapid sharing of best practices, platform for talent development • Financial flexibility to execute business plan across broad range of Balance Sheet Strength pricing; current net debt/EBITDAX among lowest in peer group 3 2Q19 Highlights Consistently delivering on our framework • Annualized 2Q19 CROIC1 of 20%, comparable to prior-year quarter despite 12% lower Corporate Returns WTI price; driving significant price normalized rate of change improvement Free Cash Flow • Organic FCF2, post-dividend, of $137MM 2Q19 and $217MM YTD • YTD dividends of $82MM, buybacks of $250MM; 25% of CFO3 returned to shareholders Return of Capital • Share repurchases of $950MM since 2018, funded entirely by organic FCF • Share repurchase authorization increased to $1.5B • US oil production above top end of guidance and up 17% from year-ago quarter Differentiated • YTD development capex 50% of annual budget; annual $2.4B budget unchanged Execution • US unit production costs down 14% from year-ago quarter; lowest since becoming independent E&P • Completed well cost (CWC) per lateral foot on declining trend vs. 2018 in all Basins Multi-Basin • Exited Kurdistan and U.K.; 10 country exits since 2013 Portfolio • Portfolio optimized to four high quality U.S. Resource Plays and free cash flow generative integrated business in Equatorial Guinea Balance Sheet • Upgraded by Moody’s and S&P; investment grade at all primary ratings agencies Strength • Peer leading leverage metrics and breakeven oil price 1CROIC = Cash return on invested capital; calculated by taking cash flow (Operating Cash Flow before working capital + net interest after tax) divided by (average Stockholder’s Equity + average Net Debt) 2 4 Organic FCF = Operating Cash Flow before working capital (excl. exploration costs other than well costs), less Development Capex, less Dividends, plus EG return of capital & other 3CFO = Cash flow from operations Total Company Cash Flow for 2Q19 Generated $137MM of organic FCF • 2Q19 development capital of $636MM; YTD of $1.2B with $2.4B full-year budget unchanged • YTD stock repurchases of $250MM; outstanding authorization raised to $1.5B • Cash Balance at June 30 excludes $335MM of held for sale cash (U.K.); pro-forma July 1 Cash Balance reflects $95MM U.K. disposition proceeds 2,000 U.K. Held for Sale 1,500 636 777 37 74 1,000 41 37 $MM 236 4 1,156 1,056 500 1,019 961 0 3/31/19 Cash Operating Development Dividends EG LNG Cash Bal b/f REx Capex Share A&D (Net) Total 6/30/19 Cash 7/1/19 pro- Balance Cash Flow b/f Capital Return of A&D, REx, Repurchase Working Balance forma Cash WC 1 Expenditures Capital & Working Capital 2 Balance Other Capital & Financing 1 Excludes $6MM of exploration costs other than well costs 2 Total working capital includes $20MM and $54MM of working capital changes associated with operating activities and investing activities, respectively 5 See the 2Q19 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations Competitively Advantaged Multi-Basin Model Multi-basin portfolio provides flexibility Appraise / Delineate Early Development Full Field Development Bakken MRO 2Q19 Oil Production by Area 2Q19 avg. 104 MBOED (85% oil) ~260,000 net surface acres International and Other STACK / SCOOP Eagle Ford Oklahoma 2Q19 avg. 82 MBOED (25% oil) ~300,000 net surface acres Northern Delaware Permian 2Q19 avg. 28 MBOED (59% oil) ~85,000 net surface acres Bakken Eagle Ford 2Q19 avg. 109 MBOED (56% oil) ~145,000 net surface acres 6 Impressive Eagle Ford Productivity Across Footprint Production Volumes and Wells to Sales • Production averaged 109 net MBOED 120 60 • Record 2Q19 IP30 well productivity despite 80 40 majority of activity outside of Karnes County • Turnbull pad in Karnes avg. IP30 of 3,230 40 20 MBOED BOED (67% oil) - new MRO pad record Operated Wells to Sales Wellsto Operated • 15 wells across Atascosa Core delivered 0 0 2Q18 3Q18 4Q18 1Q19 2Q19 avg. IP30 of 1,860 BOED (81% oil) Production Gross Wells Net WI Wells • Successful core extension test in Gonzales Driving Consistent Productivity Improvement through enhanced completion designs 1 120 − 6 well pad achieved avg. IP30 of 1,600 BOED (70% oil) 100 − 2nd Gonzales test online 4Q19 80 60 • Capital efficiency improvement continues 40 − Consistent year over year productivity 20 improvement Day Cum ProductionDay (MBOE) 0 - − Completed well cost per lateral foot on 2011 2012 2013 2014 2015 2016 2017 2018 2019 90 declining trend vs. 2018 1 90-day cumulative production normalized to 5,700’ 7 Record Well Performance in the Eagle Ford Successful Gonzales core extension test Core Extension Test in Gonzales Barnhart G - 6 LEF wells 1,600 BOED (70% oil) Gonzales 5,680’ LL Expanded Atascosa Core De Witt Chapman-Pfeil - 4 LEF wells 1,320 BOED (76% oil) Karnes Next Gonzales Test (4Q19) 6,760’ LL 4 LEF Wells Retzloff Tom-May - 3 LEF wells 9,600’ LL 1,660 BOED (80% oil) Atascosa 6,830’ LL Guajillo – 2 pads, 8 LEF wells 2,200 BOED (83% oil) 6,820’ LL MRO Eagle Ford Record Pad IP30 Turnbull H – 4 LEF wells 3,230 BOED (67% oil) Live Oak 6,140’ LL Wet Gas Bee Condensate Oil IPs shown are 30-day (includes oil, NGL and gas) and represent pad average 8 Industry Leading Capital Efficiency in Bakken Production Volumes and Wells to Sales • Production averaged 104 net MBOED 120 35 100 30 • Continuing
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