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 Wells to 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 CumProduction Day (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 successful Southern Hector 25 80 delineation 20 60

15 − 4 second quarter wells avg. IP30 of 2,450 MBOED 40 10 BOED (80% oil) 20 5 • Strong performance from South Myrmidon 0 0 Wellsto Sales Operated 2Q18 3Q18 4Q18 1Q19 2Q19 − 15 wells avg. IP30 of 2,820 BOED (80% oil) Production Gross Wells Net WI Wells − Driftwood Middle Bakken well achieved MRO YTD Completed Well Costs Trending 15% below 2018 record IP24 of 12,250 BOED (78% oil) 8.0 • Average completed well cost of $5.2MM 7.0 • YTD CWC down 15% from 2018 average

6.0 • Half of second quarter wells at or below $5MM CWC ($MM) 5.0 • Exceptional extended production from 2018 core extension tests in Ajax and Southern 4.0 Hector 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19

9 Expanding the Bakken Core Best in Basin productivity

Continued Strength in Pre-2Q19 to Sales South Myrmidon • 4 wells from Ajax core extension test 2Q19 to Sales 15 wells (2Q19) achieved total cumulative production of IP30: 2,820 BOED (80% oil) Myrmidon Includes single well IP24 >1 MMBOE at 240 days 12,250 BOED (78% oil) • 4 wells from South Hector core extension tests achieved total cumulative production of >950 MBOE at 200 days McKenzie Dunn Progressing Southern Elk Creek Hector Delineation • Additional Southern Hector and Ajax core

4 wells (2Q19) extension tests scheduled for 2H19 IP30: 2,450 BOED (80% oil) 90-Day Cumulative Oil Production1

240 Hector 200 20 of top 25 & 60 of top 100 wells, despite only drilling 160 9% of wells in Basin

Ajax 120

80 Extended Production Validates

2018 Delineation Tests (MBO)CumulativeOil 40 1

4 Ajax wells (4Q18) 4 S. Hector wells (2H18) 0 >1 MMBOE (80% oil) >950 MBOE (79% oil) 0 500 1,000 1,500 Total CUM* at 240 days Total CUM* at 200 days MRO Wells Competitor Wells

IPs shown include oil, NGL and gas 1Source - Drilling Info; dataset consists of all Bakken/Three Forks wells with first production from since Jan. 1, 2017. Plot includes 1,564 total wells. *CUM – Cumulative production 10 Oklahoma Delivering Capital Efficiency and Consistency

Production Volumes and Wells to Sales • Production averaged 82 net MBOED 100 20 • Track record of consistently strong 80 16 overpressured STACK infill results 60 12

40 8 – 8 wps Mike Stroud infill >100% above type MBOED curve at 60 days 20 4

0 0 Wellsto Sales Operated • Focus on capital efficiency paying dividends 2Q18 3Q18 4Q18 1Q19 2Q19

Production Gross Wells Net WI Wells – Most recent overpressured STACK infills (Marjorie and Lloyd) executed at industry Marjorie/Lloyd Overpressured STACK Well Cost* leading well costs 8 – Cycle times reduced ~30% vs. most recent 7.5 ~$0.5 comparable infills 7 ~$0.5 6.5 $8.0 • Leveraging operated success and OBO ~$0.5 learnings to Springer formation over 2H19 6 ~$0.2 $6.3 ~$0.4 5.5 $5.9 – 4Q18 Papa Pump Springer test achieved

CompletedWell Cost ($MM) IP180 of 1,210 BOED (79% oil) 5 Prior Actual Drilling Contract Completion Design Actual CWC Location Actual D&C CWC** Efficiencies Savings Efficiencies Savings

*Normalized to 10,000 ft. lateral; completed well cost includes D&C and location costs. Actual D&C is CWC minus location costs **Actual average CWC of two most recent offset infills wps – wells per section 11 OBO – operated by other Oklahoma Continues to Outperform Leveraging operated Springer success in 2H19

Industry Leading Dual-Pad Development Reducing Costs and Cycle Times Well Costs Blaine Kingfisher Marjorie & Lloyd Infills 2 pads, 4 wps 6 new MRMC wells $6.3MM avg. CWC* Flowing back

Strong Productivity and Predictability

Mike Stroud** Canadian 8 MRMC wps Caddo 2,480 BOED (38% oil)

Chapman 6 MRMC wps Strong Performance from the Overpressured STACK 1,810 BOED (53% oil) Leveraging Learnings 150 in Springer MRMC Volatile Oil XL Type Curve Mike Stroud Pad Avg 2H19 - 12 wells to sales Grady Chapman Pad Avg 100 >100% 4Q18 Springer Test Papa Pump IP180: 1,210 BOED

(79% oil) MBOE 50

Wet Gas Pre-2Q19 to Sales Condensate 2Q19 to Sales 0 Oil 2H19 to Sales Stephens 0 10 20 30 40 50 60 Days

IPs shown are 30-day (includes oil, NGL and gas) and represent pad average unless otherwise stated *normalized to 10,000 ft. lateral 12 **5 of 8 wells brought online during 1Q19; 3 of 8 wells brought online during 2Q19 MRMC – Meramec Strong Productivity and Improving Margins in N. Delaware

Production Volumes and Wells to Sales • Production averaged 28 net MBOED 30 25 • Continued strong Upper Wolfcamp 25 20 20 productivity in Malaga 15 15 – 11 wells avg. IP30 of 1,520 BOED (63% oil), 10 MBOED 10 or 345 BOED per one thousand foot lateral

5 5 • Improving margin profile through cost 0 0 Wellsto Sales Operated 2Q18 3Q18 4Q18 1Q19 2Q19 reductions and midstream solutions Production Gross Wells Net WI Wells – 10% sequential reduction in cash costs Water on Pipe (% of total produced) – 100% water on pipe for 2Q19 and all 80% remaining 2019 wells to sales

60% – Oil on pipe at ~70% and rising

40% • Increasing proportion of Red Hills delineation in drilling mix over 2H19 20%

0% 2Q18 3Q18 4Q18 1Q19 2Q19 % Water on Pipe

13 Strong 2Q19 Upper Wolfcamp Performance in Malaga Greater proportion of 2H19 activity in Red Hills

Arrowhead Ranger Lea China Draw Strong Upper WC Productivity

Mariner, 6 Upper WC 1,350 BOED (64% oil) 305 BOED/1000’ 2H19 Red Hills Pads Trebuchet, 3 Upper WC 1,580 BOED (64% oil) 370 BOED/1000’ Malaga Whistle Pig, 3 Upper WC/BS 1,870 BOED (64% oil) 420 BOED/1000’ Red Hills

Eddy

IPs shown are 30-day (includes oil, NGL and gas) and represent pad average Upper WC – Upper Wolfcamp horizon 14 BS – Bone Springs horizon International Simplified to FCF Generating E.G. Business

Alba Platform • Total International production of 103 net MBOED, reflecting successful return from 1Q19 E.G. turnaround

• E.G. EBITDAX1 of $142MM 2Q19 and $211MM YTD

AMPCO Methanol Plant • International portfolio simplified to free cash flow generating integrated business in E.G.

– Closed on sale of Atrush Block in Kurdistan

– Closed on U.K. divestiture July 1, removing $966MM of asset retirement obligations

EGLNG Loading Dock – 10 country exits since 2013

• Pro-forma International unit production costs (ex Kurdistan and U.K.) just $2.21 per BOE during 2Q19; guidance updated

1See the 2Q19 Investor Packet at www.Marathonoil.com for Non-GAAP reconciliations

15 Well Established Track Record of FCF & Return of Capital Six consecutive quarters of organic FCF generation • Returned ~$1.2B of capital to shareholders since 2018, representing ~25% of operating cash flow, funded entirely by organic FCF • Buyback authorization raised to $1.5B, representing $950MM increase in authorization • Return of capital included in executive compensation scorecard • Underlying free cash flow momentum accelerating into 2H19 and 2020

1,500 12%

11%

10% 1,000 9%

8% 950

$MM 1,336 Yield (%) Yield 1,037 7%

500 700 Annualized Annualized FCF 6%

250 5% 299 251 169 82 0 4% 2018 2019 YTD Since 2018 Avg WTI Price: $64.90 $57.42 $62.42 Organic FCF before Dividend Repurchases FCF Yield Dividend Organic FCF before Dividend Repurchases Dividend FCF Yield

FCF Yield = Organic FCF before Dividend / Market Cap (as of 8/5/2019)

16 Appendix Portfolio Transformation Since 2013 10 Country Exits • Optimized portfolio positioned to sustainably deliver improving corporate returns, free cash flow, and return of capital • Simplification to core assets concentrates capital allocation to highest margin, highest return US resource plays while materially reducing cash costs • Portfolio simplification has contributed to an Asset Retirement Obligation reduction of $1.8B since 2014

NORWAY (2014) UNITED KINGDOM POLAND CANADA (2014) (2017) (2019) BAKKEN LIBYA (2018) SCOOP/STACK NORTHERN KURDISTAN (2019) DELAWARE EAGLE FORD EQUATORIAL GUINEA ETHIOPIA (2016) GABON (2018) KENYA (2016)

ANGOLA (2014) CORE ASSETS

DIVESTED

18 Differentiated Execution Led the Way in 2018 Underpins confidence in ongoing delivery on our framework for success

Initial Guidance Actual Delivery 2018 Objectives @$50/bbl WTI @$65/bbl WTI

Capital Discipline $2.3B development capital $2.3B development capital

78% CROIC improvement – 30% CROIC improvement best in proxy peer group* Corporate Returns 10% CFPDAS improvement 65% CFPDAS improvement

Organic FCF positive, post- $865MM of post-dividend, Free Cash Flow dividend, above $50/bbl WTI organic FCF

Prioritize incremental return, $700MM of share buybacks above dividend, through Return of Capital and $170MM dividend sustainable organic FCF

18% total oil growth at 24% total oil growth, midpoint, divestiture divestiture adjusted – Capital Efficient Oil adjusted best in proxy peer group* Growth 22.5% resource play oil 32% resource play oil growth at midpoint growth

* Proxy peer group includes – APA, APC, CHK, CLR, DVN, ECA, EOG, HES, MUR, NBL, PXD

19 2019 Production Guidance

3Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

3Q19 2Q19* 3Q18* 3Q19 2Q19* 3Q18* United States 190 – 200 192 172 330 – 340 331 302 International 12 – 16 16 17 80 – 90 91 99 Total Net Production 202 – 216 208 189 410 – 430 422 401

FY19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

2019** 2018* 2019** 2018*

United States 185 – 195 169 320 – 330 294 International 18 – 22 17 85 – 95 98 Total Net Production 203 – 217 186 405 – 425 392

• Adjusted full year 2019 production guidance now excludes divested U.K. and Kurdistan volumes for the second half of 2019, but otherwise remains unchanged

* Divestiture-adjusted, and also removes volumes associated with the sale of our U.K. business which closed on July 1, 2019 ** Annual 2019 guidance includes 1H19 contributions from divested assets 20 2019 Cost and Tax Rate Guidance

Initial Current 2019 Guidance 2019 Guidance United States Cost Data ($ per BOE)

Production Operating $4.50 – 5.50 $4.50 – 5.50

DD&A $19.25 – 21.75 $18.25 – 20.75

S&H and Other1 $4.00 – 4.50 $4.00 – 4.50

International Cost Data ($ per BOE)

Production Operating $4.75 – 5.75 $3.75 – 4.25

DD&A $3.00 – 4.00 $3.00 – 4.00

S&H and Other1 $1.00 – 1.50 $0.75 – 1.25

Expected Tax Rates by Jurisdiction:

United States and Corporate Tax Rate –% –% Equatorial Guinea Tax Rate 25% 25%

• Updated full year 2019 guidance reflects actual realized costs for 1H19 but excludes U.K. and Kurdistan costs for 2H19

• 2Q19 pro-forma (ex U.K. and Kurdistan) International cost data ($ per BOE): - Production Operating $2.21 - DD&A $3.13 - S&H and Other $0.64

1 Excludes G&A expense

21 United States Crude Oil Derivatives As of August 5, 2019

Crude Oil

3Q19 4Q19 FY 2020 FY 2021

NYMEX WTI Three-Way Collars (a)

Volume (BBLs/day) 80,000 80,000 19,945 -

Weighted Avg Price per BBL:

Ceiling $74.19 $74.19 $67.55 -

Floor $56.75 $56.75 $55.00 -

Sold put $49.50 $49.50 $47.50 -

Basis Swaps – Argus WTI Midland (b)

Volume (BBLs/day) 15,000 15,000 15,000 -

Weighted Avg Price per BBL $(1.40) $(1.40) $(0.94) -

Basis Swaps – Net Energy Clearbrook (c)

Volume (BBLs/day) 1,000 1,000 - -

Weighted Avg Price per BBL $(3.50) $(3.50) - -

Basis Swaps – NYMEX WTI / ICE Brent (d)

Volume (BBLs/day) 5,000 5,000 5,000 808

Weighted Avg Price per BBL $(7.24) $(7.24) $(7.24) $(7.24)

Basis Swaps – Argus WTI Houston (e)

Volume (BBLs/day) 10,000 10,000 - -

Weighted Avg Price per BBL $5.51 $5.51 - -

NYMEX Roll Basis Swaps

Volume (BBLs/day) 60,000 60,000 - -

Weighted Avg Price per BBL $0.38 $0.38 - -

(a) Between July 1, 2019 and August 5, 2019, we entered into 10,000 Bbls/day of three-way collars for January – December 2020, with a ceiling of $65.12, a sold put of $48.00, and a floor of $55.00. (b) The basis differential price is indexed against Argus WTI Midland 22 (c) The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook (“UHC”) (d) The basis differential price is indexed against International Commodity Exchange (“ICE”) Brent and NYMEX WTI (e) The basis differential price is indexed against Argus WTI Houston 2019 Capital, Investment & Exploration Budget reconciliation $MM

Development Capital 2019 2019 YTD Budget 1Q19 2Q19 Actual

Cash additions to Property, Plant and Equipment 615 647 1,262

Working Capital associated with PPE (1) 54 53

Property, Plant and Equipment additions 614 701 1,315

M&S Inventory (4) (6) (10)

REx expenditures included in capital expenditures (41) (59) (100)

Exploration costs other than well costs - - -

Development Capital 2,400 569 636 1,205

Resource Exploration (REx) Capital 2019 2019 YTD Budget 1Q19 2Q19 Actual

REx expenditures included in capital expenditures 41 59 100

Additions to Other Assets and acquisitions (14) (28) (42)

Exploration costs other than well costs 10 6 16

REx Capital Expenditure 200 37 37 74

23