SECOND QUARTER 2017
Financial and Operational Review
August 2, 2017
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 future performance, business strategy, asset quality, production guidance, drilling plans, 2017 capital plans, cost and expense estimates, use of proceeds from the Company’s debt offering, cash flows, asset sales and acquisitions, future financial position, and other plans and objectives for future operations. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," “may,” "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 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; the inability of any party to satisfy closing conditions with respect to our asset disposition; 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 weatherconditions; 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 2016 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.
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 2Q 2017 Investor Packet.
2
Outstanding operational results drive 7% sequential oil growthSecond Quarter Highlights
Production• Total Company production (ex.
Libya) of 349 MBOED, up 6%sequentially; Libya 11 MBOED
• U.S. resource plays production grew 6% sequentially to 202 MBOED; exceeded high end of U.S. guidance
• Oklahoma Resource Basin production grew 11% sequentially
Key Well Results• Hansens STACK six new infill
wells avg. 30-day IP of 915 BOED• Eagle Ford top 10 wells to sales
avg. 30-day IP of 2,340 BOED• Two Hector wells with enhanced
completion designs avg. 30-day IP of 2,500 BOED
• 1st MRO-designed completion in N. Delaware achieved 30-day IP of 1,500 BOED
Portfolio• Closed sale of OSM and Northern Delaware acquisitions• $2.6B of cash on balance sheet, up from previous quarter
3
Increasing Production Guidance While Lowering CapexExceeding expectations on efficiency, base performance & new well productivity
*Adjusted for divestitures of 13 MBOED in FY16Excluding Libya and discontinued operations
U.S. Resource Play Production
Total E&P Available for Sale Volumes
MB
OED
BO
ED &
BO
PD
194
135*
0
100
200
300
400
FY 2016 FY 2017E
GuidanceE&P: 345 - 360
4Q 2016 4Q 2017
U.S. resource plays Remaining E&P Range
23 – 27%growth
• Raising original 2017 production guidance with revised budget of $2.1B - $2.2B
• 7% total E&P oil and boe production growth at the midpoint, divestiture adjusted
• 23 - 27% oil & boe growth in resource plays from 4Q16 to 4Q17
• Operational momentum to support sequential growth in resource plays into 2018
– Objective remains to live within cash flows
329*
4
Total Company Cash Flow 1H 2017Cash increased to $2.6B; liquidity at $5.9B
2,488 2,614
984 (958)
(85) 122
(1,828) 1,856
35
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
12/31/16 CashBalance
OperatingCash Flow b/f
WC
CapitalExpenditures
Dividends Total WorkingCapital
Acquisitions Disposal ofAssets
EG LNGReturn ofCapital& Other
6/30/17 CashBalance
$MM
21
1Including accruals2Total working capital includes $(61)MM and $183MM of working capital changes associated with operating activities and investing activities, respectively3Does not include March 2018 final payment of $750MM from OSM dispositionSee the 2Q 2017 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations
3
Avg. WTI $50 for 1H 2017
5
$682$854
$228
$600
$1,035
$201
$900$1,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
10-Year Debt Maturities Pro-forma 6/30/17 ($MM)
Strengthened Financial Flexibility
• Successful senior notes offering: – Extend next debt maturity to 2020* – Reduce gross debt by $750MM– Reduce annual interest expense by $60MM
• $3.4B** undrawn revolving credit facility upsized and extended through 2021
• Investment grade credit ratings at S&P (BBB-) and Fitch (BBB); Moody’s (Ba1)
Recent transactions improve maturity profile and enhance liquidity
*Lowers average cost of debt by 0.4% to 4.7% and increases average maturity by 2.5 years to 12.7 years**Includes $93MM increase in credit facility July 2017
Paid Off Debt Long-Term Debt
Retired with cash on hand
6
U.S. E&P Production Above Top End of 2Q GuidanceResumed quarterly resource play growth
189 191 202
14* 1720
0
50
100
150
200
250
2Q 2016 1Q 2017 2Q 2017 3Q 2017E
MB
OED
U.S. resource plays Other U.S. E&P Range
Available for Sale Volumes
203* 208222
U.S. E&PGuidance: 230 - 240
*Adjusted for divestitures of 21 MBOED in 2Q167
Oklahoma Grows 11% SequentiallyContinued strategic focus on delineation, leasehold and infill spacing pilots
• Production averaged 49 net MBOED; up 11% from 1Q 2017
• 20 gross operated wells to sales
• Chapman well, a STACK Meramec XL, averaged IP 30 of 3,185 BOED (52% oil)– Significantly outperforming type curve
• 6 new Hansens wells averaged IP 30 rates of 915 BOED (55% oil); 4,650’ average lateral length and $4.3MM CWC– Tested 5 wells at 660’ spacing; tested 1 well
between two strong existing producers
– Hansens parent well has cum’d 380 MBOE
• Expect 30 - 40 gross operated wells to sales in 2H 2017– 50% leasehold drilling
– 2 to 3 infill spacing pilots to sales
Hansens Meramec SL Infill Pilot
Production Volumes and Wells to Sales
MB
OED
0
10
20
30
0
20
40
60
3Q 2016 4Q 2016 1Q 2017 2Q 2017
Co-
Op
Wel
ls to
Sal
es
Production Gross Wells Net WI Wells
Upper Meramec
Lower Meramec
5,280’
1,980’800’
Effective 8-well DSU spacing
Trial between existing producers
Existing Meramec well
New wells
Existing Industry well
8
0
50
100
150
200
250
0 30 60 90 120 150 180
MB
OE
Days
Calf Rope 1-1-12MXHStrack 1-2-11XHChapman 1-26-23MXHRuthie 1-15-22MXHMRMC VO XL Type Curve
Strong Well Results Across Phase WindowsTransitioning from delineation to development drilling in 2018
IPs shown are 30 day (includes oil, NGL and gas)
Caddo
Grady
Stephens
Garvin
Blaine Kingfisher
Canadian
Hansens 6-well Infill PilotIP30 Avg: 915 BOED (55% oil)
Wet GasCondensateOil
Strack 1-2-11XHIP30: 1,270 BOED (68% oil) Alta BIA 1511 1-6-31MXH
IP30: 2,133 BOED (12% oil)
Calf Rope 1611 1-1-12MXHIP30: 1,466 BOED (70% oil)
Chapman 1511 1-26-23MXHIP30: 3,185 BOED (52% oil)
Broderson 1407 1-20MHIP30: 728 BOED (64% oil)
Ruthie 1609 1-15-22MXHIP30: 2,315 BOED (70% oil)
Isaac Taylor 0606 2-15-10WXHIP30: 1,782 BOED (23% oil)
STACK Volatile Oil XL Wells Cum Production
Eden 1308 1-4MHIP30: 1,206 BOED (35% oil)
McKinley BIA 1-4-33MXHIP30: 17.9 MMCFD
9
Eagle Ford Continues to Deliver High Capital EfficiencySequential production increase with fewer wells to sales
90 day Cumulative Production
40
50
60
70
80
90
2011 2012 2013 2014 2015 2016 2017YTD
MB
OE
• Production averaged 100 net MBOED; up from 1Q 2017
• Top 10 2Q wells averaged IP 30 of 2,340 BOED (69% oil)
• Encouraging early results from Atascosa County wells with high intensity completions; Guajillo pads on flowback
• ~10 years of gross Co-Op wells remaining in risked inventory at 2017 pace
• Set new MRO record for fastest well drilled at >4,200 ft per day; $4.2MM CWC ~flat quarter over quarter
• 90d cum. production up >30% since 2011
• Expect 65 - 70 gross operated wells to sales in 2H 2017– Two thirds in oil window
Production Volumes and Wells to Sales
MB
OED
0
30
60
90
0
40
80
120
3Q 2016 4Q 2016 1Q 2017 2Q 2017
Co-
Op
Wel
ls to
Sal
es
Production Gross Wells Net WI Wells
All wells to sales in each yearNormalized to 5,700’ lateral length
10
Live Oak
Bee
Karnes
Atascosa
Wilson
Eagle Ford 2Q Activity OverviewTop 10 wells averaged 2,340 BOED, 69% oil
Karnes City SW2 well pad
Avg: 2,402 BOED (72% oil)
Karnes City SE4 well pad
Avg: 2,152 BOED (71% oil)
Culberson Hughes3 well pad
Avg: 1,691 BOED (65% oil)
Free4 well pad
Avg: 2,026 BOED (38% oil)
Davilla Graham6 well pad
Avg: 1,401 BOED (55% oil)
Nitsch2 well pad
Avg: 1,468 BOED (27% oil)
Karnes City NW5 well pad
Avg: 2,230 BOED (74% oil)
IPs shown are 30 day (includes oil, NGL and gas)
Kimble Gilley5 well pad
Avg: 1,041 BOED (65% oil)
Bailey Retzloff5 well pad
Avg: 1,244 BOED (48% oil)
Guajillo Two 5 well padsOn Flowback
11
0
100
200
300
400
0 60 120 180 240 300 360
MB
OE
Days
E & W Myrmidon WellsE. Myrmidon Type CurveW Myrmidon Type Curve
Bakken Resumed Production Growth in 2QExtended Myrmidon production history outperforming expectations
• Production averaged 49 net MBOED, up 2% from 1Q 2017
• First two Hector high-intensity completions tests with average IP 30s of 2,500 BOED (85% oil)
• 7 Myrmidon wells to sales in July with average IP 24 rates of >4,000 BOED (78% oil)
• Set new MRO record spud to TD in ~7.5 days
• Myrmidon wells with high intensity completions outperforming expectations with extended production history
• Expect 35 - 45 gross operated wells to sales in 2H 2017– Two thirds Myrmidon development wells
MB
OED
Production Volumes and Wells to Sales
0
5
10
15
0
20
40
60
3Q 2016 4Q 2016 1Q 2017 2Q 2017
Co-
Op
Wel
ls to
Sal
es
Production Gross Wells Net WI Wells
High Intensity Myrmidon Well Performance
12
0
40
80
120
160
0 10 20 30 40 50 60
Days
Mittelstadt 34-12HHondo 34-12TFHHector Type Curve
Strong Early Well Performance From Hector Hondo PadEnhanced slickwater completions yielding encouraging results
IPs shown are 30 day (includes oil, NGL and gas)
MB
OE
Hondo Pad Cum Production Dunn
Hector
Elk Creek
Ajax
Planned 2H Hector wells
Hector: Hondo Pad
Mittelstadt 34-12H Hondo 34-12TFH2,933 BOED 2,084 BOED
8 MMLBS proppant, Plug n Perf, 45 stages, Diversion applications
13
Positive Initial Results in Northern DelawareIncreased activity to 3 rigs mid-year as planned
• Production averaged 4 net MBOED; partial quarter due to BC & BM close dates
• 2 gross operated wells to sales– Cypress 1H Wolfcamp X-Y delineation well IP
30 of 1,500 BOED (72% oil)
– Black River Wolfcamp X-Y well with strong IP 90 of 1,275 BOED (73% oil), flat with IP 30
• Gen 1 Completion Design– 100% Slickwater & 2,200 - 2,500 lb/ft
– 5 to 10 clusters/stage
• Cypress infill pilot to spud in 2H 2017– 8-well infill on 320-acres in Eddy County
– Testing spacing in X-Y and Upper Wolfcamp, delineation of middle Wolfcamp and 3rd Bone Spring benches
• Expect 15 - 20 gross operated wells to sales in 2H 2017
Cypress SL 8-Well Infill Pilot
0
400
800
1200
1600
2000
0 30 60 90
BO
ED (2
-str
eam
)
Days
Black River Production
Cypress 1H Wolfcamp well
New wells
IPs shown are 2-stream14
Play Extension of Northern Delaware ContinuesCurrent quarter wells and notable upcoming well activity
LEA COUNTY
EDDY COUNTY
CHAVES COUNTY
Cypress Spacing Pilot2H spud
4 Wolfcamp, 3 Bone Spring
Black River 15-10 State 4HWolfcamp X-Y
IP90: 1,275 (73% Oil)9,400’ LL
Grama Ridge 8 State 2H, 3H, 5H2H sales
2nd and 3rd Bone Spring
Southern Comfort 25-36 State 1H, 2H2H sales
Wolfcamp X-Y
IPs shown are 30 and 90 day (includes oil and gas)
Battle 34 Federal 4H2H sales
2nd Bone Spring
Cass 16 State 2H, 3H, 4H2H sales
Wolfcamp X-Y, Wolfcamp A & 2nd Bone Spring
Cypress 1HWolfcamp X-Y
IP30: 1,500 BOED (72% Oil)4,600’ LL
15
International E&P HighlightsEG continues to deliver substantial free cash flow
• International E&P production 127 net MBOED, near top of guidance
• Significant free cash flow from EG with $134MM of EBITDAX in 2Q
• EG production on plateau one year from gas compression project start-up
• Lower 3Q guidance due to scheduled turnarounds in the U.K. (Brae and Foinaven)
• Libya production averaged 11 net MBOED with two liftings
– Recovered underlift position in 1H 2017
– Current rates at >20 net MBOED
Intl E&P Production Volumes (Excl. Libya)
MB
OED
102 105 107
18 17 20
0
25
50
75
100
125
150
2Q 2016 1Q 2017 2Q 2017 3Q 2017E
EG International Other Range
Total EGEBITDAX $126MM $161MM $134MM
See the 2Q 2017 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations
Intl E&PGuidance: 115 - 125
16
Key Takeaways
*Production growth in both oil and boeExcluding Libya
Enhanced Hector Completion Designs
2,500 BOEDaverage 30-day IPs
1st MRO Completion in Northern Delaware
1,500 BOED30-day IP
$5.9B total liquidity; improved capital structure
Balance Sheet Strength
Oklahoma Resource Basins
11% growthsequentially
Equatorial Guinea on Plateau
107 MBOED w/ $134MM EBITDAX
Raising 2017 Production Guidance With Reduced Capital Program
23 - 27%Resource plays exit
rate growth*
7%Total E&P growth
at midpoint*
10%Reduced 2017 capital budget
2,340 BOED top 10 wells avg 30-day IPs
Continued Strong Eagle Ford Results
17
Appendix
Volumes, Exploration Expenses & Effective Tax Rate2017 (excluding Libya)
1Q 2Q 3Q 4Q Year
United States E&P Net Sales Volumes:
- Liquid Hydrocarbons (MBD) 158 165
- Natural Gas (MMCFD) 304 341
- North America E&P Total (MBOED) 208 222
International E&P Net Sales Volumes:
- Liquid Hydrocarbons (MBD) 50 55
- Natural Gas (MMCFD) 461 478
- International E&P Total (MBOED) 126 135
Total E&P Sales Volumes (MBOED) 334 357
Total E&P Available for Sale (MBOED) 330 349
- Disc. operations synthetic crude oil production (MBD)* 45 29
Equity Method Investment Net Sales Volumes:
- LNG (metric tonnes/day) 6,147 6,243
- Methanol (metric tonnes/day) 1,307 1,182
- Condensate and LPG (BOED) 14,546 11,608
Exploration Expenses (Pre-tax):
- North America E&P ($ millions) 26 30
- International E&P ($ millions) 2 -
Consolidated Effective Tax Rate (ex. Libya) Provision (Benefit) (16)% 7%
*Upgraded bitumen excluding blendstocks19
2017 EstimatesVolumes
Available for Sale 3QE
Available for Sale Year Estimate
Comments
North America E&P Total (MBOED) 230 – 240
- Liquid Hydrocarbons (MBD) 175 – 183
- Natural Gas (MMCFD) 330 – 344
International E&P Total (MBOED)* 115 – 125
- Liquid Hydrocarbons (MBD)* 39 – 42
- Natural Gas (MMCFD)* 458 – 498
Total both E&P Segments (MBOED)* 345 – 365 345 – 360 FY Guidance Updated**
Equity Method Investment LNG (metric tonnes/day) 6,100 – 6,500 6,200 – 6,600
* Excluding Libya** Raised the low end of full year E&P guidance20
2017 EstimatesExploration expenses & annual production operating costs per BOE
3QE Year Estimate
Exploration Expenses (Pre-tax):
United States E&P ($ millions) 25 – 35
International E&P ($ millions) 2 – 4
United States E&P Cost Data
Production Operating $5.00 – 6.00
DD&A $21.75 – 24.25
Other* $5.00 – 5.50
International E&P Cost Data**
Production Operating $4.50 – 5.50
DD&A $6.50 – 8.00
Other* $1.75 – 2.25
Expected Tax Rates by Jurisdiction:
U.S. and Corporate Tax Rate 0%
Equatorial Guinea Tax Rate 25%
United Kingdom Tax Rate 40%
Libya Tax Rate 93.5%
* Other includes shipping and handling, general and administrative, and other operating expenses ** Excludes Libya21
E&P Production PerformanceIncreased 2Q volumes due to outstanding operational performance
U.S. E&P Divestiture-Adj. Sales Volumes
MB
OED
203* 208 222
0
100
200
300
2Q 2016 1Q 2017 2Q 2017
Avg C&C Realizations ($/BBL)
Excluding Derivatives
$40.77 $48.46 $45.81
Including Derivatives
$40.89 $48.80 $46.88
*Adjusted for divestitures of 21 MBOED in 2Q16
MB
OED
Intl E&P Production & Sales Volumes
120 120 122 114127 124
812
11 11
0
25
50
75
100
125
150
Avg C&C Realizations($/BBL)
$42.21 $50.41 $47.04
Cumulative underlift of (1,870) MBOE in Libya, (728) MBOE in UK, and (731) MBOE in EG
SalesAvailable for Sale Libya Available for Sale Libya Sales
2Q 2016 1Q 2017 2Q 2017
22
2017 2Q Production Mix
59%20%
21% 29%
24%
47%
80%
12%8%
57%
19%
24%
Crude Oil/Condensate NGLs Natural Gas
Eagle Ford Oklahoma Resource Basins
Bakken
Total U.S. Resource Plays
56%16%
28%
Northern Delaware
23
United States E&P Crude Oil DerivativesAs of June 30, 2017
Crude Oil (Benchmark to NYMEX WTI)
3Q 2017 4Q 2017 1Q 2018 2Q 2018
Three-Way Collars(a)
Volume (Bbls/day) 50,000 50,000 20,000 20,000
Weighted Avg Price per Bbl:
Ceiling $60.37 $60.37 $57.86 $57.86
Floor $54.80 $54.80 $53.00 $53.00
Sold put $47.80 $47.80 $47.00 $47.00
Sold call options(b)
Volume (Bbls/day) 35,000 35,000 - -
Weighted Avg Price per Bbl $61.91 $61.91 - -
(a) Subsequent to 6/30/17, we entered into 20,000 Bbls/day of three-way collars for January – December 2018 with an average ceiling price of $55.09, a floor price of $50.00, and a sold put price of $43.00(b) Call Options settle monthly24
United States E&P Natural Gas DerivativesAs of June 30, 2017
Natural Gas (Benchmark to NYMEX HH)
3Q 2017 4Q 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018
Three-Way Collars
Volume (MMBtu/day) 120,000 120,000 200,000 160,000 160,000 160,000
Weighted Avg Price per MMBtu:
Ceiling $3.58 $3.71 $3.79 $3.61 $3.61 $3.61
Floor $3.09 $3.14 $3.08 $3.00 $3.00 $3.00
Sold put $2.55 $2.60 $2.55 $2.50 $2.50 $2.50
Swaps
Volume (MMBtu/day) 20,000 20,000 - - - -
Weighted Avg Price per MMBtu $2.93 $2.93 - - - -
25