second quarter 2017 · 2018-05-18 · • set new mro record for fastest well drilled at >4,200...

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

http://www.marathonoil.com/


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


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


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


Culberson Hughes3 well pad


Free4 well pad


Davilla Graham6 well pad


Nitsch2 well pad


Karnes City NW5 well pad



Kimble Gilley5 well pad


Bailey Retzloff5 well pad


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


0

5

10

15

0

20

40

60

3Q 2016 4Q 2016 1Q 2017 2Q 2017

Co-

Op

Wel

ls to

Sal

es


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


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

second quarter 2017 · 2018-05-18 · • set new mro record for fastest well drilled at >4,200...

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