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2019 CAPITAL PROGRAM & 2018 RESULTS
February 13, 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, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production, cash margins, 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 2017 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 4Q18 Investor Packet.
2
Multi-Basin Portfolio• Capital allocation flexibility, broad market access, supplier diversification,
rapid sharing of best practices, platform for talent development
Balance Sheet Strength• Financial flexibility to execute business plan across broad range of
pricing; current net debt/EBITDAX among lowest in peer group
Differentiated Execution• Continuous improvement in capital efficiency and operating costs
while enhancing our resource base; delivering on our commitments
Framework for SuccessOur working definition of capital discipline
3
Powered by our Foundation
Committed to our Framework
Corporate Returns• Portfolio transformation and focused capital allocation drive multi-year
corporate returns improvement through capital efficient oil growth
Free Cash Flow • Sustainable free cash flow at conservative pricing
Return of Capital• Return incremental capital to shareholders in addition to peer
competitive dividend; funded through free cash flow, not dispositions
Forward Outlook Prioritizes Returns, FCF, Return of CapitalOrganic FCF positive in both 2019 and 2020 above $45/bbl WTI, post-dividend
4
Corporate Returns
• Continues multi-year rate of change improvement in key enterprise performance metrics
− 20% CROIC and 18% CFPDAS CAGRs (2017-2020) at $50/bbl WTI flat
− 30% CROIC and CFPDAS CAGR (2017-2020) at $60/bbl WTI flat
Free Cash Flow
• Organic FCF positive above $45/bbl WTI in both 2019 and 2020
• Portfolio delivers strong two-year (2019-2020) organic FCF
− >$750MM at $50/bbl WTI flat
− >$2.2B at $60/bbl WTI flat
Return of Capital
• Continue to prioritize return of capital
− Returned over 25% of operating cash flow to shareholders in
2018
− Return of capital metric incorporated into executive
compensation scorecard, complementing CROIC and CFPDAS
Differentiated Execution
• High value oil growth exceeds BOE growth, an outcome of returns-
first capital allocation
− 2019 U.S. oil growth of 12% and total oil growth of 10%
• Maintaining focus on organic resource base enhancement
1Organic FCF = Operating Cash Flow before working capital (excl. exploration costs other than well costs), less Development Capex, less Dividends, plus EG return of
capital & other 2CROIC = Cash return on invested capital; calculated by taking cash flow (Operating Cash Flow before working capital + net interest after tax) divided by
(average Stockholder’s Equity + average Net Debt); 3CFPDAS = Cash flow per debt adjusted share; calculated by taking cash flow (Operating Cash Flow before working
capital + net interest after tax) divided by total shares including debt shares. Debt shares is the average net debt during a calendar year divided by the average
annual stock price; See the 4Q 2018 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations
1
Sustainable FCF in 2019 & 2020 at Conservative PricingDifferentiated annual FCF yield vs. E&P peers
0%
5%
10%
0
500
1,000
1,500
2,000
2,500
2019 - 2020 2019 - 2020 2019 - 2020
Cu
mu
lati
ve O
rgan
ic F
CF
($M
M)
2019 – 2020
($60 WTI)
Organic FCF Organic FCF Yield (Annual Avg.)
$2.2B+
Cumulative
Organic FCF
Org
an
ic F
CF
Yie
ld (
An
nu
al
Avg
.)
$750MM+
Cumulative
Organic FCF
Organic FCF+
Above $45/bbl
in Both Years
2019 – 2020
($50 WTI)
2019 – 2020
($45 WTI)
*Organic FCF yield represents average annualized yield for 2019 and 2020 using MRO stock price as of 2/8/19
5
Differentiated Execution Led the Way in 2018Underpins confidence in 2019 delivery
2018 ObjectivesInitial Guidance Actual Delivery
@$50/bbl WTI @$65/bbl WTI
Capital Discipline $2.3B development capital $2.3B development capital
Corporate Returns30% CROIC improvement 78% CROIC improvement
10% CFPDAS improvement 65% CFPDAS improvement
Free Cash FlowOrganic FCF positive, post-
dividend, above $50/bbl WTI
$865MM of post-dividend,
organic FCF
Return of CapitalPrioritize incremental return,
above dividend, through
sustainable organic FCF
$700MM of share buybacks
and $170MM dividend
Capital Efficient Oil
Growth
18% total oil growth at
midpoint, divestiture
adjusted
24% total oil growth,
divestiture adjusted
22.5% resource play oil
growth at midpoint
32% resource play oil
growth
6
Eagle Ford
Bakken
Oklahoma
Northern
Delaware
Resource Play
Capital Allocation
Resource Play
Development
REx
Other
Focused program balances corporate returns with strategic objectives
• Total capital program of $2.6B, down from 2018
– Comprised of $2.4B development capital and $200MM of resource play leasing and exploration (REx) capital
– Planning basis of $50/bbl WTI; organic free cash flow positive above $45/bbl WTI, post-dividend
• Over 95% of development capital allocated to U.S. resource plays
– ~60% of resource play capital allocated to Eagle Ford and Bakken with ~40% to Oklahoma and Northern Delaware, similar to 2018
– Capital efficient oil growth on flat wells to sales drives corporate returns improvement
– Development capital continues to fund organic resource base enhancement initiatives
• Year-over-year reduction in REx capital reflects more ratable forward spending profile
– Continues progression of LA Austin Chalk and other emerging opportunities with focus on full cycle returns
Focused Investment
7
2019 Capital Program Overview
Appraise / Delineate Early Development Full Field Development
2019 Basin Level Highlights and Objectives
Competitively advantaged multi-basin model
• 85 - 95 gross operated wells to sales
• 90% Myrmidon and Core Hector
• Continue organic enhancement initiatives
• Returns, free cash flow, oil growth
• 55 - 60 gross operated wells to sales
• Focus on Malaga Upper Wolfcamp and
Red Hills delineation
• Transition to multi-well pads
• Returns, oil growth, and margin
enhancement
Northern Delaware
• 55 - 60 gross operated wells to sales
• Development focus on overpressured
STACK and SCOOP; 95% pad drilling
• Secondary target delineation
• Predictability and competitive returns
Oklahoma
• 125 - 135 gross operated wells to sales
• 90% Karnes and Core Atascosa
• Continue organic enhancement initiatives
• Progress multi-well Phase 2 enhanced oil
recovery (EOR) pilot
• Returns and free cash flow
Eagle Ford
Bakken
8
2018 Highlights
Full-year 2018 Highlights
• Delivered capital discipline, corporate returns improvement, free cash flow generation, and enhanced return of capital to shareholders
• Drove capital efficiency improvement leading to high margin oil growth outperformance
• Enhanced resource base through core extension tests in Eagle Ford and Bakken; progressed REx program with focus on full-cycle returns
• 125% reserve replacement at <$12.50/BOE
• Closed $450MM Libya sale; received final Oil Sands Mining payment of $750MM
• Further strengthened balance sheet and financial flexibility by increasing cash and cash equivalents by ~$900MM to $1.5B at YE 2018
4Q 2018 Highlights
• $255MM of organic FCF
• Development capex down 10% sequentially to ~$500MM
• Another quarter of differentiated multi-basin execution and capital efficiency improvement
− Eagle Ford: 38 wells achieved an avg. IP 30 of 1,810 BOED (72% oil)
− Bakken: Ajax four-well pad extension test achieved avg. IP 30 of 2,370 BOED (81% oil) at ~$5MM completed well cost (CWC)
− Oklahoma: 3R SCOOP infill >60% above type curve at 45 days; positive Springer delineation well
− Northern Delaware: 4 Upper Wolfcamp wells avg. IP 30 of 340 BOED/1,000 ft. lateral (74% oil)
9
563
1,431 1,462
3,245
2,286
169
78
369
700
1,151
51
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
1/1/18 CashBalance
OperatingCash Flow
b/f WC
DevelopmentCapital
Expenditures
Dividends EG LNGReturn ofCapital& Other
CashBalanceb/f A&D,REx &
Financing
REx Capex Share Buy-Back
Acquisitions&
Disposal ofAssets (Net)
TotalWorkingCapital
12/31/18Cash
Balance
$M
M
12
3
Total Company Cash Flow for 2018
• $2.3B annual development capital budget unchanged throughout year
• $700MM of stock buy-backs and ~$170MM of annual dividend; over 25% of operating cash flow
returned to shareholders in 2018
• $369MM REx Capex more than fully funded by disposition proceeds
Generated ~$865MM of organic free cash flow at avg. WTI of $65/bbl
1 Excludes $34MM of exploration costs other than well costs
2 Acquisition and Disposal of Assets includes $105MM BLM lease costs, Libya disposition & OSM final payment
3Total working capital includes $17MM and $(68)MM of working capital changes associated with operating activities and investing activities, respectively & other
See the 4Q 2018 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations10
Standout Year for Eagle Ford on All Fronts
Full-year 2018 Highlights
• 2018 oil production growth of 7% on 5% fewer
gross operated wells to sales (WTS)
• 40 Atascosa wells achieved avg. IP 30 of 1,510
BOED (72% oil), demonstrating strength of
extended core
• Compelling returns, significant free cash flow
generation, improved well productivity
– 180-day cumulative production up 10% vs. 2017 and
up 45% vs. 2016
4Q 2018 Highlights
• Production averaged 107 net MBOED, up 2%
from year-ago quarter
• 38 WTS with avg. IP 30 of 1,810 BOED (72% oil)
• Completion stages per day up over 10% and
avg. CWC per lateral foot down over 15% vs.
year-ago quarter
Well performance history composed of MRO operated wells across all formations
Well Performance History
Production Volumes and Wells to Sales
0
20
40
60
0
40
80
120
1Q18 2Q18 3Q18 4Q18
Op
era
ted
We
lls
to
Sa
les
Production Gross Wells Net WI Wells
MB
OE
D
0
50
100
150
0 45 90 135 180
2017
2016
2015
Avg
. C
um
. P
rod
ucti
on
(M
BO
E)
Days
2018
Year-over-year growth on fewer wells to sales
11
Strong Well Productivity from the Eagle Ford Core
Guajillo East5 well pad
1,480 BOED (82% oil)
~5,960’ LL
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average
Live Oak
Bee
KarnesAtascosa
Wilson
4Q18 Pads
to Sales
CRH / Fire Opal3 well pad
1,800 BOED (73% oil)
~5,500’ LL
Challenger B / Medina H.3 well pad
1,470 BOED (79% oil)
~5,230’ LL
Jordan / Fransen / GM5 well pad
1,550 BOED (69% oil)
~3,270’ LL
San Christoval Ranch3 well pad
1,640 BOED (48% oil)
~3,310’ LLLuna / May
4 well pad
1,480 BOED (56% oil)
~5,750’ LL
Kowalik3 well pad
2,940 BOED (68% oil)
~8,950’ LL
Brown D. / Holland B.6 well pad
2,070 BOED (74% oil)
~6,010’ LL
Medina-Jonas6 well pad
1,940 BOED (83% oil)
~6,750’ LL
4Q 2018 wells driving robust corporate returns
12
~50% Y/Y Capital Efficiency Improvement
1,000
1,500
2,000
2,500
3,000
4Q17 4Q18
BO
ED
IP 30 BOED*
+15%
$4
$5
$6
$7
$8
4Q17 4Q18
CW
C (
$M
M)
CWC ($MM)
-24%
Bakken Performance Consistently Enhancing Value
* IP 30 rates normalized to 9500’.
0
10
20
30
0
20
40
60
80
100
1Q18 2Q18 3Q18 4Q18
Production Gross Wells Net WI Wells
MB
OE
D
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
Successful core extension tests in Ajax, Southern Hector, and Elk Creek
Full-year 2018 Highlights
• Capital efficient oil production growth of 53%
• 20 Northern Hector wells achieved avg. IP 30 of
2,390 BOED (78% oil), demonstrating strength of
extended core
4Q 2018 Highlights
• Production averaged 94 net MBOED, up 37%
from year-ago quarter
• 27 WTS avg. IP 30 of 3,335 BOED (76% oil)
• Ajax four-well pad extension test achieved avg. IP
30 of 2,370 BOED (81% oil) at ~$5MM CWC
• Avg. IP 30 up 15% with CWC down 24% vs. year-
ago quarter
– 8 wells achieved sub $5MM CWC with avg. IP 30 of
2,850 BOED (76% oil)
– Completion stages per day up over 65% from year-
ago quarter
13
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
30-d
ay I
P (
BO
PD
)
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
30-d
ay I
P (
BO
PD
)Leading Williston Basin Well Productivity
IPs shown in map are 30-day (includes oil, NGL and gas) and represent pad average
Source: Drilling info, competitor presentations and internal data. External data available through 4Q 2018.
Delivered 45 of the top 50 all-time Middle Bakken & Three Forks oil wells
McKenzie
Dunn
Myrmidon
Hector
Elk Creek
AjaxQ4 2018
to Sales
Axell, Nugget & Ness Pads
9 wells
3,450 BOED
(74% oil)
Irish Pad
3 wells
3,140 BOED
(74% oil)
Ringer Pad
2 wells
2,385 BOED
(84% oil)
Gloria Pad
4 wells
2,370 BOED
(81% oil)
Clara Pad
4 wells
3,510 BOED
(73% oil)
Julia Jones Pad
5 wells
4,250 BOED
(75% oil)
Historic Three Forks Well Performance
Historic Middle Bakken Well Performance
MRO 2018 MRO 2017 Peers
MRO 2018 Peers
14
0
4
8
12
16
20
0
20
40
60
80
100
1Q18 2Q18 3Q18 4Q18
Production Gross Wells Net WI Wells
Enhanced Returns & Predictability Continue in Oklahoma
Full-year 2018 Highlights
• Successful transition to infill development in overpressured STACK and SCOOP
– Competitive returns and predictable results at various spacing designs
• Completion cost per lateral ft. down >30% from prior year
4Q 2018 Highlights
• 67 net MBOED production, up 4% from year-ago quarter
• 8 well per section 3R SCOOP Woodford infill delivered avg. IP 30 of 2,600 BOED(69% liquids)
– CWC/lateral ft. ~35% below most recent SCOOP Woodford infill (Lightner)
– Springer delineation well on same pad delivers IP 30 of 1,825 BOED (81% oil)
• Completion stages per day up 55% from year-ago quarter
3R SCOOP Infill >60% Above Type Curve at 45 Days
0
40
80
120
160
0 15 30 45 60 75
Type Curve
Lightner Wells - 4 wells on 8 wps
3R Wells - 8 wps
MB
OE
D
Days
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
MB
OE
D
15
SCOOP infills outperforming type curve
wps – wells per section spacing
Focused on Overpressured STACK and SCOOP
Caddo
Grady
Stephens
Blaine
Canadian
Kingfisher
Wet Gas
Condensate
Oil
4Q18 Wells to Sales
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average on the 3R, and single well on the Papa Pump
Burton
Ellis
Olive June
Lloyd
Ruthie
Calvin
3R7 Woodford infill wells (8 wps)
2,600 BOED (69% liquids)
~10,000’ LL
Papa Pump1 Springer delineation well
1,825 BOED (81% oil)
~8,480’ LLUpcoming Infills
Multi-well development continues
16
4Q17 4Q18
Stages/day
Full-year 2018 Highlights
• Risked gross company operated locations up
~20% since play entry
• Drilling ft. per day up >20% and completion
stages per day up >30% vs. 2017
• Improved midstream access for all products
4Q 2018 Highlights
• 26 net MBOED production, up 138% from
year-ago quarter
• 12 WTS avg. IP 30 of 1,935 BOED (49% oil),
or 360 BOED per 1,000 ft. lateral
– 4Q activity featured successful Lower Wolfcamp
(WC) spacing test
– 4 Upper WC wells avg. IP 30 of 340 BOED per
1,000 ft lateral (74% oil)
• Executed comprehensive water handling
agreement covering Red Hills area
• Completion stages per day up 40% from year-
ago quarter
Strategically Pacing Northern Delaware
0
5
10
15
20
25
0
5
10
15
20
25
30
1Q18 2Q18 3Q18 4Q18
Production Gross Wells Net WI Wells
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
Co
mp
leti
on
sta
ges/d
ay
Capturing Significant Efficiency Gains
MB
OE
D
+40%
Focus on multi-well pads while progressing delineation
17
International Highlights
Alba Gas Plant
AMPCO Methanol Plant
EGLNG Plant
World Class Gas Infrastructure
Alba Gas Plant
AMPCO Methanol Plant
EGLNG Plant
Full-year 2018 Highlights
• Production of 113 net MBOED
• E.G. EBITDAX of over $650MM
• Reduced estimated U.K. asset retirement
obligation by $143MM
• Continued rigorous portfolio management
– Closed $450MM Libya sale; received final Oil
Sands Mining payment of $750MM
– Progressing full Kurdistan exit, which will mark 9th
country exit in last 5 years
4Q 2018 Highlights
• Production of 105 net MBOED
– 1Q19 volume guidance includes impact of E.G.
triennial turnaround
• E.G. EBITDAX of $153MM
18
Framework for SuccessPrioritizing Corporate Returns, FCF, Return of Capital to Shareholders
“While many in our industry talked about capital discipline, we delivered… Through improving capital efficiency and
unwavering discipline, we drove significant improvement to our corporate returns, delivered more oil growth, generated $865
million of organic free cash flow post-dividend, and returned most of that cash back to our shareholders via share
repurchases. As we turn to 2019 and beyond, we remain committed to this same framework for success.”
- Lee Tillman, Chairman, President and CEO
• Multi-year CROIC
improvement
• Organic FCF above $45/bbl
• Prioritizing return of cash
• $2.4B development capital
budget
• 10% total company oil growth
& 12% U.S. oil growth
• $200MM REx budget
Our Plan - 2019
• 78% realized CROIC
improvement
• $865MM of organic FCF
• $700MM of share buybacks
• Unchanged $2.3B
development capital budget
• 24% total company oil growth
vs. 18% initial guidance
• $369MM REx spend
Our Delivery - 2018
• Corporate Returns
• FCF Generation
• Return of Capital to
Shareholders
• Differentiated
Execution
Our Framework
Our Foundation
• Multi-Basin Portfolio • Balance Sheet Strength
19
Appendix
20
2019 Production Guidance
FY19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)
2019 2018* 2019 2018*
United States 185 - 195 169 320 - 330 295
International 20 - 30 27 90 - 100 110
Total Net Production 205 - 225 196 410 - 430 405
1Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)
Q1 2019 Q4 2018* Q1 2018* Q1 2019 Q4 2018* Q1 2018*
United States 175 - 185 180 160 295 - 305 306 278
International 20 - 30 23 30 85 - 95 102 110
Total Net Production 195 - 215 203 190 380 - 400 408 388
* Divestiture-adjusted, and also excludes Atrush volumes which are held for sale
21
2019 Cost and Tax Rate Guidance
Full-Year Estimate
United States Cost Data
Production Operating $4.50 – 5.50
DD&A $19.25 – 21.75
S&H and Other* $4.00 – 4.50
International Cost Data
Production Operating $4.75 – 5.75
DD&A $3.75 – 5.25
S&H and Other* $1.00 – 1.50
Expected Tax Rates by Jurisdiction:
United States and Corporate Tax Rate 0%
Equatorial Guinea Tax Rate 25%
United Kingdom Tax Rate 40%
* Excludes G&A expense
22
United States Crude Oil DerivativesAs of February 12, 2019
Crude Oil (Benchmark to NYMEX WTI)
1Q 2019 2Q 2019 3Q 2019 4Q 2019 FY 2020
Three-Way Collars
Volume (BBLs/day) 70,000 70,000 50,000 50,000 -
Weighted Avg Price per BBL:
Ceiling $71.21 $71.21 $75.88 $75.88 -
Floor $55.86 $55.86 $57.80 $57.80 -
Sold put $48.71 $48.71 $50.80 $50.80 -
Midland to Cushing Basis Swaps
Volume (BBLs/day) 10,000 11,000 16,000 16,000 15,000
Weighted Avg Price per BBL $(0.82) $(1.06) $(1.53) $(1.53) $(0.94)
NYMEX Roll Basis Swaps
Volume (BBLs/day) 60,000 60,000 60,000 60,000 -
Weighted Avg Price per BBL $0.38 $0.38 $0.38 $0.38 -
23
United States Natural Gas DerivativesAs of February 12, 2019
Natural Gas (Benchmark to NYMEX HH)
1Q19
Three-Way Collars
Volume (MMBtu/day) 200,000
Weighted Avg Price per MMBtu:
Ceiling $5.25
Floor $3.43
Sold put $2.88
24
1Q 2Q 3Q 4Q Full-Year
United States Net Sales Volumes:
- Crude Oil and Condensate (MBD) 164 168 173 180 171
- Natural Gas Liquids (MBD) 50 57 58 55 55
- Natural Gas (MMCFD) 420 435 433 422 429
- United States Total (MBOED) 284 298 303 305 298
International Net Sales Volumes:
- Crude Oil and Condensate (MBD) 35 32 27 29 32
- Natural Gas Liquids (MBD) 11 12 11 10 11
- Natural Gas (MMCFD) 415 461 441 411 430
- International Total (MBOED) 115 121 112 108 114
Total Sales Volumes (MBOED) 399 419 415 413 412
Total Available for Sale (MBOED) 398 419 419 411 412
Equity Method Investment Net Sales Volumes:
- LNG (metric tonnes/day) 5,541 6,141 6,152 5,384 5,805
- Methanol (metric tonnes/day) 1,195 1,316 1,334 1,119 1,241
- Condensate and LPG (BOED) 12,416 12,689 11,942 15,071 13,034
Exploration Expenses (Pre-tax):
- United States ($ millions) 51 64 55 76 246
- International ($ millions) 1 1 1 0 3
Consolidated Effective Tax Rate (ex. Libya) Provision 2% 31% 29% 4% 14%
2018 Volumes, Exploration Expense & Effective Tax RateExcluding Libya
25
4Q 2018 Net Sales Volumes and Realizations
U.S. Divestiture-Adj. Sales Volumes*
MB
OE
D
257
301 305
0
100
200
300
4Q17 3Q18 4Q18
Avg C&C
Realizations
($/BBL)
Excluding Derivatives
$55.46 $68.51 $56.01
Including Derivatives
$54.70 $62.81 $54.51
*U.S. adjusted for divestitures of 5 MBOED in 4Q17 and 2 MBOED in 3Q18
**International available for sale volumes adjusted for divestitures/held for sale of
37 MBOED in 4Q17, 3 MBOED in 3Q18, and 3 MBOED in 4Q18. Sales volumes
adjusted for divestitures/held for sale of 36 MBOED in 4Q17, 4 MBOED in 3Q18,
and 3 MBOED in 4Q18
MB
OE
D
International Divestiture-Adj. Volumes**
117 117 112 108 102 106
0
25
50
75
100
125
4Q 17 3Q 18 4Q 18
Avg C&C
Realizations
($/BBL)***
$54.03 $64.08 $58.25
*** Adjusted the average C&C by $7.29 to exclude Libya in 4Q17
Cumulative underlift of (138) MBOE in E.G., and cumulative
overlift of 6 MBOE in Kurdistan and 68 MBOE in U.K.
SalesAvailable for Sale
4Q17 3Q18 4Q18
26
4Q 2018 Production Mix
58%22%
20% 24%
28%
48%
88%
6%6%
59%18%
23%
Crude Oil/Condensate
NGLs
Natural Gas
Eagle Ford Oklahoma
Bakken
Total U.S.
Resource Plays
54%
19%
27%
Northern Delaware
27
2018 Capital, Investment & ExplorationBudget reconciliation $MM
2018
Budget
2018
Actual
Cash additions to Property, Plant and Equipment 2,753
Working Capital associated with PPE (68)
Property, Plant and Equipment additions 2,685
M&S Inventory (6)
REx expenditures included in capital expenditures (388)
Exploration costs other than well costs (5)
Development Capital 2,300 2,286
28