2019 CAPITAL PROGRAM & 2018 RESULTS - February 13, 2019 - Zone Bourse
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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
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
Forward Outlook Prioritizes Returns, FCF, Return of Capital
1
Organic FCF positive in both 2019 and 2020 above $45/bbl WTI, post-dividend
• Continues multi-year rate of change improvement in key enterprise
performance metrics
Corporate Returns − 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
• Organic FCF positive above $45/bbl WTI in both 2019 and 2020
• Portfolio delivers strong two-year (2019-2020) organic FCF
Free Cash Flow
− >$750MM at $50/bbl WTI flat
− >$2.2B at $60/bbl WTI flat
• Continue to prioritize return of capital
− Returned over 25% of operating cash flow to shareholders in
Return of Capital 2018
− Return of capital metric incorporated into executive
compensation scorecard, complementing CROIC and CFPDAS
• High value oil growth exceeds BOE growth, an outcome of returns-
first capital allocation
Differentiated Execution − 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
4 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
Sustainable FCF in 2019 & 2020 at Conservative Pricing
Differentiated annual FCF yield vs. E&P peers
$2.2B+
Cumulative
2,500 Organic FCF 10%
Organic FCF Yield (Annual Avg.)
Cumulative Organic FCF ($MM)
2,000
$750MM+
1,500 Cumulative
Organic FCF
5%
1,000
Organic FCF+
Above $45/bbl
500 in Both Years
0 0%
2019–- 2020
2019 2020 2019–- 2020
2019 2020 2019–
2019 - 2020
2020
($45 WTI) ($50 WTI) ($60 WTI)
Organic FCF Organic FCF Yield (Annual Avg.)
*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 2018
Underpins confidence in 2019 delivery
Initial Guidance Actual Delivery
2018 Objectives
@$50/bbl WTI @$65/bbl WTI
Capital Discipline $2.3B development capital $2.3B development capital
30% CROIC improvement 78% CROIC improvement
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
Return of Capital above dividend, through
and $170MM dividend
sustainable organic FCF
18% total oil growth at
24% total oil growth,
midpoint, divestiture
Capital Efficient Oil adjusted
divestiture adjusted
Growth 22.5% resource play oil 32% resource play oil
growth at midpoint growth
6
2019 Capital Program Overview
Focused program balances corporate returns with strategic objectives
• Total capital program of $2.6B, down from 2018 Focused Investment
– Comprised of $2.4B development capital and $200MM
of resource play leasing and exploration (REx) capital
Resource Play
– Planning basis of $50/bbl WTI; organic free cash flow Development
positive above $45/bbl WTI, post-dividend Other
REx
• 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 Resource Play
– Capital efficient oil growth on flat wells to sales drives Capital Allocation
corporate returns improvement
– Development capital continues to fund organic Northern
resource base enhancement initiatives Eagle Ford
Delaware
• Year-over-year reduction in REx capital reflects more
ratable forward spending profile Oklahoma
– Continues progression of LA Austin Chalk and other Bakken
emerging opportunities with focus on full cycle returns
7
2019 Basin Level Highlights and Objectives
Competitively advantaged multi-basin model
Appraise / Delineate Early Development Full Field Development
Bakken
Oklahoma
• 85 - 95 gross operated wells to sales
• 90% Myrmidon and Core Hector • 55 - 60 gross operated wells to sales
• Continue organic enhancement initiatives • Development focus on overpressured
STACK and SCOOP; 95% pad drilling
• Returns, free cash flow, oil growth
• Secondary target delineation
• Predictability and competitive returns
Northern Delaware Eagle Ford
• 55 - 60 gross operated wells to sales
• 125 - 135 gross operated wells to sales
• Focus on Malaga Upper Wolfcamp and
Red Hills delineation • 90% Karnes and Core Atascosa
• Transition to multi-well pads • Continue organic enhancement initiatives
• Returns, oil growth, and margin • Progress multi-well Phase 2 enhanced oil
enhancement recovery (EOR) pilot
• Returns and free cash flow
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 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
Total Company Cash Flow for 2018
Generated ~$865MM of organic free cash flow at avg. WTI of $65/bbl
• $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
4,000
3,500
3,000
2,286
2,500
$MM
3,245
2,000
1,500 78
369 51
169
1,000 1,151
1,431 700 1,462
500
563
0
1/1/18 Cash Operating Development Dividends EG LNG Cash REx Capex Share Buy- Acquisitions Total 12/31/18
Balance Cash Flow Capital Return of Balance Back & Working Cash
b/f WC 1 Expenditures Capital b/f A&D, Disposal of Capital 3 Balance
2
& Other REx & Assets (Net)
Financing
1 Excludes $34MM of exploration costs other than well costs
2 Acquisitionand 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
10
See the 4Q 2018 Investor Packet at www.Marathonoil.com for non-GAAP reconciliationsStandout Year for Eagle Ford on All Fronts
Year-over-year growth on fewer wells to sales
Production Volumes and Wells to Sales Full-year 2018 Highlights
120 60
• 2018 oil production growth of 7% on 5% fewer
Operated Wells to Sales
gross operated wells to sales (WTS)
80 40
• 40 Atascosa wells achieved avg. IP 30 of 1,510
MBOED
40 20
BOED (72% oil), demonstrating strength of
extended core
0 0 • Compelling returns, significant free cash flow
1Q18 2Q18 3Q18 4Q18
generation, improved well productivity
Production Gross Wells Net WI Wells
– 180-day cumulative production up 10% vs. 2017 and
Well Performance History up 45% vs. 2016
Avg. Cum. Production (MBOE)
2018 4Q 2018 Highlights
150 2017
• Production averaged 107 net MBOED, up 2%
2016
100 2015 from year-ago quarter
• 38 WTS with avg. IP 30 of 1,810 BOED (72% oil)
50
• Completion stages per day up over 10% and
0
avg. CWC per lateral foot down over 15% vs.
0 45 90 135 180 year-ago quarter
Days
Well performance history composed of MRO operated wells across all formations
11Strong Well Productivity from the Eagle Ford Core
4Q 2018 wells driving robust corporate returns
Jordan / Fransen / GM Challenger B / Medina H. CRH / Fire Opal
5 well pad 3 well pad 3 well pad
1,550 BOED (69% oil) 1,470 BOED (79% oil) 1,800 BOED (73% oil)
~3,270’ LL ~5,230’ LL ~5,500’ LL
Wilson Medina-Jonas
6 well pad
1,940 BOED (83% oil)
~6,750’ LL
Brown D. / Holland B.
Atascosa Karnes 6 well pad
San Christoval Ranch 2,070 BOED (74% oil)
3 well pad
~6,010’ LL
1,640 BOED (48% oil)
~3,310’ LL
Luna / May
4 well pad
Guajillo East 1,480 BOED (56% oil)
5 well pad ~5,750’ LL
1,480 BOED (82% oil)
~5,960’ LL Kowalik
3 well pad
Bee 2,940 BOED (68% oil)
4Q18 Pads ~8,950’ LL
to Sales Live Oak
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average
12Bakken Performance Consistently Enhancing Value
Successful core extension tests in Ajax, Southern Hector, and Elk Creek
Production Volumes and Wells to Sales Full-year 2018 Highlights
100 30
• Capital efficient oil production growth of 53%
Operated Wells to Sales
80
20 • 20 Northern Hector wells achieved avg. IP 30 of
60
MBOED
2,390 BOED (78% oil), demonstrating strength of
40
10 extended core
20
4Q 2018 Highlights
0 0
1Q18 2Q18 3Q18 4Q18 • Production averaged 94 net MBOED, up 37%
Production Gross Wells Net WI Wells from year-ago quarter
~50% Y/Y Capital Efficiency Improvement • 27 WTS avg. IP 30 of 3,335 BOED (76% oil)
3,000 $8 • Ajax four-well pad extension test achieved avg. IP
+15% 30 of 2,370 BOED (81% oil) at ~$5MM CWC
2,500 $7
CWC ($MM)
• Avg. IP 30 up 15% with CWC down 24% vs. year-
BOED
2,000 $6
-24% ago quarter
1,500 $5 – 8 wells achieved sub $5MM CWC with avg. IP 30 of
2,850 BOED (76% oil)
1,000 $4
4Q17 4Q18 4Q17 4Q18 – Completion stages per day up over 65% from year-
ago quarter
IP 30 BOED* CWC ($MM)
* IP 30 rates normalized to 9500’.
13Leading Williston Basin Well Productivity
Delivered 45 of the top 50 all-time Middle Bakken & Three Forks oil wells
Irish Pad
Historic Middle Bakken Well Performance
Julia Jones Pad 3 wells
4,000 5 wells 3,140 BOED
4,250 BOED (74% oil)
3,500 (75% oil)
30-day IP (BOPD)
3,000
Axell, Nugget & Ness Pads
2,500 Myrmidon
Clara Pad 9 wells
2,000 3,450 BOED
4 wells
1,500 3,510 BOED (74% oil)
1,000 (73% oil)
500
McKenzie
0
MRO 2018 MRO 2017 Peers
Elk Creek
Historic Three Forks Well Performance
5,000
4,500 Ringer Pad
Hector 2 wells
30-day IP (BOPD)
4,000 Dunn
3,500 2,385 BOED
(84% oil)
3,000
2,500
2,000
Gloria Pad
1,500
4 wells
1,000
2,370 BOED
500 (81% oil)
Q4 2018 Ajax
0
to Sales
MRO 2018 Peers
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.
14Enhanced Returns & Predictability Continue in Oklahoma
SCOOP infills outperforming type curve
Production Volumes and Wells to Sales Full-year 2018 Highlights
100 20
• Successful transition to infill development in
Operated Wells to Sales
80 16 overpressured STACK and SCOOP
60 12 – Competitive returns and predictable results at
MBOED
various spacing designs
40 8
• Completion cost per lateral ft. down >30%
20 4 from prior year
0 0
1Q18 2Q18 3Q18 4Q18 4Q 2018 Highlights
Production Gross Wells Net WI Wells • 67 net MBOED production, up 4% from
year-ago quarter
3R SCOOP Infill >60% Above Type Curve at 45 Days • 8 well per section 3R SCOOP Woodford
Type Curve
infill delivered avg. IP 30 of 2,600 BOED
160 Lightner Wells - 4 wells on 8 wps (69% liquids)
3R Wells - 8 wps
– CWC/lateral ft. ~35% below most recent
120 SCOOP Woodford infill (Lightner)
MBOED
80 – Springer delineation well on same pad delivers
IP 30 of 1,825 BOED (81% oil)
40
• Completion stages per day up 55% from
0
year-ago quarter
0 15 30 45 60 75
Days
wps – wells per section spacing
15Focused on Overpressured STACK and SCOOP
Multi-well development continues
Olive June Blaine Kingfisher
Lloyd
Ruthie Canadian
Ellis
Calvin
Caddo Burton
Grady 3R
7 Woodford infill wells (8 wps)
2,600 BOED (69% liquids)
~10,000’ LL
Papa Pump
1 Springer delineation well
1,825 BOED (81% oil)
Wet Gas 4Q18 Wells to Sales ~8,480’ LL
Condensate Upcoming Infills
Oil Stephens
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average on the 3R, and single well on the Papa Pump
16Strategically Pacing Northern Delaware
Focus on multi-well pads while progressing delineation
Production Volumes and Wells to Sales Full-year 2018 Highlights
30 25
• Risked gross company operated locations up
Operated Wells to Sales
25 20 ~20% since play entry
20
• Drilling ft. per day up >20% and completion
MBOED
15
15
10 stages per day up >30% vs. 2017
10
5 • Improved midstream access for all products
5
0 0 4Q 2018 Highlights
1Q18 2Q18 3Q18 4Q18
• 26 net MBOED production, up 138% from
Production Gross Wells Net WI Wells
year-ago quarter
Capturing Significant Efficiency Gains • 12 WTS avg. IP 30 of 1,935 BOED (49% oil),
or 360 BOED per 1,000 ft. lateral
Completion stages/day
– 4Q activity featured successful Lower Wolfcamp
(WC) spacing test
+40%
– 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
4Q17 4Q18 • Completion stages per day up 40% from year-
Stages/day ago quarter
17International Highlights
World Class Gas Infrastructure Full-year 2018 Highlights
EGLNG
EGLNG Plant
Plant • Production of 113 net MBOED
• E.G. EBITDAX of over $650MM
• Reduced estimated U.K. asset retirement
obligation by $143MM
Alba
• Continued rigorous portfolio management
Alba
GasGas
Plant
Plant – 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
AMPCO
AMPCO Methanol
Methanol Plant
Plant
• Production of 105 net MBOED
– 1Q19 volume guidance includes impact of E.G.
triennial turnaround
• E.G. EBITDAX of $153MM
18Framework for Success
Prioritizing 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
Our Framework Our Delivery - 2018 Our Plan - 2019
• 78% realized CROIC • Multi-year CROIC
improvement improvement
• Corporate Returns
• $865MM of organic FCF • Organic FCF above $45/bbl
• FCF Generation
• $700MM of share buybacks • Prioritizing return of cash
• Return of Capital to
• Unchanged $2.3B • $2.4B development capital
Shareholders development capital budget budget
• Differentiated • 24% total company oil growth • 10% total company oil growth
Execution vs. 18% initial guidance & 12% U.S. oil growth
• $369MM REx spend • $200MM REx budget
Our Foundation
• Multi-Basin Portfolio • Balance Sheet Strength
19Appendix 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
212019 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
22United States Crude Oil Derivatives
As 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 -
Basis Swaps (a)/(b)
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 -
(a) The basis differential price is between WTI Midland and WTI Cushing
(b) Between January 1, 2019 and February 12, 2019, the Company entered into 5,000 Bbls/day of Midland basis swaps for July - December 2019 with an average price of $(2.55) and
1,000 Bbls/day of Clearbrook basis swaps for March - December 2019 with an average price of $(3.50)
23United States Natural Gas Derivatives
As 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 $2.88
242018 Volumes, Exploration Expense & Effective Tax Rate
Excluding Libya
1Q 2Q 3Q 4Q Full-Year
United States Net Sales Volumes:
- Crude Oil and Condensate (MBD) 164 168 173 180 171
- Natural Gas Liquids (MBD) 50 57 58 55 55
- Natural Gas (MMCFD) 420 435 433 422 429
- United States Total (MBOED) 284 298 303 305 298
International Net Sales Volumes:
- Crude Oil and Condensate (MBD) 35 32 27 29 32
- Natural Gas Liquids (MBD) 11 12 11 10 11
- Natural Gas (MMCFD) 415 461 441 411 430
- International Total (MBOED) 115 121 112 108 114
Total Sales Volumes (MBOED) 399 419 415 413 412
Total Available for Sale (MBOED) 398 419 419 411 412
Equity Method Investment Net Sales Volumes:
- LNG (metric tonnes/day) 5,541 6,141 6,152 5,384 5,805
- Methanol (metric tonnes/day) 1,195 1,316 1,334 1,119 1,241
- Condensate and LPG (BOED) 12,416 12,689 11,942 15,071 13,034
Exploration Expenses (Pre-tax):
- United States ($ 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%
254Q 2018 Net Sales Volumes and Realizations
U.S. Divestiture-Adj. Sales Volumes* International Divestiture-Adj. Volumes**
125
300
100
200 75
MBOED
MBOED
301 305 117 117 112 108
257 50 102 106
100
25
0 0
4Q17 3Q18 4Q18 4Q1717
4Q 3Q3Q18
18 4Q1818
4Q
Available for Sale Sales
Excluding Derivatives Avg C&C
Realizations $54.03 $64.08 $58.25
Avg C&C $55.46 $68.51 $56.01 ($/BBL)***
Realizations
($/BBL) Including Derivatives
$54.70 $62.81 $54.51
*U.S. adjusted for divestitures of 5 MBOED in 4Q17 and 2 MBOED in 3Q18 *** Adjusted the average C&C by $7.29 to exclude Libya in 4Q17
**International available for sale volumes adjusted for divestitures/held for sale of Cumulative underlift of (138) MBOE in E.G., and cumulative
26 37 MBOED in 4Q17, 3 MBOED in 3Q18, and 3 MBOED in 4Q18. Sales volumes overlift of 6 MBOE in Kurdistan and 68 MBOE in U.K.
adjusted for divestitures/held for sale of 36 MBOED in 4Q17, 4 MBOED in 3Q18,
and 3 MBOED in 4Q184Q 2018 Production Mix
Eagle Ford Oklahoma
20% 24% Total U.S.
Resource Plays
48%
22% 58%
28%
23%
Crude Oil/Condensate
NGLs
18% 59%
Bakken Northern Delaware
Natural Gas
6%6%
27%
54%
88% 19%
272018 Capital, Investment & Exploration
Budget reconciliation $MM
2018 2018
Budget 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
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