-
SECOND QUARTER 2020
August 5, 2020
-
Forward-Looking Statements and Other Matters
2
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 capital budgets and allocations (including development capital budget and resource play leasing and exploration spend), future performance, 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, leasing and exploration activities, future financial position, tax rates and other plans and objectives for future operations. Words such as “anticipate”, “believe”, “could”, “enter,” “estimate”, “expect”, “forecast”, “future”, “guidance”, “intend”, “line of sight,” “may”, “outlook”, “plan”, “positioned,” “potential”, “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, but not limited to: conditions in the oil and gas industry, including supply/demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the U.S. and Equatorial Guinea, including changes in foreign currency exchange rates, interest rates, inflation rates; actions taken by the members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia affecting the production and pricing of crude oil; and other global and domestic political, economic or diplomatic developments; capital available for exploration and development; risks related to the Company’s hedging activities; voluntary or involuntary curtailments, delays or cancellations of certain drilling activities; well production timing; liability resulting from litigation; drilling and operating risks; lack of, or disruption in, access to storage capacity, pipelines or other transportation methods; 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, a health pandemic (including COVID-19), acts of war or terrorist acts and the government or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations, requirements or initiatives, including initiatives addressing the impact of global climate change, air emissions, or water management; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company’s 2019 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at https://ir.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 operating cash flow before working capital, and pro-forma cash balance. Reconciliations of the differences between non-GAAP financial measures used in this presentation and their most directly comparable GAAP financial measures are available at https://ir.marathonoil.com/ in the 2Q20 Investor Packet.
https://ir.marathonoil.com/https://ir.marathonoil.com/
-
Maintaining Focus During Unprecedented TimesStrong results in a challenging environment
“Amid tremendous commodity volatility, our ongoing response to the COVID-19 global
pandemic, and a challenging year for our industry, we have remained focused on the
factors we can control: how we allocate capital, how we manage our cost structure, and
how we execute… Our differentiated capital efficiency is illustrated by a 2021 benchmark
maintenance scenario that we believe could deliver total Company oil production in-line
with 4Q20 at a free cash flow breakeven of approximately $35/bbl.”
Chairman, President, and CEO Lee Tillman
3
-
Capital Efficiency Outperforming on Differentiated Execution
Managing Cost
Structure
• Record low U.S. unit production costs during 2Q20 of $4.09 per BOE
• Successfully implemented cash cost reduction efforts and on track to realize
$260MM of savings in 2020, inclusive of 2Q20 severance payments
• Driving 17% annualized G&A reduction compared to 2019 and 25% annualized
G&A reduction compared to 2018
Successfully positioned for FCF at prices well below forward curve
4
Protecting Balance
Sheet and Liquidity
• Balance sheet strength remains top priority; $3.5B of liquidity at end 2Q20 and investment grade credit rating at all three rating agencies
• 2H20 free cash flow breakeven in low $30/bbl WTI range while protecting operational momentum into 2021
• Differentiated capital efficiency highlighted by 2021 FCF breakeven of ~$35/bbl for benchmark maintenance scenario on an unhedged basis; delivers oil production in-line with 4Q20 average (>170 MBOPD)
Reducing Capital
Expenditures
• Low 2Q20 capex of $137MM and strong 2Q20 total oil production of 197 MBOPD
on capital efficiency outperformance
• Reducing 2020 capital spending guidance to $1.2B and raising 2020 oil production guidance to 190 MBOPD at midpoint, inclusive of curtailments
• 2Q20 average completed well cost (CWC) per lateral foot down ~10% vs. 2019 average
• Expect 2H20 CWC per lateral foot to decline >20% vs. 2019 average
-
Lowering full year capex while protecting operational momentum
• 2020 capex guidance reduced to $1.2 billion on strong execution and capital efficiency
− 50% reduction vs. beginning of year capital budget
− 2H20 spend high-graded and concentrated in Eagle Ford and Bakken, prioritizing returns, free cash flow, and capital efficiency
− 2H20 wells to sales heavily weighted to 4Q20
• 2020 total oil production guidance raised to 190MBOPD at midpoint, inclusive of curtailments
− 2Q20 frac pause and wells to sales timing leads to 3Q20 production trough for U.S. oil production
− U.S. oil production on improving trend into 4Q20
− Enter 2021 with DUC (drilled but uncompleted) backlog optimized for operational needs
• 2020 Resource Play Exploration (REx) drilling program successfully completed
2020 Capital Program & Guidance Update
5
2020 Gross Wells to Sales by Quarter
Eagle Ford
Bakken
~90%
Wells to Sales Timing Drives 3Q20
Production Trough
0
40
Apr '20 May '20 Jun '20 Jul '20 Aug '20 Sep '20
0
100
1Q20 2Q20 3Q20e 4Q20e
Bakken and Eagle Ford
Other
2Q20 3Q20e
-
Total Company Cash Flow for 2Q20
• Ended 2Q20 with $522MM cash balance and undrawn revolving credit facility of $3.0B
• Pro-Forma July 3rd cash balance of $611MM after receipt of Alternative Minimum Tax
(AMT) Refund
• Significant 2Q20 working capital headwinds expected to normalize over 2H20
• 2H20 free cash flow breakeven in low $30/bbl WTI range
Ending cash balance impacted by working capital
1 Excludes $8MM of exploration costs other than well costs included within Capital Expenditures2 Includes $(74)MM of changes in operating working capital (excluding $(3)MM of M&S Inventory) and $(187)MM of working capital changes associated with investing activities3 Cash balance as of July 3rd; inclusive of AMT refund and excludes all other activity incurred post June 30th
See the 2Q20 Investor Packet at https://ir.marathonoil.com/ for non-GAAP reconciliations
817 774
522611
94 137
261
9 89
0
500
1,000
3/31/20 CashBalance
Operating CashFlow b/f WC
CapitalExpenditures
Cash Bal b/f A&Dand Working
Capital
WorkingCapital
A&D (net) 6/30/20 CashBalance
AMT Refund 7/3/20 CashBalance - Pro
forma
$m
illio
ns
1 2
3
6
https://ir.marathonoil.com/
-
Competitively Advantaged Multi-Basin Model
High quality U.S. assets span development cycle
Eagle Ford
2Q20 avg. 108 MBOED (61% oil)
~160,000 net acres
Bakken
2Q20 avg. 103 MBOED (78% oil)
~260,000 net acres
STACK / SCOOP
2Q20 avg. 60 MBOED (25% oil)
~300,000 net acres
7
Appraise / Delineate Early Development Full Field DevelopmentExplore
Northern Delaware
2Q20 avg. 30 MBOED (53% oil)
~85,000 net acres
Texas Delaware Oil Play>60,000 net acres
Louisiana Austin Chalk~200,000 net acres
-
0
10
20
30
40
50
0
20
40
60
80
100
120
2Q19 3Q19 4Q19 1Q20 2Q20
Production Gross Wells Net WI Wells
Eagle Ford Driving Capital Efficiency Improvement
Production Volumes and Wells to Sales
Resumed activity in 3Q20 with no loss in efficiency
• 2Q20 production averaged 108 net MBOED
with 20 gross operated wells to sales in April
• Planning to average 2 rigs and 1 frac crew
over 2H20
• Expecting ~25 wells to sales for rest of year,
weighted to 4Q20
• Realizing continued completed well cost
(CWC) reductions and efficiency gains
– 2Q20 CWC per lateral foot down more than 10%
from 2019 average
– Line of sight to driving average CWC below $700
per lateral foot
– 2Q20 completion stages per day improved ~15%
from 2019 average
• Deployed proprietary Field Service
Management (FSM) technology to drive base
production and expense improvements
8
Op
era
ted
Wells t
o S
ale
s
MB
OE
D
Completed Well Cost per Lateral Foot
CW
C p
er
Late
ral F
oo
t
$600
$900
2018 1H19 2H19 1H20 2H20e
-
0
5
10
15
20
25
30
35
0
20
40
60
80
100
120
2Q19 3Q19 4Q19 1Q20 2Q20
Production Gross Wells Net WI Wells
Bakken Delivering Execution Excellence
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
Record low cash costs during 2Q20
• 2Q20 production averaged 103 net MBOED
with 8 gross operated wells to sales; majority
of wells brought online in April
• 2Q20 oil production averaged 80 net MBOPD,
inclusive of ~4 MBOPD of curtailments
• Planning to average 2 rigs and 1 frac crew
over 2H20
• Expecting ~25 wells to sales over 2H20,
weighted to 4Q20
• Relentless focus on well costs and capital
efficiency
– New quarterly record for completion stages per
day
– 4 of 8 wells achieved average CWC below $500
per lateral foot; all 4 were in Myrmidon
– Line of sight to driving average CWC to ~$450
per lateral foot
9
MB
OE
D
Completed Well Cost per Lateral Foot
CW
C p
er
Late
ral F
oo
t
$400
$600
2018 1H19 2H19 1H20 2H20e
-
0
5
10
15
20
25
0
5
10
15
20
25
30
2Q19 3Q19 4Q19 1Q20 2Q20
Production Gross Wells Net WI Wells
0
4
8
12
16
20
0
20
40
60
80
100
2Q19 3Q19 4Q19 1Q20 2Q20
Production Gross Wells Net WI Wells
Capital Allocation Optionality in Oklahoma and N. Delaware
Oklahoma Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
Assets focused on base performance and expense management
Oklahoma
• 2Q20 production averaged 60 net MBOED
with no gross operated wells to sales
• Oil production averaged 15 net MBOPD,
inclusive of ~5 MBOPD of curtailments
• No wells to sales planned for rest of year
Northern Delaware
• 2Q20 production averaged 30 net MBOED
with 6 gross operated wells to sales
• Oil production averaged 16 MBOPD,
inclusive of ~2 MBOPD of curtailments
• Limited wells to sales over balance of year
10
MB
OE
D
N. Delaware Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
MB
OE
D
-
0
25
MRO RExWells
2019Industry
DelawareBasin
MRO RExWells
2019Industry
DelawareBasin
Encouraging Texas Delaware Oil Play Results2020 Resource Play Exploration (REx) D&C activity completed
• 4 Woodford wells and 2 Meramec wells
successfully brought online since play entry
• Wells demonstrate strong productivity, high
oil cuts, and shallow declines
– Gas-oil ratios in line with pre-drill expectations
– Low water-oil ratios of ~1:1
– No H2S and negligible CO2, as expected
• Productivity compares favorably against
industry Delaware Basin Wolfcamp and
Bone Spring wells; water-oil ratios also
lower
• Program has shown significant and
continuous improvement in drilling and
completion costs
11
1 90 day average includes 4 wells with >90 days of production and 180 day average includes 3 wells with >180 days of production
2 Source: Enverus production data for horizontal wells in Delaware DI Basin with 1st production date in 2019 and gross perforated interval over 1,000 feet
90-Day 180-Day
Av
era
ge C
um
ula
tiv
e
MB
OE
per
1,0
00’
Oil
Gas
1 1
2 2
Woodford Well
Meramec Well
Texas Delaware Oil Play Producing Wells
MRO Acreage
Marathon Oil vs. Industry Productivity
-
International E&P: Equatorial Guinea
• 2Q20 production of 83 net MBOED with unit
production costs of $1.88 per BOE
• Expecting sequentially lower 3Q20 production
due to impact of higher prices on net interest
under production sharing contract (PSC) as well
as natural decline
• Lower realized condensate pricing in 2Q20
reflected timing of liftings into oversupplied
market
• Third party Alen backfill gas project progressing
on schedule with startup expected in early 2021
Alen backfill gas project progressing on schedule
12
Alen Slug Catcher
Alen Pipeline Shore Landing
-
Committed to Sustainability
1 Methodology and definitions based on information from online 2018 MRO Sustainability Report
2 Based on Total Recordable Incident Rate 4 Metrics impact short-term incentive plan
3 World Health Organization
The foundation for long-term financial outperformance
Environmental & Safety1 Social Governance
• Leveraging the Bioko Island
Malaria Elimination Project
vaccine lab, endorsed by the
WHO3 to test more than 35,000
people in Equatorial Guinea for
COVID-19
• Working with community partners
to transition education programs
to distance learning
• Supporting local communities
through virtual volunteer
opportunities
• Protecting our business and
communities through our Business
Continuity and Emergency
Response Plans
• Year-to-date safety performance is
best in Company history2
• 96% total Company gas capture
during 2Q20 and year-to-date
• In 2019, achieved 19% reduction in
methane intensity relative to 2018
and 44% reduction relative to 2014
• In response to COVID-19,
Business Continuity and
Emergency Response Plan
continued with uninterrupted field
operations and work from home
practices
• 7 of 8 directors are independent
with lead independent director; 25%
of Board is female
• ~5 year average director tenure;
50% of directors joined in last 36
months
• All committees made up of entirely
NYSE independent directors
• GHG intensity metric added to
2020 executive compensation
scorecard4
• Base salary reductions for CEO and
other corporate officers and
reduction of Board of Director
compensation in 2020
13
-
Prioritizing Financial Strength and Flexibility
Reduction of $100MM
vs. prior guidance
2020 Capital Budget
Reduced
FCF breakeven in low $30/bbl range for 2H20
$1.2B
Significant
Liquidity
$3.5BNo significant maturities
until Nov. 2022
Reducing Capital
Expenditures
Managing Cost
Structure
Protecting Balance Sheet
and Liquidity
2020 Oil Production
Raised
190 MBOPDMidpoint of revised
guidance, inclusive of
curtailments
July 3rd Cash
Balance1
Pro-forma for Alternative
Minimum Tax refund
Record Low U.S.
Production Expense
$4.09/BOEDown ~20% from 2019
~17%
14
$611MM
Annualized G&A
Reduction
Relative to
2019
1 Inclusive of AMT refund and excludes all other activity incurred post June 30th
2 Delivers in-line oil production relative to expected 4Q20 total company average (>170 MBOPD) on an unhedged basis
See the 2Q20 Investor Packet at https://ir.marathonoil.com/ for non-GAAP reconciliations
2021 FCF Breakeven of ~$35/bbl for benchmark maintenance scenario2
https://ir.marathonoil.com/
-
Appendix
-
2020 Production Guidance
Net Production Oil Production (MBOPD) Equivalent Production (MBOED)
2020 2Q20 1Q20 2019* 2020 2Q20 1Q20 2019*
United States 173 – 179 182 207 191 295 – 305 307 340 323
International 13 – 15 15 14 15 75 – 79 83 82 85
Total Net Production 186 – 194 197 221 206 370 – 384 390 422 408
* Divestiture-adjusted
16
• Revised midpoint of 2020 total Company oil production guidance 190 MBOPD
• Revised guidance inclusive of all curtailments; prior guidance was on an underlying basis and excluded the impact
of curtailments, which totaled ~11 MBOPD during 2Q20
-
2020 Cost and Tax Rate Guidance
Current
2020 Guidance
United States Cost Data ($ per BOE)
Production Operating $4.25 – 5.25
DD&A $19.00 – 21.00
S&H and Other1 $3.85 – 4.10
International Cost Data ($ per BOE)
Production Operating $2.15 – 2.65
DD&A $2.50 – 3.50
S&H and Other1 $0.10 – 0.60
Expected Tax Rates by Jurisdiction:
United States and Corporate Tax Rate –
Equatorial Guinea Tax Rate 25%
1 Excludes G&A expense
17
-
United States Crude Oil DerivativesAs of August 5, 2020
3Q20 4Q20 FY 2021
NYMEX WTI Three-Way Collars
Volume (Bbls/day) 80,000 80,000 -
Ceiling $64.40 $64.40 -
Floor $55.00 $55.00 -
Sold put $48.00 $48.00 -
NYMEX WTI Two-Way Collars
Volume (Bbls/day) 36,739 10,000 10,000
Ceiling $41.14 $48.65 $52.37
Floor $31.47 $37.00 $35.00
Fixed Price WTI Swaps
Volume (Bbls/day) 10,000 - -
Weighted Avg Price per Bbl $32.77 - -
Basis Swaps – Argus WTI Midland (a)
Volume (Bbls/day) 15,000 15,000 -
Weighted Avg Price per Bbl $(0.94) $(0.94) -
Basis Swaps – NYMEX WTI / ICE Brent (b)
Volume (Bbls/day) 5,000 5,000 808
Weighted Avg Price per Bbl $(7.24) $(7.24) $(7.24)
NYMEX Roll Basis Swaps
Volume (Bbls/day) 60,000 30,000 -
Weighted Avg Price per Bbl $(1.58) $(0.81) -
(a) The basis differential price is indexed against Argus WTI Midland
(b) The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI
18
-
United States Natural Gas/NGL DerivativesAs of August 5, 2020
(a) The basis differential price is indexed against Waha and NYMEX Henry Hub
19
3Q20 4Q20 FY 2021
Natural Gas
Two-Way Collars
Volume (MMBtu/day) 66,304 150,000 112,329
Weighted Avg Price per MMBtu
Ceiling $2.49 $2.62 $3.00
Floor $2.00 $2.13 $2.42
Basis Swaps – WAHA / HH (a)
Volume (MMBtu/day) 10,000 10,000 -
Weighted average price per MMBtu $(0.37) $(0.37) -
NGL
Fixed Price Ethane Swaps
Volume (Bbls/day) 7,304 10,000 -
Weighted average price per Bbl $8.78 $8.78 -
-
Capital, Investment & ExplorationBudget reconciliation ($MM)
2020
Budget
1Q20
Actual
2Q20
Actual
Cash additions to Property, Plant and Equipment 620 326
Working Capital associated with PPE (52) (187)
Property, Plant and Equipment additions 568 139
Exploration Costs other than Well Costs 6 8
M&S Inventory & Other 5 (10)
Total Capital Expenditure 1,200 579 137
20
• Updated capital budget of $1.2B compares to 1Q20 guidance of