2019 barclays ceo energy-power conference...2019 barclays ceo energy-power conference...
TRANSCRIPT
Lee Tillman
President & Chief Executive Officer
September 4, 2019
2019 Barclays CEO
Energy-Power
Conference
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, 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, 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 2018 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 2Q19 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
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
3
2Q19 HighlightsConsistently delivering on our framework
4
• Annualized 2Q19 CROIC1 of 20%, comparable to prior-year quarter despite 12% lower
WTI price; driving significant price normalized rate of change improvement
• Organic FCF2, post-dividend, of $137MM 2Q19 and $217MM YTD
• YTD dividends of $82MM, buybacks of $250MM; 25% of CFO3 returned to shareholders
• Share repurchases of $950MM since 2018, funded entirely by organic FCF
• Share repurchase authorization increased to $1.5B
• US oil production above top end of guidance and up 17% from year-ago quarter
• YTD development capex 50% of annual budget; annual $2.4B budget unchanged
• US unit production costs down 14% from year-ago quarter; lowest since becoming
independent E&P
• Completed well cost (CWC) per lateral foot on declining trend vs. 2018 in all Basins
• Exited Kurdistan and U.K.; 10 country exits since 2013
• Portfolio optimized to four high quality U.S. Resource Plays and free cash flow
generative integrated business in Equatorial Guinea
• Upgraded by Moody’s and S&P; investment grade at all primary ratings agencies
• Peer leading leverage metrics and breakeven oil price
Corporate Returns
Free Cash Flow
Return of Capital
Multi-Basin
Portfolio
Balance Sheet
Strength
Differentiated
Execution
1CROIC = 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)2Organic 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 3CFO = Cash flow from operations
Total Company Cash Flow for 2Q19
• 2Q19 development capital of $636MM; YTD of $1.2B with $2.4B full-year budget unchanged
• YTD stock repurchases of $250MM; outstanding authorization raised to $1.5B
• Cash Balance at June 30 excludes $335MM of held for sale cash (U.K.); pro-forma July 1 Cash
Balance reflects $95MM U.K. disposition proceeds
Generated $137MM of organic FCF
5
1,0191,156
9611,056
777 636
41
37
37 236 4
74
0
500
1,000
1,500
2,000
3/31/19 CashBalance
OperatingCash Flow b/f
WC
DevelopmentCapital
Expenditures
Dividends EG LNGReturn ofCapital &
Other
Cash Bal b/fA&D, REx,WorkingCapital &Financing
REx Capex ShareRepurchase
A&D (Net) TotalWorkingCapital
6/30/19 CashBalance
7/1/19 pro-forma Cash
Balance
$M
M
1 2
U.K. Held
for Sale
1 Excludes $6MM of exploration costs other than well costs2 Total working capital includes $20MM and $54MM of working capital changes associated with operating activities and investing activities, respectively
See the 2Q19 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations
Appraise / Delineate Early Development Full Field Development
Competitively Advantaged Multi-Basin Model
Multi-basin portfolio provides flexibility
Eagle Ford
2Q19 avg. 109 MBOED (56% oil)
~145,000 net surface acres
Northern Delaware
2Q19 avg. 28 MBOED (59% oil)
~85,000 net surface acres
Bakken
2Q19 avg. 104 MBOED (85% oil)
~260,000 net surface acres
STACK / SCOOP
2Q19 avg. 82 MBOED (25% oil)
~300,000 net surface acres
MRO 2Q19 Oil Production by Area
Eagle Ford
Bakken
Permian
Oklahoma
International and Other
6
Impressive Eagle Ford Productivity Across Footprint
Driving Consistent Productivity Improvement
Production Volumes and Wells to Sales
0
20
40
60
0
40
80
120
2Q18 3Q18 4Q18 1Q19 2Q19
Op
era
ted
We
lls
to
Sa
les
Production Gross Wells Net WI Wells
MB
OE
D
• Production averaged 109 net MBOED
• Record 2Q19 IP30 well productivity despite majority of activity outside of Karnes County
• Turnbull pad in Karnes avg. IP30 of 3,230 BOED (67% oil) - new MRO pad record
• 15 wells across Atascosa Core delivered avg. IP30 of 1,860 BOED (81% oil)
• Successful core extension test in Gonzales through enhanced completion designs
− 6 well pad achieved avg. IP30 of 1,600 BOED (70% oil)
− 2nd Gonzales test online 4Q19
• Capital efficiency improvement continues
− Consistent year over year productivity improvement
− Completed well cost per lateral foot on declining trend vs. 2018
90-D
ay C
um
Pro
du
cti
on
(M
BO
E)1
7
0
20
40
60
80
100
120
2011 2012 2013 2014 2015 2016 2017 2018 2019
1 90-day cumulative production normalized to 5,700’
Record Well Performance in the Eagle Ford
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average
8
Live Oak
Bee
Karnes
Atascosa
Gonzales
De Witt
Wet Gas
Condensate
Oil
Successful Gonzales core extension test
Expanded Atascosa Core
Turnbull H – 4 LEF wells
3,230 BOED (67% oil)
6,140’ LL
Retzloff Tom-May - 3 LEF wells
1,660 BOED (80% oil)
6,830’ LL
Chapman-Pfeil - 4 LEF wells
1,320 BOED (76% oil)
6,760’ LL
MRO Eagle Ford Record
Pad IP30
Barnhart G - 6 LEF wells
1,600 BOED (70% oil)
5,680’ LL
Core Extension Test in
Gonzales
Next Gonzales Test (4Q19)
4 LEF Wells
9,600’ LL
Guajillo – 2 pads, 8 LEF wells
2,200 BOED (83% oil)
6,820’ LL
• Production averaged 104 net MBOED
• Continuing successful Southern Hector delineation
− 4 second quarter wells avg. IP30 of 2,450 BOED (80% oil)
• Strong performance from South Myrmidon
− 15 wells avg. IP30 of 2,820 BOED (80% oil)
− Driftwood Middle Bakken well achieved MRO record IP24 of 12,250 BOED (78% oil)
• Average completed well cost of $5.2MM
• YTD CWC down 15% from 2018 average
• Half of second quarter wells at or below $5MM
• Exceptional extended production from 2018 core extension tests in Ajax and Southern Hector
YTD Completed Well Costs Trending 15% below 2018
Industry Leading Capital Efficiency in Bakken
0
5
10
15
20
25
30
35
0
20
40
60
80
100
120
2Q18 3Q18 4Q18 1Q19 2Q19
Production Gross Wells Net WI Wells
MB
OE
D
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
9
4.0
5.0
6.0
7.0
8.0
1Q18 2Q18 3Q18 4Q18 1Q19 2Q19
CW
C (
$M
M)
McKenzie
Dunn
Myrmidon
Hector
Ajax
Elk Creek
2Q19 to Sales
Pre-2Q19 to Sales
Expanding the Bakken CoreBest in Basin productivity
10
IPs shown include oil, NGL and gas
1Source - Drilling Info; dataset consists of all Bakken/Three Forks wells with first production from since Jan. 1, 2017. Plot includes 1,564 total wells.
*CUM – Cumulative production
1
• 4 wells from Ajax core extension test achieved total cumulative production of >1 MMBOE at 240 days
• 4 wells from South Hector core extension tests achieved total cumulative production of >950 MBOE at 200 days
• Additional Southern Hector and Ajax core extension tests scheduled for 2H19
Extended Production Validates
2018 Delineation Tests
4 Ajax wells (4Q18)
>1 MMBOE (80% oil)
Total CUM* at 240 days
4 S. Hector wells (2H18)
>950 MBOE (79% oil)
Total CUM* at 200 days
Progressing Southern
Hector Delineation
4 wells (2Q19)
IP30: 2,450 BOED (80% oil)
Continued Strength in
South Myrmidon
15 wells (2Q19)
IP30: 2,820 BOED (80% oil)
Includes single well IP24
12,250 BOED (78% oil)
90-Day Cumulative Oil Production1
0
40
80
120
160
200
240
Cu
mu
lati
ve O
il (
MB
O)
20 of top 25 & 60 of top 100
wells, despite only drilling
9% of wells in Basin
MRO Wells Competitor Wells
0 500 1,000 1,500
$8.0
$6.3$5.9
~$0.5
~$0.5
~$0.5
~$0.2
~$0.4
5
5.5
6
6.5
7
7.5
8
Prior ActualCWC**
DrillingEfficiencies
ContractSavings
CompletionEfficiencies
DesignSavings
Actual CWC Location Actual D&C
0
4
8
12
16
20
0
20
40
60
80
100
2Q18 3Q18 4Q18 1Q19 2Q19
Production Gross Wells Net WI Wells
Oklahoma Delivering Capital Efficiency and Consistency
• Production averaged 82 net MBOED
• Track record of consistently strong
overpressured STACK infill results
– 8 wps Mike Stroud infill >100% above type
curve at 60 days
• Focus on capital efficiency paying dividends
– Most recent overpressured STACK infills
(Marjorie and Lloyd) executed at industry
leading well costs
– Cycle times reduced ~30% vs. most recent
comparable infills
• Leveraging operated success and OBO
learnings to Springer formation over 2H19
– 4Q18 Papa Pump Springer test achieved
IP180 of 1,210 BOED (79% oil)
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
MB
OE
D
11
Marjorie/Lloyd Overpressured STACK Well Cost*
Co
mp
lete
d W
ell C
ost
($M
M)
*Normalized to 10,000 ft. lateral; completed well cost includes D&C and location costs. Actual D&C is CWC minus location costs
**Actual average CWC of two most recent offset infills
wps – wells per section
OBO – operated by other
Oklahoma Continues to Outperform
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average unless otherwise stated
*normalized to 10,000 ft. lateral
**5 of 8 wells brought online during 1Q19; 3 of 8 wells brought online during 2Q19
MRMC – Meramec
Leveraging operated Springer success in 2H19
12
Caddo
Grady
Stephens
Blaine
Canadian
Kingfisher
Wet Gas
Condensate
Oil
2Q19 to Sales
2H19 to Sales
Pre-2Q19 to Sales
0
50
100
150
0 10 20 30 40 50 60
MRMC Volatile Oil XL Type Curve
Mike Stroud Pad Avg
Chapman Pad Avg
Strong Performance from the Overpressured STACK
Days
MB
OE
>100%
Industry Leading
Well Costs
Marjorie & Lloyd Infills
2 pads, 4 wps
6 new MRMC wells
$6.3MM avg. CWC*
1,650 BOED (70% oil)
Strong Productivity
and Predictability
Mike Stroud**
8 MRMC wps
2,480 BOED (38% oil)
Chapman
6 MRMC wps
1,810 BOED (53% oil)Leveraging Learnings
in Springer
2H19 - 12 wells to sales
4Q18 Springer Test
Papa Pump
IP180: 1,210 BOED
(79% oil)
Dual-Pad Development Reducing Costs and Cycle Times
• Production averaged 28 net MBOED
• Continued strong Upper Wolfcampproductivity in Malaga
– 11 wells avg. IP30 of 1,520 BOED (63% oil), or 345 BOED per one thousand foot lateral
• Improving margin profile through cost reductions and midstream solutions
– 10% sequential reduction in cash costs
– 100% water on pipe for 2Q19 and all remaining 2019 wells to sales
– Oil on pipe at ~70% and rising
• Increasing proportion of Red Hills delineation in drilling mix over 2H19
Strong Productivity and Improving Margins in N. Delaware
0
5
10
15
20
25
0
5
10
15
20
25
30
2Q18 3Q18 4Q18 1Q19 2Q19
Production Gross Wells Net WI Wells
Production Volumes and Wells to Sales
Op
era
ted
Wells t
o S
ale
s
MB
OE
D
0%
20%
40%
60%
80%
2Q18 3Q18 4Q18 1Q19 2Q19
% Water on Pipe
Water on Pipe (% of total produced)
13
Strong 2Q19 Upper Wolfcamp Performance in MalagaGreater proportion of 2H19 activity in Red Hills
IPs shown are 30-day (includes oil, NGL and gas) and represent pad average
Upper WC – Upper Wolfcamp horizon
BS – Bone Springs horizon14
Ranger
Red Hills
Malaga
Arrowhead
China
Draw
Eddy
Lea
Strong Upper WC
Productivity
Mariner, 6 Upper WC
1,350 BOED (64% oil)
305 BOED/1000’
Trebuchet, 3 Upper WC
1,580 BOED (64% oil)
370 BOED/1000’
Whistle Pig, 3 Upper WC/BS
1,870 BOED (64% oil)
420 BOED/1000’
2H19 Red Hills Pads
International Simplified to FCF Generating E.G. Business
• Total International production of 103 net
MBOED, reflecting successful return from
1Q19 E.G. turnaround
• E.G. EBITDAX1 of $142MM 2Q19 and
$211MM YTD
• International portfolio simplified to free cash
flow generating integrated business in E.G.
– Closed on sale of Atrush Block in Kurdistan
– Closed on U.K. divestiture July 1, removing
$966MM of asset retirement obligations
– 10 country exits since 2013
• Pro-forma International unit production
costs (ex Kurdistan and U.K.) just $2.21 per
BOE during 2Q19; guidance updated
15
Alba Platform
AMPCO Methanol Plant
EGLNG Loading Dock
1See the 2Q19 Investor Packet at www.Marathonoil.com for Non-GAAP reconciliations
Well Established Track Record of FCF & Return of Capital
16
• Returned ~$1.2B of capital to shareholders since 2018, representing ~25% of operating
cash flow, funded entirely by organic FCF
• Buyback authorization raised to $1.5B, representing $950MM increase in authorization
• Return of capital included in executive compensation scorecard
• Underlying free cash flow momentum accelerating into 2H19 and 2020
$M
M
4%
5%
6%
7%
8%
9%
10%
11%
12%
0
500
1,000
1,500
2018 2019 YTD Since 2018
Organic FCF before Dividend Repurchases FCF Yield Dividend
An
nu
alized
FC
F
Yie
ld (
%)
251
950
82
250
169
1,037
299
1,336
700
Avg WTI Price: $64.90 $57.42 $62.42
FCF YieldDividendRepurchasesOrganic FCF before Dividend
FCF Yield = Organic FCF before Dividend / Market Cap (as of 8/5/2019)
Six consecutive quarters of organic FCF generation
Appendix
Portfolio Transformation Since 201310 Country Exits
18
CORE ASSETS
DIVESTED
CANADA
(2017)
BAKKEN
SCOOP/STACK
EAGLE FORD
NORTHERN
DELAWARE
EQUATORIAL
GUINEA
GABON
(2018)
ANGOLA
(2014)
KURDISTAN (2019)
LIBYA (2018)
NORWAY
(2014)
UNITED KINGDOM
(2019)
POLAND
(2014)
ETHIOPIA (2016)
KENYA
(2016)
• Optimized portfolio positioned to sustainably deliver improving corporate returns, free cash flow, and
return of capital
• Simplification to core assets concentrates capital allocation to highest margin, highest return US
resource plays while materially reducing cash costs
• Portfolio simplification has contributed to an Asset Retirement Obligation reduction of $1.8B since 2014
Differentiated Execution Led the Way in 2018Underpins confidence in ongoing delivery on our framework for success
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 –
best in proxy peer group*
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 $170MM dividend
Capital Efficient Oil
Growth
18% total oil growth at
midpoint, divestiture
adjusted
24% total oil growth,
divestiture adjusted –
best in proxy peer group*
22.5% resource play oil
growth at midpoint
32% resource play oil
growth
* Proxy peer group includes – APA, APC, CHK, CLR, DVN, ECA, EOG, HES, MUR, NBL, PXD
19
2019 Production Guidance
3Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)
3Q19 2Q19* 3Q18* 3Q19 2Q19* 3Q18*
United States 190 – 200 192 172 330 – 340 331 302
International 12 – 16 16 17 80 – 90 91 99
Total Net Production 202 – 216 208 189 410 – 430 422 401
* Divestiture-adjusted, and also removes volumes associated with the sale of our U.K. business which closed on July 1, 2019
** Annual 2019 guidance includes 1H19 contributions from divested assets
FY19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)
2019** 2018* 2019** 2018*
United States 185 – 195 169 320 – 330 294
International 18 – 22 17 85 – 95 98
Total Net Production 203 – 217 186 405 – 425 392
20
• Adjusted full year 2019 production guidance now excludes divested U.K. and Kurdistan volumes for
the second half of 2019, but otherwise remains unchanged
2019 Cost and Tax Rate Guidance
Initial
2019 Guidance
Current
2019 Guidance
United States Cost Data ($ per BOE)
Production Operating $4.50 – 5.50 $4.50 – 5.50
DD&A $19.25 – 21.75 $18.25 – 20.75
S&H and Other1 $4.00 – 4.50 $4.00 – 4.50
International Cost Data ($ per BOE)
Production Operating $4.75 – 5.75 $3.75 – 4.25
DD&A $3.00 – 4.00 $3.00 – 4.00
S&H and Other1 $1.00 – 1.50 $0.75 – 1.25
Expected Tax Rates by Jurisdiction:
United States and Corporate Tax Rate –% –%
Equatorial Guinea Tax Rate 25% 25%
1 Excludes G&A expense
21
• Updated full year 2019 guidance reflects actual realized costs for 1H19 but excludes U.K. and
Kurdistan costs for 2H19
• 2Q19 pro-forma (ex U.K. and Kurdistan) International cost data ($ per BOE):- Production Operating $2.21
- DD&A $3.13
- S&H and Other $0.64
United States Crude Oil DerivativesAs of August 5, 2019
Crude Oil
3Q19 4Q19 FY 2020 FY 2021
NYMEX WTI Three-Way Collars (a)
Volume (BBLs/day) 80,000 80,000 19,945 -
Weighted Avg Price per BBL:
Ceiling $74.19 $74.19 $67.55 -
Floor $56.75 $56.75 $55.00 -
Sold put $49.50 $49.50 $47.50 -
Basis Swaps – Argus WTI Midland (b)
Volume (BBLs/day) 15,000 15,000 15,000 -
Weighted Avg Price per BBL $(1.40) $(1.40) $(0.94) -
Basis Swaps – Net Energy Clearbrook (c)
Volume (BBLs/day) 1,000 1,000 - -
Weighted Avg Price per BBL $(3.50) $(3.50) - -
Basis Swaps – NYMEX WTI / ICE Brent (d)
Volume (BBLs/day) 5,000 5,000 5,000 808
Weighted Avg Price per BBL $(7.24) $(7.24) $(7.24) $(7.24)
Basis Swaps – Argus WTI Houston (e)
Volume (BBLs/day) 10,000 10,000 - -
Weighted Avg Price per BBL $5.51 $5.51 - -
NYMEX Roll Basis Swaps
Volume (BBLs/day) 60,000 60,000 - -
Weighted Avg Price per BBL $0.38 $0.38 - -
(a) Between July 1, 2019 and August 5, 2019, we entered into 10,000 Bbls/day of three-way collars for January – December 2020, with a ceiling of $65.12, a sold put of $48.00, and
a floor of $55.00.
(b) The basis differential price is indexed against Argus WTI Midland
(c) The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook (“UHC”)
(d) The basis differential price is indexed against International Commodity Exchange (“ICE”) Brent and NYMEX WTI
(e) The basis differential price is indexed against Argus WTI Houston
22
2019 Capital, Investment & ExplorationBudget reconciliation $MM
Development Capital 2019
Budget 1Q19 2Q19
2019 YTD
Actual
Cash additions to Property, Plant and Equipment 615 647 1,262
Working Capital associated with PPE (1) 54 53
Property, Plant and Equipment additions 614 701 1,315
M&S Inventory (4) (6) (10)
REx expenditures included in capital expenditures (41) (59) (100)
Exploration costs other than well costs - - -
Development Capital 2,400 569 636 1,205
23
Resource Exploration (REx) Capital 2019
Budget 1Q19 2Q19
2019 YTD
Actual
REx expenditures included in capital expenditures 41 59 100
Additions to Other Assets and acquisitions (14) (28) (42)
Exploration costs other than well costs 10 6 16
REx Capital Expenditure 200 37 37 74