HOUSTON,
Nov. 6, 2019 /PRNewswire/ --
Marathon Oil Corporation (NYSE: MRO) today reported third quarter
2019 net income of $165 million, or
$0.21 per diluted share, which
includes the impact of certain items not typically represented in
analysts' earnings estimates and that would otherwise affect
comparability of results. Adjusted net income was $111 million, or $0.14 per diluted share. Net operating cash flow
was $737 million, or $757 million before changes in working
capital.
Highlights
- $81 million of organic free
cash flow post-dividend, bringing year-to-date organic free cash
flow to $298 million
- Approximately $300 million
of year-to-date share repurchases in addition to $122 million of dividend payments
- U.S. oil production averaged 201,000 net bopd during
third quarter, up 17% from year-ago quarter, divestiture-adjusted,
and above top end of guidance range
- Company oil production averaged 216,000 net bopd during
third quarter, up 14% from year-ago quarter, divestiture-adjusted,
and at top end of guidance range
- Development capital spend of $646
million third quarter; annual $2.4
billion development capital budget remains
unchanged
- U.S. and International unit production costs at lowest
quarterly averages since becoming an independent E&P
company
- Added over 1,000 operated locations, equivalent to about
three years of inventory, through success across all elements of
returns focused resource capture framework; highlighted by organic
enhancement in the Eagle Ford and Bakken, Resource Play Exploration
(REx) success in a new Texas Delaware oil play, and an accretive
bolt-on in the Eagle Ford
- Established a new Texas Delaware oil play with over
60,000 contiguous net acres at low entry cost of less than
$2,400 per acre; initial two wells
encouraging with strong oil productivity, low water cut and shallow
decline
- Signed agreement for Eagle Ford bolt-on of approximately
18,000 contiguous and largely undeveloped net acres; adjacent to
existing Company leasehold and cores up 70 future drilling
locations in a high return development area
- Recently closed on three financing transactions that are
collectively leverage neutral, extend maturities, generate annual
cash cost savings, and reflect Marathon Oil's commitment to
maintaining a strong balance sheet and investment grade credit
rating at all primary ratings agencies
"Third quarter again featured exceptional operational
performance across our advantaged multi-basin portfolio that is
translating to differentiated financial outcomes in our peer
space," said Chairman, President and CEO Lee Tillman. "We're driving our corporate
returns higher, have just reported our seventh consecutive quarter
of organic free cash flow generation, and have returned over 20% of
our year-to-date cash flow from operations back to our
shareholders. Since the beginning of 2018, we've repurchased
$1 billion of our own shares,
representing approximately 7% of outstanding share count, funded
entirely by post-dividend organic free cash flow. Additionally, we
are generating success across all elements of our comprehensive
resource capture framework. We've added about three years of new
inventory company-wide, while upgrading the returns on hundreds of
drilling locations in the Bakken and Eagle Ford. Our REx team is
advancing exploration and appraisal activity in two oil plays of
scale, with encouraging early well results in a new Texas Delaware
oil play. We also signed an agreement for a synergistic bolt-on
acquisition in the Eagle Ford.
"Looking ahead to 2020, our framework for success will not
change: corporate returns first, free cash flow at conservative
pricing and return of capital back to shareholders. We expect our
2020 planning basis to be set on $50/bbl WTI with an enterprise free cash flow
break-even below that level. With our focus on delivering financial
outcomes competitive with the broader market, we're planning for
capital spend to decrease year-over-year and accordingly for our
U.S. oil growth to moderate. Organic enhancement success and
industry leading returns support a higher relative capital
allocation to the Eagle Ford and Bakken, driving growth for both
assets, as we take full advantage of our multi-basin model. We'll
continue to be guided by our unwavering commitment to capital
discipline and low enterprise breakeven oil price to position
Marathon Oil for success across a wide range of commodity price
environments in 2020 and beyond."
United States
(U.S.)
U.S. production averaged 339,000 net
barrels of oil equivalent per day (boed) for third quarter 2019,
including 201,000 net barrels of oil per day (bopd). Oil production
was above the top end of the third quarter guidance range and up
17% from the year-ago quarter on a divestiture-adjusted basis. U.S.
unit production costs were $4.75 per
barrel of oil equivalent (boe), down 23% from the year-ago quarter,
the lowest quarterly average unit production costs since becoming
an independent exploration and production company in
2011.
EAGLE FORD: Marathon Oil's Eagle Ford production averaged
107,000 net boed in the third quarter 2019. The Company brought 35
gross Company-operated wells to sales in the quarter. Third quarter
activity again featured impressive results in both core
Karnes County and the expanded
core of Atascosa County,
highlighted by a new quarterly record for average 30-day initial
oil productivity for the asset. Karnes activity included five Austin Chalk wells that achieved an average
30-day initial production (IP) rate of 2,550 boed (78% oil).
In Atascosa, nine wells
achieved an average 30-day IP rate of 1,780 boed (87% oil). The
Middle McCowen four-well pad in Atascosa featured average lateral lengths of
10,900 feet, a new lateral length record for the asset,
highlighting optionality for capital efficient, long lateral
development across parts of Atascosa
County. Completed well cost per lateral foot remains on a
declining trend, with the third quarter average approximately 10%
below 2018.
BAKKEN: Marathon Oil's Bakken production averaged 109,000
net boed in the third quarter 2019. The Company brought 30 gross
Company-operated wells to sales. The Company continues to deliver
impressive capital efficiency, highlighted by strong productivity
and declining completed well costs, which averaged $4.9 million, or about 20% below the 2018
average. The successful delineation of Marathon Oil's broader
Hector acreage continued during third quarter, with the four-well
Herbert pad in South Hector achieving an average 30-day IP rate of
1,720 boed (86% oil) with an average completed well cost of
approximately $4.5
million.
OKLAHOMA: Marathon Oil's
Oklahoma production averaged
84,000 net boed in the third quarter 2019. The Company brought 19
gross Company-operated wells to sales. Marathon Oil continues to
deliver strong results from the overpressured STACK, where the
Marjorie and Lloyd four-well per section infills achieved an
average 30-day IP rate of 1,740 boed (66% oil). The average
completed well cost for the Marjorie and Lloyd pads was
$6.3 million normalized to a 10,000
foot lateral. In the SCOOP, Marathon Oil brought online three
Springer wells with strong early performance, achieving an average
30-day IP rate of 1,460 boed (72% oil), or 325 boed per 1,000-foot
lateral.
NORTHERN DELAWARE:
Marathon Oil's Northern Delaware
production averaged 30,000 net boed in the third quarter 2019. The
Company brought 10 gross Company-operated wells to sales, including
a mix of development and delineation wells. Marathon Oil continues
to make significant progress in advancing learnings, reducing its
cost structure and improving margins. Third quarter again featured
strong Upper Wolfcamp productivity in the Malaga area, where five
development wells achieved an average 30-day IP rate of 1,850 boed
(62% oil), or 365 boed per 1,000-foot lateral, with completed well
costs per lateral foot 20% below the 2018 average.
Resource Capture
Marathon Oil is
successfully executing across all three elements of its
comprehensive framework for resource capture and inventory
enhancement. The combination of organic enhancement in the Eagle
Ford and Bakken, REx success in a new Texas Delaware oil play, and
an accretive bolt-on in the Eagle Ford has added over 1,000
operated locations and meaningfully upgraded the returns for
hundreds of locations in the Eagle Ford and Bakken.
Through its REx program, Marathon Oil is now advancing
exploration and appraisal activity in two oil plays of scale: a new
Texas Delaware oil play and the Louisiana Austin Chalk.
In the Texas Delaware, Marathon Oil has established over
60,000 net acres of contiguous leasehold prospective for stacked
Woodford and Meramec oil targets.
Two wells have been drilled and completed with initial results
demonstrating strong productivity, low water cuts, and shallow
decline profiles. The Company's position in this new play was
captured at an entry cost of less than $2,400 per acre through a combination of organic
leasing and targeted acquisitions, with some acreage pending close
in the fourth quarter.
Third quarter REx capital expenditures were $35 million, with year-to-date expenditures of
$109 million through end of third
quarter. Including the leasing and acquisitions to core up its new
Texas Delaware play which are anticipated to close in fourth
quarter, full year 2019 REx capital spending is now expected to be
approximately $280 million, an
increase of $80 million from prior
guidance of $200 million.
In the Louisiana Austin Chalk, Marathon Oil is progressing
exploration drilling and acquiring 3D seismic data. Consistent with
its focus on capital discipline, the Company has secured Equinor as
a non-operating, 25% working interest partner in the Louisiana
Austin Chalk play. On a cash basis, this transaction helps fund
incremental REx capital spending relative to prior
guidance.
Outside of the REx program, in the fourth quarter Marathon
Oil signed an agreement to acquire approximately 18,000 contiguous
and largely undeveloped net acres adjacent to the Company's
existing northeast Eagle Ford leasehold. The $185 million bolt-on includes approximately 7,000
net boed of current production, associated midstream
infrastructure, and cores up a 70-well, long lateral development
with potential upside. The transaction has an effective date of
Nov. 1, 2019 and is expected to close
by Jan. 31, 2020.
International
International
production averaged 87,000 net boed for third quarter 2019. Unit
production costs averaged $1.98 per
boe. Marathon Oil closed on the sale of its U.K. business
July 1, removing $966 million of asset retirement obligations.
Coupled with the second quarter close on the sale of the Company's
last block in Kurdistan, Marathon
Oil's international portfolio has been simplified to only include
the free cash flow generative integrated business in Equatorial Guinea.
Cash Flow and Development
Capital
Net cash provided by operations was
$737 million during third quarter
2019, or $757 million before changes
in working capital.
Third quarter development capital expenditures were
$646 million, with year-to-date
development capital of $1.9 billion.
The Company's 2019 development capital budget remains unchanged at
$2.4 billion.
Organic free cash flow during third quarter totaled
$81 million post-dividend, bringing
year-to-date organic free cash flow generation to $298 million.
Production Guidance
For fourth
quarter 2019, the Company forecasts total U.S. oil production of
190,000 to 200,000 net bopd. Fourth quarter 2019 international oil
production guidance is 12,000 to 16,000 net bopd. Full year 2019
divestiture-adjusted oil production growth guidance is now expected
to be 11% for total Company and 13% for U.S., above initial
guidance of 10% and 12% respectively.
Corporate
The Company has executed
$300 million of year-to-date share
repurchases, returning additional capital to shareholders beyond
the $122 million of year-to-date
dividend payments. Since the beginning of 2018, Marathon Oil has
repurchased $1 billion of its own
shares, representing approximately 7% of its outstanding share
count, funded entirely by post-dividend organic free cash flow
generation of over $1 billion over
the same period.
The Company recently completed three separate transactions
that together will further strengthen the balance sheet and
generate annualized cash cost savings of approximately $6 million. On Sept. 24,
2019, the Company entered into a Fourth Amendment to its
Amended and Restated Credit Agreement to extend the maturity date
to 2023 and reduce the size from $3.4
billion to $3.0 billion. On
Oct. 1, 2019, the Company closed a
remarketing to investors of $600
million of sub-series A bonds with tenors ranging from 3.5
to 7 years achieving a weighted average coupon rate of 2.1%. On
Oct. 3, 2019, the Company closed the
early redemption of its $600 million
2.7% Senior Unsecured Notes due 2020. The Company's next debt
maturity will be in 2022. Together, the three transactions are
leverage neutral, extend maturities, and reflect Marathon Oil's
ongoing commitment to maintaining a strong balance sheet. Marathon
Oil is rated investment grade at all three primary credit ratings
agencies.
Total liquidity as of Sept.
30 was approximately $4.2
billion, which consisted of $1.2
billion in cash and cash equivalents and an undrawn
revolving credit facility of $3.0
billion.
The adjustments to net income for third quarter 2019
totaled $54 million before tax,
primarily due to the income impact associated with unrealized gains
on derivative instruments, coupled with gains on disposal of
assets.
As of Nov. 5, 2019, the
Company's open crude hedge positions for 2019 include an average of
80,000 bopd at a weighted average floor price of $56.75 per barrel and a weighted average ceiling
price of $74.19 per bbl, hedged
through three-way collars. The Company has also hedged 42,945 bopd
of 2020 oil production at a weighted average floor price of
$55.00 per barrel and a weighted
average ceiling price of $65.58 per
barrel.
A slide deck and Quarterly Investor Packet will be posted
to the Company's website following this release today, Nov. 6. On Thursday, Nov.
7, at 9:00 a.m. ET, the
Company will conduct a question and answer webcast/call, which will
include forward-looking information. The live webcast, replay and
all related materials will be available at
https://www.marathonoil.com/Investors.
Non-GAAP Measures
In
analyzing and planning for its business, Marathon Oil supplements
its use of GAAP financial measures with non-GAAP financial
measures, including adjusted net income, adjusted net income per
share, organic free cash flow and net cash provided by operations
before changes in working capital.
Adjusted net income is defined as net income adjusted
for gain/loss on dispositions, certain property impairments,
unrealized derivative gain/loss on commodity instruments, pension
settlement losses and other items that could be considered
"non-operating" or "non-core" in nature. Management believes
adjusted net income and adjusted net income per share are useful to
investors as additional tools to meaningfully represent the
Company's operating performance and to compare Marathon to certain
competitors.
Organic free cash flow is defined as net cash provided
by operating activities adjusted for working capital, exploration
costs (other than well costs), development capital expenditures,
dividends, and EG LNG return of capital. Management believes this
is useful to investors as a measure of the Company's ability to
fund its capital expenditure programs and dividend payments,
service debt, and other distributions to stockholders. Management
also uses net cash provided by operations before changes in working
capital to demonstrate the Company's ability to generate cash
quarterly or year-to-date by eliminating differences caused by the
timing of certain working capital items.
These non-GAAP financial measures reflect an additional
way of viewing aspects of the business that, when viewed with GAAP
results may provide a more complete understanding of factors and
trends affecting the business and are a useful tool to help
management and investors make informed decisions about Marathon
Oil's financial and operating performance. These measures should
not be considered in isolation or as alternatives to their most
directly comparable GAAP financial measures. A reconciliation to
their most directly comparable GAAP financial measures can be found
in our investor package on our website at www.marathonoil.com and
in the tables below. Marathon Oil strongly
encourages investors to review the Company's consolidated financial
statements and publicly filed reports in their entirety and not
rely on any single financial measure.
Forward-looking
Statements
This release 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. All statements, other than statements of historical
fact, including without limitation statements regarding 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,
leasing and exploration activities, production, oil growth and
other plans and objectives for future operations, are
forward-looking statements. Words such as "anticipate," "believe,"
"could," "estimate," "expect," "forecast," "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, but not limited
to: 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; our ability to
complete our announced acquisitions on the timeline currently
anticipated, if at all; risks related to the Company's 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 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, flaring, or water disposal; 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.
Media Relations
Contact:
Lee
Warren: 713-296-4103
Investor Relations
Contacts:
Guy
Baber: 713-296-1892
John Reid: 713-296-4380
Consolidated
Statements of Income (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
June
30
|
Sept.
30
|
(In millions,
except per share data)
|
2019
|
2019
|
2018
|
Revenues and other
income:
|
|
|
|
Revenues from
contracts with customers
|
$
|
1,249
|
|
$
|
1,381
|
|
$
|
1,538
|
|
Net gain (loss) on
commodity derivatives
|
47
|
|
16
|
|
(70)
|
|
Income from equity
method investments
|
21
|
|
31
|
|
64
|
|
Net gain (loss) on
disposal of assets
|
22
|
|
(8)
|
|
16
|
|
Other
income
|
6
|
|
13
|
|
119
|
|
Total revenues and
other income
|
1,345
|
|
1,433
|
|
1,667
|
|
Costs and
expenses:
|
|
|
|
Production
|
163
|
|
193
|
|
215
|
|
Shipping, handling
and other operating
|
138
|
|
170
|
|
152
|
|
Exploration
|
22
|
|
26
|
|
56
|
|
Depreciation,
depletion and amortization
|
622
|
|
605
|
|
626
|
|
Impairments
|
—
|
|
18
|
|
8
|
|
Taxes other than
income
|
81
|
|
79
|
|
86
|
|
General and
administrative
|
82
|
|
87
|
|
101
|
|
Total costs and
expenses
|
1,108
|
|
1,178
|
|
1,244
|
|
Income from
operations
|
237
|
|
255
|
|
423
|
|
Net interest and
other
|
(64)
|
|
(64)
|
|
(58)
|
|
Other net periodic
benefit costs
|
2
|
|
2
|
|
(8)
|
|
Income before
income taxes
|
175
|
|
193
|
|
357
|
|
Provision (benefit)
for income taxes
|
10
|
|
32
|
|
103
|
|
Net
income
|
$
|
165
|
|
$
|
161
|
|
$
|
254
|
|
|
|
|
|
Adjusted Net
Income
|
|
|
|
Net
income
|
$
|
165
|
|
$
|
161
|
|
$
|
254
|
|
Adjustments for
special items (pre-tax):
|
|
|
|
Net (gain) loss on
disposal of assets
|
(22)
|
|
8
|
|
(16)
|
|
Proved property
impairments
|
—
|
|
18
|
|
8
|
|
Pension
settlement
|
—
|
|
2
|
|
10
|
|
Unrealized (gain)
loss on derivative instruments
|
(33)
|
|
(11)
|
|
(19)
|
|
Reduction of U.K. ARO
estimated costs
|
—
|
|
—
|
|
(113)
|
|
Other
|
1
|
|
11
|
|
—
|
|
Benefit for income
taxes related to special items
|
—
|
|
—
|
|
76
|
|
Adjustments for
special items
|
(54)
|
|
28
|
|
(54)
|
|
Adjusted net
income (a)
|
$
|
111
|
|
$
|
189
|
|
$
|
200
|
|
Per diluted
share:
|
|
|
|
Net income
|
$
|
0.21
|
|
$
|
0.20
|
|
$
|
0.30
|
|
Adjusted net income
(a)
|
$
|
0.14
|
|
$
|
0.23
|
|
$
|
0.24
|
|
Weighted average
diluted shares
|
803
|
|
814
|
|
849
|
|
(a)
|
Non-GAAP financial
measure. See "Non-GAAP Measures" above for further
discussion.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
June
30
|
Sept.
30
|
(In
millions)
|
2019
|
2019
|
2018
|
Segment
income
|
|
|
|
United
States
|
$
|
180
|
|
$
|
215
|
|
$
|
201
|
|
International
|
43
|
|
96
|
|
116
|
|
Segment
income
|
223
|
|
311
|
|
317
|
|
Not allocated to
segments
|
(58)
|
|
(150)
|
|
(63)
|
|
Net
income
|
$
|
165
|
|
$
|
161
|
|
$
|
254
|
|
Exploration
expenses
|
|
|
|
United
States
|
$
|
22
|
|
$
|
26
|
|
$
|
55
|
|
International
|
—
|
|
—
|
|
1
|
|
Total
|
$
|
22
|
|
$
|
26
|
|
$
|
56
|
|
Cash
flows
|
|
|
|
Net cash provided by
operating activities
|
$
|
737
|
|
$
|
797
|
|
$
|
963
|
|
Minus: changes in
working capital
|
(20)
|
|
26
|
|
103
|
|
Net cash provided by
operations before changes in working capital (a)
|
$
|
757
|
|
$
|
771
|
|
$
|
860
|
|
|
|
|
|
Cash additions to
property, plant and equipment
|
$
|
(672)
|
|
$
|
(647)
|
|
$
|
(769)
|
|
(a)
|
Non-GAAP financial
measure. See "Non-GAAP Measures" above for further
discussion.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
Nine Months
Ended
|
(In
millions)
|
Sept. 30,
2019
|
Sept. 30,
2019
|
Organic Free Cash
Flow
|
|
|
Net cash provided by
operating activities
|
$
|
737
|
|
$
|
2,049
|
|
Adjustments:
|
|
|
Changes in working
capital
|
20
|
|
151
|
|
Exploration costs
other than well costs
|
6
|
|
22
|
|
Development capital
expenditures
|
(646)
|
|
(1,851)
|
|
Dividends
|
(40)
|
|
(122)
|
|
EG LNG return of
capital and other
|
4
|
|
49
|
|
Organic free cash
flow (a)
|
$
|
81
|
|
$
|
298
|
|
(a)
|
Non-GAAP financial
measure. See "Non-GAAP Measures" above for further
discussion.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
June
30
|
Sept.
30
|
(mboed)
|
2019
|
2019
|
2018
|
Net
production
|
|
|
|
United
States
|
339
|
|
332
|
|
304
|
|
International
|
87
|
|
103
|
|
115
|
|
Total net
production
|
426
|
|
435
|
|
419
|
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
June
30
|
Sept.
30
|
(mboed)
|
2019
|
2019
|
2018
|
Net
production
|
|
|
|
United
States
|
339
|
|
332
|
|
304
|
|
Less: Divestitures
(a)
|
1
|
|
2
|
|
4
|
|
Total
divestiture-adjusted United States
|
338
|
|
330
|
|
300
|
|
|
|
|
|
International
|
87
|
|
103
|
|
115
|
|
Less: Divestitures
(b)
|
—
|
|
12
|
|
16
|
|
Total
divestiture-adjusted International
|
87
|
|
91
|
|
99
|
|
|
|
|
|
Total net
production divestiture-adjusted (a)(b)
|
425
|
|
421
|
|
399
|
|
(a)
|
The Company closed on
the sale of certain United States non-core conventional assets in
third quarter 2018, first quarter 2019, and third quarter 2019. The
production volumes relating to these dispositions have been removed
from all corresponding prior periods to derive the
divestiture-adjusted United States net production.
|
(b)
|
Divestitures include
volumes associated with the sale of our U.K. business, which closed
in third quarter 2019, and the sale of our non-operated interest in
Kurdistan, which closed in second quarter 2019. These production
volumes have been removed from historical periods above in arriving
at total divestiture-adjusted International net
production.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
June
30
|
Sept.
30
|
|
2019
|
2019
|
2018
|
United States -
net sales volumes
|
|
|
|
Crude oil and
condensate (mbbld)
|
201
|
|
190
|
|
173
|
|
Eagle Ford
|
63
|
|
61
|
|
66
|
|
Bakken
|
92
|
|
88
|
|
72
|
|
Oklahoma
|
23
|
|
21
|
|
18
|
|
Northern
Delaware
|
18
|
|
15
|
|
12
|
|
Other United
States
|
5
|
|
5
|
|
5
|
|
Natural gas
liquids (mbbld)
|
61
|
|
64
|
|
58
|
|
Eagle Ford
|
22
|
|
25
|
|
26
|
|
Bakken
|
9
|
|
8
|
|
6
|
|
Oklahoma
|
23
|
|
24
|
|
21
|
|
Northern
Delaware
|
6
|
|
6
|
|
4
|
|
Other United
States
|
1
|
|
1
|
|
1
|
|
Natural gas
(mmcfd)
|
462
|
|
459
|
|
433
|
|
Eagle Ford
|
134
|
|
139
|
|
137
|
|
Bakken
|
46
|
|
42
|
|
36
|
|
Oklahoma
|
229
|
|
223
|
|
208
|
|
Northern
Delaware
|
36
|
|
36
|
|
30
|
|
Other United
States
|
17
|
|
19
|
|
22
|
|
Total United
States (mboed)
|
339
|
|
330
|
|
303
|
|
International -
net sales volumes
|
|
|
|
Crude oil and
condensate (mbbld)
|
16
|
|
30
|
|
27
|
|
Equatorial
Guinea
|
16
|
|
20
|
|
18
|
|
United
Kingdom
|
—
|
|
8
|
|
6
|
|
Other
International
|
—
|
|
2
|
|
3
|
|
Natural gas
liquids (mbbld)
|
10
|
|
10
|
|
11
|
|
Equatorial
Guinea
|
10
|
|
10
|
|
11
|
|
United
Kingdom
|
—
|
|
—
|
|
—
|
|
Natural gas
(mmcfd)
|
373
|
|
403
|
|
441
|
|
Equatorial
Guinea
|
373
|
|
392
|
|
426
|
|
United Kingdom
(a)
|
—
|
|
11
|
|
15
|
|
Total
International (mboed)
|
88
|
|
107
|
|
112
|
|
Total Company -
net sales volumes (mboed)
|
427
|
|
437
|
|
415
|
|
Net sales volumes
of equity method investees
|
|
|
|
LNG (mtd)
|
4,590
|
|
5,321
|
|
6,152
|
|
Methanol
(mtd)
|
1,036
|
|
1,134
|
|
1,334
|
|
Condensate and LPG
(boed)
|
11,586
|
|
11,080
|
|
11,942
|
|
(a)
|
Includes natural gas
acquired for injection and subsequent resale.
|
Supplemental Statistics
(Unaudited)
|
Three Months Ended
|
|
Sept. 30
|
June 30
|
Sept. 30
|
|
2019
|
2019
|
2018
|
United States - average price realizations
(a)
|
|
|
|
Crude oil and condensate ($ per bbl)
(b)
|
$
|
55.09
|
|
$
|
59.18
|
|
$
|
68.51
|
|
Eagle Ford
|
57.99
|
|
63.10
|
|
72.00
|
|
Bakken
|
53.48
|
|
56.84
|
|
67.26
|
|
Oklahoma
|
55.09
|
|
58.66
|
|
70.14
|
|
Northern
Delaware
|
54.16
|
|
55.33
|
|
55.01
|
|
Other United States
(c)
|
51.74
|
|
66.21
|
|
66.67
|
|
Natural gas liquids ($ per bbl)
|
$
|
11.37
|
|
$
|
14.60
|
|
$
|
28.07
|
|
Eagle Ford
|
11.40
|
|
13.19
|
|
28.62
|
|
Bakken
|
7.16
|
|
18.68
|
|
31.92
|
|
Oklahoma
|
13.20
|
|
14.39
|
|
25.29
|
|
Northern
Delaware
|
10.02
|
|
15.02
|
|
31.44
|
|
Other United States
(c)
|
15.21
|
|
17.25
|
|
34.71
|
|
Natural gas ($ per mcf) (d)
|
$
|
1.92
|
|
$
|
1.89
|
|
$
|
2.55
|
|
Eagle Ford
|
2.29
|
|
2.51
|
|
2.84
|
|
Bakken
|
1.83
|
|
1.70
|
|
2.64
|
|
Oklahoma
|
1.75
|
|
1.78
|
|
2.40
|
|
Northern
Delaware
|
0.84
|
|
0.18
|
|
2.24
|
|
Other United States
(c)
|
3.69
|
|
2.26
|
|
2.48
|
|
International - average price
realizations
|
|
|
|
Crude oil and condensate ($ per
bbl)
|
$
|
46.04
|
|
$
|
58.21
|
|
$
|
64.08
|
|
Equatorial
Guinea
|
46.04
|
|
54.38
|
|
61.23
|
|
United
Kingdom
|
—
|
|
68.40
|
|
73.28
|
|
Other
International
|
—
|
|
55.83
|
|
62.30
|
|
Natural gas liquids ($ per bbl)
|
$
|
1.00
|
|
$
|
1.67
|
|
$
|
2.04
|
|
Equatorial Guinea
(d)
|
1.00
|
|
1.00
|
|
1.00
|
|
United
Kingdom
|
—
|
|
37.63
|
|
50.37
|
|
Natural gas ($ per mcf)
|
$
|
0.24
|
|
$
|
0.35
|
|
$
|
0.50
|
|
Equatorial Guinea
(d)
|
0.24
|
|
0.24
|
|
0.24
|
|
United
Kingdom
|
—
|
|
4.25
|
|
8.60
|
|
Benchmark
|
|
|
|
WTI crude oil (per
bbl)
|
$
|
56.44
|
|
$
|
59.91
|
|
$
|
69.43
|
|
Brent (Europe) crude
oil (per bbl) (e)
|
$
|
61.93
|
|
$
|
68.92
|
|
$
|
75.22
|
|
Mont Belvieu NGLs
(per bbl) (f)
|
$
|
15.16
|
|
$
|
17.64
|
|
$
|
31.25
|
|
Henry Hub natural gas
(per mmbtu) (g)
|
$
|
2.23
|
|
$
|
2.64
|
|
$
|
2.90
|
|
(a)
|
Excludes gains or
losses on commodity derivative instruments.
|
(b)
|
Inclusion of realized
gains (losses) on crude oil derivative instruments would have
affected average price realizations by $0.72, $0.32 and $(5.70) for
third quarter 2019, second quarter 2019, and third quarter
2018.
|
(c)
|
Includes sales
volumes from the sale of certain non-core proved properties in our
International and United States segments.
|
(d)
|
Represents fixed
prices under long-term contracts with Alba Plant LLC, Atlantic
Methanol Production Company LLC and/or Equatorial Guinea LNG
Holdings Limited, which are equity method investees. The Alba Plant
LLC processes the NGLs and then sells secondary condensate,
propane, and butane at market prices. Marathon Oil includes its
share of income from each of these equity method investees in the
International segment.
|
(e)
|
Average of monthly
prices obtained from Energy Information Administration
website.
|
(f)
|
Bloomberg Finance
LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8%
isobutane and 7% natural gasoline.
|
(g)
|
Settlement date
average per mmbtu.
|
Q4 2019 Production
Guidance
|
Oil Production (mbbld)
|
|
Equivalent Production (mboed)
|
Q4 2019
|
Q3 2019
|
Q4 2018
|
|
Q4 2019
|
Q3 2019
|
Q4 2018
|
|
Low
|
High
|
Divestiture-
Adjusted
|
Divestiture-
Adjusted
|
|
Low
|
High
|
Divestiture-
Adjusted
|
Divestiture-
Adjusted
|
Net production
|
|
|
|
|
|
|
|
|
|
United
States
|
190
|
|
200
|
|
201
|
|
179
|
|
|
320
|
|
330
|
|
338
|
|
304
|
|
International
|
12
|
|
16
|
|
15
|
|
16
|
|
|
80
|
|
90
|
|
87
|
|
93
|
|
Total net
production
|
202
|
|
216
|
|
216
|
|
195
|
|
|
400
|
|
420
|
|
425
|
|
397
|
|
The following table sets forth outstanding derivative
contracts as of Nov. 5, 2019, and the
weighted average prices for those contracts:
|
|
2019
|
|
|
2020
|
|
|
2021
|
Crude Oil
|
|
Fourth Quarter
|
|
|
Full Year
|
|
|
Full Year
|
NYMEX WTI Three-Way Collars
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day)
|
|
80,000
|
|
|
|
42,945
|
|
|
|
—
|
|
Weighted average
price per Bbl:
|
|
|
|
|
|
|
|
|
Ceiling
|
|
$
|
74.19
|
|
|
|
$
|
65.58
|
|
|
|
—
|
|
Floor
|
|
$
|
56.75
|
|
|
|
$
|
55.00
|
|
|
|
—
|
|
Sold put
|
|
$
|
49.50
|
|
|
|
$
|
47.77
|
|
|
|
—
|
|
Basis Swaps - Argus WTI Midland
(a)
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day)
|
|
15,000
|
|
|
|
15,000
|
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
$
|
(1.40)
|
|
|
|
$
|
(0.94)
|
|
|
|
—
|
|
Basis Swaps - Net Energy Clearbrook
(b)
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day)
|
|
2,000
|
|
|
|
—
|
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
$
|
(3.33)
|
|
|
|
—
|
|
|
|
—
|
|
Basis Swaps - NYMEX WTI / ICE Brent
(c)
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day)
|
|
5,000
|
|
|
|
5,000
|
|
|
|
808
|
|
Weighted average
price per Bbl
|
|
$
|
(7.24)
|
|
|
|
$
|
(7.24)
|
|
|
|
$
|
(7.24)
|
|
Basis Swaps - Argus WTI Houston
(d)
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day)
|
|
10,000
|
|
|
|
—
|
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
$
|
5.51
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
NYMEX Roll Basis Swaps
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day)
|
|
60,000
|
|
|
|
—
|
|
|
|
—
|
|
Weighted average price
per Bbl
|
|
$
|
0.38
|
|
|
|
—
|
|
|
|
—
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
Three-Way Collars
(e)
|
|
|
|
|
|
|
|
|
Volume
(MMBtu/day)
|
|
—
|
|
|
|
24,863
|
|
|
|
—
|
|
Weighted average
price per MMBtu:
|
|
|
|
|
|
|
|
|
Ceiling
|
|
—
|
|
|
|
3.32
|
|
|
|
—
|
|
Floor
|
|
—
|
|
|
|
2.75
|
|
|
|
—
|
|
Sold put
|
|
—
|
|
|
|
2.25
|
|
|
|
—
|
|
(a)
|
The basis
differential price is indexed against Argus WTI Midland.
|
(b)
|
The basis
differential price is indexed against Net Energy Canada Bakken SW
at Clearbrook ("UHC").
|
(c)
|
The basis
differential price is indexed against International Commodity
Exchange ("ICE") Brent and NYMEX WTI.
|
(d)
|
The basis
differential price is indexed against Argus WTI Houston.
|
(e)
|
Between Oct. 1, 2019
and Nov. 5, 2019, we entered into 100,000 MMBtu/day of three-way
collars for January - March 2020 with a ceiling price of $3.32, a
floor price of $2.75, and a sold put price of $2.25.
|
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SOURCE Marathon Oil Corporation