HOUSTON, Nov. 7, 2018 /PRNewswire/ -- Marathon Oil
Corporation (NYSE: MRO) today reported third quarter 2018 net
income of $254 million, or
$0.30 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 $200 million, or $0.24 per diluted share. Net operating cash flow
was $963 million, or $889 million before changes in working
capital.
Highlights
- Generated $320 million of organic
free cash flow during third quarter, bringing year-to-date organic
free cash flow generation to over $630
million
- Executed $500 million of
year-to-date share repurchases, returning additional capital to
shareholders beyond existing $170
million annual dividend; $1
billion of repurchase authorization remaining
- Raised both 2018 total Company and resource play oil and boe
annual production guidance with no change to 2018 development
capital budget; third quarter development capital expenditures down
8% sequentially with full-year resource play wells to sales
trending slightly above the midpoint of guidance
- Total third quarter production averaged 419,000 net boed, above
the high end of guidance; total oil production averaged 204,000 net
bopd, up 3% compared to the prior quarter on a divestiture adjusted
basis
- U.S. resource play third quarter production averaged 294,000
net boed, above the high end of guidance; oil production averaged
168,000 net bopd, up 4% compared to the prior quarter
- Eagle Ford production increased to 115,000 net boed, up 8%
sequentially; 12 wells to sales in the Atascosa County extended core averaged a
30-day IP rate of 1,400 boed (81% oil)
- Bakken production averaged 85,000 net boed, up 4% sequentially,
with oil production up 5%; 21 wells to sales averaged a 30-day IP
rate of 3,460 boed (76% oil); basin leading performance continues
with a six well West Myrmidon pad achieving an average 30-day IP
rate of 4,745 boed (73% oil), three of which set new Three Forks
Williston Basin records, including one well achieving a 30-day IP
rate of 6,380 boed (75% oil); successful Hector Southern extension with two-well Lars pad
achieving an average 30-day IP rate of 1,810 boed (83% oil)
- Oklahoma production averaged
73,000 net boed; two successful STACK Meramec overpressured
multi-well pads brought on-line, achieving average 30-day IP rates
of 1,700 boed (65% oil) and 1,485 boed (63% oil), respectively
- Northern Delaware production
averaged 21,000 net boed, up 24% sequentially; 18 wells to sales
averaged a 30-day IP rate of 1,285 boed (65% oil), or 285 boed per
1,000-foot lateral; a three-well Malaga pad in Eddy county averaged a 30-day IP rate of 2,275
boed (63% oil), or 540 boed per 1,000-foot lateral
"Another quarter of outstanding operational execution and
capital efficiency across our multi-basin U.S. portfolio has again
delivered production out-performance and enabled us to raise annual
resource play production guidance for the third consecutive
quarter, with no increase to our development capital budget. Each
of our asset teams contributed to this strong outcome, highlighted
by basin leading results and continued core extension in the Eagle
Ford and Bakken, the successful transition to primarily multi-well
pad development drilling in Oklahoma, and the progression of important
multi-well tests alongside strategic advancements in the
Northern Delaware," said Marathon
Oil president and CEO Lee Tillman.
"Consistent execution and our commitment to capital discipline have
resulted in more than $630 million of
year-to-date organic free cash flow generation, enabling us to
return additional capital to shareholders through $500 million of share repurchases. At the same
time, we maintained our focus on resource base enhancement, as
evidenced by organic inventory upgrades in the Eagle Ford and
Bakken, our successful participation in the recent New Mexico lease sale, and the spud of our
first exploration well in the emerging Louisiana Austin Chalk play.
We remain on track to deliver a strong rate of change in our key
financial performance metrics, highlighted by an expected annual
increase of 85 percent in corporate cash return on invested capital
(CROIC) at $65/bbl WTI. Looking ahead
to 2019, our framework for success will not change: a focus on
corporate level returns, differentiated execution, free cash flow
delivery at conservative oil prices, and the return of capital back
to shareholders."
Development Capital
Third quarter development capital
expenditures, before working capital, were $557 million, down 8 percent sequentially. Net
cash provided by continuing operations was $963 million during third quarter 2018, or
$889 million before changes in
working capital. The Company's 2018 development capital budget
remains unchanged at $2.3
billion.
Resource Capture
Outside of the development capital
budget, total resource capture spending totaled $151 million during third quarter, including both
Resource Play leasing and exploration (REx) and small bolt-on
acquisitions. This year's resource capture spend has been more than
fully funded through divestiture proceeds received in first quarter
2018.
Third quarter 2018 REx capital expenditures totaled $46 million, bringing year-to-date REx spend to
$294 million. The Company spud its
first Louisiana Austin Chalk exploration well, with results
anticipated in 2019. Though episodic in nature, the Company
anticipates REx capital expenditures of $50 to $100 million
during fourth quarter 2018 representing no change to full-year REx
capital spending guidance.
In the Northern Delaware the
Company acquired 1,800 net acres in New
Mexico for $105 million in the
Bureau of Land Management (BLM) lease sale. These bolt-on leases
include an attractive 12.5 percent royalty interest and a 10-year
term, and are synergistic with the Company's existing footprint in
the play.
Production Guidance
Marathon Oil expects fourth
quarter 2018 U.S. production to average 295,000 to 305,000 net
barrels of oil equivalent per day (boed). The Company expects
fourth quarter 2018 U.S. resource play production to average
290,000 to 300,000 net boed, with oil production expected to
increase approximately 5 percent sequentially despite a planned
modest quarter-on-quarter reduction in wells to sales. Full-year
wells to sales continues to trend slightly above the midpoint of
guidance. Fourth quarter 2018 International production is expected
to average 105,000 to 115,000 net boed, affected by the timing of
planned maintenance in E.G.
The Company increased its annual 2018 total Company production
guidance to 405,000 to 415,000 net boed, up from 400,000 to 415,000
net boed. The Company also raised its guidance for annual resource
play oil and barrel of oil equivalent (boe) growth to 30 - 34
percent, up from 28 - 32 percent previously, with oil expected to
be at the high end of the range. All guidance is adjusted to
reflect the divestment of non-core U.S. assets that closed in July,
and which contributed 1,000 boed (75% oil) to third quarter
production, as well as an international asset sale that closed in
August, and which contributed 1,400 boed to third quarter
production (100% oil).
U.S. E&P
U.S. E&P production averaged 304,000
net boed for third quarter 2018, including oil production of
174,000 net barrels of oil per day (bopd). Oil production was up 5
percent compared to the prior quarter and up 28 percent from the
year-ago quarter on a divestiture-adjusted basis. Third quarter
production from the U.S. resource plays was 294,000 net boed,
including oil production of 168,000 net bopd. Third quarter U.S.
E&P unit production costs were $6.14 per boe. In July, the Company closed on the
previously announced sales of its non-operated Gunflint and Troika
assets in the Gulf of Mexico and a
CO2 flood in West Texas, which
collectively averaged production of 1,000 boed (76% oil) in third
quarter 2018 and 5,000 net boed in the first half of the year (76%
oil).
EAGLE FORD: Marathon Oil's Eagle Ford production averaged
115,000 net boed in the third quarter, compared to 106,000 net boed
in the prior quarter. The Company brought 38 gross Company-operated
wells to sales with an average 30-day initial production (IP) rate
of 1,680 boed (63% oil), including 12 wells with an average 30-day
IP rate of 1,400 boed (81% oil) in the extended core of
Atascosa County. The Eagle Ford
asset again generated significant free cash flow in the quarter
through a combination of well performance and oil realizations
above WTI due to strong LLS-based pricing.
BAKKEN: In third quarter 2018, Marathon Oil's Bakken production
averaged 85,000 net boed, up 4 percent compared to 82,000 net boed
in the prior quarter. Oil production was up 5 percent sequentially.
The Company brought 21 gross Company-operated wells to sales with
an average 30-day IP rate of 3,460 boed (76% oil), with activity
primarily concentrated in Myrmidon. In West Myrmidon during third
quarter, a six well pad achieved an average 30-day IP rate of 4,745
boed (73% oil). Three of these wells established new Three Forks
Williston Basin records, including the Jerome well with an average
30-day IP rate of 6,380 boed (75% oil). The Company also continues
to extend the core of its acreage position, with the two-well Lars
pad in southern Hector achieving an average 30-day IP rate of 1,810
boed (83% oil) and plans are on track to test the Ajax area before
year-end. Marathon Oil is in full compliance with state gas capture
requirements, and anticipates no impact to forward development
plans.
OKLAHOMA: Marathon Oil's
Oklahoma production averaged
73,000 net boed during third quarter 2018, down from 80,000 net
boed in the prior quarter, with only 11 wells brought to sales.
This is consistent with the Company's successful transition from
leasehold drilling to primarily multi-well pad development. In the
STACK, the Company brought on two Meramec overpressured pads at
different equivalent well spacing that illustrate the consistency
and predictability of optimized development at the drill spacing
unit (DSU) level. The Irven John infill pad on four wells per
section equivalent spacing achieved an average 30-day IP rate of
1,700 boed (65% oil) and the HR Potter infill pad on seven wells
per section equivalent spacing achieved an average 30-day IP rate
of 1,485 boed (63% oil). Four of the new HR Potter wells were
brought on at the end of third quarter, while the remaining wells
were brought on subsequent to quarter end.
NORTHERN DELAWARE: Marathon
Oil's Northern Delaware production
increased to an average of 21,000 net boed in third quarter 2018,
up 24 percent from the prior quarter. The Company brought 18 gross
Company-operated wells to sales in the Malaga and Red Hills areas, a mix of development and
appraisal wells with an average 30-day IP rate of 1,285 boed (65%
oil), or 285 boed per 1,000 foot lateral. A three-well Malaga pad
in Eddy county, which targeted
Upper Wolfcamp horizons, reported an average 30-day IP rate of
2,275 boed (63% oil), or 540 boed per 1,000 foot lateral. The
Company made important midstream advancements during third quarter
to protect flow assurance, improve realizations and reduce
expenses. Marathon Oil executed a two-year term oil sales agreement
with a strategic buyer at attractive terms and signed a gas
gathering and processing agreement covering the vast majority of
Lea and Eddy county acreage. The Company continues to
benefit from its Midland-Cushing
basis swaps, with open positions that include 10,000 bopd hedged
through remainder of 2018 and all of 2019, and 15,000 bopd hedged
for full-year 2020, all at a discount of less than $1 to WTI.
International E&P
International E&P
production averaged 115,000 net boed for third quarter 2018, down 4
percent compared to the prior quarter on a divestiture-adjusted
basis. The decrease reflects maintenance activities in both E.G.
and the U.K. In August, the Company closed on the previously
announced sale of its non-operated interest in the Sarsang block in
Kurdistan which produced 1,400 net
boed in the third quarter and averaged 2,300 net boed through the
first half of the year (100% oil). Third quarter 2018 International
E&P unit production costs averaged $4.22 per boe.
During the third quarter the Company reduced the estimated cost
of the U.K. asset retirement obligation (ARO) by $125 million, primarily due to the capture of
favorable market conditions.
In addition to the previously referenced fourth quarter 2018
maintenance, a complete shutdown is planned for E.G. during first
quarter 2019 to conduct planned turnaround activity.
Corporate
The Company has executed $500 million of year-to-date share repurchases,
returning additional capital to shareholders beyond the existing
$170 million annual dividend. Share
repurchases have been more than fully funded by year-to-date
organic free cash flow generation of over $630 million.
Total liquidity as of September 30
was approximately $5.0 billion, which
consisted of $1.6 billion in cash and
cash equivalents and an undrawn revolving credit facility of
$3.4 billion which was recently
extended by one year to 2022.
The adjustments to net income for third quarter 2018 totaled
$130 million before tax, primarily
due to the income impact associated with the reduction in the U.K.
ARO.
A slide deck and Quarterly Investor Packet will be posted to the
Company's website following this release today, Nov. 7. On Thursday, Nov.
8, 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.
Definitions
CROIC - 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).
Organic free cash flow - Operating cash flow before working capital
(excluding exploration costs other than well costs), less
development capital expenditures, less dividends, plus
other.
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 (loss), adjusted net income (loss) per share,
net cash provided by continuing operations before changes in
working capital, CROIC and organic free cash flow because the
Company believes this information is useful to investors to help
evaluate the Company's financial performance between periods and to
compare the Company's performance to certain competitors.
Management also uses net cash provided by continuing operations
before changes in working capital to demonstrate the Company's
ability to internally fund capital expenditures, pay dividends and
service debt. The Company considers adjusted net income (loss),
adjusted income (loss) from continuing operations, adjusted net
income (loss) per share and adjusted income (loss) from continuing
operations per share as another way to meaningfully represent the
Company's operational performance for the period presented;
consequently, it excludes the impact of mark-to-market accounting,
impairment charges, dispositions, pension settlements, and other
items that could be considered "non-operating" or "non-core" in
nature. 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 substitutes for 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 2018 capital budget and allocations, future
performance, organic free cash flow, corporate-level cash returns
on invested capital, business strategy, asset quality, drilling
plans, production guidance, cash margins, rates of change for
CROIC, asset sales and acquisitions, leasing and exploration
activities, production, and other plans and objectives for future
operations, are forward-looking statements. Words such as
"anticipate," "believe," "could," "estimate," "expect," "forecast,"
"guidance," "intend," "may," "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;
risks related to the Company's hedging activities; capital
available for exploration and development; drilling and operating
risks; well production timing; availability of drilling rigs,
materials and labor, including associated costs; 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; 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.
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)
|
2018
|
|
2018
|
|
2017
|
Revenues and other
income:
|
|
|
|
|
|
Revenues
from contracts with customers
|
$
|
1,538
|
|
$
|
1,447
|
|
$
|
1,136
|
Net gain
(loss) on commodity derivatives
|
(70)
|
|
(152)
|
|
(22)
|
Marketing revenues
|
—
|
|
—
|
|
48
|
Income
from equity method investments
|
64
|
|
60
|
|
63
|
Net gain
(loss) on disposal of assets
|
16
|
|
50
|
|
19
|
Other
income
|
119
|
|
12
|
|
8
|
Total revenues and
other income
|
1,667
|
|
1,417
|
|
1,252
|
Costs and
expenses:
|
|
|
|
|
|
Production
|
215
|
|
205
|
|
197
|
Marketing, including purchases from related parties
|
—
|
|
—
|
|
49
|
Shipping, handling and other operating
|
152
|
|
126
|
|
109
|
Exploration
|
56
|
|
65
|
|
294
|
Depreciation, depletion and amortization
|
626
|
|
612
|
|
641
|
Impairments
|
8
|
|
34
|
|
201
|
Taxes
other than income
|
86
|
|
65
|
|
44
|
General
and administrative
|
101
|
|
105
|
|
89
|
Total costs and
expenses
|
1,244
|
|
1,212
|
|
1,624
|
Income (loss) from
operations
|
423
|
|
205
|
|
(372)
|
Net
interest and other
|
(58)
|
|
(65)
|
|
(35)
|
Other
net periodic benefit costs
|
(8)
|
|
—
|
|
(5)
|
Loss on
early extinguishment of debt
|
—
|
|
—
|
|
(46)
|
Income (loss) from
operations before income taxes
|
357
|
|
140
|
|
(458)
|
Provision
(benefit) for income taxes
|
103
|
|
44
|
|
141
|
Net income
(loss)
|
$
|
254
|
|
$
|
96
|
|
$
|
(599)
|
|
|
|
|
|
|
Adjusted Net
Income (Loss)
|
|
|
|
|
|
Net income
(loss)
|
254
|
|
96
|
|
(599)
|
Adjustments for
special items (pre-tax):
|
|
|
|
|
|
Net (gain) loss on
disposal of assets
|
(16)
|
|
(50)
|
|
(19)
|
Proved property
impairments
|
8
|
|
34
|
|
201
|
Exploratory dry well
costs, unproved property impairments and other
|
—
|
|
—
|
|
250
|
Pension
settlement
|
10
|
|
2
|
|
8
|
Unrealized (gain)
loss on derivative instruments
|
(19)
|
|
45
|
|
56
|
Reduction of U.K. ARO
estimated costs
|
(113)
|
|
(8)
|
|
—
|
Other
|
—
|
|
—
|
|
(5)
|
Provision (benefit)
for income taxes related to special items
|
76
|
|
7
|
|
40
|
Adjustments for
special items
|
$
|
(54)
|
|
$
|
30
|
|
$
|
531
|
Adjusted net
income (loss) (a)
|
$
|
200
|
|
$
|
126
|
|
$
|
(68)
|
Per diluted
share:
|
|
|
|
|
|
Net income
(loss)
|
$
|
0.30
|
|
$
|
0.11
|
|
$
|
(0.70)
|
Adjusted net income
(loss) (a)
|
$
|
0.24
|
|
$
|
0.15
|
|
$
|
(0.08)
|
Weighted average
diluted shares
|
849
|
|
855
|
|
850
|
|
(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)
|
2018
|
|
2018
|
|
2017
|
Segment income
(loss)
|
|
|
|
|
|
United States
E&P
|
$
|
201
|
|
$
|
123
|
|
$
|
(38)
|
International
E&P
|
116
|
|
142
|
|
104
|
Segment income
(loss)
|
317
|
|
265
|
|
66
|
Not allocated to
segments
|
(63)
|
|
(169)
|
|
(665)
|
Net income
(loss)
|
$
|
254
|
|
$
|
96
|
|
$
|
(599)
|
Exploration
expenses
|
|
|
|
|
|
United States
E&P
|
$
|
55
|
|
$
|
64
|
|
$
|
41
|
International
E&P
|
1
|
|
1
|
|
3
|
Segment exploration
expenses
|
56
|
|
65
|
|
44
|
Not allocated to
segments
|
—
|
|
—
|
|
250
|
Total
|
$
|
56
|
|
$
|
65
|
|
$
|
294
|
Cash
flows
|
|
|
|
|
|
Net cash provided by
operating activities
|
$
|
963
|
|
$
|
767
|
|
$
|
564
|
Minus: changes in
working capital
|
74
|
|
(82)
|
|
62
|
Total net cash
provided from operations before changes in working capital
(a)
|
$
|
889
|
|
$
|
849
|
|
$
|
502
|
|
|
|
|
|
|
Cash additions to
property, plant and equipment
|
$
|
(769)
|
|
$
|
(638)
|
|
$
|
(530)
|
|
(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,
2018
|
|
Sept. 30,
2018
|
Organic Free Cash
Flow
|
|
|
|
Net cash provided by
operating activities
|
$
|
963
|
|
$
|
2,379
|
Development capital
expenditures
|
(557)
|
|
(1,783)
|
Dividends
|
(43)
|
|
(128)
|
Less changes in
working capital
|
(74)
|
|
66
|
Exploration costs
other than well costs
|
5
|
|
29
|
EG LNG return of
capital & other
|
25
|
|
69
|
Organic free cash
flow (a)
|
$
|
319
|
|
$
|
632
|
|
(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)
|
2018
|
|
2018
|
|
2017
|
Net
production
|
|
|
|
|
|
United States
E&P
|
304
|
|
298
|
|
245
|
International
E&P, excluding Libya (a)
|
115
|
|
121
|
|
126
|
Total net production,
excluding Libya (a)
|
419
|
|
419
|
|
371
|
Libya (a)
|
—
|
|
—
|
|
23
|
Total net
production
|
419
|
|
419
|
|
394
|
|
(a) The Company
closed on the sale of its Libya subsidiary in the first quarter
2018.
|
|
|
|
|
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
|
June
30
|
|
Sept.
30
|
(mboed)
|
2018
|
|
2018
|
|
2017
|
Net
production
|
|
|
|
|
|
United States
E&P
|
304
|
|
298
|
|
245
|
Less: Divestitures
(a)
|
1
|
|
4
|
|
8
|
Total
divestiture-adjusted United States E&P
|
303
|
|
294
|
|
237
|
|
|
|
|
|
|
International
E&P
|
115
|
|
121
|
|
149
|
Less:
Divestitures (b)
|
1
|
|
2
|
|
24
|
Total
divestiture-adjusted International E&P
|
114
|
|
119
|
|
125
|
|
|
|
|
|
|
Total net
production divestiture-adjusted (a)(b)
|
417
|
|
413
|
|
362
|
|
|
(a)
|
We closed on the sale
of certain United States E&P non-core conventional assets
primarily in the Gulf of Mexico in the third quarter of 2018,
Oklahoma and Colorado in the third quarter of 2017. These
production volumes have been removed from all historical periods
shown in arriving at total divestiture-adjusted United States
E&P net production.
|
|
|
(b)
|
The Company closed on
the sale of its Libya subsidiary in the first quarter 2018.
Additionally, divestitures include the sale of certain non-core
International E&P assets which closed in the third quarter of
2018. These production volumes have been removed from all
historical periods shown in arriving at total divestiture-adjusted
International E&P net production.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
|
June
30
|
|
Sept.
30
|
|
2018
|
|
2018
|
|
2017
|
United States
E&P - net sales volumes
|
|
|
|
|
|
Crude oil
and condensate (mbbld)
|
173
|
|
168
|
|
139
|
Eagle Ford
|
66
|
|
63
|
|
58
|
Bakken
|
72
|
|
69
|
|
49
|
Oklahoma
|
18
|
|
18
|
|
17
|
Northern Delaware
|
12
|
|
11
|
|
6
|
Other United States
(a)
|
5
|
|
7
|
|
9
|
Natural gas
liquids (mbbld)
|
58
|
|
57
|
|
44
|
Eagle Ford
|
26
|
|
22
|
|
22
|
Bakken
|
6
|
|
7
|
|
6
|
Oklahoma
|
21
|
|
24
|
|
14
|
Northern Delaware
|
4
|
|
3
|
|
—
|
Other United States
(a)
|
1
|
|
1
|
|
2
|
Natural gas
(mmcfd)
|
433
|
|
435
|
|
369
|
Eagle Ford
|
137
|
|
127
|
|
126
|
Bakken
|
36
|
|
35
|
|
26
|
Oklahoma
|
208
|
|
230
|
|
161
|
Northern Delaware
|
30
|
|
18
|
|
15
|
Other United States
(a)
|
22
|
|
25
|
|
41
|
Total United
States E&P (mboed)
|
303
|
|
298
|
|
244
|
International
E&P - net sales volumes
|
|
|
|
|
|
Crude oil
and condensate (mbbld)
|
27
|
|
32
|
|
68
|
Equatorial Guinea
|
18
|
|
18
|
|
27
|
United Kingdom
|
6
|
|
10
|
|
15
|
Libya (b)
|
—
|
|
—
|
|
23
|
Other
International
|
3
|
|
4
|
|
3
|
Natural gas
liquids (mbbld)
|
11
|
|
12
|
|
13
|
Equatorial Guinea
|
11
|
|
11
|
|
12
|
United Kingdom
|
—
|
|
1
|
|
1
|
Natural gas
(mmcfd)
|
441
|
|
461
|
|
507
|
Equatorial Guinea
|
426
|
|
443
|
|
482
|
United Kingdom
(c)
|
15
|
|
18
|
|
25
|
Total
International E&P (mboed)
|
112
|
|
121
|
|
165
|
Total Company -
net sales volumes (mboed)
|
415
|
|
419
|
|
409
|
Net sales volumes
of equity method investees
|
|
|
|
|
|
LNG (mtd)
|
6,152
|
|
6,141
|
|
6,943
|
Methanol (mtd)
|
1,334
|
|
1,316
|
|
1,366
|
Condensate and LPG
(boed)
|
11,942
|
|
12,689
|
|
17,216
|
|
|
(a)
|
Includes sales
volumes from the sale of certain United States E&P non-core
conventional assets primarily in the Gulf of Mexico in the third
quarter of 2018, Oklahoma and Colorado in the third quarter of
2017, respectively.
|
|
|
(b)
|
The Company closed on
the sale of its Libya subsidiary in the first quarter
2018.
|
|
|
(c)
|
Includes natural gas
acquired for injection and subsequent resale.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
Sept.
30
|
|
June
30
|
|
Sept.
30
|
|
2018
|
|
2018
|
|
2017
|
United States
E&P - average price realizations (a)
|
|
|
|
|
|
Crude oil
and condensate ($ per bbl) (b)
|
$
|
68.51
|
|
$
|
66.03
|
|
$
|
46.65
|
Eagle Ford
|
72.00
|
|
68.77
|
|
47.56
|
Bakken
|
67.26
|
|
64.41
|
|
46.06
|
Oklahoma
|
70.14
|
|
66.90
|
|
46.39
|
Northern Delaware
|
55.01
|
|
60.01
|
|
44.49
|
Other United States
(c)
|
66.67
|
|
64.42
|
|
45.83
|
Natural gas
liquids ($ per bbl)
|
$
|
28.07
|
|
$
|
22.09
|
|
$
|
20.86
|
Eagle Ford
|
28.62
|
|
22.68
|
|
19.52
|
Bakken
|
31.92
|
|
25.52
|
|
17.89
|
Oklahoma
|
25.29
|
|
20.75
|
|
23.58
|
Northern Delaware
|
31.44
|
|
19.10
|
|
30.23
|
Other United States
(c)
|
34.71
|
|
25.62
|
|
24.94
|
Natural gas
($ per mcf) (d)
|
$
|
2.55
|
|
$
|
2.18
|
|
$
|
2.71
|
Eagle Ford
|
2.84
|
|
2.82
|
|
2.83
|
Bakken
|
2.64
|
|
2.46
|
|
2.08
|
Oklahoma
|
2.40
|
|
1.84
|
|
2.69
|
Northern Delaware
|
2.24
|
|
1.48
|
|
3.00
|
Other United States
(c)
|
2.48
|
|
2.11
|
|
2.67
|
International
E&P - average price realizations
|
|
|
|
|
|
Crude oil
and condensate ($ per bbl)
|
$
|
64.08
|
|
$
|
66.12
|
|
$
|
51.23
|
Equatorial Guinea
|
61.23
|
|
60.30
|
|
46.91
|
United Kingdom
|
73.28
|
|
77.15
|
|
51.72
|
Libya (e)
|
—
|
|
—
|
|
56.93
|
Other
International
|
62.30
|
|
64.73
|
|
40.67
|
Natural gas
liquids ($ per bbl)
|
$
|
2.04
|
|
$
|
2.91
|
|
$
|
2.25
|
Equatorial Guinea
(f)
|
1.00
|
|
0.99
|
|
1.00
|
United Kingdom
|
50.37
|
|
43.20
|
|
32.58
|
Natural gas
($ per mcf)
|
$
|
0.50
|
|
$
|
0.52
|
|
$
|
0.51
|
Equatorial Guinea
(f)
|
0.24
|
|
0.24
|
|
0.24
|
United Kingdom
|
8.60
|
|
7.39
|
|
5.71
|
Benchmark
|
|
|
|
|
|
WTI crude oil (per
bbl)
|
$
|
69.43
|
|
$
|
67.91
|
|
$
|
48.20
|
Brent (Europe) crude
oil (per bbl)(g)
|
$
|
75.22
|
|
$
|
74.50
|
|
$
|
52.11
|
Henry Hub natural gas
(per mmbtu)(h)
|
$
|
2.90
|
|
$
|
2.80
|
|
$
|
3.00
|
|
|
(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 $(5.70), $(7.04), and
$2.42, for the third and second quarter of 2018, and third quarter
of 2017.
|
|
|
(c)
|
Includes sales
volumes from the sale of certain United States E&P non-core
conventional assets primarily in the Gulf of Mexico in the third
quarter of 2018, Oklahoma and Colorado in the third quarter of
2017, respectively.
|
|
|
(d)
|
Inclusion of realized
gains (losses) on natural gas derivative instruments would have a
minimal impact on average price realizations for the periods
presented.
|
|
|
(e)
|
The Company closed on
the sale of its Libya subsidiary in the first quarter
2018.
|
|
|
(f)
|
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 E&P segment.
|
|
|
(g)
|
Average of monthly
prices obtained from Energy Information Administration
website.
|
|
|
(h)
|
Settlement date
average per mmbtu.
|
The following tables set forth outstanding derivative contracts
as of November 5, 2018 and the
weighted average prices for those contracts:
Crude
Oil
|
4Q
2018
|
FY
2019
|
FY
2020
|
Three-Way
Collars
|
|
|
|
Volume
(Bbls/day)
|
95,000
|
60,000
|
—
|
Weighted average
price per Bbl:
|
|
|
|
Ceiling
|
$57.65
|
$73.18
|
—
|
Floor
|
$52.11
|
$56.67
|
—
|
Sold put
|
$45.21
|
$49.59
|
—
|
Basis Swaps
(a)
|
|
|
|
Volume
(Bbls/day)
|
10,000
|
10,000
|
15,000
|
Weighted average
price per Bbl
|
$(0.67)
|
$(0.82)
|
$(0.94)
|
NYMEX Roll
Basis Swaps
|
|
|
|
Volume
(Bbls/day)
|
—
|
60,000
|
—
|
Weighted average price
per Bbl
|
—
|
$0.38
|
—
|
|
|
|
|
Natural
Gas
|
4Q
2018
|
1Q
2019
|
|
Three-Way
Collars (b)
|
|
|
|
Volume
(MMBtu/day)
|
160,000
|
100,000
|
—
|
Weighted average
price per MMBtu:
|
|
|
|
Ceiling
|
$3.61
|
$3.75
|
—
|
Floor
|
$3.00
|
$3.00
|
—
|
Sold put
|
$2.50
|
$2.50
|
—
|
|
(a) The basis
differential price is between WTI Midland and WTI
Cushing.
|
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SOURCE Marathon Oil Corporation