HOUSTON, Aug. 1, 2018 /PRNewswire/ -- Marathon Oil
Corporation (NYSE: MRO) today reported second quarter 2018 net
income of $96 million, or
$0.11 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 $126 million, or $0.15 per diluted share. Net operating cash flow
was $767 million, or $849 million before changes in working
capital.
Highlights
- Total production averaged 419,000 net boed; U.S. production
averaged 298,000 net boed, both up 5% (ex-Libya) compared to the prior quarter
- U.S. resource plays averaged 285,000 net boed, up 6% compared
to the prior quarter with all four basins growing sequentially
- Eagle Ford production increased to 106,000 net boed, up 2%
sequentially; 39 wells to sales had an average 30-day initial
production (IP) rate of 1,880 boed (66% oil)
- Bakken production averaged 82,000 net boed, up 11%
sequentially, with oil production up 14%; 21 wells to sales
averaged a 30-day IP rate of 2,700 boed (77% oil); Winona and Mamie
wells in West Myrmidon set new basin Three Forks records on 30-day
IP oil rate; three new Elk Creek wells averaged a 30-day IP rate of
2,530 boed (72% oil)
- Oklahoma production averaged
80,000 net boed, up 7% sequentially; four-well Lightner SCOOP
Woodford infill pad delivered an average 30-day IP rate of 2,620
boed (48% oil) on equivalent eight-well per section spacing
- Northern Delaware production
averaged 17,000 net boed; six new wells from the Cypress infill
pilot averaged 1,235 boed IP 30 (52% oil) and the three-well Fiddle
Fee pad averaged 1,745 boed IP 30 (66% oil); executed agreement for
water gathering and disposal in Eddy County
- In July, closed on the sale of three non-core, non-operated
conventional assets in the U.S., including two in the Gulf of Mexico, further concentrating and
simplifying the portfolio
- Raised both 2018 total Company oil and boe production guidance
and 2018 resource play oil and boe production guidance, with no
change to 2018 development capital budget
"Another quarter of outstanding operational execution across our
multi-basin U.S. portfolio has driven better than expected
production in the resource plays, and has enabled us to raise our
annual resource play production guidance for the second consecutive
quarter with no increase to our development capital budget. Our
Eagle Ford and Bakken asset teams continue to set the standard for
performance in their respective basins, while our Oklahoma and Northern Delaware assets progress important
multi-well infill tests," said Marathon Oil president and CEO
Lee Tillman. "Additionally, we
continue to benefit from about half of our oil production for the
quarter being linked to LLS or Brent, and the flexibility afforded
by our differentiated position in the four best U.S. unconventional
plays. In the second half of the year, we plan to drill our first
exploration well in the emerging Louisiana Austin Chalk play as we
continue our pursuit of low entry cost opportunities to enhance
full-cycle returns. Our focus remains on execution and capital
discipline, and we generated more than $250
million in organic free cash flow in the second quarter. We
remain on track to deliver a strong rate of change in our key
financial performance metrics highlighted by an expected annual
increase of more than 70 percent in corporate cash return on
invested capital (CROIC) at current strip prices."
Development Capital
Second quarter development capital
expenditures, before working capital, were $608 million. Net cash provided by continuing
operations was $767 million during
second quarter 2018, or $849 million
before changes in working capital. The Company's 2018 development
capital budget remains at $2.3
billion with capital in the second half of the year
moderating primarily due to reduced working interest consistent
with planned well mix in the resource plays.
Resource Capture
Outside of the development capital
budget, second quarter resource play leasing and exploration (REx)
capital expenditures peaked for the year at $154 million. First half of the year spend of
$248 million was more than fully
funded through the divestiture proceeds received in first quarter
2018. Year-to-date, the Company has leased approximately 240,000
net acres in the emerging Louisiana Austin Chalk play. Though
episodic in nature, the Company anticipates REx capital
expenditures of $100 to $150 million in the second half of 2018 for
continued leasing, exploration drilling and 3D seismic
acquisition.
Production Guidance
Marathon Oil expects third quarter
2018 U.S. production to average 290,000 to 300,000 net barrels of
oil equivalent per day (boed), which is adjusted for the sale of
non-core, non-operated conventional U.S. assets that produced 4,200
net boed in the second quarter and averaged 5,000 net boed in the
first half of the year (76% oil). The Company expects third quarter
2018 U.S. resource play production to average 280,000 to 290,000
net boed, consistent with planned timing of wells to sales and with
sequential growth resuming in the fourth quarter. Third quarter
2018 International production is expected to average 105,000 to
115,000 net boed, lower than second quarter due to planned
maintenance activity in E.G. and the U.K.
The Company increased its annual 2018 total Company production
guidance to 400,000 to 415,000 net boed, up from 390,000 to 410,000
net boed. The Company also raised its guidance for annual resource
play oil and barrel of oil equivalent (boe) growth to 28 - 32
percent, up from 25 - 30 percent previously.
U.S. E&P
U.S. E&P production averaged 298,000
net boed for second quarter 2018, up 5 percent compared to the
prior quarter and up 36 percent from the year-ago quarter on a
divestiture-adjusted basis. Second quarter production from the U.S.
resource plays was 285,000 net boed, up from 269,000 net boed in
the prior quarter. Second quarter U.S. E&P unit production
costs were down just over 20 cents
sequentially to $5.66 per boe and are
expected to continue to moderate through 2018 as the Company
accesses additional infrastructure in the Northern Delaware and as production volumes
grow in the second half of the year. In July, the Company closed on
the sales of its non-operated Gunflint and Troika assets in the
Gulf of Mexico and a CO2 flood in
West Texas. Combined, these assets
produced 4,200 net boed in the second quarter, and averaged 5,000
net boed in the first half of the year (76% oil).
EAGLE FORD: Marathon Oil's Eagle Ford production averaged
106,000 net boed in the second quarter, compared to 104,000 net
boed in the prior quarter. The Company brought 39 gross
Company-operated wells to sales with an average 30-day IP rate of
1,880 boed (66% oil). The Company continued to deliver impressive
results from core Karnes County,
where the six-well Karnes City NE pad had an average 30-day IP rate
of 2,330 boed (72% oil). The five-well Guajillo 10 South pad
achieved an average 30-day IP rate of 1,660 boed (75% oil), further
confirming the extension of core acreage into Atascosa County. The Eagle Ford asset
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 second quarter 2018, Marathon Oil's Bakken production
averaged 82,000 net boed, up 11 percent compared to 74,000 net boed
in the prior quarter. Oil production was up 14 percent
sequentially. The Company brought 21 gross Company-operated wells
to sales with an average 30-day IP rate of 2,700 boed (77% oil). Of
these, 12 were in core Hector with an average 30-day IP rate of
2,285 boed (79% oil). As the Company continues its efforts to
uplift performance outside the Myrmidon and Hector core, enhanced
completion techniques were applied for the first time in Elk Creek
with the three-well Bear Den pad achieving an impressive average
30-day IP rate of 2,530 boed (72% oil). In West Myrmidon, the
Winona and the Mamie Three Forks wells set two new basin records
delivering 30-day IP oil rates of 3,095 barrels of oil per day
(bopd) and 3,090 bopd, respectively. Marathon Oil remains in full
compliance with state gas capture requirements, and anticipates no
impact to forward development plans.
OKLAHOMA: Marathon Oil's
Oklahoma production averaged
80,000 net boed during second quarter 2018, up 7 percent from
75,000 net boed in the prior quarter. In the SCOOP, the Company
brought on the four-well Woodford
Lightner infill pad on 660-foot spacing across a half
section, with an average 30-day IP rate of 2,620 boed (48% oil,
6,840-foot average lateral length). The pad's IP rate and oil cut
both exceeded expectations. In the STACK, four Meramec wells in the
Siegrist infill pad achieved an average 30-day IP rate of 900 boed
(71% oil, 4,505-foot average lateral length), meeting expectations
with strong oil rates. Marathon Oil also signed a firm
transportation agreement for 100 million cubic feet per day
beginning in fourth quarter 2018 to protect near-term natural gas
production and bridge to the start-up of the Midship Pipeline on
which Marathon Oil is an anchor shipper.
NORTHERN DELAWARE: Marathon
Oil's Northern Delaware production
increased to an average of 17,000 net boed in second quarter 2018,
up 6 percent from the prior quarter. The Company brought 13 gross
Company-operated wells to sales in the Malaga area in Eddy County,
a mix of development and appraisal wells with an average 30-day IP
rate of 1,130 boed (61% oil). The Cypress infill pilot, which
targeted the Bone Spring, Upper Wolfcamp, and Lower Wolfcamp
horizons, reported an average 30-day IP rate of 1,235 boed (52%
oil; 60% oil excluding Lower Wolfcamp well). The three-well Fiddle
Fee pad in the Bone Spring and Upper Wolfcamp reported an average
30-day IP rate of 1,745 boed (66% oil). Drilling efficiencies
enabled the Company to reduce its rig count from five to four in
the second quarter, without changing its full-year guidance of 50
to 55 gross operated wells to sales. In June, the Company executed
an agreement with San Mateo for
water gathering and disposal in Eddy County, which will
significantly reduce unit production costs. The Company continues
to benefit from its Midland-Cushing basis swaps, with open positions that
include 10,000 bopd hedged for the second half 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. Additionally,
the Company is in the process of finalizing a new term oil sales
agreement in both Eddy and Lea counties.
International E&P
International E&P
production averaged 121,000 net boed for second quarter 2018, up 6
percent compared to 114,000 net boed in the prior quarter excluding
Libya. The increase reflects the
completion of planned turnaround activity in E.G. in the first
quarter. Second quarter 2018 International E&P unit production
costs averaged $4.71 per boe,
compared to $5.37 per boe in the
prior quarter excluding Libya, due
to the completion of the scheduled turnaround in E.G. in first
quarter and fewer U.K. liftings in second quarter. The Company has
signed agreements for the sales of its interest in the non-operated
Sarsang and Atrush blocks in Kurdistan.
Corporate
Total liquidity as of June 30 was approximately $5.1 billion, which consisted of $1.7 billion in cash and cash equivalents and an
undrawn revolving credit facility of $3.4
billion.
Net income and adjusted net income in second quarter 2018 were
negatively impacted by an increase in accrued expense of
$14 million for stock-based
performance units tied to the Company's improved total shareholder
return, and $15 million in dry well
and seismic expense.
The adjustments to net income for second quarter 2018 totaled
$23 million before tax, primarily due
to proved property impairments of $34
million associated with International and domestic
conventional assets and an unrealized loss of $45 million on commodity derivatives, partially
offset by a $50 million gain on sale
that was primarily associated with acreage trading activity.
The Company maintained open hedges for the remainder of 2018,
and during the second quarter increased its full-year 2019 open
hedge positions to an average of 50,000 bopd at a weighted average
floor price of $56.01 and a weighted
average ceiling price of $71.74,
using three-way collars.
A slide deck and Quarterly Investor Packet will be posted to the
Company's website following this release today, Aug. 1. On Thursday, Aug.
2, at 10:00 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 income (loss) from continuing
operations, adjusted net income (loss) per share, adjusted income
(loss) from continuing operations 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
|
|
June
30
|
|
Mar.
31
|
|
June
30
|
|
(In millions,
except per share data)
|
2018
|
|
2018
|
|
2017
|
|
Revenues and other
income:
|
|
|
|
Revenues
from contracts with customers
|
$
|
1,447
|
|
$
|
1,537
|
|
$
|
902
|
|
Net gain
(loss) on commodity derivatives
|
(152)
|
|
(102)
|
|
56
|
|
Marketing revenues
|
—
|
|
—
|
|
35
|
|
Income
from equity method investments
|
60
|
|
37
|
|
51
|
|
Net gain
(loss) on disposal of assets
|
50
|
|
257
|
|
6
|
|
Other
income
|
12
|
|
4
|
|
9
|
|
Total revenues and
other income
|
1,417
|
|
1,733
|
|
1,059
|
|
Costs and
expenses:
|
|
|
|
Production
|
205
|
|
217
|
|
178
|
|
Marketing, including purchases from related parties
|
—
|
|
—
|
|
38
|
|
Shipping, handling and other operating
|
126
|
|
130
|
|
111
|
|
Exploration
|
65
|
|
52
|
|
30
|
|
Depreciation, depletion and amortization
|
612
|
|
590
|
|
592
|
|
Impairments
|
34
|
|
8
|
|
—
|
|
Taxes
other than income
|
65
|
|
64
|
|
45
|
|
General
and administrative
|
105
|
|
100
|
|
90
|
|
Total costs and
expenses
|
1,212
|
|
1,161
|
|
1,084
|
|
Income (loss) from
operations
|
205
|
|
572
|
|
(25)
|
|
Net
interest and other
|
(65)
|
|
(45)
|
|
(86)
|
|
Other
net periodic benefit costs
|
—
|
|
(3)
|
|
(1)
|
|
Income (loss) from
continuing operations before income taxes
|
140
|
|
524
|
|
(112)
|
|
Provision
(benefit) for income taxes
|
44
|
|
168
|
|
41
|
|
Income (loss) from
continuing operations
|
96
|
|
356
|
|
(153)
|
|
Income (loss) from
discontinued operations (a)
|
—
|
|
—
|
|
14
|
|
Net income
(loss)
|
$
|
96
|
|
$
|
356
|
|
$
|
(139)
|
|
|
|
|
|
Adjusted Net
Income
|
|
|
|
Income (loss) from
continuing operations
|
96
|
|
356
|
|
(153)
|
|
Adjustments for
special items from continuing operations (pre-tax):
|
|
|
|
Net (gain) loss on
dispositions
|
(50)
|
|
(257)
|
|
(6)
|
|
Proved property
impairments
|
34
|
|
8
|
|
—
|
|
Pension
settlement
|
2
|
|
4
|
|
3
|
|
Unrealized (gain)
loss on derivative instruments
|
45
|
|
43
|
|
(43)
|
|
Other
|
(8)
|
|
—
|
|
(3)
|
|
Provision (benefit)
for income taxes related to special items from continuing
operations
|
7
|
|
—
|
|
—
|
|
Adjustments for
special items from continuing operations:
|
$
|
30
|
|
$
|
(202)
|
|
$
|
(49)
|
|
Adjusted income
(loss) from continuing operations (b)
|
$
|
126
|
|
$
|
154
|
|
$
|
(202)
|
|
Income (loss) from
discontinued operations (a)
|
—
|
|
—
|
|
14
|
|
Adjustments for
special items from discontinued operations (pre-tax):
|
|
|
|
Net (gain) loss on
disposition (a)
|
—
|
|
—
|
|
43
|
|
Provision (benefit)
for income taxes related to special items from discontinued
operations (a)
|
—
|
|
—
|
|
—
|
|
Adjusted net
income (loss) (b)
|
$
|
126
|
|
$
|
154
|
|
$
|
(145)
|
|
Per diluted
share:
|
|
|
|
Income (loss) from
continuing operations
|
$
|
0.11
|
|
$
|
0.42
|
|
$
|
(0.18)
|
|
Net Income
(loss)
|
$
|
0.11
|
|
$
|
0.42
|
|
$
|
(0.16)
|
|
Adjusted income
(loss) from continuing operations (b)
|
$
|
0.15
|
|
$
|
0.18
|
|
$
|
(0.24)
|
|
Adjusted net income
(loss) (b)
|
$
|
0.15
|
|
$
|
0.18
|
|
$
|
(0.17)
|
|
Weighted average
diluted shares
|
855
|
|
852
|
|
850
|
|
(a) The Company sold
the Canadian oil sands business which is reflected as discontinued
operations in periods prior to and including the second quarter
2017.
|
(b) Non-GAAP
financial measure. See "Non-GAAP Measures" above for further
discussion.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
June
30
|
|
Mar.
31
|
|
June
30
|
|
(in
millions)
|
2018
|
|
2018
|
|
2017
|
|
Segment income
(loss)
|
|
|
|
United States
E&P
|
$
|
123
|
|
$
|
125
|
|
$
|
(107)
|
|
International
E&P
|
142
|
|
132
|
|
59
|
|
Segment income
(loss)
|
265
|
|
257
|
|
(48)
|
|
Not allocated to
segments
|
(169)
|
|
99
|
|
(105)
|
|
Loss from continuing
operations
|
96
|
|
356
|
|
(153)
|
|
Discontinued
operations (a)
|
—
|
|
—
|
|
14
|
|
Net income
(loss)
|
$
|
96
|
|
$
|
356
|
|
$
|
(139)
|
|
Exploration
expenses
|
|
|
|
United States
E&P
|
$
|
64
|
|
$
|
51
|
|
$
|
30
|
|
International
E&P
|
1
|
|
1
|
|
—
|
|
Total
|
$
|
65
|
|
$
|
52
|
|
$
|
30
|
|
Cash
flows
|
|
|
|
Net cash provided by
operating activities from continuing operations
|
$
|
767
|
|
$
|
649
|
|
$
|
422
|
|
Minus: changes in
working capital
|
(82)
|
|
(58)
|
|
(49)
|
|
Total net cash
provided from continuing operations before changes in working
capital (b)
|
$
|
849
|
|
$
|
707
|
|
$
|
471
|
|
Net cash provided by
operating activities from discontinued operations (a)
|
—
|
|
—
|
|
46
|
|
|
|
|
|
Cash additions to
property, plant and equipment
|
$
|
(638)
|
|
$
|
(662)
|
|
$
|
(492)
|
|
(a) The Company sold
the Canadian oil sands business which is reflected as discontinued
operations in periods prior to and including the second quarter
2017.
|
(b) Non-GAAP
financial measure. See "Non-GAAP Measures" above for further
discussion.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
(in
millions)
|
June 30,
2018
|
Organic Free Cash
Flow
|
|
Net cash provided by
operating activities from continuing operations
|
$
|
767
|
Development capital
expenditures
|
(608)
|
Dividends
|
(43)
|
Changes in working
capital
|
82
|
Exploration costs
other than well costs
|
14
|
EG LNG return of
capital & other
|
43
|
Organic free cash
flow (a)
|
$
|
255
|
(a) Non-GAAP
financial measure. See "Non-GAAP Measures" above for further
discussion.
|
|
Three Months
Ended
|
|
June
30
|
|
Mar.
31
|
|
June
30
|
|
(mboed)
|
2018
|
|
2018
|
|
2017
|
|
Net
production
|
|
|
|
United States
E&P
|
298
|
|
284
|
|
222
|
|
International E&P
excluding Libya (a)
|
121
|
|
114
|
|
127
|
|
Total continuing
operations, excluding Libya (a)
|
419
|
|
398
|
|
349
|
|
Libya (a)
|
—
|
|
28
|
|
11
|
|
Total continuing
operations
|
419
|
|
426
|
|
360
|
|
|
(a) The Company
closed on the sale of its Libya subsidiary in the first quarter
2018.
|
|
Three Months
Ended
|
|
June
30
|
|
Mar.
31
|
|
June
30
|
|
(mboed)
|
2018
|
|
2018
|
|
2017
|
|
Net
production
|
|
|
|
United States
E&P
|
298
|
|
284
|
|
222
|
|
Less:
Divestitures (a)
|
—
|
|
(1)
|
|
(3)
|
|
Divestiture-adjusted
United States E&P (a)
|
298
|
|
283
|
|
219
|
|
Divestiture-adjusted total continuing operations,
excluding Libya (a)
|
419
|
|
397
|
|
346
|
|
Discontinued
operations (b)
|
—
|
|
—
|
|
29
|
|
|
(a) Divestitures
include the sale of certain conventional assets in Oklahoma in
September 2017 and Colorado in October 2017. These production
volumes have been removed from all historical periods shown in
arriving at divestiture-adjusted United States E&P net
production and divestiture-adjusted total continuing operations,
excluding Libya. The Company closed on the sale of its Libya
subsidiary in the first quarter 2018.
|
(b) The Company sold
the Canadian oil sands business which is reflected as discontinued
operations in periods prior to and including the second quarter
2017.
|
Supplemental
Statistics (Unaudited)
|
Three Months
Ended
|
|
June
30
|
|
Mar.
31
|
|
June
30
|
|
|
2018
|
|
2018
|
|
2017
|
|
United States
E&P - net sales volumes
|
|
|
|
Crude oil
and condensate (mbbld)
|
168
|
|
164
|
|
125
|
|
Eagle Ford
|
63
|
|
63
|
|
59
|
|
Bakken
|
69
|
|
61
|
|
39
|
|
Oklahoma
|
18
|
|
20
|
|
14
|
|
Northern Delaware
|
11
|
|
10
|
|
2
|
|
Other United States
(a)
|
7
|
|
10
|
|
11
|
|
Natural gas
liquids (mbbld)
|
57
|
|
50
|
|
40
|
|
Eagle Ford
|
22
|
|
21
|
|
20
|
|
Bakken
|
7
|
|
7
|
|
6
|
|
Oklahoma
|
24
|
|
18
|
|
12
|
|
Northern Delaware
|
3
|
|
3
|
|
1
|
|
Other United States
(a)
|
1
|
|
1
|
|
1
|
|
Natural gas
(mmcfd)
|
435
|
|
420
|
|
341
|
|
Eagle Ford
|
127
|
|
122
|
|
127
|
|
Bakken
|
35
|
|
35
|
|
25
|
|
Oklahoma
|
230
|
|
216
|
|
138
|
|
Northern Delaware
|
18
|
|
17
|
|
7
|
|
Other United States
(a)
|
25
|
|
30
|
|
44
|
|
Total United
States E&P (mboed)
|
298
|
|
284
|
|
222
|
|
International
E&P - net sales volumes
|
|
|
|
Crude oil
and condensate (mbbld)
|
32
|
|
63
|
|
43
|
|
Equatorial Guinea
|
18
|
|
15
|
|
18
|
|
United Kingdom
|
10
|
|
15
|
|
13
|
|
Libya (b)
|
—
|
|
28
|
|
11
|
|
Other
International
|
4
|
|
5
|
|
1
|
|
Natural gas
liquids (mbbld)
|
12
|
|
11
|
|
12
|
|
Equatorial Guinea
|
11
|
|
11
|
|
12
|
|
United Kingdom
|
1
|
|
—
|
|
—
|
|
Natural gas
(mmcfd)
|
461
|
|
437
|
|
478
|
|
Equatorial Guinea
|
443
|
|
403
|
|
452
|
|
United Kingdom
(c)
|
18
|
|
12
|
|
26
|
|
Libya (b)
|
—
|
|
22
|
|
—
|
|
Total
International E&P (mboed)
|
121
|
|
147
|
|
135
|
|
Total Company
continuing operations - net sales volumes (mboed)
|
419
|
|
431
|
|
357
|
|
Net sales volumes
of equity method investees
|
|
|
|
LNG (mtd)
|
6,141
|
|
5,541
|
|
6,243
|
|
Methanol (mtd)
|
1,316
|
|
1,195
|
|
1,182
|
|
Condensate and LPG
(boed)
|
12,689
|
|
12,416
|
|
11,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Includes sales
volumes from conventional onshore assets sold in the applicable
periods. The sale of certain Oklahoma and Colorado assets closed in
September 2017 and October 2017.
|
(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
|
|
June
30
|
|
Mar.
31
|
|
June
30
|
|
|
2018
|
|
2018
|
|
2017
|
|
United States
E&P - average price realizations (a)
|
|
|
|
Crude oil
and condensate ($ per bbl) (c)
|
$
|
66.03
|
|
$
|
62.22
|
|
$
|
45.81
|
|
Eagle Ford
|
68.77
|
|
64.37
|
|
45.75
|
|
Bakken
|
64.41
|
|
60.20
|
|
46.20
|
|
Oklahoma
|
66.90
|
|
62.70
|
|
45.42
|
|
Northern Delaware
|
60.01
|
|
60.45
|
|
43.38
|
|
Other United States
(b)
|
64.42
|
|
61.71
|
|
45.71
|
|
Natural gas
liquids ($ per bbl)
|
$
|
22.09
|
|
$
|
22.95
|
|
$
|
17.61
|
|
Eagle Ford
|
22.68
|
|
22.85
|
|
16.63
|
|
Bakken
|
25.52
|
|
23.57
|
|
15.16
|
|
Oklahoma
|
20.75
|
|
22.59
|
|
19.63
|
|
Northern Delaware
|
19.10
|
|
22.11
|
|
17.54
|
|
Other United States
(b)
|
25.62
|
|
28.66
|
|
23.78
|
|
Natural gas
($ per mcf) (d)
|
$
|
2.18
|
|
$
|
2.59
|
|
$
|
3.05
|
|
Eagle Ford
|
2.82
|
|
3.03
|
|
3.06
|
|
Bakken
|
2.46
|
|
3.25
|
|
3.14
|
|
Oklahoma
|
1.84
|
|
2.20
|
|
3.07
|
|
Northern Delaware
|
1.48
|
|
3.09
|
|
2.72
|
|
Other United States
(b)
|
2.11
|
|
2.64
|
|
2.92
|
|
International
E&P - average price realizations
|
|
|
|
Crude oil
and condensate ($ per bbl)
|
$
|
66.12
|
|
$
|
66.23
|
|
$
|
47.04
|
|
Equatorial Guinea
|
60.30
|
|
51.94
|
|
39.73
|
|
United Kingdom
|
77.15
|
|
69.95
|
|
54.15
|
|
Libya (e)
|
—
|
|
73.75
|
|
50.94
|
|
Other
International
|
64.73
|
|
55.29
|
|
40.64
|
|
Natural gas
liquids ($ per bbl)
|
$
|
2.91
|
|
$
|
1.83
|
|
$
|
1.77
|
|
Equatorial Guinea
(f)
|
0.99
|
|
1.00
|
|
1.00
|
|
United Kingdom
|
43.20
|
|
44.53
|
|
32.33
|
|
Natural gas
($ per mcf)
|
$
|
0.52
|
|
$
|
0.65
|
|
$
|
0.57
|
|
Equatorial Guinea
(f)
|
0.24
|
|
0.24
|
|
0.24
|
|
United Kingdom
|
7.39
|
|
7.32
|
|
6.27
|
|
Libya (e)
|
—
|
|
4.57
|
|
—
|
|
Benchmark
|
|
|
|
WTI crude oil (per
bbl)
|
$
|
67.91
|
|
$
|
62.89
|
|
$
|
48.15
|
|
Brent (Europe) crude
oil (per bbl)(g)
|
$
|
74.50
|
|
$
|
66.81
|
|
$
|
49.67
|
|
Henry Hub natural gas
(per mmbtu)(h)
|
$
|
2.80
|
|
$
|
3.00
|
|
$
|
3.18
|
|
|
(a) Excludes gains or
losses on commodity derivative instruments.
|
(b) Includes sales
volumes from conventional onshore assets sold in the applicable
periods. The sale of certain Oklahoma and Colorado assets closed in
September 2017 and October 2017.
|
(c) Inclusion of
realized gains (losses) on crude oil derivative instruments would
have affected average price realizations by $(7.04), $(4.33),
and $1.07, for the second and first quarter of 2018, and second
quarter of 2017.
|
(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 July 31, 2018 and the weighted
average prices for those contracts:
Crude
Oil
|
3Q
2018
|
4Q
2018
|
FY
2019
|
FY
2020
|
Three-Way
Collars
|
|
|
|
|
Volume
(Bbls/day)
|
95,000
|
95,000
|
50,000
|
—
|
Weighted average
price per Bbl:
|
|
|
|
|
Ceiling
|
$57.65
|
$57.65
|
$71.74
|
—
|
Floor
|
$52.11
|
$52.11
|
$56.01
|
—
|
Sold put
|
$45.21
|
$45.21
|
$48.91
|
—
|
Basis Swaps
(a)
|
|
|
|
|
Volume
(Bbls/day)
|
10,000
|
10,000
|
10,000
|
15,000
|
Weighted average
price per Bbl
|
$(0.67)
|
$(0.67)
|
$(0.82)
|
$(0.94)
|
|
|
|
|
|
Natural
Gas
|
3Q
2018
|
4Q
2018
|
|
|
Three-Way
Collars
|
|
|
|
|
Volume
(MMBtu/day)
|
160,000
|
160,000
|
|
|
Weighted average
price per MMBtu:
|
|
|
|
|
Ceiling
|
$3.61
|
$3.61
|
|
|
Floor
|
$3.00
|
$3.00
|
|
|
Sold put
|
$2.50
|
$2.50
|
|
|
(a) The
basis differential price is between WTI Midland and WTI
Cushing.
|
View original content with
multimedia:http://www.prnewswire.com/news-releases/marathon-oil-reports-second-quarter-2018-results-300690556.html
SOURCE Marathon Oil Corporation