Marathon Oil Corporation (NYSE:MRO) today reported a third quarter
2017 net loss of $599 million, or $0.70 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. The adjusted net loss was $68 million, or
$0.08 per diluted share. Net operating cash flow was $564 million,
or $502 million before changes in working capital.
Highlights
- Total Company production excluding Libya averaged 371,000 net
boed, up 6% sequentially and above top end of guidance; 23,000 net
boed from Libya
- U.S. resource play production increased 12% sequentially,
averaging 227,000 net boed; oil up 14% sequentially
- Eagle Ford production of 101,000 net boed up slightly, despite
effects of Hurricane Harvey; continued strong results in Atascosa
County
- Bakken production grew 20% sequentially to 59,000 net boed;
five Hector wells achieved average 30-day rates of 2,380 boed (85%
oil)
- Oklahoma Resource Basin production increased 18% sequentially
to 58,000 net boed; STACK volatile oil wells continue to outperform
expectations
- Northern Delaware production averaged 9,000 net boed; two
Wolfcamp X-Y wells (both 4,600-foot laterals) achieved 30-day rates
of 2,020 boed (67% oil) and 1,500 boed (69% oil); added fourth rig
in October
- Expect full-year total Company production, excluding Libya, to
be toward the high end of the revised 350,000 - 360,000 net boed
range with a capital program, excluding lease and acquisition
costs, of $2.1 billion
- Raised 2017 resource play exit rate guidance to 25 - 30
percent, up from 23 - 27 percent
- Anticipate full-year 2017 free cash flow neutrality, including
dividends and working capital
"All year we've consistently executed across our portfolio
delivering outstanding new well productivity, strong base
performance, cost reductions and improved efficiencies," said
Marathon Oil President and CEO Lee Tillman. "We continued this
trend in the third quarter, exceeding the top end of our production
guidance for both our U.S. and International E&P segments,
while exercising capital discipline and achieving record low unit
production costs in the U.S. Importantly, we now expect to end the
year toward the high end of our full-year production guidance,
while living within our means, including the dividend, at current
strip pricing. This highlights the strength of our transformed
portfolio and sets the stage for 2018 as we integrate the same
discipline into our ongoing budget efforts."
U.S. E&P U.S. E&P production available
for sale averaged 245,000 net barrels of oil equivalent per day
(boed) for third quarter 2017, above the top end of guidance. On a
divestiture-adjusted basis, production was up 10 percent compared
to the prior quarter and up 17 percent from the year-ago quarter.
Third quarter unit production costs were $5.38 per barrel of oil
equivalent (boe), 8 percent lower than the previous quarter and a
record best for the Company since becoming an independent E&P
in 2011.
EAGLE FORD: Marathon Oil's production in the Eagle Ford averaged
101,000 net boed in the third quarter, up from 100,000 net boed in
the prior quarter, despite the effects of Hurricane Harvey. As
planned, the Company brought 36 gross Company-operated wells to
sales in the third quarter, compared to 41 wells to sales in the
previous quarter. The testing of enhanced completion designs in
Atascosa County continued to deliver encouraging results with the
Guajillo South five-well pad averaging 30-day initial production
(IP) rates of 1,920 boed (77% oil, 6,100-foot laterals).
BAKKEN: In third quarter 2017, Marathon Oil's Bakken production
averaged 59,000 net boed, up 20 percent compared to 49,000 net boed
in the prior quarter. The Company brought 20 gross Company-operated
wells to sales in the third quarter, including eight in West
Myrmidon, seven in East Myrmidon and five in Hector, all of which
demonstrated strong early results. Enhanced completion design
trials in the Company's 115,000-acre Hector area continued to
exceed expectations with average 30-day IP rates from the five
Hector wells of 2,380 boed (85% oil). This includes the Clarice
Middle Bakken well in the Hector area that set an industry record
for the best 30-day oil rate in the Williston Basin with 2,785
barrels of oil per day (3,285 boed, 85% oil).
OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma
production increased 18 percent to 58,000 net boed during third
quarter 2017, compared to 49,000 net boed in the prior quarter and
up more than 40 percent from the year-ago quarter. The Company
brought 15 gross Company-operated wells to sales during the quarter
predominately focused on leasehold capture and delineation
activity. The Landreth, a STACK Meramec leasehold well in the
volatile oil window in Blaine County, had an average 30-day IP rate
of 2,420 boed (59% oil, 4,600-foot lateral), and an early test of
the Osage in Kingfisher County achieved promising results with a
30-day IP of 850 boed (55% oil, 4,700-foot lateral).
NORTHERN DELAWARE: The Company's Northern Delaware production
averaged 9,000 net boed in third quarter 2017, reflecting a full
quarter of production and five wells to sales in Eddy and Lea
Counties. The Chicken Fry and El Presidente, both Wolfcamp X-Y
wells in southwest Eddy County, achieved 2,020 boed (67% oil,
4,600-foot lateral) and 1,500 boed (69% oil, 4,600-foot lateral),
respectively. The Company transitioned to a dedicated completions
crew at the end of the third quarter, and added a fourth rig in
October.
International E&PInternational E&P
production available for sale (excluding Libya) averaged 126,000
net boed for third quarter 2017, above the top end of guidance.
This compares to 127,000 net boed in the prior quarter, and 128,000
net boed in the year-ago quarter. Third quarter 2017 unit
production costs (excluding Libya) were $5.18 per boe. Equatorial
Guinea production available for sale averaged 112,000 net boed in
third quarter 2017, up from 107,000 net boed in the previous
quarter, primarily due to facilities and well optimization. U.K.
production available for sale averaged 12,000 net boed in third
quarter 2017, compared to 18,000 net boed in the previous quarter,
reflecting the beginning of planned turn-around activity at Brae
and Foinaven. Marathon Oil had four liftings in Libya, with
production available for sale averaging 23,000 net boed in the
third quarter.
GuidanceMarathon Oil expects fourth quarter
2017 U.S. E&P production available for sale to average 255,000
to 265,000 net boed. Fourth quarter International E&P
production available for sale, excluding Libya, is expected to be
within a range of 120,000 to 130,000 net boed including the
completion of planned turnaround activity at Brae and Foinaven.
The Company expects full-year total Company production available
for sale, excluding Libya, to end the year toward the top end of
guidance and has narrowed its forecast, resulting in a new range of
350,000 to 360,000 net boed. U.S. resource play exit rate
production guidance for both oil and BOE is now expected to be 25
to 30 percent higher than fourth quarter 2016, up slightly from the
prior guidance range. Marathon Oil expects its 2017 capital
program, excluding lease and acquisition costs, to be approximately
$2.1 billion, at the low end of the guidance range.
CorporateNet cash provided by operating
activities from continuing operations was $564 million during third
quarter 2017, and net cash provided by continuing operations before
changes in working capital was $502 million. Cash additions to
property, plant and equipment (PP&E) were $530 million in third
quarter 2017.
Total liquidity as of Sept. 30 was $5.2 billion, which consists
of $1.8 billion in cash and cash equivalents and an undrawn
revolving credit facility of $3.4 billion. Approximately $750
million in remaining proceeds from the sale of the Company's
Canadian subsidiary are scheduled to be received in first quarter
2018.
For the remainder of 2017, Marathon Oil's open hedge positions
included 70,000 barrels per day (bpd) of oil at a weighted average
floor price of $53.82, hedged through a combination of three-way
collars and fixed price swaps, as of Sept. 30. Additionally, in
2018 the Company had hedged 68,500 bpd of oil at a weighted average
floor price of $50.95 through three-way collars, as of Sept.
30.
The adjustments to net loss from continuing operations for third
quarter 2017 totaled $491 million before tax, and include $451
million primarily consisting of non-cash impairment charges on
proved and unproved properties as a result of the anticipated sale
of the Company's non-operated working interests in certain non-core
international assets and due to lower forecasted long-term
commodity prices. Also included in these adjustments are a gain on
termination of interest rate swaps of $47 million, offset by a loss
on early extinguishment of debt of $46 million and an unrealized
loss on commodity derivatives of $56 million.
The Company's webcast commentary and associated slides related
to Marathon Oil's financial and operational review, as well as the
Quarterly Investor Packet, will be posted to the Company's website
at http://ir.marathonoil.com following this release today,
Nov. 1. The Company will conduct a question and answer webcast/call
on Thursday, Nov. 2, at 9:00 a.m. ET. The associated commentary and
answers to questions will include forward-looking information. To
listen to the live webcast, visit the Marathon Oil website at
http://www.marathonoil.com. The audio replay of the webcast will be
posted by Nov. 3.
Non-GAAP MeasuresIn 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) and net cash provided by operations
before changes in working capital, to 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 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) as another way to meaningfully represent
our 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. See the tables below for reconciliations between each
non-GAAP financial measure and its most directly comparable GAAP
financial measure. 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 StatementsThis 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 future performance, business strategy, asset quality,
drilling plans, production guidance, capital plans, cash flows,
future payments for the Canadian disposition, 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; the
inability for any party to satisfy closing conditions with respect
to the Canadian subsidiary disposition; 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 2016 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.
A photo accompanying this announcement is available
at http://www.globenewswire.com/NewsRoom/AttachmentNg/ba379186-10c7-48e7-b0be-336ea3d94a93
Media Relations Contact:Lee Warren:
713-296-4103
Investor Relations Contact:Zach Dailey:
713-296-4140
Consolidated Statements of Income (Unaudited) |
Three Months Ended |
|
Sept. 30 |
June 30 |
Sept. 30 |
(In
millions, except per share data) |
2017 |
2017 |
2016 |
Revenues and
other income: |
|
|
|
Sales and other
operating revenues, including related party |
$ |
1,114 |
|
$ |
958 |
|
$ |
781 |
|
Marketing
revenues |
48 |
|
35 |
|
80 |
|
Income from
equity method investments |
63 |
|
51 |
|
59 |
|
Net gain (loss)
on disposal of assets |
19 |
|
6 |
|
47 |
|
Other
income |
8 |
|
9 |
|
23 |
|
Total revenues and
other income |
1,252 |
|
1,059 |
|
990 |
|
Costs and
expenses: |
|
|
|
Production |
194 |
|
176 |
|
160 |
|
Marketing,
including purchases from related parties |
49 |
|
38 |
|
80 |
|
Other
operating |
109 |
|
111 |
|
183 |
|
Exploration |
294 |
|
30 |
|
83 |
|
Depreciation,
depletion and amortization |
641 |
|
592 |
|
522 |
|
Impairments |
201 |
|
— |
|
47 |
|
Taxes other than
income |
44 |
|
45 |
|
35 |
|
General and
administrative |
97 |
|
93 |
|
104 |
|
Total costs and
expenses |
1,629 |
|
1,085 |
|
1,214 |
|
Income (loss)
from operations |
(377 |
) |
(26 |
) |
(224 |
) |
Net interest and
other |
(35 |
) |
(86 |
) |
(89 |
) |
Loss on early
extinguishment of debt |
(46 |
) |
— |
|
— |
|
Income (loss)
from continuing operations before income taxes |
(458 |
) |
(112 |
) |
(313 |
) |
Provision
(Benefit) for income taxes |
141 |
|
41 |
|
(107 |
) |
Income (loss)
from continuing operations |
(599 |
) |
(153 |
) |
(206 |
) |
Discontinued operations
(a) |
— |
|
14 |
|
14 |
|
Net income
(loss) |
$ |
(599 |
) |
$ |
(139 |
) |
$ |
(192 |
) |
Adjustments for special
items from continuing operations (pre-tax): |
|
|
|
Net
(gain) loss on dispositions |
(19 |
) |
(6 |
) |
(38 |
) |
Proved
property impairments |
201 |
|
— |
|
47 |
|
Exploratory dry well costs, unproved property impairments and
other |
250 |
|
— |
|
— |
|
Pension
settlement |
8 |
|
3 |
|
14 |
|
Unrealized (gain) loss on derivative instruments |
56 |
|
(43 |
) |
(25 |
) |
Gain on
termination of interest rate swaps |
(47 |
) |
— |
|
— |
|
Loss on
extinguishment of debt |
46 |
|
— |
|
— |
|
Rig
termination payment |
— |
|
— |
|
113 |
|
Other |
(4 |
) |
(3 |
) |
37 |
|
Provision (benefit) for
income taxes related to special items from continuing
operations |
40 |
|
— |
|
(53 |
) |
Adjustments for special
items from continuing operations: |
$ |
531 |
|
$ |
(49 |
) |
$ |
95 |
|
Adjusted net
income (loss) from continuing operations (b) |
$ |
(68 |
) |
$ |
(202 |
) |
$ |
(111 |
) |
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) |
$ |
(68 |
) |
$ |
(145 |
) |
$ |
(97 |
) |
Per diluted
share: |
|
|
|
Income
(loss) from continuing operations |
$ |
(0.70 |
) |
$ |
(0.18 |
) |
$ |
(0.24 |
) |
Net
Income (loss) |
$ |
(0.70 |
) |
$ |
(0.16 |
) |
$ |
(0.23 |
) |
Adjusted
net income (loss) from continuing operations (b) |
$ |
(0.08 |
) |
$ |
(0.24 |
) |
$ |
(0.13 |
) |
Adjusted
net income (loss) (b) |
$ |
(0.08 |
) |
$ |
(0.17 |
) |
$ |
(0.11 |
) |
Weighted
average diluted shares |
850 |
|
850 |
|
847 |
|
(a) The Company closed on its sale of the Canadian oil sands
business in the second quarter of 2017. The Canadian oil
sands business is reflected as discontinued operations in all
periods presented. The discontinued operations presentation has not
yet been audited; therefore, reported values are
preliminary.(b) 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) |
2017 |
2017 |
2016 |
Segment income
(loss) |
|
|
|
United States
E&P |
$ |
(38 |
) |
$ |
(107 |
) |
$ |
(59 |
) |
International
E&P |
104 |
|
59 |
|
59 |
|
Segment
income (loss) |
66 |
|
(48 |
) |
— |
|
Not
allocated to segments |
(665 |
) |
(105 |
) |
(206 |
) |
Loss from
continuing operations |
(599 |
) |
(153 |
) |
(206 |
) |
Discontinued operations (a) |
— |
|
14 |
|
14 |
|
Net income (loss) |
$ |
(599 |
) |
$ |
(139 |
) |
$ |
(192 |
) |
Exploration
expenses |
|
|
|
United States
E&P |
$ |
41 |
|
$ |
30 |
|
$ |
35 |
|
International
E&P |
3 |
|
— |
|
10 |
|
Segment
exploration expenses |
44 |
|
30 |
|
45 |
|
Not
allocated to segments |
250 |
|
— |
|
38 |
|
Total |
$ |
294 |
|
$ |
30 |
|
$ |
83 |
|
Cash
flows |
|
|
|
Net cash provided by
operating activities from continuing operations |
$ |
564 |
|
$ |
422 |
|
$ |
259 |
|
Minus: changes in
working capital |
62 |
|
(49 |
) |
72 |
|
Total net cash provided
from continuing operations before changes in working capital
(b) |
$ |
502 |
|
$ |
471 |
|
$ |
187 |
|
Net cash provided by
operating activities from discontinued operations (a) |
— |
|
46 |
|
108 |
|
|
|
|
|
Cash
additions to property, plant and equipment |
$ |
(530 |
) |
$ |
(492 |
) |
$ |
(221 |
) |
(a) The Company closed on its sale of the Canadian oil sands
business in the second quarter of 2017. The Canadian oil sands
business is reflected as discontinued operations in all periods
presented. The discontinued operations presentation has not yet
been audited; therefore, reported values are
preliminary.(b) Non-GAAP financial measure. See "Non-GAAP
Measures" above for further discussion.
|
Three Months Ended |
Guidance(a) |
|
Sept. 30 |
June 30 |
Sept. 30 |
Fourth Quarter |
Full Year |
(mboed) |
2017 |
2017 |
2016 |
2017 |
2017 |
Net production
available for sale |
|
|
|
|
|
United States E&P
(a) |
245 |
|
222 |
|
216 |
|
255-265 |
|
International E&P
excluding Libya (b) |
126 |
|
127 |
|
128 |
|
120-130 |
|
Total continuing
operations, excluding Libya (b) |
371 |
|
349 |
|
344 |
|
|
350-360 |
Libya |
23 |
|
11 |
|
— |
|
|
|
Total
continuing operations |
394 |
|
360 |
|
344 |
|
|
|
(a) The Company closed on sales of certain Oklahoma conventional
assets in September 2017, certain Wyoming assets in June and
November 2016, and certain fields within New Mexico and West Texas
in July, August, and October 2016.(b) Libya is excluded because of
the timing of future production and sales levels.
|
Three Months Ended |
|
Sept. 30 |
June 30 |
Sept. 30 |
(mboed) |
2017 |
2017 |
2016 |
Net production
available for sale |
|
|
|
United States
E&P |
245 |
|
222 |
|
216 |
|
Less:
Divestitures (a) |
(2 |
) |
(2 |
) |
(9 |
) |
Divestiture-adjusted United States E&P |
243 |
|
220 |
|
207 |
|
Divestiture-adjusted total continuing
operations |
392 |
|
358 |
|
335 |
|
Discontinued operations (b) |
— |
|
29 |
|
58 |
|
(a) Divestitures include the sale of certain Oklahoma
conventional assets closed in September 2017, certain Wyoming
assets closed in June and November 2016, and certain New Mexico and
West Texas assets closed in July, August, and October 2016. These
production volumes have been removed from all periods shown in
arriving at divestiture-adjusted United States E&P net
production available for sale.
(b) The Company closed on its sale of the Canadian oil sands
business on May 31, 2017. The Canadian oil sands business is
reflected as discontinued operations in all periods presented. The
discontinued operations presentation has not yet been audited;
therefore, reported values are preliminary.
Supplemental Statistics (Unaudited) |
Three Months Ended |
|
Sept. 30 |
June 30 |
Sept. 30 |
|
2017 |
2017 |
2016 |
United States
E&P - net sales volumes |
|
|
|
Liquid
hydrocarbons (mbbld) |
183 |
|
165 |
|
164 |
|
Oklahoma
resource basins |
31 |
|
26 |
|
22 |
|
Eagle
Ford |
80 |
|
79 |
|
76 |
|
Bakken |
55 |
|
45 |
|
50 |
|
Northern
Delaware |
6 |
|
3 |
|
— |
|
Other
United States (a) |
11 |
|
12 |
|
16 |
|
Crude
oil and condensate (mbbld) |
139 |
|
125 |
|
122 |
|
Oklahoma
resource basins |
17 |
|
14 |
|
11 |
|
Eagle
Ford |
58 |
|
59 |
|
54 |
|
Bakken |
49 |
|
39 |
|
44 |
|
Northern
Delaware |
6 |
|
2 |
|
— |
|
Other
United States (a) |
9 |
|
11 |
|
13 |
|
Natural
gas liquids (mbbld) |
44 |
|
40 |
|
42 |
|
Oklahoma
resource basins |
14 |
|
12 |
|
11 |
|
Eagle
Ford |
22 |
|
20 |
|
22 |
|
Bakken |
6 |
|
6 |
|
6 |
|
Northern
Delaware |
— |
|
1 |
|
— |
|
Other
United States (a) |
2 |
|
1 |
|
3 |
|
Natural
gas (mmcfd) |
369 |
|
341 |
|
315 |
|
Oklahoma
resource basins |
161 |
|
138 |
|
116 |
|
Eagle
Ford |
126 |
|
127 |
|
127 |
|
Bakken |
26 |
|
25 |
|
25 |
|
Northern
Delaware |
15 |
|
7 |
|
— |
|
Other
United States (a) |
41 |
|
44 |
|
47 |
|
Total United States E&P (mboed) |
244 |
|
222 |
|
216 |
|
International
E&P - net sales volumes |
|
|
|
Liquid
hydrocarbons (mbbld) |
81 |
|
55 |
|
44 |
|
Equatorial Guinea |
39 |
|
30 |
|
38 |
|
Libya |
23 |
|
11 |
|
— |
|
United
Kingdom |
16 |
|
13 |
|
6 |
|
Other
International |
3 |
|
1 |
|
— |
|
Crude
oil and condensate (mbbld) |
68 |
|
43 |
|
32 |
|
Equatorial Guinea |
27 |
|
18 |
|
26 |
|
Libya |
23 |
|
11 |
|
— |
|
United
Kingdom |
15 |
|
13 |
|
6 |
|
Other
International |
3 |
|
1 |
|
— |
|
Natural
gas liquids (mbbld) |
13 |
|
12 |
|
12 |
|
Equatorial Guinea |
12 |
|
12 |
|
12 |
|
United
Kingdom |
1 |
|
— |
|
— |
|
Natural
gas (mmcfd) |
507 |
|
478 |
|
489 |
|
Equatorial Guinea |
482 |
|
452 |
|
462 |
|
United
Kingdom (b) |
25 |
|
26 |
|
27 |
|
Total
International E&P (mboed) |
165 |
|
135 |
|
126 |
|
Total Company continuing operations - net sales volumes
(mboed) |
409 |
|
357 |
|
342 |
|
Net sales
volumes of equity method investees |
|
|
|
LNG (mtd) |
6,943 |
|
6,243 |
|
6,620 |
|
Methanol
(mtd) |
1,366 |
|
1,182 |
|
1,529 |
|
Condensate and LPG (boed) |
17,216 |
|
11,608 |
|
16,766 |
|
(a) Includes Oklahoma, Wyoming, New Mexico, and other
conventional onshore U.S. production. The sale of certain Oklahoma
assets closed in September 2017, certain Wyoming assets closed in
June and November 2016, and certain New Mexico and West Texas
assets closed in July, August, and October 2016.(b) Includes
natural gas acquired for injection and subsequent resale.
Supplemental Statistics (Unaudited) |
Three Months Ended |
|
Sept. 30 |
June 30 |
Sept. 30 |
|
2017 |
2017 |
2016 |
United States
E&P - average price realizations (a) |
|
|
|
Liquid
hydrocarbons ($ per bbl) |
$ |
40.48 |
|
$ |
39.00 |
|
$ |
34.00 |
|
Oklahoma
resource basins |
35.84 |
|
33.78 |
|
27.60 |
|
Eagle
Ford |
39.87 |
|
38.35 |
|
32.81 |
|
Bakken |
43.09 |
|
42.22 |
|
37.33 |
|
Northern
Delaware |
44.00 |
|
37.58 |
|
— |
|
Other
United States (b) |
43.23 |
|
42.72 |
|
37.91 |
|
Crude
oil and condensate ($ per bbl) (c) |
$ |
46.65 |
|
$ |
45.81 |
|
$ |
41.35 |
|
Oklahoma
resource basins |
46.39 |
|
45.42 |
|
42.04 |
|
Eagle
Ford |
47.56 |
|
45.75 |
|
41.67 |
|
Bakken |
46.06 |
|
46.20 |
|
41.25 |
|
Northern
Delaware |
44.49 |
|
43.38 |
|
— |
|
Other
United States (b) |
45.83 |
|
45.71 |
|
39.89 |
|
Natural
gas liquids ($ per bbl) |
$ |
20.86 |
|
$ |
17.61 |
|
$ |
12.44 |
|
Oklahoma
resource basins |
23.58 |
|
19.63 |
|
13.87 |
|
Eagle
Ford |
19.52 |
|
16.63 |
|
11.45 |
|
Bakken |
17.89 |
|
15.16 |
|
10.63 |
|
Northern
Delaware |
30.23 |
|
17.54 |
|
— |
|
Other
United States (b) |
24.94 |
|
23.78 |
|
22.50 |
|
Natural
gas ($ per mcf) (d) |
$ |
2.71 |
|
$ |
3.05 |
|
$ |
2.67 |
|
Oklahoma
resource basins |
2.69 |
|
3.07 |
|
2.74 |
|
Eagle
Ford |
2.83 |
|
3.06 |
|
2.72 |
|
Bakken |
2.08 |
|
3.14 |
|
1.95 |
|
Northern
Delaware |
3.00 |
|
2.72 |
|
— |
|
Other United States (b) |
2.67 |
|
2.92 |
|
2.73 |
|
International
E&P - average price realizations |
|
|
|
Liquid
hydrocarbons ($ per bbl) |
$ |
43.69 |
|
$ |
37.11 |
|
$ |
30.40 |
|
Equatorial Guinea |
32.78 |
|
24.30 |
|
27.44 |
|
Libya |
56.93 |
|
50.94 |
|
— |
|
United
Kingdom |
51.12 |
|
53.66 |
|
48.01 |
|
Other
International |
40.67 |
|
40.64 |
|
— |
|
Crude
oil and condensate ($ per bbl) |
$ |
51.23 |
|
$ |
47.04 |
|
$ |
41.45 |
|
Equatorial Guinea |
46.91 |
|
39.73 |
|
39.70 |
|
Libya |
56.93 |
|
50.94 |
|
— |
|
United
Kingdom |
51.72 |
|
54.15 |
|
49.82 |
|
Other
International |
40.67 |
|
40.64 |
|
— |
|
Natural
gas liquids ($ per bbl) |
$ |
2.25 |
|
$ |
1.77 |
|
$ |
1.93 |
|
Equatorial Guinea (e) |
1.00 |
|
1.00 |
|
1.00 |
|
United
Kingdom |
32.58 |
|
32.33 |
|
26.36 |
|
Natural
gas ($ per mcf) |
$ |
0.51 |
|
$ |
0.57 |
|
$ |
0.46 |
|
Equatorial Guinea (e) |
0.24 |
|
0.24 |
|
0.24 |
|
United Kingdom |
5.71 |
|
6.27 |
|
4.19 |
|
Benchmark |
|
|
|
WTI crude
oil (per bbl) |
$ |
48.20 |
|
$ |
48.15 |
|
$ |
44.94 |
|
Brent
(Europe) crude oil (per bbl)(f) |
$ |
52.11 |
|
$ |
49.67 |
|
$ |
45.79 |
|
Henry Hub natural gas (per mmbtu)(g) |
$ |
3.00 |
|
$ |
3.18 |
|
$ |
2.81 |
|
(a) Excludes gains or losses on derivative instruments.(b)
Includes Oklahoma, Wyoming, New Mexico, and other conventional
onshore U.S. production. The sale of certain Oklahoma assets closed
in September 2017, certain Wyoming assets closed in June and
November 2016, and certain New Mexico and West Texas assets closed
in July, August, and October 2016.(c) Inclusion of realized gains
on crude oil derivative instruments would have increased liquid
hydrocarbons average price realizations by $2.42, $1.07, and $1.55,
for the third and second quarter of 2017, and third quarter of
2016, 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) 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.(f) Average
of monthly prices obtained from Energy Information Administration
("EIA") website.(g) Settlement date average per mmbtu.
Crude Oil |
|
2017 |
|
2018 |
|
|
Fourth Quarter |
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Three-Way Collars (a) |
|
|
|
|
|
Volume
(Bbls/day) |
|
50,000 |
|
75,000 |
|
|
75,000 |
|
|
62,000 |
|
|
62,000 |
|
Weighted
average price per Bbl: |
|
|
|
|
|
Ceiling |
$ |
60.37 |
$ |
56.24 |
|
$ |
56.24 |
|
$ |
56.08 |
|
$ |
56.08 |
|
Floor |
$ |
54.80 |
$ |
51.33 |
|
$ |
51.33 |
|
$ |
50.50 |
|
$ |
50.50 |
|
Sold put |
$ |
47.80 |
$ |
44.73 |
|
$ |
44.73 |
|
$ |
43.61 |
|
$ |
43.61 |
|
Swaps
(b)(c) |
|
|
|
|
|
Volume (Bbls/day) |
|
20,000 |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Weighted average price per Bbl |
$ |
51.37 |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Sold call
options (d) |
|
|
|
|
|
Volume (Bbls/day) |
|
35,000 |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Weighted
average price per Bbl |
$ |
61.91 |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Basis Swaps (e) |
|
|
|
|
|
Volume
(Bbls/day) |
|
— |
|
5,000 |
|
|
5,000 |
|
|
10,000 |
|
|
10,000 |
|
Weighted average price per Bbl |
|
— |
$ |
(0.60 |
) |
$ |
(0.60 |
) |
$ |
(0.67 |
) |
$ |
(0.67 |
) |
(a) Between Sept. 30, 2017 and Oct. 30, 2017, Marathon Oil
entered into 10,000 Bbls/day of three-way collars for July -
December 2018 with an average ceiling price of $58.07, a floor
price of $53.70, and a sold put price of $47.00.(b) The
counterparties have the option to execute fixed-price swaps
(swaptions) at a weighted average price of $52.67 per Bbl indexed
to NYMEX WTI, which is exercisable on Dec. 29, 2017. If the
counterparties exercise, the term of the fixed-price swaps would be
from January - June 2018 and, if all such options are exercised,
for 10,000 Bbls/day.(c) Between Sept. 30, 2017 and Oct. 30,
2017, we entered into 40,000 Bbls/day of fixed-price swaps for
November - December 2017 with a weighted average price of $54.11.
(d) Call options settle monthly.(e) The basis
differential price is between WTI Midland and WTI Cushing.
Natural Gas |
|
2017 |
|
2018 |
|
Fourth Quarter |
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Three-Way Collars |
|
|
|
|
|
Volume
(MMBtu/day) |
|
120,000 |
|
200,000 |
|
160,000 |
|
160,000 |
|
160,000 |
Weighted
average price per MMBtu: |
|
|
|
|
|
Ceiling |
$ |
3.71 |
$ |
3.79 |
$ |
3.61 |
$ |
3.61 |
$ |
3.61 |
Floor |
$ |
3.14 |
$ |
3.08 |
$ |
3.00 |
$ |
3.00 |
$ |
3.00 |
Sold put |
$ |
2.60 |
$ |
2.55 |
$ |
2.50 |
$ |
2.50 |
$ |
2.50 |
Swaps |
|
|
|
|
|
Volume
(MMBtu/day) |
|
20,000 |
|
— |
|
— |
|
— |
|
— |
Weighted average price per MMBtu |
$ |
2.93 |
|
— |
|
— |
|
— |
|
— |
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