Marathon Oil Corporation (NYSE:MRO) today announced a $2.3 billion
returns-driven development capital budget for 2018, which is
self-funding at $50 average WTI, including dividends, and generates
meaningful free cash flow at $60 average WTI. More than 90 percent
will be directed to the four U.S. resource plays, with corporate
cash return on invested capital (CROIC) expected to increase by
about 30 percent year over year at $50 average WTI.
Almost 60 percent of the development budget will be allocated to
the high-return Eagle Ford and Bakken assets, which have
demonstrated step-change performance improvements while operating
at scale. Approximately one-third of the development budget will be
allocated to the Company's Northern Delaware and Oklahoma assets,
where the majority of drilling activity will be transitioning to
multi-well pads, while continuing strategic delineation and
appraisal.
As a result of this concentrated capital allocation, the U.S.
resource plays will increase to about 70 percent of the total
Company production mix, driving a natural expansion in margins.
Additionally, Marathon Oil expects to deliver a strong annual rate
of change on the key corporate performance metrics of CROIC and
cash flow per debt adjusted share (CFPDAS), both of which are now
integrated into the executive compensation structure.
2018 Production GuidanceFor full year 2018, the
Company forecasts total production available for sale, excluding
Libya, to average 390,000 to 410,000 net barrels of oil equivalent
per day (boed), up 12 percent at the midpoint compared to 2017 on a
divestiture-adjusted basis. Total annual oil production available
for sale, excluding Libya, is expected to increase about 18 percent
at the midpoint on a divestiture-adjusted basis, driven by 20 - 25
percent annual oil growth in the U.S. resource plays.
For first quarter 2018, U.S. production is expected to average
265,000 to 275,000 net boed. International production, excluding
Libya, is expected to average 105,000 to 115,000 net boed, which
reflects planned turnaround activity in EG.
2017 Review
- Achieved cash flow neutrality*, including dividends and working
capital, with $51 average WTI
- Total production (excluding Libya) of 358,000 net boed; up 9%
year over year on a divestiture-adjusted basis
- U.S. resource plays exited 2017 with oil production 31% higher
than fourth quarter 2016
- Entered Northern Delaware basin and divested Canadian oil sands
business
- Reduced unit production costs 7% for U.S. E&P and 6% for
International E&P (excluding Libya) compared to the prior
year
- Reduced gross debt by approximately $1.75 billion, lowering
annualized interest expense by $115 million
- Organic reserve replacement of 121%, excluding acquisitions and
dispositions, at a drillbit finding and development cost of $12.81
per boe
* Excludes a one-time $108 million U.K. tax payment that is
currently under appeal.
"We finished 2017 with another quarter of outstanding
operational execution across all four resource plays," said
Marathon Oil President and CEO Lee Tillman. "We delivered some of
the most productive unconventional wells in our Company’s history
in our high-return Eagle Ford and Bakken assets, while achieving
strong rates from our nine-well STACK infill development and
excellent well results across the Northern Delaware. Last year we
reached key milestones in our portfolio transformation, further
strengthened our balance sheet, drove costs even lower and
delivered production near the top of our production guidance, all
while maintaining cash flow neutrality. In 2018, we expect to
improve corporate-level returns from our disciplined development
capital program that's self-funding at $50 and will generate
meaningful free cash flow at $60 average WTI, including the
dividend."
Marathon Oil reported a fourth quarter 2017 net loss of $28
million, or $0.03 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 $56 million, or $0.07 per diluted share.
Net operating cash flow was $501 million, or $637 million before
changes in working capital and the one-time U.K. tax payment.
Fourth Quarter 2017 Highlights
- Total Company production excluding Libya averaged 383,000 net
boed, up 4% sequentially on a divestiture-adjusted basis; 33,000
net boed from Libya
- U.S. resource play production averaged 249,000 net boed, up 10%
sequentially
- Eagle Ford production averaged 105,000 net boed; up 4%
sequentially with fewer wells to sales
- Bakken production increased 17% sequentially to 69,000 net
boed; set new Williston Basin 30-day IP oil record at 3,005
bpd
- Oklahoma production up 10% sequentially to 64,000 net boed;
nine-well STACK infill development averaged 30-day IP rates of
1,840 boed (60% oil)
- Northern Delaware production averaged 11,000 net boed; two-well
pad averaged 30-day IP rates of 3,265 boed (62% oil)
U.S. E&P U.S. E&P production available
for sale averaged 262,000 net boed for fourth quarter 2017. On a
divestiture-adjusted basis, production was up 8 percent compared to
the prior quarter and up 27 percent from the year-ago quarter.
Fourth quarter unit production costs were $5.33 per barrel of oil
equivalent (boe), down from $5.38 in the previous quarter, and a
new record low for the Company since becoming an independent
E&P in 2011. Full-year unit production costs averaged $5.57 per
boe.
EAGLE FORD: Marathon Oil's production in the Eagle Ford averaged
105,000 net boed in the fourth quarter, up from 101,000 net boed in
the prior quarter. The Company brought 33 gross Company-operated
wells to sales in the fourth quarter with average 30-day initial
production (IP) rates of 1,800 boed (73% oil). The testing of
enhanced completion designs in Atascosa County continued to deliver
encouraging results. The five-well Guajillo Unit 8 South pad
delivered average 30-day IP rates of 1,730 boed (77% oil,
6,300-foot average lateral length) and the three-well Middle
McCowen pad, the Company's western-most test of 2017, achieved
average 30-day IP rates of 2,080 boed (87% oil, 9,915-foot average
lateral length). In Karnes County, average 30-day IP rates from two
Austin Chalk wells on the Challenger pad were 2,415 boed (75% oil,
5,350-foot average lateral length).
BAKKEN: In fourth quarter 2017, Marathon Oil's Bakken production
averaged 69,000 net boed, up 17 percent compared to 59,000 net boed
in the prior quarter. The Company brought 13 gross Company-operated
wells to sales in the fourth quarter, nine of which came in West
Myrmidon with average 30-day IP rates of 2,935 boed. The Forsman
Middle Bakken well in West Myrmidon set a new Williston Basin
30-day IP oil record with a rate of 3,005 barrels per day. The
testing of enhanced completion designs continued to deliver
encouraging results, with the three-well Chapman pad on the eastern
side of Hector achieving average 30-day IP rates of 1,810 boed (85%
oil).
OKLAHOMA: The Company's production in Oklahoma increased 10
percent to 64,000 net boed during fourth quarter 2017, up from
58,000 net boed in the prior quarter. The Company brought 26 gross
Company-operated wells to sales during the quarter predominately
focused in the STACK on Meramec infill wells and leasehold
activity. The Company's first STACK volatile oil infill
development, the Tan, in southwest Kingfisher County averaged
30-day IP rates of 1,840 boed (60% oil). The nine new infills were
comprised of eight XL wells (10,400-foot average lateral length)
and one SL well (5,400-foot lateral length). The Eve, the Company's
third and farthest east infill spacing pilot in Kingfisher County’s
black oil window, averaged 30-day IP rates from the five new wells
of 715 boed (65% oil, 5,000-foot average lateral length).
NORTHERN DELAWARE: The Company's Northern Delaware production
averaged 11,000 net boed in fourth quarter 2017, up from 9,000 net
boed in the prior quarter. The Company brought 11 gross
Company-operated wells to sales in Eddy and Lea Counties, which had
30-day IP rates that averaged 1,835 boed (66% oil). A two-well pad
achieved average 30-day IP rates of 3,265 boed (62% oil) and a
nearby third well averaged a 30-day rate of 2,910 boed (63%
oil).
International E&PInternational E&P
production available for sale (excluding Libya) averaged 121,000
net boed for fourth quarter 2017. This compares to 126,000 net boed
in the prior quarter, and 129,000 net boed in the year-ago quarter.
The decrease was due to the temporary shut-down of the
outside-operated Forties Pipeline System and planned turn-around
activity in the U.K, as well as natural field declines. Libya
production available for sale averaged 33,000 net boed in the
fourth quarter. Fourth quarter 2017 International E&P unit
production costs (excluding Libya) averaged $3.85 per boe.
Full-year 2017 unit production costs (excluding Libya) were $4.13
per boe, below the low end of guidance of $4.50 to $5.50 per
boe.
Corporate and Special ItemsNet cash provided by
continuing operations was $501 million during fourth quarter 2017,
or $637 million before changes in working capital and the one-time
U.K. tax payment under appeal. Fourth quarter 2017 cash additions
to property, plant and equipment (PP&E) were $669 million, up
sequentially due to the timing of invoice payments and resource
play exploration leasing.
As previously disclosed, Marathon Oil received an adverse ruling
from the U.K. first-tier tax tribunal during fourth quarter 2017
related to the timing of deductibility for certain Brae area
decommissioning costs. While the Company is appealing the ruling,
the Company was required to pay the disputed tax amount of $108
million in order to pursue the appeal.
Total liquidity as of Dec. 31 was approximately $4 billion,
which consisted of $560 million in cash and cash equivalents and an
undrawn revolving credit facility of $3.4 billion. Remaining
proceeds of $750 million from the sale of the Company's Canadian
subsidiary are scheduled to be received in March.
The adjustments to net income from continuing operations for
fourth quarter 2017 totaled $96 million before tax, and include an
unrealized loss of $145 million on commodity derivatives and $24
million proved property impairment, partially offset by a $32
million gain from dispositions.
ReservesDuring 2017, Marathon Oil added proved
reserves of 193 million boe for a reserve replacement ratio of 140
percent excluding dispositions. Virtually all of the additions were
in U.S. E&P. The Company's organic reserve replacement ratio,
excluding acquisitions and dispositions, was 121 percent at a
drillbit finding and development (F&D) cost of $12.81. Net
proved reserves were approximately 1.45 billion boe at year-end
2017, down from year-end 2016 primarily due to the sale of the
Canadian Oil Sands business.
A slide deck and Quarterly Investor Packet will be posted to the
Company's website at https://www.marathonoil.com/Investors
following this release today, Feb. 14. The Company will conduct a
question and answer webcast/call on Thursday, Feb. 15, at 9:00 a.m.
ET. The commentary and answers to questions will include
forward-looking information. To listen to the live webcast, visit
the Marathon Oil website at https://www.marathonoil.com. The audio
replay of the webcast will be posted by Feb. 16.
DefinitionsCROIC - 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).
CFPDAS - Cash flow per debt adjusted share;
calculated by taking cash flow (operating cash flow before working
capital + net interest after tax) divided by total shares including
debt shares. Debt shares is the average net debt during a calendar
year divided by the average annual stock price.
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), net cash provided by operations before changes in
working capital and the one-time U.K. tax payment under appeal,
CROIC and CFPDAS 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 and the one-time U.K. tax payment
under appeal 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. CROIC and CFPDAS will be integrated into our
executive compensation structure and management will use this
information for purposes of comparing its financial performance
with the financial performance of other companies in the industry.
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 of
adjusted net income (loss) and net cash provided by operations
before changes in working capital and the one-time U.K. tax payment
under appeal and its most directly comparable GAAP financial
measure. A reconciliation of CROIC’s components to their most
directly comparable GAAP financial measures can be found in our
investor package on our website at www.marathonoil.com. 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 2018 capital budget and allocations, future performance,
free cash flow, corporate cash return on invested capital, business
strategy, asset quality, cash margins, production, rates of change
for CROIC and CFPDAS, 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.
Media Relations Contact:Lee Warren:
713-296-4103
Investor Relations Contacts:Zach Dailey:
713-296-4140John Reid: 713-296-4380
Consolidated Statements of Income (Unaudited) |
Three Months Ended |
Year Ended |
|
Dec.
312017 |
|
Sept.
302017 |
|
Dec.
312016 |
|
Dec.
312017 |
|
Dec.
312016 |
|
(In
millions, except per share data) |
|
|
|
|
|
Revenues and
other income: |
|
|
|
|
|
Sales and other operating revenues, including related party |
$ |
1,185 |
|
$ |
1,114 |
|
$ |
898 |
|
$ |
4,211 |
|
$ |
2,930 |
|
Marketing revenues |
45 |
|
48 |
|
38 |
|
162 |
|
240 |
|
Income from equity method investments |
73 |
|
63 |
|
65 |
|
256 |
|
175 |
|
Net
gain (loss) on disposal of assets |
32 |
|
19 |
|
108 |
|
58 |
|
389 |
|
Other income |
47 |
|
8 |
|
15 |
|
78 |
|
53 |
|
Total revenues and
other income |
1,382 |
|
1,252 |
|
1,124 |
|
4,765 |
|
3,787 |
|
Costs and
expenses: |
|
|
|
|
|
Production |
185 |
|
194 |
|
180 |
|
706 |
|
712 |
|
Marketing, including purchases from related parties |
47 |
|
49 |
|
44 |
|
168 |
|
245 |
|
Other
operating |
122 |
|
109 |
|
111 |
|
431 |
|
484 |
|
Exploration |
57 |
|
294 |
|
34 |
|
409 |
|
323 |
|
Depreciation, depletion and amortization |
583 |
|
641 |
|
573 |
|
2,372 |
|
2,156 |
|
Impairments |
24 |
|
201 |
|
19 |
|
229 |
|
67 |
|
Taxes
other than income |
55 |
|
44 |
|
38 |
|
183 |
|
151 |
|
General
and administrative |
101 |
|
97 |
|
95 |
|
400 |
|
481 |
|
Total costs and
expenses |
1,174 |
|
1,629 |
|
1,094 |
|
4,898 |
|
4,619 |
|
Income (loss)
from operations |
208 |
|
(377 |
) |
30 |
|
(133 |
) |
(832 |
) |
Net
interest and other |
(71 |
) |
(35 |
) |
(76 |
) |
(270 |
) |
(332 |
) |
Loss on
early extinguishment of debt |
(5 |
) |
(46 |
) |
— |
|
(51 |
) |
— |
|
Income (loss)
from continuing operations before income taxes |
132 |
|
(458 |
) |
(46 |
) |
(454 |
) |
(1,164 |
) |
Provision
(Benefit) for income taxes |
160 |
|
141 |
|
1,337 |
|
376 |
|
923 |
|
Income (loss)
from continuing operations |
(28 |
) |
(599 |
) |
(1,383 |
) |
(830 |
) |
(2,087 |
) |
Discontinued operations
(a) |
— |
|
— |
|
12 |
|
(4,893 |
) |
(53 |
) |
Net income
(loss) |
$ |
(28 |
) |
$ |
(599 |
) |
$ |
(1,371 |
) |
$ |
(5,723 |
) |
$ |
(2,140 |
) |
|
|
|
|
|
|
Adjusted Net
Income |
|
|
|
|
|
Income (loss) from
continuing operations |
(28 |
) |
(599 |
) |
(1,383 |
) |
(830 |
) |
(2,087 |
) |
Adjustments for special
items from continuing operations (pre-tax): |
|
|
|
|
|
Net
(gain) loss on dispositions |
(32 |
) |
(19 |
) |
(108 |
) |
(57 |
) |
(379 |
) |
Proved
property impairments |
24 |
|
201 |
|
— |
|
225 |
|
47 |
|
Exploratory dry well costs, unproved property impairments and
other |
— |
|
250 |
|
— |
|
250 |
|
118 |
|
Pension
settlement |
7 |
|
8 |
|
10 |
|
32 |
|
103 |
|
Unrealized (gain) loss on derivative instruments |
145 |
|
56 |
|
21 |
|
81 |
|
110 |
|
Gain on
termination of interest rate swaps |
— |
|
(47 |
) |
— |
|
(47 |
) |
— |
|
Loss on
extinguishment of debt |
5 |
|
46 |
|
— |
|
51 |
|
— |
|
Rig
termination payment |
— |
|
— |
|
— |
|
— |
|
113 |
|
Other |
(53 |
) |
(4 |
) |
(4 |
) |
(59 |
) |
55 |
|
Provision (benefit) for
income taxes related to special items from continuing
operations |
(12 |
) |
(1 |
) |
23 |
|
(13 |
) |
(66 |
) |
Valuation
Allowance |
— |
|
41 |
|
1,346 |
|
41 |
|
1,346 |
|
Adjusted net
income (loss) from continuing operations (b) |
$ |
56 |
|
$ |
(68 |
) |
$ |
(95 |
) |
$ |
(326 |
) |
$ |
(640 |
) |
Income (loss) from
discontinued operations (a) |
— |
|
— |
|
12 |
|
(4,893 |
) |
(53 |
) |
Adjustments for special
items from discontinued operations (pre-tax): |
|
|
|
|
|
Canadian
oil sands business impairment (a) |
— |
|
— |
|
— |
|
6,636 |
|
— |
|
Net
(gain) loss on disposition (a) |
— |
|
— |
|
— |
|
43 |
|
— |
|
Provision (benefit) for
income taxes related to special items from discontinued operations
(a) |
— |
|
— |
|
— |
|
(1,674 |
) |
— |
|
Adjusted net income (loss) (b) |
$ |
56 |
|
$ |
(68 |
) |
$ |
(83 |
) |
$ |
(214 |
) |
$ |
(693 |
) |
Per diluted
share: |
|
|
|
|
|
Income
(loss) from continuing operations |
$ |
(0.03 |
) |
$ |
(0.70 |
) |
$ |
(1.63 |
) |
$ |
(0.97 |
) |
$ |
(2.55 |
) |
Net
Income (loss) |
$ |
(0.03 |
) |
$ |
(0.70 |
) |
$ |
(1.62 |
) |
$ |
(6.73 |
) |
$ |
(2.61 |
) |
Adjusted
net income (loss) from continuing operations (b) |
$ |
0.07 |
|
$ |
(0.08 |
) |
$ |
(0.11 |
) |
$ |
(0.38 |
) |
$ |
(0.78 |
) |
Adjusted
net income (loss) (b) |
$ |
0.07 |
|
$ |
(0.08 |
) |
$ |
(0.10 |
) |
$ |
(0.25 |
) |
$ |
(0.85 |
) |
Weighted
average diluted shares |
850 |
|
850 |
|
847 |
|
850 |
|
819 |
|
(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(b) Non-GAAP financial measure. See "Non-GAAP
Measures" above for further discussion. |
Supplemental Statistics (Unaudited) |
Three Months Ended |
Year Ended |
|
Dec. 312017 |
|
Sept. 302017 |
|
Dec.
312016 |
|
Dec.
312017 |
|
Dec.
312016 |
|
(in
millions) |
|
|
|
|
|
Segment income
(loss) |
|
|
|
|
|
United States
E&P |
$ |
76 |
|
$ |
(38 |
) |
$ |
(91 |
) |
$ |
(148 |
) |
$ |
(415 |
) |
International
E&P |
118 |
|
104 |
|
110 |
|
374 |
|
228 |
|
Segment
income (loss) |
194 |
|
66 |
|
19 |
|
226 |
|
(187 |
) |
Not
allocated to segments |
(222 |
) |
(665 |
) |
(1,402 |
) |
(1,056 |
) |
(1,900 |
) |
Loss from
continuing operations |
(28 |
) |
(599 |
) |
(1,383 |
) |
(830 |
) |
(2,087 |
) |
Discontinued operations (a) |
— |
|
— |
|
12 |
|
(4,893 |
) |
(53 |
) |
Net income (loss) |
$ |
(28 |
) |
$ |
(599 |
) |
$ |
(1,371 |
) |
$ |
(5,723 |
) |
$ |
(2,140 |
) |
Exploration
expenses |
|
|
|
|
|
United States
E&P |
$ |
57 |
|
$ |
41 |
|
$ |
37 |
|
$ |
154 |
|
$ |
127 |
|
International
E&P |
— |
|
3 |
|
(3 |
) |
5 |
|
17 |
|
Segment
exploration expenses |
57 |
|
44 |
|
34 |
|
159 |
|
144 |
|
Not
allocated to segments |
— |
|
250 |
|
— |
|
250 |
|
179 |
|
Total |
$ |
57 |
|
$ |
294 |
|
$ |
34 |
|
$ |
409 |
|
$ |
323 |
|
Cash
flows |
|
|
|
|
|
Net cash provided by
operating activities from continuing operations |
$ |
501 |
|
$ |
564 |
|
$ |
375 |
|
$ |
1,988 |
|
$ |
901 |
|
Minus: changes in
working capital |
(28 |
) |
62 |
|
12 |
|
(27 |
) |
(6 |
) |
Minus: U.K. tax
payment |
(108 |
) |
— |
|
— |
|
(108 |
) |
— |
|
Total net cash provided
from continuing operations before changes in working capital and
the U.K. tax payment (b) |
$ |
637 |
|
$ |
502 |
|
$ |
363 |
|
$ |
2,123 |
|
$ |
907 |
|
Net cash provided by
operating activities from discontinued operations (a) |
— |
|
— |
|
80 |
|
141 |
|
177 |
|
|
|
|
|
|
|
Cash
additions to property, plant and equipment |
$ |
(669 |
) |
$ |
(530 |
) |
$ |
(255 |
) |
$ |
(1,974 |
) |
$ |
(1,204 |
) |
(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(b) Non-GAAP financial measure. See "Non-GAAP
Measures" above for further discussion. |
|
Three Months Ended |
Year Ended |
|
Dec. 31 |
|
Sept. 30 |
|
Dec. 31 |
|
Dec. 31 |
|
Dec. 31 |
|
(mboed) |
2017 |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Net production
available for sale |
|
|
|
|
|
United States E&P
(a) |
262 |
|
245 |
|
212 |
|
235 |
|
223 |
|
International E&P
excluding Libya (b) |
121 |
|
126 |
|
129 |
|
123 |
|
119 |
|
Total continuing
operations, excluding Libya (b) |
383 |
|
371 |
|
341 |
|
358 |
|
342 |
|
Libya |
33 |
|
23 |
|
8 |
|
19 |
|
3 |
|
Total
continuing operations |
416 |
|
394 |
|
349 |
|
377 |
|
345 |
|
(a) The
Company closed on the sale of certain Oklahoma and Colorado assets
in September 2017 and October 2017, respectively. The sales of
certain Wyoming assets closed in 2016.(b) Libya is excluded because
of the timing of future production and sales levels. |
|
Three Months Ended |
Year Ended |
|
Dec. 31 |
|
Sept. 30 |
|
Dec. 31 |
|
Dec. 31 |
|
Dec. 31 |
|
(mboed) |
2017 |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Net production
available for sale |
|
|
|
|
|
United States
E&P |
262 |
|
245 |
|
212 |
|
235 |
|
223 |
|
Less:
Divestitures (a) |
(1 |
) |
(3 |
) |
(6 |
) |
(2 |
) |
(16 |
) |
Divestiture-adjusted United States E&P |
261 |
|
242 |
|
206 |
|
233 |
|
207 |
|
Divestiture-adjusted total continuing
operations |
415 |
|
391 |
|
343 |
|
375 |
|
329 |
|
Discontinued operations (b) |
— |
|
— |
|
47 |
|
18 |
|
48 |
|
(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 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. |
Supplemental Statistics (Unaudited) |
Three Months Ended |
Year Ended |
|
Dec. 31 |
|
Sept. 30 |
|
Dec. 31 |
|
Dec. 31 |
|
Dec. 31 |
|
|
2017 |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
United States
E&P - net sales volumes |
|
|
|
|
|
Liquid
hydrocarbons (mbbld) |
199 |
|
183 |
|
160 |
|
176 |
|
171 |
|
Oklahoma |
34 |
|
31 |
|
24 |
|
29 |
|
18 |
|
Eagle
Ford |
84 |
|
80 |
|
74 |
|
80 |
|
82 |
|
Bakken |
64 |
|
55 |
|
47 |
|
52 |
|
50 |
|
Northern
Delaware |
9 |
|
6 |
|
— |
|
5 |
|
— |
|
Other
United States (a) |
8 |
|
11 |
|
15 |
|
10 |
|
21 |
|
Crude oil and
condensate (mbbld) |
150 |
|
139 |
|
121 |
|
133 |
|
131 |
|
Oklahoma |
16 |
|
17 |
|
13 |
|
15 |
|
9 |
|
Eagle
Ford |
61 |
|
58 |
|
54 |
|
59 |
|
60 |
|
Bakken |
58 |
|
49 |
|
41 |
|
46 |
|
44 |
|
Northern
Delaware |
8 |
|
6 |
|
— |
|
4 |
|
— |
|
Other
United States (a) |
7 |
|
9 |
|
13 |
|
9 |
|
18 |
|
Natural gas
liquids (mbbld) |
49 |
|
44 |
|
39 |
|
43 |
|
40 |
|
Oklahoma |
18 |
|
14 |
|
11 |
|
14 |
|
9 |
|
Eagle
Ford |
23 |
|
22 |
|
20 |
|
21 |
|
22 |
|
Bakken |
6 |
|
6 |
|
6 |
|
6 |
|
6 |
|
Northern
Delaware |
1 |
|
— |
|
— |
|
1 |
|
— |
|
Other
United States (a) |
1 |
|
2 |
|
2 |
|
1 |
|
3 |
|
Natural gas
(mmcfd) |
376 |
|
369 |
|
315 |
|
348 |
|
314 |
|
Oklahoma |
180 |
|
161 |
|
123 |
|
149 |
|
102 |
|
Eagle
Ford |
127 |
|
126 |
|
119 |
|
125 |
|
137 |
|
Bakken |
26 |
|
26 |
|
26 |
|
25 |
|
25 |
|
Northern
Delaware |
14 |
|
15 |
|
— |
|
9 |
|
— |
|
Other
United States (a) |
29 |
|
41 |
|
47 |
|
40 |
|
50 |
|
Total United States E&P (mboed) |
262 |
|
244 |
|
212 |
|
234 |
|
223 |
|
International
E&P - net sales volumes |
|
|
|
|
|
Liquid
hydrocarbons (mbbld) |
71 |
|
81 |
|
64 |
|
64 |
|
46 |
|
Equatorial Guinea |
32 |
|
39 |
|
32 |
|
32 |
|
31 |
|
Libya |
29 |
|
23 |
|
10 |
|
19 |
|
3 |
|
United
Kingdom |
6 |
|
16 |
|
22 |
|
11 |
|
12 |
|
Other
International |
4 |
|
3 |
|
— |
|
2 |
|
— |
|
Crude oil and
condensate (mbbld) |
58 |
|
68 |
|
52 |
|
52 |
|
35 |
|
Equatorial Guinea |
20 |
|
27 |
|
20 |
|
21 |
|
20 |
|
Libya |
29 |
|
23 |
|
10 |
|
19 |
|
3 |
|
United
Kingdom |
5 |
|
15 |
|
22 |
|
10 |
|
12 |
|
Other
International |
4 |
|
3 |
|
— |
|
2 |
|
— |
|
Natural gas
liquids (mbbld) |
13 |
|
13 |
|
12 |
|
12 |
|
11 |
|
Equatorial Guinea |
12 |
|
12 |
|
12 |
|
11 |
|
11 |
|
United
Kingdom |
1 |
|
1 |
|
— |
|
1 |
|
— |
|
Natural gas
(mmcfd) |
493 |
|
507 |
|
482 |
|
485 |
|
453 |
|
Equatorial Guinea |
464 |
|
482 |
|
454 |
|
459 |
|
425 |
|
Libya |
14 |
|
— |
|
— |
|
4 |
|
— |
|
United
Kingdom (b) |
15 |
|
25 |
|
28 |
|
22 |
|
28 |
|
Total
International E&P (mboed) |
153 |
|
165 |
|
145 |
|
145 |
|
122 |
|
Total Company continuing operations - net sales volumes
(mboed) |
415 |
|
409 |
|
357 |
|
379 |
|
345 |
|
Net sales
volumes of equity method investees |
|
|
|
|
|
LNG
(mtd) |
6,353 |
|
6,943 |
|
6,743 |
|
6,423 |
|
5,874 |
|
Methanol
(mtd) |
1,637 |
|
1,366 |
|
1,316 |
|
1,374 |
|
1,358 |
|
Condensate and LPG (boed) |
14,605 |
|
17,216 |
|
15,381 |
|
14,501 |
|
13,430 |
|
(a)
Includes production from conventional onshore assets sold in the
applicable periods. The sale of certain Oklahoma and Colorado
assets closed in September 2017 and October 2017, respectively. The
sales of certain Wyoming assets closed in 2016.(b) Includes natural
gas acquired for injection and subsequent resale. |
Supplemental Statistics (Unaudited) |
Three Months Ended |
Year Ended |
|
Dec.
312017 |
|
Sept.
302017 |
|
Dec.
312016 |
|
Dec.
312017 |
|
Dec.
312016 |
|
|
|
|
|
|
|
United States
E&P - average price realizations (a) |
|
|
|
|
|
Liquid
hydrocarbons ($ per bbl) |
$ |
47.61 |
|
$ |
40.48 |
|
$ |
39.00 |
|
$ |
42.31 |
|
$ |
32.71 |
|
Oklahoma |
38.41 |
|
35.84 |
|
34.28 |
|
36.07 |
|
28.15 |
|
Eagle
Ford |
48.32 |
|
39.87 |
|
38.16 |
|
41.86 |
|
31.61 |
|
Bakken |
51.38 |
|
43.09 |
|
41.96 |
|
45.83 |
|
35.65 |
|
Northern
Delaware |
50.35 |
|
44.00 |
|
— |
|
46.08 |
|
— |
|
Other
United States (b) |
46.26 |
|
43.23 |
|
41.69 |
|
43.82 |
|
33.96 |
|
Crude oil and
condensate ($ per bbl) (c) |
$ |
55.46 |
|
$ |
46.65 |
|
$ |
45.89 |
|
$ |
49.35 |
|
$ |
38.57 |
|
Oklahoma |
53.90 |
|
46.39 |
|
46.30 |
|
48.79 |
|
41.78 |
|
Eagle
Ford |
57.82 |
|
47.56 |
|
45.96 |
|
49.93 |
|
38.76 |
|
Bakken |
54.42 |
|
46.06 |
|
46.28 |
|
49.28 |
|
39.25 |
|
Northern
Delaware |
53.74 |
|
44.49 |
|
— |
|
48.84 |
|
— |
|
Other
United States (b) |
48.87 |
|
45.83 |
|
43.78 |
|
46.98 |
|
34.93 |
|
Natural gas
liquids ($ per bbl) |
$ |
23.60 |
|
$ |
20.86 |
|
$ |
17.31 |
|
$ |
20.55 |
|
$ |
13.15 |
|
Oklahoma |
24.16 |
|
23.58 |
|
20.79 |
|
22.74 |
|
15.84 |
|
Eagle
Ford |
22.54 |
|
19.52 |
|
16.34 |
|
19.32 |
|
12.40 |
|
Bakken |
24.09 |
|
17.89 |
|
11.97 |
|
18.38 |
|
8.56 |
|
Northern
Delaware |
26.79 |
|
30.23 |
|
— |
|
24.04 |
|
— |
|
Other
United States (b) |
30.06 |
|
24.94 |
|
24.56 |
|
24.61 |
|
23.51 |
|
Natural gas ($
per mcf) (d) |
$ |
2.65 |
|
$ |
2.71 |
|
$ |
2.87 |
|
$ |
2.84 |
|
$ |
2.38 |
|
Oklahoma |
2.54 |
|
2.69 |
|
2.90 |
|
2.82 |
|
2.47 |
|
Eagle
Ford |
2.82 |
|
2.83 |
|
2.91 |
|
2.89 |
|
2.37 |
|
Bakken |
2.82 |
|
2.08 |
|
2.63 |
|
2.80 |
|
2.12 |
|
Northern
Delaware |
2.37 |
|
3.00 |
|
— |
|
2.70 |
|
— |
|
Other United States (b) |
2.56 |
|
2.67 |
|
2.82 |
|
2.82 |
|
2.38 |
|
International
E&P - average price realizations |
|
|
|
|
|
Liquid
hydrocarbons ($ per bbl) |
$ |
51.13 |
|
$ |
43.69 |
|
$ |
37.85 |
|
$ |
43.36 |
|
$ |
32.10 |
|
Equatorial Guinea |
33.56 |
|
32.78 |
|
26.60 |
|
29.62 |
|
25.78 |
|
Libya |
68.31 |
|
56.93 |
|
57.69 |
|
60.72 |
|
57.69 |
|
United
Kingdom |
59.11 |
|
51.12 |
|
45.02 |
|
53.52 |
|
42.52 |
|
Other
International |
48.89 |
|
40.67 |
|
— |
|
44.73 |
|
— |
|
Crude oil and
condensate ($ per bbl) |
$ |
61.32 |
|
$ |
51.23 |
|
$ |
46.14 |
|
$ |
53.05 |
|
$ |
41.70 |
|
Equatorial Guinea |
52.92 |
|
46.91 |
|
41.60 |
|
46.02 |
|
38.85 |
|
Libya |
68.31 |
|
56.93 |
|
57.69 |
|
60.72 |
|
57.69 |
|
United
Kingdom |
61.94 |
|
51.72 |
|
45.18 |
|
54.51 |
|
43.21 |
|
Other
International |
48.89 |
|
40.67 |
|
— |
|
44.73 |
|
— |
|
Natural gas
liquids ($ per bbl) |
$ |
4.66 |
|
$ |
2.25 |
|
$ |
1.72 |
|
$ |
3.15 |
|
$ |
2.11 |
|
Equatorial Guinea (e) |
1.00 |
|
1.00 |
|
1.00 |
|
1.00 |
|
1.00 |
|
United
Kingdom |
45.71 |
|
32.58 |
|
32.58 |
|
39.65 |
|
26.41 |
|
Natural gas ($
per mcf) |
$ |
0.59 |
|
$ |
0.51 |
|
$ |
0.53 |
|
$ |
0.55 |
|
$ |
0.52 |
|
Equatorial Guinea (e) |
0.24 |
|
0.24 |
|
0.24 |
|
0.24 |
|
0.24 |
|
Libya |
5.03 |
|
— |
|
— |
|
5.03 |
|
— |
|
United Kingdom |
7.20 |
|
5.71 |
|
5.39 |
|
6.28 |
|
4.80 |
|
Benchmark |
|
|
|
|
|
WTI crude
oil (per bbl) |
$ |
55.30 |
|
$ |
48.20 |
|
$ |
49.29 |
|
$ |
50.85 |
|
$ |
43.47 |
|
Brent
(Europe) crude oil (per bbl)(f) |
$ |
61.53 |
|
$ |
52.11 |
|
$ |
49.19 |
|
$ |
54.25 |
|
$ |
43.55 |
|
Henry Hub natural gas (per mmbtu)(g) |
$ |
2.93 |
|
$ |
3.00 |
|
$ |
2.98 |
|
$ |
3.11 |
|
$ |
2.46 |
|
(a)
Excludes gains or losses on derivative instruments.(b) Includes
production from conventional onshore assets sold in the applicable
periods. The sale of certain Oklahoma and Colorado assets closed in
September 2017 and October 2017, respectively. The sales of certain
Wyoming assets closed in 2016.(c) Inclusion of crude oil derivative
instruments would have affected liquid hydrocarbons average price
realizations by a realized loss of $0.76, and realized gains of
$2.42, $0.32, $0.75, $0.92, for the fourth and third quarter of
2017, fourth quarter of 2016, and the years 2017 and 2016,
respectively.(d) Inclusion of realized gains (losses) on natural
gas derivative instruments would have a minimal impact on average
price realizations for the periods presented.(e) Represents
fixed prices under long-term contracts with Alba Plant LLC,
Atlantic Methanol Production Company LLC and/or Equatorial Guinea
LNG Holdings Limited, which are equity method investees. The Alba
Plant LLC processes the NGLs and then sells secondary condensate,
propane, and butane at market prices. Marathon Oil includes its
share of income from each of these equity method investees in the
International E&P segment.(f) Average of monthly prices
obtained from Energy Information Administration ("EIA") website.(g)
Settlement date average per mmbtu. |
|
|
|
|
Estimated Net Proved Reserves from Continuing
Operations (mmboe) |
U.S E&P |
Intl. E&P |
Total |
As of Dec. 31,
2016 |
948 |
|
456 |
|
1,404 |
|
Additions |
98 |
|
18 |
|
116 |
|
Revisions |
42 |
|
7 |
|
49 |
|
Acquisitions |
28 |
|
— |
|
28 |
|
Dispositions |
(10 |
) |
— |
|
(10 |
) |
Production |
(86 |
) |
(52 |
) |
(138 |
) |
As of Dec. 31,
2017 |
1,020 |
|
429 |
|
1,449 |
|
|
|
|
|
Changes in Reserves
(excluding dispositions) (mmboe) |
|
|
193 |
|
Production (mmboe) |
|
|
138 |
|
Reserve Replacement
Ratio (excluding dispositions) (a) |
|
|
140 |
% |
|
|
|
|
Organic Changes in
Reserves (excluding acquisitions, dispositions) (mmboe) |
|
|
165 |
|
Production (mmboe) |
|
|
136 |
|
Organic Reserve
Replacement Ratio (excluding acquisitions, dispositions) (a) |
|
|
121 |
% |
|
|
|
|
Finding Costs ($ in millions, except as
indicated) |
|
|
2017 |
Property Acquisition
Costs - Proved |
|
|
$ |
192 |
|
Property Acquisition
Costs - Unproved |
|
|
1,747 |
|
Exploration |
|
|
923 |
|
Development |
|
|
993 |
|
Total Company -
Costs Incurred from Continuing Operations |
|
|
$ |
3,855 |
|
|
|
|
|
Cost Incurred |
|
|
$ |
3,855 |
|
Changes
in Reserves (excluding dispositions) (mmboe) |
|
|
193 |
|
Finding and
development costs per BOE |
|
|
$ |
19.97 |
|
|
|
|
|
Costs Incurred |
|
|
$ |
3,855 |
|
Property Acquisition
Costs |
|
|
(1,939 |
) |
Capitalized Asset Retirement Costs |
|
|
197 |
|
Adjusted
finding and development costs (a) |
|
|
$ |
2,113 |
|
Organic
Changes in Reserves (excluding acquisitions, dispositions)
(mmboe) |
|
|
165 |
|
Adjusted finding and development costs per BOE
(a) |
|
|
$ |
12.81 |
|
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above
for further discussion. |
The following tables set forth outstanding derivative contracts
as of February 12, 2018 and the weighted average prices for those
contracts:
Crude Oil |
|
|
2018 |
|
|
|
2019 |
|
(unaudited) |
FirstQuarter |
|
SecondQuarter |
|
ThirdQuarter |
|
FourthQuarter |
|
FirstQuarter |
|
SecondQuarter |
|
ThirdQuarter |
|
FourthQuarter |
Three-Way Collars (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day) |
|
85,000 |
|
|
|
85,000 |
|
|
|
95,000 |
|
|
|
95,000 |
|
|
|
30,000 |
|
|
|
30,000 |
|
|
|
— |
|
|
|
— |
|
Weighted
average price per Bbl: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling |
$ |
56.38 |
|
|
$ |
56.38 |
|
|
$ |
57.65 |
|
|
$ |
57.65 |
|
|
$ |
65.27 |
|
|
$ |
65.27 |
|
|
$ |
— |
|
|
$ |
— |
|
Floor |
$ |
51.65 |
|
|
$ |
51.65 |
|
|
$ |
52.11 |
|
|
$ |
52.11 |
|
|
$ |
54.00 |
|
|
$ |
54.00 |
|
|
$ |
— |
|
|
$ |
— |
|
Sold
put |
$ |
45.00 |
|
|
$ |
45.00 |
|
|
$ |
45.21 |
|
|
$ |
45.21 |
|
|
$ |
46.67 |
|
|
$ |
46.67 |
|
|
$ |
— |
|
|
$ |
— |
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day) |
|
20,000 |
|
|
|
20,000 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Weighted
average price per Bbl |
$ |
55.12 |
|
|
$ |
55.12 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Basis Swaps (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(Bbls/day) |
|
5,000 |
|
|
|
5,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
Weighted average price per Bbl |
$ |
(0.60 |
) |
|
$ |
(0.60 |
) |
|
$ |
(0.67 |
) |
|
$ |
(0.67 |
) |
|
$ |
(0.82 |
) |
|
$ |
(0.82 |
) |
|
$ |
(0.82 |
) |
|
$ |
(0.82 |
) |
(a) Includes contracts we entered into between January 1, 2018
and February 12, 2018, of 10,000 Bbls/day of three-way collars for
July - December 2018 with an average ceiling price of $63.51, a
floor price of $57.00, and a sold put price of $50.00 and 20,000
Bbls/day of three-way collars for January - June 2019 with an
average ceiling price of $67.92, a floor price of $53.50, and a
sold put price of $46.50.(b) The basis differential price is
between WTI Midland and WTI Cushing. We entered into 10,000
Bbls/day of basis swaps for 2019 subsequent to December 31,
2017. |
Natural Gas |
|
|
2018 |
|
First Quarter |
SecondQuarter |
ThirdQuarter |
FourthQuarter |
Three-Way Collars |
|
|
|
|
Volume
(MMBtu/day) |
|
200,000 |
|
160,000 |
|
160,000 |
|
160,000 |
Weighted
average price per MMBtu |
|
|
|
|
Ceiling |
$ |
3.79 |
$ |
3.61 |
$ |
3.61 |
$ |
3.61 |
Floor |
$ |
3.08 |
$ |
3.00 |
$ |
3.00 |
$ |
3.00 |
Sold put |
$ |
2.55 |
$ |
2.50 |
$ |
2.50 |
$ |
2.50 |
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