Marathon Oil Announces $2.4 Billion Development Capital Budget for 2019; Reports Fourth Quarter and Full-Year 2018 Results
HOUSTON, Feb. 13, 2019 /PRNewswire/ -- Marathon Oil Corporation (NYSE:MRO) today announced its 2019 capital expenditure budget in addition to its fourth quarter and full-year 2018 financial results. The 2019 plan and 2018 financial and operating results together reflect the Company's ongoing commitment to its core strategy: corporate returns improvement, sustainable free cash flow generation at conservative oil prices, and the return of capital to shareholders.
2019 Capital Budget Highlights
-- Total 2019 capital budget of $2.6 billion, down from 2018
-- Total capital budget includes approx. $2.4 billion of development
capital and approx. $200 million of resource play leasing and
exploration (REx) spend
-- Organic free cash flow positive above approx. $45/bbl WTI,
post-dividend
-- Designed to generate meaningful organic free cash flow at $50/bbl
WTI, post-dividend
-- Cumulative two-year (2019-2020) organic free cash flow of over $750
million at flat $50/bbl WTI and over $2.2 billion at flat $60/bbl WTI
-- Continue to prioritize sustainable free cash flow and return of
capital to shareholders
-- Shareholder return of capital metric incorporated into executive
compensation scorecard complementing already well-established
corporate cash return on invested capital (CROIC) and cash flow per
debt adjusted share (CFPDAS) metrics
-- Capital efficient U.S. oil growth of 12% in 2019 with annual gross
operated wells to sales flat to 2018
-- Total Company oil growth of 10% in 2019
-- High value oil growth exceeds BOE growth, an outcome of
returns-first capital allocation
-- More than 95% of $2.4 billion development capital budget allocated to
the four U.S. resource plays with approx. 60% to the Eagle Ford and
Bakken and approx. 40% to Oklahoma and the Northern Delaware
-- Continues underlying rate of change improvement in key enterprise
financial performance metrics of CROIC and CFPDAS
-- Development capital includes dedicated funding to organic resource
base enhancement initiatives including core extension efforts
-- REx spend is expected to decline to a more ratable $200 million,
supporting progression of Louisiana Austin Chalk and other emerging
opportunities with a focus on full-cycle returns
Full-year 2018 Results
Marathon Oil reported full-year 2018 net income of $1,096 million, or $1.29 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 $601 million, or $0.71 per diluted share. Net operating cash flow was $3,234 million, or $3,211 million before changes in working capital.
Full-year 2018 Highlights
-- Delivered on commitment to capital discipline with no change to initial
$2.3 billion development capital budget
-- Realized 78% annual improvement in CROIC and 65% annual improvement in
CFPDAS
-- Generated more than $865 million of organic free cash flow,
post-dividend
-- Prioritized return of capital to shareholders by paying annual dividend
of $169 million and executing $700 million of share repurchases, leaving
$800 million of remaining repurchase authorization; over 25% of 2018 net
operating cash flow returned to shareholders
-- Improvement in capital efficiency drove oil production outperformance;
total Company oil production growth of 24%, divestiture adjusted,
outperformed initial midpoint guidance of 18%; U.S. resource play oil
production growth of 32% outperformed initial midpoint guidance of 22.5%
-- Maintained focus on resource base enhancement and full-cycle returns by
advancing successful core extension tests in Eagle Ford and Bakken and
progressing REx program; acquired approx. 260,000 net acres at less than
$850 per acre in the emerging Louisiana Austin Chalk play
-- Continued portfolio management with successful sale of Libya and receipt
of final payment for the sale of oil sands mining business; disposition
proceeds more than fully funded REx and all other resource capture
activities, including successful participation in the New Mexico Bureau
of Land Management (BLM) lease sale
-- Drillbit F&D costs of less than $12.50/boe at 125% reserve replacement
-- Further strengthened balance sheet and financial flexibility by
increasing cash and cash equivalents by $900 million to $1.5 billion at
year-end
"2018 was a year of differentiated execution for Marathon Oil," said Chairman, President and CEO Lee Tillman. "While many in our industry talked about capital discipline, we delivered. In 2018, we budgeted conservatively and never wavered, getting more for every dollar of capital we invested. We drove significant improvement to our corporate returns and cash flow per debt adjusted share. Through improving capital efficiency we delivered more oil growth, generated $865 million of organic free cash flow post-dividend, and returned most of that cash back to our shareholders via share repurchases. As we turn to 2019 and beyond, we remain committed to this same framework for success. With the foundation of a peer leading balance sheet and the competitive advantages of our multi-basin portfolio, our 2019 capital program will drive improving corporate returns and generate organic free cash flow above $45 WTI, as we continue to prioritize return of cash to our shareholders."
Fourth Quarter 2018 Results
Marathon Oil reported fourth quarter 2018 net income of $390 million, or $0.47 per diluted share. Adjusted net income was $121 million, or $0.15 per diluted share. Net operating cash flow was $855 million, or $787 million before changes in working capital.
Fourth Quarter 2018 Highlights
-- Generated more than $255 million of organic free cash flow,
post-dividend
-- Development capital spend at $503 million, down 10% sequentially
-- Total Company production averaged 411,000 net boed; total oil production
averaged 206,000 net bopd, up 17% from the year-ago quarter, divestiture
adjusted
-- U.S. resource play production averaged 295,000 net boed; oil production
averaged 174,000 net bopd, up 22% from the year-ago quarter
-- Eagle Ford production averaged 107,000 net boed; 38 wells achieved an
average 30-day IP rate of 1,810 boed (72% oil)
-- Bakken production averaged 94,000 net boed; core extension test in Ajax
area of Dunn County meaningfully exceeded expectations with four-well
pad achieving an average 30-day IP rate of 2,370 boed (81% oil) at an
average completed well cost of approx. $5 million
-- Oklahoma production averaged 67,000 net boed; transition to multi-well
pads continued with another successful SCOOP Woodford infill development
that also included a positive Springer delineation test
-- Northern Delaware production increased to 26,000 net boed; 12 gross
Company-operated wells to sales with an average 30-day IP rate of 1,935
boed (49% oil)
U.S.
U.S. production averaged 306,000 net barrels of oil equivalent per day (boed) for fourth quarter 2018, including oil production of 180,000 net barrels of oil per day (bopd). Oil production was up 4 percent compared to the prior quarter and up 22 percent from the year-ago quarter on a divestiture-adjusted basis. Fourth quarter production from the U.S. resource plays was 295,000 net boed, including oil production of 174,000 net bopd. Fourth quarter U.S. unit production costs were $5.31 per barrel of oil equivalent (boe), a sequential reduction of 14 percent.
EAGLE FORD: Marathon Oil's Eagle Ford production averaged 107,000 net boed in the fourth quarter, up 2 percent from the year-ago quarter. The Company brought 38 gross Company-operated wells to sales in the quarter with an average 30-day initial production (IP) rate of 1,810 boed (72% oil).
BAKKEN: In fourth quarter 2018, Marathon Oil's Bakken production averaged 94,000 net boed, up 37 percent from the year-ago quarter. Oil production was up over 40 percent from the year-ago quarter. The Company brought 27 gross Company-operated wells to sales with an average 30-day IP rate of 3,335 boed (76% oil), with activity primarily concentrated in Myrmidon. The Company also conducted a successful core extension test in the Ajax area of Dunn County, as the four-well Gloria pad achieved an average 30-day IP rate of 2,370 boed (81% oil) at an average completed well cost of approx. $5 million.
OKLAHOMA: Marathon Oil's Oklahoma production averaged 67,000 net boed during fourth quarter 2018, up 4 percent from the year-ago quarter, with only 12 gross Company-operated wells brought to sales. In the SCOOP Woodford, seven infill wells on the 3R pad (eight wells per section spacing) achieved an average 30-day IP rate of 2,600 boed (69% liquids). On the same pad, Marathon Oil also brought online a Springer delineation well that achieved a 30-day IP rate of 1,825 boed (81% oil).
NORTHERN DELAWARE: Marathon Oil's Northern Delaware production increased to an average of 26,000 net boed in fourth quarter 2018, up 138 percent from the year-ago quarter. The Company brought 12 gross Company-operated wells to sales in the Malaga and Red Hills areas with an average 30-day IP rate of 1,935 boed (49% oil), or 360 boed per 1,000 foot lateral. Fourth quarter activity was primarily focused on delineating the Company's acreage position, including Lower Wolfcamp spacing tests in Malaga. During the fourth quarter, the Company executed a comprehensive water management agreement covering the entire Red Hills prospect area, complementing a previously announced agreement in Eddy County.
RESOURCE CAPTURE: Outside of the development capital program, fourth quarter REx capital spending totaled $75 million, consistent with guidance, and bringing full-year 2018 REx spending to $369 million. In addition to REx, full-year 2018 resource capture also included the previously announced $105 million bolt-on acquisition in New Mexico through the BLM lease sale. Total 2018 resource capture spend of $474 million was more than fully funded through divestiture proceeds received in first quarter 2018.
International
International production averaged 105,000 net boed for fourth quarter 2018, down 13 percent compared to the year-ago quarter on a divestiture-adjusted basis. The decrease reflects unscheduled downtime at the non-operated Foinaven complex as well as natural decline and planned maintenance activities in E.G. Fourth quarter 2018 International unit production costs averaged $5.40 per boe.
Production Guidance
For full year 2019, the Company forecasts total oil production growth of 10 percent, with U.S. oil growth of 12 percent, both at the midpoint of guidance and on a divestiture adjusted basis. Oil growth is expected to outpace boe production growth, consistent with a focus on corporate returns. For first quarter 2019, the Company forecasts total oil production of 195 - 215 bopd, with U.S. oil production of 175 - 185 bopd. The first quarter 2019 U.S. production guidance range accounts for extreme weather conditions experienced early in the quarter. The first quarter 2019 International production guidance range reflects a planned triennial shutdown in E.G. to conduct turnaround activity, consistent with prior disclosure. For more specific detail regarding 2019 production guidance, please refer to the guidance tables included within this release.
Corporate
The Company has executed $700 million of share repurchases, returning additional capital to shareholders beyond the $169 million annual dividend. Share repurchases were more than fully funded by organic free cash flow of over $865 million post-dividend.
Total liquidity as of Dec. 31 was approximately $4.9 billion, which consisted of $1.5 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion which was extended by one year to 2022.
The adjustments to net income for fourth quarter 2018 totaled $256 million before tax, primarily due to the income impact associated with unrealized gains on derivative instruments, partially offset by a write off related to historical International exploration expenses and associated well costs.
For 2019, the Company's open crude hedge positions (as of Feb 12) include an average of 60,000 bopd at a weighted average floor price of $56.67 and a weighted average ceiling price of $73.18, hedged through three-way collars.
Reserves
During 2018, Marathon Oil added proved reserves of 186 million boe for a reserve replacement ratio of 125 percent excluding dispositions, at a drillbit finding and development (F&D) cost of $12.41. Virtually all of the additions were in the U.S. Net proved reserves were approximately 1.28 billion boe at year-end 2018, down from year-end 2017 primarily due to the disposition of Libya.
A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, Feb. 13. On Thursday, Feb. 14, at 9:00 a.m. ET, the Company will conduct a question and answer webcast/call, which will include forward-looking information. The live webcast, replay and all related materials will be available at https://www.marathonoil.com/Investors.
Definitions
CROIC - Cash return on invested capital; calculated by taking cash flow (operating cash flow before working capital + net interest after tax) divided by (average stockholder's equity + average net debt).
Free cash flow - Operating cash flow, less capital expenditure, less dividends, plus other.
Organic free cash flow - Operating cash flow before working capital (excluding exploration costs other than well costs), less development capital expenditures, less dividends, plus other.
Non-GAAP Measures
In analyzing and planning for its business, Marathon Oil supplements its use of GAAP financial measures with non-GAAP financial measures, including adjusted net income (loss), adjusted net income (loss) per share, net cash provided by continuing operations before changes in working capital, 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 2019 capital budget and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production guidance, cash margins, rates of change for CROIC and CFPDAS, asset sales and acquisitions, leasing and exploration activities, production, oil growth and other plans and objectives for future operations, are forward-looking statements. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," "may," "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
Year Ended
Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
(In millions, except per share data) 2018 2018 2017 2018 2017
---
Revenues and other income:
Revenues from contracts with customers $
1,380 $
1,538 $
1,336 $
5,902 $
4,247
Net gain (loss) on commodity derivatives 310 (70) (151) (14) (36)
Marketing revenues 45 162
Income from equity method investments 64 64 73 225 256
Net gain (loss) on disposal of assets (4) 16 32 319 58
Other income 15 119 47 150 78
Total revenues and other income 1,765 1,667 1,382 6,582 4,765
Costs and expenses:
Production 205 215 188 842 716
Marketing, including purchases from related parties 47 168
Shipping, handling and other operating 167 152 122 575 431
Exploration 116 56 57 289 409
Depreciation, depletion and amortization 613 626 583 2,441 2,372
Impairments 25 8 24 75 229
Taxes other than income 84 86 55 299 183
General and administrative 88 101 95 394 371
Total costs and expenses 1,298 1,244 1,171 4,915 4,879
Income (loss) from operations 467 423 211 1,667 (114)
Net interest and other (58) (58) (71) (226) (270)
Other net periodic benefit costs (3) (8) (3) (14) (19)
Loss on early extinguishment of debt (5) (51)
Income (loss) from continuing operations before income taxes 406 357 132 1,427 (454)
Provision (benefit) for income taxes 16 103 160 331 376
Income (loss) from continuing operations 390 254 (28) 1,096 (830)
Income (loss) from discontinued operations (a) (4,893)
Net income (loss) $
390 $
254 $
(28) $
1,096 $
(5,723)
Adjusted Net Income (Loss)
Income (loss) from continuing operations 390 254 (28) 1,096 (830)
Adjustments for special items from continuing operations (pre-tax):
Net (gain) loss on disposal of assets 4 (16) (32) (319) (57)
Proved property impairments 25 8 24 75 225
Exploratory dry well costs, unproved property impairments and other 40 40 250
Pension settlement 5 10 7 21 32
Unrealized (gain) loss on derivative instruments (336) (19) 145 (267) 81
Reduction of U.K. ARO estimated costs (113) (53) (121) (53)
Other 6 5 6 (2)
Provision (benefit) for income taxes related to special items from continuing operations (13) 76 (12) 70 (13)
Valuation allowance 41
Adjustments for special items (269) (54) 84 (495) 504
Adjusted income (loss) from continuing operations (a) $
121 $
200 $
56 $
601 $
(326)
Income (loss) from discontinued operations (b) (4,893)
Adjustments for special items from discontinued operations (pre-tax):
Canadian oil sands business impairment (b) 6,636
Net (gain) loss on disposition (b) 43
Provision (benefit) for income taxes related to special items from discontinued operations (b) (1,674)
Adjusted net income (loss) (a) $
121 $
200 $
56 $
601 $
(214)
---
Per diluted share:
Income (loss) from continuing operations $
0.47 $
0.30 $
(0.03) $
1.30 $
(0.97)
Net income (loss) $
0.47 $
0.30 $
(0.03) $
1.30 $
(6.73)
Adjusted income (loss) from continuing operations (a) $
0.15 $
0.24 $
0.07 $
0.71 $
(0.38)
Adjusted net income (loss) (a) $
0.15 $
0.24 $
0.07 $
0.71 $
(0.25)
Weighted average diluted shares 829 849 850 847 850
---
(a) The Company closed on its sale
of the Canadian oil sands
business in the second quarter
of 2017 which is reflected as
discontinued operations for the
year ended December 31, 2017.
(b) Non-GAAP financial measure. See
"Non-GAAP Measures" above for
further discussion.
Supplemental Statistics (Unaudited)
Three Months Ended Year Ended
Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
(In millions) 2018 2018 2017 2018 2017
---
Segment income (loss)
United States $
159 $
201 $
76 $
608 $
(148)
International 83 116 118 473 374
Segment income (loss) 242 317 194 1,081 226
Not allocated to segments 148 (63) (222) 15 (1,056)
Income (loss) from continuing operations 390 254 (28) 1,096 (830)
Income (loss) from discontinued operations (a) (4,893)
Net income (loss) $
390 $
254 $
(28) $
1,096 $
(5,723)
---
Exploration expenses
United States $
76 $
55 $
57 $
246 $
154
International 1 3 5
Segment exploration expenses 76 56 57 249 159
Not allocated to segments 40 40 250
Total $
116 $
56 $
57 $
289 $
409
---
Cash flows
Net cash provided by operating activities from continuing operations $
855 $
963 $
501 $
3,234 $
1,988
Minus: changes in working capital 68 103 (2) 23 (26)
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) $
787 $
860 $
611 $
3,211 $
2,122
Net cash provided by operating activities from discontinued operations (a)
$
$
$
$ $
141
Cash additions to property, plant and equipment $
(684) $
(769) $
(669) $
(2,753) $
(1,974)
---
(a) The Company closed on its sale
of the Canadian oil sands
business in the second quarter
of 2017 which is reflected as
discontinued operations for the
year ended December 31, 2017.
(b) Non-GAAP financial measure. See
"Non-GAAP Measures" above for
further discussion.
Supplemental Three Months
Statistics Ended
(Unaudited) Year Ended
(In
millions) Dec. 31, 2018 Dec. 31, 2018
---
Organic
Free
Cash
Flow
Net
cash
provided
by
operating
activities $
855 $
3,234
Minus:
changes
in
working
capital 68 23
Minus:
exploration
costs
other
than
well
costs (5) (34)
Development
capital
expenditures (503) (2,286)
Dividends (41) (169)
EG
LNG
return
of
capital
and
other 9 78
Organic
free
cash
flow
(a) $
257 $
868
---
(a) Non-GAAP financial measure.
See "Non-GAAP Measures"
above for further
discussion.
Supplemental
Statistics
(Unaudited) Three Months Ended Year Ended
Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
(mboed) 2018 2018 2017 2018 2017
---
Net production
United States 306 304 262 298 235
International,
excluding Libya (a) 105 115 121 114 123
Total net production
from continuing
operations,
excluding Libya (a) 411 419 383 412 358
Libya (a) 33 7 19
Total net production
from continuing
operations 411 419 416 419 377
---
(a) The Company closed on the
sale of its Libya
subsidiary in the first
quarter 2018.
Supplemental
Statistics
(Unaudited) Three Months Ended Year Ended
Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
(mboed) 2018 2018 2017 2018 2017
---
Net production
United States 306 304 262 298 235
Less: Divestitures
(a) 1 4 3 8
Total divestiture-
adjusted United
States 306 303 258 295 227
International 105 115 154 121 142
Less: Divestitures
(b) 1 35 8 20
Total divestiture-
adjusted
International 105 114 119 113 122
Total net production
divestiture-
adjusted (a)(b) 411 417 377 408 349
Discontinued
operations (c) 18
---
(a) The Company closed on the sale
of certain United States non-
core conventional assets
primarily in the Gulf of Mexico
in the third quarter of 2018,
Oklahoma and Colorado in the
third quarter of 2017. These
production volumes have been
removed from all historical
periods shown in arriving at
total divestiture-adjusted
United States net production.
(b) The Company closed on the sale
of its Libya subsidiary in the
first quarter 2018.
Additionally, divestitures
include the sale of certain
non-core International assets
which closed in the third
quarter of 2018. These
production volumes have been
removed from all historical
periods shown in arriving at
total divestiture-adjusted
International net production.
(c) The Company closed on its sale
of the Canadian oil sands
business in the second quarter
of 2017 which is reflected as
discontinued operations for the
year ended December 31, 2017.
Supplemental Statistics
(Unaudited) Three Months Ended Year Ended
Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
2018 2018 2017 2018 2017
United States -net sales
volumes
Crude oil and condensate
(mbbld) 180 173 150 171 133
Eagle Ford 62 66 61 63 59
Bakken 82 72 58 71 46
Oklahoma 16 18 16 18 15
Northern Delaware 14 12 8 12 4
Other United States (a) 6 5 7 7 9
Natural gas liquids
(mbbld) 55 58 49 55 43
Eagle Ford 24 26 23 23 21
Bakken 6 6 6 7 6
Oklahoma 19 21 18 20 14
Northern Delaware 5 4 1 4 1
Other United States (a) 1 1 1 1 1
Natural gas (mmcfd) 422 433 376 429 348
Eagle Ford 127 137 127 129 125
Bakken 35 36 26 35 25
Oklahoma 192 208 180 213 149
Northern Delaware 42 30 14 26 9
Other United States (a) 26 22 29 26 40
Total United States
(mboed) 305 303 262 298 234
---
International -net sales
volumes
Crude oil and condensate
(mbbld) 29 27 58 39 52
Equatorial Guinea 16 18 20 17 21
United Kingdom 10 6 5 11 10
Libya (b) 29 7 19
Other International 3 3 4 4 2
Natural gas liquids
(mbbld) 10 11 13 11 12
Equatorial Guinea 10 11 12 11 11
United Kingdom 1 1
Natural gas (mmcfd) 411 441 493 435 485
Equatorial Guinea 400 426 464 416 459
United Kingdom (c) 11 15 15 14 22
Libya (b) 14 5 4
Total International
(mboed) 108 112 153 122 145
Total Company -net sales
volumes (mboed) 413 415 415 420 379
---
Net sales volumes of
equity method investees
LNG (mtd) 5,384 6,152 6,353 5,805 6,423
Methanol (mtd) 1,119 1,334 1,637 1,241 1,374
Condensate and LPG (boed) 15,071 11,942 14,605 13,034 14,501
---
(a) Includes sales volumes from the
sale of certain United States
non-core conventional assets
primarily in the Gulf of Mexico
in the third quarter of 2018,
Oklahoma and Colorado in the
third quarter of 2017,
respectively.
(b) The Company closed on the sale
of its Libya subsidiary in the
first quarter 2018.
(c) Includes natural gas acquired
for injection and subsequent
resale.
Supplemental Statistics (Unaudited)
Three Months Ended Year Ended
Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
2018 2018 2017 2018 2017
United States - average price realizations (a)
Crude oil and condensate ($ per bbl) (b) $
56.01 $
68.51 $
55.46 $
63.11 $
49.35
Eagle Ford 63.27 72.00 57.82 67.19 49.93
Bakken 51.11 67.26 54.42 60.39 49.28
Oklahoma 58.42 70.14 53.90 64.63 48.79
Northern Delaware 48.04 55.01 53.74 55.23 48.84
Other United States (c) 60.41 66.67 48.87 63.11 46.98
Natural gas liquids ($ per bbl) $
24.71 $
28.07 $
23.60 $
24.54 $
20.55
Eagle Ford 21.46 28.62 22.54 24.08 19.32
Bakken 19.01 31.92 24.09 24.98 18.38
Oklahoma 29.55 25.29 24.16 24.38 22.74
Northern Delaware 28.99 31.44 26.79 26.30 24.04
Other United States (c) 26.68 34.71 30.06 28.63 24.61
Natural gas ($ per mcf) (d) $
3.27 $
2.55 $
2.65 $
2.65 $
2.84
Eagle Ford 3.69 2.84 2.82 3.09 2.89
Bakken 3.46 2.64 2.82 2.95 2.80
Oklahoma 3.22 2.40 2.54 2.38 2.82
Northern Delaware 1.80 2.24 2.37 2.08 2.70
Other United States (c) 3.65 2.48 2.56 2.73 2.82
---
International - average price realizations
Crude oil and condensate ($ per bbl) $
58.25 $
64.08 $
61.32 $
64.25 $
53.05
Equatorial Guinea 46.35 61.23 52.92 55.28 46.02
United Kingdom 78.49 73.28 61.94 74.34 54.51
Libya (e) 68.31 73.75 60.72
Other International 52.52 62.30 48.89 58.89 44.73
Natural gas liquids ($ per bbl) $
2.25 $
2.04 $
4.66 $
2.27 $
3.15
Equatorial Guinea (f) 1.00 1.00 1.00 1.00 1.00
United Kingdom 33.44 50.37 45.71 41.66 39.65
Natural gas ($ per mcf) $
0.49 $
0.50 $
0.59 $
0.54 $
0.55
Equatorial Guinea (f) 0.24 0.24 0.24 0.24 0.24
United Kingdom 9.13 8.60 7.20 8.03 6.28
Libya (e) 5.03 4.57 5.03
---
Benchmark
WTI crude oil (per bbl) $
59.34 $
69.43 $
55.30 $
64.90 $
50.85
Brent (Europe) crude oil (per bbl)(g) $
67.71 $
75.22 $
61.53 $
71.06 $
54.25
Henry Hub natural gas (per mmbtu)(h) $
3.64 $
2.90 $
2.93 $
3.09 $
3.11
---
(a) Excludes gains or losses on
commodity derivative instruments.
(b) Inclusion of realized gains
(losses) on crude oil derivative
instruments would have affected
average price realizations by
$(1.50), $(5.70), $(0.76), $(4.60)
and $0.75 for the fourth and third
quarters of 2018, the fourth
quarter of 2017, and the years
2018 and 2017, respectively.
(c) Includes sales volumes from the
sale of certain United States non-
core conventional assets primarily
in the Gulf of Mexico in the third
quarter of 2018, Oklahoma and
Colorado in the third quarter of
2017, respectively.
(d) Inclusion of realized gains
(losses) on natural gas derivative
instruments would have a minimal
impact on average price
realizations for the periods
presented.
(e) The Company closed on the sale of
its Libya subsidiary in the first
quarter 2018.
(f) Represents fixed prices under long-
term contracts with Alba Plant
LLC, Atlantic Methanol Production
Company LLC and/or Equatorial
Guinea LNG Holdings Limited, which
are equity method investees. The
Alba Plant LLC processes the NGLs
and then sells secondary
condensate, propane, and butane at
market prices. Marathon Oil
includes its share of income from
each of these equity method
investees in the International
segment.
(g) Average of monthly prices obtained
from Energy Information
Administration website.
(h) Settlement date average per mmbtu.
Full-Year 2019 Oil Production (mbbld) Equivalent Production (mboed)
Production Guidance
---
2019 2018 2019 2018
---
Low High Divestiture- Low High Divestiture-
Adjusted (a) Adjusted (a)
Net production
United States 185 195 169 320 330 295
International 20 30 27 90 100 110
Total net production 205 225 196 410 430 405
---
(a) Divestiture-adjusted also
removes volumes associated
with Atrush which is treated
as held for sale.
Q1 2019 Oil Production (mbbld) Equivalent Production (mboed)
Production Guidance
---
Q1 2019 Q4 2018 Q1 2018 Q1 2019 Q4 2018 Q1 2018
---
Low High Divestiture- Divestiture- Low High Divestiture- Divestiture-
Adjusted (a) Adjusted (a) Adjusted (a) Adjusted (a)
Net production
United States 175 185 180 160 295 305 306 278
International 20 30 23 30 85 95 102 110
Total net production 195 215 203 190 380 400 408 388
---
(a) Divestiture-adjusted also
removes volumes associated
with Atrush which is treated
as held for sale.
Estimated Net Proved Reserves from Continuing Operations (mmboe) U.S Int'l Total
---
As of December 31, 2017 1,020 429 1,449
Additions 100 2 102
Revisions 71 13 84
Acquisitions
Dispositions (4) (197) (201)
Production (109) (44) (153)
As of December 31, 2018 1,078 203 1,281
Organic Changes in Reserves (excluding dispositions) (mmboe) 186
Production (excluding dispositions) (mmboe) (a) 149
---
Organic Reserve Replacement Ratio (excluding dispositions) 125
%
Finding Costs ($ in millions, except as indicated) 2018
---
Property Acquisition Costs - Proved $
222
Property Acquisition Costs - Unproved 144
Exploration 921
Development 1,204
---
Total Company - Costs Incurred $
2,491
Cost Incurred $
2,491
Organic Changes in Reserves (excluding dispositions) (mmboe) 186
---
Finding and Development Costs per BOE $
13.39
Costs Incurred $
2,491
Property Acquisition Costs (Proved and Unproved) (366)
Capitalized Asset Retirement Costs 183
---
Organic Finding and Development Costs $
2,308
Organic Changes in Reserves (excluding dispositions) (mmboe) 186
---
Organic Finding and Development Costs per BOE $
12.41
---
(a) Excludes approximately 4 mmboe
related to certain dispositions,
primarily the sale of our Libya
subsidiary in the first quarter
2018.
The following tables set forth outstanding derivative contracts as of February 12, 2019 and the weighted average prices for those contracts:
2019 2020
Crude Oil First Quarter Second Quarter Third Quarter Fourth Quarter Full Year
---
Three-Way Collars
Volume (Bbls/day) 70,000 70,000 50,000 50,000
Weighted average price
per Bbl:
Ceiling $71.21 $71.21 $75.88 $75.88
Floor $55.86 $55.86 $57.80 $57.80
Sold put $48.71 $48.71 $50.80 $50.80
Basis Swaps (a)(b)
Volume (Bbls/day) 10,000 11,000 16,000 16,000 15,000
Weighted average price
per Bbl $(0.82) $(1.06) $(1.53) $(1.53) $(0.94)
NYMEX Roll Basis Swaps
Volume (Bbls/day) 60,000 60,000 60,000 60,000
Weighted average price
per Bbl $0.38 $0.38 $0.38 $0.38
Natural Gas
---
Three-Way Collars
Volume (MMBtu/day) 200,000
Weighted average price
per MMBtu:
Ceiling $5.25
Floor $3.43
Sold put $2.88
---
(a) The basis differential price
is between WTI Midland and
WTI Cushing.
(b) Between January 1, 2019 and
February 12, 2019, the
Company entered into 5,000
Bbls/day of Midland basis
swaps for July -December
2019 with an average price
of $(2.55) and 1,000 Bbls/
day of Clearbrook basis
swaps for March -December
2019 with an average price
of $(3.50).
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SOURCE Marathon Oil Corporation
