Le Lézard
Classified in: Oil industry, Business
Subjects: ERN, CCA

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.

(PRNewsfoto/Marathon Oil Corporation)

2019 Capital Budget Highlights

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

"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

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 Statistics (Unaudited)

Three Months Ended

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

Production Guidance

Oil Production (mbbld)


Equivalent Production (mboed)

2019

2018


2019

2018


Low

High

Divestiture-Adjusted (a)


Low

High

Divestiture-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

Production Guidance

Oil Production (mbbld)


Equivalent Production (mboed)

Q1 2019

Q4 2018

Q1 2018


Q1 2019

Q4 2018

Q1 2018


Low

High

Divestiture-Adjusted (a)

Divestiture-Adjusted (a)


Low

High

Divestiture-Adjusted (a)

Divestiture-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).

 

 

SOURCE Marathon Oil Corporation


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