News Releases

Marathon Oil Reports Second Quarter 2016 Results


Marathon Oil Corporation (NYSE:MRO) today reported a second quarter 2016 net loss of $170 million, or $0.20 per diluted share. The net loss includes the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. The adjusted net loss for the quarter was $196 million or $0.23 per diluted share.



  • Second quarter total Company production averaged 384,000 net boed in line with guidance; U.S. resource play production averaged 189,000 net boed
  • Strong Oklahoma well results including two Company-operated STACK Meramec XL wells with 30-day rates averaging 1,710 boed and 1,570 boed, both with higher than 70% oil cuts
  • Clarks Creek Middle Bakken well achieved average 30-day production of 2,840 boed; highest rate Williston basin well in the past three years
  • Reduced North America E&P production costs 5% below previous quarter and 28% below year-ago quarter; adjusting full-year guidance down $1.00 per boe
  • Eagle Ford completed well costs decreased to an average of $4.2 million while advancing higher intensity completions
  • Full-year capital program expected to be $1.3 billion inclusive of incremental capital requirements for Oklahoma STACK acquisition activity; $100 million lower than original budget
  • Over $1 billion in non-core asset sales in 2016; more than $800 million in proceeds already received
  • Announced and closed $888 million Oklahoma STACK acquisition of approximately 61,000 net surface acres
  • Achieved first gas from Equatorial Guinea Alba B3 compression project in July, on schedule and within budget


"Within six weeks of announcing our acquisition of high-quality assets in the STACK oil window, we've already closed the transaction and will accelerate an additional rig on this acreage in the third quarter while still decreasing our 2016 capital budget. This deal expands our inventory and further positions Marathon Oil for growth in Oklahoma at a competitive valuation. Coupled with recent non-core divestitures, we're delivering on our objective to further concentrate our capital allocation to the lower cost, higher margin U.S. resource plays," said Marathon OilPresident and CEO Lee Tillman. "In addition to successful portfolio management, we continued our relentless focus on reducing costs and driving durable operational efficiencies while delivering impressive new well results in the resource plays."

North America E&P
North America Exploration and Production (E&P) production available for sale averaged 224,000 net barrels of oil equivalent per day (boed) for second quarter 2016. On a divestiture-adjusted basis, production was down 6 percent from the prior quarter and 13 percent from the year-ago period. Second quarter North America production costs were 5 percent lower than the previous quarter and 28 percent lower than the year-ago period. On a per barrel basis, unit production costs were $6.28 per barrel of oil equivalent (boe), down 13 percent from the year-ago period and essentially flat with the prior period.


OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production averaged 27,000 net boed during second quarter 2016, flat to the prior quarter and up compared to 24,000 net boed in the year-ago quarter. During second quarter 2016, Marathon Oil brought online two gross Company-operated STACK Meramec extended lateral (XL) wells in the volatile oil window. The Irven John achieved a 30-day production rate of 1,710 boed (70 percent oil) and the Olive June averaged 1,570 boed (75 percent oil) over 30 days. Additionally, three SCOOP Woodford XL wells were brought online, with the Eubank well averaging 1,950 boed (30 percent oil) over 30 days.

The Company closed on the STACK acquisition on Aug. 1. Since announcing the acquisition, three additional Meramec wells -- Moeller, Blackjack and Post -- have reached 30 days of production with rates of 1,925 boed (51 percent oil), 1,365 boed (47 percent oil) and 780 boed (51 percent oil), respectively, and at an average completed well cost of approximately $4 millionMarathon Oil continues to operate the drilling rig on the acquired STACK acreage and will add one incremental rig late in the third quarter. This will bring consolidated drilling activity to four rigs in Oklahoma primarily focused in the STACK. The Company expects eight to 10 STACK Meramec wells to sales in the third quarter.

EAGLE FORD: In second quarter 2016, Marathon Oil's production in the Eagle Ford averaged 109,000 net boed, compared to 120,000 net boed in the prior quarter and 135,000 net boed in the year-ago quarter. The sequential production decrease was due to lower completion activity with 40 percent fewer gross operated wells brought to sales and reduced contribution from 2015 high-density pads drilled at tighter well spacing. During second quarter 2016, the Company brought 30 gross (21 net) operated wells to sales, of which 19 were lower Eagle Ford, three upper Eagle Ford and eight Austin Chalk, compared to 50 gross (32 net) wells to sales in the previous quarter. The Hollman six-well pad, an Austin Chalk and lower Eagle Ford co-development, was brought online with 30-day production rates averaging 1,055 to 2,020 boed (45-53 percent oil). Second quarter completed well costs were $4.2 million, down approximately 30 percent from the year-ago quarter. Wells were drilled at an average rate of 2,400 feet per day and an average spud-to-total depth of less than eight days.


BAKKEN: Marathon Oil averaged 53,000 net boed of production in the Bakken during second quarter 2016, compared to 57,000 net boed in the prior quarter and 61,000 net boed in the year-ago quarter as strong well productivity and high reliability continued supporting the base production. Four gross wells were brought to sales in the second quarter -- two Middle Bakken and two Three Forks -- all with higher intensity completions of 12 to 18 million pounds of proppant per well and about 45 stages per well. The Clarks Creek Middle Bakken well achieved a 30-day initial production rate of 2,840 boed (84 percent oil) making it the highest rate well in the Williston basin in the past three years. Additionally, the Juanita Middle Bakken well and the Charmaine well in the first bench of the Three Forks achieved 2,700 boed (84 percent oil) and 2,530 boed (84 percent oil), respectively, over 30 days. Despite the higher intensity completions, completed well costs averaged $6 millionper well.


GULF OF MEXICO: The outside-operated Gunflint oil development on Mississippi Canyon block 948 in the Gulf of Mexico achieved first production in July. The two-well field is ramping up and is expected to reach a minimum gross production of 20,000 boed with oil representing approximately 75 percent of the volumes produced. Marathon Oil holds an 18 percent working interest.


During third quarter 2016, Marathon Oil signed an agreement to terminate its Gulf of Mexico deepwater drilling rig contract. As a result, the Company expects to recognize a termination payment of $113 million in other operating expense in the quarter, which will be reported as a special item.


International E&P
International E&P production available for sale (excluding Libya) averaged 120,000 net boed for second quarter 2016, an increase of 20 percent compared to the prior quarter and up 11 percent compared to the year-ago quarter. The increase over the prior quarter was primarily a result of a full quarter of production in Equatorial Guinea, the resumption of production from Brae Alpha in the U.K., increased production efficiency at other Brae facilities and better reliability from Foinaven. Second quarter production costs (excluding Libya) were 17 percent lower than the year-ago quarter. On a per barrel basis, unit production costs (excluding Libya) were $4.34 per boe, a decrease of 25 percent compared to the year-ago quarter.


EQUATORIAL GUINEA: Production available for sale averaged 102,000 net boed in second quarter 2016 compared to 84,000 net boed in the previous quarter and 86,000 net boed in the year-ago quarter. Second quarter 2016 base production continued to benefit from last year's re-completion and development programs as well as the absence of downtime experienced in the previous and year-ago quarters. The Alba B3 compression project, designed to maintain the production plateau two additional years and extend field life up to eight years, was completed within budget and on schedule with first gas in early July. The B3 platform allows Marathon Oil to convert approximately 130 million boe of proved undeveloped reserves, more than doubling the Company's remaining proved developed reserve base in EG.


U.K.: Production available for sale averaged 18,000 net boed in second quarter 2016, compared to 16,000 net boed in the previous quarter and 22,000 net boed in the year-ago quarter. Second quarter 2016 benefited from resumption of normal operations at the Brae Alpha platform and better reliability from the outside-operated Foinaven field.


Oil Sands Mining
Oil Sands Mining (OSM) production available for sale for second quarter 2016 averaged 40,000 net barrels per day (bbld) compared to 49,000 net bbld in the prior quarter and 25,000 net bbld in the year-ago quarter. The decrease compared to first quarter 2016 was due in part to a 4,000 bbld impact from the temporary suspension of operations at the mines related to wildfire response efforts in May. In addition, planned maintenance activities at the expansion upgrader and the Jackpine mine were completed on schedule and on budget. Despite the referenced production impacts, second quarter production was within guidance as mining operations achieved record production levels in June. Operating expense per synthetic barrel (before royalties) was $39.00, an increase compared to the previous quarter due primarily to second quarter planned maintenance, currency effects and the impacts of downtime related to the wildfires.


Marathon Oil expects third quarter 2016 North America E&P production available for sale to average 200,000 to 210,000 net boed which reflects the divestment of the majority of the Wyoming assets, the inclusion of the STACK assets in Oklahoma acquired Aug. 1, and decline from the Eagle Ford high-density pads drilled in 2015. Third quarter International E&P production available for sale (excluding Libya) is expected to be within a range of 125,000 to 135,000 net boed. Considerable uncertainty remains around the timing of future production and sales levels from Libya, and Marathon Oil continues to exclude Libya volumes from its production forecasts. OSM synthetic crude oil production is expected to range from 45,000 to 50,000 net bbld.


The Company is adjusting its full-year 2016 E&P production guidance range resulting in a new range of 330,000 to 345,000 net boed, which reflects divestitures and acquisitions closed to date. OSM synthetic crude oil production guidance remains unchanged at 40,000 to 50,000 net bbld.


Full-year guidance for North America unit production costs is being adjusted down by $1.00 per boe to a range of $6.00 to $7.00 per boe. Full-year guidance for International unit production costs is being adjusted down by $0.50 per boe to a range of $4.50 to $5.50 per boe.


Additionally, the Company expects its full-year 2016 capital program to be $1.3 billion, or $100 million lower than the original budget, despite the inclusion of increased activity from the Oklahoma STACK acquisition.


Corporate and Special Items
Net cash provided by operating activities was $178 million during second quarter 2016, and net cash provided by operations before changes in working capital was $290 million. Cash additions to property, plant and equipment were $299 million in second quarter 2016. Total liquidity as of June 30 was $5.9 billion, which consists of $2.6 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.3 billion.


During the quarter, the Company announced the sale of Wyoming assets for proceeds of $870 million, before closing adjustments, of which approximately $690 million was received in the second quarter with the remaining assets expected to close before year end. The Company entered into separate agreements to sell its 10 percent working interest in the outside-operated Shenandoah in the Gulf of Mexico, assets in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds, before closing adjustments. During the quarter, it closed on certain of these asset sales and expects the remaining sales to close by year-end.


The adjustments to net loss for second quarter 2016 total $41 million before tax and largely consist of: a net gain on the sale of assets of $296 million; impairments associated with the decision to not drill remaining Gulf of Mexico undeveloped leases of $141 million; a pension settlement of $31 million; and an unrealized loss on commodity derivatives of $91 million.


The Company's webcast commentary and associated slides related to Marathon Oil's financial and operational review, as well as the Quarterly Investor Packet, will be posted to the Company's website at and to its mobile app as soon as practicable following this release today, Aug. 3. The Company will conduct a question and answer webcast/call on Thursday, Aug. 4, at 9:00 a.m. ET. The associated commentary and answers to questions will include forward-looking information. To listen to the live webcast, visit the Marathon Oil website at The audio replay of the webcast will be posted by Aug. 5.


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Non-GAAP Measures
Management uses certain non-GAAP financial measures, including adjusted net income (loss) and net cash provided by operations before changes in working capital, to evaluate the Company's financial performance between periods and to compare the Company's performance to certain competitors. Management also uses net cash provided by operations before changes in working capital to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. These measures should not be considered substitutes for their most directly comparable GAAP financial measures. See the tables below for reconciliations between each non-GAAP financial measure and its most directly comparable GAAP financial measure.


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 future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, capital plans, cost and expense estimates, asset acquisitions and sales, future financial position, 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 economic conditions in the jurisdictions in which the Company operates, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; risks related to the Company's hedging activities; the Company's level of success in integrating acquisitions; capital available for exploration and development; drilling and operating risks; well production timing; availability of materials and labor; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions; political conditions and developments, including political instability, acts of war or terrorism, and the governmental 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 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at The Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.



Consolidated Statements of Income (Unaudited) Three Months Ended
  June 30 Mar. 31 June 30
(In millions, except per share data) 2016 2016 2015
Revenues and other income:      
  Sales and other operating revenues, including related party $ 870   $ 714   $ 1,307  
  Marketing revenues 89   58   183  
  Income from equity method investments 37   14   26  
  Net gain (loss) on disposal of assets 294   (60 )  
  Other income 12   4   15  
Total revenues and other income 1,302   730   1,531  
Costs and expenses:      
  Production 350   328   450  
  Marketing, including purchases from related parties 88   58   182  
  Other operating 95   109   81  
  Exploration 189   24   111  
  Depreciation, depletion and amortization 561   609   751  
  Impairments   1   44  
  Taxes other than income 39   48   78  
  General and administrative 132   151   168  
Total costs and expenses 1,454   1,328   1,865  
Income (loss) from operations (152 ) (598 ) (334 )
  Net interest and other (86 ) (85 ) (58 )
Income (loss) before income taxes (238 ) (683 ) (392 )
  Benefit for income taxes (68 ) (276 ) (6 )
Net income (loss) $ (170 ) $ (407 ) $ (386 )
Adjustments for special items (pre-tax):      
  Net (gain) loss on dispositions (296 ) 63    
  Proved property impairments     44  
  Unproved property impairments 141      
  Pension settlement 31   48   64  
  Unrealized (gain) loss on commodity derivative instruments 91   23   44  
  Reduction in workforce 1   7   (2 )
  Other (9 )    
Provision (benefit) for income taxes related to special items 15   (51 ) (54 )
Alberta provincial corporate tax rate increase     135  
Adjusted net income (loss) (a) $ (196 ) $ (317 ) $ (155 )
Per diluted share:      
  Net Income (loss) $ (0.20 ) $ (0.56 ) $ (0.57 )
  Adjusted net income (loss) (a) $ (0.23 ) $ (0.43 ) $ (0.23 )
Weighted average diluted shares 848   730   677  


(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.



Supplemental Statistics (Unaudited) Three Months Ended
  June 30 Mar. 31 June 30
(in millions) 2016 2016 2015
Segment income (loss)      
North America E&P $ (70 ) $ (195 ) $ (45 )
International E&P 55   4   41  
Oil Sands Mining (38 ) (48 ) (77 )
  Segment income (loss) (53 ) (239 ) (81 )
  Not allocated to segments (117 ) (168 ) (305 )
    Net income (loss) $ (170 ) $ (407 ) $ (386 )
Exploration expenses      
North America E&P $ 37   $ 18   $ 91  
International E&P 4   6   20  
Oil Sands Mining 7      
  Segment exploration expenses 48   24   111  
  Not allocated to segments 141      
    Total $ 189   $ 24   $ 111  
Cash flows      
Net cash provided by operating activities $ 178   $ 74   $ 408  
Minus: changes in working capital (112 ) 19   (112 )
Net cash provided by operations before changes in working capital (a) $ 290   $ 55   $ 520  
Cash additions to property, plant and equipment $ (299 ) $ (454 ) $ (868 )

(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.



  Three Months Ended Guidance(a)
  June 30 Mar. 31 June 30 Q3 Full Year
(mboed) 2016 2016 2015 2016 2016
Net production available for sale          
North America E&P (b) 224   239   274   200-210  
International E&P excluding Libya (c) 120   100   108   125-135  
Combined North America & International E&P, excluding Libya (c) 344   339   382   325-345 330-345
Oil Sands Mining (d) 40   49   25   45-50 40-50
Total Company excluding Libya 384   388   407      
Total Company 384   388   407      

(a) Guidance includes the effect of acquisitions and divestitures closed to date.
(b)The sale of the Company's East TexasNorth Louisiana and Wilburton, Oklahoma natural gas assets closed in August 2015, and the sale of its Gulf of Mexico assets closed in December 2015 and February 2016.
(c) Libya is excluded because of uncertainty around timing of future production and sales levels.
(d) Upgraded bitumen excluding blendstocks.


  Three Months Ended
  June 30 Mar. 31 June 30
(mboed) 2016 2016 2015
Net production available for sale      
North America E&P 224   239   274  
Less:  Divestitures (a) (13 ) (15 ) (31 )
    Divestiture-adjusted North America E&P 211   224   243  

(a) Divestitures include the sale of Wyoming assets closed in June 2016East TexasNorth Louisiana and Wilburton, Oklahoma assets closed in August 2015; and the sale of Gulf of Mexico assets closed in December 2015 and February 2016. These production volumes have been removed from all periods shown in arriving at divestiture-adjusted North America E&P net production available for sale.



Supplemental Statistics (Unaudited) Three Months Ended
  June 30 Mar. 31 June 30
  2016 2016 2015
North America E&P - net sales volumes      
Liquid hydrocarbons (mbbld) 173   186   213  
  Bakken 49   53   57  
  Eagle Ford 84   95   108  
  Oklahoma resource basins 14   12   11  
  Other North America (a) 26   26   37  
Crude oil and condensate (mbbld) 135   147   176  
  Bakken 44   47   54  
  Eagle Ford 61   70   82  
  Oklahoma resource basins 6   5   5  
  Other North America (a) 24   25   35  
Natural gas liquids (mbbld) 38   39   37  
  Bakken 5   6   3  
  Eagle Ford 23   25   26  
  Oklahoma resource basins 8   7   6  
  Other North America (a) 2   1   2  
Natural gas (mmcfd) 310   315   361  
  Bakken 24   25   22  
  Eagle Ford 150   154   164  
  Oklahoma resource basins 82   89   81  
  Other North America (a) 54   47   94  
  Total North America E&P (mboed) 224   239   274  
International E&P - net sales volumes      
Liquid hydrocarbons (mbbld) 44   32   42  
  Equatorial Guinea 30   25   28  
  United Kingdom 14   7   14  
Crude oil and condensate (mbbld) 33   23   33  
  Equatorial Guinea 19   16   19  
  United Kingdom 14   7   14  
Natural gas liquids (mbbld) 11   9   9  
  Equatorial Guinea 11   9   9  
Natural gas (mmcfd) 457   382   396  
  Equatorial Guinea 430   351   365  
  United Kingdom (b) 27   31   31  
  Total International E&P (mboed) 120   96   108  
Oil Sands Mining - net sales volumes      
Synthetic crude oil (mbbld) (c) 49   59   29  
Total Company - net sales volumes (mboed) 393   394   411  
Net sales volumes of equity method investees      
  LNG (mtd) 5,797   4,322   4,991  
  Methanol (mtd) 1,303   1,280   673  
  Condensate and LPG (boed) 11,306   10,208   8,586  

(a) Includes Gulf of Mexico and other conventional onshore U.S. production. The sale of the Company's Gulf of Mexico assets closed in December 2015 and February 2016.
(b) Includes natural gas acquired for injection and subsequent resale of 5 mmcfd, 5 mmcfd, and 7 mmcfd in the second and first quarter of 2016, and second quarter of 2015, respectively.
(c) Includes blendstocks.



Supplemental Statistics (Unaudited) Three Months Ended
June 30 Mar. 31 June 30
2016 2016 2015
North America E&P - average price realizations (a)
Liquid hydrocarbons ($ per bbl) $ 35.07   $ 24.00   $ 45.96  
  Bakken 38.38   26.00   49.29  
  Eagle Ford 34.31   23.02   44.05  
  Oklahoma resource basins 25.57   19.41   30.29  
  Other North America (b) 36.27   25.51   50.89  
Crude oil and condensate ($ per bbl) (c) $ 40.77   $ 28.21   $ 52.63  
  Bakken 42.00   28.78   51.36  
  Eagle Ford 41.21   28.65   53.47  
  Oklahoma resource basins 41.55   29.74   51.00  
  Other North America (b) 37.27   25.66   52.83  
Natural gas liquids ($ per bbl) $ 14.84   $ 8.12   $ 14.77  
  Bakken 7.73   3.47   11.63  
  Eagle Ford 15.68   7.05   14.08  
  Oklahoma resource basins 14.88   11.86   14.45  
  Other North America (b) 23.64   23.47   25.65  
Natural gas ($ per mcf) $ 1.96   $ 2.02   $ 2.76  
  Bakken 1.77   2.09   2.62  
  Eagle Ford 2.02   1.98   2.71  
  Oklahoma resource basins 1.92   2.03   2.64  
  Other North America (b) 1.95   2.10   2.98  
International E&P - average price realizations      
Liquid hydrocarbons ($ per bbl) $ 32.11   $ 22.66   $ 44.70  
  Equatorial Guinea 27.28   20.43   35.74  
  United Kingdom 42.32   30.20   61.93  
Crude oil and condensate ($ per bbl) $ 42.21   $ 30.95   $ 56.70  
  Equatorial Guinea 41.46   30.93   52.27  
  United Kingdom 43.25   30.72   62.97  
Natural gas liquids ($ per bbl) $ 2.65   $ 2.20   $ 3.10  
  Equatorial Guinea (d) 1.00   1.00   1.00  
  United Kingdom 25.99   23.56   36.49  
Natural gas ($ per mcf) $ 0.53   $ 0.60   $ 0.78  
  Equatorial Guinea (d) 0.24   0.24   0.24  
  United Kingdom 5.06   4.61   6.98  
Oil Sands Mining - average price realizations      
Synthetic crude oil ($ per bbl) $ 40.88   $ 26.41   $ 52.46  
  WTI crude oil (per bbl) $ 45.64   $ 33.63   $ 57.95  
  Brent (Europe) crude oil (per bbl)(e) $ 45.52   $ 33.70   $ 61.69  
  Henry Hub natural gas (per mmbtu)(f) $ 1.95   $ 2.09   $ 2.64  
  WCS crude oil (per bbl)(g) $ 32.29   $ 19.21   $ 46.35  

(a) Excludes gains or losses on derivative instruments.
(b) Includes Gulf of Mexico and other conventional onshore U.S. production. The sale of the Company's Gulf of Mexico assets closed in December 2015 and February 2016.
(c) Inclusion of realized gains on crude oil derivative instruments would have increased average price realizations by $0.12$1.64, and $0.06 for second and first quarters of 2016 and second quarter of 2015.
(d) Represents fixed prices under long-term contracts with Alba Plant LLCAtlantic 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.
(e) Average of monthly prices obtained from Energy Information Administration ("EIA") website.
(f) Settlement date average per mmbtu.
(g) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.


Media Relations Contacts:

Lee Warren: 713-296-4103

Lisa Singhania: 713-296-4101

Investor Relations Contacts:

Zach Dailey: 713-296-4140