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 November 4, 2015 - 4:30 PM EST
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Marathon Oil Reports Third Quarter 2015 Results

Total Company 2015 Production Growth at High End of Guidance on $200 Million Lower Capital Budget

HOUSTON, Nov. 04, 2015 (GLOBE NEWSWIRE) --

Marathon Oil Corporation (NYSE:MRO) today reported a third quarter 2015 adjusted net loss of $138 million, or $0.20 per diluted share, excluding the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. The reported net loss was $749 million, or $1.11 per diluted share. Third quarter 2015 included $611 million ($949 million pre-tax) of non-cash charges comprised largely of losses and asset impairments resulting from lower forecasted commodity prices and changes in the Company's conventional exploration strategy.


Quarter Highlights

  • Third quarter capital, investment and exploration program at approximately $623 million, down 7% from second quarter; full-year 2015 program $3.1 billion
  • On track to achieve total Company and U.S. resource play production growth rates of 7% and 20%, respectively, year over year, with $200 million less capital
  • Total Company net production from continuing operations (excluding Libya) averaged 434,000 net boed, up 6% over the year-ago quarter with OSM achieving record production of 57,000 net boed; U.S. resource play production of 212,000 net boed up 10% over year-ago quarter
  • Total E&P production expense down 30% from year-ago quarter; reduced North America E&P production costs per boe 27% below year-ago quarter
  • S. resource plays featured solid performance from the early development of upper Eagle Ford, encouraging results from the SCOOP Smith infill pilot and continued strong contribution from the Bakken's West Myrmidon
  • Closed non-core asset sales in East Texas, North Louisiana and Wilburton, Oklahoma for approximately $100 million; signed agreement for sale of East Africa exploration acreage

 

“In an environment where we expect oil prices to remain low for a longer period of time, Marathon Oil continues to take strong action to deliver meaningful cost reductions and efficiency gains, while we remain on target to achieve the high end of our original total Company production growth targets," said Marathon Oil President and CEO Lee M. Tillman. "We're maximizing capital allocation to the highest return opportunities in the U.S. resource plays, but with the right balance of high-confidence development activity and continued resource delineation that positions us for growth as we look through the current cycle. This quarter's results were impacted by non-cash losses and impairments related to lower forecasted commodity prices and our continued strategic transition away from conventional exploration. Importantly, we remain focused on driving operational excellence, reducing production expenses and G&A costs, pursuing portfolio management and maintaining a strong balance sheet. Last week we announced a reduced quarterly dividend, which is expected to increase annual free cash flow by more than $425 million, and we lowered our 2015 capital, investment and exploration program to $3.1 billion. In addition, based on our current outlook and preliminary plan discussions, we would anticipate a total Company 2016 program of up to $2.2 billion, subject to Board approval, which would give us the flexibility to deliver 2016 annual average production in the U.S. resource plays flat to 2015 exit rate."


North America E&P

North America Exploration and Production (E&P) production available for sale averaged 263,000 net barrels of oil equivalent per day (boed) for third quarter 2015, a 5 percent increase over the year-ago quarter and compared to 274,000 net boed for second quarter 2015. The decrease from the second quarter 2015 was primarily a result of lower Eagle Ford volumes and the disposition of East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets, which closed in August. North America production costs were $7.43 per barrel of oil equivalent (boe), down 27 percent from the year-ago period. The Company expects full-year unit production costs to be at the low end of guidance of $7.50 to $8.50 per boe.

EAGLE FORD: In third quarter 2015, Marathon Oil's production in the Eagle Ford averaged 128,000 net boed, a 9 percent increase above the year-ago quarter and compared to 135,000 net boed in the prior quarter. The production decrease compared to the previous quarter was principally due to timing of wells to sales weighted late in the quarter, lower than anticipated results from a step-out pad in Live Oak County and three Austin Chalk wells testing the western periphery of the play. During third quarter 2015 the Company brought 57 wells to sales, of which 11 were Austin Chalk, six upper Eagle Ford and 40 lower Eagle Ford, compared to 52 wells to sales in the previous quarter. Thirty-day initial production (IP) rates from the six upper Eagle Ford wells ranged from 1,050 to 1,480 net boed (57-76 percent liquids), supportive of the 2P resource additions announced in the third quarter. Efficiency gains in drilling and completions continued, as evidenced by wells drilled at an average rate of 2,000 feet per day, an 11 percent improvement over the previous quarter. With this improvement, the time to drill an Eagle Ford well spud-to-total depth dropped to 10 days. Even as drilling efficiency continues to improve, the Company is exceeding its technical objectives with a 98 percent success rate geo-steering into a typical 25-foot target. 

OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production averaged 23,000 net boed during third quarter 2015, an increase of 21 percent over the year-ago quarter and compared to 24,000 net boed in the prior quarter. Marathon Oil brought online seven Company-operated SCOOP wells, of which one was an extended-reach lateral, and two Company-operated STACK Meramec wells. The Company-operated Smith infill pilot wells recently came online with 24-hour IP rates averaging 1,060 net boed (60 percent liquids) on 107-acre spacing (30-day rates are not yet available). The Company also spud its first operated Springer well during the third quarter and is in the process of completing the well.

BAKKEN: Marathon Oil averaged 61,000 net boed of production in the Bakken during third quarter 2015, a 9 percent increase above the year-ago quarter. Volumes were flat to the previous quarter with five wells brought to sales, all in East Myrmidon, down from 22 in the previous quarter. Production was driven by continued strong performance from the Doll pad wells in West Myrmidon, which came online in late June, as well as sustained improvement in production uptime.

GULF OF MEXICO: The outside-operated Shenandoah-4ST appraisal well on Walker Ridge Block 51 encountered more than 620 feet of net oil pay, extending the lowest known oil column downdip. Marathon Oil holds a 10 percent working interest in Shenandoah.

 

International E&P

International E&P production available for sale from continuing operations (excluding Libya) averaged 114,000 net boed for third quarter 2015 compared to 112,000 net boed in the year-ago quarter and 108,000 net boed in the previous quarter. The increase over the second quarter was primarily a result of higher Equatorial Guinea volumes, partially offset by planned maintenance activities in the U.K. Proactive cost management efforts across the Company-operated assets continue to yield repeatable savings, and coupled with higher volumes are resulting in lower unit production costs of $5.53 per boe. The Company expects full-year unit production costs to be at the low end of guidance of $6.00 to $7.00 per boe (excluding Libya).

EQUATORIAL GUINEA: Production available for sale averaged 99,000 net boed in third quarter 2015 compared to 100,000 net boed in the year-ago quarter and 86,000 net boed in the previous quarter, which was impacted by planned maintenance. The Alba C21 development well came online with higher than expected liquids yield and, combined with a successful wire-line intervention program on five existing wells, resulted in a 4,000 net boed uplift in production. The Alba field compression project, designed to maintain the production plateau two additional years and extend field life up to eight years, achieved mechanical completion at the fabrication yard in the Netherlands during the third quarter and is on schedule to be operational in mid-2016.

U.K.: Production available for sale averaged 15,000 net boed in third quarter 2015, compared to 13,000 net boed in the year-ago quarter and 22,000 net boed in the previous quarter. Third quarter volumes were impacted by planned maintenance activities at the Company-operated Brae field and the non-operated Foinaven field. The Brae maintenance was completed on time and on budget. Maintenance work at the non-operated Foinaven field has taken longer than planned and continues to impact field production in the fourth quarter.


Oil Sands Mining

Oil Sands Mining (OSM) production available for sale for third quarter 2015 averaged 57,000 net boed compared to 47,000 net boed in the prior-year quarter and 25,000 net boed in second quarter 2015, which was impacted by an extensive turnaround at the Muskeg River Mine and the base upgrader. Record production in the third quarter was largely due to improved operational reliability and no planned maintenance. Increased cost focus combined with strong production volumes resulted in operating expense per synthetic barrel (before royalties) being down 30 percent from a year ago to $26, the lowest per unit cost performance by OSM with both mine sites operating.

 

Production Guidance

Marathon Oil expects fourth quarter 2015 North America E&P production available for sale to average 244,000 to 257,000 net boed reflecting reduced completion work in the Bakken and the disposition of the East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets which closed in the third quarter. The resource plays remain on track to achieve annual growth in available for sale volumes of 20 percent year over year. Fourth quarter International E&P production available for sale (excluding Libya) is expected to be within a range of 121,000 to 128,000 net boed, up from the third quarter as the full benefits of the Alba C21 development well and successful wire-line intervention program in Equatorial Guinea are realized and U.K. Brae fields return to normal operations, partially offset by the ongoing maintenance at the non-operated Foinaven field. Marathon Oil had no liftings in Libya during third quarter 2015. 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 40,000 to 45,000 net boed in the fourth quarter with planned maintenance at both mines expected to impact production.

The Company is tightening its full-year 2015 E&P production guidance range, resulting in a new range of 380,000 to 390,000 net boed. Full-year production guidance for OSM was narrowed to 40,000 to 45,000 net boed. Full-year 2015 guidance for the total Company production growth rate is 7 percent year over year, at the upper end of the previous range of 5 to 7 percent.

 

Corporate and Special Items

Net cash provided by continuing operations before changes in working capital was $467 million during third quarter 2015, and net cash provided by operating activities was $496 million. Additions to property, plant and equipment including accruals were $595 million in third quarter 2015 compared to $678 million in the prior quarter. The Company's 2015 capital, investment and exploration program is expected to be $3.1 billion. Total liquidity as of Sept. 30 was $5.4 billion, including $2.4 billion in cash and short-term investments, $1 billion of which was used to retire maturing debt in November.

Marathon Oil reduced E&P production expenses and total Company adjusted general and administrative costs by $136 million for third quarter 2015 compared to the same quarter in 2014. These savings represent an overall reduction of 28 percent.

The Company signed an agreement in the third quarter to sell its Ethiopia and Kenya exploration acreage representing an exit from East Africa.

The adjustments to net loss for third quarter 2015 included proved and unproved property and other impairments, and loss on sale of assets totaling $647 million ($1,007 million pre-tax) due primarily to lower forecasted commodity prices and changes in the Company's conventional exploration strategy; an unrealized gain on derivatives of $50 million ($80 million pre-tax); a settlement charge of $12 million ($18 million pre-tax) in connection with the U.S. pension plans; and, severance and related expenses of $2 million ($4 million pre-tax) related to workforce reductions.

The Company's webcast commentary and associated slides related to Marathon Oil's financial and operational review, as well as the Quarterly Investor Packet, will be posted to the Company's website at http://ir.marathonoil.com and to its mobile app as soon as practicable following this release today, Nov. 4. The Company will conduct a question and answer webcast/call on Thursday, Nov. 5, at 9 a.m. EST. The webcast slides, associated commentary and answers to questions will include forward-looking information. To listen to the live webcast, visit the Marathon Oil website at http://www.marathonoil.com. The audio replay of the webcast will be posted by Nov. 7.

# # #


Non-GAAP Measures

Management uses certain non-GAAP financial measures, including adjusted net income (loss), adjusted income (loss) from continuing operations, net cash provided by continuing operations before changes in working capital, and adjusted general and administrative expenses, 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 continuing operations before changes in working capital to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. These measures generally exclude the effects of items that are considered non-recurring, are difficult to predict or to measure in advance or that are not directly related to the Company’s ongoing operations. They 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, including: (i) adjusted net income (loss) reconciled to net income (loss), (ii) adjusted income (loss) from continuing operations reconciled to income (loss) from continuing operations, (iii) net cash provided by continuing operations before changes in working capital reconciled to net cash provided by operating activities, and (iv) adjusted general and administrative expenses reconciled to total company general and administrative expenses.


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. Forward-looking statements are statements other than statements of historical fact that give current expectations or forecasts of future events, including without limitation: the Company’s operational, financial and growth strategies, including planned projects, drilling plans, cost management and expected savings, asset sales, resource growth, productivity improvements, and drilling and completion efficiencies; the Company’s ability to successfully effect those strategies and the expected timing and results thereof; the Company’s financial and operational outlook, and ability to fulfill that outlook; expectations regarding future economic and market conditions and their effects on the Company; the Company's 2015 and 2016 capital, investment and exploration programs, planned reductions and the expected benefits thereof; the Company's declared dividend and the expected benefits thereof; production cost guidance; the Company's financial position, liquidity and capital resources; and production guidance and the drivers thereof.

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 key operating markets, including international markets; capital available for exploration and development; well production timing; availability of drilling rigs, materials and labor; 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 terrorism and the governmental or military response thereto; cyber-attacks; changes in safety, health, environmental 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 2014 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.marathonoil.com. The Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.


 Three Months Ended
 Sept. 30June 30Sept. 30
(In millions, except per diluted share data) 2015  2015  2014 
Adjusted income (loss) from continuing operations (a)$(138)$(155)$388 
Adjustments for special items (net of taxes):   
Net loss on dispositions (71)
Proved property impairments (213) (28) (70)
Unproved property impairments (355)
Loss on equity method investments (8)
Pension settlement (12) (40) (14)
Unrealized gain (loss) on crude oil derivative instruments 50  (28)
Reduction in workforce (2)
Alberta provincial corporate tax rate increase (135)
   Income (loss) from continuing operations$(749)$(386)$304 
Per diluted share:   
   Adjusted income (loss) from continuing operations (a)$(0.20)$(0.23)$0.57 
   Income (loss) from continuing operations$(1.11)$(0.57)$0.45 
Adjusted net income (loss) (a)$(138)$(155)$515 
Adjustments for special items (net of taxes):   
Net loss on dispositions (71)
Proved property impairments (213) (28) (70)
Unproved property impairments (355)
Loss on equity method investments (8)
Pension settlement (12) (40) (14)
Unrealized gain (loss) on crude oil derivative instruments 50  (28)
Reduction in workforce (2)
Alberta provincial corporate tax rate increase (135)— 
   Net income (loss)$(749)$(386)$431 
Per diluted share:   
     Adjusted net income (loss) (a)$(0.20)$(0.23)$0.76 
     Net income (loss)$(1.11)$(0.57)$0.64 
Exploration expenses   
Unproved property impairments$563 $40 $39 
Dry well costs (3) 41  25 
Geological and geophysical 8  12  10 
Other 17  18  22 
   Total exploration expenses$585 $111 $96 
Cash flows   
Net cash provided by continuing operations before changes in working capital (a)$467 $520 $1,420 
Changes in working capital for continuing operations 29  (112) (62)
Total net cash provided by continuing operations 496  408  1,358 
Net cash provided by discontinued operations (b) 416 
Net cash provided by operating activities$496 $408 $1,774 
Additions to property, plant and equipment$(595)$(678)$(1,508)
Changes in working capital (33) (190) 99 
Cash additions to property, plant and equipment$(628)$(868)$(1,409)

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

(b) As a result of the sale of the Company's Norway business, it is reflected as discontinued operations in 2014.

 

 

Consolidated Statements of Income (Unaudited)Three Months Ended
 Sept. 30June 30Sept. 30
(In millions, except per share data) 2015  2015  2014 
Revenues and other income:   
  Sales and other operating revenues, including related party$1,300 $1,307 $2,316 
  Marketing revenues 84  183  554 
  Income from equity method investments 36  26  89 
  Net gain (loss) on disposal of assets (109)—  (3)
  Other income 12  15  15 
Total revenues and other income 1,323  1,531  2,971 
Costs and expenses:   
  Production 406  450  593 
  Marketing, including purchases from related parties 84  182  554 
  Other operating 93  81  99 
  Exploration 585  111  96 
  Depreciation, depletion and amortization 717  751  737 
  Impairments 337  44  109 
  Taxes other than income 46  78  115 
  General and administrative 125  168  160 
Total costs and expenses 2,393  1,865  2,463 
Income (loss) from operations (1,070) (334) 508 
  Net interest and other (75) (58) (55)
Income (loss) from continuing ops before income taxes (1,145) (392) 453 
  Provision (benefit) for income taxes (396) (6) 149 
Income (loss) from continuing operations (749) (386) 304 
Discontinued operations (a) 127 
Net income (loss) (749) (386) 431 
Per share data   
Basic:   
   Income (loss) from continuing operations$(1.11)$(0.57)$0.45 
   Discontinued operations (a)$0.19 
   Net income (loss)$(1.11)$(0.57)$0.64 
Diluted:   
   Income (loss) from continuing operations$(1.11)$(0.57)$0.45 
   Discontinued operations (a)$0.19 
   Net income (loss)$(1.11)$(0.57)$0.64 
Weighted average shares:   
   Basic 677  677  675 
   Diluted 677  677  678 

(a) As a result of the sale of the Company's Norway business, it is reflected as discontinued operations in 2014.

 

 

Supplemental Statistics (Unaudited)Three Months Ended
 Sept. 30June 30Sept. 30
(in millions) 2015  2015  2014 
Segment income (loss)   
North America E&P$(61)$(45)$292 
International E&P 29  41  106 
Oil Sands Mining (11) (77) 93 
   Segment income (loss) (43) (81) 491 
Items not allocated to segments, net of income taxes:   
   Corporate and unallocated (95) (74) (103)
   Net loss on dispositions (71)
   Proved property impairments (213) (28) (70)
   Unproved property impairments (355)
   Loss on equity method investments (8)
   Pension settlement (12) (40) (14)
   Unrealized gain (loss) on crude oil derivative instruments 50  (28)
   Reduction in workforce (2)
   Alberta provincial corporate tax rate increase (135)
     Income (loss) from continuing operations (749) (386) 304 
     Discontinued operations (a) 127 
       Net income (loss)$(749)$(386)$431 
Capital expenditures (b)   
North America E&P$564 $551 $1,277 
International E&P 30  99  166 
Oil Sands Mining (11) 16  49 
Discontinued operations (a) 125 
Corporate 12  12  16 
     Total$595 $678 $1,633 
Exploration expenses   
North America E&P$22 $91 $55 
International E&P 10  20  41 
   Segment exploration expenses 32  111  96 
   Not allocated to segments 553 
     Total$585 $111 $96 
Provision (benefit) for income taxes   
Current income taxes$9 $(15)
Deferred income taxes (405) (6) 164 
     Total$(396)$(6)$149 

(a) As a result of the sale of the Company's Norway business, it is reflected as discontinued operations in 2014.

(b) Capital expenditures include accruals.

 

 

 Three Months EndedGuidance (a)
 Sept. 30June 30Sept. 30Q4Full-Year
(mboed)20152015201420152015
Net production available for sale     
North America E&P (b)263274250244-257 
International E&P excluding Libya (c) and Disc Ops (d)114108112121-128 
Combined North America & International E&P, excluding Libya (c) and Disc Ops (d)377382362365-385380-390
Oil Sands Mining (e)57254740-4540-45
Total continuing operations excluding Libya434407409  
Discontinued operations (d)56  
Total Company excluding Libya434407465  
Libya8  
Total434407473  

(a) Guidance excludes the effect of acquisitions or dispositions not previously announced.

(b) The sale of the Company's East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets closed in August 2015. It affected third quarter 2015 volumes, and is reflected in fourth quarter and full-year 2015 guidance.

(c) Libya is excluded because of uncertainty around timing of future production and sales levels.

(d) As a result of the sale of the Company's Norway business, it is reflected as discontinued operations in 2014.

(e) Upgraded bitumen excluding blendstocks.

 

Supplemental Statistics (Unaudited)Three Months Ended
 Sept. 30June 30Sept. 30
 201520152014
North America E&P - net sales volumes   
Liquid hydrocarbons (mbbld)205213197
  Bakken585753
  Eagle Ford10010895
  Oklahoma resource basins10118
  Other North America (c)373741
Crude oil and condensate (mbbld)166 176 166 
  Bakken535450
  Eagle Ford748275
  Oklahoma resource basins453
  Other North America (c)353538
Natural gas liquids (mbbld)393731
  Bakken533
  Eagle Ford262620
  Oklahoma resource basins665
  Other North America223
Natural gas (mmcfd)338361317
  Bakken192218
  Eagle Ford161164130
  Oklahoma resource basins768163
  Other North America (c)8294106
Total North America E&P (mboed)261274250
International E&P - net sales volumes   
Liquid hydrocarbons (mbbld)464239
  Equatorial Guinea312827
  United Kingdom15146
  Libya6
Crude oil and condensate (mbbld)353329
  Equatorial Guinea211917
  United Kingdom14146
  Libya6
Natural gas liquids (mbbld)11910
  Equatorial Guinea10910
  United Kingdom1
Natural gas (mmcfd)441396439
  Equatorial Guinea418365420
  United Kingdom (b)233119
Total International E&P (mboed)119108112
Oil Sands Mining - net sales volumes   
Synthetic crude oil (mbbld) (d)652955
    
Total continuing operations - net sales volumes (mboed)445411417
Discontinued operations - net sales volumes (mboed)(a)58
Total Company - net sales volumes (mboed)445411475
Net sales volumes of equity method investees (mtd)   
  LNG5,7004,9916,265
  Methanol1,1256731,103

(a) As a result of the sale of the Company's Norway business, it is reflected as discontinued operations in 2014.

(b) Includes natural gas acquired for injection and subsequent resale of 8 mmcfd, 7 mmcfd, and 3 mmcfd in the third and second quarters of 2015, and third quarter of 2014, respectively.

(c) Includes Gulf of Mexico and other conventional onshore U.S. production.

(d) Includes blendstocks.

 

Supplemental Statistics (Unaudited)Three Months Ended
 Sept. 30June 30Sept. 30
  2015  2015  2014 
North America E&P - average price realizations (b)   
Liquid hydrocarbons ($ per bbl)$35.75 $45.96 $80.89 
  Bakken 37.41  49.29  82.67 
  Eagle Ford 34.87  44.05  79.99 
  Oklahoma resource basins 22.70  30.29  56.57 
  Other North America (c) 39.25  50.89  85.28 
Crude oil and condensate ($ per bbl) (d)$41.37 $52.63 $89.65 
  Bakken 40.18  51.36  85.28 
  Eagle Ford 42.74  53.47  93.51 
  Oklahoma resource basins 40.48  51.00  93.78 
  Other North America (c) 40.37  52.83  87.50 
Natural gas liquids ($ per bbl)$11.88 $14.77 $33.93 
  Bakken 5.07  11.63  40.60 
  Eagle Ford 12.15  14.08  30.90 
  Oklahoma resource basins 11.38  14.45  33.64 
  Other North America 23.21  25.65  51.49 
Natural gas ($ per mcf)$2.75 $2.76 $4.21 
  Bakken 1.96  2.62  4.29 
  Eagle Ford 2.85  2.71  4.21 
  Oklahoma resource basins 2.82  2.64  3.97 
  Other North America (c) 2.70  2.98  4.34 
International E&P - average price realizations   
Liquid hydrocarbons ($ per bbl)$35.88 $44.70 $66.80 
  Equatorial Guinea 28.03  35.74  51.83 
  United Kingdom 52.36  61.93  88.68 
  Libya 114.36 
Crude oil and condensate ($ per bbl)$46.18 $56.70 $89.07 
  Equatorial Guinea 41.24  52.27  80.85 
  United Kingdom 53.48  62.97  88.68 
  Libya 114.36 
  Natural gas liquids ($ per bbl)$2.69 $3.10 $1.00 
  Equatorial Guinea (e) 1.00  1.00  1.00 
  United Kingdom 28.81  36.49 
Natural gas ($ per mcf)$0.59 $0.78 $0.56 
  Equatorial Guinea (e) 0.24  0.24  0.24 
  United Kingdom 6.92  6.98  7.60 
Oil Sands Mining - average price realizations   
Synthetic crude oil ($ per bbl)$39.49 $52.46 $88.22 
    
Discontinued operations - average price realizations ($ per boe)(a) 98.62 
Benchmark   
   WTI crude oil (per bbl)(f)$46.50 $57.95 $97.25 
   Brent (Europe) crude oil (per bbl)(g)$50.23 $61.69 $101.82 
   Henry Hub natural gas (per mmbtu)(h)$2.77 $2.64 $4.06 
   WCS crude oil (per bbl)(i)$33.16 $46.35 $76.99 

(a) As a result of the sale of the Company's Norway business, it is reflected as discontinued operations in 2014.

(b) Excludes gains or losses on derivative instruments.

(c) Includes Gulf of Mexico and other conventional onshore U.S. production.

(d) Inclusion of realized gains on crude oil derivative instruments would have increased average price realizations by $1.87 for third quarter 2015 and $0.06 for  second quarter 2015. There were no crude oil derivative instruments in 2014.

(e) Represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and/or Equatorial Guinea LNG Holdings Limited, which are equity method investees. Marathon Oil includes its share of income from each of these equity method investees in the International E&P segment.

(f) NYMEX

(g) Average of monthly prices obtained from Energy Information Administration ("EIA") website.

(h) Settlement date average per mmbtu.

(i) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

 

 

 Three Months Ended
 Sept. 30June 30Sept. 30
(In millions)  2015    2015    2014  
Production expenses   
North America E&P$ 179  $ 179  $ 233  
International E&P  61    64    108  
     Total  240    243    341  
    
Total Company general and administrative expenses  125    168    160  
Adjustments for special items:   
   Pension settlement  (18)   (64)   (22) 
   Reduction in workforce  (4) —  —  
     Adjusted general and administrative expenses (a)  103    104    138  
E&P production expenses and adjusted general and administrative expenses (a)$ 343  $ 347  $ 479  

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

 

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Source: GlobeNewswire (November 4, 2015 - 4:30 PM EST)

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