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Marathon Oil Reports Fourth Quarter and Full-Year 2015 Results

HOUSTON, Feb. 17, 2016 (GLOBE NEWSWIRE) --

Marathon Oil Corporation (NYSE:MRO) today reported a full-year 2015 adjusted net loss of $869 million, or $1.28 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 $2,204 million, or $3.26 per diluted share.

Full-Year 2015

  • Full-year 2015 capital program at $3 billion, $500 million below original budget
  • Achieved 8% production growth from total Company continuing operations (excluding Libya) and 21% from U.S. resource plays year over year
  • Decreased E&P production and total Company adjusted G&A expenses by more than $435 million, or 24%, year over year
  • Completed 20% reduction in workforce to generate $160 million in annualized net savings
  • Reduced quarterly dividend increasing annual free cash flow by more than $425 million
  • Closed or announced non-core asset sales for approximately $315 million, excluding closing adjustments
  • Organic reserve replacement of 157%, excluding revisions and dispositions, at $12 per boe drillbit finding and development cost
  • Year-end liquidity of $4.2 billion comprised of $1.2 billion in cash and an undrawn $3 billion revolving credit facility

“We navigated a very challenging macro environment in 2015 by staying focused on the elements of the business within our control -- disciplined capital allocation, reducing costs, capturing efficiencies and portfolio management. Our actions early in the cycle on production expenses and G&A reset our cost structure and positioned us to realize full year benefits in 2016," said Marathon Oil President and CEO Lee Tillman. “Even with reduced activity levels and a $3 billion capital program that was 50 percent less than the prior year, we surpassed our total Company and resource play production targets.

"In the fourth quarter, our capital spend and production costs both came in better than expectations. Operational results were supported by a more than 20 percent increase in Oklahoma unconventional volumes while maintaining flat production levels in the Eagle Ford. More recently, we reached a major milestone in Equatorial Guinea with the successful installation of the jacket and topsides for the Alba field compression project, on schedule to start up by mid-year 2016," Tillman said.

The Company reported a fourth quarter 2015 adjusted net loss of $323 million, or $0.48 per diluted share, and a net loss of $793 million, or $1.17 per diluted share.

Fourth Quarter 2015

  • Fourth quarter capital program decreased to $564 million
  • Total Company net production averaged 432,000 net boed, essentially flat with third quarter 2015
  • U.S. resource play production averaged 214,000 net boed, up slightly over third quarter 2015, while maintaining flat sequential Eagle Ford production
  • North America E&P production costs per boe reduced 28% below year-ago quarter
  • Total Company adjusted G&A down 40% compared to year-ago quarter
  • First Company-operated Springer oil well in Oklahoma SCOOP performing above expectations with 30-day IP rate greater than 1,000 boed (89% liquids)
  • Closed sale of Gulf of Mexico properties

North America E&P
North America Exploration and Production (E&P) production available for sale averaged 260,000 net barrels of oil equivalent per day (boed) for fourth quarter 2015. On a divestiture-adjusted basis, it was up 2 percent over the year-ago quarter and essentially flat compared to third quarter 2015. Fourth quarter North America production costs were $6.91 per boe, down 28 percent from the year-ago period. Full-year unit production costs of $7.38 per boe were below guidance of $7.50 to $8.50 per boe.

EAGLE FORD: In fourth quarter 2015, Marathon Oil's production in the Eagle Ford averaged 128,000 net boed, compared to 131,000 net boed in the year-ago quarter and flat to the prior quarter. The production decrease compared to the year-ago quarter was principally due to decreased drilling and completion activity resulting in fewer wells brought to sales. During fourth quarter 2015 the Company brought 76 gross (44 net) wells to sales, of which 25 were Austin Chalk, eight upper Eagle Ford and 43 lower Eagle Ford, compared to 57 gross (45 net) wells to sales in the previous quarter. Efficiency gains in drilling continued, with wells drilled at an average rate of 2,175 feet per day, resulting in spud-to-total depth of 9 days compared to 2,000 feet per day and 10 days spud-to-total depth in the previous quarter. The top-performing Eagle Ford rigs drilled two wells in excess of 3,100 feet per day.

OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production averaged 28,000 net boed during fourth quarter 2015, an increase of 40 percent over the year-ago quarter and up 22 percent over the prior quarter. The Company benefited from a full quarter of production from the Smith infill pilot in the SCOOP, which is performing in line with expectations. Marathon Oil brought online four gross Company-operated wells, of which two were in the SCOOP Woodford, one in the SCOOP Springer and one in the STACK Meramec. The Company's first operated Springer oil well is performing above expectations with a 30-day IP rate of greater than 1,000 boed (89 percent liquids). The Company-operated Tyemax extended-lateral (XL) well in the SCOOP Woodford achieved a 30-day IP rate of 2,850 boed (34 percent liquids).

BAKKEN: Marathon Oil averaged 58,000 net boed of production in the Bakken during fourth quarter 2015, a 5 percent increase above the year-ago quarter and compared to 61,000 net boed in the prior quarter. Five gross wells in East Myrmidon were brought to sales, the same as the previous quarter. Additionally, the next phase of a large-scale water gathering system, expected to handle the majority of Marathon Oil's produced water and reduce production costs, is more than 50 percent complete and on-schedule to start-up in the second half of 2016. The first phase began operating in fourth quarter 2015.

International E&P
International E&P production available for sale from continuing operations (excluding Libya) averaged 123,000 net boed for fourth quarter 2015 compared to 126,000 net boed in the year-ago quarter and 114,000 net boed in the previous quarter. The sequential increase was primarily a result of higher fourth quarter production in Equatorial Guinea and lower third quarter volumes in the U.K. due to planned maintenance activities. Full-year unit production costs of $5.33 per boe (excluding Libya) were below guidance of $6.00 to $7.00 per boe.

EQUATORIAL GUINEA: Production available for sale averaged 104,000 net boed in fourth quarter 2015 compared to 106,000 net boed in the year-ago quarter and 99,000 net boed in the previous quarter. The Company benefited from a full quarter of impact from the Alba C21 development well and successful well intervention program. The jacket and topsides for the Alba field compression project were installed in January. Following completion of the planned onshore maintenance, the Alba field returned to full production rates in early February. Hook-up and commissioning activities on the Alba compression project are in progress and the new facilities are on schedule for a mid-2016 start-up.

U.K.: Production available for sale averaged 18,000 net boed in fourth quarter 2015, compared to 20,000 net boed in the year-ago quarter and 15,000 net boed in the previous quarter. Third quarter 2015 was impacted by planned maintenance activities. In late December, the Brae Alpha installation experienced a process pipe failure. Repairs are underway with resumption of full production expected in the second quarter.

Oil Sands Mining
Oil Sands Mining (OSM) production available for sale for fourth quarter 2015 averaged 49,000 net barrels per day (bbld) compared to 42,000 net bbld in the prior-year quarter and the record 57,000 net bbld in third quarter 2015. During the fourth quarter, planned maintenance at both mines was completed on time and on budget. Operating expense per synthetic barrel (before royalties) was $28.25, down 36 percent from the year-ago quarter largely as a result of higher reliability and associated production volumes, as well as a more favorable currency exchange rate.

Reserves
During 2015, Marathon Oil added proved reserves of 247 million barrels of oil equivalent (boe) through drilling activity, downspacing and improved well performance, virtually all in North America E&P. Excluding revisions and dispositions, the organic reserve replacement ratio for the year was 157 percent with a drillbit finding and development (F&D) cost of $12 per boe. Including revisions but excluding dispositions, the Company's reserve replacement ratio was 89 percent. Net proved reserves remain at approximately 2.2 billion boe at year-end 2015.

Corporate and Special Items
Net cash provided by continuing operations before changes in working capital was $278 million during fourth quarter 2015, and net cash provided by operating activities was $352 million. Additions to property, plant and equipment including accruals were $561 million in fourth quarter 2015, a 6 percent decrease from the previous quarter and down 66 percent from the year-ago quarter. For full-year 2015, net cash provided by continuing operations before changes in working capital was $1.68 billion, and net cash provided by operating activities was $1.57 billion. Total liquidity as of Dec. 31 was $4.2 billion, which consists of $1.2 billion in cash and cash equivalents and an undrawn $3 billion revolving credit facility.

Marathon Oil reduced E&P production expenses and total Company adjusted general and administrative expenses by $146 million for fourth quarter 2015 compared to the same quarter in 2014, and by $437 million for full-year 2015 compared to full-year 2014. These savings represent reductions of 31 percent and 24 percent, respectively. The Company had workforce reductions in 2015 which will result in annualized net savings of $160 million.

The Company closed on the sale of its Gulf of Mexico properties in the greater Ewing Bank area and non-operated Petronius field in December 2015, and on its non-operated Neptune field in February 2016 for combined transaction value of $205 million, before closing adjustments. The buyer assumed all future abandonment obligations for the acquired assets.

The adjustments to net loss for fourth quarter 2015 total $470 million ($498 million pre-tax) and primarily consist of: a goodwill impairment charge of $340 million ($340 million pre-tax) related to the North America E&P segment; an unproved property impairment of $218 million ($300 million pre-tax) relating to Canadian in-situ assets; and a gain on the sale of Gulf of Mexico assets of $146 million ($228 million pre-tax). For additional detail of adjustments related to special items, see attached tables.

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, Feb. 17. The Company will conduct a question and answer webcast/call on Thursday, Feb. 18, 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 Feb. 19.

# # #

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 (and oral statements made regarding the subjects of 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. These 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, workforce reductions and expected savings, production expense reductions, non-core asset sales, and drilling and completion improvements; the Company’s ability to successfully effect those strategies and the expected timing and results thereof; reserve estimates; 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; and the Company's financial position, liquidity and capital resources.

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.

Media Relations Contacts:
Lee Warren: 713-296-4103
Lisa Singhania: 713-296-4101

Investor Relations Contacts:
Chris Phillips: 713-296-3213
Zach Dailey: 713-296-4140


Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
(In millions, except per diluted share data)20152015201420152014
Adjusted income (loss) from continuing operations (a)$(323)$(138)$(89)$(869)$1,160
Adjustments for special items (net of taxes):
Net gain (loss) on dispositions146 (71) 75 (58)
Proved property impairments(20)(213) (261)(70)
Unproved property impairments(220)(355) (575)
Goodwill impairment(340) (340)
Loss on equity method investments (8) (8)
Pension settlement(13)(12)(4)(76)(63)
Unrealized gain (loss) on crude oil derivative instruments(5)50 32
Reduction in workforce(6)(2) (35)
Alberta provincial corporate tax rate increase (135)
Other(12) (12)
Income (loss) from continuing operations$(793)$(749)$(93)$(2,204)$969
Per diluted share:
Adjusted income (loss) from continuing operations (a)$(0.48)$(0.20)$(0.13)$(1.28)$1.70
Income (loss) from continuing operations$(1.17)$(1.11)$(0.14)$(3.26)$1.42
Adjusted net income (loss) (a)$(323)$(138)$(2)$(869)$1,729
Adjustments for special items (net of taxes):
Net gain (loss) on dispositions146 (71)932 75 1,450
Proved property impairments(20)(213) (261)(70)
Unproved property impairments(220)(355) (575)
Goodwill impairment(340) (340)
Loss on equity method investments (8) (8)
Pension settlement(13)(12)(4)(76)(63)
Unrealized gain (loss) on crude oil derivative instruments(5)50 32
Reduction in workforce(6)(2) (35)
Alberta provincial corporate tax rate increase (135)
Other(12) (12)
Net income (loss)$(793)$(749)$926 $(2,204)$3,046
Per diluted share:
Adjusted net income (loss) (a)$(0.48)$(0.20)$ $(1.28)$2.53
Net income (loss)$(1.17)$(1.11)$1.37 $(3.26)$4.46
Exploration expenses
Unproved property impairments$352 $563 $166 $964 $306
Dry well costs154 (3)237 250 317
Geological and geophysical8 8 58 31 85
Other18 17 18 73 85
Total exploration expenses$532 $585 $479 $1,318 $793
Cash flows
Net cash provided by continuing operations before changes in working capital (a)$278 $467 $768 $1,677 $4,661
Changes in working capital for continuing operations74 29 492 (112)75
Total net cash provided by continuing operations$352 $496 $1,260 $1,565 $4,736
Net cash provided by discontinued operations (b) (105) 751
Net cash provided by operating activities$352 $496 $1,155 $1,565 $5,487
Additions to property, plant and equipment$(561)$(595)$(1,662)$(2,936)$(5,495)
Changes in working capital33 (33)141 (540)335
Cash additions to property, plant and equipment$(528)$(628)$(1,521)$(3,476)$(5,160)

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

(b) The Company's Angola assets and Norway business were sold in 2014 and are reflected as discontinued operations.

Consolidated Statements of Income (Unaudited)Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
(In millions, except per share data)20152015201420152014
Revenues and other income:
Sales and other operating revenues, including related party$1,064 $1,300 $2,001 $4,951 $8,736
Marketing revenues100 84 397 571 2,110
Income from equity method investments47 36 78 145 424
Net gain (loss) on disposal of assets228 (109)(2)120 (90)
Other income36 12 23 74 78
Total revenues and other income1,475 1,323 2,497 5,861 11,258
Costs and expenses:
Production394 406 549 1,694 2,246
Marketing, including purchases from related parties98 84 395 569 2,105
Other operating157 93 159 438 462
Exploration532 585 479 1,318 793
Depreciation, depletion and amortization668 717 801 2,957 2,861
Impairments371 337 2 752 132
Taxes other than income43 46 87 234 406
General and administrative126 125 168 590 654
Total costs and expenses2,389 2,393 2,640 8,552 9,659
Income (loss) from operations(914)(1,070)(143)(2,691)1,599
Net interest and other(87)(75)(58)(267)(238)
Income (loss) from continuing ops before income taxes(1,001)(1,145)(201)(2,958)1,361
Provision (benefit) for income taxes(208)(396)(108)(754)392
Income (loss) from continuing operations(793)(749)(93)(2,204)969
Discontinued operations (a) 1,019 2,077
Net income (loss)$(793)$(749)$926 $(2,204)$3,046
Per share data
Basic:
Income (loss) from continuing operations$(1.17)$(1.11)$(0.14)$(3.26)$1.42
Discontinued operations (a)$ $ $1.51 $ $3.06
Net income (loss)$(1.17)$(1.11)$1.37 $(3.26)$4.48
Diluted:
Income (loss) from continuing operations$(1.17)$(1.11)$(0.14)$(3.26)$1.42
Discontinued operations (a)$ $ $1.51 $ $3.04
Net income (loss)$(1.17)$(1.11)$1.37 $(3.26)$4.46
Weighted average shares:
Basic678 677 675 677 680
Diluted678 677 675 677 683

(a) The Company's Angola assets and Norway business were sold in 2014 and are reflected as discontinued operations.

Supplemental Statistics (Unaudited)Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
(in millions)20152015201420152014
Segment income (loss)
North America E&P$(219)$(61)$(143)$(486)$693
International E&P19 29 81 112 568
Oil Sands Mining(6)(11)23 (113)235
Segment income (loss)(206)(43)(39)(487)1,496
Items not allocated to segments, net of income taxes:
Corporate and unallocated(117)(95)(50)(382)(336)
Net gain (loss) on dispositions146 (71) 75 (58)
Proved property impairments(20)(213) (261)(70)
Unproved property impairments(220)(355) (575)
Goodwill impairment(340) (340)
Loss on equity method investments (8) (8)
Pension settlement(13)(12)(4)(76)(63)
Unrealized gain (loss) on crude oil derivative instruments(5)50 32
Reduction in workforce(6)(2) (35)
Alberta provincial corporate tax rate increase (135)
Other(12) (12)
Income (loss) from continuing operations(793)(749)(93)(2,204)969
Discontinued operations (a) 1,019 2,077
Net income (loss)$(793)$(749)$926 $(2,204)$3,046
Capital expenditures (b)
North America E&P$505 $564 $1,452 $2,553 $4,698
International E&P93 30 148 368 534
Oil Sands Mining (c)(36)(11)40 (10)212
Discontinued operations (a) 14 390
Corporate(1)12 22 25 51
Total$561 $595 $1,676 $2,936 $5,885
Exploration expenses
North America E&P$214 $22 $414 $362 $608
International E&P16 10 65 101 185
Segment exploration expenses230 32 479 463 793
Not allocated to segments302 553 855
Total$532 $585 $479 $1,318 $793
Provision (benefit) for income taxes
Current income taxes$8 $9 $141 $52 $304
Deferred income taxes(216)(405)(249)(806)88
Total$(208)$(396)$(108)$(754)$392

(a) The Company's Angola assets and Norway business were sold in 2014 and are reflected as discontinued operations.
(b) Capital expenditures include accruals.
(c) Reflects reimbursements earned from the governments of Canada and Alberta related to funds previously expended for Quest CCS capital equipment. Quest CCS was successfully completed and commissioned in fourth quarter 2015.

Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
(mboed)20152015201420152014
Net production available for sale
North America E&P (a)260 263 262 270 238
International E&P excluding Libya (b) and Disc Ops (c)123 114 126 116 120
Combined North America & International E&P, excluding Libya (b) and Disc Ops (c)383 377 388 386 358
Oil Sands Mining (d)49 57 42 45 41
Total continuing operations excluding Libya432 434 430 431 399
Discontinued operations (c) 9 53
Total Company excluding Libya432 434 439 431 452
Libya 22 8
Total Company432 434 461 431 460

(a) The sale of the Company's East Texas, North 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.

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

(c) The Company's Angola assets and Norway business were sold in 2014 and are reflected as discontinued operations.

(d) Upgraded bitumen excluding blendstocks.

Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
(mboed)20152015201420152014
Net production available for sale
North America E&P260 263 262 270 238
Less: Divestitures (a)(10)(14)(17)(14)(18)
Divestiture-adjusted North America E&P250 249 245 256 220

(a) Divestitures include the sale of East Texas, North 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.

Supplemental Statistics (Unaudited)Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
20152015201420152014
North America E&P - net sales volumes
Liquid hydrocarbons (mbbld)200 205 207 210 186
Bakken52 58 52 55 48
Eagle Ford99 100 107 106 91
Oklahoma resource basins13 10 9 12 8
Other North America (a)36 37 39 37 39
Crude oil and condensate (mbbld)159 166 173 171 157
Bakken48 53 49 51 45
Eagle Ford72 74 85 80 72
Oklahoma resource basins5 4 3 5 3
Other North America (a)34 35 36 35 37
Natural gas liquids (mbbld)41 39 34 39 29
Bakken4 5 3 4 3
Eagle Ford27 26 23 26 19
Oklahoma resource basins8 6 5 7 5
Other North America (a)2 2 3 2 2
Natural gas (mmcfd)345 338 331 351 310
Bakken27 19 21 22 18
Eagle Ford166 161 144 165 123
Oklahoma resource basins89 76 64 81 61
Other North America (a)63 82 102 83 108
Total North America E&P (mboed)258 261 262 269 238
International E&P - net sales volumes
Liquid hydrocarbons (mbbld)43 46 65 43 49
Equatorial Guinea29 31 32 29 31
United Kingdom14 15 11 14 11
Libya 22 7
Crude oil and condensate (mbbld)32 35 55 33 39
Equatorial Guinea18 21 22 19 21
United Kingdom14 14 11 14 11
Libya 22 7
Natural gas liquids (mbbld)11 11 10 10 10
Equatorial Guinea11 10 10 10 10
United Kingdom 1
Natural gas (mmcfd)467 441 491 439 468
Equatorial Guinea438 418 455 410 439
United Kingdom (b)29 23 34 29 28
Libya 2 1
Total International E&P (mboed)121 119 147 116 127
Oil Sands Mining - net sales volumes
Synthetic crude oil (mbbld) (c)59 65 55 53 50
Total continuing operations - net sales volumes (mboed)438 445 464 438 415
Discontinued operations - net sales volumes (mboed)(d) 10 54
Total Company - net sales volumes (mboed)438 445 474 438 469
Net sales volumes of equity method investees (mtd)
LNG6,569 5,700 6,675 5,884 6,535
Methanol1,064 1,125 1,131 937 1,092

(a) Includes Gulf of Mexico and other conventional onshore U.S. production.
(b) Includes natural gas acquired for injection and subsequent resale of 8 mmcfd, 8 mmcfd, 9 mmcfd, 8 mmcfd and 6 mmcfd in the fourth and third quarters of 2015, and fourth quarter of 2014, and the years 2015 and 2014, respectively.
(c) Includes blendstocks.
(d) The Company's Angola assets and Norway business were sold in 2014 and are reflected as discontinued operations.

Supplemental Statistics (Unaudited)Three Months EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
20152015201420152014
North America E&P - average price realizations (a)
Liquid hydrocarbons ($ per bbl)$32.47 $35.75 $59.33 $37.85 $77.02
Bakken36.03 37.41 60.09 40.23 79.41
Eagle Ford31.34 34.87 58.88 36.75 75.83
Oklahoma resource basins22.66 22.70 39.48 25.84 50.86
Other North America (b)33.98 39.25 64.05 41.16 81.88
Crude oil and condensate ($ per bbl) (c)$37.71 $41.37 $66.16 $43.50 $85.25
Bakken38.81 40.18 61.74 42.72 81.63
Eagle Ford38.27 42.74 68.63 44.45 87.99
Oklahoma resource basins38.29 40.48 68.82 43.78 87.15
Other North America (b)34.79 40.37 66.12 42.42 84.21
Natural gas liquids ($ per bbl)$12.53 $11.88 $24.80 $13.37 $33.42
Bakken5.75 5.07 33.79 6.12 43.25
Eagle Ford12.65 12.15 22.59 13.14 29.60
Oklahoma resource basins12.80 11.38 21.65 13.90 32.61
Other North America (b)22.78 23.21 38.64 24.63 51.12
Natural gas ($ per mcf)$2.12 $2.75 $3.90 $2.66 $4.57
Bakken1.62 1.96 4.75 2.23 5.28
Eagle Ford2.15 2.85 4.03 2.64 4.43
Oklahoma resource basins2.14 2.82 4.08 2.54 4.49
Other North America (b)2.22 2.70 3.44 2.93 4.65
International E&P - average price realizations
Liquid hydrocarbons ($ per bbl)$29.18 $35.88 $61.19 $36.67 $68.98
Equatorial Guinea22.82 28.03 42.40 28.50 54.29
United Kingdom41.85 52.36 58.81 53.00 93.75
Libya 89.18 94.70
Crude oil and condensate ($ per bbl)$38.43 $46.18 $72.13 $47.50 $87.23
Equatorial Guinea35.42 41.24 61.68 42.83 81.01
United Kingdom42.17 53.48 58.89 53.91 94.31
Libya 89.18 94.70
Natural gas liquids ($ per bbl)$2.08 $2.69 $1.28 $2.81 $2.46
Equatorial Guinea (d)1.00 1.00 1.00 1.00 1.00
United Kingdom31.01 28.81 43.80 32.53 67.73
Natural gas ($ per mcf)$0.58 $0.59 $0.71 $0.68 $0.72
Equatorial Guinea (d)0.24 0.24 0.24 0.24 0.24
United Kingdom5.73 6.92 7.06 6.85 8.27
Libya 0.09 3.11
Oil Sands Mining - average price realizations
Synthetic crude oil ($ per bbl)$34.65 $39.49 $65.56 $40.13 $83.35
Discontinued operations - average price realizations ($ per boe)(e) 84.16 104.10
Benchmark
WTI crude oil (per bbl)(f)$42.16 $46.50 $73.20 $48.76 $92.21
Brent (Europe) crude oil (per bbl)(g)$43.56 $50.23 $76.40 $52.35 $99.02
Henry Hub natural gas (per mmbtu)(h)$2.27 $2.77 $4.00 $2.66 $4.42
WCS crude oil (per bbl)(i)$27.69 $33.16 $58.90 $35.28 $73.60

(a) Excludes gains or losses on derivative instruments.
(b) Includes Gulf of Mexico and other conventional onshore U.S. production.
(c) Inclusion of realized gains on crude oil derivative instruments would have increased average price realizations by $3.03, $1.87, and $1.24 for fourth quarter, third quarter and full year 2015. There were no crude oil derivative instruments in 2014.
(d) 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.
(e) The Company's Angola assets and Norway business were sold in 2014 and are reflected as discontinued operations.
(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 EndedYear Ended
Dec. 31Sept. 30Dec. 31Dec. 31Dec. 31
(In millions)20152015201420152014
Production expenses
North America E&P$164 $179 $230 $724 $891
International E&P63 61 79 255 386
Total$227 $240 $309 $979 $1,277
Total Company general and administrative expenses$126 $125 $168 $590 $654
Adjustments for special items:
Pension settlement(20)(18)(6)(119)(99)
Reduction in workforce(8)(4) (55)
Adjusted general and administrative expenses (a)$98 $103 $162 $416 $555
E&P production expenses and adjusted general and administrative expenses (a)$325 $343 $471 $1,395 $1,832

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

Estimated Net Proved Reserves
North America E&PInternational E&POSMTotal
Total (mmboe)Total (mmboe)SCO (mmbbl)(mmboe)
As of Dec. 31, 2014986 564 648 2,198
Additions246 1 247
Revisions(173)(2)67 (108)
Acquisitions1 1
Dispositions(18) (18)
Production(98)(42)(17)(157)
As of Dec. 31, 2015944 521 698 2,163
Reserve Replacement Ratio (including acquisitions & dispositions)
78%
Reserve Replacement Ratio (excluding dispositions) 89%
Organic Reserve Replacement Ratio (excluding acquisitions, dispositions & revisions) 157%

Source:Marathon Oil