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Marathon Oil Announces 2018 Development Capital Budget; Reports Fourth Quarter and Full-Year 2017 Results

HOUSTON, Feb. 14, 2018 (GLOBE NEWSWIRE) -- Marathon Oil Corporation (NYSE:MRO) today announced a $2.3 billion returns-driven development capital budget for 2018, which is self-funding at $50 average WTI, including dividends, and generates meaningful free cash flow at $60 average WTI. More than 90 percent will be directed to the four U.S. resource plays, with corporate cash return on invested capital (CROIC) expected to increase by about 30 percent year over year at $50 average WTI.

/EIN News/ -- Almost 60 percent of the development budget will be allocated to the high-return Eagle Ford and Bakken assets, which have demonstrated step-change performance improvements while operating at scale. Approximately one-third of the development budget will be allocated to the Company's Northern Delaware and Oklahoma assets, where the majority of drilling activity will be transitioning to multi-well pads, while continuing strategic delineation and appraisal.

As a result of this concentrated capital allocation, the U.S. resource plays will increase to about 70 percent of the total Company production mix, driving a natural expansion in margins. Additionally, Marathon Oil expects to deliver a strong annual rate of change on the key corporate performance metrics of CROIC and cash flow per debt adjusted share (CFPDAS), both of which are now integrated into the executive compensation structure.

2018 Production Guidance
For full year 2018, the Company forecasts total production available for sale, excluding Libya, to average 390,000 to 410,000 net barrels of oil equivalent per day (boed), up 12 percent at the midpoint compared to 2017 on a divestiture-adjusted basis. Total annual oil production available for sale, excluding Libya, is expected to increase about 18 percent at the midpoint on a divestiture-adjusted basis, driven by 20 - 25 percent annual oil growth in the U.S. resource plays.

For first quarter 2018, U.S. production is expected to average 265,000 to 275,000 net boed. International production, excluding Libya, is expected to average 105,000 to 115,000 net boed, which reflects planned turnaround activity in EG.

2017 Review

  • Achieved cash flow neutrality*, including dividends and working capital, with $51 average WTI
  • Total production (excluding Libya) of 358,000 net boed; up 9% year over year on a divestiture-adjusted basis
  • U.S. resource plays exited 2017 with oil production 31% higher than fourth quarter 2016
  • Entered Northern Delaware basin and divested Canadian oil sands business
  • Reduced unit production costs 7% for U.S. E&P and 6% for International E&P (excluding Libya) compared to the prior year
  • Reduced gross debt by approximately $1.75 billion, lowering annualized interest expense by $115 million
  • Organic reserve replacement of 121%, excluding acquisitions and dispositions, at a drillbit finding and development cost of $12.81 per boe

* Excludes a one-time $108 million U.K. tax payment that is currently under appeal.

"We finished 2017 with another quarter of outstanding operational execution across all four resource plays," said Marathon Oil President and CEO Lee Tillman. "We delivered some of the most productive unconventional wells in our Company’s history in our high-return Eagle Ford and Bakken assets, while achieving strong rates from our nine-well STACK infill development and excellent well results across the Northern Delaware. Last year we reached key milestones in our portfolio transformation, further strengthened our balance sheet, drove costs even lower and delivered production near the top of our production guidance, all while maintaining cash flow neutrality. In 2018, we expect to improve corporate-level returns from our disciplined development capital program that's self-funding at $50 and will generate meaningful free cash flow at $60 average WTI, including the dividend."

Marathon Oil reported a fourth quarter 2017 net loss of $28 million, or $0.03 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 $56 million, or $0.07 per diluted share. Net operating cash flow was $501 million, or $637 million before changes in working capital and the one-time U.K. tax payment.

Fourth Quarter 2017 Highlights

  • Total Company production excluding Libya averaged 383,000 net boed, up 4% sequentially on a divestiture-adjusted basis; 33,000 net boed from Libya
  • U.S. resource play production averaged 249,000 net boed, up 10% sequentially
  • Eagle Ford production averaged 105,000 net boed; up 4% sequentially with fewer wells to sales
  • Bakken production increased 17% sequentially to 69,000 net boed; set new Williston Basin 30-day IP oil record at 3,005 bpd
  • Oklahoma production up 10% sequentially to 64,000 net boed; nine-well STACK infill development averaged 30-day IP rates of 1,840 boed (60% oil)
  • Northern Delaware production averaged 11,000 net boed; two-well pad averaged 30-day IP rates of 3,265 boed (62% oil)

U.S. E&P
U.S. E&P production available for sale averaged 262,000 net boed for fourth quarter 2017. On a divestiture-adjusted basis, production was up 8 percent compared to the prior quarter and up 27 percent from the year-ago quarter. Fourth quarter unit production costs were $5.33 per barrel of oil equivalent (boe), down from $5.38 in the previous quarter, and a new record low for the Company since becoming an independent E&P in 2011. Full-year unit production costs averaged $5.57 per boe.

EAGLE FORD: Marathon Oil's production in the Eagle Ford averaged 105,000 net boed in the fourth quarter, up from 101,000 net boed in the prior quarter. The Company brought 33 gross Company-operated wells to sales in the fourth quarter with average 30-day initial production (IP) rates of 1,800 boed (73% oil). The testing of enhanced completion designs in Atascosa County continued to deliver encouraging results. The five-well Guajillo Unit 8 South pad delivered average 30-day IP rates of 1,730 boed (77% oil, 6,300-foot average lateral length) and the three-well Middle McCowen pad, the Company's western-most test of 2017, achieved average 30-day IP rates of 2,080 boed (87% oil, 9,915-foot average lateral length). In Karnes County, average 30-day IP rates from two Austin Chalk wells on the Challenger pad were 2,415 boed (75% oil, 5,350-foot average lateral length).

BAKKEN: In fourth quarter 2017, Marathon Oil's Bakken production averaged 69,000 net boed, up 17 percent compared to 59,000 net boed in the prior quarter. The Company brought 13 gross Company-operated wells to sales in the fourth quarter, nine of which came in West Myrmidon with average 30-day IP rates of 2,935 boed. The Forsman Middle Bakken well in West Myrmidon set a new Williston Basin 30-day IP oil record with a rate of 3,005 barrels per day. The testing of enhanced completion designs continued to deliver encouraging results, with the three-well Chapman pad on the eastern side of Hector achieving average 30-day IP rates of 1,810 boed (85% oil).

OKLAHOMA: The Company's production in Oklahoma increased 10 percent to 64,000 net boed during fourth quarter 2017, up from 58,000 net boed in the prior quarter. The Company brought 26 gross Company-operated wells to sales during the quarter predominately focused in the STACK on Meramec infill wells and leasehold activity. The Company's first STACK volatile oil infill development, the Tan, in southwest Kingfisher County averaged 30-day IP rates of 1,840 boed (60% oil). The nine new infills were comprised of eight XL wells (10,400-foot average lateral length) and one SL well (5,400-foot lateral length). The Eve, the Company's third and farthest east infill spacing pilot in Kingfisher County’s black oil window, averaged 30-day IP rates from the five new wells of 715 boed (65% oil, 5,000-foot average lateral length).

NORTHERN DELAWARE: The Company's Northern Delaware production averaged 11,000 net boed in fourth quarter 2017, up from 9,000 net boed in the prior quarter. The Company brought 11 gross Company-operated wells to sales in Eddy and Lea Counties, which had 30-day IP rates that averaged 1,835 boed (66% oil). A two-well pad achieved average 30-day IP rates of 3,265 boed (62% oil) and a nearby third well averaged a 30-day rate of 2,910 boed (63% oil).

International E&P
International E&P production available for sale (excluding Libya) averaged 121,000 net boed for fourth quarter 2017. This compares to 126,000 net boed in the prior quarter, and 129,000 net boed in the year-ago quarter. The decrease was due to the temporary shut-down of the outside-operated Forties Pipeline System and planned turn-around activity in the U.K, as well as natural field declines. Libya production available for sale averaged 33,000 net boed in the fourth quarter. Fourth quarter 2017 International E&P unit production costs (excluding Libya) averaged $3.85 per boe. Full-year 2017 unit production costs (excluding Libya) were $4.13 per boe, below the low end of guidance of $4.50 to $5.50 per boe.

Corporate and Special Items
Net cash provided by continuing operations was $501 million during fourth quarter 2017, or $637 million before changes in working capital and the one-time U.K. tax payment under appeal. Fourth quarter 2017 cash additions to property, plant and equipment (PP&E) were $669 million, up sequentially due to the timing of invoice payments and resource play exploration leasing.

As previously disclosed, Marathon Oil received an adverse ruling from the U.K. first-tier tax tribunal during fourth quarter 2017 related to the timing of deductibility for certain Brae area decommissioning costs. While the Company is appealing the ruling, the Company was required to pay the disputed tax amount of $108 million in order to pursue the appeal.

Total liquidity as of Dec. 31 was approximately $4 billion, which consisted of $560 million in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion. Remaining proceeds of $750 million from the sale of the Company's Canadian subsidiary are scheduled to be received in March.

The adjustments to net income from continuing operations for fourth quarter 2017 totaled $96 million before tax, and include an unrealized loss of $145 million on commodity derivatives and $24 million proved property impairment, partially offset by a $32 million gain from dispositions.

Reserves
During 2017, Marathon Oil added proved reserves of 193 million boe for a reserve replacement ratio of 140 percent excluding dispositions. Virtually all of the additions were in U.S. E&P. The Company's organic reserve replacement ratio, excluding acquisitions and dispositions, was 121 percent at a drillbit finding and development (F&D) cost of $12.81. Net proved reserves were approximately 1.45 billion boe at year-end 2017, down from year-end 2016 primarily due to the sale of the Canadian Oil Sands business.

A slide deck and Quarterly Investor Packet will be posted to the Company's website at https://www.marathonoil.com/Investors following this release today, Feb. 14. The Company will conduct a question and answer webcast/call on Thursday, Feb. 15, at 9:00 a.m. ET. The commentary and answers to questions will include forward-looking information. To listen to the live webcast, visit the Marathon Oil website at https://www.marathonoil.com. The audio replay of the webcast will be posted by Feb. 16.


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).

CFPDAS - Cash flow per debt adjusted share; calculated by taking cash flow (operating cash flow before working capital + net interest after tax) divided by total shares including debt shares. Debt shares is the average net debt during a calendar year divided by the average annual stock price.

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), net cash provided by operations before changes in working capital and the one-time U.K. tax payment under appeal, CROIC and CFPDAS 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 and the one-time U.K. tax payment under appeal to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. The Company considers adjusted net income (loss) as another way to meaningfully represent our 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. CROIC and CFPDAS will be integrated into our executive compensation structure and management will use this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. 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. See the tables below for reconciliations between each of adjusted net income (loss) and net cash provided by operations before changes in working capital and the one-time U.K. tax payment under appeal and its most directly comparable GAAP financial measure. A reconciliation of CROIC’s components to their most directly comparable GAAP financial measures can be found in our investor package on our website at www.marathonoil.com. 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 2018 capital budget and allocations, future performance, free cash flow, corporate cash return on invested capital, business strategy, asset quality, cash margins, production, rates of change for CROIC and CFPDAS, future payments for the Canadian disposition, 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; the inability for any party to satisfy closing conditions with respect to the Canadian subsidiary disposition; 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 2016 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:
Zach Dailey: 713-296-4140
John Reid: 713-296-4380

Consolidated Statements of Income (Unaudited) Three Months Ended Year Ended
  Dec. 31
2017
  Sept. 30
2017
  Dec. 31
2016
  Dec. 31
2017
  Dec. 31
2016
 
(In millions, except per share data)          
Revenues and other income:          
Sales and other operating revenues, including related party $ 1,185   $ 1,114   $ 898   $ 4,211   $ 2,930  
Marketing revenues 45   48   38   162   240  
Income from equity method investments 73   63   65   256   175  
Net gain (loss) on disposal of assets 32   19   108   58   389  
Other income 47   8   15   78   53  
Total revenues and other income 1,382   1,252   1,124   4,765   3,787  
Costs and expenses:          
Production 185   194   180   706   712  
Marketing, including purchases from related parties 47   49   44   168   245  
Other operating 122   109   111   431   484  
Exploration 57   294   34   409   323  
Depreciation, depletion and amortization 583   641   573   2,372   2,156  
Impairments 24   201   19   229   67  
Taxes other than income 55   44   38   183   151  
General and administrative 101   97   95   400   481  
Total costs and expenses 1,174   1,629   1,094   4,898   4,619  
Income (loss) from operations 208   (377 ) 30   (133 ) (832 )
Net interest and other (71 ) (35 ) (76 ) (270 ) (332 )
Loss on early extinguishment of debt (5 ) (46 )   (51 )  
Income (loss) from continuing operations before income taxes 132   (458 ) (46 ) (454 ) (1,164 )
  Provision (Benefit) for income taxes 160   141   1,337   376   923  
Income (loss) from continuing operations (28 ) (599 ) (1,383 ) (830 ) (2,087 )
Discontinued operations (a)     12   (4,893 ) (53 )
Net income (loss) $ (28 ) $ (599 ) $ (1,371 ) $ (5,723 ) $ (2,140 )
           
Adjusted Net Income          
Income (loss) from continuing operations (28 ) (599 ) (1,383 ) (830 ) (2,087 )
Adjustments for special items from continuing operations (pre-tax):          
Net (gain) loss on dispositions (32 ) (19 ) (108 ) (57 ) (379 )
Proved property impairments 24   201     225   47  
Exploratory dry well costs, unproved property impairments and other   250     250   118  
Pension settlement 7   8   10   32   103  
Unrealized (gain) loss on derivative instruments 145   56   21   81   110  
Gain on termination of interest rate swaps   (47 )   (47 )  
Loss on extinguishment of debt 5   46     51    
Rig termination payment         113  
Other (53 ) (4 ) (4 ) (59 ) 55  
Provision (benefit) for income taxes related to special items from continuing operations (12 ) (1 ) 23   (13 ) (66 )
Valuation Allowance   41   1,346   41   1,346  
Adjusted net income (loss) from continuing operations (b) $ 56   $ (68 ) $ (95 ) $ (326 ) $ (640 )
Income (loss) from discontinued operations (a)     12   (4,893 ) (53 )
Adjustments for special items from discontinued operations (pre-tax):          
Canadian oil sands business impairment (a)       6,636    
Net (gain) loss on disposition (a)       43    
Provision (benefit) for income taxes related to special items from discontinued operations (a)       (1,674 )  
Adjusted net income (loss) (b) $ 56   $ (68 ) $ (83 ) $ (214 ) $ (693 )
Per diluted share:          
Income (loss) from continuing operations $ (0.03 ) $ (0.70 ) $ (1.63 ) $ (0.97 ) $ (2.55 )
Net Income (loss) $ (0.03 ) $ (0.70 ) $ (1.62 ) $ (6.73 ) $ (2.61 )
Adjusted net income (loss) from continuing operations (b) $ 0.07   $ (0.08 ) $ (0.11 ) $ (0.38 ) $ (0.78 )
Adjusted net income (loss) (b) $ 0.07   $ (0.08 ) $ (0.10 ) $ (0.25 ) $ (0.85 )
Weighted average diluted shares 850   850   847   850   819  
(a) The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017.  The Canadian oil sands business is reflected as discontinued operations in all periods presented
(b) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion. 


Supplemental Statistics (Unaudited) Three Months Ended Year Ended
  Dec. 31
2017
  Sept. 30
2017
  Dec. 31
2016
  Dec. 31
2017
  Dec. 31
2016
 
(in millions)          
Segment income (loss)          
United States E&P $ 76   $ (38 ) $ (91 ) $ (148 ) $ (415 )
International E&P 118   104   110   374   228  
Segment income (loss) 194   66   19   226   (187 )
Not allocated to segments (222 ) (665 ) (1,402 ) (1,056 ) (1,900 )
Loss from continuing operations (28 ) (599 ) (1,383 ) (830 ) (2,087 )
Discontinued operations (a)     12   (4,893 ) (53 )
Net income (loss) $ (28 ) $ (599 ) $ (1,371 ) $ (5,723 ) $ (2,140 )
Exploration expenses          
United States E&P $ 57   $ 41   $ 37   $ 154   $ 127  
International E&P   3   (3 ) 5   17  
Segment exploration expenses 57   44   34   159   144  
Not allocated to segments   250     250   179  
Total $ 57   $ 294   $ 34   $ 409   $ 323  
Cash flows          
Net cash provided by operating activities from continuing operations $ 501   $ 564   $ 375   $ 1,988   $ 901  
Minus: changes in working capital (28 ) 62   12   (27 ) (6 )
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) $ 637   $ 502   $ 363   $ 2,123   $ 907  
Net cash provided by operating activities from discontinued operations (a)     80   141   177  
           
Cash additions to property, plant and equipment $ (669 ) $ (530 ) $ (255 ) $ (1,974 ) $ (1,204 )
(a) The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017. The Canadian oil sands business is reflected as discontinued operations in all periods presented
(b) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.


  Three Months Ended Year Ended
  Dec. 31   Sept. 30   Dec. 31   Dec. 31   Dec. 31  
(mboed) 2017   2017   2016   2017   2016  
Net production available for sale          
United States E&P (a) 262   245   212   235   223  
International E&P excluding Libya (b) 121   126   129   123   119  
Total continuing operations, excluding Libya (b) 383   371   341   358   342  
Libya 33   23   8   19   3  
Total continuing operations 416   394   349   377   345  
(a) The Company closed on the sale of certain Oklahoma and Colorado assets in September 2017 and October 2017, respectively. The sales of certain Wyoming assets closed in 2016.
(b) Libya is excluded because of the timing of future production and sales levels.


  Three Months Ended Year Ended
  Dec. 31   Sept. 30   Dec. 31   Dec. 31   Dec. 31  
(mboed) 2017   2017   2016   2017   2016  
Net production available for sale          
United States E&P 262   245   212   235   223  
Less:  Divestitures (a) (1 ) (3 ) (6 ) (2 ) (16 )
Divestiture-adjusted United States E&P 261   242   206   233   207  
Divestiture-adjusted total continuing operations 415   391   343   375   329  
Discontinued operations (b)     47   18   48  
(a) Divestitures include the sale of certain conventional assets in Oklahoma in September 2017 and Colorado in October 2017. These production volumes have been removed from all periods shown in arriving at divestiture-adjusted United States E&P net production available for sale.
(b) The Company closed on its sale of the Canadian oil sands business on May 31, 2017. The Canadian oil sands business is reflected as discontinued operations in all periods presented.


Supplemental Statistics (Unaudited) Three Months Ended Year Ended
  Dec. 31   Sept. 30   Dec. 31   Dec. 31   Dec. 31  
  2017   2017   2016   2017   2016  
United States E&P - net sales volumes          
Liquid hydrocarbons (mbbld) 199   183   160   176   171  
Oklahoma 34   31   24   29   18  
Eagle Ford 84   80   74   80   82  
Bakken 64   55   47   52   50  
Northern Delaware 9   6     5    
Other United States (a) 8   11   15   10   21  
Crude oil and condensate (mbbld) 150   139   121   133   131  
Oklahoma 16   17   13   15   9  
Eagle Ford 61   58   54   59   60  
Bakken 58   49   41   46   44  
Northern Delaware 8   6     4    
Other United States (a) 7   9   13   9   18  
Natural gas liquids (mbbld) 49   44   39   43   40  
Oklahoma 18   14   11   14   9  
Eagle Ford 23   22   20   21   22  
Bakken 6   6   6   6   6  
Northern Delaware 1       1    
Other United States (a) 1   2   2   1   3  
Natural gas (mmcfd) 376   369   315   348   314  
Oklahoma 180   161   123   149   102  
Eagle Ford 127   126   119   125   137  
Bakken 26   26   26   25   25  
Northern Delaware 14   15     9    
Other United States (a) 29   41   47   40   50  
Total United States E&P (mboed) 262   244   212   234   223  
International E&P - net sales volumes          
Liquid hydrocarbons (mbbld) 71   81   64   64   46  
Equatorial Guinea 32   39   32   32   31  
Libya 29   23   10   19   3  
United Kingdom 6   16   22   11   12  
Other International 4   3     2    
Crude oil and condensate (mbbld) 58   68   52   52   35  
Equatorial Guinea 20   27   20   21   20  
Libya 29   23   10   19   3  
United Kingdom 5   15   22   10   12  
Other International 4   3     2    
Natural gas liquids (mbbld) 13   13   12   12   11  
Equatorial Guinea 12   12   12   11   11  
United Kingdom 1   1     1    
Natural gas (mmcfd) 493   507   482   485   453  
Equatorial Guinea 464   482   454   459   425  
Libya 14       4    
United Kingdom (b) 15   25   28   22   28  
Total International E&P (mboed) 153   165   145   145   122  
Total Company continuing operations - net sales volumes (mboed) 415   409   357   379   345  
Net sales volumes of equity method investees          
LNG (mtd) 6,353   6,943   6,743   6,423   5,874  
Methanol (mtd) 1,637   1,366   1,316   1,374   1,358  
Condensate and LPG (boed) 14,605   17,216   15,381   14,501   13,430  
(a) Includes production from conventional onshore assets sold in the applicable periods. The sale of certain Oklahoma and Colorado assets closed in September 2017 and October 2017, respectively. The sales of certain Wyoming assets closed in 2016.
(b) Includes natural gas acquired for injection and subsequent resale.


Supplemental Statistics (Unaudited) Three Months Ended Year Ended
  Dec. 31
2017
  Sept. 30
2017
  Dec. 31
2016
  Dec. 31
2017
  Dec. 31
2016
 
           
United States E&P - average price realizations (a)          
Liquid hydrocarbons ($ per bbl) $ 47.61   $ 40.48   $ 39.00   $ 42.31   $ 32.71  
Oklahoma 38.41   35.84   34.28   36.07   28.15  
Eagle Ford 48.32   39.87   38.16   41.86   31.61  
Bakken 51.38   43.09   41.96   45.83   35.65  
Northern Delaware 50.35   44.00     46.08    
Other United States (b) 46.26   43.23   41.69   43.82   33.96  
Crude oil and condensate ($ per bbl) (c) $ 55.46   $ 46.65   $ 45.89   $ 49.35   $ 38.57  
Oklahoma 53.90   46.39   46.30   48.79   41.78  
Eagle Ford 57.82   47.56   45.96   49.93   38.76  
Bakken 54.42   46.06   46.28   49.28   39.25  
Northern Delaware 53.74   44.49     48.84    
Other United States (b) 48.87   45.83   43.78   46.98   34.93  
Natural gas liquids ($ per bbl) $ 23.60   $ 20.86   $ 17.31   $ 20.55   $ 13.15  
Oklahoma 24.16   23.58   20.79   22.74   15.84  
Eagle Ford 22.54   19.52   16.34   19.32   12.40  
Bakken 24.09   17.89   11.97   18.38   8.56  
Northern Delaware 26.79   30.23     24.04    
Other United States (b) 30.06   24.94   24.56   24.61   23.51  
Natural gas ($ per mcf) (d) $ 2.65   $ 2.71   $ 2.87   $ 2.84   $ 2.38  
Oklahoma 2.54   2.69   2.90   2.82   2.47  
Eagle Ford 2.82   2.83   2.91   2.89   2.37  
Bakken 2.82   2.08   2.63   2.80   2.12  
Northern Delaware 2.37   3.00     2.70    
Other United States (b) 2.56   2.67   2.82   2.82   2.38  
International E&P - average price realizations          
Liquid hydrocarbons ($ per bbl) $ 51.13   $ 43.69   $ 37.85   $ 43.36   $ 32.10  
Equatorial Guinea 33.56   32.78   26.60   29.62   25.78  
Libya 68.31   56.93   57.69   60.72   57.69  
United Kingdom 59.11   51.12   45.02   53.52   42.52  
Other International 48.89   40.67     44.73    
Crude oil and condensate ($ per bbl) $ 61.32   $ 51.23   $ 46.14   $ 53.05   $ 41.70  
Equatorial Guinea 52.92   46.91   41.60   46.02   38.85  
Libya 68.31   56.93   57.69   60.72   57.69  
United Kingdom 61.94   51.72   45.18   54.51   43.21  
Other International 48.89   40.67     44.73    
Natural gas liquids ($ per bbl) $ 4.66   $ 2.25   $ 1.72   $ 3.15   $ 2.11  
Equatorial Guinea (e) 1.00   1.00   1.00   1.00   1.00  
United Kingdom 45.71   32.58   32.58   39.65   26.41  
Natural gas ($ per mcf) $ 0.59   $ 0.51   $ 0.53   $ 0.55   $ 0.52  
Equatorial Guinea (e) 0.24   0.24   0.24   0.24   0.24  
Libya 5.03       5.03    
United Kingdom 7.20   5.71   5.39   6.28   4.80  
Benchmark          
WTI crude oil (per bbl) $ 55.30   $ 48.20   $ 49.29   $ 50.85   $ 43.47  
Brent (Europe) crude oil (per bbl)(f) $ 61.53   $ 52.11   $ 49.19   $ 54.25   $ 43.55  
Henry Hub natural gas (per mmbtu)(g) $ 2.93   $ 3.00   $ 2.98   $ 3.11   $ 2.46  
(a) Excludes gains or losses on derivative instruments.
(b) Includes production from conventional onshore assets sold in the applicable periods. The sale of certain Oklahoma and Colorado assets closed in September 2017 and October 2017, respectively. The sales of certain Wyoming assets closed in 2016.
(c) Inclusion of crude oil derivative instruments would have affected liquid hydrocarbons average price realizations by a realized loss of $0.76, and realized gains of $2.42, $0.32, $0.75, $0.92, for the fourth and third quarter of 2017, fourth quarter of 2016, and the years 2017 and 2016, 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) 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 E&P segment.
(f) Average of monthly prices obtained from Energy Information Administration ("EIA") website.
(g) Settlement date average per mmbtu.


       
Estimated Net Proved Reserves from Continuing Operations (mmboe) U.S E&P Intl. E&P Total
As of Dec. 31, 2016 948   456   1,404  
Additions 98   18   116  
Revisions 42   7   49  
Acquisitions 28     28  
Dispositions (10 )   (10 )
Production (86 ) (52 ) (138 )
As of Dec. 31, 2017 1,020   429   1,449  
       
Changes in Reserves (excluding dispositions) (mmboe)     193  
Production (mmboe)     138  
Reserve Replacement Ratio (excluding dispositions) (a)     140 %
       
Organic Changes in Reserves (excluding acquisitions, dispositions) (mmboe)     165  
Production (mmboe)     136  
Organic Reserve Replacement Ratio (excluding acquisitions, dispositions) (a)     121 %
       
Finding Costs ($ in millions, except as indicated)     2017
Property Acquisition Costs - Proved     $ 192  
Property Acquisition Costs - Unproved     1,747  
Exploration     923  
Development     993  
Total Company - Costs Incurred from Continuing Operations     $ 3,855  
       
Cost Incurred     $ 3,855  
Changes in Reserves (excluding dispositions) (mmboe)     193  
Finding and development costs per BOE     $ 19.97  
       
Costs Incurred     $ 3,855  
Property Acquisition Costs     (1,939 )
Capitalized Asset Retirement Costs     197  
Adjusted finding and development costs (a)     $ 2,113  
Organic Changes in Reserves (excluding acquisitions, dispositions) (mmboe)     165  
Adjusted finding and development costs per BOE (a)     $ 12.81  
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

The following tables set forth outstanding derivative contracts as of February 12, 2018 and the weighted average prices for those contracts:

Crude Oil
    2018       2019  
(unaudited) First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
Three-Way Collars (a)                              
Volume (Bbls/day)   85,000       85,000       95,000       95,000       30,000       30,000              
Weighted average price per Bbl:                              
Ceiling $ 56.38     $ 56.38     $ 57.65     $ 57.65     $ 65.27     $ 65.27     $     $  
Floor $ 51.65     $ 51.65     $ 52.11     $ 52.11     $ 54.00     $ 54.00     $     $  
Sold put $ 45.00     $ 45.00     $ 45.21     $ 45.21     $ 46.67     $ 46.67     $     $  
Swaps                              
Volume (Bbls/day)   20,000       20,000                                      
Weighted average price per Bbl $ 55.12     $ 55.12     $     $     $     $     $     $  
Basis Swaps (b)                              
Volume (Bbls/day)   5,000       5,000       10,000       10,000       10,000       10,000       10,000       10,000  
Weighted average price per Bbl $ (0.60 )   $ (0.60 )   $ (0.67 )   $ (0.67 )   $ (0.82 )   $ (0.82 )   $ (0.82 )   $ (0.82 )
(a) Includes contracts we entered into between January 1, 2018 and February 12, 2018, of 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.
(b) The basis differential price is between WTI Midland and WTI Cushing. We entered into 10,000 Bbls/day of basis swaps for 2019 subsequent to December 31, 2017.


Natural Gas
    2018
  First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Three-Way Collars        
Volume (MMBtu/day)   200,000   160,000   160,000   160,000
Weighted average price per MMBtu        
Ceiling $ 3.79 $ 3.61 $ 3.61 $ 3.61
Floor $ 3.08 $ 3.00 $ 3.00 $ 3.00
Sold put $ 2.55 $ 2.50 $ 2.50 $ 2.50

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