We are an international energy company with operations in the U.S., Canada, Africa, the Middle East and Europe. Our operations are organized into three reportable segments:

w Exploration and Production ("E&P") which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.
w Oil Sands Mining ("OSM") which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
w Integrated Gas ("IG") which produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG") and methanol, in Equatorial Guinea.

Certain sections of Management's Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as "anticipates," "believes," "estimates," "expects," "targets," "plans," "projects," "could," "may," "should," "would" or similar words indicating that future outcomes are uncertain. In accordance with "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2011 Annual Report on Form 10-K.

Key Operating and Financial Activities

In the first quarter of 2012, notable items were:

· Net liquid hydrocarbon and natural gas sales volumes of 383 thousand barrels of oil equivalent per day ("mboed"), of which 62 percent was liquid hydrocarbons

· Net international liquid hydrocarbon sales volumes, for which average realizations have exceeded West Texas Intermediate ("WTI") crude oil, were 62 percent of total liquid hydrocarbon sales

· Resumed liftings from Libya for average net sales of 17 mboed and production available for sale of 35 mboed

· Net synthetic crude oil sales of 44 thousand barrels per day ("mbbld"), a 19 percent increase over the same period of last year

· Average net sales volumes of 26 mboed from the Bakken shale, an 86 percent increase over the same quarter of last year

· Average net sales volumes of 14 mboed from the Eagle Ford shale, with 17 dedicated drilling rigs and 4 dedicated hydraulic fracturing crews working in the Eagle Ford shale

· Gulf of Mexico Ozona development impairment of $261 million due to a 2 million barrels of oil equivalent ("mmboe") reduction in estimated proved reserves

· Cash-adjusted debt-to-capital ratio of 20 percent

· Disposed of our interests in several Gulf of Mexico crude oil pipeline systems for a pretax gain of $166 million

Some significant April 2012 activities include:

· Replaced existing revolving credit facility with a new $2.5 billion facility maturing April 2017

· Entered an agreement to dispose of all of our assets in Alaska

· Entered multiple agreements to expand holdings in the core of the Eagle Ford shale by approximately 20,000 net acres

Overview and Outlook

Exploration and Production

Production

Net liquid hydrocarbon and natural gas sales averaged 383 mboed during the first quarter of 2012 compared to 400 mboed in the same quarter of 2011. Net liquid hydrocarbon sales volumes increased in the U.S., reflecting the impact of the Eagle Ford shale assets acquired in the fourth quarter of 2011 and our ongoing development programs in the Eagle Ford, Bakken and other U.S. unconventional resource plays. Net liquid hydrocarbon sales volumes from the U.K. were lower in the first quarter of 2012 than in the same period of 2011 due to unplanned repairs at Foinaven and the timing of liftings.

In the Eagle Ford shale, we had 17 operated rigs drilling and four hydraulic fracturing crews working as of March 31, 2012. Net liquid hydrocarbon sales were 14 mboed for the first quarter of 2012. To complement drilling and completions activity, we continue to build infrastructure to support production growth across the operating area. Approximately 90 miles of gathering lines were installed in the first quarter of 2012, in addition to two new central gathering and treating facilities, with six additional facilities currently under construction.

First quarter 2012 average net sales volumes from the Bakken shale were 26 mboed compared to 14 mboed in the same quarter of 2011. Our Bakken liquid hydrocarbon volumes average approximately 95 percent crude oil. We have eight drilling rigs and three hydraulic fracturing crews working in the play. Additionally, our drilling pace has exceeded expectations this year with improved "spud-to-spud" drilling times.

In the Anadarko Woodford shale, net sales volumes averaged 5 mboed during the first quarter of 2012 compared to 1 mboed in the same quarter of 2011. We have six drilling rigs working in the Anadarko Woodford play, where performance is being driven by continued strong results in the Cana core area, and additional operated activity on our Knox acreage position. We are planning to begin an 80-acre infill project in the Knox area in May 2012.

In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed and during the first quarter of 2012, sales volumes were 17 mboed. The return of our operations in Libya to pre-conflict levels is unknown at this time; however, we and our partners in the Waha concessions are assessing the condition of our assets.

Our E&P segment's Ozona development in the Gulf of Mexico began production in December 2011. During the first quarter of 2012, production rates declined significantly and have remained below initial expectations. Accordingly, our reserve engineers performed an evaluation of our future production as well as our reserves which concluded in early April 2012. This resulted in a 2 mmboe reduction in proved reserves and a $261 million impairment charge in the first quarter of 2012.

A 28-day turnaround began at our production operations in Equatorial Guinea on March 23, 2012. It was completed in April 2012 seven days ahead of schedule and below budget.

Exploration

During the first quarter of 2012, on the Birchwood oil sands lease located in Alberta, Canada, we conducted a seismic survey and drilled six water wells. We also submitted a regulatory application for a proposed 12 mbbld steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, construction is expected to begin in 2014, with first oil projected in 2016. We have a 100 percent working interest in Birchwood.

Acquisitions and Divestitures

On January 3, 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This includes our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded in the first quarter of 2012.

In April 2012, we entered agreements to sell all our assets in Alaska. The transactions are expected to close in the second half of 2012, pending regulatory approval and closing conditions.

In April 2012, we entered multiple agreements to acquire approximately 20,000 net acres in the core of the Eagle Ford shale formation in transactions valued at $767 million, subject to closing adjustments. The majority of the transactions in terms of value are expected to close in the third quarter of 2012. In addition to undeveloped acreage, on the date of the agreements, these transactions included 13 gross wells producing 7 net mboed. Approximately 45 percent of the acreage is held by production.

The above discussions include forward-looking statements with respect to the timing of the commencement of construction and first oil on the SAGD project, the sale of the Alaska assets, and acquisitions in the Eagle Ford shale. The timing of the commencement of construction and first oil on the SAGD project can be affected by delays in obtaining and conditions imposed by necessary government and third-party approvals, board approval, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, and other risks associated with construction projects. The completion of the sale of substantially all of the Alaska assets is subject to necessary government and regulatory approvals and customary closing conditions. The sale of the Alaska drilling rig is subject to the buyer's exercise of its purchase right under the purchase and sale agreement. The acquisitions in the Eagle Ford shale are subject to customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Oil Sands Mining

Our OSM operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project ("AOSP"). Our net synthetic crude oil sales were 44 mbbld in the first quarter of 2012 compared to 37 mbbld in the same quarter of 2011. This sales increase is primarily due to less downtime for planned and unplanned maintenance in the 2012 period.

With production capacity at the AOSP now at 255,000 gross barrels per day, the focus will be on improving operating efficiencies and adding capacity through debottlenecking.

Integrated Gas

LNG and methanol sales from Equatorial Guinea are conducted through equity method investees that purchase dry gas from our E&P assets in Equatorial Guinea. Our share of LNG sales totaled 6,291 metric tonnes per day ("mtd") for the first quarter of 2012 compared to 7,822 mtd in the first quarter of 2011. LNG sales volumes are down because the first quarter of 2011 also included LNG sales from Alaska which were conducted through a consolidated subsidiary. LNG sales from Alaska ceased when our interest was sold in the third quarter of 2011. Also, a 30-day turnaround began at the LNG facility in Equatorial Guinea on March 23, 2012. Full production resumed ahead of schedule on April 17, 2012.

Market Conditions


Exploration and Production

Prevailing prices for the various qualities of crude oil and natural gas that we
produce significantly impact our revenues and cash flows. Prices have been
volatile in recent years. The following table lists the benchmark crude oil and
natural gas price averages in the first quarter in 2012 compared to the same
period in 2011.

                                                                  Three Months Ended March 31,
                                                                    2012                 2011
West Texas Intermediate ("WTI") crude oil (Dollars per bbl)    $       103.03       $        94.60
Brent (Europe) crude oil (Dollars per bbl)                     $       118.49       $       104.96
Henry Hub natural gas (Dollars per million British thermal
units ("mmbtu"))(a)                                            $         2.74       $         4.11


                          (a) Settlement date average.

In the first quarter of 2012, average crude oil benchmark prices increased compared to the same quarter of 2011. The average differential of Brent to WTI was a premium of approximately $15 per barrel in the first quarter of 2012. Our international crude oil production is relatively sweet and a majority is sold in relation to the Brent crude oil benchmark.

Our domestic crude oil production was about 47 percent sour in the first quarter of 2012 compared to 70 percent in the first quarter of 2011. Reduced production from the Gulf of Mexico and increased onshore production from the Bakken and Eagle Ford shales contributed to the lower sour crude percentage. Sour crude oil contains more sulfur than light sweet WTI. Sour crude oil also tends to be heavier than and sells at a discount to light sweet crude oil because of its higher refining costs and lower refined product values.

A significant portion of our natural gas production in the lower 48 states of the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Average Henry Hub settlement prices for natural gas were lower for the first quarter of 2012 compared to the same quarter of the prior year. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and has continued beyond the first quarter of 2012 with April averaging $2.19 per mmbtu. Should U.S. natural gas prices remain depressed, impairment charges related to our natural gas assets may be necessary.

Our other major natural gas-producing regions are Europe and Equatorial Guinea. Natural gas prices in Europe have been higher than the U.S. in recent periods. In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.

Oil Sands Mining

OSM segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas oil we produce. Roughly two-thirds of our normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil market, primarily Western Canadian Select. Output mix can be impacted by operational problems or planned unit outages at the mine or upgrader.

The operating cost structure of the oil sands mining operations is predominantly fixed, and therefore many of the costs incurred in times of full operation continue during production downtime. Per unit costs are sensitive to production rate. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude prices, respectively. Recently AECO prices have declined, much as Henry Hub prices have. We would expect a significant, continued decline in natural gas prices to have a favorable impact on OSM operating costs.

The table below shows benchmark prices that impacted both our revenues and variable costs for the first quarter of 2012 compared to first quarter of 2011.

                                                                  Three Months Ended March 31,
Benchmark                                                           2012                 2011
WTI crude oil (Dollars per barrel)                             $        103.03       $       94.60
Western Canadian Select (Dollars per barrel)(a)                $         81.51       $       71.24
AECO natural gas sales index (Dollars per mmbtu)(b)            $          2.18       $        3.85

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

(b) Monthly average AECO day ahead index.

Integrated Gas

Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea

We have a 60 percent ownership in an LNG production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices.

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in Atlantic Methanol Production Company LLC ("AMPCO"). Methanol demand has a direct impact on AMPCO's earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. AMPCO's plant capacity of 1.1 million tones is about 2 percent of 2011 estimated world demand.

Results of Operations

Consolidated Results of Operations

Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Consolidated income from continuing operations before income taxes in the first quarter of 2012 was 36 percent higher than in the same quarter of 2011 primarily due to increased liquid hydrocarbon prices. As a result of increased income from continuing operations before tax in higher tax jurisdictions, primarily Norway, the effective tax rate was 69 percent in the first quarter of 2012 compared to 54 percent in the first quarter of 2011.

Revenues are summarized by segment in the following table:

                                         Three Months Ended March 31,
(In millions)                              2012                2011
E&P                                    $       3,412       $       3,327
OSM                                              379                 306
IG                                                 -                  64
  Segment revenues                             3,791               3,697
Elimination of intersegment revenues               -                 (26 )
  Total revenues                       $       3,791       $       3,671

E&P segment revenues increased $85 million in the first quarter of 2012 from the comparable prior-year period. Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Higher average crude oil prices in the first quarter of 2012 increased revenues related to supply optimization.

Revenues from the sale of our U.S. production are higher in the first quarter of 2012 primarily as a result of higher liquid hydrocarbon sales volumes and price realizations, partially offset by decreased natural gas sales volumes and price realizations. The following table gives details of net sales and average realizations of our U.S. operations.

                                                                 Three Months Ended March 31,
                                                                   2012                2011
United States Operating Statistics
   Net liquid hydrocarbons sales (mbbld) (a)                              90                  78
   Liquid hydrocarbon average realizations (per bbl) (b)       $       93.63       $       86.42

   Net natural gas sales (mmcfd)                                         344                 368
   Natural gas average realizations (per mcf) (b)              $        4.13       $        5.15


(a)  Includes crude oil, condensate and natural gas liquids.


(b)  Excludes gains and losses on derivative instruments.

Liquid hydrocarbon sales volumes increased in the first quarter of 2012, reflecting our ongoing development programs primarily in the Eagle Ford and Bakken shale plays, partially offset by decreased production in the Gulf of Mexico.

The following table gives details of net sales and average realizations of our international operations.

                                                                  Three Months Ended March 31,
                                                                    2012                 2011
International Operating Statistics
   Net liquid hydrocarbon sales (mbbld)(a)
      Europe                                                               97                  111
      Africa                                                               52                   58
       Total International                                                149                  169
   Liquid hydrocarbon average realizations  (per bbl) (b)
      Europe                                                   $       123.76       $       109.85
      Africa                                                            94.41                81.47
       Total International                                     $       113.55       $       100.10

   Net natural gas sales (mmcfd)
      Europe(c)                                                           104                  102
      Africa                                                              418                  446
       Total International                                                522                  548
   Natural gas average realizations  (per mcf) (b)
      Europe                                                   $         9.99       $        10.29
      Africa                                                             0.24                 0.25
       Total International                                     $         2.19       $         2.12

(a) Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

(b) Excludes gains and losses on derivative instruments.

(c) Includes natural gas acquired for injection and subsequent resale of 14 mmcfd and 15 mmcfd in the first quarters of 2012 and 2011.

Compared to the first quarter of 2011, international liquid hydrocarbon sales volumes were lower for the first quarter of 2012 primarily in the U.K. This was due to unplanned downtime at Foinaven and the timing of liftings.

OSM segment revenues increased $73 million in the first quarter of 2012 from the comparable prior-year period. The increase was driven primarily by a 7 percent increase in average realizations and an 18 percent increase in sales volumes as shown in the table below.

                                                                 Three Months Ended March 31,
                                                                   2012                2011
OSM Operating Statistics
  Net synthetic crude oil sales (mbbld)(a)                                44                  37

(a) Includes blendstocks.

The increased sales volumes are a result of the upgrader expansion which was completed in the second quarter of 2011 and longer periods of downtime for planned and unplanned maintenance in the first quarter of 2011.

IG segment revenues decreased $64 million in the first quarter of 2012 compared to the same period of 2011. Sales of LNG from our Alaska operations ceased completely in the third quarter of 2011 because we sold our equity interest in the facility.

Income from equity method investments decreased $39 million in the first quarter of 2012 from the comparable prior-year period. The decline is a result of lower natural gas prices and lower volumes as a result of a scheduled turnaround at our LNG facility in Equatorial Guinea.

Net gain on disposal of assets in the first quarter of 2012 was primarily the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems.

Cost of revenues increased $3 million in the first quarter of 2012 from the comparable prior-year period, primarily due to our supply optimization activities. Costs related to supply optimization were $775 million in the first quarter of 2012 compared to $738 million in the first quarter of 2011. Excluding costs related to supply optimization, the overall decrease in costs is primarily the result of lower liquid hydrocarbon sales in the U.K. due to the timing of liftings.

Depreciation, depletion and amortization ("DD&A") decreased $61 million in the first quarter of 2012 compared to the same quarter of 2011. Because both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases or decreases in sales volumes generally result in similar changes in DD&A. Decreased DD&A in the first quarter reflects the impact of lower E&P segment sales volumes, partially offset by increases in the OSM segment. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. Lower DD&A rates per barrel in our E&P operations contributed to the overall lower DD&A. The following table provides DD&A rates for our E&P and OSM segments.

Three Months Ended March 31,

($ per boe)            2012                   2011
DD&A rate
E&P Segment
   United States   $         24           $         28
   International   $          9           $         10
OSM Segment        $         18           $         16

Impairments in the first quarter of 2012 relate to the Ozona development in the Gulf of Mexico (see Note 13 to the consolidated financial statements).

General and administrative expenses decreased during the first quarter of 2012 from the comparable prior year period primarily due to decreased incentive compensation expense.

Exploration expenses were lower in the first quarter of 2012 than in the same period of 2011, primarily due to higher dry well costs in the prior period. Dry well costs in the first quarter of 2011 primarily related to the Flying Dutchman in the Gulf of Mexico and the Romeo prospect in Indonesia.

The following table summarizes the components of exploration expenses.

                                               Three Months Ended March 31,
(In millions)                                   2012                  2011
Dry well and unproved property impairment   $          58         $         172
Geological, geophysical, seismic                       43                    15
Other                                                  41                    43
   Total exploration expenses               $         142         $         230

Provision for income taxes increased $391 million in the first quarter of 2012 from the comparable period of 2011 primarily due to the increase in pretax income and the resumption of sales in Libya in the first quarter of 2012.

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in "Corporate and other unallocated items" shown in Note 8 to the consolidated financial statements.

Our effective tax rate in the first quarter of 2012 is 69 percent. This rate is higher than the U.S. statutory rate of 35 percent primarily due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rate is in excess of the U.S. statutory rate. An increase in earnings and associated taxes from foreign jurisdictions, primarily Norway, as compared to prior periods caused an increase in our valuation allowance on current year foreign tax credits. In Libya, where the statutory tax rate is in excess of 90 percent, limited production resumed in the fourth quarter of 2011 and liquid hydrocarbon sales resumed in the first quarter of 2012. A reliable estimate of 2012 annual ordinary income from our Libyan operations cannot be made and the range of possible scenarios when including ordinary income from our Libyan operations in . . .