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 second quarter of 2012, notable items were:

· Net liquid hydrocarbon and natural gas sales volumes of 407 thousand barrels of oil equivalent per day ("mboed"), of which 66 percent was liquid hydrocarbons

· Net international liquid hydrocarbon sales volumes, for which average realizations have exceeded West Texas Intermediate ("WTI") crude oil, were 66 percent of total liquid hydrocarbon sales

· Production from Libya increased over the first quarter of 2012, with average net sales of 44 mboed and production available for sale of 44 mboed in the second quarter

· Bakken shale average net sales volumes of 27 mboed, a 69 percent increase over the same quarter of last year

· Eagle Ford shale average net sales volumes of 21 mboed, an increase nearly 50 percent from the first quarter of 2012

· Turnarounds at our operated assets in Equatorial Guinea and Norway were completed in less time and at lower cost than originally anticipated

· Signed a new production sharing contract for an exploration block adjacent to the Alba field offshore Equatorial Guinea

· Cash-adjusted debt-to-capital ratio of 21 percent

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

Some significant third quarter activities through August 3, 2012 include:

· Re-entered Gabon with a non-operated 21 percent working interest in an exploration license

· Agreed to pursue exploration activities in Kenya and Ethiopia

· Closed farm out agreements on 35 percent working interests in the Harir and Safen blocks in the Kurdistan Region of Iraq

· Closed the largest previously announced acquisition in the Eagle Ford shale

Overview and Outlook

Exploration and Production

Production

Net liquid hydrocarbon and natural gas sales averaged 407 mboed during the second quarter and 395 mboed in the first six months of 2012 compared to 337 mboed and 368 mboed in the same periods of 2011. The resumption of sales from Libya in the first quarter of 2012 after production had ceased there in February of 2011 was the most significant cause of our increased sales volumes. Net liquid hydrocarbon sales volumes increased in the U.S. for both the quarter and first six months of 2012, 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 Anadarko Woodford unconventional resource plays. In addition, net liquid hydrocarbon sales volumes from the U.K. were higher in the second quarter of 2012 than in the same period of 2011 due to the timing of liftings.

We continue to ramp up operations in the core of the Eagle Ford play in Texas where we had 20 operated rigs drilling and four hydraulic fracturing crews working as of June 30, 2012. During the second quarter and first six months of 2012, we drilled 61 gross and 107 gross wells, with a total of 72 gross (50 net) wells brought to sales in the first six months of 2012. We have realized significant efficiencies in drilling over the past few months, reducing the average drilling time per well to 23 days. With these gains in efficiencies, we believe we can reduce our operated rig count to 18 for the balance of 2012 and drill the 230 to 240 wells originally planned for 2012, along with 11 incremental wells associated with the acreage acquired on August 1, 2012.

To complement drilling and completion activity in the Eagle Ford shale, we continue to build infrastructure to support production growth across the operating area. Approximately 210 miles of gathering lines were installed in the first six months of 2012, while four new central gathering and treating facilities were commissioned. Five additional facilities are under construction. We are now able to transport approximately 70 percent of our Eagle Ford production by pipeline.

Average net sales volumes from the Bakken shale were 27 mboed and 26 mboed in the second quarter and first six months of 2012 compared to 16 mboed and 15 mboed in the same periods of 2011. Our Bakken shale liquid hydrocarbon volumes average approximately 95 percent liquid hydrocarbons. During the second quarter and first six months of 2012, we drilled 26 gross and 47 gross wells, with a total of 44 gross (37 net) wells brought to sales in the first six months of 2012. We are reducing our operated rig count in the Bakken shale from eight to five in response to continued commodity price volatility and lower domestic liquid hydrocarbon prices. With this five-rig program, we expect to maintain our previously projected production levels over the next 12 to 18 months and to retain our core Bakken acreage.

In the Anadarko Woodford shale, net sales volumes averaged 6 mboed and 5 mboed during the second quarter and first six months of 2012 compared to 2 mboed and 1 mboed in the same periods of 2011. Recent performance improvements are being driven by results in the Knox area. During the second quarter of 2012, eight gross (five net) wells were brought to sales, with 17 gross (13 net) brought to sales in the first six months of 2012. In response to the continued decline in natural gas liquids prices and low natural gas prices, we are reducing our rig count in the Anadarko Woodford play from six to two. We expect to maintain our projected 2012 production level and retain our core acreage in the play with this two-rig program over the next 12 to 18 months.

Our 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.

In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed so that during the second quarter and first six months of 2012, net sales volumes averaged 44 mboed and 31 mboed. Some uncertainty concerning the sustainability of production and sales levels in Libya remains. We and our partners in the Waha concessions continue to assess the condition of our assets.

In June 2012, we submitted a plan for the development and operation of the Boyla field (PL 340) in the North Sea to the Norwegian Ministry of Petroleum and Energy. The Boyla field is located approximately 17 miles south of our operated Alvheim field. We hold a 65 percent working interest in the field. Pending approval, first production from Boyla is expected in the fourth quarter of 2014. Also during the second quarter of 2012, we completed a four-day turnaround in Norway that was originally scheduled for 14 days in the third quarter. We expect an additional one to two day planned shutdown of our Norway assets in the third 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

At June 30, 2012, we were participating in two non-operated wells in the Gulf of Mexico: an appraisal well on the Gunflint discovery located on Mississippi Canyon Block 948 and an appraisal well on the Shenandoah prospect located on Walker Ridge Block 51. We have a 15 percent and a 10 percent working interest in these prospects. The Gunflint well has confirmed expected reservoir properties and continuity, establishing the commercial viability of the field. Drilling of the Shenandoah appraisal well commenced on June 29, 2012. During the second quarter of 2012, the well costs and related unproved property costs related to the Kilchurn well were charged to exploration expenses.

In the second half of 2012, we expect to return to drilling the exploration well on the Gulf of Mexico Innsbruck prospect on Mississippi Canyon Block 993 in which we hold a 45 percent working interest. Drilling of this well was halted in 2010 due to the U.S. government imposed drilling moratorium that followed the large Gulf of Mexico spill.

We continue exploratory drilling in Poland. Our third exploratory well has completed and a fourth well, is currently drilling. We have collected extensive data, including well logs and core samples, which are being evaluated. We plan to drill six wells by the end of 2012 in Poland. We hold a 51 percent working interest in 10 operated concessions and a 100 percent working interest in one concession.

In the Kurdistan Region of Iraq, we began drilling our first operated exploration well on the Harir block on July 30, 2012 and plan to drill an exploration well on the Safen block in 2013. We have a 45 percent working (56 percent paying) interest in both the Harir and Safen blocks. Additionally, we are participating in non operated appraisal well on the Sarsang block, where we hold a 20 percent working (25 percent paying) interest.

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 thousand barrel per day ("mbbld") steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, project sanction is expected in 2014, with first oil projected in 2017. 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 multiple agreements to acquire approximately 20,000 net acres in the core of the Eagle Ford shale formation in transactions valued at $767 million, before closing adjustments. The smaller transactions closed during the second quarter of 2012. The largest transaction with a value of $750 million before closing adjustments closed on August 1, 2012. In addition to undeveloped acreage, at closing 17 gross operated and 9 gross non-operated wells were producing an average of 9 net mboed, of which 70 percent was liquid hydrocarbons.

In April 2012, we entered agreements to sell our Alaska assets. One transaction closed in the second quarter of 2012 with proceeds and a net gain of $7 million. The remaining transaction, with a value of $375 million before closing adjustments, is expected to close in the second half of 2012, pending regulatory approval and closing conditions.

In May 2012, we reached an agreement to relinquish operatorship of and our interests in the Bone Bay and Kumawa exploration licenses in Indonesia. A $36 million payment will be made upon government ratification of the agreement, to settle all of our obligations related to these licenses, including well commitments. This amount was accrued and reported as a loss on disposal of assets in the second quarter of 2012.

In June 2012, we entered an agreement to acquire a 21 percent working (25 percent paying) interest in the Diaba License G4-223 and its related permit in Gabon. The transaction is expected to close, subject to completion of the necessary Gabonese government and partner approvals, in the third quarter of 2012. The start of exploration drilling is expected in the first quarter of 2013.

During June 2012, we signed a new production sharing contract with the government of Equatorial Guinea for the exploration of Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have an 80 percent operated working interest in this block. Ratification of the contract by the government is expected in the third quarter of 2012.

In late July, we entered into an agreement to acquire positions in two onshore exploration blocks in northwest Kenya amounting to more than 11 million gross acres. The transaction includes a 50 percent working interest in Block 9 and a 15 percent working interest in Block 12A. An exploration well is planned on Block 9 in mid-2013. The transaction, subject to government approval, is expected to close in the third quarter of 2012. Additionally, we are pursuing exploration activities in Ethiopia, subject to host country government approval.

Also in late July, we closed on agreements to farm out 35 percent working (44 percent paying) interests in the Harir and Safen blocks in the Kurdistan Region of Iraq. After this transaction, we have a 45 percent working (56 percent paying) interest in each of the two blocks.

The above discussions include forward-looking statements with respect to the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, anticipated drilling rig and drilling activity, the sale of the our Alaska assets, the expected closing of agreements in Gabon and Kenya, possible exploration activity in Ethiopia, a new production sharing contract with the Government of Equatorial Guinea, a scheduled shutdown of the Norway assets and the timing of the commencement of construction and first oil on the SAGD project. Factors that could potentially affect the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, and anticipated drilling rig and drilling activity include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The completion of the sale of our Alaska assets is subject to necessary government and regulatory approvals and customary closing conditions. The agreement in Gabon is subject to government and partner approvals. The agreement in Kenya and the exploration activity in Ethiopia are subject to government approvals. The new production sharing contract with the Government of Equatorial Guinea is subject to ratification by the Equatorial Guinea government. The scheduled shutdown of the Norway assets is based on current expectations, estimates and projections and is not a guarantee of future performance. The timing of 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 the other risks associated with construction projects. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond the our control and difficult to predict. 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 second quarter and first six months of 2012 compared to 41 mbbld and 39 mbbld in the same periods of 2011. The upgrader expansion was completed and commenced operations in the second quarter of 2011 and subsequent periods' sales volumes have increased as a result.

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.

In July 2012, Alberta's primary energy regulator, the Energy and Resources Conservation Board ("ERCB"), conditionally approved the AOSP's Quest Carbon Capture and Storage ("Quest") project. The ERCB's approval positions the AOSP partners to make an investment decision on Quest in 2012.

The above discussion contains forward looking statements with regard to the Quest project. The project is subject to regulatory approvals, stakeholder engagement, detailed engineering studies and a final joint venture partner agreement.

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 5,467 metric tonnes per day ("mtd") for the second quarter and 5,879 mtd for the first six months of 2012 compared to 6,614 mtd and 7,215 mtd in the same periods of 2011. LNG sales volumes are below the prior year primarily because the second quarter and first six months of 2011 also included LNG sales from Alaska, which ceased when our interest in that production facility was sold in the third quarter of 2011. Also, the planned turnaround which began at the LNG facility in Equatorial Guinea in the first quarter of 2012 was completed in the second quarter four days ahead of schedule and 15 percent under budget.

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 benchmark crude oil and
natural gas price averages in the second quarter and first six months of 2012
compared to the same periods in 2011.

                                                       Three Months Ended June 30,             Six Months Ended June 30,
Benchmark                                               2012                 2011              2012                2011
WTI crude oil (Dollars per barrel)                 $        93.35       $       102.34     $       98.15       $       98.50
Brent
(Europe)
crude oil   (Dollars per barrel)                   $       108.42       $       117.36     $      113.45       $      111.16
Henry Hub natural gas (Dollars per million
British thermal units ("mmbtu"))(a)                $         2.22       $         4.31     $        2.48       $        4.21

(a) Settlement date average.

Average WTI crude oil benchmark prices decreased in the second quarter of 2012 compared to the same quarter of 2011, but were relatively flat for the first six months of each year. The average differential between the Brent and WTI benchmarks was a premium of approximately $15 per barrel in both periods 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 42 percent sour in the second quarter and 45 percent sour in the first six months of 2012 compared to 68 percent and 69 percent in the same periods 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 in 2012. 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 second quarter and first six months of 2012 compared to the same periods of the prior year. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and continued into the second quarter of 2012. 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 in 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 ("WCS"). Recently, the WCS discount from WTI has increased, bringing down our average price realizations. Output mix can be impacted by operational problems or planned unit outages at the mines 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, making per unit costs 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.

The table below shows benchmark prices that impacted both our revenues and variable costs for the second quarter and first six months of 2012 and 2011:

                                                              Three Months Ended June 30,           Six Months Ended June 30,
Benchmark                                                      2012                2011              2012               2011
WTI crude oil (Dollars per barrel)                         $      93.35       $       102.34     $      98.15       $      98.50
Western Canadian Select (Dollars per barrel)(a)            $      70.63       $        84.92     $      76.07       $      78.08
AECO natural gas sales index (Dollars per mmbtu)(b)        $       1.84       $         4.04     $       2.04       $       3.94

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

(b) Monthly average AECO day ahead index.

Integrated Gas

We have a 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract principally based upon Henry Hub natural gas prices.

We own a 45 percent interest in a methanol plant located in Equatorial Guinea. Methanol demand has a direct impact on the plant's earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. The plant capacity of 1.1 million tonnes is about 2 percent of 2011 estimated world demand.

Results of Operations

Consolidated Results of Operation

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 second quarter of 2012 was 55 percent higher than in the same period of 2011 primarily due to the previously discussed resumption of our operations in Libya and no impairments in the second quarter of 2012. The effective tax rate was 72 percent in the second quarter of 2012 compared to 67 percent in the second quarter of 2011, with the increase related to higher income from continuing operations in higher tax jurisdictions, primarily Norway and Libya.

Consolidated income from continuing operations before income taxes in the first six months of 2012 was 45 percent higher than in the same period of 2011 primarily due to increased income in Libya and lower exploration expenses, depreciation, depletion and amortization ("DD&A") and impairments. As a result of increased income from continuing operations before tax in higher tax jurisdictions, primarily Norway and Libya, the effective tax rate was 71 percent for the first six months of 2012 compared to 60 percent for the same period of 2011.

Revenues are summarized by segment in the following table:

                                              Three Months Ended June 30,           Six Months Ended June 30,
(In millions)                                  2012                2011              2012               2011
E&P                                        $       3,396       $       3,249     $      6,808       $      6,576
OSM                                                  335                 447              714                753
IG                                                     -                  13                -                 77
  Segment revenues                                 3,731               3,709            7,522              7,406
Elimination of intersegment revenues                   -                 (15 )              -                (41 )
  Total revenues                           $       3,731       $       3,694     $      7,522       $      7,365

E&P segment revenues increased $147 million in the second quarter and $232 million in the first six months of 2012 from the comparable prior-year periods. 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. Lower average commodity prices in the second quarter and first six months of 2012 decreased revenues related to supply optimization.

Revenues from the sale of our U.S. production are higher in the second quarter and first six months of 2012 primarily as a result of increased liquid hydrocarbon sales volumes from our U.S. shale plays. Lower liquid hydrocarbon and natural gas price realizations partially offset the volume impact. The following table gives details of net sales and average realizations of our U.S. operations.

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