• 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.

• IG which produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.

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 forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in this Annual Report on Form 10-K.
Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Item 1. Business, Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data found in this Annual Report on Form 10-K. Spin-off Downstream Business
On June 30, 2011, the spin-off of Marathon's downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. Marathon stockholders at the close of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. A private letter tax ruling received in June 2011 from the IRS affirmed the tax-free nature of the spin-off. Activities related to the downstream business have been treated as discontinued operations in 2011 and 2010 (see Item 8. Financial Statements and Supplementary Data - Note 3 to the consolidated financial statements for additional information). Overview - Market Conditions
Exploration and Production
Prevailing prices for the various grades of crude oil and natural gas that we produce significantly impact our revenues and cash flows. The following table lists benchmark crude oil and natural gas price annual averages for the past three years.

Benchmark                                     2012      2011      2010
WTI crude oil (Dollars per bbl)               $94.15    $95.11   $79.61
Brent (Europe) crude oil (Dollars per bbl)   $111.65   $111.26   $79.51
Henry Hub natural gas (Dollars per mmbtu)(a)   $2.79     $4.04    $4.39

(a) Settlement date average.

Liquid hydrocarbon - Prices of crude oil have been volatile in recent years, but less so when comparing annual averages for 2012 and 2011. In 2011, crude prices increased over 2010 levels, with increases in Brent averages outstripping those in WTI.
The quality, location and composition of our liquid hydrocarbon production mix will cause our U.S. liquid hydrocarbon realizations to differ from the WTI benchmark. In 2012, 2011 and 2010, the percentage of our U.S. crude oil and condensate production that was sour averaged 37 percent, 58 percent and 68 percent. Sour crude contains more sulfur and tends to be heavier than light sweet crude oil so that refining it is more costly and produces lower value products; therefore, sour crude is considered of lower quality and typically sells at a discount to WTI. The percentage of our U.S. crude and condensate production that is sour has been decreasing as onshore production from the Eagle Ford and Bakken shale plays increases and production from the Gulf of Mexico declines. In recent years, crude oil sold along the U.S. Gulf Coast has been priced at a premium to WTI because the Louisiana Light Sweet benchmark has been tracking Brent, while production from inland areas farther from large refineries has been at a discount to WTI. NGLs were 10 percent, 7 percent and 6 percent of our U.S. liquid hydrocarbon sales in 2012, 2011 and 2010. In 2012, our sales of NGLs increased due to our development of U.S. unconventional liquids-rich plays.

Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark. The differential between WTI and Brent average prices widened significantly in 2011 and remained in 2012 in comparison to almost no differential in 2010.
Natural gas - 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 in 2012 than in recent years. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and continued into 2012. Although prices stabilized in late 2012, they have not increased appreciably.
Our other major natural gas-producing regions are E.G. and Europe. In the case of E.G,. our natural gas sales are subject to term contracts, making realizations less volatile. Because natural gas sales from E.G. are at fixed prices, our worldwide reported average natural gas realizations may not fully track market price movements. Natural gas prices in Europe have been significantly higher than in the U.S.
Oil Sands Mining
The OSM segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily WCS. In 2012, the WCS discount from WTI had increased, putting downward pressure on our average realizations. The operating cost structure of the OSM 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 rates. 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 oil prices, respectively.
The table below shows average benchmark prices that impact both our revenues and variable costs.

Benchmark                                            2012     2011     2010
WTI crude oil (Dollars per bbl)                     $94.15   $95.11   $79.61
WCS (Dollars per bbl)(a)                            $73.18   $77.97   $65.31
AECO natural gas sales index (Dollars per mmbtu)(b)  $2.39    $3.68    $3.89

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

(b) Monthly average day ahead index.

Integrated Gas
Our IG operations include production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.
World LNG trade in 2012 has been estimated to be 240 mmt. Long-term, LNG continues to be in demand as markets seek the benefits of clean burning natural gas. Market prices for LNG are not reported or posted. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices. We have a 60 percent ownership in an LNG production facility in E.G., which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. Gross sales from the plant were 3.8 mmt, 4.1 mmt and 3.7 mmt in 2012, 2011 and 2010. We own a 45 percent interest in a methanol plant located in E.G. through our investment in AMPCO. Gross sales of methanol from the plant totaled 1.1 mmt, 1.0 mmt and 0.9 mmt in 2012, 2011 and 2010. 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. World demand for methanol in 2012 has been estimated to be 49 mmt. Our plant capacity of 1.1 mmt is about 2 percent of world demand.

Key Operating and Financial Activities
Significant operating and financial activities during 2012 include:
• Net proved reserve additions for the E&P and OSM segments combined of 389 mmboe, for a 226 percent reserve replacement ratio

• Increased proved liquid hydrocarbon and synthetic crude oil reserves by 316 mmbbls, for a reserve replacement of 268 percent for these commodities

• Recorded more than 95 percent average operational availability for operated E&P assets

• Increased E&P net sales volumes, excluding Libya, by 8 percent

• Eagle Ford shale average net sales volumes of 65 mboed for December 2012, a fourfold increase over December 2011

• Bakken shale average net sales volumes of 29 mboed, a 71 percent increase over last year

• Resumed sales from Libya and reached pre-conflict production levels

• International liquid hydrocarbon sales volumes, for which average realizations have exceeded WTI, were 62 percent of net E&P liquid hydrocarbon sales

• Closed $1 billion of acquisitions in the core of the Eagle Ford shale

• Assumed operatorship of the Vilje field located offshore Norway

• Signed agreements for new exploration positions in E.G., Gabon, Kenya and Ethiopia

• Issued $1 billion of 3-year senior notes at 0.9 percent interest and $1 billion of 10-year senior notes at 2.8 percent interest

Some significant 2013 activities through February 22, 2013 include:
• Closed sale of our Alaska assets in January 2013

• Closed sale of our interest in the Neptune gas plant in February 2013

Consolidated Results of Operations: 2012 compared to 2011 Consolidated income before income taxes was 38 percent higher in 2012 than consolidated income from continuing operations before income taxes were in 2011, largely due to higher liquid hydrocarbon sales volumes in our E&P segment, partially offset by lower earnings from our OSM and IG segments. The 7 percent decrease in income from continuing operations included lower earnings in the U.K. and E.G., partially offset by higher earnings in Libya. Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012. The effective income tax rate for continuing operations was 74 percent in 2012 compared to 61 percent in 2011.

Revenues are summarized in the following table:
(In millions)                                         2012         2011
E&P                                                 $ 14,084    $ 13,029
OSM                                                    1,552       1,588
IG                                                         -          93
Segment revenues                                      15,636      14,710
Elimination of intersegment revenues                       -         (47 )
Unrealized gain on crude oil derivative instruments       52           -
Total revenues                                      $ 15,688    $ 14,663

E&P segment revenues increased $1,055 million from 2011 to 2012, primarily due to higher average liquid hydrocarbon sales volumes. E&P segment revenues included a net realized gain on crude oil derivative instruments of $15 million in 2012 while the impact of derivatives was not significant in 2011. See Item 8. Financial Statements and Supplementary Data - Note 16 to the consolidated financial statement for more information about our crude oil derivative instruments.
Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product

types and delivery points. Volumes associated with supply optimization have been decreasing in 2012 due to market dynamics and related commodity prices were also slightly lower in 2012.
Revenues from the sale of our U.S. production are higher in 2012 than in 2011 as a result of increased liquid hydrocarbon sales volumes from our U.S. shale plays. Lower liquid hydrocarbon and natural gas realizations partially offset the volume impact. The following table gives details of net sales and average realizations of our U.S. operations.

                                                         2012      2011
U.S. Operating Statistics
Net liquid hydrocarbon sales (mbbld)                       107        75
Liquid hydrocarbon average realizations (per bbl)(a)(b)  $85.80    $92.55
Net crude oil and condensate sales (mbbld)                  96        70
Crude oil and condensate (per bbl)                       $91.29    $94.80
Net natural gas liquids sales (mbbld)                       11         5
Natural gas liquids (per bbl)                            $39.57    $58.53
Net natural gas sales (mmcfd)                              358       326
Natural gas average realizations (per mcf)(a)             $3.91     $4.95

(a) Excludes gains or losses on derivative instruments.

(b) Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon realizations $0.39 per bbl for 2012.

Revenues from our international operations are higher in 2012 than in 2011 primarily as a result of the previously discussed resumption of liquid hydrocarbon sales from Libya. Higher average liquid hydrocarbon realizations during 2012, again primarily related to Libyan crude oil, also contributed to the revenue increase. The following table gives details of net sales and average realizations of our international operations.

                                                       2012       2011
International Operating Statistics
Net liquid hydrocarbon sales (mbbld)(a)
Europe                                                    97        101
Africa                                                    78         43
Total International                                      175        144
Liquid hydrocarbon average realizations (per bbl)(b)
Europe                                                $115.16    $115.55
Africa                                                 $98.52     $73.21
Total International                                   $107.78    $102.96
Net natural gas sales (mmcfd)
Europe(c)                                                101         97
Africa                                                   443        443
Total International                                      544        540
Natural gas average realizations (per mcf)(b)
Europe                                                 $10.47      $9.84
Africa(d)                                               $0.43      $0.24
Total International                                     $2.29      $1.97

(a) The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

(b) Excludes gains or losses on derivative instruments.

(c) Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 16 mmcfd in 2012 and 2011.

(d) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC's income in our E&P segment and we include our share of AMPCO's and EGHoldings' income in our IG segment. OSM segment revenues decreased $36 million from 2011 to 2012. The decrease was primarily the result of lower average realizations which were partially offset by the increase in sales volumes.

                                                    2012      2011
OSM Operating Statistics
Net synthetic crude oil sales (mbbld)(a)               47        43
Synthetic crude oil average realizations (per bbl)  $81.72    $91.65

(a) Includes bloodstocks.

IG segment revenues decreased to zero in 2012 from $93 million in 2011. Sales of LNG from our Alaska operations ceased in the third quarter of 2011 when we sold our interest in this production facility.
Income from equity method investments decreased $92 million from 2011 to 2012 primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in E.G. Also, in January 2012, we sold our equity investments in several Gulf of Mexico crude oil pipelines.
Net gain on disposal of assets in 2012 consists primarily of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems, reduced by the $36 million loss on the assignment of our Bone Bay and Kumawa exploration licenses in Indonesia and the $18 million loss on the sale of non-core Eagle Ford acreage. In 2011, net gain on disposal of assets is primarily related to sales of non-core assets, such as the Burns Point gas plant and the Alaska LNG facility, and the assignment of interests in our DJ Basin acreage position. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.
Cost of revenues decreased $1,006 million from 2011 to 2012 primarily related to our supply optimization activities. Comparatively, costs related to supply optimization were lower by $1,152 million for 2012, primarily due to lower volumes in 2012 due to market dynamics. The related commodity prices were also slightly lower in 2012. Excluding the impact of supply optimization activities, E&P segment operating expenses have increased in proportion to our increased production from U.S. shale plays. Additionally, IG segment costs are lower in 2012 due to the sale of our interest in the Alaska LNG facility in the third quarter of 2011.
Depreciation, depletion and amortization increased $212 million from 2011 to 2012. Since both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases in sales volumes generally result in similar changes in DD&A. Increased DD&A in 2012 primarily reflects the impact of higher sales volumes. There was no depletion of our Alaska assets for much of 2012 because they were held for sale, which partially offset the DD&A increase. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in proved reserves and capitalized costs, can also cause changes in our DD&A. Our E&P segment's DD&A rates have decreased slightly since 2011 primarily due to proved reserve additions. The following table provides DD&A rates for our E&P and OSM segments.

($ per boe)    2012     2011
DD&A rate
E&P Segment
United States $  24    $  25
International     8       10
OSM Segment   $  13    $  13

Impairments in 2012 related primarily to our Ozona development in the Gulf of Mexico and to our Powder River Basin asset in Wyoming. Impairments in 2011 related primarily to our Droshky development in the Gulf of Mexico and an intangible asset for an LNG delivery contract at Elba Island. See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for further information about the impairments. Other taxes increased $59 million from 2011 to 2012. With the increase in revenues related to higher sales volumes, production taxes increased. In addition, ad valorem taxes are higher because the value of our U.S. assets has increased with the recent acquisitions in the Eagle Ford shale. Exploration expenses were higher in 2012 than 2011 primarily due to larger unproved property impairments. Unproved property impairments in 2012 related to the Marcellus shale, the Eagle Ford shale and Indonesia. The following table summarizes the components of exploration expenses.

(In millions)                     2012     2011
Unproved property impairments    $ 227    $  79
Dry well costs                     230      278
Geological, geophysical, seismic   128      120
Other                              144      167
Total exploration expenses       $ 729    $ 644

Net interest and other increased $112 million from 2011 to 2012 primarily as a result of less interest expense capitalized. See Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for more information on net interest and other.
Loss on early extinguishment of debt in 2011 relates to debt retirements in February and March of 2011. See Item 8. Financial Statements and Supplementary Data - Note 17 to the consolidated financial statements for additional discussion of these transactions.
Provision for income taxes increased $1,811 million from 2011 to 2012 primarily due to the increase in pretax income, including the impact of the previously discussed resumption of sales in Libya in the first quarter of 2012. The following is an analysis of the effective income tax rates for 2012 and 2011:

                                                              2012          2011
Statutory rate applied to income from continuing
operations before income taxes                                    35 %          35 %
Effects of foreign operations, including foreign tax
credits                                                           18             6
Change in permanent reinvestment assertion                         -             5
Adjustments to valuation allowances                               21            14
Tax law changes                                                    -             1
Effective income tax rate on continuing operations                74 %          61 %

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. 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 the reconciliation of segment income to net income below.
Effects of foreign operations - The effects of foreign operations on our effective tax rate increased in 2012 as compared to 2011, primarily due to the resumption of sales of Libyan production in first quarter of 2012, where the statutory tax rate is in excess of 90 percent.
Change in permanent reinvestment assertion - In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings.
Adjustments to valuation allowances - In 2012 and 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.
See Item 8. Financial Statements and Supplementary Data - Note 10 to the consolidated financial statements for further information about income taxes. Discontinued operations in 2011 reflect the June 30, 2011 spin-off of our downstream business and its historical operating results, net of tax. See Item 8. Financial Statements and Supplementary Data - Note 3 to the consolidated financial statements.

Segment Results: 2012 compared to 2011
Segment income for 2012 and 2011 is summarized and reconciled to net income in the following table.

(In millions)                                           2012        2011
E&P
United States                                         $   393     $   366
International                                           1,488       1,791
E&P segment                                             1,881       2,157
OSM                                                       176         256
IG                                                         91         178
Segment income                                          2,148       2,591
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items                    (441 )      (317 )
Impairments                                              (231 )      (195 )
Gain on dispositions                                       72          45
Unrealized gain on crude oil derivative instruments        34           -
Loss on early extinguishment of debt                        -        (176 )
Tax effect of subsidiary restructuring                      -        (122 )
Deferred income tax items                                   -         (61 )
Water abatement - Oil Sands                                 -         (48 )
Eagle Ford transaction costs                                -         (10 )
Income from continuing operations                       1,582       1,707
Discontinued operations                                     -       1,239
Net income                                            $ 1,582     $ 2,946

U.S. E&P income increased $27 million from 2011 to 2012. The income increase was primarily the result of higher liquid hydrocarbon sales volumes as previously discussed, partially offset by lower liquid hydrocarbon and natural gas realizations and the impact of increased production operations on DD&A and operating expenses. In addition, exploration expenses were higher primarily due to dry wells and unproved property impairments.
International E&P income decreased $303 million from 2011 to 2012. The decrease included lower earnings in the U.K. and E.G. partially offset by higher earnings in Libya. Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012.
OSM segment income decreased $80 million from 2011 to 2012. As previously discussed, lower synthetic crude oil price realizations were the primary reason for the decrease in income partially offset by higher sales volumes. IG segment income decreased $87 million from 2011 to 2012 primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in E.G. In addition, LNG sales volumes are lower in 2012 because we sold our interest in the Alaska LNG facility in the third quarter of 2011. . . .