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MRO > SEC Filings for MRO > Form 10-K on 28-Feb-2014All Recent SEC Filings

Show all filings for MARATHON OIL CORP

Form 10-K for MARATHON OIL CORP


28-Feb-2014

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Each of our segments is organized and managed based upon both geographic location and the nature of the products and services it offers:
• North America E&P - explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P - explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and

• Oil Sands Mining - 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.

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 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 for all periods prior to the spin-off (see Item 8. Financial Statements and Supplementary Data - Note 3 to the consolidated financial statements for additional information). Overview - Market Conditions
Prevailing prices for the various qualities 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 averages relative to our North America E&P and International E&P segments for the past three years.

Benchmark                                     2013      2012      2011
WTI crude oil (Dollars per bbl)               $98.05    $94.15    $95.11
Brent (Europe) crude oil (Dollars per bbl)   $108.64   $111.65   $111.26
Henry Hub natural gas (Dollars per mmbtu)(a)   $3.65     $2.79     $4.04


(a)  Settlement date average.

North America E&P
Liquid hydrocarbons - The quality, location and composition of our liquid hydrocarbon production mix can cause our North America E&P price realizations to differ from the WTI benchmark.
Quality - Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and has historically produced higher value products; therefore, light sweet crude is considered of higher quality and has historically sold at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude oil and condensate production that is light sweet crude has been increasing as onshore production from the Eagle Ford and Bakken increases and production from the Gulf of Mexico declines. In 2013, the percentage of our U.S. crude oil and condensate production that was sweet averaged 76 percent compared to 63 percent and 42 percent in 2012 and 2011.
Location - In recent years, crude oil sold along the U.S. Gulf Coast, such as that from the Eagle Ford, has been priced based on the Louisiana Light Sweet ("LLS") benchmark which has historically priced at a premium to WTI and has historically tracked closely to Brent, while production from inland areas farther from large refineries has been priced lower. The average annual WTI


discount to Brent was narrower in 2013 than in 2012 and 2011. As a result of the significant increase in U.S. production of light sweet crude oil, the historical relationship between WTI, Brent and LLS pricing may not be indicative of future periods.
Composition - The proportion of our liquid hydrocarbon sales volumes that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 15 percent of our North America E&P liquid hydrocarbon sales volumes in 2013 compared to 10 percent in 2012 and 7 percent in 2011.
Natural gas - A significant portion of our natural gas production in 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 31 percent higher for 2013 than for 2012.
International E&P
Liquid hydrocarbons - Our International E&P crude oil production is relatively sweet and has historically sold in relation to the Brent crude benchmark, which on average was 3 percent lower for 2013 than 2012.
Natural gas - Our major International E&P natural gas-producing regions are Europe and E.G. Natural gas prices in Europe have been considerably higher than the U.S. in recent years. In the case of E.G., our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from E.G. are at fixed prices; therefore, our reported average International E&P natural gas realized prices may not fully track market price movements.
Oil Sands Mining
The Oil Sands Mining 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 has historically tracked movements in WTI and one-third has historically tracked movements in the Canadian heavy crude oil marker, primarily WCS. The WCS discount to WTI has been increasing on average in each year presented below. Despite a wider WCS discount in 2013, our average Oil Sands Mining price realizations increased due to a greater proportion of higher value synthetic crude oil sales volumes compared to 2012.
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 rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the 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                                            2013     2012     2011
WTI crude oil (Dollars per bbl)                     $98.05   $94.15   $95.11
WCS (Dollars per bbl)(a)                            $72.77   $73.18   $77.97
AECO natural gas sales index (Dollars per mmbtu)(b)  $3.08    $2.39    $3.68

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

(b) Monthly average day ahead index.


Key Operating and Financial Activities
Significant 2013 activities related to our strategic imperatives:
•Production growth
•Total company net sales volume growth of 11 percent (excluding Alaska and Libya)
• North America E&P net sales volumes averaged 201 mboed, a 21 percent increase over last year

• Eagle Ford averaged net sales volumes of 81 mboed, a 136 percent increase

• Bakken averaged net sales volumes of 39 mboed, a 34 percent increase

• Oklahoma resource basins averaged net sales volumes of 14 mboed, a 68 percent increase

• Proved reserve replacement of 194 percent, excluding dispositions

• Total net proved reserves increased 8 percent to approximately 2.2 billion boe

• Quality resource capture through focused exploration

• Mirawa-1 discovery on operated Harir block in the Kurdistan Region of Iraq

• Diaman-1B discovery on non-operated Diaba License in Gabon

•         Atrush block received approval from the KRG for the first phase of oil
          development in the Kurdistan Region of Iraq


•         Shenandoah and Gunflint (both non-operated) prospects had successful
          appraisal wells in the Gulf of Mexico

• Rigorous portfolio management

• Exceeded three-year $1.5 billion to $3 billion divestiture target

• Agreements to sell working interests in Angola Blocks 31 and 32 with an aggregate transaction value of $2.1 billion, before closing adjustments

• Sold our interests in Alaska, the DJ Basin and the Neptune gas plant

• Acquired 4,800 additional net acres in the core of the Eagle Ford shale

• Grew SCOOP acreage position over 20 percent

• Commenced efforts to market our U.K. and Norway assets

• Competitive shareholder value

• Increased dividend by 12 percent to 19 cents per share

• Repurchased 14 million common shares for $500 million

•         Announced $500 million share repurchase to begin upon closing of Angola
          Block 31 sale


•         Authorized $1.2 billion increase in share repurchase program to $2.5
          billion remaining

Significant 2014 activity through February 28, 2014 includes:
• Closed sale of our interest in Angola Block 31


Consolidated Results of Operations: 2013 compared to 2012 Consolidated income from continuing operations before income taxes in 2013 was 20 percent lower than 2012 primarily due to lower liquid hydrocarbon net sales volumes in the International E&P segment and higher DD&A and exploration expenses, partially offset by higher liquid hydrocarbon net sales volumes in the North America E&P segment. The effective tax rate for continuing operations was 68 percent in 2013 compared to 74 percent in 2012, with the decrease primarily related to lower income from continuing operations in Libya and Norway, which are higher tax jurisdictions.
Sales and other operating revenues, including related party are summarized by segment in the following table:

(In millions)                                                   2013         2012
Sales and other operating revenues, including related party
North America E&P                                           $    5,068   $    3,944
International E&P                                                5,827        7,445
Oil Sands Mining                                                 1,576        1,521
Segment sales and other operating revenues, including
related party                                                   12,471       12,910
Unrealized gain (loss) on crude oil derivative instruments         (52 )         53
Sales and other operating revenues, including related party $   12,419   $   12,963

North America E&P sales and other operating revenues increased $1,124 million from 2012 to 2013 primarily due to higher liquid hydrocarbon net sales volumes resulting from ongoing development programs in the Eagle Ford, Bakken and Oklahoma resource basins, partially offset by lower natural gas net sales volumes, primarily the result of the sale of our Alaska assets in early 2013. The following table gives details of net sales volumes and average price realizations of our North America E&P segment:

                                                               2013        2012
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld)                      149         107
Liquid hydrocarbon average price realizations (per bbl) (a)
(b)                                                              $85.20      $85.80
Net crude oil and condensate sales volumes (mbbld)                126          96
   Crude oil and condensate average price realizations (per
bbl) (a)                                                         $94.19      $91.30
   Net natural gas liquids sales volumes (mbbld)                   23          11
   Natural gas liquids average price realizations (per
bbl) (a)                                                         $35.12      $39.57
Net natural gas sales volumes (mmcfd)                             312         358
Natural gas average price realizations (per mcf) (a)              $3.84       $3.92

(a) Excludes gains and losses on derivative instruments.

(b) Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon price realizations per bbl by $(0.27) for 2013 and $0.40 for 2012.

International E&P sales and other operating revenues decreased $1,618 million in 2013 from the prior year. This decrease was primarily due to lower liquid hydrocarbon net sales volumes in Libya and Norway and lower liquid hydrocarbon average price realizations.


The following table gives details of net sales volumes and average price realizations of our International E&P segment:

                                                             2013     2012
International E&P Operating Statistics
   Net liquid hydrocarbon sales volumes (mbbld)(a)
Europe                                                          86       97
Africa                                                          58       78
Total International E&P                                        144      175
   Liquid hydrocarbon average price realizations (per bbl)
Europe                                                      $112.60  $115.16
Africa                                                       $86.29   $98.52
Total International E&P                                     $102.10  $107.78
Net natural gas sales volumes (mmcfd)
Europe(b)                                                       83      101
Africa                                                         464      443
Total International E&P                                        547      544
   Natural gas average price realizations (per mcf)
Europe                                                       $12.08   $10.47
Africa(c)                                                     $0.49    $0.43
Total International E&P                                       $2.25    $2.29

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

(b) Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 15 mmcfd for 2013 and 2012.

(c) 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, AMPCO's and EGHoldings' income in our International E&P segment.

Oil Sands Mining sales and other operating revenues increased $55 million in 2013 from 2012. This increase was primarily due to a higher proportion of net sales volumes related to a premium grade synthetic crude oil and the associated average price realizations when compared to 2012. The increase was partially offset by lower feedstock sales in 2013.
The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:

                                                          2013    2012
Oil Sands Mining Operating Statistics
  Net synthetic crude oil sales volumes (mbbld) (a)          48      47
Synthetic crude oil average price realizations (per bbl)  $87.51  $81.72

(a) Includes blendstocks.

Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. These crude oil derivative instruments, all of which had terms that ended in December 2013, resulted in a $52 million net unrealized loss in 2013 compared to a net unrealized gain of $53 million in 2012. See Item 8. Financial Statements and Supplementary Data - Note 16 to the consolidated financial statements for information about our derivative positions.
Marketing revenues decreased $647 million in 2013 from 2012. North America E&P segment marketing activities, which serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points, decreased in 2013 as a result of market dynamics.
Income from equity method investments increased $53 million in 2013 from the prior year primarily due to higher LNG average price realizations.
Net gain (loss) on disposal of assets in 2013 primarily included a $114 million pretax loss on the sale of our interests in the DJ Basin, a $43 million pretax loss on the conveyance of our interests in the Marcellus natural gas shale play to the operator, a $98 million pretax gain on the sale of our interest in the Neptune gas plant, and a $55 million pretax gain on the sale of our remaining assets in Alaska. The net gain on disposal of assets in 2012 consisted primarily of a $166 million pretax gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems and a $36 million pretax loss related to our exit from Indonesia. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.
Production expenses increased $129 million in 2013 from 2012 primarily related to increased North America E&P net sales volumes in the Eagle Ford and Bakken and International E&P well workovers in Norway. The production expense rate (expense


per boe) decreased in North America E&P in 2013 compared to 2012 primarily due to improved operating efficiencies in the Eagle Ford. The International E&P production expense rate increased in 2013 compared to 2012 primarily due to the well workovers in Norway.
The following table provides production expense rates for each segment:

($ per boe)            2013     2012
North America E&P     $10.86   $11.59
International E&P      $6.24    $5.13
Oil Sands Mining (a)  $46.30    $45.95

(a) Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.

Marketing expenses decreased $672 million in 2013 from the prior year, consistent with the decrease in marketing revenues discussed above.
Exploration expenses were $282 million higher in 2013 than in 2012, primarily due to larger non-cash unproved property impairments in our North America E&P segment related to Eagle Ford leases that either expired or that we did not expect to drill, partially offset by reduced geological and geophysical costs. The following table summarizes the components of exploration expenses:

(In millions)                  2013   2012
Unproved property impairments $ 580  $ 227
Dry well costs                  218    230
Geological and geophysical       84    135
Other                           106    114
Total exploration expenses    $ 988  $ 706

Depreciation, depletion and amortization increased $313 million in 2013 from the prior year. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs. Increased DD&A in 2013 primarily reflects the impact of higher North America E&P sales volumes as well as increased amortization of capitalized asset retirement costs due to revisions of estimates for abandonment obligations in the Gulf of Mexico and the U.K. However, the disposition of our Alaska assets in January 2013 and lower International E&P DD&A primarily due to 2013 reserve additions in Norway partially offset the increase. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about the Alaska disposition.
The DD&A rate (expense per boe), which is impacted by changes in reserves and capitalized costs, can also cause changes to our DD&A. A higher 2013 DD&A rate in North America E&P versus 2012 is due to the ongoing development programs in the U.S. resource plays. A lower International E&P DD&A rate in 2013 compared to 2012 was primarily due to reserve increases for Norway. The following table provides DD&A rates for each segment:

($ per boe)         2013     2012
North America E&P  $26.23   $23.45
International E&P   $7.26    $8.08
Oil Sands Mining   $12.39   $12.57

Impairments in 2013 primarily related to capitalized costs associated with engineering and feasibility studies for a second LNG production train in E.G., the Ozona development in the Gulf of Mexico, and our Powder River Basin asset in Wyoming. Impairments in 2012 were also related to the Ozona development and Powder River Basin. See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for information about these impairments.
Taxes other than income include production, severance and ad valorem taxes in the United States, which tend to increase or decrease in relation to net sales volumes and revenues, and increased $104 million in 2013 from 2012. With the increase in North America E&P revenues and net sales volumes, production and severance taxes increased. In addition, ad valorem taxes were higher because the value of our North America E&P assets has increased with continued acquisitions in the Eagle Ford.
Net interest and other increased $55 million in 2013 from 2012 primarily due to higher interest expense related to our $2 billion issuance of senior notes in late 2012. See Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for more detailed information.


Provision for income taxes decreased $1,180 million in 2013 from 2012 primarily due to the decrease in pretax income from continuing operations, primarily in Libya and Norway, which are higher tax jurisdictions. The following is an analysis of the effective tax rates for 2013 and 2012.

                                                              2013          2012
Statutory rate applied to income from continuing
operations before income taxes                                    35 %          35 %
Effects of foreign operations, including foreign tax
credits                                                           14            18
Adjustments to valuation allowances                               18            21
Other                                                              1             -
Effective income tax rate on continuing operations                68 %          74 %

The effective income tax rate is influenced by a variety of factors including the geographic 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 appears in the "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 decreased in 2013 as compared to 2012, primarily due to decreased sales in Libya during 2013 as a result of third-party labor strikes at the Es Sider oil terminal.
Adjustments to valuation allowances - In 2013 and 2012, 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 is presented net of tax. In 2013, we entered into agreements to sell our Angola assets; therefore, the Angola operations are reflected as discontinued operations in all periods presented. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements.
Segment Results: 2013 compared to 2012
Segment income for 2013 and 2012 is summarized and reconciled to net income in the following table.

(In millions)                                                2013        2012
North America E&P                                          $   529     $   382
International E&P                                            1,423       1,660
Oil Sands Mining                                               206         171
Segment income                                               2,158       2,213
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items                         (473 )      (475 )
Unrealized gain (loss) on crude oil derivative instruments     (33 )        34
Net gain (loss) on dispositions                                (20 )        72
Impairments                                                    (39 )      (231 )
Income from continuing operations                            1,593       1,613
  Discontinued operations                                      160         (31 )
Net income                                                 $ 1,753     $ 1,582

North America E&P segment income increased $147 million in 2013 compared to 2012. The increase was largely due to increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford, Bakken and Oklahoma resource basins, partially offset by higher DD&A associated with the higher sales volumes. Segment income was also negatively impacted by higher exploration expenses related to non-cash unproved property impairments and the sale of our Alaska assets.
International E&P segment income decreased $237 million in 2013 compared to 2012. The decrease was primarily related to the lower liquid hydrocarbon net sales volumes in Libya and Norway and lower average liquid hydrocarbon price realizations, as well as higher exploration expenses, partially offset by lower DD&A associated with the lower sales volumes.

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