Segment Results: 2008 compared to 2007 Segment income or loss for 2008 and 2007 is summarized and reconciled to net income in the following table.
## Table 0 ##
(a) Amounts relate to natural gas contracts in the United Kingdom that are accounted for as derivative instruments and recorded at fair value.
See Critical Accounting Estimates – Fair Value Estimates.
(b) Impairments include a $1,412 million impairment of goodwill related to the OSM reporting unit (see Note 16 to the consolidated financial statements) and a $25 million after-tax impairment ($40 million pretax) related to our investments in ethanol producing facilities (see Note 14 to the consolidated financial statements).
United States E&P income increased $246 million, or 39 percent, in 2008 from 2007.
The majority of the increase from year to year was due to overall higher average liquid hydrocarbon and natural gas realizations with relatively flat sales volumes.
Partially offsetting the benefits of higher prices were increases in production taxes, operating expenses, DD&A and income taxes.
Exploration expenses were $238 million for 2008, lower than $274 million in 2007.  International E&P income increased $740 million, or 67 percent, in 2008 from 2007, primarily due to higher average liquid hydrocarbon realizations and higher sales volumes for both liquid hydrocarbons and natural gas.
Natural gas realizations were slightly lower because a significant portion of the natural gas sales volume increase related to that sold in Equatorial Guinea to the LNG production facility at a fixed price.
Operating expenses and DD&A, associated with production from new developments, and income taxes also increased during 2008.
OSM segment reported income of $258 million in 2008 as compared to a loss of $63 million in 2007.
An after-tax gain on crude oil derivative instruments of $32 million was included in 2008 income, while an after-tax loss of $40 million was recorded in 2007 (see Item 7A.
Quantitative and Qualitative Disclosures about Market Risk).
Results for 2008 include a full year of operations in comparison to two and one-half months of operation in 2007.
Bitumen was produced at an average rate of 25 mbpd in 2008.
Production and processing levels were adversely impacted by planned and unplanned maintenance, reliability issues and the implementation of a revised tailings management plan that impacted ore grade, which also increased operating costs.
RM&T segment income decreased $898 million in 2008 from 2007, primarily a result of a decrease in our refining and wholesale marketing gross margin per gallon from 18.48 cents in 2007 to 11.66 cents in 2008.
The refining and wholesale marketing gross margin decline was consistent with the market indicators (crack spreads) in the Midwest and Gulf Coast regions.
In addition, manufacturing expenses were higher in 2008 due primarily to higher energy costs and maintenance activities.
Included in the refining and wholesale marketing gross margins were pretax derivative losses of $87 million in 2008 and $899 million in 2007.
The variance primarily reflects falling crude futures prices in the second half of 2008, as well as the fact that we no longer use derivatives to mitigate domestic crude oil acquisition price risk.
For
Outlook Budget Our Board of Directors approved a capital, investment and exploration spending budget of $5,882 million for 2014, including budgeted capital expenditures of $5,777 million.
Our capital, investment and exploration spending budget is broken down by reportable segment in the table below.
## Table 1 ##
We continue to focus on growing profitable reserves and production worldwide.
In 2014, we are accelerating drilling activity in our three key U. S.  unconventional resource plays: the Eagle Ford, Bakken and Oklahoma resource basins, which account for approximately 60 percent of our budget.
The majority of spending in our unconventional resource plays is intended for drilling.
With an increased number of rigs in each of these areas, we plan to drill more net wells in these areas than in any previous year.
We also have dedicated a portion of our capital budget in these areas to facility construction and recompletions.
In our conventional assets, we will follow a disciplined spending plan that is intended to provide stable production,with approximately 23 percent of our budget allocated to the development of these assets worldwide.
We also plan to either drill or participate in 8 to 10 exploration wells throughout our portfolio, with 10 percent of our budget allocated to exploration projects.
For additional information about expected exploration and development activities see Item 1.  Business.
The above discussion includes forward-looking statements with respect to projected spending and investment in exploration and development activities under the 2014 capital, investment and exploration spending budget, accelerated rig and drilling activity in the Eagle Ford, Bakken, and Oklahoma resource basins, and future exploratory and development drilling activity.
Some factors which could potentially affect these forward-looking statements 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, availability of materials and labor, other risks associated with construction projects, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations.
These forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals or permits.
The development projects could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience.
The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Sales Volumes We expect to increase our U. S.  resource plays' net sales volumes by more than 30 percent in 2014 compared to 2013, excluding dispositions.
In addition, we expect total production growth to be approximately 4 percent in 2014 versus 2013, excluding dispositions and Libya.
Acquisitions and Dispositions Excluded from our budget are the impacts of acquisitions and dispositions not previously announced.
We continually evaluate ways to optimize our portfolio through acquisitions and divestitures and exceeded our previously stated goal of divesting between $1.5 billion and $3.0 billion of assets over the period of 2011 through 2013.
For the three-year period ended December 31, 2013, we closed or entered agreements for approximately $3.5 billion in divestitures, of which $2.1 billion is from the sales of our Angola assets.
The sale of our interest in Angola Block 31 closed in February 2014 and the sale of our interest in Angola Block 32 is expected to close in the first quarter of 2014.
In December 2013, we announced the commencement of efforts to market our assets in the North Sea, both in the U. K.  and Norway, which would simplify and concentrate our portfolio to higher margin growth opportunities and increase our production growth rate.
The above discussion includes forward-looking statements with respect to our percentage growth rate of production, production available for sale, the sale of our interest in Angola Block 32 and the possible sale of our U. K.  and Norway assets.
Some factors
MARATHON OIL CORPORATION Notes to Consolidated Financial Statements 91 Components of net periodic benefit cost and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.
## Table 2 ##
(a) Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.
Such settlements occurred in one or more of our U. S.  plans in 2013, 2012 and 2011.
(b) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
(c) Includes net inter-company transfers of (gains)/losses due to the spin-off of the downstream business.
The estimated net loss and prior service cost for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $24 million and $6 million.
The estimated prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 is $5 million.
Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2013, 2012 and 2011.

<table><tr><td><i>(In millions)</i></td><td>2008</td><td>2007</td></tr><tr><td>E&P</td><td></td><td></td></tr><tr><td>United States</td><td>$869</td><td>$623</td></tr><tr><td>International</td><td>1,846</td><td>1,106</td></tr><tr><td>E&P segment income</td><td>2,715</td><td>1,729</td></tr><tr><td>OSM</td><td>258</td><td>-63</td></tr><tr><td>RM&T</td><td>1,179</td><td>2,077</td></tr><tr><td>IG</td><td>302</td><td>132</td></tr><tr><td>Segment income</td><td>4,454</td><td>3,875</td></tr><tr><td>Items not allocated to segments, net of income taxes:</td><td></td><td></td></tr><tr><td>Corporate and other unallocated items</td><td>-93</td><td>-122</td></tr><tr><td>Gain (loss) on U.K. natural gas contracts<sup>(a)</sup></td><td>111</td><td>-118</td></tr><tr><td>Foreign currency gain on income taxes</td><td>252</td><td>18</td></tr><tr><td>Impairments<sup>(b)</sup></td><td>-1,437</td><td>—</td></tr><tr><td>Gain on dispositions</td><td>241</td><td>8</td></tr><tr><td>Gain on foreign currency derivative instruments</td><td>—</td><td>112</td></tr><tr><td>Deferred income taxes – tax legislation changes</td><td>—</td><td>193</td></tr><tr><td>Loss on early extinguishment of debt</td><td>—</td><td>-10</td></tr><tr><td>Net income</td><td>$3,528</td><td>$3,956</td></tr></table>
<table><tr><td>(In millions)</td><td>2014 Budget</td><td>Percent of Total</td></tr><tr><td>North America E&P</td><td>$4,241</td><td>72%</td></tr><tr><td>International E&P</td><td>1,242</td><td>21%</td></tr><tr><td>Oil Sands Mining</td><td>294</td><td>5%</td></tr><tr><td>Segment total</td><td>5,777</td><td>98%</td></tr><tr><td>Corporate and other</td><td>105</td><td>2%</td></tr><tr><td>Total capital, investment and exploration spending budget</td><td>$5,882</td><td>100%</td></tr></table>
<table><tr><td></td><td colspan="6">Pension Benefits</td><td></td><td></td><td></td></tr><tr><td></td><td colspan="2">2013</td><td colspan="2">2012</td><td colspan="2">2011</td><td colspan="3">Other Benefits</td></tr><tr><td>(In millions)</td><td>U.S.</td><td>Int’l</td><td>U.S.</td><td>Int’l</td><td>U.S.</td><td>Int’l</td><td>2013</td><td>2012</td><td>2011</td></tr><tr><td>Components of net periodic benefit cost:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$33</td><td>$22</td><td>$31</td><td>$19</td><td>$28</td><td>$19</td><td>$4</td><td>$4</td><td>$4</td></tr><tr><td>Interest cost</td><td>40</td><td>24</td><td>42</td><td>22</td><td>44</td><td>22</td><td>12</td><td>14</td><td>16</td></tr><tr><td>Expected return on plan assets</td><td>-43</td><td>-24</td><td>-43</td><td>-22</td><td>-43</td><td>-23</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>- prior service cost (credit)</td><td>6</td><td>1</td><td>7</td><td>1</td><td>6</td><td>—</td><td>-6</td><td>-7</td><td>-7</td></tr><tr><td>- actuarial loss</td><td>43</td><td>4</td><td>48</td><td>4</td><td>47</td><td>2</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net settlement loss<sup>(a)</sup></td><td>45</td><td>—</td><td>45</td><td>—</td><td>30</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net periodic benefit cost<sup>(b)</sup></td><td>$124</td><td>$27</td><td>$130</td><td>$24</td><td>$112</td><td>$20</td><td>$10</td><td>$11</td><td>$13</td></tr><tr><td>Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Actuarial loss (gain)</td><td>$-161</td><td>$-11</td><td>$172</td><td>$15</td><td>$97</td><td>$24</td><td>$-31</td><td>$7</td><td>$1</td></tr><tr><td>Amortization of actuarial (loss) gain</td><td>-88</td><td>-4</td><td>-93</td><td>-4</td><td>-77</td><td>-2</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Prior service cost (credit)</td><td>—</td><td>—</td><td>—</td><td>1</td><td>—</td><td>-11</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of prior service credit (cost)</td><td>-6</td><td>-1</td><td>-7</td><td>-1</td><td>-6</td><td>—</td><td>6</td><td>7</td><td>7</td></tr><tr><td>Spin-off downstream business<sup>(c)</sup></td><td>—</td><td>—</td><td>—</td><td>—</td><td>-24</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total recognized in other comprehensive (income) loss</td><td>$-255</td><td>$-16</td><td>$72</td><td>$11</td><td>$-10</td><td>$11</td><td>$-25</td><td>$14</td><td>$8</td></tr><tr><td>Total recognized in net periodic benefit cost and other comprehensive (income) loss</td><td>$-131</td><td>$11</td><td>$202</td><td>$35</td><td>$102</td><td>$31</td><td>$-15</td><td>$25</td><td>$21</td></tr></table>

Question: Which year is Interest cost the most for U.S. for Pension Benefits?