Marathon Oil (MRO)

        Derivative losses of $18 million and gains of $27 million were included in E&P segment income for the first nine months of 2007 and 2006, and were primarily related to derivatives utilized to protect the value of natural gas in storage and margins on natural gas purchases for resale.  Excluded from E&P segment income were losses of $111 million and gains of $182 million for the first nine months of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

        At September 30, 2007, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price risks related to our production and may enter into derivative commodity instruments when it is deemed advantageous.  As a particular but not exclusive example, we may elect to use commodity derivative instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

30

E&P Segment

Derivative losses of $24 million and gains of $24 million were included in E&P segment income for the first six months of 2007 and 2006, and were primarily related to derivatives utilized to protect the value of natural gas in storage and margins on natural gas purchases for resale.  Excluded from E&P segment income were gains of $12 million and $61 million for the first six months of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

At June 30, 2007, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price risks related to our production and may enter into derivative commodity instruments when it is deemed advantageous.  As a particular but not exclusive example, we may elect to use commodity derivative instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

27

E&P Segment

Derivative losses of $30 million and gains of $15 million were included in E&P segment income for the first quarters of 2007 and 2006, and were primarily related to derivatives utilize to protect the value of natural gas in storage and in transit.  Excluded from E&P segment income were gains of $21 million and $78 million for the first quarters of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

At March 31, 2007, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore remained exposed to market prices of commodities.  We continue to evaluate the commodity price risks related to our production and may enter into commodity derivative instruments when it is deemed advantageous.  As a particular but not exclusive example, we may elect to use commodity derivative instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

22

E&P Segment

        Derivative gains of $25 million in 2006 and $7 million in 2005 and losses of $152 million in 2004 are included in E&P segment results. Additionally, losses from discontinued cash flow hedges of $3 million are included in 2004 segment results. The discontinued cash flow hedge amounts were reclassified from accumulated other comprehensive income as it was no longer probable that the original forecasted transactions would occur. The results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are included in the E&P segment for all periods presented.

        Excluded from E&P segment results were gains of $454 million in 2006 and losses of $386 million in 2005 and $99 million in 2004 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments. For additional information on these U.K. natural gas contracts, see "Fair Value Estimates" on page 37.

        At December 31, 2006 and 2005, we had no open derivative contracts related to our oil and natural gas production and therefore remained substantially exposed to market prices of commodities. In 2004, we reduced our exposure to market prices of commodities on 26 percent of crude oil production and 7 percent of natural gas production. We continue to evaluate the commodity price risks related to our production and may enter into commodity derivative instruments when it is deemed advantageous. As a particular but not exclusive example, we may elect to use commodity derivative instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

57

IG Segment

We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing natural gas marketing and transportation activity; to hedge purchased gas injected into storage for subsequent resale; and to lock in margins for gas purchased and subsequently resold.   IG segment income included derivative losses of $9 million and derivative gains of $14 million for the first nine months of 2005 and 2004.

IG Segment

We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing natural gas marketing and transportation activity; and to hedge purchased gas injected into storage for subsequent resale.  Derivative gains included in IG segment income were $4 million and $10 million for the first six months of 2005 and 2004.

29

IG Segment

We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we will use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing natural gas marketing and transportation activity; and to hedge purchased gas injected into storage for subsequent resale.  Derivative gains or losses included in IG segment income were $(3) million and $8 million for the first quarter 2005 and 2004.

22

IG Segment

        We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we will use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing purchase for resale activity; and to hedge purchased gas injected into storage for subsequent resale. Derivative gains included in IG segment income were $17 million in 2004, compared to gains of $19 million in 2003 and losses of $8 million in 2002. Trading activity in the IG segment resulted in losses of $2 million in 2004, compared to losses of $7 million in 2003 and gains of $4 million in 2002 and have been included in the aforementioned amounts.