Marathon Oil (MRO)

Commodity Price Risk

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. We also may utilize the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical transactions.

Our E&P segment primarily uses commodity derivative instruments to mitigate the natural gas price risk during the time that the natural gas is held in storage before it is sold or on natural gas that is purchased to be marketed with our own natural gas production. We also may use commodity derivative instruments selectively to protect against price decreases on portions of our future sales of liquid hydrocarbons or natural gas when it is deemed advantageous to do so. The majority of these derivatives are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with data from active markets, making them a Level 2 in the fair value hierarchy described by SFAS No. 157.

Unrealized gains and losses on certain natural gas contracts in the U.K. that are accounted for as derivative instruments are excluded from E&P segment income. These contracts originated in the early 1990s and expire in September 2009. The contract prices are reset annually in October based on the previous twelve-month changes in a basket of energy and other indices. Consequently, the prices under these contracts do not track forward natural gas prices. The reported fair value of the U.K. natural gas contracts is measured with an income approach by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes for the shorter of the remaining contract term or 18 months. Such an internally generated model is classified as Level 3 in the fair value hierarchy.

Our OSM segment may use commodity derivative instruments to protect against price decreases on portions of our future sales of synthetic crude oil when it is deemed advantageous to do so. The reported fair value of these crude oil options, which expire December 2009, is measured using a Black-Scholes option pricing model, which is an income approach that utilizes prices from the active commodity market and market volatility calculated by a third-party service. Because a third-party service is used, and their inputs represent unobservable market data, these are classified as Level 3 in the fair value hierarchy.

Our RM&T segment primarily uses commodity derivative instruments on a selective basis to mitigate crude oil price risk during the time that crude oil inventories are held before they are actually refined into salable petroleum products. We also use derivative instruments in our RM&T segment to manage price risk related to refined petroleum products, feedstocks used in the refining process and ethanol blended with refined petroleum products and fixed price sales contracts. We use commodity derivative instruments to mitigate crude oil price risk between the time that crude oil purchases are priced and when they are actually refined into salable petroleum products, but we have decreased our use of derivatives in this manner as described further below. The majority of these derivatives are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market making them a Level 1 in the fair value hierarchy. When broker accounts are covered by master netting agreements the broker deposits are netted against the value to arrive at the fair values of Level 1 and Level 2 commodity derivatives.

Generally, commodity derivative instruments used in our E&P segment qualify for hedge accounting. As a result, we do not recognize in net income any changes in the fair value of those derivative instruments until the

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underlying physical transaction occurs. We have not qualified commodity derivative instruments used in our OSM or RM&T segments for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivative instruments used in those operations.

Commodity Price Risk

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. We also may utilize the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical transactions.

Our E&P segment primarily uses commodity derivative instruments to mitigate the natural gas price risk during the time that the natural gas is held in storage before it is sold or on natural gas that is purchased to be marketed with our own natural gas production. We also may use commodity derivative instruments selectively to protect against price decreases on portions of our future sales of liquid hydrocarbons or natural gas when it is deemed advantageous to do so. The majority of these derivatives are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with data from active markets, making them a Level 2 in the fair value hierarchy described by SFAS No. 157.

Unrealized gains and losses on certain natural gas contracts in the U.K. that are accounted for as derivative instruments are excluded from E&P segment income. These contracts originated in the early 1990s and expire in September 2009. The contract prices are reset annually in October based on the previous twelve-month changes in a basket of energy and other indices. Consequently, the prices under these contracts do not track forward natural gas prices. The reported fair value of the U.K. natural gas contracts is measured with an income approach by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes for the shorter of the remaining contract term or 18 months. Such an internally generated model is classified as Level 3 in the fair value hierarchy.

Our OSM segment may use commodity derivative instruments to protect against price decreases on portions of our future sales of synthetic crude oil when it is deemed advantageous to do so. The reported fair value of these crude oil options, which expire December 2009, is measured using a Black-Scholes option pricing model, which is an income approach that utilizes prices from the active commodity market and market volatility calculated by a third-party service. Because a third-party service is used, and their inputs represent unobservable market data, these are classified as Level 3 in the fair value hierarchy.

Our RM&T segment primarily uses commodity derivative instruments on a selective basis to mitigate crude oil price risk during the time that crude oil inventories are held before they are actually refined into salable petroleum products. We also use derivative instruments in our RM&T segment to manage price risk related to refined petroleum products, feedstocks used in the refining process and ethanol blended with refined petroleum products and fixed price sales contracts. We use commodity derivative instruments to mitigate crude oil price risk between the time that crude oil purchases are priced and when they are actually refined into salable petroleum products, but we have decreased our use of derivatives in this manner as described further below. The majority of these derivatives are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market making them a Level 1 in the fair value hierarchy. When broker accounts are covered by master netting agreements the broker deposits are netted against the value to arrive at the fair values of Level 1 and Level 2 commodity derivatives.

Generally, commodity derivative instruments used in our E&P segment qualify for hedge accounting. As a result, we do not recognize in net income any changes in the fair value of those derivative instruments until the

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underlying physical transaction occurs. We have not qualified commodity derivative instruments used in our OSM or RM&T segments for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivative instruments used in those operations.

Commodity Price Risk

SIZE="2">Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of commodity derivative instruments, including futures, forwards,
swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. We also may utilize the market knowledge gained from these activities to do a limited amount of trading not directly related
to our physical transactions.

Our E&P segment primarily uses commodity derivative instruments to mitigate the natural gas price risk
during the time that the natural gas is held in storage before it is sold or on natural gas that is purchased to be marketed with our own natural gas production. We also may use commodity derivative instruments selectively to protect against price
decreases on portions of our future sales of liquid hydrocarbons or natural gas when it is deemed advantageous to do so. The majority of these derivatives are measured at fair value with a market approach using broker quotes or third-party pricing
services, which have been corroborated with data from active markets, making them a Level 2 in the fair value hierarchy described by SFAS No. 157.

FACE="Times New Roman" SIZE="2">Unrealized gains and losses on certain natural gas contracts in the U.K. that are accounted for as derivative instruments are excluded from E&P segment income. These contracts originated in the early 1990s and
expire in September 2009. The contract prices are reset annually in October based on the previous twelve-month changes in a basket of energy and other indices. Consequently, the prices under these contracts do not track forward natural gas prices.
The reported fair value of the U.K. natural gas contracts is measured with an income approach by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes for the shorter of the
remaining contract term or 18 months. Such an internally generated model is classified as Level 3 in the fair value hierarchy.

Our OSM
segment may use commodity derivative instruments to protect against price decreases on portions of our future sales of synthetic crude oil when it is deemed advantageous to do so. The reported fair value of these crude oil options, which expire
December 2009, is measured using a Black-Scholes option pricing model, which is an income approach that utilizes prices from the active commodity market and market volatility calculated by a third-party service. Because a third-party service is
used, and their inputs represent unobservable market data, these are classified as Level 3 in the fair value hierarchy.

Our RM&T
segment primarily uses commodity derivative instruments on a selective basis to mitigate crude oil price risk during the time that crude oil inventories are held before they are actually refined into salable petroleum products. We also use
derivative instruments in our RM&T segment to manage price risk related to refined petroleum products, feedstocks used in the refining process and ethanol blended with refined petroleum products and fixed price sales contracts. We use commodity
derivative instruments to mitigate crude oil price risk between the time that crude oil purchases are priced and when they are actually refined into salable petroleum products, but we have decreased our use of derivatives in this manner as described
further below. The majority of these derivatives are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market making them
a Level 1 in the fair value hierarchy. When broker accounts are covered by master netting agreements the broker deposits are netted against the value to arrive at the fair values of Level 1 and Level 2 commodity derivatives.

Commodity Price Risk

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open commodity derivative instruments as of June 30, 2007 are provided in the following table:

(a)          We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the sensitivity analysis.  Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at June 30, 2007. Included in the natural gas impacts shown above are $44 million and $111 million related to the long-term U.K. natural gas contracts accounted for as derivative instruments for hypothetical price changes of 10 percent and 25 percent.  We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after June 30, 2007, would cause future IFO effects to differ from those presented in the table.

(b)         The number of net open contracts for the E&P segment varied throughout the second quarter of 2007, from a low of 15 contracts on April 30, 2007, to a high of 782 contracts on April 1, 2007, and averaged 322 for the quarter.  The number of net open contracts for the RM&T segment varied throughout the second quarter of 2007, from a low of 982 contracts on April 17, 2007 to a high of 21,633 contracts on June 27, 2007, and averaged 11,864 for the quarter.  The derivative commodity instruments used and positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.

(c)          The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated.  Gains and losses on options are based on changes in intrinsic value only.

(d)     The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.

(e)          Price increase.

Commodity Price Risk

        Sensitivity analyses of the incremental effects on income from operations ("IFO") of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative commodity instruments as of December 31, 2006 and December 31, 2005, are provided in the following table:

^(a)

We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the sensitivity analyses. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at December 31, 2006 and 2005. Included in the natural gas impacts shown above are effects related to the long-term U.K. natural gas contracts, which were $54 million in 2006 and $90 million in 2005, for hypothetical price changes of 10 percent and were $138 million in 2006 and $225 million in 2005 for hypothetical price changes of 25 percent. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after December 31, 2006, would cause future IFO effects to differ from those presented in this table.

^(b)

The number of net open contracts for the E&P segment varied throughout 2006, from a low of 316 contracts on June 27, 2006 to a high of 1,634 contracts on January 2, 2006, and averaged 1,054 for the year. The number of net open contracts for the RM&T segment varied throughout 2006, from a low of 166 contracts on December 7, 2006 to a high of 25,123 contracts on August 23, 2006, and averaged 13,154 for the year. The derivative commodity instruments used and positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.

^(c)

The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.

^(d)

The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.

^(e)

Price increase.

^(f)

Price decrease.

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.

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RM&T Segment

        We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivatives used in our RM&T operations. Pretax derivative gains and losses included in RM&T segment income for each of the last three years are summarized in the following table:

        Derivatives used in non-trading activities have an underlying physical commodity transaction. Since the majority of RM&T segment derivative contracts are for the sale of commodities, derivative losses generally occur when market prices increase and typically are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains generally occur when market prices decrease and are typically offset by losses on the underlying physical commodity transactions. The income effect related to derivatives and the income effect related to the underlying physical transactions may not necessarily be recognized in net income in the same period because we do not attempt to qualify these commodity derivative instruments for hedge accounting. The year-to-year change in the net impact of derivatives primarily reflects changes in market conditions.

Commodity Price Risk

Sensitivity analyses of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative instruments as of March 31, 2005 are provided in the following table:

(a)        We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reflected in the sensitivity analyses.  Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at March 31, 2005. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and adds or revises strategies to reflect anticipated market conditions and changes in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review, including the use of master netting agreements to the extent practical. Changes to the portfolio after March 31, 2005, would cause future IFO effects to differ from those presented in the table.

(b)       Net open contracts for the combined E&P and IG segments varied throughout first quarter 2005, from a low of 1,243 contracts at March 10 to a high of 2,192 contracts at January 20, and averaged 1,673 for the quarter.  The number of net open contracts for the RM&T segment varied throughout first quarter 2005, from a low of 10,125 contracts at February 17 to a high of 28,079 contracts at March 21, and averaged 19,739 for the quarter.  The commodity derivative instruments used and hedging positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.

(c)        The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated.  Gains and losses on options are based on changes in intrinsic value only.

(d)       The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.

(e)        Price increase.

Commodity Price Risk

        Sensitivity analyses of the incremental effects on income from operations ("IFO") of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative commodity instruments as of December 31, 2004 and December 31, 2003, are provided in the following table:^(a)

^(a)

We remain at risk for future changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reported in the sensitivity analyses. Amounts assume hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at December 31, 2004 and 2003. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after December 31, 2004, would cause future IFO effects to differ from those presented in the table.

^(b)

Net open contracts for the combined E&P and IG segments varied throughout 2004, from a low of 1 contract at December 15 to a high of 39,683 contracts at January 1, and averaged 19,344 for the year. The number of net open contracts for the RM&T segment varied throughout 2004, from a low of 253 contracts at July 7 to a high of 23,138 contracts at October 13, and averaged 11,437 for the year. The derivative commodity instruments used and hedging positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.

^(c)

The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.

^(d)

The direction of the price change used in calculating the sensitivity amount for each commodity is based on the largest incremental decrease in IFO when applied to the derivative commodity instruments used to hedge that commodity.

^(e)

Price increase.

^(f)

Price decrease.

E&P Segment

        Derivative losses included in the E&P segment were $169 million in 2004 compared to losses of $110 million in 2003 and gains of $34 million in 2002. Additionally, losses from discontinued cash flow hedges of $3 million are included in 2004 segment results, compared to losses of $8 million in 2003 and gains of $23 million in 2002. The discontinued cash flow hedge amounts were reclassified from accumulated other comprehensive income (loss) as it was no longer probable that the original forecasted transactions would occur.

        Excluded from the E&P segment results were losses of $99 million in 2004, losses of $66 million in 2003 and gains of $18 million in 2002 on long-term gas contracts in the United Kingdom that are accounted for as derivative instruments. For additional information on U.K. gas contracts, see "Estimated Fair Value of Derivative Contracts" on page 31.

        At December 31, 2004, we had no open equity production derivative contracts. We evaluate the commodity price risk of our equity production on an ongoing basis and may enter into commodity derivative instruments when it is deemed advantageous.

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RM&T Segment

        We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize all changes in the fair value of derivatives used in our RM&T operations in income, although most of these derivatives have an underlying physical commodity transaction. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying physical commodity transactions. Derivative gains or losses included in RM&T segment income for each of the last three years are summarized in the following table:

        During 2004, using derivative instruments MAP sold crack spreads forward through the fourth quarter 2005 at values higher than the company thought sustainable in the actual months these contracts expire. Included in the $76 million derivative loss for 2004 noted in the above table for the "Protect crack spread values" strategy was approximately an $8 million gain due to changes in the fair value of crack-spread derivatives that will expire throughout 2005.

        In addition, natural gas options are in place to manage the price risk associated with approximately 41 percent of the first quarter 2005 anticipated natural gas purchases for refinery use.

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.