Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (continued
## Table 0 ##
(a) Excludes $(26) million, $(5) million and $59 million of discounted future net cash flows from the effects of hedging transactions for 2003, 2002 and 2001, respectively.
Management’s Discussion and Analysis of Income and Operations Revenues for each of the last three years are summarized in the following table:
## Table 1 ##
E&P segment revenues increased by $279 million in 2003 from 2002 and decreased by $534 million in 2002 from 2001.
The 2003 increase was primarily due to higher worldwide natural gas and liquid hydrocarbon prices.
This increase was partially offset by lower liquid hydrocarbon and natural gas volumes.
The decrease in 2002 was primarily due to lower worldwide natural gas prices and lower liquid hydrocarbon and natural gas volumes, partially offset by higher worldwide liquid hydrocarbon prices.
Derivative gains (losses) totaled $(176) million in 2003, compared to $52 million in 2002 and $85 million in 2001.
Derivatives included losses of $66 million in 2003, compared to gains of $18 million in 2002, related to long-term gas contracts in the United Kingdom that are accounted for as derivative instruments and marked-to-market.
RM&T segment revenues increased by $8.115 billion in 2003 from 2002 and decreased by $848 million in 2002 from 2001.
The 2003 increase primarily reflected higher refined product selling prices and volumes and increased matching crude oil buy/sell transaction volumes and prices.
The decrease in 2002 was primarily due to lower refined product prices.
OERB segment revenues increased by $1.087 billion in 2003 from 2002 and $60 million in 2002 from 2001.
The increase in 2003 is a result of higher natural gas and liquid hydrocarbon prices and increased natural gas and crude oil marketing activity.
The increase in 2002 reflected a favorable effect from increased natural gas and crude oil marketing activity partially offset by lower natural gas prices.
Derivative gains (losses) totaled $19 million in 2003, compared to $(8) million in 2002 and $(29) million in 2001.
For additional information on segment results, see discussion on income from operations on page 36.
Income from equity method investments decreased by $108 million in 2003 and increased by $19 million in 2002 from 2001.
The decrease in 2003 is due to a $124 million loss on the dissolution of MKM Partners L. P. , partially offset by increased earnings of other equity method investments due to higher natural gas and liquid hydrocarbons prices.
For further discussion of the dissolution of MKM Partners L. P. , see Note 13 to the Consolidated Financial Statements.
The increase in 2002 is primarily the result of increased earnings in other equity method investments due to higher liquid hydrocarbons prices.
Net gains on disposal of assets increased by $99 million in 2003 from 2002 and $23 million in 2002 from 2001.
During 2003, Marathon sold its interest in CLAM Petroleum B. V. , interests in several pipeline companies, Yates field and gathering system, SSA stores primarily in Florida, South Carolina, North Carolina and Georgia, and certain fields in the Big Horn Basin of Wyoming.
Results from 2002 include the sale of various SSA stores and the sale of San Juan Basin assets.
Results from 2001 include the sale of various SSA stores and various domestic producing properties.
Gain (loss) on ownership change in MAP reflects the effects of contributions to MAP of certain environmental capital expenditures and leased property acquisitions funded by Marathon and Ashland.
In accordance with MAP’s limited liability company agreement, in certain instances, environmental capital
Cash Flows Net cash provided from operating activities (for continuing operations) totaled $2.678 billion in 2003, compared with $2.336 billion in 2002 and $2.749 billion in 2001.
The increase in 2003 mainly reflects the effects of higher worldwide natural gas and liquid hydrocarbons prices and a higher refining and wholesale marketing margin.
Additionally in 2003, MAP made cash contributions to its pension plans of $89 million.
The decrease in 2002 mainly reflects the effects of lower refined product margins and lower prices for natural gas.
Net cash provided from operating activities (for discontinued operations) totaled $83 million in 2003, compared with $69 million in 2002 and $887 million in 2001.
This is primarily related to Marathon’s E&P operations in western Canada sold in 2003.
Also included in 2001 is the business of United States Steel.
Capital expenditures for each of the last three years are summarized in the following table:
## Table 2 ##
(a) Amounts exclude the acquisitions of KMOC in 2003, the Equatorial Guinea interests in 2002 and Pennaco in 2001.
Capital expenditures in 2003 totaled $1.892 billion compared with $1.520 billion and $1.533 billion in 2002 and 2001, excluding the acquisitions of KMOC in 2003, Equatorial Guinea interests in 2002 and Pennaco in 2001.
The $372 million increase in 2003 mainly reflected increased spending in the RM&T segment at the Catlettsburg refinery and on the Cardinal Products Pipeline and in the E&P segment in West Africa and Norway.
The increase in OERB is due to the purchase of 30% interest in two LNG tankers which Marathon previously leased and project development costs associated with Phase 3 in Equatorial Guinea.
The $13 million decrease in 2002 mainly reflected decreased spending in the E&P segment offset by increased spending in the RM&T segment.
The decrease in the E&P segment was primarily due to the drilling of fewer gas wells in the United States in 2002 partially offset by higher capital expenditures for completion of a pipeline in Gabon, for a pipeline construction contract in Ireland and for development expenditures in Equatorial Guinea.
The increase in the RM&T segment in 2002 was attributable to increased spending on the multi-year integrated investment program at MAP’s Catlettsburg refinery and construction of the Cardinal Products Pipeline in 2002, partially offset by lower capital expenditures for SSA retail outlets and completion of the Garyville coker construction in 2001.
The decrease in corporate in 2002 was primarily due to the implementation of SAP financial and operations software in 2001.
Acquisitions included cash payments of $252 million in 2003 for the acquisition of KMOC, $1.160 billion in 2002 for the acquisitions of Equatorial Guinea interests and $506 million in 2001 for the acquisition of Pennaco.
For further discussion of acquisitions, see Note 5 to the Consolidated Financial Statements.
Cash from disposal of assets was $1.256 billion, including the disposal of discontinued operations, in 2003, compared with $146 million in 2002 and $83 million in 2001.
In 2003, proceeds were primarily from the disposition of Marathon’s E&P properties in western Canada, Yates field and gathering system, interest in CLAM Petroleum B. V. , SSA stores, interest in several pipeline companies and certain fields in the Big Horn Basin of Wyoming.
In 2002, proceeds were primarily from the disposition of various SSA stores and the sale of San Juan Basin assets.
In 2001, proceeds were primarily from the sale of certain Canadian assets, SSA stores, and various domestic producing properties.
Net cash used in financing activities totaled $888 million in 2003, compared with net cash provided of $88 million in 2002 and net cash used of $1.290 billion in 2001.
The decrease was due to activity in 2002 primarily associated with financing the acquisitions of Equatorial Guinea interests of $1.160 billion.
This was partially offset by the $295 million repayment of preferred securities in 2002 that became redeemable or were converted to a right to receive cash upon the Separation.
In early January 2002, Marathon paid $185 million to retire the 6.75% Convertible Quarterly Income Preferred Securities and $110 million to retire the 6.50% Cumulative Convertible Preferred Stock.
Additionally, distributions to the minority shareholder of MAP were $262 million in 2003,
RM&T Segment Marathon’s RM&T operations primarily use derivative commodity instruments to mitigate the price risk of certain crude oil and other feedstock purchases, to protect carrying values of excess inventories, to protect margins on fixed price sales of refined products and to lock-in the price spread between refined products and crude oil.
Derivative instruments are used to mitigate the price risk between the time foreign and domestic crude oil and other feedstock purchases for refinery supply are priced and when they are actually refined into salable petroleum products.
In addition, natural gas options are in place to manage the price risk associated with approximately 60% of the anticipated natural gas purchases for refinery use through the first quarter of 2004 and 50% through the second quarter of 2004.
Derivative commodity instruments are also used to protect the value of excess refined product, crude oil and LPG inventories.
Derivatives are used to lock in margins associated with future fixed price sales of refined products to non-retail customers.
Derivative commodity instruments are used to protect against decreases in the future crack spreads.
Within a limited framework, derivative instruments are also used to take advantage of opportunities identified in the commodity markets.
Derivative gains (losses) included in RM&T segment income for each of the last two years are summarized in the following table:
## Table 3 ##
Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transaction.
Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying physical commodity transaction.
OERB Segment Marathon has 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, Marathon will use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in its ongoing purchase for resale activity; and to hedge purchased gas injected into storage for subsequent resale.
Derivative gains (losses) included in OERB segment income were $19 million, $(8) million and $(29) million for 2003, 2002 and 2001.
OERB’s trading activity gains (losses) of $(7) million, $4 million and $(1) million in 2003, 2002 and 2001 are included in the aforementioned amounts.
Other Commodity Risk Marathon is subject to basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity.
Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets.
For example, New York Mercantile Exchange (“NYMEX”) contracts for natural gas are priced at Louisiana’s Henry Hub, while the underlying quantities of natural gas may be produced and sold in the western United States at prices that do not move in strict correlation with NYMEX prices.
To the extent that commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased exposure to basis risk.
These regional price differences could yield favorable or unfavorable results.
OTC transactions are being used to manage exposure to a portion of basis risk.
Marathon is subject to liquidity risk, caused by timing delays in liquidating contract positions due to a potential inability to identify a counterparty willing to accept an offsetting position.
Due to the large number of active participants, liquidity risk exposure is relatively low for exchange-traded transactions.

Tables referenced above, in order (Table 0 first):
<table><tr><td> <i>(In millions)</i> </td><td>United States</td><td>Europe</td><td>West Africa</td><td>Other Int’l.</td><td>Consolidated</td><td>Equity Investees</td><td>Total</td></tr><tr><td> December 31, 2003:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$13,331</td><td>$3,955</td><td>$4,471</td><td>$1,593</td><td>$23,350</td><td>$35</td><td>$23,385</td></tr><tr><td>Future production, transportation and administrative costs</td><td>-4,919</td><td>-1,050</td><td>-1,161</td><td>-827</td><td>-7,957</td><td>-19</td><td>-7,976</td></tr><tr><td>Future development costs</td><td>-758</td><td>-435</td><td>-175</td><td>-229</td><td>-1,597</td><td>-1</td><td>-1,598</td></tr><tr><td>Future income tax expenses</td><td>-2,612</td><td>-870</td><td>-780</td><td>-163</td><td>-4,425</td><td>-5</td><td>-4,430</td></tr><tr><td>Future net cash flows</td><td>5,042</td><td>1,600</td><td>2,355</td><td>374</td><td>9,371</td><td>10</td><td>9,381</td></tr><tr><td>10% annual discount for estimated timing of cash flows</td><td>-1,789</td><td>-301</td><td>-1,112</td><td>-168</td><td>-3,370</td><td>-2</td><td>-3,372</td></tr><tr><td>Standardized measure of discounted future net cash flows relating to proved oil and gas reserves<sup>(a)</sup></td><td>$3,253</td><td>$1,299</td><td>$1,243</td><td>$206</td><td>$6,001</td><td>$8</td><td>$6,009</td></tr><tr><td>December 31, 2002:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$12,994</td><td>$4,256</td><td>$4,136</td><td>$83</td><td>$21,469</td><td>$5,652</td><td>$27,121</td></tr><tr><td>Future production, transportation and administrative costs</td><td>-5,103</td><td>-1,218</td><td>-1,097</td><td>-30</td><td>-7,448</td><td>-1,465</td><td>-8,913</td></tr><tr><td>Future development costs</td><td>-650</td><td>-351</td><td>-324</td><td>-4</td><td>-1,329</td><td>-333</td><td>-1,662</td></tr><tr><td>Future income tax expenses</td><td>-2,440</td><td>-989</td><td>-753</td><td>-27</td><td>-4,209</td><td>-1,150</td><td>-5,359</td></tr><tr><td>Future net cash flows</td><td>4,801</td><td>1,698</td><td>1,962</td><td>22</td><td>8,483</td><td>2,704</td><td>11,187</td></tr><tr><td>10% annual discount for estimated timing of cash flows</td><td>-1,639</td><td>-444</td><td>-954</td><td>-5</td><td>-3,042</td><td>-2,212</td><td>-5,254</td></tr><tr><td>Standardized measure of discounted future net cash flows relating to proved oil and gas reserves<sup>(a)</sup></td><td>$3,162</td><td>$1,254</td><td>$1,008</td><td>$17</td><td>$5,441</td><td>$492</td><td>$5,933</td></tr><tr><td>Standardized measure of discounted future net cash flows relating to discontinued operations</td><td>$–</td><td>$–</td><td>$–</td><td>$384</td><td>$384</td><td>$–</td><td>$384</td></tr><tr><td>December 31, 2001:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$8,210</td><td>$3,601</td><td>$307</td><td>$–</td><td>$12,118</td><td>$3,456</td><td>$15,574</td></tr><tr><td>Future production, transportation and administrative costs</td><td>-2,848</td><td>-1,407</td><td>-111</td><td>–</td><td>-4,366</td><td>-1,198</td><td>-5,564</td></tr><tr><td>Future development costs</td><td>-661</td><td>-364</td><td>-40</td><td>–</td><td>-1,065</td><td>-178</td><td>-1,243</td></tr><tr><td>Future income tax expenses</td><td>-1,480</td><td>-572</td><td>-51</td><td>–</td><td>-2,103</td><td>-468</td><td>-2,571</td></tr><tr><td>Future net cash flows</td><td>3,221</td><td>1,258</td><td>105</td><td>–</td><td>4,584</td><td>1,612</td><td>6,196</td></tr><tr><td>10% annual discount for estimated timing of cash flows</td><td>-1,086</td><td>-267</td><td>-15</td><td>–</td><td>-1,368</td><td>-1,400</td><td>-2,768</td></tr><tr><td>Standardized measure of discounted future net cash flows relating to proved oil and gas reserves<sup>(a)</sup></td><td>$2,135</td><td>$991</td><td>$90</td><td>$–</td><td>$3,216</td><td>$212</td><td>$3,428</td></tr><tr><td>Standardized measure of discounted future net cash flows relating to discontinued operations</td><td>$–</td><td>$–</td><td>$–</td><td>$172</td><td>$172</td><td>$–</td><td>$172</td></tr></table>
<table><tr><td> <i>(In millions)</i> </td><td>2003</td><td>2002</td><td>2001</td></tr><tr><td>E&P</td><td>$3,990</td><td>$3,711</td><td>$4,245</td></tr><tr><td>RM&T</td><td>34,514</td><td>26,399</td><td>27,247</td></tr><tr><td>OERB</td><td>3,209</td><td>2,122</td><td>2,062</td></tr><tr><td>Segment revenues</td><td>41,713</td><td>32,232</td><td>33,554</td></tr><tr><td>Elimination of intersegment revenues</td><td>-750</td><td>-937</td><td>-728</td></tr><tr><td>Elimination of sales to United States Steel</td><td>–</td><td>–</td><td>-30</td></tr><tr><td>Total revenues</td><td>$40,963</td><td>$31,295</td><td>$32,796</td></tr><tr><td>Items included in both revenues and costs and expenses:</td><td></td><td></td><td></td></tr><tr><td>Consumer excise taxes on petroleum products and merchandise</td><td>$4,285</td><td>$4,250</td><td>$4,404</td></tr><tr><td>Matching crude oil and refined product buy/sell transactions settled in cash:</td><td></td><td></td><td></td></tr><tr><td>E&P</td><td>$222</td><td>$289</td><td>$454</td></tr><tr><td>RM&T</td><td>6,936</td><td>4,191</td><td>3,797</td></tr><tr><td>Total buy/sell transactions</td><td>$7,158</td><td>$4,480</td><td>$4,251</td></tr></table>
<table><tr><td> <i>(In millions)</i> </td><td> 2003</td><td>2002</td><td>2001</td></tr><tr><td>E&P<sup>(a)</sup></td><td></td><td></td><td></td></tr><tr><td>Domestic</td><td>$342</td><td>$416</td><td>$537</td></tr><tr><td>International</td><td>629</td><td>403</td><td>294</td></tr><tr><td>Total E&P</td><td>971</td><td>819</td><td>831</td></tr><tr><td>RM&T</td><td>772</td><td>621</td><td>591</td></tr><tr><td>OERB</td><td>133</td><td>49</td><td>4</td></tr><tr><td>Corporate</td><td>16</td><td>31</td><td>107</td></tr><tr><td>Total</td><td>$1,892</td><td>$1,520</td><td>$1,533</td></tr></table>
<table><tr><td><i>Strategy (In Millions)</i></td><td>2003</td><td>2002</td></tr><tr><td>Mitigate price risk</td><td>$-112</td><td>$-95</td></tr><tr><td>Protect carrying values of excess inventories</td><td>-57</td><td>-41</td></tr><tr><td>Protect margin on fixed price sales</td><td>5</td><td>11</td></tr><tr><td>Protect crack spread values</td><td>6</td><td>1</td></tr><tr><td>Trading activities</td><td>-4</td><td>–</td></tr><tr><td>Total net derivative losses</td><td>$-162</td><td>$-124</td></tr></table>

Question: Which year is Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(a) for Total the most?
Answer: 2003