MARATHON OIL CORPORATION Notes to Consolidated Financial Statements The changes in the carrying amount of goodwill for the years ended December 31, 2007, and 2008, were as follows:
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(a) Adjustments related to prior period income tax and royalty adjustments.
(b) Goodwill was allocated to the Norwegian outside-operated properties sold in 2008.17.
Fair Value Measurements As defined in SFAS No.157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
SFAS No.157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques.
The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts.
The cost approach is based on the amount that would currently be required to replace the service capacity of an asset.
This is often referred to as current replacement cost.
The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
SFAS No.157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques.
SFAS No.157 establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques.
Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk.
Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority.
The three levels of the fair value hierarchy are as follows.  ?
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  ?
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data.
These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.  ?
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
We use a market or income approach for recurring fair value measurements and endeavor to use the best information available.
Accordingly, valuation techniques that maximize the use of observable inputs are favored.
Financial assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement.
The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Proved reserves can be added as expansions are permitted, funding is approved and certain stipulations of the joint venture agreement are satisfied.
The following table sets forth changes in estimated quantities of net proved bitumen reserves for the year 2008.
Estimated Quantities of Proved Bitumen Reserves
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(a) Revisions were driven primarily by price and the impact of the new royalty regime discussed below.
The above estimated quantity of net proved bitumen reserves is a forward-looking statement and is based on a number of assumptions, including (among others) commodity prices, volumes in-place, presently known physical data, recoverability of bitumen, industry economic conditions, levels of cash flow from operations, and other operating considerations.
To the extent these assumptions prove inaccurate, actual recoveries could be different than current estimates.
For a discussion of the proved bitumen reserves estimation process, see Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Estimated Net Recoverable Reserve Quantities – Proved Bitumen Reserves.
Operations at the AOSP are not within the scope of Statement of Financial Accounting Standards (“SFAS”) No.25, “Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies (an Amendment of Financial Accounting Standards Board (“FASB”) Statement No.19),” SFAS No.69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39),” and Securities and Exchange Commission (“SEC”) Rule 4-10 of Regulation S-X; therefore, bitumen production and reserves are not included in our Supplementary Information on Oil and Gas Producing Activities.
The SEC has recently issued a release amending these disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, see Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information.
Prior to our acquisition of Western, the first fully-integrated expansion of the existing AOSP facilities was approved in 2006.
Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in late 2010 or 2011.
When Expansion 1 is complete, we will have more than 50,000 bpd of net production and upgrading capacity in the Canadian oil sands.
The timing and scope of future expansions and debottlenecking opportunities on existing operations remain under review.
During 2008, the Alberta government accepted the project’s application to have a portion of the Expansion 1 capital costs form part of the Muskeg River mine’s allowable cost recovery pool.
Due to commodity price declines in the year, royalties for 2008 were one percent of the gross mine revenue.
Commencing January 1, 2009, the Alberta Royalty regime has been amended such that royalty rates will be based on the Canadian dollar (“CAD”) equivalent monthly average West Texas Intermediate (“WTI”) price.
Royalty rates will rise from a minimum of one percent to a maximum of nine percent under the gross revenue method and from a minimum of 25 percent to a maximum of 40 percent under the net revenue method.
Under both methods, the minimum royalty is based on a WTI price of $55.00 CAD per barrel and below while the maximum royalty is reached at a WTI price of $120.00 CAD per barrel and above, with a linear increase in royalty between the aforementioned prices.
The above discussion of the Oil Sands Mining segment includes forward-looking statements concerning the anticipated completion of AOSP Expansion 1.
Factors which could affect the expansion project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.
Refining, Marketing and Transportation Refining We own and operate seven refineries in the Gulf Coast, Midwest and upper Great Plains regions of the United States with an aggregate refining capacity of 1.016 million barrels per day (“mmbpd”) of crude oil.
During 2008
believe that substantially all of our competitors must comply with similar environmental laws and regulations.
However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.
Our environmental expenditures for each of the last three years were:(a)
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(a) Amounts are determined based on American Petroleum Institute survey guidelines regarding the definition of environmental expenditures.
(b) These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded for environmental remediation.
Our environmental capital expenditures accounted for six percent of capital expenditures for continuing operations in 2008, four percent in 2007 and five percent in 2006.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated.
As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future.
We comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Our environmental capital expenditures are expected to be $373 million or seven percent of capital expenditures in 2009.
Predictions beyond 2009 can only be broad-based estimates, which have varied, and will continue to vary, due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent requirements and the availability of new technologies, among other matters.
Based on currently identified projects, we anticipate that environmental capital expenditures will be approximately $426 million in 2010; however, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.
For more information on environmental regulations that impact us, see Item 1.  Business – Environmental Matters and Item 3.
Legal Proceedings.
Critical Accounting Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.
Actual results could differ from the estimates and assumptions used.
Certain accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.
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.
Open Commodity Derivative Positions as of December 31, 2008 and Sensitivity Analysis At December 31, 2008, our E&P segment held open derivative contracts to mitigate the price risk on natural gas held in storage or purchased to be marketed with our own natural gas production in amounts that were in line with normal levels of activity.
At December 31, 2008, we had no significant open derivative contracts related to our future sales of liquid hydrocarbons and natural gas and therefore remained substantially exposed to market prices of these commodities.
The OSM segment holds crude oil options which were purchased by Western for a three year period (January 2007 to December 2009).
The premiums for the purchased put options had been partially offset through the sale of call options for the same three-year period, resulting in a net premium liability.
Payment of the net premium liability is deferred until the settlement of the option contracts.
As of December 31, 2008, the following put and call options were outstanding:

<table><tr><td><i>(In millions)</i></td><td>E&P</td><td>OSM</td><td>RM&T</td><td>Total</td></tr><tr><td>Balance as of December 31, 2006</td><td>$519</td><td>$–</td><td>$879</td><td>$1,398</td></tr><tr><td>Acquired</td><td>71</td><td>1,437</td><td>–</td><td>1,508</td></tr><tr><td>Adjusted<sup>(a)</sup></td><td>–</td><td>–</td><td>-7</td><td>-7</td></tr><tr><td>Balance as of December 31, 2007</td><td>590</td><td>1,437</td><td>872</td><td>2,899</td></tr><tr><td>Adjusted<sup>(a)</sup></td><td>-17</td><td>-25</td><td>7</td><td>-35</td></tr><tr><td>Impaired</td><td>–</td><td>-1,412</td><td>–</td><td>-1,412</td></tr><tr><td>Disposed<sup>(b)</sup></td><td>-5</td><td></td><td>–</td><td>-5</td></tr><tr><td>Balance as of December 31, 2008</td><td>$568</td><td>$–</td><td>$879</td><td>$1,447</td></tr></table>
<table><tr><td><i>(Millions of barrels)</i></td><td>2008</td></tr><tr><td>Beginning of year</td><td>421</td></tr><tr><td>Revisions<sup>(a)</sup></td><td>-30</td></tr><tr><td>Extensions, discoveries and additions</td><td>6</td></tr><tr><td>Production</td><td>-9</td></tr><tr><td>End of year</td><td>388</td></tr></table>
<table><tr><td><i>(In millions)</i></td><td>2008</td><td>2007</td><td>2006</td></tr><tr><td>Capital</td><td>$421</td><td>$199</td><td>$176</td></tr><tr><td>Compliance</td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td>379</td><td>287</td><td>309</td></tr><tr><td>Remediation<sup>(b)</sup></td><td>26</td><td>25</td><td>20</td></tr><tr><td>Total</td><td>$826</td><td>$511</td><td>$505</td></tr></table>

Question: in ( millions of barrels ) , what was the average of beginning and end of year reserves?