for the estimates of our oil sands mining reserves has 33 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986.
He is a member of SPE, having served as regional director from 1998 through 2001 and is a registered Practicing Professional Engineer in the Province of Alberta.
Audits of Estimates Third-party consultants are engaged to provide independent estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period for the purpose of auditing the in-house reserve estimates.
We met this goal for the four-year period ended December 31, 2011.
We established a tolerance level of 10 percent such that initial estimates by the third-party consultants are accepted if they are within 10 percent of our internal estimates.
Should the third-party consultants’ initial analysis fail to reach our tolerance level, both our team and the consultants re-examine the information provided, request additional data and refine their analysis if appropriate.
This resolution process is continued until both estimates are within 10 percent.
This process did not result in significant changes to our reserve estimates in 2011 or 2009.
There were no third-party audits performed in 2010.
During 2011, Netherland, Sewell & Associates, Inc.  (“NSAI”) prepared a Certification of December 31, 2010 reserves for the Alba field in Equatorial Guinea.
The NSAI summary report is filed as an exhibit to this Annual Report on Form 10-K.
The senior members of the NSAI team have over 50 years of industry experience between them, having worked for large, international oil and gas companies before joining NSAI.
The team lead has a Master of Science in mechanical engineering and is a member of SPE.
The senior technical advisor has a Bachelor of Science degree in geophysics and is a member of the Society of Exploration Geophysicists, the American Association of Petroleum Geologists and the European Association of Geoscientists and Engineers.
Both are licensed in the state of Texas.
Ryder Scott Company (“Ryder Scott”) performed audits of several of our fields in 2011 and 2009.
Their summary report on audits performed in 2011 is filed as an exhibit to this Annual Report on Form 10-K.
The team lead for Ryder Scott has over 20 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott.
He has a Bachelor of Science degree in mechanical engineering, is a member of SPE and is a registered Professional Engineer in the state of Texas.
The Corporate Reserves Group also performs separate, detailed technical reviews of reserve estimates for significant fields that were acquired recently or for properties with other indicators such as excessively short or long lives, performance above or below expectations or changes in economic or operating conditions.
Changes in Proved Undeveloped Reserves As of December 31, 2011, 395 mmboe of proved undeveloped reserves were reported, a decrease of 10 mmboe from December 31, 2010.
The following table shows changes in total proved undeveloped reserves for 2011:
## Table 0 ##
Significant additions to proved undeveloped reserves during 2011 include 91 mmboe due to acreage acquisition in the Eagle Ford shale, 26 mmboe related to Anadarko Woodford shale development, 10 mmboe for development drilling in the Bakken shale play and 8 mmboe for additional drilling in Norway.
Additionally, 139 mmboe were transferred from proved undeveloped to proved developed reserves due to startup of the Jackpine upgrader expansion in Canada.
Costs incurred in 2011, 2010 and 2009 relating to the development of proved undeveloped reserves, were $1,107 million, $1,463 million and $792 million.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as behind-pipe zones where reserves will not be accessed until the primary producing zone depletes, large development projects which take more than five years to complete, and the timing of when additional gas compression is needed.
Of the 395 mmboe of proved undeveloped reserves at year end 2011, 34 percent of the volume is associated with projects that have been included in proved reserves for more than five years.
The majority of this volume is related to a compression project in Equatorial Guinea that was sanctioned by our Board of Directors in 2004 and is expected to be completed by 2016.
Performance of this field has exceeded expectations, and estimates of initial dry gas in place increased by roughly 10 percent between 2004 and 2010.
Production is not expected to experience a natural decline from facility-limited plateau production until 2014, or possibly 2015.
The timing of the installation of compression is being driven by the reservoir performance.
A significant portion of our natural gas production in the lower 48 states of the U. S.  is sold at bid-week prices or first-of-month indices relative to our specific producing areas.
Average settlement date Henry Hub natural gas prices have been relatively stable for the periods of this report; however, a decline began in September 2011 which has continued in 2012 with February averaging $2.68 per mmbtu.
Should U. S.  natural gas prices remain depressed, an impairment charge related to our natural gas assets may be necessary.
Our other major natural gas-producing regions are Europe and EG.
Natural gas prices in Europe have been significantly higher than in the U. S.  In the case of EG our natural gas sales are subject to term contracts, making realized prices less volatile.
The natural gas sales from EG are at fixed prices; therefore, our worldwide reported average natural gas realized prices may not fully track market price movements.
Oil Sands Mining OSM segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil we produce.
Roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily Western Canadian Select.
Output mix can be impacted by operational problems or planned unit outages at the mines or the upgrader.
The operating cost structure of the oil sands mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime.
Per-unit costs are sensitive to production rates.
Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company (“AECO”) natural gas sales index and crude oil prices, respectively.
Recently AECO prices have declined, much as Henry Hub prices have.
We would expect a significant, continued declined in natural gas prices to have a favorable impact on OSM operating costs.
The table below shows average benchmark prices that impact both our revenues and variable costs.
## Table 1 ##
(a) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(b) Monthly average day ahead index.
Integrated Gas Our integrated gas operations include production and marketing of products manufactured from natural gas, such as LNG and methanol, in EG.
World LNG trade in 2011 has been estimated to be 241 mmt.
Long-term, LNG continues to be in demand as markets seek the benefits of clean burning natural gas.
Market prices for LNG are not reported or posted.
In general, LNG delivered to the U. S.  is tied to Henry Hub prices and will track with changes in U. S.  natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices.
We have a 60 percent ownership in an LNG production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices.
Gross sales from the plant were 4.1 mmt, 3.7 mmt and 3.9 mmt in 2011, 2010 and 2009.
We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in AMPCO.
Gross sales of methanol from the plant totaled 1,039,657, 850,605 and 960,374 metric tonnes in 2011, 2010 and 2009.
Methanol demand has a direct impact on AMPCO’s earnings.
Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices.
World demand for methanol in 2011 has been estimated to be 55.4 mmt.
Our plant capacity of 1.1 mmt is about 2 percent of total demand.
Operating and Financial Highlights Significant operating and financial highlights during 2011 include: ?
Completed the spin-off of our downstream business on June 30, 2011 ?
Acquired a significant operated position in the Eagle Ford shale play in south Texas ?
Added net proved reserves, for the E&P and OSM segments combined, of 307 mmboe, excluding dispositions, for a 212 percent reserve replacement ratio
?
Increased proved liquid hydrocarbon, including synthetic crude oil, reserves to 78 percent from 75 percent of proved reserves ?
Increased E&P net sales volumes, excluding Libya, by 7 percent ?
Recorded 96 percent average operational availability for all major company-operated E&P assets, compared to 94 percent in 2010 ?
Completed debottlenecking work that increased crude oil production capacity at the Alvheim FPSO in Norway to 150,000 gross bbld from the previous capacity of 142,000 gross bbld and the original 2008 capacity of 120,000 gross bbld ?
Announced two non-operated discoveries in the Iraqi Kurdistan Region and began drilling in Poland ?
Completed AOSP Expansion 1, including the start-up of the expanded Scotford upgrader, realizing an increase in net synthetic crude oil sales volumes of 48 percent ?
Completed dispositions of non-core assets and interests in acreage positions for net proceeds of $518 million ?
Repurchased 12 million shares of our common stock at a cost of $300 million ?
Retired $2,498 million principal of our long-term debt ?
Resumed limited production in Libya in the fourth quarter of 2011 following the February 2011 temporary suspension of operations Consolidated Results of Operations: 2011 compared to 2010 Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company.
Consolidated income from continuing operations before income taxes was 9 percent higher in 2011 than in 2010, largely due to higher liquid hydrocarbon prices.
This improvement was offset by increased income taxes primarily the result of excess foreign tax credits generated during 2011 that we do not expect to utilize in the future.
The effective income tax rate for continuing operations was 61 percent in 2011 compared to 54 percent in 2010.
Revenues are summarized in the following table:
## Table 2 ##
E&P segment revenues increased $2,247 million from 2010 to 2011, primarily due to higher average liquid hydrocarbon realizations, which were $99.37 per bbl in 2011, a 31 percent increase over 2010.
Revenues in 2010 included net pre-tax gains of $95 million on derivative instruments intended to mitigate price risk on future sales of liquid hydrocarbons and natural gas.
Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale.
Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points.
See the Cost of revenues discussion as revenues from supply optimization approximate the related costs.
Higher average crude oil prices in 2011 compared to 2010 increased revenues related to supply optimization.
Revenues from the sale of our U. S.  production are higher in 2011 primarily as a result of higher liquid hydrocarbon and natural gas price realizations, but sales volumes declined.
based on current expectations, estimates and projections and are not guarantees of future performance.
Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict.
Some factors that could cause actual results to differ materially include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.
Contractual Cash Obligations The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2011.
## Table 3 ##
(a) We anticipate cash payments for interest of $286 million for 2012, $542 million for 2013-2014, $535 million for 2015-2016 and $2,965 million for the remaining years for a total of $4,328 million.
(b) Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.
(c) Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
(d) Primarily includes obligations for pension and other postretirement benefits including medical and life insurance.
We have estimated projected funding requirements through 2021.
Also includes amounts for uncertain tax positions.
(e) This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,510 million.
See Item 8.
Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements.
Transactions with Related Parties We own a 63 percent working interest in the Alba field offshore Equatorial Guinea.
Onshore Equatorial Guinea, we own a 52 percent interest in an LPG processing plant, a 60 percent interest in an LNG production facility and a 45 percent interest in a methanol production plant, each through equity method investees.
We sell our natural gas from the Alba field to these equity method investees as the feedstock for their production processes.
The methanol that is produced is then sold through another equity method investee.
Off-Balance Sheet Arrangements Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally accepted in the U. S.  Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.
We will issue stand alone letters of credit when required by a business partner.
Such letters of credit outstanding at December 31, 2011, 2010 and 2009 aggregated $231 million, $439 million and $224 million.
Most of the letters of credit are in support of obligations recorded in the consolidated balance sheet.
For example, they are issued to counterparties to insure our payments for outstanding company debt, future abandonment liabilities and prior to June 30, 2011, crude purchases by our downstream business which we spun-off on that date.
The decline in the level of our outstanding letters of credit in 2011 is primarily related to the spin-off of our downstream business.
Legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and permitting delays.
The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers.
For additional information see Item 1A.
Risk Factors.
Our environmental expenditures(a) related to continuing operations for each of the last three years were:

<table><tr><td>Beginning of year</td><td>405</td></tr><tr><td>Revisions of previous estimates</td><td>15</td></tr><tr><td>Improved recovery</td><td>1</td></tr><tr><td>Purchases of reserves in place</td><td>91</td></tr><tr><td>Extensions, discoveries, and other additions</td><td>49</td></tr><tr><td>Transfer to Proved Developed</td><td>-166</td></tr><tr><td>End of year</td><td>395</td></tr></table>
<table><tr><td>Benchmark</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>WTI crude oil<i>(Dollars per bbl)</i></td><td>$95.11</td><td>$79.61</td><td>$62.09</td></tr><tr><td>Western Canadian Select<i>(Dollars per bbl)</i><sup>(a)</sup></td><td>77.97</td><td>65.31</td><td>52.13</td></tr><tr><td>AECO natural gas sales index<i>(Dollars per mmbtu)</i><sup>(b)</sup></td><td>$3.68</td><td>$3.89</td><td>$3.49</td></tr></table>
<table><tr><td><i>(In millions)</i></td><td>2011</td><td>2010</td></tr><tr><td>E&P</td><td>$13,029</td><td>$10,782</td></tr><tr><td>OSM</td><td>1,588</td><td>833</td></tr><tr><td>IG</td><td>93</td><td>150</td></tr><tr><td>Segment revenues</td><td>14,710</td><td>11,765</td></tr><tr><td>Elimination of intersegment revenues</td><td>-47</td><td>-75</td></tr><tr><td>Total revenues</td><td>$14,663</td><td>$11,690</td></tr></table>
<table><tr><td><i>(In millions)</i></td><td>Total</td><td>2012</td><td>2013-2014</td><td>2015-2016</td><td>LaterYears</td></tr><tr><td>Long-term debt (excludes interest)<sup>(a)</sup></td><td>$4,794</td><td>$141</td><td>$274</td><td>$69</td><td>$4,310</td></tr><tr><td>Lease obligations</td><td>275</td><td>64</td><td>69</td><td>53</td><td>89</td></tr><tr><td>Purchase obligations:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and gas activities<sup>(b)</sup></td><td>2,709</td><td>541</td><td>814</td><td>549</td><td>805</td></tr><tr><td>Service and materials contracts<sup>(c)</sup></td><td>1,044</td><td>169</td><td>198</td><td>129</td><td>548</td></tr><tr><td>Transportation and related contracts</td><td>1,303</td><td>322</td><td>174</td><td>129</td><td>678</td></tr><tr><td>Drilling rigs and fracturing crews</td><td>1,079</td><td>506</td><td>551</td><td>22</td><td></td></tr><tr><td>Other</td><td>276</td><td>108</td><td>85</td><td>28</td><td>55</td></tr><tr><td>Total purchase obligations</td><td>6,411</td><td>1,646</td><td>1,822</td><td>857</td><td>2,086</td></tr><tr><td>Other long-term liabilities reportedin the consolidated balancesheet<sup>(d)</sup></td><td>1,231</td><td>176</td><td>273</td><td>251</td><td>531</td></tr><tr><td>Total contractual cash obligations<sup>(e)</sup></td><td>$12,711</td><td>$2,027</td><td>$2,438</td><td>$1,230</td><td>$7,016</td></tr></table>

Question: how much has the western canadian select dollars per bbl increased since 2009?
Answer: 0.49568