Marathon maintains an equity compensation program for its non-employee directors under the Plan.
Pursuant to the program, non-employee directors must defer 50% of their annual retainers in the form of common stock units.
In addition, the program provides each non-employee director with a matching grant of up to 1,000 shares of common stock upon his or her initial election to the board if he or she purchases an equivalent number of shares within 60 days of joining the board.
Common stock units are book entry units equal in value to a share of stock.
During 2003, 15,799 shares of stock were issued; during 2002, 14,472 shares of stock were issued and during 2001, 12,358 shares of stock were issued.26.
Stockholder Rights Plan In 2002, the Marathon’s stockholder rights plan (the Rights Plan), was amended due to the Separation.
In January 2003, the expiration date of the Rights Plan was accelerated to January 31, 2003.27.
Leases Marathon leases a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, production facilities and transportation equipment.
Most long-term leases include renewal options and, in certain leases, purchase options.
Future minimum commitments for capital lease obligations (including sale-leasebacks accounted for as financings) and for operating lease obligations having remaining noncancelable lease terms in excess of one year are as follows:
## Table 0 ##
In connection with past sales of various plants and operations, Marathon assigned and the purchasers assumed certain leases of major equipment used in the divested plants and operations of United States Steel.
In the event of a default by any of the purchasers, United States Steel has assumed these obligations; however, Marathon remains primarily obligated for payments under these leases.
Minimum lease payments under these operating lease obligations of $54 million have been included above and an equal amount has been reported as sublease rentals.
Of the $181 million present value of net minimum capital lease payments, $135 million was related to obligations assumed by United States Steel under the Financial Matters Agreement.
Of the $378 million total minimum operating lease payments, $18 million was assumed by United States Steel under the Financial Matters Agreement.
During 2003, Marathon purchased two LNG tankers to transport LNG primarily from Kenai, Alaska to Tokyo, Japan which were previously leased.
A $17 million charge was recorded on the termination of the two tanker operating leases.
Operating lease rental expense was:
## Table 1 ##
(a) Excludes $23 million and $24 million paid by United States Steel in 2003 and 2002 on assumed leases.
The above discussion contains forward-looking statements with regard to the Jackpine mine expansion and Quest CCS.
Some factors that could affect the Jackpine mine expansion include the inability to obtain or delay in obtaining third-party approvals and permits.
The Quest CCS is subject to the inability to obtain or delay in obtaining government funds, the availability of materials and labor, unforeseen hazards such as weather conditions and other risks customarily associated with these types of projects.
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 difficult to predict.
The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Reserves Estimated Reserve Quantities The following table sets forth estimated quantities of our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2013, 2012 and 2011.
Included in our liquid hydrocarbon reserves are NGLs which represent approximately 7 percent, 6 percent and 5 percent of our total proved reserves on an oil equivalent barrel basis as of December 2013, 2012 and 2011.
Approximately 72 percent, 63 percent and 40 percent of those NGL reserves are associated with our U. S.  unconventional resource plays as of December 31, 2013, 2012 and 2011.
Reserves are disclosed by continent and by country if the proved reserves related to any geographic area, on an oil equivalent barrel basis, represent 15 percent or more of our total proved reserves.
A geographic area can be an individual country, group of countries within a continent, or a continent.
Due to the agreements entered in 2013 to sell our Angola assets, estimated proved reserves for Angola are reported as discontinued operations ("Disc Ops") for all presented periods.
Approximately 73 percent of our December 31, 2013 proved reserves are located in OECD countries.
## Table 2 ##
discount to Brent was narrower in 2013 than in 2012 and 2011.
As a result of the significant increase in U. S.  production of light sweet crude oil, the historical relationship between WTI, Brent and LLS pricing may not be indicative of future periods.
Composition – The proportion of our liquid hydrocarbon sales volumes that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays.
NGLs were 15 percent of our North America E&P liquid hydrocarbon sales volumes in 2013 compared to 10 percent in 2012 and 7 percent in 2011.
Natural gas – A significant portion of our natural gas production in the U. S.  is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.
Average Henry Hub settlement prices for natural gas were 31 percent higher for 2013 than for 2012.  International E&P Liquid hydrocarbons – Our International E&P crude oil production is relatively sweet and has historically sold in relation to the Brent crude benchmark, which on average was 3 percent lower for 2013 than 2012.
Natural gas – Our major International E&P natural gas-producing regions are Europe and E. G.  Natural gas prices in Europe have been considerably higher than the U. S.  in recent years.
In the case of E. G. , our natural gas sales are subject to term contracts, making realized prices in these areas less volatile.
The natural gas sales from E. G.  are at fixed prices; therefore, our reported average International E&P natural gas realized prices may not fully track market price movements.
Oil Sands Mining The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil.
Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader.
Sales prices for roughly two-thirds of the normal output mix has historically tracked movements in WTI and one-third has historically tracked movements in the Canadian heavy crude oil marker, primarily WCS.
The WCS discount to WTI has been increasing on average in each year presented below.
Despite a wider WCS discount in 2013, our average Oil Sands Mining price realizations increased due to a greater proportion of higher value synthetic crude oil sales volumes compared to 2012.
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 AECO natural gas sales index and crude oil prices, respectively.
The table below shows average benchmark prices that impact both our revenues and variable costs:
## Table 3 ##
Provision for income taxes increased $1,791 million in 2012 from 2011 primarily due to the increase in pretax income from continuing operations, including the impact of the resumption of sales in Libya in the first quarter of 2012.
The following is an analysis of the effective income tax rates for 2012 and 2011:
## Table 4 ##
The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income.
The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments.
The difference between the total provision and the sum of the amounts allocated to segments appears in the "Corporate and other unallocated items" shown in the reconciliation of segment income to net income below.
Effects of foreign operations – The effects of foreign operations on our effective tax rate increased in 2012 as compared to 2011, primarily due to the resumption of sales in Libya in the first quarter of 2012, where the statutory rate is in excess of 90 percent.
Change in permanent reinvestment assertion – In the second quarter of 2011, we recorded $716 million of deferred U. S.  tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations.
Offsetting this tax expense were associated foreign tax credits of $488 million.
In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U. S.  tax on previously undistributed earnings.
Adjustments to valuation allowances – In 2012 and 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U. S.  benefits on foreign taxes accrued in those years.
See Item 8.
Financial Statements and Supplementary Data - Note 10 to the consolidated financial statements for further information about income taxes.
Discontinued operations is presented net of tax, and reflects our downstream business that was spun off June 30, 2011 and our Angola business which we agreed to sell in 2013.
See Item 8.
Financial Statements and Supplementary Data – Notes 3 and 6 to the consolidated financial statements for additional information.

<table><tr><td> <i>(In millions)</i> </td><td> Capital  Lease  Obligations </td><td>Operating Lease Obligations</td></tr><tr><td>2004</td><td>$29</td><td>$108</td></tr><tr><td>2005</td><td>20</td><td>80</td></tr><tr><td>2006</td><td>26</td><td>67</td></tr><tr><td>2007</td><td>34</td><td>38</td></tr><tr><td>2008</td><td>26</td><td>31</td></tr><tr><td>Later years</td><td>127</td><td>131</td></tr><tr><td>Sublease rentals</td><td>–</td><td>-77</td></tr><tr><td>Total minimum lease payments</td><td>262</td><td>$378</td></tr><tr><td>Less imputed interest costs</td><td>81</td><td></td></tr><tr><td>Present value of net minimum lease payments included in long-term debt</td><td>$181</td><td></td></tr></table>
<table><tr><td> <i>(In millions)</i> </td><td rowspan="2">2003 $182(a)</td><td rowspan="2">2002 $196(a)</td><td rowspan="2">2001 $159</td></tr><tr><td>Minimum rental</td></tr><tr><td>Contingent rental</td><td>15</td><td>13</td><td>13</td></tr><tr><td>Sublease rentals</td><td>-9</td><td>-11</td><td>-11</td></tr><tr><td>Net rental expense</td><td>$188</td><td>$198</td><td>$161</td></tr></table>
<table><tr><td></td><td colspan="3">North America</td><td colspan="3">Africa</td><td rowspan="2">Europe Total</td><td></td><td></td></tr><tr><td>December 31, 2013</td><td>U.S.</td><td>Canada</td><td>Total</td><td>E.G.</td><td>Other</td><td>Total</td><td>Disc Ops<sup></sup></td><td>GrandTotal</td></tr><tr><td>Proved Developed Reserves</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquid hydrocarbons(mmbbl)</td><td>292</td><td>—</td><td>292</td><td>55</td><td>176</td><td>231</td><td>78</td><td>19</td><td>620</td></tr><tr><td>Natural gas(bcf)</td><td>540</td><td>—</td><td>540</td><td>823</td><td>95</td><td>918</td><td>41</td><td>—</td><td>1,499</td></tr><tr><td>Synthetic crude oil(mmbbl)</td><td>—</td><td>674</td><td>674</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>674</td></tr><tr><td>Total proved developed reserves(mmboe)</td><td>382</td><td>674</td><td>1,056</td><td>193</td><td>192</td><td>385</td><td>84</td><td>19</td><td>1,544</td></tr><tr><td>Proved Undeveloped Reserves</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquid hydrocarbons(mmbbl)</td><td>324</td><td>—</td><td>324</td><td>43</td><td>39</td><td>82</td><td>11</td><td>9</td><td>426</td></tr><tr><td>Natural gas(bcf)</td><td>485</td><td>—</td><td>485</td><td>497</td><td>110</td><td>607</td><td>80</td><td>—</td><td>1,172</td></tr><tr><td>Synthetic crude oil(mmbbl)</td><td>—</td><td>6</td><td>6</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Total proved undeveloped reserves(mmboe)</td><td>405</td><td>6</td><td>411</td><td>125</td><td>57</td><td>182</td><td>25</td><td>9</td><td>627</td></tr><tr><td>Total Proved Reserves</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquid hydrocarbons(mmbbl)</td><td>616</td><td>—</td><td>616</td><td>98</td><td>215</td><td>313</td><td>89</td><td>28</td><td>1,046</td></tr><tr><td>Natural gas(bcf)</td><td>1,025</td><td>—</td><td>1,025</td><td>1,320</td><td>205</td><td>1,525</td><td>121</td><td>—</td><td>2,671</td></tr><tr><td>Synthetic crude oil(mmbbl)</td><td>—</td><td>680</td><td>680</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>680</td></tr><tr><td>Total proved reserves(mmboe)</td><td>787</td><td>680</td><td>1,467</td><td>318</td><td>249</td><td>567</td><td>109</td><td>28</td><td>2,171</td></tr></table>
<table><tr><td>Benchmark</td><td>2013</td><td>2012</td><td>2011</td></tr><tr><td>WTI crude oil(Dollars per bbl)</td><td>$98.05</td><td>$94.15</td><td>$95.11</td></tr><tr><td>WCS(Dollars per bbl)<sup>(a)</sup></td><td>$72.77</td><td>$73.18</td><td>$77.97</td></tr><tr><td>AECO natural gas sales index(Dollars per mmbtu)<sup>(b)</sup></td><td>$3.08</td><td>$2.39</td><td>$3.68</td></tr></table>
<table><tr><td></td><td>2012</td><td>2011</td></tr><tr><td>Statutory rate applied to income from continuing operations before income taxes</td><td>35%</td><td>35%</td></tr><tr><td>Effects of foreign operations, including foreign tax credits</td><td>18</td><td>6</td></tr><tr><td>Change in permanent reinvestment assertion</td><td>—</td><td>5</td></tr><tr><td>Adjustments to valuation allowances</td><td>21</td><td>14</td></tr><tr><td>Tax law changes</td><td>—</td><td>1</td></tr><tr><td>Effective income tax rate on continuing operations</td><td>74%</td><td>61%</td></tr></table>

Question: by what percentage did adjustments to valuation allowances increase from 2011 to 2012>
Answer: 0.5