Cash-Adjusted Debt-To-Capital Ratio Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 20 percent and 14 percent at December 31, 2011 and 2010.
## Table 0 ##
Capital Requirements Capital Spending Our approved capital, investment and exploration budget for 2012 is $4,822 million.
Additional details related to the 2012 budget are discussed in Outlook.
Other Expected Cash Outflows We plan to make contributions of up to $113 million to our pension plans during 2012.
As of December 31, 2011, $141 million of our long-term debt is due in the next twelve months.
Dividends of $0.80 per common share or $567 million were paid during 2011 reflecting quarterly dividends of $0.25 per share in the first two quarters and $0.15 per share in the two quarters after the spin-off of our downstream business.
On January 27, 2012, we announced that our Board of Directors had declared a dividend of $0.17 cents per share on Marathon Oil common stock, payable March 12, 2012, to stockholders of record at the close of business on February 16, 2012.
This is a 13 percent increase over the dividend paid in the preceding quarter.
Share Repurchase Program Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion.
As of December 31, 2011, we had repurchased 78 million common shares at a cost of $3,222 million, with 66 million shares purchased for $2,922 million prior to the spin-off of our downstream business and 12 million shares acquired at a cost of $300 million in the third quarter of 2011.
Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions.
This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.
The program’s authorization does not include specific price targets or timetables.
The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information.
If this information proves to be inaccurate, future availability of financing may be adversely affected.
Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.
The discussion of liquidity above also contains forward-looking statements regarding expected capital, investment and exploration spending and planned funding of our pension plans.
The forward-looking statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance.
The forward-looking statements about our common share repurchase program are
## Table 1 ##
Preparation of Reserve Estimates All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X.
Crude oil and condensate, NGLs, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and his staff of Reserve Coordinators.
Crude oil and condensate, NGLs and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs").
QREs are engineers or geoscientists who hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed Marathon Oil's QRE training course.
All QREs must complete a QRE refresher course at least once every three years.
Our Corporate Reserves group screens all fields with net proved reserves of 20 mmboe or greater, every year, to determine if a field review is required.
Any change to proved reserve estimates in excess of 1 mmboe on a total field basis, within a single month, must be approved by a Reserve Coordinator.
Our Director of Corporate Reserves, who reports to our Vice President, Technology and Innovation, has a Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in the State of Texas.
In his 28 years with Marathon Oil, he has held numerous engineering and management positions, including managing our OSM segment.
He is a member of the Society of Petroleum Engineers ("SPE") and a former member of the Petroleum Engineering Advisory Council for the University of Texas at Austin.
Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Alberta, Canada, third-party consultants.
Their reports for all years are filed as exhibits to this Annual Report on Form 10-K.
The individual responsible for the estimates of our synthetic crude oil reserves has 15 years of experience in petroleum engineering, has conducted surface mineable oil sands evaluations since 2009 and is a registered Practicing Professional Engineer in the Province of Alberta.
Audits of Estimates We engage third-party consultants to provide, at a minimum, independent estimates for fields that comprise 80% of our total proved reserves over a rolling four-year period.
We exceeded this percentage for the four-year period ended December 31, 2015, with 82% of our total proved reserves independently audited.
We have established a tolerance level of +/- 10% such that initial estimates by the third-party consultants for each field are accepted if they are within 10% of our internal estimates.
Should the third-party consultants’ initial analysis fail to reach our tolerance level, both parties re-examine the information provided, request additional data and refine their analysis, if appropriate.
In the very limited instances where differences outside the 10% tolerance cannot be resolved by year end, a plan to resolve the difference is developed and executive management consent is obtained.
The audit process did not result in any significant changes to our reserve estimates for 2015, 2014 or 2013.
Outlook Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business.
Commodity prices began declining in the second half of 2014 and continued through 2015 and into 2016.
We believe we can manage in this lower commodity price cycle through operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, while continuing to focus on balance sheet protection.
Capital ProgramOur Board of Directors approved a Capital Program of $1.4 billion for 2016.
We intend to be flexible with respect to our capital allocation decisions in light of this challenged commodity pricing environment.
With that in mind, we have engaged in an active program to divest of non-core assets, which together with our anticipated cash flows from operations, plus the savings embedded from the cost reductions we have put in place, should allow us to meet our current Capital Program, operating costs, debt service and dividends.
The discipline undertaken as part of a real-time evaluation of our revenues, expenditures, and asset dispositions should allow us to live within our means.
Our Capital Program is broken down by reportable segment in the table below:
## Table 2 ##
North America E&P – Approximately $1.2 billion of our Capital Program is allocated to our three core U. S.  resource plays.
Eagle Ford - Approximately $600 million is planned, we expect to average five rigs and bring 124-132 gross-operated wells to sales.
Included in Eagle Ford spending is approximately $520 million for drilling and completions.
The 2016 drilling program will continue to focus on the co-development of the Lower and Upper Eagle Ford horizons as well as Austin Chalk in the core of the play.
Oklahoma Resource Basins - Spending of approximately $200 million is targeted, we expect to average two rigs which will focus primarily on lease retention in the STACK and delineation of the Meramec, and bring 20-22 gross-operated wells to sales.
Spending includes approximately $195 million for drilling and completions, including $55 million for outside-operated activity.
We expect to be approximately 70% held by production in the STACK by year end, with SCOOP already 90% held by production.
Bakken - We plan to spend just under $200 million in North Dakota.
Drilling activity will average one rig for half of 2016 and bring online 13-15 gross-operated wells.
Bakken spending includes approximately $150 million for drilling and completions, including $75 million for outside-operated activity.
Facilities and infrastructure spending will be significantly lower than 2015 with the next phase of the water-gathering system scheduled to be complete in the second half of 2016. International E&P – Approximately $170 million of our Capital Program is dedicated to our international assets, primarily in E. G.  and the Kurdistan Region of Iraq.
The Alba field compression project in E. G.  remains on schedule to start up by midyear, and will extend plateau production by two years as well as the asset’s life by up to eight years.
Approximately $30 million of our Capital Program will be spent on a targeted exploration program impacting both the North America E&P and the International E&P segments.
Activity in 2016 is limited to fulfilling existing commitments in the Gulf of Mexico and Gabon, with no operated exploration wells planned.
Oil Sands Mining – We expect to spend $40 million of the Capital Program for sustaining capital projects.
The remainder of our Capital Program consists of Corporate and Other and is expected to total approximately $40 million.
For information about expected exploration and development activities more specific to individual assets, see Item 1.  Business.
Production Volumes  We forecast 2016 production available for sale from the combined North America E&P and International E&P segments, excluding Libya, to average 335 to 355 net mboed and the OSM segment to average 40 to 50 net mbbld of synthetic crude oil.

<table><tr><td><i>(Dollars in millions)</i></td><td>2011</td><td>2010</td></tr><tr><td>Long-term debt due within one year</td><td>$141</td><td>$295</td></tr><tr><td>Long-term debt</td><td>4,674</td><td>7,601</td></tr><tr><td>Total debt</td><td>$4,815</td><td>$7,896</td></tr><tr><td>Cash</td><td>$493</td><td>$3,951</td></tr><tr><td>Equity</td><td>$17,159</td><td>$23,771</td></tr><tr><td>Calculation:</td><td></td><td></td></tr><tr><td>Total debt</td><td>$4,815</td><td>$7,896</td></tr><tr><td>Minus cash</td><td>493</td><td>3,951</td></tr><tr><td>Total debt minus cash</td><td>4,322</td><td>3,945</td></tr><tr><td>Total debt</td><td>4,815</td><td>7,896</td></tr><tr><td>Plus equity</td><td>17,159</td><td>23,771</td></tr><tr><td>Minus cash</td><td>493</td><td>3,951</td></tr><tr><td>Total debt plus equity minus cash</td><td>$21,481</td><td>$27,716</td></tr><tr><td>Cash-adjusted debt-to-capital ratio</td><td>20%</td><td>14%</td></tr></table>
<table><tr><td></td><td colspan="3">North America</td><td colspan="3">Africa</td><td></td><td></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>Other Int'l</td><td>Cont Ops</td><td>Disc Ops</td><td>Total</td></tr><tr><td colspan="4">Proved Developed Reserves</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil and condensate(mmbbl)</td><td>241</td><td>—</td><td>241</td><td>37</td><td>176</td><td>213</td><td>19</td><td>473</td><td>77</td><td>550</td></tr><tr><td>Natural gas liquids(mmbbl)</td><td>51</td><td>—</td><td>51</td><td>18</td><td>—</td><td>18</td><td>1</td><td>70</td><td>—</td><td>70</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>21</td><td>1,479</td><td>20</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>674</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>23</td><td>1,464</td><td>80</td><td>1,544</td></tr><tr><td colspan="4">Proved Undeveloped Reserves</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil and condensate(mmbbl)</td><td>256</td><td>—</td><td>256</td><td>27</td><td>39</td><td>66</td><td>6</td><td>328</td><td>14</td><td>342</td></tr><tr><td>Natural gas liquids(mmbbl)</td><td>68</td><td>—</td><td>68</td><td>16</td><td>—</td><td>16</td><td>—</td><td>84</td><td>—</td><td>84</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>7</td><td>1,099</td><td>73</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>6</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>8</td><td>601</td><td>26</td><td>627</td></tr><tr><td colspan="4">Total Proved Reserves</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil and condensate(mmbbl)</td><td>497</td><td>—</td><td>497</td><td>64</td><td>215</td><td>279</td><td>25</td><td>801</td><td>91</td><td>892</td></tr><tr><td>Natural gas liquids(mmbbl)</td><td>119</td><td>—</td><td>119</td><td>34</td><td>—</td><td>34</td><td>1</td><td>154</td><td>—</td><td>154</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>28</td><td>2,578</td><td>93</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>680</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>31</td><td>2,065</td><td>106</td><td>2,171</td></tr></table>
<table><tr><td>(In millions)</td><td>2016 Capital Program</td><td>Percent of Total</td></tr><tr><td>North America E&P</td><td>$1,166</td><td>81%</td></tr><tr><td>International E&P</td><td>185</td><td>13%</td></tr><tr><td>Oil Sands Mining</td><td>41</td><td>3%</td></tr><tr><td>Segment total</td><td>1,392</td><td>97%</td></tr><tr><td>Corporate and other</td><td>40</td><td>3%</td></tr><tr><td>Total Capital Program</td><td>$1,432</td><td>100%</td></tr></table>

Question: In the section with lowest amount of Total proved developed reserves(mmboe), what's the increasing rate of Natural gas(bcf)?
Answer: 2.28571