Average Production Cost per Unit(a)
## Table 0 ##
(a) Production, severance and property taxes are excluded; however, shipping and handling as well as other operating expenses are included in the production costs used in this calculation.
See Item 8.
Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production costs.
N. M.  Not meaningful information due to limited sales in 2014.
Marketing and Midstream Our operating segments include activities related to the marketing and transportation of substantially all of our liquid hydrocarbon, synthetic crude oil and natural gas production.
These activities include the transportation of production to market centers, the sale of commodities to third parties and the storage of production.
We balance our various sales, storage and transportation positions in order to aggregate volumes to satisfy transportation commitments and to achieve flexibility within product types and delivery points.
Such activities can include the purchase of commodities from third parties for resale.
As discussed previously, we currently own and operate gathering systems and other midstream assets in some of our production areas.
We continue to evaluate midstream infrastructure investments in connection with our development plans.
Delivery Commitments We have committed to deliver quantities of crude oil and synthetic crude oil to customers under a variety of contracts.
As of December 31, 2014, those contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to liquid hydrocarbon production in the Eagle Ford and Bakken, and OSM synthetic crude oil production.
Eagle Ford liquid hydrocarbon production sales commitments range from a minimum of 76 mbbld increasing to 113 mbbld in 2015 through 2018 and 51 mbbld to 65 mbbld in 2019 through 2020.
Bakken liquid hydrocarbon production sales commitments of 10 mbbld commence in the fourth quarter of 2016 and expire June 1, 2026.
Synthetic crude oil production sales commitments fall under a 3-year agreement for 13.5 mbbld which expires July 2017.
Our current production rates, forecasts and proved reserves are sufficient to meet these commitments.
All of these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate.
In addition to the sales contracts discussed above, we have entered into numerous agreements for transportation and processing of our equity production.
Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms.
Competition and Market Conditions Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves.
We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties.
Based upon statistics compiled in the "2014 Global Upstream Performance Review" published by IHS Inc. , we rank tenth among U. S. -based petroleum companies on the basis of 2013 worldwide liquid hydrocarbon and natural gas production.
See Item 1A.
Risk Factors for discussion of specific areas in which we compete and related risks.
We also compete with other producers of synthetic crude oil for the sale of our synthetic crude oil to refineries primarily in North America.
Additional synthetic crude oil projects are being contemplated by various competitors and, if undertaken and completed, may result in a significant increase in the supply of synthetic crude oil to the market.
Because not all refineries are able to process or refine synthetic crude oil in significant volumes, sufficient market demand may not exist at all times to absorb our share of the synthetic crude oil production from the AOSP at economically viable prices.
Our operating results are affected by price changes for liquid hydrocarbons and natural gas, as well as changes in competitive conditions in the markets we serve.
Generally, results from oil and gas production and OSM operations benefit from higher liquid hydrocarbons and natural gas prices.
Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations.
See Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Overview – Market Conditions for additional discussion of the impact of prices on our operations.
Supplementary Information on Oil and Gas Producing Activities (Unaudited) 116 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves U. S.  GAAP prescribes guidelines for computing the standardized measure of future net cash flows and changes therein relating to estimated proved reserves, giving very specific assumptions to be made such as the use of a 10% discount rate and an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month.
These and other required assumptions have not always proved accurate in the past, and other valid assumptions would give rise to substantially different results.
This information is not the fair value nor does it represent the expected present value of future cash flows of our crude oil and condensate, natural gas liquid, natural gas and synthetic crude oil reserves.
## Table 1 ##
(a) Future cash flows for Other International reflects the impact of future abandonment costs related to the U. K.
During 2015, 2014 and 2013, Netherland, Sewell & Associates, Inc.  ("NSAI") prepared a certification of the prior year's reserves for the Alba field in E. G.  The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K.  Members of the NSAI team have multiple years of industry experience, having worked for large, international oil and gas companies before joining NSAI.
The senior technical advisor has over 35 years of practical experience in petroleum geosciences, with over 15 years experience in the estimation and evaluation of reserves.
The second team member has over 10 years of practical experience in petroleum engineering, with over five years experience in the estimation and evaluation of reserves.
Both are registered Professional Engineers in the State of Texas.
Ryder Scott Company ("Ryder Scott") also performed audits of the prior years' reserves of several of our fields in 2015, 2014 and 2013.
Their summary reports are filed as exhibits 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 is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional Engineer in the State of Texas.
Changes in Proved Undeveloped Reserves As of December 31, 2015, 603 mmboe of proved undeveloped reserves were reported, a decrease of 125 mmboe from December 31, 2014.
The following table shows changes in total proved undeveloped reserves for 2015:
## Table 2 ##
The revisions to previous estimates were largely due to a result of reductions to our capital development program which deferred proved undeveloped reserves beyond the 5-year plan.
A total of 139 mmboe was booked as extensions, discoveries or other additions and revisions due to the application of reliable technology.
Technologies included statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, reservoir simulation and volumetric analysis.
The observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves.
Transfers from proved undeveloped to proved developed reserves included 47 mmboe in the Eagle Ford, 14 mmboe in the Bakken and 5 mmboe in the Oklahoma Resource Basins due to development drilling and completions.
Costs incurred in 2015, 2014 and 2013 relating to the development of proved undeveloped reserves were $1,415 million, $3,149 million and $2,536 million.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as large development projects which take more than five years to complete, or the timing of when additional gas compression is needed.
Of the 603 mmboe of proved undeveloped reserves at December 31, 2015, 26% 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 E. G.  that was sanctioned by our Board of Directors in 2004.
During 2012, the compression project received the approval of the E. G.  government, fabrication of the new platform began in 2013 and installation of the platform at the Alba Field occurred in January 2016.
Commissioning is currently underway, with first production expected by mid-2016.
Proved undeveloped reserves for the North Gialo development, located in the Libyan Sahara desert, were booked for the first time in 2010.
This development is being executed by the operator and encompasses a multi-year drilling program including the design, fabrication and installation of extensive liquid handling and gas recycling facilities.
Anecdotal evidence from similar development projects in the region leads to an expected project execution time frame of more than five years from the time the reserves were initially booked.
Interruptions associated with the civil and political unrest have also extended the project duration.
Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in through early 2016.
The operator is committed to the project’s completion and continues to assign resources in order to execute the project.
Our conversion rate for proved undeveloped reserves to proved developed reserves for 2015 was 11%.
However, excluding the aforementioned long-term projects in E. G.  and Libya, our 2015 conversion rate would be 15%.
Furthermore, our

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td colspan="3">North America</td><td colspan="3">Africa</td><td></td><td></td><td></td></tr><tr><td>(Dollars per boe)</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>Disc Ops</td><td>Total</td></tr><tr><td>2014</td><td>$13.34</td><td>$46.63</td><td>$18.73</td><td>$4.03</td><td>N.M.</td><td>$5.72</td><td>$47.06</td><td>$8.92</td><td>$15.37</td></tr><tr><td>2013</td><td>13.60</td><td>55.42</td><td>20.79</td><td>2.88</td><td>7.40</td><td>3.80</td><td>38.87</td><td>8.24</td><td>14.51</td></tr><tr><td>2012</td><td>13.61</td><td>53.61</td><td>21.51</td><td>3.59</td><td>3.57</td><td>3.59</td><td>28.33</td><td>5.55</td><td>12.98</td></tr></table>
<table><tr><td>(In millions)</td><td>U.S.</td><td>Canada</td><td>E.G.</td><td>OtherAfrica</td><td>Other Int'l</td><td></td><td>Total</td></tr><tr><td>Year Ended December 31, 2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$31,026</td><td>$31,087</td><td>$2,671</td><td>$12,157</td><td>$1,281</td><td></td><td>$78,222</td></tr><tr><td>Future production and support costs</td><td>-12,270</td><td>-27,459</td><td>-1,095</td><td>-901</td><td>-902</td><td></td><td>-42,627</td></tr><tr><td>Future development costs</td><td>-6,637</td><td>-2,929</td><td>-94</td><td>-689</td><td>-1,537</td><td></td><td>-11,886</td></tr><tr><td>Future income tax expenses</td><td>-778</td><td>—</td><td>-369</td><td>-9,857</td><td>602</td><td></td><td>-10,402</td></tr><tr><td>Future net cash flows</td><td>$11,341</td><td>$699</td><td>$1,113</td><td>$710</td><td>$-556</td><td><sup>(a)</sup></td><td>$13,307</td></tr><tr><td>10% annual discount for timing of cash flows</td><td>-6,082</td><td>-534</td><td>-380</td><td>-441</td><td>352</td><td></td><td>-7,085</td></tr><tr><td colspan="8">Standardized measure of discounted future net cash flows-</td></tr><tr><td>-related to continuing operations</td><td>$5,259</td><td>$165</td><td>$733</td><td>$269</td><td>$-204</td><td></td><td>$6,222</td></tr><tr><td>-related to discontinued operations</td><td>$—</td><td>$—</td><td>$—</td><td>$—</td><td>—</td><td></td><td>—</td></tr><tr><td>Year Ended December 31, 2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$66,307</td><td>$55,675</td><td>$5,027</td><td>$23,803</td><td>$3,040</td><td></td><td>$153,852</td></tr><tr><td>Future production and support costs</td><td>-19,504</td><td>-34,838</td><td>-1,270</td><td>-803</td><td>-1,452</td><td></td><td>-57,867</td></tr><tr><td>Future development costs</td><td>-14,626</td><td>-9,754</td><td>-259</td><td>-680</td><td>-1,669</td><td></td><td>-26,988</td></tr><tr><td>Future income tax expenses</td><td>-8,124</td><td>-2,190</td><td>-922</td><td>-21,008</td><td>-9</td><td></td><td>-32,253</td></tr><tr><td>Future net cash flows</td><td>$24,053</td><td>$8,893</td><td>$2,576</td><td>$1,312</td><td>$-90</td><td></td><td>$36,744</td></tr><tr><td>10% annual discount for timing of cash flows</td><td>-12,138</td><td>-6,613</td><td>-915</td><td>-742</td><td>221</td><td></td><td>-20,187</td></tr><tr><td colspan="8">Standardized measure of discounted future net cash flows-</td></tr><tr><td>-related to continuing operations</td><td>$11,915</td><td>$2,280</td><td>$1,661</td><td>$570</td><td>$131</td><td></td><td>$16,557</td></tr><tr><td>-related to discontinued operations</td><td>$—</td><td>$—</td><td>$—</td><td>$—</td><td>$—</td><td></td><td>$—</td></tr><tr><td>Year Ended December 31, 2013</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$54,099</td><td>$59,585</td><td>$5,911</td><td>$28,195</td><td>$3,178</td><td></td><td>$150,968</td></tr><tr><td>Future production and support costs</td><td>-16,774</td><td>-35,954</td><td>-1,619</td><td>-976</td><td>-1,191</td><td></td><td>-56,514</td></tr><tr><td>Future development costs</td><td>-9,685</td><td>-9,694</td><td>-367</td><td>-793</td><td>-1,302</td><td></td><td>-21,841</td></tr><tr><td>Future income tax expenses</td><td>-7,592</td><td>-3,098</td><td>-1,032</td><td>-24,982</td><td>-643</td><td></td><td>-37,347</td></tr><tr><td>Future net cash flows</td><td>$20,048</td><td>$10,839</td><td>$2,893</td><td>$1,444</td><td>$42</td><td></td><td>$35,266</td></tr><tr><td>10% annual discount for timing of cash flows</td><td>-9,940</td><td>-8,300</td><td>-1,084</td><td>-828</td><td>128</td><td></td><td>-20,024</td></tr><tr><td colspan="8">Standardized measure of discounted future net cash flows-</td></tr><tr><td>-related to continuing operations</td><td>$10,108</td><td>$2,539</td><td>$1,809</td><td>$616</td><td>$170</td><td></td><td>$15,242</td></tr><tr><td>-related to discontinued operations</td><td>$—</td><td>$—</td><td>$—</td><td>$1,302</td><td>$1,228</td><td></td><td>$2,530</td></tr></table>
<table><tr><td>Beginning of year</td><td>728</td></tr><tr><td>Revisions of previous estimates</td><td>-223</td></tr><tr><td>Improved recovery</td><td>1</td></tr><tr><td>Purchases of reserves in place</td><td>1</td></tr><tr><td>Extensions, discoveries, and other additions</td><td>175</td></tr><tr><td>Dispositions</td><td>—</td></tr><tr><td>Transfers to proved developed</td><td>-79</td></tr><tr><td>End of year</td><td>603</td></tr></table>

Question: how many of the year end 2015 proved undeveloped reserves were converted to proved developed reserves?
Answer: 66.33
Reasoning program: multiply(603,11%)