Table of Contents as of September 28, 2013.
The Company’s share repurchase program does not obligate it to acquire any specific number of shares.
Under the program, shares may be repurchased in privately negotiated and/or open market transactions, including under plans complying with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
In August 2012, the Company entered into an accelerated share repurchase arrangement (“ASR”) with a financial institution to purchase up to $1.95 billion of the Company’s common stock in 2013.
In the first quarter of 2013, 2.6 million shares were initially delivered to the Company.
In April 2013, the purchase period for the ASR ended and an additional 1.5 million shares were delivered to the Company.
In total, 4.1 million shares were delivered under the ASR at an average repurchase price of $478.20 per share.
The shares were retired in the quarters they were delivered, and the up-front payment of $1.95 billion was accounted for as a reduction to shareholders’ equity in the Company’s Consolidated Balance Sheet in the first quarter of 2013.
In April 2013, the Company entered into a new ASR program with two financial institutions to purchase up to $12 billion of the Company’s common stock.
In exchange for up-front payments totaling $12 billion, the financial institutions committed to deliver shares during the ASR’s purchase periods, which will end during 2014.
The total number of shares ultimately delivered, and therefore the average price paid per share, will be determined at the end of the applicable purchase period based on the volume weighted average price of the Company’s stock during that period.
During the third quarter of 2013, 23.5 million shares were initially delivered to the Company and retired.
This does not represent the final number of shares to be delivered under the ASR.
The up-front payments of $12 billion were accounted for as a reduction to shareholders’ equity in the Company’s Consolidated Balance Sheet.
The Company reflected the ASRs as a repurchase of common stock for purposes of calculating earnings per share and as forward contracts indexed to its own common stock.
The forward contracts met all of the applicable criteria for equity classification, and, therefore, were not accounted for as derivative instruments.
During 2013, the Company repurchased 19.4 million shares of its common stock in the open market at an average price of $464.11 per share for a total of $9.0 billion.
These shares were retired upon repurchase.
Note 8 – Comprehensive Income Comprehensive income consists of two components, net income and other comprehensive income.
Other comprehensive income refers to revenue, expenses, and gains and losses that under GAAP are recorded as an element of shareholders’ equity but are excluded from net income.
The Company’s other comprehensive income consists of foreign currency translation adjustments from those subsidiaries not using the U. S.  dollar as their functional currency, net deferred gains and losses on certain derivative instruments accounted for as cash flow hedges, and unrealized gains and losses on marketable securities classified as available-for-sale.
The following table shows the components of AOCI, net of taxes, as of September 28, 2013 and September 29, 2012 (in millions):
## Table 0 ##
North America E&P--Exploration In September 2015, we announced our intention to scale back our conventional exploration program.
Our 2016 Capital Program includes $15 million for conventional exploration.
No conventional exploration wells are planned in 2016.
Our Capital Program is limited to existing commitments in the Gulf of Mexico.
We continue to evaluate options for utilization of our remaining commitments on the Maersk Valiant drillship.
The rig is currently being operated by our rig share partner, and we anticipate the rig to be available for our use in early 2017.
The Solomon exploration prospect located on Walker Ridge Block 225 was spud during the second quarter of 2015 and reached total depth in the fourth quarter.
The well did encounter the lower tertiary target interval.
The well was plugged and abandoned, with well costs charged to dry well expense, and the rig was released with no further activity planned on the block.
We hold a 58% operated working interest in this prospect.
We hold interests in both operated and non-operated exploration stage oil sand leases in Alberta, Canada, which could be developed using in-situ methods of extraction.
These leases cover approximately 142,000 gross (54,000 net) acres in four project areas: Namur, in which we hold a 70% operated interest; Birchwood, in which we hold a 100% operated interest; Ells River, in which we hold a 20% non-operated interest; and Saleski in which we hold a 33% non-operated interest.
During 2015, in connection with our decision to scale back our conventional exploration program, and also after further evaluation of the estimated recoverable resources and our development plans at Birchwood, Ells River and Namur, we impaired the remaining net book values of these in-situ properties.
International E&P Segment We are engaged in oil and gas exploration, development and/or production activities in E. G. , Gabon, the Kurdistan Region of Iraq, Libya and the U. K.  We include the results of our natural gas liquefaction operations and methanol production operations in E. G.  in our International E&P segment.
The following table provides net sales volumes for our significant operational areas within this segment:
## Table 1 ##
(a) Includes natural gas acquired for injection and subsequent resale of 8 mmcfd, 6 mmcfd and 7 mmcfd for 2015, 2014, and 2013.
Africa Equatorial Guinea – Production – We own a 63% operated working interest under a PSC in the Alba field which is offshore E. G.  Operational availability from our company-operated facilities averaged approximately 97% in 2015.
In the third quarter of 2015, production was increased as the Alba C21 development well came online with higher than expected liquid yields, in combination with a successful well intervention program on five existing Alba wells.
In January 2016, we completed the installation of an offshore compression platform which is expected to start up mid-2016 following completion of hookup and commissioning activities.
The compression project was designed to maintain the production plateau two additional years and extend field life up to eight years.
Equatorial Guinea – Gas Processing – We own a 52% interest in Alba Plant LLC, an equity method investee, that operates an onshore LPG processing plant located on Bioko Island.
Alba field natural gas is processed by the LPG plant.
Under a longterm contract at a fixed price per btu, the LPG plant extracts secondary condensate and LPG from the natural gas stream and uses some of the remaining dry natural gas in its operations.
We also own 60% of EGHoldings and 45% of AMPCO, both of which are accounted for as equity method investments.
EGHoldings operates an LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island.
These facilities allow us to monetize natural gas reserves from the Alba field.
EGHoldings' 3.7 mmta LNG production facility sells LNG under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement through 2023.
The purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index.
Gross sales of LNG from this production facility totaled 3.6 mmta in 2015.
5-year annual conversion rate (2011-2015) averaged 21% and would be 32%, excluding the long-term projects in E. G.  and Libya.
All proved undeveloped reserve drilling locations are scheduled to be drilled prior to the end of 2020.
As of December 31, 2015, future development costs estimated to be required for the development of proved undeveloped crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves for the years 2016 through 2020 are projected to be $630 million, $859 million, $1,389 million, $1,764 million and $986 million.
## Table 2 ##
(a) The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b) Excludes volumes acquired from third parties for injection and subsequent resale.
(c) Upgraded bitumen excluding blendstocks.
Average Sales Price per Unit
## Table 3 ##
(a) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and/or EGHoldings, which are equity method investees.
We include our share of income from each of these equity method investees in our International E&P Segment.
Average Production Cost per Unit(a)

<table><tr><td></td><td>2013</td><td>2012</td></tr><tr><td>Cumulative foreign currency translation</td><td>$-105</td><td>$8</td></tr><tr><td>Net unrecognized gains/losses on derivative instruments</td><td>-175</td><td>-240</td></tr><tr><td>Net unrealized gains/losses on marketable securities</td><td>-191</td><td>731</td></tr><tr><td>Accumulated other comprehensive income/(loss)</td><td>$-471</td><td>$499</td></tr></table>
<table><tr><td>Net Sales Volumes</td><td>2015</td><td>Increase(Decrease)</td><td>2014</td><td>Increase(Decrease)</td><td>2013</td></tr><tr><td>Equivalent Barrels (mboed)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equatorial Guinea</td><td>97</td><td>-7%</td><td>104</td><td>-3%</td><td>107</td></tr><tr><td>United Kingdom<sup>(a)</sup></td><td>19</td><td>19%</td><td>16</td><td>-20%</td><td>20</td></tr><tr><td>Libya</td><td>—</td><td>-100%</td><td>7</td><td>-75%</td><td>28</td></tr><tr><td>Total International E&P (mboed)</td><td>116</td><td>-9%</td><td>127</td><td>-18%</td><td>155</td></tr><tr><td>Net Sales Volumes of Equity Method Investees</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>LNG (mtd)</td><td>5,884</td><td>-10%</td><td>6,535</td><td>—%</td><td>6,548</td></tr><tr><td>Methanol (mtd)</td><td>937</td><td>-14%</td><td>1,092</td><td>-13%</td><td>1,249</td></tr></table>
<table><tr><td></td><td colspan="3">North America</td><td colspan="3">Africa</td><td></td><td></td><td></td></tr><tr><td></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>Year Ended December 31,</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td colspan="2">2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude and condensate(mbbld)<sup>(a)</sup></td><td>171</td><td>—</td><td>171</td><td>19</td><td>—</td><td>19</td><td>14</td><td>—</td><td>204</td></tr><tr><td>Natural gas liquids(mbbld)</td><td>39</td><td>—</td><td>39</td><td>10</td><td>—</td><td>10</td><td>—</td><td>—</td><td>49</td></tr><tr><td>Natural gas(mmcfd)<sup>(b)</sup></td><td>351</td><td>—</td><td>351</td><td>410</td><td>—</td><td>410</td><td>21</td><td>—</td><td>782</td></tr><tr><td>Synthetic crude oil(mbbld)<sup>(c)</sup></td><td>—</td><td>45</td><td>45</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>45</td></tr><tr><td>Total production sold(mboed)</td><td>269</td><td>45</td><td>314</td><td>97</td><td>—</td><td>97</td><td>18</td><td>—</td><td>429</td></tr><tr><td colspan="2">2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude and condensate(mbbld)<sup>(a)</sup></td><td>157</td><td>—</td><td>157</td><td>21</td><td>7</td><td>28</td><td>11</td><td>48</td><td>244</td></tr><tr><td>Natural gas liquids(mbbld)</td><td>29</td><td>—</td><td>29</td><td>10</td><td>—</td><td>10</td><td>—</td><td>—</td><td>39</td></tr><tr><td>Natural gas(mmcfd)<sup>(b)</sup></td><td>310</td><td>—</td><td>310</td><td>439</td><td>1</td><td>440</td><td>21</td><td>37</td><td>808</td></tr><tr><td>Synthetic crude oil(mbbld)<sup>(c)</sup></td><td>—</td><td>41</td><td>41</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>41</td></tr><tr><td>Total production sold(mboed)</td><td>238</td><td>41</td><td>279</td><td>104</td><td>7</td><td>111</td><td>15</td><td>54</td><td>459</td></tr><tr><td colspan="2">2013</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude and condensate(mbbld)<sup>(a)</sup></td><td>126</td><td>—</td><td>126</td><td>23</td><td>24</td><td>47</td><td>14</td><td>81</td><td>268</td></tr><tr><td>Natural gas liquids(mbbld)</td><td>23</td><td>—</td><td>23</td><td>11</td><td>—</td><td>11</td><td>1</td><td>—</td><td>35</td></tr><tr><td>Natural gas(mmcfd)<sup>(b)</sup></td><td>312</td><td>—</td><td>312</td><td>442</td><td>22</td><td>464</td><td>25</td><td>51</td><td>852</td></tr><tr><td>Synthetic crude oil(mbbld)<sup>(c)</sup></td><td>—</td><td>42</td><td>42</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>42</td></tr><tr><td>Total production sold(mboed)</td><td>201</td><td>42</td><td>243</td><td>107</td><td>27</td><td>134</td><td>20</td><td>89</td><td>486</td></tr></table>
<table><tr><td></td><td colspan="3">North America</td><td colspan="4">Africa</td><td></td><td></td><td></td></tr><tr><td>(Dollars per unit)</td><td>U.S.</td><td>Canada</td><td>Total</td><td>E.G.</td><td></td><td>Other</td><td>Total</td><td>Other Int'l</td><td>Disc Ops</td><td>Total</td></tr><tr><td colspan="2">2015</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude and condensate(bbl)</td><td>$43.50</td><td>$—</td><td>$43.50</td><td>$42.83</td><td></td><td>$—</td><td>$42.83</td><td>$53.91</td><td>$—</td><td>$44.14</td></tr><tr><td>Natural gas liquids(bbl)</td><td>13.37</td><td>—</td><td>13.37</td><td>1.00</td><td><sup>(a)</sup></td><td>—</td><td>1.00</td><td>32.53</td><td>—</td><td>11.16</td></tr><tr><td>Natural gas(mcf)</td><td>2.66</td><td>—</td><td>2.66</td><td>0.24</td><td><sup>(a)</sup></td><td>—</td><td>0.24</td><td>6.85</td><td>—</td><td>1.50</td></tr><tr><td>Synthetic crude oil(bbl)</td><td>—</td><td>40.13</td><td>40.13</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>40.13</td></tr><tr><td colspan="2">2014</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude and condensate(bbl)</td><td>$85.25</td><td>$—</td><td>$85.25</td><td>$81.01</td><td></td><td>$94.70</td><td>$84.48</td><td>$94.31</td><td>$109.80</td><td>$90.37</td></tr><tr><td>Natural gas liquids(bbl)</td><td>33.42</td><td>—</td><td>33.42</td><td>1.00</td><td><sup>(a)</sup></td><td>—</td><td>1.00</td><td>67.73</td><td>—</td><td>25.25</td></tr><tr><td>Natural gas(mcf)</td><td>4.57</td><td>—</td><td>4.57</td><td>0.24</td><td><sup>(a)</sup></td><td>3.11</td><td>0.25</td><td>8.27</td><td>9.94</td><td>2.55</td></tr><tr><td>Synthetic crude oil(bbl)</td><td>—</td><td>83.35</td><td>83.35</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>83.35</td></tr><tr><td colspan="2">2013</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Crude and condensate(bbl)</td><td>$94.19</td><td>$—</td><td>$94.19</td><td>$90.62</td><td></td><td>$122.92</td><td>$107.31</td><td>$110.76</td><td>$112.36</td><td>$102.81</td></tr><tr><td>Natural gas liquids(bbl)</td><td>35.12</td><td>—</td><td>35.12</td><td>1.00</td><td><sup>(a)</sup></td><td>—</td><td>1.00</td><td>72.14</td><td>—</td><td>24.78</td></tr><tr><td>Natural gas(mcf)</td><td>3.84</td><td>—</td><td>3.84</td><td>0.24</td><td><sup>(a)</sup></td><td>5.44</td><td>0.49</td><td>10.64</td><td>13.01</td><td>2.75</td></tr><tr><td>Synthetic crude oil(bbl)</td><td>—</td><td>87.51</td><td>87.51</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>87.51</td></tr></table>

Question: What was the average of the Natural gas(mcf) in the years where Synthetic crude oil(bbl) is positive?