EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) F-41 Net Proved Undeveloped Reserves.
The following table presents the changes in EOG's total proved undeveloped reserves during 2016, 2015 and 2014 (in MBoe):
## Table 0 ##
For the twelve-month period ended December 31, 2016, total PUDs increased by 7 MMBoe to 1,053 MMBoe.
EOG added approximately 21 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.
Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-35 and F-36 of this Annual Report on Form 10-K), EOG added 117 MMBoe.
The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Rocky Mountain area, and 82% of the additions were crude oil and condensate and NGLs.
During 2016, EOG drilled and transferred 149 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,230 million.
Revisions of PUDs totaled positive 64 MMBoe, primarily due to improved well performance, primarily in the Delaware Basin, and lower production costs, partially offset by the impact of decreases in the average crude oil and natural gas prices used in the December 31, 2016, reserves estimation as compared to the prices used in the prior year estimate.
During 2016, EOG sold 46 MMBoe of PUDs primarily in the Haynesville play.
All PUDs for drilled but uncompleted wells (DUCs) are scheduled for completion within five years of the original reserve booking.
For the twelve-month period ended December 31, 2015, total PUDs decreased by 104 MMBoe to 1,046 MMBoe.
EOG added approximately 52 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.
Based on the technology employed by EOG to identify and record PUDs, EOG added 153 MMBoe.
The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs.
During 2015, EOG drilled and transferred 121 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,349 million.
Revisions of PUDs totaled negative 242 MMBoe, primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate.
During 2015, EOG did not sell any PUDs and acquired 54 MMBoe of PUDs.
For the twelve-month period ended December 31, 2014, total PUDs increased by 158 MMBoe to 1,149 MMBoe.
EOG added approximately 50 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.
Based on the technology employed by EOG to identify and record PUDs, EOG added 354 MMBoe.
The PUD additions were primarily in the Eagle Ford and Permian Basin, and 80% of the additions were crude oil and condensate and NGLs.
During 2014, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,655 million.
Revisions of PUDs totaled negative 80 MMBoe, primarily due to removal of certain natural gas PUDs.
During 2014, EOG sold 10 MMBoe and acquired 4 MMBoe of PUDs.
Capitalized Costs Relating to Oil and Gas Producing Activities.
The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2016 and 2015:
## Table 1 ##
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) F-44 Net Proved Undeveloped Reserves.
The following table presents the changes in EOG's total proved undeveloped reserves during 2017, 2016 and 2015 (in MBoe):
## Table 2 ##
For the twelve-month period ended December 31, 2017, total PUDs increased by 110 MMBoe to 1,163 MMBoe.
EOG added approximately 38 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.
Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-38 and F-39 of this Annual Report on Form 10-K), EOG added 199 MMBoe.
The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 74% of the additions were crude oil and condensate and NGLs.
During 2017, EOG drilled and transferred 153 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,440 million.
Revisions of PUDs totaled positive 33 MMBoe, primarily due to updated type curves resulting from improved performance of offsetting wells in the Permian Basin, the impact of increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate, and lower costs.
During 2017, EOG sold or exchanged 8 MMBoe of PUDs primarily in the Permian Basin.
All PUDs, including drilled but uncompleted wells (DUCs), are scheduled for completion within five years of the original reserve booking.
For the twelve-month period ended December 31, 2016, total PUDs increased by 7 MMBoe to 1,053 MMBoe.
EOG added approximately 21 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.
Based on the technology employed by EOG to identify and record PUDs, EOG added 117 MMBoe.
The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Rocky Mountain area, and 82% of the additions were crude oil and condensate and NGLs.
During 2016, EOG drilled and transferred 149 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,230 million.
Revisions of PUDs totaled positive 64 MMBoe, primarily due to improved well performance, primarily in the Delaware Basin, and lower production costs, partially offset by the impact of decreases in the average crude oil and natural gas prices used in the December 31, 2016, reserves estimation as compared to the prices used in the prior year estimate.
During 2016, EOG sold 46 MMBoe of PUDs primarily in the Haynesville play.
All PUDs for drilled but uncompleted wells (DUCs) are scheduled for completion within five years of the original reserve booking.
For the twelve-month period ended December 31, 2015, total PUDs decreased by 104 MMBoe to 1,046 MMBoe.
EOG added approximately 52 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.
Based on the technology employed by EOG to identify and record PUDs, EOG added 153 MMBoe.
The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs.
During 2015, EOG drilled and transferred 121 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,349 million.
Revisions of PUDs totaled negative 242 MMBoe, primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate.
During 2015, EOG did not sell any PUDs and acquired 54 MMBoe of PUDs.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) F-45 Capitalized Costs Relating to Oil and Gas Producing Activities.
The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2017 and 2016:
## Table 3 ##
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.
The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil aand Gas Topic of the Accounting Standards Codification (ASC).
Acquisition costs include costs incurred to purchase, lease or otherwise acquire property.
Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses.
Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.
The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units and stock that were anti-dilutive.
Shares underlying the excluded stock options and SARs totaled 2.6 million, 10.3 million and 10.2 million for the years ended December 31, 2017, 2016 and 2015, respectively.
For the year ended December 31, 2016, 4.5 million shares of restricted stock and restricted stock units and performance units and performance stock were excluded.10.
Supplemental Cash Flow Information Net cash paid for interest and income taxes was as follows for the years ended December 31, 2017, 2016 and 2015 (in thousands):
## Table 4 ##
EOG's accrued capital expenditures at December 31, 2017, 2016 and 2015 were $475 million, $388 million and $416 million, respectively.
Non-cash investing activities for the year ended December 31, 2017 included non-cash additions of $282 million to EOG's oil and gas properties as a result of property exchanges.
Non-cash investing activities for the year ended December 31, 2016 included $3,834 million in non-cash additions to EOG's oil and gas properties related to the Yates transaction (see Note 17).11.  Business Segment Information EOG's operations are all crude oil and natural gas exploration and production related.
The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements.
Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance.
EOG's chief operating decision-making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers.
This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Trinidad, the United Kingdom and China.
For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
## Table 5 ##
(1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations.
The Argentina operations were sold in the third quarter of 2016.
(2) Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas.
Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.
(3) Billion cubic feet.

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td>2016</td><td>2015</td><td>2014</td></tr><tr><td>Balance at January 1</td><td>1,045,640</td><td>1,149,309</td><td>991,067</td></tr><tr><td>Extensions and Discoveries</td><td>138,101</td><td>205,152</td><td>403,713</td></tr><tr><td>Revisions</td><td>64,413</td><td>-241,973</td><td>-79,630</td></tr><tr><td>Acquisition of Reserves</td><td>—</td><td>54,458</td><td>4,239</td></tr><tr><td>Sale of Reserves</td><td>-45,917</td><td>—</td><td>-10,176</td></tr><tr><td>Conversion to Proved Developed Reserves</td><td>-149,210</td><td>-121,306</td><td>-159,904</td></tr><tr><td>Balance at December 31</td><td>1,053,027</td><td>1,045,640</td><td>1,149,309</td></tr></table>
<table><tr><td></td><td>2016</td><td>2015</td></tr><tr><td>Proved properties</td><td>$45,751,965</td><td>$49,623,518</td></tr><tr><td>Unproved properties</td><td>3,840,126</td><td>989,723</td></tr><tr><td>Total</td><td>49,592,091</td><td>50,613,241</td></tr><tr><td>Accumulated depreciation, depletion and amortization</td><td>-26,247,062</td><td>-28,877,593</td></tr><tr><td>Net capitalized costs</td><td>$23,345,029</td><td>$21,735,648</td></tr></table>
<table><tr><td></td><td>2017</td><td>2016</td><td>2015</td></tr><tr><td>Balance at January 1</td><td>1,053,027</td><td>1,045,640</td><td>1,149,309</td></tr><tr><td>Extensions and Discoveries</td><td>237,378</td><td>138,101</td><td>205,152</td></tr><tr><td>Revisions</td><td>33,127</td><td>64,413</td><td>-241,973</td></tr><tr><td>Acquisition of Reserves</td><td>—</td><td>—</td><td>54,458</td></tr><tr><td>Sale of Reserves</td><td>-8,253</td><td>-45,917</td><td>—</td></tr><tr><td>Conversion to Proved Developed Reserves</td><td>-152,644</td><td>-149,210</td><td>-121,306</td></tr><tr><td>Balance at December 31</td><td>1,162,635</td><td>1,053,027</td><td>1,045,640</td></tr></table>
<table><tr><td></td><td>2017</td><td>2016</td></tr><tr><td>Proved properties</td><td>$48,845,672</td><td>$45,751,965</td></tr><tr><td>Unproved properties</td><td>3,710,069</td><td>3,840,126</td></tr><tr><td>Total</td><td>52,555,741</td><td>49,592,091</td></tr><tr><td>Accumulated depreciation, depletion and amortization</td><td>-29,191,247</td><td>-26,247,062</td></tr><tr><td>Net capitalized costs</td><td>$23,364,494</td><td>$23,345,029</td></tr></table>
<table><tr><td></td><td>2017</td><td>2016</td><td>2015</td></tr><tr><td>Interest, Net of Capitalized Interest</td><td>$275,305</td><td>$252,030</td><td>$222,088</td></tr><tr><td>Income Taxes, Net of Refunds Received</td><td>$188,946</td><td>$-39,293</td><td>$41,108</td></tr></table>
<table><tr><td></td><td>UnitedStates</td><td>Trinidad</td><td>OtherInternational<sup>-1</sup></td><td>Total</td></tr><tr><td>Natural Gas (Bcf)<sup>(3)</sup></td><td></td><td></td><td></td><td></td></tr><tr><td>Net proved reserves at December 31, 2014</td><td>4,905.5</td><td>405.6</td><td>31.5</td><td>5,342.6</td></tr><tr><td>Revisions of previous estimates</td><td>-1,453.1</td><td>16.8</td><td>5.6</td><td>-1,430.7</td></tr><tr><td>Purchases in place</td><td>72.3</td><td>—</td><td>—</td><td>72.3</td></tr><tr><td>Extensions, discoveries and other additions</td><td>306.3</td><td>21.7</td><td>4.4</td><td>332.4</td></tr><tr><td>Sales in place</td><td>-3.9</td><td>—</td><td>-11.1</td><td>-15.0</td></tr><tr><td>Production</td><td>-337.3</td><td>-127.5</td><td>-10.9</td><td>-475.7</td></tr><tr><td>Net proved reserves at December 31, 2015</td><td>3,489.8</td><td>316.6</td><td>19.5</td><td>3,825.9</td></tr><tr><td>Revisions of previous estimates</td><td>298.4</td><td>29.5</td><td>5.2</td><td>333.1</td></tr><tr><td>Purchases in place</td><td>91.5</td><td>—</td><td>—</td><td>91.5</td></tr><tr><td>Extensions, discoveries and other additions</td><td>202.1</td><td>59.9</td><td>—</td><td>262.0</td></tr><tr><td>Sales in place</td><td>-752.0</td><td>—</td><td>—</td><td>-752.0</td></tr><tr><td>Production</td><td>-308.6</td><td>-125.1</td><td>-8.9</td><td>-442.6</td></tr><tr><td>Net proved reserves at December 31, 2016</td><td>3,021.2</td><td>280.9</td><td>15.8</td><td>3,317.9</td></tr><tr><td>Revisions of previous estimates</td><td>602.8</td><td>-27.4</td><td>8.6</td><td>584.0</td></tr><tr><td>Purchases in place</td><td>4.8</td><td>—</td><td>—</td><td>4.8</td></tr><tr><td>Extensions, discoveries and other additions</td><td>619.3</td><td>174.2</td><td>35.9</td><td>829.4</td></tr><tr><td>Sales in place</td><td>-56.4</td><td>—</td><td>—</td><td>-56.4</td></tr><tr><td>Production</td><td>-293.2</td><td>-114.3</td><td>-9.1</td><td>-416.6</td></tr><tr><td>Net proved reserves at December 31, 2017</td><td>3,898.5</td><td>313.4</td><td>51.2</td><td>4,263.1</td></tr><tr><td>Oil Equivalents (MBoe)<sup>(2)</sup></td><td></td><td></td><td></td><td></td></tr><tr><td>Net proved reserves at December 31, 2014</td><td>2,414,202</td><td>68,937</td><td>14,117</td><td>2,497,256</td></tr><tr><td>Revisions of previous estimates</td><td>-470,401</td><td>2,802</td><td>995</td><td>-466,604</td></tr><tr><td>Purchases in place</td><td>56,215</td><td>—</td><td>—</td><td>56,215</td></tr><tr><td>Extensions, discoveries and other additions</td><td>241,513</td><td>3,682</td><td>736</td><td>245,931</td></tr><tr><td>Sales in place</td><td>-1,467</td><td>—</td><td>-2,039</td><td>-3,506</td></tr><tr><td>Production</td><td>-187,701</td><td>-21,578</td><td>-1,896</td><td>-211,175</td></tr><tr><td>Net proved reserves at December 31, 2015</td><td>2,052,361</td><td>53,843</td><td>11,913</td><td>2,118,117</td></tr><tr><td>Revisions of previous estimates</td><td>145,542</td><td>4,978</td><td>1,722</td><td>152,242</td></tr><tr><td>Purchases in place</td><td>42,330</td><td>—</td><td>—</td><td>42,330</td></tr><tr><td>Extensions, discoveries and other additions</td><td>198,973</td><td>9,990</td><td>—</td><td>208,963</td></tr><tr><td>Sales in place</td><td>-167,669</td><td>—</td><td>—</td><td>-167,669</td></tr><tr><td>Production</td><td>-183,145</td><td>-21,150</td><td>-2,755</td><td>-207,050</td></tr><tr><td>Net proved reserves at December 31, 2016</td><td>2,088,392</td><td>47,661</td><td>10,880</td><td>2,146,933</td></tr><tr><td>Revisions of previous estimates</td><td>205,262</td><td>-4,493</td><td>1,249</td><td>202,018</td></tr><tr><td>Purchases in place</td><td>2,332</td><td>—</td><td>—</td><td>2,332</td></tr><tr><td>Extensions, discoveries and other additions</td><td>385,354</td><td>29,340</td><td>6,104</td><td>420,798</td></tr><tr><td>Sales in place</td><td>-20,687</td><td>—</td><td>—</td><td>-20,687</td></tr><tr><td>Production</td><td>-203,351</td><td>-19,366</td><td>-1,707</td><td>-224,424</td></tr><tr><td>Net proved reserves at December 31, 2017</td><td>2,457,302</td><td>53,142</td><td>16,526</td><td>2,526,970</td></tr></table>

Question: What is the average amount of Conversion to Proved Developed Reserves of 2014, and Accumulated depreciation, depletion and amortization of 2016 ?
Answer: 1.32035e+07
Reasoning program: add(159904.0,26247062.0), divide(#0,const_2)