DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Future development costs include not only development costs but also future asset retirement costs.
Included as part of the $10.8 billion of future development costs are $1.5 billion of future asset retirement costs.
The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
## Table 0 ##
23.
Supplemental Quarterly Financial Information (Unaudited) Following is a summary of Devon’s unaudited interim results of operations.
## Table 1 ##
NOTE 21.
SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED) Costs Incurred.
FCX’s oil and gas acquisition, exploration and development activities since the acquisitions of PXP and MMR follow:
## Table 2 ##
a.
Included $12.2 billion from the acquisitions of PXP and MMR.
b.
Included $11.1 billion from the acquisitions of PXP and MMR.
These amounts included AROs of $1.1 billion (including $1.0 billion assumed in the acquisitions of PXP and MMR), capitalized general and administrative expenses of $67 million and capitalized interest of $69 million.
Capitalized Costs.
The following table presents the aggregate capitalized costs subject to amortization for oil and gas properties and the aggregate related accumulated amortization as of December 31, 2013:
## Table 3 ##
The average amortization rate per barrel of oil equivalents (BOE) was $35.54 for the period from June 1, 2013, to December 31, 2013.
Costs Not Subject to Amortization.
The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization as of December 31, 2013:
## Table 4 ##
FCX expects that 61 percent of the costs not subject to amortization at December 31, 2013, will be transferred to the amortization base over the next five years and the majority of the remainder in the next seven to ten years.
Approximately 41 percent of the total U. S.  net undeveloped acres is covered by leases that expire from 2014 to 2016; however, a significant portion of this acreage is expected to be retained by drilling operations or other means.
The lease for FM O&G’s Morocco acreage expires in 2016; however, FM O&G has the ability to extend the lease through 2019.
Over 90 percent of the acreage in the Haynesville shale play in Louisiana and over 70 percent of the acreage in the Eagle Ford shale play in Texas is currently held by production or held by operations, and future plans include drilling or otherwise extending leases on the remaining acreage.
Results of Operations for Oil and Gas Producing Activities.
The results of operations from oil and gas producing activities from June 1, 2013, to December 31, 2013, presented below exclude non-oil and gas revenues, general and administrative expenses, interest expense and interest income.
Income tax expense was determined by applying the statutory rates to pre-tax operating results:
## Table 5 ##
Proved Oil and Natural Gas Reserve Information.
The following information summarizes the net proved reserves of oil (including condensate and natural gas liquids (NGLs)) and natural gas and the standardized measure as described below.
All of the oil and natural gas reserves are located in the U. S.  Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable.
However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond FCX’s control.
Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Because all oil and natural gas reserve estimates are to some degree subjective, the quantities of oil and natural gas that are
The following table details the growth in global weighted average berths and the global, North American, European and Asia/Pacific cruise guests over the past five years (in thousands, except berth data):

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2014</td><td>2013</td><td>2012</td></tr><tr><td></td><td colspan="3">(In millions)</td></tr><tr><td>Beginning balance</td><td>$15,741</td><td>$13,221</td><td>$17,844</td></tr><tr><td>Net changes in prices and production costs</td><td>2,561</td><td>3,018</td><td>-9,889</td></tr><tr><td>Oil, bitumen, gas and NGL sales, net of production costs</td><td>-6,865</td><td>-5,613</td><td>-4,388</td></tr><tr><td>Changes in estimated future development costs</td><td>-768</td><td>399</td><td>-1,094</td></tr><tr><td>Extensions and discoveries, net of future development costs</td><td>4,836</td><td>4,047</td><td>4,669</td></tr><tr><td>Purchase of reserves</td><td>6,422</td><td>14</td><td>18</td></tr><tr><td>Sales of reserves in place</td><td>-2,384</td><td>-44</td><td>-25</td></tr><tr><td>Revisions of quantity estimates</td><td>-746</td><td>-1,040</td><td>162</td></tr><tr><td>Previously estimated development costs incurred during the period</td><td>1,933</td><td>1,986</td><td>1,321</td></tr><tr><td>Accretion of discount</td><td>1,746</td><td>1,940</td><td>1,420</td></tr><tr><td>Other, primarily changes in timing and foreign exchange rates</td><td>-107</td><td>-583</td><td>113</td></tr><tr><td>Net change in income taxes</td><td>-1,895</td><td>-1,604</td><td>3,070</td></tr><tr><td>Ending balance</td><td>$20,474</td><td>$15,741</td><td>$13,221</td></tr></table>
<table><tr><td></td><td colspan="5">2014</td></tr><tr><td></td><td>First Quarter</td><td> Second Quarter</td><td> Third Quarter</td><td>Fourth Quarter</td><td>Full Year</td></tr><tr><td></td><td colspan="5">(In millions, except per share amounts)</td></tr><tr><td>Operating revenues</td><td>$3,725</td><td>$4,510</td><td>$5,336</td><td>$5,995</td><td>$19,566</td></tr><tr><td>Earnings (loss) before income taxes</td><td>$560</td><td>$1,554</td><td>$1,654</td><td>$291</td><td>$4,059</td></tr><tr><td>Net earnings (loss) attributable to Devon</td><td>$324</td><td>$675</td><td>$1,016</td><td>$-408</td><td>$1,607</td></tr><tr><td>Basic net earnings (loss) per share attributable to Devon</td><td>$0.80</td><td>$1.65</td><td>$2.48</td><td>$-1.01</td><td>$3.93</td></tr><tr><td>Diluted net earnings (loss) per share attributable to Devon</td><td>$0.79</td><td>$1.64</td><td>$2.47</td><td>$-1.01</td><td>$3.91</td></tr><tr><td></td><td colspan="5">2013</td></tr><tr><td></td><td>First Quarter</td><td> Second Quarter</td><td> Third Quarter</td><td>Fourth Quarter</td><td>Full Year</td></tr><tr><td></td><td colspan="5">(In millions, except per share amounts)</td></tr><tr><td>Operating revenues</td><td>$1,971</td><td>$3,088</td><td>$2,714</td><td>$2,624</td><td>$10,397</td></tr><tr><td>Earnings (loss) before income taxes</td><td>$-1,962</td><td>$997</td><td>$639</td><td>$475</td><td>$149</td></tr><tr><td>Net earnings (loss) attributable to Devon</td><td>$-1,339</td><td>$683</td><td>$429</td><td>$207</td><td>$-20</td></tr><tr><td>Basic net earnings (loss) per share attributable to Devon</td><td>$-3.34</td><td>$1.69</td><td>$1.06</td><td>$0.51</td><td>$-0.06</td></tr><tr><td>Diluted net earnings (loss) per share attributable to Devon</td><td>$-3.34</td><td>$1.68</td><td>$1.05</td><td>$0.51</td><td>$-0.06</td></tr></table>
<table><tr><td>Proved properties<sup>a</sup></td><td>$12,205</td></tr><tr><td>Unproved properties<sup>b</sup></td><td>11,259</td></tr><tr><td>Exploration costs</td><td>502</td></tr><tr><td>Development costs</td><td>854</td></tr><tr><td></td><td>$24,820</td></tr></table>
<table><tr><td>Properties subject to amortization</td><td>$13,829</td></tr><tr><td>Accumulated amortization</td><td>-1,357</td></tr><tr><td></td><td>$12,472</td></tr></table>
<table><tr><td>Acquisition costs</td><td>$3,109</td></tr><tr><td>Exploration costs</td><td>8</td></tr><tr><td>Capitalized interest</td><td>11</td></tr><tr><td>Offshore</td><td></td></tr><tr><td>Acquisition costs</td><td>7,528</td></tr><tr><td>Exploration costs</td><td>163</td></tr><tr><td>Capitalized interest</td><td>53</td></tr><tr><td>International:</td><td></td></tr><tr><td>Offshore</td><td></td></tr><tr><td>Acquisition costs</td><td>15</td></tr><tr><td>Exploration costs</td><td>—</td></tr><tr><td>Capitalized interest</td><td>—</td></tr><tr><td></td><td>$10,887</td></tr></table>
<table><tr><td>Revenues from oil and gas producing activities</td><td>$2,616</td></tr><tr><td>Production and delivery costs</td><td>-682</td></tr><tr><td>Depreciation, depletion and amortization</td><td>-1,358</td></tr><tr><td>Income tax expense (based on FCX's statutory tax rate)</td><td>-219</td></tr><tr><td>Results of operations from oil and gas producing activities (excluding general and administrative expenses, interest expense and interest income)</td><td>$357</td></tr></table>

Question: If operating revenue develops with the same increasing rate in 2014, what will it reach in 2015? (in million)
Answer: 36821
Reasoning program: subtract(19566,10397), divide(#0,10397), add(#1,1), multiply(#2,19566)