bevaya/FinQA huggingface dataset:
performance graph comparison of five-year cumulative total return the following graph and table compare the cumulative total return on citi 2019s common stock , which is listed on the nyse under the ticker symbol 201cc 201d and held by 65691 common stockholders of record as of january 31 , 2018 , with the cumulative total return of the s&p 500 index and the s&p financial index over the five-year period through december 31 , 2017 . the graph and table assume that $ 100 was invested on december 31 , 2012 in citi 2019s common stock , the s&p 500 index and the s&p financial index , and that all dividends were reinvested . comparison of five-year cumulative total return for the years ended date citi s&p 500 financials .

Table: date citi s&p 500 s&p financials 31-dec-2012 100.0 100.0 100.0 31-dec-2013 131.8 132.4 135.6 31-dec-2014 137.0 150.5 156.2 31-dec-2015 131.4 152.6 153.9 31-dec-2016 152.3 170.8 188.9 31-dec-2017 193.5 208.1 230.9

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Question: what was the percentage cumulative total return for the five year period ended 31-dec-2017 of citi common stock?
Answer: 93.5%
Calculation: divide(subtract(193.5, const_100), const_100)
entergy mississippi , inc . management 2019s financial discussion and analysis 2010 compared to 2009 net revenue consists of operating revenues net of : 1 ) fuel , fuel-related expenses , and gas purchased for resale , 2 ) purchased power expenses , and 3 ) other regulatory charges ( credits ) . following is an analysis of the change in net revenue comparing 2010 to 2009 . amount ( in millions ) .

Table: amount ( in millions ) 2009 net revenue $ 536.7 volume/weather 18.9 other -0.3 ( 0.3 ) 2010 net revenue $ 555.3

the volume/weather variance is primarily due to an increase of 1046 gwh , or 8% ( 8 % ) , in billed electricity usage in all sectors , primarily due to the effect of more favorable weather on the residential sector . gross operating revenues , fuel and purchased power expenses , and other regulatory charges ( credits ) gross operating revenues increased primarily due to an increase of $ 22 million in power management rider revenue as the result of higher rates , the volume/weather variance discussed above , and an increase in grand gulf rider revenue as a result of higher rates and increased usage , offset by a decrease of $ 23.5 million in fuel cost recovery revenues due to lower fuel rates . fuel and purchased power expenses decreased primarily due to a decrease in deferred fuel expense as a result of prior over-collections , offset by an increase in the average market price of purchased power coupled with increased net area demand . other regulatory charges increased primarily due to increased recovery of costs associated with the power management recovery rider . other income statement variances 2011 compared to 2010 other operation and maintenance expenses decreased primarily due to : a $ 5.4 million decrease in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense ; and the sale of $ 4.9 million of surplus oil inventory . the decrease was partially offset by an increase of $ 3.9 million in legal expenses due to the deferral in 2010 of certain litigation expenses in accordance with regulatory treatment . taxes other than income taxes increased primarily due to an increase in ad valorem taxes due to a higher 2011 assessment as compared to 2010 , partially offset by higher capitalized property taxes as compared with prior year . depreciation and amortization expenses increased primarily due to an increase in plant in service . interest expense decreased primarily due to a revision caused by ferc 2019s acceptance of a change in the treatment of funds received from independent power producers for transmission interconnection projects. .

Question: in 2010 what was the net change in net revenue in millions
Answer: 18.6
Calculation: add(18.9, 0.3)
entergy louisiana , inc . management's financial discussion and analysis gross operating revenues , fuel and purchased power expenses , and other regulatory credits gross operating revenues increased primarily due to : 2022 an increase of $ 98.0 million in fuel cost recovery revenues due to higher fuel rates ; and 2022 an increase due to volume/weather , as discussed above . the increase was partially offset by the following : 2022 a decrease of $ 31.9 million in the price applied to unbilled sales , as discussed above ; 2022 a decrease of $ 12.2 million in rate refund provisions , as discussed above ; and 2022 a decrease of $ 5.2 million in gross wholesale revenue due to decreased sales to affiliated systems . fuel and purchased power expenses increased primarily due to : 2022 an increase in the recovery from customers of deferred fuel costs ; and 2022 an increase in the market price of natural gas . other regulatory credits increased primarily due to : 2022 the deferral in 2004 of $ 14.3 million of capacity charges related to generation resource planning as allowed by the lpsc ; 2022 the amortization in 2003 of $ 11.8 million of deferred capacity charges , as discussed above ; and 2022 the deferral in 2004 of $ 11.4 million related to entergy's voluntary severance program , in accordance with a proposed stipulation with the lpsc staff . 2003 compared to 2002 net revenue , which is entergy louisiana's measure of gross margin , consists of operating revenues net of : 1 ) fuel , fuel-related , and purchased power expenses and 2 ) other regulatory charges ( credits ) . following is an analysis of the change in net revenue comparing 2003 to 2002. .

Table: ( in millions ) 2002 net revenue $ 922.9 deferred fuel cost revisions 59.1 asset retirement obligation 8.2 volume -16.2 ( 16.2 ) vidalia settlement -9.2 ( 9.2 ) other 8.9 2003 net revenue $ 973.7

the deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in december 2002 and a further revision made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs . the asset retirement obligation variance was due to the implementation of sfas 143 , "accounting for asset retirement obligations" adopted in january 2003 . see "critical accounting estimates" for more details on sfas 143 . the increase was offset by decommissioning expense and had no effect on net income . the volume variance was due to a decrease in electricity usage in the service territory . billed usage decreased 1868 gwh in the industrial sector including the loss of a large industrial customer to cogeneration. .

Question: what are the deferred fuel cost revisions as a percentage of the increase in fuel cost recovery revenues?
Answer: 60.3%
Calculation: divide(59.1, 98.0)
supplementary information on oil and gas producing activities ( unaudited ) c o n t i n u e d summary of changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves ( in millions ) 2007 2006 2005 sales and transfers of oil and gas produced , net of production , transportation and administrative costs $ ( 4887 ) $ ( 5312 ) $ ( 3754 ) net changes in prices and production , transportation and administrative costs related to future production 12845 ( 1342 ) 6648 .

Table: ( in millions ) 2007 2006 2005 sales and transfers of oil and gas produced net of production transportation and administrative costs $ -4887 ( 4887 ) $ -5312 ( 5312 ) $ -3754 ( 3754 ) net changes in prices and production transportation and administrative costs related to future production 12845 -1342 ( 1342 ) 6648 extensions discoveries and improved recovery less related costs 1816 1290 700 development costs incurred during the period 1654 1251 1030 changes in estimated future development costs -1727 ( 1727 ) -527 ( 527 ) -552 ( 552 ) revisions of previous quantity estimates 290 1319 820 net changes in purchases and sales of minerals in place 23 30 4557 accretion of discount 1726 1882 1124 net change in income taxes -6751 ( 6751 ) -660 ( 660 ) -6694 ( 6694 ) timing and other -12 ( 12 ) -14 ( 14 ) 307 net change for the year 4977 -2083 ( 2083 ) 4186 beginning of year 8518 10601 6415 end of year $ 13495 $ 8518 $ 10601 net change for the year from discontinued operations $ 2013 $ -216 ( 216 ) $ 162

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Question: if current development costs increased in 2008 as much as in 2007 , what would the 2008 total be , in millions?
Answer: 2057
Calculation: add(subtract(1654, 1251), 1654)
included in the corporate and consumer loan tables above are purchased distressed loans , which are loans that have evidenced significant credit deterioration subsequent to origination but prior to acquisition by citigroup . in accordance with sop 03-3 , the difference between the total expected cash flows for these loans and the initial recorded investments is recognized in income over the life of the loans using a level yield . accordingly , these loans have been excluded from the impaired loan information presented above . in addition , per sop 03-3 , subsequent decreases to the expected cash flows for a purchased distressed loan require a build of an allowance so the loan retains its level yield . however , increases in the expected cash flows are first recognized as a reduction of any previously established allowance and then recognized as income prospectively over the remaining life of the loan by increasing the loan 2019s level yield . where the expected cash flows cannot be reliably estimated , the purchased distressed loan is accounted for under the cost recovery method . the carrying amount of the company 2019s purchased distressed loan portfolio at december 31 , 2010 was $ 392 million , net of an allowance of $ 77 million as of december 31 , 2010 . the changes in the accretable yield , related allowance and carrying amount net of accretable yield for 2010 are as follows : in millions of dollars accretable carrying amount of loan receivable allowance .

Table: in millions of dollars accretable yield carrying amount of loan receivable allowance beginning balance $ 27 $ 920 $ 95 purchases ( 1 ) 1 130 2014 disposals/payments received -11 ( 11 ) -594 ( 594 ) 2014 accretion -44 ( 44 ) 44 2014 builds ( reductions ) to the allowance 128 2014 -18 ( 18 ) increase to expected cash flows -2 ( 2 ) 19 2014 fx/other 17 -50 ( 50 ) 2014 balance at december 31 2010 ( 2 ) $ 116 $ 469 $ 77

( 1 ) the balance reported in the column 201ccarrying amount of loan receivable 201d consists of $ 130 million of purchased loans accounted for under the level-yield method and $ 0 under the cost-recovery method . these balances represent the fair value of these loans at their acquisition date . the related total expected cash flows for the level-yield loans were $ 131 million at their acquisition dates . ( 2 ) the balance reported in the column 201ccarrying amount of loan receivable 201d consists of $ 315 million of loans accounted for under the level-yield method and $ 154 million accounted for under the cost-recovery method. .

Question: in 2010 what was the percentage change of the carrying amount of loan receivable net of the allowance
Answer: -52.5%
Calculation: divide(subtract(subtract(469, 77), subtract(920, 95)), subtract(920, 95))
devon energy corporation and subsidiaries notes to consolidated financial statements 2013 ( continued ) asset divestitures in conjunction with the asset divestitures in 2013 and 2014 , devon removed $ 26 million and $ 706 million of goodwill , respectively , which were allocated to these assets . impairment devon 2019s canadian goodwill was originally recognized in 2001 as a result of a business combination consisting almost entirely of conventional gas assets that devon no longer owns . as a result of performing the goodwill impairment test described in note 1 , devon concluded the implied fair value of its canadian goodwill was zero as of december 31 , 2014 . this conclusion was largely based on the significant decline in benchmark oil prices , particularly after opec 2019s decision not to reduce its production targets that was announced in late november 2014 . consequently , in the fourth quarter of 2014 , devon wrote off its remaining canadian goodwill and recognized a $ 1.9 billion impairment . other intangible assets as of december 31 , 2014 , intangible assets associated with customer relationships had a gross carrying amount of $ 569 million and $ 36 million of accumulated amortization . the weighted-average amortization period for the customer relationships is 13.7 years . amortization expense for intangibles was approximately $ 36 million for the year ended december 31 , 2014 . other intangible assets are reported in other long-term assets in the accompanying consolidated balance sheets . the following table summarizes the estimated aggregate amortization expense for the next five years . year amortization amount ( in millions ) .

Table: year amortization amount ( in millions ) 2015 $ 45 2016 $ 45 2017 $ 45 2018 $ 45 2019 $ 44

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Question: what is the average amortization amount , in millions , from 2015-2019?
Answer: 44.8
Calculation: divide(add(multiply(45, const_4), 44), const_5)
before the purchase in november 2008 , the units will be reflected in diluted earnings per share calculations using the treasury stock method as defined by sfas no . 128 , earnings per share . under this method , the number of shares of common stock used in calculating diluted earnings per share ( based on the settlement formula applied at the end of the reporting period ) is deemed to be increased by the excess , if any , of the number of shares that would be issued upon settlement of the purchase contracts less the number of shares that could be purchased by the company in the market at the average market price during the period using the proceeds to be received upon settlement . therefore , dilution will occur for periods when the average market price of the company 2019s common stock for the reporting period is above $ 21.816 . senior secured revolving credit facility in september 2005 , the company entered into a $ 250 million , three-year senior secured revolving credit facility . as a result of the citadel investment in november 2007 , the facility was terminated and all unamortized debt issuance costs were expensed . corporate debt covenants certain of the company 2019s corporate debt described above have terms which include customary financial covenants . as of december 31 , 2007 , the company was in compliance with all such covenants . early extinguishment of debt in 2006 , the company called the entire remaining $ 185.2 million principal amount of its 6% ( 6 % ) notes for redemption . the company recorded a $ 0.7 million loss on early extinguishment of debt relating to the write-off of the unamortized debt offering costs . the company did not have any early extinguishments of debt in 2005 . other corporate debt the company also has multiple term loans from financial institutions . these loans are collateralized by equipment and are included within other borrowings on the consolidated balance sheet . see note 14 2014securities sold under agreement to repurchase and other borrowings . future maturities of corporate debt scheduled principal payments of corporate debt as of december 31 , 2007 are as follows ( dollars in thousands ) : years ending december 31 .

Table: 2008 $ 2014 2009 2014 2010 2014 2011 453815 2012 2014 thereafter 2996337 total future principal payments of corporate debt 3450152 unamortized discount net -427454 ( 427454 ) total corporate debt $ 3022698

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Question: what percentage of total future principal payments of corporate debt are due after 2012?
Answer: 87%
Calculation: divide(2996337, 3450152)
part ii item 5 2014market for registrant 2019s common equity and related stockholder matters market information . the common stock of the company is currently traded on the new york stock exchange ( nyse ) under the symbol 2018 2018aes . 2019 2019 the following tables set forth the high and low sale prices for the common stock as reported by the nyse for the periods indicated . price range of common stock .

Table: 2002 first quarter high $ 17.84 low $ 4.11 2001 first quarter high $ 60.15 low $ 41.30 second quarter 9.17 3.55 second quarter 52.25 39.95 third quarter 4.61 1.56 third quarter 44.50 12.00 fourth quarter 3.57 0.95 fourth quarter 17.80 11.60

holders . as of march 3 , 2003 , there were 9663 record holders of the company 2019s common stock , par value $ 0.01 per share . dividends . under the terms of the company 2019s senior secured credit facilities entered into with a commercial bank syndicate , the company is not allowed to pay cash dividends . in addition , the company is precluded from paying cash dividends on its common stock under the terms of a guaranty to the utility customer in connection with the aes thames project in the event certain net worth and liquidity tests of the company are not met . the ability of the company 2019s project subsidiaries to declare and pay cash dividends to the company is subject to certain limitations in the project loans , governmental provisions and other agreements entered into by such project subsidiaries . securities authorized for issuance under equity compensation plans . see the information contained under the caption 2018 2018securities authorized for issuance under equity compensation plans 2019 2019 of the proxy statement for the annual meeting of stockholders of the registrant to be held on may 1 , 2003 , which information is incorporated herein by reference. .

Question: what was the difference in dollars of the high low sale price for the common stock in the fourth quarter of 2002?
Answer: 2.62
Calculation: subtract(3.57, 0.95)
the following performance graph shows the cumulative total return to a holder of the company 2019s common stock , assuming dividend reinvestment , compared with the cumulative total return , assuming dividend reinvestment , of the standard & poor ( "s&p" ) 500 index and the dow jones us financials index during the period from december 31 , 2009 through december 31 , 2014. .

Table: 12/09 12/10 12/11 12/12 12/13 12/14 e*trade financial corporation 100.00 90.91 45.23 50.85 111.59 137.81 s&p 500 index 100.00 115.06 117.49 136.30 180.44 205.14 dow jones us financials index 100.00 112.72 98.24 124.62 167.26 191.67

table of contents .

Question: what was the total return percentage for e*trade financial corporation for the five years ended 12/14?
Answer: 37.81%
Calculation: divide(subtract(137.81, const_100), const_100)
part ii item 5 . market for registrant 2019s common equity , related stockholder matters and issuer purchases of equity securities the following table presents reported quarterly high and low per share sale prices of our common stock on the new york stock exchange ( 201cnyse 201d ) for the years 2010 and 2009. .

Table: 2010 high low quarter ended march 31 $ 44.61 $ 40.10 quarter ended june 30 45.33 38.86 quarter ended september 30 52.11 43.70 quarter ended december 31 53.14 49.61 2009 high low quarter ended march 31 $ 32.53 $ 25.45 quarter ended june 30 34.52 27.93 quarter ended september 30 37.71 29.89 quarter ended december 31 43.84 35.03

on february 11 , 2011 , the closing price of our common stock was $ 56.73 per share as reported on the nyse . as of february 11 , 2011 , we had 397612895 outstanding shares of common stock and 463 registered holders . dividends we have not historically paid a dividend on our common stock . payment of dividends in the future , when , as and if authorized by our board of directors , would depend upon many factors , including our earnings and financial condition , restrictions under applicable law and our current and future loan agreements , our debt service requirements , our capital expenditure requirements and other factors that our board of directors may deem relevant from time to time , including the potential determination to elect reit status . in addition , the loan agreement for our revolving credit facility and term loan contain covenants that generally restrict our ability to pay dividends unless certain financial covenants are satisfied . for more information about the restrictions under the loan agreement for the revolving credit facility and term loan , our notes indentures and the loan agreement related to our securitization , see item 7 of this annual report under the caption 201cmanagement 2019s discussion and analysis of financial condition and results of operations 2014liquidity and capital resources 2014factors affecting sources of liquidity 201d and note 6 to our consolidated financial statements included in this annual report. .

Question: on february 112011 what was the market capitalization
Answer: 22556579533.3
Calculation: multiply(397612895, 56.73)
entergy corporation and subsidiaries management's financial discussion and analysis the decrease in interest income in 2002 was primarily due to : fffd interest recognized in 2001 on grand gulf 1's decommissioning trust funds resulting from the final order addressing system energy's rate proceeding ; fffd interest recognized in 2001 at entergy mississippi and entergy new orleans on the deferred system energy costs that were not being recovered through rates ; and fffd lower interest earned on declining deferred fuel balances . the decrease in interest charges in 2002 is primarily due to : fffd a decrease of $ 31.9 million in interest on long-term debt primarily due to the retirement of long-term debt in late 2001 and early 2002 ; and fffd a decrease of $ 76.0 million in other interest expense primarily due to interest recorded on system energy's reserve for rate refund in 2001 . the refund was made in december 2001 . 2001 compared to 2000 results for the year ended december 31 , 2001 for u.s . utility were also affected by an increase in interest charges of $ 61.5 million primarily due to : fffd the final ferc order addressing the 1995 system energy rate filing ; fffd debt issued at entergy arkansas in july 2001 , at entergy gulf states in june 2000 and august 2001 , at entergy mississippi in january 2001 , and at entergy new orleans in july 2000 and february 2001 ; and fffd borrowings under credit facilities during 2001 , primarily at entergy arkansas . non-utility nuclear the increase in earnings in 2002 for non-utility nuclear from $ 128 million to $ 201 million was primarily due to the operation of indian point 2 and vermont yankee , which were purchased in september 2001 and july 2002 , respectively . the increase in earnings in 2001 for non-utility nuclear from $ 49 million to $ 128 million was primarily due to the operation of fitzpatrick and indian point 3 for a full year , as each was purchased in november 2000 , and the operation of indian point 2 , which was purchased in september 2001 . following are key performance measures for non-utility nuclear: .

Table: 2002 2001 2000 net mw in operation at december 31 3955 3445 2475 generation in gwh for the year 29953 22614 7171 capacity factor for the year 93% ( 93 % ) 93% ( 93 % ) 94% ( 94 % )

2002 compared to 2001 the following fluctuations in the results of operations for non-utility nuclear in 2002 were primarily caused by the acquisitions of indian point 2 and vermont yankee ( except as otherwise noted ) : fffd operating revenues increased $ 411.0 million to $ 1.2 billion ; fffd other operation and maintenance expenses increased $ 201.8 million to $ 596.3 million ; fffd depreciation and amortization expenses increased $ 25.1 million to $ 42.8 million ; fffd fuel expenses increased $ 29.4 million to $ 105.2 million ; fffd nuclear refueling outage expenses increased $ 23.9 million to $ 46.8 million , which was due primarily to a .

Question: what was the percent of the increase in non-utility nuclear earnings in 2002
Answer: 57%
Calculation: divide(subtract(201, 128), 128)