sharick008/convfinqa huggingface dataset:
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 ) 2006 2005 2004 sales and transfers of oil and gas produced , net of production , transportation and administrative costs $ ( 5312 ) $ ( 3754 ) $ ( 2689 ) net changes in prices and production , transportation and administrative costs related to future production ( 1342 ) 6648 771 .

2006: sales and transfers of oil and gas produced net of production transportation and administrative costs: -5312
net changes in prices and production transportation and administrative costs related to future production: -1342
extensions discoveries and improved recovery less related costs: 1290
development costs incurred during the period: 1251
changes in estimated future development costs: -527
revisions of previous quantity estimates: 1319
net changes in purchases and sales of minerals in place: 30
accretion of discount: 1882
net change in income taxes: -660
timing and other: -14
net change for the year: -2083
beginning of year: 10601
end of year: 8518
net change for the year from discontinued operations: -216
2005: sales and transfers of oil and gas produced net of production transportation and administrative costs: -3754
net changes in prices and production transportation and administrative costs related to future production: 6648
extensions discoveries and improved recovery less related costs: 700
development costs incurred during the period: 1030
changes in estimated future development costs: -552
revisions of previous quantity estimates: 820
net changes in purchases and sales of minerals in place: 4557
accretion of discount: 1124
net change in income taxes: -6694
timing and other: 307
net change for the year: 4186
beginning of year: 6415
end of year: 10601
net change for the year from discontinued operations: 162
2004: sales and transfers of oil and gas produced net of production transportation and administrative costs: -2689
net changes in prices and production transportation and administrative costs related to future production: 771
extensions discoveries and improved recovery less related costs: 1349
development costs incurred during the period: 609
changes in estimated future development costs: -628
revisions of previous quantity estimates: 948
net changes in purchases and sales of minerals in place: 33
accretion of discount: 757
net change in income taxes: -627
timing and other: 97
net change for the year: 620
beginning of year: 5795
end of year: 6415
net change for the year from discontinued operations: -152

.

Questions:
what was the cash flow balance at the end of 2006?
what was the balance at the start of the year?
what is the ratio of the balance at the end of the year to the start?
what was the cash flow balance at the end of 2006?
what is the value at the end of 2006 multiplied by the ratio of the balances?

Answers:
8518
10601
80.4%
8518
6844
system energy resources , inc . management 2019s financial discussion and analysis also in addition to the contractual obligations , system energy has $ 382.3 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions . see note 3 to the financial statements for additional information regarding unrecognized tax benefits . in addition to routine spending to maintain operations , the planned capital investment estimate includes specific investments and initiatives such as the nuclear fleet operational excellence initiative , as discussed below in 201cnuclear matters , 201d and plant improvements . as a wholly-owned subsidiary , system energy dividends its earnings to entergy corporation at a percentage determined monthly . sources of capital system energy 2019s sources to meet its capital requirements include : 2022 internally generated funds ; 2022 cash on hand ; 2022 debt issuances ; and 2022 bank financing under new or existing facilities . system energy may refinance , redeem , or otherwise retire debt prior to maturity , to the extent market conditions and interest and dividend rates are favorable . all debt and common stock issuances by system energy require prior regulatory approval . debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements . system energy has sufficient capacity under these tests to meet its foreseeable capital needs . system energy 2019s receivables from the money pool were as follows as of december 31 for each of the following years. .

2015: ( in thousands ): ( in thousands )
$ 33809: 39926
2014: ( in thousands ): ( in thousands )
$ 33809: 2373
2013: ( in thousands ): ( in thousands )
$ 33809: 9223

see note 4 to the financial statements for a description of the money pool . the system energy nuclear fuel company variable interest entity has a credit facility in the amount of $ 120 million scheduled to expire in may 2019 . as of december 31 , 2016 , $ 66.9 million in letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the system energy nuclear fuel company variable interest entity . see note 4 to the financial statements for additional discussion of the variable interest entity credit facility . system energy obtained authorizations from the ferc through october 2017 for the following : 2022 short-term borrowings not to exceed an aggregate amount of $ 200 million at any time outstanding ; 2022 long-term borrowings and security issuances ; and 2022 long-term borrowings by its nuclear fuel company variable interest entity . see note 4 to the financial statements for further discussion of system energy 2019s short-term borrowing limits. .

Questions:
what is the net change in value of the system energy 2019s receivable from the money pool from 2015 to 2016?
what is the percent change?

Answers:
-6117
-15.3%
entergy louisiana , llc and subsidiaries management 2019s financial discussion and analysis plan to spin off the utility 2019s transmission business see the 201cplan to spin off the utility 2019s transmission business 201d section of entergy corporation and subsidiaries management 2019s financial discussion and analysis for a discussion of this matter , including the planned retirement of debt and preferred securities . results of operations net income 2011 compared to 2010 net income increased $ 242.5 million primarily due to a settlement with the irs related to the mark-to-market income tax treatment of power purchase contracts , which resulted in a $ 422 million income tax benefit . the net income effect was partially offset by a $ 199 million regulatory charge , which reduced net revenue , because a portion of the benefit will be shared with customers . see note 3 to the financial statements for additional discussion of the settlement and benefit sharing . 2010 compared to 2009 net income decreased slightly by $ 1.4 million primarily due to higher other operation and maintenance expenses , a higher effective income tax rate , and higher interest expense , almost entirely offset by higher net revenue . net revenue 2011 compared to 2010 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 2011 to 2010 . amount ( in millions ) .

amount ( in millions ): 2010 net revenue: 1043.7
mark-to-market tax settlement sharing: -195.9
retail electric price: 32.5
volume/weather: 11.6
other: -5.7
2011 net revenue: 886.2

the mark-to-market tax settlement sharing variance results from a regulatory charge because a portion of the benefits of a settlement with the irs related to the mark-to-market income tax treatment of power purchase contracts will be shared with customers , slightly offset by the amortization of a portion of that charge beginning in october 2011 . see notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing . the retail electric price variance is primarily due to a formula rate plan increase effective may 2011 . see note 2 to the financial statements for discussion of the formula rate plan increase. .

Questions:
what was the difference in net revenue from 2010 to 2011?
what was the percent change?

Answers:
-157.5
15.1%
condition are valued using a monte carlo model . expected volatility is based on historical volatilities of traded common stock of the company and comparative companies using daily stock prices over the past three years . the expected term is three years and the risk-free interest rate is based on the three-year u.s . treasury rate in effect as of the measurement date . the following table provides the weighted average assumptions used in the monte carlo simulation and the weighted average grant date fair values of psus granted for the years ended december 31: .

2018: expected volatility: -17.23
risk-free interest rate: -2.36
expected life ( years ): 3
grant date fair value per share: 73.62
2017: expected volatility: -17.4
risk-free interest rate: -1.53
expected life ( years ): 3
grant date fair value per share: 72.81
2016: expected volatility: -15.9
risk-free interest rate: -0.91
expected life ( years ): 3
grant date fair value per share: 77.16

the grant date fair value of psus that vest ratably and have market and/or performance conditions are amortized through expense over the requisite service period using the graded-vesting method . if dividends are paid with respect to shares of the company 2019s common stock before the rsus and psus are distributed , the company credits a liability for the value of the dividends that would have been paid if the rsus and psus were shares of company common stock . when the rsus and psus are distributed , the company pays the participant a lump sum cash payment equal to the value of the dividend equivalents accrued . the company accrued dividend equivalents totaling $ 1 million , less than $ 1 million and $ 1 million to accumulated deficit in the accompanying consolidated statements of changes in shareholders 2019 equity for the years ended december 31 , 2018 , 2017 and 2016 , respectively . employee stock purchase plan the company maintains a nonqualified employee stock purchase plan ( the 201cespp 201d ) through which employee participants may use payroll deductions to acquire company common stock at a discount . prior to february 5 , 2019 , the purchase price of common stock acquired under the espp was the lesser of 90% ( 90 % ) of the fair market value of the common stock at either the beginning or the end of a three -month purchase period . on july 27 , 2018 , the espp was amended , effective february 5 , 2019 , to permit employee participants to acquire company common stock at 85% ( 85 % ) of the fair market value of the common stock at the end of the purchase period . as of december 31 , 2018 , there were 1.9 million shares of common stock reserved for issuance under the espp . the espp is considered compensatory . during the years ended december 31 , 2018 , 2017 and 2016 , the company issued 95 thousand , 93 thousand and 93 thousand shares , respectively , under the espp. .

Questions:
what was the net change in the grant date fair value per share from 2017 to 2018?
what was the value in 2017?
what is the percent change?

Answers:
0.81
72.81
1.1%
notes to consolidated financial statements ( continued ) note 2 2014financial instruments ( continued ) covered by collateral , third-party flooring arrangements , or credit insurance are outstanding with the company 2019s distribution and retail channel partners . one customer accounted for approximately 11% ( 11 % ) of trade receivables as of september 29 , 2007 , while no customers accounted for more than 10% ( 10 % ) of trade receivables as of september 30 , 2006 . the following table summarizes the activity in the allowance for doubtful accounts ( in millions ) : september 29 , september 30 , september 24 , 2007 2006 2005 .

september 29 2007: beginning allowance balance: 52
charged to costs and expenses: 12
deductions: -17
ending allowance balance: 47
september 30 2006: beginning allowance balance: 46
charged to costs and expenses: 17
deductions: -11
ending allowance balance: 52
september 24 2005: beginning allowance balance: 47
charged to costs and expenses: 8
deductions: -9
ending allowance balance: 46

vendor non-trade receivables the company has non-trade receivables from certain of its manufacturing vendors resulting from the sale of raw material components to these manufacturing vendors who manufacture sub-assemblies or assemble final products for the company . the company purchases these raw material components directly from suppliers . these non-trade receivables , which are included in the consolidated balance sheets in other current assets , totaled $ 2.4 billion and $ 1.6 billion as of september 29 , 2007 and september 30 , 2006 , respectively . the company does not reflect the sale of these components in net sales and does not recognize any profits on these sales until the products are sold through to the end customer at which time the profit is recognized as a reduction of cost of sales . derivative financial instruments the company uses derivatives to partially offset its business exposure to foreign exchange risk . foreign currency forward and option contracts are used to offset the foreign exchange risk on certain existing assets and liabilities and to hedge the foreign exchange risk on expected future cash flows on certain forecasted revenue and cost of sales . the company 2019s accounting policies for these instruments are based on whether the instruments are designated as hedge or non-hedge instruments . the company records all derivatives on the balance sheet at fair value. .

Questions:
what is the ending allowance balance in 2006?
what about in 2005?
what is the net change?
what percentage change does this represent?
what is the value of non-trade receivables in 2007?
what about in 2006?
what is the net change?

Answers:
52
46
6
13%
2.4
1.6
0.8
item 2 : properties information concerning applied 2019s properties is set forth below: .

united states: owned: 4530
leased: 1037
total: 5567
other countries: owned: 2417
leased: 1341
total: 3758
total: owned: 6947
leased: 2378
total: 9325

because of the interrelation of applied 2019s operations , properties within a country may be shared by the segments operating within that country . the company 2019s headquarters offices are in santa clara , california . products in semiconductor systems are manufactured in santa clara , california ; austin , texas ; gloucester , massachusetts ; kalispell , montana ; rehovot , israel ; and singapore . remanufactured equipment products in the applied global services segment are produced primarily in austin , texas . products in the display and adjacent markets segment are manufactured in alzenau , germany and tainan , taiwan . other products are manufactured in treviso , italy . applied also owns and leases offices , plants and warehouse locations in many locations throughout the world , including in europe , japan , north america ( principally the united states ) , israel , china , india , korea , southeast asia and taiwan . these facilities are principally used for manufacturing ; research , development and engineering ; and marketing , sales and customer support . applied also owns a total of approximately 269 acres of buildable land in montana , texas , california , israel and italy that could accommodate additional building space . applied considers the properties that it owns or leases as adequate to meet its current and future requirements . applied regularly assesses the size , capability and location of its global infrastructure and periodically makes adjustments based on these assessments. .

Questions:
what portion of the total area the company uses is owned by them?
and what is that ratio only for facilities in the us?

Answers:
74.5%
81.4%
entergy gulf states , inc . management's financial discussion and analysis .

( in millions ): 2002 net revenue: 1130.7
volume/weather: 17.8
fuel write-offs in 2002: 15.3
net wholesale revenue: 10.2
base rate decreases: -23.3
nisco gain recognized in 2002: -15.2
rate refund provisions: -11.3
other: -14.1
2003 net revenue: 1110.1

the volume/weather variance was due to higher electric sales volume in the service territory . billed usage increased a total of 517 gwh in the residential and commercial sectors . the increase was partially offset by a decrease in industrial usage of 470 gwh due to the loss of two large industrial customers to cogeneration . the customers accounted for approximately 1% ( 1 % ) of entergy gulf states' net revenue in 2002 . in 2002 , deferred fuel costs of $ 8.9 million related to a texas fuel reconciliation case were written off and $ 6.5 million in expense resulted from an adjustment in the deregulated asset plan percentage as the result of a power uprate at river bend . the increase in net wholesale revenue was primarily due to an increase in sales volume to municipal and co- op customers and also to affiliated systems related to entergy's generation resource planning . the base rate decreases were effective june 2002 and january 2003 , both in the louisiana jurisdiction . the january 2003 base rate decrease of $ 22.1 million had a minimal impact on net income due to a corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting to reflect an assumed extension of river bend's useful life . in 2002 , a gain of $ 15.2 million was recognized for the louisiana portion of the 1988 nelson units 1 and 2 sale . entergy gulf states received approval from the lpsc to discontinue applying amortization of the gain against recoverable fuel , resulting in the recognition of the deferred gain in income . rate refund provisions caused a decrease in net revenue due to additional provisions recorded in 2003 compared to 2002 for potential rate actions and refunds . gross operating revenues and fuel and purchased power expenses gross operating revenues increased primarily due to an increase of $ 440.2 million in fuel cost recovery revenues as a result of higher fuel rates in both the louisiana and texas jurisdictions . fuel and purchased power expenses increased $ 471.1 million due to an increase in the market prices of natural gas and purchased power . other income statement variances 2004 compared to 2003 other operation and maintenance expenses decreased primarily due to : 2022 voluntary severance program accruals of $ 22.5 million in 2003 ; and 2022 a decrease of $ 4.3 million in nuclear material and labor costs due to reduced staff in 2004. .

Questions:
what was the net revenue in 2002, in millions?
and what was it in 2003, also in millions?
what was, then, the change in net revenue over the year?
and what was the increase in fuel cost recovery revenues in that same period?
how much, then, does this increase represent in relation to the that change in net revenue, in percentage?

Answers:
1130.7
1110.1
20.6
440.2
2137%
shareowner return performance graph the following performance graph and related information shall not be deemed 201csoliciting material 201d or to be 201cfiled 201d with the sec , nor shall such information be incorporated by reference into any future filing under the securities act of 1933 or securities exchange act of 1934 , each as amended , except to the extent that the company specifically incorporates such information by reference into such filing . the following graph shows a five year comparison of cumulative total shareowners 2019 returns for our class b common stock , the standard & poor 2019s 500 index , and the dow jones transportation average . the comparison of the total cumulative return on investment , which is the change in the quarterly stock price plus reinvested dividends for each of the quarterly periods , assumes that $ 100 was invested on december 31 , 2010 in the standard & poor 2019s 500 index , the dow jones transportation average , and our class b common stock. .

12/31/2010: united parcel service inc .: 100
standard & poor 2019s 500 index: 100
dow jones transportation average: 100
12/31/2011: united parcel service inc .: 103.88
standard & poor 2019s 500 index: 102.11
dow jones transportation average: 100.01
12/31/2012: united parcel service inc .: 107.87
standard & poor 2019s 500 index: 118.43
dow jones transportation average: 107.49
12/31/2013: united parcel service inc .: 158.07
standard & poor 2019s 500 index: 156.77
dow jones transportation average: 151.97
12/31/2014: united parcel service inc .: 171.77
standard & poor 2019s 500 index: 178.22
dow jones transportation average: 190.08
12/31/2015: united parcel service inc .: 160.61
standard & poor 2019s 500 index: 180.67
dow jones transportation average: 158.23

.

Questions:
what is the difference between the united parcel service inc. share price of 12/31/2015 and that of 12/31/2010?
how much does that difference represents in relation to the united parcel service inc. share price of 12/31/2010?
what is the standard & poor 2019s 500 index of 12/31/2015?
what is the difference between that and that of 12/31/2010?
how much does that difference represents in relation to the standard & poor 2019s 500 index of 12/31/2010?
what is the difference between the answer a1 and the answer a3?

Answers:
60.61
60.61%
180.67
80.67
80.67%
-20.06%