Answer: 0.62946

Question: what is the money pool activity use of operating cash flows as a percentage of receivables from the money pool in 2003?

Context:
System Energy Resources, Inc.  Management's Financial Discussion and Analysis 269 Operating Activities Cash flow from operations increased by $232.1 million in 2004 primarily due to income tax refunds of $70.6 million in 2004 compared to income tax payments of $230.9 million in 2003. The increase was partially offset by money pool activity, as discussed below. In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $430 million deduction for System Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. Cash flow from operations decreased by $124.8 million in 2003 primarily due to the following: ? an increase in federal income taxes paid of $74.0 million in 2003 compared to 2002; ? the cessation of the Entergy Mississippi GGART. System Energy collected $21.7 million in 2003 and $40.8 million in 2002 from Entergy Mississippi in conjunction with the GGART, which provided for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligation. The MPSC authorized cessation of the GGART effective July 1, 2003. See Note 2 to the domestic utility companies and System Energy financial statements for further discussion of the GGART; and ? money pool activity, as discussed below. System Energy's receivables from the money pool were as follows as of December 31 for each of the following years:

2004	2003	2002	2001

(In Thousands)

$61,592	$19,064	$7,046	$13,853

 Money pool activity used $42.5 million of System Energy's operating cash flows in 2004, used $12.0 million in 2003, and provided $6.8 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool. Investing Activities Net cash used for investing activities was practically unchanged in 2004 compared to 2003 primarily because an increase in construction expenditures caused by a reclassification of inventory items to capital was significantly offset by the maturity of $6.5 million of other temporary investments that had been made in 2003, which provided cash in 2004. The increase of $16.2 million in net cash used in investing activities in 2003 was primarily due to the following: ? the maturity in 2002 of $22.4 million of other temporary investments that had been made in 2001, which provided cash in 2002; ? an increase in decommissioning trust contributions and realized change in trust assets of $8.2 million in 2003 compared to 2002; and ? other temporary investments of $6.5 million made in 2003. Partially offsetting the increases in net cash used in investing activities was a decrease in construction expenditures of $22.1 million in 2003 compared to 2002 primarily due to the power uprate project in 2002. Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis 25 proposed in the Initial Decision are arbitrary and are so complex that they would be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALJ's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. An assessment of the potential effects of the ALJ's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009:

	Range of Annual Paymentsor (Receipts)	Average AnnualPayments or (Receipts)for 2005-2009 Period

	(In Millions)	(In Millions)

Entergy Arkansas	$154 to $281	$215

Entergy Gulf States	-$130 to ($15)	-$63

Entergy Louisiana	-$199 to ($98)	-$141

Entergy Mississippi	-$16 to $8	$1

Entergy New Orleans	-$17 to ($5)	-$12

 Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation. In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC ALJ's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis 30 whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005. Federal Legislation Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the United States Congress for the past several years. In the last Congress, both the House and Senate passed separate versions of comprehensive energy legislation, negotiated a conference package, and fell two votes short of bringing the conferenced bill up for a vote in the Senate. The bill contained electricity provisions that would, among other things, allow for participant funding of transmission interconnections and upgrades, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide the FERC with new authority over utility mergers and acquisitions, and codify the FERC's authority over market- based rates. It is expected that the United States House and Senate will again craft and consider energy legislation in the 109th Congress. Market and Credit Risks Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Entergy is exposed to the following significant market risks: ? The commodity price risk associated with Entergy's Non-Utility Nuclear and Energy Commodity Services segments.  ? The foreign currency exchange rate risk associated with certain of Entergy's contractual obligations.  ? The interest rate and equity price risk associated with Entergy's investments in decommissioning trust funds. Entergy is also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Where it is a significant consideration, counterparty credit risk is addressed in the discussions that follow. Commodity Price Risk Power Generation The sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Entergy's Non-Utility Nuclear business has entered into PPAs and other contracts to sell the power produced by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:

	 2005	 2006	 2007	 2008	 2009

 Non-Utility Nuclear:

Percent of planned generation sold forward:

Unit-contingent	36%	20%	17%	1%	0%

Unit-contingent with availability guarantees	54%	52%	38%	25%	0%

Firm liquidated damages	4%	4%	2%	0%	0%

Total	94%	76%	57%	26%	0%

Planned generation (TWh)	34	35	34	34	35

Average contracted price per MWh	$39	$41	$42	$44	N/A

 Entergy Corporation Notes to Consolidated Financial Statements 82 Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U. S.  Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million, and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax as a result of a one-time cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset for certain of its domestic utility companies and System Energy of $86.9 million as of December 31, 2004 and $72.4 million as of December 31, 2003 to reflect an estimate of incurred but uncollected removal costs previously recorded as a component of accumulated depreciation. The decommissioning and retirement cost liability for certain of the domestic utility companies and System Energy includes a regulatory liability of $34.6 million as of December 31, 2004 and $26.8 million as of December 31, 2003 representing an estimate of collected but not yet incurred removal costs. For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of $595 million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings in 2003 of $155 million net-of-tax as a result of a one-time cumulative effect of accounting change. The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy were as follows:


Answer: 4.64711

Question: In the years with lowest amount of Operating lease obligations in table 1, what's the increasing rate of Pension and other postretirement cash requirements in table 1?

Context:
Revenues N&SS revenues decreased 1% in 2008 and 2% in 2007. The decrease of $137 million in 2008 is primarily due to decreased revenues in FCS, Proprietary and satellite programs partially offset by increased revenues in the SBInet program. The decrease of $292 million in 2007 was primarily due to the exclusion of government Delta volume, now a component of our equity investment in ULA and lower FCS volume, partially offset by increased volume on SBInet and several satellite programs. Delta launch and new-build satellite deliveries were as follows:

Years ended December 31,	 2008	2007	2006

Delta II Commercial	 2	3

Delta II Government			2

Delta IV Government			3

Satellites	 1	4	4

 Delta government launches are excluded from our deliveries after December 1, 2006 due to the formation of ULA. Operating Earnings N&SS operating earnings increased by $171 million in 2008 was primarily due to increased earnings from our investment in ULA. The decrease in 2007 was due to lower earnings on FCS and several satellite programs. These decreases were partially offset by higher award fees on GMD and a $44 million gain on sale of a property in Anaheim. N&SS operating earnings include equity earnings of $73 million, $85 million and $71 million from the United Space Alliance joint venture in 2008, 2007, and 2006, respectively and equity earnings of $105 million, a loss of $11 million and equity earnings of $5 million from the ULA joint venture in 2008, 2007 and 2006, respectively. The ULA equity earnings and loss amounts are net of the basis difference amortization. Research and Development The N&SS research and development funding remains focused on the development of communications, command and control, computers, intelligence, surveillance and reconnaissance systems (C4ISR); communications and command and control (C3) capabilities that support a network-enabled architecture approach for our various government customers. We are investing in communications capabilities to enable connectivity between existing air/ground platforms, increase communications availability and bandwidth through more robust space systems, and leverage innovative communications concepts. Key programs in this area include JTRS, FCS, Global Positioning System, Tracking and Data Relay Satellite, Ares 1 Crew Launch Vehicle and GMD. Investments were also made to support concepts that may lead to the development of next-generation space intelligence systems. Along with increased funding to support these areas of architecture and network-enabled capabilities development, we also maintained our investment levels in global missile defense and advanced missile defense concepts and technologies. Backlog N&SS total backlog decreased by 12% in 2008 compared with 2007 primarily due to revenues recognized on multi-year orders received in prior years on FCS, GMD and C3 programs, partially offset by an increase in the International Space Station program. Total backlog decreased by 7% in 2007 compared with 2006 due to revenues recognized on FCS and Proprietary programs, partially offset by an increase in Space Exploration programs. Additional Considerations Items which could have a future impact on N&SS operations include the following: United Launch Alliance On December 1, 2006, we completed the transaction with Lockheed Martin Corporation (Lockheed) to create a 50/50 joint venture named United Launch Alliance L. L. C.  (ULA). ULA combines the production, engineering, test and launch operations associated with U. S.  government launches of Boeing Delta and Lockheed Atlas rockets. In connection with the transaction, billion of unused borrowing on revolving credit line agreements. We anticipate that these credit lines will primarily serve as backup liquidity to support our general corporate borrowing needs. Financing commitments totaled $18.1 billion and $15.9 billion as of December 31, 2012 and 2011. We anticipate that we will not be required to fund a significant portion of our financing commitments as we continue to work with third party financiers to provide alternative financing to customers. Historically, we have not been required to fund significant amounts of outstanding commitments. However, there can be no assurances that we will not be required to fund greater amounts than historically required. In the event we require additional funding to support strategic business opportunities, our commercial aircraft financing commitments, unfavorable resolution of litigation or other loss contingencies, or other business requirements, we expect to meet increased funding requirements by issuing commercial paper or term debt. We believe our ability to access external capital resources should be sufficient to satisfy existing short-term and long-term commitments and plans, and also to provide adequate financial flexibility to take advantage of potential strategic business opportunities should they arise within the next year. However, there can be no assurance of the cost or availability of future borrowings, if any, under our commercial paper program, in the debt markets or our credit facilities. At December 31, 2012 and 2011, our pension plans were $19.7 billion and $16.6 billion underfunded as measured under GAAP. On an ERISA basis our plans are more than 100% funded at December 31, 2012 with minimal required contributions in 2013. We expect to make discretionary contributions to our plans of approximately $1.5 billion in 2013. We may be required to make higher contributions to our pension plans in future years. As of December 31, 2012, we were in compliance with the covenants for our debt and credit facilities. The most restrictive covenants include a limitation on mortgage debt and sale and leaseback transactions as a percentage of consolidated net tangible assets (as defined in the credit agreements), and a limitation on consolidated debt as a percentage of total capital (as defined). When considering debt covenants, we continue to have substantial borrowing capacity. Contractual Obligations The following table summarizes our known obligations to make future payments pursuant to certain contracts as of December 31, 2012, and the estimated timing thereof.

(Dollars in millions)	Total	Lessthan 1year	1-3years	3-5years	After 5years

Long-term debt (including current portion)	$10,251	$1,340	$2,147	$1,095	$5,669

Interest on debt-1	6,177	510	864	749	4,054

Pension and other postretirement cash requirements	25,558	579	1,244	7,025	16,710

Capital lease obligations	184	102	78	4

Operating lease obligations	1,405	218	334	209	644

Purchase obligations not recorded on the Consolidated Statements of Financial Position	118,002	44,472	41,838	18,956	12,736

Purchase obligations recorded on the Consolidated Statements of Financial Position	15,981	14,664	1,307	1	9

Total contractual obligations	$177,558	$61,885	$47,812	$28,039	$39,822

 (1) Includes interest on variable rate debt calculated based on interest rates at December 31, 2012. Variable rate debt was less than 1% of our total debt at December 31, 2012. Industry Competitiveness The commercial jet airplane market and the airline industry remain extremely competitive. Market liberalization in Europe, the Middle East and Asia is enabling low-cost airlines to continue gaining market share. These airlines are increasing the pressure on airfares. This results in continued cost pressures for all airlines and price pressure on our products. Major productivity gains are essential to ensure a favorable market position at acceptable profit margins. Continued access to global markets remains vital to our ability to fully realize our sales potential and longterm investment returns. Approximately 91% of Commercial Airplanes’ total backlog, in dollar terms, is with non-U. S.  airlines. We face aggressive international competitors who are intent on increasing their market share. They offer competitive products and have access to most of the same customers and suppliers. With government support,Airbus has historically invested heavily to create a family of products to compete with ours. Regional jet makers Embraer and Bombardier continue to develop and market larger and increasingly more capable airplanes, including Embraer’s E-195 in the regional jet market and Bombardier’s C Series in the 100-150 seat transcontinental market. Additionally, other competitors from Russia, China and Japan are developing commercial jet aircraft. Some of these competitors have historically enjoyed access to governmentprovided financial support, including “launch aid,” which greatly reduces the cost and commercial risks associated with airplane development activities. This has enabled the development of airplanes without commercial viability; others to be brought to market more quickly than otherwise possible; and many offered for sale below market-based prices. Many competitors have continued to make improvements in efficiency, which may result in funding product development, gaining market share and improving earnings. This market environment has resulted in intense pressures on pricing and other competitive factors, and we expect these pressures to continue or intensify in the coming years. We are focused on improving our products and services and continuing our cost-reduction efforts, which enhances our ability to compete. We are also focused on taking actions to ensure that Boeing is not harmed by unfair subsidization of competitors. Results of Operations

Years ended December 31,	2017	2016	2015

Revenues	$56,729	$58,012	$59,399

% of total company revenues	61%	61%	62%

Earnings from operations	$5,432	$1,995	$4,284

Operating margins	9.6%	3.4%	7.2%

Research and development	$2,247	$3,706	$2,311

 Revenues Commercial Airplanes revenues decreased by $1,283 million or 2% in 2017 compared with 2016 due to delivery mix, with fewer twin aisle deliveries more than offsetting the impact of higher single aisle deliveries. Commercial Airplanes revenues decreased by $1,387 million or 2% in 2016 compared with 2015 primarily due to fewer deliveries. Through February 25, 2016, we repurchased approximately $415.0 million of shares of our common stock, which includes the $250.0 million of shares that we repurchased from certain selling stockholders on February 10, 2016. In order to achieve operational synergies, we expect cash outlays related to our integration plans to be approximately $290.0 million in 2016. These cash outlays are necessary to achieve our integration goals of net annual pre-tax operating profit synergies of $350.0 million by the end of the third year post-Closing Date. Also as discussed in Note 20 to our consolidated financial statements, as of December 31, 2015, a short-term liability of $50.0 million and long-term liability of $264.6 million related to Durom Cup product liability claims was recorded on our consolidated balance sheet. We expect to continue paying these claims over the next few years. We expect to be reimbursed a portion of these payments for product liability claims from insurance carriers. As of December 31, 2015, we have received a portion of the insurance proceeds we estimate we will recover. We have a long-term receivable of $95.3 million remaining for future expected reimbursements from our insurance carriers. We also had a short-term liability of $33.4 million related to Biomet metal-on-metal hip implant claims. At December 31, 2015, we had ten tranches of senior notes outstanding as follows (dollars in millions):


Answer: 319.0

Question: The total amount of which section ranks first for Years Ended December 31, for Credit loss impairments? (in million)

Context:
Shares of common stock issued, in treasury, and outstanding were (in thousands of shares):

	Shares Issued	Treasury Shares	Shares Outstanding

Balance at December 29, 2013	376,832	—	376,832

Exercise of stock options, issuance of other stock awards, and other	178	—	178

Balance at December 28, 2014	377,010	—	377,010

Exercise of warrants	20,480	—	20,480

Issuance of common stock to Sponsors	221,666	—	221,666

Acquisition of Kraft Foods Group, Inc.	592,898	—	592,898

Exercise of stock options, issuance of other stock awards, and other	2,338	-413	1,925

Balance at January 3, 2016	1,214,392	-413	1,213,979

Exercise of stock options, issuance of other stock awards, and other	4,555	-2,058	2,497

Balance at December 31, 2016	1,218,947	-2,471	1,216,476

 Note 13.  Financing Arrangements We routinely enter into accounts receivable securitization and factoring programs . We account for transfers of receivables pursuant to these programs as a sale and remove them from our consolidated balance sheet. At December 31, 2016 , our most significant program in place was the U. S.  securitization program, which was amended in May 2016 and originally entered into in October of 2015. Under the program, we are entitled to receive cash consideration of up to $800 million (which we elected to reduce to $500 million , effective February 21, 2017) and a receivable for the remainder of the purchase price (the “Deferred Purchase Price”). This securitization program utilizes a bankruptcyremote special-purpose entity (“SPE”). The SPE is wholly-owned by a subsidiary of Kraft Heinz and its sole business consists of the purchase or acceptance, through capital contributions of receivables and related assets, from a Kraft Heinz subsidiary and subsequent transfer of such receivables and related assets to a bank. Although the SPE is included in our consolidated financial statements, it is a separate legal entity with separate creditors who will be entitled, upon its liquidation, to be satisfied out of the SPE's assets prior to any assets or value in the SPE becoming available to Kraft Heinz or its subsidiaries. The assets of the SPE are not available to pay creditors of Kraft Heinz or its subsidiaries. This program expires in May 2017. In addition to the U. S.  securitization program, we have accounts receivable factoring programs denominated in Australian dollars, New Zealand dollars, British pound sterling, euros, and Japanese yen. Under these programs, we generally receive cash consideration up to a certain limit and a receivable for the Deferred Purchase Price. There is no Deferred Purchase Price associated with the Japanese yen contract. Related to these programs, our aggregate cash consideration limit, after applying applicable hold-backs, was $245 million U. S.  dollars at December 31, 2016. Generally, each of these programs automatically renews annually until terminated by either party. The cash consideration and carrying amount of receivables removed from the consolidated balance sheets in connection with the above programs were $904 million at December 31, 2016 and $267 million at January 3, 2016 . The fair value of the Deferred Purchase Price for the programs was $129 million at December 31, 2016 and $583 million at January 3, 2016 . The Deferred Purchase Price is included in sold receivables on the consolidated balance sheets and had a carrying value which approximated its fair value at December 31, 2016 and January 3, 2016 . The proceeds from these sales are recognized on the consolidated statements of cash flows as a component of operating activities. We act as servicer for these arrangements and have not recorded any servicing assets or liabilities for these arrangements as of December 31, 2016 and January 3, 2016 because they were not material to the financial statements. PRUDENTIAL FINANCIAL, INC.  Notes to Consolidated Financial Statements The following table sets forth a rollforward of pre-tax amounts remaining in OCI related to fixed maturity securities with credit loss impairments recognized in earnings, for the periods indicated:

	Years Ended December 31,

	2018	2017

	(in millions)

Credit loss impairments:

Balance, beginning of period	$319	$359

New credit loss impairments	1	10

Additional credit loss impairments on securities previously impaired	0	11

Increases due to the passage of time on previously recorded credit losses	10	15

Reductions for securities which matured, paid down, prepaid or were sold during the period	-162	-58

Reductions for securities impaired to fair value during the period-1	-24	-13

Accretion of credit loss impairments previously recognized due to an increase in cash flows expected to be collected	-4	-5

Balance, end of period	$140	$319

 (1) Represents circumstances where the Company determined in the current period that it intends to sell the security or it is more likely than not that it will be required to sell the security before recovery of the security’s amortized cost. Assets Supporting Experience-Rated Contractholder Liabilities The following table sets forth the composition of “Assets supporting experience-rated contractholder liabilities,” as of the dates indicated:

	December 31, 2018	December 31, 2017

	AmortizedCost or Cost	FairValue	AmortizedCost or Cost	FairValue

	(in millions)

Short-term investments and cash equivalents	$215	$215	$245	$245

Fixed maturities:

Corporate securities	13,258	13,119	13,816	14,073

Commercial mortgage-backed securities	2,346	2,324	2,294	2,311

Residential mortgage-backed securities-1	828	811	961	966

Asset-backed securities-2	1,649	1,665	1,363	1,392

Foreign government bonds	1,087	1,083	1,050	1,057

U.S. government authorities and agencies and obligations of U.S. states	538	577	357	410

Total fixed maturities-3	19,706	19,579	19,841	20,209

Equity securities	1,378	1,460	1,278	1,643

Total assets supporting experience-rated contractholder liabilities-4	$21,299	$21,254	$21,364	$22,097

 (1) Includes publicly-traded agency pass-through securities and collateralized mortgage obligations. (2) Includes credit-tranched securities collateralized by sub-prime mortgages, auto loans, credit cards, education loans and other asset types. Includes collateralized loan obligations at fair value of $1,028 million and $943 million as of December 31, 2018 and 2017, respectively, all of which were rated AAA. (3) As a percentage of amortized cost, 93% and 92% of the portfolio was considered high or highest quality based on NAIC or equivalent ratings, as of December 31, 2018 and 2017, respectively. (4) As a percentage of amortized cost, 78% and 80% of the portfolio consisted of public securities as of December 31, 2018 and 2017, respectively. The net change in unrealized gains (losses) from assets supporting experience-rated contractholder liabilities still held at period end, recorded within “Other income (loss),” was $(778) million, $300 million and $75 million during the years ended December 31, 2018, 2017 and 2016, respectively. Equity Securities The net change in unrealized gains (losses) from equity securities, still held at period end, recorded within “Other income (loss),” was $(1,157) million during the year ended December 31, 2018. The net change in unrealized gains (losses) from equity securities, still held at period end, recorded within “Other comprehensive income (loss),” was $(494) million and $760 million during the years ended December 31, 2017 and 2016, respectively. Benefits and expenses increased $735 million. Excluding the impact of our annual reviews and update of assumptions and other refinements, as discussed above, benefits and expenses increased $709 million primarily driven by an increase in policyholders’ benefits, including the change in policy reserves, related to the increase in premiums discussed above. Account Values Account values are a significant driver of our operating results, and are primarily driven by net additions (withdrawals) and the impact of market changes. The income we earn on most of our fee-based products varies with the level of fee-based account values, since many policy fees are determined by these values. The investment income and interest we credit to policyholders on our spread-based products varies with the level of general account values. To a lesser extent, changes in account values impact our pattern of amortization of DAC and VOBA and general and administrative expenses. The following table shows the changes in the account values and net additions (withdrawals) of Retirement segment products for the periods indicated. Net additions (withdrawals) are plan sales and participant deposits or additions, as applicable, minus plan and participant withdrawals and benefits. Account values include both internally- and externallymanaged client balances as the total balances drive revenue for the Retirement segment. For more information on internally-managed balances, see “—PGIM. ”


Answer: 1.15

Question: what was the change in fair value of retained interests in billions as of december 2018 and december 2017?

Context:
THE GOLDMAN SACHS GROUP, INC.  AND SUBSIDIARIES Notes to Consolidated Financial Statements ‰ Purchased interests represent senior and subordinated interests, purchased in connection with secondary market-making activities, in securitization entities in which the firm also holds retained interests. ‰ Substantially all of the total outstanding principal amount and total retained interests relate to securitizations during 2014 and thereafter as of December 2018, and relate to securitizations during 2012 and thereafter as of December 2017. ‰ The fair value of retained interests was $3.28 billion as of December 2018 and $2.13 billion as of December 2017. In addition to the interests in the table above, the firm had other continuing involvement in the form of derivative transactions and commitments with certain nonconsolidated VIEs. The carrying value of these derivatives and commitments was a net asset of $75 million as of December 2018 and $86 million as of December 2017, and the notional amount of these derivatives and commitments was $1.09 billion as of December 2018 and $1.26 billion as of December 2017. The notional amounts of these derivatives and commitments are included in maximum exposure to loss in the nonconsolidated VIE table in Note 12. The table below presents information about the weighted average key economic assumptions used in measuring the fair value of mortgage-backed retained interests.

	As of December

$ in millions	2018	2017

Fair value of retained interests	$ 3,151	$2,071

Weighted average life (years)	7.2	6.0

Constant prepayment rate	11.9%	9.4%

Impact of 10% adverse change	$ -27	$ -19

Impact of 20% adverse change	$ -53	$ -35

Discount rate	4.7%	4.2%

Impact of 10% adverse change	$ -75	$ -35

Impact of 20% adverse change	$ -147	$ -70

 In the table above: ‰ Amounts do not reflect the benefit of other financial instruments that are held to mitigate risks inherent in these retained interests. ‰ Changes in fair value based on an adverse variation in assumptions generally cannot be extrapolated because the relationship of the change in assumptions to the change in fair value is not usually linear. ‰ The impact of a change in a particular assumption is calculated independently of changes in any other assumption. In practice, simultaneous changes in assumptions might magnify or counteract the sensitivities disclosed above. ‰ The constant prepayment rate is included only for positions for which it is a key assumption in the determination of fair value. ‰ The discount rate for retained interests that relate to U. S.  government agency-issued collateralized mortgage obligations does not include any credit loss. Expected credit loss assumptions are reflected in the discount rate for the remainder of retained interests. The firm has other retained interests not reflected in the table above with a fair value of $133 million and a weighted average life of 4.2 years as of December 2018, and a fair value of $56 million and a weighted average life of 4.5 years as of December 2017. Due to the nature and fair value of certain of these retained interests, the weighted average assumptions for constant prepayment and discount rates and the related sensitivity to adverse changes are not meaningful as of both December 2018 and December 2017. The firm’s maximum exposure to adverse changes in the value of these interests is the carrying value of $133 million as of December 2018 and $56 million as of December 2017. Note 12. Variable Interest Entities A variable interest in a VIE is an investment (e. g. , debt or equity) or other interest (e. g. , derivatives or loans and lending commitments) that will absorb portions of the VIE’s expected losses and/or receive portions of the VIE’s expected residual returns. The firm’s variable interests in VIEs include senior and subordinated debt; loans and lending commitments; limited and general partnership interests; preferred and common equity; derivatives that may include foreign currency, equity and/or credit risk; guarantees; and certain of the fees the firm receives from investment funds. Certain interest rate, foreign currency and credit derivatives the firm enters into with VIEs are not variable interests because they create, rather than absorb, risk. VIEs generally finance the purchase of assets by issuing debt and equity securities that are either collateralized by or indexed to the assets held by the VIE. The debt and equity securities issued by a VIE may include tranches of varying levels of subordination. The firm’s involvement with VIEs includes securitization of financial assets, as described in Note 11, and investments in and loans to other types of VIEs, as described below. See Note 11 for further information about securitization activities, including the definition of beneficial interests. See Note 3 for the firm’s consolidation policies, including the definition of a VIE. The completion factor method is used for the months of incurred claims prior to the most recent three months because the historical percentage of claims processed for those months is at a level sufficient to produce a consistently reliable result. Conversely, for the most recent three months of incurred claims, the volume of claims processed historically is not at a level sufficient to produce a reliable result, which therefore requires us to examine historical trend patterns as the primary method of evaluation. Medical cost trends potentially are more volatile than other segments of the economy. The drivers of medical cost trends include increases in the utilization of hospital and physician services, prescription drugs, and new medical technologies, as well as the inflationary effect on the cost per unit of each of these expense components. Other external factors such as government-mandated benefits or other regulatory changes, catastrophes, and epidemics also may impact medical cost trends. Additionally, as we realign our commercial strategy, we continue to reduce the level of traditional utilization management functions such as preauthorization of services, monitoring of inpatient admissions, and requirements for physician referrals. Other internal factors such as system conversions and claims processing interruptions also may impact our ability to accurately predict estimates of historical completion factors or medical cost trends. All of these factors are considered in estimating IBNR and in estimating the per member per month claims trend for purposes of determining the reserve for the most recent three months. Each of these factors requires significant judgment by management. The completion and claims per member per month trend factors are the most significant factors impacting the IBNR estimate. The following table illustrates the sensitivity of these factors and the estimated potential impact on our operating results caused by changes in these factors based on December 31, 2003 data:

Completion Factor (a):	Claims Trend Factor (b):

 (Decrease) Increase in Factor	Increase (Decrease) in Medical and Other Expenses Payable	(Decrease) Increase in Factor	Increase (Decrease) in Medical and Other Expenses Payable

(dollars in thousands)

-3%	$136,000	-3%	$-59,000

-2%	$88,000	-2%	$-41,000

-1%	$43,000	-1%	$-22,000

1%	$-40,000	1%	$14,000

2%	$-79,000	2%	$33,000

3%	$-116,000	3%	$51,000

 (a) Reflects estimated potential changes in medical and other expenses payable caused by changes in completion factors for incurred months prior to the most recent three months. (b) Reflects estimated potential changes in medical and other expenses payable caused by changes in annualized claims trend used for the estimation of per member per month incurred claims for the most recent three months. Most medical claims are paid within a few months of the member receiving service from a physician or other health care provider. As a result, these liabilities generally are described as having a “short-tail”, which causes less than 2% of our medical and other expenses payable as of the end of any given period to be outstanding for more than 12 months. As such, we expect that substantially all of the 2003 estimate of medical and other expenses payable will be known and paid during 2004. Our reserving practice is to consistently recognize the actuarial best point estimate within a level of confidence required by actuarial standards. Actuarial standards of practice generally require a level of confidence such that the liabilities established for IBNR have a greater probability of being adequate versus being insufficient, or such that the liabilities established for IBNR are sufficient to cover obligations under an assumption of moderately adverse conditions. Adverse conditions are situations in which the actual claims are TRICARE change orders occur when we perform services or incur costs under the directive of the federal government that were not originally specified in our contracts. Under federal regulations we are entitled to an equitable adjustment to the contract price, which results in additional premium revenues. Examples of items that have necessitated substantial change orders in recent years include congressionally legislated increases in the level of benefits for TRICARE beneficiaries and the administration of new government programs such as TRICARE for Life and TRICARE Senior Pharmacy. Like BPAs, we record revenue applicable to change orders when these amounts are determinable and the collectibility is reasonably assured. Unlike BPAs, where settlement only occurs at specified intervals, change orders may be negotiated and settled at any time throughout the year. Total TRICARE premium and ASO fee receivables were as follows at December 31, 2003 and 2002:

	2003	2002

	(in thousands)

TRICARE premiums receivable:

Base receivable	$254,688	$190,339

Bid price adjustments (BPAs)	92,875	104,044

Change orders	7,073	1,400

Subtotal	354,636	295,783

Less: long-term portion of BPAs	-38,794	-86,471

Total TRICARE premiums receivable	$315,842	$209,312

TRICARE ASO fees receivable:

Base receivable	$—	$7,205

Change orders	11,968	56,230

Total TRICARE ASO fees receivable	$11,968	$63,435

 Our TRICARE contracts also contain risk-sharing provisions with the federal government to minimize any losses and limit any profits in the event that medical costs for which we are at risk differ from the levels targeted in our contracts. Amounts receivable from the federal government under such risk-sharing provisions are included in the BPA receivable above, while amounts payable to the federal government under these provisions of approximately $17.3 million at December 31, 2003 are included in medical and other expenses payable in our consolidated balance sheets. Investment Securities Investment securities totaled $1,995.8 million, or 38% of total assets at December 31, 2003. Debt securities totaled $1,960.6 million, or 98% of our total investment portfolio. More than 94% of our debt securities were of investment-grade quality, with an average credit rating of AA by Standard & Poor’s at December 31, 2003. Most of the debt securities that are below investment grade are rated at the higher end (B or better) of the noninvestment grade spectrum. Our investment policy limits investments in a single issuer and requires diversification among various asset types. Duration is indicative of the relationship between changes in market value to changes in interest rates, providing a general indication of the sensitivity of the fair values of our debt securities to changes in interest rates. However, actual market values may differ significantly from estimates based on duration. The average duration of our debt securities was approximately 3.5 years at December 31, 2003. Based on this duration, a 1% increase in interest rates would generally decrease the fair value of our debt securities by approximately $70 million. Our investment securities are categorized as available for sale and, as a result, are stated at fair value. Fair value of publicly traded debt and equity securities are based on quoted market prices. Non-traded debt securities are priced independently by a third party vendor. Fair value of venture capital debt securities that are privately Revenue for other healthcare services is recognized on a fee-for-service basis at estimated collectible amounts at the time services are rendered. Our fees are determined in advance for each type of service performed. Investment Securities Investment securities totaled $9.8 billion, or 47.3% of total assets at December 31, 2013, and $9.8 billion, or 49% of total assets at December 31, 2012. Debt securities, detailed below, comprised this entire investment portfolio at December 31, 2013 and at December 31, 2012. The fair value of debt securities were as follows at December 31, 2013 and 2012:


Answer: 0.00699

Question: What is the ratio of Operating lease obligations to Total contractual obligations in 1-3 years?


Answer: 2010.0

Question: For Three Months Ended Dec 31,which year is Total stock-based compensation greater than 2400 thousand?

Context:
(2) Includes stock-based compensation expense and asset acquisition related write-offs as follows:

	Three Months Ended

	Mar 29,2009	Jun 28,2009	Sept 30,2009	Dec 31,2009	Mar 31,2010	Jun 30,2010	Sept 30,2010	Dec 31,2010

	($ amounts in 000's)

Cost of product revenue	24	27	25	26	24	26	26	25

Cost of services revenue	124	172	169	193	208	234	242	245

Research and development	378	498	516	571	554	587	600	598

Sales and marketing	644	692	767	917	866	897	1,017	1,030

General and administrative	380	404	459	475	496	520	549	571

Total stock-based compensation	1,550	1,793	1,936	2,182	2,148	2,264	2,434	2,469

Asset acquisition related write-offs	—	631	93	1,663	—	—	—	—

Total stock based compensation and asset acquisition related write-offs	1,550	2,424	2,029	3,845	2,148	2,264	2,434	2,469

 (3) See Note 7 to the Consolidated Financial Statements. Seasonality, Cyclicality and Quarterly Revenue Trends Our quarterly results reflect seasonality in the sale of our products, subscriptions and services. In general, a pattern of increased customer buying at year-end has positively impacted sales activity in the fourth quarter. In the first quarter we generally experience lower sequential billings and product revenues, which results in lower product revenue. Our product revenue in the third quarter can be negatively affected by reduced economic activity in Europe during the summer months. During fiscal 2010, the growth in the Americas during the third quarter more than offset the slight decline in Europe, but this may not always be the case. Similarly, our gross margins and operating income have been affected by these historical trends because expenses are relatively fixed in the near-term. Although these seasonal factors are common in the technology sector, historical patterns should not be considered a reliable indicator of our future sales activity or performance. On a quarterly basis, we have usually generated the majority of our product revenue in the final month of each quarter and a significant amount in the last two weeks of a quarter. We believe this is due to customer buying patterns typical in this industry. Our total quarterly revenue over the past twelve quarters has increased sequentially in every quarter except for the first quarters of fiscal 2010 and fiscal 2009. We believe these declines in the first and third quarters of fiscal 2010 are based on seasonality as discussed above, which particularly impacts our product revenue. Product revenue in all of the quarters of fiscal 2010 was higher as compared to the same periods in fiscal 2009, which we believe was due in part to the investments made in our sales organization and improvements in overall corporate IT spending. THE GOLDMAN SACHS GROUP, INC.  AND SUBSIDIARIES Management’s Discussion and Analysis The Risk Committee of the Board and the Risk Governance Committee approve liquidity risk limits at the firmwide level, consistent with our risk appetite statement. Limits are reviewed frequently and amended, with required approvals, on a permanent and temporary basis, as appropriate, to reflect changing market or business conditions. Our liquidity risk limits are monitored by Treasury and Liquidity Risk Management. Liquidity Risk Management is responsible for identifying and escalating to senior management and/or the appropriate risk committee, on a timely basis, instances where limits have been exceeded. GCLA and Unencumbered Metrics GCLA. Based on the results of our internal liquidity risk models, described above, as well as our consideration of other factors, including, but not limited to, an assessment of our potential intraday liquidity needs and a qualitative assessment of our condition, as well as the financial markets, we believe our liquidity position as of both December 2018 and December 2017 was appropriate. We strictly limit our GCLA to a narrowly defined list of securities and cash because they are highly liquid, even in a difficult funding environment. We do not include other potential sources of excess liquidity in our GCLA, such as less liquid unencumbered securities or committed credit facilities. The table below presents information about our average GCLA

	Average for the Year Ended December

$ in millions	 2018	2017

 Denomination

U.S. dollar	 $155,348	$155,020

Non-U.S.dollar	 77,995	63,528

 Total	 $233,343	$218,548

 Asset Class

Overnight cash deposits	 $ 98,811	$ 93,617

U.S. government obligations	 79,810	75,108

U.S. agency obligations	 12,171	11,813

Non-U.S.governmentobligations	 42,551	38,010

 Total	 $233,343	$218,548

 Entity Type

Group Inc. and Funding IHC	 $ 40,920	$ 37,507

Major broker-dealer subsidiaries	 104,364	98,160

Major bank subsidiaries	 88,059	82,881

 Total	 $233,343	$218,548

 In the table above: ‰ The U. S.  dollar-denominated GCLA consists of (i) unencumbered U. S.  government and agency obligations (including highly liquid U. S.  agency mortgage-backed obligations), all of which are eligible as collateral in Federal Reserve open market operations and (ii) certain overnight U. S.  dollar cash deposits. ‰ The non-U. S.  dollar-denominated GCLA consists of non-U. S.  government obligations (only unencumbered German, French, Japanese and U. K.  government obligations) and certain overnight cash deposits in highly liquid currencies. We maintain our GCLA to enable us to meet current and potential liquidity requirements of our parent company, Group Inc. , and its subsidiaries. Our Modeled Liquidity Outflow and Intraday Liquidity Model incorporate a consolidated requirement for Group Inc. , as well as a standalone requirement for each of our major broker-dealer and bank subsidiaries. Funding IHC is required to provide the necessary liquidity to Group Inc.  during the ordinary course of business, and is also obligated to provide capital and liquidity support to major subsidiaries in the event of our material financial distress or failure. Liquidity held directly in each of our major broker-dealer and bank subsidiaries is intended for use only by that subsidiary to meet its liquidity requirements and is assumed not to be available to Group Inc.  or Funding IHC unless (i) legally provided for and (ii) there are no additional regulatory, tax or other restrictions. In addition, the Modeled Liquidity Outflow and Intraday Liquidity Model also incorporate a broader assessment of standalone liquidity requirements for other subsidiaries and we hold a portion of our GCLA directly at Group Inc.  or Funding IHC to support such requirements. Other Unencumbered Assets. In addition to our GCLA, we have a significant amount of other unencumbered cash and financial instruments, including other government obligations, high-grade money market securities, corporate obligations, marginable equities, loans and cash deposits not included in our GCLA. The fair value of our unencumbered assets averaged $177.08 billion for 2018 and $158.41 billion for 2017. We do not consider these assets liquid enough to be eligible for our GCLA. Liquidity Regulatory Framework As a BHC, we are subject to a minimum Liquidity Coverage Ratio (LCR) under the LCR rule approved by the U. S.  federal bank regulatory agencies. The LCR rule requires organizations to maintain an adequate ratio of eligible high-quality liquid assets (HQLA) to expected net cash outflows under an acute short-term liquidity stress scenario. Eligible HQLA excludes HQLA held by subsidiaries that is in excess of their minimum requirement and is subject to transfer restrictions. We are required to maintain a minimum LCR of 100%. We expect that fluctuations in client activity, business mix and the market environment will impact our average LCR. The table below presents information about our average daily LCR.

	Average for the Three Months Ended

$ in millions	 December 2018	September 2018

Total HQLA	 $226,473	$233,721

Eligible HQLA	 $160,016	$170,621

Net cash outflows	 $126,511	$133,126

 LCR	 127%	128%

 Liquidity and Capital Resources


Answer: 444.0

Question: What's the total amount of the Non-GAAP adjusted operating income (loss) in the years where Operating income (loss) is greater than 0? (in million)

Context:
Backlog Applied manufactures systems to meet demand represented by order backlog and customer commitments. Backlog consists of: (1) orders for which written authorizations have been accepted and assigned shipment dates are within the next 12 months, or shipment has occurred but revenue has not been recognized; and (2) contractual service revenue and maintenance fees to be earned within the next 12 months. Backlog by reportable segment as of October 27, 2013 and October 28, 2012 was as follows:

	2013	2012		(In millions, except percentages)

Silicon Systems Group	$1,295	55%	$705	44%

Applied Global Services	591	25%	580	36%

Display	361	15%	206	13%

Energy and Environmental Solutions	125	5%	115	7%

Total	$2,372	100%	$1,606	100%

 Applied’s backlog on any particular date is not necessarily indicative of actual sales for any future periods, due to the potential for customer changes in delivery schedules or cancellation of orders. Customers may delay delivery of products or cancel orders prior to shipment, subject to possible cancellation penalties. Delays in delivery schedules and/or a reduction of backlog during any particular period could have a material adverse effect on Applied’s business and results of operations. Manufacturing, Raw Materials and Supplies Applied’s manufacturing activities consist primarily of assembly, test and integration of various proprietary and commercial parts, components and subassemblies (collectively, parts) that are used to manufacture systems. Applied has implemented a distributed manufacturing model under which manufacturing and supply chain activities are conducted in various countries, including the United States, Europe, Israel, Singapore, Taiwan, and other countries in Asia, and assembly of some systems is completed at customer sites. Applied uses numerous vendors, including contract manufacturers, to supply parts and assembly services for the manufacture and support of its products. Although Applied makes reasonable efforts to assure that parts are available from multiple qualified suppliers, this is not always possible. Accordingly, some key parts may be obtained from only a single supplier or a limited group of suppliers. Applied seeks to reduce costs and to lower the risks of manufacturing and service interruptions by: (1) selecting and qualifying alternate suppliers for key parts; (2) monitoring the financial condition of key suppliers; (3) maintaining appropriate inventories of key parts; (4) qualifying new parts on a timely basis; and (5) locating certain manufacturing operations in close proximity to suppliers and customers. Research, Development and Engineering Applied’s long-term growth strategy requires continued development of new products. The Company’s significant investment in research, development and engineering (RD&E) has generally enabled it to deliver new products and technologies before the emergence of strong demand, thus allowing customers to incorporate these products into their manufacturing plans at an early stage in the technology selection cycle. Applied works closely with its global customers to design systems and processes that meet their planned technical and production requirements. Product development and engineering organizations are located primarily in the United States, as well as in Europe, Israel, Taiwan, and China. In addition, Applied outsources certain RD&E activities, some of which are performed outside the United States, primarily in India. Process support and customer demonstration laboratories are located in the United States, China, Taiwan, Europe, and Israel. Applied’s investments in RD&E for product development and engineering programs to create or improve products and technologies over the last three years were as follows: $1.3 billion (18 percent of net sales) in fiscal 2013, $1.2 billion (14 percent of net sales) in fiscal 2012, and $1.1 billion (11 percent of net sales) in fiscal 2011. Applied has spent an average of 14 percent of net sales in RD&E over the last five years. In addition to RD&E for specific product technologies, Applied maintains ongoing programs for automation control systems, materials research, and environmental control that are applicable to its products. Item 2: Properties Information concerning Applied’s principal properties at October 27, 2013 is set forth below:

Location	Type	Principal Use	SquareFootage	Ownership

Santa Clara, CA	Office, Plant & Warehouse	Headquarters; Marketing; Manufacturing; Distribution; Research, Development,Engineering; Customer Support	1,476,000150,000	OwnedLeased

Austin, TX	Office, Plant & Warehouse	Manufacturing	1,719,000145,000	OwnedLeased

Rehovot, Israel	Office, Plant & Warehouse	Manufacturing; Research,Development, Engineering;Customer Support	417,0005,000	OwnedLeased

Singapore	Office, Plant & Warehouse	Manufacturing andCustomer Support	392,00010,000	OwnedLeased

Gloucester, MA	Office, Plant & Warehouse	Manufacturing; Research,Development, Engineering;Customer Support	315,000131,000	OwnedLeased

Tainan, Taiwan	Office, Plant & Warehouse	Manufacturing andCustomer Support	320,000	Owned

 Because of the interrelation of Applied’s operations, properties within a country may be shared by the segments operating within that country. Products in the Silicon Systems Group are manufactured in Austin, Texas; Singapore; Gloucester, Massachusetts; and Rehovot, Israel. Remanufactured equipment products in the Applied Global Services segment are produced primarily in Austin, Texas. Products in the Display segment are manufactured in Tainan, Taiwan; Santa Clara, California; and Alzenau, Germany. Products in the Energy and Environmental Solutions segment are primarily manufactured in Alzenau, Germany; Treviso, Italy; and Cheseaux, Switzerland. In addition to the above properties, Applied also owns and leases offices, plants and/or warehouse locations in 78 locations throughout the world: 18 in Europe, 21 in Japan, 15 in North America (principally the United States), 8 in China, 7 in Korea, 6 in Southeast Asia, and 3 in Taiwan. These facilities are principally used for manufacturing; research, development and engineering; and marketing, sales and/or customer support. Applied also owns a total of approximately 139 acres of buildable land in 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. Fiscal 2013 operating results reflected a recovery in demand for TV manufacturing equipment and continued demand for advanced mobile display equipment, which resulted in increased new orders, net sales, operating income and non-GAAPadjusted operating income compared to fiscal 2012. In the fourth quarter of fiscal 2013, new orders were $114 million, down 55 percent from the prior quarter, and reflected customer push-outs of orders. Net sales in the fourth quarter of fiscal 2013 were $163 million, almost flat compared to the prior quarter. Two customers accounted for approximately 50 percent of net sales for the Display segment in fiscal 2013. Fiscal 2012 operating results reflected a continued overcapacity in the large substrate LCD TV equipment industry that resulted in decreased new orders and net sales in fiscal 2012. The downturn in the LCD TV equipment industry was partially offset by increased demand for advanced mobile display equipment. Four customers accounted for 60 percent of net sales for the Display segment in fiscal 2012. Energy and Environmental Solutions Segment The Energy and Environmental Solutions segment includes products for fabricating c-Si solar PVs, as well as high throughput roll-to-roll deposition equipment for flexible electronics, packaging and other applications. This business is focused on delivering solutions to generate and conserve energy, with an emphasis on lowering the cost to produce solar power and increasing conversion efficiency. While end-demand for solar PVs has been robust over the last several years, investment levels in capital equipment remain depressed. Global solar PV production capacity exceeds anticipated demand, which has caused solar PV manufacturers to significantly reduce or delay investments in manufacturing capacity and new technology, or in some instances to cease operations. Certain significant measures for the past three fiscal years were as follows:

				Change

2013	2012	2011	2013 over 2012	2012 over 2011

	(In millions, except percentages and ratios)

New orders	$166	$195	$1,684	$-29	-15%	$-1,489	-88%

Net sales	173	425	1,990	-252	-59%	-1,565	-79%

Book to bill ratio	1.0	0.5	0.8

Operating income (loss)	-433	-668	453	235	35%	-1,121	-247%

Operating margin	-250.3%	-157.2%	22.8%		-93.1 points		-180.0 points

Non-GAAP Adjusted Results

Non-GAAP adjusted operating income (loss)	-115	-184	444	69	38%	-628	-141%

Non-GAAP adjusted operating margin	-66.5%	-43.3%	22.3%		-23.2 points		-65.6 points

 Reconciliations of non-GAAP adjusted measures are presented under "Non-GAAP Adjusted Results" below. Net Operating Revenues by Operating Segment Information about our net operating revenues by operating segment as a percentage of Company net operating revenues is as follows:


Answer: 3.40615

Question: what was the percentage change in the gross profit from 2009 to 2010 \\n

Context:
McKESSON CORPORATION FINANCIAL REVIEW (Continued)

	 Years Ended March 31,	 Change

 (Dollars in millions) 	 2012	 2011	 2010	 2012	 2011

Distribution Solutions

Direct distribution & services	$85,523	$77,554	$72,210	10%	7%

Sales to customers’ warehouses	20,453	18,631	21,435	10	-13

Total U.S. pharmaceutical distribution & services	105,976	96,185	93,645	10	3

Canada pharmaceutical distribution & services	10,303	9,784	9,072	5	8

Medical-Surgical distribution & services	3,145	2,920	2,861	8	2

Total Distribution Solutions	119,424	108,889	105,578	10	3

Technology Solutions

Services	2,594	2,483	2,439	4	2

Software & software systems	596	590	571	1	3

Hardware	120	122	114	-2	7

Total Technology Solutions	3,310	3,195	3,124	4	2

Total Revenues	$122,734	$112,084	$108,702	10	3

 Revenues increased 10% to $122.7 billion in 2012 and 3% to $112.1 billion in 2011. The increase in revenues in each year primarily reflects market growth in our Distribution Solutions segment, which accounted for approximately 97% of our consolidated revenues, and our acquisition of US Oncology. Direct distribution and services revenues increased in 2012 compared to 2011 primarily due to market growth, which includes growing drug utilization and price increases, and from our acquisition of US Oncology. These increases were partially offset by price deflation associated with brand to generic drug conversions. Direct distribution and services revenues increased in 2011 compared to 2010 primarily due to market growth, the effect of a shift of revenues from sales to customers’ warehouses to direct store delivery, the lapping of which was completed in the third quarter of 2011, and due to our acquisition of US Oncology. These increases were partially offset by a decline in demand associated with the flu season and the impact of price deflation associated with brand to generic drug conversions. Sales to customers’ warehouses for 2012 increased compared to 2011 primarily due to a new customer and new business with existing customers. Sales to customers’ warehouses for 2011 decreased compared to 2010 primarily reflecting reduced revenues associated with existing customers, the effect of a shift of revenues to direct store delivery, the lapping of which was completed in the third quarter of 2011, and the impact of price deflation associated with brand to generic drug conversions. Sales to retail customers’ warehouses represent large volume sales of pharmaceuticals primarily to a limited number of large self-warehousing retail chain customers whereby we order bulk product from the manufacturer, receive and process the product through our central distribution facility and subsequently deliver the bulk product (generally in the same form as received from the manufacturer) directly to our customers’ warehouses. This distribution method is typically not marketed or sold by the Company as a stand-alone service; rather, it is offered as an additional distribution method for our large retail chain customers that have an internal self-warehousing distribution network. Sales to customers’ warehouses provide a benefit to these customers because they can utilize the Company as one source for both their direct-to-store business and their warehouse business. We generally have significantly lower gross profit margins on sales to customers’ warehouses as we pass much of the efficiency of this low cost-to-serve model on to the customer. These sales do, however, contribute to our gross profit dollars. McKESSON CORPORATION FINANCIAL NOTES (Continued) Expected benefit payments, including assumed executive lump sum payments, for our pension plans are as follows: $180 million, $64 million, $64 million, $62 million and $62 million for 2020 to 2024 and $327 million for 2025 through 2029. Expected benefit payments are based on the same assumptions used to measure the benefit obligations and include estimated future employee service. Expected contributions to be made for our pension plans are $146 million for 2020. Weighted-average assumptions used to estimate the net periodic pension expense and the actuarial present value of benefit obligations were as follows:

	U.S. Plans Years Ended March 31,	Non-U.S. Plans Years Ended March 31,

	2019	2018	2017	2019	2018	2017

Net periodic pension expense

Discount rates	3.83%	3.55%	3.40%	2.35%	2.34%	2.72%

Rate of increase in compensation	N/A -1	4.00	4.00	3.13	2.72	2.76

Expected long-term rate of return on plan assets	5.25	6.25	6.25	3.71	4.03	4.51

Benefit obligation

Discount rates	3.65%	3.69%	3.39%	2.13%	2.35%	2.35%

Rate of increase in compensation	N/A -1	N/A -1	4.00	3.18	2.59	3.18

 (1) This assumption is no longer needed in actuarial valuations as U. S.  plans are frozen or have fixed benefits for the remaining active participants. Our defined benefit pension plan liabilities are valued using a discount rate based on a yield curve developed from a portfolio of high quality corporate bonds rated AA or better whose maturities are aligned with the expected benefit payments of our plans. For March 31, 2019, our U. S.  defined benefit liabilities are valued using a weighted average discount rate of 3.65%, which represents a decrease of 4 basis points from our 2018 weighted-average discount rate of 3.69%. Our non-U. S.  defined benefit pension plan liabilities are valued using a weighted-average discount rate of 2.13%, which represents a decrease of 22 basis points from our 2018 weighted average discount rate of 2.35%. Plan Assets Investment Strategy: The overall objective for U.  S.  pension plan assets has been to generate long-term investment returns consistent with capital preservation and prudent investment practices, with a diversification of asset types and investment strategies. Periodic adjustments were made to provide liquidity for benefit payments and to rebalance plan assets to their target allocations. In September 2018, a new investment allocation strategy was put in place to protect the funded status of the U. S.  plan assets subsequent to Board approval of U. S.  pension plan termination. The target allocation for U. S.  plan assets at March 31, 2019 is 100% fixed income investments including cash and cash equivalents. The target allocations for U. S.  plan assets at March 31, 2018 were 26% equity investments, 70% fixed income investments including cash and cash equivalents and 4% real estate. Equity investments include common stock, preferred stock, and equity commingled funds. Fixed income investments include corporate bonds, government securities, mortgage-backed securities, asset-backed securities, other directly held fixed income investments, and fixed income commingled funds. The real estate investments are in a commingled real estate fund. Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 Net revenues increased $207.5 million, or 24.2%, to $1,063.9 million in 2010 from $856.4 million in 2009. Net revenues by product category are summarized below:

	Year Ended December 31,

(In thousands)	2010	2009	$ Change	% Change

Apparel	$853,493	$651,779	$201,714	30.9%

Footwear	127,175	136,224	-9,049	-6.6

Accessories	43,882	35,077	8,805	25.1

Total net sales	1,024,550	823,080	201,470	24.5

License revenues	39,377	33,331	6,046	18.1

Total net revenues	$1,063,927	$856,411	$207,516	24.2%

 Net sales increased $201.5 million, or 24.5%, to $1,024.6 million in 2010 from $823.1 million in 2009 as noted in the table above. The increase in net sales primarily reflects: ? $88.9 million, or 56.8%, increase in direct to consumer sales, which includes 19 additional stores in 2010; and ? unit growth driven by increased distribution and new offerings in multiple product categories, most significantly in our training, base layer, mountain, golf and underwear categories; partially offset by ? $9.0 million decrease in footwear sales driven primarily by a decline in running and training footwear sales. License revenues increased $6.1 million, or 18.1%, to $39.4 million in 2010 from $33.3 million in 2009. This increase in license revenues was primarily a result of increased sales by our licensees due to increased distribution and continued unit volume growth. We have developed our own headwear and bags, and beginning in 2011, these products are being sold by us rather than by one of our licensees. Gross profit increased $120.4 million to $530.5 million in 2010 from $410.1 million in 2009. Gross profit as a percentage of net revenues, or gross margin, increased 200 basis points to 49.9% in 2010 compared to 47.9% in 2009. The increase in gross margin percentage was primarily driven by the following: ? approximate 100 basis point increase driven by increased direct to consumer higher margin sales; ? approximate 50 basis point increase driven by decreased sales markdowns and returns, primarily due to improved sell-through rates at retail; and ? approximate 50 basis point increase driven primarily by liquidation sales and related inventory reserve reversals. The current year period benefited from reversals of inventory reserves established in the prior year relative to certain cleated footwear, sport specific apparel and gloves. These products have historically been more difficult to liquidate at favorable prices. Selling, general and administrative expenses increased $93.3 million to $418.2 million in 2010 from $324.9 million in 2009. As a percentage of net revenues, selling, general and administrative expenses increased to 39.3% in 2010 from 37.9% in 2009. These changes were primarily attributable to the following: ? Marketing costs increased $19.3 million to $128.2 million in 2010 from $108.9 million in 2009 primarily due to an increase in sponsorship of events and collegiate and professional teams and athletes, increased television and digital campaign costs, including media campaigns for specific customers and additional personnel costs. In addition, we incurred increased expenses for our performance incentive plan as compared to the prior year. As a percentage of net revenues, marketing costs decreased to 12.0% in 2010 from 12.7% in 2009 primarily due to decreased marketing costs for specific customers.


Answer: 0.15641

Question: what percent of the net change in revenue between 2006 and 2007 was due to transmission revenue?

Context:
Entergy Texas, Inc.  Management's Financial Discussion and Analysis 361 Fuel and purchased power expenses increased primarily due to an increase in power purchases as a result of the purchased power agreements between Entergy Gulf States Louisiana and Entergy Texas and an increase in the average market prices of purchased power and natural gas, substantially offset by a decrease in deferred fuel expense as a result of decreased recovery from customers of fuel costs. Other regulatory charges increased primarily due to an increase of $6.9 million in the recovery of bond expenses related to the securitization bonds. The recovery became effective July 2007. See Note 5 to the financial statements for additional information regarding the securitization bonds.2007 Compared to 2006 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. Following is an analysis of the change in net revenue comparing 2007 to 2006.

	Amount (In Millions)

2006 net revenue	$403.3

Purchased power capacity	13.1

Securitization transition charge	9.9

Volume/weather	9.7

Transmission revenue	6.1

Base revenue	2.6

Other	-2.4

2007 net revenue	$442.3

 The purchased power capacity variance is due to changes in the purchased power capacity costs included in the calculation in 2007 compared to 2006 used to bill generation costs between Entergy Texas and Entergy Gulf States Louisiana. The securitization transition charge variance is due to the issuance of securitization bonds. As discussed above, in June 2007, EGSRF I, a company wholly-owned and consolidated by Entergy Texas, issued securitization bonds and with the proceeds purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. See Note 5 to the financial statements herein for details of the securitization bond issuance. The volume/weather variance is due to increased electricity usage on billed retail sales, including the effects of more favorable weather in 2007 compared to the same period in 2006. The increase is also due to an increase in usage during the unbilled sales period. Retail electricity usage increased a total of 139 GWh in all sectors. See "Critical Accounting Estimates" below and Note 1 to the financial statements for further discussion of the accounting for unbilled revenues. The transmission revenue variance is due to an increase in rates effective June 2007 and new transmission customers in late 2006. The base revenue variance is due to the transition to competition rider that began in March 2006. Refer to Note 2 to the financial statements for further discussion of the rate increase. Gross operating revenues, fuel and purchased power expenses, and other regulatory charges Gross operating revenues decreased primarily due to a decrease of $179 million in fuel cost recovery revenues due to lower fuel rates and fuel refunds. The decrease was partially offset by the $39 million increase in net revenue described above and an increase of $44 million in wholesale revenues, including $30 million from the System Agreement cost equalization payments from Entergy Arkansas. The receipt of such payments is being Noble Energy, Inc.  Notes to Consolidated Financial Statements Additional fair value disclosures about plan assets are as follows:

	Fair Value Measurements Using

Asset Category	Quoted Prices inActive Markets forIdentical Assets(Level 1)(1)	SignificantObservable Inputs(Level 2)(1)	SignificantUnobservable Inputs(Level 3)(1)	Total

(millions)

December 31, 2011

Federal Money Market Funds	$1	$-	$-	$1

Mutual Funds

Large Cap Funds	66	-	-	66

Mid Cap Funds	10	-	-	10

Blended Funds	6	-	-	6

Emerging Markets Funds	6	-	-	6

Fixed Income Funds	77	-	-	77

Common Collective Trust Funds

Large Cap Funds	-	17	-	17

Small Cap Funds	-	12	-	12

International Funds	-	24	-	24

Total	$166	$53	$-	$219

December 31, 2010

Federal Money Market Funds	$2	$-	$-	$2

Mutual Funds

Large Cap Funds	69	-	-	69

Mid Cap Funds	10	-	-	10

Blended Funds	6	-	-	6

Emerging Markets Funds	7	-	-	7

Fixed Income Funds	55	-	-	55

Common Collective Trust Funds

Large Cap Funds	-	16	-	16

Small Cap Funds	-	12	-	12

International Funds	-	29	-	29

Total	$149	$57	$-	$206

 (1) See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy. Additional information about plan assets, including methods and assumptions used to estimate the fair values of plan assets, is as follows: Federal Money Market Funds Investments in federal money market funds consist of portfolios of high quality fixed income securities (such as US Treasury securities) which, generally, have maturities of less than one year. The fair value of these investments is based on quoted market prices for identical assets as of the measurement date. Mutual Funds Investments in mutual funds consist of diversified portfolios of common stocks and fixed income instruments. The common stock mutual funds are diversified by market capitalization and investment style as well as economic sector and industry. The fixed income mutual funds are diversified primarily in government bonds, mortgage backed securities, and corporate bonds, most of which are rated investment grade. The fair values of these investments are based on quoted market prices for identical assets as of the measurement date. Common Collective Trust Funds Investments in common collective trust funds consist of common stock investments in both US and non-US equity markets. Portfolios are diversified by market capitalization and investment style as well as economic sector and industry. The investments in the non-US equity markets are used to further enhance the plan’s overall equity diversification which is expected to moderate the plan’s overall risk volatility. In addition to the normal risk associated with stock market investing, investments in foreign equity markets may carry additional political, regulatory, and currency risk which is taken into account by the committee in its deliberations. The fair value of these investments is based on quoted prices for similar assets in active markets. All of the investments in common collective trust funds represent exchange-traded securities with readily observable prices. Risk Management The oil and gas business is subject to many significant risks, including operational, strategic, financial and compliance/ regulatory risks. We strive to maintain a proactive enterprise risk management (ERM) process to plan, organize, and control our activities in a manner which is intended to minimize the effects of risk on our capital, cash flows and earnings. ERM expands our process to include risks associated with accidental losses, as well as operational, strategic, financial, compliance/regulatory, and other risks. Our ERM process is designed to operate in an annual cycle, integrated with our long range plans, and supportive of our capital structure planning. Elements include, among others, cash flow at risk analysis, credit risk management, a commodity hedging program to reduce the impacts of commodity price volatility, an insurance program to protect against disruptions in our cash flows, a robust global compliance program, and government and community relations initiatives. We benchmark our program against our peers and other global organizations. See Item 1A. Risk Factors for a discussion of specific risks we face in our business. Available Information Our website address is www. nobleenergyinc. com. Available on this website under “Investors – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www. sec. gov. Also posted on our website under “About Us – Corporate Governance”, and available in print upon request made by any stockholder to the Investor Relations Department, are charters for our Audit Committee, Compensation, Benefits and Stock Option Committee, Corporate Governance and Nominating Committee, and Environment, Health and Safety Committee. Copies of the Code of Conduct and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are also posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002. Item 1A. Risk Factors Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic and political environment intensifies many of these risks. We are currently experiencing a severe downturn in the oil and gas business cycle, and an extended or more severe downturn could have material adverse effects on our operations, our liquidity, and the price of our common stock. Our ability to operate profitably, maintain adequate liquidity, grow our business and pay dividends on our common stock depend highly upon the prices we receive for our crude oil, natural gas, and NGL production. Commodity prices are volatile. Crude oil prices, in particular, began to decline significantly in the fourth quarter 2014, declined further in 2015 and have continued to trade at a low level or decline further thus far in 2016. High and low monthly daily average prices for crude oil and high and low contract expiration prices for natural gas for the last three years and into 2016 were as follows:

	Jan. 1 - Feb.12, 2016	Year Ended December 31,

	2015	2014	2013

NYMEX

Crude Oil - WTI (per Bbl) High(1)	$31.78	$59.83	$105.15	$110.53

Crude Oil - WTI (per Bbl) Low(1)	29.71	37.33	59.29	86.68

Natural Gas - HH (Per MMbtu) High	2.23	3.19	5.56	4.46

Natural Gas - HH (Per MMbtu) Low	2.05	2.03	3.73	3.11

Brent

Crude Oil - (per Bbl) High	32.80	64.32	111.76	118.90

Crude Oil - (per Bbl) Low	31.93	38.21	62.91	97.69


Answer: 0.17122

Question: In the year with lowest amount of Working capital, what's the increasing rate of Total assets?

Context:
Part I Item 1 Entergy Corporation, Utility operating companies, and System Energy 253 including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017. In October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center (RISEC), in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased RISEC for $346 million in December 2011. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Pursuant to the PPA termination agreement, Consumers Energy will pay Entergy $172 million for the early termination of the PPA. The PPA termination agreement is subject to regulatory approvals. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intends to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. Entergy expects to enter into a new PPA with Consumers Energy under which the plant would continue to operate through October 1, 2018. In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State has agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also has agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. Even without opposition, the NRC license renewal process is expected to continue at least into 2018. With the settlement concerning Indian Point, Entergy now has announced plans for the disposition of all of the Entergy Wholesale Commodities nuclear power plants, including the sales of Vermont Yankee and FitzPatrick, and the earlier than previously expected shutdowns of Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” for further discussion. Property Nuclear Generating Stations Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:

Power Plant	Market	In Service Year	Acquired	Location	Capacity - Reactor Type	License Expiration Date

Pilgrim (a)	IS0-NE	1972	July 1999	Plymouth, MA	688 MW - Boiling Water	2032 (a)

FitzPatrick (b)	NYISO	1975	Nov. 2000	Oswego, NY	838 MW - Boiling Water	2034 (b)

Indian Point 3 (c)	NYISO	1976	Nov. 2000	Buchanan, NY	1,041 MW - Pressurized Water	2015 (c)

Indian Point 2 (c)	NYISO	1974	Sept. 2001	Buchanan, NY	1,028 MW - Pressurized Water	2013 (c)

Vermont Yankee (d)	IS0-NE	1972	July 2002	Vernon, VT	605 MW - Boiling Water	2032 (d)

Palisades (e)	MISO	1971	Apr. 2007	Covert, MI	811 MW - Pressurized Water	2031 (e)

Consolidated Balance Sheet Data	At July 31,

(In millions)	2014	2013	2012	2011	2010

Cash, cash equivalents and investments	$1,914	$1,661	$744	$1,421	$1,622

Long-term investments	31	83	75	63	91

Working capital	1,200	1,116	258	449	1,074

Total assets	5,201	5,486	4,684	5,110	5,198

Current portion of long-term debt	—	—	—	500	—

Long-term debt	499	499	499	499	998

Other long-term obligations	203	167	166	175	143

Total stockholders’ equity	3,078	3,531	2,744	2,616	2,821

 ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) includes the following sections: ? Executive Overview that discusses at a high level our operating results and some of the trends that affect our business.  ? Critical Accounting Policies and Estimates that we believe are important to understanding the assumptions and judgments underlying our financial statements.  ? Results of Operations that includes a more detailed discussion of our revenue and expenses.  ? Liquidity and Capital Resources which discusses key aspects of our statements of cash flows, changes in our balance sheets and our financial commitments. You should note that this MD&A discussion contains forward-looking statements that involve risks and uncertainties. Please see the section entitled “Forward-Looking Statements and Risk Factors” at the beginning of Item 1A for important information to consider when evaluating such statements. You should read this MD&A in conjunction with the financial statements and related notes in Item 8 of this Annual Report. In fiscal 2014 we acquired Check Inc.  and in fiscal 2012 we acquired Demandforce, Inc.  We have included their results of operations in our consolidated results of operations from the dates of acquisition. In fiscal 2013 we completed the sale of our Intuit Websites business and in fiscal 2014 we completed the sales of our Intuit Financial Services (IFS) and Intuit Health businesses. We accounted for all of these businesses as discontinued operations and have therefore reclassified our statements of operations for all periods presented to reflect them as such. We have also reclassified our balance sheets for all periods presented to reflect IFS as discontinued operations. The net assets of Intuit Websites and Intuit Health were not significant, so we have not reclassified our balance sheets for any period presented to reflect them as discontinued operations. Because the cash flows of our Intuit Websites, IFS, and Intuit Health discontinued operations were not material for any period presented, we have not segregated the cash flows of those businesses from continuing operations on our statements of cash flows. See “Results of Operations – Non-Operating Income and Expense – Discontinued Operations” later in this Item 7 for more information. Unless otherwise noted, the following discussion pertains to our continuing operations. Executive Overview This overview provides a high level discussion of our operating results and some of the trends that affect our business. We believe that an understanding of these trends is important in order to understand our financial results for fiscal 2014 as well as our future prospects. This summary is not intended to be exhaustive, nor is it intended to be a substitute for the detailed discussion and analysis provided elsewhere in this Annual Report on Form 10-K. See the table later in this Note 7 for more information on the IFS operating results. The carrying amounts of the major classes of assets and liabilities of IFS at July 31, 2013 were as shown in the following table. These carrying amounts approximated fair value.

(In millions)	July 31, 2013

Accounts receivable	$40

Other current assets	4

Property and equipment, net	31

Goodwill	914

Purchased intangible assets, net	4

Other assets	6

Total assets	999

Accounts payable	15

Accrued compensation	21

Deferred revenue	3

Long-term obligations	9

Total liabilities	48

Net assets	$951

 Intuit Health In July 2013 management having the authority to do so formally approved a plan to sell our Intuit Health business and on August 19, 2013 we completed the sale for cash consideration that was not significant. We recorded a $4 million pre-tax loss on the disposal of Intuit Health that was more than offset by a related income tax benefit of approximately $14 million, resulting in a net gain on disposal of approximately $10 million in the first quarter of fiscal 2014. The decision to sell the Intuit Health business was a result of management's desire to focus resources on its offerings for small businesses, consumers, and accounting professionals. Intuit Health was part of our former Other Businesses reportable segment. We determined that our Intuit Health business became a long-lived asset held for sale in the fourth quarter of fiscal 2013. A long-lived asset classified as held for sale is measured at the lower of its carrying amount or fair value less cost to sell. Since the carrying value of Intuit Health at July 31, 2013 was less than the estimated fair value less cost to sell, no adjustment to the carrying value of this long-lived asset was necessary at that date. We also classified our Intuit Health business as discontinued operations in the fourth quarter of fiscal 2013 and have segregated its operating results in our statements of operations for all periods presented. See the table later in this Note for more information. We have not segregated the net assets of Intuit Health on our balance sheets for any period presented. Net assets held for sale at July 31, 2013 consisted primarily of operating assets and liabilities that were not material. Because operating cash flows from the Intuit Health business were also not material for any period presented, we have not segregated them from continuing operations on our statements of cash flows. Intuit Websites In July 2012 management having the authority to do so formally approved a plan to sell our Intuit Websites business, which was a component of our Small Business reportable segment. The decision was the result of a shift in our strategy for helping small businesses to establish an online presence. On August 10, 2012 we signed a definitive agreement to sell our Intuit Websites business and on September 17, 2012 we completed the sale for approximately $60 million in cash. We recorded a gain on disposal of approximately $32 million, net of income taxes. We determined that our Intuit Websites business became a long-lived asset held for sale in the fourth quarter of fiscal 2012. A long-lived asset classified as held for sale is measured at the lower of its carrying amount or fair value less cost to sell. Since the carrying value of Intuit Websites at July 31, 2012 was less than the estimated fair value less cost to sell, no adjustment to the carrying value of this long-lived asset was necessary at that date.