Question: What is the sum of Capital lease obligations for payments due by period ? (in thousand)

def solution():
    # Define variables name and value
    less_than_1_year = 6139
    one_to_three_years = 11794
    four_to_five_years = 11139
    after_five_years = 56879

    # Do math calculation to get the answer
    answer = less_than_1_year + one_to_three_years + four_to_five_years + after_five_years

    return answer

REPUBLIC SERVICES, INC.  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED approximately $32 million of federal tax payments were deferred and paid in 2009 as a result of the Allied acquisition.

The following table summarizes the activity in our gross unrecognized tax benefits for the years ended December 31:

||2010|2009|2008|
|Balance at beginning of year|$242.2|$611.9|$23.2|
|Additions due to the Allied acquisition|-|13.3|582.9|
|Additions based on tax positions related to current year|2.8|3.9|10.6|
|Reductions for tax positions related to the current year|-|-|-5.1|
|Additions for tax positions of prior years|7.5|5.6|2.0|
|Reductions for tax positions of prior years|-7.4|-24.1|-1.3|
|Reductions for tax positions resulting from lapse of statute of limitations|-10.4|-0.5|-0.4|
|Settlements|-11.9|-367.9|-|
|Balance at end of year|$222.8|$242.2|$611.9|

New accounting guidance for business combinations became effective for our 2009 financial statements.

This new guidance changed the treatment of acquired uncertain tax liabilities.

Under previous guidance, changes in acquired uncertain tax liabilities were recognized through goodwill.

Under the new guidance, subsequent changes in acquired unrecognized tax liabilities are recognized through the income tax provision.

As of December 31, 2010, $206.5 million of the $222.8 million of unrecognized tax benefits related to tax positions taken by Allied prior to the 2008 acquisition.

Included in the balance at December 31, 2010 and 2009 are approximately $209.1 million and $217.6 million of unrecognized tax benefits (net of the federal benefit on state issues) that, if recognized, would affect the effective income tax rate in future periods.

During 2010, the IRS concluded its examination of our 2005 and 2007 tax years.

The conclusion of this examination reduced our gross unrecognized tax benefits by approximately $1.9 million.

We also resolved various state matters during 2010 that, in the aggregate, reduced our gross unrecognized tax benefits by approximately $10.0 million.

During 2009, we settled our outstanding tax dispute related to Allied’s risk management companies (see – Risk Management Companies) with both the Department of Justice (DOJ) and the Internal Revenue Service (IRS).

This settlement reduced our gross unrecognized tax benefits by approximately $299.6 million.

During 2009, we also settled with the IRS, through an accounting method change, our outstanding tax dispute related to intercompany insurance premiums paid to Allied’s captive insurance company.

This settlement reduced our gross unrecognized tax benefits by approximately $62.6 million.

In addition to these federal matters, we also resolved various state matters that, in the aggregate, reduced our gross unrecognized tax benefits during 2009 by approximately $5.8 million.

We recognize interest and penalties as incurred within the provision for income taxes in our consolidated statements of income.

Related to the unrecognized tax benefits previously noted, we accrued interest of $19.2 million during 2010 and, in total as of December 31, 2010, have recognized a liability for penalties of $1.2 million and interest of $99.9 million.

During 2009, we accrued interest of $24.5 million and, in total at December 31, 2009, had recognized a liability for penalties of $1.5 million and interest of $92.3 million.

During 2008, we accrued penalties of $0.2 million and interest of $5.2 million and, in total at December 31, 2008, had recognized a liability for penalties of $88.1 million and interest of $180.0 million.

NONREGULATED OPERATING MARGINS The following table details the changes in nonregulated revenue and margin included in continuing operations:

| (Millions of Dollars)|2005|2004|2003|
|Nonregulated and other revenue|$74|$75|$134|
|Nonregulated cost of goods sold|-25|-29|-81|
|Nonregulated margin|$49|$46|$53|

2004 Comparison to 2003 Nonregulated revenue decreased in 2004, due primarily to the discontinued consolidation of an investment in an independent power-producing entity that was no longer majority owned.

NON-FUEL OPERATING EXPENSES AND OTHER ITEMS Other Utility Operating and Maintenance Expenses Other operating and maintenance expenses for 2005 increased by approximately $87 million, or 5.5 percent, compared with 2004.

An outage at the Monticello nuclear plant and higher outage costs at Prairie Island in 2005 increased costs by approximately $26 million.

Employee benefit costs were higher in 2005, primarily due to increased pension benefits and long-term disability costs.

Also contributing to the increase were higher uncollectible receivable costs, attributable in part to modifications to the bankruptcy laws, higher fuel prices and certain changes in the credit and collections process.

Other operating and maintenance expenses for 2004 increased by approximately $21 million, or 1.4 percent, compared with 2003.

Of the increase, $12 million was incurred to assist with the storm damage repair in Florida and was offset by increased revenue.

The remaining increase of $9 million is primarily due to higher electric service reliability costs, higher information technology costs, higher plant-related costs, higher costs related to a customer billing system conversion and increased costs primarily related to compliance with the Sarbanes-Oxley Act of 2002.

The higher costs were partially offset by lower employee benefit and compensation costs and lower nuclear plant outage costs

| (Millions of Dollars)|2005 vs. 2004|2004 vs. 2003|
|Higher (lower) employee benefit costs|$31|$-12|
|Higher (lower) nuclear plant outage costs|26|-13|
|Higher uncollectible receivable costs|19|2|
|Higher donations to energy assistance programs|4|1|
|Higher mutual aid assistance costs|1|12|
|Higher electric service reliability costs|9|9|
|Higher (lower) information technology costs|-6|8|
|Higher (lower) plant-related costs|-7|4|
|Higher costs related to customer billing system conversion|4|4|
|Higher costs to comply with Sarbanes-Oxley Act of 2002|—|4|
|Other|6|2|
|Total operating and maintenance expense increase|$87|$21|

Other Nonregulated Operating and Maintenance Expenses Other nonregulated operating and maintenance expenses decreased $16 million, or 35.4 percent, in 2005 compared with 2004, primarily due to the accrual of $18 million in 2004 for a settlement agreement related to shareholder lawsuits.

Other nonregulated operating and maintenance expenses decreased $9 million, or 17.5 percent, in 2004 compared with 2003.

This decrease resulted from the dissolution of Planergy International and the discontinued consolidation of an investment in an independent powerproducing entity that was no longer majority owned after the divestiture of NRG.

Depreciation and Amortization Depreciation and amortization expense for 2005 increased by approximately $61 million, or 8.7 percent, compared with 2004.

The changes were primarily due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant and software system additions, both of which have relatively short depreciable lives compared with other capital additions.

The Prairie Island steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013.

In addition, the Minnesota Renewable Development Fund and renewable cost-recovery amortization, which is recovered in revenue as a non-fuel rider and does not have an impact on net income, increased over 2004.

The increase was partially offset by the changes in useful lives and net salvage rates approved by Minnesota regulators in August 2005.

Depreciation and amortization expense for 2004 decreased by $21 million, or 2.9 percent, compared with 2003.

The reduction is largely due to several regulatory decisions.

In 2004, as a result of a Minnesota Public Utilities Commission (MPUC) order, NSP-Minnesota modified its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million in 2004 compared with 2003.

In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, reducing annual depreciation expense by $20 million.

PSCo experienced the full impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003.

These decreases were partially offset by plant additions.

Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs.

The following is a summarized table of contractual obligations and other commercial commitments at Dec.  31, 2007.

See additional discussion in the consolidated statements of capitalization and Notes 4, 5, and 15 to the consolidated financial statements.

(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date.

Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms.

At Dec.  31, 2006, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $176.8 million.

In addition, at the end of the equipment leases’ terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value or equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.

(b) Included in operating lease payments are $76.6 million, $151.7 million, $124.5 million and $916.6 million, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to five purchase power agreements that were accounted for as operating leases.

(c) Included in other long-term obligations are tax, penalties and interest related to unrecognized tax benefits recorded according to FIN 48.

(d) Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements.

Additionally, the utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations.

Certain contractual purchase obligations are adjusted based on indices.

The effects of price changes are mitigated through cost-of-energy adjustment mechanisms.

(e) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $1.6 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

Xcel Energy has also executed five additional purchase power agreements that are conditional upon achievement of certain conditions, including becoming operational.

Estimated payments under these conditional obligations are $52.8 million, $165.7 million, $177.9 million and $1.7 billion, respectively, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories.

Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors.

Xcel Energy’s objective is to increase the annual dividend in the range of 2 percent to 4 percent per year.

Xcel Energy’s dividend policy balances: ?

Projected cash generation from utility operations; ?

Projected capital investment in the utility businesses; ?

A reasonable rate of return on shareholder investment; and ?

The impact on Xcel Energy’s capital structure and credit ratings.

In addition, there are certain statutory limitations that could affect dividend levels.

Federal law places certain limits on the ability of public utilities within a holding company system to declare dividends.

Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account.

The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from its utility subsidiaries.

The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company.

The limitation is imposed through equity ratio limitations that range from 30 percent to 60 percent.

Some utility subsidiaries must comply with bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios.

Results of Operations The following table summarizes the diluted EPS for Xcel Energy and subsidiaries:

Answer: 85951.0


Question: What is the sum of Tier 1 capital of Standardized Approach for Bank of America Corporation in 2018 and Granted of Options in 2006? (in million)

def solution():
    # Define variables name and value
    tier_1_capital_2018 = 189038
    options_granted_2006 = 934000

    # Do math calculation to get the answer
    answer = tier_1_capital_2018 + options_granted_2006

    return answer

(1) Regulatory capital metrics at December 31, 2017 reflect Basel 3 transition provisions for regulatory capital adjustments and deductions, which were fully phased-in as of January 1, 2018.

(2) The December 31, 2018 and 2017 amounts include a transition capital conservation buffer of 1.875 percent and 1.25 percent and a transition global systemically important bank surcharge of 1.875 percent and 1.5 percent.

The countercyclical capital buffer for both periods is zero.

(3) Percent required to meet guidelines to be considered “well capitalized” under the PCA framework.

(4) Total capital under the Advanced approaches differs from the Standardized approach due to differences in the amount permitted in Tier 2 capital related to the qualifying allowance for credit losses.

(5) Reflects adjusted average total assets for the three months ended December 31, 2018 and 2017.

The capital adequacy rules issued by the U. S.  banking regulators require institutions to meet the established minimums outlined in the table above.

Failure to meet the minimum requirements can lead to certain mandatory and discretionary actions by regulators that could have a material adverse impact on the Corporation’s financial position.

At December 31, 2018 and 2017, the Corporation and its banking entity affiliates were “well capitalized.

” Other Regulatory Matters The Federal Reserve requires the Corporation’s bank subsidiaries to maintain reserve requirements based on a percentage of certain deposit liabilities.

The average daily reserve balance requirements, in excess of vault cash, maintained by the Corporation with the Federal Reserve Bank were $11.4 billion and $8.9 billion for 2018 and 2017.

At December 31, 2018 and 2017, the Corporation had cash and cash equivalents in the amount of $5.8 billion and $4.1 billion, and securities with a fair value of $16.6 billion and $17.3 billion that were segregated in compliance with securities regulations.

Cash held on deposit with the Federal Reserve Bank to meet reserve requirements and cash and cash equivalents segregated in compliance with securities regulations are components of restricted cash.

For additional information, see Note 10 – Federal Funds Sold or Purchased, Securities Financing Agreements, Short-term Borrowings and Restricted Cash.

In addition, at December 31, 2018 and 2017, the Corporation had cash deposited with clearing organizations of $8.1 billion and $11.9 billion primarily recorded in other assets on the Consolidated Balance Sheet.

Bank Subsidiary Distributions The primary sources of funds for cash distributions by the Corporation to its shareholders are capital distributions received from its bank subsidiaries, BANA and Bank of America California, N. A.

In 2018, the Corporation received dividends of $26.1 billion from BANA and $320 million from Bank of America California, N. A.

In addition, Bank of America California, N. A.  returned capital of $1.4 billion to the Corporation in 2018.

The amount of dividends that a subsidiary bank may declare in a calendar year without OCC approval is the subsidiary bank’s net profits for that year combined with its retained net profits for the preceding two years.

Retained net profits, as defined by the OCC, consist of net income less dividends declared during the period.

In 2019, BANA can declare and pay dividends of approximately $3.1 billion to the Corporation plus an additional amount equal to its retained net profits for 2019 up to the date of any such dividend declaration.

Bank of America California, N. A.  can pay dividends of $40 million in 2019 plus an additional amount equal to its retained net profits for 2019 up to the date of any such dividend declaration.

Investment Management Fees Investment management fees are generally calculated under contractual arrangements with our SIPs and the products for which we provide sub-advisory services as a percentage of the market value of AUM.

Annual rates vary by investment objective and type of services provided.

Rates for products sold outside of the U. S.  are generally higher than for U. S.  products because they are structured to compensate for certain distribution costs.

Investment management fees decreased $856.1 million in fiscal year 2016 primarily due to a 14% decrease in average AUM and the impact of a lower effective fee rate.

Investment management fees decreased $237.9 million in fiscal year 2015 primarily due to a 2% decrease in average AUM and the impact of a lower effective fee rate.

The decrease in average AUM in fiscal year 2016 occurred in all sales regions and primarily in the global/international and hybrid investment objectives.

The decrease in average AUM in fiscal year 2015 primarily occurred in the international sales regions and in the global/ international investment objectives, partially offset by slight increases in the other investment objectives.

Our effective investment management fee rate (investment management fees divided by average AUM) was 59.7, 61.3 and 62.7 basis points for fiscal years 2016, 2015 and 2014.

The rate decrease in fiscal year 2016 was primarily due to higher weightings of AUM in U. S.  products and in lower fee products in the global/international investment objectives in the Europe, Middle East and Africa and Asia-Pacific sales regions, partially offset by higher performance fees.

The rate decrease in fiscal year 2015 was primarily due to higher weightings of AUM in U. S.  products and in lower fee products in the global/international investment objectives in the Europe, Middle East and Africa sales region, as well as lower performance fees.

Performance-based investment management fees were $26.5 million, $19.8 million and $50.9 million for fiscal years 2016, 2015 and 2014.

The higher fees in fiscal year 2014 were primarily related to fund of hedge funds products.

U. S.  industry asset-weighted average management fee rates were as follows1 :

|(in basis points)|Industry Average|
|for the fiscal years ended September 30,|2016|2015|2014|
|Equity||||
|Global/international|53|55|58|
|United States|37|39|41|
|Hybrid|50|52|53|
|Fixed Income||||
|Tax-free|35|35|35|
|Taxable||||
|Global/international2|43|46|55|
|United States|33|35|37|
|Cash Management|10|9|11|

1 U. S.  industry asset-weighted average management fee rates were calculated using information available from Lipper, a Thomson Reuters Company, as of September 30, 2016, 2015 and 2014 and include all U. S. -registered open-end funds that reported expense data to Lipper as of the funds’most recent annual report date, and for which expenses were equal to or greater than zero.

As defined by Lipper, management fees include fees from providing advisory and fund administration services.

The averages combine retail and institutional funds data and include all share classes and distribution channels, without exception.

Variable annuity and fund of fund products are not included.2 The decreases in the average rate in fiscal years 2016 and 2015 reflect lower weightings of two large higher fee funds and higher weightings of a large low fee fund.

Our actual effective investment management fee rates are generally higher than the U. S.  industry average rates as we actively manage our products and have a higher level of international AUM, both of which generate higher fees.

Changes to our effective investment management fee rates in the U. S.  have not varied significantly from changes in industry rates.

Our product offerings and global operations are diverse.

As such, the impact of future changes in the market value of AUM on investment management fees will be affected by the relative mix of investment objective, geographic region, distribution channel and investment vehicle of the assets.

Greensboro, we have two office buildings (leased), a six-inch wafer production facility (owned), a R&D and prototyping facility (leased) and other leased office space.

In Greensboro, we also have a previously idled production facility (leased) that has been reconfigured to perform certain manufacturing operations.

In Hillsboro, we have a single facility (owned) that includes office space and a wafer fabrication facility.

We also have wafer fabrication facilities in Richardson, Texas (owned), Apopka, Florida (owned) and Bend, Oregon (leased).

In the first quarter of fiscal 2017, we acquired an additional wafer fabrication facility in Farmers Branch, Texas, which we currently plan to use to expand our BAW filter capacity.

We have assembly and test facilities located in Beijing, China (the building is owned and we hold a land-use right for the land), where we assemble and test modules.

During fiscal 2016, we brought a new assembly and test facility in Dezhou, China on-line (the equipment is owned and we lease the land and building).

We operate a filter assembly and test facility in San Jose, Costa Rica (owned).

In Broomfield, Colorado (leased), Brooksville, Florida (owned), Richardson, Texas (owned), and the Philippines (leased), we have assembly and test sites for highly customized modules and products, including modules and products that support our aerospace and defense business.

We also have a facility capable of supporting a variety of packaging and test technologies in Nuremberg, Germany (leased).

We lease space for our design centers in Chandler, Arizona; Newberry Park, San Jose, Torrance, California; Broomfield, Colorado; Hiawatha, Iowa; Chelmsford, Massachusetts; High Point, North Carolina; Tokyo, Japan; Shanghai, China; Utrecht, The Netherlands; Zele, Belgium; Munich, Germany; N?rresundby, Denmark; and Colomiers, France.

In addition, we lease space for sales and customer support centers in Beijing, Shanghai, and Shenzhen, China; Hong Kong; Reading, England; Bangalore, India; Tokyo, Japan; Seoul, South Korea; Singapore; and Taipei, Taiwan.

We believe our properties have been well-maintained, are in sound operating condition and contain all equipment and facilities necessary to operate at present levels.

We believe all of our facilities are suitable and adequate for our present purposes.

We do not identify or allocate assets by operating segment.

For information on net property, plant and equipment by country, see Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of this report.

See the information under the heading “Legal Matters” in Note 9 of the Notes to the Consolidated Financial Statements set forth in Part II, Item 8 of this report.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is traded on the NASDAQ Global Select Market under the symbol “QRVO.

” The table below shows the high and low sales prices of our common stock from the date of the Business Combination through the end of our fiscal year, as reported by The NASDAQ Stock Market LLC.

As of May 13, 2016, there were 799 holders of record of our common stock.

This number does not include the beneficial owners of unexchanged stock certificates related to the Business Combination or the additional beneficial owners of our common stock who held their shares in street name as of that date.

||High|Low|
|Fiscal Year Ended April 2, 2016|||
|First Quarter|$88.35|$65.44|
|Second Quarter|82.25|42.24|
|Third Quarter|60.00|42.67|
|Fourth Quarter|51.95|33.30|
|Fiscal Year Ended March 28, 2015|High|Low|
|Fourth Quarter|$85.63|$63.02|

We have never declared or paid cash dividends on our common stock.

Although we currently intend to retain our earnings for use in our business, our future dividend policy with respect to our common stock may change and will depend on our earnings, capital requirements, debt covenants and other factors deemed relevant by our Board of Directors.

PREFERRED STOCK PURCHASE RIGHTS Each outstanding share of common stock has one half of a share purchase right.

Each purchase right may be exercised to purchase one two-hundredth of a share of Series A Junior Participating Preferred Stock at an exercise price of $220.00, subject to adjustment.

The rights, which do not have voting rights, expire on March 10, 2016, and may be redeemed by the Company at a price of $0.01 per right at any time prior to the tenth day following the public announcement that a person has acquired beneficial ownership of 15% or more of the outstanding shares of common stock.

In the event that the Company is acquired in a merger or other business combination transaction, provision shall be made so that each holder of a right (other than a holder who is a 14.9%-or-more shareowner) shall have the right to receive, upon exercise thereof, that number of shares of common stock of the surviving Company having a market value equal to two times the exercise price of the right.

Similarly, if anyone becomes the beneficial owner of more than 15% of the then outstanding shares of common stock (except pursuant to an offer for all outstanding shares of common stock which the independent directors have deemed to be fair and in the best interest of the Company), provision will be made so that each holder of a right (other than a holder who is a 14.9%-or-more shareowner) shall thereafter have the right to receive, upon exercise thereof, common stock (or, in certain circumstances, cash, property or other securities of the Company) having a market value equal to two times the exercise price of the right.

At December 29, 2007 there were 40,189,394 outstanding rights.

There are 250,000 shares of Series A Junior Participating Preferred Stock reserved for issuance in connection with the rights.

STOCK-BASED COMPENSATION PLANS The Company has stockbased compensation plans for salaried employees and non-employee members of the Board of Directors.

The plans provide for discretionary grants of stock options, restricted stock units, and other stock-based awards.

The plans are generally administered by the Compensation and Organization Committee of the Board of Directors, consisting of non-employee directors.

Stock Options Stock options are granted at the fair market value of the Company’s stock on the date of grant and have a 10 year term.

Generally, stock option grants vest ratably between one and four years from the date of grant.

The expense for stock options granted to retirement eligible employees (those aged 55 and over and with 10 or more years of service) is recognized by the date they became retirement eligible, or on the date of grant if they are already retirement eligible, as such employees may retain their options for the 10 year contractual term in the event they retire prior to the end of the vesting period stipulated in the grant.

The following describes how certain assumptions affecting the estimated fair value of stock options are determined: the dividend yield is computed as the annualized dividend rate at the date of grant divided by the strike price of the stock option; expected volatility is based on an average of the market implied volatility and historical volatility for the 5 year expected life; the risk-free interest rate is based on U. S.  Treasury securities with maturities equal to the expected life of the option; and an eight percent forfeiture rate is assumed.

The Company uses historical data in order to estimate exercise, termination and holding period behavior for valuation purposes.

The number of stock options and weighted-average exercise prices follows:

At December 29, 2007, the range of exercise prices on outstanding stock options was $19.34 to $63.04.

Stock option expense was $8.6 million and $8.2 million for the years ended December 29, 2007 and December 30, 2006, respectively.

No stock option expense was recognized in the year ended December 31, 2005 because under APB 25, no compensation cost was recognized for stock options when the quoted market price of the stock at the grant date was equal to the amount per share the employee had to pay to acquire the stock after fulfilling the vesting period.

The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2007, 2006 and 2005, respectively: dividend yield of 2.4%, 2.4% and 2.4%; expected volatility of 28%, 26%, 27%; and risk-free interest rates of 3.6%, 4.2%, 4.4%.

An expected life of 5 years was used in each period and a weighted average vesting period of 2.5 years in 2007, 2.3 years in 2006 and 2.5 years in 2005.

The weighted average fair value of stock options granted in 2007, 2006 and 2005 was $12.15, $12.03, and $11.44, respectively.

At December 29, 2007, the Company had $15.6 million of unrecognized pretax compensation expense for stock options.

This expense will be recognized over the remaining vesting periods which are 1.6 years on a weighted average basis.

For 2007, the Company received $65.7 million in cash from the exercise of stock options.

The related tax benefit from the exercise of these options is $16.5 million.

During 2007, 2006 and 2005 the total intrinsic value of options exercised was $37.9 million, $35.5 million and $23.3 million, respectively.

When options are exercised, the related shares are issued from treasury stock.

SFAS 123R requires the benefit arising from tax deductions in excess of recognized compensation cost to be classified as a financing cash flow rather than as an operating cash flow as all such tax benefits were classified under earlier accounting guidance.

To quantify the recognized compensation cost on which the excess tax benefit is computed, both actual compensation expense recorded following the adoption of SFAS 123R on

Answer: 1123038.0


Question: What is the sum of Home equity in 2011 and Operating lease obligations for Total? (in million)

def solution():
    # Define variables name and value
    home_equity_2011 = 2057.7
    operating_lease_obligations_total = 1494

    # Do math calculation to get the answer
    answer = home_equity_2011 + operating_lease_obligations_total

    return answer

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, 2016 and 2015, our pension plans were $20.1 billion and $17.9 billion underfunded as measured under GAAP.

On an Employee Retirement Income Security Act (ERISA) basis our plans are more than 100% funded at December 31, 2016 with minimal required contributions in 2017.

We expect to make contributions to our plans of approximately $0.5 billion in 2017.

We may be required to make higher contributions to our pension plans in future years.

At December 31, 2016, 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, 2016, and the estimated timing thereof.

|(Dollars in millions)|Total|Lessthan 1year|1-3years|3-5years|After 5years|
|Long-term debt (including current portion)|$9,945|$327|$1,911|$1,840|$5,867|
|Interest on debt-1|5,656|459|872|691|3,634|
|Pension and other postretirement cash requirements|15,476|779|3,412|3,969|7,316|
|Capital lease obligations|144|60|64|13|7|
|Operating lease obligations|1,494|239|400|235|620|
|Purchase obligations not recorded on the Consolidated Statements of Financial Position|107,564|38,458|31,381|20,478|17,247|
|Purchase obligations recorded on the Consolidated Statements of Financial Position|17,415|16,652|746|3|14|
|Total contractual obligations-2|$157,694|$56,974|$38,786|$27,229|$34,705|

(1) Includes interest on variable rate debt calculated based on interest rates at December 31, 2016.

Variable rate debt was 3% of our total debt at December 31, 2016.

As of December 31, 2016, our net liability for income taxes payable, including uncertain tax positions of $1,557 million, was $1,169 million.

For further discussion of income taxes, see Note 4 to our Consolidated Financial Statements.

We are not able to reasonably estimate the timing of future cash flows related to uncertain tax positions.

Pension and Other Postretirement Benefits Pension cash requirements are based on an estimate of our minimum funding requirements, pursuant to ERISA regulations, although we may make additional discretionary contributions.

Estimates of other postretirement benefits are based on both our estimated future benefit payments and the estimated contributions to plans that are funded through trusts.

Purchase Obligations Purchase obligations represent contractual agreements to purchase goods or services that are legally binding; specify a fixed, minimum or range of quantities; specify a fixed, minimum, variable, or indexed price provision; and specify approximate timing of the transaction.

Purchase obligations include amounts recorded as well as amounts that are not recorded on the Consolidated Statements of Financial Position.

2007: The gain from asset sales relates to the sale of the Corporation’s interests in the Scott and Telford fields in the United Kingdom North Sea.

The charge for asset impairments relates to two mature fields also in the United Kingdom North Sea.

The estimated production imbalance settlements represent a charge for adjustments to prior meter readings at two offshore fields, which are recorded as a reduction of sales and other operating revenues.2006: The gains from asset sales relate to the sale of certain United States oil and gas producing properties located in the Permian Basin in Texas and New Mexico and onshore Gulf Coast.

The accrued office closing cost relates to vacated leased office space in the United Kingdom.

The related expenses are reflected principally in general and administrative expenses.

The income tax adjustment represents a one-time adjustment to the Corporation’s deferred tax liability resulting from an increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%.

The Corporation’s future Exploration and Production earnings may be impacted by external factors, such as political risk, volatility in the selling prices of crude oil and natural gas, reserve and production changes, industry cost inflation, exploration expenses, the effects of weather and changes in foreign exchange and income tax rates.

Marketing and Refining Earnings from Marketing and Refining activities amounted to $277 million in 2008, $300 million in 2007 and $394 million in 2006.

After considering the liquidation of LIFO inventories reflected in the table on page 21 and discussed below, the earnings were $277 million, $276 million and $394 million, respectively.

Refining: Refining earnings, which consist of the Corporation’s share of HOVENSA’s results, Port Reading earnings, interest income on a note receivable from PDVSA and results of other miscellaneous operating activities, were $73 million in 2008, $193 million in 2007, and $240 million in 2006.

The Corporation’s share of HOVENSA’s net income was $27 million ($44 million before income taxes) in 2008, $108 million ($176 million before income taxes) in 2007 and $124 million ($201 million before income taxes) in 2006.

The lower earnings in 2008 and 2007, compared with the respective prior years, were principally due to lower refining margins.

The 2008 utilization rate for the fluid catalytic cracking unit at HOVENSA reflects lower utilization due to weak refining margins, planned and unplanned maintenance of certain units, and a refinery wide shut down for Hurricane Omar.

In 2007, the coker unit at HOVENSAwas shutdown for approximately 30 days for a scheduled turnaround.

Certain related processing units were also included in this turnaround.

In 2006, the fluid catalytic cracking unit at HOVENSA was shutdown for approximately 22 days of unscheduled maintenance.

Cash distributions received by the Corporation from HOVENSA were $50 million in 2008, $300 million in 2007 and $400 million in 2006.

Pre-tax interest income on the PDVSA note was $4 million, $9 million and $15 million in 2008, 2007 and 2006, respectively.

Interest income is reflected in other income in the income statement.

At December 31, 2008, the remaining balance of the PDVSA note was $15 million, which was fully repaid in February 2009.

Port Reading and other after-tax refining earnings were $43 million in 2008, $79 million in 2007 and $107 million in 2006, also reflecting lower refining margins.

The following table summarizes refinery utilization rates:

* Refinery utilization in 2007 and 2006 is based on capacity of 65 thousand barrels per day

Lending Activities People’s United Financial conducts its lending activities principally through its Commercial Banking and Retail and Business Banking operating segments.

People’s United Financial’s lending activities consist of originating loans secured by commercial and residential properties, and extending secured and unsecured loans to commercial and consumer customers.

Total loans increased $2.65 billion in 2013 compared to 2012 and increased $1.35 billion in 2012 compared to 2011.

People’s United Financial acquired loans with fair values of $1.87 billion in 2011 and $3.49 billion in 2010.

Loans acquired in connection with business combinations beginning in 2010 are referred to as ‘acquired’ loans as a result of the manner in which they are accounted for (see further discussion under ‘Acquired Loans’ in Note 1 to the Consolidated Financial Statements).

All other loans are referred to as ‘originated’ loans.

At December 31, 2013 and 2012, the carrying amount of the acquired loan portfolio totaled $1.53 billion and $2.24 billion, respectively.

The following table summarizes the loan portfolio before deducting the allowance for loan losses:

(1) Following the Company’s 2010 acquisitions and core system conversion, the Company undertook a portfolio review to ensure consistent classification of commercial loans in an effort to align policy across the Company’s expanded franchise and better conform to industry practice for such loans.

As a result, approximately $875 million of loans secured, in part, by owner-occupied commercial properties were reclassified from commercial real estate loans to commercial and industrial loans as of March 31, 2011.

The primary collateral for these loans generally consists of the borrower’s general business assets (i. e.  non-real estate collateral) and the loans were underwritten principally on the basis of the adequacy of business cash flows.

This reclassification is being applied prospectively as it was deemed impracticable to do so for prior periods due to the fact that the underlying loan information is no longer available as it previously resided on legacy loan systems that are no longer utilized or supported following the Company’s core system conversion.

Plywood prices increased from 2006, providing a partial offset to the lower prices realized for OSB.

– The contribution from engineered I-joists and engineered solid section declined $180 million – about 50 percent from lower price realizations and 50 percent from reduced shipment volumes.

– The contribution from sales of other building products declined approximately $40 million primarily as a result of reduced shipment volumes due to the decline in demand.

?The net effect of legal settlements adversely affected the segment by $483 million.2007 included $21 million of charges for legal settlements.2006 included income of $462 million, including: – $344 million of income from refunds of countervailing and anti-dumping deposits relating to the softwood lumber dispute between the U. S.  and Canada, – $95 million of income from a reversal of the reserve for alder antitrust litigation and – $23 million of income from a reduction in the reserve for hardboard siding claims.

?Charges resulting from the closure or sale of various manufacturing facilities and distribution locations.

?Gains on the sale of operations declined by $51 million as 2006 included the sale of the North American composite panel operations and 2007 had no comparable activity.

These decreases were partially offset by lower raw material, manufacturing, and selling and general administrative costs, which increased the contribution to earnings by approximately $290 million.

OUR OUTLOOK The segment recognized a fourth-quarter loss of $960 million, which included $761 million of charges for asset impairments, closures and restructuring activities.

The operating results reflected significantly lower prices for lumber and oriented strand board and reduced sales volumes as a result of the continued decline in the housing market.

We expect challenging housing market conditions to continue into the first quarter 2009 and expect first-quarter results for the segment to be comparable to the fourth quarter of 2008, excluding asset impairment, closure and restructuring charges.

CELLULOSE FIBERS HOW WE DID IN 2008 We report sales volume and annual production data for our Cellulose Fibers business segment in Our Business/What We Do/Cellulose Fibers.

Here is a comparison of net sales and revenues and contribution to earnings for the last three years: Net Sales and Revenues and Contribution to Earnings for Cellulose Fibers

Answer: 3551.7


Question: What was the total amount of the adjusted profit in the years / sections where profit of profit before taxes is greater than 5000? (in million)

def solution():
    # Define variables name and value
    profit_before_taxes_2018 = 7822
    profit_before_taxes_2017 = 0
    restructuring_costs_2018 = 386
    mark_to_market_losses_2018 = 495

    # Do math calculation to get the answer
    answer = (profit_before_taxes_2018 + restructuring_costs_2018) + (profit_before_taxes_2017 + mark_to_market_losses_2018)

    return answer

print(solution())

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our discussion of cautionary statements and significant risks to the company’s business under Item 1A.

Risk Factors of the 2018 Form?10-K.  OVERVIEW Our sales and revenues for 2018 were $54.722 billion, a 20?percent increase from 2017 sales and revenues of $45.462?billion.

The increase was primarily due to higher sales volume, mostly due to improved demand across all regions and across the three primary segments.

Profit per share for 2018 was $10.26, compared to profit per share of $1.26 in 2017.

Profit was $6.147 billion in 2018, compared with $754 million in 2017.

The increase was primarily due to lower tax expense, higher sales volume, decreased restructuring costs and improved price realization.

The increase was partially offset by higher manufacturing costs and selling, general and administrative (SG&A) and research and development (R&D) expenses and lower profit from the Financial Products Segment.

Fourth-quarter 2018 sales and revenues were $14.342 billion, up $1.446 billion, or 11 percent, from $12.896 billion in the fourth quarter of 2017.

Fourth-quarter 2018 profit was $1.78 per share, compared with a loss of $2.18 per share in the fourth quarter of 2017.

Fourth-quarter 2018 profit was $1.048 billion, compared with a loss of $1.299 billion in 2017.

Highlights for 2018 include: z Sales and revenues in 2018 were $54.722 billion, up 20?percent from 2017.

Sales improved in all regions and across the three primary segments.

z Operating profit as a percent of sales and revenues was 15.2?percent in 2018, compared with 9.8 percent in 2017.

Adjusted operating profit margin was 15.9 percent in 2018, compared with 12.5 percent in 2017.  z Profit was $10.26 per share for 2018, and excluding the items in the table below, adjusted profit per share was $11.22.

For 2017 profit was $1.26 per share, and excluding the items in the table below, adjusted profit per share was $6.88.  z In order for our results to be more meaningful to our readers, we have separately quantified the impact of several significant items:

||Full Year 2018|Full Year 2017|
|(Millions of dollars)|Profit Before Taxes|ProfitPer Share|Profit Before Taxes|ProfitPer Share|
|Profit|$7,822|$10.26|$4,082|$1.26|
|Restructuring costs|386|0.50|1,256|1.68|
|Mark-to-market losses|495|0.64|301|0.26|
|Deferred tax valuation allowance adjustments|—|-0.01|—|-0.18|
|U.S. tax reform impact|—|-0.17|—|3.95|
|Gain on sale of equity investment|—|—|-85|-0.09|
|Adjusted profit|$8,703|$11.22|$5,554|$6.88|

z Machinery, Energy & Transportation (ME&T) operating cash flow for 2018 was about $6.3 billion, more than sufficient to cover capital expenditures and dividends.

ME&T operating cash flow for 2017 was about $5.5 billion.

Restructuring Costs In recent years, we have incurred substantial restructuring costs to achieve a flexible and competitive cost structure.

During 2018, we incurred $386 million of restructuring costs related to restructuring actions across the company.

During 2017, we incurred $1.256 billion of restructuring costs with about half related to the closure of the facility in Gosselies, Belgium, and the remainder related to other restructuring actions across the company.

Although we expect restructuring to continue as part of ongoing business activities, restructuring costs should be lower in 2019 than 2018.

Notes: z Glossary of terms included on pages 33-34; first occurrence of terms shown in bold italics.

z Information on non-GAAP financial measures is included on pages 42-43.

Recognition of finance revenue and rental revenue is suspended and the account is placed on non-accrual status when management determines that collection of future income is not probable (generally after 120 days past due).

Recognition is resumed, and previously suspended income is recognized, when the account becomes current and collection of remaining amounts is considered probable.

Revenues are presented net of sales and other related taxes.3.

Stock-Based Compensation Our stock-based compensation plans primarily provide for the granting of stock options, stock-settled stock appreciation rights (SARs), restricted stock units (RSUs) and performance-based restricted stock units (PRSUs) to Officers and other key employees, as well as non-employee Directors.

Stock options permit a holder to buy Caterpillar stock at the stock’s price when the option was granted.

SARs permit a holder the right to receive the value in shares of the appreciation in Caterpillar stock that occurred from the date the right was granted up to the date of exercise.

RSUs are agreements to issue shares of Caterpillar stock at the time of vesting.

PRSUs are similar to RSUs and include performance conditions in the vesting terms of the award.

Our long-standing practices and policies specify that all stockbased compensation awards are approved by the Compensation Committee (the Committee) of the Board of Directors.

The award approval process specifies the grant date, value and terms of the award.

The same terms and conditions are consistently applied to all employee grants, including Officers.

The Committee approves all individual Officer grants.

The number of stock-based compensation award units included in an individual’s award is determined based on the methodology approved by the Committee.

The exercise price methodology?approved by the Committee is the closing price of the Company stock on the date of the grant.

In June of 2014, shareholders approved the Caterpillar Inc.  2014 Long-Term Incentive Plan (the Plan) under which all new stock-based compensation awards are granted.

In June of 2017, the Plan was amended and restated.

The Plan initially provided that up to 38,800,000 Common Shares would be reserved for future issuance under the Plan, subject to adjustment in certain events.

Subsequent to the shareholder approval of the amendment and restatement of the Plan, an additional 36,000,000 Common Shares became available for all awards under the Plan.

Common stock issued from Treasury stock under the plans totaled 5,590,641 for 2018, 11,139,748 for 2017 and 4,164,134 for 2016.

The total number of shares authorized for equity awards under the amended and restated Caterpillar Inc.  2014 Long-Term Incentive Plan is 74,800,000, of which 44,139,162 shares remained available for issuance as of December?31,?2018.

Stock option and RSU awards generally vest according to a threeyear graded vesting schedule.

One-third of the award will become vested on the first anniversary of the grant date, one-third of the award will become vested on the second anniversary of the grant date and one-third of the award will become vested on the third anniversary of the grant date.

PRSU awards generally have a threeyear performance period and cliff vest at the end of the period based upon achievement of performance targets established at the time of grant.

Upon separation from service, if the participant is 55 years of age or older with more than five years of service, the participant meets the criteria for a “Long Service Separation.

” Award terms for awards granted in 2016 allow for immediate vesting upon separation of all outstanding options and RSUs with no requisite service period for employees who meet the criteria for a “Long Service Separation.

” Compensation expense for the 2016 grant was fully recognized immediately on the grant date for these employees.

Award terms for the 2018 and 2017 grants allow for continued vesting as of each vesting date specified in the award document for employees who meet the criteria for a “Long Service Separation” and fulfill a requisite service period of six months.

Compensation expense for eligible employees for the 2018 and 2017 grants was recognized over the period from the grant date to the end date of the six-month requisite service period.

For employees who become eligible for a “Long Service Separation” subsequent to the end date of the six-month requisite service period and prior to the completion of the vesting period, compensation expense is recognized over the period from the grant date to the date eligibility is achieved.

At grant, SARs and option awards have a term life of ten years.

For awards granted prior to 2016, if the “Long Service Separation” criteria are met, the vested options/SARs have a life that is the lesser of ten years from the original grant date or five years from the separation date.

For awards granted in 2018, 2017, and 2016, the vested options have a life equal to ten years from the original grant date.

Prior to 2017, all outstanding PRSU awards granted to employees eligible for a “Long Service Separation” may vest at the end of the performance period based upon achievement of the performance target.

Compensation expense for the 2016 PRSU grant was fully recognized immediately on the grant date for these employees.

For PRSU awards granted in 2018 and 2017, only a prorated number of shares may vest at the end of the performance period based upon achievement of the performance target, with the proration based upon the number of months of continuous employment during the three-year performance period.

Employees with a “Long Service Separation” must also fulfill a six-month requisite service period in order to be eligible for the prorated vesting of outstanding PRSU awards granted in 2018 and 2017.

Compensation expense for the 2018 and 2017 PRSU grants is being recognized on a straight-line basis over the three-year performance period for all participants.

Accounting guidance on share-based payments requires companies to estimate the fair value of options/SARs on the date of grant using an option-pricing model.

The fair value of our option/SAR grants was estimated using a lattice-based option-pricing model.

The latticebased option-pricing model considers a range of assumptions related to volatility, risk-free interest rate and historical employee behavior.

Expected volatility was based on historical Caterpillar stock price movement and current implied volatilities from traded options on Caterpillar stock.

The risk-free interest rate was based on U. S.  Treasury security yields at the time of grant.

The weighted-average dividend yield was based on historical information.

The expected life was determined from the lattice-based model.

The latticebased model incorporated exercise and post vesting forfeiture assumptions based on analysis of historical data.

The following table provides the assumptions used in determining the fair value of the Option/SAR awards for the years ended December?31, 2018, 2017 and 2016, respectively.

||Grant Year|
||2018|2017|2016|
|Weighted-average dividend yield|2.7%|3.4%|3.2%|
|Weighted-average volatility|30.2%|29.2%|31.1%|
|Range of volatilities|21.5-33.0%|22.1-33.0%|22.5-33.4%|
|Range of risk-free interest rates|2.02-2.87%|0.81-2.35%|0.62-1.73%|
|Weighted-average expected lives|8 years|8 years|8 years|

Answer: 8703.0


Question: In the year with largest amount of Management and financial advice fees, what's the sum of Distribution fees and Net investment income? (in million)

def solution():
    # Define variables name and value
    distribution_fees = 91
    net_investment_income = 439

    # Do math calculation to get the answer
    answer = distribution_fees + net_investment_income

    return answer

Protection The following table presents the results of operations of our Protection segment on an operating basis:

||Years Ended December 31,|||
||2013|2012|Change|
||(in millions)||
|Revenues|||||
|Management and financial advice fees|$58|$55|$3|5%|
|Distribution fees|91|91|—|—|
|Net investment income|439|429|10|2|
|Premiums|1,188|1,121|67|6|
|Other revenues|410|392|18|5|
|Total revenues|2,186|2,088|98|5|
|Banking and deposit interest expense|—|1|-1|—|
|Total net revenues|2,186|2,087|99|5|
|Expenses|||||
|Distribution expenses|62|53|9|17|
|Interest credited to fixed accounts|145|143|2|1|
|Benefits, claims, losses and settlement expenses|1,252|1,146|106|9|
|Amortization of deferred acquisition costs|118|110|8|7|
|Interest and debt expense|25|24|1|4|
|General and administrative expense|248|238|10|4|
|Total expenses|1,850|1,714|136|8|
|Operating earnings|$336|$373|$-37|-10%|

Our Protection segment pretax operating income, which excludes net realized gains or losses and the market impact on indexed universal life benefits (net of hedges and the related DAC amortization, unearned revenue amortization and the reinsurance accrual), decreased $37 million, or 10%, to $336 million for the year ended December 31, 2013 compared to $373 million for the prior year reflecting lower auto and home earnings.

Net Revenues Net revenues, which exclude net realized gains or losses and the unearned revenue amortization and the reinsurance accrual offset to the market impact on indexed universal life benefits, increased $99 million, or 5%, to $2.2 billion for the year ended December 31, 2013 compared to $2.1 billion for the prior year primarily due to the impact of unlocking and growth in auto and home premiums, as well as an increase in net investment income.

Net investment income, which excludes net realized gains or losses, increased $10 million, or 2%, to $439 million for the year ended December 31, 2013 compared to $429 million for the prior year due to an increase in investment income on fixed maturities driven by higher average invested assets for life and health.

Premiums increased $67 million, or 6%, to $1.2 billion for the year ended December 31, 2013 compared to $1.1 billion for the prior year primarily due to growth in auto and home premiums driven by new policy sales growth across market segments, primarily from our affinity relationships with Costco and Progressive.

Auto and home policy counts increased 11% year-over-year.

Other revenues increased $18 million, or 5%, to $410 million for the year ended December 31, 2013 compared to $392 million for the prior year primarily due to an $18 million unfavorable impact from unlocking for the year ended December 31, 2013 compared to a $41 million unfavorable impact in the prior year.

The primary driver of the unlocking impact to other revenues in both periods was lower projected gains on reinsurance contracts resulting from favorable mortality experience.

Expenses Total expenses, which exclude the market impact on indexed universal life benefits (net of hedges and the related DAC amortization), increased $136 million, or 8%, to $1.9 billion for the year ended December 31, 2013 compared to $1.7 billion for the prior year primarily due to an increase in benefits, claims, losses and settlement expenses.

Distribution expenses increased $9 million, or 17%, to $62 million for the year ended December 31, 2013 compared to $53 million for the prior year driven by higher compensation related to higher sales.

Benefits, claims, losses and settlement expenses, which exclude the market impact on indexed universal life benefits (net of hedges), increased $106 million, or 9%, to $1.3 billion for the year ended December 31, 2013 compared to $1.1 billion for the prior year due to the impact of unlocking, higher expenses related to our auto and home business, an

We expect net interest expense of approximately $135 to $140 in 2011, subject to capital deployment activities during the year.

Our effective tax rate was 31.2 percent in 2008, 31.5 percent in 2009 and 30.7 percent in 2010.

The 2008 rate includeda$35, or approximately $0.09 per-share, benefit from the settlement of tax refund litigation, which reduced the 2008 tax rate by 100 basis points.

We anticipate an effective tax rate of approximately 31 percent in 2011.

For additional discussion of tax matters, see Note E to the Consolidated Financial Statements.

In 2008, we entered into an agreement to sell our Spanish nitrocellulose operation and recognized a pretax loss of $11 in discontinued operations in anticipation of the sale.

The sale of this operation was completed in 2010.

Our reported revenues exclude the revenues associated with this divested business.

We have presented the operating results of this business, along with the loss from the sale, as discontinued operations, net of income taxes.

R E V I EW OF BU S I NESS GROU P S AEROSPACE Review of 2010 vs.  2009

The Aerospace group’s revenues increased in 2010 compared with 2009 due primarily to steady growth in aircraft services activity throughout the year.

Aircraft manufacturing and outfitting revenues remained consistent with 2009 levels, with an increase in manufac- turing volume offset by reduced outfitting work.

Aircraft manufacturing revenues increased 9 percent in 2010, the result of additional deliveries and a more favorable mix of green Gulfstream aircraft.

The decline in aircraft outfitting revenues was associated primarily with the group’s completions work for other original equipment manufacturers (OEMs), reflecting decreased OEM production across the broader business-jet market.

Aircraft services revenues, which include both Gulfstream and Jet Aviation’s maintenance and repair work, fixed-base operations and aircraft management services, increased 15 percent in 2010, reflecting the growing installed base of business-jet aircraft and increased utilization as the business-jet market recovers following the economic downturn.

Revenues from sales of pre-owned aircraft were down slightly from 2009.

The group’s operating earnings improved significantly in 2010 compared with 2009, with improvements in all areas of the group’s portfolio.

The components of the earnings growth were as follows:

|Aircraft manufacturing and outfitting|$68|
|Pre-owned aircraft|40|
|Aircraft services|29|
|SG&A/other|16|
|Total increase in operating earnings|$153|

The group’s aircraft manufacturing and outfitting earnings were up in 2010 compared with 2009 due to the increase in aircraft manufacturing volume, as well as improved pricing on large-cabin aircraft and mix shift within large-cabin models.

This increase was offset in part by reduced liquidated damages associated with fewer customer defaults.

Margins for these activities were up 190 basis points compared with 2009.

Pre-owned aircraft earnings improved significantly from 2009, when the group wrote down the carrying value of its pre-owned aircraft inventory.

Pricing in the pre-owned market has improved since mid-2009, particularly for large-cabin aircraft, although inventories across the industry remain higher than historic norms.

In 2010, the Aerospace group realized modest profits on its pre-owned sales, took no pre-owned aircraft write-downs and ended the year with no pre-owned aircraft in inventory.

Consistent with the increased volume, aircraft services earnings continued to improve from 2009.

Margins associated with aircraft services were up 70 basis points in 2010 due to improved marketplace pricing.

The group’s operating earnings in 2010 were also favorably impacted by the timing of R&D expenditures and the absence of severance costs associated with workforce reductions in 2009.

As a result of the factors discussed above, the group’s overall operating margins increased 250 basis points in 2010 compared with 2009.  Review of 2009 vs.  2008

The Aerospace group’s revenues decreased in 2009, the result ofadecline in sales of Gulfstream aircraft that was offset in part by the addition of Jet Aviation, which we acquired in the fourth quarter of 2008.

We reduced Gulfstream’s 2009 aircraft production, primarily in the group’s mid-cabin

In summary, our cash flows for each period were as follows:

|Years Ended(In Millions)|Dec 30,2017|Dec 31,2016|Dec 26,2015|
|Net cash provided by operating activities|$22,110|$21,808|$19,018|
|Net cash used for investing activities|-15,762|-25,817|-8,183|
|Net cash provided by (used for) financing activities|-8,475|-5,739|1,912|
|Net increase (decrease) in cash and cash equivalents|$-2,127|$-9,748|$12,747|

OPERATING ACTIVITIES Cash provided by operating activities is net income adjusted for certain non-cash items and changes in assets and liabilities.

For 2017 compared to 2016, the $302 million increase in cash provided by operating activities was due to changes to working capital partially offset by adjustments for non-cash items and lower net income.

Tax Reform did not have an impact on our 2017 cash provided by operating activities.

The increase in cash provided by operating activities was driven by increased income before taxes and $1.0 billion receipts of customer deposits.

These increases were partially offset by increased inventory and accounts receivable.

Income taxes paid, net of refunds, in 2017 compared to 2016 were $2.9 billion higher due to higher income before taxes, taxable gains on sales of ASML, and taxes on the ISecG divestiture.

We expect approximately $2.0 billion of additional customer deposits in 2018.

For 2016 compared to 2015, the $2.8 billion increase in cash provided by operating activities was due to adjustments for non-cash items and changes in working capital, partially offset by lower net income.

The adjustments for non-cash items were higher in 2016 primarily due to restructuring and other charges and the change in deferred taxes, partially offset by lower depreciation.

INVESTING ACTIVITIES Investing cash flows consist primarily of capital expenditures; investment purchases, sales, maturities, and disposals; and proceeds from divestitures and cash used for acquisitions.

Our capital expenditures were $11.8 billion in 2017 ($9.6 billion in 2016 and $7.3 billion in 2015).

The decrease in cash used for investing activities in 2017 compared to 2016 was primarily due to higher net activity of available-for sale-investments in 2017, proceeds from our divestiture of ISecG in 2017, and higher maturities and sales of trading assets in 2017.

This activity was partially offset by higher capital expenditures in 2017.

The increase in cash used for investing activities in 2016 compared to 2015 was primarily due to our completed acquisition of Altera, net purchases of trading assets in 2016 compared to net sales of trading assets in 2015, and higher capital expenditures in 2016.

This increase was partially offset by lower investments in non-marketable equity investments.

FINANCING ACTIVITIES Financing cash flows consist primarily of repurchases of common stock, payment of dividends to stockholders, issuance and repayment of short-term and long-term debt, and proceeds from the sale of shares of common stock through employee equity incentive plans.

The increase in cash used for financing activities in 2017 compared to 2016 was primarily due to net long-term debt activity, which was a use of cash in 2017 compared to a source of cash in 2016.

During 2017, we repurchased $3.6 billion of common stock under our authorized common stock repurchase program, compared to $2.6 billion in 2016.

As of December 30, 2017, $13.2 billion remained available for repurchasing common stock under the existing repurchase authorization limit.

We base our level of common stock repurchases on internal cash management decisions, and this level may fluctuate.

Proceeds from the sale of common stock through employee equity incentive plans totaled $770 million in 2017 compared to $1.1 billion in 2016.

Our total dividend payments were $5.1 billion in 2017 compared to $4.9 billion in 2016.

We have paid a cash dividend in each of the past 101 quarters.

In January 2018, our Board of Directors approved an increase to our cash dividend to $1.20 per share on an annual basis.

The board has declared a quarterly cash dividend of $0.30 per share of common stock for Q1 2018.

The dividend is payable on March 1, 2018 to stockholders of record on February 7, 2018.

Cash was used for financing activities in 2016 compared to cash provided by financing activities in 2015, primarily due to fewer debt issuances and the repayment of debt in 2016.

This activity was partially offset by repayment of commercial paper in 2015 and fewer common stock repurchases in 2016.

Answer: 530.0


Question: what was the value , in millions of dollars , of net revenues in 2007?

def solution():
    # Define variables name and value
    net_revenue_2008 = 2.12 * 1000
    decrease_from_2007 = 112

    # Do math calculation to get the answer
    net_revenue_2007 = net_revenue_2008 + decrease_from_2007

    return net_revenue_2007

DUKE ENERGY CORPORATION· DUKE ENERGY CAROLINAS, LLC· PROGRESS ENERGY INC. · DUKE ENERGY PROGRESS, LLC· DUKE ENERGY FLORIDA, LLC· DUKE ENERGY OHIO, INC. · DUKE ENERGY INDIANA, LLC· PIEDMONT NATURAL GAS COMPANY, INC.

Combined Notes to Consolidated Financial Statements – (Continued) 25.

QUARTERLY FINANCIAL DATA (UNAUDITED) DUKE ENERGY Quarterly EPS amounts may not sum to the full-year total due to changes in the weighted average number of common shares outstanding and rounding.

|(in millions, except per share data)|First Quarter|Second Quarter|Third Quarter|Fourth Quarter|Total|
|2017||||||
|Operating revenues|$5,729|$5,555|$6,482|$5,799|$23,565|
|Operating income|1,437|1,387|1,695|1,262|5,781|
|Income from continuing operations|717|691|957|705|3,070|
|Loss from discontinued operations, net of tax|—|-2|-2|-2|-6|
|Net income|717|689|955|703|3,064|
|Net income attributable to Duke Energy Corporation|716|686|954|703|3,059|
|Earnings per share:||||||
|Income from continuing operations attributable to Duke Energy Corporation common stockholders||||||
|Basic|$1.02|$0.98|$1.36|$1.00|$4.37|
|Diluted|$1.02|$0.98|$1.36|$1.00|$4.37|
|Loss from discontinued operations attributable to Duke Energy Corporation common stockholders||||||
|Basic|$—|$—|$—|$—|$-0.01|
|Diluted|$—|$—|$—|$—|$-0.01|
|Net income attributable to Duke Energy Corporation common stockholders||||||
|Basic|$1.02|$0.98|$1.36|$1.00|$4.36|
|Diluted|$1.02|$0.98|$1.36|$1.00|$4.36|
|2016||||||
|Operating revenues|$5,377|$5,213|$6,576|$5,577|$22,743|
|Operating income|1,240|1,259|1,954|888|5,341|
|Income from continuing operations|577|624|1,001|376|2,578|
|Income (Loss) from discontinued operations, net of tax|122|-112|180|-598|-408|
|Net income (loss)|699|512|1,181|-222|2,170|
|Net income (loss) attributable to Duke Energy Corporation|694|509|1,176|-227|2,152|
|Earnings per share:||||||
|Income from continuing operations attributable to Duke Energy Corporation common stockholders||||||
|Basic|$0.83|$0.90|$1.44|$0.53|$3.71|
|Diluted|$0.83|$0.90|$1.44|$0.53|$3.71|
|Income (Loss) from discontinued operations attributable to Duke Energy Corporation common stockholders||||||
|Basic|$0.18|$-0.16|$0.26|$-0.86|$-0.60|
|Diluted|$0.18|$-0.16|$0.26|$-0.86|$-0.60|
|Net income (loss) attributable to Duke Energy Corporation common stockholders||||||
|Basic|$1.01|$0.74|$1.70|$-0.33|$3.11|
|Diluted|$1.01|$0.74|$1.70|$-0.33|$3.11|

The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years.

|(in millions)|First Quarter|Second Quarter|Third Quarter|Fourth Quarter|Total|
|2017||||||
|Costs to Achieve Piedmont Merger (see Note 2)|$-16|$-30|$-23|$-34|$-103|
|Regulatory Settlements (see Note 4)|—|—|-135|-23|-158|
|Commercial Renewables Impairments (see Notes 10 and 11)|—|—|-84|-18|-102|
|Impacts of the Tax Act (see Note 22)|—|—|—|102|102|
|Total|$-16|$-30|$-242|$27|$-261|
|2016||||||
|Costs to Achieve Mergers (see Note 2)|$-120|$-111|$-84|$-208|$-523|
|Commercial Renewables Impairment (see Note 12)|—|—|-71|—|-71|
|Loss on Sale of International Disposal Group (see Note 2)|—|—|—|-514|-514|
|Impairment of Assets in Central America (see Note 2)|—|-194|—|—|-194|
|Cost Savings Initiatives (see Note 19)|-20|-24|-19|-29|-92|
|Total|$-140|$-329|$-174|$-751|$-1,394|

|(in millions)|First Quarter|Second Quarter|Third Quarter|Fourth Quarter|Total|
|2017||||||
|Costs to Achieve Piedmont Merger (see Note 2)|$-4|$-6|$-5|$-5|$-20|
|Impacts of the Tax Act (see Note 22)|—|—|—|-15|-15|
|Total|$-4|$-6|$-5|$-20|$-35|
|2016||||||
|Costs to Achieve Mergers|$-11|$-12|$-13|$-68|$-104|
|Cost Savings Initiatives (see Note 19)|-10|-10|-8|-11|-39|
|Total|$-21|$-22|$-21|$-79|$-143|

PART II The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Carolinas.

The below percentages for retail customer classes represent billed sales only.

Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

|Increase (Decrease) over prior year|2017|2016|
|Residential sales|-4.8%|0.1%|
|General service sales|-1.8%|0.7%|
|Industrial sales|-0.8%|-0.9%|
|Wholesale power sales|6.3%|9.8%|
|Joint dispatch sales|18.2%|-2.3%|
|Total sales|-1.4%|1.8%|
|Average number of customers|1.5%|1.4%|

Year Ended December 31, 2017, as Compared to 2016 Operating Revenues.

a $179 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year.

a $74 million increase in rider revenues and retail pricing primarily related to energy efficiency programs; ?

a $41 million increase in weather-normal sales volumes to retail customers, net of fuel revenues; ?

a $30 million increase in fuel revenues primarily due to changes in generation mix partially offset by lower retail sales; and ?

a $7 million increase in wholesale power revenues, net of sharing and fuel, primarily due to additional volumes for customers served under long-term contracts.

a $145 million decrease in operations, maintenance and other expense primarily due to lower expenses at generating plants, lower costs associated with merger commitments related to the Piedmont acquisition in 2016, lower severance expenses, and lower employee benefit costs, partially offset by higher energy efficiency program costs.

a $25 million increase in fuel expense (including purchased power) primarily due to changes in generation mix, partially offset by lower retail sales; and ?

a $15 million increase in depreciation and amortization expense primarily due to additional plant in service, partially offset by lower amortization of certain regulatory assets.

The variance was primarily due to a decrease in recognition of post in-service equity returns for projects that had been completed prior to being reflected in customer rates.

The variance was primarily due to an increase in pretax income and the impact of the Tax Act, offset by the impact of research credits and the manufacturing deduction.

See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.

Matters Impacting Future Results An order from regulatory authorities disallowing recovery of costs related to closure of ash impoundments could have an adverse impact on Duke Energy Carolinas’ financial position, results of operations and cash flows.

See Notes 4 and 9 to the Consolidated Financial Statements, “Regulatory Matters” and “Asset Retirement Obligations,” respectively, for additional information.

On May 18, 2016, the NCDEQ issued proposed risk classifications for all coal ash surface impoundments in North Carolina.

All ash impoundments not previously designated as high priority by the Coal Ash Act were designated as intermediate risk.

Certain impoundments classified as intermediate risk, however, may be reassessed in the future as low risk pursuant to legislation enacted on July 14, 2016.

Duke Energy Carolinas’ estimated AROs related to the closure of North Carolina ash impoundments are based upon the mandated closure method or a probability weighting of potential closure methods for the impoundments that may be reassessed to low risk.

As the final risk ranking classifications in North Carolina are delineated, final closure plans and corrective action measures are developed and approved for each site, the closure work progresses, and the closure method scope and remedial action methods are determined, the complexity of work and the amount of coal combustion material could be different than originally estimated and, therefore, could materially impact Duke Energy Carolinas’ financial position.

See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information.

Duke Energy Carolinas is a party to multiple lawsuits and subject to fines and other penalties related to operations at certain North Carolina facilities with ash basins.

The outcome of these lawsuits, fines and penalties could have an adverse impact on Duke Energy Carolinas’ financial position, results of operations and cash flows.

See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information.

Duke Energy Carolinas filed a general rate case on August 25, 2017, to recover costs of complying with CCR regulations and the Coal Ash Act, as well as costs of capital investments in generation, transmission and distribution systems and any increase in expenditures subsequent to previous rate cases.

Duke Energy Carolinas’ earnings could be adversely impacted if the rate increase is delayed or denied by the NCUC.

Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.

Our non-operating investment activity resulted in net losses of $12.7 million in 2009 and $52.3 million in 2008.

The improvement of nearly $40 million is primarily attributable to a reduction in the other than temporary impairments recognized on our investments in sponsored mutual funds in 2009 versus 2008.

The following table details our related mutual fund investment gains and losses (in millions) during the past two years.

||2008|2009|Change|
|Other than temporary impairments recognized|$-91.3|$-36.1|$55.2|
|Capital gain distributions received|5.6|2.0|-3.6|
|Net gain (loss) realized on fund dispositions|-4.5|7.4|11.9|
|Net loss recognized on fund holdings|$-90.2|$-26.7|$63.5|

Lower income of $16 million from our money market holdings due to the significantly lower interest rate environment offset the improvement experienced with our fund investments.

There is no impairment of any of our mutual fund investments at December 31, 2009.

The 2009 provision for income taxes as a percentage of pretax income is 37.1%, down from 38.4% in 2008 and .9% lower than our present estimate of 38.0% for the 2010 effective tax rate.

Our 2009 provision includes reductions of prior years’ tax provisions and discrete nonrecurring benefits that lowered our 2009 effective tax rate by 1.0%.2008 versus 2007.

Investment advisory revenues decreased 6.3%, or $118 million, to $1.76 billion in 2008 as average assets under our management decreased $16 billion to $358.2 billion.

The average annualized fee rate earned on our assets under management was 49.2 basis points in 2008, down from the 50.2 basis points earned in 2007, as lower equity market valuations resulted in a greater percentage of our assets under management being attributable to lower fee fixed income portfolios.

Continuing stress on the financial markets and resulting lower equity valuations as 2008 progressed resulted in lower average assets under our management, lower investment advisory fees and lower net income as compared to prior periods.

Net revenues decreased 5%, or $112 million, to $2.12 billion.

Operating expenses were $1.27 billion in 2008, up 2.9% or $36 million from 2007.

Net operating income for 2008 decreased $147.9 million, or 14.8%, to $848.5 million.

Higher operating expenses in 2008 and decreased market valuations during the latter half of 2008, which lowered our assets under management and advisory revenues, resulted in our 2008 operating margin declining to 40.1% from 44.7% in 2007.

Non-operating investment losses in 2008 were $52.3 million as compared to investment income of $80.4 million in 2007.

Investment losses in 2008 include non-cash charges of $91.3 million for the other than temporary impairment of certain of the firm’s investments in sponsored mutual funds.

Net income in 2008 fell 27% or nearly $180 million from 2007.

Diluted earnings per share, after the retrospective application of new accounting guidance effective in 2009, decreased to $1.81, down $.59 or 24.6% from $2.40 in 2007.

A non-operating charge to recognize other than temporary impairments of our sponsored mutual fund investments reduced diluted earnings per share by $.21 in 2008.

Investment advisory revenues earned from the T.  Rowe Price mutual funds distributed in the United States decreased 8.5%, or $114.5 million, to $1.24 billion.

Average mutual fund assets were $216.1 billion in 2008, down $16.7 billion from 2007.

Mutual fund assets at December 31, 2008, were $164.4 billion, down $81.6 billion from the end of 2007.

Net inflows to the mutual funds during 2008 were $3.9 billion, including $1.9 billion to the money funds, $1.1 billion to the bond funds, and $.9 billion to the stock funds.

The Value, Equity Index 500, and Emerging Markets stock funds combined to add $4.1 billion, while the Mid-Cap Growth and Equity Income stock funds had net redemptions of $2.2 billion.

Net fund inflows of $6.2 billion originated in our target-date Retirement Funds, which in turn invest in other T.  Rowe Price funds.

Fund net inflow amounts in 2008 are presented net of $1.3 billion that was transferred to target-date trusts from the Retirement Funds during the year.

Decreases in market valuations and income not reinvested lowered our mutual fund assets under management by $85.5 billion during 2008.

Investment advisory revenues earned on the other investment portfolios that we manage decreased $3.6 million to $522.2 million.

Average assets in these portfolios were $142.1 billion during 2008, up slightly from $141.4 billion in 2007.

These minor changes, each less than 1%, are attributable to the timing of declining equity market valuations and cash flows among our separate account and subadvised portfolios.

Net inflows, primarily from institutional investors, were $13.2 billion during 2008, including the $1.3 billion transferred from the Retirement Funds to target-date trusts.

Decreases in market valuations, net of income, lowered our assets under management in these portfolios by $55.3 billion during 2008.

Answer: 2232.0


Question: In the year with largest amount of Payments, what's the increasing rate of Marketplaces?

def solution():
    # Define variables name and value
    marketplaces_2010 = 1071499
    marketplaces_2009 = 968266

    # Do math calculation to get the answer
    increase = marketplaces_2010 - marketplaces_2009
    answer = (increase / marketplaces_2009) * 100

    return answer

Summary of Cost of Net Revenues The following table summarizes changes in cost of net revenues:

Cost of Net Revenues Cost of net revenues consists primarily of costs associated with payment processing, customer support and site operations and Skype telecommunications (through November 2009).

Significant components of these costs include bank transaction fees, credit card interchange and assessment fees, interest expense on indebtedness incurred to finance the purchase of consumer loans receivable by Bill Me Later, employee compensation, contractor costs, facilities costs, depreciation of equipment and amortization expense.

Marketplaces Marketplaces cost of net revenues increased $103.2 million, or 11%, in 2010 compared to 2009.

The increase during 2010 was due primarily to the inclusion of a full year of costs attributable to Gmarket and increased site operation costs.

Marketplaces cost of net revenues as a percentage of Marketplaces net revenues increased slightly in 2010 compared to 2009 due primarily to the addition of Gmarket, the settlement of a lawsuit and the establishment of a reserve related to certain indirect tax positions (recorded as a reduction in revenue).

Marketplaces cost of net revenues increased $61.1 million, or 7%, in 2009 compared to 2008.

The increase during 2009 was due primarily to the inclusion of costs attributable to Gmarket and Den Bl?

Avis and BilBasen, partially offset by a decrease in customer support and site operations costs associated with our restructuring activities.

Marketplaces cost of net revenues increased as a percentage of Marketplaces net revenues during 2009 compared to 2008 due primarily to the impact of foreign currency movements on revenues, pricing initiatives (which are recorded as a reduction in revenue) and faster growth in our lower margin Marketplaces businesses.

Payments Payments cost of net revenues increased $272.5 million, or 22%, in 2010 compared to 2009.

The increase in cost of net revenues was primarily due to the impact from our growth in net TPV.

Payments cost of net revenues as a percentage of Payments net revenues decreased slightly in 2010 compared to 2009 due primarily to improved leverage of our customer support infrastructure and existing site operations.

expect that these credit rating agencies will continue to monitor developments in our planned separation of PayPal, including the capital structure for each company after separation, which could result in additional downgrades.

Our borrowing costs depend, in part, on our credit ratings and because downgrades would likely increase our borrowing costs we disclose these ratings to enhance the understanding of the effects of our ratings on our costs of funds.

In addition, to assist PayPal in our planned separation we are currently working with credit rating agencies to obtain separate credit ratings for PayPal and we believe that immediately following separation both eBay and PayPal will be rated investment grade.

Commitments and Contingencies As of December 31, 2014 , approximately $20.2 billion of unused credit was available to PayPal Credit accountholders.

While this amount represents the total unused credit available, we have not experienced, and do not anticipate, that all of our PayPal Credit accountholders will access their entire available credit at any given point in time.

In addition, the individual lines of credit that make up this unused credit are subject to periodic review and termination by the chartered financial institutions that are the issuer of PayPal Credit products based on, among other things, account usage and customer creditworthiness.

When a consumer makes a purchase using a PayPal Credit products, the chartered financial institution extends credit to the consumer, funds the extension of credit at the point of sale and advances funds to the merchant.

We subsequently purchase the consumer receivables related to the consumer loans and as result of that purchase, bear the risk of loss in the event of loan defaults.

However, we subsequently sell a participation interest in the entire pool of consumer loans to the chartered financial institution that extended the consumer loans.

Although the chartered financial institution continues to own the customer accounts, we own and bear the risk of loss on the related consumer receivables, less the participation interest held by the chartered financial institution, and PayPal is responsible for all servicing functions related to the customer account balances.

As of December 31, 2014 , the total outstanding principal balance of this pool of consumer loans was $3.7 billion , of which the chartered financial institution owns a participation interest of $163 million , or 4.4% of the total outstanding balance of consumer receivables at that date.

We have certain fixed contractual obligations and commitments that include future estimated payments for general operating purposes.

Changes in our business needs, contractual cancellation provisions, fluctuating interest rates, and other factors may result in actual payments differing from the estimates.

We cannot provide certainty regarding the timing and amounts of these payments.

The following table summarizes our fixed contractual obligations and commitments:

The significant assumptions used in our determination of amounts presented in the above table are as follows: ?

Debt amounts include the principal and interest amounts of the respective debt instruments.

For additional details related to our debt, please see “Note 10 – Debt” to the consolidated financial statements included in this report.

This table does not reflect any amounts payable under our $3 billion revolving credit facility or $2 billion commercial paper program, for which no borrowings were outstanding as of December 31, 2014 .  ?

Lease amounts include minimum rental payments under our non-cancelable operating leases for office facilities, fulfillment centers, as well as computer and office equipment that we utilize under lease arrangements.

The amounts presented are consistent with contractual terms and are not expected to differ significantly from actual results under our existing leases, unless a substantial change in our headcount needs requires us to expand our occupied space or exit an office facility early.

MARATHON OIL CORPORATION Notes to Consolidated Financial Statements equivalent to the Exchangeable Shares at the acquisition date as discussed below.

Additional shares of voting preferred stock will be issued as necessary to adjust the number of votes to account for changes in the exchange ratio.

Preferred shares – In connection with the acquisition of Western discussed in Note 6, the Board of Directors authorized a class of voting preferred stock consisting of 6 million shares.

Upon completion of the acquisition, we issued 5 million shares of this voting preferred stock to a trustee, who holds the shares for the benefit of the holders of the Exchangeable Shares discussed above.

Each share of voting preferred stock is entitled to one vote on all matters submitted to the holders of Marathon common stock.

Each holder of Exchangeable Shares may direct the trustee to vote the number of shares of voting preferred stock equal to the number of shares of Marathon common stock issuable upon the exchange of the Exchangeable Shares held by that holder.

In no event will the aggregate number of votes entitled to be cast by the trustee with respect to the outstanding shares of voting preferred stock exceed the number of votes entitled to be cast with respect to the outstanding Exchangeable Shares.

Except as otherwise provided in our restated certificate of incorporation or by applicable law, the common stock and the voting preferred stock will vote together as a single class in the election of directors of Marathon and on all other matters submitted to a vote of stockholders of Marathon generally.

The voting preferred stock will have no other voting rights except as required by law.

Other than dividends payable solely in shares of voting preferred stock, no dividend or other distribution, will be paid or payable to the holder of the voting preferred stock.

In the event of any liquidation, dissolution or winding up of Marathon, the holder of shares of the voting preferred stock will not be entitled to receive any assets of Marathon available for distribution to its stockholders.

The voting preferred stock is not convertible into any other class or series of the capital stock of Marathon or into cash, property or other rights, and may not be redeemed.25.

Leases We lease a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, production facilities and transportation equipment.

Most long-term leases include renewal options and, in certain leases, purchase options.

Future minimum commitments for capital lease obligations (including sale-leasebacks accounted for as financings) and for operating lease obligations having initial or remaining noncancelable lease terms in excess of one year are as follows:

|(In millions)|Capital Lease Obligations (a)|Operating Lease Obligations|
|2010|$46|$165|
|2011|45|140|
|2012|58|121|
|2013|44|102|
|2014|44|84|
|Later years|466|313|
|Sublease rentals|-|-16|
|Total minimum lease payments|$703|$909|
|Less imputed interest costs|-257||
|Present value of net minimum lease payments|$446||

(a) Capital lease obligations include $164 million related to assets under construction as of December 31, 2009.

These leases are currently reported in long-term debt based on percentage of construction completed at $36 million.

In connection with past sales of various plants and operations, we assigned and the purchasers assumed certain leases of major equipment used in the divested plants and operations of United States Steel.

In the event of a default by any of the purchasers, United States Steel has assumed these obligations; however, we remain primarily obligated for payments under these leases.

Minimum lease payments under these operating lease obligations of $16 million have been included above and an equal amount has been reported as sublease rentals.

Answer: 10.661636368518568