Corporate and Government Bonds Corporate and government bonds are classified as Level 2 assets, as they are either valued at quoted market prices from observable pricing sources at the reporting date or valued based upon comparable securities with similar yields and credit ratings.
Real Estate Pooled Funds Real estate pooled funds are classified as Level 3 assets, as they are carried at the estimated fair value of the underlying properties.
Estimated fair value is calculated utilizing a combination of key inputs, such as revenue and expense growth rates, terminal capitalization rates, and discount rates.
These key inputs are consistent with practices prevailing within the real estate investment management industry.
Other Pooled Funds Other pooled funds classified as Level 2 assets are valued at the NAV of the shares held at year end, which is based on the fair value of the underlying investments.
Securities and interests classified as Level 3 are carried at the estimated fair value.
The estimated fair value is based on the fair value of the underlying investment values, which includes estimated bids from brokers or other third-party vendor sources that utilize expected cash flow streams and other uncorroborated data including counterparty credit quality, default risk, discount rates, and the overall capital market liquidity.
Insurance Contracts Insurance contracts are classified as Level 3 assets, as they are carried at contract value, which approximates the estimated fair value.
The estimated fair value is based on the fair value of the underlying investment of the insurance company.
Contributions and Projected Benefit Payments Pension contributions to funded plans and benefit payments for unfunded plans for fiscal year 2016 were $79.3.
Contributions for funded plans resulted primarily from contractual and regulatory requirements.
Benefit payments to unfunded plans were due primarily to the timing of retirements and cost reduction actions.
We anticipate contributing $65 to $85 to the defined benefit pension plans in 2017.
These contributions are anticipated to be driven primarily by contractual and regulatory requirements for funded plans and benefit payments for unfunded plans, which are dependent upon timing of retirements and actions to reorganize the business.
Projected benefit payments, which reflect expected future service, are as follows:
## Table 0 ##
These estimated benefit payments are based on assumptions about future events.
Actual benefit payments may vary significantly from these estimates.
Defined Contribution Plans We maintain a nonleveraged employee stock ownership plan (ESOP) which forms part of the Air Products and Chemicals, Inc.  Retirement Savings Plan (RSP).
The ESOP was established in May of 2002.
The balance of the RSP is a qualified defined contribution plan including a 401(k) elective deferral component.
A substantial portion of U. S.  employees are eligible and participate.
We treat dividends paid on ESOP shares as ordinary dividends.
Under existing tax law, we may deduct dividends which are paid with respect to shares held by the plan.
Shares of the Company’s common stock in the ESOP totaled 3,031,534 as of 30 September 2016.
Our contributions to the RSP include a Company core contribution for certain eligible employees who do not receive their primary retirement benefit from the defined benefit pension plans, with the core contribution based
distillate retail gross margin partially offset by higher administrative expenses.
The refining and wholesale marketing margin in 2003 averaged 6.0 cents per gallon, versus 2002 level of 3.9 cents.
The gasoline and distillate gross margin for its retail business was 12.3 cents per gallon in 2003, as compared to 10.1 cents per gallon in 2002.
The higher administrative expenses were due primarily to higher employee related costs.
Results for 2003 also included $34 million of gains from the sale of certain interests in refined product pipelines.
Derivative losses, which are included in the refining and wholesale marketing margin, were $272 million in 2004 compared to $158 million in 2003 and $124 million in 2002.
These derivative losses were generally incurred to mitigate the price risk of certain crude oil and other feedstock purchases, to protect carrying values of excess inventories and to protect crack spread values.
Gains on the sale of SSA stores included in segment income were $17 million, $8 million and $37 million for 2004, 2003 and 2002.
IG segment income increased by $51 million in 2004 from 2003, following a decrease of $26 million in 2003 from 2002.
The increase in 2004 was primarily due to increased earnings from our investment in AMPCO and higher income from LNG operations, partially offset by costs associated with ongoing development of certain integrated gas projects and lower margins from gas marketing activities, including recognized changes in the fair value of derivatives used to support those activities.
The AMPCO methanol plant in Equatorial Guinea operated at a 95 percent on-stream factor in 2004 and prices were strong, averaging nearly $227 per ton for the year.
Additionally, the 2003 results included an impairment charge of $22 million on an equity method investment and a loss of $17 million on the termination of two tanker operating leases.
The decrease in 2003 is due to the impairment charge of $22 million and the loss of $17 million on leases as discussed above and higher expenses related to the development of an integrated gas business, partially offset by higher AMPCO earnings.
Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity Financial Condition Current assets increased $2.823 billion from year-end 2003, primarily due to an increase in cash and cash equivalents and receivables.
The increase in cash and cash equivalents was mainly due to the issuance on March 31, 2004, of 34,500,000 shares of common stock resulting in net proceeds of $1.004 billion and the suspension of cash distributions to Ashland.
The increase in receivables was mainly due to higher year-end commodity prices.
Current liabilities increased $1.046 billion from year-end 2003, primarily due to an increase in accounts payable as a result of higher priced year-end crude oil purchases at MAP.
Investments and long-term receivables increased $223 million from year-end 2003, primarily due to contributions to an equity investee to fund the LPG expansion project in Equatorial Guinea and restricted cash of $66 million at EGHoldings.
Net property, plant and equipment increased $980 million from year-end 2003.
Net property, plant and equipment for each of the last two years is summarized in the following table:
## Table 1 ##
The increase in international E&P is due to the construction of the Alba field condensate expansion project in Equatorial Guinea.
The increase in RM&T is primarily due to refinery upgrade projects to enable the production of low sulfur gasoline and diesel fuel and the Detroit, Michigan refinery expansion project, partially offset by sales of SSA stores.
The increase in IG is primarily due to costs associated with the LNG project in Equatorial Guinea.
Long-term debt at December 31, 2004 was $4.057 billion, a decrease of $28 million from year-end 2003.
See ‘‘Liquidity and Capital Resources’’ on page 40, for further discussion.
MARATHON OIL CORPORATION Notes to Consolidated Financial Statements The following table presents net financial assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2008:
## Table 2 ##
Deposits of $121 million in broker accounts covered by master netting agreements are included in fair values of commodity derivatives.
Derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market.
Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with data from active markets.
Level 3 derivatives are measured at fair value using either a market or income approach.
Generally at least one input is unobservable, such as the use of an internally generated model or an external data source.
Commodity derivatives in Level 3 include a $72 million liability related to two U. K.  natural gas sales contracts that are accounted for as derivative instruments and a $52 million asset for crude oil options related to sales of Canadian synthetic crude oil.
The fair value of the U. K.  natural gas contracts is measured with an income approach by applying the difference between the contract price and the U. K.  forward natural gas strip price to the expected sales volumes for the shorter of the remaining contract term or 18 months.
These contracts originated in the early 1990s and expire in September 2009.
The contract prices are reset annually in October based on the previous twelve-month changes in a basket of energy and other indices.
Consequently, the prices under these contracts do not track forward natural gas prices.
The crude oil options, which expire December 2009, are measured at fair value using a Black-Scholes option pricing model, an income approach that utilizes prices from an active market and market volatility calculated by a third-party service.
The interest rate derivatives are measured at fair value using quotes from our counterparties which are compared to internal calculations made using rates posted by a pricing service.
Because we are unable to independently verify those rates directly to the market, such inputs are considered Level 3.
The following is a reconciliation of the net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy.
## Table 3 ##
The change in unrealized losses included in net income related to instruments held at December 31, 2008, was an addition of $299 million for 2008.
Amounts reported in net income are classified as sales and other operating revenues or cost of revenues for commodity derivative instruments, as net interest and other financing income for interest rate derivative instruments and as cost of revenues for foreign currency derivatives, except those designated as hedges of future capital expenditures.
Amounts related to foreign currency derivatives designated as hedges of future capital expenditures accumulate in other comprehensive income and are amortized to depletion, depreciation and amortization over the life of the capital asset.
Supplementary Information on Oil and Gas Producing Activities (Unaudited) 109 Results of Operations for Oil and Gas Producing Activities The following reconciles results of operations for oil and gas producing activities to segment income:
## Table 4 ##
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
## Table 5 ##
The following table gives details of net sales volumes and average price realizations of our International E&P segment:
## Table 6 ##
(a) Corresponds with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b) Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 15 mmcfd for 2013 and 2012.
(c) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO, and EGHoldings, equity method investees.
We include our share of Alba Plant LLC's, AMPCO's and EGHoldings' income in our International E&P segment.
Oil Sands Mining sales and other operating revenues increased $55 million in 2013 from 2012.
This increase was primarily due to a higher proportion of net sales volumes related to a premium grade synthetic crude oil and the associated average price realizations when compared to 2012.
The increase was partially offset by lower feedstock sales in 2013.
The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:

<table><tr><td></td><td>U.S.</td><td>International</td></tr><tr><td>2017</td><td>$150.3</td><td>$45.7</td></tr><tr><td>2018</td><td>152.7</td><td>48.3</td></tr><tr><td>2019</td><td>157.2</td><td>50.2</td></tr><tr><td>2020</td><td>161.8</td><td>51.1</td></tr><tr><td>2021</td><td>166.7</td><td>54.3</td></tr><tr><td>2022–2026</td><td>909.6</td><td>306.9</td></tr></table>
<table><tr><td><i>(In millions)</i>  </td><td> 2004 </td><td>2003 </td></tr><tr><td>E&P</td><td></td><td></td></tr><tr><td>Domestic</td><td>$2,644</td><td>$2,636</td></tr><tr><td>International</td><td>3,530</td><td>3,351</td></tr><tr><td>Total E&P</td><td>6,174</td><td>5,987</td></tr><tr><td>RM&T</td><td>4,842</td><td>4,492</td></tr><tr><td>IG</td><td>621</td><td>153</td></tr><tr><td>Corporate</td><td>173</td><td>198</td></tr><tr><td>Total</td><td>$11,810</td><td>$10,830</td></tr></table>
<table><tr><td><i>(In millions)</i></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td>Derivative instruments:</td><td></td><td></td><td></td><td></td></tr><tr><td>Commodity</td><td>$107</td><td>$6</td><td>$-55</td><td>$58</td></tr><tr><td>Interest rate</td><td>–</td><td>–</td><td>29</td><td>29</td></tr><tr><td>Foreign currency</td><td>–</td><td>-75</td><td>–</td><td>-75</td></tr><tr><td>Total derivative instruments</td><td>107</td><td>-69</td><td>-26</td><td>12</td></tr><tr><td>Other assets</td><td>2</td><td>–</td><td>–</td><td>2</td></tr><tr><td>Total at fair value</td><td>$109</td><td>$-69</td><td>$-26</td><td>$14</td></tr></table>
<table><tr><td><i>(In millions)</i></td><td>December 31, 2008</td></tr><tr><td>Beginning balance</td><td>$-355</td></tr><tr><td>Total realized and unrealized losses:</td><td></td></tr><tr><td>Included in net income</td><td>210</td></tr><tr><td>Included in other comprehensive income</td><td>1</td></tr><tr><td>Purchases, sales, issuances and settlements, net</td><td>118</td></tr><tr><td>Ending balance</td><td>$ -26</td></tr></table>
<table><tr><td>(In millions)</td><td>2013</td><td>2012</td><td>2011</td></tr><tr><td>Results of continuing operations</td><td>$1,746</td><td>$1,593</td><td>$1,906</td></tr><tr><td>Items not included in results of oil and gas operations, net of tax:</td><td></td><td></td><td></td></tr><tr><td>Marketing income and other non-oil and gas producing related activities</td><td>42</td><td>49</td><td>182</td></tr><tr><td>Income from equity method investments</td><td>340</td><td>309</td><td>351</td></tr><tr><td>Items not allocated to segment income, net of tax:</td><td></td><td></td><td></td></tr><tr><td>Loss (gain) on asset dispositions</td><td>20</td><td>31</td><td>-24</td></tr><tr><td>Long-lived asset impairments</td><td>10</td><td>231</td><td>181</td></tr><tr><td>Water abatement-Oil Sands Mining</td><td>—</td><td>—</td><td>48</td></tr><tr><td>Segment income</td><td>$2,158</td><td>$2,213</td><td>$2,644</td></tr></table>
<table><tr><td></td><td colspan="6">December 31,</td></tr><tr><td>(In millions)</td><td>U.S.</td><td>Canada</td><td>E.G.</td><td>OtherAfrica</td><td>Europe</td><td>Total</td></tr><tr><td>2013</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$54,099</td><td>$59,585</td><td>$5,911</td><td>$28,195</td><td>$11,395</td><td>$159,185</td></tr><tr><td>Future production and administrative costs</td><td>-16,774</td><td>-35,954</td><td>-1,619</td><td>-976</td><td>-2,986</td><td>-58,309</td></tr><tr><td>Future development costs</td><td>-9,685</td><td>-9,694</td><td>-367</td><td>-793</td><td>-2,178</td><td>-22,717</td></tr><tr><td>Future income tax expenses</td><td>-7,592</td><td>-3,098</td><td>-1,032</td><td>-24,982</td><td>-4,581</td><td>-41,285</td></tr><tr><td>Future net cash flows</td><td>$20,048</td><td>$10,839</td><td>$2,893</td><td>$1,444</td><td>$1,650</td><td>$36,874</td></tr><tr><td>10 percent annual discount for estimated timing of cash flows</td><td>-9,940</td><td>-8,300</td><td>-1,084</td><td>-828</td><td>-252</td><td>-20,404</td></tr><tr><td>Standardized measure of discounted future net cash flows -</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>related to continuing operations</td><td>$10,108</td><td>$2,539</td><td>$1,809</td><td>$616</td><td>$1,398</td><td>$16,470</td></tr><tr><td>related to discontinued operations</td><td>$—</td><td>$—</td><td>$—</td><td>$1,302</td><td>$—</td><td>$1,302</td></tr><tr><td>2012</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$42,710</td><td>$55,171</td><td>$6,627</td><td>$28,173</td><td>$11,271</td><td>$143,952</td></tr><tr><td>Future production and administrative costs</td><td>-13,765</td><td>-32,131</td><td>-1,829</td><td>-1,015</td><td>-2,302</td><td>-51,042</td></tr><tr><td>Future development costs</td><td>-11,104</td><td>-9,350</td><td>-451</td><td>-787</td><td>-1,673</td><td>-23,365</td></tr><tr><td>Future income tax expenses</td><td>-4,489</td><td>-2,948</td><td>-1,191</td><td>-25,020</td><td>-5,274</td><td>-38,922</td></tr><tr><td>Future net cash flows</td><td>$13,352</td><td>$10,742</td><td>$3,156</td><td>$1,351</td><td>$2,022</td><td>$30,623</td></tr><tr><td>10 percent annual discount for estimated timing of cash flows</td><td>-6,956</td><td>-7,842</td><td>-1,178</td><td>-743</td><td>-327</td><td>-17,046</td></tr><tr><td>Standardized measure of discounted future net cash flows -</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>related to continuing operations</td><td>$6,396</td><td>$2,900</td><td>$1,978</td><td>$608</td><td>$1,695</td><td>$13,577</td></tr><tr><td>related to discontinued operations</td><td>$—</td><td>$—</td><td>$—</td><td>$642</td><td>$—</td><td>$642</td></tr><tr><td>2011</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows</td><td>$28,108</td><td>$59,365</td><td>$7,318</td><td>$28,197</td><td>$12,120</td><td>$135,108</td></tr><tr><td>Future production and administrative costs</td><td>-10,751</td><td>-28,048</td><td>-1,931</td><td>-1,099</td><td>-2,752</td><td>-44,581</td></tr><tr><td>Future development costs</td><td>-6,341</td><td>-10,346</td><td>-435</td><td>-559</td><td>-1,702</td><td>-19,383</td></tr><tr><td>Future income tax expenses</td><td>-2,740</td><td>-4,490</td><td>-1,368</td><td>-25,463</td><td>-5,375</td><td>-39,436</td></tr><tr><td>Future net cash flows</td><td>$8,276</td><td>$16,481</td><td>$3,584</td><td>$1,076</td><td>$2,291</td><td>$31,708</td></tr><tr><td>10 percent annual discount for estimated timing of cash flows</td><td>-4,539</td><td>-11,845</td><td>-1,331</td><td>-509</td><td>-446</td><td>-18,670</td></tr><tr><td>Standardized measure of discounted future net cash flows -</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>related to continuing operations</td><td>$3,737</td><td>$4,636</td><td>$2,253</td><td>$567</td><td>$1,845</td><td>$13,038</td></tr><tr><td>related to discontinued operations</td><td>$—</td><td>$—</td><td>$—</td><td>$743</td><td>$—</td><td>$743</td></tr></table>
<table><tr><td></td><td>2013</td><td>2012</td></tr><tr><td>International E&P Operating Statistics</td><td></td><td></td></tr><tr><td>Net liquid hydrocarbon salesvolumes(mbbld)<sup>(a)</sup></td><td></td><td></td></tr><tr><td>Europe</td><td>86</td><td>97</td></tr><tr><td>Africa</td><td>58</td><td>78</td></tr><tr><td>Total International E&P</td><td>144</td><td>175</td></tr><tr><td>Liquid hydrocarbon average price realizations(per bbl)</td><td></td><td></td></tr><tr><td>Europe</td><td>$112.60</td><td>$115.16</td></tr><tr><td>Africa</td><td>$86.29</td><td>$98.52</td></tr><tr><td>Total International E&P</td><td>$102.10</td><td>$107.78</td></tr><tr><td>Net natural gas sales volumes(mmcfd)</td><td></td><td></td></tr><tr><td>Europe<sup>(b)</sup></td><td>83</td><td>101</td></tr><tr><td>Africa</td><td>464</td><td>443</td></tr><tr><td>Total International E&P</td><td>547</td><td>544</td></tr><tr><td>Natural gas average price realizations(per mcf)</td><td></td><td></td></tr><tr><td>Europe</td><td>$12.08</td><td>$10.47</td></tr><tr><td>Africa<sup>(c)</sup></td><td>$0.49</td><td>$0.43</td></tr><tr><td>Total International E&P</td><td>$2.25</td><td>$2.29</td></tr></table>

Question: What is the sum of Future net cash flows 2011 of December 31, Canada, and Results of continuing operations of 2013 ?
Answer: 18227