Table of Contents totaled an absolute notional equivalent of $292.3 million and $190.5 million, respectively, with the year-over-year increase primarily driven by earnings growth.
At this time, we do not hedge these long-term investment exposures.
We do not use foreign exchange contracts for speculative trading purposes, nor do we hedge our foreign currency exposure in a manner that entirely offsets the effects of changes in foreign exchange rates.
We regularly review our hedging program and assess the need to utilize financial instruments to hedge currency exposures on an ongoing basis.
Cash Flow Hedging—Hedges of Forecasted Foreign Currency Revenue We may use foreign exchange purchased options or forward contracts to hedge foreign currency revenue denominated in Euros, British Pounds and Japanese Yen.
We hedge these cash flow exposures to reduce the risk that our earnings and cash flows will be adversely affected by changes in exchange rates.
These foreign exchange contracts, carried at fair value, may have maturities between one and twelve months.
We enter into these foreign exchange contracts to hedge forecasted revenue in the normal course of business and accordingly, they are not speculative in nature.
We record changes in the intrinsic value of these cash flow hedges in accumulated other comprehensive income (loss) until the forecasted transaction occurs.
When the forecasted transaction occurs, we reclassify the related gain or loss on the cash flow hedge to revenue.
In the event the underlying forecasted transaction does not occur, or it becomes probable that it will not occur, we reclassify the gain or loss on the related cash flow hedge from accumulated other comprehensive income (loss) to interest and other income, net on our Consolidated Statements of Income at that time.
For the fiscal year ended November 30, 2018, there were no net gains or losses recognized in other income relating to hedges of forecasted transactions that did not occur.
Balance Sheet Hedging—Hedging of Foreign Currency Assets and Liabilities We hedge exposures related to our net recognized foreign currency assets and liabilities with foreign exchange forward contracts to reduce the risk that our earnings and cash flows will be adversely affected by changes in foreign currency exchange rates.
These foreign exchange contracts are carried at fair value with changes in the fair value recorded as interest and other income, net.
These foreign exchange contracts do not subject us to material balance sheet risk due to exchange rate movements because gains and losses on these contracts are intended to offset gains and losses on the assets and liabilities being hedged.
At November 30, 2018, the outstanding balance sheet hedging derivatives had maturities of 180 days or less.
See Note 5 of our Notes to Consolidated Financial Statements for information regarding our hedging activities.
Interest Rate Risk Short-Term Investments and Fixed Income Securities At November 30, 2018, we had debt securities classified as short-term investments of $1.59 billion.
Changes in interest rates could adversely affect the market value of these investments.
The following table separates these investments, based on stated maturities, to show the approximate exposure to interest rates (in millions):
## Table 0 ##
A sensitivity analysis was performed on our investment portfolio as of November 30, 2018.
The analysis is based on an estimate of the hypothetical changes in market value of the portfolio that would result from an immediate parallel shift in the yield curve of various magnitudes.
Management’s Discussion and Analysis of Financial Condition and Results of Operations 47 Southern Company 2017 Annual Report Retail energy sales increased 261 million KWHs in 2016 as compared to the prior year.
This increase was primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 and customer growth, partially offset by decreased customer usage.
The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, paper, pipeline, and stone, clay, and glass sectors.
A strong dollar, low oil prices, and weak global economic conditions constrained growth in the industrial sector in 2016.
Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth.
Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting.
Household income, one of the primary drivers of residential customer usage, had modest growth in 2016.
See “Electric Operating Revenues” above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.
Other Revenues Other revenues increased $20 million, or 24.1%, in 2017 as compared to the prior year.
The 2017 increase was primarily due to additional third party infrastructure services.
Other revenues increased $83 million in 2016 as compared to the prior year.
The 2016 increase was primarily due to revenues from certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as other revenues for consistency of presentation on a consolidated basis following the PowerSecure acquisition.
In prior periods, these revenues were included in other income (expense), net.
Fuel and Purchased Power Expenses Fuel costs constitute one of the largest expenses for the electric utilities.
The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units.
Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.
Details of the Southern Company system’s generation and purchased power were as follows:
## Table 1 ##
(*) Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
In 2017, total fuel and purchased power expenses were $5.3 billion, an increase of $152 million, or 3.0%, as compared to the prior year.
The increase was primarily the result of a $196 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $44 million net decrease in the volume of KWHs generated and purchased.
In 2016, total fuel and purchased power expenses were $5.1 billion, a decrease of $284 million, or 5.3%, as compared to the prior year.
The decrease was primarily the result of a $650 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $366 million increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income.
See FUTURE EARNINGS POTENTIAL – “Regulatory Matters – Fuel Cost Recovery” herein for
Consolidated Statements of Capitalization At December 31, 2017 and 2016
## Table 2 ##
The accompanying notes are an integral part of these consolidated financial statements.
At December 31, 2006, we had entered into basis swap transactions related to natural gas production.
These basis swaps have been combined with NYMEX commodity swaps and designated as cash flow hedges.
The basis swaps are as follows:
## Table 3 ##
(1) ANR Pipeline (2) Panhandle Eastern Pipe Line The costless collar, fixed price swap and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed price or floor price.
We would pay the counterparty if the settlement price for the scheduled trading day applicable for each calculation period is more than the fixed price or ceiling price.
The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the fixed or ceiling price in respect of each calculation period.
The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess, if any, of the fixed or floor price over the floating price in respect of each calculation period.
Accumulated Other Comprehensive Loss—As of December 31, 2006 and 2005, the balance in AOCL included net deferred losses of $104 million and $764 million, respectively, related to the fair value of crude oil and natural gas derivative instruments accounted for as cash flow hedges.
The net deferred losses are net of deferred income tax benefit of $63 million and $411 million, respectively.
If commodity prices were to stay the same as they were at December 31, 2006, approximately $21 million of deferred losses, net of tax, related to the fair values of crude oil and natural gas derivative instruments included in AOCL at December 31, 2006 would be reclassified to earnings during the next twelve months as the forecasted transactions occur, and would be recorded as a reduction in oil and gas sales of approximately $34 million before tax.
Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur.
All current crude oil and natural gas derivative instruments, except those described in the following paragraph, are designated as cash flow hedges.
All forecasted transactions currently being hedged are expected to occur by December 2010.
Other Derivative Instruments—In addition to the derivative instruments described above, NEMI, from time to time, employs derivative instruments in connection with purchases and sales of production in order to establish a fixed margin and mitigate the risk of price volatility.
Most of the purchases are on an index basis; however, purchasers in the markets in which NEMI sells often require fixed or NYMEX-related pricing.
NEMI may use a derivative instrument to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.
Changes in the allowance for doubtful accounts are as follows:
## Table 4 ##
Amounts charged to expense include $14 million in 2007, $15 million in 2006 and $11 million in 2005 to cover potentially uncollectible balances related to Ecuador power operations.
These amounts are included in electricity generation expense.
Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us.
We are pursuing various strategies to protect our interests including international arbitration and litigation.
The allowance was also increased by $2 million in 2006 and $1 million in 2005 to record various provisions related to our US business.
In addition, in 2005 the allowance was decreased due to the final write-off of certain allowances recorded in prior years ($6 million).
Materials and Supplies Inventories—Materials and supplies inventories, consisting principally of tubular goods and production equipment, are stated at the lower of cost or market.
Property, Plant and Equipment— Successful Efforts Method—We account for crude oil and natural gas properties under the successful efforts method of accounting.
Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized.
Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-ofproduction method based on proved crude oil and natural gas reserves on a property-by-property basis as estimated by our engineers.
Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
Repairs and maintenance are expensed as incurred.
Proved Property Impairment—In accordance with SFAS No.144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we review proved oil and gas properties and other long-lived assets for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or sustained decrease in commodity prices.
We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable.
When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amount of the properties is reduced to their estimated fair value.
The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices and operating expenses, timing of future production, future capital expenditures and a riskadjusted discount rate.
We recorded impairments of approximately $4 million in 2007, $9 million in 2006 and $5 million in 2005, primarily related to downward reserve revisions on US properties and/or adjustment of the carrying value of properties to their fair values.
Unproved Property Impairment—We also periodically assess individually significant unproved properties for impairment of value and recognize a loss at the time of impairment by providing an impairment allowance.
Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil and natural gas reserves, future commodity prices and future costs to extract the reserves.
Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors.
Other individually insignificant unproved properties are amortized on a composite method based on our experience of successful drilling and average holding period.
We recorded impairments of individually significant unproved properties of approximately $3 million in 2007, $1 million in 2006, and $3 million in 2005 and included the amounts in exploration expense.
Properties Acquired in Business Combinations—In determining the fair values of proved and unproved properties acquired in business combinations, we prepare estimates of crude oil and natural gas reserves.
We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows.
For the fair value assigned to proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the
Noble Energy, Inc.  Notes to Consolidated Financial Statements
## Table 5 ##
(1) Revenues from third parties for all foreign countries, in total, were $1.6 billion in 2011, $1.0 billion in 2010, and $791 million in 2009.
(2) Long-lived assets located in all foreign countries, in total, were $3.5 billion, $2.4 billion, and $1.6 billion at December 31, 2011, 2010, and 2009, respectively.
(3) Revenues through December 31, 2010 include decreases resulting from hedging activities.
The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues.

<table><tr><td>Due within one year</td><td>$612.1</td></tr><tr><td>Due between one and two years</td><td>564.2</td></tr><tr><td>Due between two and three years</td><td>282.2</td></tr><tr><td>Due after three years</td><td>127.7</td></tr><tr><td>Total</td><td>$1,586.2</td></tr></table>
<table><tr><td></td><td>2017</td><td>2016</td><td>2015</td></tr><tr><td>Total generation(in billions of KWHs)</td><td>194</td><td>188</td><td>187</td></tr><tr><td>Total purchased power(in billions of KWHs)</td><td>20</td><td>19</td><td>13</td></tr><tr><td>Sources of generation(percent)—</td><td></td><td></td><td></td></tr><tr><td>Gas</td><td>46</td><td>46</td><td>46</td></tr><tr><td>Coal</td><td>30</td><td>33</td><td>34</td></tr><tr><td>Nuclear</td><td>16</td><td>16</td><td>16</td></tr><tr><td>Hydro</td><td>2</td><td>2</td><td>3</td></tr><tr><td>Other</td><td>6</td><td>3</td><td>1</td></tr><tr><td>Cost of fuel, generated(in cents per net KWH)—</td><td></td><td></td><td></td></tr><tr><td>Gas</td><td>2.79</td><td>2.48</td><td>2.60</td></tr><tr><td>Coal</td><td>2.81</td><td>3.04</td><td>3.55</td></tr><tr><td>Nuclear</td><td>0.79</td><td>0.81</td><td>0.79</td></tr><tr><td>Average cost of fuel, generated(in cents per net KWH)</td><td>2.44</td><td>2.40</td><td>2.64</td></tr><tr><td>Average cost of purchased power(in cents per net KWH)<sup>(</sup><sup>*)</sup></td><td>5.19</td><td>4.81</td><td>6.11</td></tr></table>
<table><tr><td></td><td></td><td>2017</td><td>2016</td><td>2017</td><td>2016</td></tr><tr><td></td><td></td><td colspan="2">(in millions)</td><td colspan="2">(percent of total)</td></tr><tr><td>Long-Term Debt:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Long-term debt payable to affiliated trusts —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Variable rate (4.44% at 12/31/17) due 2042</td><td></td><td>$206</td><td>$206</td><td></td><td></td></tr><tr><td>Long-term senior notes and debt —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Maturity</td><td>Interest Rates</td><td></td><td></td><td></td><td></td></tr><tr><td>2017</td><td>1.30% to 7.20%</td><td>—</td><td>2,019</td><td></td><td></td></tr><tr><td>2018</td><td>1.50% to 5.40%</td><td>2,402</td><td>2,403</td><td></td><td></td></tr><tr><td>2019</td><td>1.85% to 5.55%</td><td>3,074</td><td>3,076</td><td></td><td></td></tr><tr><td>2020</td><td>2.00% to 4.75%</td><td>2,273</td><td>1,326</td><td></td><td></td></tr><tr><td>2021</td><td>2.35% to 9.10%</td><td>2,643</td><td>2,655</td><td></td><td></td></tr><tr><td>2022</td><td>1.00% to 8.70%</td><td>2,016</td><td>1,378</td><td></td><td></td></tr><tr><td>2023 through 2047</td><td>1.85% to 7.30%</td><td>22,142</td><td>20,369</td><td></td><td></td></tr><tr><td>Variable rates (1.82% to 3.75% at 1/1/17) due 2017</td><td></td><td>—</td><td>461</td><td></td><td></td></tr><tr><td>Variable rates (2.29% to 3.05% at 12/31/17) due 2018</td><td></td><td>1,420</td><td>1,520</td><td></td><td></td></tr><tr><td>Variable rates (2.04% to 2.18% at 12/31/17) due 2020</td><td></td><td>825</td><td>—</td><td></td><td></td></tr><tr><td>Variable rates (2.55% to 2.79% at 12/31/17) due 2021</td><td></td><td>25</td><td>25</td><td></td><td></td></tr><tr><td>Variable rate (3.75% at 1/1/17) due 2032 to 2036</td><td></td><td>—</td><td>15</td><td></td><td></td></tr><tr><td>Total long-term senior notes and debt</td><td></td><td>36,820</td><td>35,247</td><td></td><td></td></tr><tr><td>Other long-term debt —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pollution control revenue bonds —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Maturity</td><td>Interest Rates</td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>4.55%</td><td>25</td><td>25</td><td></td><td></td></tr><tr><td>2022</td><td>2.10% to 2.35%</td><td>90</td><td>90</td><td></td><td></td></tr><tr><td>2023 through 2049</td><td>1.15% to 5.15%</td><td>1,379</td><td>1,339</td><td></td><td></td></tr><tr><td>Variable rates (2.45% to 2.50% at 12/31/17) due 2018</td><td></td><td>40</td><td>76</td><td></td><td></td></tr><tr><td>Variable rates (1.86% to 1.87% at 12/31/17) due 2021</td><td></td><td>65</td><td>65</td><td></td><td></td></tr><tr><td>Variable rates (1.83% to 1.84% at 12/31/17) due 2022</td><td></td><td>17</td><td>17</td><td></td><td></td></tr><tr><td>Variable rates (1.59% to 1.88% at 12/31/17) due 2024 to 2053</td><td></td><td>1,680</td><td>1,721</td><td></td><td></td></tr><tr><td>Plant Daniel revenue bonds -7.13% due 2021</td><td></td><td>270</td><td>270</td><td></td><td></td></tr><tr><td>FFB loans —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2.57% to 3.86% due 2020</td><td></td><td>44</td><td>44</td><td></td><td></td></tr><tr><td>2.57% to 3.86% due 2021</td><td></td><td>44</td><td>44</td><td></td><td></td></tr><tr><td>2.57% to 3.86% due 2022</td><td></td><td>44</td><td>44</td><td></td><td></td></tr><tr><td>2.57% to 3.86% due 2023 to 2044</td><td></td><td>2,493</td><td>2,493</td><td></td><td></td></tr><tr><td>First mortgage bonds —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>4.70% due 2019</td><td></td><td>50</td><td>50</td><td></td><td></td></tr><tr><td>2.66% to 6.58% due 2023 to 2057</td><td></td><td>975</td><td>575</td><td></td><td></td></tr><tr><td>Gas facility revenue bonds —</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Variable rate (1.71% at 12/31/17) due 2022</td><td></td><td>47</td><td>47</td><td></td><td></td></tr><tr><td>Variable rate (1.71% at 12/31/17) due 2024 to 2033</td><td></td><td>154</td><td>154</td><td></td><td></td></tr><tr><td>Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077</td><td></td><td>3,570</td><td>2,350</td><td></td><td></td></tr><tr><td>Total other long-term debt</td><td></td><td>10,987</td><td>9,404</td><td></td><td></td></tr><tr><td>Unamortized fair value adjustment of long-term debt</td><td></td><td>525</td><td>578</td><td></td><td></td></tr><tr><td>Capitalized lease obligations</td><td></td><td>204</td><td>136</td><td></td><td></td></tr><tr><td>Unamortized debt premium</td><td></td><td>44</td><td>52</td><td></td><td></td></tr><tr><td>Unamortized debt discount</td><td></td><td>-206</td><td>-194</td><td></td><td></td></tr><tr><td>Unamortized debt issuance expense</td><td></td><td>-226</td><td>-213</td><td></td><td></td></tr><tr><td colspan="2">Total long-term debt (annual interest requirement — $1.8 billion)</td><td>48,354</td><td>45,216</td><td></td><td></td></tr><tr><td>Less amount due within one year</td><td></td><td>3,892</td><td>2,587</td><td></td><td></td></tr><tr><td>Long-term debt excluding amount due within one year</td><td></td><td>44,462</td><td>42,629</td><td>63.2%</td><td>61.3%</td></tr></table>
<table><tr><td> </td><td colspan="2"> Natural Gas</td></tr><tr><td> Production Period</td><td> MMBtupd</td><td> Average  Differential  per MMBtu</td></tr><tr><td>2007 (CIG vs. NYMEX)</td><td>100,000</td><td>$2.02</td></tr><tr><td>2007 (ANR(1)vs. NYMEX)</td><td>30,000</td><td>1.17</td></tr><tr><td>2007 (PEPL(2)vs. NYMEX)</td><td>10,000</td><td>1.11</td></tr><tr><td>2008 (CIG vs. NYMEX)</td><td>100,000</td><td>1.66</td></tr><tr><td>2008 (ANR vs. NYMEX)</td><td>40,000</td><td>1.01</td></tr><tr><td>2008 (PEPL vs. NYMEX)</td><td>10,000</td><td>0.98</td></tr></table>
<table><tr><td></td><td colspan="3">Year Ended December 31,</td></tr><tr><td></td><td>2007</td><td>2006</td><td>2005</td></tr><tr><td></td><td colspan="3">(in thousands)</td></tr><tr><td>Balance at beginning of period</td><td>$34,535</td><td>$18,644</td><td>$13,093</td></tr><tr><td>Charged to expense</td><td>14,183</td><td>19,404</td><td>14,688</td></tr><tr><td>Deductions and other</td><td>1,089</td><td>-3,513</td><td>-9,137</td></tr><tr><td>Balance at end of period</td><td>$49,807</td><td>$34,535</td><td>$18,644</td></tr></table>
<table><tr><td></td><td>Consolidated</td><td>United States</td><td>West Africa</td><td>EasternMediterranean</td><td>NorthSea</td><td>Other Int'l, Corporate</td></tr><tr><td>(millions)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from Third Parties</td><td>$3,568</td><td>$2,125</td><td>$592</td><td>$307</td><td>$357</td><td>$187</td></tr><tr><td>Income from Equity Method Investees</td><td>195</td><td>2</td><td>193</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Revenues-1</td><td>3,763</td><td>2,127</td><td>785</td><td>307</td><td>357</td><td>187</td></tr><tr><td>DD&A</td><td>965</td><td>758</td><td>69</td><td>25</td><td>87</td><td>26</td></tr><tr><td>Gain on Divestiture</td><td>-25</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-25</td></tr><tr><td>Asset Impairments</td><td>759</td><td>757</td><td>-</td><td>-</td><td>2</td><td>-</td></tr><tr><td>(Gain) Loss on Commodity Derivative Instruments</td><td>-42</td><td>-74</td><td>32</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Income (Loss) Before Income Taxes</td><td>715</td><td>96</td><td>561</td><td>228</td><td>213</td><td>-383</td></tr><tr><td>Equity Method Investments</td><td>329</td><td>72</td><td>257</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Additions to Long-Lived Assets</td><td>4,358</td><td>3,007</td><td>618</td><td>687</td><td>-</td><td>46</td></tr><tr><td>Goodwill at End of Year</td><td>696</td><td>696</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Assets at End of Year-2</td><td>16,444</td><td>11,201</td><td>2,728</td><td>1,751</td><td>544</td><td>220</td></tr><tr><td>Year Ended December 31, 2010</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from Third Parties</td><td>$2,924</td><td>$1,893</td><td>$349</td><td>$191</td><td>$309</td><td>$182</td></tr><tr><td>Reclassification from AOCL-3</td><td>-20</td><td>-20</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Income from Equity Method Investees</td><td>118</td><td>-</td><td>118</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Revenues-1</td><td>3,022</td><td>1,873</td><td>467</td><td>191</td><td>309</td><td>182</td></tr><tr><td>DD&A</td><td>883</td><td>719</td><td>39</td><td>22</td><td>64</td><td>39</td></tr><tr><td>Net Gain on Asset Sales</td><td>-113</td><td>-113</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Asset Impairments</td><td>144</td><td>119</td><td>-</td><td>25</td><td>-</td><td>-</td></tr><tr><td>(Gain) Loss on Commodity Derivative Instruments</td><td>-157</td><td>-168</td><td>11</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Income (Loss) Before Income Taxes</td><td>1,031</td><td>713</td><td>355</td><td>119</td><td>183</td><td>-339</td></tr><tr><td>Equity Method Investments</td><td>285</td><td>-</td><td>285</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Additions to Long-Lived Assets</td><td>2,789</td><td>1,796</td><td>612</td><td>270</td><td>64</td><td>47</td></tr><tr><td>Goodwill at End of Year</td><td>696</td><td>696</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Assets at End of Year-2</td><td>13,282</td><td>9,091</td><td>2,270</td><td>919</td><td>770</td><td>232</td></tr><tr><td>Year Ended December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from Third Parties</td><td>$2,287</td><td>$1,484</td><td>$340</td><td>$144</td><td>$153</td><td>$166</td></tr><tr><td>Reclassification from AOCL-3</td><td>-58</td><td>-29</td><td>-29</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Income from Equity Method Investees</td><td>84</td><td>-</td><td>84</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Revenues-1</td><td>2,313</td><td>1,455</td><td>395</td><td>144</td><td>153</td><td>166</td></tr><tr><td>DD&A</td><td>816</td><td>689</td><td>38</td><td>20</td><td>34</td><td>35</td></tr><tr><td>Asset Impairments</td><td>604</td><td>504</td><td>-</td><td>-</td><td>-</td><td>100</td></tr><tr><td>Gain on Commodity Derivative Instruments</td><td>110</td><td>73</td><td>37</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Income (Loss) Before Income Taxes</td><td>-264</td><td>-287</td><td>257</td><td>98</td><td>62</td><td>-394</td></tr><tr><td>Equity Method Investments</td><td>303</td><td>-</td><td>303</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Additions to Long-Lived Assets</td><td>1,282</td><td>911</td><td>124</td><td>103</td><td>103</td><td>41</td></tr><tr><td>Goodwill at End of Year</td><td>758</td><td>758</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Total Assets at End of Year-2</td><td>11,807</td><td>8,669</td><td>1,731</td><td>486</td><td>635</td><td>286</td></tr></table>

Question: As As the chart 2 shows,which year is the value of Total long-term senior notes and debt the highest?
Answer: 2017