Proved reserves estimates at December 31, 2007 were as follows:
## Table 0 ##
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i. e. , prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
For additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see Item 8.
Financial Statements and Supplementary Data—Supplemental Oil and Gas Information (Unaudited) and Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates— Reserves.
Engineers in our Houston, Denver and London offices prepare all reserve estimates for our different geographical regions.
These reserve estimates are reviewed and approved by senior engineering staff and division management with final approval by the Director of Asset Development and certain members of senior management.
During each of the years 2007, 2006 and 2005, we retained Netherland, Sewell & Associates, Inc.  (“NSAI”), independent thirdparty reserve engineers, to perform reserve audits of proved reserves.
A “reserve audit”, as we use the term, is a process involving an independent third-party engineering firm’s visits, collection of any and all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of reserve estimates.
Our use of the term “reserve audit” is intended only to refer to the collective application of the procedures which NSAI was engaged to perform.
The term “reserve audit” may be defined and used differently by other companies.
The reserve audit for 2007 included a detailed review of 16 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately 71% of US proved reserves and 96% of international proved reserves (81% of total proved reserves).
The reserve audit for 2006 included a detailed review of 14 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately 80% of our total proved reserves.
The reserve audit for 2005 included a detailed review of 11 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately 72% of our total proved reserves.
In connection with the 2007 reserve audit, NSAI prepared its own estimates of our proved reserves.
In order to prepare its estimates of proved reserves, NSAI examined our estimates with respect to reserve quantities, future producing rates, future net revenue, and the present value of such future net revenue.
NSAI also examined our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance.
In the conduct of the reserve audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production.
However, if in the course of the examination something came to the attention of NSAI
Financing Activities—Net cash used in financing activities decreased $482 million during 2007 as compared with 2006.
The change was due to net increases in the credit facility during 2007 as compared with payments being made to decrease outstanding debt during 2006.
In 2007 there was also a net decrease of $297 million in amounts used to repurchase common stock as compared with 2006.
Cash flows were provided by financing activities in 2005, as compared with 2006, and totaled $583 million.
In 2005, cash was provided by borrowings under the credit facility and exercise of stock options, partially offset by dividend payments and the repayment of debt acquired in the Patina Merger.
Acquisition, Capital and Other Exploration Expenditures Expenditure information (on an accrual basis) is as follows:
## Table 1 ##
Total capital expenditures during 2007 increased $392 million, or 29%, as compared with 2006.
The increase was due to lease acquisition in the US, exploratory activities in West Africa and the North Sea, and increased development activity in the Northern region and Gulf of Mexico area of our US operations.
Total capital expenditures during 2006 increased $457 million, or 51%, as compared with 2005.
The increase was primarily due to development expenditures in the US and the North Sea.
Capital expenditures for 2005 included $275 million of post-merger exploration and development-related expenditures on Patina properties.
As a result of the U. S.  Exploration acquisition in 2006, we allocated $413 million to proved properties and $131 million to unproved properties.
As a result of the Patina Merger in 2005, we allocated $2.6 billion to proved properties and $1.1 billion to unproved properties.
Insurance Recoveries See Item 8.
Financial Statements and Supplementary Data—Note 4—Effect of Gulf Coast Hurricanes.
Our corporate insurance program provides up to $260 million property damage coverage per loss event.
However, our insurance carrier’s aggregation limit for catastrophic windstorm events is $750 million.
If an insured catastrophic loss event occurs, we could still recover less than our stated limits should the total aggregate losses realized by our carrier exceed its $750 million aggregation limit applicable to any single loss event.
We carry additional property damage and control of well coverage for our deepwater Gulf of Mexico and remaining Gulf of Mexico shelf properties.
This additional insurance provides coverage only for claims in excess of $100 million, which exceed the $260 million property damage coverage or where the $260 million property damage coverage is reduced by application of the $750 million aggregation limit.
We carry business interruption insurance for certain international locations.
Effective June 2007, we no longer carry business interruption insurance for our Gulf of Mexico operations.
Financing Activities Long-Term Debt—Our long-term debt totaled $1.9 billion (excluding unamortized discount) at December 31, 2007.
Maturities range from 2009 to 2097.
Our principal source of liquidity is an unsecured revolving credit facility (the “Credit Facility”).
In November 2007, we extended the Credit Facility until December 9, 2012.
The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion.
The Credit Facility (i) provides for Credit Facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregate amount of $300 million and (iii) provides for
Interest Expense and Capitalized Interest—Interest expense and capitalized interest were as follows:
## Table 2 ##
Interest expense, net of capitalized interest, decreased in 2007 primarily due to a declining rate of interest applicable to the Credit Facility from 5.69% at December 31, 2006 to 5.28% at December 31, 2007.
Interest expense, net of capitalized interest, increased in 2006 due to additional borrowings related to the Patina Merger and acquisition of U. S.  Exploration and to increases in the interest rate applicable to the Credit Facility from 4.82% at December 31, 2005 to 5.69% at December 31, 2006.
Interest is capitalized on development projects using an interest rate equivalent to the average rate paid on long-term debt.
Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-ofproduction basis.
The majority of the capitalized interest related to long lead-time projects in West Africa, the North Sea and deepwater Gulf of Mexico in 2007; the North Sea and deepwater Gulf of Mexico in 2006; and deepwater Gulf of Mexico and projects in West Africa in 2005.
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk.
At December 31, 2007, AOCL included a deferred loss of $4 million, net of tax, related to interest rate swaps.
$3 million of this amount is being reclassified into earnings, at the rate of $0.8 million per year, as an adjustment to interest expense over the term of our 5?% senior notes due 2014.
The remaining $1 million loss relates to interest rate locks that will expire in third quarter 2008.
See Item 8.
Financial Statements and Supplementary Data—Note 12—Derivative Instruments and Hedging Activities.
(Gain) Loss on Derivative Instruments—See Item 8.
Financial Statements and Supplementary Data—Note 12— Derivative Instruments and Hedging Activities.
Gain on Sale of Assets—See Item 8.
Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures.
Loss on Involuntary Conversion—See Item 8.
Financial Statements and Supplementary Data—Note 4—Effect of Gulf Coast Hurricanes.
Electricity Sales—Ecuador Integrated Power Project—Through our subsidiaries, EDC Ecuador Ltd.  and MachalaPower Cia.
Ltda.
, we have a 100% ownership interest in an integrated natural gas-to-power project.
The project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the Machala power plant.
Electricity sales are included in other revenues and electricity generation expense is included in other expense, net in the consolidated statements of operations.
Operating data is as follows:
## Table 3 ##
The volume of natural gas produced and electric power generated in Ecuador are related to thermal electricity demand in Ecuador which typically declines at the onset of the rainy season.
When Ecuador has sufficient rainfall to allow hydroelectric power producers to provide base load power, we provide electricity only to meet peak demand.
As seasonal rains subside, we experience increasing demand for thermal electricity.
Electricity generation expense includes net increases in the allowance for doubtful accounts of $14 million in 2007, $15 million in 2006 and $11 million in 2005.
These increases have been made to cover potentially uncollectible
Note 10—Additional Shareholders’ Equity Information Activity in shares of our common stock and treasury stock was as follows:
## Table 4 ##
During 2007, we completed a $500 million common stock repurchase program begun in 2006.
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
## Table 5 ##
The effective income tax rate applied to AOCL increased from 35% at December 31, 2005 to 37.6% at December 31, 2006 and remained 37.6% at December 31, 2007.
Note 11—Benefit Plans Pension Plan and Other Postretirement Benefit Plans—We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006.
The benefits are based on an employee’s years of service and average earnings for the 60 consecutive calendar months of highest compensation.
Our funding
factors, including the market price of our Common Stock, general economic and market conditions and applicable legal requirements.
The repurchase program may be commenced, suspended or discontinued at any time.
In fiscal 2019, we repurchased approximately 2.1 million shares of our Common Stock for an aggregate cost of $88.6 million.
In fiscal 2018, we repurchased approximately 3.4 million shares of our Common Stock for an aggregate cost of $195.1 million.
As of September 30, 2019, we had approximately 19.1 million shares of Common Stock available for repurchase under the program.
We anticipate that we will be able to fund our capital expenditures, interest payments, dividends and stock repurchases, pension payments, working capital needs, note repurchases, restructuring activities, repayments of current portion of long-term debt and other corporate actions for the foreseeable future from cash generated from operations, borrowings under our credit facilities, proceeds from our A/R Sales Agreement, proceeds from the issuance of debt or equity securities or other additional long-term debt financing, including new or amended facilities.
In addition, we continually review our capital structure and conditions in the private and public debt markets in order to optimize our mix of indebtedness.
In connection with these reviews, we may seek to refinance existing indebtedness to extend maturities, reduce borrowing costs or otherwise improve the terms and composition of our indebtedness.
Contractual Obligations We summarize our enforceable and legally binding contractual obligations at September 30, 2019, and the effect these obligations are expected to have on our liquidity and cash flow in future periods in the following table.
Certain amounts in this table are based on management’s estimates and assumptions about these obligations, including their duration, the possibility of renewal, anticipated actions by third parties and other factors, including estimated minimum pension plan contributions and estimated benefit payments related to postretirement obligations, supplemental retirement plans and deferred compensation plans.
Because these estimates and assumptions are subjective, the enforceable and legally binding obligations we actually pay in future periods may vary from those presented in the table.

Tables referenced above, in order (Table 0 first):
<table><tr><td></td><td colspan="3">December 31, 2007</td></tr><tr><td></td><td>Proved Developed Reserves</td><td>Proved Undeveloped Reserves</td><td>Total Proved Reserves</td></tr><tr><td>United States</td><td></td><td></td><td></td></tr><tr><td>Natural gas (Bcf)</td><td>1,259</td><td>581</td><td>1,840</td></tr><tr><td>Crude oil (MMBbls)</td><td>129</td><td>78</td><td>207</td></tr><tr><td>Total US (MMBoe)</td><td>339</td><td>175</td><td>514</td></tr><tr><td>International</td><td></td><td></td><td></td></tr><tr><td>Natural gas (Bcf)</td><td>1,297</td><td>170</td><td>1,467</td></tr><tr><td>Crude oil (MMBbls)</td><td>100</td><td>22</td><td>122</td></tr><tr><td>Total International (MMBoe)</td><td>316</td><td>50</td><td>366</td></tr><tr><td>Worldwide</td><td></td><td></td><td></td></tr><tr><td>Natural gas (Bcf)</td><td>2,556</td><td>751</td><td>3,307</td></tr><tr><td>Crude oil (MMBbls)</td><td>229</td><td>100</td><td>329</td></tr><tr><td>Total Worldwide (MMBoe)</td><td>655</td><td>225</td><td>880</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>Acquisition, Capital and Other Exploration Expenditures</td><td></td><td></td><td></td></tr><tr><td>Lease acquisition of unproved property</td><td>$145,326</td><td>$53,652</td><td>$16,793</td></tr><tr><td>Exploration expenditures</td><td>371,758</td><td>203,035</td><td>161,515</td></tr><tr><td>Development expenditures</td><td>1,185,385</td><td>1,054,780</td><td>662,585</td></tr><tr><td>Corporate and other expenditures</td><td>36,361</td><td>35,069</td><td>21,478</td></tr><tr><td>Total consolidated capital expenditures</td><td>1,738,830</td><td>1,346,536</td><td>862,371</td></tr><tr><td>Our share of equity investee development costs</td><td>516</td><td>580</td><td>27,639</td></tr><tr><td>Total</td><td>$1,739,346</td><td>$1,347,116</td><td>$890,010</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>Interest expense, net</td><td>$112,957</td><td>$117,045</td><td>$87,541</td></tr><tr><td>Capitalized interest</td><td>16,595</td><td>12,515</td><td>8,684</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>Electricity sales (in thousands)</td><td>$70,916</td><td>$71,603</td><td>$74,228</td></tr><tr><td>Electricity generation expense (in thousands)</td><td>56,552</td><td>59,494</td><td>53,137</td></tr><tr><td>Operating income (in thousands)</td><td>14,364</td><td>12,109</td><td>21,091</td></tr><tr><td>Power generation (MW)</td><td>911,830</td><td>865,983</td><td>799,160</td></tr><tr><td>Average power price ($/Kwh)</td><td>$0.078</td><td>$0.083</td><td>$0.093</td></tr></table>
<table><tr><td></td><td colspan="2">Year Ended December 31,</td></tr><tr><td></td><td>2007</td><td>2006</td></tr><tr><td>Common stock shares issued</td><td></td><td></td></tr><tr><td>Shares at beginning of period</td><td>188,808,087</td><td>184,893,510</td></tr><tr><td>Exercise of common stock options</td><td>1,479,040</td><td>3,848,521</td></tr><tr><td>Restricted stock awards, net of forfeitures</td><td>527,182</td><td>66,056</td></tr><tr><td>Shares at end of period</td><td>190,814,309</td><td>188,808,087</td></tr><tr><td>Treasury stock</td><td></td><td></td></tr><tr><td>Shares at beginning of period</td><td>16,574,384</td><td>9,268,932</td></tr><tr><td>Shares repurchased</td><td>2,006,481</td><td>8,373,400</td></tr><tr><td>Rabbi trust shares sold</td><td>-</td><td>-1,067,948</td></tr><tr><td>Shares at end of period</td><td>18,580,865</td><td>16,574,384</td></tr></table>
<table><tr><td></td><td colspan="4">Accumulated Other Comprehensive Loss</td></tr><tr><td></td><td>Oil and Gas Cash Flow Hedges</td><td>Interest Rate Lock Cash Flow Hedges</td><td>Minimum Pension Liability and Other</td><td>Total</td></tr><tr><td></td><td colspan="4">(in thousands)</td></tr><tr><td>December 31, 2004</td><td>$-6,939</td><td>$-4,577</td><td>$-3,271</td><td>$-14,787</td></tr><tr><td>Cash flow hedges</td><td></td><td></td><td></td><td></td></tr><tr><td>Realized amounts reclassified into earnings</td><td>154,500</td><td>492</td><td>-</td><td>154,992</td></tr><tr><td>Unrealized amounts reclassified into earnings</td><td>33,638</td><td>-</td><td>-</td><td>33,638</td></tr><tr><td>Unrealized change in fair value</td><td>-945,033</td><td>-</td><td>-</td><td>-945,033</td></tr><tr><td>Net change in minimum pension liability and other</td><td>-</td><td>-</td><td>-12,309</td><td>-12,309</td></tr><tr><td>December 31, 2005</td><td>-763,834</td><td>-4,085</td><td>-15,580</td><td>-783,499</td></tr><tr><td>Cash flow hedges</td><td></td><td></td><td></td><td></td></tr><tr><td>Realized amounts reclassified into earnings</td><td>145,035</td><td>637</td><td>-</td><td>145,672</td></tr><tr><td>Unrealized amounts reclassified into earnings</td><td>264,520</td><td>-</td><td>-</td><td>264,520</td></tr><tr><td>Unrealized change in fair value</td><td>249,974</td><td>-</td><td>-</td><td>249,974</td></tr><tr><td>Net change in minimum pension liability and other</td><td>-</td><td>-</td><td>16,225</td><td>16,225</td></tr><tr><td>Adoption of SFAS 158</td><td>-</td><td>-</td><td>-33,401</td><td>-33,401</td></tr><tr><td>December 31, 2006</td><td>-104,305</td><td>-3,448</td><td>-32,756</td><td>-140,509</td></tr><tr><td>Cash flow hedges</td><td></td><td></td><td></td><td></td></tr><tr><td>Realized amounts reclassified into earnings</td><td>33,761</td><td>473</td><td>2,000</td><td>36,234</td></tr><tr><td>Unrealized change in fair value</td><td>-184,254</td><td>-751</td><td></td><td>-185,005</td></tr><tr><td>Net change in other</td><td>-</td><td>-</td><td>5,095</td><td>5,095</td></tr><tr><td>December 31, 2007</td><td>$-254,798</td><td>$-3,726</td><td>$-25,661</td><td>$-284,185</td></tr></table>

Question: Which year has the greatest proportion of Oil and Gas Cash Flow Hedges? (in thousand)
Answer: 2005