10-Q 1 form10-q.htm FORM 10-Q 9-30-07 form10-q.htm

 



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549


FORM 10-Q
x   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

OR

¨   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from________ to _________

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)
Delaware
73-0785597
(State of incorporation)
(I.R.S. employer identification number)
   
100 Glenborough Drive, Suite 100
 
Houston, Texas
77067
(Address of principal executive offices)
(Zip Code)
(281) 872-3100
 
(Registrant’s telephone number, including area code)

 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o



Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o    No x

Number of shares of common stock outstanding as of October 24, 2007: 171,449,686
 
 



 



PART I. FINANCIAL INFORMATION
 
ITEM 1. FINANCIAL STATEMENTS
 
             
Noble Energy, Inc. and Subsidiaries
 
Consolidated Balance Sheets
 
(in thousands, except share amounts)
 
             
   
(Unaudited)
       
   
September 30,
   
December 31,
 
   
2007
   
2006
 
ASSETS
           
Current Assets
           
     Cash and cash equivalents
  $
450,773
    $
153,408
 
     Accounts receivable - trade, net
   
555,850
     
586,882
 
     Deferred income taxes
   
64,337
     
99,835
 
     Probable insurance claims
   
12,193
     
101,233
 
     Other current assets
   
114,857
     
127,188
 
          Total current assets
   
1,198,010
     
1,068,546
 
Property, plant and equipment
               
     Oil and gas properties (successful efforts method of accounting)
   
9,924,532
     
8,867,639
 
     Other property, plant and equipment
   
93,475
     
79,646
 
     
10,018,007
     
8,947,285
 
     Accumulated depreciation, depletion and amortization
    (2,292,108 )     (1,776,528 )
     Total property, plant and equipment, net
   
7,725,899
     
7,170,757
 
Other noncurrent assets
   
561,270
     
568,032
 
Goodwill
   
766,249
     
781,290
 
          Total Assets
  $
10,251,428
    $
9,588,625
 
                 
LIABILITIES AND SHAREHOLDERS’ EQUITY
               
Current Liabilities
               
     Accounts payable - trade
  $
588,453
    $
518,609
 
     Derivative instruments
   
372,027
     
254,625
 
     Income taxes
   
54,055
     
107,136
 
     Short-term borrowings
   
25,000
     
-
 
     Asset retirement obligations
   
15,081
     
68,500
 
     Other current liabilities
   
176,579
     
235,392
 
         Total current liabilities
   
1,231,195
     
1,184,262
 
     Deferred income taxes
   
1,882,518
     
1,758,452
 
     Asset retirement obligations
   
108,589
     
127,689
 
     Derivative instruments
   
127,944
     
328,875
 
     Other noncurrent liabilities
   
341,873
     
274,720
 
     Long-term debt
   
1,941,018
     
1,800,810
 
         Total Liabilities
   
5,633,137
     
5,474,808
 
                 
Commitments and Contingencies
               
                 
Shareholders’ Equity
               
     Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
   
-
     
-
 
     Common stock - par value $3.33 1/3; 250,000,000 shares authorized; 190,462,250 and 188,808,087 shares issued, respectively
   
634,860
     
629,360
 
     Capital in excess of par value
   
2,088,891
     
2,041,048
 
     Accumulated other comprehensive loss
    (177,023 )     (140,509 )
     Treasury stock, at cost:18,580,865 and 16,574,384 shares, respectively
    (612,976 )     (511,443 )
     Retained earnings
   
2,684,539
     
2,095,361
 
         Total Shareholders’ Equity
   
4,618,291
     
4,113,817
 
         Total Liabilities and Shareholders’ Equity
  $
10,251,428
    $
9,588,625
 
                 
The accompanying notes are an integral part of these financial statements
               

2

Noble Energy, Inc. and Subsidiaries
 
Consolidated Statements of Operations
 
(in thousands, except per share amounts)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
Revenues
                       
     Oil and gas sales
  $
746,258
    $
683,544
    $
2,140,218
    $
2,044,656
 
     Income from equity method investees
   
45,371
     
33,810
     
139,904
     
108,901
 
     Other revenues
   
22,182
     
23,965
     
70,447
     
72,339
 
     Total Revenues
   
813,811
     
741,319
     
2,350,569
     
2,225,896
 
                                 
Costs and Expenses
                               
     Lease operating costs
   
81,767
     
76,928
     
243,205
     
238,307
 
     Production and ad valorem taxes
   
26,752
     
30,697
     
80,667
     
83,663
 
     Transportation costs
   
13,260
     
4,531
     
40,346
     
18,463
 
     Exploration costs
   
45,794
     
30,904
     
144,796
     
92,327
 
     Depreciation, depletion and amortization
   
195,266
     
165,765
     
540,453
     
458,878
 
     General and administrative
   
49,518
     
40,657
     
142,368
     
113,716
 
     Accretion of discount on asset retirement obligations
   
1,909
     
2,426
     
6,337
     
8,405
 
     Interest, net of amount capitalized
   
29,247
     
28,556
     
87,105
     
95,642
 
     Loss (gain) on derivative instruments
   
1,514
      (6,315 )     (557 )    
389,723
 
     Loss (gain) on sale of assets
   
1,684
      (200,676 )     (4,381 )     (211,691 )
     Loss on involuntary conversion
   
-
     
-
     
51,406
     
-
 
     Other expense, net
   
23,823
     
22,880
     
78,594
     
89,008
 
     Total Costs and Expenses
   
470,534
     
196,353
     
1,410,339
     
1,376,441
 
                                 
Income Before Taxes
   
343,277
     
544,966
     
940,230
     
849,455
 
Income Tax Provision
   
120,602
     
226,902
     
296,638
     
336,009
 
Net Income
  $
222,675
    $
318,064
    $
643,592
    $
513,446
 
                                 
Earnings Per Share
                               
     Basic
  $
1.30
    $
1.80
    $
3.76
    $
2.91
 
     Diluted
  $
1.28
    $
1.75
    $
3.72
    $
2.85
 
                                 
Weighted average number of shares outstanding
                               
    Basic
   
171,123
     
176,218
     
170,953
     
176,505
 
    Diluted
   
173,350
     
181,077
     
173,156
     
180,158
 
                                 
The accompanying notes are an integral part of these financial statements
                         

3

Noble Energy, Inc. and Subsidiaries
 
Consolidated Statements of Cash Flows
 
(in thousands)
 
(Unaudited)
 
   
Nine Months Ended
 
   
September 30,   
 
   
2007
   
2006
 
Cash Flows From Operating Activities
           
Net income
  $
643,592
    $
513,446
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
     Depreciation, depletion and amortization - oil and gas production
   
540,453
     
458,878
 
     Depreciation, depletion and amortization - electricity generation
   
10,558
     
11,842
 
     Dry hole expense
   
47,769
     
24,164
 
     Impairment of operating assets
   
3,661
     
6,359
 
     Amortization of unproved leasehold costs
   
12,700
     
15,180
 
     Stock-based compensation expense
   
20,040
     
9,320
 
     Gain on sale of assets
    (4,381 )     (211,691 )
     Deferred income taxes
   
192,137
     
146,709
 
     Accretion of discount on asset retirement obligations
   
6,337
     
8,405
 
     Increase in allowance for doubtful accounts
   
10,780
     
10,564
 
     Income from equity method investees
    (139,904 )     (108,901 )
     Dividends from equity method investees
   
153,331
     
18,000
 
     Deferred compensation expense
   
23,089
     
15,673
 
     (Gain) loss on derivative instruments
    (133,580 )    
430,328
 
     Loss on involuntary conversion
   
51,406
     
-
 
     Other
   
6,861
      (17,657 )
Changes in operating assets and liabilities, net of acquisition:
               
     Decrease (increase) in accounts receivable - trade
   
20,984
      (41,222 )
     (Increase) decrease in other current assets
    (2,733 )    
13,479
 
     Decrease in probable insurance claims
   
94,695
     
101,612
 
     Decrease in accounts payable
    (11,875 )     (29,246 )
     Decrease in other current liabilities
    (225,309 )     (34,429 )
Net Cash Provided by Operating Activities
   
1,320,611
     
1,340,813
 
                 
Cash Flows From Investing Activities
               
     Additions to property, plant and equipment
    (1,017,702 )     (1,030,430 )
     U.S. Exploration acquisition, net of cash acquired
   
-
      (412,257 )
     Proceeds from sales of assets
   
-
     
504,259
 
     Investments in equity method investees
   
-
      (5,126 )
     Distributions from equity method investees
   
2,100
     
116,521
 
Net Cash Used in Investing Activities
    (1,015,602 )     (827,033 )
                 
Cash Flows From Financing Activities
               
     Exercise of stock options
   
19,381
     
50,576
 
     Tax benefits from stock-based awards
   
13,922
     
18,534
 
     Cash dividends paid
    (54,414 )     (35,776 )
     Purchases of treasury stock
    (101,533 )     (192,632 )
     Proceeds from credit facility
   
280,000
     
300,000
 
     Repayment of credit facility
    (165,000 )     (605,000 )
     Repayment of term loans
   
-
      (105,000 )
     Net proceeds from short term borrowings
   
-
     
35,000
 
Net Cash Used in Financing Activities
    (7,644 )     (534,298 )
Increase (Decrease) in Cash and Cash Equivalents
   
297,365
      (20,518 )
Cash and Cash Equivalents at Beginning of Period
   
153,408
     
110,321
 
Cash and Cash Equivalents at End of Period
  $
450,773
    $
89,803
 
                 
The accompanying notes are an integral part of these financial statements
               

4

Noble Energy, Inc. and Subsidiaries
 
Consolidated Statements of Shareholders' Equity
 
(in thousands)
 
(Unaudited)
 
                                                 
                     
Deferred
   
Accumulated
                   
               
Capital in
   
Compensation -
   
Other
   
Treasury
         
Total
 
   
Common Stock
   
Excess of
   
Restricted
   
Comprehensive
   
Stock
   
Retained
   
Shareholders'
 
   
Shares
   
Amount
   
Par Value
   
Stock
   
Loss
   
at Cost
   
Earnings
   
Equity
 
                                                 
December 31, 2006
   
188,808
    $
629,360
    $
2,041,048
    $
-
    $ (140,509 )   $ (511,443 )   $
2,095,361
    $
4,113,817
 
Net income
   
-
     
-
     
-
     
-
     
-
     
-
     
643,592
     
643,592
 
Stock-based compensation expense  
-
     
-
     
20,040
     
-
     
-
     
-
     
-
     
20,040
 
Exercise of stock options
   
1,128
     
3,760
     
15,621
     
-
     
-
     
-
     
-
     
19,381
 
Tax benefits from stock-based awards  
-
     
-
     
13,922
     
-
     
-
     
-
     
-
     
13,922
 
Restricted stock grants, net
   
526
     
1,740
      (1,740 )    
-
     
-
     
-
     
-
     
-
 
Dividends ($0.315 per share)
   
-
     
-
     
-
     
-
     
-
     
-
      (54,414 )     (54,414 )
Purchases of treasury stock
   
-
     
-
     
-
     
-
     
-
      (101,533 )    
-
      (101,533 )
Oil and gas cash flow hedges:
                                                         
Realized amounts reclassified into earnings  
-
     
-
     
-
     
-
     
5,180
     
-
     
-
     
5,180
 
Unrealized change in fair value
   
-
     
-
     
-
     
-
      (44,006 )    
-
     
-
      (44,006 )
Net change in other
   
-
     
-
     
-
     
-
     
2,312
     
-
     
-
     
2,312
 
September 30, 2007
   
190,462
    $
634,860
    $
2,088,891
    $
-
    $ (177,023 )   $ (612,976 )   $
2,684,539
    $
4,618,291
 
                                                                 
December 31, 2005
   
184,894
    $
616,311
    $
1,945,239
    $ (5,288 )   $ (783,499 )   $ (148,476 )   $
1,465,857
    $
3,090,144
 
Net income
   
-
     
-
     
-
     
-
     
-
     
-
     
513,446
     
513,446
 
Adoption of SFAS 123(R), net of tax  
-
     
-
      (5,288 )    
5,288
     
-
     
-
     
-
     
-
 
Stock-based compensation expense
   
-
     
-
     
9,320
     
-
     
-
     
-
     
-
     
9,320
 
Exercise of stock options
   
2,815
     
9,382
     
41,194
     
-
     
-
     
-
     
-
     
50,576
 
Tax benefits from stock-based awards  
-
     
-
     
18,534
     
-
     
-
     
-
     
-
     
18,534
 
Restricted stock grants, net
   
64
     
217
      (217 )    
-
     
-
     
-
     
-
     
-
 
Dividends ($0.20 per share)
   
-
     
-
     
-
     
-
     
-
     
-
      (35,776 )     (35,776 )
Rabbi trust shares sold
   
-
     
-
     
7,837
     
-
     
-
     
24,005
     
-
     
31,842
 
Purchases of treasury stock
   
-
     
-
     
-
     
-
     
-
      (192,632 )    
-
      (192,632 )
Oil and gas cash flow hedges:
                                                         
Realized amounts reclassifed into earnings
   
-
     
-
     
-
     
-
     
136,546
     
-
     
-
     
136,546
 
Unrealized change in fair value
   
-
     
-
     
-
     
-
     
197,239
     
-
     
-
     
197,239
 
Unrealized amounts reclassified into earnings
   
-
     
-
     
-
     
-
     
264,265
     
-
     
-
     
264,265
 
Net change in other
   
-
     
-
     
-
     
-
     
533
     
-
     
-
     
533
 
September 30, 2006
   
187,773
    $
625,910
    $
2,016,619
    $
-
    $ (184,916 )   $ (317,103 )   $
1,943,527
    $
4,084,037
 
                                                                 
The accompanying notes are an integral part of these financial statements
                         


5

Noble Energy, Inc. and Subsidiaries           
 
Consolidated Statements of Comprehensive Income
 
(in thousands)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
                         
Net income
  $
222,675
    $
318,064
    $
643,592
    $
513,446
 
                                 
Other items of comprehensive income (loss)
                               
Oil and gas cash flow hedges:
                               
    Realized amounts reclassified into earnings
   
12,324
     
43,798
     
8,302
     
219,035
 
        Less tax provision
    (4,634 )     (16,494 )     (3,122 )     (82,489 )
    Unrealized change in fair value
   
11,804
     
274,361
      (70,523 )    
266,483
 
        Less tax provision
    (4,438 )     (87,952 )    
26,517
      (69,244 )
    Unrealized amounts reclassified into earnings
   
-
     
-
     
-
     
423,910
 
        Less tax provision
   
-
     
-
     
-
      (159,645 )
Net change in other:
   
186
     
354
     
3,705
     
855
 
        Less tax provision
    (70 )     (134 )     (1,393 )     (322 )
Other comprehensive income (loss)
   
15,172
     
213,933
      (36,514 )    
598,583
 
                                 
Comprehensive income
  $
237,847
    $
531,997
    $
607,078
    $
1,112,029
 
                                 
The accompanying notes are an integral part of these financial statements
                 

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (Unaudited)

Note 1 - Organization and Nature of Operations
 
Noble Energy, Inc. (“Noble Energy”, “we”, “our” or “us”) is an independent energy company engaged in the exploration, development, production and marketing of crude oil and natural gas. We have exploration, exploitation and production operations domestically and internationally. We operate throughout major basins in the US including Colorado’s Wattenberg field, the Mid-continent area of western Oklahoma and the Texas Panhandle, the San Juan Basin in New Mexico, the Gulf Coast and the deepwater Gulf of Mexico. In addition, we conduct business internationally in West Africa (Equatorial Guinea and Cameroon), the Mediterranean Sea (Israel), Ecuador, the North Sea (UK, the Netherlands and Norway), China, Argentina and Suriname.

Note 2 - Basis of Presentation
 
Presentation – The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US generally accepted accounting principles (“GAAP”) for complete financial statements. The accompanying unaudited consolidated financial statements at September 30, 2007 and December 31, 2006 and for the three and nine months ended September 30, 2007 and 2006 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three and nine months ended September 30, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes included in our annual report on Form 10-K for the year ended December 31, 2006.

Estimates – The preparation of consolidated financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates.


7

Balance Sheet and Statement of Operations Information –
Other balance sheet and statement of operations information is as follows:
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(in thousands)
 
Other Current Assets
           
Derivative instruments
  $
20,282
    $
35,242
 
Materials and supplies inventories
   
62,399
     
46,973
 
Prepaid expenses and other current assets
   
32,176
     
44,973
 
Total
  $
114,857
    $
127,188
 
Other Noncurrent Assets
               
Equity method investments
  $
358,940
    $
373,372
 
Mutual fund investments
   
125,860
     
116,314
 
Probable insurance claims
   
40,846
     
46,500
 
Derivative instruments
   
5,172
     
2,862
 
Other noncurrent assets
   
30,452
     
28,984
 
Total
  $
561,270
    $
568,032
 
Other Current Liabilities
               
Accrued and other current liabilities
  $
151,292
    $
219,885
 
Interest payable
   
25,287
     
15,507
 
Total
  $
176,579
    $
235,392
 
Other Noncurrent Liabilities
               
Deferred compensation liability
  $
207,825
    $
173,253
 
Accrued benefit costs
   
57,850
     
58,491
 
Other noncurrent liabilities
   
76,198
     
42,976
 
Total
  $
341,873
    $
274,720
 

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)         
 
Other Revenues
                       
Electricity sales
  $
16,616
    $
16,241
    $
53,745
    $
49,672
 
Gathering, marketing and processing
   
5,566
     
7,724
     
16,702
     
22,667
 
Total
  $
22,182
    $
23,965
    $
70,447
    $
72,339
 
                                 
Other Expense, net
                               
Electricity generation
  $
13,679
    $
17,876
    $
41,941
    $
43,099
 
Gathering, marketing and processing
   
4,100
     
4,204
     
13,093
     
15,674
 
Deferred compensation expense
   
8,423
     
933
     
23,089
     
15,673
 
Impairment of operating assets
   
3,661
     
-
     
3,661
     
6,359
 
Other
    (6,040 )     (133 )     (3,190 )    
8,203
 
Total
  $
23,823
    $
22,880
    $
78,594
    $
89,008
 

Note 3 - Derivative Instruments and Hedging Activities
 
Cash Flow Hedges – We use various derivative instruments in connection with forecasted crude oil and natural gas sales to mitigate the variability of cash flows associated with commodity price fluctuations. Such instruments include variable to fixed price swaps, costless collars and basis swaps.  While these instruments mitigate the cash flow risk of future reductions in commodity prices they may also curtail benefits from future increases in commodity prices.

We account for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and have elected to designate certain of our derivative instruments as cash flow hedges. Derivative instruments designated as cash flow hedges are reflected at fair value in the consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are reported in accumulated other comprehensive income or loss (“AOCL”) until the forecasted transaction occurs. Gains and losses from such derivative instruments related to our crude oil and natural gas sales, and which qualify for hedge accounting treatment, are recorded in oil and gas sales on our consolidated statements of operations upon sale of the associated commodity. We assess hedge effectiveness quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is immediately recognized in earnings.

8

(Gain) loss on derivative instruments included the following:
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)      
 
                         
Ineffectiveness (gains) losses
  $
1,514
    $ (2,957 )   $ (557 )   $
8,384
 
Reclassified from AOCL
   
-
     
-
     
-
     
423,910
 
Mark-to-market gain on derivative instruments not accounted for as cash flow hedges
   
-
      (3,358 )    
-
      (42,571 )
Loss (gain) on derivative instruments
  $
1,514
    $ (6,315 )   $ (557 )   $
389,723
 

During 2006, $424 million of losses deferred in AOCL were reclassified to our earnings when it became probable that forecasted sales would not occur. Of this amount, $399 million related to the sale of Gulf of Mexico shelf assets.

Effects of cash flow hedges on natural gas and crude oil sales were as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)         
 
                         
Increase (decrease) in natural gas sales
  $
47,973
    $
2,588
    $
120,057
    $ (59,348 )
Decrease in crude oil sales
    (60,297 )     (46,386 )     (128,359 )     (159,687 )
Total decrease in oil and gas sales
  $ (12,324 )   $ (43,798 )   $ (8,302 )   $ (219,035 )

The increase in natural gas sales in 2007 includes non-cash increases related to hedge contracts that were re-designated at the time of our Gulf of Mexico shelf asset sale in 2006 and settled during the first nine months of 2007. These non-cash increases totaled $42 million for third quarter 2007 and $133 million for the first nine months of 2007.

At September 30, 2007, we had entered into, and designated as cash flow hedges, the following variable to fixed price swap derivative instruments related to natural gas and crude oil sales.
   
Natural Gas   
   
Crude Oil   
 
         
Average Price
         
Average price
 
Production Period
 
MMBtupd
   
per MMBtu
   
Bopd
   
per Bbl
 
October - December 2007 (NYMEX)
   
170,000
    $
5.97
     
17,100
    $
38.74
 
                                 
2008 (NYMEX)
   
170,000
     
5.66
     
16,500
     
38.23
 


9

At September 30, 2007, we had entered into basis swap derivative instruments related to natural gas sales. These basis swaps have been combined with NYMEX variable to fixed swaps and designated as cash flow hedges. The basis swaps are as follows:
   
Natural Gas   
 
         
Average
 
         
Differential
 
Production Period
 
MMBtupd
   
per MMBtu
 
October - December 2007 (CIG (1) vs. NYMEX)
   
100,000
    $
2.02
 
October - December 2007 (ANR (2) vs. NYMEX)
   
30,000
     
1.17
 
October - December 2007 (PEPL (3) vs. NYMEX)
   
10,000
     
1.11
 
                 
2008 (CIG vs. NYMEX)
   
100,000
     
1.66
 
2008 (ANR vs. NYMEX)
   
40,000
     
1.01
 
2008 (PEPL vs. NYMEX)
   
10,000
     
0.98
 
                 
(1)
Colorado Interstate Gas - Northern System
(2)
ANR Oklahoma Pipeline
(3)
Panhandle Eastern Pipe Line
 
At September 30, 2007, we had entered into, and designated as cash flow hedges, the following costless collar derivative instruments related to natural gas and crude oil sales.
   
Natural Gas      
   
Crude Oil      
 
         
Average price
         
Average price
 
         
per MMBtu
         
per Bbl   
 
Production Period
 
MMBtupd
   
Floor
   
Ceiling
   
Bopd
   
Floor
   
Ceiling
 
October - December 2007 (NYMEX)
   
-
    $
-
    $
-
     
2,700
    $
60.00
    $
74.30
 
October - December 2007 (CIG)
   
12,000
     
6.50
     
9.50
     
-
     
-
     
-
 
October - December 2007 (Dated Brent)
   
-
     
-
     
-
     
5,565
     
45.00
     
70.29
 
                                                 
2008 (NYMEX)
   
-
     
-
     
-
     
3,100
     
60.00
     
72.40
 
2008 (CIG)
   
14,000
     
6.75
     
8.70
     
-
     
-
     
-
 
2008 (Dated Brent)
   
-
     
-
     
-
     
4,074
     
45.00
     
66.52
 
                                                 
2009 (NYMEX)
   
-
     
-
     
-
     
3,700
     
60.00
     
70.00
 
2009 (CIG)
   
15,000
     
6.00
     
9.90
     
-
     
-
     
-
 
2009 (Dated Brent)
   
-
     
-
     
-
     
3,074
     
45.00
     
63.04
 
                                                 
2010 (NYMEX)
   
-
     
-
     
-
     
3,500
     
55.00
     
73.80
 
2010 (CIG)
   
15,000
     
6.25
     
8.10
     
-
     
-
     
-
 

If commodity prices were to stay the same as they were at September 30, 2007, approximately $107 million of deferred losses, net of taxes, related to the fair values of the derivative instruments included in AOCL at September 30, 2007 would be reversed during the next twelve months as the forecasted transactions occur, and settlements would be recorded as a reduction in oil and gas sales. All forecasted transactions currently being hedged are expected to occur through December 2010.

10

Note 4 – Defined Benefit Pension, Restoration and Medical and Life Plans
 
We have a noncontributory, tax-qualified defined benefit pension plan covering certain domestic employees. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. We sponsor other plans for the benefit of our employees and retirees, which include medical and life insurance benefits. Net periodic benefit cost related to the pension, restoration and medical and life plans was as follows:
 
   
Retirement & Restoration
   
Medical & Life
 
   
Plan Benefits   
   
Plan Benefits   
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)
 
Three Months Ended September 30,
                       
Service cost
  $
2,579
    $
2,400
    $
468
    $
420
 
Interest cost
   
2,536
     
2,224
     
307
     
296
 
Expected return on plan assets
    (2,898 )     (2,046 )    
-
     
-
 
Transition obligation recognition
   
60
     
60
     
-
     
-
 
Amortization of prior service cost
    (129 )     (114 )     (231 )     (246 )
Recognized net actuarial loss
   
560
     
420
     
204
     
320
 
Net periodic benefit cost
  $
2,708
    $
2,944
    $
748
    $
790
 
                                 
Nine Months Ended September 30,
                               
Service cost
  $
8,753
    $
8,406
    $
1,472
    $
1,692
 
Interest cost
   
7,484
     
6,736
     
893
     
986
 
Expected return on plan assets
    (8,284 )     (6,027 )    
-
     
-
 
Transition obligation recognition
   
180
     
180
     
-
     
-
 
Amortization of prior service cost
    (387 )     (66 )     (695 )     (489 )
Recognized net actuarial loss
   
2,516
     
1,660
     
790
     
868
 
Net periodic benefit cost
  $
10,262
    $
10,889
    $
2,460
    $
3,057
 

Cash contributions to the pension plan totaled $10 million during third quarter 2007.

Note 5 - Stock-Based Compensation
 
We recognized stock-based compensation expense as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)        
 
Stock-based compensation expense
  $
7,962
    $
2,997
    $
20,040
    $
9,320
 
Tax benefit from expense recognized
   
2,994
     
1,129
     
7,535
     
3,510
 
 
During the nine months ended September 30, 2007, we granted 1,535,919 stock options with a weighted-average grant-date fair value of $18.72 per option and awarded 538,893 shares of restricted stock with a weighted-average grant-date fair value of $53.63 per share.

11

Note 6 - Effect of Gulf Coast Hurricanes
 
We have completed our cleanup activities relating to the damage caused by Hurricane Ivan in 2004 and Katrina in 2005.  During early third quarter 2007, we completed the lifting and removal of the four platform decks that were sheared from their supporting structures during the storms.

During the first half of 2007, several factors contributed to an increase in our estimated cleanup costs for damage related to Hurricanes Ivan and Katrina.  These factors included cost escalation due to weather delays and an increase in effort for the design and construction of the deck lifting barge and mooring system, as well as additional costs for the actual deck lifting activities.  These increases caused the total project costs, combined with net book value of the assets destroyed, to exceed certain insurance coverage limitations.  As a result, we recorded $51 million as a loss on involuntary conversion for the first six months of 2007.

As of September 30, 2007, we have recorded probable insurance claims of $53 million. We are currently assessing the scope and timing of our redevelopment of the Main Pass properties. Ultimate recovery of our insurance claim is associated with redevelopment or possible settlement resolution with our insurance providers.

Insurance reimbursements received to date have been for cleanup and repair costs and are included in cash flows from operating activities.

Note 7 - Asset Retirement Obligations
 
Asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows:

   
Nine Months Ended
 
   
September 30, 2007
 
   
(in thousands)
 
Asset retirement obligations at December 31, 2006
  $
196,189
 
Liabilities incurred in current period
   
5,926
 
Liabilities settled in current period
    (163,226 )
Revisions
   
78,444
 
Accretion expense
   
6,337
 
Asset retirement obligations at September 30, 2007
  $
123,670
 

Liabilities settled and revisions during the period were primarily related to cleanup of hurricane damage at Main Pass.


12

Note 8 – Equity Method Investments
 
Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations.  Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations.

Equity method investments are as follows:
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(in thousands)
 
Equity method investments:
           
Atlantic Methanol Production Company, LLC ("AMPCO") (45% interest)
  $
204,091
    $
211,325
 
Alba Plant LLC ("Alba Plant") (27.8% interest)
   
140,501
     
146,051
 
Other
   
14,348
     
15,996
 
Total equity method investments
  $
358,940
    $
373,372
 

Summarized, 100%, combined financial information for AMPCO, Alba Plant and other equity method investees is as follows:

               
September 30,
   
December 31,
 
               
2007
   
2006
 
               
(in thousands)
 
Balance sheet information:
                       
Current assets
              $
262,330
    $
252,201
 
Noncurrent assets
               
839,524
     
857,465
 
Current liabilities
               
165,987
     
171,028
 
Noncurrent liabilities
               
2,181
     
2,385
 
                             
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)
 
Statements of operations information:
                           
Operating revenues
  $
218,584
    $
179,087
    $
641,897
    $
533,949
 
Less cost of goods sold
   
57,309
     
55,157
     
161,606
     
145,900
 
Gross margin
   
161,275
     
123,930
     
480,291
     
388,049
 
Less other expense, net
   
8,488
     
9,993
     
28,977
     
36,654
 
Less income tax expense
   
8,966
     
1,956
     
27,598
     
18,795
 
Net income
  $
143,821
    $
111,981
    $
423,716
    $
332,600
 



13

Note 9 - Basic and Diluted Earnings Per Share
 
Basic earnings per share (“EPS”) of common stock were computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options and restricted stock. The following table summarizes the calculation of basic and diluted EPS:

   
2007   
   
2006   
 
         
Weighted
         
Weighted
 
   
Net
   
Average
   
Net
   
Average
 
   
Income
   
Shares
   
Income
   
Shares
 
   
(in thousands, except per share amounts)
 
Three Months Ended September 30,
                       
Net income available to common shareholders and weighted average shares outstanding
  $
222,675
     
171,123
    $
318,064
     
176,218
 
Basic EPS
  $
1.30
            $
1.80
         
                                 
Net income available to common shareholders and weighted average shares outstanding
  $
222,675
     
171,123
    $
318,064
     
176,218
 
Plus incremental shares from assumed conversions:
                         
  Dilutive stock options
   
-
     
1,983
     
-
     
3,198
 
  Dilutive restricted stock
   
-
     
244
     
-
     
141
 
  Dilutive rabbi trust shares
   
-
     
-
    $ (708 )    
1,520
 
Adjusted net income and shares
  $
222,675
     
173,350
    $
317,356
     
181,077
 
Diluted EPS
  $
1.28
            $
1.75
         
                                 
Nine Months Ended September 30,
                               
Net income available to common shareholders and weighted average shares outstanding
  $
643,592
     
170,953
    $
513,446
     
176,505
 
Basic EPS
  $
3.76
            $
2.91
         
                                 
Net income available to common shareholders and weighted average shares outstanding
  $
643,592
     
170,953
    $
513,446
     
176,505
 
Plus incremental shares from assumed conversions:
                         
  Dilutive stock options
   
-
     
2,008
     
-
     
3,508
 
  Dilutive restricted stock
   
-
     
195
     
-
     
145
 
Adjusted net income and shares
  $
643,592
     
173,156
    $
513,446
     
180,158
 
Diluted EPS
  $
3.72
            $
2.85
         

Certain stock options, shares of restricted stock and shares of our common stock held in a rabbi trust were antidilutive and were excluded from the calculation of diluted EPS. These items represented 2.1 million and 0.8 million weighted average shares for third quarter 2007 and 2006, respectively, and 2.4 million and 2.0 million weighted average shares for the first nine months of 2007 and 2006, respectively.

Note 10 - Income Taxes
 
The income tax provision consists of the following:
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)         
 
Current
  $
31,981
    $
127,252
    $
104,501
    $
189,300
 
Deferred
   
88,621
     
99,650
     
192,137
     
146,709
 
Total income tax provision
  $
120,602
    $
226,902
    $
296,638
    $
336,009
 

14


In assessing whether or not deferred tax assets are realizable, we consider whether it is more likely than not that some portion of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2006, we had recorded deferred tax assets subject to valuation allowances of $74 million related to foreign tax credits and losses on foreign operations.  The valuation allowances with respect to the deferred tax assets totaled $74 million at December 31, 2006.

Adoption of FIN 48 and FSP FIN 48-1– We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”) as of January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We also adopted FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”) as of January 1, 2007. FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. The adoption of FIN 48 and FSP FIN 48-1 had no effect on our financial position or results of operations.

As of adoption at January 1, 2007 and at September 30, 2007, we had unrecognized tax benefits totaling $400,000. These tax benefits are “unrecognized” because they did not meet the threshold for financial statement recognition, which provides that a tax position should be recognized if it is more likely than not, based on the technical merits, that the position will be sustained upon examination. If these tax benefits were to meet the recognition criteria in the future, they would be recognized in our financial statements and would affect our effective tax rate. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US - 2004, Equatorial Guinea - 2006, China - 2006, Israel - 2000, UK - 2005 and the Netherlands - 2005. We recognize interest and penalties related to unrecognized tax benefits in income tax expense. We had accrued no interest or penalties at September 30, 2007, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax, and we believe that we are below the minimum statutory threshold for imposition of penalties.


15

Note 11 - Segment Information
 
We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are primarily in the business of natural gas and crude oil exploration and production:  North America (US); West Africa (Equatorial Guinea and Cameroon); North Sea (UK, the Netherlands and Norway); Israel; and Other International, Corporate and Marketing. Other International includes Argentina, China, Ecuador and Suriname. The following data was prepared on the same basis as our consolidated financial statements. The information excludes the effects of income taxes except for equity method investees.
 
                                 
Other Int'l
 
         
North
   
West
               
Corporate &
 
   
Consolidated
   
America
   
Africa
   
North Sea
   
Israel
   
Marketing
 
   
(in thousands)
 
Three Months Ended September 30, 2007
                               
Revenues from third parties
  $
768,440
    $
397,148
    $
97,893
    $
121,774
    $
35,626
    $
115,999
 
Intersegment revenue
   
-
     
60,201
     
-
     
-
     
-
      (60,201 )
Income from equity method investees
   
45,371
     
-
     
45,371
     
-
     
-
     
-
 
Total Revenues
   
813,811
     
457,349
     
143,264
     
121,774
     
35,626
     
55,798
 
                                                 
Depreciation, depletion and amortization
   
195,266
     
143,574
     
8,716
     
29,741
     
5,178
     
8,057
 
Loss on derivative instruments
   
1,514
     
1,514
     
-
     
-
     
-
     
-
 
Income (loss) before taxes
   
343,277
     
181,291
     
112,273
     
77,536
     
27,957
      (55,780 )
                                                 
Three Months Ended September 30, 2006
                                         
Revenues from third parties
  $
707,509
    $
406,173
    $
85,498
    $
26,082
    $
30,451
    $
159,305
 
Intersegment revenue
   
-
     
99,549
     
-
     
-
     
-
      (99,549 )
Income from equity method investees
   
33,810
     
-
     
33,810
     
-
     
-
     
-
 
Total Revenues
   
741,319
     
505,722
     
119,308
     
26,082
     
30,451
     
59,756
 
                                                 
Depreciation, depletion and amortization
   
165,765
     
146,010
     
5,353
     
2,603
     
4,115
     
7,684
 
Gain on derivative instruments
    (6,315 )     (6,315 )    
-
     
-
     
-
     
-
 
Income (loss) before taxes
   
544,966
     
435,432
     
107,206
     
15,707
     
24,785
      (38,164 )
                                                 
16

                                 
Other Int'l
 
         
North
   
West
               
Corporate &
 
   
Consolidated
   
America
   
Africa
   
North Sea
   
Israel
   
Marketing
 
   
(in thousands)
 
Nine Months Ended September 30, 2007
                               
Revenues from third parties
  $
2,210,665
    $
1,209,760
    $
283,168
    $
239,104
    $
84,937
    $
393,696
 
Intersegment revenue
   
-
     
227,141
     
-
     
-
     
-
      (227,141 )
Income from equity method investees
   
139,904
     
-
     
139,904
     
-
     
-
     
-
 
Total Revenues
   
2,350,569
     
1,436,901
     
423,072
     
239,104
     
84,937
     
166,555
 
                                                 
Depreciation, depletion and amortization
   
540,453
     
427,861
     
18,731
     
56,849
     
13,011
     
24,001
 
Gain on derivative instruments
    (557 )     (557 )    
-
     
-
     
-
     
-
 
Loss on involuntary conversion
   
51,406
     
51,406
     
-
     
-
     
-
     
-
 
Income (loss) before taxes
   
940,230
     
558,784
     
338,082
     
137,057
     
65,132
      (158,825 )
                                                 
Nine Months Ended September 30, 2006
                                         
Revenues from third parties
  $
2,116,995
    $
1,097,212
    $
306,870
    $
88,723
    $
68,441
    $
555,749
 
Intersegment revenue
   
-
     
372,656
     
-
     
-
     
-
      (372,656 )
Income from equity method investees
   
108,901
     
-
     
108,901
     
-
     
-
     
-
 
Total Revenues
   
2,225,896
     
1,469,868
     
415,771
     
88,723
     
68,441
     
183,093
 
                                                 
Depreciation, depletion and amortization
   
458,878
     
402,033
     
15,674
     
5,933
     
10,367
     
24,871
 
Loss on derivative instruments
   
389,723
     
389,723
     
-
     
-
     
-
     
-
 
Income (loss) before taxes
   
849,455
     
484,655
     
373,490
     
59,250
     
52,851
      (120,791 )
                                                 
Total assets at September 30, 2007 (1)
  $
10,251,428
    $
7,515,385
    $
1,222,046
    $
476,729
    $
265,026
    $
772,242
 
Total assets at December 31, 2006 (1)
   
9,588,625
     
7,224,920
     
960,357
     
343,236
     
256,913
     
803,199
 

(1)
North America includes goodwill of $766 million and $781 million at September 30, 2007 and December 31, 2006, respectively.

Note 12 - Commitments and Contingencies
 
Legal Proceedings–  We are among a group of eighteen defendants named in a lawsuit filed August 23, 2002 by Dore Energy Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish, Louisiana.  The lawsuit alleges damage to property owned by Dore resulting from oil and gas activities dating to the 1930’s.  Our predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999.  This disclosure is being made due to Dore’s recent delivery of documents alleging approximately $140 million in damages.  We intend to vigorously defend against these allegations and believe that our share of damages, if any, will not have a material adverse effect on our results of operations, financial condition or liquidity.
 
The Illinois Environmental Protection Agency (“IEPA”) issued a notice of violation to Equinox Oil Company on September 25, 2001 alleging violation of air emission and permitting regulations for a facility known as the Zif Gas Plant located near Clay City, Illinois.  On January 17, 2007, the IEPA re-issued written notices of these alleged violations in the name of Equinox’s successors in interest, and our wholly-owned subsidiaries, Elysium Energy, LLC and Noble Energy Production, Inc. On March 16, 2007, the IEPA accepted our compliance commitment agreement wherein we agreed to pay a delayed permit fee, install an incineration/caustic scrubber emissions control system at the site, and fund a supplemental environmental project (“SEP”) in the nearby community.  At this time, we expect no additional monies to be expended other than these amounts for which we have fully accrued.  As of September 30, 2007, the emissions control system is operational and test information is being collected to provide to the IEPA.  The initial SEP project has been completed.

We are involved in various legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we do not believe that the ultimate disposition of such proceedings will have a material adverse effect on our financial position, results of operations or cash flows.

17

Note 13 - Capitalized Exploratory Well Costs
 
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period.
 
   
Nine Months Ended
 
   
September 30, 2007
 
   
(in thousands)
 
       
Capitalized exploratory well costs at beginning of period
  $
80,359
 
Additions to capitalized exploratory well costs pending determination of proved reserves
   
145,575
 
Reclassified to proved oil and gas properties based on determination of proved reserves
    (4,595 )
Capitalized exploratory well costs charged to expense
    (6,454 )
Capitalized exploratory well costs at end of period
  $
214,885
 

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
   
September 30,
   
December 31,
 
   
2007
   
2006
 
   
(in thousands)   
 
Capitalized exploratory well costs that have been capitalized for a period of one year or less
  $
174,602
    $
58,493
 
Capitalized exploratory well costs that have been capitalized for a period greater than one year after completion of drilling
   
40,283
     
21,866
 
Balance at end of period
  $
214,885
    $
80,359
 
                 
Number of projects that have exploratory well costs that have been capitalized for a period greater than one
               
   year after completion of drilling
   
2
     
4
 

Exploratory well costs capitalized for more than one year at September 30, 2007 included two projects. One project relates to Blocks O and I, offshore Equatorial Guinea, and includes approximately $21 million of suspended exploratory well costs.  Since drilling the initial well for the project, additional seismic work has been completed and appraisal wells are being drilled to further evaluate this potential discovery.  The other project relates to Redrock (Mississippi Canyon Block 204), located in deepwater Gulf of Mexico, and includes approximately $19 million of suspended exploratory well costs.  We are assessing the economic and operating viability of the well and are currently planning a side-track project which will facilitate tie-back options.

18

Note 14 - Recently Issued Pronouncements
 
SFAS 157  In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already required or permitted by other standards for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We expect to adopt SFAS 157 on January 1, 2008 and are currently evaluating the provisions of SFAS 157 and assessing the impact it may have on our financial position and results of operations.

SFAS 159 – In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 159 and assessing the impact it may have on our financial position and results of operations.

FSP FIN 39-1– In April 2007, the FASB issued FSP FIN 39-1, “An Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”).   FSP FIN 39-1 allows companies to offset fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master netting arrangement. A company must make an accounting policy decision whether or not to offset fair value amounts. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007 and is to be applied retrospectively. We are currently evaluating the provisions of FSP FIN 39-1 and assessing the impact it may have on our financial position and results of operations.






19

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

We explore for and produce crude oil and natural gas on a worldwide basis.  Our strategy is to achieve growth in earnings and cash flow through the development of a high quality portfolio of producing assets that is balanced between domestic and international projects.

Third quarter 2007 financial results included the following:
 
 
·
net income of $223 million and diluted earnings per share of $1.28, as compared with net income of $318 million and diluted earnings per share of $1.75 for third quarter 2006 (which included the sale of our Gulf of Mexico shelf assets); and
 
·
cash flow from operating activities of $548 million, as compared with $407 million for third quarter 2006.
 
Third quarter 2007 operational results included the following:
 
 
·
oil discovery on Benita appraisal well on Block I, offshore Equatorial Guinea;
 
·
successful appraisal well (Belinda) on Block O, offshore Equatorial Guinea;
 
·
exploration success at the YoYo prospect on PH-77 license, offshore Cameroon;
 
·
continued ramp-up of Dumbarton oil production in the North Sea;
 
·
record quarterly natural gas production in Israel; and
 
·
increasing natural gas sales to a liquefied natural gas (“LNG”) plant in Equatorial Guinea.

In addition, we were the high bidder, subject to regulatory approval, on nine deepwater lease blocks at the Central Gulf of Mexico Outer Continental Shelf Sale 205 held in October 2007.

OUTLOOK

We expect crude oil and natural gas production to increase in 2007 compared to 2006. The expected year-over-year increase in production is impacted by several factors including:
 
 
·
production contributions from the sale of natural gas from the Alba field in Equatorial Guinea to an LNG facility;
 
·
the contribution of production from the Dumbarton North Sea development;
 
·
growing natural gas sales in Israel due to the planned conversion of additional power plants to use natural gas as fuel;
 
·
growing production from the Piceance Basin and the Niobrara Trend areas in the Northern region of our North America operations, where we are continuing active drilling programs;
 
·
a full year of production from our acquisition of U.S. Exploration;
 
·
partially offset by loss of production from Gulf of Mexico shelf assets sold in July 2006, natural field decline in the Gulf Coast area and specific well performance in the deepwater Gulf of Mexico.

Factors impacting our expected production profile for the remainder of 2007 include:
 
 
·
infrastructure development in Israel;
 
·
potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas;
 
·
potential winter storm-related volume curtailments in the Northern region of our North America operations;
 
·
potential pipeline and processing facility capacity constraints in the Rocky Mountain area of our Northern region;
 
·
seasonal rainfall variations in Ecuador that affect our natural gas-to-power project;
 
·
natural gas volume curtailments in Equatorial Guinea due to LNG plant repairs; and
 
·
timing of capital expenditures, as discussed below, which are expected to result in near-term production.
 
 
20

2007 Capital Expenditures – We currently expect 2007 capital expenditures to total approximately $1.7 billion compared to the $1.4 billion announced in February of this year. The increases are primarily related to the acquisition and development of property in the Piceance Basin, acquisition of additional acreage in the Niobrara and New Albany Shale areas, leasing of offshore deepwater blocks in the Gulf of Mexico (subject to regulatory approval) and increases in our deepwater Gulf of Mexico and West Africa programs.  The increase in deepwater Gulf of Mexico is primarily associated with the recent Isabela discovery, Raton development and Ticonderoga field development.  Capital additions in West Africa are due to the addition of a second drilling rig which has now completed operations in Cameroon.  Approximately 29% of the 2007 capital expenditures will be spent for exploration opportunities and 71% will be spent for production, development and other projects. On a geographic basis, approximately 77% of the capital expenditures will be domestic spending, 20% will be international spending and 3% will be corporate spending. Expected 2007 capital expenditures do not include the impact of possible additional asset purchases. We expect that our 2007 capital expenditures will be funded primarily from cash flows from operations and borrowings under our revolving credit facility. We will evaluate the level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations, and property acquisitions and divestitures.

Recent Developments in Equatorial Guinea  Effective November 2006, the government of Equatorial Guinea enacted a new hydrocarbons law (the “2006 Hydrocarbons Law”) governing their domestic petroleum operations. The governmental agency overseeing the energy industry was given the authority to renegotiate any contract for the purpose of adapting any terms and conditions that are inconsistent with the new law.  Our assessment of the impact of the change in the law remains ongoing, and we are working with various governmental authorities to determine the effect on our current contracts.  However, at this time, the final impact of the 2006 Hydrocarbons Law on our operations in Equatorial Guinea remains uncertain.

Recently Issued Pronouncements – See Item 1. Financial Statements – Note 14 - Recently Issued Pronouncements.

LIQUIDITY AND CAPITAL RESOURCES

Overview
 
Our primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments and interest payments on debt. Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under credit facilities. Occasional sales of non-strategic crude oil and natural gas assets may also generate funds. We had $451 million in cash and cash equivalents at September 30, 2007, compared with $153 million at December 31, 2006. Substantially all of this cash is located in our foreign subsidiaries and would be subject to additional US income taxes if repatriated. The cash is denominated in US dollars and is invested in highly liquid, investment-grade securities with maturities of three months or less at the time of purchase.  We currently intend to use the cash located in our foreign subsidiaries to fund international projects, including the development of West Africa.

Cash Flows
 
Cash flow information is as follows:
   
Nine Months Ended
 
   
September 30,   
 
   
2007
   
2006
 
   
(in thousands)   
 
Total cash provided by (used in):
           
     Operating activities
  $
1,320,611
    $
1,340,813
 
     Investing activities
    (1,015,602 )     (827,033 )
     Financing activities
    (7,644 )     (534,298 )
     Increase (decrease) in cash and cash equivalents
  $
297,365
    $ (20,518 )

21

Operating Activities– For the first nine months of 2007, we reported net cash provided by operating activities of $1.3 billion as compared with $1.3 billion for the first nine months of 2006.  Significant factors impacting net cash provided by operating activities included:
 
 
·
cash flows from higher liquid commodity prices; and
 
·
dividends from equity method investees, which had been classified as investing cash flows in 2006 (See Item 2. Results of Operations – Equity Method Investees);
offset by:
 
·
a decrease in non-cash working capital resulting from decreases in the current portions of asset retirement obligations and other accrued liabilities; and
 
·
an increase in exploration costs, general and administrative expense and transportation costs.
 
Investing Activities – Net cash used in investing activities for the first nine months of 2007 totaled $1.0 billion, as compared with $827 million for the first nine months of 2006.  Significant factors impacting net cash used in investing activities included:
 
 
·
a slight decrease in capital expenditures during 2007 as compared to 2006;
 
·
a decrease in acquisition and divestiture activity during 2007 as compared to the acquisition of U.S. Exploration and sale of our Gulf of Mexico shelf assets during 2006; and
 
·
a decrease in distributions received from equity method investees for 2007 as compared to 2006 (See Item 2. Results of Operations – Equity Method Investees).

Financing Activities – Net cash used in financing activities for the first nine months of 2007 totaled $8 million, as compared with $534 million for the first nine months of 2006.  As compared with the first nine months of 2006, financing activities for the first nine months of 2007 included:
 
 
·
a net increase in cash from short-term and long-term borrowings in 2007 as compared with a net decrease from short-term and long-term borrowing repayments in 2006; and
 
·
a reduction of cash used for repurchases of our common stock during the first nine months of 2007 as compared with the first nine months of 2006.

Acquisition, Capital and Other Exploration Expenditures
 
Acquisition, capital and other exploration expenditure information (on an accrual basis) is as follows:

   
Three Months Ended   
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)         
 
Acquisition, Capital and Other Exploration Expenditures
                   
Lease acquisition of unproved property
  $
1,892
    $
-
    $
93,346
    $
130,819
 
Lease acquisition of proved property
   
116
     
-
     
5,703
     
412,687
 
Exploration expenditures
   
97,407
     
51,819
     
249,973
     
192,896
 
Development expenditures
   
344,870
     
328,218
     
841,888
     
825,481
 
Corporate and other expenditures
   
4,847
     
5,866
     
23,662
     
15,948
 
Total
  $
449,132
    $
385,903
    $
1,214,572
    $
1,577,831
 

Insurance Recoveries
 
See Item I. Financial Statements - Note 6 – Effect of Gulf Coast Hurricanes.

Financing Activities
 
Long-Term Debt Our long-term debt totaled $1.9 billion (excluding unamortized discount) at September 30, 2007. Maturities range from 2009 to 2097. Our ratio of debt-to-book capital was 30% at September 30, 2007 and December 31, 2006. We define our ratio of debt-to-book capital as total debt (which consists of long-term debt, excluding unamortized discount, plus short-term borrowings) divided by the sum of total debt plus equity.

Our principal source of liquidity is a $2.1 billion unsecured revolving credit facility (the “Credit Facility”) due December 2011. 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 swingline loans up to an aggregate amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the Credit Facility. The Credit Facility is with certain commercial lending institutions and is available for general corporate purposes. At September 30, 2007, $1.3 billion in borrowings were outstanding under the Credit Facility.  The weighted average interest rate applicable to borrowings under the Credit Facility at September 30, 2007 was 5.77%.

22

We have $650 million of fixed-rate debt outstanding at September 30, 2007 with a weighted average interest rate of 6.92%. Maturities range from 2014 to 2097.

Piceance Installment Payments Due – During second quarter 2007, we purchased working interests in oil and gas properties in the Piceance Basin of western Colorado for $75 million. After making an initial cash payment of $25 million, we owe $50 million in the form of installment payments to the seller. Installments of $25 million each are due on May 12, 2008 and May 11, 2009.  The amount due in 2008 is included in short-term borrowings and the amount due in 2009 is included in long-term debt in the consolidated balance sheets. Interest on the unpaid amounts is due quarterly. Interest accrues at a three-month LIBOR rate plus a margin.  The interest rate was 5.66% at September 30, 2007.

Other Short-Term Borrowings – Our Credit Facility is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing.  There were no borrowings outstanding under uncommitted credit lines at September 30, 2007.

Dividends – We paid quarterly cash dividends of 12 cents per share of common stock during third quarter 2007 as compared with 7.5 cents per share of common stock during third quarter 2006.  For the first nine months of 2007, we paid total cash dividends of 31.5 cents per share of common stock as compared with 20 cents per share of common stock for the first nine months of 2006. On October 23, 2007, our Board of Directors declared a quarterly cash dividend of 12 cents per common share, payable November 19, 2007 to shareholders of record on November 5, 2007. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

Exercise of Stock Options – We received $4 million from the exercise of stock options during third quarter of 2007 as compared with $21 million during third quarter 2006 and $19 million during the first nine months of 2007 as compared with $51 million during the first nine months of 2006.

23

RESULTS OF OPERATIONS

Natural Gas Information
 
Natural gas sales increased 2% during third quarter 2007 as compared with third quarter 2006 due to a 25% increase in sales volumes offset by a 19% decline in average realized sales prices. Natural gas sales increased 2% for the first nine months of 2007 as compared with 2006 due to an 8% increase in sales volumes offset by a 5% decrease in average realized sales prices. Natural gas sales were as follows:
   
Three Months Ended
 
Nine Months Ended
   
September 30,  
 
September 30,
   
2007
 
2006
 
2007
 
2006
   
(in thousands)      
                 
Natural gas sales
 
 $        296,360
 
 $         290,845
 
 $      935,364
 
 $      917,673

Natural gas sales are net of the effects of the settlement of derivative contracts that are accounted for as cash flow hedges. Natural gas sales in 2007 also include non-cash increases related to hedge contracts that were re-designated at the time of the Gulf of Mexico shelf asset sale in 2006 and settled during the first nine months of 2007. These non-cash increases totaled $42 million for third quarter 2007 and $133 million for the first nine months of 2007.

Average daily natural gas sales volumes and average realized sales prices were as follows:

   
2007   
   
2006   
 
   
Mcfpd
   
$/Mcf
   
Mcfpd
   
$/Mcf
 
Three Months Ended September 30,
                       
North America (1)
   
404,238
    $
6.77
     
430,072
    $
6.41
 
West Africa (2) (3)
   
207,501
     
0.27
     
40,498
     
0.39
 
North Sea
   
5,496
     
7.26
     
8,553
     
6.62
 
Israel
   
131,115
     
2.95
     
116,718
     
2.84
 
Ecuador (4)
   
24,844
     
-
     
20,131
     
-
 
Other International
   
-
     
-
     
198
     
1.51
 
Total
   
773,194
    $
4.30
     
616,170
    $
5.30
 
                                 
Nine Months Ended September 30,
                               
North America (1)
   
410,083
    $
7.42
     
461,843
    $
6.55
 
West Africa (2) (3)
   
126,820
     
0.29
     
44,232
     
0.38
 
North Sea
   
5,967
     
6.05
     
8,460
     
8.13
 
Israel
   
110,675
     
2.81
     
91,656
     
2.74
 
Ecuador (4)
   
25,571
     
-
     
22,764
     
-
 
Other International
   
-
     
-
     
324
     
1.20
 
Total
   
679,116
    $
5.24
     
629,279
    $
5.54
 
 
(1)
Average realized sales prices include the effects of hedging activities. Hedging activities resulted in increases (reductions) per Mcf of $1.29 and $0.07 for third quarter 2007 and 2006, respectively, and $1.07 and $(0.47) for the first nine months of 2007 and 2006, respectively.
(2)
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The price on an Mcf basis has been adjusted to reflect Btu content. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.  The volumes sold by the LPG plant are included in the table below under crude oil information.
(3)
Equatorial Guinea natural gas volumes include sales to an LNG plant of 154,637 Mcfpd for third quarter 2007 and 72,010 Mcfpd for the first nine months of 2007.  There were no natural gas sales to the LNG plant in 2006.
(4)
The natural gas-to-power project in Ecuador is 100% owned by our subsidiaries and intercompany natural gas sales are eliminated for accounting purposes. Electricity sales of $54 million and $50 million are included in other revenues for the first nine months of 2007 and 2006, respectively.
 
24

Factors contributing to the increase in natural gas sales volumes for the third quarter and first nine months of 2007 as compared with 2006 included:
 
 
·
sales of natural gas to an LNG facility in Equatorial Guinea;
 
·
a full nine months of production from U.S. Exploration properties and successful development activity in the Northern region of our North America operations; and
 
·
a full nine months of sales to Israeli Electric Company’s Reading power plant in Tel Aviv, as well as increased seasonal demand for electricity;
offset by:
 
·
reduction due to sale of our Gulf of Mexico shelf assets in 2006;
 
·
a temporary decline in production due to third party processing downtime and inclement weather in the Northern region of our North America operations;
 
·
natural field decline in the Gulf Coast area; and
 
·
declining performance and storm shut-in in the deepwater Gulf of Mexico.

Crude Oil Information
 
Crude oil sales increased 15% for third quarter 2007 as compared with third quarter 2007 due to a 7% increase in total consolidated sales volumes and a 7% increase in average realized sales prices. Crude oil sales increased 7% for the first nine months of 2007 as compared with 2006 due to a 4% increase in total consolidated sales volumes and a 3% increase in average realized sales prices. Crude oil sales were as follows:
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(in thousands)         
 
Crude oil sales
  $
449,898
    $
392,699
    $
1,204,854
    $
1,126,983
 

Crude oil sales are net of the effects of the settlement of derivative contracts that are accounted for as cash flow hedges. Average daily crude oil production and sales volumes and average realized sales prices were as follows:

   
2007      
   
2006      
 
   
Production (1)
   
Sales   
   
Production (1)
   
Sales   
 
   
Bopd
   
Bopd
   
$/Bbl
   
Bopd
   
Bopd
   
$/Bbl
 
Three Months Ended September 30,
                               
North America (2)
   
39,992
     
39,992
    $
55.85
     
48,193
     
48,193
    $
56.84
 
West Africa (3)
   
15,327
     
13,757
     
73.25
     
17,324
     
13,649
     
66.93
 
North Sea
   
15,722
     
16,644
     
77.13
     
3,675
     
3,292
     
68.90
 
Other International
   
6,630
     
6,578
     
55.55
     
7,783
     
6,825
     
56.96
 
Total Consolidated Operations
   
77,671
     
76,971
     
63.53
     
76,975
     
71,959
     
59.32
 
Equity Investees (4)
   
7,949
     
7,472
     
57.24
     
7,994
     
8,932
     
48.88
 
Total
   
85,620
     
84,443
    $
62.98
     
84,969
     
80,891
    $
58.17
 
                                                 
Nine Months Ended September 30,
                                         
North America (2)
   
43,525
     
43,525
    $
51.04
     
45,834
     
45,834
    $
51.48
 
West Africa (3)
   
15,874
     
14,936
     
66.97
     
17,790
     
17,374
     
63.73
 
North Sea
   
11,954
     
11,926
     
70.41
     
3,867
     
3,619
     
70.79
 
Other International
   
7,043
     
6,998
     
50.30
     
7,338
     
7,463
     
54.31
 
Total Consolidated Operations
   
78,396
     
77,385
     
57.03
     
74,829
     
74,290
     
55.57
 
Equity Investees (4)
   
8,220
     
7,862
     
50.93
     
7,503
     
8,168
     
46.96
 
Total
   
86,616
     
85,247
    $
56.47
     
82,332
     
82,458
    $
54.72
 

25

(1) The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings.
(2)
Average realized sales prices include the effects of hedging activities. Hedging activities resulted in reductions per Bbl of $15.64 and $10.46 for third quarter 2007 and 2006, respectively, and $10.57 and $12.76 for the first nine months of 2007 and 2006, respectively.
(3)
Average realized sales prices include the effects of hedging activities. Hedging activities resulted in reductions per Bbl of $2.18 for third quarter 2007 and $0.68 for the first nine months of 2007.
(4)
Volumes represent our share of sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG volumes were 5,530 Bpd and 6,957 Bpd for third quarter 2007 and 2006, respectively, and 5,907 Bopd and 6,409 Bopd for the first nine months of 2007 and 2006, respectively.

Factors contributing to the increases in crude oil sales volumes for the third quarter and first nine months of 2007 as compared with 2006 included:
 
 
·
contribution of Dumbarton North Sea development;
 
·
a full nine months of production from U.S. Exploration properties; and
 
·
successful development activity in the Northern region of our North America operations;
offset by:
 
·
reduction due to sale our of Gulf of Mexico shelf assets in 2006;
 
·
timing of liftings in Equatorial Guinea;
 
·
temporary decline in production due to inclement weather in the Northern region;
 
·
natural field decline in the Gulf Coast area; and
 
·
declining performance and storm shut-in in the deepwater Gulf of Mexico.

Effect of Hedging Activities
 
We hedge varying portions of forecasted future crude oil and natural gas sales to reduce the exposure to commodity price fluctuations. Revenues from oil and gas sales include the results of crude oil and natural gas cash flow hedging activities. Cash flow hedging activities decreased oil and gas sales by $12 million and $44 million for third quarter 2007 and 2006, respectively, and $8 million and $219 million for the first nine months of 2007 and 2006, respectively. See Item I. Financial Statements - Note 3 – Derivative Instruments and Hedging Activities.

Equity Method Investees
 
Our share of operations of equity method investees was as follows:
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
Net income (in thousands):
                       
   AMPCO and affiliates
  $
14,649
    $
3,302
    $
50,404
    $
27,415
 
   Alba Plant
  $
30,722
    $
30,508
    $
89,500
    $
81,486
 
Distributions/Dividends (in thousands):
                               
   AMPCO and affiliates
  $
17,513
    $
-
    $
59,920
    $
19,500
 
   Alba Plant
  $
40,975
    $
39,001
    $
95,511
    $
115,021
 
Sales volumes:
                               
   Methanol (Kgal)
   
43,541
     
18,769
     
116,792
     
85,233
 
   Condensate (Bopd)
   
1,942
     
1,975
     
1,955
     
1,759
 
   LPG (Bpd)
   
5,530
     
6,957
     
5,907
     
6,409
 
Production volumes:
                               
   Condensate (Bopd)
   
1,815
     
1,811
     
1,896
     
1,726
 
   LPG (Bpd)
   
6,134
     
6,183
     
6,324
     
5,777
 
Average realized prices:
                               
   Methanol (per gallon)
  $
0.80
    $
0.83
    $
0.96
    $
0.83
 
   Condensate (per Bbl)
  $
77.91
    $
69.46
    $
69.63
    $
67.51
 
   LPG (per Bbl)
  $
49.98
    $
43.03
    $
44.75
    $
41.32
 

For third quarter 2007, net income from AMPCO and affiliates increased substantially relative to 2006 due to a more than twofold increase in methanol sales volumes. For the first nine months of 2007, net income from AMPCO and affiliates increased 84% relative to 2006 due to a 37% increase in methanol sales volumes and a 16% increase in average realized methanol prices. The increase in methanol sales volumes for both the three months and nine months ended September 30, 2007 was due to a 57-day shutdown of methanol production for the plant turnaround that occurred during May and June 2006 followed by 35 days of compressor repairs.

For third quarter 2007, net income from Alba Plant increased 1% relative to 2006 due to a 16% increase in average realized LPG prices and a 12% increase in average realized condensate prices offset by a 21% decrease in LPG sales volumes. The decrease in LPG sales volumes for the three months ended September 30, 2007 was due to the timing of liftings. For the first nine months of 2007, net income from Alba Plant increased 10% relative to 2006 due to an 11% increase in condensate sales volumes and an 8% increase in average realized LPG prices offset by an 8% decrease in LPG sales volumes.

For the first nine months of 2007, $96 million received from Alba Plant was classified within operating cash flows as a dividend from equity method investee as compared with the first nine months of 2006 in which the distributions were classified within investing cash flows as a repayment of a loan. The change in classification was the result of all outstanding loans being repaid to us by Alba Plant in December 2006.


26

Costs and Expenses
 
Production Costs – Production costs were as follows:
         
North
   
West
               
Other Int'l /
 
   
Consolidated
   
America
   
Africa
   
North Sea
   
Israel
   
Corporate(2)
 
   
(in thousands)               
 
Three Months Ended September 30, 2007
                               
Oil and gas operating costs (1)
  $
77,283
    $
50,007
    $
7,483
    $
10,697
    $
2,615
    $
6,481
 
Workover and repair expense
   
4,484
     
4,460
     
-
     
-
     
-
     
24
 
Lease operating expense
   
81,767
     
54,467
     
7,483
     
10,697
     
2,615
     
6,505
 
Production and ad valorem taxes
   
26,752
     
21,389
     
-
     
-
     
-
     
5,363
 
Transportation costs
   
13,260
     
10,111
     
-
     
2,859
     
-
     
290
 
Total production costs
  $
121,779
    $
85,967
    $
7,483
    $
13,556
    $
2,615
    $
12,158
 
                                                 
Three Months Ended September 30, 2006
                                         
Oil and gas operating costs (1)
  $
66,431
    $
50,753
    $
6,310
    $
3,355
    $
2,134
    $
3,879
 
Workover and repair expense
   
10,497
     
10,453
     
-
     
-
     
-
     
44
 
Lease operating expense
   
76,928
     
61,206
     
6,310
     
3,355
     
2,134
     
3,923
 
Production and ad valorem taxes
   
30,697
     
22,636
     
-
     
-
     
-
     
8,061
 
Transportation costs
   
4,531
     
3,358
     
-
     
952
     
-
     
221
 
Total production costs
  $
112,156
    $
87,200
    $
6,310
    $
4,307
    $
2,134
    $
12,205
 
                                                 
Nine Months Ended September 30, 2007
                                         
Oil and gas operating costs (1)
  $
228,672
    $
155,980
    $
25,014
    $
23,954
    $
6,896
    $
16,828
 
Workover and repair expense
   
14,533
     
14,327
     
-
     
-
     
-
     
206
 
Lease operating expense
   
243,205
     
170,307
     
25,014
     
23,954
     
6,896
     
17,034
 
Production and ad valorem taxes
   
80,667
     
65,933
     
-
     
-
     
-
     
14,734
 
Transportation costs
   
40,346
     
31,887
     
-
     
7,091
     
-
     
1,368
 
Total production costs
  $
364,218
    $
268,127
    $
25,014
    $
31,045
    $
6,896
    $
33,136
 
                                                 
Nine Months Ended September 30, 2006
                                         
Oil and gas operating costs (1)
  $
195,550
    $
147,357
    $
21,760
    $
7,998
    $
6,389
    $
12,046
 
Workover and repair expense
   
42,757
     
42,628
     
-
     
-
     
-
     
129
 
Lease operating expense
   
238,307
     
189,985
     
21,760
     
7,998
     
6,389
     
12,175
 
Production and ad valorem taxes
   
83,663
     
66,373
     
-
     
-
     
-
     
17,290
 
Transportation costs
   
18,463
     
14,022
     
-
     
3,843
     
-
     
598
 
Total production costs
  $
340,433
    $
270,380
    $
21,760
    $
11,841
    $
6,389
    $
30,063
 
 
(1) Oil and gas operating costs include labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs.
(2)
Other international includes Ecuador, China, and Argentina.
 
Oil and gas operating costs increased $11 million, or 16%, third quarter 2007, as compared with third quarter 2006, and increased $33 million, or 17%, for the first nine months of 2007, as compared with the first nine months of 2006.  The increases are primarily the result of expanded operations in the North Sea, the deepwater Gulf of Mexico and the Rocky Mountain and Mid-continent areas of our North America operations.  In addition, the first nine months of 2007 includes increased expense, including snow removal cost, related to severe winter weather in the Northern region.

Workover and repair expense decreased $6 million for third quarter 2007 and decreased $28 million for the first nine months of 2007, as compared with 2006.  The decrease was due to a reduction in hurricane-related repair expense. Hurricane-related repair expense was de minimis for third quarter 2007 and $1 million for the first nine months of 2007, as compared with $4 million for third quarter 2006 and $26 million for the first nine months of 2006.

27

Transportation costs increased third quarter 2007 and the first nine months of 2007, as compared with 2006, primarily due to changes in the terms of certain sales contracts for Northern region production.

Selected expenses on a per BOE sales volume basis were as follows (Natural gas volumes are converted to oil equivalent volumes on the basis of six Mcf per barrel.):
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
                         
Oil and gas operating costs
  $
4.08
    $
4.14
    $
4.40
    $
4.00
 
Workover and repair expense
   
0.24
     
0.65
     
0.28
     
0.87
 
Lease operating expense
   
4.32
     
4.79
     
4.68
     
4.87
 
Production and ad valorem taxes
   
1.41
     
1.91
     
1.55
     
1.71
 
Transportation costs
   
0.70
     
0.28
     
0.78
     
0.38
 
Total production costs (1)
  $
6.43
    $
6.98
    $
7.01
    $
6.96
 

(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees. The sales volumes include natural gas sales to the Equatorial Guinea LNG plant that began late first quarter of 2007. The inclusion of these volumes reduced the unit rates by $0.92 per BOE and $0.47 per BOE for the three and nine months ending September 30, 2007, respectively.

The changes in the unit rates of total production costs are primarily due to the impact of the mix of sales volumes.  Workover and repair costs per BOE decreased in 2007 due to a reduction in hurricane-related repair expense.

Oil and Gas Exploration Expense – Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic expense, staff expense and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense was $46 million for third quarter 2007, as compared with $31 million for third quarter 2006. The increase was due to a $10 million increase in seismic expenditures primarily for the Gulf of Mexico and an $8 million increase in dry hole expense in West Africa, offset by a $2 million decrease in undeveloped leasehold amortization. Oil and gas exploration expense was $145 million for the first nine months of 2007, as compared with $92 million for the first nine months of 2006. The increases were due to a $27 million increase in seismic expenditures primarily for the Gulf of Mexico and North Sea, a $24 million increase in dry hole expense in West Africa, and a $5 million increase in staff expense for new venture activity, offset by a $2 million decrease in undeveloped leasehold amortization.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization (“DD&A”) expense was as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
                         
DD&A expense (in thousands)
  $
195,266
    $
165,765
    $
540,453
    $
458,878
 
Unit rate per BOE sales volume (1)
  $
10.31
    $
10.32
    $
10.39
    $
9.38
 

(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees. The sales volumes include natural gas sales to the Equatorial Guinea LNG plant that began late first quarter of 2007. The inclusion of these volumes reduced the unit rates by $1.20 per BOE and $0.57 per BOE for the three and nine months ending September 30, 2007, respectively.

DD&A expense for third quarter 2007 increased as compared with 2006 due to higher sales volumes in the North Sea, Equatorial Guinea and Israel. DD&A expense for the first nine months of 2007 increased as compared with 2006 due to higher sales volumes in the North Sea, Equatorial Guinea and Israel and also due to higher DD&A rates.  The increase in the unit rate was primarily due to higher finding and development costs in the Northern region of our North America operations and the Dumbarton North Sea development.


28

General and Administrative Expense– General and administrative expense (“G&A”) was as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,   
   
September 30,   
 
   
2007
   
2006
   
2007
   
2006
 
                         
G&A expense (in thousands)
  $
49,518
    $
40,657
    $
142,368
    $
113,716
 
Unit rate per BOE sales volume (1)
  $
2.61
    $
2.53
    $
2.74
    $
2.32
 

(1)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees. The sales volumes include natural gas sales to the Equatorial Guinea LNG plant that began late first quarter of 2007. The inclusion of these volumes reduced the unit rates by $0.38 per BOE and $0.18 per BOE for the three and nine months ending September 30, 2007, respectively.

G&A expense for third quarter and the first nine months of 2007 increased as compared with 2006 primarily due to higher salaries and wages resulting from an increase in the number of employees to address our increased activities.  G&A expense includes stock-based compensation expense of $8 million and $3 million for third quarter 2007 and 2006, respectively, and $19 million and $9 million for the first nine months of 2007 and 2006, respectively. Stock-based compensation expense increased in 2007 as compared with 2006 due to an increase in the quantity and fair market values of stock-based awards.

Interest Expense and Capitalized Interest – Interest expense, net of interest capitalized, was $29 million for third quarter 2007 and 2006. For the first nine months of 2007, interest expense, net of interest capitalized, decreased to $87 million, from $96 million for the first nine months of 2006. Capitalized interest was $4 million and $1 million for third quarter 2007 and 2006, respectively, and $10 million and $3 million for the first nine months of 2007 and 2006, respectively. Interest expense, net of interest capitalized, decreased in 2007 due to a lower average outstanding debt balance.

(Gain) Loss on Derivative Instruments – See Item I. Financial Statements - Note 3 – Derivative Instruments and Hedging Activities.

Gain on Sale of Assets– Third quarter 2006 includes a pretax gain of $204 million from the sale of substantially all of our Gulf of Mexico shelf assets.

Other Expense, Net – See Item I. Financial Statements - Note 2 – Basis of Presentation.

Income Tax Provision – The income tax provision was as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,  
   
September 30,  
 
   
2007
   
2006
   
2007
   
2006
 
                         
Income tax provision (in thousands)
  $
120,602
    $
226,902
    $
296,638
    $
336,009
 
Effective rate
    35.1 %     41.6 %     31.5 %     39.6 %

Tax expense was higher in 2006 because $100 million of goodwill associated with the sale of the Gulf of Mexico shelf assets was not deductible, there was an increase in the valuation allowance on a deferred tax asset for future foreign tax credits and there was an increase in deferred tax liabilities due to a rate change in the UK.  In addition, income from equity method investments was higher in 2007, which is a favorable permanent difference in calculating income tax expense.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

Commodity Price Risk
 
Derivative Instruments Held for Non-Trading Purposes– We are exposed to market risk in the normal course of business operations. We believe that we are well positioned with our mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to commodity price changes.

At September 30, 2007, we had entered into variable to fixed price swaps, costless collars and basis swaps related to crude oil and natural gas sales.  See Item 1. Financial Statements - Note 3 – Derivative Instruments and Hedging Activities.

At September 30, 2007, we had a net unrealized loss of $229 million (pre-tax) related to crude oil and natural gas derivative instruments entered into for hedging purposes. A net unrealized loss of $143 million, net of tax, is recorded in AOCL in the shareholders’ equity section in the consolidated balance sheets. We will reclassify the loss to earnings as adjustments to revenue when future sales occur.

Interest Rate Risk
 
We are exposed to interest rate risk related to our variable and fixed interest rate debt. At September 30, 2007, we had $1.9 billion (excluding unamortized discount) of long-term debt outstanding, of which $650 million was fixed-rate debt. The weighted average interest rate on our fixed-rate debt was 6.92% at September 30, 2007. We believe that anticipated near term changes in interest rates would not have a material effect on the fair value of our fixed-rate debt and would not expose us to the risk of material earnings or cash flow loss.

At September 30, 2007, we had $1.3 billion of long-term variable-rate debt and $25 million of short-term variable-rate debt outstanding. Variable rate debt exposes us to the risk of earnings or cash flow loss due to changes in market interest rates. We estimate that a hypothetical 10% change in the floating interest rates applicable to our September 30, 2007 balance of variable-rate debt would result in a change in annual interest expense of approximately $8 million.

Foreign Currency Risk
 
We have not entered into foreign currency derivatives.  Transactions that are completed in a foreign currency are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. We do not have any significant monetary assets or liabilities denominated in a foreign currency and consequently transaction gains or losses are not material in any of the periods presented. We do not believe we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense, net on the statements of operations.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:

 
·
our growth strategies;
 
·
our ability to successfully and economically explore for and develop crude oil and natural gas resources;
 
·
anticipated trends in our business;
 
·
our future results of operations;
 
·
our liquidity and ability to finance our exploration and development activities;
 
·
market conditions in the oil and gas industry;
 
·
our ability to make and integrate acquisitions; and

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·
the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included herein and included in our 2006 annual report on Form 10-K, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.  Our 2006 annual report on Form 10-K is available on our website at www.nobleenergyinc.com.

ITEM 4.  CONTROLS AND PROCEDURES

Based on the evaluation of our disclosure controls and procedures by Charles D. Davidson, our principal executive officer, and Chris Tong, our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, are effective. There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II. OTHER INFORMATION
ITEM 1.  LEGAL PROCEEDINGS

See  Item I. Financial Statements -  Note 12 – Commitments and Contingencies.

ITEM 1A.  RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2006 other than the following:

Information technology systems implementation issues could disrupt our internal operations and adversely affect our financial results or our ability to report our financial results.
 
We are currently in the process of implementing a new Enterprise Resource Planning software system to replace our various legacy systems. Our implementation is based on a phased approach and we expect to have the first phase implemented by the end of 2007. As a part of this effort, we are transitioning data and changing processes and this may be more expensive, time consuming and resource intensive than planned. Any disruptions that may occur in the implementation or operation of this system or any future systems could increase our expenses and adversely affect our ability to report in an accurate and timely manner our financial position, results of operations and cash flows and to otherwise operate our business.

ITEM 6.  EXHIBITS

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

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SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934 as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
 
NOBLE ENERGY, INC.
 
 
 
 
(Registrant)
 
 
 
 
 
 
 
 
 
Date
October 31, 2007
 
/s/ CHRIS TONG
 
 
 
CHRIS TONG
 
 
Senior Vice President and Chief Financial Officer




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INDEX TO EXHIBITS
Exhibit
 
 
Number
 
Exhibit
 
 
 
31.1
 
Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
 
 
 
31.2
 
Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
 
 
 
32.1
 
Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
 
 
 
32.2
 
Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).


 
34