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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


FORM 10-Q


ý

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

For the quarterly period ended September 30, 2002

OR

o

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: 0-7062


NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware
(State of incorporation)
  73-0785597
(I.R.S. employer identification number)

350 Glenborough Drive, Suite 100
Houston, Texas
(Address of principal executive offices)

 

77067
(Zip Code)

(281) 872-3100
(Registrant's telephone number, including area code)

NOBLE AFFILIATES, INC.
(Registrant's former name)

        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 ý    No o

        Number of shares of common stock outstanding as of November 4, 2002: 57,290,842





PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS


NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEET

(Dollars in thousands)

 
  September 30,
2002

  December 31,
2001

 
 
  (Unaudited)

   
 
ASSETS              
Current Assets:              
  Cash and short-term investments   $ 6,407   $ 73,237  
  Accounts receivable-trade     192,831     182,979  
  Oil and gas price risk management receivable     10,135     33,424  
  Materials and supplies inventories     10,202     10,828  
  Other current assets     30,784     51,103  
   
 
 
    Total Current Assets     250,359     351,571  
   
 
 
Property, Plant and Equipment, at cost     4,209,229     3,974,754  
  Less: accumulated depreciation, depletion and amortization     (2,145,666 )   (2,021,543 )
   
 
 
    Total property, plant and equipment, net     2,063,563     1,953,211  
   
 
 
Investment in Unconsolidated Subsidiary     238,643     117,735  
   
 
 
Other Assets     52,315     57,331  
   
 
 
   
Total Assets

 

$

2,604,880

 

$

2,479,848

 
   
 
 

LIABILITIES AND SHAREHOLDERS' EQUITY

 

 

 

 

 

 

 
Current Liabilities:              
  Accounts payable-trade   $ 250,214   $ 270,091  
  Short-term note payable     10,000     25,000  
  Current installments of long-term debt     43,629     19,507  
  Oil and gas price risk management payable     19,240     25,363  
  Other current liabilities     44,620     40,624  
   
 
 
    Total Current Liabilities     367,703     380,585  
   
 
 
Deferred Income Taxes     179,043     176,259  
   
 
 
Other Deferred Credits and Noncurrent Liabilities     70,658     75,629  
   
 
 
Long-Term Debt     987,105     837,177  
   
 
 

Shareholders' Equity:

 

 

 

 

 

 

 
  Common stock     199,308     198,369  
  Capital in excess of par value     403,346     396,104  
  Retained earnings     443,961     449,985  
  Accumulated other comprehensive income (loss)     (6,914 )   5,070  
   
 
 
      1,039,701     1,049,528  

Less Common Stock in Treasury (at cost, 2,505,522 shares)

 

 

(39,330

)

 

(39,330

)
   
 
 
   
Total Shareholders' Equity

 

 

1,000,371

 

 

1,010,198

 
   
 
 
     
Total Liabilities and Shareholders' Equity

 

$

2,604,880

 

$

2,479,848

 
   
 
 

See notes to consolidated condensed financial statements.

2



NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 
  Three Months Ended September 30,
 
 
  2002
  2001
 
REVENUES:              
  Oil and gas sales and royalties   $ 177,991   $ 168,547  
  Gathering, marketing and processing     154,461     134,417  
  Electricity sales     3,931        
  Income from unconsolidated subsidiary     5,184     1,229  
  Other income (loss)     (1,901 )   643  
   
 
 
      339,666     304,836  
   
 
 

COSTS AND EXPENSES:

 

 

 

 

 

 

 
  Oil and gas operations     42,314     32,005  
  Oil and gas exploration     50,628     48,862  
  Gathering, marketing and processing     150,737     130,782  
  Electricity generation     3,117        
  Depreciation, depletion and amortization     70,637     68,536  
  Selling, general and administrative     14,835     9,726  
  Interest     14,979     10,974  
  Interest capitalized     (4,649 )   (3,575 )
   
 
 
      342,598     297,310  
   
 
 

INCOME (LOSS) BEFORE TAXES

 

 

(2,932

)

 

7,526

 

INCOME TAX PROVISION (BENEFIT)

 

 

(1,742

)

 

3,718

 
   
 
 

NET INCOME (LOSS)

 

$

(1,190

)

$

3,808

 
   
 
 

BASIC EARNINGS (LOSS) PER SHARE

 

$

(0.02

)

$

0.07

 
   
 
 

DILUTED EARNINGS (LOSS) PER SHARE

 

$

(0.02

)

$

0.07

 
   
 
 

See notes to consolidated condensed financial statements.

3



NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

 
  Nine Months Ended September 30,
 
 
  2002
  2001
 
REVENUES:              
  Oil and gas sales and royalties   $ 505,422   $ 714,537  
  Gathering, marketing and processing     476,005     562,387  
  Electricity sales     3,931        
  Income from unconsolidated subsidiary     1,278     482  
  Other income     972     1,912  
   
 
 
      987,608     1,279,318  
   
 
 

COSTS AND EXPENSES:

 

 

 

 

 

 

 
  Oil and gas operations     112,969     98,573  
  Oil and gas exploration     107,266     114,153  
  Gathering, marketing and processing     468,559     552,457  
  Electricity generation     3,117        
  Depreciation, depletion and amortization     219,188     209,647  
  Selling, general and administrative     38,241     32,207  
  Interest     47,092     30,704  
  Interest capitalized     (13,732 )   (10,372 )
   
 
 
      982,700     1,027,369  
   
 
 

INCOME BEFORE TAXES

 

 

4,908

 

 

251,949

 

INCOME TAX PROVISION

 

 

4,077

 

 

90,898

 
   
 
 

NET INCOME

 

$

831

 

$

161,051

 
   
 
 

BASIC EARNINGS PER SHARE

 

$

0.01

 

$

2.85

 
   
 
 

DILUTED EARNINGS PER SHARE

 

$

0.01

 

$

2.81

 
   
 
 

See notes to consolidated condensed financial statements.

4



NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

AND SHAREHOLDERS' EQUITY

(Dollars in Thousands)

(Unaudited)

 
  Comprehensive
Income (Loss)

  Common
Stock

  Capital in
Excess of
Par Value

  Retained
Earnings

  Accumulated
Other
Comprehensive
Income (Loss)

  Treasury
Stock
At Cost

  Total
Shareholders'
Equity

 
Balance at December 31, 2001         $ 198,369   $ 396,104   $ 449,985   $ 5,070   $ (39,330 ) $ 1,010,198  
  Net income   $ 831                 831                 831  
  Reclassification of unrealized gains on hedges to net income, net of $107 income tax     199                       199           199  
  Change in fair value of cash flow hedges, net of income tax     (12,183 )                     (12,183 )         (12,183 )
  Shares issued           939     7,242                       8,181  
  Dividends declared ($0.12 per share)                       (6,855 )               (6,855 )
   
 
 
 
 
 
 
 
  Total   $ (11,153 )                                    
   
                                     
Balance at September 30, 2002         $ 199,308   $ 403,346   $ 443,961   $ (6,914 ) $ (39,330 ) $ 1,000,371  
         
 
 
 
 
 
 

See notes to consolidated condensed financial statements.

5



NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 
  Nine Months Ended September 30,
 
 
  2002
  2001
 
Cash Flows from Operating Activities:              
  Net income   $ 831   $ 161,051  
  Adjustments to reconcile net income to net cash provided by operating activities:              
    Depreciation, depletion and amortization     219,188     209,647  
    Dry hole     62,126     79,661  
    Amortization of undeveloped lease costs     15,510     12,297  
    (Gain) loss on disposal of assets     48     (1,919 )
    Deferred income taxes     2,783     40,981  
    Income from unconsolidated subsidiary     (1,278 )   (482 )
    Dividends received from unconsolidated subsidiary     5,363        
    Increase (decrease) in deferred credits     (4,971 )   3,033  
    (Increase) decrease in other     6,375     (9,188 )
  Changes in working capital, not including cash:              
    (Increase) decrease in accounts receivable     (9,852 )   64,715  
    (Increase) decrease in other current assets and inventories     24,900     (84,411 )
    Increase (decrease) in accounts payable     (19,877 )   (48,775 )
    Increase (decrease) in other current liabilities     3,997     35,352  
   
 
 
Net Cash Provided by Operating Activities     305,143     461,962  
   
 
 
Cash Flows From Investing Activities:              
  Capital expenditures     (427,587 )   (544,421 )
  Investment in unconsolidated subsidiary     (7,838 )   (43,736 )
  Proceeds from sale of property, plant and equipment     20,363     1,295  
  Distribution from unconsolidated subsidiary     5,500        
   
 
 
Net Cash Used in Investing Activities     (409,562 )   (586,862 )
   
 
 
Cash Flows From Financing Activities:              
  Exercise of stock options     8,181     16,533  
  Cash dividends     (6,855 )   (6,777 )
  Proceeds from bank debt     153,489     235,000  
  Repayment of bank debt     (100,000 )   (125,000 )
  Repayment of note payable obtained on Aspect acquisition     (17,226 )      
   
 
 
Net Cash Provided by Financing Activities     37,589     119,756  
   
 
 
Decrease in Cash and Short-term Investments     (66,830 )   (5,144 )
   
 
 
Cash and Short-term Investments at Beginning of Period     73,237     23,152  
   
 
 
Cash and Short-term Investments at End of Period   $ 6,407   $ 18,008  
   
 
 
Supplemental Disclosures of Cash Flow Information:              
  Cash paid (received) during the period for:              
  Interest (net of amount capitalized)   $ 13,914   $ 16,389  
  Income taxes paid (refunded)   $ (40,394 ) $ 66,131  
  Debt obtained from consolidation of AMCCO (net of discount)   $ 122,655   $    

See notes to consolidated condensed financial statements.

6




NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(Unaudited)

        In the opinion of Noble Energy, Inc. (the "Company"), the accompanying unaudited consolidated condensed financial statements contain all adjustments, consisting only of necessary and normal recurring adjustments, necessary to present fairly the Company's financial position as of September 30, 2002 and December 31, 2001; the results of operations for the three month and nine month periods ended September 30, 2002 and 2001, respectively; the statement of comprehensive income and equity for the nine month period ended September 30, 2002; and the cash flows for the nine month periods ended September 30, 2002 and 2001. These consolidated condensed financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the Company's annual report on Form 10-K for the year ended December 31, 2001.

(1) INCOME TAX PROVISION (BENEFIT)

        For the three months ended September 30:

 
  (In thousands)

 
 
  2002
  2001
 
Current   $ (249 ) $ (12,788 )
Deferred     (1,493 )   16,506  
   
 
 
    $ (1,742 ) $ 3,718  
   
 
 

        For the nine months ended September 30:

 
  (In thousands)

 
  2002
  2001
Current   $ 1,294   $ 49,917
Deferred     2,783     40,981
   
 
    $ 4,077   $ 90,898
   
 

(2) BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE

        Basic earnings per share of common stock was computed using the weighted average number of shares of common stock outstanding during each period. The diluted net income per share of common stock includes the effect of outstanding stock options.

        The following table summarizes the calculation of basic earnings per share ("EPS") and diluted EPS.

7



        For the three months ended September 30:

 
  2002
  2001
(in thousands, except per share)

  Income
(Numerator)

  Shares
(Denominator)

  Income
(Numerator)

  Shares
(Denominator)

Net income (loss)/shares   $ (1,190 ) 57,287   $ 3,808   56,595
   
 
 
 
Basic EPS   $ (.02)   $ .07
   
 
 
 
Net income (loss)/shares   $ (1,190 ) 57,287   $ 3,808   56,595
Effect of Dilutive Securities                    
  Stock options(1)                   575
   
 
 
 
Adjusted net income (loss)/shares   $ (1,190 ) 57,287   $ 3,808   57,170
   
 
 
 
Diluted EPS   $ (.02)   $ .07
   
 
 
 

(1)
The effect of dilutive securities on third quarter 2002 diluted EPS is antidilutive as a result of the net operating loss; therefore, the basic EPS and diluted EPS are the same. The number of dilutive securities that would have been used to determine fully diluted EPS was 395 with adjusted shares of 57,682.

8


        For the nine months ended September 30:

 
  2002
  2001
(in thousands, except per share)

  Income
(Numerator)

  Shares
(Denominator)

  Income
(Numerator)

  Shares
(Denominator)

Net income/shares   $ 831   57,159   $ 161,051   56,502
   
 
 
 
Basic EPS   $ .01   $ 2.85
   
 
 
 
Net income/shares   $ 831   57,159   $ 161,051   56,502
Effect of Dilutive Securities                    
  Stock options         566         829
   
 
 
 
Adjusted net income/shares   $ 831   57,725   $ 161,051   57,331
   
 
 
 
Diluted EPS   $ .01   $ 2.81
   
 
 
 

(3) GEOGRAPHICAL DATA

        The Company has operations throughout the world. The following information is grouped into four components that are all primarily in the business of natural gas and crude oil exploration and production: Domestic Operations, North Sea, Equatorial Guinea and Other International. The following segment data was prepared on the same basis as Noble's consolidated financial statements.

9


        for the Three Months Ended 9/30/2002

(Dollars in thousands)
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International

  Corporate and
Other

 
REVENUES                                      
  Oil Sales   $ 81,911   $ 44,061   $ 18,041   $ 11,483   $ 8,249   $ 77  
  Gas Sales     96,080     92,319     3,812     922           (973 )
  Gathering, Marketing and Processing Revenue     154,461                             154,461  
  Electricity Sales     3,931                       3,931        
  Income from Unconsolidated Subsidiaries     5,184                 5,184              
  Other     (1,901 )   (2,561 )   196           (296 )   760  
   
 
 
 
 
 
 
    Total Revenues     339,666     133,819     22,049     17,589     11,884     154,325  
COSTS AND EXPENSES                                      
  Oil and Gas Operations     42,314     30,831     4,951     2,466     4,778     (712 )
  Oil and Gas Exploration     50,628     36,489     414     4     13,500     221  
  Gathering, Marketing and Processing Costs     150,737                             150,737  
  Electricity Generation     3,117                       3,117        
  DD&A     70,637     60,889     5,986     1,781     2,076     (95 )
  SG&A     14,835     8,844     184     572     310     4,925  
   
 
 
 
 
 
 
    Total Costs and Expenses     332,268     137,053     11,535     4,823     23,781     155,076  
OPERATING INCOME (LOSS)   $ 7,398   $ (3,234 ) $ 10,514   $ 12,766   $ (11,897 ) $ (751 )
   
 
 
 
 
 
 
INTEREST EXPENSE (NET)     10,330                             10,330  
   
 
 
 
 
 
 
NET INCOME (LOSS) BEFORE TAX   $ (2,932 ) $ (3,234 ) $ 10,514   $ 12,766   $ (11,897 ) $ (11,081 )
   
 
 
 
 
 
 

        for the Three Months Ended 9/30/2001

(Dollars in thousands)
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International

  Corporate and
Other

 
REVENUES                                      
  Oil Sales   $ 65,571   $ 40,321   $ 9,599   $ 10,423   $ 5,207   $ 21  
  Gas Sales     102,976     98,869     3,930     800     177     (800 )
  Gathering, Marketing and Processing Revenue     134,417                             134,417  
  Electricity Sales                                      
  Income from Unconsolidated Subsidiaries     1,229                 1,229              
  Other     643     (412 )   312     2     7     734  
   
 
 
 
 
 
 
    Total Revenues     304,836     138,778     13,841     12,454     5,391     134,372  
COSTS AND EXPENSES                                      
  Oil and Gas Operations     32,005     28,835     1,328     1,330     1,730     (1,218 )
  Oil and Gas Exploration     48,862     26,652     20,618     35     1,929     (372 )
  Gathering, Marketing and Processing Costs     130,782                             130,782  
  Electricity Generation                                      
  DD&A     68,536     60,742     4,105     902     2,301     486  
  SG&A     9,726     6,311     289     222     195     2,709  
   
 
 
 
 
 
 
    Total Costs and Expenses     289,911     122,540     26,340     2,489     6,155     132,387  
OPERATING INCOME (LOSS)   $ 14,925   $ 16,238   $ (12,499 ) $ 9,965   $ (764 ) $ 1,985  
   
 
 
 
 
 
 
INTEREST EXPENSE (NET)     7,399                             7,399  
   
 
 
 
 
 
 
NET INCOME (LOSS) BEFORE TAX   $ 7,526   $ 16,238   $ (12,499 ) $ 9,965   $ (764 ) $ (5,414 )
   
 
 
 
 
 
 

10


        for the Nine Months Ended 9/30/2002

(Dollars in thousands)
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International

  Corporate and
Other

 
REVENUES                                      
  Oil Sales   $ 219,655   $ 113,068   $ 52,510   $ 31,540   $ 22,423   $ 114  
  Gas Sales     285,767     271,390     14,253     2,144           (2,020 )
  Gathering, Marketing and Processing Revenue     476,005                             476,005  
  Electricity Sales     3,931                       3,931        
  Income from Unconsolidated Subsidiaries     1,278                 1,278              
  Other     972     (411 )   197           (199 )   1,385  
   
 
 
 
 
 
 
    Total Revenues     987,608     384,047     66,960     34,962     26,155     475,484  
COSTS AND EXPENSES                                      
  Oil and Gas Operations     112,969     84,474     14,862     6,973     9,600     (2,940 )
  Oil and Gas Exploration     107,266     83,941     3,594     3     19,173     555  
  Gathering, Marketing and Processing Costs     468,559                             468,559  
  Electricity Generation     3,117                       3,117        
  DD&A     219,188     187,427     19,827     3,852     7,353     729  
  SG&A     38,241     24,577     457     1,293     689     11,225  
   
 
 
 
 
 
 
    Total Costs and Expenses     949,340     380,419     38,740     12,121     39,932     478,128  
OPERATING INCOME (LOSS)   $ 38,268   $ 3,628   $ 28,220   $ 22,841   $ (13,777 ) $ (2,644 )
   
 
 
 
 
 
 
INTEREST EXPENSE (NET)     33,360                             33,360  
   
 
 
 
 
 
 
NET INCOME (LOSS) BEFORE TAX   $ 4,908   $ 3,628   $ 28,220   $ 22,841   $ (13,777 ) $ (36,004 )
   
 
 
 
 
 
 

        for the Nine Months Ended 9/30/2001

(Dollars in thousands)
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International

  Corporate and
Other

 
REVENUES                                      
  Oil Sales   $ 194,701   $ 124,382   $ 24,042   $ 30,499   $ 15,672   $ 106  
  Gas Sales     519,836     504,260     15,120     1,628     456     (1,628 )
  Gathering, Marketing and Processing Revenue     562,387                             562,387  
  Electricity Sales                                      
  Income from Unconsolidated Subsidiaries     482                 482              
  Other     1,912     (257 )   436     2     82     1,649  
   
 
 
 
 
 
 
    Total Revenues     1,279,318     628,385     39,598     32,611     16,210     562,514  
COSTS AND EXPENSES                                      
  Oil and Gas Operations     98,573     87,720     3,988     4,578     5,085     (2,798 )
  Oil and Gas Exploration     114,153     74,365     32,295     39     7,960     (506 )
  Gathering, Marketing and Processing Costs     552,457                             552,457  
  Electricity Generation                                      
  DD&A     209,647     187,499     11,423     2,877     6,675     1,173  
  SG&A     32,207     19,729     1,940     622     470     9,446  
   
 
 
 
 
 
 
    Total Costs and Expenses     1,007,037     369,313     49,646     8,116     20,190     559,772  
OPERATING INCOME (LOSS)   $ 272,281   $ 259,072   $ (10,048 ) $ 24,495   $ (3,980 ) $ 2,742  
   
 
 
 
 
 
 
INTEREST EXPENSE (NET)     20,332                             20,332  
   
 
 
 
 
 
 
NET INCOME (LOSS) BEFORE TAX   $ 251,949   $ 259,072   $ (10,048 ) $ 24,495   $ (3,980 ) $ (17,590 )
   
 
 
 
 
 
 
LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET)                                      
  As of 9/30/02   $ 2,063,563   $ 1,228,930   $ 90,087   $ 116,156   $ 620,907   $ 7,483  
  As of 9/30/01   $ 1,728,563   $ 1,200,867   $ 105,661   $ 84,261   $ 330,791   $ 6,983  

11


(4) TRADING AND HEDGING ACTIVITIES

      The Company, through its subsidiaries, from time to time, uses various price risk management arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price forward sales, costless collars and other contractual arrangements. Although these arrangements expose the Company to credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties; however, the Company is not able to predict sudden changes in its counterparties' creditworthiness. Gains and losses from such arrangements related to the Company's oil and gas production and which qualify for hedge accounting treatment are recorded in oil and gas sales and royalties upon sale of the associated products.

        During the third quarter of 2002, the Company entered into various natural gas costless collars, natural gas costless collar combinations and crude oil costless collar transactions related to its production.

        In the third quarter of 2002, natural gas costless collars were for 120,000 MMBTU of natural gas per day, with floor prices ranging from $2.75 to $3.25 per MMBTU and ceiling prices ranging from $3.50 to $5.10 per MMBTU; and the costless collar combinations were for 75,000 MMBTU of natural gas per day, with floor prices ranging from $3.00 to $3.25 per MMBTU and ceiling prices ranging from $4.30 to $5.00 per MMBTU, with a $.50 premium to index on prices below the floors. The realized effect of the natural gas arrangements on gas sales for the third quarter was an increase of $.05 per MCF. For the first nine months of 2002, the Company had natural gas costless collars for 113,443 MMBTU per day, with floor prices ranging from $2.00 to $3.25 per MMBTU and ceiling prices ranging from $2.45 to $5.10 per MMBTU; and the costless collar combinations were for 58,608 MMBTU of natural gas per day, with floor prices ranging from $2.00 to $3.25 per MMBTU and ceiling prices ranging from $2.95 to $5.00 per MMBTU, with a $.25 to $.50 premium to index on prices below the floors. The realized effect of the natural gas arrangements for the first nine months of 2002 in the average natural gas price was an increase of $.04 per MCF.

        The crude oil costless collars for the third quarter were for 10,000 BBLS of oil per day, with floor prices ranging from $23.00 to $24.00 per BBL and ceiling prices ranging from $29.30 to $30.00 per BBL. The realized effect on oil sales for the third quarter for these crude oil costless collars was a decrease of $.02 per BBL. For the first nine months of 2002, the Company had crude oil costless collars for 4,487 BBLS of oil per day, with floor prices ranging from $23.00 to $24.00 per BBL and ceiling prices ranging from $29.30 to $30.00 per BBL. The realized effect of the costless collar transactions for the first nine months of 2002 in the average crude oil price was a decrease of $.01 per BBL.

12



        In addition, the Company has entered into natural gas and crude oil costless collars to support the Company's investment program as follows:

 
  Gas
  Oil
Production
Period

  Volumes
Per Day

  Price
Per MMBTU
Floor—Ceiling

  Volumes
Per Day

  Price
Per BBL
Floor—Ceiling

4Q2002   165,000   $3.24-$4.46   7,500   $24.00-$30.04
1Q2003   185,000   $3.39-$4.78   15,000   $23.00-$28.63
2Q2003   145,000   $3.34-$4.45   15,000   $23.00-$28.63
3Q2003   145,000   $3.34-$4.45   10,000   $23.00-$27.95
4Q2003   145,000   $3.34-$4.75   10,000   $23.00-$27.95

        Of the 165,000 MMBTU of natural gas per day costless collars for the fourth quarter of 2002, 25,000 MMBTU of natural gas per day was terminated and as a result, the Company will recognize an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in the fourth quarter of 2002.

13


        The Company assumed swaps related to the acquisition of Aspect Resources, Inc. Based on the cost of these swaps, the Company will realize prices of approximately $3.20 per MMBTU and $22.00 per BBL for this time period related to these volumes. There was no realized effect on the average gas price and a realized effect of $.03 per BBL decrease in the average crude oil price in the third quarter of 2002 due to the purchased swaps. The realized effect of the purchased swaps for the first nine months of 2002 was an increase of $.01 per MCF and a decrease of $.02 per BBL in the average natural gas and crude oil prices. The remaining Aspect fixed price hedges are listed in the table below:

 
  Gas
  Oil
Production
Period

  Volumes
Per Day

  Price
Per MMBTU

  Volumes
Per Day

  Price
Per BBL

4Q2002   4,730   $ 4.68   110   $ 25.57
2003   2,480   $ 4.39   40   $ 23.45
1Q2004   1,154   $ 4.24   18   $ 22.81

        During the third quarter of 2001, the Company had no price risk management arrangements for its production other than those entered into by Noble Gas Marketing, Inc. ("NGM"), which are described below.

14


        NGM employs various price risk management arrangements in connection with its purchases and sales of third party production to lock in profits or limit exposure to gas price risk. Most of the purchases made by NGM are on an index basis; however, purchasers in the markets in which NGM sells often require fixed or NYMEX related pricing. NGM may use a hedge to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.

        NGM records hedging gains or losses relating to fixed term sales as gathering, marketing and processing revenues in the periods in which the related contract is completed.

        At September 30, 2002, the Company recorded oil and gas hedge receivables of $10.9 million, oil and gas hedge liabilities of $21.2 million and other comprehensive loss, net of tax, of $6.9 million related to the Company's cash flow hedging contracts.

(5) METHANOL PLANT

        Prior to January 2002, Atlantic Methanol Capital Company ("AMCCO") was a 50 percent owned joint venture that owned an indirect 90 percent interest in Atlantic Methanol Production Company ("AMPCO"), which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due 2004 to fund the remaining construction payments. On January 2, 2002, the Company's partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner's sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO's $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company's partner. Since the Company's partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO in 2002, thereby including the $125 million Series A-2 Notes in the Company's balance sheet effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. The construction cost of the turnkey contract was $322.5 million. There are no further construction contract phase payments due for the methanol plant. The plant produced approximately 225,000 metric tons of methanol in the third quarter of 2002. For the first nine months of 2002, the methanol plant produced approximately 491,000 metric tons of methanol. The plant's output for the balance of the year 2002 is under contract.

(6) COMPANY STOCK REPURCHASE PLAN

        The Company's Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company's common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock. The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company's current cash flow. On September 17, 2001 the Company's Board of Directors approved an expansion of the original repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase forward program, one of the Company's banks purchased approximately $35 million of the Company's stock or 1,044,454 shares on the open market during the first quarter of 2002.

15



        The agreement is scheduled to mature in January 2003. Under the provisions of the agreement, the Company can choose to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that the share price has decreased, or receive from the bank a net amount of cash to the extent that the share price has increased. The bank has the right to terminate the agreement prior to the maturity date if the Company's share price decreases by 50 percent ($16.77) or if the Company's credit rating is downgraded below BBB- (S&P) or Baa3 (Moody's). If either event occurs and the bank exercises its right to terminate, the Company still retains the right to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to 14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or reduction to the Company's capital in excess of par value. No settlements have occurred to date. As of September 30, 2002, the fair value of the Company's obligation under the contract would be an obligation to pay approximately $35.5 million to the bank (and hold the shares as treasury stock), or the bank would return 1,011 shares of Company stock to the Company, or the bank would pay a de minimis amount to the Company.

(7) RECENTLY ISSUED PRONOUNCEMENTS

        SFAS No. 143, "Accounting for Asset Retirement Obligations," was issued in June 2001. This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets

16


and the associated asset retirement costs. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Company has not quantified the impact of adopting SFAS No. 143, but plans to adopt the statement by January 1, 2003.

        SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," was issued in August 2001. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." This statement requires (a) recognition of an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (b) measurement of an impairment loss as the difference between the carrying amount and fair value of the asset. The Company adopted the statement January 1, 2002 with no material impact on the Company's results of operations or financial position.


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

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

        General.    We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect the Company and to take advantage of the "safe harbor" protection for forward-looking statements afforded under federal securities laws. From time to time, the Company's management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include projections and estimates concerning the timing and success of specific projects and the Company's future (1) income, (2) oil and gas production, (3) oil and gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "goal" or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this Form 10-Q, the matters discussed in this Form 10-Q are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.

        We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward-looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our stockholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere. All of the Company's forward-looking statements, in this document or elsewhere, are qualified by this cautionary disclosure.

17



        Volatility and Level of Hydrocarbon Commodity Prices.    Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets generally and are outside of our control. Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas and/or crude oil could have a material adverse effect on (1) the Company's financial position and results of operations (including reduced cash flow and borrowing capacity), (2) the quantities of natural gas and crude oil reserves that we can economically produce, (3) the quantity of estimated proved reserves that may be attributed to our properties and (4) our ability to fund our capital program.

        Production Rates and Reserve Replacement.    Projecting future rates of oil and gas production is inherently imprecise. Producing oil and gas reservoirs generally have declining production rates. Production rates depend on a

18


number of factors, including geological, geophysical and engineering factors, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climate. Another factor affecting production rates is our ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, our ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, our finding and development costs may not justify the use of resources to explore for and develop such reserves. There can be no assurances as to the level or timing of success, if any, that we will be able to achieve in finding and developing or acquiring additional reserves. Acquisitions that result in successful exploration or exploitation projects require assessment of numerous factors, many of which are beyond our control. There can be no assurance that any acquisition of property interests by us will be successful and, if unsuccessful, that such failure will not have an adverse effect on our financial condition, results of operations and cash flows.

        Reserve Estimates.    Our forward-looking statements may be predicated on our estimates of our oil and gas reserves. All of the reserve data in this Form 10-Q or otherwise made by or on behalf of the Company are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond our control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, it is common that estimates made by different engineers will vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

        Laws and Regulations.    Our forward-looking statements are generally based on the assumption that the legal and regulatory environment will remain stable. Changes in the legal and/or regulatory environment could have a material adverse effect on our future results of operations and financial condition. Our ability to economically produce and sell our oil and gas production is affected and could possibly be restrained by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting (1) oil and gas production, including allowable rates of production by well or proration unit, (2) taxes applicable to the Company and/or our production, (3) the amount of oil and gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities and (5) the marketing of competitive fuels. Our operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These environmental laws and regulations continue to change and may become more onerous or restrictive in the future. Our forward-looking statements are generally based upon the expectation that we will not be required in the near future to expend amounts to comply with environmental laws and regulations that are material in relation to our total capital expenditures program. However, inasmuch as such laws

19



and regulations are frequently changed, we are unable to accurately predict the ultimate cost of such compliance.

        Drilling and Operating Risks.    Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids. In addition, a substantial amount of our operations are currently offshore, domestically and internationally, and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision and damage or loss from severe weather. Our drilling operations are also subject to the risk that no commercially productive natural gas or oil reserves will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.

        Competition.    The Company's forward-looking statements are generally based on a stable competitive environment. Competition in the oil and gas industry is intense both domestically and internationally. We actively compete for reserve acquisitions and exploration leases and licenses, as well as in the gathering and marketing of natural gas and crude oil. Our competitors include the major oil companies, independent oil and gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to

20


industrial, commercial and individual consumers. To the extent our competitors have greater financial resources than currently available to us, we may be disadvantaged in effectively competing for certain reserves, leases and licenses. Recently announced consolidations in the industry may enhance the financial resources of certain of our competitors. From time to time, the level of industry activity may result in a tight supply of labor or equipment required to operate and develop oil and gas properties. The availability of drilling rigs and other equipment, as well as the level of rates charged, may have an effect on our ability to compete and achieve success in our exploration and production activities.

        In marketing our production, we compete with other producers and marketers on such factors as deliverability, price, contract terms and quality of product and service. Competition for the sale of energy commodities among competing suppliers is influenced by various factors, including price, availability, technological advancements, reliability and creditworthiness. In making projections with respect to natural gas and crude oil marketing, we assume no material decrease in the availability of natural gas and crude oil for purchase. We believe that the location of our properties, our expertise in exploration, drilling and production operations, the experience of our management and the efforts and expertise of our marketing units generally enable us to compete effectively. In making projections with respect to numerous aspects of our business, we generally assume that there will be no material change in competitive conditions that would adversely affect us.


LIQUIDITY AND CAPITAL RESOURCES

        Net cash provided by operating activities decreased $156.8 million to $305.1 million in the nine months ended September 30, 2002 from $461.9 million in the same period of 2001. Cash and short-term investments decreased from $73.2 million at December 31, 2001 to $6.4 million at September 30, 2002. These decreases are primarily a result of lower natural gas prices in 2002 versus the comparable period in 2001.

        During the first half of 2002, the Company repaid a net $30 million on its $400 million credit facility and, during the third quarter 2002, the Company borrowed a net $30 million on its $400 million credit facility, which resulted in the September 30, 2002 balance of $380 million being the same amount that was drawn on the $400 million credit facility at December 31, 2001. The Company also has available a $200 million 364-day credit agreement with certain commercial lending institutions. At September 30, 2002, there were no amounts outstanding under this credit agreement. Long-term debt at September 30, 2002 was $987.1 million compared with $837.2 million at December 31, 2001.

        The Company initially set its 2002 capital expenditure budget at approximately $520 million; however, international projects are moving forward ahead of schedule and, as a result, on October 29, 2002 the Board of Directors approved a $65 million increase in the 2002 capital expenditure budget bringing it to $585 million. Through September 30, 2002, the Company has expended approximately $423 million of its revised $585 million 2002 capital expenditure budget. The Company expects to fund its remaining 2002 capital budget from cash flows from operations and additional borrowings from the credit facility as required. The Company continues to evaluate possible strategic and tactical acquisitions and believes it is positioned to access external sources of funding should it be necessary or desirable in connection with an acquisition.

        Prior to January 2002, Atlantic Methanol Capital Company ("AMCCO") was a 50 percent owned joint venture that owned an indirect 90 percent interest in Atlantic Methanol Production Company ("AMPCO"). Through AMPCO, the Company participated, with a 50 percent expense interest

21



(45 percent ownership net of a five percent carried interest for the Equatorial Guinea Government), in a joint venture with a partner in the construction of a methanol plant on Bioko Island in Equatorial Guinea. The plant is using the gas from the Company's 34 percent owned Alba field as feedstock. The plant is designed to utilize up to 125 MMCF of gas per day and can produce 2,500 metric tons of methanol per day, which equates to approximately 20,000 BBLS per day. Initial production of commercial grade methanol commenced May 2, 2001. The plant's output for the balance of the year 2002 is under contract.

        During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due 2004 to fund the remaining construction payments. On January 2, 2002, the Company's partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner's sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO's $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company's partner. Since the Company's partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO in 2002, thereby including the $125 million Series A-2 Notes in the Company's balance sheet effective January 2002. The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. The construction cost of the turnkey contract was $322.5 million. Payments were due upon the completion of specific phases of the construction. There are no further construction contract phase payments due for the

22


methanol plant. The plant produced approximately 225,000 metric tons of methanol in the third quarter of 2002. For the first nine months of 2002, the methanol plant produced approximately 491,000 metric tons of methanol.

        The Company follows the entitlement method of accounting for its gas imbalances. The Company's estimated gas imbalance receivables were $20.7 million at September 30, 2002 and $20.9 million at December 31, 2001. Estimated gas imbalance liabilities were $14.7 million at September 30, 2002 and $15.5 million at December 31, 2001. These imbalances are valued at the amount which is expected to be received or paid to settle the imbalances. The settlement of the imbalances can occur either over the life or at the end of the life of a well, on a volume basis or by cash settlement. The Company does not expect that a significant portion of the settlements will occur in any one year. Thus, the Company believes the settlement of gas imbalances will not have a material impact on its liquidity.


RESULTS OF OPERATIONS

        For the third quarter of 2002, the Company recorded a net loss of $1.2 million, or $(.02) per share, compared with net income of $3.8 million, or $.07 per share, in the third quarter of 2001. The decrease in net income in the third quarter reflected an 11 percent decline in natural gas production volumes compared with the same period in 2001, largely due to significantly lower domestic production volumes. This decrease was partially offset by higher overall commodity prices and liquids volumes, and increased operating income from the North Sea operations. During the first nine months of 2002, the Company recorded net income of $0.8 million, or $.01 per share, compared with $161.1 million, or $2.85 per share, in the first nine months of 2001. The decreased earnings through the first nine months of 2002 were a result of predominately lower domestic natural gas prices and volumes. Natural gas prices decreased 38 percent and natural gas production decreased nine percent, respectively, compared with the corresponding period in 2001.

        Gas sales for the Company, excluding third party sales by Noble Gas Marketing, Inc. ("NGM"), a wholly owned subsidiary of the Company, decreased seven percent and 45 percent, respectively, for the three months and nine months ended September 30, 2002 compared with the same periods in 2001. Third quarter sales were down primarily due to decreases in domestic production of 15 percent and year-to-date sales declined mainly due to 12 percent and 38 percent decreases, respectively, in domestic production and prices for the nine month period ending September 30, 2002 compared with the same period in 2001.

        Oil sales for the Company, excluding third party sales by Noble Trading, Inc. ("NTI"), a wholly owned subsidiary of the Company, increased 25 percent and 13 percent, respectively, for the three months and nine months ended September 30, 2002 compared to the same periods in 2001. Third quarter sales were up due to increases of eight percent in average daily production compared to the same period in 2001, with over half of the increase attributable to increased production in the North Sea. Compared to the first nine months of 2001, year-to-date 2002 sales were up mostly due to increased production and prices in the North Sea and other international projects, somewhat offset by declines in domestic prices.

        NGM markets the majority of the Company's natural gas, as well as certain third party gas. NGM sells gas directly to end-users, gas marketers, industrial users, interstate and intrastate pipelines and local distribution companies. NTI markets a portion of the Company's oil, as well as certain third-party

23



oil. The Company records all of NGM's and NTI's sales and expenses as gathering, marketing and processing revenues and expenses. All intercompany sales and expenses have been eliminated.

        For the third quarter of 2002, revenues and expenses from NGM and NTI third party sales totaled $154.5 million and $150.7 million, respectively, for a combined gross margin of $3.8 million. In comparison, for the third quarter of 2001, NGM and NTI third party sales and expenses of $134.4 million and $130.8 million, respectively, resulted in a combined gross margin of $3.6 million. For the nine months ended September 30, 2002, combined NGM and NTI revenues and expenses from third party sales totaled $476.0 million and $468.6 million, respectively, for a gross margin of $7.4 million. In comparison, combined NGM and NTI third party sales and expenses of $562.4 million and $552.5 million, respectively, resulted in a gross margin of $9.9 million for the same period in 2001.

        The Company, through its subsidiaries, from time to time, uses various price risk management arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price forward sales, costless collars and other contractual arrangements. Although these arrangements expose the Company to credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties; however, the Company is not able to predict sudden changes in its counterparties' creditworthiness. Gains and losses from such arrangements related to the Company's oil and gas production and which

24


qualify for hedge accounting treatment are recorded in oil and gas sales and royalties upon sale of the associated products. For more information, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk" of this Form 10-Q.

        At September 30, 2002, the Company recorded oil and gas hedge receivables of $10.9 million, oil and gas hedge liabilities of $21.2 million and other comprehensive loss, net of tax, of $6.9 million related to the Company's hedging contracts.

        Certain selected geographical oil and gas operating statistics follow:

 
  for the Three Months Ended 9/30/2002
 
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International(1)

 
  Daily Production                                
    Liquids (Bbl)     34,339     19,033     7,418     4,871     3,017  
    Natural Gas (Mcf)     383,082 (2)   320,517     14,310     40,968     7,287 (2)
  Average Realized Price                                
    Liquids per Bbl   $ 25.93   $ 25.19   $ 26.44   $ 25.62   $ 29.72  
    Natural Gas per Mcf   $ 2.80   $ 3.13   $ 2.90   $ 0.24   $    
 
  for the Three Months Ended 9/30/2001
 
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International(1)

 
  Daily Production                                
    Liquids (Bbl)     31,665     18,608     4,990     5,296     2,771  
    Natural Gas (Mcf)     431,132 (2)   378,132     16,115     34,868     2,017 (2)
  Average Realized Price                                
    Liquids per Bbl   $ 22.50   $ 23.57   $ 20.91   $ 21.39   $ 20.42  
    Natural Gas per Mcf   $ 2.60   $ 2.82   $ 2.65   $ 0.24   $ 0.96  
 
  for the Nine Months Ended 9/30/2002
 
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International(1)

 
  Daily Production                                
    Liquids (Bbl)     34,454     18,460     7,940     4,988     3,066  
    Natural Gas (Mcf)     388,549 (2)   336,002     17,291     32,045     3,211 (2)
  Average Realized Price                                
    Liquids per Bbl   $ 23.35   $ 22.45   $ 24.22   $ 23.16   $ 26.78  
    Natural Gas per Mcf   $ 2.73   $ 2.96   $ 3.02   $ 0.25   $    
 
  for the Nine Months Ended 9/30/2001
 
Oil & Gas Operations

  Consolidated
  Domestic
  North Sea
  Equatorial
Guinea

  Other
International(1)

 
  Daily Production                                
    Liquids (Bbl)     29,773     18,454     4,022     4,619     2,678  
    Natural Gas (Mcf)     427,151 (2)   383,071     17,740     24,573     1,767 (2)
  Average Realized Price                                
    Liquids per Bbl   $ 23.95   $ 24.71   $ 21.89   $ 24.18   $ 21.43  
    Natural Gas per Mcf   $ 4.46   $ 4.82   $ 3.12   $ 0.24   $ 0.94  

BBL—barrel
MCF—thousand cubic feet


(1)
Other International includes operations in Argentina, China, Ecuador, Israel and Vietnam.

25


(2)
Ecuador natural gas volumes are included in Other International and Consolidated production, but are not included in natural gas sales revenue for either. Because the gas-to-power project in Ecuador is 100 percent owned by Noble Energy, intercompany natural gas sales are eliminated for accounting purposes.

        Oil and gas exploration expense increased $1.8 million and decreased $6.9 million for the three months and nine months, respectively, ended September 30, 2002, as compared with the same periods in 2001. The third quarter 2002 increase is primarily due to an increase in undeveloped lease amortization and the nine month decrease is attributable to a $17.5 million decrease in dry hole expense offset by a $10.6 million increase in seismic, undeveloped lease amortization and other expenses.

26


        Oil and gas operations expense increased $10.3 million and $14.4 million for the three months and nine months, respectively, ended September 30, 2002, as compared with the same periods in 2001. The increase in oil and gas operating costs was due primarily to higher international transportation expense, higher workover expense and increased taxes in Argentina.

        Depreciation, depletion and amortization (DD&A) expense increased $2.1 million and $9.5 million for the three months and nine months, respectively, ended September 30, 2002 compared with the same periods in 2001. The unit rate of DD&A per barrel of oil equivalents (BOE), converting gas to oil on the basis of six MCF per barrel, was $8.09 for the first nine months of 2002 compared with $7.61 for the same period of 2001. The increase in the unit rate per BOE is due primarily to increased development costs incurred in the Gulf of Mexico to stabilize the Company's oil and gas production volumes, which are being amortized in the current and subsequent quarters as the oil and natural gas are produced. The Company has recorded, through charges to DD&A, a reserve for future liabilities related to dismantlement and reclamation costs for offshore facilities. This reserve is based on the best estimates of Company engineers of such costs to be incurred in future years.

        SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," was issued in August 2001. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." This statement requires (a) recognition of an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (b) measurement of an impairment loss as the difference between the carrying amount and fair value of the asset. The Company adopted the statement January 1, 2002 with no material impact on the Company's results of operations or financial position.

        Interest expense increased 36 percent and 53 percent for the three months and nine months, respectively, ended September 30, 2002 as compared with the same periods in 2001. The increase in interest expense is attributable to additional credit facility borrowings, interest expense associated with the AMCCO debt, and short-term loans which fluctuate according to the Company's financial needs. The average interest rate on short-term loans for the nine month period was 2.81 percent. There were no short-term loans made in 2001.


FUTURE TRENDS

        The Company expects oil and gas production to increase in 2002 and 2003 compared to 2001. The increase in 2002 will be due primarily to a full year of production from the expansion of the Alba field in Equatorial Guinea and the Hanze field in the North Sea. The increase in 2003 would be due primarily to a full year of production in China and Ecuador.

        The Company initially set its 2002 capital expenditure budget at approximately $520 million; however, international projects are moving forward ahead of schedule and, as a result, on October 29, 2002 the Board of Directors approved a $65 million increase in the 2002 capital expenditure budget bringing it to $585 million. Such expenditures are planned to be funded through internally generated cash flows. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or borrowings.

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        Management believes that the Company is well positioned with its balanced reserves of oil and gas to take advantage of future price increases that may occur. However, the uncertainty of oil and gas prices continues to affect the oil and gas industry. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.

        The Company's Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company's common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock. The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company's current cash flow. On September 17, 2001 the Company's Board of Directors approved an expansion of the original repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase forward program, one of the Company's banks purchased approximately $35 million of the Company's stock or 1,044,454 shares on the open market during the first quarter of 2002.

        The agreement is scheduled to mature in January 2003. Under the provisions of the agreement, the Company can choose to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that the share price has decreased, or receive from the bank

28


a net amount of cash to the extent that the share price has increased. The bank has the right to terminate the agreement prior to the maturity date if the Company's share price decreases by 50 percent ($16.77) or if the Company's credit rating is downgraded below BBB- (S&P) or Baa3 (Moody's). If either event occurs and the bank exercises its right to terminate, the Company still retains the right to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to 14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or reduction to the Company's capital in excess of par value. No settlements have occurred to date. As of September 30, 2002, the fair value of the Company's obligation under the contract would be an obligation to pay approximately $35.5 million to the bank (and hold the shares as treasury stock), or the bank would return 1,011 shares of Company stock to the Company, or the bank would pay a de minimis amount to the Company.


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

        The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of oil and gas reserves to take advantage of future price increases that may occur. However, the uncertainty of oil and gas prices continues to impact the domestic oil and gas industry. Due to the volatility of oil and gas prices, the Company, from time to time, has used derivative hedging and may do so in the future as a means of limiting its exposure to price changes.

        During the third quarter of 2002, the Company had entered into various natural gas costless collars, natural gas costless collar combinations and crude oil costless collar transactions related to its production.

        In the third quarter of 2002, natural gas costless collars were for 120,000 MMBTU of natural gas per day, with floor prices ranging from $2.75 to $3.25 per MMBTU and ceiling prices ranging from $3.50 to $5.10 per MMBTU; and the costless collar combinations were for 75,000 MMBTU of natural gas per day, with floor prices ranging from $3.00 to $3.25 per MMBTU and ceiling prices ranging from $4.30 to $5.00 per MMBTU, with a $.50 premium to index on prices below the floors. The realized effect of the natural gas arrangements on gas sales for the third quarter was an increase of $.05 per MCF. For the first nine months of 2002, the Company had natural gas costless collars for 113,443 MMBTU per day, with floor prices ranging from $2.00 to $3.25 per MMBTU and ceiling prices ranging from $2.45 to $5.10 per MMBTU; and the costless collar combinations were for 58,608 MMBTU of natural gas per day, with floor prices ranging from $2.00 to $3.25 per MMBTU and ceiling prices ranging from $2.95 to $5.00 per MMBTU, with a $.25 to $.50 premium to index on prices below the floors. The realized effect of the natural gas arrangements for the first nine months of 2002 in the average natural gas price was an increase of $.04 per MCF.

        The crude oil costless collars for the third quarter were for 10,000 BBLS of oil per day, with floor prices ranging from $23.00 to $24.00 per BBL and ceiling prices ranging from $29.30 to $30.00 per BBL. The realized effect on oil sales for the third quarter for these crude oil costless collars was a decrease of $.02 per BBL. For the first nine months of 2002, the Company had crude oil costless collars for 4,487 BBLS of oil per day, with floor prices ranging from $23.00 to $24.00 per BBL and ceiling prices ranging from $29.30 to $30.00 per BBL. The realized effect of the costless collar

29



transactions for the first nine months of 2002 in the average crude oil price was a decrease of $.01 per BBL.

        In addition, the Company has entered into natural gas and crude oil costless collars to support the Company's investment program as follows:

 
  Gas
  Oil
Production
Period

  Volumes
Per Day

  Price
Per MMBTU
Floor—Ceiling

  Volumes
Per Day

  Price
Per BBL
Floor—Ceiling

4Q2002   165,000   $3.24-$4.46   7,500   $24.00-$30.04
1Q2003   185,000   $3.39-$4.78   15,000   $23.00-$28.63
2Q2003   145,000   $3.34-$4.45   15,000   $23.00-$28.63
3Q2003   145,000   $3.34-$4.45   10,000   $23.00-$27.95
4Q2003   145,000   $3.34-$4.75   10,000   $23.00-$27.95

        Of the 165,000 MMBTU of natural gas per day costless collars for the fourth quarter of 2002, 25,000 MMBTU of natural gas per day was terminated and as a result, the Company will recognize an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in the fourth quarter of 2002.

30


        The Company assumed swaps related to the acquisition of Aspect Resources, Inc. Based on the cost of these swaps, the Company will realize prices of approximately $3.20 per MMBTU and $22.00 per BBL for this time period related to these volumes. There was no realized effect on the average gas price and a realized effect of $.03 per BBL decrease in the average crude oil price in the third quarter of 2002 due to the purchased swaps. The realized effect of the purchased swaps for the first nine months of 2002 was an increase of $.01 per MCF and a decrease of $.02 per BBL in the average natural gas and crude oil prices. The remaining Aspect fixed price hedges are listed in the table below:

 
  Gas
  Oil
Production
Period

  Volumes
Per Day

  Price
Per MMBTU

  Volumes
Per Day

  Price
Per BBL

4Q2002   4,730   $ 4.68   110   $ 25.57
2003   2,480   $ 4.39   40   $ 23.45
1Q2004   1,154   $ 4.24   18   $ 22.81

        The contracts entitle the Company (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period, in amounts, if any, by which the settlement price for the last scheduled NYMEX trading day applicable for each calculation period is less than the floor or fixed price. The Company would pay the counterparty, if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period, is more than the ceiling or fixed price. The amount payable by the floating price payor, if the floating price is above the ceiling or fixed price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the ceiling or fixed price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is below the floor or fixed price, is the product of the notional quantity per calculation period and the excess, if any, of the floor or fixed price over the floating price in respect of each calculation period.

        During the third quarter of 2001, the Company had no price risk management arrangements for its production other than those entered into by NGM, which are described below.

        NGM, from time to time, employs price risk management arrangements in connection with its purchases and sales of production. While most of NGM's purchases are made for an index-based price, NGM's customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NGM may convert a fixed or NYMEX sale to an index-based sales price (such as purchasing a NYMEX futures contract at the Henry Hub with an adjoining basis swap at a physical location). Due to the size of such transactions and certain restraints imposed by contract and by Company guidelines, as of September 30, 2002 the Company believes it had no material market risk exposure from NGM's price risk arrangements. During the third quarter of 2002, NGM had price risk arrangements with broker-dealers that represented approximately 1,221,000 MMBTU's of gas per day. Arrangements for October 2002 through May 2006, which range from 20,000 MMBTU's to 999,000 MMBTU's of gas per day, for future physical transactions, were not closed at September 30, 2002. During the third quarter of 2001, NGM had price risk arrangements with broker-dealers that represented approximately 1,473,000 MMBTU's of gas per day. For the nine months ended September 30, 2002, NGM had hedging transactions that represented approximately 1,388,000 MMBTU's of gas per day, compared with 1,290,000 MMBTU's of gas per day for the same period in 2001.

31



        The Company has a $400 million credit agreement, which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At September 30, 2002, the Company had $380 million outstanding on its $400 million credit facility, which has a maturity date of November 30, 2006. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating. The Company also has a $200 million 364-day credit agreement, which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 62.5 to 150 basis points depending upon the percentage of utilization and credit rating. At September 30, 2002, there were no amounts outstanding under this credit agreement. All other Company long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates.

        The Company does not invest in foreign currency derivatives. The U.S. dollar is considered the functional currency for each of the Company's international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense on the income statement. However, certain sales transactions are concluded

32


in foreign currencies and the Company therefore is exposed to potential risk of loss based on fluctuation in exchange rates from time to time.


ITEM 4. CONTROLS AND PROCEDURES

        Based on the evaluation of the Company's disclosure controls and procedures by Charles D. Davidson, the Company's principal executive officer, and James L. McElvany, the Company's principal financial officer, as of a date within 90 days of the filing date of this quarterly report, each of them has concluded that the Company's disclosure controls and procedures are effective. There were no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

33




PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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

(b)
The following reports on Form 8-K were filed by the Company:

(i)
A Form 8-K was filed on August 7, 2002, relating to the filing of sworn statements of the Chief Executive Officer and the Chief Financial Officer of the Company to the Commission as required by SEC Order 4-460. The date of such report (the date of the earliest event reported) was August 7, 2002.

(ii)
A Form 8-K was filed on August 13, 2002, relating to the disclosure of the correspondence to the Commission, regarding the certifications of the Chief Executive Officer and the Chief Financial Officer of the Company submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that accompanied the Company's quarterly report on Form 10-Q for the quarter ended June 30, 2002.

34



SIGNATURE

        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            November 13, 2002            

 

By:

/s/  
JAMES L. MCELVANY      
JAMES L. McELVANY
Senior Vice President, Chief Financial Officer and Treasurer

35



CERTIFICATION

I, Charles D. Davidson, certify that:

1.
I have reviewed this quarterly report on Form 10-Q of the Company;

2.
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this quarterly report;

4.
The Company's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and we have:
a)
designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)
evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)
presented in this quarterly report our conclusions and about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The Company's other certifying officers and I have disclosed, based on our most recent evaluation, to the Company's auditors and the audit committee of Company's board of directors (or persons performing the equivalent function):
a)
all significant deficiencies in the design or operation of internal controls, which could adversely affect the Company's ability to record, process, summarize and report financial data and have identified for the Company's auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal controls; and
6.
The Company's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:            November 13, 2002            

/s/ CHARLES D. DAVIDSON              
CHARLES D. DAVIDSON
Chief Executive Officer

36



CERTIFICATION

I, James L. McElvany, certify that:

1.
I have reviewed this quarterly report on Form 10-Q of the Company;

2.
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this quarterly report;

4.
The Company's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and we have:
a)
designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)
evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)
presented in this quarterly report our conclusions and about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The Company's other certifying officers and I have disclosed, based on our most recent evaluation, to the Company's auditors and the audit committee of Company's board of directors (or persons performing the equivalent function):
a)
all significant deficiencies in the design or operation of internal controls, which could adversely affect the Company's ability to record, process, summarize and report financial data and have identified for the Company's auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal controls; and
6.
The Company's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:            November 13, 2002            

/s/ JAMES L. MCELVANY                    
JAMES L. McELVANY
Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit
Number

  Exhibit

99.1   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)

99.2

 

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)



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PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
NOBLE ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEET (Dollars in thousands)
NOBLE ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (Dollars in Thousands, Except Per Share Amounts) (Unaudited)
NOBLE ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (Dollars in Thousands, Except Per Share Amounts) (Unaudited)
NOBLE ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME AND SHAREHOLDERS' EQUITY (Dollars in Thousands) (Unaudited)
NOBLE ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS (Dollars in Thousands) (Unaudited)
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Unaudited)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURE
CERTIFICATION
CERTIFICATION
INDEX TO EXHIBITS

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EXHIBIT 99.1


CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

        In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the "Company") on Form 10-Q for the period ended September 30, 2002 (the "Report"), I, Charles D. Davidson, Chief Executive Officer of the Company, hereby certify that to my knowledge:



Date:        November 13, 2002            

/s/  
CHARLES D. DAVIDSON      
CHARLES D. DAVIDSON
Chief Executive Officer



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CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)

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EXHIBIT 99.2


CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

        In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the "Company") on Form 10-Q for the period ended September 30, 2002 (the "Report"), I, James L. McElvany, Chief Financial Officer of the Company, hereby certify that to my knowledge:



Date:        November 13, 2002            

/s/  
JAMES L. MCELVANY      
JAMES L. McELVANY
Chief Financial Officer



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CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (18 U.S.C. SECTION 1350)