UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
|
|
For the quarterly period ended June 30, 2003 |
OR |
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) |
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) | ||
|
|
| ||
|
| 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 ýNo o |
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
| Yes ýNo o |
Number of shares of common stock outstanding as of April 30,August 8, 2003: 57,390,61656,476,254
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NOBLE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Dollars in Thousands)
|
| (Unaudited) |
|
|
| |||||||||
|
| March 31, |
| December 31, |
|
| (Unaudited) |
|
|
| ||||
|
|
|
|
|
|
| June 30, |
| December 31, |
| ||||
ASSETS |
|
|
|
|
|
|
|
|
|
| ||||
Current Assets: |
|
|
|
|
|
|
|
|
|
| ||||
Cash and short-term investments |
| $ | 33,319 |
| $ | 15,442 |
|
| $ | 48,733 |
| $ | 15,442 |
|
Accounts receivable - trade |
| 333,869 |
| 232,924 |
|
| 217,562 |
| 232,924 |
| ||||
Oil and gas hedges receivable |
| 8,159 |
| 10,271 |
|
| 3,580 |
| 10,271 |
| ||||
Materials and supplies inventories |
| 13,292 |
| 10,663 |
|
| 15,649 |
| 10,663 |
| ||||
Assets held for sale |
| 14,636 |
|
|
| |||||||||
Other current assets |
| 34,835 |
| 41,074 |
|
| 52,413 |
| 41,074 |
| ||||
Total Current Assets |
| 423,474 |
| 310,374 |
|
| 352,573 |
| 310,374 |
| ||||
Property, Plant and Equipment, at cost |
| 4,531,729 |
| 4,334,015 |
|
| 4,512,817 |
| 4,334,015 |
| ||||
Less: accumulated depreciation, depletion and amortization |
| (2,288,420 | ) | (2,194,230 | ) |
| (2,261,838 | ) | (2,194,230 | ) | ||||
Total property, plant and equipment, net |
| 2,243,309 |
| 2,139,785 |
|
| 2,250,979 |
| 2,139,785 |
| ||||
Investment in Unconsolidated Subsidiary |
| 235,978 |
| 234,668 |
|
| 230,922 |
| 234,668 |
| ||||
Other Assets |
| 52,457 |
| 45,188 |
|
| 40,947 |
| 45,188 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Total Assets |
| $ | 2,955,218 |
| $ | 2,730,015 |
|
| $ | 2,875,421 |
| $ | 2,730,015 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
|
|
|
|
|
| ||||
Current Liabilities: |
|
|
|
|
|
|
|
|
|
| ||||
Accounts payable - trade |
| $ | 418,847 |
| $ | 351,856 |
|
| $ | 322,723 |
| $ | 351,856 |
|
Current installments of long-term debt |
| 42,245 |
| 41,919 |
|
| 85,680 |
| 41,919 |
| ||||
Oil and gas hedges payable |
| 46,398 |
| 32,285 |
|
| 28,836 |
| 32,285 |
| ||||
Other current liabilities |
| 41,123 |
| 36,159 |
|
| 38,771 |
| 36,159 |
| ||||
Income taxes - current |
| 23,211 |
| 9,535 |
|
| 38,577 |
| 9,535 |
| ||||
Total Current Liabilities |
| 571,824 |
| 471,754 |
|
| 514,587 |
| 471,754 |
| ||||
Deferred Income Taxes |
| 203,920 |
| 201,939 |
|
| 197,301 |
| 201,939 |
| ||||
Asset Retirement Obligation |
| 115,529 |
|
|
| |||||||||
Other Deferred Credits and Noncurrent Liabilities |
| 189,470 |
| 69,820 |
|
| 72,764 |
| 69,820 |
| ||||
Long-Term Debt |
| 958,450 |
| 977,116 |
|
| 940,933 |
| 977,116 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Total Liabilities |
| 1,923,664 |
| 1,720,629 |
|
| 1,841,114 |
| 1,720,629 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Shareholders’ Equity: |
|
|
|
|
|
|
|
|
|
| ||||
Common stock |
| 199,649 |
| 199,558 |
|
| 200,008 |
| 199,558 |
| ||||
Capital in excess of par value |
| 406,049 |
| 405,271 |
|
| 408,826 |
| 405,271 |
| ||||
Retained earnings |
| 491,052 |
| 458,490 |
|
| 517,825 |
| 458,490 |
| ||||
Accumulated other comprehensive loss |
| (25,866 | ) | (14,603 | ) |
| (16,396 | ) | (14,603 | ) | ||||
|
| 1,070,884 |
| 1,048,716 |
|
| 1,110,263 |
| 1,048,716 |
| ||||
Less Common Stock in Treasury (at cost, 2,505,522 shares) |
| (39,330 | ) | (39,330 | ) | |||||||||
|
|
|
|
|
| |||||||||
Less: Common Stock in Treasury, at cost |
| (75,956 | ) | (39,330 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
Total Shareholders’ Equity |
| 1,031,554 |
| 1,009,386 |
|
| 1,034,307 |
| 1,009,386 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Total Liabilities and Shareholders’ Equity |
| $ | 2,955,218 |
| $ | 2,730,015 |
|
| $ | 2,875,421 |
| $ | 2,730,015 |
|
See notes to consolidated condensed financial statements.
2
NOBLE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
|
| Three Months Ended March 31, |
| |||||||||||
|
| 2003 |
| 2002 |
|
| Three Months Ended June 30, |
| ||||||
|
|
|
|
|
|
| 2003 |
| 2002 |
| ||||
REVENUES: |
|
|
|
|
|
|
|
|
|
| ||||
Oil and gas sales and royalties |
| $ | 248,495 |
| $ | 146,072 |
|
| $ | 226,384 |
| $ | 175,966 |
|
Gathering, marketing and processing |
| 17,900 |
| 14,781 |
|
| 19,880 |
| 13,876 |
| ||||
Electricity sales |
| 19,325 |
|
|
|
| 9,181 |
|
|
| ||||
Income (loss) from unconsolidated subsidiary |
| 12,732 |
| (425 | ) |
| 11,874 |
| (3,480 | ) | ||||
Other income |
| 169 |
| 3,007 |
| |||||||||
|
|
|
|
|
| |||||||||
Other loss, net |
| (5,866 | ) | (135 | ) | |||||||||
|
| 298,621 |
| 163,435 |
|
|
|
|
|
| ||||
|
|
|
|
|
|
| 261,453 |
| 186,227 |
| ||||
COSTS AND EXPENSES: |
|
|
|
|
|
|
|
|
|
| ||||
Oil and gas operations |
| 45,366 |
| 32,375 |
|
| 41,416 |
| 27,254 |
| ||||
Transportation |
| 3,539 |
| 4,773 |
|
| 3,580 |
| 4,444 |
| ||||
Oil and gas exploration |
| 35,402 |
| 36,405 |
|
| 34,676 |
| 20,233 |
| ||||
Gathering, marketing and processing |
| 18,444 |
| 13,085 |
|
| 15,538 |
| 11,850 |
| ||||
Electricity generation |
| 13,586 |
|
|
|
| 10,035 |
|
|
| ||||
Depreciation, depletion and amortization |
| 82,276 |
| 75,502 |
|
| 78,988 |
| 70,090 |
| ||||
Selling, general and administrative |
| 13,629 |
| 11,323 |
|
| 14,945 |
| 12,083 |
| ||||
Accretion of asset retirement liability |
| 2,333 |
|
|
| |||||||||
Accretion of asset retirement obligation |
| 2,281 |
|
|
| |||||||||
Interest |
| 15,457 |
| 15,419 |
|
| 15,501 |
| 16,694 |
| ||||
Interest capitalized |
| (1,930 | ) | (4,351 | ) |
| (3,253 | ) | (4,732 | ) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
| 228,102 |
| 184,531 |
|
| 213,707 |
| 157,916 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
INCOME (LOSS) BEFORE TAXES |
| 70,519 |
| (21,096 | ) | |||||||||
INCOME BEFORE TAXES |
| 47,746 |
| 28,311 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
INCOME TAX PROVISION (BENEFIT) |
| 29,823 |
| (5,998 | ) | |||||||||
INCOME TAX PROVISION |
| 16,661 |
| 11,598 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE |
| $ | 40,696 |
| $ | (15,098 | ) | |||||||
INCOME BEFORE DISCONTINUED OPERATIONS |
| 31,085 |
| 16,713 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX |
| (5,839 | ) |
|
| |||||||||
DISCONTINUED OPERATIONS, NET OF TAX |
| (2,015 | ) | 406 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
NET INCOME (LOSS) |
| $ | 34,857 |
| $ | (15,098 | ) | |||||||
NET INCOME |
| $ | 29,070 |
| $ | 17,119 |
| |||||||
|
|
|
|
|
|
|
|
|
|
| ||||
EARNINGS PER SHARE: |
|
|
|
|
| |||||||||
EARNINGS (LOSS) PER SHARE: |
|
|
|
|
| |||||||||
Basic – |
|
|
|
|
|
|
|
|
|
| ||||
Income (loss) before cumulative effect of change in accounting principle |
| $ | 0.71 |
| $ | (0.26 | ) | |||||||
Cumulative effect of change in accounting principle, net of tax |
| (0.10 | ) |
|
| |||||||||
Income before discontinued operations |
| $ | 0.54 |
| $ | 0.29 |
| |||||||
Discontinued operations, net of tax |
| (0.03 | ) | 0.01 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
| $ | 0.61 |
| $ | (0.26 | ) | |||||||
Net income |
| $ | 0.51 |
| $ | 0.30 |
| |||||||
|
|
|
|
|
|
|
|
|
|
| ||||
Diluted – |
|
|
|
|
|
|
|
|
|
| ||||
Income (loss) before cumulative effect of change in accounting principle |
| $ | 0.70 |
| $ | (0.26 | ) | |||||||
Cumulative effect of change in accounting principle, net of tax |
| (0.10 | ) |
|
| |||||||||
Income before discontinued operations |
| $ | 0.53 |
| $ | 0.29 |
| |||||||
Discontinued operations, net of tax |
| (0.03 | ) | 0.01 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
| $ | 0.60 |
| $ | (0.26 | ) | |||||||
Net income |
| $ | 0.50 |
| $ | 0.30 |
| |||||||
|
|
|
|
|
|
|
|
|
|
| ||||
Weighted average number of shares outstanding – Basic |
| 57,376 |
| 57,014 |
|
| 57,181 |
| 57,171 |
| ||||
Weighted average number of shares outstanding – Diluted |
| 57,883 |
| 57,014 |
|
| 57,670 |
| 57,895 |
|
See notes to consolidated condensed financial statements.
3
NOBLE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOMEAND SHAREHOLDERS’ EQUITY
OPERATIONS
(Dollars in Thousands)
Thousands, Except Per Share Amounts)
(Unaudited)
|
| Comprehensive |
| Common |
| Capital in |
| Retained |
| Accumulated |
| Treasury |
| Total |
| |||||||
Balance at December 31, 2002 |
|
|
| $ | 199,558 |
| $ | 405,271 |
| $ | 458,490 |
| $ | (14,603 | ) | $ | (39,330 | ) | $ | 1,009,386 |
| |
Net income |
| $ | 34,857 |
|
|
|
|
| 34,857 |
|
|
|
|
| 34,857 |
| ||||||
Change in fair value of cash flow hedges, net of income tax |
| (11,263 | ) |
|
|
|
|
|
| (11,263 | ) |
|
| (11,263 | ) | |||||||
Shares issued |
|
|
| 91 |
| 778 |
|
|
|
|
|
|
| 869 |
| |||||||
Dividends declared ($0.04 per share) |
|
|
|
|
|
|
| (2,295 | ) |
|
|
|
| (2,295 | ) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Total |
| $ | 23,594 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Balance at March 31, 2003 |
|
|
| $ | 199,649 |
| $ | 406,049 |
| $ | 491,052 |
| $ | (25,866 | ) | $ | (39,330 | ) | $ | 1,031,554 |
|
|
| Six Months Ended June 30, |
| ||||
|
| 2003 |
| 2002 |
| ||
REVENUES: |
|
|
|
|
| ||
Oil and gas sales and royalties |
| $ | 468,177 |
| $ | 317,645 |
|
Gathering, marketing and processing |
| 37,780 |
| 28,657 |
| ||
Electricity sales |
| 28,506 |
|
|
| ||
Income (loss) from unconsolidated subsidiary |
| 24,606 |
| (3,905 | ) | ||
Other income (loss) |
| (5,697 | ) | 2,872 |
| ||
|
|
|
|
|
| ||
|
| 553,372 |
| 345,269 |
| ||
|
|
|
|
|
| ||
COSTS AND EXPENSES: |
|
|
|
|
| ||
Oil and gas operations |
| 84,869 |
| 57,709 |
| ||
Transportation |
| 7,119 |
| 9,217 |
| ||
Oil and gas exploration |
| 70,078 |
| 56,638 |
| ||
Gathering, marketing and processing |
| 33,982 |
| 24,935 |
| ||
Electricity generation |
| 23,621 |
|
|
| ||
Depreciation, depletion and amortization |
| 157,779 |
| 141,988 |
| ||
Selling, general and administrative |
| 28,574 |
| 23,406 |
| ||
Accretion of asset retirement obligation |
| 4,614 |
|
|
| ||
Interest |
| 30,958 |
| 32,113 |
| ||
Interest capitalized |
| (5,183 | ) | (9,083 | ) | ||
|
|
|
|
|
| ||
|
| 436,411 |
| 336,923 |
| ||
|
|
|
|
|
| ||
INCOME BEFORE TAXES |
| 116,961 |
| 8,346 |
| ||
|
|
|
|
|
| ||
INCOME TAX PROVISION |
| 46,028 |
| 5,996 |
| ||
|
|
|
|
|
| ||
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE |
| 70,933 |
| 2,350 |
| ||
|
|
|
|
|
| ||
DISCONTINUED OPERATIONS, NET OF TAX |
| (1,167 | ) | (329 | ) | ||
|
|
|
|
|
| ||
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX |
| (5,839 | ) |
|
| ||
|
|
|
|
|
| ||
NET INCOME |
| $ | 63,927 |
| $ | 2,021 |
|
|
|
|
|
|
| ||
EARNINGS (LOSS) PER SHARE: |
|
|
|
|
| ||
Basic – |
|
|
|
|
| ||
Income before discontinued operations and cumulative effect of change in accounting principle |
| $ | 1.24 |
| $ | 0.04 |
|
Discontinued operations, net of tax |
| (0.02 | ) |
|
| ||
Cumulative effect of change in accounting principle, net of tax |
| (0.10 | ) |
|
| ||
|
|
|
|
|
| ||
Net income |
| $ | 1.12 |
| $ | 0.04 |
|
|
|
|
|
|
| ||
Diluted – |
|
|
|
|
| ||
Income before discontinued operations and cumulative effect of change in accounting principle |
| $ | 1.23 |
| $ | 0.04 |
|
Discontinued operations, net of tax |
| (0.02 | ) | (0.01 | ) | ||
Cumulative effect of change in accounting principle, net of tax |
| (0.10 | ) |
|
| ||
|
|
|
|
|
| ||
Net income |
| $ | 1.11 |
| $ | 0.03 |
|
|
|
|
|
|
| ||
Weighted average number of shares outstanding – Basic |
| 57,278 |
| 57,094 |
| ||
Weighted average number of shares outstanding – Diluted |
| 57,776 |
| 57,752 |
|
See notes to consolidated condensed financial statements.
4
NOBLE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND SHAREHOLDERS’ EQUITY
(Dollars in Thousands)
(Unaudited)
|
| Comprehensive |
| Common |
| Capital in |
| Retained |
| Accumulated |
| Treasury |
| Total |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Balance at December 31, 2002 |
|
|
| $ | 199,558 |
| $ | 405,271 |
| $ | 458,490 |
| $ | (14,603 | ) | $ | (39,330 | ) | $ | 1,009,386 |
| |
Net income |
| $ | 63,927 |
|
|
|
|
| 63,927 |
|
|
|
|
| 63,927 |
| ||||||
Change in fair value of cash flow hedges, net of income tax |
| (1,793 | ) |
|
|
|
|
|
| (1,793 | ) |
|
| (1,793 | ) | |||||||
Shares issued |
|
|
| 450 |
| 3,555 |
|
|
|
|
|
|
| 4,005 |
| |||||||
Dividends declared |
|
|
|
|
|
|
| (4,592 | ) |
|
|
|
| (4,592 | ) | |||||||
Treasury stock obligation |
|
|
|
|
|
|
|
|
|
|
| (36,626 | ) | (36,626 | ) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Total |
| $ | 62,134 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Balance at June 30, 2003 |
|
|
| $ | 200,008 |
| $ | 408,826 |
| $ | 517,825 |
| $ | (16,396 | ) | $ | (75,956 | ) | $ | 1,034,307 |
|
See notes to consolidated condensed financial statements.
5
NOBLE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
|
| Three Months Ended March 31, |
| |||||||||||
|
| 2003 |
| 2002 |
|
| Six Months Ended June 30, |
| ||||||
|
|
|
|
|
|
| 2003 |
| 2002 |
| ||||
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
| $ | 34,857 |
| $ | (15,098 | ) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
| |||||||||
Net income |
| $ | 63,927 |
| $ | 2,021 |
| |||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
| |||||||||
Depreciation, depletion and amortization |
| 82,276 |
| 75,502 |
|
| 157,779 |
| 141,988 |
| ||||
Depreciation, depletion and amortization - electricity generation |
| 7,565 |
|
|
|
| 12,281 |
|
|
| ||||
Dry hole expense |
| 20,312 |
| 22,961 |
|
| 39,095 |
| 30,244 |
| ||||
Amortization of unproved leasehold costs |
| 5,804 |
| 3,859 |
|
| 11,305 |
| 7,717 |
| ||||
Cumulative effect of changes in accounting principles, net of tax |
| 5,839 |
|
|
| |||||||||
(Gain) loss on disposal of assets |
| 1,045 |
| (3,598 | ) | |||||||||
Noncurrent deferred income taxes (benefits) |
| 5,125 |
| (1,560 | ) | |||||||||
Accretion of asset retirement liability |
| 2,333 |
|
|
| |||||||||
Non-cash effect of discontinued operations |
| 8,527 |
| 329 |
| |||||||||
Cumulative effect of change in accounting principle, net of tax |
| 5,839 |
|
|
| |||||||||
Loss (gain) on disposal of assets |
| 5,857 |
| (2,556 | ) | |||||||||
Deferred income taxes |
| 226 |
| 4,276 |
| |||||||||
Accretion of asset retirement obligation |
| 4,614 |
|
|
| |||||||||
(Income) loss from unconsolidated subsidiary |
| (12,732 | ) | 426 |
|
| (24,606 | ) | 3,905 |
| ||||
Dividends received from unconsolidated subsidiary |
| 12,375 |
|
|
|
| 28,125 |
| 488 |
| ||||
Increase in deferred credits |
| 7,496 |
| 14,108 |
|
| 2,746 |
| 2,081 |
| ||||
(Increase) in other |
| (7,181 | ) | (395 | ) | |||||||||
Decrease (increase) in other |
| 7,203 |
| (14,046 | ) | |||||||||
Changes in operating assets and liabilities, not including cash: |
|
|
|
|
|
|
|
|
|
| ||||
(Increase) in accounts receivable |
| (100,945 | ) | (28,702 | ) | |||||||||
Decrease in other current assets and inventories |
| 8,573 |
| 36,745 |
| |||||||||
Increase (decrease) in accounts payable |
| 66,991 |
| (7,980 | ) | |||||||||
Decrease in accounts receivable |
| 15,362 |
| 14,358 |
| |||||||||
(Increase) decrease in other current assets and inventories |
| (29,454 | ) | 30,709 |
| |||||||||
Decrease in accounts payable |
| (29,133 | ) | (37,676 | ) | |||||||||
Increase (decrease) in other current liabilities |
| 18,640 |
| (22,097 | ) |
| 31,710 |
| (2,452 | ) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Net Cash Provided by Operating Activities |
| 158,373 |
| 74,171 |
|
| 311,403 |
| 181,386 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Cash Flows From Investing Activities: |
|
|
|
|
|
|
|
|
|
| ||||
Capital expenditures |
| (119,733 | ) | (155,087 | ) |
| (248,659 | ) | (289,039 | ) | ||||
Investment in unconsolidated subsidiary |
| (953 | ) | (4,781 | ) |
| 227 |
| (6,844 | ) | ||||
Proceeds from sale of property, plant and equipment |
|
|
| 19,635 |
|
| 101 |
| 20,016 |
| ||||
Distribution from unconsolidated subsidiary |
|
|
| 5,500 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
| ||||
Net Cash Used in Investing Activities |
| (120,686 | ) | (140,233 | ) |
| (248,331 | ) | (270,367 | ) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Cash Flows From Financing Activities: |
|
|
|
|
|
|
|
|
|
| ||||
Exercise of stock options |
| 869 |
| 1,256 |
|
| 4,005 |
| 7,672 |
| ||||
Cash dividends paid |
| (2,295 | ) | (2,280 | ) |
| (4,592 | ) | (4,563 | ) | ||||
Proceeds from bank debt |
| 70,200 |
| 97,724 |
|
| 60,314 |
| 122,842 |
| ||||
Repayment of bank debt |
| (87,011 | ) | (63,000 | ) |
| (86,999 | ) | (95,000 | ) | ||||
Repayment of note payable obtained in Aspect acquisition |
| (1,573 | ) | (7,561 | ) |
| (2,509 | ) | (13,526 | ) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Net Cash Provided by (Used in) Financing Activities |
| (19,810 | ) | 26,139 |
|
| (29,781 | ) | 17,425 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Increase (Decrease) in Cash and Short-term Investments |
| 17,877 |
| (39,923 | ) |
| 33,291 |
| (71,556 | ) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Cash and Short-term Investments at Beginning of Period |
| 15,442 |
| 73,237 |
|
| 15,442 |
| 73,237 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Cash and Short-term Investments at End of Period |
| $ | 33,319 |
| $ | 33,314 |
|
| $ | 48,733 |
| $ | 1,681 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Supplemental Disclosures of Cash Flow Information: |
|
|
|
|
|
|
|
|
|
| ||||
Cash paid (received) during the period for: |
|
|
|
|
|
|
|
|
|
| ||||
Interest (net of amount capitalized) |
| $ | 5,147 |
| $ | 2,555 |
|
| $ | 18,849 |
| $ | 13,801 |
|
Income taxes refunded |
| $ | (4,353 | ) | $ | (23,905 | ) | |||||||
Income taxes paid (refunded) |
| $ | 17,147 |
| $ | (40,394 | ) | |||||||
Debt obtained from consolidation of AMCCO (net of discount) |
| $ |
|
| $ | 122,076 |
|
| $ |
|
| $ | 122,510 |
|
Treasury stock obligation |
| $ | 36,626 |
| $ |
|
|
See notes to consolidated condensed financial statements.
56
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
In the opinion of Noble Energy, Inc. (the “Company” or “Noble Energy”), 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 March 31, 2003 and December 31, 2002;June 30, 2003; the results of operations for the three month and six month periods ended March 31,June 30, 2003 and 2002, respectively; the statement of comprehensive income and shareholders’ equity for the threesix month period ended March 31,June 30, 2003; and the cash flows for the threesix month periods ended March 31,June 30, 2003 and 2002. 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, 2002.
(1) STOCK-BASED EMPLOYEE COMPENSATION
The Company currently accounts for stock-based employee compensation plans under the recognition and measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.”
The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.
For the three months ended March 31:June 30:
(in thousands except per share amounts) |
| 2003 |
| 2002 |
|
| 2003 |
| 2002 |
| ||||
Net income, as reported |
| $ | 34,857 |
| $ | (15,098 | ) |
| $ | 29,070 |
| $ | 17,119 |
|
Add: Stock-based compensation cost recognized, net of related tax effects |
| 70,857 |
| 349,385 |
|
|
|
|
|
| ||||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
| (79,268 | ) | (358,388 | ) |
| (2,542 | ) | (2,379 | ) | ||||
Pro forma net income |
| $ | 26,446 |
| $ | (24,101 | ) |
| $ | 26,528 |
| $ | 14,740 |
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
| ||||
Basic - as reported |
| $ | 0.61 |
| $ | (0.26 | ) |
| $ | 0.51 |
| $ | 0.30 |
|
Basic - pro forma |
| $ | 0.46 |
| $ | (0.42 | ) |
| $ | 0.46 |
| $ | 0.26 |
|
Diluted - as reported |
| $ | 0.61 |
| $ | (0.26 | ) |
| $ | 0.50 |
| $ | 0.30 |
|
Diluted - pro forma |
| $ | 0.46 |
| $ | (0.42 | ) |
| $ | 0.46 |
| $ | 0.25 |
|
For the six months ended June 30:
(in thousands except per share amounts) |
| 2003 |
| 2002 |
| ||
Net income, as reported |
| $ | 63,927 |
| $ | 2,021 |
|
Add: Stock-based compensation cost recognized, net of related tax effects |
| 71 |
| 349 |
| ||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
| (5,084 | ) | (4,758 | ) | ||
Pro forma net income |
| $ | 58,914 |
| $ | (2,388 | ) |
Earnings per share: |
|
|
|
|
| ||
Basic - as reported |
| $ | 1.12 |
| $ | 0.04 |
|
Basic - pro forma |
| $ | 1.03 |
| $ | (0.04 | ) |
Diluted - as reported |
| $ | 1.11 |
| $ | 0.03 |
|
Diluted - pro forma |
| $ | 1.02 |
| $ | (0.04 | ) |
7
(2) INCOME TAX PROVISION (BENEFIT)
For the three months ended March 31:June 30:
|
| (In thousands) |
| |||||||||||
|
| 2003 |
| 2002 |
|
| (In thousands) |
| ||||||
|
|
|
|
|
|
| 2003 |
| 2002 |
| ||||
Current |
| $ | 24,698 |
| $ | (4,438 | ) |
| $ | 21,560 |
| $ | 5,762 |
|
Deferred |
| 5,125 |
| (1,560 | ) |
| (4,899 | ) | 5,836 |
| ||||
|
| $ | 29,823 |
| $ | (5,998 | ) |
|
|
|
|
| ||
|
| $ | 16,661 |
| $ | 11,598 |
|
For the six months ended June 30:
|
| (In thousands) |
| ||||
|
| 2003 |
| 2002 |
| ||
Current |
| $ | 45,802 |
| $ | 1,720 |
|
Deferred |
| 226 |
| 4,276 |
| ||
|
|
|
|
|
| ||
|
| $ | 46,028 |
| $ | 5,996 |
|
6In assessing whether or not deferred tax assets are realizable, management considers 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. During the second quarter of 2003, the Company achieved certain milestones on its Israel development project, which led management to conclude that the prior valuation allowance was no longer required for the deferred tax asset related to that project. This resulted in a decrease in tax expense for the quarter of approximately $2.6 million.
The income tax benefit associated with discontinued operations was $629 thousand and $177 thousand for the six-month period ending June 30, 2003 and 2002, respectively. For the three-month period ending June 30, 2003 and 2002, the tax benefit was $1.1 million and expense of $219 thousand, respectively.
(3) BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
Basic earnings per share (“EPS”) 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 and diluted EPS.
For the three months ended March 31:June 30:
|
| 2003 |
| 2002 |
| ||||||
(in thousands, except per share) |
| Income |
| Shares |
| Income |
| Shares |
| ||
Net income (loss)/shares |
| 34,857 |
| 57,376 |
| $ | (15,098 | ) | 57,014 |
| |
Basic EPS |
|
| $0.61 |
|
| $(0.26 ) |
| ||||
|
|
|
|
|
|
|
|
|
| ||
Net income (loss)/shares |
| 34,857 |
| 57,376 |
| $ | (15,098 | ) | 57,014 |
| |
Effect of Dilutive Securities Stock options (1) |
|
|
| 507 |
|
|
|
|
| ||
Adjusted net income (loss)/shares |
| 34,857 |
| 57,883 |
| $ | (15,098 | ) | 57,014 |
| |
Diluted EPS |
|
| $0.60 |
|
| $(0.26 ) |
| ||||
|
| 2003 |
| 2002 |
| ||||||
(in thousands, except per share) |
| Income |
| Shares |
| Income |
| Shares |
| ||
Net income/shares |
| $ | 29,070 |
| 57,181 |
| $ | 17,119 |
| 57,171 |
|
Basic EPS |
| $ | 0.51 |
|
|
| $ | 0.30 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net income/shares |
| $ | 29,070 |
| 57,181 |
| $ | 17,119 |
| 57,171 |
|
Effect of Dilutive Securities Stock options |
|
|
| 489 |
|
|
| 724 |
| ||
Adjusted net income/shares |
| $ | 29,070 |
| 57,670 |
| $ | 17,119 |
| 57,895 |
|
Diluted EPS |
| $ | 0.50 |
|
|
| $ | 0.30 |
|
|
|
8
(1) The effect of dilutive securities on first quarter 2002 diluted EPS is antidilutive as a result of
For 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 606 with adjusted shares of 57,620.six months ended June 30:
|
| 2003 |
| 2002 |
| |||||||
(in thousands, except per share) |
| Income |
| Shares |
| Income |
| Shares |
| |||
Net income/shares |
| $ | 63,927 |
| 57,278 |
| $ | 2,021 |
| 57,094 |
| |
Basic EPS |
| $ | 1.12 |
|
|
| $ | 0.04 |
|
|
| |
|
|
|
|
|
|
|
|
|
| |||
Net income/shares |
| $ | 63,927 |
| 57,278 |
| $ | 2,021 |
| 57,094 |
| |
Effect of Dilutive Securities |
|
|
|
|
|
|
|
|
| |||
Stock options |
|
|
| 498 |
|
|
| 658 |
| |||
Adjusted net income/shares |
| $ | 63,927 |
| 57,776 |
| $ | 2,021 |
| 57,752 |
| |
Diluted EPS |
| $ | 1.11 |
|
|
|
|
| $ | 0.03 |
| |
The table below reflects the amount of options not included in the EPS calculation above, as they were antidilutive.
For the three months ended March 31:June 30:
|
| 2003 |
| 2002 |
|
| 2003 |
| 2002 |
| ||
Options excluded from dilution calculation |
| 2,703,293 |
| 2,241,933 |
|
| 2,917,959 |
| 1,531,811 |
| ||
Range of exercise prices |
| $35.37 - $43.21 |
| $35.40 - $43.21 |
|
| $35.40 - $43.21 |
| $38.88 - $43.21 |
| ||
Weighted average exercise price |
| $41.53 |
| $39.87 |
|
| $ | 37.91 |
| $ | 41.36 |
|
For the six months ended June 30:
|
| 2003 |
| 2002 |
| ||
Options excluded from dilution calculation |
| 2,791,501 |
| 1,695,775 |
| ||
Range of exercise prices |
| $35.40 - $43.21 |
| $37.25 - $43.21 |
| ||
Weighted average exercise price |
| $ | 39.63 |
| $ | 41.05 |
|
(4) GEOGRAPHICAL DATA
The Company has operations throughout the world and generally manages its operations by country. The following information is grouped into five componentsreporting segments that are all primarily in the business of natural gas and crude oil exploration and production: United States, North Sea, Equatorial Guinea, IsraelIsrael; and Other International, Corporate and Marketing. Other International includes operations in Argentina, China, Ecuador and Vietnam. The following segment data was prepared on the same basis as Noble Energy’s consolidated financial statements. The information does not include the effects of income taxes.
79
Oil & Gas Operations
Three Months Ended 3/31/6/30/2003
(Dollars in Thousands)
|
| Consolidated |
| United States |
| North Sea |
| Equatorial |
| Israel |
| Other Int’l, |
|
| Consolidated |
| United States |
| North Sea |
| Equatorial |
| Israel |
| Other Int’l, |
| ||||||||||||
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Oil Sales |
| $ | 100,003 |
| $ | 44,177 |
| $ | 23,599 |
| $ | 16,900 |
| $ |
|
| $ | 15,327 |
|
| $ | 93,611 |
| $ | 45,927 |
| $ | 17,490 |
| $ | 14,259 |
| $ |
|
| $ | 15,935 |
|
Gas Sales |
| 148,492 |
| 142,146 |
| 5,349 |
| 970 |
|
|
| 27 |
|
| 132,773 |
| 127,428 |
| 4,295 |
| 1,011 |
|
|
| 39 |
| ||||||||||||
Gathering, Marketing and Processing Revenue |
| 17,900 |
|
|
|
|
|
|
|
|
| 17,900 |
|
| 19,880 |
|
|
|
|
|
|
|
|
| 19,880 |
| ||||||||||||
Electricity Sales |
| 19,325 |
|
|
|
|
|
|
|
|
| 19,325 |
|
| 9,181 |
|
|
|
|
|
|
|
|
| 9,181 |
| ||||||||||||
Income from Unconsolidated Subsidiaries |
| 12,732 |
|
|
|
|
| 12,732 |
|
|
|
|
|
| 11,874 |
|
|
|
|
| 11,874 |
|
|
|
|
| ||||||||||||
Other |
| 169 |
| (1,029 | ) | (23 | ) |
|
| 1 |
| 1,220 |
|
| (5,866 | ) | (4,898 | ) | 202 |
|
|
|
|
| (1,170 | ) | ||||||||||||
Total Revenues |
| 298,621 |
| 185,294 |
| 28,925 |
| 30,602 |
| 1 |
| 53,799 |
|
| 261,453 |
| 168,457 |
| 21,987 |
| 27,144 |
|
|
| 43,865 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Oil and Gas Operations |
| 45,366 |
| 31,982 |
| 2,935 |
| 4,285 |
|
|
| 6,164 |
|
| 41,416 |
| 29,644 |
| 2,788 |
| 3,882 |
|
|
| 5,102 |
| ||||||||||||
Transportation |
| 3,539 |
|
|
| 2,268 |
|
|
|
|
| 1,271 |
|
| 3,580 |
|
|
| 2,315 |
|
|
|
|
| 1,265 |
| ||||||||||||
Oil and Gas Exploration |
| 35,402 |
| 21,221 |
| 605 |
| 46 |
| 274 |
| 13,256 |
|
| 34,676 |
| 21,683 |
| 6,847 |
| 4 |
| 5,182 |
| 960 |
| ||||||||||||
Gathering, Marketing and Processing Costs |
| 18,444 |
|
|
|
|
|
|
|
|
| 18,444 |
|
| 15,538 |
|
|
|
|
|
|
|
|
| 15,538 |
| ||||||||||||
Electricity Generation |
| 13,586 |
|
|
|
|
|
|
|
|
| 13,586 |
|
| 10,035 |
|
|
|
|
|
|
|
|
| 10,035 |
| ||||||||||||
DD&A |
| 82,276 |
| 67,878 |
| 7,727 |
| 2,175 |
| 9 |
| 4,487 |
|
| 78,988 |
| 64,880 |
| 7,414 |
| 1,431 |
| 10 |
| 5,253 |
| ||||||||||||
SG&A |
| 13,629 |
| 4,188 |
|
|
| 60 |
|
|
| 9,381 |
|
| 14,945 |
| 4,419 |
|
|
| 97 |
|
|
| 10,429 |
| ||||||||||||
Accretion of Asset Retirement Liability |
| 2,333 |
|
|
|
|
|
|
|
|
| 2,333 |
| |||||||||||||||||||||||||
Accretion of Asset Retirement Obligation |
| 2,281 |
|
|
|
|
|
|
|
|
| 2,281 |
| |||||||||||||||||||||||||
Interest Expense (net) |
| 13,527 |
|
|
|
|
|
|
|
|
| 13,527 |
|
| 12,248 |
|
|
|
|
|
|
|
|
| 12,248 |
| ||||||||||||
Total Costs and Expenses |
| 228,102 |
| 125,269 |
| 13,535 |
| 6,566 |
| 283 |
| 82,449 |
|
| 213,707 |
| 120,626 |
| 19,364 |
| 5,414 |
| 5,192 |
| 63,111 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
OPERATING INCOME (LOSS) |
| $ | 70,519 |
| $ | 60,025 |
| $ | 15,390 |
| $ | 24,036 |
| $ | (282 | ) | $ | (28,650 | ) |
| $ | 47,746 |
| $ | 47,831 |
| $ | 2,623 |
| $ | 21,730 |
| $ | (5,192 | ) | $ | (19,246 | ) |
Discontinued Operations |
| 3,100 |
| 3,100 |
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS |
| $ | 44,646 |
| $ | 44,731 |
| $ | 2,623 |
| $ | 21,730 |
| $ | (5,192 | ) | $ | (19,246 | ) |
Three Months Ended 6/30/2002
Three Months Ended 3/31/2002 (Dollars in Thousands) |
| ||||||||||||||||||
| |||||||||||||||||||
|
| Consolidated |
| United States |
| North Sea |
| Equatorial |
| Israel |
| Other Int’l, |
| ||||||
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil Sales |
| $ | 61,362 |
| $ | 29,818 |
| $ | 15,877 |
| $ | 9,552 |
| $ |
|
| $ | 6,115 |
|
Gas Sales |
| 84,710 |
| 78,924 |
| 5,720 |
| 825 |
|
|
| (759 | ) | ||||||
Gathering, Marketing and Processing Revenue |
| 14,781 |
|
|
|
|
|
|
|
|
| 14,781 |
| ||||||
Electricity Sales |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income from Unconsolidated Subsidiaries |
| (425 | ) |
|
|
|
| (425 | ) |
|
|
|
| ||||||
Other |
| 3,007 |
| 2,947 |
| 127 |
| 1 |
|
|
| (68 | ) | ||||||
Total Revenues |
| 163,435 |
| 111,689 |
| 21,724 |
| 9,953 |
|
|
| 20,069 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil and Gas Operations |
| 32,375 |
| 26,790 |
| 2,355 |
| 2,095 |
|
|
| 1,135 |
| ||||||
Transportation |
| 4,773 |
|
|
| 2,449 |
|
|
|
|
| 2,324 |
| ||||||
Oil and Gas Exploration |
| 36,405 |
| 29,762 |
| 2,178 |
| 36 |
| 1,358 |
| 3,071 |
| ||||||
Gathering, Marketing and Processing Costs |
| 13,085 |
|
|
|
|
|
|
|
|
| 13,085 |
| ||||||
Electricity Generation |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
DD&A |
| 75,502 |
| 64,135 |
| 7,191 |
| 1,144 |
| 5 |
| 3,027 |
| ||||||
SG&A |
| 11,323 |
| 4,765 |
| (35 | ) | 204 |
| 2 |
| 6,387 |
| ||||||
Interest Expense (net) |
| 11,068 |
|
|
|
|
|
|
|
|
| 11,068 |
| ||||||
Total Costs and Expenses |
| 184,531 |
| 125,452 |
| 14,138 |
| 3,479 |
| 1,365 |
| 40,097 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) |
| $ | (21,096 | ) | $ | (13,763 | ) | $ | 7,586 |
| $ | 6,474 |
| $ | (1,365 | ) | $ | (20,028 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
As of 3/31/03 |
| $ | 2,243,309 |
| $ | 1,291,219 |
| $ | 94,165 |
| $ | 190,659 |
| $ | 207,460 |
| $ | 459,806 |
|
As of 3/31/02 |
| $ | 1,989,938 |
| $ | 1,288,811 |
| $ | 99,853 |
| $ | 91,995 |
| $ | 123,346 |
| $ | 385,933 |
|
(Dollars in Thousands)
|
| Consolidated |
| United States |
| North Sea |
| Equatorial |
| Israel |
| Other Int’l, |
| ||||||
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil Sales |
| $ | 74,139 |
| $ | 36,946 |
| $ | 18,591 |
| $ | 10,504 |
| $ |
|
| $ | 8,098 |
|
Gas Sales |
| 101,827 |
| 96,996 |
| 4,721 |
| 397 |
|
|
| (287 | ) | ||||||
Gathering, Marketing and Processing Revenue |
| 13,876 |
|
|
|
|
|
|
|
|
| 13,876 |
| ||||||
Electricity Sales |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income from Unconsolidated |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Subsidiaries |
| (3,480 | ) |
|
|
|
| (3,480 | ) |
|
|
|
| ||||||
Other |
| (135 | ) | (1,403 | ) | 322 |
|
|
|
|
| 946 |
| ||||||
Total Revenues |
| 186,227 |
| 132,539 |
| 23,634 |
| 7,421 |
|
|
| 22,633 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil and Gas Operations |
| 27,254 |
| 22,367 |
| 2,819 |
| 2,411 |
|
|
| (343 | ) | ||||||
Transportation |
| 4,444 |
|
|
| 2,288 |
|
|
|
|
| 2,156 |
| ||||||
Oil and Gas Exploration |
| 20,233 |
| 9,375 |
| 876 |
| (38 | ) | 312 |
| 9,708 |
| ||||||
Gathering, Marketing and Processing Costs |
| 11,850 |
|
|
|
|
|
|
|
|
| 11,850 |
| ||||||
Electricity Generation |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
DD&A |
| 70,090 |
| 58,996 |
| 6,650 |
| 927 |
| 6 |
| 3,511 |
| ||||||
SG&A |
| 12,083 |
| 4,468 |
| 228 |
| 517 |
|
|
| 6,870 |
| ||||||
Interest Expense (net) |
| 11,962 |
|
|
|
|
|
|
|
|
| 11,962 |
| ||||||
Total Costs and Expenses |
| 157,916 |
| 95,206 |
| 12,861 |
| 3,817 |
| 318 |
| 45,714 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) |
| $ | 28,311 |
| $ | 37,333 |
| $ | 10,773 |
| $ | 3,604 |
| $ | (318 | ) | $ | (23,081 | ) |
Discontinued Operations |
| (625 | ) | (625 | ) |
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS |
| $ | 28,936 |
| $ | 37,958 |
| $ | 10,773 |
| $ | 3,604 |
| $ | (318 | ) | $ | (23,081 | ) |
810
Oil & Gas Operations
Six Months Ended 6/30/2003
(Dollars in Thousands)
|
| Consolidated |
| United States |
| North Sea |
| Equatorial |
| Israel |
| Other Int’l, |
| ||||||
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil Sales |
| $ | 190,511 |
| $ | 87,001 |
| $ | 41,089 |
| $ | 31,159 |
| $ | — |
| $ | 31,262 |
|
Gas Sales |
| 277,666 |
| 265,975 |
| 9,644 |
| 1,981 |
|
|
| 66 |
| ||||||
Gathering, Marketing and Processing Revenue |
| 37,780 |
|
|
|
|
|
|
|
|
| 37,780 |
| ||||||
Electricity Sales |
| 28,506 |
|
|
|
|
|
|
|
|
| 28,506 |
| ||||||
Income from Unconsolidated Subsidiaries |
| 24,606 |
|
|
|
|
| 24,606 |
|
|
|
|
| ||||||
Other |
| (5,697 | ) | (5,927 | ) | 179 |
|
|
| 1 |
| 50 |
| ||||||
Total Revenues |
| 553,372 |
| 347,049 |
| 50,912 |
| 57,746 |
| 1 |
| 97,664 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil and Gas Operations |
| 84,869 |
| 59,713 |
| 5,723 |
| 8,167 |
|
|
| 11,266 |
| ||||||
Transportation |
| 7,119 |
|
|
| 4,583 |
|
|
|
|
| 2,536 |
| ||||||
Oil and Gas Exploration |
| 70,078 |
| 42,904 |
| 7,452 |
| 50 |
| 5,455 |
| 14,217 |
| ||||||
Gathering, Marketing and Processing Costs |
| 33,982 |
|
|
|
|
|
|
|
|
| 33,982 |
| ||||||
Electricity Generation |
| 23,621 |
|
|
|
|
|
|
|
|
| 23,621 |
| ||||||
DD&A |
| 157,779 |
| 129,273 |
| 15,141 |
| 3,606 |
| 20 |
| 9,739 |
| ||||||
SG&A |
| 28,574 |
| 8,607 |
|
|
| 157 |
|
|
| 19,810 |
| ||||||
Accretion of Asset Retirement Obligation |
| 4,614 |
|
|
|
|
|
|
|
|
| 4,614 |
| ||||||
Interest Expense (net) |
| 25,775 |
|
|
|
|
|
|
|
|
| 25,775 |
| ||||||
Total Costs and Expenses |
| 436,411 |
| 240,497 |
| 32,899 |
| 11,980 |
| 5,475 |
| 145,560 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) |
| $ | 116,961 |
| $ | 106,552 |
| $ | 18,013 |
| $ | 45,766 |
| $ | (5,474 | ) | $ | (47,896 | ) |
Discontinued Operations |
| 1,796 |
| 1,796 |
|
|
|
|
|
|
|
|
| ||||||
Cumulative Effect of SFAS 143 |
| 8,983 |
| 8,983 |
|
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS |
| $ | 106,182 |
| $ | 95,773 |
| $ | 18,013 |
| $ | 45,766 |
| $ | (5,474 | ) | $ | (47,896 | ) |
Six Months Ended 6/30/2002
(Dollars in Thousands)
|
| Consolidated |
| United States |
| North Sea |
| Equatorial |
| Israel |
| Other Int’l, |
| ||||||
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil Sales |
| $ | 133,537 |
| $ | 64,800 |
| $ | 34,468 |
| $ | 20,056 |
| $ |
|
| $ | 14,213 |
|
Gas Sales |
| 184,108 |
| 173,491 |
| 10,441 |
| 1,222 |
|
|
| (1,046 | ) | ||||||
Gathering, Marketing and Processing Revenue |
| 28,657 |
|
|
|
|
|
|
|
|
| 28,657 |
| ||||||
Electricity Sales |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income from Unconsolidated Subsidiaries |
| (3,905 | ) |
|
|
|
| (3,905 | ) |
|
|
|
| ||||||
Other |
| 2,872 |
| 1,544 |
| 449 |
| 1 |
|
|
| 878 |
| ||||||
Total Revenues |
| 345,269 |
| 239,835 |
| 45,358 |
| 17,374 |
|
|
| 42,702 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Oil and Gas Operations |
| 57,709 |
| 47,237 |
| 5,174 |
| 4,506 |
|
|
| 792 |
| ||||||
Transportation |
| 9,217 |
|
|
| 4,737 |
|
|
|
|
| 4,480 |
| ||||||
Oil and Gas Exploration |
| 56,638 |
| 39,137 |
| 3,054 |
| (2 | ) | 1,670 |
| 12,779 |
| ||||||
Gathering, Marketing and Processing Costs |
| 24,935 |
|
|
|
|
|
|
|
|
| 24,935 |
| ||||||
Electricity Generation |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
DD&A |
| 141,988 |
| 119,527 |
| 13,841 |
| 2,071 |
| 13 |
| 6,536 |
| ||||||
SG&A |
| 23,406 |
| 9,233 |
| 193 |
| 721 |
| 2 |
| 13,257 |
| ||||||
Interest Expense (net) |
| 23,030 |
|
|
|
|
|
|
|
|
| 23,030 |
| ||||||
Total Costs and Expenses |
| 336,923 |
| 215,134 |
| 26,999 |
| 7,296 |
| 1,685 |
| 85,809 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) |
| $ | 8,346 |
| $ | 24,701 |
| $ | 18,359 |
| $ | 10,078 |
| $ | (1,685 | ) | $ | (43,107 | ) |
Discontinued Operations |
| 506 |
| 506 |
|
|
|
|
|
|
|
|
| ||||||
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS |
| $ | 7,840 |
| $ | 24,195 |
| $ | 18,359 |
| $ | 10,078 |
| $ | (1,685 | ) | $ | (43,107 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
As of 6/30/03 |
| $ | 2,250,979 |
| $ | 1,227,305 |
| $ | 85,886 |
| $ | 253,976 |
| $ | 225,898 |
| $ | 457,914 |
|
As of 6/30/02 |
| $ | 2,044,334 |
| $ | 1,294,096 |
| $ | 94,186 |
| $ | 101,547 |
| $ | 142,333 |
| $ | 412,172 |
|
11
(5) DERIVATIVES AND HEDGING ACTIVITIES
The Company, directly or through its subsidiaries, from time to time, uses various derivative arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price swaps, 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 including periodic assessment of necessary provisions for bad debt allowance; however, the Company is not able to predict sudden changes in its counterparties’ creditworthiness. The Company accounts for its derivative arrangements under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative arrangements as cash flow hedges. Gains and losses from such arrangements related to the Company’s crude oil and natural gas production and which qualify for hedge accounting treatment are recorded in oil and gas sales and royalties upon sale of the associated products.
The Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production for the firstsecond quarter of 2003. The table below depicts the various transactions that settled for the firstsecond quarter.
Natural Gas |
| Crude Oil |
| |||||
Hedge MMBTUpd |
| 188,000 |
| Hedge Bpd |
| 15,000 |
| |
Floor price range |
| $3.25 - $3.75 |
| Floor price |
| $23.00 |
| |
Ceiling price range |
| $4.00 - $5.20 |
| Ceiling price range |
| $27.20 - $30.00 |
| |
Percent of daily production |
| 49 | % | Percent of daily production |
| 40 | % | |
Realized loss per Mcf |
| $(0.85 | ) | Realized loss per Bbl |
| $(2.05 | ) | |
Of
Natural Gas |
| Crude Oil |
| ||||||
Hedge MMBTUpd |
| 185,000 |
| Hedge Bpd |
| 15,000 |
| ||
Floor price range |
| $ | 3.25 - $3.80 |
| Floor price |
| $ | 23.00 |
|
Ceiling price range |
| $ | 4.00 - $5.00 |
| Ceiling price range |
| $ | 27.20 - $30.00 |
|
Percent of daily production |
| 50 | % | Percent of daily production |
| 38 | % | ||
Realized loss per Mcf |
| $ | (0.43 | ) | Realized loss per Bbl |
| $ | (0.29 | ) |
For the abovefirst six months of 2003, the Company entered into various natural gas costless collars 45,000 MMBTUpd relateand crude oil costless collar transactions related to its production. The table below depicts the Aspect acquisition and were put in place in November 2001.various transactions that settled for the first six months.
Natural Gas |
| Crude Oil |
| ||||||
Hedge MMBTUpd |
| 185,000 |
| Hedge Bpd |
| 15,000 |
| ||
Floor price range |
| $ | 3.25 - $3.80 |
| Floor price |
| $ | 23.00 |
|
Ceiling price range |
| $ | 4.00 - $5.20 |
| Ceiling price range |
| $ | 27.20 - $30.00 |
|
Percent of daily production |
| 50 | % | Percent of daily production |
| 39 | % | ||
Realized loss per Mcf |
| $ | (0.66 | ) | Realized loss per Bbl |
| $ | (1.18 | ) |
As of March 31,June 30, 2003, the Company had entered into future costless collars related to its natural gas and crude oil production to support the Company’s investment program as follows:
|
| Natural Gas |
| Crude Oil |
| ||||
Production |
| Volumes |
| Average Price |
| Volumes |
| Average Price |
|
|
|
|
|
|
|
|
|
|
|
2Q2003 |
| 185,000 |
| $3.43 - $4.57 |
| 15,000 |
| $23.00 - $28.63 |
|
3Q2003 |
| 185,000 |
| $3.43 - $4.60 |
| 15,000 |
| $23.67 - $29.53 |
|
4Q2003 |
| 185,000 |
| $3.43 - $4.84 |
| 10,000 |
| $23.00 - $27.95 |
|
1Q2004 |
| 60,000 |
| $4.63 - $6.30 |
|
|
|
|
|
2Q2004 |
| 30,000 |
| $3.75 - $5.16 |
|
|
|
|
|
|
| Natural Gas |
| Crude Oil |
| ||||
Production |
| Volumes |
| Average Price |
| Volumes |
| Average Price |
|
3Q2003 |
| 185,000 |
| $3.43 - $4.60 |
| 15,000 |
| $23.67 - $29.53 |
|
4Q2003 |
| 185,000 |
| $3.43 - $4.84 |
| 15,000 |
| $23.67 - $29.78 |
|
1Q2004 |
| 120,000 |
| $4.81 - $7.73 |
| 5,000 |
| $25.00 - $30.28 |
|
2Q2004 |
| 90,000 |
| $4.08 - $5.82 |
|
|
|
|
|
3Q2004 |
| 60,000 |
| $4.25 - $6.08 |
|
|
|
|
|
4Q2004 |
| 60,000 |
| $4.25 - $6.49 |
|
|
|
|
|
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 price. The Company would pay the counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period were more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is below the floor price, is the product of the notional quantity per calculation period and the excess, if any, of the floor price over the floating price in respect of each calculation period.
12
The Company entered into various natural gas costless collars related to its production for the firstsecond quarter of 2002. The table below depicts the various transactions that settled for the second quarter.
Natural Gas |
| |||
Hedge MMBTUpd |
| 180,000 |
| |
Floor price range |
| $2.00 - $3.25 |
| |
Ceiling price range |
| $2.95 - $5.10 |
| |
Percent of daily production |
| 49 | % | |
Realized loss per Mcf |
| $ | (0.06 | ) |
For the first six months of 2002, the Company entered into various natural gas costless collar transactions related to its production. The table below depicts the various transactions that settled for the first quarter.six months.
| |||
|
| ||
|
| ||
|
| ||
|
|
| |
|
|
Natural Gas |
| |||
Hedge MMBTUpd |
| 160,387 |
| |
Floor price range |
| $2.00 - $3.25 |
| |
Ceiling price range |
| $2.45 - $5.10 |
| |
Percent of daily production |
| 42 | % | |
Realized gain per Mcf |
| $ | 0.05 |
|
9
Noble Energy Marketing, Inc. (“NEMI”), from time to time, employs various derivative 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 NEMI are on an index basis; however, purchasers in the markets in which NEMI sells often require fixed or NYMEX-related pricing. NEMI may use a derivative to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.
NEMI records hedginggains and losses on derivatives using mark-to-market accounting. Under this accounting method, the change in the market value of outstanding financial instruments is recognized as gains or losses relating to fixed-term sales as gathering, marketing and processing revenues in the periods in which the related contract is completed.period of change.
At March 31,June 30, 2003, the Company recorded crude oil and natural gas hedge receivables of $8.2$3.6 million, crude oil and natural gas hedge liabilities of $46.5$28.8 million and other comprehensive loss, net of tax, of $25.9$16.4 million related to the Company’s cash flow hedging contracts.
During the first quarter ofthree month and six month periods ending June 30, 2003, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in $5.7$600 thousand and $6.3 million of income, respectively, (net of allowance) recognized in earnings. In addition, as of March 31,June 30, 2003, the Company had NYMEX-related transactions totaling 227208 contracts with ENAa mark-to-market receivable value of $2.5 million compared to 227 contracts with a mark-to-market receivable value of $1.9 million.million in the first quarter of 2003. For additional discussion of ENA matters, see Note 10, “Commitments and Contingencies” of this Form 10-Q.
13
(6) ATLANTIC METHANOL PRODUCTION COMPANY (“AMPCO”) METHANOL OPERATIONS
The following are the results of operations for the Company’s unconsolidated subsidiaries as of March 31,June 30, 2003.
AMPCO METHANOL OPERATIONS (Unaudited) (Dollars in Thousands)
|
| Three Months Ended June 30, |
| ||||
(dollars in thousands) (unaudited) |
| 2003 |
| 2002 |
| ||
|
|
|
|
|
| ||
REVENUE: |
|
|
|
|
| ||
Methanol sales |
| $ | 49,429 |
| $ | 17,654 |
|
Other income |
| 3,727 |
| 10,461 |
| ||
Total Revenue |
| $ | 53,156 |
| $ | 28,115 |
|
Less cost of goods sold |
| 21,337 |
| 30,211 |
| ||
Gross Margin |
| $ | 31,819 |
| $ | (2,096 | ) |
|
|
|
|
|
| ||
EXPENSES: |
|
|
|
|
| ||
DD&A |
| $ | 5,043 |
| $ | 5,262 |
|
Administrative |
| 848 |
| 812 |
| ||
Total Expenses |
| $ | 5,891 |
| $ | 6,074 |
|
|
|
|
|
|
| ||
NET INCOME (LOSS) |
| $ | 25,928 |
| $ | (8,170 | ) |
|
|
|
|
|
| ||
Methanol Sales (MGal) |
| 66,313 |
| 30,933 |
| ||
Average Realized Price ($/Gal) |
| $ | 0.72 |
| $ | 0.39 |
|
|
| Three Months Ended March 31, |
| ||||
|
| 2003 |
| 2002 |
| ||
REVENUES: |
|
|
|
|
| ||
Methanol sales |
| $ | 22,595 |
| $ | 8,835 |
|
Sales of purchased methanol |
| 2,058 |
|
|
| ||
Other |
| 1,635 |
| 1,100 |
| ||
|
|
|
|
|
| ||
Total Revenues |
| 26,288 |
| 9,935 |
| ||
|
|
|
|
|
| ||
COSTS AND EXPENSES: |
|
|
|
|
| ||
Cost of goods manufactured |
| 8,577 |
| 7,533 |
| ||
Cost of purchased methanol |
| 2,016 |
|
|
| ||
DD&A |
| 2,408 |
| 2,412 |
| ||
SG&A |
| 555 |
| 416 |
| ||
|
|
|
|
|
| ||
Total Costs and Expenses |
| 13,556 |
| 10,361 |
| ||
|
|
|
|
|
| ||
INCOME (LOSS) FROM UNCONS. SUBS. |
| $ | 12,732 |
| $ | (426 | ) |
|
|
|
|
|
| ||
Methanol Sales (MGal) |
| 34,486 |
| 30,941 |
| ||
Average Realized Price ($/Gal) |
| $ | 0.66 |
| $ | 0.29 |
|
|
| Six Months Ended June 30, |
| ||||
(dollars in thousands) (unaudited) |
| 2003 |
| 2002 |
| ||
|
|
|
|
|
| ||
REVENUE: |
|
|
|
|
| ||
Methanol sales |
| $ | 104,212 |
| $ | 37,286 |
|
Other income |
| 6,390 |
| 12,108 |
| ||
Total Revenue |
| $ | 110,602 |
| $ | 49,394 |
|
Less cost of goods sold |
| 44,877 |
| 46,843 |
| ||
Gross Margin |
| $ | 65,725 |
| $ | 2,551 |
|
|
|
|
|
|
| ||
EXPENSES: |
|
|
|
|
| ||
DD&A |
| $ | 10,164 |
| $ | 10,393 |
|
Administrative |
| 1,850 |
| 1,540 |
| ||
Total Expenses |
| $ | 12,014 |
| $ | 11,933 |
|
|
|
|
|
|
| ||
NET INCOME (LOSS) |
| $ | 53,711 |
| $ | (9,382 | ) |
|
|
|
|
|
| ||
Methanol Sales (MGal) |
| 142,949 |
| 99,691 |
| ||
Average Realized Price ($/Gal) |
| $ | 0.68 |
| $ | 0.32 |
|
(7) 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 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.
As of June 10, 2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net settle the contract.
14
The program was scheduled to mature in January 2003 but hashad been extended to January 2004. Under the provisions of the agreement with the bank, the Company can choosecould have chosen to either purchase the shares from the bank, issue additional
10
shares to the bank to the extent that the share price hashad decreased, pay the bank a net amount of cash to the extent that the share price hashad decreased, or receive from the bank a net amount of cash to the extent that the share price hashad increased. The bank hashad the right to terminate the agreement prior to the maturity date if the Company’s share price decreasesdecreased by 50 percent (to $16.77 per share) or if the Company’s credit rating iswas downgraded below BBB- (S&P) or Baa3 (Moody’s). If either event occurs and
During the bank exercises its right to terminate,second quarter of 2003, the Company still retains the right to settle in cash or additional shares. The agreement limits the numberadopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of shares to be issued byBoth Liabilities and Equity.” As a result, the Company to 14,000,000recorded an 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 excess1.04 million shares of par value. No settlements have occurred to date. Astreasury stock at a cost of March 31,$36.6 million and a current obligation of $36.6 million. On July 28, 2003, the fair value ofCompany paid $10 million on the Company’s obligation under the contract would be an obligation to pay approximately $36.4 million to the bank (and hold the shares as treasury stock), or the Company would distribute 20,294 shares of Company stock to the bank, or the Company would pay $696 thousand to the bank.obligation.
(8) RECOGNITION AND REPORTING OF GAINS AND LOSSES ON ENERGY TRADING CONTRACTS
In June 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues contained in Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” While the Company does not engage in material energy trading activities, the EITF has expanded its definition of energy trading activities to include the marketing activities in which the Company is engaged. As of January 1, 2003, the Company presents, in its gathering, marketing and processing activities in the statementstatements of operations for all periods, its marketing activities on a net rather than a gross basis. The change significantly decreased reported marketing sales and purchases, but had no effect on operating income or cash flow. Prior results have been reclassified to present the activity on a consistent basis.
(9) RECENTLY ISSUED PRONOUNCEMENTS
SFAS No. 143, “Accounting for Asset Retirement Obligations,” was issued in June 2001. This statement2001, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets 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 adopted SFAS No. 143 on January 1, 2003 and recognized as the fair value of asset retirement obligations $99.8 million related to the United States and $10.0 million related to the North Sea. The Company also recognized an after tax charge of $5.8 million as the cumulative effect of adoption of this standard in the first quarter of 2003.
Below is a reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations.
(Dollars in Thousands) |
| Three Months Ended |
|
| Six Months Ended |
| ||
|
|
|
| |||||
Beginning of the period |
| $ |
|
|
| $ |
|
|
Initial adoption entry |
| 109,821 |
|
| 109,821 |
| ||
Liabilities incurred in the current period |
|
|
|
| 1,316 |
| ||
Liabilities settled in the current period |
|
|
|
| (222 | ) | ||
Accretion expense |
| 2,333 |
|
| 4,614 |
| ||
End of the period |
| $ | 112,154 |
|
| $ | 115,529 |
|
The following table summarizes the pro forma net income and earnings per share, for the three months and six months ended March 31,June 30, 2002, for the change in accounting implemented on January 1, 2002 (in thousands, except per share amounts):
|
| Three Months Ended |
| Six Months Ended |
| |||||||||||||||
|
| As Reported |
| Pro Forma |
|
| As Reported |
| Pro Forma |
| As Reported |
| Pro Forma |
| ||||||
Net income |
| (15,098 | ) | (17,493 | ) |
| $ | 17,119 |
| $ | 14,712 |
| $ | 2,021 |
| $ | (2,781 | ) | ||
Net income per share, basic |
| $ | (.26 | ) | $ | (.31 | ) |
| $ | 0.30 |
| $ | 0.26 |
| $ | 0.04 |
| $ | (0.05 | ) |
Net income per share, diluted |
| $ | (.26 | ) | $ | (.31 | ) |
| $ | 0.30 |
| $ | 0.25 |
| $ | 0.03 |
| $ | (0.05 | ) |
In addition, on a pro forma basis as required by SFAS No. 143, if the Company had applied the provisions of SFAS No. 143 as of January 1, 2002, the amount of asset retirement obligations would have been $99.7 million.
SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” was issued in April 2003. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement is effective for
1115
contracts entered into or modified after June 30, 2003. The Company has not quantified the impact of adopting SFAS No. 149, but believes there will be no material impact on the Company’s results of operations or financial position.
(10) COMMITMENTS AND CONTINGENCIES
On October 15, 2002, Noble Gas Marketing, Inc., Samedan Oil Corporation and Aspect Resources L.L.C., collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and certain of its subsidiaries and affiliates, including ENA, under Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements and aggregate approximately $18 million.
On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim, sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to invalidate the arbitration provisions contained in certain of the agreements in issue. The Noble Defendants intend to vigorously defend against ENA’s claims and do not believe that the ultimate disposition of the bankruptcy proceeding will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.
On January 13, 2003, the Noble Defendants each filed an answer to the complaint. On January 29, 2003, the Noble Defendants filed the Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., Aspect Resources L.L.C., and Noble Energy, Inc., as Successor to Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L. Gropper (United States Bankruptcy Judge for the Southern District of New York) is acting as mediator for this case and the other trading cases which have been referred to him. The mediation for this case is currently anticipated to occur in the fourth quarter 2003.
(11) ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS
The Financial Accounting Standards Board (“FASB”) and representatives of the accounting staff of the Securities and Exchange Commission (“SEC”) are currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” with companies in the extractive industries, including oil and gas companies. The FASB and SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets on the balance sheets, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.
Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties pursuant to the provisions of SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” In the event the FASB and SEC staff determine that costs associated with mineral rights are required to be classified as intangible assets, a substantial portion of the Company’s oil and gas property acquisition costs since the June 30, 2001 effective date of SFAS No. 141 and SFAS No. 142 would be separately classified on the balance sheets as intangible assets. However, the results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules. Further, we do not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on our compliance with covenants under our debt agreements.
(12) DISCONTINUED OPERATIONS
During June 2003, the Company determined that it would dispose of certain properties through a sale. On July 16, 2003, the Company sold various domestic onshore crude oil and natural gas properties for a total of $22.2 million.
16
Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which replaced APB Opinion No. 30 for the disposal of segments of a business, the Company’s consolidated financial statements have been reclassified for all periods presented to reflect the operations and assets of the properties being sold as discontinued operations. The assets of such properties have been classified as “Assets held for sale” on the June 30, 2003 consolidated balance sheet and consists of the following:
(dollars in thousands) |
| June 30, 2003 |
| |
Property, plant and equipment, net |
| $ | 14,636 |
|
The net income (loss) from discontinued operations was classified on the consolidated financial statements of operations as “Discontinued operations, net of tax.” Summarized results of discontinued operations are as follows:
|
| Three Months Ended |
| Six Months Ended |
| ||||||||
(dollars in thousands) |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
REVENUES |
|
|
|
|
|
|
|
|
| ||||
Oil and gas sales and royalties |
| $ | 5,937 |
| $ | 5,393 |
| $ | 12,640 |
| $ | 9,786 |
|
|
|
|
|
|
|
|
|
|
| ||||
COSTS AND EXPENSES |
|
|
|
|
|
|
|
|
| ||||
Write down to fair value |
| $ | 4,914 |
| $ |
|
| $ | 4,914 |
| $ |
|
|
Oil and gas operations |
| 2,199 |
| 1,809 |
| 4,113 |
| 3,729 |
| ||||
Depreciation, depletion and amortization |
| 1,924 |
| 2,959 |
| 5,409 |
| 6,563 |
| ||||
|
| $ | 9,037 |
| $ | 4,768 |
| $ | 14,436 |
| $ | 10,292 |
|
|
|
|
|
|
|
|
|
|
| ||||
INCOME (LOSS) BEFORE INCOME TAXES |
| $ | (3,100 | ) | $ | 625 |
| $ | (1,796 | ) | $ | (506 | ) |
INCOME TAX PROVISION (BENEFIT) |
| (1,085 | ) | 219 |
| (629 | ) | (177 | ) | ||||
INCOME (LOSS) FROM DISCONTINUED OPERATIONS |
| $ | (2,015 | ) | $ | 406 |
| $ | (1,167 | ) | $ | (329 | ) |
The long-term debt of the Company is recorded at the consolidated level and is not reflected by each segment. Thus, the Company has not allocated interest expense to the discontinued operations.
(13) RECLASSIFICATION
Certain reclassifications have been made to the 2002 consolidated financial statements to conform to the 2003 presentation. These reclassifications are not material to the Company’s financial position.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
General. Noble Energy is including the following discussion to generally inform ourits existing and potential security holders 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 management’s behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include, but are not limited to, projections and estimates concerning the timing and success of specific projects and the Company’s future: (1) income, (2) crude oil and natural gas production, (3) crude oil and natural 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 the Company 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.
17
Noble Energy believes the factors discussed below are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made herein or elsewhere by the Company or on its 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. Noble Energy does not intend to update its description of important factors each time a potential important factor arises. The Company advises its stockholders that they should: (1) be aware that important factors not described below could affect the accuracy of ourits forward-looking statements, and (2) use caution and common sense when analyzing ourits forward-looking statements in this document or elsewhere. All of such forward-looking statements are qualified in their entirety by this cautionary statement.
12
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 supply and demand fundamentals and changes in the political, regulatory and economic climates and other factors that affect commodities markets generally and are outside of Noble Energy’s control. Some of Noble Energy’s 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. The Company expects its assumptions may change over time and that actual prices in the future may differ from our estimates. Any substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1) the Company’s financial position and results of operations, (2) the quantities of natural gas and crude oil reserves that the Company can economically produce, (3) the quantity of estimated proved reserves that may be attributed to its properties, and (4) the Company’s ability to fund its capital program.
Production Rates and Reserve Replacement. Projecting future rates of crude oil and natural gas production is inherently imprecise. Producing crude oil and natural gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering issues, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climates. Another factor affecting production rates is Noble Energy’s 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, the Company’s 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, Noble Energy’s finding and development costs may not justify the use of resources to explore for and develop such reserves.
Reserve Estimates. Noble Energy’s forward-looking statements are predicated, in part, on the Company’s estimates of its crude oil and natural 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 crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond the Company’s 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, estimates made by different engineers may 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 may be different from the quantities of crude oil and natural gas that are ultimately recovered.
Laws and Regulations. Noble Energy’s forward-looking statements are generally based on the assumption that the legal and regulatory environments will remain stable. Changes in the legal and/or regulatory environments could have a material effect on the Company’s future results of operations and financial condition. Noble Energy’s ability to economically produce and sell crude oil, natural gas, methanol and power is affected 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) crude oil and natural gas production, (2) taxes applicable to the Company and/or its production, (3) the amount of crude oil and natural gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities, and (5) the marketing of competitive fuels. The Company’s 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. Noble Energy’s forward-looking statements are generally based upon the expectation that the Company will not be required, in the near future, to expend cash to comply with environmental laws and regulations that are material in relation to its total capital
18
expenditures program. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to accurately predict the ultimate financial impact of compliance.
Drilling and Operating Risks. Noble Energy’s drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of crude oil, natural gas or well fluids. In addition, a substantial amount of the Company’s 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. 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.
13
Competition. The Company’s forward-looking statements are generally based on a stable competitive environment. Competition in the industry is intense. Noble Energy actively competes for reserve acquisitions and exploration leases and licenses, for the labor and equipment required to operate and develop crude oil and natural gas properties and in the gathering and marketing of natural gas, crude oil, methanol and power. The Company’s competitors include the major integrated oil companies, independent crude oil and natural 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 industrial, commercial and individual consumers, many of whom have greater financial resources than the Company.
Noble Energy believes that the location of its properties, its expertise in exploration, drilling and production operations, the experience of its management and the efforts and expertise of its marketing units generally enable it to compete effectively. In making projections with respect to numerous aspects of the Company’s business, Noble Energy generally assumes that there will be no material adverse change in competitive conditions.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operating activities increased $84.2$130.0 million to $158.4$311.4 million in the threesix months ended March 31,June 30, 2003 from $74.2$181.4 million in the same period of 2002. Cash and short-term investments increased from $15.4 million at December 31, 2002 to $33.3$48.7 million at March 31,June 30, 2003. These increases are primarily a result of higher natural gas and liquids prices in 2003 versus the comparable period in 2002.
On October 15, 2002, Noble Gas Marketing, Inc., Samedan Oil Corporation and Aspect Resources L.L.C., collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and certain of its subsidiaries and affiliates, including ENA, under Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements and aggregate approximately $18 million.
On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim, sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to invalidate the arbitration provisions contained in certain of the agreements in issue. The Noble Defendants intend to vigorously defend against ENA’s claims and do not believe that the ultimate disposition of the bankruptcy proceeding will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.
On January 13, 2003, the Noble Defendants each filed an answer to the complaint. On January 29, 2003, the Noble Defendants filed the Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., Aspect Resources L.L.C., and Noble Energy, Inc., as Successor to Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L. Gropper (United States Bankruptcy Judge for the Southern District of New York) is acting as mediator for this case and the other trading cases which have been referred to him. The mediation for this case is currently anticipated to occur in the fourth quarter 2003.
During the first quarterhalf of 2003, the Company borrowed and repaid $20a net $25 million on its $400 million credit facility, which resulted in the March 31,June 30, 2003 balance of $380 million being the same amount that was drawn on the $400 million credit facility at December 31, 2002.$355 million. The Company also has available a $200 million 364-day credit agreement with certain commercial lending institutions. At March 31,June 30, 2003, there were no amounts outstanding under thiswas a net $15 million borrowed on the $200 million credit agreement. Long-term debt at March 31,June 30, 2003 was $958.4$940.9 million compared with $977.1 million at
19
December 31, 2002. At June 30, 2003, total debt was $1.027 billion, which was an $8 million increase over $1.019 billion at December 31, 2002. This increase was primarily attributable to a net increase in short-term borrowings, which included a $36.6 million obligation on treasury stock.
The Company set its 2003 capital expenditures budget at approximately $510 million. Through March 31,June 30, 2003, the Company has expended approximately $110$259 million of its $510 million 2003 capital expenditures budget. Such expenditures are planned to be funded principally 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 available lines of credit and other borrowing opportunities.
Through AMPCO, the Company participated with a 50 percent expense interest (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
14
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 methanol plant has a 25-year contract to purchase natural gas from the Alba field.
The plant produced approximately 231,000244,000 metric tons of methanol in the firstsecond quarter of 2003.2003, compared with 57,000 metric tons for the same period of 2002. The methanol plant was shut down for 65 days for repairs during the second quarter of 2002. For the first threesix months of 2002,2003, the methanol plant produced approximately 209,000475,000 metric tons of methanol. The plant’s outputmethanol compared with 266,000 metric tons of methanol for the same period of 2002. For the balance of 2003 approximately 90 percent of the plant's output is under contract.
The Company follows the entitlements method of accounting for its natural gas imbalances. The Company’s estimated natural gas imbalance receivables were $20.0$21.0 million at March 31,June 30, 2003 and $20.1 million at December 31, 2002. Estimated natural gas imbalance liabilities were $16.4$16.8 million at March 31,June 30, 2003 and $15.4 million at December 31, 2002. These imbalances are valued at the amount that 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 natural gas imbalances will not have a material impact on its liquidity.
RESULTS OF OPERATIONS
For the firstsecond quarter of 2003, the Company recorded net income of $34.9$29.1 million, or $.61$0.51 per share, compared with a net lossincome of $15.1$17.1 million, or ($.26)$0.30 per share, in the firstsecond quarter of 2002. The increase in net income primarily reflected higher commodity prices and improved realization from methanol prices. Natural gas prices increased 34 percent, crude oil prices increased six percent and methanol prices increased 85 percent, compared with the second quarter of 2002. During the first six months of 2003, the Company recorded net income of $63.9 million, or $1.12 per share, compared with $2.0 million, or $0.04 per share, in the first quarter wassix months of 2002. The increased earnings through the first half of 2003 were a result of significantly higher commodity prices. Realized natural gas andprices, which increased 63 percent, coupled with a 24 percent increase in crude oil prices increased 101and a 113 percent and 48 percent, respectively,increase in methanol prices, compared with the same periodfirst half of 2002.
20
Certain selected geographical oil and gas operating statistics follow:
|
| Consolidated |
| United |
| North Sea |
| Equatorial |
| Other |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Oil & Gas Operations |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Before Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids (Bbl) |
| 41,090 |
| 20,997 |
| 7,438 |
| 6,198 |
| 6,457 |
| ||||||||||
Natural Gas (Mcf) |
| 374,252 | (2) | 302,676 |
| 13,431 |
| 44,455 |
| 13,690 | (2) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids per Bbl |
| $ | 25.83 |
| $ | 25.91 |
| $ | 25.84 |
| $ | 25.28 |
| $ | 27.12 |
| |||||
Natural Gas per Mcf |
| $ | 4.12 |
| $ | 4.95 |
| $ | 3.51 |
| $ | 0.25 |
| $ | 0.41 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
After Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids (Bbl) |
| 39,804 |
| 19,711 |
| 7,438 |
| 6,198 |
| 6,457 |
| ||||||||||
Natural Gas (Mcf) |
| 367,506 | (2) | 295,930 |
| 13,431 |
| 44,455 |
| 13,690 | (2) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids per Bbl |
| $ | 25.84 |
| $ | 25.60 |
| $ | 25.84 |
| $ | 25.28 |
| $ | 27.12 |
| |||||
Natural Gas per Mcf |
| $ | 4.11 |
| $ | 4.73 |
| $ | 3.51 |
| $ | 0.25 |
| $ | 0.41 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Oil & Gas Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Before Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids (Bbl) |
| 34,641 |
| 18,278 |
| 8,179 |
| 5,040 |
| 3,144 |
| ||||||||||
Natural Gas (Mcf) |
| 374,631 |
| 336,973 |
| 18,643 |
| 17,592 |
| 1,423 |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids per Bbl |
| $ | 24.24 |
| $ | 23.57 |
| $ | 24.98 |
| $ | 22.90 |
| $ | 28.25 |
| |||||
Natural Gas per Mcf |
| $ | 3.08 |
| $ | 3.25 |
| $ | 2.78 |
| $ | 0.25 |
| $ | 0.85 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
After Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids (Bbl) |
| 33,393 |
| 17,030 |
| 8,179 |
| 5,040 |
| 3,144 |
| ||||||||||
Natural Gas (Mcf) |
| 363,949 |
| 326,291 |
| 18,643 |
| 17,592 |
| 1,423 |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Liquids per Bbl |
| $ | 24.40 |
| $ | 23.85 |
| $ | 24.98 |
| $ | 22.90 |
| $ | 28.25 |
| |||||
Natural Gas per Mcf |
| $ | 3.07 |
| $ | 3.27 |
| $ | 2.78 |
| $ | 0.25 |
| $ | 0.85 |
| |||||
21
|
| Consolidated |
| United |
| North Sea |
| Equatorial |
| Other |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Oil & Gas Operations |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Before Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| |||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids (Bbl) |
| 39,433 |
| 19,770 |
| 7,515 |
| 6,227 |
| 5,921 |
| |||||
Natural Gas (Mcf) |
| 377,541 | (2) | 298,954 |
| 14,495 |
| 43,949 |
| 20,143 | (2) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids per Bbl |
| $ | 27.54 |
| $ | 26.01 |
| $ | 30.21 |
| $ | 27.64 |
| $ | 29.17 |
|
Natural Gas per Mcf |
| $ | 4.38 |
| $ | 5.04 |
| $ | 3.68 |
| $ | 0.25 |
| $ | 0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
After Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| |||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids (Bbl) |
| 38,179 |
| 18,516 |
| 7,515 |
| 6,227 |
| 5,921 |
| |||||
Natural Gas (Mcf) |
| 370,707 | (2) | 292,120 |
| 14,495 |
| 43,949 |
| 20,143 | (2) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids per Bbl |
| $ | 27.57 |
| $ | 25.96 |
| $ | 30.21 |
| $ | 27.64 |
| $ | 29.17 |
|
Natural Gas per Mcf |
| $ | 4.36 |
| $ | 5.03 |
| $ | 3.68 |
| $ | 0.25 |
| $ | 0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Gas Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Production |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids (Bbl) |
| 34,512 |
| 18,168 |
| 8,206 |
| 5,047 |
| 3,091 |
| |||||
Natural Gas (Mcf) |
| 391,328 |
| 343,872 |
| 18,808 |
| 27,509 |
| 1,139 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids per Bbl |
| $ | 22.05 |
| $ | 21.00 |
| $ | 23.20 |
| $ | 21.95 |
| $ | 25.33 |
|
Natural Gas per Mcf |
| $ | 2.68 |
| $ | 2.86 |
| $ | 3.07 |
| $ | 0.25 |
| $ | 0.85 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
After Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
| |||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids (Bbl) |
| 33,279 |
| 16,935 |
| 8,206 |
| 5,047 |
| 3,091 |
| |||||
Natural Gas (Mcf) |
| 379,923 |
| 332,467 |
| 18,808 |
| 27,509 |
| 1,139 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids per Bbl |
| $ | 22.16 |
| $ | 21.14 |
| $ | 23.20 |
| $ | 21.95 |
| $ | 25.33 |
|
Natural Gas per Mcf |
| $ | 2.68 |
| $ | 2.88 |
| $ | 3.07 |
| $ | 0.25 |
| $ | 0.85 |
|
Mcf - thousand cubic feet
(1) Other International includes operations in 2002. Methanol prices increased 128Argentina, China, Ecuador, Israel and Vietnam.
(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 in the first quarter of 2003 compared with the same period in 2002.owned by Noble Energy, intercompany natural gas sales are eliminated for accounting purposes.
Natural gas sales for the Company, excluding third-party sales by NEMI, a wholly owned subsidiary of the Company, increased 7530 percent for the three months ended March 31,June 30, 2003 compared with the same period in 2002. Natural gas sales increased due to a 34 percent increase in natural gas prices coupled with a one percent increase in average daily natural gas production volumes. Domestically, natural gas sales increased 8031 percent, primarily due to ana 45 percent increase of 117 percent in natural gas prices, offset by a decrease of 16nine percent in average daily natural gas production volumes,volumes. In Equatorial Guinea, natural gas sales more than doubled due to a corresponding increase in average daily natural gas sales volumes. The methanol plant was shut down 65 days in the second quarter of 2002 for repairs.
During the first six months of 2003, natural gas sales increased 51 percent compared with the same period in 2002. In the North Sea, naturalNatural gas sales decreased six percent, primarilyincreased due to a 63 percent increase in natural gas prices, offset by a decrease of 18two percent in average daily natural gas production volumes,volumes. Domestically, natural gas sales increased 53 percent, primarily due to a 75 percent
22
increase in natural gas prices, offset by a decrease of 12 percent in average daily natural gas production volumes. In Equatorial Guinea, natural gas sales increased 62 percent due to an increase of 1460 percent in average daily natural gas prices.sales volumes. The methanol plant was shut down 65 days in the first half of 2002 for repairs.
Crude oil sales for the Company, excluding third-party sales by NEMI, increased 6326 percent for the three months ended March 31,June 30, 2003 compared with the same period in 2002. First quarterCrude oil sales were upincreased due to a 4819 percent increase in average daily crude oil production volumes coupled with a six percent increase in crude oil prices. Domestically, crude oil sales increased 24 percent, primarily due to a 16 percent increase in average daily crude oil production coupled with a seven percent increase in crude oil prices. In Equatorial Guinea, crude oil sales increased 36 percent, primarily due to a 23 percent increase in average daily crude oil production coupled with a 10 percent increase in crude oil prices. In Other International, Corporate and Marketing, crude oil sales increased 97 percent, primarily due to start-up operations in China, which commenced in the first quarter of 2003.
During the first six months of 2003, crude oil sales increased 43 percent compared the same period in 2002. Crude oil sales increased due to a 15 percent increase in average daily crude oil production coupled with a 24 percent increase in crude oil prices. Domestically, crude oil sales increased 34 percent, primarily due to a 23 percent increase in crude oil prices coupled with a 10nine percent increase in average daily crude oil production. Domestically, crude oil sales increased 48 percent, primarily due to an increase of 44 percent in crude oil prices, coupled with an increase of three percent in average daily crude oil production. In the North Sea, crude oil sales increased 49 percent due to an increase of 61 percent in the average crude oil price, offset by a decrease of eight percent in the average daily crude oil production. In Equatorial Guinea, crude oil sales increased 7755 percent, primarily due to ana 26 percent increase of 43 percent in crude oil prices coupled with ana 23 percent increase of 24 percent in the average daily crude oil production. In Other International, Corporate and Marketing, crude oil sales increased 152120 percent, primarily due to an increase of 42 percentthe start-up operations in China, which commenced in the average crude oil price, coupled with an increasefirst quarter of 77 percent in the average daily crude oil production.2003.
NEMI markets the majority of the Company’s domestic natural gas, as well as certain third-party natural gas. NEMI sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. NEMI markets a portion of the Company’s domestic crude oil, as well as certain third-party crude oil. As of January 1, 2003, the Company presents, in its gathering, marketing and processing activities in the statementstatements of operations for all periods, its marketing activities on a net rather than a gross basis. All other expenses are recorded as gathering, marketing and processing expenses. All intercompany sales and expenses have been eliminated in the Company’s consolidated financial statements.
For the firstsecond quarter of 2003, net revenues and expenses from NEMI third-party sales totaled $17.9$19.9 million and $18.4$15.5 million, respectively, for a combined gross margin of ($.5)$4.4 million. In comparison, for the firstsecond quarter of 2002, NEMI third-party sales and expenses of $14.8$13.9 million and $13.1$11.8 million, respectively, resulted in a combined gross margin of $1.7$2.1 million. For the six months ended June 30, 2003, net revenues and expenses from NEMI third-party sales totaled $37.8 million and $34.0 million, respectively, for a combined gross margin of $3.8 million. In comparison, for the first six months of 2002, NEMI third-party sales and expenses of $28.7 million and $24.9 million, respectively, resulted in a combined gross margin of $3.8 million. The Company adopted EITF Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts”Contracts,” on January 1, 2003. The result of the adoption of EITF Topic 02-03 was to reduceaccount for gathering, marketing and processing revenues and expenses.expenses related to derivative trading activities on a net basis. The adoption did not have an effect on the Company’s net results from operations for either period.any periods.
The Company, directly or through its subsidiaries, from time to time, uses various derivative arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price swaps, 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 including periodic assessment of necessary provisions for bad debt allowance; however, the Company is not
15
able to predict sudden changes in its counterparties’ creditworthiness. The Company accounts for its derivative arrangements under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative arrangements as cash flow hedges. Gains and losses from such arrangements related to the Company’s crude oil and natural gas production and which 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 March 31,June 30, 2003, the Company recorded crude oil and natural gas hedge receivables of $8.2$3.6 million, crude oil and natural gas hedge liabilities of $46.5$28.8 million and other comprehensive loss, net of tax, of $25.9$16.4 million related to the Company’s cash flow hedging contracts.
During the first quarter ofthree month and six month periods ending June 30, 2003, the Company had contracts with ENA that resulted in $5.7$600 thousand and $6.3 million of income, respectively, (net of allowance) recognized in earnings. In addition, as of March 31,June 30, 2003, the Company had NYMEX-related transactions totaling 227208 contracts with ENAa mark-to-market receivable value of $2.5 million compared to 227 contracts with a mark-to-market receivable value of $1.9 million.million in the
23
first quarter of 2003. For additional discussion of ENA matters, see Note 10, “Commitments and Contingencies” of this Form 10-Q.
SFAS No. 143, “Accounting for Asset Retirement Obligations,” was issued in June 2001. This statement2001, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets 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 adopted SFAS No. 143 on January 1, 2003 and recognized as the fair value of asset retirement obligations $99.8 million related to the United States and $10.0 million related to the North Sea. The Company also recognized an after tax charge of $5.8 million as the cumulative effect of adoption of this standard in the first quarter of 2003.
Certain selected geographical oil and gas operating statistics follow:
Oil & Gas Operations |
| Consolidated |
| United |
| North Sea |
| Equatorial |
| Other | (1) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids (Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||||
Natural Gas (Mcf) |
| 37,757 |
| 18,528 |
| 7,594 |
| 6,257 |
| 5,378 |
| |||||
|
| 380,868 | (2) | 295,192 |
| 15,572 |
| 43,436 |
| 26,668 | (2) | |||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids per Bbl |
| $ | 29.43 |
| $ | 26.49 |
| $ | 34.53 |
| $ | 30.01 |
| $ | 31.66 |
|
Natural Gas per Mcf |
| $ | 4.65 |
| $ | 5.35 |
| $ | 3.82 |
| $ | 0.25 |
| $ | 0.32 |
|
Oil & Gas Operations |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Daily Production |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids (Bbl) |
| 34,381 |
| 18,053 |
| 8,235 |
| 5,056 |
| 3,037 |
| |||||
Natural Gas (Mcf) |
| 408,209 |
| 350,843 |
| 18,975 |
| 37,538 |
| 853 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Average Realized Price |
|
|
|
|
|
|
|
|
|
|
| |||||
Liquids per Bbl |
| $ | 19.83 |
| $ | 18.37 |
| $ | 21.42 |
| $ | 20.99 |
| $ | 22.27 |
|
Natural Gas per Mcf |
| $ | 2.31 |
| $ | 2.47 |
| $ | 3.35 |
| $ | 0.24 |
| $ | 0.86 |
|
Mcf - thousand cubic feet
(1) Other International includes operations in Argentina, China, Ecuador, Israel and Vietnam.
(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.
Crude oil and natural gas exploration expense decreased $1.0increased $14.4 million for the three months ended March 31,June 30, 2003, as compared with the same period in 2002. The firstsecond quarter 2003 decreaseincrease is primarily due to a decreaseincreased dry hole expense, which consisted of $4.9 million in Israel and $5.5 million in the North Sea; coupled with an increase of $1.6 million in undeveloped lease amortization and an increase of $0.9 million in seismic, related to the Company’s joint venture with Aspect Energy. For the six months ended June 30, 2003, exploration expense increased $13.4 million, as compared with the same period in 2002. The increase was due to an $8.9 million and $3.6 million increase, respectively, in dry hole expense and undeveloped lease amortization expense.
Crude oil and natural gas operations expense increased $13.0$14.2 million for the three months ended March 31,June 30, 2003, as compared with the same period in 2002. The increase in crude oil and natural gas operating costs was dueconsists primarily to higherof a $1.8 million increase in production taxes resulting from higher natural gas and crude oilcommodity prices and an $11.2 million increase in operating costs associated with the start-up of new international properties. For the six months ended June 30, 2003, operations expense increased ad valorem taxes.$27.2 million, as compared with the same period in 2002. The increase consists primarily of a $5.5 million increase in production taxes resulting from higher commodity prices and a $21.2 million increase in operating costs associated with the start-up of new international properties and additional deepwater production projects.
16
Depreciation, depletion and amortization (“DD&A”) expense increased $6.8$8.9 million for the three months ended March 31,June 30, 2003, as compared with the same period in 2002. The unit rate of DD&A per barrel of oil equivalentsequivalent (“BOE”), converting gas to oil on the basis of six MCF per barrel, was $9.03$8.59 for the first three monthssecond quarter of 2003 compared with $8.192003. The unit rate per barrel for the same period of 2002. The increase in 2002 was $8.19. For the six months ended June 30, 2003, the unit rate per BOE is due primarily to the adoption of SFAS No. 143, increased capitalized costsbarrel was $8.72 compared with $8.12 for the expansion projectssame period in Equatorial Guinea2002. The increase was primarily due to higher finding costs in the Gulf of Mexico shallow shelf in prior years and the higher initial capital costscarry associated with the Company’s joint venture with Aspect Energy. The adoption of SFAS No. 143, as of January 1, 2003, which related to accounting for abandonment costs, also contributed to higher DD&A.
Interest expense remained level at $15.5 milliondecreased seven percent for the three months ended March 31,June 30, 2003 as compared to $15.4 million forwith the same period in 2002. The average interest rate on short-term loans for the three-month period ending March 31,June 30, 2003 was 2.182.27 percent compared to 2.772.62 percent for the same period in 2002. Short-term borrowings outstanding for the three-month period ending June 30, 2003 averaged $14.3 million compared to $14.1 million for the same period in 2002. For the six months ended June 30, 2003, interest expense decreased four percent as compared with the same period in 2002. The average interest rate on short-term loans for the first half of 2003 was 2.23 percent compared to 2.67 percent for the same period in 2002. Short-term borrowings outstanding for the six-month period ending June 30, 2003 averaged $14.1 million compared to $14.7 million for the same period in 2002.
On January 1, 2003, the Company adopted SFAS No. 143, thatwhich requires the accretion of interest for retirement obligations and thisobligations. This amount totaled $2.3 million and $4.6 million, respectively, for the quarter.three months and six months ended June 30, 2003.
FUTURE TRENDS
The Company set its 2003 capital expenditures budget at approximately $510 million. Such expenditures are planned to be funded principally 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 available lines of credit and other borrowing opportunities.
24
Management believes that the Company is well positioned with its balanced reserves of crude oil and natural gas and downstream projects. The uncertainty of commodity prices continues to affect the crude oil, natural gas and methanol industries. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.
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 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.
As of June 10, 2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net settle the contract.
The program was scheduled to mature in January 2003 but hashad been extended to January 2004. Under the provisions of the agreement with the bank, the Company can choosecould have chosen to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price hashad decreased, pay the bank a net amount of cash to the extent that the share price hashad decreased, or receive from the bank a net amount of cash to the extent that the share price hashad increased. The bank hashad the right to terminate the agreement prior to the maturity date if the Company’s share price decreasesdecreased by 50 percent (to $16.77 per share) or if the Company’s credit rating iswas downgraded below BBB- (S&P) or Baa3 (Moody’s). If either event occurs and
During the bank exercises its right to terminate,second quarter of 2003, the Company still retainsadopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” As a result, the rightCompany recorded an additional 1.04 million shares of treasury stock at a cost of $36.6 million and a current obligation of $36.6 million. On July 28, 2003, the Company paid $10 million on the obligation and plans to settleextinguish the balance by year-end.
ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS
The FASB and representatives of the accounting staff of the SEC are currently engaged in cash or additional shares.discussions regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” with companies in the extractive industries, including oil and gas companies. The agreement limitsFASB and SEC staff are considering whether the numberprovisions of sharesSFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets on the balance sheets, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.
Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties pursuant to the provisions of SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” In the event the FASB and SEC staff determine that costs associated with mineral rights are required 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 March 31, 2003, the fair valueclassified as intangible assets, a substantial portion of the Company’s obligation underoil and gas property acquisition costs since the contractJune 30, 2001 effective date of SFAS No. 141 and SFAS No. 142 would be an obligationseparately classified on the balance sheets as intangible assets. However, the results of operations would not be affected since such intangible assets would continue to pay approximately $36.4 million tobe depleted and assessed for impairment in accordance with successful efforts accounting rules. Further, we do not believe the bank (and hold the sharesclassification of oil and gas lease acquisition costs as treasury stock), or the Companyintangible assets would distribute 20,294 shares of Company stock to the bank, or the Company would pay $696 thousand to the bank.have any impact on our compliance with covenants under our debt agreements.
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 crude oil and natural gas reserves to take advantage of future price increases
17
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, the Company, from time to time, has used derivative hedging instruments and may do so in the future as a means of managing its exposure to price changes.
25
The Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production for the firstsecond quarter of 2003. The table below depicts the various transactions that settled for the firstsecond quarter.
Natural Gas | Natural Gas |
| Crude Oil |
| Natural Gas |
| Crude Oil |
| ||||||||||||
Hedge MMBTUpd |
| 188,000 |
| Hedge Bpd |
| 15,000 |
|
| 185,000 |
| Hedge Bpd |
| 15,000 |
| ||||||
Floor price range |
|
| $3.25 - $3.75 |
| Floor price |
|
| $23.00 |
|
| $ | 3.25 - $3.80 |
| Floor price |
| $ | 23.00 |
| ||
Ceiling price range |
|
| $4.00 - $5.20 |
| Ceiling price range |
|
| $27.20 - $30.00 |
|
| $ | 4.00 - $5.00 |
| Ceiling price range |
| $ | 27.20 - $30.00 |
| ||
Percent of daily production |
| 49 | % | Percent of daily production |
| 40 | % |
| 50 | % | Percent of daily production |
| 38 | % | ||||||
Realized loss per Mcf |
|
| $(0.85 | ) | Realized loss per Bbl |
|
| $(2.05 | ) |
| $ | (0.43 | ) | Realized loss per Bbl |
| $ | (0.29 | ) |
OfFor the abovefirst six months of 2003, the Company entered into various natural gas costless collars 45,000 MMBTUpd relateand crude oil costless collar transactions related to its production. The table below depicts the Aspect acquisition and were put in place in November 2001.various transactions that settled for the first six months.
Natural Gas |
| Crude Oil |
| ||||||
Hedge MMBTUpd |
| 185,000 |
| Hedge Bpd |
| 15,000 |
| ||
Floor price range |
| $ | 3.25 - $3.80 |
| Floor price |
| $ | 23.00 |
|
Ceiling price range |
| $ | 4.00 - $5.20 |
| Ceiling price range |
| $ | 27.20 - $30.00 |
|
Percent of daily production |
| 50 | % | Percent of daily production |
| 39 | % | ||
Realized loss per Mcf |
| $ | (0.66 | ) | Realized loss per Bbl |
| $ | (1.18 | ) |
As of March 31,June 30, 2003, the Company had entered into future costless collars related to its natural gas and crude oil production to support the Company’s investment program as follows:
|
| Natural Gas |
| Crude Oil |
| ||||
Production |
| Volumes |
| Average Price |
| Volumes |
| Average Price |
|
|
|
|
|
|
|
|
|
|
|
2Q2003 |
| 185,000 |
| $3.43 - $4.57 |
| 15,000 |
| $23.00 - $28.63 |
|
3Q2003 |
| 185,000 |
| $3.43 - $4.60 |
| 15,000 |
| $23.67 - $29.53 |
|
4Q2003 |
| 185,000 |
| $3.43 - $4.84 |
| 10,000 |
| $23.00 - $27.95 |
|
1Q2004 |
| 60,000 |
| $4.63 - $6.30 |
|
|
|
|
|
2Q2004 |
| 30,000 |
| $3.75 - $5.16 |
|
|
|
|
|
|
| Natural Gas |
| Crude Oil |
| ||||
Production |
| Volumes |
| Average Price |
| Volumes |
| Average Price |
|
3Q2003 |
| 185,000 |
| $3.43 - $4.60 |
| 15,000 |
| $23.67 - $29.53 |
|
4Q2003 |
| 185,000 |
| $3.43 - $4.84 |
| 15,000 |
| $23.67 - $29.78 |
|
1Q2004 |
| 120,000 |
| $4.81 - $7.73 |
| 5,000 |
| $25.00 - $30.28 |
|
2Q2004 |
| 90,000 |
| $4.08 - $5.82 |
|
|
|
|
|
3Q2004 |
| 60,000 |
| $4.25 - $6.08 |
|
|
|
|
|
4Q2004 |
| 60,000 |
| $4.25 - $6.49 |
|
|
|
|
|
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 price. The Company would pay the counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period were more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is below the floor price, is the product of the notional quantity per calculation period and the excess, if any, of the floor price over the floating price in respect of each calculation period.
The Company entered into various natural gas costless collars related to its production for the firstsecond quarter of 2002. The table below depicts the various transactions that settled for the second quarter.
Natural Gas |
| |||
Hedge MMBTUpd |
| 180,000 |
| |
Floor price range |
| $2.00 - $3.25 |
| |
Ceiling price range |
| $2.95 - $5.10 |
| |
Percent of daily production |
| 49 | % | |
Realized loss per Mcf |
| $ | (0.06 | ) |
26
For the first six months of 2002, the Company entered into various natural gas costless collar transactions related to its production. The table below depicts the various transactions that settled for the first quarter.six months.
| |||
|
| ||
|
| ||
|
| ||
|
|
| |
|
|
Natural Gas |
| |||
Hedge MMBTUpd |
| 160,387 |
| |
Floor price range |
| $2.00 - $3.25 |
| |
Ceiling price range |
| $2.45 - $5.10 |
| |
Percent of daily production |
| 42 | % | |
Realized gain per Mcf |
| $ | 0.05 |
|
NEMI, from time to time, employs derivative arrangements in connection with its purchases and sales of production. While most of NEMI’s purchases are made for an index-based price, NEMI’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, NEMI 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 March 31,June 30, 2003, the Company believes it had no material market risk exposure from NEMI’s derivative arrangements. During the firstsecond quarter of 2003, NEMI had derivative arrangements with broker-dealers that represented approximately 1,463,000900,000 MMBTU’s of natural gas per day. Arrangements for AprilJuly 2003 through May 2006, which range from 20,000 MMBTU’s to 602,000675,000 MMBTU’s of natural gas per day for future physical
18
transactions, were not closed at March 31,June 30, 2003. During the firstsecond quarter of 2002, NEMI had derivative arrangements with broker-dealers that represented approximately 1,903,0001,047,000 MMBTU’s of natural gas per day. For the six months ended June 30, 2003, NEMI had hedging transactions that represented approximately 1,180,000 MMBTU’s of natural gas per day, compared with 1,473,000 MMBTU’s of natural gas per day for the same period in 2002.
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 March 31,June 30, 2003, the Company had $380$355 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 March 31,June 30, 2003, there were no amounts outstanding underwas $15 million borrowed on this credit agreement. All other significant 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 inenter into 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 statementstatements of operations. However, certain sales transactions are concluded 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 daysthe end of the filing date ofperiod covered by 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 over financial reporting that occurred during the quarter covered by this report that have materially affected, or in other factors that could significantlyis reasonably likely to materially affect, theseour internal controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.over financial reporting.
1927
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The annual meeting of stockholders of the Company was held at 9:30 a.m., Central time, on Tuesday, April 29, 2003 in Houston, Texas.
(b) Proxies were solicited by the Board of Directors of the Company pursuant to Regulation 14A under the Securities Exchange Act of 1934. There was no solicitation in opposition to the Board of Directors’ nominees as listed in the proxy statement and all such nominees were duly elected.
(c) Out of a total of 57,387,559 shares of common stock of the Company outstanding and entitled to vote, 50,788,811 shares were present in person or by proxy, representing approximately 89 percent.
|
| Number of Shares |
| Number of Shares |
|
|
|
|
|
|
|
Michael A. Cawley |
| 49,620,280 |
| 1,168,531 |
|
Edward F. Cox |
| 50,156,953 |
| 631,858 |
|
Charles D. Davidson |
| 49,990,224 |
| 798,587 |
|
James C. Day |
| 46,161,188 |
| 4,627,623 |
|
Kirby L. Hedrick |
| 50,157,089 |
| 631,722 |
|
Dale P. Jones |
| 50,128,878 |
| 659,933 |
|
Bruce A. Smith |
| 49,633,427 |
| 1,155,384 |
|
(d) The only other matter voted on by the shareholders, as fully described in the proxy statement for the annual meeting, and the results of the voting is as follows:
1. To consider and vote upon a proposal to approve an amendment to the Company’s 1992 Stock Option Plan to (a) increase the aggregate number of shares that may be awarded by stock option grants and (b) increase the maximum number of shares for which options may be awarded to a single employee in a single year. (For 34,741,941; Against 15,879,973; Abstaining 166,897).
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) AOn May 2, 2003, Noble Energy furnished a current report on Form 8-K to report under Item 9 that it was filed on January 2, 2003, relating tofiling a copy of its press release announcing its financial results for its first fiscal quarter ended March 31, 2003. The date of such report (the date of the announcement by the Company that the annual stockholder meeting had been rescheduled fromearliest event reported) was April 22, 2003 to April 29,30, 2003.
2028
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 |
|
| /s/ JAMES L. McELVANY | ||
|
|
| JAMES L. McELVANY | ||
|
21
|
| ||
| |||
| |||
| |||
22
|
| ||
| |||
| |||
| |||
2329
INDEX TO EXHIBITS
Exhibit |
| Exhibit |
|
|
|
10.1 |
| Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended, dated |
|
|
|
| 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) |
|
|
|
|
| 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) |
24
30