UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2003

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

For the transition period from to

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

100 Glenborough Drive, Suite 100 Houston, Texas		77067
(Address of principal executive offices)		(Zip Code)

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

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

Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes ý No o

Number of shares of common stock outstanding as of August 8, 2003: 56,476,254

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

	(Unaudited)
	June 30, 2003			December 31, 2002
ASSETS
Current Assets:
Cash and short-term investments	$	48,733		$	15,442
Accounts receivable - trade	217,562			232,924
Oil and gas hedges receivable	3,580			10,271
Materials and supplies inventories	15,649			10,663
Assets held for sale	14,636
Other current assets	52,413			41,074
Total Current Assets	352,573			310,374
Property, Plant and Equipment, at cost	4,512,817			4,334,015
Less: accumulated depreciation, depletion and amortization	(2,261,838		)	(2,194,230		)
Total property, plant and equipment, net	2,250,979			2,139,785
Investment in Unconsolidated Subsidiary	230,922			234,668
Other Assets	40,947			45,188

Total Assets	$	2,875,421		$	2,730,015

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	322,723		$	351,856
Current installments of long-term debt	85,680			41,919
Oil and gas hedges payable	28,836			32,285
Other current liabilities	38,771			36,159
Income taxes - current	38,577			9,535
Total Current Liabilities	514,587			471,754
Deferred Income Taxes	197,301			201,939
Asset Retirement Obligation	115,529
Other Deferred Credits and Noncurrent Liabilities	72,764			69,820
Long-Term Debt	940,933			977,116

Total Liabilities	1,841,114			1,720,629

Shareholders’ Equity:
Common stock	200,008			199,558
Capital in excess of par value	408,826			405,271
Retained earnings	517,825			458,490
Accumulated other comprehensive loss	(16,396		)	(14,603		)
	1,110,263			1,048,716

Less: Common Stock in Treasury, at cost (December 31, 2002, 2,505,522 shares and June 30, 2003, 3,549,976 shares)	(75,956		)	(39,330		)

Total Shareholders’ Equity	1,034,307			1,009,386

Total Liabilities and Shareholders’ Equity	$	2,875,421		$	2,730,015

See notes to consolidated condensed financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended June 30,
	2003			2002
REVENUES:
Oil and gas sales and royalties	$	226,384		$	175,966
Gathering, marketing and processing	19,880			13,876
Electricity sales	9,181
Income (loss) from unconsolidated subsidiary	11,874			(3,480		)
Other loss, net	(5,866		)	(135		)

	261,453			186,227
COSTS AND EXPENSES:
Oil and gas operations	41,416			27,254
Transportation	3,580			4,444
Oil and gas exploration	34,676			20,233
Gathering, marketing and processing	15,538			11,850
Electricity generation	10,035
Depreciation, depletion and amortization	78,988			70,090
Selling, general and administrative	14,945			12,083
Accretion of asset retirement obligation	2,281
Interest	15,501			16,694
Interest capitalized	(3,253		)	(4,732		)

	213,707			157,916

INCOME BEFORE TAXES	47,746			28,311

INCOME TAX PROVISION	16,661			11,598

INCOME BEFORE DISCONTINUED OPERATIONS	31,085			16,713

DISCONTINUED OPERATIONS, NET OF TAX	(2,015		)	406

NET INCOME	$	29,070		$	17,119

EARNINGS (LOSS) PER SHARE:
Basic –
Income before discontinued operations	$	0.54		$	0.29
Discontinued operations, net of tax	(0.03		)	0.01

Net income	$	0.51		$	0.30

Diluted –
Income before discontinued operations	$	0.53		$	0.29
Discontinued operations, net of tax	(0.03		)	0.01

Net income	$	0.50		$	0.30

Weighted average number of shares outstanding – Basic	57,181			57,171
Weighted average number of shares outstanding – Diluted	57,670			57,895

See notes to consolidated condensed financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	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.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

AND SHAREHOLDERS’ EQUITY

(Dollars in Thousands)

(Unaudited)

	Comprehensive Income (Loss)			Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Loss			Treasury Stock At Cost			Total Shareholders’ Equity

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 ($0.08 per share)								(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.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30,
	2003			2002
Cash Flows from Operating Activities:
Net income	$	63,927		$	2,021
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	157,779			141,988
Depreciation, depletion and amortization - electricity generation	12,281
Dry hole expense	39,095			30,244
Amortization of unproved leasehold costs	11,305			7,717
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	(24,606		)	3,905
Dividends received from unconsolidated subsidiary	28,125			488
Increase in deferred credits	2,746			2,081
Decrease (increase) in other	7,203			(14,046		)
Changes in operating assets and liabilities, not including cash:
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	31,710			(2,452		)

Net Cash Provided by Operating Activities	311,403			181,386

Cash Flows From Investing Activities:
Capital expenditures	(248,659		)	(289,039		)
Investment in unconsolidated subsidiary	227			(6,844		)
Proceeds from sale of property, plant and equipment	101			20,016
Distribution from unconsolidated subsidiary				5,500

Net Cash Used in Investing Activities	(248,331		)	(270,367		)

Cash Flows From Financing Activities:
Exercise of stock options	4,005			7,672
Cash dividends paid	(4,592		)	(4,563		)
Proceeds from bank debt	60,314			122,842
Repayment of bank debt	(86,999		)	(95,000		)
Repayment of note payable obtained in Aspect acquisition	(2,509		)	(13,526		)

Net Cash Provided by (Used in) Financing Activities	(29,781		)	17,425

Increase (Decrease) in Cash and Short-term Investments	33,291			(71,556		)

Cash and Short-term Investments at Beginning of Period	15,442			73,237

Cash and Short-term Investments at End of Period	$	48,733		$	1,681

Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during the period for:
Interest (net of amount capitalized)	$	18,849		$	13,801
Income taxes paid (refunded)	$	17,147		$	(40,394	)
Debt obtained from consolidation of AMCCO (net of discount)	$			$	122,510
Treasury stock obligation	$	36,626		$

See notes to consolidated condensed financial statements.

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 June 30, 2003; the results of operations for the three month and six month periods ended June 30, 2003 and 2002, respectively; the statement of comprehensive income and shareholders’ equity for the six month period ended June 30, 2003; and the cash flows for the six month periods ended 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 June 30:

(in thousands except per share amounts)	2003			2002
Net income, as reported	$	29,070		$	17,119
Add: Stock-based compensation cost recognized, net of related tax effects
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,542		)	(2,379		)
Pro forma net income	$	26,528		$	14,740
Earnings per share:
Basic - as reported	$	0.51		$	0.30
Basic - pro forma	$	0.46		$	0.26
Diluted - as reported	$	0.50		$	0.30
Diluted - pro forma	$	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	)

(2) INCOME TAX PROVISION (BENEFIT)

For the three months ended June 30:

	(In thousands)
	2003			2002
Current	$	21,560		$	5,762
Deferred	(4,899		)	5,836

	$	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

In 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 June 30:

	2003			2002
(in thousands, except per share)	Income (Numerator)		Shares (Denominator)	Income (Numerator)		Shares (Denominator)
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

For the six months ended June 30:

	2003			2002
(in thousands, except per share)	Income (Numerator)		Shares (Denominator)	Income (Numerator)		Shares (Denominator)
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 June 30:

	2003		2002
Options excluded from dilution calculation	2,917,959		1,531,811
Range of exercise prices	$35.40 - $43.21		$38.88 - $43.21
Weighted average exercise price	$	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 reporting segments that are all primarily in the business of natural gas and crude oil exploration and production: United States, North Sea, Equatorial Guinea, Israel; 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.

Oil & Gas Operations

Three Months Ended 6/30/2003

(Dollars in Thousands)

	Consolidated			United States			North Sea		Equatorial Guinea		Israel			Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	93,611		$	45,927		$	17,490	$	14,259	$			$	15,935
Gas Sales	132,773			127,428			4,295		1,011					39
Gathering, Marketing and Processing Revenue	19,880													19,880
Electricity Sales	9,181													9,181
Income from Unconsolidated Subsidiaries	11,874								11,874
Other	(5,866		)	(4,898		)	202							(1,170		)
Total Revenues	261,453			168,457			21,987		27,144					43,865

COSTS AND EXPENSES
Oil and Gas Operations	41,416			29,644			2,788		3,882					5,102
Transportation	3,580						2,315							1,265
Oil and Gas Exploration	34,676			21,683			6,847		4		5,182			960
Gathering, Marketing and Processing Costs	15,538													15,538
Electricity Generation	10,035													10,035
DD&A	78,988			64,880			7,414		1,431		10			5,253
SG&A	14,945			4,419					97					10,429
Accretion of Asset Retirement Obligation	2,281													2,281
Interest Expense (net)	12,248													12,248
Total Costs and Expenses	213,707			120,626			19,364		5,414		5,192			63,111

OPERATING INCOME (LOSS)	$	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

(Dollars in Thousands)

	Consolidated			United States			North Sea		Equatorial Guinea			Israel			Other Int’l, Corporate & Marketing
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	)

Oil & Gas Operations

Six Months Ended 6/30/2003

(Dollars in Thousands)

	Consolidated			United States			North Sea		Equatorial Guinea		Israel			Other Int’l, Corporate & Marketing
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 Guinea			Israel			Other Int’l, Corporate & Marketing
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

(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 second quarter of 2003. The table below depicts the various transactions that settled for the second quarter.

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 first six months of 2003, the Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production. The table below depicts the 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 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 Period	Volumes Per Day	Average Price Per MMBTU Floor - Ceiling	Volumes Per Day	Average Price Per Bbl Floor - Ceiling
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 second 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 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

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 gains 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 in the period of change.

At June 30, 2003, the Company recorded crude oil and natural gas hedge receivables of $3.6 million, crude oil and natural gas hedge liabilities of $28.8 million and other comprehensive loss, net of tax, of $16.4 million related to the Company’s cash flow hedging contracts.

During the three month and six month periods ending June 30, 2003, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in $600 thousand and $6.3 million of income, respectively, (net of allowance) recognized in earnings. In addition, as of June 30, 2003, the Company had NYMEX-related transactions totaling 208 contracts with a mark-to-market receivable value of $2.5 million compared to 227 contracts with a mark-to-market receivable value of $1.9 million in the first quarter of 2003. For additional discussion of ENA matters, see Note 10, “Commitments and Contingencies” of this Form 10-Q.

(6) ATLANTIC METHANOL PRODUCTION COMPANY (“AMPCO”) METHANOL OPERATIONS

The following are the results of operations for the Company’s unconsolidated subsidiaries as of June 30, 2003.

	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

	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.

The program was scheduled to mature in January 2003 but had been extended to January 2004. Under the provisions of the agreement with the bank, the Company could have chosen to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price had decreased, pay the bank a net amount of cash to the extent that the share price had decreased, or receive from the bank a net amount of cash to the extent that the share price had increased. The bank had the right to terminate the agreement prior to the maturity date if the Company’s share price decreased by 50 percent (to $16.77 per share) or if the Company’s credit rating was downgraded below BBB- (S&P) or Baa3 (Moody’s).

During the second quarter of 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” As a result, the Company 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.

(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 statements 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,” issued in June 2001, 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.

Below is a reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations.

(Dollars in Thousands)	Six Months Ended June 30, 2003
Beginning of the period	$
Initial adoption entry	109,821
Liabilities incurred in the current period	1,316
Liabilities settled in the current period	(222		)
Accretion expense	4,614
End of the period	$	115,529

The following table summarizes the pro forma net income and earnings per share, for the three months and six months ended 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
Net income	$	17,119	$	14,712	$	2,021	$	(2,781	)
Net income per share, basic	$	0.30	$	0.26	$	0.04	$	(0.05	)
Net income per share, diluted	$	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.

(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.

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 June 30					Six Months Ended June 30
(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 its 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.

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 its forward-looking statements, and (2) use caution and common sense when analyzing its forward-looking statements in this document or elsewhere. All of such forward-looking statements are qualified in their entirety by this cautionary statement.

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

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.

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 $130.0 million to $311.4 million in the six months ended June 30, 2003 from $181.4 million in the same period of 2002. Cash and short-term investments increased from $15.4 million at December 31, 2002 to $48.7 million at June 30, 2003. These increases are primarily a result of higher natural gas and liquids prices in 2003 versus the comparable period in 2002.

During the first half of 2003, the Company repaid a net $25 million on its $400 million credit facility, which resulted in the June 30, 2003 balance of $355 million. The Company also has available a $200 million 364-day credit agreement with certain commercial lending institutions. At June 30, 2003, there was a net $15 million borrowed on the $200 million credit agreement. Long-term debt at June 30, 2003 was $940.9 million compared with $977.1 million at

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 June 30, 2003, the Company has expended approximately $259 million of its 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 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 244,000 metric tons of methanol in the second quarter of 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 six months of 2003, the methanol plant produced approximately 475,000 metric tons of methanol 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 $21.0 million at June 30, 2003 and $20.1 million at December 31, 2002. Estimated natural gas imbalance liabilities were $16.8 million at 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 second quarter of 2003, the Company recorded net income of $29.1 million, or $0.51 per share, compared with net income of $17.1 million, or $0.30 per share, in the second 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 six months of 2002. The increased earnings through the first half of 2003 were a result of significantly higher natural gas prices, which increased 63 percent, coupled with a 24 percent increase in crude oil prices and a 113 percent increase in methanol prices, compared with the first half of 2002.

Certain selected geographical oil and gas operating statistics follow:

	Consolidated				United States			North Sea			Equatorial Guinea			Other International(1)

Oil & Gas Operations for the Three Months Ended 6/30/2003

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 for the Three Months Ended 6/30/2002

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

	Consolidated			United States		North Sea		Equatorial Guinea		Other International(1)

Oil & Gas Operations for the Six Months Ended 6/30/2003

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 for the Six Months Ended 6/30/2002

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

Bbl - - barrel

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.

Natural gas sales for the Company, excluding third-party sales by NEMI, a wholly owned subsidiary of the Company, increased 30 percent for the three months ended 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 31 percent, primarily due to a 45 percent increase in natural gas prices, offset by a decrease of nine percent in average daily natural gas production 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. Natural gas sales increased due to a 63 percent increase in natural gas prices, offset by a decrease of two percent in average daily natural gas production volumes. Domestically, natural gas sales increased 53 percent, primarily due to a 75 percent

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 60 percent in average daily natural gas 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 26 percent for the three months ended June 30, 2003 compared with the same period in 2002. Crude oil sales increased due to a 19 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 nine percent increase in average daily crude oil production. In Equatorial Guinea, crude oil sales increased 55 percent, primarily due to a 26 percent increase in crude oil prices coupled with a 23 percent increase in average daily crude oil production. In Other International, Corporate and Marketing, crude oil sales increased 120 percent, primarily due to the start-up operations in China, which commenced in the first quarter of 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 statements 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 second quarter of 2003, net revenues and expenses from NEMI third-party sales totaled $19.9 million and $15.5 million, respectively, for a combined gross margin of $4.4 million. In comparison, for the second quarter of 2002, NEMI third-party sales and expenses of $13.9 million and $11.8 million, respectively, resulted in a combined gross margin of $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,” on January 1, 2003. The result of the adoption of EITF Topic 02-03 was to account for gathering, marketing and processing revenues and 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 any periods.

During the three month and six month periods ending June 30, 2003, the Company had contracts with ENA that resulted in $600 thousand and $6.3 million of income, respectively, (net of allowance) recognized in earnings. In addition, as of June 30, 2003, the Company had NYMEX-related transactions totaling 208 contracts with a mark-to-market receivable value of $2.5 million compared to 227 contracts with a mark-to-market receivable value of $1.9 million in the

first quarter of 2003. For additional discussion of ENA matters, see Note 10, “Commitments and Contingencies” of this Form 10-Q.

Crude oil and natural gas exploration expense increased $14.4 million for the three months ended June 30, 2003, as compared with the same period in 2002. The second quarter 2003 increase is primarily due to increased 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 $14.2 million for the three months ended June 30, 2003, as compared with the same period in 2002. The increase consists primarily of a $1.8 million increase in production taxes resulting from higher commodity 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 $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.

Depreciation, depletion and amortization (“DD&A”) expense increased $8.9 million for the three months ended June 30, 2003, as compared with the same period in 2002. The unit rate of DD&A per barrel of oil equivalent (“BOE”), converting gas to oil on the basis of six MCF per barrel, was $8.59 for the second quarter of 2003. The unit rate per barrel for the same period in 2002 was $8.19. For the six months ended June 30, 2003, the unit rate per barrel was $8.72 compared with $8.12 for the same period in 2002. The increase was primarily due to higher finding costs in the Gulf of Mexico shallow shelf in prior years and the initial capital carry 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 decreased seven percent for the three months ended June 30, 2003 as compared with the same period in 2002. The average interest rate on short-term loans for the three-month period ending June 30, 2003 was 2.27 percent compared to 2.62 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, which requires the accretion of interest for retirement obligations. This amount totaled $2.3 million and $4.6 million, respectively, for the three months and six months ended June 30, 2003.

FUTURE TRENDS

The Company expects crude oil and natural gas production to increase in 2003 and 2004 compared to 2002. The increase in 2003 is expected primarily from the phase 2A expansion of the Alba field in Equatorial Guinea, the startup of production from the Mari-B field, offshore Israel, production from the CDX block in China and a full year of production in Ecuador. The increase in 2004 is expected from the continued expansion of markets in Israel and phase 2B expansion of the LPG plant in Equatorial Guinea.

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.

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

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.

ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS

The FASB and representatives of the accounting staff of the 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, 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.

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	)

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 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 Period	Volumes Per Day	Average Price Per MMBTU Floor - Ceiling	Volumes Per Day	Average Price Per Bbl Floor - Ceiling
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

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	)

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 June 30, 2003, the Company believes it had no material market risk exposure from NEMI’s derivative arrangements. During the second quarter of 2003, NEMI had derivative arrangements with broker-dealers that represented approximately 900,000 MMBTU’s of natural gas per day. Arrangements for July 2003 through May 2006, which range from 20,000 MMBTU’s to 675,000 MMBTU’s of natural gas per day for future physical transactions, were not closed at June 30, 2003. During the second quarter of 2002, NEMI had derivative arrangements with broker-dealers that represented approximately 1,047,000 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 June 30, 2003, the Company had $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 June 30, 2003, there was $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 enter 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 statements 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 the end of the period covered by this quarterly report, each of them has concluded that the Company’s disclosure controls and procedures are effective. There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter covered by this report that have materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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

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

(i) On May 2, 2003, Noble Energy furnished a current report on Form 8-K to report under Item 9 that it was filing 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 earliest event reported) was April 30, 2003.

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	August 14, 2003	/s/ JAMES L. McELVANY
		JAMES L. McELVANY Senior Vice President, Chief Financial Officer and Treasurer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

10.1		Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended, dated July 22, 2003

31.1		Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

31.2		Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

32.1		Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

32.2		Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)