10-K

Securities and Exchange Commission
Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2002

OR

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

Commission File Number: 1–8094

Ocean Energy, Inc.
(Exact name of registrant as specified in its charter)

             Delaware                      74–1764876
(State or other jurisdiction of              (I.R.S. Employer
incorporation or organization)            Identification No.)

1001 Fannin, Suite 1600, Houston, Texas 77002-6794
(Address of principal executive offices)                        (Zip code)

(713) 265-6000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

                                                          Name of each exchange on
   Title of each class                 which registered
Common Stock, par value $.10 per share      New York Stock Exchange
      Preferred Stock Purchase Rights            New York Stock Exchange

        Securities registered pursuant to Section 12(g) of the Act:
None

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10–K or any amendment to this Form 10–K. [X]

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b–2 of the Act). Yes [X] No [ ]

     As of June 28, 2002, approximately 175,818,834 shares of Common Stock, par value $0.10 per share, were outstanding and the aggregate market value of the outstanding shares of Common Stock of the Company held by non–affiliates (based on the closing price of these shares on the New York Stock Exchange) was approximately $3.8 billion. For purposes of determining the above amount, all directors and executive officers are considered affiliates.

     As of February 28, 2003, approximately 177,690,917 shares of Common Stock, par value $0.10 per share, were outstanding and the aggregate market value of the outstanding shares of Common Stock of the Company held by non–affiliates (based on the closing price of these shares on the New York Stock Exchange) was approximately $3.5 billion. For purposes of determining the above amount, all directors and executive officers are considered affiliates.

Documents Incorporated by Reference
The information required by Part III of Form 10–K will be incorporated by reference to the Company’s definitive proxy statement for its annual meeting of stockholders in 2003. To the extent that such proxy statement is not filed within 120 days of the Company’s fiscal year end, the Company will file an amendment to this Form 10–K to include such information.

Ocean Energy, Inc.

Index

	Page
Part I
Item 1.   Business	1
Oil and Gas Operations	3
U.S. Regulation	14
Competition	16
Environmental Matters	17
Risk Factors	18
Employees	22
Executive Officers of the Company	23
Item 2.   Properties	26
Item 3.   Legal Proceedings	26
Item 4.   Submission of Matters to a Vote of Security Holders	27
Part II
Item 5.   Market for Registrant’s Common Stock and Related Stockholder Matters	27
Item 6.   Selected Financial Data	28
Item 7.   Management’s Discussion and Analysis of Financial Condition and
Results of Operations	29
Item 7a. Quantitative and Qualitative Disclosures About Market Risk	47
Item 8.   Financial Statements and Supplementary Data	50
Item 9.   Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure	88
Part III
Item 10.   Directors and Executive Officers of the Registrant	88
Item 11.   Executive Compensation	88
Item 12.   Security Ownership of Certain Beneficial Owners and Management	88
Item 13.   Certain Relationships and Related Transactions	88
Item 14.   Controls and Procedures	89
Part IV
Item 15.   Exhibits, Financial Statement Schedules and Reports on Form 8-K	89
Signatures	97
Certifications	98
Index to Exhibits	100

(i)

Ocean Energy, Inc.

Part I

Item 1.   Business

     Ocean Energy, Inc. (the “Company,” “OEI” or “Ocean”) is one of the largest independent oil and gas exploration and production companies in the United States. The Company conducts North American operations in the shelf and deepwater areas of the Gulf of Mexico, the Rocky Mountains, Permian Basin, Anadarko, East Texas, North Louisiana and the Gulf Coast regions. Internationally, Ocean holds a leading position among U.S. independents in West Africa with oil and gas activities in Equatorial Guinea, Angola, Nigeria and Côte d’Ivoire. The Company also conducts operations in Egypt, the Russian Republic of Tatarstan, Brazil and Indonesia.

Recent Developments

     On February 23, 2003, Ocean and Devon Energy Corporation (“Devon”) entered into an Agreement and Plan of Merger that provides for the merger of Ocean into a subsidiary of Devon. In connection with the merger, which is anticipated to close mid–year 2003, Ocean stockholders will receive 0.414 share of common stock of Devon for each share of Ocean common stock they own. After the merger, the stockholders of Ocean are expected to own approximately 32% of the outstanding common stock of the combined company. The merger is expected to qualify as a tax–free transaction with no gain or loss recognized for U.S. Federal income tax purposes by the Ocean stockholders upon receipt of Devon common stock in exchange for shares of Ocean common stock. The merger is subject to approval by the stockholders of each Company and certain other customary closing conditions, including regulatory review under the Hart–Scott–Rodino Antitrust Improvements Act of 1976. The agreement between the companies contains reciprocal provisions for the payment of break–up fees under certain termination events.

     We believe the combination of Ocean and Devon will yield operational and financial benefits:

• Devon’s stable, gas–focused North American assets will be complemented by Ocean’s high–potential international and deepwater development and exploration projects.
• The transaction creates an entity with a stronger balance sheet and greater financial flexibility, allowing for acceleration of key exploration opportunities.
• The companies expect general and administrative cost savings of at least $50 million annually.
• Devon and Ocean have significant core area overlap that will provide operational synergies.

     The combination of Ocean and Devon will create the largest U.S.–based independent oil and natural gas producer with production of approximately 650,000 BOE per day, and upon completion of the merger, the combined company will have an estimated enterprise value of approximately $20 billion. After the merger the combined company will, based on information as of December 31, 2002:

• Produce approximately 2.4 billion cubic feet of natural gas and approximately 250,000 barrels of oil and natural gas liquids per day.
• Have approximately 2.2 billion BOE proved reserves, with 84 percent in North America.
• Have 90 percent of its worldwide production from North America, of which 69 percent will be natural gas.
• Have long–term debt of approximately 52 percent of total capitalization.

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Ocean Energy, Inc.

• Hold approximately 29 million net undeveloped acres worldwide.
• Be the largest independent deepwater Gulf leaseholder, with interests in more than 500 deepwater Gulf of Mexico blocks.

General

     Ocean has developed a strong position among U.S. independent oil and gas exploration and production companies in the deep waters off the coasts of the Gulf of Mexico, Brazil and West Africa. The Company has assumed an operator position as controlling partner on selected properties in each of these deepwater areas. During 2002, Ocean increased its deepwater net acreage position in the Gulf of Mexico and expanded its international operations by adding new blocks in Angola, Nigeria and Egypt.

     In 2002, the Company reduced its capital expenditure budget approximately 30% from the prior year in response to the lower commodity price environment that existed at the beginning of the year. With a reduced capital expenditure budget, a greater portion of the budget was used to fund deepwater development projects resulting from three prior years of exploratory success, and exploration and acquisition spending were reduced.

     The reduction in capital spending negatively impacted the Company’s reserve replacement rate and finding and development costs for 2002. The 2002 reserve replacement rate was 111% as compared to 387% for 2001, and 2002 finding and development cost was $12.11 per BOE as compared to $5.52 for 2001. Companies involved in exploration activities can have highly variable results from year to year. Our three–year averages include a reserve replacement rate of 254%, and a three–year average finding and development cost of $6.12 per BOE. During 2003, the Company expects to return to the exploration emphasis it had in 2001.

     Ocean’s total estimated proved reserves declined 1% to 593 MMBOE as of December 31, 2002 from 601 MMBOE at year–end 2001. Reserves were negatively affected by the impact of higher commodity prices on foreign production sharing contracts and the sales of assets. These reductions in reserves were partially offset by the impact of higher commodity prices on reserves not held under foreign production sharing contracts. Proved natural gas reserves, which comprise 50% of total proved reserves, reached 1.8 trillion cubic feet and oil reserves totaled 297 million barrels. Of these total proved reserves, 66% are located in North America and 34% are located internationally.

     Despite shut–ins caused by two hurricanes in the Gulf of Mexico and installation delays on deepwater Gulf of Mexico projects, the Company achieved a 3% year–over–year production increase and a 9% fourth quarter increase over the same period in 2001. Production averaged 153 MBOE per day for 2002 as compared to 149 MBOE per day for 2001. Higher production volumes were primarily attributable to new deepwater production from the Nansen/Boomvang complex and continued exploitation in the Zafiro field in Equatorial Guinea.

     Ocean is focused on financial discipline and a balanced property base. The Company’s assets combine revenue–generating international, domestic onshore and shelf properties as well as high–potential deepwater Gulf of Mexico and international exploratory prospects. The Company remains committed to producing low–cost energy, enhancing stockholder value, maintaining its focus on operating efficiency, and continuing to strengthen its capital structure.

     The Company’s internet address is www.oceanenergy.com. The Company makes available free

2

Ocean Energy, Inc.

of charge on or through its internet website its annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after electronically filing such material with, or furnishing it to, the Securities and Exchange Commission (the “Commission”).

Oil and Gas Operations

     The Company’s activities are focused primarily in three operating areas: (i) the continental shelf and deepwater areas of the Gulf of Mexico, (ii) onshore areas of North America, and (iii) internationally in Equatorial Guinea, Angola, Nigeria, Côte d’Ivoire, Egypt, the Russian Republic of Tatarstan, Brazil and Indonesia.

     The Company’s capital investment program for 2003 is expected to total approximately $1 billion. The spending will be funded from the Company’s discretionary cash flow based on anticipated commodity prices and is subject to change if market conditions shift or new opportunities are identified. Of the budget, $500 million to $550 million will be spent in the Gulf of Mexico region, $300 million to $400 million will be spent internationally, and $100 million to $150 million will be spent in the U.S. onshore region. Approximately one–third of the budget is allocated to exploratory projects.

     Ocean’s principal oil and gas producing areas include the following:

	Estimated Proved Reserves at December 31, 2002
	Oil (MMBbl)		Gas (Bcf)		MMBOE
Domestic:
Gulf of Mexico		97		604		198
North America Onshore		29		1,004		196
International:
Equatorial Guinea		117		--		117
Egypt		23		1		23
Cote d'Ivoire		5		126		26
Other International		26		44		33
Total		297		1,779		593

     For additional information relating to the Company’s oil and gas reserves, see Note 20 to the Consolidated Financial Statements. As required, Ocean also files estimates of oil and gas reserve data with various governmental regulatory authorities and agencies. These estimates were not materially different from the reserve estimates reported in the Consolidated Financial Statements.

DOMESTIC

     The Company’s domestic activities reside in two main areas: the Gulf of Mexico and certain onshore areas of North America. The domestic area includes 66% of the Company’s reserves and accounted for 64% of total production for the year ended December 31, 2002.

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Ocean Energy, Inc.

Gulf of Mexico

     The Company’s Gulf of Mexico properties are located in offshore waters along the coasts of Texas and Louisiana. For 2002, the Gulf of Mexico area had average daily production of 51 MBOE. This area currently accounts for 33% of Company–wide production and will be the focus of approximately 50% of the Company’s planned capital expenditures in 2003, with 75% of that amount focused on deepwater activities.

     The major growth in this area is associated with Ocean’s deepwater prospects. Ocean now ranks among the top six companies in terms of leasehold in the deepwater Gulf of Mexico with interests in approximately 860,000 net acres covering 361 blocks. The deepwater Gulf of Mexico is characterized by increasing production, multiple development projects and an active exploration program. The Company plans to utilize a hub–and–spoke concept in developing the deepwater Gulf to enhance the economics of producing from deepwater areas. Exploratory efforts are focused on specific regions followed by subsequent development of neighboring discoveries with production from a large, centrally located facility.

     Nansen/Boomvang/Navajo Complex – During 2002, production began from Ocean’s first major deepwater fields in the East Breaks area of the Gulf of Mexico where Ocean made two significant discoveries in 1999. The Nansen and Boomvang production sites feature the world’s first truss spars with a combined daily production capacity of up to 80,000 barrels of oil and 400 million cubic feet of gas. Production began from the Nansen field (50% working interest (“WI”)) in January 2002 and from the Navajo (50% WI) and Boomvang (20% WI) fields in June 2002. Additional discoveries made in the West Navajo field in East Breaks Block 689 (50% WI) and the Northwest Navajo field in East Breaks Block 646 (50% WI) during 2002 are being linked to the nearby Nansen spar via subsea tiebacks. Ocean’s combined net production from the Nansen/Boomvang/Navajo complex was approximately 37,000 BOE per day at December 31, 2002. Completion of dry tree and subsea wells will continue through the first half of 2003.

     Zia Development – The Zia project in Mississippi Canyon Block 496 (65% WI) is the first deepwater development project operated by Ocean. The field will utilize a subsea completion that will flow approximately 16 miles to a platform in South Pass 89. First production is scheduled for late summer 2003.

     Magnolia Development – Ocean is participating in the development of the Magnolia Field (25% WI) in nearly 4,700 feet of water. The deepwater development project is located in Garden Banks blocks 783 and 784. Development drilling is underway, with 2 of 8 platform development wells already drilled, and construction of a tension leg platform has begun. Production is anticipated to begin by year–end 2004.

     Redhawk Development – Two development wells (50% WI) have already been drilled and are waiting on subsea completion. Fabrication of a cell spar has begun and first production is anticipated in 2004.

     Atwater Valley Area – Two discoveries were made in the Atwater Valley area, Merganser in block 36 (50% WI) and Vortex in block 261 (33% WI). Ocean is continuing to evaluate its additional exploration opportunities in the area.

     Trident Prospect – The Trident partnership is currently evaluating Trident in Alaminos Canyon block 943 (13% WI) and offset discoveries in the area to determine overall commerciality.

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Ocean Energy, Inc.

     Deepwater Exploratory Activities – In 2003, Ocean anticipates drilling another six deepwater exploratory prospects. Four of the prospects, Yorktown in Mississippi Canyon Block 841 (50% WI), Shiner in Garden Banks Block 656 (25% WI), Tuscany in Desoto Canyon Block 179 (37.5% WI) and Aztec in Keathley Canyon Block 196 (50% WI) will be Ocean–operated.

     Gulf of Mexico Shelf – Activities in 2002 included a workover and recompletion program designed to maximize production from the area and successful development drilling programs at the Main Pass 69 field (100% WI) and the Eugene Island 126 field (100% WI). The recompletion and workover program will continue during 2003 and the Company plans to engage in exploitation and exploration drilling. The programs are concentrated in the core areas in the Delta and Central Gulf.

North America Onshore

     Ocean’s portfolio of onshore properties in North America is focused primarily in the Rocky Mountains, Permian Basin, Anadarko, East Texas, North Louisiana and the Gulf Coast regions. These properties are located mostly in mature areas where the Company can take advantage of low–cost exploitation to maintain and replace reserves. During 2002, the Company’s share of production from the North America Onshore area averaged 47 MBOE per day.

     Rocky Mountains – The Rocky Mountain area contains the Bear Paw field where Ocean has a large inventory of drilling locations. During 2002, the Company completed a 75–well development drilling program in the Bear Paw Field (96% WI). In 2003, Ocean will continue production and reserve development by expanding its drilling program to 100 wells. The Company plans to implement 3–D seismic for the first time within the Bear Paw producing areas to help identify optimum drilling locations within new fault blocks. The Company obtained a 75% working interest in approximately 60,000 acres in northwest Colorado during 2002 and plans to conduct exploratory activities on this acreage during 2003.

     Permian Basin – The Company’s 2002 activities in the Permian Basin included a successful horizontal drilling and development program in Ward County. The program included the drilling of two 17,000 foot horizontal gas wells, the Harding Fee #2H and the Harding Fee #3H (65% WI), which targeted the Montoya formation. During 2003, the Company will continue horizontal drilling and development activities and plans to drill the first exploratory horizontal well in Midland County. During 2003, the Company also plans to build upon its successful 2002 exploratory efforts in West Texas and New Mexico.

     Anadarko – The Company continues to exploit its extensive acreage position in the Anadarko area. During 2002, the primary focus was in the Strong City and Watonga–Chickasha areas in the Anadarko Basin and the Wilburton area in the Arkoma Basin. For 2003, the Company plans additional development of the Anadarko area, particularly in the Texas Panhandle. Activities will include application to the Company’s undeveloped acreage of new stimulation techniques, which have revitalized sparsely–developed, existing marginal fields.

     East Texas and North Louisiana – Focus areas are the Bossier, Carthage and Stockman Fields in East Texas and the Vernon Ansley and Ruston Field areas in North Louisiana. Development drilling and recompletion activities are ongoing.

5

Ocean Energy, Inc.

     Gulf Coast – The primary focus for 2002 was a recompletion/workover program complemented by a continued exploration effort primarily in the Wilcox trend in South Texas. Exploitation activities will continue in 2003 with increased development drilling and a continued active recompletion/workover program. Exploration activities will continue and will include the use of 3–D seismic to identify more exploration leads.

INTERNATIONAL

     The Company produces oil and gas in five countries outside of the United States – Equatorial Guinea, Egypt, Russia, Côte d’Ivoire and Indonesia. In addition, the Company has interests in other countries, including Angola, Brazil and Nigeria. The Company discontinued exploratory activities in the Arabian Sea offshore Pakistan during 2002.

     In Equatorial Guinea, Egypt, Côte d’Ivoire, Angola, and Nigeria, the Company’s acreage is generally held pursuant to production sharing contracts (“PSCs”) with the host governments. Typically, under a PSC the working interest partners pay all of the capital and operating costs and production is split between the government and the working interest partners. Working interest partners recover costs from a percentage of production. The remaining production, after cost recovery, is divided between the government and the working interest partners. Included in the government’s share of remaining petroleum are, in certain situations, the applicable income taxes for the working interest partners.

Equatorial Guinea

     In Equatorial Guinea, the Company has three PSCs covering 1.9 million gross acres. Equatorial Guinea currently includes 20% of the Company’s reserves and accounted for 22% of Company–wide production for 2002. During 2002, the Company’s share of production averaged 33 MBOE per day. Nearly half of the Company’s international budget for 2003 will be spent in Equatorial Guinea on continued development of the Zafiro field.

     Block B – Block B (23.75% WI) covers approximately 547,000 gross acres and contains the Zafiro field, where production currently occurs from two facilities, the Zafiro Producer and the Jade Platform. During 2002, the Company continued development of this area by successfully drilling eight development wells. One of these wells, the JP–6, is the longest extended reach well from the Jade Platform to date, with approximately 13,000 feet of horizontal displacement. A debottlenecking shut down was successfully completed for the Zafiro Producer and the field was returned to full production during third quarter 2002.

     The Company has also been conducting development activities in the Southern Expansion Area (“SEA”) of the Zafiro field. To date, seven development wells have been drilled and suspended pending arrival of the Serpentina, a floating production, storage and offloading vessel (“FPSO”) which will add the capacity needed to begin producing from this area. The SEA Project remains on schedule for startup of the FPSO Serpentina which is anticipated to occur in the second half of 2003.

     Block C – During 2002, the Company conducted exploratory activities on Block C (37.6% WI). An exploratory well failed to discover commercial quantities of reserves and the Company is evaluating the remaining potential for oil in Block C. This block covers approximately 649,000 gross acres.

6

Ocean Energy, Inc.

     Block N – In early 2002, the Company entered into a PSC with the government of Equatorial Guinea covering Corisco Bay Block N (25.5% WI), a 678,000 gross acre concession in the Rio Muni Basin offshore the mainland of Equatorial Guinea. Interpretation of final processed 3–D seismic data for Block N is underway and the Company expects to drill an exploratory well in the second half of 2003.

     Block D – During 2002, the Company withdrew from Block D concession after exploratory efforts indicated insufficient quantities of reserves to justify commercial recoverability.

Egypt

     Egypt currently includes 4% of the Company’s reserves and accounted for 6% of Company–wide production for 2002. During 2002, the Company’s share of production averaged 9 MBOE per day.

     The Company’s Egyptian operations consist of working interests in seven concessions covering 3.8 million gross acres. Four of these concessions are producing concessions – East Zeit, Qarun, East Beni Suef and West Abu Gharadig. Ocean also holds an interest in an exploratory block, Southwest Gebel el Zeit in the Gulf of Suez. During 2002, Ocean acquired interests in two additional exploratory blocks, Ras Abu Darag in the Northern Gulf of Suez and North Zeit Bay in the Gulf of Suez.

     East Zeit – The Company is operator of the East Zeit concession (100% WI) which covers 6,672 acres and is located offshore in the Gulf of Suez. During 2002, the Company conducted a workover program and installed jet pump surface equipment to boost production. A second platform is under construction and the Company plans to drill the C-1 well during 2003 to develop the reserves discovered by the A-21 well.

     Qarun – The Qarun concession (25% WI) covers approximately 66,000 gross acres located 45 miles southwest of Cairo, Egypt. During 2002, the Company successfully drilled two development wells.

     East Beni Suef – The East Beni Suef concession (50% WI) covers approximately 3.4 million gross acres lying adjacent and to the south of the Qarun concession. During 2002, the Company drilled the EBS–10 development well and completed it as a producer. The Company is also conducting exploratory drilling on the concession.

     West Abu Gharadig – The West Abu Gharadig concession (30% WI) covers 32,222 gross acres in lower Egypt.

     Southwest Gebel el Zeit – The Southwest Gebel el Zeit concession (43.75% WI) covers 7,413 gross acres located offshore in the Gulf of Suez. The Company assumed operatorship of the block during 2002 and is conducting exploratory activities.

     Ras Abu Darag and North Zeit Bay – The Ras Abu Darag concession (100% WI) covers 229,312 gross acres and the North Zeit Bay concession (100% WI) covers 44,973 gross acres. The Company is in the process of 3–D seismic acquisition for these exploratory blocks.

Côte d’Ivoire

     In Côte d’Ivoire, the Company is the operator on three blocks, Block CI–01 (80% WI), Block CI–02 (65% WI) and Block CI–11 (48% WI) which in total cover approximately 313,000 gross acres. The Company also owns and operates the Lion Gas Plant. During 2002, the Company’s share of production averaged 7 MBOE per day.

7

Ocean Energy, Inc.

     During 2002, an attempted coup d’etat occurred in the country. A peace accord between the government of Côte d’Ivoire, the rebels and various political parties has been signed in Paris. The political situation remains uncertain. To date, Ocean has not experienced any disruption in its operations in Côte d’Ivoire but can provide no assurance that future political or economic events affecting Côte d’Ivoire will not adversely affect its operations.

Russia

      The Company has a net 45% interest in a joint venture in Tatarstan, a republic in the Russian Federation. During 2002, the joint venture successfully drilled 29 development wells and 2 exploratory wells in the Onbysk and Demkino fields and plans additional development activity in the Onbysk and Demkino fields during 2003.

     During 2002, the Company’s share of production averaged 5 MBOE per day.

Angola

     Ocean is the only U.S. independent chosen to act as an operator in Angola and currently holds interests in 2.7 million gross acres.

     Block 10 – Ocean acquired an operated interest in Block 10 (35% WI) offshore Angola in early 2002. The Company holds an interest in 1.2 million gross acres in Block 10 and is in the process of conducting 3–D seismic acquisition. The Company plans to drill the first exploratory well on Block 10 during 2003.

     Block 24 – Block 24 (40% WI) is in the Kwanza Basin adjacent to Block 10. Ocean will become operator of this Block following the drilling of the Varina North well which spud in February 2003. The Company anticipates drilling a second exploratory well on Block 24 in late 2003. The Company holds an interest in 1.2 million gross acres in Block 24.

     Block 19 – During 2002, the Company discontinued exploratory activities on Block 19 (20% WI) in the Lower Congo Basin after exploratory efforts indicated insufficient quantities of reserves to justify commercial recoverability.

Brazil

     Ocean holds an interest in two deepwater exploration blocks offshore Brazil. The Company has a 65% working interest in Block BM–C–15, which it operates, and a 20% working interest in Block BM–S–22. The two blocks cover a total of 1.2 million gross acres. The Company is in the process of interpreting 3–D seismic data on Block BM–C–15 in the Campos Basin and plans to drill on this block in late 2003 or early 2004. Drilling activities on Block BM–S–22 are not anticipated to begin until 2004.

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Ocean Energy, Inc.

Nigeria

     In early 2003, the Company finalized a production sharing contract to become operator of OPL Block 256 (95% WI). The 631,000 gross acre block spans approximately 87 miles and is located in water depths of 6,000–9,500 feet. The working program calls for seismic studies and the drilling of three obligatory exploration wells, the first of which is expected to spud in 2004. The Company plans to farm out a portion of its interest in this block.

Indonesia

      Ocean owns a 1.7% interest in a joint venture in East Kalimantan, Indonesia. The majority of the joint venture’s revenues results from the sale of liquefied natural gas.

Production

     The following table summarizes the Company’s production, average sales prices and production–related operating costs for the periods indicated:

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Ocean Energy, Inc.

	Year Ended December 31,
		2002		2001		2000
Domestic:
Net production:
Oil and NGL (MBbl)		11,445		10,170		9,974
Gas (MMcf)		144,870		151,937		136,722
Average sales price:(1)
Oil and NGL (per Bbl)	$	22.79	$	22.70	$	25.85
Gas (per Mcf)	$	3.20	$	4.26	$	3.95
Average production–related operating
costs (per BOE)(2)	$	6.11	$	5.75	$	4.79
Equatorial Guinea:
Net oil production (MBbl)		12,054		11,112		8,344
Average oil sales price (per Bbl)(1)	$	23.10	$	21.17	$	26.06
Average production–related operating
costs (per BOE)(2)	$	2.44	$	1.76	$	2.19
Egypt:
Net production:
Oil and NGL (MBbl)		3,429		3,123		3,228
Gas (MMcf)		152		218		217
Average sales price:(1)
Oil and NGL (per Bbl)	$	22.85	$	22.18	$	26.61
Gas (per Mcf)	$	4.36	$	4.06	$	5.12
Average production–related operating
costs (per BOE)(2)	$	3.34	$	3.36	$	4.41
Côte d’Ivoire:
Net production:
Oil and NGL (MBbl)		1,134		1,166		1,409
Gas (MMcf)		8,090		6,914		8,552
Average sales price: (1)
Oil and NGL (per Bbl)	$	22.15	$	22.00	$	24.15
Gas (per Mcf)	$	2.69	$	2.47	$	2.28
Average production–related operating
costs (per BOE)(2)	$	4.34	$	4.56	$	3.64
Other International:
Net production:
Oil and NGL (MBbl)		1,977		1,929		1,796
Gas (MMcf)		2,330		2,552		3,312
Average sales price: (1)
Oil and NGL (per Bbl)	$	14.05	$	15.40	$	20.14
Gas (per Mcf)	$	4.04	$	4.34	$	3.78
Average production–related operating
costs (per BOE)(2)	$	8.25	$	6.58	$	4.77
Total:
Net production:
Oil and NGL (MBbl)		30,039		27,500		24,751
Gas (MMcf)		155,442		161,621		148,803
Average sales price:(1)
Oil and NGL (per Bbl)	$	22.32	$	21.48	$	25.51
Gas (per Mcf)	$	3.19	$	4.18	$	3.85
Average sales price including hedging:(1)
Oil and NGL (per Bbl)	$	22.03	$	20.23	$	22.11
Gas (per Mcf)	$	3.22	$	4.33	$	3.54
Average production–related operating
costs (per BOE)(2)	$	5.16	$	4.78	$	4.26

⁽¹⁾ Average sales prices are before deduction of production, severance, and other taxes and transportation expenses.

(2) Operating costs represent costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among other things, repairs and maintenance, workover expenses, labor, materials, supplies, property taxes, insurance, severance taxes, transportation expenses and general operating expenses. These costs exclude certain employee costs that support the Company’s ongoing oil and gas activities.

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Ocean Energy, Inc.

Oil and Gas Drilling Activities

     Ocean’s oil and gas exploratory and developmental drilling activities are as follows for the periods indicated. A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil or gas. The term “gross wells” means the total number of wells in which Ocean owns an interest, while the term “net wells” means the sum of the fractional working interests Ocean owns in gross wells. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

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Ocean Energy, Inc.

	Year Ended December 31,
	2002				2001				2000
	Gross		Net		Gross		Net		Gross		Net
Domestic:
Exploratory Drilling:
Productive Wells		14		5		21		7		19		8
Dry Holes		11		5		12		5		25		10
Development Drilling:
Productive Wells		137		77		213		81		165		90
Dry Holes		29		23		26		17		26		21
Equatorial Guinea:
Exploratory Drilling:
Productive Wells		--		--		--		--		--		--
Dry Holes		1		1		3		1		--		--
Development Drilling:
Productive Wells		8		2		6		1		4		1
Dry Holes		--		--		--		--		--		--
Egypt:
Exploratory Drilling:
Productive Wells		--		--		2		1		--		--
Dry Holes		2		1		--		--		3		1
Development Drilling:
Productive Wells		3		1		2		1		6		2
Dry Holes		1		1		--		--		--		--
Côte d’Ivoire:
Exploratory Drilling:
Productive Wells		--		--		--		--		--		--
Dry Holes		--		--		--		--		--		--
Development Drilling:
Productive Wells		--		--		--		--		1		--
Dry Holes		--		--		--		--		--		--
Other International:
Exploratory Drilling:
Productive Wells		2		1		1		1		2		1
Dry Holes		1		--		1		--		3		3
Development Drilling:
Productive Wells		29		14		28		14		33		16
Dry Holes		--		--		--		--		--		--
Total:
Exploratory Drilling:
Productive Wells		16		6		24		8		21		9
Dry Holes		15		7		16		7		31		14
Development Drilling:
Productive Wells		177		94		249		97		209		109
Dry Holes		30		24		26		17		26		21

     The Company had 36 gross (16 net) exploratory wells and 72 gross (37 net) development wells in progress at December 31, 2002. Wells classified as “in progress” at year–end represent wells where drilling activity is ongoing, wells awaiting installation of permanent equipment and wells awaiting the drilling of additional delineation wells.

12

Ocean Energy, Inc.

     The following table sets forth information regarding the number of productive wells in which the Company held a working interest at December 31, 2002. Productive wells are either producing wells or wells capable of commercial production although currently shut–in. One or more completions in the same borehole are counted as one well.

	Gross Wells								Net Wells
							Multiple								Mutiple
	Oil		Gas		Total		Completions		Oil		Gas		Total		Completions
Domestic:
Gulf of Mexico		272		161		433		20		175		59		234		58
North America
Onshore		213		3,311		3,524		103		100		2,007		2,107		64
International:
Equatorial Guinea		37		--		37		--		9		--		9		--
Egypt		70		--		70		16		28		--		28		4
Côte d’Ivoire		13		4		17		2		6		2		8		1
Other International		292		--		292		--		149		--		149		--
		897		3,476		4,373		141		467		2,068		2,535		127

Developed and Undeveloped Oil and Gas Acreage

     As of December 31, 2002, the Company owned working interests in the following developed and undeveloped oil and gas acreage (amounts in thousands):

	Developed				Undeveloped(1)				Total
	Gross		Net		Gross		Net		Gross		Net
Domestic:
Gulf of Mexico Deepwater		58		17		2,016		843		2,074		860
Gulf of Mexico Shelf		384		188		191		119		575		307
North America Onshore		977		587		1,644		542		2,621		1,129
International:
Equatorial Guinea		36		9		1,838		538		1,874		547
Egypt		117		39		3,679		1,977		3,796		2,016
Côte d’Ivoire		313		244		--		--		313		244
Angola		--		--		2,676		978		2,676		978
Brazil		--		--		1,178		458		1,178		458
Russia		39		18		--		--		39		18
Total		1,924		1,102		13,222		5,455		15,146		6,557

⁽¹⁾ Excludes an interest in 1,194,000 gross (239,000 net) acres in Angola Block 19 which was relinquished in early 2003 and 1,485,000 gross (1,262,000 net) acres in the Makran Central block in Pakistan which was assigned in early 2003.

     Additionally, as of December 31, 2002, the Company owned mineral and/or royalty interests in 185,445 gross (1,750 net) developed acres and 3.4 million gross (39,832 net) undeveloped acres in other international locations.

     For additional information relating to oil and gas producing activities, see Notes 19 and 20 to the Consolidated Financial Statements.

13

Ocean Energy, Inc.

U.S. Regulation

     The availability of a ready market for oil and natural gas production depends upon numerous regulatory factors beyond the Company’s control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control and state limits on allowable rates of production by a well or proration unit. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment.

     Regulation of Oil and Natural Gas Exploration and Production. Exploration and production operations of the Company are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The Company’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production requirements regarding the ratability of production.

     Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale of natural gas in U.S. interstate commerce has been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the Federal Energy Regulatory Commission ("FERC"). The FERC regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or NGA, and the Natural Gas Policy Act of 1978, or NGPA. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

     Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales.

     Commencing in April 1992, the FERC issued Order Nos. 636 and subsequent orders in the same proceeding (collectively "Order No. 636"), which require interstate pipelines to provide transportation services separate, or "unbundled," from the pipelines’ sales of gas. Also, Order No. 636 requires pipelines to provide open access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although the FERC continues to review and modify their open access regulations. These initiatives may affect the intrastate transportation of gas under certain circumstances.

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Ocean Energy, Inc.

     In particular, the FERC is conducting a broad review of their transportation regulations, including how they operate in conjunction with state proposals for retail gas market restructuring, whether to eliminate cost–of–service rates for short–term transportation, whether to allocate all short–term capacity on the basis of competitive auctions, and whether changes to long–term transportation policies may also be appropriate to avoid a market bias toward short–term contracts. In February 2000, the FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to "fine tune" the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Among other things, Order No. 637 revised FERC pricing policy by waiving price ceilings for short–term released capacity for a two–year period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting. The U.S. Court of Appeals for the District of Columbia Circuit recently issued a decision that either upheld or declared premature for review most major aspects of Order No. 637. Order No. 637 required interstate natural gas pipelines to implement the policies mandated by the order through individual compliance filings. The FERC has now ruled on a number of the individual compliance filings, although its decisions in such proceedings remain subject to the outcome of pending rehearing requests and possible court appeals. We cannot predict whether and to what extent FERC’s market reforms will survive judicial review and, if so, whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.

     The Outer Continental Shelf Lands Act (“OCSLA”) requires that all pipelines operating on or across the Outer Continental Shelf (“OCS”) provide open–access, non–discriminatory transportation service on their systems. Commencing in April 2000, FERC issued Order Nos. 639 and 639–A (collectively, "Order No. 639"), which required “gas service providers” operating on the OCS to make public their rates, terms and conditions of service. The purpose of Order No. 639 was to provide regulators and other interested parties with sufficient information to detect and to remedy discriminatory conduct by such service providers. In a recent decision, the U.S. District Court for the District of Columbia permanently enjoined the FERC from enforcing Order No. 639, on the basis that the FERC did not possess the requisite rule–making authority under the OCSLA for issuing Order No. 639. FERC’s appeal of the court’s decision is pending in the U.S. Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of this appeal, nor can we predict what further action FERC will take with respect to this matter.

     On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No. RM01–10. The proposed rules would expand FERC’s current standards of conduct to include a regulated transmission provider and all of its energy affiliates. It is not known whether FERC will issue a final rule in this docket and, if it does, whether the final rule would impact our operations.

     Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

     Offshore Leasing. U.S. offshore operations the Company conducts are on federal oil and gas leases. Ocean must comply with regulatory restrictions from numerous agencies, including the U.S. Minerals Management Service (“MMS”), U.S. Bureau of Land Management, U.S. Coast Guard and U.S. Environmental Protection Agency. For offshore operations, the Company must obtain regulatory

15

Ocean Energy, Inc.

approval for exploration, development and production plans prior to the commencement of such operations. These agencies have stringent engineering and construction specifications, safety–related regulations concerning the design and operating procedures for offshore production platforms and pipelines, regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization, regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities and other rules and regulations governing many phases of offshore operations. To cover the various obligations of lessees, governmental agencies generally require substantial bonds or other acceptable assurances that such obligations will be met.

     The restructuring of oil and gas markets has resulted in a shifting of markets downstream from the wells. Deregulation has altered the marketplace such that lessors, including the MMS, are challenging the methods of valuation of production for royalty purposes. In addition, the MMS is conducting an inquiry into certain contract settlement agreements from which producers on MMS leases have received settlement proceeds that are royalty bearing and the extent to which producers have paid the appropriate royalties on those proceeds.

     The MMS issued a final rule that amended its regulations governing the valuation of crude oil produced from federal leases. This rule, which became effective June 1, 2000, provides that the MMS will collect royalties based on the market value of oil produced from federal leases. The lawfulness of the new rule has been challenged in federal court. We cannot predict whether this new rule will be upheld in federal court, nor can we predict whether the MMS will take further action on this matter. However, we do not believe that this new rule will affect us any differently than other producers and marketers of crude oil.

Competition and Significant Customers

     The Company’s competitors in oil and gas exploration, development and production include major oil companies, as well as numerous independent oil and gas companies, individuals and drilling partnerships. Some of these competitors have financial and personnel resources substantially in excess of those available to the Company and, therefore, the Company may be placed at a competitive disadvantage. The Company’s success in discovering reserves will depend on its ability to select suitable prospects for future exploration in today’s competitive environment. For further discussion of the Company’s customers and markets see Note 2 to the Consolidated Financial Statements.

     Duke Energy Trading & Marketing and affiliates (“DETM”), a wholly–owned subsidiary of Duke Energy Corp., and ExxonMobil Sales and Supply (“EMSS”), a wholly–owned subsidiary of ExxonMobil Corporation, accounted for significant portions of the Company’s total oil and gas production revenues during 2002, 2001 and 2000 as follows:

	Year Ended December 31,
		2002		2001		2000
Percentage of total oil and gas production
revenues purchased by:
Duke Energy Trading & Marketing		27	%	42	%	44	%
ExxonMobil Sales and Supply		24	%	19	%	20	%

16

Ocean Energy, Inc.

Because a ready market exists for the Company’s oil and gas production, the Company does not believe the loss of any individual customer would have a material adverse effect on its financial position or results of operations.

Environmental Matters

     Ocean’s operations are subject to federal, foreign, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or production commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas, restrict the rate of oil and gas production, require remedial actions to prevent pollution from former operations and impose substantial liabilities for pollution resulting from the Company’s operations. In addition, these laws and regulations may impose substantial liabilities and penalties for the Company’s failure to comply with them or for any contamination resulting from the Company’s operations.

     The Company has established policies and procedures for continuing compliance with environmental laws and regulations. However, the Company does not believe costs relating to these laws and regulations have had a material adverse effect on the Company’s operations or financial condition in the past. As these laws and regulations are becoming more stringent and complex, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact in the future. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations. It is likely that the costs of compliance with environmental laws and regulations could increase the cost of operating drilling equipment or significantly limit drilling and operation or production activities.

     The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by the OPA. In addition OPA regulations require parties responsible for offshore facilities to provide financial assurance in the amount of $35 million to cover potential OPA liabilities. This amount can be increased up to $150 million in certain limited circumstances. OPA regulations also require the development and implementation of oil spill response plans. The Company believes it is in substantial compliance with OPA requirements.

17

Ocean Energy, Inc.

Risk Factors

     In addition to the other information in this document, investors in our common stock should consider carefully the following risks.

     Ocean’s Pending Merger with Devon. Ocean’s pending merger with Devon, described above under “Business—Recent Developments”, is subject to a number of closing conditions and may not be consummated. The merger agreement requires, among other things, adoption of the merger agreement by Ocean’s stockholders and approval by Devon’s stockholders of the issuance of shares of Devon common stock to Ocean’s stockholders pursuant to the merger agreement. The merger agreement also requires termination or expiration of the waiting period under the Hart–Scott–Rodino Antitrust Improvements Act of 1976.

     Even if the merger is consummated, Ocean stockholders may not realize the anticipated benefits expected to result from the combination. To be successful following the merger, management of the combined company will need to combine and integrate the operations of Ocean and Devon into one company. Because of the size, complexity and diverse asset base of each company, integration will be a difficult process that will require substantial management attention that could detract attention from the day–to–day business of the combined company. If Ocean and Devon cannot be integrated successfully, some of the expected benefits of the merger, including expected cost savings, may not be realized. Moreover, any difficulties associated with the transition and integration process could have an adverse effect on the revenue, level of expenses and operating results of the combined company. In addition, the combined company may not realize the accretion to various financial measurements that Ocean expects to result from the merger. Finally, the combined company’s debt level is expected to be significant and will be higher than Ocean’s debt level on a stand–alone basis.

18

Ocean Energy, Inc.

     Dependence on Oil and Gas Prices. Ocean’s success will depend on the market prices of oil and gas. These market prices tend to fluctuate significantly in response to factors beyond the Company’s control. The prices the Company receives for its crude oil production are based on global market conditions. The continued threat of war in the Middle East, the continuing economic crisis in Venezuela (a major oil exporter), and actions of OPEC and its maintenance of production constraints, as well as other economic, political, and environmental factors will continue to affect world supply. Natural gas prices fluctuate significantly in response to numerous factors including the U.S. economic environment, North American weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.

     The year 2002 began with lower commodity prices as a result of the global economic downturn and decreases in demand. During 2002, crude oil prices increased due to a combination of factors including fears of war in Iraq (and the resulting impact on the Middle East), Venezuelan strikes that reduced oil exports, and continued OPEC production discipline. Natural gas prices also increased throughout 2002 as U.S. productive capacity declined and as demand increased in the fourth quarter with below–normal temperatures. Commodity prices ended the year at their highest levels and have remained strong in 2003. The Company expects that commodity prices will continue to fluctuate significantly in the future.

     Changes in commodity prices significantly affect the Company’s capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non–cash charges to earnings due to a ceiling test writedown under the full cost method of accounting which the Company uses to account for its exploration and development activities. The Company uses derivative financial instruments to hedge its exposure to price risk from changing commodity prices and the Company has hedged a substantial portion of its anticipated production for 2003.

     Significant Capital Requirements. Ocean must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and gas reserves. Historically, we have paid for these expenditures with cash from operating activities, proceeds from debt and equity financings and asset sales. Ocean’s revenues or cash flows could be reduced because of lower oil and gas prices or for other reasons. If Ocean’s revenues or cash flows decrease, we may not have the funds available to replace our reserves or to maintain production at current levels. If this occurs, our production will decline over time. Other sources of financing may not be available if Ocean’s cash flows from operations are not sufficient to fund its capital expenditure requirements. Where Ocean is not the majority owner or operator of an oil and gas project, it may have no control over the timing or amount of capital expenditures associated with the particular project. If Ocean cannot fund its capital expenditures, its interests in some projects may be reduced or forfeited.

     Our Oil and Gas Reserve Information Is Estimated. The proved oil and gas reserve information included in this document represents estimates. These estimates are based primarily on reports prepared by internal reserve engineers and were calculated using oil and gas prices as of December 31, 2002. These prices could change. An independent petroleum engineering firm annually reviews at least 80% of the Company’s estimates of proved reserves. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

19

Ocean Energy, Inc.

• historical production from the area compared with production from other similar producing areas;
• the assumed effects of regulations by governmental agencies;
• assumptions concerning future oil and gas prices; and
• assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

     Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:

• the quantities of oil and gas that are ultimately recovered;
• the production and operating costs incurred;
• the amount and timing of future development expenditures; and
• future oil and gas sales prices.

     Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Ocean’s actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this document should not be considered as the current market value of the estimated oil and gas reserves attributable to Ocean’s properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

• the amount and timing of actual production;
• supply and demand for oil and gas;
• increases or decreases in consumption; and
• changes in governmental regulations or taxation.

     In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

     Ocean Operates in Foreign Countries and Will Be Subject to Political, Economic and Other Uncertainties. Ocean conducts significant operations in foreign countries including Equatorial Guinea, Côte d’Ivoire and Egypt. As of December 31, 2002, 34% of the Company’s reserves were located in foreign countries. Ocean may also expand its foreign operations in the future. Operations in foreign countries are subject to political, economic and other uncertainties, including:

• the risk of war, acts of terrorism, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, import, export and transportation regulations and tariffs;

20

Ocean Energy, Inc.

• taxation policies, including royalty and tax increases and retroactive tax claims;
• exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over Ocean's international operations;
• laws and policies of the U.S. affecting foreign trade, taxation and investment; and
• the possibility of having to be subject to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States.

     Foreign countries have occasionally asserted rights to land, including oil and gas properties, through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to Ocean by another country, Ocean’s interests could be lost or decreased in value. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might assume a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign–owned assets. This could adversely affect Ocean’s interests. The Company seeks to manage these risks by, among other things, concentrating its international exploration efforts in areas where the Company believes that the existing government is favorably disposed towards United States exploration and production companies. The Company maintains insurance against certain political uncertainties. However, the occurrence of an event that is not fully covered by insurance could have a material adverse effect on the financial position and results of operations of Ocean.

     Oil and Gas Operations Involve Substantial Costs and Are Subject to Various Economic Risks. The oil and gas operations of Ocean are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause Ocean’s exploration, development and production activities to be unsuccessful. This could result in a total loss of Ocean’s investment in a particular property. If exploration efforts in a country are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs would be charged against earnings as impairments. In addition, the cost and timing of drilling, completing and operating wells is often uncertain.

     Drilling Oil and Gas Wells Could Involve Blowouts, Environmental Hazards and Other Risks. The nature of the oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to Ocean. In addition, Ocean may be liable for environmental damages associated with Ocean’s historical activities at sites no longer owned or operated by Ocean, and third-party activities at sites currently owned or operated by Ocean. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of Ocean’s properties. Additionally, some of Ocean’s oil and gas operations are located in areas that are subject to tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. In accordance with customary industry practices, Ocean maintains insurance against some, but not all, of such risks and losses. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on the financial position and results of operations of Ocean.

21

Ocean Energy, Inc.

     Competition Within the Oil and Gas Industry is Intense. The exploration and production business is highly competitive. Many of Ocean’s competitors have substantially larger financial resources, staffs and facilities than Ocean. These competitors include other independent oil and gas producers such as Anadarko Petroleum Corporation, Apache Corporation, Burlington Resources Inc., Devon Energy Corporation, EOG Resources, Inc., Kerr–McGee Corporation, Noble Energy, Inc., Pioneer Natural Resources Company, and Unocal Corporation as well as major oil and gas companies such as ExxonMobil Corporation, ChevronTexaco Corporation, Shell Oil Company and BP Corporation.

     Government Agencies Can Increase Costs and Can Terminate or Suspend Operations. Ocean’s business is subject to foreign, federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Many of these laws and regulations have become stricter in recent years. These laws and regulations often impose greater liability on a larger number of potentially responsible parties. Under some circumstances, the U.S. Minerals Management Service may require the operations of Ocean on federal leases to be suspended or terminated. These circumstances include Ocean’s failure to pay royalties, Ocean’s failure to comply with safety and environmental regulations and the MMS’ reaction to political pressure to limit offshore drilling in environmentally sensitive areas. This could have a material adverse effect on Ocean’s financial condition and operations. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations. It is likely that the costs of compliance could increase the cost of operating offshore drilling equipment or significantly limit drilling activity.

     Terrorist Attacks or Similar Hostilities May Adversely Impact Our Results of Operations. The impact that future terrorist attacks or regional hostilities (particularly in the Middle East) may have on the energy industry in general, and on us in particular, is not known at the time. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. Moreover, we have incurred additional costs since the terrorist attacks of September 11, 2001 to safeguard certain of our assets and we may be required to incur significant additional costs in the future.

     The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to such attacks have made certain types of insurance more difficult for us to obtain. There can be no assurance that insurance will be available to us without significant additional costs. A lower level of economic activity could also result in a decline in energy consumption which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

Employees

     As of February 28, 2003, the Company had approximately 948 employees. In addition to the services of its full time employees, the Company contracts, as needed, the services of consulting geologists, engineers, regulatory consultants, contract pumpers and certain other temporary employees. Except for local national employees in Côte d’Ivoire, none of the Company’s employees are represented by a labor union. The Company considers its relations with its employees to be satisfactory.

22

Ocean Energy, Inc.

Executive Officers of the Company

     The executive officers of the Company, each of who has been elected to serve until his successor is elected and qualified, are as follows:

Name Age Present Position and Prior Business Experience

James T. Hackett* 49 President and Chief Executive Officer since March 1999 and Chairman of the Board since January 2000; President and Chief Executive Officer of Seagull from September 1998 and Chairman of the Board of Seagull from January 1999 to March 1999; Group President of Duke Energy's unregulated operations and Executive Vice President of PanEnergy from January 1996 to September 1998.

Robert K. Reeves* 45 Executive Vice President, General Counsel and Secretary since March 1999; Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. (a predecessor entity) from June 1997 to March 1999; Senior Vice President, General Counsel and Secretary of Ocean Energy, Inc. (a predecessor entity) from May 1994 to June 1997.

John D. Schiller, Jr.* 43 Executive Vice President, Exploration & Production since March 2002; Executive Vice President, Operations from March 2000 to March 2002, Senior Vice President, North America Onshore and International Operations from March 1999 to March 2000; Senior Vice President, Operations of Seagull from September 1998 to March 1999; Production Manager - Gulf Coast Division of Burlington Resources from October 1997 to August 1998; Engineering Manager - Offshore Division of Burlington Resources from April 1994 to September 1997.

William L. Transier* 48 Executive Vice President and Chief Financial Officer since March 1999; Executive Vice President and Chief Financial Officer of Seagull from September 1998 to March 1999; Senior Vice President and Chief Financial Officer of Seagull from May 1996 to September 1998; For the previous 20 years, he held a variety of positions at KPMG LLP including partner from July 1986 until April 1996.

John H. Campbell, Jr. 45 Senior Vice President, North American Onshore Operations since February 2003; Vice President Exploitation North America Onshore from April 1999 to January 2003; Vice President and Chief Engineer, Seagull Energy Corporation, from October 1998 to March 1999; Regional Deepwater and Acquisitions Engineer, Burlington Resources Offshore Division, from June 1997 to September 1998; Regional Engineer, Burlington Resources Offshore Division from May 1994 to May 1997.

William S. Flores, Jr. 46 Senior Vice President, Drilling since March 1999; Vice President, Drilling of Ocean Energy, Inc. (a predecessor entity) from March 1998 to March 1999; Vice President, Operations of Ocean Energy, Inc. (a predecessor entity) from August 1993 to March 1998.

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Ocean Energy, Inc.

Name Age Present Position and Prior Business Experience

Scott A. Griffiths 48 Senior Vice President, Exploration & International New Ventures since March 2002; Senior Vice President, International Exploration from March 1999 to March 2002; Senior Vice President Domestic Exploration of Seagull from September 1998 to March 1999; Vice President Domestic Exploration of Seagull from May 1997 to September 1998; Vice President of Domestic Exploration of Seagull from October 1996 to May 1997; Vice President of Exploration of Global Natural Resources from 1992 to October 1996.

K. Earl Reynolds 42 Senior Vice President, International and Gulf of Mexico Operations since February 2003; Senior Vice President, International Operations from March 2000 to February 2003; General Manger and Director Burlington Resources from January 1998 to March 2000.

Bruce Busmire 45 Vice President, Investor Relations since February 2000; Controller of Altura Energy Ltd. from March 1997 to January 2000; For the previous 16 years, Mr. Busmire held a variety of positions in finance, accounting and investor relations at Amoco Corporation.

Mario M. Coll, III 41 Vice President, Operational Planning and Chief Information Officer since March 2001; Vice President, Operational Planning from March 1999 to March 2001; Vice President, Planning - Corporate and International of Ocean Energy, Inc. (a predecessor entity) from April 1998 to March 1999; Business Planning Coordinator of Ocean Energy, Inc. (a predecessor entity) from September 1996 to April 1998.

Peggy T. d'Hemecourt 51 Vice President, Human Resources since March 1999; Director, Human Resources of Ocean Energy, Inc. (a predecessor entity) from March 1998 to February 1999; Vice President, Human Resources of UMC Petroleum Corporation from April 1997 to February 1998; Director, Human Resources of United Meridian Corporation ("UMC") from January 1996 to March 1997.

Philip J. Iracane 48 Vice President, Marketing since December 2000; Vice President, Sales and Services, Columbia Gas of Virginia from December 1998 to December 2000; For the previous 11 years, Mr. Iracane was Sr. Vice President, Marketing–East Coast of Coastal Gas Marketing.

John J. Patton 62 Vice President and Associate General Counsel, since September 1999; Vice President and Assistant General Counsel – International of Ocean Energy, Inc. (a predecessor entity) from March 1998 to March 1999; Senior Vice President and General Counsel of UMC from April 1995 to March 1998.

Andrew J. Sheu 40 Vice President, Tax since March 1999; Assistant Vice President, Tax of Seagull from January 1998 to March 1999; Director, Tax of Torch Energy Advisors, Inc. from December 1995 to January 1998.

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Ocean Energy, Inc.

Name Age Present Position and Prior Business Experience

Alan L. Smith 40 Vice President, Business Development since March 2001; Manager, Anadarko Asset Team/NA Onshore Business Development December 1999 to March 2001; Vice President Acquisitions, XPLOR Energy from November 1998 to December 1999 and Vice President Operations March 1997 to November 1998; Prior to XPLOR, Mr. Smith held positions at Vastar Resources, Burlington Resources and Ryder Scott.

Winston M. Talbert* 40 Vice President – Finance & Treasurer since October 2002;Vice President and Treasurer since July 2001; Assistant Treasurer, Corporate Finance from October 1999 to July 2001; Assistant Treasurer of PennzEnergy Company from November 1998 to October 1999; Manager, International Finance of Pennzoil Company from December 1996 to November 1998.

Robert L. Thompson* 56 Vice President and Controller since January 2001; Senior Consultant with Cambridge Energy Research Associates from January 2000 to January 2001; Member of merger transition team of Kerr McGee Corp. from February 1999 to December 1999; Vice President, Planning and Controller of Oryx Energy Company ("Oryx") from September 1997 to February 1999; Comptroller and Corporate Planning Director of Oryx from January 1995 to September 1997.

Cathy L. Tompkins 41 Vice President, Information Technology since December 2002; Director Information Technology from November 1999 to December 2002; Director Information Technology of Total Safety, Inc. from September 1999 to November 1999; Information Technology Manager of Ocean Energy, Inc. (a predecessor entity) from May 1998 to May 1999; Manager of Applications of UMC Petroleum from March 1997 to May 1998.

Carl E. Volke 59 Vice President, Administration since March 1999; Vice President, Administration of Seagull from November 1996 to March 1999; Director, Administration of Seagull from November 1986 to November 1996.

Janice Aston White 50 Vice President, Corporate Communications since December 2000; Director, Corporate Communications of Ocean from November 1999 to November 2000; Owner and President of Acclaim Communications from January 1997 to November 1999; Director of Corporate Communications of Tenneco Energy from February 1990 to December 1996.

Frank D. Willoughby 37 Vice President, Financial Planning since March 1999; Prior to March 1999, Mr. Willoughby held various financial positions with Ocean Energy, Inc. (a predecessor entity), including Treasurer and Controller.

*  Denotes persons deemed “officers” for purposes of Section 16 of the Securities Exchange Act of 1934. Other persons listed are not deemed “officers” for that purpose.

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Ocean Energy, Inc.

Defined Terms

     Oil, condensate and natural gas liquids (“NGL”) are stated in barrels (“Bbl”) or thousand barrels (“MBbl”). Natural gas is stated herein in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil, condensate and NGL are converted to gas at a ratio of one barrel of liquids per six Mcf of gas. MMBOE, MBOE and BOE represent one million barrels, one thousand barrels and one barrel of oil equivalent, respectively, with six Mcf of gas converted to one barrel of liquid. “MMBtu” represents one million British Thermal Units. Bcfe represents one billion cubic feet of gas equivalent. “Net” acres, production or wells refers to the total acres, production or wells in which the Company has a working interest, multiplied by the percentage working interest owned by the Company.

Item 2.   Properties

     Incorporated herein by reference to Item 1 of this Annual Report on Form 10–K.

Item 3.   Legal Proceedings

     The Company is a named defendant in lawsuits and is a party in governmental proceedings from time to time arising in the ordinary course of business. While the outcome of such lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position or results of operations of the Company.

     A lawsuit captioned Breakwater Partners, LP v. James T. Hackett, et. al. (Case No. 2003–10161) was filed on February 27, 2003 in the District Court of Harris County, Texas, naming as defendants Ocean and all of the members of Ocean’s board of directors. The complaint generally alleges that:

• the 0.414 exchange ratio is inadequate and unfair to Ocean common stockholders; and
• the defendants breached their fiduciary duties to Ocean stockholders, including the duty of care and the duty of loyalty, or aided and abetted in the breach of those fiduciary duties, by, among other things, (1) failing to conduct a “full and fair auction process or active market check;” (2) agreeing to the terms of the merger agreement, including a non-solicitation provision and the termination fee that is payable by Ocean to Devon under certain circumstances; (3) failing to make an informed decision; (4) failing to ensure that conflicts of interest are resolved in the best interests of Ocean’s public stockholders; (5) personally benefiting from the merger; and (6) not appointing “any truly independent person or entity” to negotiate on behalf of Ocean stockholders.

The complaint seeks class action status. It also seeks (1) injunctive relief against completing the merger or, if the merger is completed, rescission of the merger; (2) monetary damages in an unspecified amount; and (3) recovery of the plaintiff’s costs and attorneys’ fees. Ocean believes that the lawsuit is without merit and intends to defend against it vigorously. We can provide no assurance that additional claims may not be made or filed the substance of which is similar to the allegations described above or that otherwise might arise from, or in connection with, the merger agreement and related transactions. See Note 18 to the Company’s Consolidated Financial Statements.

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Ocean Energy, Inc.

Item 4.   Submission of Matters to a Vote of Security Holders

     None during the fourth quarter of 2002.

Part II

Item 5.   Market for Registrant’s Common Stock and Related Stockholder Matters

A. The Company’s Common Stock (the “Common Stock”) is traded on the New York Stock Exchange under the ticker symbol “OEI.” The high and low sales prices on the New York Stock Exchange Composite Tape for each quarterly period during the last two fiscal years for the registrant were as follows:

	2002						2001
	High			Low			High			Low
First Quarter	$	19	.90	$	16	.20	$	21	.60	$	15	.31
Second Quarter		22	.62		18	.93		20	.50		15	.40
Third Quarter		22	.15		16	.68		20	.73		14	.52
Fourth Quarter		21	.00		17	.51		19	.81		15	.60

B. As of February 28, 2003, there were approximately 2,806 holders of record of Common Stock.

C. Since January 2001, the Company has paid quarterly dividends of $0.04 per share on its Common Stock. The amount of future dividends will be determined on a quarterly basis at the discretion of the Company’s board of directors, and will depend on earnings, financial condition, capital requirements and other factors. The Company did not declare any cash dividends on its Common Stock during the first three quarters of 2000 or in 1999 or 1998. The Company’s revolving credit agreement and outstanding indentures restrict the Company’s declaration or payment of dividends on and repurchases of Common Stock. Under the most restrictive of these tests, as of December 31, 2002, approximately $519 million was available for payment of dividends or repurchase of Common Stock. In addition, the terms of the Company’s Series B Convertible Preferred Stock and certain debt securities limit the Company’s ability to pay cash dividends.

     D.      Equity Compensation Plans

            The table below provides information relating to the Company’s equity compensation plans as of December 31, 2002:

						Number of securities
						remaining available
	Number of securities					for future issuance
	to be issued		Weighted–average			under compensation plans
	upon exercise of		exercise price of			(excluding
	outstanding options,		outsanding options,			securities reflected
Plan Category	warrants and rights		warrants and rights			in first column)
Equity compensation plans
approved by security holders		8,947,657	$	16	.29		3,486,279
Equity compensation plans
not approved by security holders		9,307,926		12	.79		2,859,300
Total		18,255,583	$	14	.51		6,345,579

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Ocean Energy, Inc.

Item 6.   Selected Financial Data

Selected Financial Data⁽¹⁾
(Amounts in Thousands Except Per Share Data)

	Year Ended December 31,
		2002		2001		2000		1999			1998
Revenues	$	1,162,083	$	1,255,466	$	1,073,554	$	757,565		$	535,871
Net income (loss) from continuing
operations(2)		135,175		273,782		213,203		(21,552	)		(406,879	)
Earnings (loss) from continuing
operations per share (2):
Basic		0.76		1.59		1.26		(0.16	)		(4.04	)
Diluted		0.74		1.53		1.22		(0.16	)		(4.04	)
Cash dividends declared on
common stock (per share)		0.16		0.16		0.04		--			--
Net cash provided by operating
activities before changes in
operating assets and
liabilities		722,159		824,285		694,310		336,148			219,075
Net cash provided by operating
activities		613,402		860,802		585,706		333,751			229,924
Total assets		3,893,396		3,469,178		2,890,400		2,783,143			2,006,960
Long–term debt		1,442,790		1,282,981		1,032,564		1,333,410			1,371,890
Stockholders’ equity		1,574,709		1,472,436		1,152,688		947,695			376,943
Capital expenditures		769,135		876,946		577,518		369,026			961,979
Acquisitions, net of cash acquired		5,881		305,227		5,598		991,409			--
Standardized measure of
discounted future
net cash flows		4,708,492		2,768,888		5,846,993		2,415,418			903,823

⁽¹⁾ Includes the effect of the Company’s merger with Seagull Energy Company since March 30, 1999.

⁽²⁾ Includes after–tax impairments of $50 million, $13 million, $43 million and $335 million in 2002, 2000, 1999 and 1998, respectively, and after–tax merger and integration costs of $2 million, $31 million and $33 million in 2000, 1999 and 1998, respectively.

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Ocean Energy, Inc.

Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

     Ocean Energy, Inc. (the “Company,” “OEI” or “Ocean”) is an independent energy company engaged in the exploration, development, production and acquisition of crude oil and natural gas. North American operations are focused in the shelf and deepwater areas of the Gulf of Mexico, the Rocky Mountains, Permian Basin, Anadarko, East Texas, North Louisiana and the Gulf Coast regions. Internationally, Ocean holds a leading position among U.S. independents in West Africa with oil and gas activities in Equatorial Guinea, Angola, Nigeria and Côte d’Ivoire. The Company also conducts operations in Egypt, the Russian Republic of Tatarstan, Brazil and Indonesia.

     On February 23, 2003, Ocean entered into an Agreement and Plan of Merger under the terms of which Ocean would merge into a subsidiary of Devon Energy Corporation ("Devon"). Under the terms of the agreement, Ocean stockholders will receive 0.414 share of Devon common stock for each Ocean common share. The proposed merger is subject to approval by the stockholders of each company as well as other customary closing conditions and is expected to be completed mid–year 2003. The discussions included in this Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Item 7.a Quantitative and Qualitative Disclosures About Market Risks do not reflect the effect the proposed merger would have on Ocean.

     The Company’s accompanying Consolidated Financial Statements contain detailed information that should be referred to in conjunction with the following discussion.

Corporate Governance

     Ocean supports the recent initiatives by the United States Congress, the Securities and Exchange Commission and the New York Stock Exchange to restore investor confidence and to ensure the credibility and transparency of financial reporting. Ocean has been built on a culture where integrity is the first and most important value, and this value has long been a part of the Company’s corporate values. Ocean has endeavored to maintain best practices in the area of corporate governance including having an independent majority of the Board of Directors, with only independent members serving on the Audit, Governance and Nominating and Organization and Compensation committees; board governance guidelines and charters for all committees; a business conduct policy; independent auditors; and an internal audit function.

     Recently the Company has enhanced its corporate governance by adopting a new Code of Business Conduct and Ethics that includes adopting a new Code of Ethics for Senior Financial Officers; adopting new Corporate Governance Guidelines; amending and restating its committee charters for the Audit, the Governance and Nominating and the Compensation and Benefits Committees of the Board of Directors, forming a Disclosure Committee of senior management to assist the Company’s certifying officers in fulfilling their responsibility for oversight of the accuracy and timeliness of the disclosures made by the Company. The Company has also taken steps to ensure that the Company’s independent auditors do not perform prohibited non–audit services and, therefore, are able to maintain their independence.

     The Board of Directors has also adopted a standard of independence and evaluated each director in light of this standard. The Board has concluded that it has three non–independent directors and ten independent directors. The Company will continue to have solely independent directors on each of its Audit Committee, Governance and Nominating Committee and Organization and Compensation

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Ocean Energy, Inc.

Committees. The Board’s non–management directors will regularly meet in executive session. The Company will continue to enhance its governance practices as new ideas and best practices emerge.

Results of Operations

     In 2002, the Company reduced its capital expenditure budget as a result of the lower commodity price environment that existed at the beginning of the year. Company plans were to fund development commitments generated by earlier exploration successes while maintaining balance sheet strength. The Company was successful in this regard. At the same time, reduced capital spending, lower commodity prices, adverse weather and installation delays in the Gulf of Mexico led to some mixed operating results. Production growth was lower than expected at the start of 2002. Reserve replacement and the current year finding and development cost were below the Company’s targets. With rising commodity prices and new production, the Company ended 2002 with a strong fourth quarter.

     The Company reached a milestone in its deepwater strategy with the installation and start up of its first Gulf of Mexico deepwater development in the Nansen and Boomvang fields. There was further exploitation success in the Zafiro field in Equatorial Guinea and the Company continued to expand its exploration activities in the deepwater Gulf of Mexico region, West Africa and other international locations.

     Results for 2002 can be summarized as follows:

• 3% year–over–year and 9% fourth quarter over prior–year quarter production increase
• refinanced fixed–rate debt to achieve lower cost of capital
• maintenance of 48% debt to total capitalization ratio
• 34% reduction in capital expenditures to accommodate lower commodity prices
• 111% reserve replacement rate
• $12.11 per BOE finding and development cost.

     The Company reported net income of $135 million, or $0.74 per diluted share for 2002 compared to net income of $274 million, or $1.53 per diluted share for 2001. For fourth quarter 2002, the Company reported net income of $67 million, or $0.37 per diluted share, as compared to $21 million, or $0.12 per diluted share, for fourth quarter 2001.

     Two special items affected this year’s results. First, the Company announced that it would discontinue exploratory activities in the Arabian Sea offshore Pakistan and on Block 19 in the Lower Congo Basin offshore Angola. As a result, the Company recognized an impairment in the amount of $76 million ($50 million, after tax). Second, the Company repurchased $202 million of fixed–rate debt, resulting in a loss on the early extinguishment of debt of $12 million ($8 million, after tax).

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Ocean Energy, Inc.

Oil and Gas Operations
(Amounts in Thousands)

	Year Ended December 31,
		2002			2001			2000
Oil and Gas Operations:
Revenues:
Crude oil	$	661,701		$	556,331		$	547,137
Natural gas		500,382			699,135			526,417
		1,162,083			1,255,466			1,073,554
Operating expenses		312,191			286,737			239,237
Depreciation, depletion and amortization		357,745			344,342			304,976
Impairment of oil and gas properties		76,400			--			20,066
Operating profit		415,747			624,387			509,275
Corporate		(76,270	)		(57,412	)		(52,715	)
Total Operating Profit	$	339,477		$	566,975		$	456,560

     Revenues – Ocean operates in highly competitive markets where energy prices fluctuate significantly. As oil and gas prices fluctuate, so do the Company’s revenues, results of operations and cash flows. The year began with lower commodity prices as a result of the global economic downturn and decreases in demand. These conditions were only partially offset by OPEC’s supply constraints. During 2002, crude oil prices increased due to a combination of factors including fears of war in Iraq, Venezuelan strikes that reduced oil exports and continued OPEC production discipline. Natural gas prices rose throughout 2002 as U.S. productive capacity declined. Demand for natural gas increased in the fourth quarter with below–normal temperatures. Commodity prices ended the year at their highest levels and have remained strong in 2003. High oil prices also support natural gas prices by not competing as effectively as a substitute fuel source.

     Oil Revenues – For 2002, revenues from sales of crude oil totaled $662 million, an increase of $106 million, or 19%, compared to revenues of $556 million for 2001. The change in revenues included:

• An increase in revenues of $26 million due to a 4% increase in the average realized price for crude oil, excluding the impact of financial derivatives, to $22.32 per Bbl for 2002 from $21.48 per Bbl for 2001.
• An increase in revenues of $55 million due to a 9% increase in production. Average daily oil production was 82 MBbl per day for 2002 as compared to 75 MBbl per day for 2001. Higher production volumes were primarily attributable to new deepwater production in the Gulf of Mexico and continued success with Zafiro field exploitation initiatives in Equatorial Guinea.
• A positive year–over–year net change of $25 million relating to the Company’s use of crude oil derivative financial instruments. The effect of derivative financial instruments on oil revenues was a decrease of $9 million for 2002 as compared to a decrease of $34 million for 2001.

     For 2001, revenues from sales of crude oil totaled $556 million, an increase of $9 million, or 2%, compared to revenues of $547 million for 2000. The change in revenues included:

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Ocean Energy, Inc.

• A decrease in revenues of $111 million due to a 16% decline in the average realized price for crude oil, excluding the impact of financial derivatives, to $21.48 per Bbl for 2001 from $25.51 per Bbl for 2000.
• An increase in revenues of $70 million due to a 10% increase in production. Average daily oil production was 75 MBbl for 2001 as compared to 68 MBbl for 2000. Higher production volumes were primarily attributable to increased exploration and exploitation success from the Gulf of Mexico shelf properties and the Zafiro field in Equatorial Guinea.
• A positive year–over–year net change of $50 million relating to the Company’s use of crude oil derivative financial instruments. The effect of derivative financial instruments on oil revenues was a decrease of $34 million for 2001 as compared to a decrease of $84 million for 2000.

     Oil prices were on a steady upward trend through 2002. The Company expects that future crude oil prices will fluctuate significantly. The continued threat of war in the Middle East, the continuing economic crisis in Venezuela (a major oil exporter), and actions of OPEC and its maintenance of production constraints, as well as other economic, political and environmental factors will continue to affect world supply.

     Gas Revenues – For 2002, revenues from sales of natural gas totaled $500 million, a decrease of $199 million, or 28%, compared to revenues of $699 million for 2001. The change in revenues included:

• A decrease in revenues of $155 million due to a 24% decline in the average realized price for natural gas, excluding the impact of financial derivatives, to $3.19 per Mcf for 2002 from $4.18 per Mcf for 2001.
• A decrease in revenues of $26 million due to a 4% decline in production. Average daily gas production was 426 MMcf for 2002 as compared to 443 MMcf for 2001.
• A negative year–over–year net change of $18 million related to the Company’s use of natural gas derivative financial instruments. The effect of derivative financial instruments on gas revenues was an increase of $5 million for 2002 as compared to an increase of $23 million for 2001.

     For 2001, revenues from sales of natural gas totaled $699 million, an increase of $173 million, or 33%, compared to revenues of $526 million for 2000. The change in revenues included:

• An increase in revenues of $53 million due to a 9% increase in the average realized price for natural gas, excluding the impact of financial derivatives, to $4.18 per Mcf for 2001 compared to $3.85 per Mcf for 2000.
• An increase in revenues of $51 million due to a 9% increase in production. Average daily gas production was 443 MMcf for 2001 as compared to 407 MMcf for 2000. Higher production volumes were primarily attributable to successful results from U.S. drilling activities and acquisitions of producing properties in Texas and Louisiana during 2001.
• A positive year–over–year net change of $69 million relating to the Company’s use of natural gas derivative financial instruments. The effect of derivative financial instruments on gas revenues was an increase of $23 million for 2001 as compared to a decrease of $46 million for 2000.

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Ocean Energy, Inc.

     Natural gas prices fluctuate significantly in response to numerous factors. Since most of Ocean’s gas reserves and production are in the United States, future natural gas prices will be dependent primarily on the U.S. economic environment, North American weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on natural gas supply and the environmental and access issues that limit future drilling activities for the industry.

Operating Data (*)

	Year Ended December 31,
		2002		2001		2000
Net Daily Oil and NGL Production (Bbl):
Domestic		31,355		27,864		27,254
Equatorial Guinea		33,025		30,442		22,798
Egypt		9,396		8,557		8,820
Other International		8,524		8,479		8,755
Total		82,300		75,342		67,627
Average Oil and NGL Prices ($ per Bbl):
Domestic	$	22.79	$	22.70	$	25.85
Equatorial Guinea	$	23.10	$	21.17	$	26.06
Egypt	$	22.85	$	22.18	$	26.61
Other International	$	17.01	$	17.88	$	21.90
Weighted Average	$	22.32	$	21.48	$	25.51
Average Oil and NGL Prices Including the
Impact of Financial Derivatives ($ per Bbl)	$	22.03	$	20.23	$	22.11
Net Daily Natural Gas Production (Mcf):
Domestic		396,904		416,265		373,560
International		28,965		26,533		33,006
Total		425,869		442,798		406,566
Average Natural Gas Prices ($ per Mcf):
Domestic	$	3.20	$	4.26	$	3.95
International	$	3.01	$	3.00	$	2.74
Weighted Average	$	3.19	$	4.18	$	3.85
Average Natural Gas Prices Including the
Impact of Financial Derivatives ($ per Mcf)	$	3.22	$	4.33	$	3.54

(*) All price information excludes the impact of financial derivatives, unless otherwise stated.

     Total production for 2002 was 56 MMBOE, a 3% increase over 2001. Average daily production for the full year was 426 MMcf of gas and 82 MBbl of oil, or 153 MBOE per day. For fourth quarter 2002, average daily production was 158 MBOE per day, an increase of 9% over fourth quarter 2001 average daily production of 145 MBOE per day. The Company expects its production to increase during 2003 as a result of increased production from the deepwater Gulf of Mexico and Equatorial Guinea and from Egypt, net of anticipated declines in onshore and Gulf of Mexico shelf areas related to their constrained capital spending in 2002 and asset sales which occurred in late 2002.

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Ocean Energy, Inc.

     Total production for 2001 was 54 MMBOE as compared to 50 MMBOE for 2000. Average daily production for the full year was 443 MMcf of gas and 75 MBbl of oil, or 149 MBOE per day.

     Reclassification of Expenses – The Company expenses employee costs associated with operating and general corporate activities. In prior years, a portion of costs related to certain administrative functions which support the Company’s ongoing operating activities were included in operating expense. During 2002, the Company reclassified costs of certain administrative functions as general and administrative expense. As a result, previous years have been reclassified to conform to current year presentation. While this reclassification had no effect on net income, it did decrease operating expense, and increase general and administrative expense, by $24 million, $20 million and $18 million for the years ended December 31, 2002, 2001 and 2000, respectively.

     Operating Expenses – Total operating expenses increased $25 million, or 9%, to $312 million for 2002 from $287 million for 2001 due to higher transportation expense related to new deepwater Gulf of Mexico production, increased workover and repair expense and higher lease operating expense due to increased production, offset by lower production and ad valorem taxes due to lower natural gas prices.

     Total operating expense per BOE increased 6% to $5.58 per BOE for the year ended December 31, 2002, compared to $5.27 for 2001.

     Total operating expenses increased $48 million, or 20%, to $287 million for the year ended December 31, 2001 from $239 million for 2000 due to increased workover expense; increases in production and ad valorem taxes due to increased production, higher commodity prices and an increase in the production tax rate for the State of Louisiana; and higher lease operating expense due to the 10% increase in production.

     Operating expenses per BOE increased 9% to $5.27 per BOE for the year ended December 31, 2001, compared to $4.83 for 2000.

     Depreciation, Depletion and Amortization Expense – Total depreciation, depletion and amortization (“DD&A”) expense for oil and gas operations increased $14 million, or 4%, to $358 million for 2002 from $344 million for 2001 due to increased production and increased rates from higher estimated future development costs. DD&A expense per BOE related to oil and gas operations increased 1% to $6.39 per BOE for 2002 as compared to $6.33 per BOE for 2001 primarily due to higher estimated future development costs and 2002 finding and development cost of $12.11 per BOE.

     Total DD&A expense for oil and gas operations increased $39 million to $344 million for the year ended December 31, 2001, from $305 million for 2000 primarily due to increased production. DD&A expense per BOE related to oil and gas operations rose 3% to $6.33 per BOE for the year ended December 31, 2001, from $6.15 per BOE for 2000 primarily due to the effects of property acquisitions, higher estimated future development costs and the geographic mix of production.

     Impairment of Oil and Gas Properties – During 2002, the Company announced that it would discontinue current exploratory activities in Pakistan and on Block 19 offshore Angola. As a result, the Company recognized an impairment in the amount of $76 million. During 2000, the Company recognized an impairment in the amount of $20 million related to the discontinuance of exploration activities in the Republic of Yemen. The Company recognized no impairments during 2001 and had no ceiling test limitations in 2002, 2001 or 2000.

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Ocean Energy, Inc.

Corporate

     Corporate expenditures are comprised of general and administrative expenses and the DD&A expense for non–oil and gas assets.

     General and Administrative Expenses – General and administrative expenses increased $13 million, or 25%, to $64 million for the year ended December 31, 2002, compared to $51 million for 2001. This increase was due primarily to increases in insurance cost, occupancy cost, transportation and certain employee-related costs. On a per BOE basis, general and administrative expenses rose to $1.14 per BOE for 2002 from $0.94 per BOE for 2001.

     General and administrative expenses increased $5 million, or 11%, to $51 million for the year ended December 31, 2001, compared to $46 million for 2000. This increase was due primarily to increases in employee–related costs. On a per BOE basis, general and administrative expenses rose to $0.94 per BOE for 2001 from $0.93 per BOE for 2000.

     The Company capitalizes certain employee–related costs that are directly attributable to oil and gas operations. The Company capitalized costs of $61 million, $58 million and $45 million in 2002, 2001 and 2000, respectively. The increases are related to the Company’s expanding activities in deepwater Gulf of Mexico and to new cost centers in Angola and Brazil.

     DD&A – DD&A expense for non–oil and gas assets was approximately $12 million, $6 million and $6 million for the years 2002, 2001 and 2000, respectively. The increase in 2002 was due to an increase in corporate assets.

Other

     Interest Expense – Interest expense decreased $2 million, or 3%, to $61 million for the year ended December 31, 2002, from $63 million in 2001. Interest expense for 2002 was reduced as a result of lower average borrowing rates achieved on the Company’s outstanding debt. Borrowing rates were reduced due to refinancings of fixed–rate debt during 2002 and 2001 and a lower average rate applicable to the Company’s credit facility. In addition, the effect of interest rate swaps relating to the Company’s 7 5/8% and 7 7/8% senior notes was a reduction in interest expense of $7 million in 2002 compared to $3 million in 2001. The interest savings was offset by a $1 million reduction in the amount of interest capitalized ($44 million during 2002 compared to $45 million during 2001) and by an increase in the total debt balance.

     Interest expense decreased $12 million, or 16%, to $63 million for the year ended December 31, 2001, from $75 million in 2000. This decrease was primarily the result of lower average borrowing rates achieved on the Company’s outstanding debt due to a refinancing of fixed–rate debt and to a lower average rate applicable to the Company’s credit facility during 2001. In addition, the interest rate swaps described above reduced interest expense by approximately $3 million in 2001.

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Ocean Energy, Inc.

     The Company capitalized interest expense of $44 million, $45 million and $44 million in 2002, 2001 and 2000, respectively. The amount of interest expense capitalized is generally a function of the Company’s average interest cost and level of capital expenditures.

     Early Extinguishment of Debt – During 2002, the Company repurchased $175 million of its 8 7/8% senior subordinated notes due July 2007 and $27 million of its 8 3/8% senior subordinated notes due July 2008. In connection with these repurchases, the Company recorded other expense of $12 million and a related tax benefit of $4 million.

     During 2001, the Company retired existing higher interest–rate debt by exercising call provisions for $100 million of its 8 5/8% senior subordinated notes due 2005 and $2 million of its 9 3/4% senior subordinated notes due 2006. The Company also repurchased $22 million of its 8 3/8% senior subordinated notes due July 2008 and $25 million of its 8 7/8% senior subordinated notes due July 2007. The repurchase of these notes was funded with available cash balances and borrowings under the Company’s existing credit facility. In connection with these repurchases, the Company recorded other expense of $6 million and a related tax benefit of $2 million.

     The Company reported losses on early extinguishment of debt as extraordinary items until fourth quarter 2002. During fourth quarter 2002, the Company early adopted certain provisions of Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections ("SFAS No. 145"). With the adoption of SFAS No. 145, the classification of losses associated with extinguishments of debt, that were previously recorded as extraordinary items, were reclassified into other expense with the related tax benefit reclassified into income tax expense.

     Merger and Integration Costs – Merger and integration costs of $3 million associated with the merger of Ocean and Seagull Energy Corporation were recorded in the first quarter of 2000 and related primarily to severance costs.

     Income Tax Expense – Income tax expense of $130 million relating to continuing operations was recognized for the year ended December 31, 2002, compared to expense of $224 million for the year ended December 31, 2001. The effective income tax rate was 49% for 2002 and 45% for 2001. The increase in effective income tax rate for 2002 was primarily due to the effect of the international impairments as the tax benefit resulting from the impairments was calculated at a lower incremental tax rate.

     Income tax expense of $224 million was recognized for the year ended December 31, 2001, compared to expense of $165 million for the year ended December 31, 2000. Total income tax expense increased primarily due to higher revenues and operating profit recognized in 2001. The effective income tax rate was 45% for 2001 and 44% for 2000.

     Dividends – Quarterly stock dividends, which were first declared in December 2000, continued for each quarter of 2002 and 2001. The Company paid cash dividends on common stock totaling approximately $28 million and $27 million during 2002 and 2001, respectively. The amount of future dividends for OEI common stock will be determined on a quarterly basis and will depend on earnings, financial condition, capital requirements and other factors.

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Ocean Energy, Inc.

     Preferred Dividends – The Company pays quarterly dividends on its preferred stock. The preferred stock has a 6.5% cumulative dividend.

Liquidity and Capital Resources

     Liquidity – The Company’s primary sources of liquidity are its cash on hand, cash flows from operations and available borrowing capacity under its credit facility. The Company made significant progress during 2002 in improving liquidity, primarily by expanding its borrowing capacity and reducing costs of capital. Ocean continued to take advantage of the positive interest–rate environment and improve its credit position by repurchasing higher fixed–rate debt and replacing it with lower–cost debt. In addition, a new credit facility, with an extended term, will provide increased flexibility to the Company.

     The Company successfully maintained its balance sheet leverage during 2002. The debt to total capitalization ratio was 48% at December 31, 2002 compared to 47% at December 31, 2001. Although the balance sheet reflects a $160 million increase in debt at year–end 2002 compared to year–end 2001, this increase is partially offset by a $66 million increase in the year–end cash balance.

     New Revolving Credit Facility – During 2002, the Company was able to extend by two years and double the amount of its credit facility. The new credit facility provides for $1 billion in borrowing capacity and has a maturity date of May 2006. The credit facility replaced the Company’s previous $500 million facility which was scheduled to mature in March 2004. As of December 31, 2002, the Company’s outstanding borrowings under the credit facility were zero, and letters of credit totaled $28 million, leaving $972 million of available borrowing capacity under the Company’s credit facility. The Company’s obligations under the credit facility are unsecured and guaranteed by Ocean Energy, Inc., a Louisiana corporation. The credit facility bears interest, at the Company’s option, at LIBOR or prime rates plus applicable margins ranging from zero to 1.7% or at a competitive bid. The average interest rate on the facilities was 3% during 2002.

     Debt Issuances and Repurchases – The Company took advantage of current low interest rates to refinance a significant portion of its debt during 2002 by issuing $400 million of 4 3/8% senior notes due October 2007. The proceeds were used to repay amounts outstanding under the credit facility which included balances used to retire debt earlier in the year when the Company exercised call provisions for $175 million of its 8 7/8% senior subordinated notes due July 2007. In addition, the Company purchased $27 million of its 8 3/8% senior subordinated notes due July 2008. The 4 3/8% notes are redeemable at any time at the Company’s option and, upon certain changes in control, the notes would be subject to a mandatory repurchase offer.

     During 2001, the Company issued $350 million of 7 1/4% senior notes due October 2011. A portion of the proceeds was used to repay amounts outstanding under the Company’s credit facility, and the remainder of the proceeds was used to retire existing higher interest rate debt by exercising call provisions for $100 million of 8 5/8% senior subordinated notes due 2005 and $2 million of 9 3/4% senior subordinated notes due 2006. Also during 2001, the Company repurchased on the open market $22 million of its 8 3/8% senior subordinated notes due July 2008 and $25 million of its 8 7/8% senior subordinated notes due July 2007. The repurchase of these notes was funded with available cash balances and borrowings under the Company’s existing credit facility. The 7 1/4% notes are redeemable at any time at the Company’s option and, upon certain changes in control, the notes would be subject to a mandatory repurchase option.

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Ocean Energy, Inc.

     The Company’s 7 7/8% senior notes, in the amount of $100 million, are due in August 2003. The Company has established the necessary credit capacity, through its credit facility, to refinance the 7 7/8% senior notes and it is the Company’s current intention to refinance these obligations on a long–term basis. The Company’s 8 3/8% senior subordinated notes due July 2008 are redeemable at a premium beginning in July 2003. The Company may choose to call these notes if market conditions warrant.

     Asset Sales – During 2002, the Company closed the sale of selected royalty, overriding royalty and mineral interests in various locations throughout the United States and two packages of non–core working interests. Total net proceeds from the sales provided additional cash flow of $74 million to the Company. The Company received $64 million in proceeds from the sales of certain non-core properties during 2001.

     Operating Leases – During 2002, the Company leased two spars that are being used in the development of the Nansen and Boomvang fields in the Gulf of Mexico. The operating leases extend for 20 years and contain various options whereby the Company may purchase the lessors’ interests in the spars. Future cash payments under the operating leases total $9 million, $11 million, $15 million, $15 million and $15 million for the years 2003, 2004, 2005, 2006 and 2007, respectively, and $258 million total for all years thereafter. The Company has guaranteed that the spars will have residual values to the lessors at the end of the operating leases equal to at least 10% of the fair market value of the spars at the inception of the leases. The total guaranteed value is $20 million in 2022 for the spars and the amount may be reduced under the terms of the lease agreements.

     Prepaid Commodity Transactions – In 1999 and 2000, the Company entered into two standard prepaid commodity transactions, one for crude oil in 1999 and one for natural gas in 2000. The prepaid crude oil sales contract provides that the Company deliver approximately 5.6 MBbl per day of crude oil for the period February 2000 through May 2003. In exchange for the crude oil to be provided, the Company received an advance payment of approximately $100 million. The prepaid natural gas sales contract is a market–sensitive contract which, as amended, provides that the Company deliver 53,500 MMBtu per day of natural gas for 2003 and 55,600 MMBtu per day for 2004. In exchange for the natural gas to be provided, the Company received an advance payment of approximately $75 million.

     The obligations associated with the future delivery of the crude oil and natural gas have been recorded as deferred revenue in the Company’s accompanying Consolidated Balance Sheets, and the remaining unamortized balance was approximately $87 million as of December 31, 2002. The prepaid proceeds were shown as a component of cash flows from financing activities in the Company’s Consolidated Statements of Cash Flows in the years in which they were received. The prepaid proceeds are being amortized into revenue as scheduled deliveries of crude oil and natural gas are made. This amortization is deducted from net income when computing Net Cash Provided by Operating Activities in the Company’s Consolidated Statements of Cash Flows as scheduled delivery occurs.

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Ocean Energy, Inc.

     Financing Transaction – During 2000, the Company conveyed certain Internal Revenue Code Section 29 tax credit–bearing properties to a trust for approximately $70 million, which was recorded in other noncurrent liabilities. The trust receives the operating cash flow from the properties until the investor recoups its investment plus a required after–tax rate of return. At December 31, 2002, payout is estimated to occur during second quarter 2009. The transaction is determined to have an embedded derivative financial instrument as described in Note 12 to the Company’s Consolidated Financial Statements.

Capital Expenditures
(Amounts in Thousands)

	Year Ended December 31,
		2002		2001		2000
Leasehold acquisitions	$	68,383	$	93,468	$	62,350
Exploration costs		256,304		352,952		202,860
Development costs		424,331		411,624		300,247
Acquisitions		5,881		305,227		5,598
Total oil and gas capital expenditures		754,899		1,163,271		571,055
Corporate and other capital expenditures		20,117		18,902		12,061
Total capital expenditures	$	775,016	$	1,182,173	$	583,116

     The reduced capital expenditure program in 2002 compared to 2001 reflected a desire to manage expenditures in relation to expected cash flows from operations and to maintain the debt to total capital ratio at a time when the Company was operating in an environment of lower commodity prices and economic recession. During 2002, a greater portion of the capital expenditure budget was used to fund deepwater development projects resulting from three prior years of exploratory success, and exploration spending was reduced by $97 million.

     The Company had a reserve replacement of 111% for 2002 compared to 387% for 2001 and a finding and development cost of $12.11 per BOE for 2002 compared to $5.52 for 2001 reflecting the higher level of development expenditures and the reduced exploratory investment. Ocean’s total estimated proved reserves declined 1% to 593 MMBOE as of December 31, 2002, from 601 MMBOE at year–end 2001. This amount includes the effect of approximately 14 MMBOE in divestitures during the year. The Company’s estimated three–year average reserve replacement rate now stands at 254%, and its three–year average finding and development cost is $6.12 per BOE. Finding and development costs and reserve replacement results are expected to be variable in an exploration–oriented company and long–term averages are a better measure of value creation than just twelve month results.

     During 2002, oil and gas expenditures, excluding acquisitions, totaled $509 million for domestic operations and $240 million for international operations and the Company completed a total of 238 gross wells (131 net wells), with an 81% success rate. Of the 238 gross wells completed, 31 were exploratory wells and 207 were development wells. The success rate for exploratory wells was 52%.

     During 2001, oil and gas expenditures, excluding acquisitions, totaled $634 million for domestic operations and $224 million for international operations and the Company completed a total of 315 gross wells (129 net wells), with an 87% success rate. Of the 315 gross wells completed, 40 were exploratory wells and 275 were development wells. The success rate for exploratory wells was 60%.

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Ocean Energy, Inc.

     Acquisitions in 2001 totaled $305 million and included the purchase of all outstanding shares of stock of Texoil, Inc., an independent oil and gas company. The Company also purchased oil and gas assets located primarily in East Texas and North Louisiana from EnSight Resources, L.L.C. for a cash purchase price of approximately $118 million. In addition, the Company recognized a deferred tax liability of approximately $50 million due to the excess of book over tax basis of the oil and gas properties acquired in the purchase of Texoil.

     2003 Capital Expenditure Budget – The Company’s capital expenditure budget for the year 2003 is approximately $1 billion, a 30% increase over 2002, and in 2003 the Company anticipates returning to the level of exploration spending it had in 2001. In addition, a significant portion of the 2003 capital program is dedicated to development of the Company’s exploration successes in West Africa and the deepwater Gulf of Mexico.

     On a geographic basis, over half of the projected 2003 capital spending budget will be directed toward Gulf of Mexico activities, with 75% of that amount focused on deepwater activities. Approximately 30% to 40% will be targeted to international assets with the remainder funding domestic onshore exploration and exploitation.

     In the Gulf of Mexico, the Company plans to spend approximately $500 to $550 million. The majority of these funds will be used to develop recent deepwater discoveries and grow the Company’s reserve base through additional deepwater exploration in addition to ongoing activities on the shelf. Some $275 million will fund development drilling, completions and construction activities at the Red Hawk, Magnolia and Zia deepwater discoveries and further development activities in the Nansen and Boomvang deepwater fields. The Company anticipates drilling six deepwater exploration prospects, four of which will be Ocean–operated. These include Yorktown in Mississippi Canyon Block 841, Shiner in Garden Banks Block 656, Tuscany in Desoto Canyon Block 179 and Aztec in Keathley Canyon Block 196 (50% WI).

     The Company has allocated approximately $300 to $400 million to international operations. Nearly half of the expenditures will be directed toward activities in Equatorial Guinea where development will continue in the southern expansion area of the Zafiro field. The Company has planned a full–year, three–rig drilling and completion program on Block B in preparation for the start of production in fall 2003 from the Serpentina FPSO, a floating production, storage and offloading vessel. In Angola, the Company is currently planning to drill the first exploratory well on the Ocean–operated Block 10, and two exploratory wells are budgeted on Block 24. Also in Africa, the Company expects to install a new platform and drill a development well on its East Zeit concession in the Gulf of Suez offshore Egypt. Plans also include additional drilling in Russia, continued exploratory activities in Brazil and funding of Nigerian Block 256 and initial exploratory activities there.

     The Company has allocated approximately $100 to $150 million to exploitation and exploration of its domestic onshore properties. In the Rockies, Ocean plans to drill approximately 100 development wells in its Bear Paw field in north central Montana. The majority of the remaining onshore budget will focus on activities to develop gas production in the Anadarko, East Texas, South Texas and Permian Basin regions.

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Ocean Energy, Inc.

     Actual capital spending may vary and is subject to change if market conditions shift or new opportunities are identified. The 2003 capital expenditure budget was developed using certain assumed price levels for the sales of crude oil and natural gas and forecasted production growth. Changes in commodity prices or variances from forecasted production growth could impact the Company’s cash flows from operations and funds available for reinvestment. For example, shortfalls in budgeted cash flows from operations could result in the reduction of the Company’s capital spending program, increases in borrowing under the credit facility, issuance of additional equity or debt securities or divestments of properties. The Company will evaluate its level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions. In general, the Company’s strategy is to maintain capital spending, excluding acquisitions and/or divestments, at levels near discretionary cash flows (cash flows from operations before changes in working capital).

     The Company makes, and will continue to make, substantial capital expenditures for the acquisition, exploration, development and production of oil and gas reserves. The Company has historically funded its expenditures from cash flows from operating activities, bank borrowings, sales of equity and debt securities, sales of non-strategic oil and gas properties, sales of partial interests in exploration concessions and project finance borrowings. The Company intends to finance capital expenditures for the year 2003 primarily with cash flows from operations and intends to balance the demand for capital from exploration and development programs with maintenance of a strong balance sheet. As discussed below, the Company has engaged in hedging activities to reduce the risk from fluctuations in commodity prices on its 2003 capital expenditure program.

     The ability of the Company to satisfy its obligations and fund planned capital expenditures will be dependent upon its future performance. Such future performance is subject to many conditions that are beyond the Company’s control, particularly oil and gas prices, and the Company’s ability to obtain additional debt and equity financing, if necessary. In addition, where the Company is not the majority owner and/or operator of the venture, it may have less control over the timing or amount of capital expenditures associated with the particular project. The Company currently expects that its cash flows from operations and availability under the credit facility will be adequate to execute its business plan for the year 2003. No assurance can be given that the Company will not experience liquidity problems from time to time or on a long–term basis. If the Company’s cash flows from operations and availability under the credit facility are not sufficient to satisfy its cash requirements, there can be no assurance that additional debt or equity financing will be available to meet its requirements.

     Commodity Pricing – Changes in commodity prices significantly affect the Company’s capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. The prices the Company receives for its crude oil production are based on global market conditions. The prices the Company receives for its natural gas production are primarily driven by North American market forces. Oil and gas prices have fluctuated significantly in recent years in response to numerous economic, political and environmental factors. The year 2002 began with a weakened commodity environment and lower prices. However, prices were on an upward trend through the year. Prices are also affected by weather, factors of supply and demand, and commodity inventory levels. The Company expects that commodity prices will continue to fluctuate significantly in the future.

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Ocean Energy, Inc.

     The Company has utilized and expects to continue to utilize derivative financial instruments with respect to a portion of its oil and gas production to achieve a more predictable cash flow by reducing its exposure to price fluctuations. Cash flow hedges are maintained at levels which management considers necessary to manage its cash flow in support of the 2003 capital expenditure budget. As of February 28, 2003, the Company has hedged approximately 86% of total estimated production for March through December of 2003. See Notes 2 and 13 to the Company’s Consolidated Financial Statements.

Disclosures About Contractual Obligations and Commercial Commitments

     The following table sets forth the Company’s obligations and commitments to make future payments under its debt agreements, lease agreements, transportation agreements and other long–term obligations as of December 31, 2002:

	Payments due by Period (in thousands)
Contractual Obligations	Total		1 year		2–3 years		4–5 years		After 5 years
Principal Payments on Long–Term
Debt	$	1,457,000	$	101,000	$	127,000	$	402,000	$	827,000
Interest Payments on Long–Term
Debt		864,000		96,000		177,000		158,000		433,000
Operating Leases:
Office space, equipment, vehicles		26,000		10,000		12,000		4,000		--
Spar operating leases		323,000		9,000		26,000		30,000		258,000
Future Minimum Transportation
Payments		6,000		2,000		2,000		2,000		--
Benefit Plans		20,000		1,000		1,000		1,000		17,000
Total Contractual Cash
Obligations		2,696,000		219,000		345,000		597,000		1,535,000
Other Long–Term Obligations:
Deferred Revenue(1)		87,000		49,000		38,000		--		--
Conveyance of Sec 29 Properties(2)		41,000		8,000		14,000		11,000		8,000
Total Contractual Obligations	$	2,824,000	$	276,000	$	397,000	$	608,000	$	1,543,000

⁽¹⁾ Represents amortization of forward sales as product is delivered.
⁽²⁾ Represents estimates of proceeds from related trust properties as payments for obligation.

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Ocean Energy, Inc.

	Amount of Commitment Expiration Per Period (in thousands)
Other	Total
Commercial	Amounts				2–3		4–5		After 5
Commitments	Committed		1 Year		Years		Years		Years
Standby Letters of Credit	$	28,000	$	26,000	$	2,000	$	--	$	--
Guarantees		5,000		1,000		2,000		2,000		--
Total Commercial
Commitments	$	33,000	$	27,000	$	4,000	$	2,000	$	--

     Under the terms of certain joint venture agreements, international production sharing contracts or concession agreements, the Company has commitments to conduct seismic activity or to participate in other exploratory or development activities. Certain agreements are backed by letters of credit or parent company guarantees.

     Under certain conditions relating to a change of control, the Company’s long–term debt may be subject to a mandatory repurchase offer. In addition, under the terms of the Nansen and Boomvang Operating Leases, the Company would be required to provide letters of credit or other comparable credit support up to a maximum amount (approximately $43 million under the Nansen Operating Lease and approximately $15 million under the Boomvang Operating Lease at December 31, 2002) if the Company’s senior debt credit rating were to be downgraded below investment grade by both Moody’s and Standard & Poor’s.

Critical Accounting Policies

     Application of generally accepted accounting principles requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. In addition, alternatives can exist among various accounting methods. In such cases, the choice of accounting method can also have a significant impact on reported amounts. The following is a discussion of the Company’s critical accounting policies which management believes affect its more significant judgments and estimates used in the preparation of its Consolidated Financial Statements.

     Full Cost Method of Accounting for Oil and Gas Properties – The Company’s exploration and production activities are accounted for using the full cost method. Under the full cost method all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized. The Company believes that the full cost method is the most appropriate method to use to account for its oil and gas production activities. The Company is conducting significant exploration programs in the Gulf of Mexico and in certain international regions. The full cost method more appropriately treats the costs of entering these ventures as part of an overall investment in discovering and developing proved reserves and allows for comparable analysis with our peers. Application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs, lower exploration costs and higher DD&A rates than application of the successful efforts method of accounting.

     Reserves – Estimates of the Company’s proved oil and gas reserves are prepared by the Company’s engineers in accordance with guidelines established by the SEC. Those guidelines require that reserve estimates be prepared under existing economic and operating conditions with no provisions for increases in commodity prices except by contractual arrangement and assuming continuation of existing operating conditions. Estimation of oil and gas reserve quantities is inherently difficult and is subject to numerous uncertainties. Such uncertainties include the projection of future rates of production and the timing of development expenditures. The accuracy of the estimates depends on the quality of available geological and geophysical data and requires interpretation and judgment. Estimates may be revised either upward or downward by results of future drilling, production or well performance. The Company’s estimates of its reserves are expected to change as additional information becomes available. Each year an independent petroleum engineering firm reviews at least 80% of the Company’s year–end estimates of proved reserves.

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Ocean Energy, Inc.

     In general, estimates of volumes considered to be commercially recoverable increase with increases in commodity prices. However, the terms of certain international production sharing contracts (PSCs) create an inverse relationship between commodity prices and reserve quantities. When commodity prices increase, the amount of reserves necessary to recoup expenditures through the cost recovery mechanism inherent in these PSCs is reduced, resulting in lower proved reserves.

     The estimates of proved oil and gas reserves have a significant effect on the Company’s depreciation, depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the Company’s DD&A rate increases and therefore net income is reduced.

     Full Cost Ceiling Calculation – Where proved reserves are established, capitalized costs are limited on a country–by–country basis (“ceiling limitation”). The amount of capitalized costs in the full cost pools are compared to the present value of future net cash flows, using current unescalated pricing, discounted at 10%, and the lower of cost or fair value of unproved properties (“ceiling test”). If the capitalized cost of the full cost pool exceeds the ceiling limitation, the excess is charged to earnings. The full cost ceiling is primarily impacted by current commodity prices and by reserve estimates. Changes in prices, reserve estimates and future development costs impact the full cost ceiling. The Company performs quarterly ceiling tests. The Company had no ceiling limitations in 2002, 2001 or 2000. The full cost ceiling calculation is more stringent than the impairment test under the successful efforts method of accounting. In a successful efforts impairment test future net cash flows are estimated by applying estimated future oil and gas prices rather than current unescalated prices.

     Impairment of Unproved Oil and Gas Properties – In countries where the existence of proved reserves has not yet been determined, costs incurred during the exploration phase remain capitalized in unproved property cost centers until proved reserves have been established or until exploration activities cease. The Company evaluates these costs periodically to determine whether the value of the exploratory costs incurred have been permanently diminished in part or in whole. Based on the Company’s impairment evaluation and its future exploration plans, the unproved property cost centers related to the area of interest could be impaired, in which case accumulated costs are charged against earnings.

     The Company’s evaluation of these costs, and therefore the amount and timing of any impairment, can be significantly impacted by a number of factors including: the results of exploration activities; availability of funds for future activities; determination of commerciality of reserves based on cash flow forecasts with estimated future commodity prices and operating costs; and the current and projected political climate in the areas in which the Company operates.

     At December 31, 2002, the Company had unproved oil and gas property costs of $81 million in Angola, $37 million in Brazil and $17 million in other international locations. If the Company were to determine that the values of any of these properties had been permanently diminished, there would be a charge against earnings.

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Ocean Energy, Inc.

     Capitalized Interest and Employee Costs – In accordance with the full cost method, the Company capitalizes a portion of interest expense on borrowed funds. Employee–related costs that are directly attributable to exploration and development activities are also capitalized. These costs are considered to be direct costs based on the nature of their function as it relates to the exploration and development activities.

     Derivative Financial Instruments and Hedging Activities – The Company uses derivative financial instruments primarily to hedge its exposure to price risk from changing commodity prices. The Company’s hedging program is a tool the Company uses to manage cash flows in support of its annual capital expenditure budget. The Company does not enter into derivative or other financial instruments for trading purposes. Management exercises significant judgment related to its hedge program in determining the types of instruments to be used, the amount of production volumes to be hedged, the prices at which to hedge and the counterparties and their creditworthiness, all of which is covered by the Company’s hedging policy.

      The Company must estimate the correlation between future changes in the fair value of the derivative instrument and the transaction being hedged, both at inception and on an ongoing basis. Hedge effectiveness is assessed at least quarterly, and any ineffective portion of the derivative instrument’s change in fair value is recognized immediately as an increase or a decrease in revenues.

     For cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction is recognized in earnings. Therefore, prior to settlement of the derivative instruments, changes in the fair market value of these instruments can cause significant increases or decreases in other comprehensive income. The result of the settlement of the hedge is included in income when the forecasted transactions occur.

Environmental

     Compliance with applicable environmental and safety regulations by the Company has not required any significant capital expenditures or materially affected its business or earnings. The Company believes it is in substantial compliance with environmental and safety regulations and foresees no material expenditures in the future; however, the Company is unable to predict the impact that compliance with future regulations may have on its capital expenditures, earnings and competitive position.

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Ocean Energy, Inc.

Forward–Looking Statements May Prove Inaccurate

     This document contains “forward–looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, and information that is based on management’s belief and assumptions made by management based on currently available information. All statements other than statements of historical fact included in this document are forward–looking statements. When used in this document, words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “intend,” “project” and similar expressions serve to identify forward-looking statements. Although we believe that the expectations reflected in our forward–looking statements are reasonable, we can give no assurance that these expectations will prove correct. Our forward–looking statements are subject to risks, uncertainties and assumptions. Should one of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may vary materially from those expected. Among the key factors that may have a direct bearing on our results of operations and financial condition are:

• competitive practices in the oil and gas industry;
• geological, mechanical and economic risk inherent in the drilling and operation of exploratory and development wells;
• risk of impairment of unproved property costs in countries where proved reserves have not yet been established;
• risk of impairment of proved property costs due to declines in prices, downward revisions in reserves or significant increases in finding and development costs;
• volatility of energy commodity prices, generally, and fluctuations in the commodity prices for crude oil and natural gas that have not been properly hedged;
• general economic and capital markets conditions, including fluctuations in interest rates;
• the impact of current and future laws and governmental regulations, particularly environmental regulations, affecting the energy industry in general, and our oil and gas operations in particular;
• environmental liabilities that are not covered by insurance or indemnity;
• the political and economic climate in the foreign or domestic jurisdictions in which we conduct oil and gas operations, including risk of war or potential adverse results of military or terrorist actions in those areas; and
• the effect on our results of operations and financial condition associated with implementing various accounting rules and regulations.

     In addition, this Form 10–K contains forward–looking statements relating to the Company’s proposed merger with Devon. Please read “Risk Factors” for a more complete description of risks relating to the merger and other risks which may cause our forward–looking statements to be inaccurate. The Company undertakes no obligation to publicly update or revise any forward–looking statements.

Defined Terms

     Oil, condensate and natural gas liquids (“NGL”) are stated herein in barrels (“Bbl”) or thousand barrels (“MBbl”). Oil, condensate and NGL are converted to gas at a ratio of one barrel of liquids per six Mcf of gas. Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). MMBOE, MBOE and BOE represent one million barrels, one thousand barrels and one barrel of oil equivalent, respectively, with six Mcf of gas converted to one barrel of liquid. MMBtu and BBtu are one million British Thermal Units and one billion British Thermal Units, respectively.

46

Ocean Energy, Inc.

Selected Quarterly Financial Data

Summarized quarterly financial data is as follows (amounts in thousands except per share data):

	Quarter Ended
	March 31		June 30		September 30			December 31
2002:
Revenues	$	220,329	$	287,989	$	314,353		$	339,412
Operating Profit	$	52,088	$	103,309	$	45,178		$	138,901
Net Income(1)	$	20,467	$	48,483	$	(851	)	$	67,076
Earnings per Share:
Basic(2)	$	0.11	$	0.27	$	(0.01	)	$	0.38
Diluted(2)	$	0.11	$	0.27	$	(0.01	)	$	0.37
2001:
Revenues	$	403,255	$	355,842	$	279,021		$	217,348
Operating Profit	$	240,095	$	175,374	$	100,143		$	51,364
Net Income	$	123,384	$	81,407	$	47,843		$	21,150
Earnings per Share:
Basic(2)	$	0.73	$	0.47	$	0.28		$	0.12
Diluted(2)	$	0.70	$	0.46	$	0.27		$	0.12

⁽¹⁾ Includes pre-tax impairment of oil and gas assets of $76 million in the third quarter of 2002.

⁽²⁾ Quarterly earnings per common share may not total to the full year per share amount, as the weighted average number of shares outstanding for each quarter fluctuated as a result of the assumed exercise of stock options.

Item 7a.   Quantitative and Qualitative Disclosures About Market Risk

Market Risk Disclosures

     The Company experiences market risks in two major areas: commodity prices and interest rates. Because the U.S. dollar is the functional currency for all of the Company’s existing foreign operations, with predominantly all transactions being denominated in U.S. dollars, the Company currently has limited risk from foreign currency translation.

     Commodity Price Risk – The Company experiences market risk primarily in the area of commodity prices. The Company has utilized derivative financial instruments with respect to a portion of its 2002 oil and gas production to achieve a more predictable cash flow by reducing its exposure to price fluctuations. The Company does not enter into derivative or other financial instruments for trading purposes.

     At February 28, 2003, the Company had the following volumes under derivative contracts related to its oil and gas producing activities:

47

Ocean Energy, Inc.

				Weighted
		Instrument	Daily	Average
Production Period	Index	Type	Volumes	Price
Crude Oil:
01/01/03 – 12/31/03	WTI	3–way Collar (1)	43 MBbl	$19.00 – 23.00 – 27.98
01/01/03 – 12/31/03	Dated Brent	3–way Collar(1)	10 MBbl	$19.00 – 23.00 – 27.22
03/01/03 – 12/31/03(2)	Dated Brent	Swap	30 MBbl	$26.88
04/01/03 – 12/31/03(2)	Dated Brent	Swap	5 MBbl	$26.90
Natural Gas:
01/01/03 – 12/31/03	NYMEX	3–way Collar(1)	120,000 MMBtu	$2.50 – 3.50 – 5.00
01/01/03 – 12/31/03	NYMEX	Collar	50,000 MMBtu	$3.75 – 5.26
03/01/03 – 12/31/03(2)	NYMEX	Swap	185,000 MMBtu	$4.86
04/01/03 – 06/30/03	NYMEX	Collar	20,000 MMBtu	$3.75 – 5.06
09/01/03 – 10/31/03	NYMEX	Collar	20,000 MMBtu	$3.75 – 5.23
Gas Swap of
Related Trust:
01/01/03 – 12/31/03	NYMEX	Swap	11,100 MMBtu	$3.60
01/01/04 – 12/31/04	NYMEX	Swap	9,600 MMBtu	$3.41
01/01/05 – 12/31/05	NYMEX	Swap	8,300 MMBtu	$3.28

⁽¹⁾ A "3–way collar" combines a sold call, a purchased put and a sold put. The purchased put and sold put establish a floating minimum price ("floating floor") and the sold call establishes a maximum price ("ceiling price") the Company will receive for the volumes under contract.

⁽²⁾ Contract entered into subsequent to December 31, 2002.

     These instruments have been designated as cash flow hedges. See Notes 2 and 13 to the Company’s Consolidated Financial Statements for a description of the Company’s accounting policies for derivative financial instruments and for additional information regarding the derivative financial instruments to which the Company was a party at December 31, 2002.

     To calculate the potential effect of the derivatives contracts on future revenues, the Company applied the average New York Mercantile Exchange (“NYMEX”) or Brent, as applicable, oil and gas strip prices as of December 31, 2002 to the quantity of the Company’s oil and gas production covered by derivative contracts to which the Company was a party at December 31, 2002. The following table shows the estimated potential effects of the derivative financial instruments on future revenues (in millions):

48

Ocean Energy, Inc.

				Estimated Increase			Estimated Decrease
	Estimated Decrease			(Decrease) in			in Revenues
	In Revenues			Revenues with 10%			with 10%
Instrument	at Current Prices			Decrease in Prices			Increase in Prices
Oil collars	$	(8	)	$	7		$	(32	)
Gas collars	$	(1	)	$	--		$	(7	)
Gas swap of related trust	$	(9	)	$	(4	)	$	(13	)

     All derivative financial instruments outstanding at December 31, 2001, except for the gas swap of a related trust noted above, have expired. The effect of derivative financial instruments outstanding at December 31, 2001 was a $4 million decrease in revenues during 2002.

     Interest Rate Risk – The Company has minimal exposure to risk resulting from changes in interest rates because substantially all debt obligations at December 31, 2002, were at fixed interest rates. At December 31, 2002, the Company had long–term debt outstanding of $1.4 billion. Of this amount 99% is fixed rate debt. As of December 31, 2002, the Company’s outstanding borrowings under the credit facility were zero.

     At December 31, 2002, the Company was party to interest rate swap agreements relating to its 7 5/8% senior notes due July 2005 and its 7 7/8% senior notes due August 2003. Under the terms of the agreements, the counterparties pay the Company a weighted average fixed annual rate of 7.74% on total notional amounts of $225 million, and the Company pays the counterparties a variable annual rate equal to the average six–month LIBOR rate plus a weighted average rate of 2.73%. The swap agreements remain in effect through the maturity dates of the respective notes.

49

Ocean Energy, Inc.

Item 8.   Financial Statements and Supplementary Data

Report of Management to Stockholders

     The management of Ocean Energy, Inc. is responsible for the preparation and integrity of financial statements and related data in this Annual Report, whether audited or unaudited. The financial statements were prepared in conformity with generally accepted accounting principles and include certain estimates and judgments that management believes are reasonable under the circumstances.

     Management is also responsible for and maintains a system of internal accounting controls that is designed to provide reasonable assurance that assets are safeguarded against loss or unauthorized use and that financial records are reliable for preparing financial statements, as well as to prevent and detect fraudulent financial reporting. The internal control system is supported by written policies and procedures and the employment of trained, qualified personnel. The Company has an internal audit function that reviews the adequacy of the internal accounting controls and compliance with them. Management has considered the recommendations of internal audit and KPMG LLP, independent certified public accountants, concerning the Company’s system of internal controls and has responded appropriately to those recommendations.

     KPMG LLP, independent certified public accountants, have audited the accompanying consolidated financial statements of Ocean Energy, Inc. as of December 31, 2002, and their report is included herein. Their audit was made in accordance with generally accepted auditing standards and included a review of the system of internal controls to the extent considered necessary to determine the audit procedures required to support their opinion on the consolidated financial statements.

     The Board of Directors, through its Audit Committee composed exclusively of independent directors, meets periodically with representatives of management, internal audit and the independent auditors to ensure the existence of effective internal accounting controls and that financial information is reported accurately and timely with all appropriate disclosures included. The independent auditors and internal audit have full and free access to, and meet with, the Audit Committee, with and without management present.

/s/ James T. Hackett James T. Hackett	/s/ William L. Transier William L. Transier	/s/ Robert L. Thompson Robert L. Thompson
Chairman of the Board,	Executive Vice President	Vice President and
President and Chief	and Chief Financial Officer	Controller
Executive Officer

January 28, 2003

50

Ocean Energy, Inc.

Independent Auditors’ Report

The Board of Directors and Stockholders
Ocean Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Ocean Energy, Inc. and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the three–year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ocean Energy, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three–year period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative financial instruments.

/s/ KPMG LLP
KPMG LLP

Houston, Texas
January 28, 2003

51

Ocean Energy, Inc.
Consolidated Statements of Operations
(Amounts in Thousands Except Per Share Data)

	Year Ended December 31,
		2002		2001		2000
Revenues	$	1,162,083	$	1,255,466	$	1,073,554
Costs of Operations:
Operating expenses		312,191		286,737		239,237
Depreciation, depletion and amortization		369,997		350,805		311,383
Impairment of oil and gas properties		76,400		--		20,066
General and administrative		64,018		50,949		46,308
		822,606		688,491		616,994
Operating Profit		339,477		566,975		456,560
Other Expense:
Interest expense		60,597		62,707		75,065
Loss on early extinguishment of debt		11,986		6,112		--
Merger and integration costs		--		--		3,273
Other expense		1,800		309		132
Income Before Income Taxes		265,094		497,847		378,090
Income Tax Expense		129,919		224,065		164,887
Net Income		135,175		273,782		213,203
Preferred Stock Dividends		3,250		3,250		3,250
Net Income Available to Common Stockholders	$	131,925	$	270,532	$	209,953
Earnings Per Share:
Basic	$	0.76	$	1.59	$	1.26
Diluted	$	0.74	$	1.53	$	1.22
Cash Dividends Declared Per Common Share	$	0.16	$	0.16	$	0.04
Weighted Average Number of Common Shares Outstanding:
Basic		173,983		170,178		167,144
Diluted		182,030		178,416		174,749

See accompanying Notes to Consolidated Financial Statements.

52

Ocean Energy, Inc.
Consolidated Balance Sheets
(Amounts in Thousands Except Share Data)

	December 31,
		2002			2001
Assets
Current Assets:
Cash and cash equivalents	$	85,850		$	20,006
Accounts receivable, net		211,685			135,204
Other current assets		117,174			99,518
Total Current Assets		414,709			254,728
Property, Plant and Equipment, at cost, full cost method for oil and
gas properties:
Proved oil and gas properties		5,185,023			5,063,614
Oil and gas properties excluded from amortization		752,712			774,888
Other		167,939			172,701
		6,105,674			6,011,203
Accumulated Depreciation, Depletion and Amortization		(2,701,007	)		(2,861,917	)
		3,404,667			3,149,286
Other Assets		74,020			65,164
Total Assets	$	3,893,396		$	3,469,178
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts and notes payable	$	386,038		$	291,174
Accrued interest payable		33,202			39,890
Accrued liabilities		47,210			44,230
Total Current Liabilities		466,450			375,294
Long–Term Debt		1,442,790			1,282,981
Deferred Revenue		86,545			116,294
Deferred Income Taxes		213,963			133,685
Other Noncurrent Liabilities		108,939			88,488
Commitments and Contingencies		--			--
Stockholders’ Equity:
Preferred stock, $1.00 par value; authorized 10,000,000 shares;
issued 50,000 shares		50			50
Common stock, $0.10 par value; authorized 520,000,000 shares;
issued 178,887,756 and 174,936,240 shares, respectively		17,888			17,494
Additional paid–in capital		1,634,038			1,579,899
Retained earnings (deficit)		2,949			(100,832	)
Treasury stock, at cost; 2,562,430 and 2,641,640 shares,
respectively		(35,109	)		(35,654	)
Deferred compensation and other		(14,626	)		(12,540	)
Accumulated other comprehensive income (loss)		(30,481	)		24,019
Total Stockholders’ Equity		1,574,709			1,472,436
Total Liabilities and Stockholders’ Equity	$	3,893,396		$	3,469,178

See accompanying Notes to Consolidated Financial Statements.

53

Ocean Energy, Inc.
Consolidated Statements of Cash Flows
(Amounts in Thousands)

	Year Ended December 31,
		2002			2001			2000
Operating Activities:
Net income	$	135,175		$	273,782		$	213,203
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization		369,997			350,805			311,383
Impairment of oil and gas properties		76,400			--			20,066
Deferred income taxes		105,978			177,007			142,746
Loss on early extinguishment of debt		11,986			6,112			--
Tax benefit from stock option exercises		11,990			15,049			--
Amortization of deferred compensation		8,966			3,380			1,141
Other		1,667			(1,850	)		5,771
Changes in operating assets and liabilities, net of
acquisitions:
Decrease (increase) in accounts receivable		(76,481	)		100,431			(52,443	)
Increase in other current assets and other		(47,277	)		(2,880	)		(24,828	)
Increase (decrease) in accounts payable		34,802			(21,404	)		(272	)
Amortization of deferred revenue		(29,748	)		(29,748	)		(27,269	)
Increase (decrease) in accrued expenses and other		9,947			(9,882	)		(3,792	)
Net Cash Provided by Operating Activities		613,402			860,802			585,706
Investing Activities:
Oil and gas capital expenditures		(749,018	)		(858,044	)		(565,457	)
Acquisition costs, net of cash acquired		(5,881	)		(236,199	)		(5,598	)
Corporate and other capital expenditures		(20,117	)		(18,902	)		(12,061	)
Proceeds from sales of property, plant and equipment		74,192			63,791			86,043
Other		1,189			--			(9,295	)
Net Cash Used in Investing Activities		(699,635	)		(1,049,354	)		(506,368	)
Financing Activities:
Proceeds from debt		1,787,181			2,356,419			1,552,865
Principal payments on debt		(1,621,907	)		(2,162,529	)		(1,805,744	)
Proceeds from issuance of common stock		30,454			36,225			21,355
Dividends paid		(31,240	)		(30,453	)		(3,250	)
Premiums paid on debt buy back		(9,335	)		(4,984	)		--
Purchase of treasury stock		--			(6,671	)		(32,217	)
Increase in deferred revenue		--			--			74,947
Proceeds from conveyance of Section 29 credit properties		--			--			69,644
Other		(3,076	)		(2,488	)		1,212
Net Cash Provided by (Used in) Financing Activities		152,077			185,519			(121,188	)
Increase (Decrease) in Cash and Cash Equivalents		65,844			(3,033	)		(41,850	)
Cash and Cash Equivalents at Beginning of Year		20,006			23,039			64,889
Cash and Cash Equivalents at End of Year	$	85,850		$	20,006		$	23,039

See accompanying Notes to Consolidated Financial Statements.

54

Ocean Energy, Inc.
Consolidated Statements of Stockholders’ Equity
(Amounts in Thousands)

									Retained
						Additional			Earnings
	Preferred		Common			Paid–In			(Accumulated
	Stock		Stock			Capital			Deficit)
Balance, January 1, 2002	$	50	$	17,494		$	1,579,899		$	(100,832	)
Exercise of common stock options and employee
stock purchases		--		332			30,127			--
Treasury stock purchase		--		--			--			--
Deferred compensation		--		63			11,857			--
Amortization of deferred compensation		--		--			--			--
Preferred stock dividends		--		--			--			(3,250	)
Common stock dividends		--		--			--			(28,144	)
Tax benefit from exercise of stock options		--		--			11,990			--
Funding of supplemental benefit plans trust		--		--			362			--
Transfer of supplemental benefit plans trust
obligation		--		--			--			--
Contribution of shares to employee plans		--		--			375			--
Other		--		(1	)		(572	)		--
Comprehensive income:
Net income		--		--			--			135,175
Other comprehensive income (net of tax):
Net effect of derivative financial instruments		--		--			--			--
Other		--		--			--			--
Balance, December 31, 2002	$	50	$	17,888		$	1,634,038		$	2,949
Balance, January 1, 2001	$	50	$	17,007		$	1,517,064		$	(343,962	)
Exercise of common stock options and employee
stock purchases		--		408			32,008			--
Treasury stock purchase		--		--			--			--
Deferred compensation		--		79			13,808			--
Amortization of deferred compensation		--		--			--			--
Preferred stock dividends		--		--			--			(3,250	)
Common stock dividends		--		--			--			(27,402	)
Tax benefit from exercise of stock options		--		--			15,049			--
Funding of supplemental benefit plans trust		--		--			1,582			--
Transfer of supplemental benefit plans trust obligation		--		--			--			--
Other		--		--			388			--
Comprehensive income:
Net income		--		--			--			273,782
Other comprehensive income (net of tax):
Cumulative effect of accounting change for derivative
financial instruments		--		--			--			--
Net effect of derivative financial instruments		--		--			--			--
Other		--		--			--			--
Balance, December 31, 2001	$	50	$	17,494		$	1,579,899		$	(100,832	)
Balance, January 1, 2000	$	50	$	16,699		$	1,484,688		$	(547,216	)
Exercise of common stock options		--		282			24,449			--
Treasury stock purchase		--		--			--			--
Deferred compensation		--		26			2,481			--
Amortization of deferred compensation		--		--			(25	)		--
Preferred stock dividends		--		--			--			(3,250	)
Common stock dividends declared		--		--			--			(6,699	)
Tax benefit from exercise of stock options		--		--			5,622			--
Other		--		--			(151	)		--
Comprehensive income:
Net income		--		--			--			213,203
Balance, December 31, 2000	$	50	$	17,007		$	1,517,064		$	(343,962	)

See accompanying Notes to Consolidated Financial Statements.

55

Ocean Energy, Inc.
Consolidated Statements of Stockholders’ Equity, Continued
(Amounts in Thousands)

							Accumulated
				Deferred			Other			Total
	Treasury			Compensation			Comprehensive			Stockholders’			Comprehensive
	Stock			and Other			Income (Loss)			Equity			Income (Loss)
Balance, January 1, 2002	$	(35,654	)	$	(12,540	)	$	24,019		$	1,472,436
Exercise of common stock options and
employee stock purchases		--			--			--			30,459
Treasury stock purchase		(1,959	)		--			--			(1,959	)
Deferred compensation		162			(12,082	)		--			--
Amortization of deferred compensation		--			8,966			--			8,966
Preferred stock dividends		--			--			--			(3,250	)
Common stock dividends		--			--			--			(28,144	)
Tax benefit from exercise of stock options		--			--			--			11,990
Funding of supplemental benefit plans trust		806			(1,168	)		--			--
Transfer of supplemental benefit plans
trust obligation		--			1,124			--			1,124
Contribution of shares to employee plans		1,527			--			--			1,902
Other		9			1,074			--			510
Comprehensive income:
Net income		--			--			--			135,175		$	135,175
Other comprehensive income (net of tax):
Net effect of derivative
financial instruments		--			--			(53,319	)		(53,319	)		(53,319	)
Other		--			--			(1,181	)		(1,181	)		(1,181	)
Balance, December 31, 2002	$	(35,109	)	$	(14,626	)	$	(30,481	)	$	1,574,709		$	80,675
Balance, January 1, 2001	$	(35,354	)	$	(2,117	)	$	--		$	1,152,688
Exercise of common stock options
and employee stock purchases		--			--			--			32,416
Treasury stock purchase		(6,671	)		--			--			(6,671	)
Deferred compensation		--			(13,887	)		--			--
Amortization of deferred compensation		--			3,380			--			3,380
Preferred stock dividends		--			--			--			(3,250	)
Common stock dividends		--			--			--			(27,402	)
Tax benefit from exercise of stock options		--			--			--			15,049
Funding of supplemental benefit plans trust		6,343			(7,925	)		--			--
Transfer of supplemental benefit plans
trust obligation		--			7,868			--			7,868
Other		28			141			--			557
Comprehensive income:
Net income		--			--			--			273,782		$	273,782
Other comprehensive income (net of tax):
Cumulative effect of accounting change for
derivative financial instruments		--			--			(14,262	)		(14,262	)		(14,262	)
Net effect of derivative financial instruments		--			--			38,701			38,701			38,701
Other		--			--			(420	)		(420	)		(420	)
Balance, December 31, 2001	$	(35,654	)	$	(12,540	)	$	24,019		$	1,472,436		$	297,801
Balance, January 1, 2000	$	(3,114	)	$	(3,412	)	$	--		$	947,695
Exercise of common stock options		--			--			--			24,731
Treasury stock purchase		(32,217	)		--			--			(32,217	)
Deferred compensation		--			(2,507	)		--			--
Amortization of deferred compensation		--			1,141			--			1,116
Preferred stock dividends		--			--			--			(3,250	)
Common stock dividends declared		--			--			--			(6,699	)
Tax benefit from exercise of stock options		--			--			--			5,622
Other		(23	)		2,661			--			2,487
Comprehensive income:
Net income		--			--			--			213,203		$	213,203
Balance, December 31, 2000	$	(35,354	)	$	(2,117	)	$	--		$	1,152,688		$	213,203

See accompanying Notes to Consolidated Financial Statements.

56

Ocean Energy, Inc.
Notes to Consolidated Financial Statements

1.   Organization

     Ocean Energy, Inc. (the “Company,” “OEI” or “Ocean”) is an independent energy company engaged in the exploration, development, production and acquisition of crude oil and natural gas. North American operations are focused in the shelf and deepwater areas of the Gulf of Mexico, the Rocky Mountains, Permian Basin, Anadarko, East Texas, North Louisiana and the Gulf Coast regions. Internationally, the Company conducts oil and gas activities in West Africa in Equatorial Guinea, Angola, Nigeria and Côte d’Ivoire. The Company also conducts operations in Egypt, the Russian Republic of Tatarstan, Brazil and Indonesia.

     On February 23, 2003, Ocean and Devon Energy Corporation (“Devon”) executed an Agreement and Plan of Merger. The merger must be approved by the stockholders of both Ocean and Devon. Under the terms of the merger agreement, Ocean’s common stockholders will receive 0.414 shares of Devon common stock for each common share of Ocean. After the merger, the stockholders of Ocean will own approximately 32% of the outstanding common stock of the combined company. The merger is expected to qualify as a tax–free transaction and is subject to each Company’s stockholders’ approval and certain other conditions. The transaction is anticipated to be completed mid–year 2003.

2.   Summary of Significant Accounting Policies

     General – The accompanying Consolidated Financial Statements of the Company have been prepared according to generally accepted accounting principles and pursuant to the rules and regulations of the Securities and Exchange Commission. These accounting principles require the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of amounts previously reported have been made to conform to current year presentations.

     Consolidation – The accompanying Consolidated Financial Statements include the accounts of Ocean Energy, Inc. and its majority–owned entities. All significant intercompany transactions have been eliminated. At this time, the Company does not believe the requirements of the recently issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, will result in consolidation of any additional entities.

     Cash Equivalents – The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

     Inventories – Materials and supplies and oil inventories are valued at the lower of average cost or market value (net realizable value).

     Oil and Gas Properties – The Company’s exploration and production activities are accounted for using the full cost method. Under this method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized. These capitalized costs are accumulated in pools on a country–by–country basis. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred. Proceeds from sales of reserves in place, unless significant, are recorded as reductions to oil and gas properties.

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     Where proved reserves are established, capitalized costs are limited on a country–by–country basis (the ceiling limitation). The ceiling limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using end–of–period prices, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected income tax effects. If the capitalized cost of the full cost pool exceeds the ceiling limitation, the excess is charged to expense as additional depreciation, depletion and amortization (“DD&A”) expense.

     Depreciation, depletion and amortization of oil and gas properties is computed on a country–by–country basis using a unit–of–production method based on estimated proved reserves. Through December 31, 2002, all costs associated with proved oil and gas properties, including an estimate of future development, restoration, dismantlement and abandonment costs associated therewith, were included in the computation base. As of January 1, 2003, capitalized costs related to asset retirement obligations were included in the full cost pool. The costs of investments in unproved properties and portions of costs associated with major development projects are excluded from the DD&A calculation until the project is evaluated and proved reserves are established or impaired.

     Unproved property costs include leasehold costs, seismic costs and other costs incurred during the exploration phase. In areas where proved reserves are established, significant unproved properties are evaluated periodically for impairment. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Unproved properties whose acquisition costs are not individually significant are aggregated, and the portion of such costs estimated to be ultimately nonproductive, based on experience, is amortized to the full cost pool over an average holding period.

     In countries where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs and other costs incurred during the exploration phase remain capitalized in unproved property cost centers until proved reserves have been established or until exploration activities cease. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to depreciation, depletion and amortization and the application of the ceiling test. If exploration efforts in a country are unsuccessful in establishing proved reserves, the Company may determine that the value of its exploratory costs incurred have been permanently diminished in part or in whole. Therefore, based on the Company’s impairment evaluation and its future exploration plans, the unproved property cost centers related to the area of interest could be impaired, in which case accumulated costs are charged against earnings.

     During 2002, the Company announced that it would discontinue current exploratory activities in Pakistan and on Block 19 offshore Angola. As a result, the Company recognized an impairment in the amount of $76 million ($50 million, after–tax). During 2000, the Company recognized an impairment in the amount of $20 million ($13 million, after–tax) related to the discontinuance of exploration activities in the Republic of Yemen. The Company recognized no impairments during 2001 and had no ceiling limitations in 2002, 2001 or 2000.

     Interest cost capitalized as property, plant and equipment amounted to $44 million, $45 million and $44 million in 2002, 2001 and 2000, respectively. The Company also capitalized certain employee costs related to exploratory and development activities in the amounts of $61 million, $58 million and $45 million in 2002, 2001 and 2000, respectively.

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Ocean Energy, Inc.

     The Company estimates oil and gas reserves quarterly. An independent petroleum engineering firm annually reviews at least 80% of the Company’s estimates of proved reserves.

     Other Property, Plant and Equipment – Other property, plant and equipment consists of oil and gas pipeline facilities, gas processing plant, and corporate–related assets and equipment with a net book value of $106 million and $102 million at December 31, 2002 and 2001, respectively. Depreciation of other property is computed principally using the straight–line method over their estimated useful lives, which vary from three to twenty years. The Company groups and evaluates other property, plant and equipment for impairment based on the ability to identify separate cash flows generated therefrom in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long–Lived Assets (“SFAS No. 144”). No impairment charges related to other property, plant and equipment were recorded during 2002, 2001 and 2000.

     Maintenance, repairs and renewals are charged to operating expense except that renewals which extend the life of the asset are capitalized.

     Environmental Liabilities – Environmental expenditures that relate to an existing condition caused by past operations, and that do not contribute to current or future revenue generation, are expensed. Liabilities are accrued when environmental assessments and/or clean–ups are probable, and the costs can be reasonably estimated.

     Treasury Stock – The Company follows the weighted average cost method of accounting for treasury stock transactions.

     Revenue Recognition – The Company records revenues from the sales of crude oil and natural gas when delivery to the customer has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred. The Company may have an interest with other producers in certain properties. The Company uses the entitlements method to account for sales of production in these instances. The Company may receive more or less than its entitled share of production. Under the entitlements method, if the Company receives more than its entitled share of production, the imbalance is treated as a liability. If the Company receives less than its entitled share, the imbalance is recorded as an asset.

     Reclassification of General and Administrative Expense – The Company expenses employee costs associated with production and other operating activities and general corporate activities. In prior years, a portion of costs related to certain administrative functions that support the Company’s ongoing operating activities were included in operating expense. During 2002, the Company reclassified costs of certain administrative functions as general and administrative expense. As a result, previous years have been reclassified to conform to current year presentation. While this reclassification had no effect on net income, it did decrease operating expense, and increase general and administrative expense, by $24 million, $20 million and $18 million for the years ended December 31, 2002, 2001 and 2000, respectively.

     Derivative Instruments and Hedging Activities – From time to time, the Company has utilized and expects to continue to utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments.

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Ocean Energy, Inc.

     The Company uses derivative financial instruments with respect to a portion of its oil and gas production to achieve a more predictable cash flow by reducing its exposure to price fluctuations. These transactions generally are swaps, collars or options and are entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce the Company’s exposure to declines in the market prices of crude oil and natural gas that the Company produces and sells, and to manage cash flows in support of the Company’s annual capital expenditure budget. Prior to January 1, 2001, gains and losses from derivative financial instruments were recognized in oil and gas revenues as the associated production occurred.

     The Company may also utilize derivative financial instruments such as interest rate swap agreements. Prior to January 1, 2001, gains and losses from interest rate hedges were included in interest expense.

     Effective January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheets as assets or liabilities.

     Adoption of SFAS No. 133 at January 1, 2001, resulted in the recognition of $1 million of additional derivative assets, included in other current assets; $23 million of derivative liabilities, $11 million of which were included in current liabilities and $12 million of which were included in other noncurrent liabilities in the Company’s Consolidated Balance Sheets; and $14 million, net of taxes, of deferred hedging losses, included in accumulated other comprehensive income (loss) as the effect of the change in accounting principle. The Company also recorded a deferred tax asset of $9 million upon adoption. Amounts were determined as of January 1, 2001, based on quoted market values, the Company’s portfolio of derivative instruments, and the Company’s measurement of hedge effectiveness.

     The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at its inception. SFAS No. 133 requires that a company document, at the inception of a hedge, the hedging relationship, the entity’s risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

     Derivative instruments designated as cash flow hedges are reflected at fair value in the Company’s Consolidated Balance Sheets. Changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in revenues.

     The Company may utilize derivative financial instruments that have not been designated as hedges under SFAS No. 133 even though they protect the Company from changes in commodity prices. These instruments are marked to market with the resulting changes in fair value recorded in oil and gas revenues.

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     The Company may also utilize derivative financial instruments to hedge exposure to interest rates. Instruments may include contracts to convert the interest rate on fixed–rate debt to floating, or contracts to convert the interest rate on floating–rate debt to fixed. Both types of contracts are reflected at fair value in the Company’s Consolidated Balance Sheets. The Company currently only has contracts that convert the interest rates on its fixed rate debt to floating. These transactions qualify as fair value hedges. Therefore, the related portion of fixed–rate debt being hedged is reflected at an amount equal to the sum of its carrying value plus an adjustment representing the change in its fair value attributable to the interest rate risk being hedged. The gains or losses on the derivative financial instrument and the hedged item, as well as the settlements on the derivative financial instrument, are recognized currently in interest expense. The net effect of this accounting on the Company’s operating results is that interest expense on the portion of fixed–rate debt being hedged is generally recorded based on variable interest rates.

     Income Taxes – The Company uses the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date.

     Foreign Currency Translation – The U.S. dollar is the functional currency for all of the Company’s existing foreign operations, as predominantly all transactions in these operations are denominated in U.S. dollars.

     Stock–Based Compensation – The Company currently has stock option plans and an employee stock purchase plan, which are further described in Note 15. The Company accounts for stock–based compensation plans for employees and directors using the intrinsic value method. Under this method, the Company records no compensation expense for stock options granted when the exercise price of options granted is equal to or greater than the fair market value of the Company’s common stock on the date of grant. The Company also records no compensation expense for employee purchases of stock under its employee stock purchase plan because the plan is considered noncompensatory. The following table presents the effect on net income and earnings per share if the Company had applied a fair value recognition method:

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Ocean Energy, Inc.

	Year Ended December 31,
		2002		2001		2000
Net income, as reported	$	135,175	$	273,782	$	213,203
Deduct: Total stock–based employee compensation
expense determined under fair value based method
for all awards, net of related tax effects		10,224		11,190		7,658
Pro forma	$	124,951	$	262,592	$	205,545
Earnings per share:
Basic – as reported	$	0.76	$	1.59	$	1.26
Basic – pro forma	$	0.70	$	1.52	$	1.21
Diluted – as reported	$	0.74	$	1.53	$	1.22
Diluted – pro forma	$	0.68	$	1.47	$	1.18

     Concentrations of Market Risk – The future results of the Company’s oil and gas operations will be affected by the market prices of oil and gas. The availability of a ready market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

     The Company operates in various phases of the oil and gas industry. The Company’s receivables include amounts due from purchasers of oil and gas production and amounts due from joint venture partners for their respective portions of operating expense and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit–related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long term. Trade receivables are generally not collateralized. The Company analyzes customers’ and joint venture partners’ historical credit positions and payment histories prior to extending credit.

     Duke Energy Trading & Marketing and affiliates (“DETM”), a wholly–owned subsidiary of Duke Energy Corp., and ExxonMobil Sales and Supply (“EMSS”), a wholly–owned subsidiary of ExxonMobil Corporation, accounted for significant portions of the Company’s total oil and gas production revenues during 2002, 2001 and 2000 as follows:

	Year Ended December 31,
		2002		2001		2000
Percentage of total oil and gas production
revenues purchased by:
Duke Energy Trading & Marketing		27	%	42	%	44	%
ExxonMobil Sales and Supply		24	%	19	%	20	%

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Ocean Energy, Inc.

     DETM has an implied senior debt rating of BBB from Standard & Poor’s (“S&P”) and Duke Energy Corporation’s senior debt is rated A– by S&P and A3 by Moody’s. EMSS is not rated but ExxonMobil Corporation’s senior debt is rated AAA by S&P and Aaa by Moody’s.

     The Company has a significant portion of its operations in various international areas. The Company’s activities in these areas are subject to risks associated with international operations, including political and economic uncertainties, risks of cancellation or unilateral modification of agreements, operating restrictions, currency repatriation restrictions, expropriation, export restrictions, the imposition of new taxes and the increase of existing taxes, inflation, foreign exchange fluctuations and other risks arising out of international government sovereignty over areas in which the operations are conducted. The Company has endeavored to protect itself against political and commercial risks inherent in these operations. There is no certainty that the steps taken by the Company will provide adequate protection.

     Concentrations of Credit Risk – Derivative financial instruments that hedge the price of oil and gas and interest rates are generally executed with major financial or commodities trading institutions which expose the Company to market and credit risks, and may at times be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non–performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continuing review and full performance is anticipated. The Company’s policy is to execute financial derivatives only with counterparties having a senior debt rating of A or higher.

     Impact of Recently–Issued Accounting Pronouncements – The Financial Accounting Standards Board (“FASB”) has recently issued the following accounting pronouncements:

     Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”) requires entities to record the liability for asset retirement obligation at fair value in the period in which it is incurred and a corresponding increase in the carrying amount of the related long–lived asset. This statement is required to be adopted for periods after December 31, 2002 using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. The Company adopted SFAS No. 143 as of January 1, 2003. The adoption of this statement resulted in the recognition of a liability for asset retirement obligations of $94 million, $1 million of which was included in accrued liabilities and $93 million of which was included in other noncurrent liabilities, a corresponding increase in net property, plant and equipment of $116 million in the Company’s balance sheets, and a cumulative accounting adjustment of $13 million, net of $9 million deferred tax expense, as the effect of the change in accounting principle.

     Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (“SFAS No. 145”) rescinds Statement of Financial Accounting Standards No. 4, Reporting Gains and Losses from Extinguishment of Debt, and requires that all gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Accounting Principles Board Opinion No. 30, Reporting the Results of Operations (“APB No. 30”). Applying APB No. 30 distinguishes transactions that are part of an entity’s recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. The Company early adopted the provisions related to the rescission of SFAS No. 4 during fourth quarter 2002. With the adoption of SFAS No. 145, the classification of losses associated with extinguishments of debt that were previously recorded as extraordinary items were reclassified into other expense with the related tax benefit reclassified into income tax expense.

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Ocean Energy, Inc.

     During 2002, the FASB issued two interpretations: FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”) and FASB Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). There was no current impact of FIN 45 or FIN 46 on the Company’s financial position or results of operations.

3.   Earnings Per Share

The following table provides a reconciliation between basic and diluted earnings per share (stated in thousands except per share data):

	Net Income		Weighted Average
	Available to		Common Shares		Earnings Per
	Common Stockholders		Outstanding		Share Amount
Year Ended December 31, 2002:
Basic	$	131,925		173,983	$	0	.76
Effect of dilutive securities:
Stock options		--		4,586
Convertible preferred stock		3,250		3,461
Diluted	$	135,175		182,030	$	0	.74

Year Ended December 31, 2001:
Basic	$	270,532	170,178	$	1	.59
Effect of dilutive securities:
Stock options		--	4,814
Convertible preferred stock		3,250	3,424
Diluted	$	273,782	178,416	$	1	.53
Year Ended December 31, 2000:
Basic	$	209,953	167,144	$	1	.26
Effect of dilutive securities:
Stock options		--	4,217
Convertible preferred stock		3,250	3,388
Diluted	$	213,203	174,749	$	1	.22

     Basic earnings per share is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the assumption that outstanding stock options have been converted using the average common stock price for the period and that convertible preferred stock has been converted at its stated conversion price.

     Options to purchase shares of common stock are excluded from the computation of diluted earnings per share when their exercise prices are greater than the average market price of the common shares during the period. The following options were excluded from the computation of diluted earnings per share (options in thousands):

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Ocean Energy, Inc.

	Year Ended December 31,
	2002	2001	2000
Weighted average options excluded from
computation of diluted earnings per share	3,640	4,305	6,600
Option exercise price range	$19.61 – $36.54	$18.35 – $36.54	$13.46 – $36.54

These options expire at various dates through 2012.

4.   Operating Expenses

Components of operating expenses are as follows (in thousands):

	Year Ended December 31,
		2002		2001		2000
Lease operating expense	$	210,146	$	178,148	$	143,331
Production taxes		35,938		47,350		40,634
Transportation expenses		32,875		25,211		23,727
Ad valorem taxes and other		9,660		9,730		3,486
Production–related operating expenses		288,619		260,439		211,178
Other operating expenses		23,572		26,298		28,059
Total operating expenses	$	312,191	$	286,737	$	239,237

Other operating expenses include certain employee costs that support the Company’s ongoing oil and gas activities.

5.   Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information are as follows (in thousands):

	Year Ended December 31,
		2002		2001		2000
Cash paid during the year for:
Interest	$	107,028	$	101,688	$	114,708
Income taxes	$	33,081	$	22,966	$	38,244

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Ocean Energy, Inc.

6.   Other Current Assets

Other current assets include the following at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002		2001
Prepaid drilling costs	$	44,220	$	38,887
Inventories		38,432		24,107
Oil and gas derivative financial instruments at fair market value		--		32,396
Current deferred taxes		19,821		1,209
Tax refund due		9,750		--
Other		4,951		2,919
Other current assets	$	117,174	$	99,518

7.   Acquisition and Disposition of Assets

     Acquisitions – During 2001, the Company acquired Texoil, Inc. (“Texoil”) for a cash purchase price of $115 million before assumed bank debt of $15 million. Texoil was an independent oil and gas company engaged in exploration, development, and acquisition of oil and gas reserves in Texas and Louisiana. No goodwill was recorded in connection with the purchase of Texoil. The Company also acquired certain oil and gas assets from EnSight Resources, L.L.C. for a cash purchase price of $118 million. The properties are located primarily in East Texas and North Louisiana. Pro forma results of operations assuming acquisitions occurred at the beginning of the period would not have been significantly different from actual results for 2001.

     Dispositions – During 2002, the Company closed the sale of selected royalty, overriding royalty and mineral interests in various locations throughout the United States and two packages of non–core working interests for total net proceeds of $74 million. The Company received $64 million in proceeds from the sales of certain non–core properties during 2001. Under full cost accounting rules, the proceeds were recorded as a reduction of the U.S. cost pool and no gain or loss was realized.

8.   Other Noncurrent Assets

Other noncurrent assets include the following at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002		2001
Oil and gas imbalances (net of current portion of $6 million and $3.5
million in 2002 and 2001, respectively)	$	26,811	$	30,023
Deferred financing costs		22,369		19,747
Interest rate swap agreements at fair market value		13,376		3,869
Assets held in supplemental benefit plans trust at fair market value		3,621		3,668
Other		7,843		7,857
Other noncurrent assets	$	74,020	$	65,164

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Ocean Energy, Inc.

9.   Accrued Liabilities

Accrued liabilities include the following at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002		2001
Income taxes payable	$	24,922	$	24,760
Contribution to Ocean Retirement Savings Plan		6,205		5,854
Production and ad valorem taxes		4,241		6,050
Payroll and related employee benefits		5,062		4,228
Accrued spar lease payments		3,633		--
Other		3,147		3,338
Accrued liabilities	$	47,210	$	44,230

10.   Debt

Long–term debt consisted of the following at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002			2001
Credit Facility (average interest rate of 3%) due May 2006	$	--		$	50,000
Public Notes:
7 7/8% Senior Notes, due August 2003		100,000			100,000
7 5/8% Senior Notes, due July 2005		125,000			125,000
4 3/8% Senior Notes, due October 2007		400,000			--
7 1/4% Senior Notes, due October 2011		350,000			350,000
8 1/4% Senior Notes, due July 2018		125,000			125,000
7 1/2% Senior Notes, due September 2027		150,000			150,000
8 7/8% Senior Subordinated Notes, due July 2007		--			174,875
8 3/8% Senior Subordinated Notes, due July 2008		200,117			227,600
Other		20,344			9,084
		1,470,461			1,311,559
Less: Current maturities		(1,132	)		(1,132	)
Unamortized debt discount		(26,539	)		(27,446	)
Total long–term debt	$	1,442,790		$	1,282,981

     Credit Facility – As of December 31, 2002, the Company’s credit facility consisted of a $1 billion revolving credit facility with a maturity date of May 2006. The credit facility replaced the Company’s previous $500 million facility which was scheduled to mature in March 2004. The Company’s obligations under the credit facility are unsecured. The credit facility bears interest, at the Company’s option, at LIBOR or prime rates plus applicable margins ranging from zero to 1.7% or at a competitive bid. As of December 31, 2002, the Company’s outstanding borrowings under the credit facility were zero, and letters of credit totaled $28 million, leaving $972 million of available credit.

     Other Financing Activities – During 2002, the Company issued $400 million of 4 3/8% senior notes due October 2007 pursuant to a shelf registration statement. The notes are redeemable at any time at the Company’s option, and upon certain changes in control, the notes would be subject to a mandatory repurchase offer. The proceeds were used to repay amounts outstanding under the Company’s credit facility which included balances used to retire debt earlier in 2002 when the Company exercised call provisions for $175 million of its 8 7/8% senior subordinated notes due July 2007. The Company has also repurchased $27 million of its 8 3/8% senior subordinated notes due July 2008. In connection with these repurchases, the Company recorded other expense of $12 million and a related tax benefit of $4 million.

     During 2001, the Company issued $350 million of 7 1/4% senior notes due October 2011 pursuant to a shelf registration statement. The notes are redeemable at any time at the Company’s option, and upon certain changes in control, the notes would be subject to a mandatory repurchase offer. A portion of the proceeds was used to repay amounts outstanding under the Company’s credit facility, and the remainder of the proceeds was used to retire existing higher interest rate debt by exercising call provisions for $100 million of 8 5/8% senior subordinated notes due 2005 and $2 million of 9 3/4% senior subordinated notes due 2006. Also during 2001, the Company repurchased on the open market $22 million of its 8 3/8% senior subordinated notes due July 2008 and $25 million of its 8 7/8% senior

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subordinated notes due July 2007. The repurchase of these notes was funded with available cash balances and borrowings under the Company’s existing credit facility. In connection with these repurchases, the Company recorded other expense of $6 million and a related tax benefit of $2 million.

     Public Notes – The Company’s senior and senior subordinated notes are general unsecured obligations of the Company. Ocean Energy, Inc. (incorporated in Louisiana), a wholly–owned subsidiary of the Company, has guaranteed the payment of principal, premium (if any), and interest on the Company’s outstanding notes. Other than intercompany arrangements and transactions, the consolidated financial statements of the subsidiary are equivalent in all material respects to those of the Company and therefore are not presented separately.

     The Company’s debt contains conditions and restrictive provisions including, among other things, restrictions on incurrence of additional indebtedness by the Company and its subsidiaries, the payment of dividends or repurchases of common stock and entering into sale and leaseback transactions, and requires the maintenance of certain financial ratios. Under the most restrictive of these provisions, approximately $519 million was available for payment of cash dividends on common stock or to repurchase common stock as of December 31, 2002.

     Annual Maturities – At December 31, 2002, the Company’s aggregate annual maturities of long–term debt are $101 million, $1 million, $126 million, $1 million and $401 million for the years 2003, 2004, 2005, 2006 and 2007, respectively. The Company’s 8 3/8% senior subordinated notes due July 2008 are redeemable at a premium beginning in July 2003.

     The Company’s 7 7/8% senior notes, in the amount of $100 million, are due in August 2003. The Company has established the necessary credit capacity, through its credit facility, to refinance these notes. Therefore, in accordance with SFAS No. 6, Classification of Short–term Obligations Expected to be Refinanced, the notes will continue to be classified as long–term debt because it is the Company’s intent to refinance these obligations on a long–term basis.

     Deferred Financing Costs – Deferred financing costs represent financing costs incurred in connection with the execution of various debt facilities entered into or securities issued by the Company. These costs are capitalized as other noncurrent assets in the Company’s Consolidated Balance Sheets and amortized to interest expense over the life of the related debt.

11.   Deferred Revenue

     In 1999, the Company entered into a prepaid crude oil sales contract to deliver 5.6 MBbl per day of crude oil for the period February 2000 through May 2003. In exchange for the crude oil to be provided, the Company received an advance payment of $100 million.

     The Company is party to a market–sensitive prepaid natural gas sales contract to deliver 53,500 MMBtu per day of natural gas for the period January 2003 through December 2003 and 55,600 MMBtu per day of natural gas for the period January 2004 through December 2004. In exchange for the natural gas to be provided, the Company received an advance payment of $75 million during 2000. The contract also provides that the purchaser will make additional payments to the Company in the event the spot price, as defined in the contract, exceeds $2.50 per MMBtu for any delivery month during 2003 or exceeds $3.00 for any delivery month during 2004.

     The obligations associated with the future delivery of the crude oil and natural gas have been recorded as deferred revenue in the Company’s Consolidated Balance Sheets. The prepaid proceeds

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were included in cash flows from financing activities in the Company’s Consolidated Statements of Cash Flows in the years in which they were received. The prepaid proceeds are being amortized into revenue as scheduled deliveries of crude oil and natural gas are made. This amortization is deducted from net income when computing Net Cash Provided by Operating Activities in the Company’s Consolidated Statements of Cash Flows as scheduled delivery occurs. Deliveries of crude oil and natural gas are made as follows:

	Year Ended December 31,
		2003		2004
Revenues (in thousands)	$	48,757	$	37,788
Annual crude oil delivery (MBbl)		845		--
Annual natural gas delivery (BBtu)		19,260		20,016

12.   Other Noncurrent Liabilities

Other noncurrent liabilities include the following at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002		2001
Conveyance of Section 29 credit properties:
Tax credit agreement	$	40,899	$	52,342
Embedded derivative at fair market value		8,697		(7,592	)
Oil and gas imbalances (net of current portion of $4 million in 2002
and $2 million in 2001)		14,280		15,581
Supplemental benefit plans		10,808		8,535
Deferred spar lease fees		11,324		--
Other		22,931		19,622
Other noncurrent liabilities	$	108,939	$	88,488

     Conveyance of Section 29 Credit Properties – In 2000, the Company conveyed certain Internal Revenue Code Section 29 tax credit–bearing properties to a trust for $70 million, which was recorded in other noncurrent liabilities. The trust receives the operating cash flow from the properties until the investor recoups its investment plus a required after–tax rate of return. At December 31, 2002, payout is estimated to occur during second quarter 2009. As part of the transaction, the trust was required to hedge 85% of its total estimated gas production through December 31, 2005. Although the Company is not a party to the financial instrument, under SFAS No. 133 this transaction is determined to have an embedded derivative financial instrument. The fair market value of that financial derivative is a liability of $9 million at December 31, 2002 and an asset of $8 million at December 31, 2001, and is included with the trust liability in other noncurrent liabilities.

     Supplemental Benefit Plans – Supplemental benefit plans represent the Company’s obligation under its executive supplemental retirement plan ($7 million), the outside directors deferred fee plan ($2 million) and other supplemental benefit plans ($2 million).

     Deferred Spar Lease Fees – See discussion of spar operating leases in Note 18.

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13.   Fair Value of Financial Instruments

     The estimated fair value of financial instruments has been determined by the Company using available market information. The estimated fair values of the Company’s financial instruments are summarized as follows (in thousands):

	December 31,
	2002						2001
		Carrying			Estimated			Carrying			Estimated
		Amount			Fair Value			Amount			Fair Value
Asset (liability)
Long–term debt	$	(1,443,922	)	$	(1,617,870	)	$	(1,284,113	)	$	(1,301,609	)
Derivative financial instruments:
Interest rate swaps		13,376			13,376			3,869			3,869
Oil and gas derivative
financial instruments		(38,073	)		(38,073	)		32,369			32,369
Embedded derivative
financial instrument		(8,697	)		(8,697	)		7,592			7,592

     Debt – The fair value of public notes is estimated based on quoted market prices for the same or similar issues. The carrying amount of all other debt approximates fair value because these instruments bear interest at rates tied to current market rates or mature in one year.

     Derivative Financial Instruments – The Company’s derivative financial instruments are recorded at fair market value in the Company’s Consolidated Balance Sheets. The fair market values are the amounts the Company would expect to receive or pay to settle the instruments at the reporting date, taking into account the difference between market prices or index prices at year end and the contract prices of the instruments. The fair market values were obtained from the third–party counterparties to the instruments.

     Interest Rate Swaps –The Company has entered into interest rate swap agreements relating to its 7 5/8% senior notes due July 2005 and its 7 7/8% senior notes due August 2003. Under the terms of the agreements, the counterparties pay the Company a weighted average fixed annual rate of 7.74% on total notional amounts of $225 million, and the Company pays the counterparties a variable annual rate equal to the average six–month LIBOR rate plus a weighted average rate of 2.73%. The swap agreements remain in effect through the maturity dates of the respective notes. The swap agreements have been designated as fair value hedges and are included in other noncurrent assets in the Company’s Consolidated Balance Sheets. Interest expense for 2002 and 2001 was reduced by $7 million and $3 million, respectively as a result of the interest rate swaps.

     Oil and Gas Derivative Financial Instruments – At February 28, 2003, the Company had the following volumes under derivative contracts related to its oil and gas producing activities:

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				Weighted
Production		Instrument	Daily	Average
Period	Index	Type	Volumes	Price
Crude Oil:
01/01/03 – 12/31/03	WTI	3–way Collar (1)	43 MBbl	$19.00 – 23.00 – 27.98
01/01/03 – 12/31/03	Dated Brent	3–way Collar (1)	10 MBbl	$19.00 – 23.00 – 27.22
03/01/03 – 12/31/03 (2)	Dated Brent	Swap	30 MBbl	$26.88
04/01/03 – 12/31/03 (2)	Dated Brent	Swap	5 MBbl	$26.90
Natural Gas:
01/01/03 – 12/31/03	NYMEX	3–way Collar (1)	120,000 MMBtu	$2.50 – 3.50 – 5.00
01/01/03 – 12/31/03	NYMEX	Collar	50,000 MMBtu	$3.75 – 5.26
03/01/03 – 12/31/03 (2)	NYMEX	Swap	185,000 MMBtu	$4.86
04/01/03 – 06/30/03	NYMEX	Collar	20,000 MMBtu	$3.75 – 5.06
09/01/03 – 10/31/03	NYMEX	Collar	20,000 MMBtu	$3.75 – 5.23

(1)  A “3–way collar” combines a sold call, a purchased put and a sold put. The purchased put and sold put establish a floating minimum price (“floating floor”) and the sold call establishes a maximum price (“ceiling price”) the Company will receive for the volumes under contract.

(2)  Contract entered into subsequent to December 31, 2002.

     The Company’s oil and gas derivative financial instruments have been designated as cash flow hedges and are included in accounts and notes payable at December 31, 2002 and in other current assets at December 31, 2001 in the Company’s Consolidated Balance Sheets.

     The Company may utilize derivative financial instruments that have not been designated as cash flow hedges even though they protect the Company from changes in commodity prices. These instruments would be marked to market quarterly with the resulting changes in fair value recorded in oil and gas revenues.

     Embedded Derivative Financial Instrument – A related trust, to which the Company conveyed Section 29 tax credit–bearing properties, is required to hedge 85% of total estimated gas production from these properties through 2005. Through a swap agreement, the trust has hedged the following volumes:

							Weighted
					Daily		Average
Production Period	Index		Instrument Type		Volumes		Price
Gas Swap of Related Trust:
01/01/03 – 12/31/03		NYMEX		Swap		11,100 MMBtu		$3.60
01/01/04 – 12/31/04		NYMEX		Swap		9,600 MMBtu		$3.41
01/01/05 – 12/31/05		NYMEX		Swap		8,300 MMBtu		$3.28

     The fair market value of the embedded derivative financial instrument is the amount the trust would expect to receive or pay to settle the instrument at the reporting date. The financial instrument has been designated as a cash flow hedge.

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     The change in fair values of the Company’s oil and gas derivative financial instruments and the embedded derivative financial instrument included in revenues are as follows (in thousands):

	Year Ended December 31,
		2002			2001
Financial derivative settlements transferred from other comprehensive income	$	(1,077	)	$	(16,289	)
Net change in fair market value of options		1,368			4,120
Ineffective portion of derivative financial instruments		(2,171	)		2,173
Decrease in revenues from derivative financial instruments qualifying
as cash flow hedges		(1,880	)		(9,996	)
Decrease in revenues from other oil and gas derivative financial instruments		(1,674	)		(1,120	)
Decrease in revenues from oil and gas derivative financial instruments	$	(3,554	)	$	(11,116	)

     If commodity prices were to stay the same as they were at December 31, 2002, approximately $24 million of net deferred losses related to those fair values included in accumulated other comprehensive income (loss) at December 31, 2002 would be reversed during the next twelve months as the forecasted transactions occur, and would be recorded as a reduction in revenues. Any actual increase/decrease in revenues will be determinant upon market conditions over the period the forecasted transactions occur. All forecasted transactions currently being hedged are expected to occur by December 2005.

     Prior to the adoption of SFAS No. 133 at January 1, 2001, the impact of oil and gas derivative financial instruments and the embedded derivative financial instrument were recorded in revenues as the associated production occurred. During 2002 and 2001, there were no gains or losses reclassified into earnings as a result of the discontinuance of hedge accounting treatment for any of the Company’s derivative financial instruments.

     The net effect of the Company’s oil and gas derivative financial instruments and the embedded derivative financial instrument included as a component of other comprehensive income, net of tax, is as follows (in thousands):

	Year Ended December 31,
		2002			2001
Cumulative effect of accounting change for oil and gas
derivative financial instruments	$	--		$	(14,262	)
Net change in fair market value of oil and gas derivative
financial instruments		(52,654	)		40,104
Financial derivative settlements taken to income		(665	)		(1,403	)
Net effect of oil and gas derivative financial instruments,
increase (decrease) in stockholders’ equity	$	(53,319	)	$	24,439

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14.    Stockholders’ Equity

     The following table reflects the activity in shares of the Company’s common stock, preferred stock and treasury stock during the three years ended December 31, 2002:

	Year Ended December 31,
		2002		2001		2000
Common Stock Outstanding:
Shares at beginning of year		174,936,240		170,069,114		166,979,981
Exercise of common stock options		3,147,155		3,996,634		2,820,008
Deferred compensation		633,550		779,500		269,125
Employee stock purchase plan		177,443		90,992		--
Other		(6,632	)	--		--
Shares at end of year		178,887,756		174,936,240		170,069,114
Preferred Stock Outstanding		50,000		50,000		50,000
Treasury Stock Outstanding:
Shares at beginning of year		2,641,640		2,754,566		378,171
Purchase of shares		103,930		361,278		2,376,395
Transfer to supplemental benefit plans trust		(59,000	)	(472,000	)	--
Contribution of shares to employee plans		(112,140	)	(2,204	)	--
Directors deferred compensation		(12,000	)	--		--
Shares at end of year		2,562,430		2,641,640		2,754,566

     Preferred Stock – The Company is authorized to issue 10,000,000 shares of preferred stock, in one or more series. As of December 31, 2002, the Company had outstanding 50,000 shares of Series B Convertible Preferred Stock. The preferred stock has a 6.5% cumulative dividend payable semiannually and ranks senior to the Company’s common stock with respect to dividend distribution and distribution upon liquidation. Upon liquidation, the holders of the preferred shares are entitled to receive $1,000 per share, plus any accrued and unpaid dividends. The Company’s preferred stock is subject to automatic conversion to shares of OEI common stock, if, and only if, for 20 consecutive trading days the closing price of OEI common stock equals or exceeds the forced conversion price which was $22.02 at December 31, 2002. The adjusted conversion price of the preferred shares decreases based on the amount of dividends paid on common stock and was $14.68 at December 31, 2002.

     Common Stock Dividends – At December 31, 2002, the Company had accrued dividends payable of $7 million ($0.04 per share) on the Company’s outstanding common stock. Dividends of $28 million were charged to retained earnings during 2002. See Note 10 for discussion of restrictions on payment of cash dividends on common stock.

     Preferred Share Purchase Rights – The Company has a Rights Agreement (the “Plan”) to protect the Company’s stockholders from coercive or unfair takeover tactics. Under the Plan, each outstanding share and each share of common stock subsequently issued has attached to it one Right, exercisable at $30.75, subject to certain adjustments. In the event a person or group acquires 10% or more of the outstanding common stock, or in the event the Company is acquired in a merger or other business combination, or 50% or more of the Company’s consolidated assets or earning power is sold, each Right unless redeemed, entitles the holder to purchase $30.75 worth of shares of common stock of the Company or of the acquiring company, as the case may be, for half of the then–current, per–share market prices.

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     The Rights, under certain circumstances, are redeemable at the option of OEI’s Board of Directors at a price of $0.005 per Right, within 10 days (subject to extension) following the day on which the acquiring person or group exceeds the 10% threshold. If any person or group acquires 10% or more (but less than 50%) of the Company’s outstanding common stock, the Board may, at its option, issue common stock in exchange for all or part of the outstanding and exercisable Rights (other than Rights owned by such person or group which would become null and void) at an exchange ratio of one share of common stock for each two shares of common stock for which each Right is then exercisable, subject to adjustment. The Rights expire on May 21, 2003, but may be extended by an action of the Board of Directors. The Plan was amended in connection with the Company’s execution of the merger agreement with Devon to except Devon and the merger agreement from the operative provisions of the Plan.

     Accumulated Other Comprehensive Income (Loss) – Components of accumulated other comprehensive income consisted of the following at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002			2001
Net effect of oil and gas derivative financial
instruments	$	(28,880	)	$	24,439
Minimum supplemental retirement plans liability
adjustment and other		(1,601	)		(420	)
Accumulated other comprehensive income (loss)	$	(30,481	)	$	24,019

     At December 31, 2002, the effect of derivative financial instruments is net of a deferred income tax benefit of $18 million. The minimum supplemental retirement plans liability adjustment and other is net of a deferred income tax benefit of $1 million. At December 31, 2001, the effect of derivative financial instruments is net of deferred income tax expense of $15 million. The minimum supplemental retirement plans liability adjustment and other is net of deferred income tax benefit of $260,000.

15.   Benefit Plans

     Stock Option Plans – The Company currently has various stock option plans. The stock options generally become exercisable over a three–year period and expire 10 years after the date of grant. At December 31, 2002, 6 million shares of common stock were available for grant. Information relating to stock options is summarized as follows:

	2002						2001						2000
				Weighted						Weighted						Weighted
				Average						Average						Average
				Exercise						Exercise						Exercise
				Price Per						Price Per						Price Per
	Shares			Share			Shares			Share			Shares			Share
Balance outstanding –
Beginning of year		17,438,866		$	13	.81		19,589,741		$	12	.45		22,515,302		$	12	.88
Granted		3,096,200		$	18	.81		3,069,200		$	16	.79		3,085,950		$	8	.09
Exercised		(3,147,155	)	$	8	.80		(3,996,634	)	$	7	.78		(2,820,008	)	$	8	.55
Forfeited		(351,729	)	$	18	.86		(1,223,441	)	$	19	.22		(3,191,503	)	$	14	.73
Balance outstanding –
End of year		17,036,182		$	15	.54		17,438,866		$	13	.81		19,589,741		$	12	.45
Options exercisable –
End of year		11,231,712		$	15	.00		11,561,734		$	14	.57		14,239,266		$	14	.23

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     The weighted average fair value of stock options granted during 2002, 2001 and 2000 was $7.94, $7.99 and $4.86 per share, respectively. The fair value of each option grant is estimated on the date of grant using the Black–Scholes options–pricing model with the following weighted average assumptions used for grants in 2002, 2001 and 2000:

	Year Ended December 31,
		2002	2001	2000
Risk–free interest rate		4.5%	4.8%	6.5%
Expected life		5 years	5 years	5 years
Expected volatility		45%	53%	65%
Expected dividend yield		1%	1%	0%

     Actual value realized, if any, is dependent on the future performance of Ocean common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Black–Scholes model.

     Information relating to stock options outstanding at December 31, 2002 is summarized as follows:

	Options Outstanding							Options Exercisable
			Weighted		Weighted			Number		Weighted
	Number		Average		Average			Exercisable at		Average
Range of	Outstanding at		Remaining		Exercise Price			December 31,		Exercise Price
Exercise Prices	December 31, 2002		Contractual Life		Per Share			2002		Per Share
$3.65 – 7.30		1,780,063		5.5	$	6	.54		1,780,063	$	6	.54
$7.31 – 10.96		3,582,314		5.7	$	8	.21		2,829,847	$	8	.42
$10.97 – 14.61		1,090,231		4.8	$	12	.29		1,039,061	$	12	.27
$14.62 – 18.26		3,456,977		7.1	$	16	.70		1,562,102	$	16	.74
$18.27 – 21.92		4,314,096		7.6	$	19	.07		1,294,238	$	19	.85
$21.93 – 25.57		2,139,751		4.7	$	23	.41		2,053,651	$	23	.45
$25.58 – 36.54		672,750		3.7	$	30	.20		672,750	$	30	.20
		17,036,182		6.2	$	15	.54		11,231,712	$	15	.00

     The Company accounts for its stock–based compensation plans under Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees, and related interpretations. All outstanding options were issued at an exercise price equal to fair market value or greater of the Company’s common stock as of the date of grant. Accordingly, for the years ended December 31, 2002, 2001 and 2000, no compensation expense relating to these options was recognized in the Company’s results of operations.

     Executive Supplemental Retirement Plan – The Executive Supplemental Retirement Plan (the “Plan”) was established to provide supplemental retirement benefits to certain key employees. The Plan is a non–contributory defined benefit retirement plan, which provides for supplemental benefits based on the employee’s years of service and compensation. The Company’s policy generally is to fund the benefits as they become payable.

     The following tables set forth the Plan’s benefit obligation, Plan assets, reconciliation of funded status, amounts recognized in the Consolidated Balance Sheets, and the actuarial assumptions used (in thousands):

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Ocean Energy, Inc.

	Year Ended December 31,
		2002			2001
Change in benefit obligation:
Benefit obligation at beginning of year	$	4,205		$	3,482
Service cost		338			261
Interest cost		183			118
Actuarial loss		2,449			612
Benefits paid		(268	)		(268	)
Benefit obligation at end of year		6,907			4,205
Change in Plan assets:
Fair value of Plan assets at beginning of year		--			--
Employer contribution		268			268
Benefits paid		(268	)		(268	)
Fair value of Plan assets at end of year		--			--
Funded status		(6,907	)		(4,205	)
Unrecognized actuarial (gain) loss		1,939			(14	)
Net amount recognized	$	(4,968	)	$	(4,219	)
Amounts recognized in the balance sheets consist of:
Accrued benefit cost	$	(4,968	)	$	(4,219	)
Additional minimum liability		(1,939	)		(629	)
Deferred taxes		741			240
Accumulated other comprehensive loss		1,198			389
Net amount recognized	$	(4,968	)	$	(4,219	)

Net periodic benefit cost for the Plan includes the following components (in thousands):

	Year Ended December 31,
		2002		2001		2000
Service cost	$	338	$	261	$	147
Interest cost		183		118		65
Recognized actuarial (gain) loss		10		--		(30	)
Net periodic benefit cost	$	531	$	379	$	182

Weighted average assumptions include the following:

	Year Ended December 31,
		2002	2001	2000
Discount rate		6.75%	7.25%	7.5%

     Employee Stock Purchase Plan – During 2001, the Company established an Employee Stock Purchase Plan (“ESPP”) that allows eligible employees to purchase common stock of the Company at a 15% discount from the lower of the stock price at the beginning of the offering period or at the end of the offering period. There are two offering periods annually, and employees may elect to make contributions to the ESPP in amounts from 1% to 15% of eligible compensation. An employee’s contribution in any calendar year is limited to an amount that will purchase no more than the number of shares having a fair market value of $25,000 on the first day of an offering period.

     Deferred Compensation – The Company awarded common stock as deferred compensation to various Company employees during 2002, 2001 and 2000. The fair market value of the stock at the date

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of grant is included as a charge to equity and amortized to earnings as compensation expense over the vesting period, which is generally three years for restricted stock awards. These shares are included in the calculation of diluted earnings per share. The number of common shares issued and the average fair market value of the shares at grant date are as follows:

	Year Ended December 31,
		2002		2001		2000
Shares issued to employees		633,550		779,500		269,125
Average fair market value per share at
grant date	$	18.72	$	17.81	$	9.31
Shares issued to non–employee directors		12,000		--		--
Average fair market value per share at
grant date	$	18.66	$	--	$	--

     Supplemental Benefit Plans Trust – During 2001, the Company established a trust (the “Trust”) to assist the Company in funding its obligations under deferred compensation plans for certain employees and non–employee directors. Trust assets consist of investments in marketable securities and shares of Company common stock. The Trust assets are included in the Company’s Consolidated Balance Sheets. Investments in marketable securities of $4 million are classified as trading securities and reported at fair value at December 31, 2002 and 2001 with unrealized gains and losses included in earnings. Obligations which are to be settled by Trust assets other than shares of Company common stock total $4 million at December 31, 2002 and 2001 and are included in other noncurrent liabilities in the Company’s Consolidated Balance Sheets.

     For investments in Company common stock, the Trust has been funded with treasury stock as compensation is earned. The related compensation obligation will be settled by the delivery of a fixed number of shares of Company common stock, and diversification is not permitted. As a result, when funding of shares of stock to the Trust occurs, the balance in the Company’s treasury stock account is reduced by the average cost of the shares to the Company. The Trust records the shares at fair market value, and the difference is recorded to additional paid–in capital. The stock held by the Trust is included in stockholders’ equity and changes in the fair value are not recognized subsequent to funding. The related obligation totaled $9 million and $8 million at December 31, 2002 and 2001, respectively, and is also classified in stockholders’ equity. The Trust held 506,818 shares of common stock at December 31, 2002 and 472,000 shares of common stock at December 31, 2001. These shares are included in the calculations of basic and diluted earnings per share as though they were outstanding.

     The Trust assets and the related obligation were as follows at December 31, 2002 and 2001 (in thousands):

	December 31,
		2002		2001
Assets funded to Supplemental Benefit Plans Trust:
Marketable securities and other	$	3,621	$	3,668
Common stock		9,093		7,925
Total assets held in Trust	$	12,714	$	11,593
Amount included in other noncurrent liabilities	$	3,901	$	3,687
Amount included in stockholders’ equity		8,991		7,867
Total supplemental benefit plans obligation	$	12,892	$	11,554

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     Other Benefit Plans – The Company maintains the Ocean Retirement Savings Plan (the “ORS Plan”), a defined contribution plan created from the January 2001 merger of several previous 401(k) plans and an employee stock ownership plan. All eligible employees, as defined in the ORS Plan, may participate, and the Company matches a portion of employees’ contributions. Company contributions, including additional optional annual contributions, to the ORS Plan and the previous plans were $10 million, $8 million and $8 million in 2002, 2001 and 2000, respectively, and were included in operating and general and administrative expenses.

16.   Income Taxes

     The income before income taxes and the components of income tax expense (benefit) for each of the years ended December 31, 2002, 2001 and 2000 were as follows (in thousands):

	Year Ended December 31,
		2002			2001		2000
Income before income taxes:
Domestic	$	112,474		$	291,290	$	159,058
Foreign		152,620			206,557		219,032
	$	265,094		$	497,847	$	378,090
Current income tax expense (benefit):
Federal	$	(17,748	)	$	1,710	$	(685	)
Foreign		41,252			42,333		23,195
State		437			900		(633	)
Total current		23,941			44,943		21,877
Deferred income tax expense:
Federal		73,809			138,100		98,105
Foreign		30,407			36,587		42,364
State		1,762			4,435		2,541
Total deferred		105,978			179,122		143,010
Income tax expense	$	129,919		$	224,065	$	164,887

     The Company recognized tax benefits on the exercise of non–qualified stock options of $12 million in 2002, $15 million in 2001 and $6 million in 2000. In addition, in 2001 the Company recognized a deferred tax liability of $50 million due to the excess of book over tax basis of the oil and gas properties acquired in the purchase of Texoil.

     As of December 31, 2002 and 2001, the Company and its subsidiaries had U.S. federal net operating loss (NOL) carryforwards of $488 million. These loss carryforward amounts will expire during the years 2012 through 2021. The Company has a statutory depletion carryforward of $7.7 million and an alternative minimum tax credit carryforward of $17.7 million at December 31, 2002.

     For federal income tax purposes, certain limitations are imposed on an entity’s ability to utilize its NOLs in future periods if a change of control, as defined for federal income tax purposes, has taken place. In general terms, the limitation on utilization of NOLs and other tax attributes during any one year is determined by the value of an acquired entity at the date of the change of control multiplied by the then–existing long–term tax–exempt interest rate. The manner of determining an acquired entity’s value has not yet been addressed by the Internal Revenue Service. The Company has determined that, for federal income tax purposes, a change of control occurred during 1999. However, the Company does not believe such limitations will significantly impact the Company’s ability to utilize the NOLs.

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Ocean Energy, Inc.

     Income tax expense for each of the years ended December 31, 2002, 2001 and 2000 was different than the amount computed using the federal statutory rate (35%) for the following reasons (in thousands):

	Year Ended December 31,
		2002		2001		2000
Amount computed using the statutory rate	$	92,783	$	174,247	$	132,332
Increase in taxes resulting from:
Net book deductions not available for tax due to differences
in book/tax basis		636		520		539
State and local income taxes, net of federal effect		2,553		3,468		1,240
Taxation of foreign operations, net of federal effect		33,947		45,830		30,510
Other		--		--		266
Income tax expense	$	129,919	$	224,065	$	164,887

     The tax effects of temporary differences that gave rise to significant portions of the deferred tax liabilities and deferred tax assets as of December 31, 2002 and 2001 were as follows (in thousands):

	December 31,
		2002			2001
Deferred tax assets:
Net operating loss carryforwards	$	170,925		$	170,636
Percentage depletion carryforwards		2,688			2,688
Alternative minimum tax credit carryforwards		17,676			5,897
Components of other comprehensive income		18,881			--
Other		10,075			16,948
Deferred tax assets		220,245			196,169
Deferred tax liabilities:
Property, plant and equipment, due to differences in depreciation,
depletion and amortization		(414,387	)		(313,767	)
Components of other comprehensive income		-			(14,878	)
Deferred tax liabilities		(414,387	)		(328,645	)
Net deferred tax assets (liabilities)		(194,142	)		(132,476	)
Less – reclassification to current deferred tax assets		(19,821	)		(1,209	)
Net noncurrent deferred tax assets (liabilities)	$	(213,963	)	$	(133,685	)

17.   Related Party Transactions

     During 2001 and 2000, the Company purchased 300,000 shares and 750,000 shares, respectively, of its common stock from members of its Board of Directors, or related entities, for $6 million and $12 million, respectively. These transactions were part of the Company’s stock repurchase plan and were purchased at market prices on the day of the transaction. Such director purchase programs are no longer in place at the Company.

     The Company paid an annual consulting fee of $425,000 from June 1, 1999 through May 31, 2002 to a member of the Company’s Board of Directors as part of a contractual severance agreement in relinquishing his role as an officer of the predecessor company.

79

Ocean Energy, Inc.

     Effective January 1, 2000, the Company paid an annual salary of $100,000 to the Vice Chairman of the Board of Directors of the Company. Upon the Vice Chairman’s resignation on January 23, 2001, the contract was terminated.

     During 2002, the Company retained the law firm of Vinson & Elkins L.L.P. (“V&E”) to perform various legal services for the Company. One of the members of the Board of Directors of the Company is a retired managing partner of V&E. Fees paid to V&E totaled $1 million for each of the years ended December 31, 2002, 2001 and 2000. V&E has been retained to perform similar services in 2003.

     The Company retains Southwest Bank of Texas to perform various banking services for the Company. One of the members of the Board of Directors of the Company serves on the board of directors of Southwest Bank of Texas.

     During 2002 and 2001, the Company paid fees of $200,000 and $500,000, respectively, to Cal Dive International, Inc. (“CDI”), a company that provides subsea services to the oil and gas industry. A member of the Company’s senior management serves on the board of CDI.

18.    Commitments and Contingencies

     Marketing Contract – Approximately 53% of the Company’s monthly domestic gas production is being sold pursuant to a purchase and sale agreement with Duke Energy Trading and Marketing, L.L.C. The agreement is in effect through September 30, 2003.

     Transportation Commitments – The Company has entered into various agreements for transportation of specified quantities of natural gas with estimated future minimum transportation expense payments of $2 million for 2003 and $1 million for each of the years 2004, 2005, 2006 and 2007.

     Lease Commitments – The Company leases certain office space, equipment and vehicles under operating lease arrangements. Total rental expense under operating leases net of sub–lease income was $9 million in 2002, $7 million in 2001 and $5 million in 2000.

     During 2002, the Company leased two spars that are being used in the development of the Nansen and Boomvang fields in the Gulf of Mexico. The operating leases are for 20–year terms and contain various options whereby the Company may purchase the lessors’ interests in the spars. At the inception of the leases, the Company received approximately $11 million in connection with the lessors’ purchases of the spars from third parties. This amount is included in other noncurrent liabilities in the Company’s Consolidated Balance Sheets and is being amortized over the life of each lease. Total rental expense under the operating leases was $13 million in 2002. The Company has guaranteed that the spars will have residual values at the end of the operating leases equal to at least 10% of the fair market value of the spars at the inception of the leases. The total guaranteed value is $20 million in 2022 for the spars and the amount may be reduced under the terms of the lease agreements.

     Scheduled minimum future lease payments under the Company’s operating leases are as follows (in millions):

80

Ocean Energy, Inc.

	Office Space and
Year	Equipment Leases		Spar Leases
2003	$	10	$	9
2004		9		11
2005		3		15
2006		3		15
2007		1		15
Thereafter		--		258
Minimum future lease payments	$	26	$	323

     Guarantee – The Company has guaranteed the payment of principal and interest under the terms of a note utilized by its partners in a related operation. The note is due in 2008 and the maximum amount of future payments required if the Company had to perform under the guarantee, based on the balance outstanding at December 31, 2002, would be $5 million.

     Other — The Company is a party to ongoing litigation in the normal course of business. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations and cash flows, if any, will not be material.

     A lawsuit captioned Breakwater Partners, LP v. James T. Hackett, et. al. (Case No. 2003–10161) was filed on February 27, 2003 in the District Court of Harris County, Texas, naming as defendants Ocean and all of the members of Ocean’s board of directors. The complaint generally alleges that:

• the 0.414 exchange ratio is inadequate and unfair to Ocean common stockholders; and
• the defendants breached their fiduciary duties to Ocean stockholders, including the duty of care and the duty of loyalty, or aided and abetted in the breach of those fiduciary duties, by, among other things, (1) failing to conduct a “full and fair auction process or active market check;” (2) agreeing to the terms of the merger agreement, including a non-solicitation provision and the termination fee that is payable by Ocean to Devon under certain circumstances; (3) failing to make an informed decision; (4) failing to ensure that conflicts of interest are resolved in the best interests of Ocean’s public stockholders; (5) personally benefiting from the merger; and (6) not appointing “any truly independent person or entity” to negotiate on behalf of Ocean stockholders.

The complaint seeks class action status. It also seeks (1) injunctive relief against completing the merger or, if the merger is completed, rescission of the merger; (2) monetary damages in an unspecified amount; and (3) recovery of the plaintiff’s costs and attorneys’ fees. Ocean believes that the lawsuit is without merit and intends to defend against it vigorously. We can provide no assurance that additional claims may not be made or filed the substance of which is similar to the allegations described above or that otherwise might arise from, or in connection with, the merger agreement and related transactions.

19.   Oil and Gas Operations

Capitalized Costs Relating to Oil and Gas Producing Activities
(Amounts in Thousands)

				Equatorial						Côte			Other
	Domestic			Guinea			Egypt			d’Ivoire			International			Total
December 31, 2002:
Proved oil and
gas properties	$	3,970,367		$	732,360		$	215,052		$	183,631		$	83,613		$	5,185,023
Oil and gas properties
excluded from
amortization		517,038			78,251			22,478			--			134,945	(1)		752,712
Total capitalized costs		4,487,405			810,611			237,530			183,631			218,558			5,937,735
Accumulated depreciation,
depletion and amortization		(2,015,444	)		(370,212	)		(93,344	)		(138,842	)		(20,788	)		(2,638,630	)
Net capitalized costs	$	2,471,961		$	440,399		$	144,186		$	44,789		$	197,770		$	3,299,105
December 31, 2001:
Proved oil and gas properties	$	4,036,538		$	596,849		$	171,118		$	183,076		$	76,033		$	5,063,614
Oil and gas properties
excluded from amortization		510,489			66,927			24,276			--			173,196			774,888
Total capitalized costs		4,547,027			663,776			195,394			183,076			249,229			5,838,502
Accumulated depreciation,
depletion and amortization		(2,274,508	)		(311,301	)		(63,797	)		(126,966	)		(14,654	)		(2,791,226	)
Net capitalized costs	$	2,272,519		$	352,475		$	131,597		$	56,110		$	234,575		$	3,047,276

(1) Other International unproved properties are located in Angola ($81 million), Brazil ($37 million), and other international locations ($17 million).

81

Ocean Energy, Inc.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(Amounts in Thousands)

			Equatorial					Côte		Other
	Domestic		Guinea		Egypt			d’Ivoire		International		Total
Year Ended December 31, 2002:
Acquisition costs:
Proved	$	5,756	$	--	$	--		$	--	$	--	$	5,756
Unproved		125		--		--			--		--		125
Leasehold unproved costs		52,095		5,209		4,658			--		6,421		68,383
Exploration costs		190,952		18,782		4,537			203		41,830		256,304
Development costs		265,495		117,826		33,924			145		6,941		424,331
Total costs incurred	$	514,423	$	141,817	$	43,119		$	348	$	55,192	$	754,899
Year Ended December 31, 2001:
Acquisition costs:
Proved	$	234,510	$	--	$	--		$	--	$	--	$	234,510
Unproved		70,217		--		--			--		500		70,717
Leasehold unproved costs		55,903		5,299		1,782			--		30,484		93,468
Exploration costs		270,584		9,747		32,986			1,539		38,096		352,952
Development costs		307,060		64,613		26,760			1,764		11,427		411,624
Total costs incurred	$	938,274	$	79,659	$	61,528		$	3,303	$	80,507	$	1,163,271
Year Ended December 31, 2000:
Acquisition costs:
Proved	$	6,276	$	--	$	(727	)	$	--	$	--	$	5,549
Unproved		--		--		--			--		--		--
Leasehold unproved costs		46,915		7,860		2,044			--		5,531		62,350
Exploration costs		148,703		5,595		6,132			1,510		40,920		202,860
Development costs		191,318		68,179		13,985			14,695		12,070		300,247
Total costs incurred	$	393,212	$	81,634	$	21,434		$	16,205	$	58,521	$	571,006

     Costs being excluded from amortization consist of the following at December 31, 2002, and are presented by the year incurred (in thousands):

			Year Ended December 31,
		Total		2002		2001		2000		1999 and Prior
Unproved property costs	$	494,230	$	105,945	$	144,762	$	63,653	$	179,870
Exploration costs		194,367		104,786		72,141		9,149		8,291
Development costs		64,115		9,565		--		11,599		42,951
	$	752,712	$	220,296	$	216,903	$	84,401	$	231,112

82

Ocean Energy, Inc.

Results of Operations for Oil and Gas Producing Activities
(Amounts in Thousands)

			Equatorial				Côte		Other
	Domestic		Guinea		Egypt		d’Ivoire		International			Total
Year Ended December 31, 2002:
Revenues	$	720,569	$	278,405	$	79,032	$	46,882	$	37,195		$	1,162,083
Production–related
operating expenses(1)		217,369		29,432		11,542		10,780		19,496			288,619
DD&A(2)		247,002		59,423		29,547		15,070		6,703			357,745
Impairment of oil and
gas properties		--		--		--		--		76,400			76,400
Income tax expense (benefit)(3)		96,074		95,260		13,840		7,386		(18,433	)		194,127
Results of activities	$	160,124	$	94,290	$	24,103	$	13,646	$	(46,971	)	$	245,192
Year Ended December 31, 2001:
Revenues	$	881,460	$	220,354	$	70,161	$	42,722	$	40,769		$	1,255,466
Production–related
operating expenses(1)		204,226		19,539		10,621		10,561		15,492			260,439
DD&A(2)		235,008		55,094		25,315		15,401		13,524			344,342
Income tax expense(3)		165,835		80,577		15,906		13,856		9,632			285,806
Results of activities	$	276,391	$	65,144	$	18,319	$	2,904	$	2,121		$	364,879
Year Ended December 31, 2000:
Revenues	$	711,012	$	193,840	$	77,563	$	47,729	$	43,410		$	1,073,554
Production–related
operating expenses(1)		156,976		18,311		14,378		10,318		11,195			211,178
DD&A(2)		198,669		55,192		21,352		17,753		12,010			304,976
Impairment of oil and
gas properties		--		--		--		--		20,066			20,066
Income tax expense(3)		133,262		62,668		15,680		9,776		7,241			228,627
Results of activities	$	222,105	$	57,669	$	26,153	$	9,882	$	(7,102	)	$	308,707

(1) Operating expenses represent costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among other things, repairs and maintenance, labor, materials, supplies, property taxes, insurance, severance taxes, transportation expense, and all overhead expenses directly related to oil and gas producing activities.

(2) DD&A represents depreciation, depletion and amortization.

(3) Income tax expense (benefit) is calculated by applying the statutory tax rate to operating profit, then adjusting for any applicable permanent tax differences or tax credits and allowances.

83

Ocean Energy, Inc.

20.    Supplemental Oil and Gas Information (Unaudited)

Reserve Quantity Information

				Equatorial						Côte			Other
	Domestic			Guinea			Egypt			d’Ivoire			International			Total
Proved Reserves (MBOE):
January 1, 2002		378,553			122,857			31,418			29,758			38,247			600,833
Revisions of previous estimates		11,620			(4,071	)		(5,604	)		(1,182	)		(5,669	)		(4,906	)
Extensions and discoveries		51,224			10,100			440			--			3,551			65,315
Purchases of reserves in place		1,931			--			--			--			--			1,931
Sales of reserves in place		(13,807	)		--			--			--			--			(13,807	)
Production		(35,590	)		(12,054	)		(3,455	)		(2,483	)		(2,364	)		(55,946	)
December 31, 2002		393,931			116,832			22,799			26,093			33,765			593,420
January 1, 2001		284,448			97,082			16,110			30,042			32,439			460,121
Revisions of previous estimates		582			27,887			2,074			2,034			4,862			37,439
Extensions and discoveries		101,738			9,000			16,394			--			3,300			130,432
Purchases of reserves in place		43,052			--			--			--			--			43,052
Sales of reserves in place		(15,774	)		--			--			--			--			(15,774	)
Production		(35,493	)		(11,112	)		(3,160	)		(2,318	)		(2,354	)		(54,437	)
December 31, 2001		378,553			122,857			31,418			29,758			38,247			600,833
January 1, 2000		282,483			48,223			20,722			36,529			27,040			414,997
Revisions of previous estimates		(2,153	)		48,008			(1,371	)		(3,653	)		4,073			44,904
Extensions and discoveries		74,353			9,195			23			--			3,674			87,245
Purchases of reserves in place		1,193			--			--			--			--			1,193
Sales of reserves in place		(38,666	)		--			--			--			--			(38,666	)
Production		(32,762	)		(8,344	)		(3,264	)		(2,834	)		(2,348	)		(49,552	)
December 31, 2000		284,448			97,082			16,110			30,042			32,439			460,121
Proved Developed Reserves (MBOE):
December 31, 2002		254,561			32,763			16,512			12,286			26,112			342,234
December 31, 2001		258,067			32,394			12,247			12,358			28,769			343,835
December 31, 2000		185,673			22,302			7,672			11,104			21,210			247,961
December 31, 1999		225,773			18,381			11,003			13,382			18,285			286,824
Proved Developed Oil Reserves
(MBbl):
December 31, 2002		80,258			32,763			16,425			3,895			18,826			152,167
December 31, 2001		73,679			32,394			12,129			3,497			20,950			142,649
December 31, 2000		43,477			22,302			7,572			2,750			14,962			91,063
December 31, 1999		74,445			18,381			10,809			2,836			11,929			118,400
Proved Developed Gas Reserves
(MMcf):
December 31, 2002		1,045,816			--			519			50,345			43,720			1,140,400
December 31, 2001		1,106,330			--			709			53,165			46,911			1,207,115
December 31, 2000		853,176			--			608			50,121			37,487			941,392
December 31, 1999		907,968			--			1,167			63,273			38,134			1,010,542

     The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of future operations of the Company and changes in economic conditions. Reserves for Equatorial Guinea, Egypt and Côte d’Ivoire are shown in accordance with the terms of production sharing contracts. The reserves include estimated quantities allocated to Ocean for recovery of costs and taxes and Ocean’s net equity share after recovery of such costs.

84

Ocean Energy, Inc.

Reserve Quantity Information

				Equatorial						Côte			Other
	Domestic			Guinea			Egypt			d’Ivoire			International			Total
Proved Oil Reserves (MBbl):
January 1, 2002		115,537			122,857			31,299			4,672			30,428			304,793
Revisions of previous estimates		10,945			(4,071	)		(5,638	)		1,506			(5,523	)		(2,781	)
Extension and discoveries		15,089			10,100			440			--			3,551			29,180
Purchases of reserves in place		774			--			--			--			--			774
Sales of reserves in place		(5,083	)		--			--			--			--			(5,083	)
Production		(11,445	)		(12,054	)		(3,429	)		(1,134	)		(1,977	)		(30,039	)
December 31, 2002		125,817			116,832			22,672			5,044			26,479			296,844
January 1, 2001		80,682			97,082			16,008			4,238			23,635			221,645
Revisions of previous estimates		3,896			27,887			2,020			1,600			5,422			40,825
Extension and discoveries		41,071			9,000			16,394			--			3,300			69,765
Purchases of reserves in place		12,463			--			--			--			--			12,463
Sales of reserves in place		(12,405	)		--			--			--			--			(12,405	)
Production		(10,170	)		(11,112	)		(3,123	)		(1,166	)		(1,929	)		(27,500	)
December 31, 2001		115,537			122,857			31,299			4,672			30,428			304,793
January 1, 2000		89,808			48,223			20,492			7,039			18,237			183,799
Revisions of previous estimates		(330	)		48,008			(1,279	)		(1,392	)		3,520			48,527
Extension and discoveries		27,546			9,195			23			--			3,674			40,438
Purchases of reserves in place		406			--			--			--			--			406
Sales of reserves in place		(26,774	)		--			--			--			--			(26,774	)
Production		(9,974	)		(8,344	)		(3,228	)		(1,409	)		(1,796	)		(24,751	)
December 31, 2000		80,682			97,082			16,008			4,238			23,635			221,645
Proved Gas Reserves (MMcf):
January 1, 2002		1,578,095			--			722			150,513			46,911			1,776,241
Revisions of previous estimates		4,047			--			191			(16,129	)		(861	)		(12,752	)
Extension and discoveries		216,813			--			--			--			--			216,813
Purchases of reserves in place		6,940			--			--			--			--			6,940
Sales of reserves in place		(52,345	)		--			--			--			--			(52,345	)
Production		(144,870	)		--			(152	)		(8,090	)		(2,330	)		(155,442	)
December 31, 2002		1,608,680			--			761			126,294			43,720			1,779,455
January 1, 2001		1,222,602			--			609			154,825			52,820			1,430,856
Revisions of previous estimates		(19,892	)		--			331			2,602			(3,357	)		(20,316	)
Extension and discoveries		364,000			--			--			--			--			364,000
Purchases of reserves in place		183,538			--			--			--			--			183,538
Sales of reserves in place		(20,216	)		--			--			--			--			(20,216	)
Production		(151,937	)		--			(218	)		(6,914	)		(2,552	)		(161,621	)
December 31, 2001		1,578,095			--			722			150,513			46,911			1,776,241
January 1, 2000		1,156,049			--			1,375			176,943			52,820			1,387,187
Revisions of previous estimates		(10,935	)		--			(549	)		(13,566	)		3,312			(21,738	)
Extension and discoveries		280,840			--			--			--			--			280,840
Purchases of reserves in place		4,723			--			--			--			--			4,723
Sales of reserves in place		(71,353	)		--			--			--			--			(71,353	)
Production		(136,722	)		--			(217	)		(8,552	)		(3,312	)		(148,803	)
December 31, 2000		1,222,602			--			609			154,825			52,820			1,430,856

     The Company’s standardized measure of discounted future net cash flows as of December 31, 2002 and 2001, and changes therein for each of the years 2002, 2001 and 2000, are provided based on the present value of future net revenues from proved oil and gas reserves. The Company’s estimates of proved oil and gas reserves are prepared by internal petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission and are reviewed by an independent petroleum engineering firm. These estimates were computed by applying year–end prices for oil and gas to estimated future production of proved oil and gas reserves over the economic lives of the reserves and

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Ocean Energy, Inc.

assuming continuation of existing operating conditions. Year–end 2002 and 2001 calculations were made using net estimated realized prices at December 31, 2002 and 2001. The following table shows the net estimated realized prices used in the calculation as well as the base pricing used before any adjustments for location, transportation or other factors:

	December 31,
		2002			2001
Oil and NGL Prices ($ per Bbl):
Year–end prices used for standardized measure of
discounted future net cash flows	$	27	.41	$	17	.23
Average realized oil and NGL prices excluding the
impact of financial derivatives	$	22	.32	$	21	.48
NYMEX WTI at Cushing	$	31	.20	$	19	.84
Brent	$	28	.66	$	19	.01
Natural Gas Prices ($ per Mcf):
Year–end prices used for standardized measure of
discounted future net cash flows	$	4	.54	$	2	.64
Average realized gas prices excluding the
impact of financial derivatives	$	3	.19	$	4	.18
Henry Hub	$	4	.74	$	2	.65

     Because the disclosure requirements are standardized, significant changes can occur in these estimates based upon oil and gas prices in effect at year end. The following estimates should not be viewed as an estimate of fair market value. Income taxes are computed by applying the statutory income tax rate in the jurisdiction to the net cash inflows relating to proved oil and gas reserves less the tax bases of the properties involved and giving effect to appropriate net operating loss carryforwards, tax credits and allowances relating to such properties.

86

Ocean Energy, Inc.

Standardized Measure of Discounted Future Net Cash Flows
(Amounts in Thousands)

				Equatorial						Côte			Other
	Domestic			Guinea			Egypt			d’Ivoire			International			Total
December 31, 2002:
Future cash inflows	$	11,028,927		$	3,308,674		$	621,720		$	531,722		$	718,626		$	16,209,669
Future development costs		(1,111,006	)		(323,220	)		(72,642	)		(89,149	)		(30,021	)		(1,626,038	)
Future production costs		(2,743,972	)		(807,484	)		(145,948	)		(121,647	)		(289,924	)		(4,108,975	)
Future net cash flows before
income taxes		7,173,949			2,177,970			403,130			320,926			398,681			10,474,656
10% annual discount		(2,834,717	)		(777,829	)		(118,210	)		(155,272	)		(184,582	)		(4,070,610	)
Discounted future
net cash flows
before income taxes		4,339,232			1,400,141			284,920			165,654			214,099			6,404,046
Discounted income taxes		(1,078,806	)		(404,120	)		(70,998	)		(61,909	)		(79,721	)		(1,695,554	)
Standardized measure
of discounted
future net cash flows	$	3,260,426		$	996,021		$	213,922		$	103,745		$	134,378		$	4,708,492
December 31, 2001:
Future cash inflows	$	6,299,765		$	2,150,338		$	557,149		$	409,176		$	529,131		$	9,945,559
Future development costs		(839,346	)		(252,411	)		(117,410	)		(91,225	)		(37,090	)		(1,337,482	)
Future production costs		(2,030,995	)		(413,738	)		(84,464	)		(106,064	)		(258,325	)		(2,893,586	)
Future net cash flows before
income taxes		3,429,424			1,484,189			355,275			211,887			233,716			5,714,491
10% annual discount		(1,417,802	)		(529,891	)		(125,218	)		(116,784	)		(118,362	)		(2,308,057	)
Discounted future
net cash flows
before income taxes		2,011,622			954,298			230,057			95,103			115,354			3,406,434
Discounted income taxes		(257,220	)		(256,611	)		(50,236	)		(31,928	)		(41,551	)		(637,546	)
Standardized measure
of discounted
future net cash flows	$	1,754,402		$	697,687		$	179,821		$	63,175		$	73,803		$	2,768,888

Principal Sources of Change in the Standardized Measure of
Discounted Future Net Cash Flows
(Amounts in Thousands)

	Year Ended December 31,
		2002			2001			2000
Beginning of Year	$	2,768,888		$	5,846,993		$	2,415,418
Revisions of previous quantity estimates less related costs		(38,702	)		298,266			568,080
Extensions and discoveries less related costs		545,467			462,453			1,960,883
Purchases of reserves in place		5,756			234,510			5,549
Sales of reserves in place		(74,192	)		(63,791	)		(86,043	)
Net changes in future prices and production costs		3,044,998			(6,076,392	)		3,775,961
Future development costs incurred during the period		424,331			411,625			300,247
Sales of oil and gas produced, net of production costs		(849,892	)		(948,361	)		(816,672	)
Accretion of discount		340,643			848,836			295,185
Net changes in income taxes		(1,058,008	)		2,003,829			(2,104,939	)
Changes in estimated future development costs, production,
timing and other		(400,797	)		(249,080	)		(466,676	)
		1,939,604			(3,078,105	)		3,431,575
End of Year	$	4,708,492		$	2,768,888		$	5,846,993

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Ocean Energy, Inc.

Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     None.

Part III

Item 10.   Directors and Executive Officers of the Registrant

     The information required by Part III, Item 10 of this Form 10–K will be incorporated by reference to the following section of the Company’s definitive proxy statement for its annual meeting of stockholders in 2003 – “Election of Directors.” To the extent that such proxy statement is not filed within 120 days of the Company’s fiscal year end, the Company will file an amendment to this Form 10-K to include such information.

Item 11.   Executive Compensation

     The information required by Part III, Item 11 of this Form 10–K will be incorporated by reference to the following sections of the Company’s definitive proxy statement for its annual meeting of stockholders in 2003 – “Executive Compensation — Summary Compensation Table,” “—Compensation Arrangements,” “—Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year–End Option/SAR Values,” “—Option/SAR Grants in Last Fiscal Year,” and “—Executive Supplemental Retirement Plan” and “Election of Directors—Compensation of Directors.” To the extent that such proxy statement is not filed within 120 days of the Company’s fiscal year end, the Company will file an amendment to this Form 10–K to include such information. Notwithstanding any provision in this Annual Report on Form 10–K to the contrary, under no circumstances are the “Report of the Organization and Compensation Committee on Executive Compensation” or the information under the heading “Stockholder Return Performance Presentation” incorporated herein for any purpose.

Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     The information required by Part III, Item 12 of this Form 10–K will be incorporated by reference to the following sections of the Company’s definitive proxy statement for its annual meeting of stockholders in 2003 – “Principal Stockholders,” “Election of Directors — Security Ownership of Directors and Management.” To the extent that such proxy statement is not filed within 120 days of the Company’s fiscal year end, the Company will file an amendment to this Form 10–K to include such information.

Item 13.   Certain Relationships and Related Transactions

     The information required by Part III, Item 13 of this Form 10–K will be incorporated by reference to the following section of the Company’s definitive proxy statement for its annual meeting of stockholders in 2003 – “Election of Directors — Certain Transactions.” To the extent that such proxy statement is not filed within 120 days of the Company’s fiscal year end, the Company will file an amendment to this Form 10–K to include such information.

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Ocean Energy, Inc.

Item 14.   Controls and Procedures

     Within 90 days prior to the filing date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the Company’s disclosure controls and procedures (as defined in Rule 13a–14(c) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective.

     There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Part IV

Item 15.   Exhibits, Financial Statement Schedules and Reports on Form 8–K

(a)          1. Financial Statements:

     The following financial statements, the Report of Management to Stockholders and the Independent Auditors’ Report are filed as a part of this report on the pages indicated:

	Page
Report of Management to Stockholders		50
Independent Auditor’s Report		51
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000		52
Consolidated Balance Sheets – December 31, 2002 and 2001		53
Consolidated Statements of Cash Flows for the Years Ended December 31, 1002, 2001 and 2000		54
Consolidated Statements of Stockholders’ Equity for the Years Ended
December 31, 2002, 2001 and 2000		55

2.  Schedules:

     All schedules have been omitted because the required information is insignificant or not applicable.

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Ocean Energy, Inc.

3.  Exhibits:

2.1 Agreement and Plan of Merger (the "Merger Agreement"), dated as of February 23, 2003, among Ocean, Devon Energy Corporation (“Devon”) and Devon Newco Corporation, a wholly owned subsidiary of Devon (incorporated by reference to Exhibit 2.1) to the Company’s current report on Form 8–K filed with the Securities and Exchange Commission (the “SEC”) on February 25, 2003.

2.2 Agreement and Plan of Merger, dated March 30, 2001, by and between Ocean Energy Inc., a Texas corporation, and Ocean Energy Inc., a Delaware corporation, incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

3.1 Certificate of Incorporation of Ocean Energy, Inc., a Delaware corporation, incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

3.2 Bylaws of Ocean Energy, Inc., a Delaware corporation, incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

3.3 Certificate of Designations relating to Series B Convertible Preferred Stock of Ocean Energy, Inc., a Delaware corporation, incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.1 Amended and Restated Rights Agreement dated March 17, 1989, as amended effective June 13, 1992, and amended and restated as of December 12, 1997, between the Company and Equiserve Trust Company, N.A., including Form of Statement of Resolution Establishing the Series B Junior Participating Preferred Stock, the Form of Right Certificate and Form of Summary of Rights to Purchase Preferred Shares (the Agreement is incorporated by reference to Exhibit 2 to Current Report on Form 8–K dated December 15, 1997; Amendment No. 1 dated November 24, 1998 is incorporated by reference to Exhibit 4.1 to Current Report on Form 8–K filed on December 1, 1998). Amendment No. 2, dated as of March 10, 1999, is incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on March 12, 1999; Amendment No. 3, dated as of May 19, 1999, is incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 21, 1999). Amendment No. 4, dated as of May 19, 2000, is incorporated by reference to the Company’s Current Report on Form 8–K filed with the SEC on May 22, 2000; Amendment No. 5, dated as of May 9, 2001, incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001; Amendment No. 6, dated as of December 12, 2001, incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001; Amendment No. 7, dated as of February 23, 2003, incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K, as filed with the SEC on February 25, 2003.

4.2 Revolving Credit Agreement dated as of May 31, 2002, by and among Ocean Energy, Inc., a Delaware corporation, Ocean Energy, Inc. (a Louisiana corporation) and the lenders signatory thereto (as incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8–K, as filed with the SEC on June 3, 2002).

4.3 Guaranty Agreement dated as of May 31, 2002 by and among Ocean Energy, Inc., (a Louisiana corporation), and the lenders signatory thereto (as incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8–K, as filed with the SEC on June 3, 2002).

4.4 Senior Indenture dated as of July 15, 1993, relating to the 7 7/8% Notes due 2003, by and between the Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10–Q for the quarter ended March 31, 1998); First Supplemental Indenture, dated as of March 30, 1999, is incorporated by reference to Exhibit 4.11 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

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Ocean Energy, Inc.

4.5 Senior Indenture among the Company and The Bank of New York, as Trustee, and Specimen of 7 1/2% Senior Notes (incorporated by reference to Exhibit 4.4 to Annual Report on Form 10–K for the year ended December 31, 1997; the First Supplemental Indenture, dated as of March 30, 1999, is incorporated by reference to Exhibit 4.10 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.4 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.6 Indenture, dated as of July 8, 1998, among Ocean Energy, Inc., its Subsidiary Guarantors, and U.S. Bank Trust National Association, relating to the 8 3/8% Series A Senior Subordinated Notes due 2008 and the 8 3/8% Series B Senior Subordinated Notes due 2008 (the Indenture is incorporated by reference to Exhibit 10.22 to the Form 10–Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0–25058); the First Supplemental Indenture, dated March 30, 1999, is incorporated by reference to Exhibit 4.3 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001 incorporated by reference to Exhibit 99.7 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.7 Indenture, dated as of July 8, 1998, among Ocean Energy, Inc., its Subsidiary Guarantors, and Norwest Bank Minnesota, National Association (Norwest Bank) as Trustee, relating to the 7 5/8% Senior Notes due 2005 (the Indenture is incorporated by reference to Exhibit 10.23 to the Form 10–Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0–25058); the First Supplemental Indenture, dated March 30, 1999, is incorporated by reference to Exhibit 4.4 to the Company’s Form 10’Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.8 Indenture, dated as of July 8, 1998, among Ocean Energy, Inc., its Subsidiary Guarantors, and Norwest Bank as Trustee, relating to the 8 1/4% Senior Notes due 2018 (the Indenture is incorporated by reference to Exhibit 10.24 to the Form 10–Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0–25058); the First Supplemental Indenture, dated March 30, 1999, is incorporated by reference to Exhibit 4.5 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.9 Senior Indenture dated as of September 28, 2001 between Ocean Energy, Inc. (a Louisiana corporation) and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on September 28, 2001). Officer’s Certificate establishing the terms of the 7 1/4% Senior Notes due October 1, 2011, including the form of global note relating thereto (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8–K filed with the SEC on September 28, 2001).

4.10 Purchase Agreement dated as of September 17, 2002 relating to the 4.375% Senior Notes Due October 1, 2007 by and among the Company and the underwriters named therein (incorporated by reference to Exhibit 1.1 to the Company’s Current Report on Form 8–K filed with the SEC on September 17, 2002). Officers’ Certificate evidencing the terms of the 4.375% Senior Notes due October 1, 2007, including the form of global note relating thereto (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on September 17, 2002).

#10.1 1999 Long–Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 10–Q for the period ended June 30, 1999).

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Ocean Energy, Inc.

#10.2 Seagull Energy Corporation 1983 Stock Option Plan (Restated), including forms of agreements, as amended (plan is incorporated by reference to Exhibit 10.4 to Quarterly Report on Form 10–Q for the quarter ended March 31, 1998).

#10.3 Seagull Energy Corporation 1990 Stock Option Plan, including forms of agreements, as amended (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended March 31, 2001); Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.5 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001.

#10.4 Global Natural Resources Inc. 1989 Key Employees Stock Option Plan incorporated by reference to Exhibit 4.1 to Registration Statement No. 33–31537 of Global Natural Resources Inc.; Form of Stock Option Agreement incorporated by reference to Exhibit 4.2 to Registration Statement No. 33–31537 of Global Natural Resources Inc.; Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10–K for the ear ended December 31, 2001.

#10.5 Global Natural Resources Inc. 1992 Stock Option Plan and Form of Stock Option Agreement (incorporated by reference to Exhibit 10.7 to Annual Report on Form 10–K for the year ended December 31, 2000); Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.7 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001.

#10.6 Seagull Energy Corporation 1993 Nonemployee Directors’ Stock Option Plan, including forms of agreements, as amended (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1997).

#10.7 Seagull Energy Corporation 1993 Stock Option Plan, as amended (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1997).

#10.8 1995 Omnibus Stock (incorporated by reference to exhibit 10.10 to Annual Report on Form 10–K for the year ended December 31, 2000); Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001).

#10.9 1998 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended June 30, 1998).

#10.10 UMC 1987 Nonqualified Stock Option Plan, as amended, (the Plan is incorporated herein by reference to Exhibit 10.3 to UMC’s Form S–1 (No. 33-63532) filed with the SEC on May 28, 1993; the Third Amendment, dated November 16, 1993, and the Fourth Amendment, dated April 6, 1994, are incorporated by reference to Exhibit 10.12 to Annual Report on Form 10–K for the year ended December 31, 2000; the Fifth Amendment, dated November 19, 1997, is incorporated by reference to Exhibit 4.7 to UMC’s Form S–3 (No. 333–42467); the Sixth Amendment, dated March 27, 1998, and the Seventh Amendment, dated February 1, 1999, are incorporated by reference to Exhibit 10.3 to Form 10–Q for the period ended March 31, 1999).

#10.11 UMC 1994 Employee Nonqualified Stock Option Plan, as amended (the Plan is incorporated by reference to Exhibit 4.14 to UMC’s Form S–8 (No. 33-79160) filed with the SEC on May 19, 1994; the First Amendment, dated November 16, 1994, is incorporated by reference to Exhibit 4.11.1 to UMC’s Form S–8 (No. 33–86480) filed with the SEC on November 18, 1994; the Second Amendment, dated May 22, 1996, is incorporated by reference to Exhibit 4.3.2 to UMC’s Form S–8 (No. 333–05401) filed with the SEC on June 6, 1996; the Third Amendment, dated November 13, 1996, is incorporated by reference to Exhibit 4.3.3 to UMC’s Form S–8 (No. 333–28017) filed with the SEC on May 29, 1997; the Fourth Amendment, dated May 29, 1997, is incorporated herein by reference to Exhibit 4.3.4 to UMC’s Form S–8 (No. 333–28017) filed with the SEC on May 29, 1997; the Fifth Amendment, dated November 19, 1997, is incorporated by reference to Exhibit 4.8 to UMC’s Form S–3 (No. 333–42467) filed with the SEC on December 17, 1997; the Sixth Amendment, dated March 27, 1998 is incorporated by reference to Exhibit 10.4 to Form 10–Q for the period ended March 31, 1999).

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Ocean Energy, Inc.

#10.12 UMC 1994 Outside Directors’ Nonqualified Stock Option Plan, as amended (the Plan is incorporated herein by reference to Exhibit 4.15 to UMC’s Form S–8 (No. 33–79160) filed with the SEC on May 19, 1994; the First Amendment, dated May 22, 1996, is incorporated by reference to Exhibit 4.4.1 to UMC’s Form S–8 (No. 333–05401) filed with the SEC on June 6, 1996; the Second Amendment, dated November 13, 1996, is incorporated herein by reference to Exhibit 4.4 to UMC’s Form S–8 (No. 333–28017) filed with the SEC on May 29, 1997; the Third Amendment, dated November 19, 1997, is incorporated by reference to Exhibit 4.9 to UMC’s Form S–3 (No. 333–42467); Fourth Amendment, dated March 27, 1998 is incorporated by reference to Exhibit 10.6 to Form 10–Q for the period ended March 31, 1999).

#10.13 1994 Long–Term Incentive Plan (the Plan, as amended, is incorporated by reference to Exhibit 10.3 to Amendment No. 2 to the Registration Statement on Form S–1 (No. 33–84308) of Ocean Energy, Inc. (Registration No. 0–25058); the Second Amendment, dated March 27, 1998 is incorporated by reference to Exhibit 4.2 to Form 10–Q for the period ended March 31, 1999).

#10.14 1996 Long–Term Incentive Plan, as amended (the Plan, as amended, is incorporated by reference to Exhibit 99.1 to the Form S–8 (No. 333–45117) of Ocean Energy, Inc. (Registration No. 0–25058) filed with the SEC on January 29, 1998; the Second Amendment, dated March 27, 1998, is incorporated by reference to Exhibit 4.2 to Form 10–Q for the period ended March 31, 1999).

#10.15 1998 Long–Term Incentive Plan (incorporated by reference to Appendix E to Ocean Energy, Inc.’s Joint Proxy Statement Prospectus on Form S–4 (333–43933) filed with the SEC on January 9, 1998).

#10.16 Long–Term Incentive Plan for Non–Executive Employees, as amended (the Plan, as amended, is incorporated by reference to Exhibit 99.1 to the Form S–8 (No. 333–45119) of Ocean Energy, Inc. (Registration No. 0–25058); Amendment No. 2, incorporated by reference to Exhibit 99.2 to the Form S–8 (No. 333–49185) of Ocean Energy, Inc.; Amendment No. 3, dated as of May 20, 1998, is incorporated by reference to Exhibit 10.46 to the Annual Report on Form 10–K for the year ended December 31, 1998, of Ocean Energy, Inc. (Registration No. 0–25058); Amendment No. 4 is incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10–K for the year ended December 31, 1999; Amendment No. 5 is incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended September 30, 2001; Amendment No. 6 is incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10–K for the year ended December 31, 2001; Amendment No. 7 is incorporated by reference to incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S–8, (No. 333–100903), filed with the SEC on October 31, 2002.

#10.17 Ocean Energy, Inc. 2001 Long–Term Incentive Plan, incorporated by reference to Exhibit 99.9 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

#10.18 Outside Directors Deferred Fee Plan as Amended and Restated Effective July 1, 2001 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended June 30, 2001).

#10.19 Ocean Energy, Inc. Directors Compensation Plan (as amended and restated effective July 1, 2002), (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended June 30, 2002).

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Ocean Energy, Inc.

#10.20 Ocean Energy Inc. Executive Supplemental Retirement Plan (as Amended and Restated) as of July 1, 2001 (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10–Q for the quarter ended September 30, 2001); Amendment No. 1 effective July 18, 2002 is incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10–Q for the quarter ended June 30 2002.

#10.21 Ocean Energy Inc. Supplemental Benefit Plan, as Amended and Restated Effective July 1, 2001 (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10–Q for the quarter ended June 30, 2001).

#10.22 Ocean Energy, Inc. Excess Benefit Plan dated September 29, 2000, incorporated by reference to the Company’s Form 10–Q for the quarter ended September 30, 2000; First Amendment thereto, dated December 14, 2000, (incorporated by reference to Exhibit 10.24 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.23 Form of Indemnification Agreements among the Company and certain executive officers and directors (incorporated by reference to Exhibit 10.19 to Form 10–Q for the period ended March 31, 1999).

#10.24 Employment Agreement by and between the Company and James T. Hackett, as amended (the Agreement is incorporated by reference to Exhibit 10.6 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998; Amendment to Employment Agreement dated November 24, 1998 is incorporated by reference to Exhibit 10.15 to Form 10–Q for the period ended March 31, 1999; Second Amendment to Employment Agreement, effective as of December 15, 1999, is incorporated by reference to Exhibit 99.2 to Current Report on Form 8–K filed with the SEC on January 7, 2000; Third Amendment to Employment Agreement, dated as of February 23, 2003, is incorporated by reference to the Company’s Current Report on Form 8–K filed with the SEC on February 25, 2003).

#10.25 Employment and Consulting Agreement by and between the Company and Barry J. Galt, as amended (the Agreement is incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998; Amendment to Employment and Consulting Agreement dated November 24, 1998 is incorporated by reference to Exhibit 10.16 to Form 10–Q for the period ended March 31, 1999; Second Amendment to Employment and Consulting Agreement is incorporated by reference to Exhibit 10.6 to Form 10–Q for the period ended June 30, 1999).

#10.26 Employment Agreement between the Company and Robert K. Reeves (incorporated by reference to Exhibit 10.41 to Form 10–Q for the period ended June 30, 1999).

#10.27 Employment Agreement between the Company and William L. Transier (incorporated by reference to Exhibit 10.5 to Form 10–Q for the period ended June 30, 1999).

#10.28 Employment Agreement between the Company and John D. Schiller Jr. dated July 20, 2000 (incorporated by reference to Exhibit 10.4 to the Company’s Form 10–Q for the period ended September 30, 2000).

#10.29 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and James T. Hackett (incorporated by reference to Exhibit 10.7 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998); First Amendment to Executive Supplemental Retirement Plan Membership Agreement effective as of June 26, 2000, incorporated by reference to Exhibit 10.3 to the Company’s Form 10–Q for the period ended September 30, 2000; Second Amendment to Executive Supplemental Retirement Plan Membership Agreement effective as of January 1, 2001, (incorporated by reference to Exhibit 10.33 to Annual Report on Form 10–K for the year ended December 31, 2000).

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Ocean Energy, Inc.

#10.30 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and Robert K. Reeves effective January 1, 2001 (incorporated by reference to Exhibit 10.35 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.31 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and John D. Schiller effective January 1, 2001 (incorporated by reference to Exhibit 10.36 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.32 Executive Supplemental Retirement Plan Membership Agreement between the Company and Barry J. Galt dated as of February 3, 1986, as amended (incorporated by reference to Exhibit 10.34 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001).

#10.33 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and William L. Transier effective January 1, 2001 (incorporated by reference to Exhibit 10.37 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.34 Severance Agreement between the Company and James T. Hackett, as amended (incorporated by reference to Exhibit 10.8 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998). Amendment to Severance Agreement, effective as of December 15, 1999, incorporated by reference to Exhibit 99.1 to Current Report on Form 8–K filed with the SEC on January 7, 2000. Second Amendment to Severance Agreement dated as of February 23, 2003, incorporated by reference to the Company’s Current Report on Form 8–K filed with the SEC on February 25, 2003.

#10.35 Severance Agreement between the Company and Robert L. Thompson dated January 16, 2001, (incorporated by reference to Exhibit 10.40 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.36 Ocean Energy, Inc. 2001 Change of Control Severance Plan dated September 27, 2001 (incorporated by reference to the Company’s Quarterly Report on Form 10–Q for the quarter ended September 30, 2001).

10.37 Ocean Energy, Inc. 2001 Employee Stock Purchase Plan, incorporated by reference to Exhibit 4.8 to the Company’s Form S–8 filed with the SEC on November 13, 2000.

*10.38 Natural Gas Purchase and Sale Agreement dated October 1, 2001 between the Company as Seller and Duke Energy Trading and Marketing, L.L.C., as Buyer incorporated by reference to Exhibit 10.43 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001; Amendment to Natural Gas Purchase and Sale Agreement dated November 14, 2002, filed herewith.

*21.1 Subsidiaries of Ocean Energy, Inc.

*23.1 Consent of KPMG LLP.

*99.1 Certification of Chief Executive Officer of Ocean Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.

*99.2 Certification of Chief Financial Officer of Ocean Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.

*  Filed herewith.

#  Identifies management contracts and compensatory plans or arrangements.

95

Ocean Energy, Inc.

(b)  Reports on Form 8–K

     On February 25, 2003, the Company filed a Current Report on Form 8–K containing the Agreement and Plan of Merger, dated as of February 23, 2003, among Ocean, Devon Energy Corporation ("Devon") and Devon Newco Corporation, a wholly owned subsidiary of Devon. The item reported in such Current Report was Item 5 (Other Events).

96

Ocean Energy, Inc.

Signatures

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Ocean Energy, Inc.

Date: March 7, 2003 By: /s/ James T. Hackett                                        
     James T. Hackett, Chairman of the Board,
     President and Chief Executive Officer
     (Principal Executive Officer)

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

By:     /s/ James T. Hackett                                  
          James T. Hackett, Chairman of the Board,
          President, Chief Executive Officer and Director
          (Principal Executive Officer)
Date:  March 7, 2003 By:     /s/ Peter J. Fluor                 
          Peter J. Fluor, Director
 Date: March 7, 2003
       

By:     /s/ William L. Transier                                  
          William L. Transier, Executive Vice President
          and Chief Financial Officer
          (Principal Financial Officer)
Date:  March 7, 2003 By:     /s/ Barry J. Galt                 
          Barry J. Galt, Director
 Date: March 7, 2003
       

By:     /s/ Robert L. Thompson                               
           Robert L. Thompson, Vice President and
          Controller (Principal Accounting Officer)
Date:  March 7, 2003 By:     /s/ Wanda G. Henton          
          Wanda G. Henton, Director
 Date: March 7, 2003
       

By:     /s/ J. Evans Attwell                                      
           J. Evans Attwell, Director
Date:  March 7, 2003 By:     /s/ Robert L. Howard            
          Robert L. Howard, Director
 Date: March 7, 2003
       

By:     /s/ John B. Brock                                        
           John B. Brock, Director
Date:  March 7, 2003 By:     /s/ Elvis L. Mason                 
          Elvis L. Mason, Director
 Date: March 7, 2003
       

By:     /s/ Milton Carroll                                        
          Milton Carroll, Director
Date:  March 7, 2003 By:     /s/ Charles F. Mitchell, M.D.  
          Charles F. Mitchell, M.D.,
          Director
 Date: March 7, 2003
       

By:     /s/ Thomas D. Clark, Jr.                              
          Thomas D. Clark, Jr., Director
Date:  March 7, 2003 By:     /s/ David K. Newbigging      
          David K. Newbigging,
          Director
 Date: March 7, 2003
       

By:     /s/ Dee S. Osborne              
          Dee S. Osborne, Director
 Date: March 7, 2003
       

97

Ocean Energy, Inc.

Certifications

I, James T. Hackett, certify that:

1. I have reviewed this annual report on Form 10–K of Ocean Energy, Inc.;

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

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

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 7, 2003 By: /s/ James T. Hackett                                        
     James T. Hackett, Chairman of the Board,
     President and Chief Executive Officer

98

Ocean Energy, Inc.

Certifications

I, William L. Transier, certify that:

1. I have reviewed this annual report on Form 10–K of Ocean Energy, Inc.;

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

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

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–14 and 15d–14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 7, 2003 By: /s/ William L. Transier                                        
     William L. Transier
     Executive Vice President
     and Chief Financial Officer

99

Ocean Energy, Inc.

Index to Exhibits

2.1 Agreement and Plan of Merger (the "Merger Agreement"), dated as of February 23, 2003, among Ocean, Devon Energy Corporation (“Devon”) and Devon Newco Corporation, a wholly owned subsidiary of Devon (incorporated by reference to Exhibit 2.1) to the Company’s current report on Form 8–K filed with the Securities and Exchange Commission (the “SEC”) on February 25, 2003.

2.2 Agreement and Plan of Merger, dated March 30, 2001, by and between Ocean Energy Inc., a Texas corporation, and Ocean Energy Inc., a Delaware corporation, incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

3.1 Certificate of Incorporation of Ocean Energy, Inc., a Delaware corporation, incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

3.2 Bylaws of Ocean Energy, Inc., a Delaware corporation, incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

3.3 Certificate of Designations relating to Series B Convertible Preferred Stock of Ocean Energy, Inc., a Delaware corporation, incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.1 Amended and Restated Rights Agreement dated March 17, 1989, as amended effective June 13, 1992, and amended and restated as of December 12, 1997, between the Company and Equiserve Trust Company, N.A., including Form of Statement of Resolution Establishing the Series B Junior Participating Preferred Stock, the Form of Right Certificate and Form of Summary of Rights to Purchase Preferred Shares (the Agreement is incorporated by reference to Exhibit 2 to Current Report on Form 8–K dated December 15, 1997; Amendment No. 1 dated November 24, 1998 is incorporated by reference to Exhibit 4.1 to Current Report on Form 8–K filed on December 1, 1998). Amendment No. 2, dated as of March 10, 1999, is incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on March 12, 1999; Amendment No. 3, dated as of May 19, 1999, is incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 21, 1999). Amendment No. 4, dated as of May 19, 2000, is incorporated by reference to the Company’s Current Report on Form 8–K filed with the SEC on May 22, 2000; Amendment No. 5, dated as of May 9, 2001, incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001; Amendment No. 6, dated as of December 12, 2001, incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001; Amendment No. 7, dated as of February 23, 2003, incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K, as filed with the SEC on February 25, 2003.

4.2 Revolving Credit Agreement dated as of May 31, 2002, by and among Ocean Energy, Inc., a Delaware corporation, Ocean Energy, Inc. (a Louisiana corporation) and the lenders signatory thereto (as incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8–K, as filed with the SEC on June 3, 2002).

4.3 Guaranty Agreement dated as of May 31, 2002 by and among Ocean Energy, Inc., (a Louisiana corporation), and the lenders signatory thereto (as incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8–K, as filed with the SEC on June 3, 2002).

4.4 Senior Indenture dated as of July 15, 1993, relating to the 7 7/8% Notes due 2003, by and between the Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10–Q for the quarter ended March 31, 1998); First Supplemental Indenture, dated as of March 30, 1999, is incorporated by reference to Exhibit 4.11 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

100

Ocean Energy, Inc.

4.5 Senior Indenture among the Company and The Bank of New York, as Trustee, and Specimen of 7 1/2% Senior Notes (incorporated by reference to Exhibit 4.4 to Annual Report on Form 10–K for the year ended December 31, 1997; the First Supplemental Indenture, dated as of March 30, 1999, is incorporated by reference to Exhibit 4.10 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.4 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.6 Indenture, dated as of July 8, 1998, among Ocean Energy, Inc., its Subsidiary Guarantors, and U.S. Bank Trust National Association, relating to the 8 3/8% Series A Senior Subordinated Notes due 2008 and the 8 3/8% Series B Senior Subordinated Notes due 2008 (the Indenture is incorporated by reference to Exhibit 10.22 to the Form 10–Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0–25058); the First Supplemental Indenture, dated March 30, 1999, is incorporated by reference to Exhibit 4.3 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001 incorporated by reference to Exhibit 99.7 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.7 Indenture, dated as of July 8, 1998, among Ocean Energy, Inc., its Subsidiary Guarantors, and Norwest Bank Minnesota, National Association (Norwest Bank) as Trustee, relating to the 7 5/8% Senior Notes due 2005 (the Indenture is incorporated by reference to Exhibit 10.23 to the Form 10–Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0–25058); the First Supplemental Indenture, dated March 30, 1999, is incorporated by reference to Exhibit 4.4 to the Company’s Form 10’Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.8 Indenture, dated as of July 8, 1998, among Ocean Energy, Inc., its Subsidiary Guarantors, and Norwest Bank as Trustee, relating to the 8 1/4% Senior Notes due 2018 (the Indenture is incorporated by reference to Exhibit 10.24 to the Form 10–Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0–25058); the First Supplemental Indenture, dated March 30, 1999, is incorporated by reference to Exhibit 4.5 to the Company’s Form 10–Q for the period ended March 31, 1999); Second Supplemental Indenture, dated as of May 9, 2001, incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

4.9 Senior Indenture dated as of September 28, 2001 between Ocean Energy, Inc. (a Louisiana corporation) and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on September 28, 2001). Officer’s Certificate establishing the terms of the 7 1/4% Senior Notes due October 1, 2011, including the form of global note relating thereto (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8–K filed with the SEC on September 28, 2001).

4.10 Purchase Agreement dated as of September 17, 2002 relating to the 4.375% Senior Notes Due October 1, 2007 by and among the Company and the underwriters named therein (incorporated by reference to Exhibit 1.1 to the Company’s Current Report on Form 8–K filed with the SEC on September 17, 2002). Officers’ Certificate evidencing the terms of the 4.375% Senior Notes due October 1, 2007, including the form of global note relating thereto (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8–K filed with the SEC on September 17, 2002).

#10.1 1999 Long–Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 10–Q for the period ended June 30, 1999).

101

Ocean Energy, Inc.

#10.2 Seagull Energy Corporation 1983 Stock Option Plan (Restated), including forms of agreements, as amended (plan is incorporated by reference to Exhibit 10.4 to Quarterly Report on Form 10–Q for the quarter ended March 31, 1998).

#10.3 Seagull Energy Corporation 1990 Stock Option Plan, including forms of agreements, as amended (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended March 31, 2001); Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.5 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001.

#10.4 Global Natural Resources Inc. 1989 Key Employees Stock Option Plan incorporated by reference to Exhibit 4.1 to Registration Statement No. 33–31537 of Global Natural Resources Inc.; Form of Stock Option Agreement incorporated by reference to Exhibit 4.2 to Registration Statement No. 33–31537 of Global Natural Resources Inc.; Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10–K for the ear ended December 31, 2001.

#10.5 Global Natural Resources Inc. 1992 Stock Option Plan and Form of Stock Option Agreement (incorporated by reference to Exhibit 10.7 to Annual Report on Form 10–K for the year ended December 31, 2000); Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.7 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001.

#10.6 Seagull Energy Corporation 1993 Nonemployee Directors’ Stock Option Plan, including forms of agreements, as amended (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1997).

#10.7 Seagull Energy Corporation 1993 Stock Option Plan, as amended (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1997).

#10.8 1995 Omnibus Stock (incorporated by reference to exhibit 10.10 to Annual Report on Form 10–K for the year ended December 31, 2000); Form of Amendment to Stock Option Agreement(s) incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001).

#10.9 1998 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended June 30, 1998).

#10.10 UMC 1987 Nonqualified Stock Option Plan, as amended, (the Plan is incorporated herein by reference to Exhibit 10.3 to UMC’s Form S–1 (No. 33-63532) filed with the SEC on May 28, 1993; the Third Amendment, dated November 16, 1993, and the Fourth Amendment, dated April 6, 1994, are incorporated by reference to Exhibit 10.12 to Annual Report on Form 10–K for the year ended December 31, 2000; the Fifth Amendment, dated November 19, 1997, is incorporated by reference to Exhibit 4.7 to UMC’s Form S–3 (No. 333–42467); the Sixth Amendment, dated March 27, 1998, and the Seventh Amendment, dated February 1, 1999, are incorporated by reference to Exhibit 10.3 to Form 10–Q for the period ended March 31, 1999).

#10.11 UMC 1994 Employee Nonqualified Stock Option Plan, as amended (the Plan is incorporated by reference to Exhibit 4.14 to UMC’s Form S–8 (No. 33-79160) filed with the SEC on May 19, 1994; the First Amendment, dated November 16, 1994, is incorporated by reference to Exhibit 4.11.1 to UMC’s Form S–8 (No. 33–86480) filed with the SEC on November 18, 1994; the Second Amendment, dated May 22, 1996, is incorporated by reference to Exhibit 4.3.2 to UMC’s Form S–8 (No. 333–05401) filed with the SEC on June 6, 1996; the Third Amendment, dated November 13, 1996, is incorporated by reference to Exhibit 4.3.3 to UMC’s Form S–8 (No. 333–28017) filed with the SEC on May 29, 1997; the Fourth Amendment, dated May 29, 1997, is incorporated herein by reference to Exhibit 4.3.4 to UMC’s Form S–8 (No. 333–28017) filed with the SEC on May 29, 1997; the Fifth Amendment, dated November 19, 1997, is incorporated by reference to Exhibit 4.8 to UMC’s Form S–3 (No. 333–42467) filed with the SEC on December 17, 1997; the Sixth Amendment, dated March 27, 1998 is incorporated by reference to Exhibit 10.4 to Form 10–Q for the period ended March 31, 1999).

102

Ocean Energy, Inc.

#10.12 UMC 1994 Outside Directors’ Nonqualified Stock Option Plan, as amended (the Plan is incorporated herein by reference to Exhibit 4.15 to UMC’s Form S–8 (No. 33–79160) filed with the SEC on May 19, 1994; the First Amendment, dated May 22, 1996, is incorporated by reference to Exhibit 4.4.1 to UMC’s Form S–8 (No. 333–05401) filed with the SEC on June 6, 1996; the Second Amendment, dated November 13, 1996, is incorporated herein by reference to Exhibit 4.4 to UMC’s Form S–8 (No. 333–28017) filed with the SEC on May 29, 1997; the Third Amendment, dated November 19, 1997, is incorporated by reference to Exhibit 4.9 to UMC’s Form S–3 (No. 333–42467); Fourth Amendment, dated March 27, 1998 is incorporated by reference to Exhibit 10.6 to Form 10–Q for the period ended March 31, 1999).

#10.13 1994 Long–Term Incentive Plan (the Plan, as amended, is incorporated by reference to Exhibit 10.3 to Amendment No. 2 to the Registration Statement on Form S–1 (No. 33–84308) of Ocean Energy, Inc. (Registration No. 0–25058); the Second Amendment, dated March 27, 1998 is incorporated by reference to Exhibit 4.2 to Form 10–Q for the period ended March 31, 1999).

#10.14 1996 Long–Term Incentive Plan, as amended (the Plan, as amended, is incorporated by reference to Exhibit 99.1 to the Form S–8 (No. 333–45117) of Ocean Energy, Inc. (Registration No. 0–25058) filed with the SEC on January 29, 1998; the Second Amendment, dated March 27, 1998, is incorporated by reference to Exhibit 4.2 to Form 10–Q for the period ended March 31, 1999).

#10.15 1998 Long–Term Incentive Plan (incorporated by reference to Appendix E to Ocean Energy, Inc.’s Joint Proxy Statement Prospectus on Form S–4 (333–43933) filed with the SEC on January 9, 1998).

#10.16 Long–Term Incentive Plan for Non–Executive Employees, as amended (the Plan, as amended, is incorporated by reference to Exhibit 99.1 to the Form S–8 (No. 333–45119) of Ocean Energy, Inc. (Registration No. 0–25058); Amendment No. 2, incorporated by reference to Exhibit 99.2 to the Form S–8 (No. 333–49185) of Ocean Energy, Inc.; Amendment No. 3, dated as of May 20, 1998, is incorporated by reference to Exhibit 10.46 to the Annual Report on Form 10–K for the year ended December 31, 1998, of Ocean Energy, Inc. (Registration No. 0–25058); Amendment No. 4 is incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10–K for the year ended December 31, 1999; Amendment No. 5 is incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended September 30, 2001; Amendment No. 6 is incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10–K for the year ended December 31, 2001; Amendment No. 7 is incorporated by reference to incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S–8, (No. 333–100903), filed with the SEC on October 31, 2002.

#10.17 Ocean Energy, Inc. 2001 Long–Term Incentive Plan, incorporated by reference to Exhibit 99.9 to the Company’s Current Report on Form 8–K filed with the SEC on May 14, 2001.

#10.18 Outside Directors Deferred Fee Plan as Amended and Restated Effective July 1, 2001 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended June 30, 2001).

#10.19 Ocean Energy, Inc. Directors Compensation Plan (as amended and restated effective July 1, 2002), (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended June 30, 2002).

103

Ocean Energy, Inc.

#10.20 Ocean Energy Inc. Executive Supplemental Retirement Plan (as Amended and Restated) as of July 1, 2001 (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10–Q for the quarter ended September 30, 2001); Amendment No. 1 effective July 18, 2002 is incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10–Q for the quarter ended June 30 2002.

#10.21 Ocean Energy Inc. Supplemental Benefit Plan, as Amended and Restated Effective July 1, 2001 (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10–Q for the quarter ended June 30, 2001).

#10.22 Ocean Energy, Inc. Excess Benefit Plan dated September 29, 2000, incorporated by reference to the Company’s Form 10–Q for the quarter ended September 30, 2000; First Amendment thereto, dated December 14, 2000, (incorporated by reference to Exhibit 10.24 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.23 Form of Indemnification Agreements among the Company and certain executive officers and directors (incorporated by reference to Exhibit 10.19 to Form 10–Q for the period ended March 31, 1999).

#10.24 Employment Agreement by and between the Company and James T. Hackett, as amended (the Agreement is incorporated by reference to Exhibit 10.6 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998; Amendment to Employment Agreement dated November 24, 1998 is incorporated by reference to Exhibit 10.15 to Form 10–Q for the period ended March 31, 1999; Second Amendment to Employment Agreement, effective as of December 15, 1999, is incorporated by reference to Exhibit 99.2 to Current Report on Form 8–K filed with the SEC on January 7, 2000; Third Amendment to Employment Agreement, dated as of February 23, 2003, is incorporated by reference to the Company’s Current Report on Form 8–K filed with the SEC on February 25, 2003).

#10.25 Employment and Consulting Agreement by and between the Company and Barry J. Galt, as amended (the Agreement is incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998; Amendment to Employment and Consulting Agreement dated November 24, 1998 is incorporated by reference to Exhibit 10.16 to Form 10–Q for the period ended March 31, 1999; Second Amendment to Employment and Consulting Agreement is incorporated by reference to Exhibit 10.6 to Form 10–Q for the period ended June 30, 1999).

#10.26 Employment Agreement between the Company and Robert K. Reeves (incorporated by reference to Exhibit 10.41 to Form 10–Q for the period ended June 30, 1999).

#10.27 Employment Agreement between the Company and William L. Transier (incorporated by reference to Exhibit 10.5 to Form 10–Q for the period ended June 30, 1999).

#10.28 Employment Agreement between the Company and John D. Schiller Jr. dated July 20, 2000 (incorporated by reference to Exhibit 10.4 to the Company’s Form 10–Q for the period ended September 30, 2000).

#10.29 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and James T. Hackett (incorporated by reference to Exhibit 10.7 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998); First Amendment to Executive Supplemental Retirement Plan Membership Agreement effective as of June 26, 2000, incorporated by reference to Exhibit 10.3 to the Company’s Form 10–Q for the period ended September 30, 2000; Second Amendment to Executive Supplemental Retirement Plan Membership Agreement effective as of January 1, 2001, (incorporated by reference to Exhibit 10.33 to Annual Report on Form 10–K for the year ended December 31, 2000).

104

Ocean Energy, Inc.

#10.30 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and Robert K. Reeves effective January 1, 2001 (incorporated by reference to Exhibit 10.35 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.31 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and John D. Schiller effective January 1, 2001 (incorporated by reference to Exhibit 10.36 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.32 Executive Supplemental Retirement Plan Membership Agreement between the Company and Barry J. Galt dated as of February 3, 1986, as amended (incorporated by reference to Exhibit 10.34 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001).

#10.33 Executive Supplemental Retirement Plan Membership Agreement by and between the Company and William L. Transier effective January 1, 2001 (incorporated by reference to Exhibit 10.37 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.34 Severance Agreement between the Company and James T. Hackett, as amended (incorporated by reference to Exhibit 10.8 to Quarterly Report on Form 10–Q for the quarter ended September 30, 1998). Amendment to Severance Agreement, effective as of December 15, 1999, incorporated by reference to Exhibit 99.1 to Current Report on Form 8–K filed with the SEC on January 7, 2000. Second Amendment to Severance Agreement dated as of February 23, 2003, incorporated by reference to the Company’s Current Report on Form 8–K filed with the SEC on February 25, 2003.

#10.35 Severance Agreement between the Company and Robert L. Thompson dated January 16, 2001, (incorporated by reference to Exhibit 10.40 to Annual Report on Form 10–K for the year ended December 31, 2000).

#10.36 Ocean Energy, Inc. 2001 Change of Control Severance Plan dated September 27, 2001 (incorporated by reference to the Company’s Quarterly Report on Form 10–Q for the quarter ended September 30, 2001).

10.37 Ocean Energy, Inc. 2001 Employee Stock Purchase Plan, incorporated by reference to Exhibit 4.8 to the Company’s Form S–8 filed with the SEC on November 13, 2000.

*10.38 Natural Gas Purchase and Sale Agreement dated October 1, 2001 between the Company as Seller and Duke Energy Trading and Marketing, L.L.C., as Buyer incorporated by reference to Exhibit 10.43 to the Company’s Annual Report on Form 10–K for the year ended December 31, 2001; Amendment to Natural Gas Purchase and Sale Agreement dated November 14, 2002, filed herewith.

*21.1 Subsidiaries of Ocean Energy, Inc.

*23.1 Consent of KPMG LLP.

*99.1 Certification of Chief Executive Officer of Ocean Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.

*99.2 Certification of Chief Financial Officer of Ocean Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.

*  Filed herewith.

#  Identifies management contracts and compensatory plans or arrangements.

105

EX-10

November 14, 2002

Mr. Phil Iracane
Ocean Energy, Inc.
1001 Fannin, Suite 1600
Houston, TX 77002-6794

RE: Amendment to Natural Gas Purchase and Sale Agreement

The parties hereby agree to amend the subject Natural Gas Purchase and Sale Agreement between Duke Energy Trading and Marketing, L.L.C. (“DETM”) or (“Buyer”) and Ocean Energy, Inc. (“Ocean”) dated October 1, 2001 (the “Agreement”) as follows:

1.   Article VIII shall be amended by the addition of the following language to the end of Article VIII:

“In addition to the foregoing, if the credit rating of Buyer is reduced below investment grade as determined by Standard and Poor’s, within five (5) business days of a demand from Ocean, Buyer shall supply to Ocean an irrevocable, unconditional letter of credit (in a form satisfactory to Ocean) (the “Letter of Credit”) issued by a national financial institution having an office in the United States and whose credit rating is at least “A-” by Standard and Poor’s and at least “A3” by Moodys, in favor of Ocean in an amount equal to one hundred percent (100%) of the estimated payables for 60 days of flow under the Agreement. It is agreed that the amount of such Letter of Credit shall be determined by Ocean in its sole discretion.

Should Buyer be required to provide the Letter of Credit above, such Letter of Credit shall remain in force and effect until (i) Ocean is satisfied Buyer is fully capable of performing its obligations under the Agreement which determination shall be made in Ocean’s sole discretion, or (ii) the termination of the Agreement and fulfillment of all obligations thereunder by Buyer.

The Parties acknowledge and agree that were it not for Buyer’s agreement to supply Ocean with such Letter of Credit as provided in this Amendment, Ocean would exercise its right to terminate the Agreement. In the event Ocean draws on such Letter of Credit, Buyer agrees to supply a replacement Letter of Credit (within five (5) business days) and will continue to provide additional Letters of Credit in the manner specified herein within such time period.

The Parties agree that if Buyer fails to provide a Letter of Credit as provided herein, the Agreement will be immediately terminated.

In order to secure its obligations hereunder, Buyer grants a security interest to Ocean in Ocean’s Gas being purchased hereunder. In accordance with this provision, Ocean is filing a Financing Statement with the Secretary of State of the State of Delaware.

To the extent this Amendment conflicts in any manner with the Agreement, the Parties agree that this Amendment shall control.

Except as amended herein, the Agreement remains in full force and effect.”

All capitalized terms used herein shall have the same meaning given them in the Agreement.

Please sign in the space provided below and return one original to DETM as soon as possible.

We thank you for your continued business.

_________________

Tim McCabe
Sr. Director, East Gas Origination

Agreed to and accepted this 22nd day of November, 2002.

_________________

Ocean Energy, Inc.

EX-21

Exhibit 21.1

Ocean Energy, Inc.

The following is a listing of significant subsidiaries as of March 9, 2002:

	Jurisdiction of Incorporation
Name of Subsidiary	or Organization
Big Sky Gas Marketing Corporation	Delaware
Havre Pipeline Co. L.L.C	Texas
Ocean Angola Corporation	Delaware
Ocean Côte d’Ivoire, Ltd.	Cayman Islands
Ocean Energy, Inc.	Louisiana
Ocean Energy Limitada	Brazil
Ocean Equatorial Guinea Corporation	Delaware
Ocean International, Ltd.	Delaware
Ocean International Holdings, Ltd.	Cayman Islands
Ocean East Zeit Petroleum, Ltd.	Cayman Islands
Ocean (Egypt), Ltd.	Cayman Islands
Ocean (Egypt) East Beni Suef, Ltd.	Cayman Islands
Ocean Field Services Company	Texas
Ocean SW Gebel El Zeit, Ltd.	Cayman Islands
Ocean WAG Petroleum, Ltd.	Cayman Islands
Seagull Marketing Services Inc.	Texas
Seagull Pipeline & Marketing Inc.	Delaware
Seagull Series 1995 L.L.C.	Delaware
Seagull Series 1995 Trust	Delaware
Texneft Inc.	Texas

EX-23

Independent Auditors’ Consent

The Board of Directors Ocean Energy, Inc.:

We consent to the incorporation by reference in the following registration statements of Ocean Energy, Inc. and subsidiaries of our report dated January 28, 2003, with respect to the consolidated balance sheets of Ocean Energy, Inc. and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three–year period ended December 31, 2002, which report appears in the December 31, 2002, annual report on Form 10–K of Ocean Energy, Inc. and subsidiaries.

Our report refers to a change in the method of accounting for derivative financial instruments, effective January 1, 2001.

1. Form S–8, Seagull Energy Corporation 1981 Non–Qualified and Incentive Stock Option Plan (2–80834).
2. Form S–8, Seagull Energy Corporation 1983 Stock Option Plan, as amended (2–93087).
3. Forms S–8 and S–3, Seagull Energy Corporation 1986 Stock Option Plan (33–22475).
4. Form S–8, Seagull Energy Corporation 1990 Stock Option Plan, as amended (33–43483).
5. Form S–8, Seagull Energy Corporation 1993 Stock Option Plan, as amended (33–50643).
6. Form S–8, Seagull Energy Corporation 1993 Nonemployee Directors’ Stock Option Plan, as amended (33–50645).
7. Form S–8, Seagull Energy Corporation 1995 Omnibus Stock Plan, as amended (33–64041).
8. Form S–8, Global Natural Resources Inc. 1989 Key Employee Stock Option Plan and Global Natural Resources, Inc. 1992 Stock Option Plan, as amended (333–13393).
9. Form S–8, Seagull Energy Corporation 1998 Omnibus Stock Plan, as amended (333–71375).
10. Form S–8, Ocean Energy, Inc. 1999 Long–Term Incentive Plan, as amended (333–95507).
11. Form S–8, Ocean Energy, Inc. 1996 Long–Term Incentive Plan, Ocean Energy, Inc. 1994 Long–Term Incentive Plan, and United Meridian Corporation 1994 Outside Directors’ Nonqualified Stock Option Plan, as amended (333–78255).
12. Form S–8, Ocean Energy, Inc. 1998 Long–Term Incentive Plan, Ocean Energy, Inc. Long–Term Incentive Plan For Nonexecutive Employees, United Meridian Corporation 1994 Employee Nonqualified Stock Option Plan, and United Meridian Corporation 1987 Nonqualified Stock Option Plan, as amended (333–68679).
13. Form S–8, Ocean Energy, Inc. 2001 Employee Stock Purchase Plan, as amended (333–49756).
14. Form S–3, Ocean Energy, Inc. $1 Billion Debt Securities, Common Stock, Preferred Stock, Depository Shares, Warrants, Guarantees of Debt Securities, Stock Purchase Contracts and Stock Purchase Units, as amended (333–67136).
15. Form S–8, Ocean Energy, Inc. Retirement Savings Plan, Ocean Energy Inc. Retirement Savings Plus Plan, Ocean Energy Inc. Supplemental Benefit Plan and Ocean Energy Inc. Outside Directors Deferred Fee Plan (333–75268).
16. Form S–8, Ocean Energy, Inc. 2001 Long–Term Incentive Plan (333–75270).
17. Form S–8, Ocean Energy, Inc. Long–Term Incentive Plan for Non–Executive Employees (333–100903).

/s/ KPMG LLP

Houston, Texas
March 7, 2003

EX-99

EXHIBIT 99.1

Certification Of Chief Executive Officer Of Ocean Energy, Inc.
Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant To
Section 906 Of The Sarbanes–Oxley Act Of 2002

I, James T. Hackett, Chairman of the Board, President and Chief Executive Officer of Ocean Energy, Inc. (the “Company”), hereby certify that the Company’s annual report on Form 10–K for the period ended December 31, 2002 and filed with the Securities and Exchange Commission on March 7, 2003 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ James T. Hackett
Name: James T. Hackett
Title: Chairman of the Board, President and
Chief Executive Officer
Date: March 7, 2003

EX-99

EXHIBIT 99.2

Certification Of Chief Financial Officer Of Ocean Energy, Inc.
Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant To
Section 906 Of The Sarbanes–Oxley Act Of 2002

I, William L. Transier, Executive Vice President and Chief Financial Officer of Ocean Energy, Inc. (the “Company”), hereby certify that the Company’s annual report on Form 10–K for the period ended December 31, 2003 and filed with the Securities and Exchange Commission on March 7, 2003 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ William L. Transier
Name: William L. Transier
Title: Executive Vice President and
Chief Financial Officer
Date: March 7, 2003