mruszczy: NEED LOGOS!!

1. mruszczy: NEED LOGOS!! IPAA - OGIS April, 2004 Gerald Schlief Sr. Vice President Al Reese, Jr. Sr. Vice President and CFO

2. Cautionary Statement Regarding Forward-looking Statements • This presentation includes forward-looking statements and projections, made in reliance on the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this presentation, including, without limitation, changes in commodity prices for oil and natural gas; estimates of reserves; future production and operating costs; marketing and commodity price risk management activities. While the Company makes these statements and projections in good faith, neither the Company nor its management can guarantee that anticipated future results will be achieved. The Company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the Company, whether as a result of new information, future events, or otherwise.

3. Company Overview • Founded in 1991 as a development and production company • Low-risk (development only), geographically focused operations • 100% offshore - Gulf of Mexico (67%) and North Sea (33%) • Strong proved reserve base at December 31, 2003 • Proved reserves of 303 Bcfe • SEC PV-10% of $776 million ($547 million after tax) • Reserves are prepared by independent reservoir engineering firms • 10+ year production profile based on current development program • 99% of reserves operated by ATP • Substantial proved undeveloped drilling inventory • Highly successful development track record • Brought 35 of36 proved undeveloped (“PUD”) projects to commercial production • 97% success rate

4. Areas of Operations • 50 blocks in the Gulf of Mexico • 12 blocks in the North Sea

5. Business Strategy • Acquisition and development of proved reserves with the following characteristics: • Primarily proved undeveloped reserves • Close proximity to developed markets • Existing infrastructure of pipelines and platforms • Stable regulatory environment • High working interests and operating control • Develop projects to key value creation point • No exploration risks

6. History Phase I: InitialOperations Phase II: Expansion

7. Year-End • Oil and Gas • Reserves

8. Types of Reserve Report • The level of involvement by the independent engineering firm can vary dramatically and generally falls within three categories – Review, Audit or Prepared. • Review: The independent engineering firm analyzes the processes and procedures that the company uses in estimating reserves to assure they comply with relevant standards. Least reliable independent method. • Audit: Generally means that, within a level of tolerance, a detailed examination of the company’s reserves by the independent engineering firm has come within the company’s estimate. The independent engineering firm focuses on properties that account for 70%-90% of the company’s PV-10%. If the company’s estimate falls within the independent engineering firm’s level of tolerance, then the company’s estimate will be presented as fact. The level of tolerance is typically ±10%. • Prepared: A detailed and thorough evaluation of the company’s reserves. The independent engineering firm performs a comprehensive examination and evaluation of all available source data and prepares the reserve report based upon its estimates. The reserve report represents estimates of the independent engineering firm, not those of the company. Most reliable independent method and the method used by ATP from inception.

9. History of Increasing Reserves

10. Proved Reserves Summary • As of 12/31/2003 • 32% increase over 2002 • 2003 reserve replacement ratio 526% Since December 31, 2003, ATP has moved more than 20 Bcfe with a SEC PV-10 value of more than $80 million from Proved Undeveloped to Proved Developed.

11. Location and Composition of Reserves • Proved Reserves By Region Proved Reserves By Commodity

12. Prior, Current, and Future Developments

13. Brazos 544 • Key Features • Acquired 1996 • 96% developed • Cumulative production of proved, probable and possible reserves has exceeded original third party estimates by more than 160% • 100% working interest • Development Plans • Gross production 10.0 MMcf/d • Compression installed February 2004; current gross production 15 MMcf/d • Behind pipe zones still to be produced

14. Garden Banks 409 (Ladybug) • Key Features • Acquired in 2000 • Initial 2001 production rate 8,000 Bbl/d, current 2004 rate > 3,000 Bbl/d • Cumulative gross production > 5.5 million Boe and $150 million in revenues • Still producing from initial zones • ATP operates with 50% working interest • Unocal is partner • Company’s first deepwater (1,360’) subsea development project • Two subsea wells tied back to GB 189 • Longest oil subsea tieback (17.4 miles) in the world when installed

15. Helvellyn Key Features • Acquired in 2001 • Began production February 2004 • Current production of 60 MMcfe/d gross and 30 MMcfe/d net • ATP operates with a 50% working interest • Water depth less than 120 feet (40 meters)

16. Multi-Year Development Inventory • Quality inventory of 247 Bcfe of proved undeveloped reserves (19 properties) • 3+ years of development opportunities without any future acquisitions • 8 Gulf of Mexico properties included in 2004 development (3 already on production) • Emerald Field (North Sea), potentially ATP’s largest property, not yet included in ATP’s proved reserves ATP operates 100% of its future developments. 97% Success rate in converting PUDs to PD

17. 2004 Scheduled Development Program • Gulf of Mexico • Garden Banks 186 (On production March 2004) • Ship Shoal 358 (1st well on production March 2004, 2nd well completing, 3rd well to be drilled) • Matagorda Island 709* (On production March 2004) • Eugene Island 30/71* • West Cameron 237* (Two well re-entry and side track beginning April/May 2004) • West Cameron 101* • East Cameron 240* • West Cameron 432* • North Sea • Helvellyn (On production February 2004) • Venture (UK) • Emerald (UK) (Shoot proprietary 3-D seismic Summer 2004) • Block L-06d (Netherlands) * Existing infrastructure in place Note – The above developments are those scheduled as of April 2004. Actual developments will be reported during the year, which may vary from those listed above.

18. Second Quarter Developments GOM Major 2Q04 developments in progress: • SS 358 #2 & #3 • MI 709 • WC 237 #1 & #2

19. Second Quarter Development Activities • Ship Shoal 358 – water depth 385’ • At Ship Shoal 358, the first well was placed on production March 21, 2004. The Ship Shoal 358 A-1 well reached TD at 8,855' and logged 77' of gross and 45' of net oil and natural gas pay from two expected productive sands. Drilling of the second well began March 22, 2004 and is expected to commence production during April. A third well will commence after completion of the second well. ATP is the operator and has a 51% working interest. • Matagorda Island 709 – water depth 88’ • The Matagorda Island 709 A-1 ST1 well, TD 11,325’, encountered the proved undeveloped reserves that ATP had expected and the well was placed on production March 24, 2004. The proved reserves in the Miocene Marg "A" sands that ATP was expecting amounted to 346' of gross and 113' of net natural gas pay. ATP additionally encountered a new pay sand with approximately 152' of gross and 64' of net natural gas pay. ATP is the operator with a 62.5% working interest. Production is currently curtailed as a result of downstream pipeline repairs. • West Cameron 237 – water depth 70’ • At West Cameron 237, two wells will be re-entered and sidetracked in 2004 to develop proved undeveloped reserves from a natural gas reservoir at approximately 5,600’ TVD and from three other reservoirs located between 7,200’ and 8,100’ TVD. ATP is the operator and has a 75% working interest.

20. Mississippi Canyon 711 (2005 Development) • Key Features • MC 711 (“Gomez’) gross proved reserves > 100 Bcfe • Approximately 3,000’ water depth • Six wells encountered hydrocarbons; four wells re-enterable • ATP operates with a 99% WI • 2005 Development Plans • Re-enter two wells; production projected late 2005 • Future Development Plans • Re-enter other two wells • Target other identified reserves

21. 10km The Tors (UK) (2006 Development) • Key Features • Located in 185 feet of water • Two wells were tested at 33 MMcf/d and 12 MMcf/d • Cluster of reservoirs in the North Sea • ATP operates with a 75% working interest • Gaz de France owns remaining 25% interest • Target 2006 first production date

22. Converting 247 Bcfe of PUD to PD (2004 – 2008) PUD Sales PUD PUD to PD

23. Production and Financial Highlights

24. Production • ATP produced 17.1 Bcfe in 2003 (63% natural gas) • All 2003 production was from the Gulf of Mexico • ATP expects a substantial increase in 2004 production from both the Gulf of Mexico and the North Sea 100E Daily Production (MMcfe/d) 2004 Production Contributors Helvellyn West Cameron 237 #1 & #2 Garden Banks 142Ship Shoal 358 #2 & #3 Garden Banks 186West Cameron 101 Matagorda Island 709 Eugene Island 30/71 Ship Shoal 358 #1 East Cameron 240 Brazos 544 compressionWest Cameron 432 Red – New 2004 Production

25. Development Capital Impact on Production There is a high correlation between “Drilling CAPEX” in one year and “Production” in the subsequent year

26. 2004 Capital Expenditures Budget Capex Budget by Region Capex Budget by Type • ($ in millions) • ($ in millions)

27. Comprehensive Hedging Program 12.3 Bcfe hedged in 2004 at $5.13/Mcfe 3.8 Bcfe hedged in 2005 at $5.37/Mcfe

28. New $185 Million CSFB Senior Term Loan • Maturity • Five Year March 2009 • New funds and liquidity • $56.0 million • Collateral • Same as retired facility, substantially all of our US and UK oil and gas properties • Terms • $150 million LIBOR (floor of 2%) + 8.50% (9.5% after 6 months) • $35 million LIBOR (floor of 2%) + 10.00% • Warrants - 2.45 million shares at $7.25 for six years • OID 97%

29. 2004 Cash Flows • New Senior Term Loan • Sale of approximately 25% interest in 7 predominantly PUD properties for $19.5 million • Cash Flow from increased production • Higher Hedged Prices ($5.13/Mcfe in 2004 and $5.37/Mcfe in 2005)

30. Peer Analysis

31. Selected Offshore E&P Companies Red-ATP Peer Comps

32. Peer Analysis – Proved Reserves

33. Peer Analysis – SEC PV 10% SEC PV-10 values incorporate future operating costs, development costs, and price differentials. Note: Enterprise Value is pro forma announced 2004 capital transactions.

34. Peer Analysis – Competitive Economics

35. Peer Analysis – Attractive ATP Equity Upside

36. Growth Strategy Summary • Enhance our attractive PUD inventory • Improve on already competitive F&D costs • Maintain a proactive hedging program • Minimum of 40% of PDP production hedged • Commence MC 711 development plans • Shoot 3-D seismic survey at Emerald Oil Field • Better imaging to optimize recovery of oil and gas reserves

37. Investment Highlights • Strong liquidity position • Rapid 2004 production growth • Successful development track record (97% success rate) • High quality, multi-year development inventory • Upside potential: Emerald, Gomez and The Tors • ATP’s shares provide compelling value

38. ATP Oil & Gas Corporation (NASDAQ: ATPG) ATP Oil & Gas Corporation4600 Post Oak Place, Suite 200Houston, TX 77027-9726713-622-3311 ATP Oil & Gas (UK) Limited Victoria House, London Square, Cross Lanes Guildford, Surrey GU1 1UJ United Kingdom 44 (0) 1483 307200 ATP Oil & Gas (Netherlands) B.V. Water-Staete Gebouw Dokweg 31 (B) 1976 CA IJmuiden The Netherlands 31 (0) 255 523377 www.atpog.com