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 of 36 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

Period Event

1991 - Founded

1994 - Two simultaneous operations in the GOM

1995 - Drilled ATP's first horizontal well

1996 - ATP operated subsea well with Shell as partner

End of 1997 - Gulf of Mexico: 10 blocks

1998 - Acquired all Statoil GOM shelf properties

2000 - Entered U.K. Sector of the North Sea- Acquired Ladybug (1st deepwater GOM subsea project)

2001 - Initial Public Offering (February 5, 2001)

2003 - Entered Dutch Sector of the North Sea

End of 2003 - Gulf of Mexico: 50 blocks- North Sea: 12 blocks

Phase II:Expansion

Phase I:Initial

Operations

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

Proved Reserves(Bcfe)

50

104125

235 230

303

1998 1999 2000 2001 2002 2003

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.

Reserves SEC PV-10%Reserve Category (Bcfe) ($ millions)

Proved Developed 56 214$

Proved Undeveloped 247 562$

Total Proved Reserves 303 776$

11

Location and Composition of Reserves

Proved Reserves By Region

Proved Reserves By Commodity

Gulf of Mexico

67%

North Sea33%

Oil24%

Gas76%

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

BA 544BA 544

#3-11050

A-2 ST-1 BP1

BA_543_2

BA_544_1BA_544_2

BA_544_A1BA_544_A2

BA_544_B1

BA_544_A1

3093600 3098600 3103600 3108600 3113600

163100

168100

173100

3093600 3098600 3103600 3108600 3113600X/Y :

163100

168100

173100

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

Major 2Q04 developments in progress:

SS 358 #2 & #3

MI 709

WC 237 #1 & #2

GOM

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

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

10km

22

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

PUD PUD to PD PUD Sales

YE 2003

100%

YE 2004

77% 19%

4%

YE 2005

4%

40%

56%

YE 2006

19%4%

77%

YE 2007

4%16%

80%

YE 2008

2%

4%

94%

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

40

75+

0

20

40

60

80

100

4Q03 Current YE 04E

Daily Production (MMcfe/d)

Helvellyn West Cameron 237 #1 & #2Garden Banks 142 Ship Shoal 358 #2 & #3Garden Banks 186 West Cameron 101Matagorda Island 709 Eugene Island 30/71Ship Shoal 358 #1 East Cameron 240Brazos 544 compression West Cameron 432

Red – New 2004 Production

2004 Production Contributors

100E

25

Development Capital Impact on Production

24.5 25.7 26.5

17.1

$-

$10

$20

$30

$40

$50

$60

$70

$80

$90

2000 2001 2002 2003 2004E

($ m

illio

ns)

0

5

10

15

20

25

30

Bcf

e

Drilling Infrastructure Production

There is a high correlation between “Drilling CAPEX” in one year and “Production” in the subsequent year

26

2004 Capital Expenditures Budget

($ in millions)

Gulf of Mexico $50-60

North Sea $5-10

Exploration $0

PUD Development

$55-70

Capex Budget by Region Capex Budget by Type($ 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

1Q 2Q 3Q 4Q FY 1Q 2Q 3Q 4Q FYFixed Forwards and SwapsNatural Gas

Volumes (MMMbtu) 2,150 2,469 2,806 2,806 10,231 2,250 605 460 460 3,775 Price 5.30$ 4.99$ 5.08$ 5.13$ 5.12$ 5.51$ 5.25$ 5.10$ 5.10$ 5.37$

Crude OilVolumes (Mbbls.) 60.5 83.5 46.3 23.0 213 Price 31.09$ 31.43$ 31.20$ 28.68$ 30.99$

CollarsNatural Gas

Volumes (MMMbtu) 300 300 Ceiling 5.80$ 5.80$ Floor 4.40$ 4.40$

Recent Hedges:

April 5, 2004 Hedge - 3,000 MMbtu/d June - December 2004 at $6.07/MMbtu.

20052004

The above are hedges, derivatives and fixed price contracts that are in effect at April 12, 2004. Additional hedges, derivatives and fixed price contracts, if any, will be announced during the year.

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

Proved After TaxReserves SEC PV 10%

Name Ticker (Bcfe) ($ millions)

Pogo Producing PPP 1,701.5 2,450.3 Newfield Exploration NFX 1,316.7 2,935.4 Magnum Hunter Resources MHR 838.4 1,481.7 Stone Energy SGY 816.3 1,795.9 Spinnaker Exploration SKE 332.6 803.8 ATP Oil & Gas ATPG 302.7 547.1 Energy Partners Limited EPL 298.9 529.4 Callon Petroleum CPE 216.9 519.0 Remington Oil & Gas REM 212.1 486.3 PetroQuest Energy PQUE 83.3 175.2

32

Peer Analysis – Proved Reserves

Proved Reserves

212 217

299 303

333

REM CPE EPL ATPG SKE

Note: Proved Reserves at 12/31/03

REM CPE EPL ATPG SKE

Market Cap ($millions) 552$ 146$ 438$ 162$ 1,220$

33

After Tax SEC PV10 ($ millions)

$486$519 $529 $547

$804

REM CPE EPL ATPG SKE

Note: SEC PV 10 value is after tax at 12/31/03

Peer Analysis – SEC PV 10%

SEC PV-10 values incorporate future operating costs, development costs, and price differentials.

REM CPE EPL ATPG SKE

Market Cap ($millions) 552$ 146$ 438$ 162$ 1,220$ Enterprise Value ($millions) 554$ 419$ 498$ 337$ 1,243$

Note: Enterprise Value is pro forma announced 2004 capital transactions.

34

Peer Analysis – Competitive Economics

Capital Invested per Mcfe

$2.76

2.56

1.79

2.32

1.59 $1.62$1.64

$1.85$1.87

1.461.64

1.85

1.23

1.551.70

SKE EPL ATPG REM CPE

5-Year Capital Invested 4-Year Capital Invested 3-Year Capital Invested

Four-year Capital Invested per Mcfe SKE EPL ATPG REM CPE

Costs Incurred(1) (2000 - 2003) 1,144$ 548$ 310$ 390$ 285$ Future Development Costs 178$ 264$ 400$ 140$ 112$ Subtotal 1,322$ 813$ 710$ 530$ 397$

Production (2000 - 2003) 183.7 141.6 93.7 111.9 54.2 Future Production / Reserves (Bcfe) 332.6 298.9 302.7 212.1 216.9 Subtotal 516.3 440.5 396.4 324.0 271.2

Capital Invested per Mcfe 2.56$ 1.85$ 1.79$ 1.64$ 1.46$ (1) Net of divestitures / asset sales

35

Peer Analysis – Attractive ATP Equity Upside

Share Price to SEC PV 10 Net Asset Value

43%52%

98%

113%

154%

ATP CPE EPL REM SKE

ATP CPE EPL REM SKESEC PV 10 ($millions) 547.1$ 519.0$ 529.4$ 486.3$ 803.8$ Long-term Debt(1) 185.0$ 245.2$ 150.4$ 18.0$ 50.0$ Net Working Capital(1) 9.6$ 2.8$ 125.1$ 16.1$ 26.7$ NAV 371.6$ 276.6$ 504.1$ 484.4$ 780.4$ Shares(2) 24.5 14.0 36.7 26.9 33.4NAV / Share 15.17$ 19.79$ 13.73$ 18.01$ 23.37$ Share Price (4/9/04) 6.47$ 10.39$ 13.50$ 20.43$ 35.90$ Share Price / NAV 43% 52% 98% 113% 154%(1) Pro forma announced 2004 capital transactions

(2) Pro forma dilutive securities that are trading above conversion prices

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 77027-9726

713-622-3311

ATP Oil & Gas (UK) LimitedVictoria 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 IJmuidenThe Netherlands31 (0) 255 523377

www.atpog.com