IPAA - OGIS April, 2004 Gerald Schlief Sr. Vice President Al Reese, Jr. Sr. Vice President and CFO.
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Transcript of IPAA - OGIS April, 2004 Gerald Schlief Sr. Vice President Al Reese, Jr. Sr. Vice President and CFO.
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