ATP Oil & Gas Corporation

Transcription

1 ATP Oil & Gas Corporation Enercom Investor Presentation Denver Colorado August 7-11, 2005 Gerald W. Schlief, Senior Vice President Albert L. Reese Jr., Chief Financial Officer Brian C. Nelson, Director of Financial Analysis

2 Forward Looking Statement This presentation contains projections and other forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of These projections and statements reflect the Company s current view with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company documents filed with the Securities and Exchange Commission. This presentation does not constitute an offer to sell, or a solicitation of an offer to buy, any securities, or the solicitation of a proxy or an attempt to influence any voting of securities, by any person. 2

3 ATP s Goals Since 1991 ATP has focused its strategy on: Acquiring Developing Operating Producing The Tors 3

4 Areas of Operation Gulf of Mexico North Sea Gulf of Mexico 181 Bcfe 1991 Shelf 2000 Off the Shelf to 1, Deeper water to 3,000 North Sea 94 Bcfe 2000 United Kingdom Sector 2003 Dutch Sector Note: Proved reserves at 12/31/04 were 275 Bcfe with a pre-tax PV 10 of $776 million. 4

5 History of Growth Phase I: Initial Operations Period Event Founded Two simultaneous operations in the Gulf of Mexico ("GOM") Drilled ATP's first horizontal well ATP operated subsea well with Shell as partner End of Gulf of Mexico: 10 blocks Acquired all of Statoil's GOM shelf properties Phase II: Expansion Phase III: Rapid Production Growth Entered U.K. Sector North Sea - Acquired Ladybug (1 st deepwater GOM subsea project) Initial Public Offering (February 5, 2001) Entered Dutch Sector North Sea Well test at Mississippi Canyon Completed seismic acquisition at Cheviot Field End of Gulf of Mexico: 52 blocks - North Sea: 12 blocks Simultaneous operations in the GOM, U.K. UK Sector North Sea and Dutch Sector North Sea - $1 billion threshold reached on current strip pre-tax PV-10% - Production exit rate target of 160+ MMcfe/d 5

6 Financial Growth Production Growth Price Realization Growth Future Growth is an E&P Company s Future 6

7 Near-term Production Growth 1Q05 3Q05 In a period when company-wide efforts are directed towards a step change in production in 4Q05, ATP has continued to deliver solid production (54-65 MMcfe/d) since 3Q04 4Q05 Substantial increase in production Mississippi Canyon 711, L-06d, and possibly Tors major drivers of production increase in 4Q05 Year-end production exit rate 160+ MMcfe/d 7

8 Long-term Production Growth % annual increase Forecast Over 200 Bcfe of PUD s to be developed L-06d, WC 432, HI 74 etc. Mississippi Canyon 711 (Gomez) Tors New acquisitions 2008 and Beyond Cheviot multi-well developments Future acquisitions Five Years of Production Growth

9 Near-term Price Realizations Six Months Ended June 30, 2005 June 30, 2004 %Change Price realizations: Oil ($/bbl) $ $ % Gas ($/Mcf) $ 6.42 $ % Revenue ($millions) $ 70,468 $ 56,890 24% EBITDAX ($millions) $ 53,458 $ 38,132 40% 9

10 Long-term Price Realization Growth Average Annual Hedge Price ($/MMbtue) $8.08 $5.21 $ (13.0 Bcfe) (12.6 Bcfe) (5.1 Bcfe) Hedged contract value of $122 million for , representing 17.7 Bcfe (1) of production. (1) Only includes fixed forward and swap contracts. 10

11 1 2 3 Future Cash Returns F&D / Cash Return $/Mcfe $10.00 $9.00 $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $- 49% ROI $1.01 Projected Cash Return ($/Mcfe) F&D Costs Cash Returns $2.59 $5.56 $2.06 $2.06 $2.06 Actual 2Q05 126% ROI Proforma 160 MMcfe/d 1H05 Pricing 270% ROI Current Strip Pro Forma 160 MMcfe/d 1H05 1H05 24-Mth Strip (1) Production (MMcfe/d) Price realizations ($/Mcfe) $ 6.55 $ 6.55 $ 9.52 Per Unit Costs ($/Mcfe) Lease operating expense $ 1.06 $ 1.06 $ 1.06 G&A expense $ 0.94 $ 0.32 $ 0.32 Interest Expense $ 1.49 $ 0.51 $ 0.51 Total cash costs per unit (2) $ 3.48 $ 1.90 $ Year F&D costs $ 2.06 $ 2.06 $ 2.06 Full Cycle Cash Return $ 1.01 $ 2.59 $ 5.56 (1) NYMEX oil and gas closing prices on August 1, (2) Based on 1H05 costs (LOE $10.6 million, G&A $9.4 million and interest $14.9 million). 11

12 Analysts Cash Flow Per Share Estimates ATP CAGR 89% $8.88 $2.49 $ E(1) 2006E(1) CAGR 16% $8.70 Peers $11.09 $ E(1) 2006E(1) 1. Source: First Call Estimates July 28,

13 Financial Strength Aug $175 million non-convertible, perpetual preferred equity transaction Apr Term loan increased to $350 million, interest rate reduced, flexibility added Dec $53 million common equity transaction Sep Term loan increased to $220 million, interest rate reduced, flexibility added Mar $185 million five year term loan Proforma June 30, 2005 cash on hand $284 million 13

14 Perpetual Preferred Issuance Key Features Net proceeds of $169 million Perpetual, but callable by ATP Non-convertible 13.5% non-cash dividend Benefits of Issuing a Preferred Security Does not dilute common shareholders Non-cash feature allows for additional investment in oil and gas developments Does not further encumber oil and gas properties Net proceeds will be used to accelerate or expand current developments, fund new acquisitions, potentially drill first well at Cheviot, and for general corporate purposes 14

15 Preferred Improves Balance Sheet June 30, 2005 Pro Forma ($ millions) Actual Preferred Offering (1) Working Capital $ 80.3 $ Cash $ $ Long-term Debt $ $ Net Long-term Debt $ $ 54.0 Shareholder's Equity $ 50.3 $ Net Debt / Book Capitalization 82% 20% Proved Reserves (2) (Bcfe) Net Debt / Proved Reserves $ 0.81 $ 0.20 SEC PV 10 (2) $ $ Net Debt / SEC PV 10 30% 7% (1) Received net proceeds of $169.5 million from a $175 million perpetual preferred offering on August 3, (2) As of December 31, Preferred Equity substantially improves credit metrics 15

16 Properties to Production Tors (Kilmar) Jacket MC 711 Subsea Tree L-06d Host Platform Reserves and developments driving production growth 16

17 Proved Reserves Summary All reserves are prepared by reservoir engineering firms Ryder Scott - Gulf of Mexico and Dutch-Sector North Sea Troy Ikoda UK-Sector North Sea 66% of proved reserves are located in the Gulf of Mexico, 34% in the North Sea 75% natural gas 99% of all proved reserves on a PV-10% basis are operated by ATP Positive reserve revision in 2003 and 2004 $530 72% $733 million PV-10 PV10 Value in Excess of Cost $203 28% Net Booked Cost 17

18 Properties Not Included in 2004 Reserve Report Gulf of Mexico 10 blocks in the Gulf of Mexico owned at December 31, 2004, 6 with well penetrations 7 blocks awarded in the Central Gulf of Mexico Lease Sale in March 2005, 3 with well penetrations MC 667 and MC 668 are contiguous to the northern boundary of MC 711 Another one of the blocks is contiguous to an ATP development in the West Cameron area SMI 166 acquired in 2005 North Sea Cheviot is expected to have proved reserves at 12/31/05 Acquired remaining 25% interest in Tors in June 2005 ATP s now holds a 100% WI. 18

19 2005 Development Programs Working Expected 1st Prospect Interest Production Region Operator Full Scale Development Mississippi Canyon % 2005 Gulf of Mexico ATP Tors 100% 2006 North Sea ATP Venture 50% 2006 North Sea ATP Ship Shoal % 2006 Gulf of Mexico ATP South Marsh Island % 2005 Gulf of Mexico ATP L-06d 50% 2005 North Sea ATP High Island 74 75% On Production Gulf of Mexico ATP Brazos % 2005 Gulf of Mexico ATP West Cameron % 2005 Gulf of Mexico ATP Additional Development West Cameron % On Production Gulf of Mexico ATP East Cameron % 2005 Gulf of Mexico ATP Matagorda Island % 2005 Gulf of Mexico ATP Eugene Island 71 75% On Production Gulf of Mexico ATP Garden Banks % On Production Gulf of Mexico ATP West Cameron 462/ % 2005 Gulf of Mexico ATP Brazos % 2005 Gulf of Mexico ATP Red - Recent additions to 2005 development program. 19

20 Gulf of Mexico Shelf Developments West Cameron 432 Placed on production in 1Q05 High Island 74 First production 2Q05 Matagorda Island 704 / 709 Third well added in early 2005 and placed on production in 2Q05 Ship Shoal 351 Two new wells planned for 2005 South Marsh Island 166 New well planned for 2005 West Cameron 101 New well planned for 2005 Brazos 578 New well planned for 2005 and will be tied to Brazos

21 Mississippi Canyon Gomez Key Features ~100 Bcfe proved reserves at 12/31/04 5 wells encountered hydrocarbons; 4 can be re-entered Tested at 134 MMcfe/d in 4Q04 ATP operates with a 100% W.I. Development Plans 2005 Complete two wells in Southern section, lay pipeline and retrofit platform Initial production projected in 4Q05 Future Complete two additional wells Develop the two proved and evaluate five other identified reservoirs MC 711 has the potential to add 100 MMcfe/d net to ATP s current daily production rate 21

22 Mississippi Canyon Gomez August Development Plan Update Pipelines Approximately 50% complete Facilities Rowan Midland modifications underway Well Operations Ocean Voyager finalizing the completion of the first well All three phases (pipelines, facilities, well operations) are coming together for a fourth quarter production start 22

23 Tors Key Features 84 Bcfe proved reserves at 12/31/04 5 wells encountered hydrocarbons Well tests, combined 82 MMcf/d: Kilmar: 12 and 33 MMcf/d Garrow: 18 and 19 MMcf/d ATP operates with a 100% W.I. Development Plans 2005 Kilmar: Lay pipeline, install jacket and deck, and complete 1 st well Initial production projected in early 2006 / very late 2005 Future Reenter and complete 2 additional wells Drill 3 new wells Garrow: Lay pipeline to Kilmar and install jacket and deck 23

24 Tors August Development Plan Update Pipeline Pipeline lay to begin in in 3Q05 Facilities Kilmar Jacket and Deck Complete. Installation underway Well Operations ENSCO 70 rig to arrive end of August Tors has the potential to add MMcf/d net to ATP s current daily production rate 24

25 L-06d Key Features 14 Bcfe proved reserves at 12/31/04 2 wells encountered hydrocarbons Well Test 40 MMcf/d ATP operates with a 50% W.I. L-06-2 ST Development Plans Re-enter and sidetrack existing well Tie-in well to host platform Initial production projected in 4Q

26 L-06d August Development Plan Update Pipeline Pipeline and umbilical lay 60% complete Facilities Host platform to be installed 3Q05 Well Operations Perforation and completion of the well nearly finished L-06d has the potential to add 20 MMcf/d net to ATP s current daily production rate 26

27 Cheviot (UK North Sea) Key Features Acquired in 2003 with 100% W.I. Old Emerald Field Original oil and gas in place Oil MMbbls Gas 59 Bcf Produced 16 million barrels from with less than 8% recovered of original oil in place of 232 MMBbls Expect to book reserves in 2005 Undeveloped locations with well penetrations Identified exploration opportunity Development Progress to Date Proprietary 3-D seismic shoot completed 4Q04 Evaluating 3-D seismic and engineering data Cheviot, potentially ATP s largest field, not yet included in ATP s reserve report 27

28 Cheviot (UK North Sea) 2005 Program Complete new 3-D seismic interpretation Complete detailed G&G reservoir studies Formulate redevelopment plan Keys to booking proved reserves at year end 2005 Innovative development Surrounding opportunities 28

29 Investment Highlights Financial strength to execute 2005 program Exceptional growth projected in Revenue, EBITDAX, Cash Flow, and Earnings Five years ( ) of production increases forecast Positive step changes Production (Gomez and Tors) Reserves (Cheviot) Incentivized management & employees Every employee an owner (38% inside ownership) The Volvo Challenge 29

30 ATP Oil & Gas Corporation - NASDAQ: ATPG ATP Oil & Gas Corporation 4600 Post Oak Place, Suite 200 Houston, TX ATP Oil & Gas (UK) Limited Victoria House, London Square, Cross Lanes Guildford, Surrey GU1 1UJ United Kingdom 44 (0) ATP Oil & Gas (Netherlands) B.V. Water-Staete Gebouw Dokweg 31 (B) 1976 CA IJmuiden The Netherlands 31 (0)

31 Hedged Production Volumes Q 2Q 3Q 4Q FY 1Q 2Q 3Q 4Q FY Gulf of Mexico: Fixed Forwards and Swaps Natural Gas Volumes (MMMBtu) 2,520 2,425 2,300 2,239 9,484 1, ,780 Price ($/MMbtu) $ 5.60 $ 6.23 $ 6.27 $ 6.54 $ 6.15 $ 7.38 $ 7.30 $ 7.30 $ 7.30 $ 7.35 Crude Oil Volumes (MBbls) Price ($/bbl) $ $ $ $ $ $ $ $ $ Equivalents Volumes (MMMBtue) 3,222 3,108 3,100 2,901 12,331 2, ,583 Price ($/MMbtue) $ 5.77 $ 6.40 $ 6.56 $ 6.76 $ 6.36 $ 7.51 $ 7.65 $ 7.65 $ 7.85 $ 7.60 Puts Natural Gas Volumes (MMMBtu) Floor Price ($/MMBtu) $ 5.01 $ 5.01 $ 5.01 $ 5.01 North Sea: Swaps Natural Gas (1) Volumes (MMMBtu) Price ( /MMBtu) The above are hedges, derivatives and fixed price contracts that are in effect at August 5, 2005 or have settled prior to such date. Additional hedges, derivatives and fixed price contracts, if any, will be announced during the year. Recent Gulf of Mexico Crude Oil Fixed Forwards: June 23, 2005: 300 bopd July - December 2005 at $60.05/bbl. Recent Gulf of Mexico Gas Fixed Forwards: June 10, 2005: 5000 MMBtu/d April - October 2006 at $7.301/MMBtu Recent North Sea Gas Swaps: May 9, 2005: 2000 MMBtu/d January - March 2006 at 6.32/MMBtu 6.32/MMBtu approximates $12.01/MMBtu using the translation rate of $1.90 to June 8, 2005: 2000 MMBtu/d January - March 2006 at 7.31/MMBtu 7.31/MMBtu approximates $13.89/MMBtu using the translation rate of $1.90 to (1) Swap for 1Q05 liquidated January 13, 2005 for approximately $710,000 in favor of the Company Avg. Hedge Price Calculation US UK* Consolidated Bcfe $/MMbtue Bcfe $/MMbtue Bcfe $/MMbtue 12,331 $ $ ,601 $ 6.41 * Assumes a translation rate of $ to at December 31, Avg. Hedge Price Calculation US UK* Consolidated Bcfe $/MMbtue Bcfe $/MMbtue Bcfe $/MMbtue 4,583 $ $ ,123 $ 8.08 * Assumes a translation rate of $ to

32 Reconciliation of Non-GAAP Financial Items ATP Oil & Gas Corporation Rolling EBITDAX Calculation Consolidated Quarter Quarter Quarter Quarter Quarter Quarter Quarter ($thousands) 4Q03 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 Consolidated Net Income (loss) Net income (loss) (38,636) (2,393) 6, (3,774) 1,000 (3,322) Loss (gain) on disposition of properties - (2,982) (3,029) - - Consolidated Net Income (loss) (38,636) (5,375) 3, (3,774) 1,000 (3,322) Consolidated EBITDAX Add to Consolidated Net Income: Income Taxes 20, Consolidated Interest Expense 2,806 3,749 6,010 6,179 6,324 6,289 8,595 DD&A 9,144 11,583 13,961 11,697 18,396 20,502 15,201 Exploration and dry hole 2,173 G&G Impairment 1, Non-cash compensation expense ,019 Other non-cash charges: Accretion expense (Gain) loss on abandonment 564 (256) (17) Extraordinary items: Loss on unsuccessful property acquisition 8, Loss on extinguishment of debt - 3, Cumulative effect Consolidated EBITDAX ($millions)

33 Stock Price Appreciation ATPG PEERS M-04 $ 5.78 $ A-04 $ % $ % M-04 $ % $ % J-04 $ % $ % J-04 $ % $ % A-04 $ % $ % S-04 $ % $ % O-04 $ % $ % N-04 $ % $ % D-04 $ % $ % J-05 $ % $ % F-05 $ % $ % M-05 $ % $ % A-05 $ % $ % M-05 $ % $ % J-05 $ % $ % J-05 $ % $ % A-05 $ % $ % Peers: EPL, NFX, PPP, REM, SGY, and SKE Price as of Aug. 03,

34 First Call Cash Flow First Call Cash Flow E (1) 2006E (1) # Shares CAGR ATP $2.49 $3.65 $ ,966,000 89% Peer Average $8.70 $11.09 $ ,751,571 16% Peers: EPL, NFX, PPP, REM, SGY, and SKE (1). Source: First Call Estimates June 25,

35 Margin Analysis Pro Forma 160 MMcfe/d 1H05 1H05 24-Mth Strip (1) Production (MMcfe/d) Operating Statistics ($millions) Lease operating expense $ 10.6 $ 30.7 $ 30.7 G&A expense $ 9.4 $ 9.4 $ 9.4 Interest Expense $ 14.9 $ 14.9 $ 14.9 Total cash costs $ 34.8 $ 54.9 $ 54.9 Per Unit Price realizations ($/Mcfe) $ 6.55 $ 6.55 $ 9.52 Lease operating expense $ 1.06 $ 1.06 $ 1.06 G&A expense $ 0.94 $ 0.32 $ 0.32 Interest Expense $ 1.49 $ 0.51 $ 0.51 Total cash costs per unit (2) $ 3.48 $ 1.90 $ Year F&D costs $ 2.06 $ 2.06 $ 2.06 Full Cycle Cash Return $ 1.01 $ 2.59 $ 5.56 (1) NYMEX oil and gas closing prices on August 1, (2) Based on 1H05 costs (LOE $10.6 million, G&A $9.4 million and interest $14.9 million). 6-year F&D Cost Adjusted Costs Incurred $ 56,051 $ 76,516 $ 109,958 $ 33,914 $ 83,034 $ 86,176 Proceeds from Property Sales $ 1,137 $ - $ - $ - $ - $ 19,200 Production (MMcfe) (17,301) (24,480) (25,697) (26,456) (17,094) (22,411) Future Development Cost $ 414,657 Total Reserves 275,237 6-year F&D Cost $