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2	An Overview of The Energy Industry in the United States SABIT Oil & Gas Offshore Exploration & Production Session Mayer, Brown, Rowe & Maw May 9, 2003 Houston, Texas U.S.A.
3	U.S. Energy Usage
4	Electricity Generation By Fuel 1970 – 2020
5	Energy Consumption By Fuel 1970 - 2020
6	U.S. Energy Suppliers 1989
7	U.S. Energy Suppliers 2002
8	Global Supply and Demand
9	U.S. Energy Usage
10	U.S. Wells Drilled and Average Wellhead Price
11	The Energy Conundrum: Prices Went Up Drilling Went Down Drilling, Operational and Service Costs Escalated Company Growth Outran Opportunities It’s The Economy! Markets Changed and Capital Moved to Industries Perceived to be Lower Risk and Higher Return Commodity Price Volatility Political Policy to Insure Affordable Energy Public Environmental Pressure
12	Changes in the Industry Planning Driven by Financial Markets Focus on “P” Value Range – P10 to P90 (Probabilistic Risk Analysis) Global Shift to Natural Gas Shift to Offshore and International Larger Targets, Higher Deliverability and Larger Reserves Mergers, Acquisitions and Divestitures to Consolidate and Restructure Pressure to Decrease Costs and Risks
13	The Growth of Natural Gas in the United States Demand for Electrical Power Generation Environmental Concerns – “Clean Fuel” Consumption Expected to Increase for Industrial, Commercial and Residential Markets Large Technically (Economically?) Recoverable Resources - ~ 2,500 Trillion Cubic Feet Includes “Unconventional” Gas – Coalbed and Coalmine Methane, Ventilation Air Methane
14	Industry Structure
15	The “Super Majors” BP + Amoco Exxon + Mobil Chevron + Texaco Total + Fina + Elf Conoco + Phillips Royal Dutch Shell + ?
16	The “Super Independents” Devon (Mitchell Energy, Ocean and others) Anadarko (Union Pacific Resources) Apache Encana (Alberta Energy + PanCanadian) Swift Burlington Kerr McGee
17	The Portfolio Approach Technology & Tools Portfolio Risk Management Sensitivity Analysis and Monte Carlo Simulation 3-D and 4-D Seismic Visualization Software Enhanced Wellbore Logging Tools Advanced Fracture Stimulation Workstation to PC Evolution With Powerful, Affordable PC Based Geologic Mapping & Geophysical Interpretation Programs
18	"Multilaterals and Coil Tubing Drilling" Multilaterals and Coil Tubing Drilling Expandable Casing New Generation Drilling Rigs Wireless Real Time Field Data Delivery
19	Growth Strategy and Balanced Portfolio of a Typical Super Independent United States Shift Exploration to Offshore Shift other Exploration to Production in “Mature” Basins Consolidate Assets via Merger, Acquisition and Divestiture. Solidify Core Areas and Shed Poorer Performing Assets Enhance Production – Secondary or Tertiary Recovery Control Costs and “Hedge” Production Collaborative Relationships Long term Contracts with Service Companies and Suppliers International Exploration Potential in “Immature” Basins Leverage Technology Developed Domestically Develop Discoveries Collaboration with National Oil Companies
20	Major U.S. Areas of Activity Deepwater Gulf of Mexico (“GOM”) Deep Gas (Bossier Sand) Play East Texas and North Louisiana Barnett Shale North Texas South Texas Deep Gas (Vicksburg, et al) Rocky Mountain Deep Gas and Tight Gas Sand Plays The Commonality – Deeper Horizons and / or Pushing the “Technology Envelope”
21	U.S. 3-D Seismic Coverage
22	Shallow Shelf “Deep Gas” Flow Rates in New Reservoirs Tended to Be Higher the Deeper the Completed Wells Went Below 15,000 Ft. At 15,000-15,999 Ft Tvd Subsea, the Average Maximum Rate for 20 Completions in 2001-02 Was 13.8 Mmcfd, and None Exceeded 25 Mmcfd. At 16,000-16,999 Ft Tvd Ss, 12 Completions Had an Average Maximum Rate of 32.2 Mmcfd. One Tested Nearly 80 Mmcfd, and Three Others Exceeded 50 Mmcfd. At Greater Than 17,000 Ft Tvd Ss, 13 Completions Had an Average Maximum Rate of 44.8 Mmcfd. Two of the 13 Tested at More Than 100 Mmcfd, and Four Others Exceeded Maximum Test Rates of 50 Mmcfd. South Timbalier Block 204. El Paso Production Co., Houston, Discovered the Field in Late 2000 and Placed It Online in 2001, MMS Said. Production in 2002 Was Upwards of 350 Mmcfd of Gas Plus Condensate.
23	Deepwater Gulf of Mexico- Why It’s Important 25% of U.S. Natural Gas Comes From GOM, 80% of That From Shallow Shelf, Which Has High Decline Rates. An Expanding Frontier That Will Be of Increasing Importance to U.S. Energy Supplies, According to a Report by the Department of Interior's Minerals Management Service (“MMS”). Deepwater Gulf of Mexico 2002: America’s Expanding Frontier "The Large Volume of Active Deepwater Leases, the Increased Drilling Program, and the Growing Deepwater Infrastructure All Indicate That the Deepwater GOM Will Increase in Importance As an Integral Part of This Nation's Energy Supply and Will Remain One of the World's Premier Oil and Gas Basins.” MMS Calls the Growth of Oil and Gas Industry Activity in the Deepwater (1,000 Ft of Water or More) Gulf Over the Past 7 Years "Extraordinary". MMS Officials Said That 59% of All Oil Production in the GOM Now Comes From Deep Water.
24	GOM Production 1980 to 2000 by Depth
25	Recent History of Deepwater The Step From Shallow Water to Deepwater Development in the Gulf of Mexico Began in the Late 1970s: Cognac Field, Discovered by Shell on Mississippi Canyon Block 194, Was a Milestone. It Broke the 1,000-ft Water Depth Barrier; Set a Record for a Deepwater Fixed Platform at 1,014 Ft; And, With Gas Production at 130 Mmcfd (Peak), Demonstrated That Deepwater Reservoirs Could Be of High Quality. Ten Years After Cognac, in 1989, Shell’s Bullwinkle (Gc65) Platform Was Set in 1,330 Ft of Water Depth, Pushing the Water Depth Limits for Fixed Structures. In the Early 1990s Deepwater Development Accelerated With 12 Fields Coming on Line, Centered in Mississippi Canyon and Garden Banks: Most Notable Was Shell’s Auger Field (Gb426) With a Peak Capacity of 300 Mmcfd That Established an Important Deepwater Hub at 3,000 Ft of Water. The Second Half of the 1990s Has Been Marked by an Acceleration in New Field Discoveries, Records for Deepwater Exploration and Development, And, Most Significantly, the Discovery of Giant Size Fields. In 2000 and 2001, 9 More Significant Fields Were Discovered. Since 1998, Four Giant Fields–in Excess of 400 Million Boe–have Been Found (Mad Dog, Crazy Horse, Crazy Horse North, Trident). 218 Fields Have Been Discovered to Date in the Deepwater Gulf, 45 Are "Significant," Containing Reserves in Excess of 100 Million BOE. Thunder Horse Is the Largest With 1.5 Billion Barrels Reserves.
26	Deepwater Positives and Negatives High Capital Expenditure (“Capex”) and Development Costs Capex Spending From 2003 to 2007 Estimated at $18 Billion Well Costs of ~ $100 MM and Production Facility Costs of ~ $1 Billion Lag Time from Discovery to Production Upward of 3 years? High Productivity – A Positive Economic Factor Cutting Edge Technology Platform Infrastructure on Shallow Shelf to Host Subsea Tiebacks > 40,000 KM of Offshore Pipelines in Place Mardi Gras (BP)Transportation System being Constructed – 485 Miles Total MMS Royalty Relief
27	Productivity A Shell Ursa Field (Mississippi Canyon Block 854) Well Produced 30,000 B/d of Oil and Lease Condensate. A BP Troika Field (Green Canyon Block 244) Well Produced 31,000 B/d of Oil and 66 Mmcfd of Gas. Positive Experience Has Led to a Dramatic Revision in Development Strategies and Production Economics. Shell’s 1 Tcfg Mensa Field, Where a Single Well Produced 100 Mmcfd, Will Be Developed With Only 3 Subsea Wells. The 1992 NPC Gas StudyAssumed That a Field of This Size Would Require 30 to 40 Wells (Rather Than 3) to Develop.
28	Cutting Edge Technology Compliant Towers, Tension Leg Platforms (TLP), Spars, Subsea Tiebacks and Floating Production Systems. 3-D seismic and Seismic Sequence Stratigraphy Continued reductions in drilling costs and improvements in drilling efficiencies Subsea completions and "hubs and corridors“, the Shell Oil concept of anchoring an area with a central platform and using subsea tiebacks, has changed the capital requirements and economics. Floating Production, Storage, and Offloading systems (FPSOs) for use in ultradeep waters in the gulf, Including LNG. Shuttle Tankers
29	2002 Central GOM Lease Sale The Sale High Bid Was $17.5 Million Submitted by Phillips Petroleum Co. For Green Canyon Block 199 Located in 800-1,599 M of Water. The Block in Deepest Water to Receive a Bid Was Atwater Valley 347 in 2,665 M. There Were 71 Blocks in More Than 1,600 M of Water With Apparent High Bids Amounting to $94.3 Million. Another 81 Blocks, in 800-1,599 M With Apparent High Bids of $100.9 Million. The Lease Term for Blocks in Less Than 400 M of Water Is 5 Years, With a Minimum Bid of $25/acre. For Blocks in 400-799 M, the Term Is 8 Years With $25/acre Minimum Bid. For Blocks in 800 M or More, the Term Is 10 Years With Minimum Bid of $37.50/acre.
30	Factors Affecting Future Development The Pace and Extent of Technological Advances. Access to Currently Restricted Areas of the Eastern Gulf. Future Environmental Requirements Affecting Offshore Development. Financial Incentives Available to Stimulate Development, Including Continued Royalty Relief. Availability of Ultradeepwater Infrastructure to Bring New Supplies to Market. The Continued Advance of Technology and Prices Will Mean Even Smaller Fields Will Be Economic to Develop.
31	Capex and Operations
32	Major International Areas of Activity Caspian Region Offshore India Offshore China Offshore and Onshore Egypt Offshore West Africa In 2000 – 2001 8 Discoveries > 180 MMBOE Kashagan @ ~ 10 BBOE Offshore New Field Well Success, Reserves per NFW and Average Reserves Increased
33	Caspian Region CIS Oil Reserves = 20% of World Reserves Caspian Oil Reserves = 21% of CIS Reserves CIS Gas Reserves = 34% of World Reserves Caspian Gas Reserves = 22% of CIS Reserves In 2001 CIS Produced 8.5 MMBD & 69 BCFGD Caspian Produced 1.3 MMBD & 6.5 BCFGD In 2011 CIS Will Produce 13.2 MMBD & 91 BCFGD (Projected) Caspian Will Produce 4.5 MMBD & 21.5 BCFGD
34	International Fiscal Terms Concessionary (Tax and Royalty) Book 100% of Reserves Contractual (Production Sharing Contract “PSC”) Book Cost Recovery and Profit Service Contracts (Pemex) Joint Ventures EOR Contracts Rate of Return Contracts
35	International Issues Legal and Business Risks Operational Administrative and Regulatory Ownership / Equity Contractual Political and Socio-Economic Commercial Risks Constraint on Foreign Investment Adverse Contractual Changes Lack of Infrastructure, Materials and Services Pipelines etcetera
36	International Growth of Natural Gas Worldwide Stranded Gas Potential Lines out of Caspian Region New Offshore India Discovery? China Proposed West to East Pipeline “Corridor” May Opt to Move to Natural Gas as “Fuel of Future” Rather than Petroleum Ongoing and New Coalbed Methane, Coalmine Methane and Abandoned Mine Projects Australasia Region Somewhat Limited by Market and New CBM Projects Will Likely Add Deliverability LNG and CNG CNG Tanker ~ 2 BCFG per Ship with Docking Flexibility New LNG Terminals being Permitted
37	Acquisition and Divestiture Why to Sell Properties Strong Seller’s Market Follow Up To Larger Acquisition Lower Debt / Equity Ratio Raise Cash Why Not to Sell Properties Volume Growth Driven by Securities Analysts Company Promises Growth Uncertainty on Long Term Pricing Outlook Not Rewarded for Debt Reduction vs. Volumes
38	A & D Outlook Supermajors Have Not Pruned Properties Yet Although Several Have Made Recent Announcements. Large Packages Will Lead to More Divestitures Cautious Optimism About Deal Flow Commodity Price Volatility A Concern
39	Past Commodity Pricing
40	Overview of the Divestment Market
41	Implied Reserve Value for U.S. Transactions
42	Oil Conversion Nomograph Tons To Barrels of Oil
43	Natural Gas Conversion Nomograph MCF To Cubic Meters