Natural Gas Producer to Consumer

Transcription

1 Natural Gas Producer to Consumer Cy Esphahanian CCOP Beijing - June 25 Scope of this Presentation History and Overview The Physical Flow of Natural Gas Infrastructure The Financial/Business Structure Pricing Outlook

2 Lower 48 Dry Gas Reserves Trillion Cubic Feet World War II Ends Lower 48 Dry Natural Gas Reserves and Production, Rapid Reserves Peak 1967 HISTORY Production Peak TCF Proved Reserves Decline Flattens High Gas Prices and Drilling Lower Gas Demand Lower 48 Reserves Lower 48 Prod (Dry) AEO 2 Reference Case Projected Production in TCF AEO Lower 48 Dry Gas Production Trillion Cubic Feet U.S. Natural Gas Pipeline Profile Interstate vs Intrastate Pipelines Gathering System --> > Gas Processing Plant --> Mainline Pipeline System --> > Underground Storage --> > Local Distribution System Size of pipelines range from inches on mainlines, inches for LDCs and gathering systems (some plastic) Hubs or Market Centers provide interconnections among pipelines

3 U.S. Gas Industry at a Glance Industry Segment Participants Regulatory Regime Producers 6,8 U.S. oil and gas companies Phased price deregulation began in Major energy companies completed with Decontrol Act of 1989 Interstate Pipelines 9 FERC Intrastate Pipelines about 7 State Regulatory Commissions Local Gas Utilities 14 State Regulatory Commissions Marketers about 3 Unregulated Underground Storage 12 operators (415 Fields) FERC if part of interstate system Operators State Regulatory Commissions for others Gas Consumers Residential 59 million Commercial 5 million Industrial 235 Thousand Electric Generators: Utilities 648 plants Non-Utilities 356 Plants Interstate commerce - FERC Intrastate commerce - State Commissions

4 A Vast Network of Pipelines Provides Interstate Transportation Major Natural Gas Producing Basins and Associated Transportation Corridors Western Canada Sedimentary Basin Williston Basin Michigan Basin Green River Basin Powder River Basin Denver- Julesberg Basin Illinois Basin Scotian Basin Sable Island Uinta/Piceance Basin Hugoton Appalachian Basin Sacramento Basin San Joaquin Basin San Juan Basin Permian Basin Raton Anadarko/ Arkoma Black Warrior Basin Capacity (in Million Cubic Feet per Day) as of June 22 East Texas/ 15, 12, North Louisiana 9, 6, Basins 3, = Direction of Flow Gulf Coast Basin = Bi-directional South Texas Basin Source: Energy Information Administration, GasTran Gas Transportation Information System

5 Average Pipeline Utilization Varied in 1998 Capacity (in Million Cubic Feet per Day) 15, 12, 9, 6, 3, = Less than 1 MMcf/d Capacity

6 1 8 Seasonal Natural Gas Load Patterns By Sector (BCF) Residential 1 8 Commercial Jan-1 Mar-1 May-1 Jul-1 Sep-1 Nov-1 Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-1 Mar-1 May-1 Jul-1 Sep-1 Nov-1 Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov Industrial 1 8 Electric Power Jan-1 Mar-1 May-1 Jul-1 Sep-1 Nov-1 Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-1 Mar-1 May-1 Jul-1 Sep-1 Nov-1 Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Source: EIA. Natural Gas Storage Critical supply component during heating season Smoothes the production of gas throughout the year Withdrawals help satisfy sudden shifts in demand and supply caused by weather Supports hub services (parking, loaning )

7 There are Over 4 Storage Facilities in the U.S. Consuming West Consuming East Depleted Fields Salt Caverns Aquifers LNG Storage Facilities Total withdrawal capability is 78 billion cubic feet per day. Working Gas 3.9 Tcf Deliverability 78 Bcf per day Producing Types of Underground Natural Gas Storage E A Source: PB-KBB Inc B C D Underground Storage: A. Salt Caverns B. Mines C. Aquifers D. Depleted Reservoirs E. Hard-rock Caverns

8 Changes in Storage Operations Over the last five years More emphasis on inventory management Significant growth in deliverability Commodization of storage risk management tool: price hedge Emergence of third party operators Increased capital investment by local utilities and large consumers Supports hub services and intra-day services Linkage between storage and spot prices Supports market liquidity Peak Day Storage Facilities Liquefied natural gas typically more expensive than underground storage. Used mostly in areas where other storage not available. Peak-shaving facilities (propane) typically used during brief periods when demand spikes. Pipeline Line pack through increased compression, uses the pipeline as a temporary storage facility

9 Infrastructure Development There is No Centralized Planning of Additions to Gas Pipeline Capacity Need determined by estimates of future gas demand Pipelines obtain approval of FERC: - demonstrate need for capacity - minimize adverse environmental and cultural impact

10 Nature of Pipeline Investments The Company Perspective Utility franchise (FERC regulation) Relatively capital intensive with long lived immobile facilities Stable and predictable cash flow that provides financial synergies and higher credit ratings Demand Growth Has Led to Expanded Pipeline Capacity Options: - New pipelines - Additional compression - Looping - A combination of each

11 Pipeline Expansion Projects Reflect: The expanding development of deep- the Gulf of Mexico. water production in The growing production capacity in western and offshore eastern Canada. Shippers seeking greater access to alternate sources of supply. Capacity constrained production seeking greater access to Non- traditional markets. Between 199 & 1998, 18 new natural gas pipeline systems were built in the U.S. Tuscarora Pipeline 1995 (11 MMcf/d) Northern Border Extn 1998 (65 Mmcf/d) Bluewater Pipeline 1995 (25 MMcf/d Bi-directional) Empire Pipeline 1994 (5 MMcf/d) PNGTS/Maritime 1998 (632 Mmcf/d) Iroquois Pipeline 1991 (85 MMcf/d) Kern River Pipeline 1992 (75 MMcf/d) Pony Express Pipeline 1997 (255 MMcf/d) Crossroads Pipeline 1995 (25 MMcf/d) Mojave Pipeline 1992 (45 MMcf/d) TransColorado Pipeline 1996 (Southern Leg) (12 MMcf/d) Nautilus Pipeline 1997 (6 MMcf/d) Garden Banks Offshore System 1997 (6 MMcf/d) Manta Ray Gathering System 1997 (3 MMcf/d) Mobile Bay Pipeline 1993 (6 MMcf/d) DIGS Main Pass Gathering System 1997 (2 MMcf/d) Discovery Pipeline 1997 (6 MMcf/d) Destin Pipeline 1998 (1, Mmcf/d)

12 Proposed natural gas pipeline expansions (78 Projects, 23.7 Bcf/d) Central 1 Projects Bcf/d Midwest 17 Projects Bcf/d Northeast 23 Projects Bcf/d Western 9 Projects -.9 Bcf/d Southeast 12 Projects Bcf/d Southwest 7 Projects Bcf/d

13 Except for , 96, the amount of added capacity each year has been above 4 Bcf/d Million Cubic Feet per Day 14, 12, 1, 8, 6, 4, 2, 6,35 4,3 6,21 1,725 Additions to Capacity 1,875 2,574 6,542 8,46 (Announced and/or 12,35 Approved Projects) 5, Expenditures for pipeline development/expansions could jump to almost $5 billion in 2 Completed 8, Proposed 7, Millions of Dollars 6, 5, 4, 3, 2, 1,397 2,38 2,124 (Preliminary) 4,876 (Estimated) 1,

14 Financial/Business Structure How Pipelines Make Money Provide transportation and storage service under firm and interruptible contracts Most revenue collected under long term contracts with creditworthy customers Relatively limited exposure to throughput and basis fluctuations Subject to Cost of Service regulation Allowed to recover prudently incurred costs Rates include an allowed rate of return Allowed to recover costs through rates based on Cost of Service O&M and A&G Expenses + Depreciation Expense + Taxes Other Than Income (state, ad valorem) + Federal and State Income Taxes + Allowed Return Cost of Service (revenue) o Allowed Return = Rate Base x Rate of Return % Rate Base = Net Plant + Working Capital Deferred Taxes Rate of Return % = weighted average cost of debt and equity

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16 U.S. Gas Market Changes over the Last Decade Physical Changes: increase in pipeline capacity development of high-deliverability storage new pipeline routes, more interconnections technology advances Development of market centers Structural Changes: regulations -- encourage competition, protect environment role of pipelines -- transporters only open access to suppliers Development of futures market deregulation of wellhead prices, spot market emergence of a secondary market for trading pipeline capacity

17 Financial transactions are no longer closely tied to the flow of the commodity Physical Flow of Natural Gas Remain Much the Same Producers Pipelines LDC s End Users More Market Participants Involved in Financial Transactions Producers (Wellhead Prices) Pipelines LDC s Marketers On-System End Users Off-System End Users Transportation Commodity Bundled = Transactions captured by current data collectors. = Transactions not captured by current data collectors. Interstate Transportation Market in 2 Pipelines -- Transporters, Not Merchants More Choices for Shippers Improved Pricing Information Increased Competition New Services New Challenges

18 Effects of Physical and Structural Changes: Pipeline Companies Shifting risk/cost Increased competition Customer oriented New business strategies: consolidate spin-off diversify enter unregulated business areas Choices of Pipeline Services Have Changed in the 199 s 25 2 Released Capacity Quadrillion Btu 15 1 Interruptible Transportation No-Notice Service 5 Sales Firm Transportation

19 Natural Gas Market Centers Serve As Major Trading and Transshipment Points Sumas Hub Chicago Center PGT Center Golden Gate Center California Energy Center Western Center Mid-Continent Center Columbia Gas Center Iroquois Center New York Center Ellisburg-Leidy Center CNG/Sabine Center Mojave Center Waha (Delphi) Hub PG&E Waha Hub Blanco Center Buffalo Wallow Center Waha (Lone Star) Hub Waha (TECO)Hub Perryville (NORAM) Center Carthage Hub Equitable Resources Hub Katy (TECO) Hub Texaco Gulf Star Center Katy (Western) Hub Houston Hub Henry Hub Egan Hub Louisiana Center Aqua Dulce Hub Moss Bluff Hub Market Center and Hub Services Wheeling Parking Loaning Storage Peaking Balancing Gas Sales Title Transfer Electronic Trading Administration Compression Risk Management Hub-to to-hub Transfers

20 Effects of Physical and Structural Changes: Industry New industry players: Marketers Increased competition Development of hubs and market centers Efficiency Gains: Increased throughput, decreased unit costs Technology advances Market signals communicated Corporate combinations & convergence Spot Market Development More opportunities and risks (volatility) Effects of Physical and Structural Changes: Shippers New responsibilities and risks More Choices - for services and providers More transparent price information Changes to delivery system utilization strategic use of storage more inventory management shedding unused capacity Financial instruments (e.g. future market)

21 To Obtain Transportation Services Step 1. Reserve capacity (via contract) with the pipeline or a releaser of capacity Types of contracts: Long-term firm transportation (FT) Short-term term firm service Interruptible (IT) Capacity release (firm or recall) Step 2. Nominate to use capacity Step 3. Confirmation of nomination by the pipeline company Step 4. Gas flows are scheduled by the pipeline company Trends in Transportation Contracts LDCs hold the bulk of contracted capacity. Contract expirations are significant Shippers want flexibility and reliability In the aggregate total commitments have increased slightly. The length and size of long-term contracts have decreased. Market concentration varies by region

22 Marketers Have Increased Their Share of the Transportation Market Marketers 22% July 1, 1997 Electric Utilities 4% Marketers 27% July 1, 1999 Electric Utilities 4% Pipeline Companies 7% Others 3% Industrials 5% Total Firm Capacity is 93 trillion Btu per day. LDCs 59% Pipeline Companies 7% Others 5% Industrials 5% Total Firm Capacity is 97 trillion Btu per day. LDCs 52% Volatility of Natural Gas Prices has Increased Over the Last Several years

23 Average Annual Wellhead Prices Have Been Close To The Record High Price Set In 1983 $5 $4 $3 $2 $1 Nominal Dollars Constant 23 Dollars Projection $ Dollars per Thousand Cubic Feet Sources: History: EIA; Projections: Short-Term Energy Outlook, August 23 U.S. Natural Gas Prices Are Expected to Trend Upward Through 25 $16 $14 History Outlook Dollars Per Mcf $12 $1 $8 $6 $4 $2 Residential Commercial Industrial Electric Utilities Wellhead $ Jan-96 Jan-97 Jan-98 Jan-99 Jan- Jan-1 Jan-2 Jan-3 Jan-4 Jan-5 Sources: History: EIA; Projections: Short-Term Energy Outlook, August 24.

24 In Recent Years Natural Gas Prices Show Greater Volatility $4.5 $4. $ Dollars January January 2 Dollars per Mcf $3. $2.5 $2. $1.5 $1. $.5 $. Nominal Dollars Natural Gas Spot Prices Are Volatile 1.5 Henry Hub Daily Midpoint Price $18.85 on 2/25/3 Dollars per MMBtu Dec-97 Apr-98 Aug-98 Dec-98 Apr-99 Aug-99 Dec-99 Apr- Aug- Dec- Apr-1 Aug-1 Dec-1 Apr-2 Aug-2 Dec-2 Apr-3 Source: Natural Gas Intelligence, Natural Gas Index

25 What Are The Main Drivers Of Short-term Price Volatility? Weather Economic/business conditions Stock levels Pipeline capacity Operational difficulties Lack of timely, reliable information Affects Supply Affects Demand Illustrative Supply and Demand Curves More Inelastic Demand More Elastic Demand D 2 D 1 S D D 3 4 S wellhead price D D 1 2 percent supply utilization rate wellhead price D D 3 4 percent supply utilization rate

26 Natural gas is second only to electricity in energy futures price volatility 1 Electricity at Palo Verde 8 Electricity at CA-OR Border Volatility Index (Percent) 6 4 Natural Gas Average of 3 Petroleum Products Winter 1999/2: Fuel Oil and Gas Market Developments New England heating oil prices increased $.78 per gallon (to $1.97) between 1/17 and 2/7 Factors that led to the surge increases in crude oil prices cold weather low fuel oil stocks refinery outages transportation problems natural gas interruptible load switching to distillate

27 Natural Gas Futures Trading Market Is Used to Hedge Against Price Volatility New York Mercantile Exchange (NYMEX) for deliveries at Henry Hub Allows a buyer to lock-in a price for an amount of gas (1, MMBtu) that will be delivered at some time in the future (36 consecutive months). Trading for the next month s deliveries stop three business days prior to the first day of the delivery month. The Gap Between Crude Prices and Gas Prices Widened During Winter 1999/2 $6. West Texas Intermediate $5. NYMEX Henry Hub near-month futures contract closing price Henry Hub Spot Avg $4. Dollars per MMBtu $3. $2. $1. $. Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99 Jan- Feb-