The Outlook for U.S. Natural Gas Supply and Demand and the Potential Role for Liquefied Natural

THE OUTLOOK FOR U.S. NATURAL GAS SUPPLY AND DEMAND AND THE

POTENTIAL ROLE FOR LIQUEFIED NATURAL GAS

a Presentation to the National Association of Petroleum Investment Analysts &

the Petroleum Investor Relations Association

La Quinta, California

October 10, 2002

JAMES T. JENSEN Phone (781) 894 2362 Jensen Associates Fax (781) 894 9130

49 Crescent Street; Weston, MA 02493 U.S.A. E Mail [email protected] Website JAI-Energy.com

FOLLOWING A DECADE OF LOW NATURAL GAS PRICES, GAS MARKETS SUFFERED A

SEVERE SHOCK IN THE WINTER OF 2000/01

Two Strong Perceptions Have Emerged from the Turmoil

Short Term Natural Gas Prices Are More Volatile Than We Had Previously Anticipated, And

The Complacency About the Ability of the Conventional North American Gas Resource Base to Carry Sharply Expanded Gas Demand Was Severely Tested - Imported LNG and Arctic Gas Pipelines Are Now

Back on the Table

THIS IN TURN HAS FOCUSSED ATTENTION ON THE UNDERLYING DISCONNECT

BETWEEN

The Volatile Price Behavior of Short Term Commodity Markets, and

The Need for Stable, Long Term Price Incentives Both to Stimulate the Necessary Levels of Drilling Activity and to Justify These Major New Long Term Supply Projects

Just How Volatile Recent Price Changes Have Been - Both Up and Down - Can Be Seen from a Decade of Monthly "Bid Week" Spot Quotations for Henry Hub

The December 2000 Quote Was Nearly Two and a Half Times the Previous January 1997 High

It Was Also Far Higher Than the Average Price Levels that Most Forecasters - the EIA, the Canadian NEB, and the IEA - Were Anticipating at the Time for the Year 2020, Let Alone 2010

And the EIA - In its Most Recent Annual Energy Outlook - Still Expects Wellhead Prices in 2020 to be 9% Lower Than Those Actually Experienced in 2000

While the Market's Response to the Price Shock Quickly Brought Supply and Demand Back Into Balance and Prices Back to Earlier Levels,

Prices Remain Unusually High Given the Fact that Gas Storage Inventories Have Been Near Record Levels and Demand has Been Unusually Weak

The Market Seems to Waiting For Some Resolution of the Issue as to Whether a Return to Growing Demand Will Create More Problems for Conventional Gas Supply

A GAS MARKET "WAKE UP CALL" FOR THE 2000/01 WINTERBID WEEK SPOT NATURAL GAS PRICES @ HENRY HUB, LOUISIANA

MONTHLY DATA - $/MMBTU

N90 N91 N92 N93 N94 N95 N96 N97 N98 N99 N00 N01$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$/MMBTU

SPOT PRICE@ HENRY HUB

Previous Rangeof Spot Prices

The Winter of 2000/01

Weather-Driven "Spike" In 1997 Sets the Previous High

Jensen

GAS PRICES AND THE MAJOR GAS PRICE FORECASTSTHE WINTER CHALLENGE AND THE SUMMER PRICE COLLAPSE BID WEEK NATURAL GAS PRICES [1] @ HENRY HUB, LOUISIANA

MONTHLY DATA - $/MMBTU

JAN 1999 JUL JAN 2000 JUL JAN 2001 JUL JAN 2002 JUL$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$/MMBTU

HENRY HUBSPOT

12 MONTHNYMEX STRIP

Range of the EIA, NEB, and IEA Year 2000 Price Forecasts for 2010

Jensen

The Challenge to Model Price Forecasts Began in the Spring of 2000

But Despite a Drop in Demand and High Storage Inventories, Prices Remain Higher Than Anticipated

Prices Spiked in the Winter

[1] Including 12 Month NYMEX "Strip" (Average Forward 12 Month Futures Contract)

THE GAS PRICE SHOCK HAS PROVIDED SOME VALUABLE INSIGHTS INTO NATURAL

GAS PRICE BEHAVIOR AND THE WAY IN WHICH IT IS INFLUENCED BY OIL PRICES

The Shape of the Short Run Gas Supply/Demand Curve is More Complex than Those Found in the Economics Textbooks

In Demand, What is Important is the Relationship Between Gas and Oil Prices, Rather Than the Absolute Price of Gas Itself

Demand is Quite Inelastic In the Short Run, Both For Premium Uses and - Once The Market is Fully Satisfied - for New Loads Developed Through Price Discounting

In Between is an Elastic "Bench" Where Rising Gas Prices Threaten Loss of Load to Fuel Oil in Dual-Fired Utility and Industrial Boilers

Since Short Run Supply is Also Quite Inelastic, A Market In Surplus Will Be Decoupled From Oil Competition and "Gas-to-Gas" Competition - Sometimes Below Replacement Costs - Will Be the Result

This Has Been the Predominant Pattern Over the Last Decade

THE THEORETICAL BEHAVIOR OF SUPPLY, DEMAND AND PRICE ACCORDING TO "ECONOMICS 101"

Increasing Volume

Increasing Price

Supply Increases With Price

Demand Decreases With Price

Market Clearing Price

Market Clearing VolumeJensen

Increasing Gas Price Relative to Oil Price(Gas as % of RAC)

A MORE REALISTIC SHORT TERM GAS SUPPLY/DEMAND CURVEA MARKET IN GAS-TO-GAS COMPETITION

Increasing Volume

Inelastic Premium Demand

Elastic Gas Demand in Competition with Residual Oil in Switchable Boilers

Inelastic Load Building

Inelastic Short Term Supply

In Surplus, Oil and Gas Prices Are Decoupled - Resulting in "Gas-to-Gas" Competition - Prices Are Volatile

The "Cusp" Where Gas Prices Become Decoupled from Oil

Discounted Prices

Jensen

But When Supply Tightens, Switching to Residual Fuel Oil Takes Place, Restoring Oil-to-Gas Competition With Residual Fuel Oil Setting a Cap on Gas Prices

It Also Exposes Gas Prices to the Risk of a Collapse in Oil Prices - Another Element of Market Concern

But If the Market is Tight Enough, Residual Fuel Oil Switching Capability (Perhaps 1,500-2,000 MMcfd, or 2.5% to 3% of Consumption) May Be Exhausted

Then Switching May Move Into a New Region Where Gas Competes With the More Plentiful, But More Costly, Distillate Fuel Oil

It Was This Competition With Distillate That Explained the High Prices of the 2000/01 Winter

Increasing Gas Price Relative to Oil Price(Gas as % of RAC)

ANOTHER SHORT TERM GAS SUPPLY/DEMAND CURVETWO MARKETS WITH OIL-TO-GAS COMPETITION RESTORED

Increasing Volume

Inelastic Load Building

Oil and Gas Prices Still Coupled But With Higher-Priced Distillate, Rather Than Residual Fuel, Competition

Oil and Gas Prices Recoupled - Resid Prices Set a Cap On Gas Prices - Prices May Be More Stable But Are Exposed to Oil Price Risks

1

2

Elastic Gas Demand in Competition with Residual Oil in Switchable Boilers

Elastic Gas Demand in Competition with DistillateOil in Switchable Boilers

Inelastic Short Term Supply

Inelastic Short Term Supply 1

2

1

2

Jensen

BY EXAMINING EIA ELECTRIC UTILITY FUEL CONSUMPTION DATA, IT IS POSSIBLE TO DEVELOP AN ESTIMATE OF THE PRICE AT WHICH GAS AND OIL PRICES RECOUPLE

Some Seasonal Switching to Oil For Customers on Interruptible Contracts is Normal, Particularly in the Northeast

But Under Tight Supply Conditions or Unfavorable Gas/Oil Price Relationships, Price-Driven Abnormal Switching to Oil Takes Place, Largely in the Electric Utility Sector

By Using EIA Data for Generating Fuels, Together with the Refiner's Aquisition Cost of Crude Oil (RAC) as a Measure of Oil Prices, It is Possible to Estimate Utility Switching During These Periods and Thus the "Cusp" Where Oil-to-Gas Competition Replaces Gas-to-Gas Competition as the Major Determinant of Gas Pricing

In the 1980s the Data Seemed to Confirm an Industry Rule of Thumb that the Relationship Between Crude Oil and Gas Prices in a Price-Competitive Market Was "Ten to One" - That is $25 Oil Was Equivalent to $2.50 Gas

My Estimates Are That the Linkage Now Occurs at About 90%% of RAC

For $25 Oil, That Implies a Gas Price of $3.88

Interestingly Enough, Gas Price Expectations Appear to Remain Linked to Oil Despite Weak Demand and High Storage Inventories

HENRY HUB SPOT GAS PRICE AS A PERCENT OF REFINER ACQUISITION COST OF CRUDE OIL

(BOTH IN $/MMBTU)

0%

50%

100%

150%

200%

HENRY HUB ($/MMBTU) PERCENT OF RAC

Early View of the "Cusp" - The Oil Price Coupling Level;

Increased Switching Danger

Gas Keeps Market

1985 1990 1995 2000

1986 Oil Price Collapse

Weak Oil Prices Cold Weather, Strong Gas Prices

1998 Oil Price Collapse

This Is Probably a Better Estimate of Today's Cusp

December 2000

Jensen

ABNORMAL SWITCHING FROM GAS TO OIL BY U.S. ELECTRIC GENERATORS DURING SELECTED MONTHS WITH

OIL/GAS PRICE COMPETITIONMMCFD

0

500

1,000

1,500

2,000

2,500

3,000

3,500

SWITCHING IN MMCFD

Jun/Sep 86 Oct 88/Mar 89 Nov 89/Jan 90 May/Sep 98 Nov 00/Jan 01

August 1986 December 1988 December 1989 July 1998 December 2000 Oil Collapse Weak Oil Prices Record Cold Oil Collapse Gas Shortage Gas $1.47 Gas $2.23 Gas $2.17 Gas $2.37 Gas $6.11 Oil $11.92 Oil $13.98 Oil $19.54 Oil $11.92 Oil $26.31 72 % of RAC 93% of RAC 64% of RAC 115 % of RAC 213 % of RAC

It Now Takes Higher Prices For Equivalent Levels of Switching

Jensen

But Actual Prices are Made by Traders Who Judge the Status of the Short Term Supply/Demand Balance by Monitoring the Weekly EIA Storage Reports

And Storage - Which Was Dangerously Low at the Start of the 2000/01 Winter - Was Refilled Very Quickly During the Following Summer Suggesting a Return of Surpluses

Hence the High Prices Could Not Hold

Key Questions - "Where Did the Demand Go?", Why Did Prices Remain Linked to Oil in the Face of Surplus?, And, "Do the Investments in Long Term Supply That Looked So Attractive a Year and a Half Ago Still Make Sense?"

YEAR-TO-YEAR CHANGES IN GAS STORAGE INVENTORIES AS MEASURED BY ANNUALIZED NET STORAGE INJECTIONS OVER THE

YEAR SHOWING APPROXIMATE PRICE/VOLUME RANGESTWELVE MONTH MOVING AVERAGE IN MMCFD

Apr 00 Oct Apr 01 Oct Apr 02

(2,000)

(1,000)

0

1,000

2,000

3,000

NET INJECTIONS - 12 MONTH MOVING AVERAGE IN MMCFD

Jensen

Storage Inventory Levels Were Steadily Below the Previous Year Before the Winter Started

Then After A Severe Cold Spell, the Net Injection Pattern Sharply Reversed With Rapid Refill of Storage

Winter 2000/01 Price Spike

NormallyGas-to-GasCompetitive

ResidCompetitive

DistillateCompetitive

ApproximatePrice/Volume Ranges

2001 Year End Gas Storage Inventories Were At the Highest Level in Twenty Years

SINCE THE PRICE SHOCK GAS PRICES HAVE BEEN HAVE BEEN LINKED TO OIL PRICES - GAS PRICE VOLATILITY REFLECTS OIL PRICE

VOLATILITY $/MMBTU

1995 1996 1997 1998 1999 2000 2001 2002$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$ PER MILLION BTU

NYMEX STRIP

90% OF RAC

Jensen

Traditional Gas-to-Gas Competition Below Oil Linkage

Now Oil-to-Gas Competition

THE DRAMATIC REVERSAL DURING 2001 FROM LOW STORAGE INVENTORIES TO A TWENTY-YEAR HIGH BY THE END OF THE

YEAR IS LARGELY ATTRIBUTABLE TO DEMAND REDUCTION

Consumption Levels Initially Increased, Largely Due to Weather Effects, But Then Declining Demand Accounted for 57% of the Total Storage Shift by the End of the Year

The Production Figures Have Been Somewhat Disappointing Given the Much Higher Early Gas Rig Count And Are Thus the Major Source of Concern About Supply

YEAR TO YEAR CHANGES IN FACTORS CONTRIBUTING TO RAPID STORAGE REFILL DURING 2001

CUMULATIVE CHANGES FROM PREVIOUS YEAR - BCF

Jan Apr Jul Oct

0

500

1,000

1,500

2,000INCREASE IN STORAGE OVER PREVIOUS YEAR BCF

CHANGE INWITHDRAWALS

Jan Apr Jul Oct

0

500

1,000

1,500

2,000

FACTORS INCREASING STORAGE

BALANCINGITEM [1]IMPORTINCREASEPRODUCTIONINCREASECONSUMPTIONDECREASE

The Decrease in Consumption Has Become the Largest Factor in the Change in Storage;Production Has Been Somewhat Disappointing

[1] The "Balancing Item" is a Statistical Difference EntryJensen

The EIA's Electric Utility Data Appear to Indicate that Reduced Utility Demand Was Responsible for a Significant Portion of the Decline in Consumption

But the EIA Has Had a Data Problem Since it Began Treating Utility Plants Sold to Independent Operators (Such as in California) as Industrial Load

An Adjustment to the Raw Gas Consumption Numbers to Account for Plants Transferred Out of the Utility Category Suggests that it Was Actually Reduced Demand In Industrial Heat and Process Applications (Excluding Industrial Cogeneration) That Has Been Primarily Responsible for the Decline

YEAR TO YEAR CHANGES IN SECTORAL CONSUMPTION CONTRIBUTING TO RAPID 2001 STORAGE REFILLCUMULATIVE CHANGES FROM PREVIOUS YEAR - BCF

[1] Adjusted to Include Transferred Plants

Jan Apr

Jul Oct

(1,500)

(1,000)

(500)

0

500

1,000

CHANGE FROM PREVIOUS YEAR BCF

INCREASE INCONSUMPTION

[1] Adjusted to Include Transferred PlantsJan Apr Jul Oct

(1,500)

(1,000)

(500)

0

500

1,000

INCREASES OVER PREVIOUS YEAR

INDUSTRIALHEAT, PROCESSLEASE, PLANT,PIPELINEINDUSTRIALCOGENERATIONRESIDENTIAL,COMMERCIALELECTRICUTILITIES1]

The Sharpest Drop Has Been Registered by Industrial Heat; Industrial Cogeneration Has Actually Grown While Utility Growth Has Been Stagnant

Consumption Was Initially Higher But More Recently It Has Been Significantly Down

Jensen

THE REVIVED INTEREST IN LNG AND ARCTIC GAS IS BEING DRIVEN BY THE EXPECTATION

OF UNPRECEDENTED GROWTH IN GAS DEMAND COUPLED WITH NEW QUESTIONS ABOUT TRADITIONAL SOURCES OF SUPPLY

Gas is Expected to Dominate the Markets for Stationary Energy, Largely Conceding the Transportation Market to Oil

And It Has Become the Preferred Energy Source for the Growth of Electric Power Generation

U.S. NATURAL GAS DEMAND BY SECTORHISTORY 1972/2001 AND EIA FORECAST 2010 & 2020

TCF

1972 1980 1990 20000

20

40

60

80

100

BILLION CUBIC FEET PER DAY

FIELD &PIPELINEELECTRICUTILITIES

INDUSTRIAL

RESIDENTIALCOMMERCIAL

Shortage & Curtailment

Partial Deregulation, Conservation, the "Gas Bubble"

Restructuring, Adoption of CCGT Power

Projected 2010 Demand 31% and 2020 58% Higher Than 2000 Based Largely on Increased Consumption for Power Generation

2020

Demand in 2000 Exceeded That In 1972 for the First Time in 28 Years

Jensen

THIS IS EXPECTED TO REQUIRE A VERY SUBSTANTIAL INCREASE IN DOMESTIC GAS PRODUCTION AND PIPELINE IMPORTS FROM

CANADA

And Despite the "Gas Price Shock" of the Winter of 2000/2001, the EIA's "Annual Energy Outlook 2002" Still Anticipates that North American Gas Will Carry the Lion's Share of the Increase in Demand

The Role of Imported LNG, While Increasing is Still Projected to be Limited and the EIA Does Not Anticipate a Role for Alaska Before That Time

U.S. NATURAL GAS SUPPLYHISTORY 1972/2001 AND EIA FORECAST 2010 & 2020

BCFD

1972 1980 1990 20000

20

40

60

80

100

BILLION CUBIC FEET PER DAY

LNGIMPORTSNET PIPELINEIMPORTS

U.S.

While U.S. Production In 2001 Was 10% Lower Than In 1972, Total North American Availability Was 4% Higher

2010 2020

Domestic Production Plus Pipeline Imports Are Expected to be 47% Higher Than 2001by 2020

Jensen

LNG Accounts for Only 2.6% of Projected Supply; There is No Provision for the Alaska Pipeline

THE EIA PROJECTIONS SUGGEST THAT IT REMAINS OPTIMISTIC ABOUT LONG RUN

SUPPLY ELASTICITY AS WELL AS THE OUTLOOK FOR UNCONVENTIONAL GAS

SOURCES, SUCH AS COALBED METHANE AND TIGHT GAS

As a Result, the EIA's Price Projections Imply a Continuation of Gas-to-Gas Competition at Prices That May Challenge the Feasibility of Some of the Recent LNG Proposals and the Alaska Pipeline

If the Definition of Gas-to-Gas Competition is a Gas Price Below 90% of the Refiner Aquisition Cost of Crude, Then in All But Two of Its Alternative Scenarios - The Low World Oil Price and Low Technological Progress Cases - the EIA Foresees Conditions That Rule Out a Return to Oil-to-Gas Competition

PROJECTED OIL AND GAS PRICES FOR THE YEAR 2020 UNDER DIFFERENT SCENARIOS

FROM EIA ANNUAL ENERGY OUTLOOK 2002

0

1

2

3

4

5

6

$/MILLION BTU

Gas PricesOil Prices

Jensen Refere

nce

Low G

rowth

Low O

il Pric

e

High O

il Pric

e

High G

rowth

Rapid

Tech

Progre

ss

Slow Te

ch

Progre

ss

GAS PRICE AS A PERCENT OF RAC 77% 101% 95% 82% 73% 65% 64%

In Only Two Scenarios Do Gas Prices Exceed 90% of RAC

THUS THE EIA PROJECTIONS TREAT THE GAS PRICE SHOCK OF THE 2000/01 WINTER

AS AN ABERRATION AND CAST SUBSTANTIAL DOUBT ON THE PRICE SIGNALS THAT

TRIGGERED MUCH OF THE INTEREST IN LNG AND ARCTIC PIPELINES

But While the EIA Reference Case Does Project Significant Growth in LNG Imports From 0.6 Bcfd to 2.5 Bcfd by 2020, It Does Not Include the Alaskan Project

And in a Series of Six Additional Scenarios in the Annual Energy Outlook 2002, EIA Did Not Foresee Any Additional LNG Contribution For the Year 2020 Over its Reference Case Estimate

However, In a Subsequent Report, "Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply", EIA Did Provide Several Additional Scenarios, Two of Which - "CO2 Limits" and "Low LNG Costs" Did Foresee LNG Increases

In One Annual Energy Outlook Scenario, a "High Priced Oil Case" it Increased Alaskan Production (Presumably for the Pipeline) by 2.6 Bcfd, While the Current Company Proposals Envision 4.5 Bcfd Project

PROJECTED LOWER 48 GAS SUPPLY UNDER DIFFERENT ECONOMIC AND TECHNICAL SCENARIOS

FROM EIA ANNUAL ENERGY OUTLOOK 2002

0

10

20

30

40

BCFD

AlaskaPipelineNet PipelineImports

Unconventional

Conventional

LNG GrossImports

Jensen

Refere

nce

Low G

rowth

Low O

il Pric

e

High O

il Pric

eHigh

Grow

th

Rapid

Tech

Progre

ss

Slow Te

ch

Progre

ss

LNG Imports Do Not Change With Scenario

Additional Alaskan Production Presumably for Alaskan Pipeline

THE GROWTH OF GROSS LNG IMPORTS BETWEEN 2000 AND 2020 UNDER VARIOUS LNG SENSITIVITY SCENARIOS

FROM EIA MIDTERM PROSPECTS REPORT DECEMBER 2001

Reference Case High LNG Cost CO2 Limits Low LNG Cost0

1

2

3

4

5

6

BILLION CUBIC FEET PER DAY

Gross LNGImports

Jensen

No Change With Higher LNG Costs

But Imports Grow Significantly More with CO2 Limits or Lower Costs

BUT LNG - LIKE GAS FROM ARCTIC PIPELINES - IS DIFFICULT TO DEAL WITH IN COMPUTER MODELS SINCE IT REQUIRES

JUDGMENTS AS TO WHETHER OR NOT INDIVIDUAL PROJECT DEVELOPERS WILL

PROVE SUCCESSFUL

The Judgments Are Heavily Dependent on an Understanding of the Potential Economics of the Project Within the Market Environment that the Model Envisions

And LNG Projects Are Not Only Highly Capital Intensive But Involve Significant Geopolitical Considerations as Well

On a Full Cycle Basis, LNG Projects are Multi Billion Dollar Efforts in Which the Receipt and Regasification Terminal is Usually a Relatively Small Part

ELEMENTS OF AN LNG DELIVERY SYSTEMBASIS: TWO 4 MMT TRAINS - 5,900 NAUTICAL MILES

(APPROXIMATE DISTANCE FROM NIGERIA TO THE U.S. GULF) REQUIRES ABOUT 12.8 TCF OF RESERVES TO SUPPORT

20 YEARS OF FULL DELIVERABILITY

CAPEX MARGINField Development (Varies) $1.6 Bn $0.80

Liquefaction $1.9 Bn $1.02

Tankers (11 @$180 Mn) $2.0 Bn $0.91

Regasification (Varies) $0.6 Bn $0.33

Total $6.1 Bn $3.05

THE INDUSTRY'S INTEREST IN LNG HAS DEVELOPED NOT ONLY BECAUSE OF THE

RECENT GAS PRICE SHOCK

Technology Has Provided a Substantial Reduction in Costs in Recent Years, Reviving Interest in Projects That Were Previously Viewed as Uneconomic

The Growth in the Spot and Short Term LNG Market Has Made it Possible to Arbitrage International Markets and Import Cargoes from Previously Unthinkable Sources

And the Growing Emphasis on "Monetizing Gas Discoveries" Has Focussed the Industry's Attention on LNG

A HYPOTHETICAL COMPARISON OF NIGERIAN LNG PROJECT ECONOMICS USING TODAY'S COSTS AND THOSE OF FIVE YEAR'S AGO ILLUSTRATES HOW MUCH COSTS HAVE

COME DOWN

Then, a New Greenfield Project Could Not Return a Target Netback (Assumed to be $0.80) to the Plant Gate

With Today's Reduced Costs, a Greenfield Project Delivering to the Northeast Is Now Economic (Assuming $2.85 Gas at Henry Hub and a $0.25 Basis Differential)

Expansion Economics Are Even Better

THE IMPROVEMENT IN U.S. EAST COAST LNG NETBACKS OVER THE PAST FIVE YEARS - A NIGERIAN EXAMPLE

ECONOMICS OF A HYPOTHETICAL 1997 GREEENFIELD PROJECT COMPARED TO CURRENT GREENFIELD AND CURRENT EXPANSION PROJECTS [1]

1997 Greenfield 2002 Greenfield 2002 Expansion$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$/MMBTU

RegasificationTankerLiquefactionInto Plant

$0.80 Target

Uneconomic with the Then Cost Structure

Now Economicwith New Cost Structure

Further Improved with Expansion at Existing SIte

[1] Assuming $2.85 Gas, a $0.25 Basis Differential and a Target Netback of $0.80 Into Plant

$2.85 @ Henry Hub Plus $0.25 Basis

The Reduction in Liquefaction Costs is Largely Attributable to Improved Gas Turbine Technology That Has Permitted Larger Train Sizes With Attendant Economies of Scale

The Reduction in Tanker Costs Is Partially Due to Increased Sizes, But Also Reflects Greater Competition from Shipyards, a Saving That Might Not Last With a Surge in Tanker Orders

And New Designs for Small Terminals, Such as the One That Has Been Built in Puerto Rico, Has Enabled the Industry to Access Smaller Markets Economically

Other New Technologies on the Drawing Boards Include Shell's Proposal for a Floating Production, Storage and Offtake Plant (FPSO) for the Sunrise Field in the Timor Sea And El Paso's Proposal to Install Regasification on Tankers (The El Paso "Energy Bridge") to Eliminate the Need for Regasifcation Terminals Altogether

In Both Cases the Proposals Represent The Combination Of Previously Independent Functions in the LNG Chain- Production and Liquefaction in One Case and Tanker Transportation and Terminalling in the Other - to Achieve Integrated Savings in Selected Project Situations

THE SURGE OF IMPORTS INTO THE U.S. IS LARGELY DRIVEN BY SPOT VOLUMES

However,Some of These Shipments, Such as Those Diverted from Australia and the Middle East, Take Advantage of Marginal Cost Pricing in the Presence of Surplus Plant and Tanker Capacity and Thus Do Not Reflect the Recovery of Full Return on Investment

A Shipment from Western Australia to Boston in 1997 Illustrates the Economics

But Others Reflect the Emergence of the Interaction Between the U.S. and European Markets With the Potential for Market Arbitrage

ILLUSTRATIVE NETBACK TO THE FIELD IN WESTERN AUSTRALIA FROM A 1997 SHIPMENT TO EVERETT, MASSACHUSETTS

COMPARING FULLY ALLOCATED COST, TANKER CHARTERNG AND COMPLETE MARGINAL COST TREATMENT

[1] Includes FuelFully Allocated Charter In Tanker Marginal Cost

$0.00

$1.00

$2.00

$3.00

$ PER MMBTU

Tanker OPEX [1]Charter TankerTanker Capital ChargesPlant OPEX [1]Plant Capital ChargesNetback Into Plant

Jensen

Netback is Negative on a Fully Allocated Cost Basis, But Rises to $0.62 With Tanker Chartering and $1.62 on a Total Marginal Cost Basis

Actual Price Delivered to Everett as Liquid - $2.56

LNG IMPORTS INTO THE U.S. IN 2001 ILLUSTRATE THE IMPORTANCE OF SPOT VOLUMES IN THE U.S. MIX

BCF

Contract Atlantic Basin Spot Pacific Basin Spot0

25

50

75

100

125

BCF

QatarOmanAustraliaNigeriaAlgeriaTrinidad

Jensen

38% 47% 15%

Trinidad is Being Run as a Classic Atlantic Basin Arbitrage

These Volumes Represent Surpluses to Pacific Markets

WHICH OF THE TWO VIEWS PREVAILS - THE EIA'S EXPECTATION OF CONTINUING GAS-TO-GAS COMPETITION OR THE

MARKET'S TENTATIVE EXPECTATION THAT HIGHER PRICES MAY HAVE RETURNED -

WILL GO A LONG WAY TOWARDS DETERMINING HOW OPTIMISTIC TO BE

ABOUT LNGSome LNG Projects, Such as the Trinidad and Nigerian Expansions, and Possibly a Greenfield Project in Venezuela, are Economic Even at Comparatively Pessimistic Price Expectations (Nigerian Economics Are Helped by the Pressure to Reduce Flaring) and Hence Form the Basis for Expected Growth

But Some of the Others Look Comparatively Unattractive as U.S.-Dedicated Projects at the EIA's Anticipated 2010 Prices, Although Some May Be More Feasible as Part of Combined Europe/U.S. Expansions

A RELATIVELY PESSIMISTIC SCENARIO FOR ATLANTIC BASIN LNGILLUSTRATIVE LNG NETBACKS FROM HENRY HUB TO THE OUTLET

OF THE GAS GATHERING SYSTEM ASSUMING THE EIA'S 2010 PRICE FORECAST FOR U.S. WELLHEAD

0

1

2

3

$/MMBTU

U.S.SectionCanadianSectionAlaskanSection

Regasification

TankerTransportLNGLiquefaction

Pipeline

Netback

Basis Diffferentials Help Ever ett But not Florida viathe Bahamas

Trin

idad/

Evere

tt

Trin

isad/

Lake C

harle

s

Alas

ka P

ipelin

e

Egyp

t/Lak

e Cha

r les

Vene

zuela/L

ake C

harles

Niger

ia/Lake

Cha

rles

Niger

ia via B

aham

as

Jensen

$2.85

Threshhold at Which a Field Investment of $3.85 per Annual Mcf Earns a 15% ROI

Ango

la/La

ke C

harle

s

Qatar

/Lak

e Cha

rles

Norway

/Lak

e Cha

rles

But if One Assumes a Return to Tighter Markets and Oil-to-Gas Competition With Stable Oil Prices, - a Pricing Structure Based on 90% of the EIA's 2010 Oil Price - It Makes Most of the Projects Much More Interesting

Similarly, West Coast Projects (Probably Based on Mexican Delivery) Look Unattractive at the EIA's 2010 Gas Price But Improve Substantially if Oil-to-Gas Price Levels are Reached

The West Coast Also Introduces a Significant Element of Basis Risk (A Collapse of Prices Below Henry Hub Levels as a Result of Overloading the Market) as the Experience of Pacific Gas Transmission's 1994 Expansion in California Illustrates

A MORE OPTIMISTIC SCENARIO FOR ATLANTIC BASIN LNGILLUSTRATIVE LNG NETBACKS FROM HENRY HUB TO THE POINT OF DELIVERY

FROM THE GAS GATHERING SYSTEM ASSUMING 90% OF THE EIA'S 2010 OIL PRICE FORECAST

0

1

2

3

4

$/MMBTU

U.S.SectionCanadianSectionAlaskanSection

Regasification

TankerTransportLNGLiquefaction

Pipeline

Netback

Basis Diffferentials Help Ever ett But not Florida viathe Bahamas

Trin

idad/

Evere

tt

Trin

isad/

Lake C

harle

s

Alas

ka P

ipelin

e

Egyp

t/Lak

e Cha

r les

Vene

zuela/L

ake C

harles

Niger

ia/Lake

Cha

rles

Niger

ia via B

aham

as

Jensen

90% of $23.36/B

Threshhold at Which a Field Investment of $3.85 per Annual Mcf Earns a 15% ROI

Ango

la/La

ke C

harle

s

Qatar

/Lak

e Cha

rles

Norway

/Lak

e Cha

rles

A PESSIMISTIC SCENARIO FOR CALIFORNIA LNGILLUSTRATIVE LNG NETBACKS FROM SAN DIEGO TO THE OUTLET

OF THE GAS GATHERING SYSTEM VIA A MEXICAN TERMINALASSUMING THE EIA'S 2010 PRICE FORECAST, NO BASIS DIFFERENTIAL TO

CALIFORNIA AND A $0.10 TRANSIT FEE FROM BAJA CALIFORNIA

0

1

2

3

$/MMBTU

Regasification

TankerTransportLNGLiquefaction

Pipeline

Netback IntoPlant or Pipeline

Sakh

alin

Jensen

Threshhold at Which a Field Investment of $3.85 per Annual Mcf Earns a 15% ROI

Mala

ysia

Aust

ralia

NW

She

lf

Boliv

ia

Indo

nesia

Bon

tang

Indo

nesia

Tan

gguh

$2.91 Import Price Minus $0.10

A MORE OPTIMISTIC SCENARIO FOR CALIFORNIA LNGILLUSTRATIVE LNG NETBACKS FROM SAN DIEGO TO THE OUTLET

OF THE GAS GATHERING SYSTEM VIA A MEXICAN TERMINALASSUMING 90% OF THE 2010 OIL PRICE FORECAST, A $0.50 BASIS DIFFERENTIAL AND A $0.10 TRANSIT FEE FROM BAJA CALIFORNIA

0

1

2

3

4

5

$/MMBTU

Regasification

TankerTransportLNGLiquefaction

Pipeline

Netback IntoPlant or Pipeline

Sakh

alin

Jensen

Threshhold at Which a Field Investment of $3.85 per Annual Mcf Earns a 15% ROI

Mala

ysia

Aust

ralia

NW

She

lf

Boliv

ia

Indo

nesia

Bon

tang

Indo

nesia

Tan

gguh

90% of $23.36/B Plus $0.50 Minus $0.10

"BASIS RISK" - COLLAPSE OF THE BASIS DIFFERENTIAL BETWEEN THE CALIFORNIA BORDER AND HENRY HUB FOLLOWING THE 1994

EXPANSION OF PACIFIC GAS TRANSMISSION FROM ALBERTATHREE MONTH MOVING AVERAGE

Jan 94 Jul Jan 95 Jul Jan 96 Jul

($1.50)

($1.00)

($0.50)

$0.00

BASIS - CALIFORNIA BORDER MINUS HENRY HUB

Jensen

PGT Expansion Adds 470 MMcfd to the 5,800 MMcfd California Market at the Beginning of the 1994/95 Heating Season

Prices Collapse Next Year as Market Absorbs Incremental Supply

Ordinarily, Gas Prices at the California Border Should Be Higher Than Those In Louisiana (A Positive Basis Differential)

THE EIA'S CONSERVATIVE PRICING OUTLOOK ALSO AFFECTS THE 17 DIFFERENT

PROPOSALS FOR NEW OR EXPANDED LNG RECEIPT TERMINAL CAPACITY INVOLVING

NEARLY 11 BCFD TO SERVE U.S. MARKETS

The EIA's Base Projection of LNG Demand for theYear 2020 Could Readily Be Accomodated by Capacity Already in Place at the Four Existing Terminals

And Even to Cover its Highest Scenario Case Would Require Only Limited Capacity Additions Over and Above What Seems Most Likely to Be Built Anyway

Obviously, if the EIA Projections are Correct, Most of the Proposed Terminals Will Never See the Light of Day

COMPARISON OF EIA'S LNG PROJECTIONS FOR GROSS LNG IMPORTS WITH EXISTING, PROBABLE [1] AND SPECULATIVE [1] TERMINAL

CAPACITY ADDITIONS INCLUDING MEXICAN AND BAHAMIAN CAPACITY FOR U.S. MARKET

0

5

10

15

BILLION CUBIC FEET PER DAY

Low LNGCostCO2LimitsReferenceCase2000Actual

Specualtive

ProbableAdditionalExistingLake CharlesExistingElba IslandExistingCove PointExistingEverett

Jensen

Existing Capacity Would Satisfy the EIA Basic Projection

There Are Many More Projects Reported in the Trade Press Than Are Likely to Be Needed

Probable Expansions Would Nearly Satisfy the EIA's Highest Scenario

[1] Jensen Estimates Based on Trade Press Reports

Existing and Proposed Terminal Capacity EIA Scenario Projections

THE U.S. PIONEERED THE RESTRUCTURING OF THE GAS INDUSTRY AND THUS IT IS

LOGICAL THAT THE ULTIMATE TEST OF HOW LNG MARKETS RESPOND TO THE NEW

ORDER SHOULD TAKE PLACE HERE

The Advantages of the Restructuring Particularly,Through the Development of Spot Markets, Are Very Apparent

They Include:Greater Efficiencies Through Price CompetitionThe Ability to Tailor Offtake Agreements to the Needs of

the BuyerHence, Buyer Flexibility to Meet Variations in DemandMore Efficient Utilization of Plant and Tanker CapacityGreater Flexibility to Balance Supplies to Regional

Markets

BUT JUST LNG'S RESTRUCTURING PROVIDES DISTINCT ADVANTAGES, THERE

MAY BE SOME SUBTLE DISADVANTAGES THAT SUCCESSFUL PROJECT DEVELOPERS

MUST IDENTIFY AND ADDRESS

The Industry Has Traditionally Been Based on Fairly Rigid Long Term Contracting Between Buyer and Seller

The Fact That the Buyer Assumed the Volume Risk Through Take-or-Pay Provisions and the Seller Assumed the Price Risk Though Price Escalation Clauses Assured the Financial Community of Reliable Project Cash Flow

The Assurance of Debt Service Coverage Thus Permitted High Debt/Equity Ratio Financing and Reduced the Cost of Capital

Such Contracting Does Not Work Very Well in a Gas-to-Gas Competitive Market Since Buyers Are No Longer Guaranteed That Their Regulated Utility Customers Will Cover Their Mistakes

But If the Pricing Clauses Are Tied Directly to the U.S. Spot Market, the Buyer Has Effectively Opted Out of His Volume Responsibility (He Can Always Resell at the Market Price), Thereby Shifting Project Risk Essentially to the Seller

Thus One Test of the New System Will Be to See if the Pressures are to Move Towards Higher Levels of Equity Financing, Implying Higher Project Hurdle Rates

The Evidence That the U.S. Spot Market is Inherently More Volatile Than the Traditional Pacific Basin System is Shown by Comparing Japanese LNG Pricing With Henry Hub

A COMPARISON OF PRICE VOLATILITY JAPANESE IMPORTED LNG VERSUS HENRY HUB SPOT AS A PERCENT

OF THE TEN YEAR AVERAGE12 MONTH MOVING AVERAGE TO ELIMINATE SEASONALITY - $/MMBTU

1992 20020%

50%

100%

150%

200%

PERCENT OF TEN YEAR AVERAGE

SPOT PRICE@ HENRY HUB

JAPANESE LNG

Jensen

Even Absent the Price Shock of 2000/2001, Henry Hub Has Been More Volatile Than Japanese LNG

THE ABILITY TO ARBITRAGE EUROPEAN AND POSSIBLY PACIFIC LNG MARKETS AGAINST THE U.S. MARKET OFFERS THE POTENTIAL

FOR HIGHER CAPACITY UTILIZATION IN PLANTS AND TANKERS

But It May Come at the Cost of Less Efficient Utilization of Receipt Terminals as Shippers, Seeking Higher Netbacks, Periodically Divert Cargoes to Other Markets

The Following Two Figures Compare Hypothetical Netbacks to Shipping Ports in Nigeria and Indonesia That Would Have Prevailed Over the Past Decade Had The Arbitrage Possibility Existed

A HYPOTHETICAL COMPARISON OF THE NETBACKS TO THE LOADING PORT THAT A NIGERIAN SHIPPER WOULD HAVE REALIZED IN

SHIPPING TO THE U.S. EAST COAST OR TO FRANCEASSUMING FULLY ALLOCATED TANKER COSTS

Jan 95 Jan 96 Jan 97 Jan 98 Jan 99 Jan 00 Jan 01 Jan 02$0.00

$2.50

$5.00

$7.50

$10.00

$/MMBTU

FRENCHNETBACK

U.S.NETBACK

More Attractive to Ship to U.S.

More Atttractive to Ship to Europe.

Jensen

A HYPOTHETICAL COMPARISON OF THE NETBACKS TO THE LOADING PORT THAT AN INDONESIAN (BONTANG) SHIPPER WOULD HAVE

REALIZED SHIPPING TO THE U.S. WEST COAST OR TO JAPAN ASSUMING FULLY ALLOCATED TANKER COSTS

Jan 95 Jan 96 Jan 97 Jan 98 Jan 99 Jan 00 Jan 01 Jan 02

$0.00

$2.50

$5.00

$7.50

$10.00

$12.50

$15.00

$/MMBTU

JAPANESENETBACK

U.S.NETBACK

But During the "Price Shock" it Became More Attractive to Ship to the U.S. West Coast

It Has Almost Always Been More Atttractive to Ship to Japan

Jensen

UNDENIABLY, THE NEWLY RESTRUCTURED LNG INDUSTRY OFFERS SUBSTANTIAL

PROFIT OPPORTUNITIES

But It Also Provides a Riskier Environment

Large Companies With Diversified Portfolios of LNG Supplies, Flexible Tanker Capacity and Access to Terminals in Multiple Markets Will Be in a Position to Diversify Risks and Take Advantage of Opportunities as They Arise

But Other Companies With Less Diversification Will Need Develop Strategies That Fit Their Own Individual Positions If They are to Benefit

TO CONCLUDE

The Gas Price Shock of the 2000/2001 Winter Has Raised Questions About How Robust Traditional North American Supply Will Be in the Face of the Anticipated High Growth in Demand

This In Turn Has Stimulated Interest in Supplemental Sources Such as LNG

The EIA's Forecast is Predicated on a Continuation of Gas-to-Gas Competition at Price Levels That May Make Some of These Projects Uneconomic

But Even the EIA's Conservative Views on LNG Still See Significant Growth - a 7% Growth Rate in Gross LNG Imports by 2020

However, the Recent Optimism About the Many Opportunities for New LNG Import Terminal Capacity and the Growth of a Significant Import Capacity on the West Coast are Probably Predicated on Higher Price Levels than Those that the EIA Foresees

Whichever View Prevails - That the Gas Price Shock Was a Temporary Aberration or a Foretaste of New, Higher Price Gas Levels - Will Go a Long Way Towards Defining the Future Outlook for U.S. LNG