Federal Energy Regulatory Commission Natural Gas Markets Conference Balancing Natural Gas Policy:

Federal Energy Regulatory Commission

Natural Gas Markets Conference

Balancing Natural Gas Policy:Fueling the Demands of a Growing Economy

October 14, 2003

National Petroleum Council Natural Gas Study

National Petroleum CouncilNational Petroleum Council

• Federally chartered, privately funded advisory committee

• Sole purpose is to advise and make recommendations to the Secretary of Energy

• Operates under the Federal Advisory Committee Act

• Council comprised of ~175 members

National Petroleum CouncilThe Study Could Not Be More Timely

“Examine the potential implications of new supplies, new technologies,

new perceptions of risk, and other evolving market conditions that may

affect the potential for natural gas demand, supplies, and delivery through

2025 ... provide insights on energy market dynamics, including price

volatility and future fuel choice, and an outlook on the longer-term

sustainability of natural gas supplies … advice on actions that can be

taken by industry and Government to increase the productivity and

efficiency of North American natural gas markets and to ensure adequate

and reliable supplies of energy for consumers.”Spencer Abraham

Secretary of EnergyMarch 2002

National Petroleum Council

Coordinating Subcommittee

Committee on Natural Gas

Supply Transmission &

Distribution Demand

Study Organization


Higher Prices Reflect a FundamentalShift in Supply & Demand

CANADA SUPPLY

U.S. SUPPLY

0

5

10

15

20

25

30

1985 1990 1995 2000

TCF

GAS PRICE, $/MMBTU

$8

$6

$4

$2

$0

U.S. & CANADATOTAL DEMAND

National Petroleum CouncilWe Must Improve from the Status Quo

The current policy direction — unaltered — will likely lead to difficult conditions in the natural gas market, but industries, government, and consumers will react.

Therefore, this study assumes action beyond the status quo: Arctic pipelines built, substantial LNG imports, success in Lower-48 permitting, increased energy efficiency, fully-compliant coal and renewable generation.


The NPC Analyzed Two BaseScenarios Beyond the Status Quo

Reactive Path

Balanced Future

Public policies remain in conflict, encouraging consumption while inhibiting supply … resulting in higher prices and volatility

Public policies aligned: alternate fuels and new natural gas supply sources compete to ensure lowest consumer cost

National Petroleum CouncilPotential Price Range

2000 2005 2010 2015 2020 2025

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

2000 2005 2010 2015 2020 2025$0.00

1995

Annual Average Henry Hub Prices, $/MMBTU ($2002)

Reactive Path

Balanced Future

Reactive Path

Balanced Future

National Petroleum CouncilThe NPC Recommends Action in All These Areas

Higher economic growth

Higher employment

Stronger industrial activity

Improve demand flexibility & efficiency

Increase supply diversity

Sustain and enhance infrastructure

Promote efficient markets

and

and

and


Supply Task Group Report


Natural Gas Supply

National Petroleum CouncilSupply Task Group Approach

• Conduct a comprehensive review of the North American resource base

• Analyze historical production performance

• Evaluate new supply sources (LNG, Arctic)

• Consider effects of advancing technology and regulatory environment

• Focus on production outlook

National Petroleum CouncilSupply Task Group Participants

Subgroups

Technology*

ChevronTexacoBob Howard

Baker-HughesBP/Shell - WorkshopChevronTexacoConocoPhillipsDOEEl PasoExxonMobilGas Tech InstituteHalliburtonLandmarkMarathon

Envir/Reg/Access

BurlingtonDavid Blackmon

ARIBLMBurlingtonChevronTexacoConocoPhillipsDOEExxonMobilForest ServiceMarathonMMSShell

LNG

ShellJohn Hritcko

BPChevronTexacoConocoPhillipsDOE/FERCEl PasoExxonMobilKeySpanSempra LNGShell US GP

Resource*

ExxonMobilGerry WorthingtonGary StoneAnadarkoBob Stancil

AnadarkoBPChevronTexacoConocoPhillipsDevonEl PasoEnCanaExxonMobilKerr-McGeeMarathonNaborsParkerShellUSGS/MMS/CGPC

Task GroupLeadersExxonMobilMark SikkelBill StrawbridgeDOEElena Melchert

MembersAlcornAnadarkoBPBurlingtonChevronTexacoConocoPhillipsDOEEl PasoENSCOMarathonOcean EnergyShell

Arctic P/L

ExxonMobilRobbie SchilhabBPKen KonradConocoPhillipsJoe Marushack

AnadarkoChevronTexacoImperial

*Additional participants from regional workshops

National Petroleum CouncilSupply History and Outlook

0

5

10

15

20

25

30

35

1 990 19 95 20 00 200 5 201 0 20 15 20 20 202 5

TC

F/Y

ear

Othe r Lowe r 4 8

N on-Arct ic Ca nada

Al aska

LNG

GOM S hel f

Rocki es

M ac ke nzie

GOM Sl ope

Reactive Path Case

National Petroleum CouncilSupply Findings

“Traditional North American producing areas will provide 75% of long-term U.S. gas needs, but will be unable to meet projected demand.”

“Traditional North American producing areas will provide 75% of long-term U.S. gas needs, but will be unable to meet projected demand.”

“Increased access to U.S. resources (excluding designated wilderness areas and national parks) could save consumers $300 billion in natural gas costs over the next 20 years.”

“Increased access to U.S. resources (excluding designated wilderness areas and national parks) could save consumers $300 billion in natural gas costs over the next 20 years.”

“New, large-scale resources such as LNG and Arctic gas are available and could meet 20%-25% of demand, but are higher-cost, have longer lead times, and face major barriers to development.”

“New, large-scale resources such as LNG and Arctic gas are available and could meet 20%-25% of demand, but are higher-cost, have longer lead times, and face major barriers to development.”

National Petroleum CouncilSupply Recommendations

Increase access and reduce permitting impediments to development of Lower - 48 natural gas resources.

Enact enabling legislation in 2003 for an Alaska gas pipeline

Process LNG project permit applications within one year

Increase access and reduce permitting impediments to development of Lower - 48 natural gas resources.

Enact enabling legislation in 2003 for an Alaska gas pipeline

Process LNG project permit applications within one year

National Petroleum CouncilSupply Development Roadmap

• Resource Base

• Historical Production Performance

• Cost Estimates

• Technology

Commercial Resource andProduction Outlook

- Access

- Arctic Gas

- LNG


Resource Base


• Objective to determine commercial resource through 2025

– Assessed components - Proved, Growth and New Fields

– Assessed costs of finding, developing and operating

– Developed commercial resource estimates by modeling supply/demand balance

• Proved Reserves

– Verified EIA reported data with decline curve analysis

• Growth of Proved - (existing fields)

Extrapolation of historical recovery/well trends

• New Fields (Undiscovered)

– Based on statistical field size distribution and chance of success, by basin

– Conventional and Nonconventional (tight gas, CBM, shale gas)

• Study based on publicly available data (government & commercial)

– Resource assessments from USGS, MMS, CGPC for Canada, and IHS for Mexico

– Historical cost, production, field data from API, IHS, EEA, Nehring, etc

• Industry workshops used to validate or adjust publicly available data

Resource Assessment Methodology

National Petroleum CouncilResource Assessment Process

Workshops(Validate resource, supply cost, access and technology issues for significant regions)

BestPractice(Provideconsistentmethodology)

CoreResource

Team

Case1

Case2

Case3

Etc.

ModelRuns(Multiplecases forlearning &uncertaintyanalysis)

Proved

Growth

NewFields

Techn-ology

Access

Dev./Cost

GOM

Conv.

RockyMts.

Non-Conv.Conv.

Alaska

Conv.

Canada

Non-Conv.

Conv.Non-Conv.Conv.

EastInterior Mexico

Conv.

Perm./Anad.

Non-Conv.Conv.Non-

Conv.Conv.

GulfCoast

Model-ing

National Petroleum CouncilResource Assessment

Total Technical Resource = 1969 TCF

30371

11224 6

85

22

295

284

64

88110

33

183

329

121

0

50

100

150

200

250

300

Ala

sk

a

Gu

lf o

f M

ex

ico

Ro

ck

ies

WC

SB

Ea

ste

rn I

nte

rio

r

Gu

lf C

oa

st

Me

xic

o

Ea

ste

rn C

an

ad

a

Arc

tic

Ca

na

da

TC

F

Nonconventional

Conventional

Undiscovered Technical Resource = 1366 TCF*

* Current Technology

National Petroleum CouncilTechnical Resource Base

• Lower - 48 technical resource of 1250 TCF is 210 TCF (14%) lower than 1999 Study

• Reduced assessment for growth to proved reserves half of difference

• Probabilistic uncertainty range - P10 = 135% Mean, P90 = 70% Mean

0

200

400

600

800

1000

1200

1400

1600

1992 NPC 1999 NPC USGS/MMS 2003 NPC

Non-ConventionalNew FieldGrowthProved

Lower - 48

0

500

1000

1500

2000

2500

3000

1992 NPC 1999 NPC 2003 NPC

Lower - 48 Alaska Canada Mexico

North America

Mean Assessment - 1999 Base, Advanced Technology (TCF)


Production Performance

National Petroleum CouncilProduction Performance Methodology

• Analyzed the production performance of all gas wells drilled since 1990

• Quantified average well performance parameters for each producing basin- Expected recovery- Initial production rate- Decline rate

• Evaluated rate of base production decline from existing wells

• Analyzed the production response to increased drilling activity

• Results used to establish future well performance expectations

National Petroleum CouncilProduction Performance - Recovery per Well

Rockies Coal Bed Methane

0.0

0.2

0.4

0.6

0.8

1.0

0 12 24 36 48 60 72 84

MMcf/d

90-95 96-98 1999 2000

EUR = 5 BCF

1.4 BCF

1.0 BCF0.5 BCF

Pro

du

ctio

n R

ate

Months

Recovery per Gas Connection

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

1990 1992 1994 1996 1998 2000

Lower - 48 (Excluding Nonconventional and DW GOM)

Western Canada

BC

F p

er G

as C

on

nec

tio

n

Source: Base data from EEA GSR


Anadarko Basin

Trends by Vintage - Initial Rate, Decline Rate, and EURTrends by Vintage - Initial Rate, Decline Rate, and EUR

Western Canada Sedimentary Basin

Production Performance - Basin Trends

National Petroleum CouncilProduction Performance - Decline Trends

Lower - 48 Wet Gas Production from Gas Wells,

by Year of Production Start

0

10

20

30

40

50

60

1992 1994 1996 1998 2000 2002

BCFDLower - 48 Decline Rate From Existing Wells

-30%

-25%

-20%

-15%

-10%

-5%

0%

1992 1994 1996 1998 2000

Source: Base data from IHS


Production Performance Review – 2001 Drilling Response

Incremental drilling: 2001 vs. 1999 What each well made: Buildup: Total 2.9 BCFD

0 200 400 600

GOM

S. Texas

Permian

E. Tx + N.La

Rockies ex PRB

Mid-continent

Powder River

1st Yr Calc. Buildup (MMscfd)

0 1 2 3 4 5

GOM

S. Texas

Permian

E. Tx + N.La

Rockies ex PRB

Mid-continent

Powder River

Avg 1st Yr Rate (MMscfd)

0 1000 2000 3000

GOM

S. Texas

Permian

E. Tx + N.La

Rockies ex PRB

Mid-continent

Powder River

Incremental Connections

Monthly U.S. L-48 Dry Gas Production

0

5

10

15

20

25

30

35

40

45

50

55

60

Jan-90 Jan-92 Jan-94 Jan-96 Jan-98 Jan-00 Jan-02

Avg

. Dai

ly V

olum

e, B

CFD

0

100

200

300

400

500

600

700

800

900

1000

1100

Act

ive

Gas

Dri

lling

Rig

s

Rigs

Gas Rate

Monthly L-48 Dry Gas Production

• Analysis of incremental drilling 2001 vs. 1999

• Average first year recovery declined 10-25%

- Decline greater for incremental wells

• Calculated incremental production of 2.9 BCFD

- Compares to observed ~2.4 BCFD

- 1999 drilling program yielded ~ 6 BCFD

Source: EEA GSR and Baker Hughes


Cost Estimates

National Petroleum CouncilCost Methodology

Methodology• Public and commercial databases used• Drilling and Completion

+ Lower 48 - API Joint Association Survey+ GOM - MMS data+ Canada - Petroleum Services Assoc. Canada

• Facilities+ Lower 48 - EIA Equipment and Operating costs+ GOM - Wood Mackenzie+ Canada - EEA database

• Costs benchmarked to industry experience

Results• Overall drilling costs compare well to 1999 study• GOM costs higher for deeper reservoirs• Lower rig attrition assumed than 1999 study


4 1, 2

1, 2

3 3

5

Current NPC Study

Water Depth Pleistocene /Pliocene

Miocene TexasDeepShelf

Foldbelt(Perdido)

Foldbelt(Miss. Fan)

0 – 40 m 9000’ 11,500’ 25,000’40 – 200 m 9000’ 11,500’ 25,000’200 – 400 m 11,500’ 14,500’400 – 800 m 11,500’ 14,500’ 17,000’800 – 1600 m 11,500’ 14,500’/20,000’ 11,000’ 17,000’> 1600 m 11,500’ 14,500’/20,000’ 11,000’ 17,000’

(1) (2) (4) (3) (3)

1999 NPC STUDY

Central/Western (1-4)

Water DepthConventional Subsalt

0 – 40 m 11,000’40 – 200 m 11,000’ 13,000’200 – 1000 m 13,500’ 15,500’1000 – 1500 m 13,250’1500 - 3000 m 15,000’1000 – 3000 m 15,250’

Gulf of Mexico Drilling Cost Development

National Petroleum CouncilCost Results

South Texas Gas Well Costs

0

1

2

3

4

5

0 - 5 5 - 10 10 - 15 >15

Drilling Depth, Thousand Feet

Wel

l C

os

t, 2

000

$M

M

1999 Study 2003 Study

Deepwater GOM Development

Cost Comparison

0.0

1.0

2.0

3.0

4.0

5.0

0 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Reserves, MMBOET

ota

l D

eve

lop

me

nt

Co

st,

$M

M

1999 Study2003 Miocene Deep


Technology


• Technology Subgroup determined impact new technologies will have on

supply

• Six workshops held with industry experts to gather insights on technology

advancements and estimated impact

• Technology improvement parameters developed for model input

• Gas production 14% higher in 2025 as result of technology enhancements

• Sensitivity cases analyzed to determine range of technology advancement

Technology Improvement Process

Natural Gas HydratesDeepwater Infrastructure

Subsurface ImagingCompletion

DrillingCoal Bed Methane

National Petroleum CouncilTechnology Improvement Parameters

-10%-0..44%-32%-1.52%-22%-1.00%Operating Expense

-15%-0.63%-35%-1.73%-26%-1.18%Infrastructure Cost

6%0.24%32%1.13%20%0.74%Initial Production

-8%-.034%23%0.83%-29%-1.37%Completion Cost

-23%-1.02%-33%-1.60%-37%-1.81%Drilling Cost

6%0.23%45%1.49%24%0.87%Recovery per Well

3%0.13%24%0.87%11%0.46%Development Success

2%0.08%24%0.87%14%0.53%Exploration Success

% Overall Improvement

% Annual Improvement


% Annual Improvement


% Annual ImprovementTechnology

Area

Reactive Path Low AdvancementHigh Advancement

These numbers represent the average of the parameters

National Petroleum CouncilTechnology Improvement Sensitivities

Pricing Sensitivity vs Reactive PathGas Price at Henry Hub ($2002)

-$2.00

-$1.50

-$1.00

-$0.50

$0.00

$0.50

$1.00

$1.50

$2.00

2000 2005 2010 2015 2020 2025$/M

Mb

tu

High Advancement Low Advancement

Technology Impact on U.S. and Canadian Natural Gas Production

20

22

24

26

28

30

32

2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

Year

TCF/

Yea

r

No Advancement

Low Advancement

High Advancement

Reactive Path


Commercial Resource and Production Outlook

National Petroleum CouncilModeling Methodology

• Key inputs to model, by region and reservoir depth- Technical resource and field size distribution- Production performance parameters - Drilling, development, and operating costs- Technology improvement parameters

• Model calculates costs to develop new supplies for each region

• Model develops “lowest cost” supplies until demand is met

• Model determines supply/demand equilibrium and resulting price

• Price is established by cost of last increment of supply

• Arctic gas and LNG imports were “fixed” model inputs

• Model determines commercial resource available for development

National Petroleum CouncilCommercial Resource

• Commercial resource determined from

econometric modeling

• 760 TCF commercial at $4.00/mmbtu,

60% of technical resource

• Supply curves developed for resource

type and region

0

200

400

600

800

1000

1200

1400

2003 NPC $3.00 $4.00 $5.00

Non-ConventionalNew FieldGrowthProved

CommercialTechnical

Lower - 48 Resource Base - (TCF)

National Petroleum CouncilSupply Curves

0%

20%

40%

60%

80%

100%

$2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00

Growth New Fields Nonconventional Total Gas

Lower - 48 Supply Curve - Resource Type

% U

np

rove

n R

eser

ves

0%

20%

40%

60%

80%

100%

$2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00

RockiesGOMEastern InteriorTotal GasGulf CoastMidcontinent

Lower - 48 Supply Curve - Regions

% U

np

rove

n R

eser

ves

National Petroleum CouncilProduction Outlook, Lower-48 and Non-Arctic Canada

Gas Production by Resource Type

0

5

10

15

20

25

30

2000 2005 2010 2015 2020 2025

TC

F/Y

ear

Associated

Conventional

Nonconventional

Gas Production by Region

0

5

10

15

20

25

30

2000 2005 2010 2015 2020 2025

TC

F/Y

ear

Other

Gulf Coast Onshore

Mid Cont / Permian

Canada - WestCanada - East

Eastern Interior

Rockies

GOM - Slope

GOM - Shelf

• Conventional production declining

• Nonconventional increase maintains overall production level

• Mature regions declining

• Production growth from new offshore areas and nonconventional regions

Reactive Path Case


0

5

10

15

20

25

30

2000 2005 2010 2015 2020 2025

TC

F/Y

ea

r

Supply at Constant Price - $/MMBTU ($2002)

$5 Fixed Price

$4 Fixed Price

$3 Fixed Price

• Production declines in $3 price environment

• Maintaining production levels requires $5+ outlook for Reactive Path case

Production Outlook, Lower-48 and Non-Arctic Canada

Production by Resource Category

0

5

10

15

20

25

30

2000 2005 2010 2015 2020 2025

Tcf

/Yea

r

Proved

Growth

Undiscovered

Conventional

Undiscovered

NonconventionalFuture

Drilling

Required

• Proved reserves from existing wells declining at 25-30% per year

• New wells required to develop non-proved resource

• All segments critical to outlook

Reactive Path Case

National Petroleum CouncilDrilling and Capital Outlook

Reactive Path Case

2025

North America Exploration and

Production CAPEX

0

10

20

30

40

50

60

70

80

1990 1995 2000 2005 2010 2015 2020

$ B

illi

on

s (

20

02

$)

United States

Canada

Gas Well Activity Level

0

5,000

10,000

15,000

20,000

25,000

1990 1995 2000 2005 2010 2015 2020 2025

Gas

Wel

ls

US L48

Canada

National Petroleum CouncilLower - 48 Production Comparison

2025

0

5

10

15

20

25

2000 2005 2010 2015 2020

TC

F/y

r

EIA 2003 Energy Outlook ($3.00 - $3.50)

NPC 1999 ($2.50 - $3.50)

NPC 2003 - Reactive Path ($5.00 - $7.00)

Lower - 48 Production Outlooks

NPC 2003 vs NPC 1999

• Outlook lower for all regions except Rockies; especially GOM

- Technical resource

- Production performance parameters

- Technology improvement factors

NPC 2003 vs EIA 2003

• Offshore outlooks similar

• EIA higher onshore outlook

- Higher resource

- Higher non-conventional recovery

- Different activity mix

Reactive Path CaseNPC 2003 and EIA 2003 Comparison - Onshore

Resource

0

50

100

150

200

250

300

350

400

450

500

TC

F

EIA 2003NPC 2003

Conv. Non - conv.

Recovery

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

BC

F /

We

ll

Conv. Non - conv.EIA 2003NPC 2003

Activity

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Wel

ls /

Yr.

Conv. Non - conv.EIA 2003NPC 2003


Access

National Petroleum CouncilAccess Evaluation

Objectives

• Clearly articulate complexity of the regulatory/environmental issues

• Quantify the impact on access to and recovery of natural gas resources

• Recommend actions supportive of environmentally sound development activities

Approach

• Expand on 1999 NPC study work; assess “conditions of approval”

- Compile habitat maps for major basins

- Estimate cost and timing impacts of regulatory process; quantify statistically

• Recommend specific improvements


Quantification Process

Etc. (Approx 60 maps)

Quantify requirements ifspecies / actions arepresent; cost, time

delays, and probabilityof

surveys mitigation studies, EIS

no surface access

Within studyboundaries,

map the areashaving species

or actions ofinterest

Calculatepercent ofstudy area.

Conduct analysis to determine

cost and time delays for 1000 potential wells.

Determine access inputs to model.

per well range of costs and average per well range of delays and average legislative/administrative withdrawn area effective area inaccessible due to regulation

Develop curves for cost and for delay.

$k

Well 1 2 3 4 5 6 … 1000


species / actions arepresent; cost, time


surveys mitigation studies, EIS

no surface access




surveys mitigation studies, EA, EIS no surface access

Raptor Habitat

Winter Range

T & E Species







Access Evaluation Process


Colorado

Wyoming

Basin Outline

Utah

Green River, Wyoming

Green River Basin - Big Game Crucial Ranges


Utah

Colorado

Wyoming

Basin Outline

Green River, Wyoming

Grizzly Bear

Canadian Lynx

Gray Wolf

Green River Basin - Grizzly Bear,Canadian Lynx, Grey Wolf

National Petroleum CouncilAccess Analysis Matrix

Sample Analysis Matrix -- Rockies

Im pact on Im pact onSurface

AuthorityActivity Sequence, Probability, and

GroupingW ildcat W ells Developm ent

W ells

Ite

m N

um

be

r

Item

Fe

de

ral

Ac

tio

n

Sta

te L

an

ds

Pri

va

teL

an

ds

Co

nti

ng

en

to

n I

tem

XH

ap

pe

nin

gF

irs

t

Pro

ba

bil

ity

or

Co

nti

ng

en

tP

rob

ab

ilit

y %

Co

rre

lati

on

wit

h I

tem

X

Co

rre

lati

on

Fa

cto

r

Ite

mN

um

be

rs o

fC

om

mo

nG

rou

p

Ad

de

d c

os

t($

)

Tim

e D

ela

y(m

os

)

Ad

de

d c

os

t($

)

Tim

e D

ela

y(m

os

) No

Ac

ce

ss

1Raptor SurveyGeneral 1 1 0 99.4 700 1

2Raptor Nest Survey

1 1 0 28.1 1 3500 1 350 1

3Active Raptor NestsFound: No Access 1 1 1 2 5.7 X

4Active Raptor NestsFound: M itigation 1 1 1 2 30.0 3 -1 3 106,000 3 106,000 3

5Big Gam e Survey

1 1 0 40.0 1200 360

6Big Gam e Found:Relocate/Directional 1 1 0 5 10.0 150,000 3 150,000 3

7Big Gam e Found:M itigation 1 1 0 5 90.0 6 -1 6 5280 3 5280 3

8Blackfooted FerretSurvey 1 1 0 54.5 7500 6 7500 6

9Blackfooted FerretFound: No Access 1 1 0 8 1.0 X

10Blackfooted FerretFound: M itigation 1 1 0 8 10.0 9 -1 9 106,000 3 106,000 3

… etc

Approxim ately 50 key item s per basin.

National Petroleum CouncilAccess Impact

Category Green

River

Uinta/

Piceance

Powder

River

San

Juan

No Leasing - % resource 7% 4% 4% 5%

Prohibitive Conditions

of Approval - %

36% 17% 34% 6%

Added Costs per Well

($thousands)

55 - 100 55 - 110 20 - 60 35 - 55

Time Delay per Well

(months)

12 - 22 8 - 13 7 - 14 6 - 8

National Petroleum CouncilAccess Impact

Pricing Sensitivity vs Reactive PathGas Price at Henry Hub ($2002)

-$1.00

-$0.80

-$0.60

-$0.40

-$0.20

$0.00

$0.20

$0.40

$0.60

2000 2005 2010 2015 2020 2025

$/M

Mb

tu

Increased Access Reduced Access

33TCF

25TCF

125TCF

21TCF

69 Off-Limits

Technical Resource Impacted byAccess Restrictions - TCF

Increase Access - Rockies access improves 50% over 5 years - OCS moratoria lifted beginning 2005

Reduced Access - Rockies impact doubles over 10 years


Recommendation: Increase Access (Excluding Wilderness Areas

and National Parks) and Reduce Permitting Costs/Delays 50%

over Five Years

• Improve government land-use planning

• Expedite leasing of nominated and expired tracts

• Expand use of categorical exclusions of sundry notices as alternatives to

processes imposed by NEPA

• Streamline and expedite permitting processes

• Establish cultural resource report standards and eliminate duplicate

survey requirements

• Establish qualification requirements and technical review procedures for

nomination of endangered species

• Fund and staff federal agencies at levels, and in manners, appropriate for

timely performance of responsibilities

Access Recommendations - Onshore


Recommendation: Lift Moratoria on Selected Areas of the

Federal OCS by 2005

• Lift, in a phased manner, moratoria on selected OCS areas having high

resource-bearing potential

• Update resource estimates for MMS-administered areas

• Ensure continued access to those OCS areas identified in the 2002-2007

5-year leasing program

• Ensure that Marine Protected Areas are meeting their intended purposes

• Require federal and state joint development of CZM plans

Access Recommendations - Offshore


Arctic Gas


Approach• Analysis based on work by resource holders• Identified hurdles to commercial development • Developed recommendations to address risks

Assumptions• Government frameworks achieved and market

conditions supportive• Projects come on line at earliest feasible dates• Mackenzie Gas Project

– 2009 start-up at 1 BCF/D, expansion to 1.5

BCF/D in 2015• Alaska Gas Pipeline

– 2013 start-up at 2.5 BCF/D, 4 BCF/D 2014– Potential to expand with additional

discoveries

Sensitivity• No Alaska pipeline case raised average natural

gas prices by 8% from 2015 to 2025

Arctic Supplies

Alaska NorthSlope Region

Mackenzie DeltaRegion

Arctic Gas Volumes Delivered to Alberta

0

1

2

3

4

5

6

2005 2010 2015 2020 2025

BC

F/D

Alaska

Canadian


Recommendation: Enact Enabling Legislation in 2003 for an

Alaska Gas Pipeline

• Congress should enact enabling legislation in 2003

• Canadian agencies should develop and implement a timely regulatory

process

• Alaska needs to provide fiscal certainty for the project

• Governments should refrain from potentially project-threatening actions

• Infrastructure improvements incidental to Alaska gas pipeline construction

must be planned in a timely and coordinated manner

Arctic Recommendations


• Documentation

– Study results documented in Supply Task Group Report

+ Resource base workshop proceedings and extensive database

+ Production performance analysis by basin

+ Cost estimating regional details

+ Upstream technology outlook

+ “Conditions of Approval” analysis for resource access

+ LNG educational primer

– Data will reside in two models for future use

• Future Studies/Activities

– Resource base

+ Resource assessment methodology; industry/government collaboration

+ Rockies non-conventional assessment

– Future production outlook collaboration with EIA

– Ongoing use of econometric model and maintenance of database; USGS and

others

Documentation/Future Studies


Liquefied Natural Gas


• Objective - Determine North America LNG import potential through 2025

– Assessed cost of LNG value chain (Supply, Transportation and Regasification )

– Evaluated competitive global market place (Supply, Shipping, Markets)

– Identified “controlling” assumptions that affect the pace of new LNG imports

– Developed three cases for modeling input

– Identified barriers/issues to LNG terminal development

– Formed recommendations

– Developed LNG educational primer

• Study based on publicly available data (government & commercial)

LNG Assessment Methodology


• Economies of scale essential for LNG project development

– Significant reserves required: 7 - 10+TCF fields

– Chain investments required: $2.0 - $5.0 Billion

– Large Volumes: 500 MMCFD to 1.0+ BCFD

– Contracts: typically long term 20-25 years, spot sales market

emerging

• Trends

– Continued cost reduction throughout the chain

•Timing

– Preliminary development at least 1 year

– Permitting: ~2 years

– Engineering, Design and Construction: 3+ years

LNG Value Chain/Characteristics


• LNG supply growing• Multiple LNG supply proposals announced• Long term LNG supply outlook robust

Global LNG Supply

WORLD PROVEDRESERVES 2002:

6270 TCF

NORTH AMERICARESERVES4%

Worldwide Natural Gas Resources are Vast

Source: Cedigaz

Existing

Under Construction

Proposed

Global LNG Supply Facilities

National Petroleum CouncilLNG Import Countries

0

20

40

60

80

100

120

1964

1966

1968

1970

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

MT

A

TURKEY

TAIWAN

S. KOREA

JAPAN

W. GERMANY

BELGIUM

ITALY

US

SPAIN

FRANCE

UK

Belgium Korea Taiwan Turkey

PuertoRico

DominicanRepublic

2003

Italy

SpainUS

JapanFrance

Source: CedigazGlobal LNG Market Established and Growing - 6 - 10% per year

UK

National Petroleum CouncilCompetitive LNG Potential

Announced Value-Chain BTULNG Supply* Cost to US Range(TCF) ($/Million btu) (btu per cubic feet)

Atlantic 100 GOM: $ 2.00 - 5.00Middle East 54 GOM: $ 3.00 - 4.00 1040-1160Pacific 112 WC: $ 2.50 - 5.50

* Significant future potential exist

National Petroleum CouncilFactors Impacting Pace of Development

Supply• Project economics• Foreign governments• Construction timing

Transportation• Existing shipping fleet primarily dedicated - short term impact• Ship yard capacity - New LNG carriers needed to support projects, large backorder• Construction timing - 3 years for new build LNG carrier

Regasification Import Terminals• Limited onshore sites available (access to deep water port & sufficient land, near

infrastructure)• Offshore: Gravity based, Floating, Direct regas (each has special requirements)• Public Opposition• Permitting for onshore

– process not coordinated or aligned between federal & state agencies– lengthy - significant number of permits required– impact on agency workloads

• Construction timing

Pipeline Interconnects• Capacity expansions may be needed• LNG Interchangeability

National Petroleum CouncilLNG Imports

- Existing- Potential New

Lake Charles

Elba Island

Cove Pt

Everett

GOM Offshore

Onshore(2)

Baja

Altamira

GOM Onshore(2)

LNG Terminal Locations

West Coast

Florida(Bahamas)

North America LNG Imports

0

2

4

6

8

10

12

14

16

2000 2005 2010 2015 2020 2025

BC

F/D

Existing Expansion

New-“Reactive” New - “Balanced”

National Petroleum CouncilNorth American LNG Imports for NPC LNG Scenarios

0

2

4

6

8

10

12

14

16

2000 2005 2010 2015 2020 2025

Reactive Path Balanced Future Low Sensitvity

Bcf per day

Permitting Streamlined9 New Terminals

6 Expansions

7 New Terminals4 Expansions

(14% US gas supply)

Public Opposition2 New Terminals

1 Expansion

National Petroleum CouncilPricing Sensitivity at Henry Hub versus Reactive Path

-$0.80

-$0.60

-$0.40

-$0.20

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

2000 2005 2010 2015 2020 2025

Balanced Future Low Sensitvity

$/Mmbtu ($2002)

National Petroleum CouncilLNG Recommendations

Recommendation: Process LNG project permit applications for onshore terminals within one year

• Coordinate and streamline multiple reviews

• Fund and staff agencies appropriately

• Undertake public education surrounding LNG

• Update natural gas interchangeability standards

• LNG industry standards should be reviewed and revised if necessary


Supply Summary

National Petroleum CouncilSelected Sensitivity Analyses

High Resource Base P10

Fuel FlexibilityHigh Supply Technology

Low Economic GrowthIncreased Access

High LNG Imports

Less Access

High Electricity ElasticityHigh Economic Growth

WTI $28 Oil PriceNo Alaska Pipeline

Low LNG Imports

Static Supply Technology

Low Resource P90

Change in PriceVs. Reactive Path

$2002

Change in Volumes (BCF/Year)Vs. Reactive Path

-2.00-4.00 2.00 4.000.00 -4,000 4,0000 2,000-2,000

Values shown are averages for the 2011 to 2025 period

National Petroleum CouncilSelected Supply Sensitivity Analyses

Federal Energy Regulatory Commission Natural Gas Markets Conference Balancing Natural Gas Policy:

Documents

Transcript of Federal Energy Regulatory Commission Natural Gas Markets Conference Balancing Natural Gas Policy: