Balancing Natural Gas Policy Vol-1 Summary (NPC, 2003)

BALANCINGNATURALGAS

SEPTEMBER 2003

SUMMARY

NATIONAL PETROLEUM COUNCIL

RECOMMENDATIONSOF FINDINGS AND

POLICYFUELING THE DEMANDS

OF A GROWING

ECONOMY

VOLUME I


Phone: (202) 393-6100Fax: (202) 331-8539

An Oil and Natural Gas Advisory Committee to the Secretary of Energy

1625 K Street, N.W.Washington, D.C. 20006-1656

September 25, 2003

The HonorableE. Spencer AbrahamSecretary of EnergyWashington, D.C. 20585

Dear Mr. Secretary:

On behalf of the members of the National Petroleum Council, I am pleased to submit to you theCouncil’s report on natural gas: Balancing Natural Gas Policy – Fueling the Demands of a Growing Economy.This report was prepared at your request to provide insights on energy market dynamics as well as advice onactions that can be taken by industry and government to ensure adequate and reliable supplies of energy forAmerican consumers. We further recognize the importance of your request and the urgency of ourrecommendations, given the heightened sensitivity among consumers to energy costs and reliability.

Natural gas continues to be a vital source of energy and raw material, and will play an important role in achieving the nation’s economic and environmental quality goals. The Council finds that recentfundamental shifts in North American natural gas markets have led to the current market conditions ofhigher gas prices and increased price volatility. This situation will likely persist and could deteriorate unlesspublic policy makers act now to reduce the conflicts that are inherent in current public policies.

Clearly, the recent tightening of the natural gas supply/demand balance places greater urgency onaddressing the future of this important energy source and resolving conflicting policies that favor natural gasusage, but hinder its supply. The Council has reached out to hundreds of experts in the public and privatesectors, representing both suppliers and consumers, to analyze future supply, demand, and infrastructurerequirements, in order to advance recommendations that we believe will equip local, state, and nationalpolicy makers to make sound and balanced decisions for the future.

The Council recommends a balanced portfolio of actions by industry and government that includes:

• Encouraging conservation and efficiency

• Improving demand flexibility and efficiency

• Increasing supply diversity

• Sustaining and enhancing infrastructure

• Promoting efficiency of markets.

The Hon. E. Spencer AbrahamSeptember 25, 2003Page Two

Policies most likely to have an immediate impact are actions to promote consumer conservation and energy efficiency. Actions to increase supply diversity and demand flexibility should also be takenimmediately because several years will elapse before their full impacts will be felt. The Council'srecommended approach includes action in all of these interdependent areas, because neither increasingsupplies nor improving the efficiency of gas consumption would alone be sufficient to achieve the country’sgoals. It is vital to accomplish both.

The Council further recommends that the Department of Energy schedule a series of workshopsdesigned to review steps taken to implement the report’s recommendations, and to monitor the implicationsof ongoing changes in market conditions.

The Council is available to discuss further the results of this report and to aid in the implementationof its recommendations.

Respectfully submitted,

Bobby S. ShackoulsChair


Bobby S. Shackouls, ChairLee R. Raymond, Vice Chair

Marshall W. Nichols, Executive Director

U.S. DEPARTMENT OF ENERGY

Spencer Abraham, Secretary

The National Petroleum Council is a federaladvisory committee to the Secretary of Energy.

The sole purpose of the National Petroleum Council is to advise, inform, and make recommendations

to the Secretary of Energy on any matter requested by the Secretary

relating to oil and natural gas or to the oil and gas industries.

All Rights ReservedLibrary of Congress Control Number: 2003113298

© National Petroleum Council 2003Printed in the United States of America

TABLE OF CONTENTSSUMMARY

Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Study Request . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Study Organization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Study Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Retrospectives on the 1999 Study. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Findings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Finding 1: Shift in Supply/Demand Balance . . . . . . . . . . . . . . . . . . . . . . . . . 17

Finding 2: Demand – Energy Efficiency and Conservation. . . . . . . . . . . . . . 20

Finding 3: Demand – Fuel Flexibility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Finding 4: Demand – Growth in Gas Consumption . . . . . . . . . . . . . . . . . . . 24

Finding 5: Supply – Traditional North American Producing Areas . . . . . . . 30

Finding 6: Supply – Access to U.S. Resources. . . . . . . . . . . . . . . . . . . . . . . . . 33

Finding 7: Supply – LNG and Arctic Resources . . . . . . . . . . . . . . . . . . . . . . . 35

Finding 8: Infrastructure – Pipeline and Distribution Investments . . . . . . . 40

Finding 9: Infrastructure – Barriers to Long-Term Contracts. . . . . . . . . . . . 46

Finding 10: Markets – Price Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Finding 11: Public Policy for a Balanced Future . . . . . . . . . . . . . . . . . . . . . . 50

Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Recommendation 1: Improve Demand Flexibility and Efficiency. . . . . . . . . 57

Recommendation 2: Increase Supply Diversity . . . . . . . . . . . . . . . . . . . . . . . 60

Recommendation 3: Sustain and Enhance Natural Gas Infrastructure. . . . . 65

Recommendation 4: Promote Efficiency of Natural Gas Markets. . . . . . . . . 66

Stewardship of Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Future Work and Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Appendices

Appendix A: Request Letter and Description of the NPC . . . . . . . . . . . . . . A-1

Appendix B: Study Group Rosters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

Acronyms and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AC-1

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GL-1

Study Request

By letter dated March 13, 2002, Secretary of EnergySpencer Abraham requested the National PetroleumCouncil (NPC) to undertake a new study on naturalgas in the United States in the 21st Century.Specifically, the Secretary stated:

Such a study should examine the potential impli-cations of new supplies, new technologies, newperceptions of risk, and other evolving marketconditions that may affect the potential for natu-ral gas demand, supplies, and delivery through2025. It should also provide insights on energymarket dynamics, including price volatility andfuture fuel choice, and an outlook on the longer-term sustainability of natural gas supplies. Ofparticular interest is the Council’s advice onactions that can be taken by industry andGovernment to increase the productivity and effi-ciency of North American natural gas marketsand to ensure adequate and reliable supplies ofenergy for consumers.

In making his request, the Secretary made referenceto the 1992 and 1999 NPC natural gas studies, andnoted the considerable changes in natural gas marketssince 1999. These included “new concerns over na-tional security, a changed near-term outlook for theeconomy, and turbulence in energy markets based onperceived risk, price volatility, fuel-switching capabili-ties, and the availability of other fuels.” Further, theSecretary pointed to the projected growth in thenation’s reliance on natural gas and noted that thefuture availability of gas supplies could be affected by“the availability of investment capital and infrastruc-

ture, the pace of technology progress, access to theNation’s resource base, and new sources of suppliesfrom Alaska, Canada, liquefied natural gas imports,and unconventional resources.” (Appendix A containsthe complete text of the Secretary’s request letter and adescription of the NPC.)

Study Organization

In response to the Secretary’s request, the Councilestablished a Committee on Natural Gas to undertakea new study on this topic and to supervise the prepara-tion of a draft report for the Council’s consideration.The Council also established a Coordinating Sub-committee and three Task Groups – on Demand,Supply, and Transmission & Distribution – to assist theCommittee in conducting the study.

Bobby S. Shackouls, Chairman, President and ChiefExecutive Officer, Burlington Resources Inc., chairedthe Committee,1 and Robert G. Card, Under Secretaryof Energy, served as the Committee’s GovernmentCochair. Robert B. Catell, Chairman and ChiefExecutive Officer, KeySpan Corporation; Lee R.Raymond, Chairman and Chief Executive Officer,Exxon Mobil Corporation; and Richard D. Kinder,Chairman and Chief Executive Officer, Kinder MorganEnergy Partners, L.P., served as the Committee’s ViceChairs of Demand, Supply, and Transmission &Distribution, respectively. Jerry J. Langdon, ExecutiveVice President and Chief Administrative Officer,Reliant Resources, Inc., chaired the CoordinatingSubcommittee, and Carl Michael Smith, Assistant

SUMMARY - PREFACE 1

PREFACESUMMARY

1 William A. Wise, Retired President and Chief Executive Officer, El Paso Energy Corp., served as Chair of the Committee until May 16, 2003.

Secretary, Fossil Energy, U.S. Department of Energy,served as Government Cochair.

The members of the various study groups weredrawn from the NPC members’ organizations as wellas from many other industries, non-governmentalorganizations, and government organizations. Thesestudy participants represented broad and diverseinterests including large and small producers, trans-porters, service providers, financers, regulators, localdistribution companies, power generators, and indus-trial consumers of natural gas. Appendix B containsrosters of the study’s Committee, CoordinatingSubcommittee, three Task Groups and their sub-groups. In addition to the participants listed inAppendix B, many more people were involved inregional and sector-specific workshops in the UnitedStates and Canada.

Study Approach

The study benefited from an unprecedented degreeof support, involvement, and commitment from thegas industry. The breadth of support was based ongrowing concerns about the adequacy of natural gassupplies to meet the continuing strong demand forgas, particularly in view of the role of gas as an envi-ronmentally preferred fuel. The study addresses boththe short-term and long-term outlooks (through2025) for North America, defined in this study as con-sisting of Canada, Mexico, and the United States. Thereader should recognize that this is a natural gas study,and not a comprehensive analysis of all energy sourcessuch as oil, coal, nuclear, and renewables. However,this study does address and make assumptions regard-ing these competing energy sources in order to assessthe factors that may influence the future of natural gasuse in North America. The analytical portion of thisstudy was conducted over a 12-month period begin-ning in August 2002 under the auspices of theCoordinating Subcommittee and three primary TaskGroups.

The Demand Task Group developed a comprehen-sive sector-by-sector demand outlook. This analysiswas done by four subgroups (Electric Power,Industrial, Commercial/Residential, and Economics/Demographics). The task of each group was to try tounderstand the economic and environmental deter-minants of gas consumption and to analyze how thevarious sectors might respond to different gas priceregimes. The Demand Task Group was composed of

representatives from a broad cross-section of thepower industry as well as industrial consumers fromgas-intensive industries. It drew on expertise fromthe power industry to develop a broad understandingof the role of alternative sources for generating elec-tric power based on renewables, nuclear, coal-fired,oil-fired or hydroelectric generating technology. Italso conducted an outreach program to draw uponthe expertise of power generators and industrial con-sumers in both the United States and Canada.

The Supply Task Group developed a basin-by-basinsupply picture, and analyzed potential new sources ofsupply such as liquefied natural gas (LNG) and Arcticgas. The Supply Task Group worked through five sub-groups: Resource, Technology, LNG, Arctic, andEnvironmental/Regulatory/Access. Over 100 peopleparticipated. These people were drawn from majorand independent producers, service companies, con-sultants, and government agencies. These workinggroups conducted thirteen workshops across theUnited States and Canada to assess the potentialresources available for exploration and development.Workshops were also held to examine the potentialimpact on gas production from advancing technology.Particular emphasis was placed on the commercialpotential of the technical resource base and theknowledge gained from analysis of North Americanproduction performance history.

The Transmission & Distribution Task Group ana-lyzed existing and potential new infrastructure. Theiranalysis was based on the work of three subgroups(Transmission, Distribution, and Storage). Industryparticipants undertook an extensive review of existingand planned infrastructure capacity in North America.Their review emphasized, among other things, theneed to maintain the current infrastructure and toensure its reliability. Participants in the Transmission& Distribution Task Group included representativesfrom U.S. and Canadian pipeline, storage, marketing,and local distribution companies as well as from theproducing community, the Federal Energy RegulatoryCommission (FERC), and the Energy InformationAdministration (EIA).

Separately, two other groups also provided guid-ance on key issues that crossed the boundaries of theprimary task groups. An ad hoc financial teamlooked at capital requirements and capital formation.Another team examined the issue of increased gasprice volatility.

SUMMARY - PREFACE2

Due to similarities between the Canadian and U.S.economies and, especially, the highly interdependentcharacter of trade in natural gas, the evaluation of nat-ural gas supply and demand in Canada and the UnitedStates was completely integrated. The study includedCanadian participants and many other participatingcompanies that have operations in both the UnitedStates and Canada. For Mexico, the evaluation of nat-ural gas supply and demand for the internal marketwas less detailed, mainly due to time limitations.Instead, the analysis focused on the net gas trade bal-ances and their impact on North American markets.

As in the 1992 and 1999 studies, econometric mod-els of North American energy markets and other ana-lytical tools were used to support the analyses.Significant computer modeling and data support wereobtained from outside contractors; and an internalNPC study modeling team was established to takedirect responsibility for some of the modeling work.The Coordinating Subcommittee and its Task Groupsmade all decisions on model input data and assump-tions, directed or implemented appropriate modifica-tions to model architecture, and reviewed all output.Energy and Environmental Analysis, Inc. (EEA) ofArlington, Virginia, supplied the principal energymarket models used in this study, and supplementalanalyses were conducted with models from AltosManagement of Los Altos, California.

The use of these models was designed to give quan-tified estimates of potential outcomes of natural gasdemand, supply, price and investment over the studytime horizon, with a particular emphasis on illustrat-ing the impacts of policy choices on natural gas mar-kets. The results produced by the models are criticallydependent on many factors, including the structureand architecture of the models, the level of detail ofthe markets portrayed in the models, the mathemati-cal algorithms used, and the input assumptions spec-ified by the NPC Study Task Groups. As such, theresults produced by the models and portrayed in theNPC report should not be viewed as forecasts or asprecise point estimates of any future level of supply,demand or price. Rather, they should be used as indi-cators of trends and ranges of likely outcomes stem-ming from the particular assumptions made. Inparticular, the model results are indicative of the likely directional impacts of pursuing particular pub-lic policy choices relative to North American naturalgas markets.

This study built on the knowledge gained andprocesses developed in previous NPC studies,enhanced those processes, created new analyticalapproaches and tools, and identified opportunities forimprovement in future studies. Specific improve-ments included the following elements developed bythe Supply Task Group:

• A detailed play-based approach to assessment ofthe North American natural gas resource base,using regional workshops to bring together indus-try experts to update existing assessments. Thiswas used in two detailed descriptive models, onebased on 72 producing regions in the UnitedStates and Canada, and the other based on 230supply points in the United States, Canada, andMexico. Both models distinguished between con-ventional and nonconventional gas and betweenproved reserves, reserve growth, and undiscoveredresource.

• Cost of supply curves, including discovery processmodels, were used to determine the economicallyoptimal pace of development of North Americannatural gas resources.

• An extensive analysis of recent production per-formance history, which clearly identified basinsthat are maturing and those where productiongrowth potential remains. This analysis helpedcondition the forward-looking assumptions used inthe models.

• A model to assess the impact of permitting in areascurrently subject to conditions of approval.

• A first-ever detailed NPC view and analysis of LNGand Arctic gas potential.

The Demand Task Group also achieved significantimprovements over previous study methods. Theseimprovements include the following:

• Regional power workshops and sector-specificindustrial workshops to obtain direct input on con-suming trends and the likely impact of changing gasprices.

• Ongoing detailed support from the power industryfor technology and cost factors associated with cur-rent and future electric power generation.

• Development of a model of industrial demandfocusing on the most gas-intensive industries andprocesses.

SUMMARY - PREFACE 3

Retrospectives on 1999 Study

In requesting the current study, the Secretary notedthat natural gas markets had changed substantiallysince the Council’s 1999 study. These changes were thereasons why the 2003 study needed to be a compre-hensive analysis of natural gas supply, demand, andinfrastructure issues. By way of background, the 1999study was designed to test the capability of the supplyand delivery systems to meet the then-public forecastsof an annual U.S. market demand of 30+ trillion cubicfeet (TCF) early in this century. The approach taken in1999 was to review the resource base estimates of the1992 study and make any needed modifications basedon performance since the publication of that study.This assessment of the natural gas industry’s ability toconvert the nation’s resource base into available supplyalso included the first major analytical attempt toquantify the effects of access restrictions in the UnitedStates, and specifically the Rocky Mountain area.Numerous government agencies used this work as astarting point to attempt to inventory various restric-tions to development. This access work has been fur-ther expanded upon in the current study. Furtherdiscussions of the 1999 analyses are contained in theTask Group reports.

The 1999 report stated that growing futuredemands could be met if government would addressseveral critical factors. The report envisioned animpending tension between supply and demand thathas since become reality in spite of lower economicgrowth over the intervening time period. On thedemand side, government policy at all levels continuesto encourage use of natural gas. In particular, this has

led to large increases in natural gas-fired power gener-ation capacity. The 1999 study assumed 144 gigawattsof new capacity through 2015, while the actual newcapacity is expected to exceed 200 gigawatts by 2005.On the supply side, limits on access to resources andother restrictive policies continue to discourage thedevelopment of natural gas supplies. Examples of thisare the 75% reduction in the Minerals ManagementService (MMS) Eastern Gulf Lease Sale 181 and thefederal government’s “buying back” of the DestinDome leases off the coast of Florida.

The maturity of the resource base in the traditionalsupply basins in North America is another significantconsideration. In the four years leading up to the pub-lication of this study, North America has experiencedtwo periods of sustained high natural gas prices.Although the gas-directed rig count did increase sig-nificantly between 1999 and 2001, the result was onlyminor increases in production. Even more sobering isthe fact that the late 1990s was a time when weatherconditions were milder than normal, masking thegrowing tension between supply and demand.

In looking forward, the Council believes that thefindings and recommendations of this study are amplysupported by the analyses conducted by the studygroups. Further, the Council wishes to emphasize thesignificant challenges facing natural gas markets andto stress the need for all market participants (con-sumers, industry, and government) to work coopera-tively to develop the natural gas resources, infra-structure, energy efficiency, and demand flexibilitynecessary to sustain the nation’s economic growth andmeet environmental goals.

SUMMARY - PREFACE4

SUMMARY - EXECUTIVE SUMMARY 5

Natural gas is a critical source of energy and rawmaterial, and will play a vital role in achievingthe nation’s economic and environmental

goals. Current higher gas prices are the result of a fun-damental shift in the supply and demand balance.North America is moving to a period in its history inwhich it will no longer be self-reliant in meeting itsgrowing natural gas needs; production from traditionalU.S. and Canadian basins has plateaued. Governmentpolicy encourages the use of natural gas but does notaddress the corresponding need for additional naturalgas supplies. A status quo approach to these conflictingpolicies will result in undesirable impacts to consumersand the economy, if not addressed. The solution is abalanced portfolio that includes all of the following elements: increased energy efficiency and conservation;alternate energy sources for industrial consumers andpower generators, including renewables; gas resourcesfrom previously inaccessible areas of the United States;liquefied natural gas (LNG) imports; and gas from theArctic. The following is a summary of key findings andof recommendations that will help achieve a balancedfuture for natural gas.

Alternative Scenarios

A status quo approach to natural gas policy yieldsundesirable outcomes because it discourages economicfuel choice, new supplies from traditional basins andthe Arctic, and new LNG terminal capacity. The NPCdeveloped two scenarios of future supply and demandthat move beyond the status quo. Both require signif-icant actions by policy makers and industry stakehold-ers to effect change. These scenarios, “Reactive Path”and “Balanced Future,” are discussed below.

The Reactive Path scenario assumes continued con-flict between natural gas supply and demand policiesthat support natural gas use, but tend to discouragesupply development. This scenario results in contin-ued tightness in supply and demand leading to highernatural gas prices and price volatility over the studyperiod. To achieve even the Reactive Path outcome, thefollowing actions must be taken:

• Continue improvements in energy efficiency andconservation.

• Enact enabling legislation for the Alaskan gaspipeline.

• Overcome local siting opposition to new LNG ter-minals.

• Streamline permitting processes to allow increaseddrilling and development activity in the RockyMountains.

• Implement a Joint Agency Review Process for newinfrastructure.

• Clarify New Source Review requirements for indus-trial and power plant facilities.

The Balanced Future scenario builds in the effects ofsupportive policies for supply development and allowsgreater flexibility in fuel-switching and fuel choice.This results in a more favorable balance between supplyand demand, price projections more in line with alter-nate fuels, and lower prices for consumers. This sce-nario allows for a balanced future by taking all theactions of the Reactive Path as well as:

• Improving demand flexibility and efficiency.

• Increasing supply diversity.

EXECUTIVE SUMMARYSUMMARY

• Sustaining and enhancing infrastructure.

• Promoting efficiency of markets.

There are uncertainties that could significantlyimpact the supply/demand balance for each scenario.These uncertainties include, but are not limited to,

weather, oil price, economic growth, and potentialtreatment of carbon dioxide (CO2) emissions.

This report analyzes supply, demand, and the infrastructure for natural gas in North Americathrough 2025. Recommendations from this analysisare intended to preserve the critical benefits of naturalgas to the North American economy and environment.

SUMMARY - EXECUTIVE SUMMARY6

Demand

Greater energy efficiency and conservation arevital near-term and long-term mechanisms formoderating price levels and reducing volatility.

Power generators and industrial consumers aremore dependent on gas-fired equipment and lessable to respond to higher gas prices by utilizingalternate sources of energy.

Gas consumption will grow, but such growth willbe moderated as the most price-sensitive indus-tries become less competitive, causing someindustries and associated jobs to relocate outsideNorth America.

Infrastructure

Pipeline and distribution investments will average$8 billion per year, with an increasing sharerequired to sustain the reliability of existing infra-structure

Regulatory barriers to long-term contracts fortransportation and storage impair infrastructureinvestment.

Supply

Traditional North American producingareas will provide 75% of long-term U.S. gasneeds, but will be unable to meet projecteddemand.

Increased access to U.S. resources (excludingdesignated wilderness areas and national parks)could save consumers $300 billion in naturalgas costs over the next 20 years.

New, large-scale resources such as LNG andArctic gas are available and could meet 20-25% of demand, but are higher-cost, havelonger lead times, and face major barriers todevelopment.

Markets

Price volatility is a fundamental aspect of a freemarket, reflecting the variable nature ofdemand and supply; physical and risk manage-ment tools allow many market participants tomoderate the effects of volatility.

There has been a fundamental shift in the natural gas supply/demand balance that has resulted inhigher prices and volatility in recent years. This situation is expected to continue, but can bemoderated.

A balanced future that includes increased energy efficiency, immediate development of new resources,and flexibility in fuel choice, could save $1 trillion in U.S. natural gas costs over the next 20 years. Publicpolicy must support these objectives.

National Petroleum Council projections of futuredemand and supply are illustrated in Figures 1 and 2.

These figures illustrate some of the key attributes ofthe NPC outlooks.

Findings


• Natural gas demand for power generation increases, reflecting future utilization of recent, significant additions of natural gas-fired generation.

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*Includes net Mexico exports, lease/plant/pipeline fuel, and net storage.

• Natural gas use in the industrial sector erodes, illustrating projected losses in industrial capacity in the most gas-intensive industries.

Figure 1. U.S. and Canadian Natural Gas Demand

• Production from traditional basins remains strong but has plateaued; Rockies and deepwater Gulf of Mexico offset declines in other areas.

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• Growth is driven by LNG imports and Arctic supply.

Figure 2. U.S. and Canadian Natural Gas Supply


Natural gas supplies approximately 25% of U.S.energy, generating about 19% of electric power,supplying heat to over 60 million households, andproviding over 40% of all primary energy for indus-tries. The NPC assessed future demand in each ofthe key consumer sectors – residential /commercial,power generation, and industrial. These assess-ments focused on the increased capability to con-

sume natural gas in power generation and the effectof higher prices on industrial consumers, commer-cial establishments, and residential consumers.These analyses incorporate the effects of energyefficiency improvements in each of these consumersectors, as summarized in Figure 3. Figure 4 showsthe diverse nature of natural gas demand in NorthAmerica, on both a geographic and sectoral basis.

Figure 3. Energy Efficiency Effect on Gas Consumption

Natural Gas Demand

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Note: Energy efficiency gains in NPC modeling of future gas demand are principally from: decreased electric power demand intensity; increased efficiency in gas-fired power generation, industrial boilers, and industrial process heat; and efficiency gains in commercial and residential gas consumption.


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Figure 4. North American Natural Gas Demand by Sector, 2002


Natural Gas Supply

Abundant natural gas resources exist in NorthAmerica and worldwide. A thorough study was con-ducted to assess the remaining potential of traditionalNorth American natural gas producing basins, as well

as the potential for growth in supply from areas such asthe deepwater Gulf of Mexico, the Rockies, Arcticregions, and imported LNG. Figure 5 shows sources ofnatural gas supply.

TRADITIONAL

GROWTH

MORATORIA

LNG

FIGURE 5 SOURCES OF NATURAL GAS SUPPLY

Figure 5. Sources of Natural Gas Supply

Range of Potential Prices

Supply and demand will balance at a higher range ofprices than historical levels. That price range will beprimarily driven by demand response through effi-ciency and fuel flexibility, the ability to increase con-ventional and nonconventional supply from NorthAmerica including the Arctic, and increasing access to

world resources through LNG. Price ranges for the alter-nate scenarios are illustrated in Figure 6. These are not sta-tus quo scenarios. They both require significant initiativeby policy makers and industry stakeholders to implementthe recommendations of this report in order to achieve abalanced future.


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Note: Natural gas prices shown are average annual prices at Henry Hub, the reference/delivery point for NYMEX futures contracts. Prices on any given day and/or at different locations can vary significantly, due to variations in weather, national and local supply/ demand factors, transportation and distribution costs, etc.

Figure 6. Average Annual Henry Hub Prices


Improve Demand Flexibility and Efficiency

Encourage increased efficiency and conservationthrough market-oriented initiatives and con-sumer education.

Increase industrial and power generation capa-bility to utilize alternate fuels.

Sustain and Enhance Infrastructure

Provide regulatory certainty by maintaining aconsistent cost-recovery and contracting envi-ronment and removing regulatory barriers tolong-term capacity contracting and cost recoveryof collaborative research.

Permit projects within a one-year period utiliz-ing a Joint Agency Review Process.

Increase Supply Diversity

Increase access and reduce permitting impedi-ments to development of lower-48 natural gasresources.

Enact enabling legislation in 2003 for an Alaskagas pipeline.

Process LNG project permit applications withinone year.

Promote Efficiency of Markets

Improve transparency of price reporting.

Expand and enhance natural gas market data col-lection and reporting.

Recommendations

Overall, this comprehensive NPC report provides anumber of recommendations, all of which requireaction and are required to achieve the Balanced Future,

thus creating a more favorable outcome for consumersand the economy.

SUMMARY - INTRODUCTION 13

Natural gas is a critical source of energy and rawmaterial, permeating virtually all sectors of theeconomy. Today natural gas provides nearly

one-quarter of U.S. energy requirements2 and is anenvironmentally superior fuel, thereby contributingsignificantly to reduced levels of air pollutants. It pro-vides about 19% of electric power generation and is aclean fuel for heating and cooking in over 60 millionU.S. households. U.S. industries get over 40% of allprimary energy from natural gas. Figure 7 illustratesthe contribution of natural gas to U.S. energy needs,and Figure 8 shows gas use by sector.

North America’s natural gas exploration and produc-tion industry has been successful in efficiently findingand developing the continent’s indigenous resources, andan extensive infrastructure has been developed to effi-ciently transport natural gas from its diverse sources toits multiple markets. Technology advances throughoutthe supply chain have increased supply, reduced costs,and minimized environmental effects. Effective mecha-nisms for the sale, purchase, and pricing of natural gashave evolved, and there has been a progressive reliance inrecent years on competition and open markets at eachpoint along the natural gas supply value chain.

From the 1930s until the 1980s most of the interstatenatural gas industry was highly regulated. Many ofthese regulations were in conflict. Low, regulatedprices constrained supply growth while demand grewrapidly. During the 1970s these policies resulted in gasshortages. Additional regulations in the late 1970s

attempted to allocate and curtail gas deliveries to somecustomers, such as industrial consumers and electricgenerators. These regulations exacted an enormouscost on U.S. industry and consumers, and ultimatelyon the U.S. economy. Price controls on natural gaswere effectively removed in the late 1980s and compet-itive markets emerged; for example, gas futures tradingon the New York Mercantile Exchange (NYMEX)began in April 1990.

Today, many regulations and policies affecting natu-ral gas are in conflict. Public policies are promoting

INTRODUCTIONSUMMARY

Source: Energy Information Administration.

NUCLEAR 8% RENEWABLES 7%

COAL 23%

NATURAL GAS 24%

PETROLEUM 38%

Figure 7. Average Annual Energy Use, 1997-200197 TCF per Year (Equivalent)

Source: Energy Information Administration

2 Data from Energy Information Administration,Monthly Energy Review, April 2003.

the use of natural gas as an efficient and environmen-tally attractive fuel. These policies have led to restric-tions on fuels other than natural gas for the siting ofpower generation and industrial facilities, restrictionson fuel switching, and fuel choice limitations. Otherlaws and regulations have been enacted that limitaccess to gas-prone areas – areas where gas can beexplored for and produced in an efficient and environ-mentally friendly manner – and there are outright bansto drilling in certain regions. There are laws and regu-lations that unnecessarily hinder pipeline and infra-structure siting or interfere with the functionality ofthe market in ways that lead to inefficiencies. Overall,these conflicting policies have contributed to today’stight supply/demand balance, with higher and volatilegas prices. The beneficial effects of additional gas usecan be achieved more efficiently and at a lower costwith policies that eliminate the current conflicts.

In order to illustrate the findings and recommenda-tions of this study, the NPC developed two contrastingscenarios that represent plausible and feasible futuretrends in North American natural gas markets. All ofthe Task Groups were involved in the development ofthese scenarios, including representatives of producers,pipelines, distributors, final consumers, power compa-nies and government agencies. These scenarios and

their results should not be considered as forecasts butas internally consistent frameworks for analyzingchoices open to the principal stakeholders in NorthAmerican gas over the study time period.

Each of the two scenarios has different assumptionsregarding some of the key variables related to supplyand demand responses to public policy choices. Thesekey variables include degrees of access to gas resources,greater energy efficiency and conservation, andincreased flexibility to use fuels other than gas forindustry and power generation. The two scenariosresult in contrasting demand, supply, infrastructure,and price profiles. The names of the two scenarios are“Reactive Path” and “Balanced Future.” The full detailsof the assumptions used in the Reactive Path andBalanced Future can be found in the Integrated Reportof this study.

Reactive Path assumes current laws remain in effect,and governmental policies at federal, state/provincial,and local levels continue to broadly encourage gas usagewhile discouraging access to lower-48 gas resources.However, in addition to these broad policies, theassumptions built into this case acknowledge that result-ant high natural gas prices will likely be reflected in significant societal pressure to allow reasonable, eco-

SUMMARY - INTRODUCTION14

0 10 20 30 40

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RESIDENTIAL

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Figure 8. U.S. Primary Energy Use by Sector, Year 2002

nomically driven choices to occur on both the consum-ing and producing segments of the natural gas industry.Thus, the Reactive Path is not a status quo outlook. Inessence, market participants, including public policymakers, “react” to the current situation while inherentconflicts continue. The supply response assumes a con-siderable amount of success and deviation from pasttrends, evidenced by a major expansion of LNG facili-ties, construction of arctic pipelines, and a significantresponse in lower-48 production from accessible areas.Overall demand levels from both NPC scenarios arelower than other outlooks, resulting in less upward pres-sure on the supply/demand balance. Even with uncer-tainty surrounding air quality regulations, the modelingeffort projects construction of new, state of the art,emission-controlled coal plants at levels that approachthe prior coal boom years in the 1970s. Together, thisscenario implies a degree of success in supply anddemand responses significantly beyond what has beendemonstrated over recent years.

The results of the Reactive Path show that, eventhough consumers and producers act rationally withinthis policy framework, impediments to growing natu-ral gas supply, and lack of flexibility of fuel consump-tion, inevitably lead to higher prices, which, in turn,bring negative impacts on gas intensive industries andthe economy as a whole. Price volatility remains a con-sistent feature of gas markets in this scenario. PerhapsFederal Reserve Board Chairman Alan Greenspan pro-vided the best characterization of the conflict betweenpolicy choices in his testimony to the United StatesSenate Committee on Energy and Natural Resources:

We have been struggling to reach an agreeabletradeoff between environmental and energy con-cerns for decades. I do not doubt we will continue tofine-tune our areas of consensus. But it is essentialthat our policies be consistent. For example, we can-not, on the one hand, encourage the use of environ-mentally desirable natural gas in this country whilebeing conflicted on larger imports of LNG. Suchcontradictions are resolved only by debilitatingspikes in price.

Alternatively, Balanced Future is a scenario in whichgovernment policies are focused on eliminating barri-ers to market efficiencies. This scenario enables natu-ral gas markets to develop in a manner in whichimproved economic and environmental choices can bemade by both producers and consumers. On thedemand side, opportunities for conservation, energyefficiency, and fuel flexibility are both authorized and

encouraged. On the supply side, barriers to develop-ment of new natural gas sources are progressively low-ered, both for domestic and imported natural gas. Theresult, with enhanced supply and more flexibledemand, would be a market with lower gas prices andless potential for upward price spikes. This case is abetter outcome for North American consumers thanthe continuing market tightness associated with theReactive Path.

It would be possible to construct many different sce-narios or visions of the future to illustrate the NPCanalysis. For example, neither the Reactive Path northe Balanced Future scenario considers the effect of notdeveloping major new LNG import facilities or theArctic gas pipelines; neither scenario considers actionsthat might severely limit CO2 emissions or the permit-ted carbon content of fuels; neither scenario attemptsto speculate on ground-breaking new technology thatcould fundamentally alter demand patterns or supplypotential. The NPC did not consider such possibilitiesas being likely outcomes to be modeled in the basescenarios. However, each base scenario was testedagainst variabilities in many of the major underlyingassumptions, such as weather patterns, economicgrowth, the price of competing fuels, the size of thedomestic gas resource base, timing of infrastructureimplementation, and the role of other electric genera-tion technologies such as nuclear and hydroelectricplants. These sensitivity analyses provide additionaldirectional insight to the conclusions reached from thebase scenarios and reinforce the study findings andrecommendations.

In either scenario, it is clear that North Americannatural gas supplies from traditional basins will beinsufficient to meet projected demand; choices must bemade immediately to determine how the nation’s nat-ural gas needs will be met in the future. The best solu-tion to these issues requires actions on multiple paths.Flexibility in fuel use must be encouraged, diverse sup-ply sources must be developed, and infrastructuremust be made to be as reliable as possible. Policychoices must consider domestic and foreign sources ofsupply, large and small increments of production, andthe use of other fuels as well as gas for power genera-tion. All choices face obstacles, but all must be sup-ported if robust competition among energyalternatives and the lowest cost for consumers and thenation are to be achieved. The benefits of the BalancedFuture scenario to the economy and environment

SUMMARY - INTRODUCTION 15

unfold over time; but it is important that these policychanges be implemented now; otherwise their benefitswill be pushed that much farther into the future, andthe uneasy supply/demand balance we are experienc-ing will continue.

The findings of the National Petroleum Councildescribed in this volume of the report represent theconclusions of the Council from the detailed analysisundertaken over the past year. They provide the clearmotivation for the recommendations that follow.Collectively and individually, policy makers will makedecisions affecting the future of natural gas in theeconomy. These choices will have significant effects onresource availability, on natural gas production, on thecost-effective use of natural gas, on the capacity ofinfrastructure to serve markets, and on prices and pricevolatility. Prompt implementation of the NPC’s rec-ommendations will reduce the conflicts in currentpublic policy and benefit both consumers and the envi-ronment.

The National Petroleum Council has identified thefollowing key findings based on its analysis of the nat-ural gas market:

• There has been a fundamental shift in the naturalgas supply/demand balance that has resulted inhigher prices and volatility in recent years. Thissituation is expected to continue, but can be mod-erated.

• Greater energy efficiency and conservation are vitalnear-term and long-term mechanisms for moderat-ing price levels and reducing volatility.

• Power generators and industrial consumers aremore dependent on gas-fired equipment and less

able to respond to higher gas prices by utilizingalternate sources of energy.

• Gas consumption will grow, but such growth will bemoderated as the most price-sensitive industriesbecome less competitive, causing some industriesand associated jobs to relocate outside NorthAmerica.

• Traditional North American producing areas willprovide 75% of long-term U.S. gas needs, but will beunable to meet projected demand.

• Increased access to U.S. resources (excluding desig-nated wilderness areas and national parks) couldsave $300 billion in natural gas costs over the next 20years.

• New, large-scale resources such as LNG and Arcticgas are available and could meet 20-25% of demand,but are higher-cost, have longer lead times, and facemajor barriers to development.

• Pipeline and distribution investments will average$8 billion per year, with an increasing sharerequired to sustain the reliability of existing infra-structure.

• Regulatory barriers to long-term contracts for trans-portation and storage impair infrastructure invest-ment.

• Price volatility is a fundamental aspect of a freemarket, reflecting the variable nature of demandand supply; physical and risk management toolsallow many consumers to moderate the effects ofvolatility.

• A balanced future that includes increased energyefficiency, immediate development of newresources, and flexibility in fuel choice could save $1 trillion in U.S. natural gas costs over the next 20years. Public policy must support these objectives.

SUMMARY - INTRODUCTION16

SUMMARY - FINDINGS 17

During the 1990s, environmental standards and eco-nomic growth were the forces driving the demand fornatural gas in North America. Historically, NorthAmerican drilling activity has responded quickly tomarket signals and, has yielded sufficient production tomeet demand. Figure 9 shows U.S. and Canadian pro-duction. It now appears, however, that natural gas pro-ductive capacity from accessible basins in the UnitedStates and Western Canada has reached a plateau.

FINDINGSSUMMARY

Finding 1: There has been a fundamentalshift in the natural gas supply/demandbalance that has resulted in higher pricesand volatility in recent years. This situa-tion is expected to continue, but can bemoderated.

U.S. LOWER-48

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Figure 9. U.S. Lower-48 and Canadian Natural Gas Production

Source: Energy and Environmental Analysis, Inc., GSR.

Recent experience shows steeper decline rates in exist-ing production and a lower average productionresponse to higher prices from new wells in these areas.This trend is expected to continue. As a result, marketsfor natural gas have tightened to a degree not seen inrecent experience and prices have increased well abovehistorical levels. These higher prices have been accom-panied by significant price volatility, as illustrated inFigure 10.

Natural gas demand grew by more than 40%between 1986 and 1997, from 16 TCF/year to 23 TCF/year, as illustrated in Figure 11. While overall demandhas persisted between 22 TCF/year and 23 TCF/yearsince 1997, the market has fundamentally changed.Natural gas used for power generation has grown since1997, while industrial use has declined. Today, it isproductive capacity, including established importcapacity, that drives the tight supply/demand balance;the resulting higher prices are limiting the ability ofnatural gas demand to grow.

This is in contrast to the “gas bubble” environmentof the late 1980s and 1990s that was characterized by asurplus of supply and weak demand. This “bubble”kept prices low and dampened price volatility. This

market was influenced by a succession of since-modified legislative and regulatory decisions begin-ning with the Powerplant and Industrial Fuel Use Actof 1978 (PIFUA) and the Natural Gas Policy Act of1978 (NGPA). While the PIFUA placed restrictions onindustrial and power generation uses of natural gas,the NGPA set in motion a process that encouraged gassupply growth. Amendments in 1987 to the PIFUAremoved restrictions on the use of gas in power gener-ation, and the Natural Gas Wellhead Decontrol Act of1990 removed wellhead price controls.

Thus, a responsive market developed in the early1990s for the supply and trade of natural gas. Thismarket grew out of deregulation of supply anddemand, and was reinforced by a series of FERCOrders creating an unbundled and more flexible trans-portation system. The excess productive capacity ofNorth America, combined with storage capability formeeting seasonal demand surges meant that there wassufficient supply to meet daily, seasonal, and annual gasrequirements, including those driven by weatherand/or economic growth.

The capability to consume natural gas continues toincrease. The number of residential natural gas

SUMMARY - FINDINGS18

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Figure 11. U.S. and Canadian Natural Gas Demand

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Figure 12. Lower-48 Dry Gas Production vs. Dry Gas Productive Capacity

customers grew from 48 million in 1987 to 60 millionin 2001.1 Of the 200,000 megawatts of new power-plant capacity recently constructed or about to beplaced in operation over the next few years, well over90% are fueled with natural gas.2 Industrial consump-tion, including cogeneration applications, grew byalmost 48% from 1986 to 2001.

The combination of growing demand and limitedsupply has resulted in a disappearance of the “gas bub-ble,” as shown in Figure 12. It has created an overalltightening of the market and led in recent years tohigher gas prices and price volatility. The market is lessable to absorb changes in supply or demand without asignificant swing in price. This dynamic will continueuntil additional supplies are brought to market andmore demand flexibility is achieved.

Improved efficiency of energy use has been a majorfeature of the U.S. economy since the 1970s. For thepast 30 years, the amount of gas used in the productionof a dollar’s worth of economic output has continuedto decrease. Since 1974, the industrial sector alone hasreduced its energy use for fuel and power consumptionper unit of output by nearly 40%. Residential con-sumers reduced natural gas use per customer by 16%from 1980 to 2001, primarily as a result of more-efficient space heating and improved housing charac-teristics.3 The power generation industry has alsoachieved significant efficiency gains through the intro-duction of highly efficient combustion turbines, com-bined heat and power configurations, and combinedcycle applications. Between 1997 and 2001, the neteffect of these innovations has been a 15% increase inefficiency of gas consumed to produce power.


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Per Dollar of Industrial Output)

Figure 14. Gas-Fired Generation Heat Rate

1 U.S. Energy Information Administration.2 Daniel Yergin Speech before the Natural Gas Summit in

Washington, DC, June 26, 2003.3 American Gas Association, Energy Analysis EA 2003-01,

June 16, 2003.

Finding 2: Greater energy efficiency andconservation are vital near-term and long-term mechanisms for moderating pricelevels and reducing volatility.


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Note: Energy efficiency gains in NPC modeling of future gas demand are principally from: decreased electric power demand intensity; increased efficiency in gas-fired power generation, industrial boilers, and industrial process heat; and efficiency gains in commercial and residential gas consumption.

2005 2015

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EFFICIENCY GAINS

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Figure 16. Energy Efficiency Effect on Gas Consumption

Continued energy conservation and more efficientuse of existing equipment can ease short-term mar-ket pressures. Natural gas conservation and effi-ciency measures in residences and commercialestablishments – which collectively represent over40% of total U.S. demand – can contribute substan-tially to higher efficiencies. For example, electricityconservation can reduce the demand on regionalpower systems, minimizing the operation of “peak-ing” capacity that is often supplied by gas-fired facil-ities. Electric power generators can also reducenatural gas demand by ensuring higher utilization ofcombined-cycle units instead of less-efficient gas-fired boilers.

The economy has generally become more efficient inits use of natural gas and other energy sources, evenduring periods of low prices, due to technologicalinnovation, the ongoing shift to less energy-intensiveindustries, and government policies. Figures 13, 14,and 15 illustrate efficiency gains in natural gas utiliza-tion for the industrial, electric power, and residentialand commercial sectors, respectively. These historicalgains will generally be sustained due to historical andfuture changes in capital stock, and as new construc-tion incorporates more-efficient building codes andstandards. These continuing improvements in the effi-ciency of electricity and natural gas consumption areassumed in both the Reactive Path and BalancedFuture scenarios, and are illustrated for the BalancedFuture scenario in Figure 16. The increased residentialand commercial energy efficiencies in the BalancedFuture scenario are assumed to be the result of marketmechanisms that provide clear natural gas and powerprice signals to consumers, by consumer education,and by appropriate changes to building standards.

For the past 15 years, industrial consumers andpower generators have become increasingly depend-ent on natural gas-based technologies for meetingtheir energy requirements and for satisfying more-

stringent air quality standards. These consumershave chosen gas-fired equipment based on the follow-ing factors:

• Life-cycle economics. Gas-fired applications gener-ally have lower capital costs. Gas-fired combustionturbines used in power generation and industrialcogeneration require shorter construction leadtimes and are available in convenient modulardesigns. This saving in capital costs was especiallyattractive in the late 1980s and 1990s when gas priceswere consistently below the equivalent liquid fuelprices.

• Environmental performance. Improved air emis-sions performance of natural gas-based technologieshas favored investments in facilities that use naturalgas. In many instances, power generators and indus-trial consumers made investment decisions favoringnatural gas in order to achieve compliance with“New Source Performance Standards” and/or as acondition of a “New Source Review” proceeding.

• Land use. Gas applications generally require lessland and are less intrusive than other fossil fuelapplications. Modular gas-fired generation facilitieshave been used to meet increased electric powerdemand frequently as an alternative to extendingpower transmission lines to certain areas.

As shown in Figure 17, natural gas demand forpower generation (including industrial-based genera-tion) grew by more than 50% in the 15 years ending in2002. Despite recent declines in demand from theindustrial sector – particularly portions of the chemi-cal industry and metals manufacturers – overall indus-trial gas demand is greater today than 15 years ago.

At the same time, the stock of gas-fired power gen-eration and industrial equipment became less flexiblein its ability to operate with alternate fuels. This loss offlexibility has been driven in part by an array of gov-ernmental policies such as local siting restrictions onfuel backup and New Source Review proceedings.World economic and competitive forces provided theincentive for energy consumers to seek industrialprocess efficiencies and control costs. For example,existing burners are “tuned” to maximize operationaland environmental efficiency when operating solelywith natural gas. Power generators and industrial gasusers have retired or mothballed boilers and otherequipment capable of using dual fuels, such as oil and


Finding 3: Power generators and indus-trial consumers are more dependent ongas-fired equipment and less able torespond to higher gas prices by utilizingalternate sources of energy.


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gas. In addition, not using oil or coal in current orretiring processes yielded the emission credits thatwere needed for plant expansions or new process con-struction. Some plant sites, once capable of using dualfuels now lack the permits to burn fuels other than nat-ural gas and/or lack both the infrastructure and thephysical storage capacity for using alternative fuels.

Figure 18 approximates the current short-term flex-ibility of U.S. power generation and industrial capacityfor responding to changes in natural gas prices, as con-sidered in NPC modeling. This indicates that about 6 billion cubic feet per day (BCF/D) of fuel-switchingor demand suppression would be expected to occur atprices up to $6.50/MMBtu, and up to 10 BCF/D atprices of $8.00/MMBtu.

Through at least 2008, natural gas-based technolo-gies will represent about one-third of U.S. generationcapacity. Subject to significant variation due to theweather, natural gas should supply between 15% and20% of the electricity generated during this time. Incontrast, oil/gas boiler generation capacity is about12% of total U.S. capacity, and will provide about 2%of the electricity generated. Figure 19 shows the rela-tive shares of oil and gas used in power generation.

Boiler fuel for steam generation represents 25%-30% of industrial gas consumption. An industry-widesurvey by the Energy Information Administration forthe period 1994-1998, suggested that up to 26% ofindustrial boilers at the end of that period were fuel-switchable. However, one finding of the workshopsconducted by the Demand Task Group and the manygas-intensive industrial users was that the practicallevel of boiler fuel-switching capability is much lowertoday; only approximately 10% of the total – orapproximately 200 BCF/year; some industrial con-sumers reported it to be as low as 5%.

Long-term natural gas demand is expected toincrease due to economic growth and increased envi-ronmental regulations, fundamental changes in energy


Finding 4: Gas consumption will grow,but such growth will be moderated as themost price-sensitive industries becomeless competitive, causing some industriesand associated jobs to relocate outsideNorth America.

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usage patterns and in investments in gas-intensiveequipment. Influenced heavily by short-term weathercycles, these increases will be driven by changingdemographic patterns, and by actions taken by powergenerators and industrial consumers to comply withincreasing air quality standards. This growth will beslowed by higher prices that will principally affectenergy-intensive consumers in the industrial sector –chemicals, refining, and metals – that, unlike powergenerators, generally compete in world markets.

Future U.S. and Canadian natural gas demand isreflected in Figure 20 for the Reactive Path case. Thisfigure shows an overall increase of about 23% by 2025from 2002. The Reactive Path and the Balanced Futurecases both assume average annual U.S. GDP growthfrom 2005-2025 of 3%, and annual Canadian GDPgrowth of 2.6%, based on historical averages. The casesalso assume weather conditions at the average of thepast 30 years. Each case assumes future air regulationswill conform to current law; but the cases differ in theirexpectations for coal plant shutdowns due to mercuryemission rules. The Balanced Future assumes deliber-ate introduction of fuel flexibility in power generationand industrial applications, as well as increased energyefficiency in the commercial and residential sector.

Demand in the Balanced Future is not greatly differentto that of the Reactive Path, because the offsettingeffects of greater energy efficiency and greater use ofalternate fuels assumed in the Balanced Future wouldtend to reduce demand, but would be offset by theeffects of lower prices, which tend to increase demand.

Power Generation

U.S. electricity demand grew 31% from 1990 to2002, and the increase in U.S. gas supply directed topower generation increased from 22% to 30%. Therapid buildup of gas-based generation capacity startingin the 1990s reflects investment efficiencies, environ-mental performance, operational flexibility, siting ease,and production costs for these facilities. The outlookfor natural gas in power generation is defined by thefollowing factors.

• Electricity demand. Electricity demand hassteadily grown in relation to GDP growth, and theNPC expects this growth to continue. U.S. electric-ity demand has grown an average of 2.5%/yearsince 1973. In the Reactive Path scenario, electrici-ty demand is assumed to grow an average of1.9%/year through 2025, while in the BalancedFuture scenario growth of 1.7%/year is assumed.


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Figure 20. Historical Gas Demand and Reactive Path Projection

Although each scenario assumes similar GDPgrowth as in the past three decades, power demandgrowth is forecast to be lower than in the past,reflecting greater energy efficiency.

• Power generation capacity. The scenarios assume:(a) in the Reactive Path scenario, retirement ormothballing of 18 gigawatts (GW) of oil- and gas-fired steam boiler units through 2010, and retire-ment of 21 GW of smaller coal-fired units in2007-2009 due to the Maximum Achievable ControlTechnology (MACT) standards for mercury;(b) lower levels of oil/gas and coal retirements in theBalanced Future scenario; (c) continued exclusion ofnew coal-based technology from the U.S. west coastand from ozone non-attainment areas of the U.S.east coast in each scenario; (d) continued develop-ment of renewable technology, reflecting a combina-tion of tax incentives and efficiency increases overtime, with 73 GW constructed through 2025 in theReactive Path scenario, and 155 GW in the BalancedFuture scenario; (e) competitive coal-based technol-ogy – using all required environmental controls –with over 80 GW of capacity likely to be constructedin the Reactive Path scenario and over 100 GW inthe Balanced Future scenario, primarily after 2015;

(f) in each scenario continued operation of existingnuclear capacity through at least 2025, but no newnuclear capacity due to overall costs and perceivedinvestment risks associated with waste disposal; and(g) in each scenario some increase in hydroelectricgeneration in Canada, none in the United States.

Figure 21 shows future U.S. generation capacity, byfuel type, as projected in the Reactive Path scenario.Figure 22 illustrates the quantities of electricity generat-ed by fuel type. Because short-term weather cycles willhave a significant effect on electric power demand, theNPC also conducted sensitivity analyses, which indicat-ed that these cycles could markedly change natural gasrequirements for power generation in any given year.

Industrial Use

U.S. industries derive 40% of their primary energyfrom natural gas. Natural gas and/or the ethane pro-duced in association with natural gas are the key rawmaterials in the manufacture of ammonia, methanol,ethylene, and the hydrogen that is produced outside ofpetroleum refining processes. Natural gas usage wasanalyzed for key categories of industrial consumers –chemicals, refining, primary metals, paper, stone/clay/glass, food/beverage, and other industries.


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Figure 22. Electricity Generated by Fuel Type

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OTHER INDUSTRIES

2030

Figure 23. Industrial Gas Consumption by Industry in Reactive Path Scenario

The potential demand for natural gas by industrialconsumers in the Reactive Path scenario is illustratedin Figure 23; Figure 24 shows gas use by principalindustrial application. In this case, industrial demandwould be most affected in the near-term, as highernatural gas prices increase the pressure on gas-intensive industrial consumers to discontinue someoperations and limit investments in North Americanchemical process capacity. Manufacturers of ammo-nia, methanol, petrochemicals, and metals would bemost affected.

In the Reactive Path scenario, the most gas-intensiveindustries are likely to experience little-to-no growth,and would be at risk of permanent relocation toregions of the world that have less-expensive gas supplies. The NPC attempted to understand the impli-cations for gas demand of potential economic disloca-tions by doing sensitivity analyses of differentindustrial production rates in the chemicals and pri-mary metals industries. These analyses indicated thatreduced production in these industries would result inreduced natural gas demand. Conversely, an increasein production in these industries, perhaps caused byhigh economic growth in the U.S. relative to other

areas of the world, would result in increased naturalgas demand.

In the Balanced Future scenario, industrial demandwould still be reduced in the near-term, as higher nat-ural gas prices continue to induce gas-intensive indus-trial consumers to discontinue some operations andlimit investments in North American industrialprocess capacity. However, if investments in fuel-flexibility and enhanced supplies were facilitated bygovernment policies, industrial consumers in NorthAmerica would be more competitive on a world scale.There would be less demand erosion, and the financialincentive would exist for construction of additionalindustrial capacity in North America.

Commercial and Residential Use

Over 60 million U.S. households use natural gas, andover 40% of commercial energy requirements are metby natural gas. Commercial and residential demandgrowth will reflect demographic shifts, penetration ofgas-based technologies, growth in floor space, and lev-els of energy efficiency. To forecast future natural gasdemand in the commercial and residential sectors, the


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BOILERS

Figure 24. Lower-48 Industrial Gas Demand Breakdown(New Cogeneration After 1998 Not Included)

NPC used both an econometric model and a model ofcapital stock employed. These models consideredmany variables, including the weather, demographictrends, population growth, responsiveness of these sec-tors to gas price increases, residential housing stock,the efficiency of the capital stock, commercial floorspace, and penetration of gas-based technology.

Commercial and residential natural gas demand isexpected to increase in both the Reactive Path andBalanced Future scenarios, due to penetration of gas-based technology, population growth, and growth infloor space, only partially offset by continuing gains inenergy efficiency. Energy efficiency is one of the keydifferences between the two scenarios, with theBalanced Future having greater efficiency gains in resi-dential appliances, commercial equipment, and build-ing standards.

Mexico

Rapidly growing Mexican gas demand and laggingdomestic production development will result in Mexicocontinuing to rely on U.S. gas imports through at least2005 and likely thorough 2025. Significant unknownsrelated to both demand and supply give rise to widely

varying potentials for imports and exports. This bal-ance ultimately rests on Mexico’s success in attractingforeign participation in its exploration and productionindustries and its ability to attract LNG imports. TheMexican government projects higher growth rates forsupply and demand than assumed by the NPC.Therefore Mexico’s impact on the North American gasbalance remains uncertain. Both the Reactive Path andBalanced Future outlooks assume that Mexico willimport up to 1.6 BCF/D from the United States in thenear term and a net of 700 MMCF/D in the longerterm, as illustrated in Figure 25.

Key Uncertainties in Natural Gas Demand

Natural gas demand varies seasonally, and grows ordecreases from year-to-year based on a wide number offactors that were considered in the modeling of boththe Reactive Path and the Balanced Future scenarios.The respective effects of key uncertainties were evaluat-ed with sensitivity analyses, and are discussed in theIntegrated Report. Those factors with the largestimpact on the demand for natural gas are weathercycles, North American and worldwide economic activ-ity, crude oil prices, and changing regulations includingthe potential for limits on carbon dioxide emissions.


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NET IMPORTS

NET IMPORTS TO MEXICO

NET EXPORTS TO U.S.

YEAR

HISTORICAL PROJECTED

Figure 25. Mexico Import/Export Balance Assumptions

The NPC undertook a comprehensive review of theNorth American resource base. As described in earlierstudies, there is a large North American gas resourcebase that will play a key role in providing future natu-ral gas supply. A key aspect of this review, and astepout from previous NPC studies, was a detailedanalysis of production performance over the past tenyears. Evaluating historical performance is one way togain an understanding of current production and tobuild a sound basis for establishing future projections.This review used historical well production data fromthe lower-48 states and western Canada to analyze ini-tial production rates, production decline rates, andtotal well recoveries for each major producing basin.

The key finding from this analysis was that, on aver-age, initial production rates from new wells have beensustained through the use of advancing technologies;

however, production declines from these initial rateshave increased significantly, and recoverable volumesfrom new wells drilled in mature producing basinshave declined over time, as shown in Figure 26.

Declining well recoveries and higher initial declinerates for new wells are characteristics of many produc-ing basins. This is the underlying reason that theannual rate of decline for North American productioncontinues to increase, and why it is often said that pro-ducers are “running harder to stay even.” Figure 26 alsoshows how drilling activity has increased, a trend thathas tended to offset the effect of the declining wellrecoveries.

Without the benefit of new drilling, indigenous sup-plies have reached a point at which U.S. productiondeclines by 25-30% each year, as shown in Figure 27. Inother words, new wells must make up that volume eachyear before any growth from prior year levels can beachieved. Figure 28 shows how the lower-48 base pro-duction from existing wells is expected to decline andthe level of new production that must be achieved fromfuture drilling in the Reactive Path case. Eighty percentof gas production in ten years will be from wells yet tobe drilled. The future gas wells that are required for this


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(EXCLUDING DEEPWATER GULF OF MEXICO, NONCONVENTIONAL GAS)

1992 1996 1998

Source: Energy and Environmental Analysis, Inc., GSR.

Figure 26. Recovery per Gas Connection

Finding 5: Traditional North Americanproducing areas will provide 75% of long-term U.S. gas needs, but will be unable tomeet projected demand.

Source: Base data from Energy and Environmental Analysis, Inc., GSR.


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Figure 27. Lower-48 Decline Rate from Existing Wells

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Figure 28. Lower-48 Production, Existing and Future Wells

production outlook are shown in Figure 29.Independent producers, who account for about 70% ofU.S. production, will drill most of these wells.

The gas drilling activity projected is an increasefrom the levels of the 1990s, but is consistent with thelevels at which the industry has operated in recentyears. In this outlook, the number of nonconven-tional wells drilled is increasing, offsetting the pro-jected decline in conventional wells. Given theshorter drilling time for nonconventional wells, thisresults in a relatively flat outlook for gas drilling rigsduring the study period.

This production outlook not only requires a con-tinued high level of drilling activity, but also assumescontinued improvement in technologies that increaserecovery, reduce costs, and improve drilling successrates. The resources to be found and developed overthe next 25 years will be more technologically chal-lenging. These resources will come from reservoirsthat are smaller, deeper, and/or lower in permeabil-ity. Technology will play a key role in commercializ-ing these resources. Of the projected production in2025, 14% is attributable to expected advances intechnology. This contribution is discussed in detail

in the Technology section of the Supply Task GroupReport.

To understand the effects of increased drilling activ-ity, the NPC analyzed the supply response from thelower-48 states associated with the doubling of rigactivity in 2000/2001. There were limited opportuni-ties in more prolific areas. Most of the additionaldrilling occurred in basins where low initial rates andlow well recoveries were to be expected. Thus, the sup-ply response was less than 5% of lower-48 productioneven with a doubling of rig activity. In addition, pro-duction levels quickly fell when rig activities declined.Figure 30 shows the limited supply increase in responseto that doubling of drilling activity.

Based on analysis of the lower-48 and Canadianresource base and on production performance data,the NPC has concluded that conventional gas produc-tion will inevitably decline, and that the overall level ofindigenous production will be largely dependent onindustry’s ability to increase its production of noncon-ventional gas. Nonconventional gas includes gas fromtight formations, shales, and coal seams. Given the rel-atively low production rates from nonconventionalwells, the analysis further suggests that even in a robust


CONVENTIONAL

NONCONVENTIONAL

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Note: Historical ratios are estimated.

GA

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Figure 29. New Onshore Gas Wells Drilled in Lower-48 States

Note: Historical ratios are estimated.

future price environment, industry will be challengedto maintain overall production at its current level. Thisconclusion is reached even though new discoveries inmature North American basins represent the largestcontribution to future supplies of any component ofthis supply outlook. Figures 31 and 32 show projec-tions of the Reactive Path case for production byresource type and from each of the key producingregions.

Although most of the regions are expected to con-tinue to decline with time, some key areas are likely togrow enough to partially offset this decline. Notably,growth in production should occur from the deepwaters of the Gulf of Mexico slope, which effectivelyoffsets decline in the more mature, shallower waters ofthe Gulf of Mexico shelf. In addition, significantgrowth is expected in production of nonconventionalgas, principally in the Rocky Mountains, which effec-tively offsets declines in other areas.

The NPC estimates that production from the lower-48 states and non-Arctic Canada can meet 75% of U.S.demand through 2025. However, these indigenoussupplies will be unable to meet the projected naturalgas demand.

Access to indigenous resources is essential for reach-ing North America’s full supply potential. New discov-eries in mature North American basins represent thelargest component of the future supply outlook,including potential contributions from imports andAlaska. However, the trend towards increasing leasingand regulatory land restrictions in the RockyMountain region and the Outer Continental Shelf(OCS) is occurring in precisely the areas that hold sig-nificant potential for natural gas production.

In the Rocky Mountain areas, previous studies haveevaluated the effects of federal leasing stipulations. Thisstudy expanded those evaluations to include post-leas-ing conditions of approval on both public and privatelands to more fully quantify the effect of regulatoryprocesses on resource development. The NPC created a


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1990 1995 2000YEAR

Sources: Energy and Environmental Analysis, Inc., GSR; and Baker Hughes.

Figure 30. Monthly Lower-48 Dry Gas Production

Finding 6: Increased access to U.S.resources (excluding designated wilder-ness areas and national parks) could save$300 billion in natural gas costs over thenext 20 years.


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Figure 32. U.S. Lower-48 and Non-Arctic Canadian Gas Production by Region

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Figure 31. U.S. Lower-48 and Non-Arctic Canadian Gas Production by Type

comprehensive model incorporating key wildlife habi-tat and simulated the effects of regulatory processes ondevelopment activities. The results of this analysis aresummarized for four key basins in Figure 33.

Overall, restrictions from conditions of approvalwere found to be more of an impediment to develop-ment than leasing stipulations. For example, in theGreen River basin, 9% of the area was unavailable forleasing. A further 31% of the area was available for leas-ing, but was “effectively” off-limits to development dueto prohibitive conditions of approval, bringing the total

area not available to development to 40%. In addition,conditions of approval added cost and time delays.

In total, the study found that 69 TCF, or 29%, of theRocky Mountain area technical resource base is currently “effectively” off-limits to exploration anddevelopment, and that access-related regulatoryrequirements impacted an additional 56 TCF of poten-tial resource with added costs and delays to develop-ment. The details of the methodology used to developthis assessment are included in the Access section ofthe Supply Task Group Report.


CATEGORY GREEN RIVER UINTA-PICEANCE POWDER RIVER SAN JUAN

No Leasing 9% 4% 5% 2%(% Resource)

Prohibitive Conditions 31% 17% 26% 6%of Approval (%)

Added Costs per Well $55 - 100 $55 - 110 $20 - 60 $35 - 55(Thousands)

Time Delay per Well 12 - 22 8 - 13 7 - 14 6 - 8(Months)

Figure 33. Effect of “Conditions of Approval” on Rocky Mountain Resource Development

Note: Volumes are undiscovered, technically recoverable.

33TCF

25TCF

21TCF

125 TCF

69 OFF-LIMITS

Figure 34. Lower-48 Technical Resource Impacted by Access Restrictions

Note: Volumes are undiscovered,technically recoverable.

Leasing moratoria in the Eastern Gulf of Mexico,Atlantic Coast, and the Pacific Coast currently pro-hibit access to these areas of the OCS. The NPC hasestimated that 80 TCF of technically recoverableresources potentially underlie these moratoria areas.It should be noted that limited data have beenacquired in these areas due to the moratoria so therange of uncertainty with regard to the size of thisresource is large. Figure 34 shows the major regions ofthe lower-48 states with such access constraints andthe volume of technical resource restricted fromexploration and development.

The NPC evaluated the effect of removing the OCSmoratoria and of reducing the impact of conditions ofapproval on the Rocky Mountain areas by 10% per yearfor five years. These changes could potentially add 3 BCF/D to production by 2020. In addition, this in-creased production was found to reduce average priceprojections by $0.60/MMBtu (nominal dollars), whichtranslates into a reduction in the cost of natural gas toconsumers of about $300 billion over a 20-year period.This outlook is reflected in the Balanced Future case,and can play an important role, along with other newsupply sources, in meeting the projected natural gasdemand.

With the outlook for production from the U.S.lower-48 and non-Arctic Canada flat to declining,new sources of supply will be required to meet theprojected growth in natural gas demand. Both theReactive Path and Balanced Future cases project liq-uefied natural gas and Arctic gas to become majorsupply sources, providing 20-25% of U.S. demand by2025. These new sources also diversify the natural gassupply beyond traditional indigenous sources, andprovide access to the rapidly developing global LNGmarket.

Liquefied natural gas is already a significant supplysource for many countries in the world, includingJapan, South Korea and several west European

nations. Fortunately, the world’s gas resource base islarge. The NPC analysis concludes that significantquantities of LNG will need to be imported into theUnited States in the future to meet the expecteddemand for natural gas. LNG has a proven safetyrecord with 33,000 carrier voyages covering 60 millionmiles with no major accidents over a 40-year history.Historically, LNG imports into the United States havecontributed less than 1% to U.S. supply, primarily dueto low gas prices and the relatively high cost of LNG.This situation has changed. New technology hasreduced the cost of making and transporting LNG.New LNG supply sources have also begun to enter themarket and, because of higher gas prices, are nowcompetitive in the North American market. Figure 35illustrates the diverse global natural gas supply sourcesfor LNG.

The Reactive Path case assumes the four existingU.S. regasification terminals will be fully utilized by2007, and that seven additional regasification terminals(and seven expansions) will be built in North Americato meet gas demand through 2025. This would resultin a total LNG import capacity of 12.5 BCF/D, withLNG providing 14% of the U.S. supply of natural gasby 2025. In the Balanced Future case, projects are per-mitted more quickly and two additional terminals andtwo additional expansions are assumed built. Thisincreases total LNG import capacity to 15 BCF/D or17% of the U.S. supply of natural gas by 2025.Figure 36 shows the locations of existing and potentialnew LNG terminals, and Figure 37 shows the projectedvolume contribution from LNG.

While there is clear potential for LNG imports to fallshort of these projections due to market uncertaintiesand possible opposition to siting of LNG regasificationterminals, the upside potential, while significant, is alsouncertain. One implication of natural gas price pro-jections in the Reactive Path case is that even largerquantities of imports might be attracted. However,LNG developments will also be subject to the risk oflower North American demand due to higher prices, aswell as competition from other North Americansources of natural gas production.

The assumptions in either case represent a majorundertaking, since developing a large, new LNGimport capability in North America will not be easy.LNG imports require alignment of the entire supplychain from development of foreign source gas reserves,


Finding 7: New, large-scale resources suchas LNG and Arctic gas are available andcould meet 20-25% of demand, but arehigher-cost, have longer lead times, andface major barriers to development.

to liquefaction of the supply, to construction of spe-cialized LNG carriers, to regasification and deliveryinto the North American transmission infrastructure.Capital requirements for a typical LNG developmentfrom source to an interconnection with an existingpipeline grid are on the order of $5-$10 billion perBCF/D of capacity. For the Reactive Path case, the esti-mated capital requirements for LNG during the studyperiod are over $90 billion, and nearly $115 billion forthe Balanced Future case.

The typical regasification terminal in the UnitedStates is estimated to take over five years from initialpermit application to commencement of imports.Under current regulations, permitting can take fromone year (offshore terminals) to over two years(onshore terminals) assuming minimal resistance anda well-coordinated permitting process. The ReactivePath case assumed a permitting time of two years,while the Balanced Future case assumed one year.

Recently, the U.S. government implemented two policy changes to facilitate development of new LNGimport regasification terminals. First, the Deep WaterPort Act was amended to include natural gas/LNG/CNG; this resulted in two significant changes for

offshore LNG import terminals. Such terminals willnow be under the jurisdiction of the United States CoastGuard, and permit applications will have a discretetimeline. Second, the Federal Energy RegulatoryCommission, which has the jurisdictional authority foronshore LNG import regasification terminals, ruled thattwo such terminals will be treated similarly to gas pro-cessing plants, no longer requiring open-access regula-tion. The latter policy allows companies to developintegrated LNG projects, which is important in reducingthe risk associated with these large, complex, projects.

These efforts, while encouraging new LNG importterminal development, will not overcome all the hur-dles faced by the industry. New terminals may facesubstantial local opposition. Permits for new termi-nals, particularly onshore terminals, will only be issuedin a timely fashion with the support of local govern-ments and communities. A continued leadership role,as demonstrated by FERC in the recent reactivation ofthe Cove Point and Elba Island facilities, will be needed to move the permitting process forward in atimely manner. Any setbacks from what the NPC proj-ects as substantially successful development of LNGsupply would reduce projected supplies and increasegas prices.


Figure 35. Global LNG Supply

EXISTING

UNDER CONSTRUCTION

PROPOSED


LAKE

CHARLES

ELBA ISLAND

COVE PT

EVERETT

EXISTING

POTENTIAL

GOM

OFFSHORE

EAST COAST

BAJA

ALTAMIRA

GULF COAST

ONSHORE

EASTERN

CANADA

BAHAMAS

LAZARO

CARDENAS

WEST

COAST

LOCATIONS OF

LNG TERMINALSNORTH SLOPE

MACKENZIE DELTA

ARCTIC REGIONS

Figure 36. Potential Large-Scale Sources of Natural Gas Supply

To evaluate the impact of potential setbacks, a sensi-tivity case was evaluated in which only two new LNGterminals were constructed due to permitting difficul-ties. In this case, LNG import capacity was reduced by6 BCF/D and the average gas price increased by 10%.Clearly the ability to import increasing volumes ofLNG is important to achieving a more comfortablesupply/demand balance.

A second source of significant potential new sup-plies is Arctic gas. This includes gas from the AlaskaNorth Slope and the Mackenzie Delta region in Canada(illustrated in Figure 36) where substantial quantitieshave already been discovered, but require long, newpipelines to be developed.

Efforts have been underway by industry for over 30years to commercialize Alaskan gas. Major hurdles forcommercializing this resource include costs, permit-ting, state fiscal uncertainty, and market risks. Thecompanies involved in oil and gas production atPrudhoe Bay, Alaska estimate the cost to bring Alaskangas to U.S. markets to be on the order of $20 billionwith a lead time of ten years, assuming construction offull pipeline infrastructure south of Alberta to U.S.

markets. The NPC study analysis indicates somecapacity may be available in existing infrastructure,potentially reducing the amount of new pipeline con-struction required.

Industry is working to advance new technology thatcould reduce the capital cost. However, securing all thenecessary permits in a timely manner from variousjurisdictions in the United States and Canada repre-sents a significant challenge. Another hurdle is theuncertainty regarding how royalty and tax payments tothe state of Alaska will be calculated over the life of apipeline project. Conditions must be particularlystrong to support an investment of this magnitudeconsidering the long lead-time and the inherent risks.The NPC has assumed that these challenges will beovercome, and that conditions will support an Alaskagas pipeline start-up in the 2013-14 time frame. Thiswould contribute 4 BCF/D, about 6% of U.S. supply,through the remaining years of the study period.

Given the commercial, regulatory, and cost-relatedrisks associated with this project, a sensitivity case wasrun in which it was assumed that the Alaska gas pipeline


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Figure 37. North American LNG Imports

will not be built. This increased gas price projections byroughly 8% over the period from 2015 to 2025, puttingfurther stress on the economy and illustrating theimportance of this project to the overall outlook.

Similar issues confront a proposed pipeline from theMackenzie Delta in Canada. Although that project issmaller, and most of the gas will probably find a mar-ket in Canada, there will be an effect on the U.S. gassupply. A Canadian regulatory process is evolving toaddress First Nations’ rights as well as other local andfederal issues in a timely manner. The NPC hasassumed that permits can be secured and market con-ditions could support start-up of a Mackenzie Deltapipeline in 2009 at a rate of 1 BCF/D, with an expan-sion in 2015 to 1.5 BCF/D.

All of these projects face barriers to developmentand have very long lead times. Thus these potentialsources of supply will not affect the short-term funda-mentals of the current market environment. Figure 38shows the relationship of these new supply sources toother sources of supply in the Reactive Path case.

The NPC also evaluated potential new supplysources that require technology advances to be com-

mercially competitive. These new sources, includingmethane hydrates are viewed as unlikely to make mate-rial contributions prior to 2025, but they do representpotential longer-term supply sources. Additionaldetails can be found in the Technology section of theSupply Task Group Report.

Figure 39 illustrates expected capital expendi-tures for infrastructure through 2025 for theBalanced Future case (the results of the ReactivePath case are very similar). Through 2025 it isanticipated that in the United States, $35 billion($1.5 billion per year) will be invested in new andexpanded pipeline and storage infrastructure toprovide deliveries of new supply sources to the mar-ketplace. Additionally $12 billion in pipeline and


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Figure 38. U.S. and Canadian Natural Gas Supply

Finding 8: Pipeline and distributioninvestments will average $8 billion peryear, with an increasing share required tosustain the reliability of existinginfrastructure.

storage infrastructure expenditures is projected forCanada. Nearly $70 billion ($3 billion per year) willbe required for distribution facilities in the UnitedStates (twice the rate for pipeline and storage).

As can be seen, the projected need for capital for newinfrastructure is decreasing in the future while sustain-ing capital is becoming an increasing percentage oftotal capital requirements. It is anticipated that overthe next 22 years $70 billion of expenditures will beneeded in sustaining capital for the existing pipelineand distribution infrastructure in the United States,and $3 billion in Canada. From 2000 to 2002, sustain-ing capital is estimated as 21% of total transmissionexpenditures. By 2020 to 2022, sustaining capital willincrease to almost 75%. Sustaining capital for trans-mission, distribution, and storage is estimated as 21%of total expenditures for 2000-2002. By 2020, sustain-ing capital for the three segments is projected to be45% of total expenditures.

As discussed previously, growth in onshore produc-tion in the lower-48 states is effectively limited to theRocky Mountain region. Major new sources of gas willhave to come from outside the lower-48 states and willrely on the existing network of nearly 290,000 miles of

high-pressure pipelines to transport the gas to markets.Figure 40 shows the anticipated new pipeline transmis-sion requirements in the Balanced Future case by 2025.

Major new pipeline infrastructure will be needed tobring Arctic production to the Alberta hub. The addi-tional capacity needed to move the Arctic gas awayfrom the Alberta hub is a function of the rate of declineof Western Canadian Sedimentary Basin (WCSB) pro-duction, which is anticipated to continue its decline asthe Arctic gas comes on line, and growth in demand forgas in Canada, including an increasing gas demand foroil sands development. Currently, there is about 15 BCF/D of pipeline capacity from western Canadaand it is about 85%-utilized in transporting WCSB gasto downstream markets. The NPC analysis suggeststhat an additional 0.5 to 2 BCF/D of new or expansioncapacity will be required with the remainder movingon existing pipeline infrastructure.

The NPC outlook indicates that LNG import termi-nals are a critical element needed to meet demand onthe east and west coasts. To the extent that these LNGregasification terminals can be sited close to demandcenters, additional pipeline infrastructure investmentmay be minimized, particularly where existing capacity


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Figure 39. North American Capital Expenditures for Transmission, Distribution, and Storage


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Figure 40. New Pipeline and LNG Capacity (Million Cubic Feet Per Day) Change from 2003 to 2025

is made available by declines in domestic production.If such terminals cannot be sited in market regions,however, additional pipeline infrastructure and greaterreliance on the existing pipelines from the Gulf Coastmay be needed to deliver LNG to major markets. Thiswill result in higher basis between Henry Hub and themarket and higher costs for consumers.

Additional pipeline take-away capacity will also beneeded from the Rocky Mountains, deep waters of theGulf of Mexico, and Eastern Canada offshore. Thisnew capacity will be limited to that needed to interfacethe existing pipeline grid. From there, it is expectedthat the gas will move on existing pipeline systems toaccess markets throughout the lower-48 states.

Capacity must also be constructed to transport gasfrom storage to market centers. Mid-Atlantic andNortheast markets will require additional storage.Since the lack of suitable reservoirs restricts the poten-tial development of this storage capacity to the westernportions of Pennsylvania and New York and EasternOhio, incremental short-haul pipeline capacity ofapproximately 2 BCF/D will have to be constructed tothe major northeastern market centers, which includeNew York City, Boston, and Philadelphia.

Natural gas demand has always been seasonal, but arecent phenomenon is that, due to increased gas-firedgeneration implemented around the continent, a newsummer season peak is also developing. Other thanthe industrial load, which is fairly steady on a daily andseasonal basis, the other major demand sectors (resi-dential, commercial, and electric generation) areweather sensitive and have a high degree of variability.Demand in North America is projected to grow by 19%between 2003 and 2015, industrial demand is project-ed to grow by only 3%. This means the stable indus-trial demand sector is becoming a smaller percentageof total demand. This effect is more pronounced in theUnited States, where industrial demand is projected todecline by 6% from 2005 to 2015.

Demand for power generation, which will make upthe majority of projected demand growth, is highlyvariable on an hourly, daily, and monthly basis. As canbe seen in Figures 41 and 42, power generation notonly increases the number and magnitude of winterdemand peaks, but it also creates a secondary demandpeak in the summer. It also creates an hourly demandprofile that is even more pronounced and unpre-dictable than that of a traditional residential/commer-

cial load profile. The growing summer peak impactsthe summer season gas storage injection period, pri-marily allowing for injections only in the off-peak elec-tric demand hours of the day and thus requiring morevolume to be injected into storage during the shouldermonths of April through June and September throughOctober, historically lower demand months.

Regardless of the growing power generation needs inthe summer months, local distribution companies(LDCs) will need to fill their market area storage to beable to meet their customer’s winter consumptionrequirements reliably. The growing divergence of thetwo sectors’ needs will require storage operators toconstruct additional storage capacity and increase theflexibility of their current facilities.

Construction of significant new LDC facilities willalso be required to meet customer demands. Thesefacilities include main reinforcements, main extensions,and the construction of services to bring the gas into anindividual home or business. New and even more envi-ronmentally sensitive and lower cost construction tech-niques are needed. Better technologies for locatingexisting underground facilities will enhance the safetyand operation of existing facilities4 and reduce the costsof new construction. A 1% annual gain in productivityfrom technological advances was assumed in this study.Such a gain would result in reduced customer costs of$300 to $400 million per year, over the costs of the pre-vious year. Therefore, continued R&D is needed to pro-vide new techniques and technologies to minimizethese future costs while assuring safe and reliable oper-ation of distribution systems.

Existing Infrastructure

Gas transmission and distribution has been thesafest mode of energy transportation. Use of the exist-ing pipeline and distribution infrastructure is antici-pated to increase as many lines reverse flow, and othersincrease in utilization. Significant ongoing expendi-tures will be required to undertake additional preven-tative measures to maintain safe and reliableoperations. Pipeline and storage companies operateover 290,000 miles of transmission pipe and approxi-mately 16,000,000 horsepower. Of the 290,000 miles,255,000 miles, or 88%, was installed prior to the 1970s.Figure 43 shows the North American pipeline grid.


4 “Third party damage” where someone other than anLDC hits the distribution pipe is the leading cause ofdamage to the distribution system.


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Figure 42. 2025 Daily Loads for the United States and Canada

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Figure 41. 1997 Daily Loads for the United States and Canada


Figure 43. North American Pipeline Grid (24" Diameter and Greater)

Congress enacted in 2002 the Pipeline SafetyImprovements Act, which has significantly increasedpipeline testing and reporting requirements for thetransmission and distribution industries. In additionto improving the “one call” systems used by the statesand requiring enhanced operator qualifications, theAct mandates updated maintenance programs andcontinuing inspections of all pipelines located in pop-ulation centers. These mandates will increase costs toconsumers several ways. Additional costs will arisebecause facilities will need to be temporarily taken outof service to perform the mandated testing. This maycause deliverability constraints during testing periodsdue to reduced capacity. Costs will also increase as aresult of the direct costs of integrity inspections andthe required modifications of pipeline and distributionfacilities. Both of these costs will tend to put upwardpressure on gas transportation rates.

Because of the decreasing life expectancy of theinstalled horsepower and pending and potential envi-ronmental mandates, significant horsepower will haveto be replaced over the study period. If operators wereto replace all horsepower over the next 50 years,320,000 horsepower would need to be replaced eachyear. Similarly if all pipe was replaced over the nextfifty years, 5,800 miles of pipe would need to bereplaced each year. Sustaining capital for transmissionwas calculated on the basis of replacing 700 miles ofpipe and 77,000 horsepower of compression each year.This is viewed as a conservative estimate as it is a smallfraction of the existing 290,000 miles of pipe and

16,000,000 horsepower of compression, much ofwhich is over 40 years old. The basis for using thelower number is that it better matches the historicallevel of replacement. Because of the impacts of thePipeline Safety Improvements Act, however, the NPCdoubled the historical levels for the purposes of thestudy. If pipelines aren’t able to retire the pipe and/orcompression in the future due to continuing need orotherwise, sustaining capital could be significantlyhigher. At some point in the future, however, the pro-gressive aging of pipelines and compressors will resultin further significant increases in the miles of pipe andhorsepower replaced per year.

The average transportation contract term onpipelines has shortened. New pipeline and storageinfrastructure are generally financially supported bylong-term contracts for a period of ten to twentyyears. Companies are less willing to invest dollars innew infrastructure if contract durations for existing ornew pipeline/storage capacity are shortened by theimpact of regulatory policies. In a free market, ship-pers make long-term commitments when they see theneed for the service that will be provided. If barriersexist to shippers making long-term commitments,investment in new infrastructure is impacted. Thisaffects both new and existing pipelines. As shown inFigure 44, the average contract term on gas pipelines isbeing shortened. Pipeline operators believe a signifi-cant factor is the regulatory policies on contractingpractices by some federal and state regulatory agen-cies. As a result, even though the pipelines carry basi-cally the same amount of gas to serve the samemarkets, the revenue stream is viewed as more short-term in nature and less likely to support long-terminfrastructure investments.

From the beginning of the transmission industryuntil recently, LDCs were the dominant parties con-tracting for long-term pipeline and storage capacity.Their contracts were crucial for the development ofnew pipelines and the expansion of existing onesbecause they provided the financial underpinning nec-essary to raise the required capital. This role began tochange in the late 1990s as a result of regulatory


Finding 9: Regulatory barriers to long-term contracts for transportation andstorage impair infrastructure investment.

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changes at the federal and state level. Regulatorychanges associated with a competitive market thatresulted in the growth of independent marketing com-panies as sellers of gas to both utilities and to end usersgave LDCs more supply options and incentives to con-tract for less capacity and to hold shorter-term capa-city contracts.

Marketing companies saw rapid growth in the early1990s as they provided the intermediary functionbetween producers and consumers that arose as thepipeline sales function disappeared. LDCs and majorindustrial consumers became responsible for purchas-ing their own gas supplies. Most began by buying gasin the production area directly from producers andtransporting it to market via their existing contracts.Over time, marketing companies began to offer citygate sales service to LDCs and large end-users by effi-ciently packaging portfolios of transportation andstorage contracts obtained from the original contractholders either through agency agreements, contractreleases or, in the later stages, by direct contract owner-ship. Marketers desired to hold transportation andstorage contracts similar in term to their associatedsales agreements to lower their financial exposure.Many of the marketers’ sales contracts were relativelyshort term. Some marketer’s portfolios held some longterm capacity contracts but it was for a much smallerproportion of their portfolio than was common forpipeline customers in the pre-restructuring period.Thus, as illustrated in Figure 44, although the pipelineswere carrying basically the same amount of gas to servethe same end-uses, their average contract term short-ened.

A contributing factor in the shortening of pipelinecontracts was the restructuring of many LDC busi-nesses in the 1990s. The opening of LDC distributionsystem capacity to transport by third parties was devel-oped as a means to increase competition and lowerprices. By the end of the 1990s, restructuring was com-plete in many states for gas in the industrial and elec-tric generation segments and was underway in theresidential/commercial sector. Although retail choiceprograms are in place in many states, to date the vastmajority of residential customers have elected toremain with their original utility. Nevertheless, a direc-tive from some states is that LDCs should not contractfor the long term in pipeline, storage, or upstreamcapacity since their share of the future market wasunknown and subject to considerable risk in the face ofdeveloping competition. Generally, LDCs are not will-

ing to contract for long-term capacity and take the riskof being second-guessed in future prudency reviews.

Today, the turmoil of the gas marketer business seg-ment has almost eliminated independent and affiliatedmarketers from the list of prospective purchasers ofexisting and/or proposed pipeline transmission capac-ity. Even if such firms wanted to contract for capacity,their creditworthiness may make them too great a riskfor pipelines and downstream customers to considerwithout the gas marketer providing significant creditassurances.

Many LDCs will not enter into long-term contractswith marketers in today’s market out of fear that regu-lators may subsequently deem them imprudent.Similarly, power producers, especially those that pro-vide peaking service, are reluctant to contract for firmpipeline service because charges for firm service can-not be economically justified in power sales. The resultis that regulatory barriers may be inhibiting efficientmarkets and discouraging the financial incentives todevelop and maintain pipeline infrastructure.

Since the 1980s, the natural gas market has continu-ously evolved following FERC and Congressionalactions to implement the free market system for thetrade of natural gas. Accompanying this deregulationhas been greater variability of gas prices as marketforces worked to establish prices in the monthly anddaily markets. Price volatility is a natural phenomenonin a market where supply and demand vary on adaily/hourly basis. The principal drivers behind pricevolatility are supply and demand fundamentals, whichinclude demand variability, weather effects, supply andstorage levels, the cost of competing fuels, and overallmarket trends. Relatively large price changes can andhave occurred when supply and/or demand sectors areunable to quickly adjust to unexpected changes inmarket conditions. Figure 45 shows Henry Hubmonthly prices for the last ten years. Natural gas priceshave been more volatile than crude oil prices but


Finding 10: Price volatility is a funda-mental aspect of a free market, reflectingthe variable nature of demand and supply;physical and risk management tools allowmany market participants to moderate theeffects of volatility.

significantly less volatile than electricity prices. Manyconsumers and producers have access to a broad rangeof physical and risk management tools to manage itseffects.

The North American natural gas market is thelargest and most liquid gas market in the world, withhundreds of suppliers and thousands of major con-sumers including LDCs, industrials, and power gener-ators. The market is functioning efficiently withlessened government involvement following years ofregulatory reform. In a free market, participants needprice signals in order to make rational decisions aboutwhether to produce or consume more gas. Customerswho want gas, even in the highest demand periods, gettheir gas if they contract for delivery in advance – oralternatively pay the market price on the day.Additionally, producers respond to price signals forincreased supply by increasing their exploration anddrilling efforts.

Most residential and commercial customers servedby LDCs are insulated from day-to-day price volatility,through state or local regulation with periodic adjust-ments reflecting the average cost of gas purchased over

a longer period. Ultimately consumers’ bills reflectprice level changes.

Industrial gas consumers tend to be more exposed toshort-term price effects since they usually buy gas in themonthly and daily markets, and therefore have beenmost affected by rising prices (this also makes them thefirst to benefit from falling prices). Rising gas priceshave caused some industrial plant shutdowns and relo-cations of some manufacturing to foreign locationswith lower cost natural gas. Industries most affected arethe fertilizer, methanol, steel and chemicals.

There are several steps that market participants andregulators can take to mitigate price volatility. Theseinclude: 1) contracting for firm transportation andstorage; 2) switching to lower cost alternate fuels;3) using financial hedges – a strategy that does not elim-inate risk, but does create price certainty; 4) contractingunder long-term fixed price agreements; and 5) makingavailable timely and reliable information regarding sup-ply, demand, and storage levels. Items 1-4 require acost-to-benefit analysis to determine whether theyshould be adopted by individual market participants.Item 5 is best facilitated by government action.


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Figure 45. Henry Hub Monthly Index Prices

Exposure to price volatility to a great extent is aboutchoices that market participants make. Participantsmay choose to buy or sell in the short-term daily mar-ket and not contract for storage or transportationcapacity – this exposes them to increased volatility.Others may choose to contract under long termarrangements for the purchase or sale of gas and holdfirm transport capacity thereby reducing their expo-sure to price volatility. Additionally the futures marketmay be used to manage forward pricing. In summary,tools are available to help manage the risk of pricevolatility, but they come at a cost.

There have been major changes in gas market par-ticipants over the past two years. Several large market-ing companies have exited the physical and financialgas trading business, and on-line trading operationshave declined. The number of participants offering abroad portfolio of financial products has been reducedand the need to trade with credit-worthy entities hasbeen reinforced. These changes have highlighted apotential decline in market depth (e.g., number ofplayers) particularly for long-term hedges, and there-fore have contributed to a reduction in some cus-tomers’ ability to manage long-term price volatility.

The rise of financial products has been fairly dra-matic since 1990. The trend in the use of NYMEXfinancial instruments is illustrated in Figure 46 andshows increasing open interest in NYMEX contractsthrough mid 2002. Open interest is a measure of activ-ity on NYMEX and gives some indication of overallmarket depth and liquidity. Current levels of NYMEXtrading at the Henry Hub are below the 2002 peak butabove the overall range of the 1990s. Marketers havetraditionally been the major market makers and coun-ter parties for a broad suite of NYMEX and over-the-counter financial tools (price swaps, forward priceoptions, basis swaps, etc.) in addition to physical gasvolumes. There are now fewer marketing entities offer-ing these comprehensive services as they now also havefewer parties to transact with and mitigate exposures.

Despite the recent changes in market participants,overall liquidity remains sufficient for parties to trans-act at multiple physical trading hubs and to accesseffective financial markets. Although physical flowshave remained relatively constant, liquidity at somelocations other than the major hubs is reduced fromthat of recent years, and reported trading volumes havedeclined from recent peaks. Continued enhancement


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Figure 46. NYMEX Open Interest – Natural Gas Contracts

of market liquidity and expanded market depth remaingoals for industry, and the market is adjusting asappropriate. Government should allow free-marketforces to work, and markets will continue adjusting foran effective, efficient balance.

Competitive markets are the most effective means toensure that consumers get the greatest benefit from theuse of our natural gas resource endowment. Thesebenefits are significantly affected by policy choices atall levels of government. The most difficult task facedby the NPC was to assess the future balance of con-sumption and new supplies in the face of a tight mar-ket for natural gas. On the demand side, the ability andlikelihood of consumers to switch to lower-cost fuelswas comprehensively evaluated, as was the potential formore stringent environmental regulation – a coursethat could lead to an even greater demand for gas. Onthe supply side, consideration was given to the uncer-tainties in estimating the size of the indigenous NorthAmerican resource base, the rate of technology devel-opment, as well as regulatory actions that might accel-erate or delay development of domestic and foreignsources of supply.

As previously described, two primary scenarioswere used to evaluate the long-range outlook. TheReactive Path case was modeled based on existingenvironmental regulations and policies for both pro-duction and consumption of natural gas. This casecontinues the current limitations on fuel switchingand the use of alternative fuels, as well as the restric-tions to supplies, particularly in the Rocky Mountainregion and offshore lower-48 states. Despite theselimitations, the Reactive Path case assumes industrywill be able to discover and develop significant newquantities of gas in the lower-48 states and Canada,import very large volumes of LNG, and commercializeArctic gas in a timely manner. The Reactive Path casealso assumes that there is no major new environmen-tal law or initiative that significantly reduces the

ability of coal, nuclear, and hydroelectric power toprovide electricity.

Even with these potentially optimistic assump-tions, the Reactive Path outlook still results in a verytight balance of supply and demand. Overall natu-ral gas demand continues to grow largely as a resultof strong new power generation needs. Industrialdemand is lower in response to higher prices and thetight supply and demand balance. Increasing natu-ral gas demand is met primarily with growing LNGimports and Arctic gas developments, while robustprices are required to maintain production levelsfrom indigenous lower-48 and Canadian sources.After development of Arctic resources, the value ofgas relative to alternate fuels continues to grow inthe Reactive Path case. The demand and supplycomponents for the Reactive Path case are shown inFigures 47 and 48. The price range outlooks for theReactive Path and Balanced Future cases are shownin Figure 49.

This outlook raises many questions and concerns.Many believe that market forces should better balancesupply and demand, and that our inexperience withsuch a sustained high-price environment may beaffecting our ability to model the response of supplyand demand. For example, it is possible that such pricesignals could lead to periods of oversupply, as numer-ous high-volume, long-lead-time supply projects comeon stream, potentially in an environment in whichdemand has been reduced by high prices. However,given the supply and demand assumptions inherent inthe Reactive Path case, the NPC was unable to developa credible case for such a balance without policyactions that encourage supply and give industrial con-sumers and power generators more options in theirchoice of fuel.

To evaluate these policy choices, the Balanced Futurecase was developed. This case incorporates govern-ment policies that encourage a more diverse but envi-ronmentally sound future fuel mix, and which wouldrelieve some of the pressure placed on gas by existingregulations. As a result, this case increases renewable,coal, and oil generation capacity. This assumes a regu-latory regime with respect to mercury that reducesretirements of coal-fired capacity, increases the outputof existing nuclear facilities, and reduces retirement ofexisting oil/gas switchable capacity. Additionally, thiscase assumes a systematic re-introduction of fuel flexi-bility in both industrial and power generation


Finding 11: A balanced future that includesincreased energy efficiency, immediatedevelopment of new resources, andflexibility in fuel choice could save $1 trillion in U.S. natural gas costs over thenext 20 years. Public policy must supportthese objectives.


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Figure 47. U.S. and Canadian Natural Gas Demand – Reactive Path Scenario

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Figure 48. U.S. and Canadian Natural Gas Supply – Reactive Path Scenario

applications; 25% of existing gas-fired capacity isretrofitted for oil backup, 25% of new gas-fired capac-ity includes oil backup capability, and industrial boilersreturn to the fuel-switching level of 28% by 2025.These assumptions incorporate control technologies toassure continued compliance with existing air qualityregulations. Finally, this case assumes enhanced effi-ciencies in residential and commercial sectors due toenhanced building codes, smart controls, and efficientmarket mechanisms such as real-time pricing.

On the supply side, the Balanced Future case assumesthat improvements will be made in permitting pro-cesses and access to resources, which allow an increasedsupply outlook to be achieved, both through indigenousproduction and increased LNG imports (an additional2.5 BCF/D) above the Reactive Path case. Lower-costdomestic production is achieved through lifting of theOCS moratoria and by reducing the effect of accessrestrictions caused by restrictive conditions of approvalin the Rocky Mountain area by 50% over a 5-yearperiod. The net effect of these policy-related changes isto reduce the cost to consumers of providing similarquantities of gas. Figures 50 and 51 show the demandand supply components of the Balanced Future case.Figure 49 shows the price range projections.

With lower cost supplies being made available, moredemand can be satisfied, recognizing some demandbeing met by alternate fuels. It is particularly signifi-cant that more industrial demand for gas is satisfied inthe Balanced Future case. Relatively small adjustmentscan make a big difference in achieving a comfortablesupply/demand balance.

The NPC also evaluated cases that reflect even moredifficult futures than the Reactive Path case, such ascontrols on carbon emissions and more limited accessto gas resources. These evaluations are described in theIntegrated Report. These assumptions clearly entailvery high demand for gas, very tight supplies, and sig-nificant upward pressure on prices.

The NPC recognizes that this kind of analysis is sen-sitive to changes in assumptions. Any of a number ofkey variables – including economic growth, oil prices,resource base size, and technology development – candramatically influence the outlook for future gas mar-kets. Even recognizing those sensitivities, the funda-mentals of the current situation are evident, especiallyfor the next five years or so: indigenous supply is flat todeclining, demand is growing, and there will beupward pressure on prices.


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Figure 50. U.S. and Canadian Natural Gas Demand – Balanced Future Scenario

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Figure 51. U.S. and Canadian Natural Gas Supply – Balanced Future Scenario


Figure 53. U.S. and Canadian Infrastructure, Capital Expenditures – Balanced Future Scenario

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Capital Requirements

The NPC also evaluated the capital requirementsof these outlooks. Almost $1.4 trillion (2002 dollars)in capital expenditures will be required to fund theU.S. and Canadian gas upstream and infrastructureindustry from 2003 to 2025. Eighty-five percent willbe spent in the exploration and production sector($1.2 trillion) with the remaining 15% ($0.2 trillion)spent on pipelines, storage, and distribution, asshown in Figures 52 and 53. These expendituresrepresent a significant increase over the 1990-2000period for the exploration and production sector.Expenditures for the pipeline, storage, and distribu-tion sector are expected to remain relatively con-stant, considering increasing needs for “sustainingcapital” to meet reliability requirements.

While a majority of the required capital will comefrom reinvested cash flow, industry will continue toneed capital from the markets to fund the growth. Toachieve this level of capital investment, industry must

compete with other investment opportunities anddeliver returns equal to or better than other S&P 500companies. Some industry segments have notachieved this in the past and this presents a challengefor the future.

However, the capital spending envisioned in thisoutlook provides opportunity for a wide range of com-panies including small, private companies and largemultinationals. Although there have been recent,notable bankruptcies and credit rating downgrades forcompanies linked to energy trading and merchantpower activities, there is more than sufficient capitalavailability, liquidity and participation from credit-worthy companies to complete the projects withacceptable economic returns.

Clearly a broad spectrum of industries and con-sumers will be affected by the policy choices ahead.The NPC’s recommendations on how to achieve aBalanced Future are listed in the section that follows.


SUMMARY - RECOMMENDATIONS 57

To achieve our nation’s economic goals and meetour aspirations for the environment, natural gaswill play a vital role in a balanced energy future.

Stable and secure long-term supply, a balanced fuelportfolio, and reasonable costs will be enabled by acomprehensive solution composed of key actions facil-itated by public policy at all levels of government. Keyrecommendations to assure long-term supply and abalanced fuel portfolio at reasonable cost fall into fourstrategic themes highlighted and summarized here:

• Improve demand flexibility and efficiency

– Encourage increased efficiency and conservationthrough market-oriented initiatives and con-sumer education

– Increase industrial and power generation capabil-ity to utilize alternate fuels

• Increase supply diversity

– Increase access and reduce permitting impedi-ments to development of lower-48 natural gasresources

– Enact enabling legislation in 2003 for an Alaskagas pipeline

– Process LNG project permit applications withinone year

• Sustain and enhance natural gas infrastructure

– Provide regulatory certainty by maintaining aconsistent cost-recovery and contracting environ-ment and remove regulatory barriers to long-term capacity contracting and cost recovery ofcollaborative research

– Permit projects within a one-year period using a“Joint Agency Review Process”

• Promote efficiency of natural gas markets

– Improve transparency of price reporting

– Expand and enhance natural gas market data col-lection and reporting.

North American natural gas resources have histori-cally provided stable supplies, and will continue to sup-ply the vast majority of the continent’s needs. However,future needs will not be met by continued developmentof these resources alone, and a significant share ofdemand will be met with Arctic and global LNGresources. Natural gas provides about 25% of the con-tinent’s total energy needs and will be one of the vehi-cles for continued air quality improvements. However,as part of the balance between supply and demand,flexibility in current fuel use and diversity in futureindustrial and power generation fuels will be required.Following are details of NPC recommendations.

Natural gas is a critical source of energy and rawmaterial, permeating all sectors of the economy. Eachsector of the economy can make contributions to usingnatural gas resources more efficiently.

The changes in demand require involvement ofeach consumer segment and can be broadly character-ized as:

• Energy efficiency and conservation

• Fuel switching and fuel diversity.

RECOMMENDATIONSSUMMARY

Recommendation 1: Improve demandflexibility and efficiency

In the very near-term, reducing demand is the primarymeans to keep the market in balance because of thelead times required to bring new supply to market.While current market forces encourage conservationamong all consumers and fuel switching for large cus-tomers who have that capability, proactive governmentpolicy can augment market forces by educating thepublic and assisting low-income households. Key rec-ommendations are summarized below.

Encourage Increased Efficiency andConservation through Market-OrientedInitiatives and Consumer Education

Energy efficiency is most effectively achieved in themarketplace, and can be accelerated by effective utiliza-tion of power generation capacity, deployment of high-efficiency distributed energy (including cogenerationwhich captures waste heat for energy), updating build-ing codes and equipment standards reflecting currenttechnology and relevant life-cycle cost analyses, pro-moting high-efficiency consumer products includingbuilding materials and Energy Star appliances, encour-aging energy control technology including “smart”controls, and facilitating consumer responsivenessthrough efficient price signals.

• Educate consumers. All levels of governmentshould collaborate with non-governmental organi-zations to enhance and expand public educationprograms for energy conservation, efficiency, andweatherization.

• Improve conservation programs. DOE shouldidentify best practices utilized by states for the low-income weatherization programs and encourageadoption of such practices nationwide.

• Review and upgrade efficiency standards. DOE,State Energy Offices, and other responsible state andlocal officials should review the various building andappliance standards which were previously adoptedto ensure decisions reached under cost/benefit rela-tionships are valid under potentially higher energyprices.

• Provide market price signals to consumers to facil-itate efficient gas use. FERC, Regional Transmis-sion Organization (RTOs), and state utilitycommissions should facilitate adoption of market-based mechanisms and/or rate regimes, coupledwith metering and information technology to pro-vide consumers with gas and power market pricesignals to allow them to make efficient decisions fortheir energy consumption.

• Improve efficiency of gas consumption by resolvingthe North American wholesale power market struc-ture. FERC and the states/provinces, and if necessarycongressional legislation, should improve wholesaleelectricity competition in the United States, Canada,and interconnected areas of Northern Mexico. FERCshould mitigate rate and capacity issues at the seamsbetween adjoining RTOs to maximize efficient energyflows between market areas.

• Remove regulatory and rate-structure incentivesto inefficient fuel use. FERC, RTOs, and state regu-lators should ensure central dispatch authority rules,procedures and, where applicable, cost-recoverymechanisms, require dispatch of the most efficientgenerating units while meeting lowest cost and sys-tem reliability requirements.

• Provide industrial cogeneration facilities withaccess to markets. Congress, FERC, RTOs and,where applicable, state regulators should ensure thatlaws, regulations, and market designs provide indus-trial applications of cogeneration with either accessto competitive markets or market-based pricingconsistent with the regulatory structure where thecogeneration facility is located.

• Remove barriers to energy efficiency from NewSource Review. Remove barriers to investment inenergy efficiency improvements, and investments innew technologies and modernization of power-plants and manufacturing facilities by implementingreforms to New Source Review such as those pro-posed by the U.S. Environmental Protection Agencyin June 2002.

Increase Industrial and Power GenerationCapability to Utilize Alternate Fuels

Natural gas has become an integral fuel for industrialconsumers and power generators due to a range of fac-tors, including its environmental benefits, and theseconsumers should continue to be allowed to choosenatural gas to derive these benefits. However, thegreatest consumer benefit will be derived from market-based competition among alternatives, while achievingacceptable environmental performance. The ability ofa customer to switch fuels serves to buffer short-termpressures on the supply/demand balance and is aneffective gas demand peak shaving strategy that shouldreduce upward price volatility. Increasing fuel diver-sity, the installation of new industrial or generationcapacity using a fuel other than natural gas, serves toreduce greater gas consumption over the life of the new

SUMMARY - RECOMMENDATIONS58

capacity. Most facilities that would consider installingnon-gas fueled capacity tend to be large and energyintensive. Therefore, increasing fuel diversity will havea large cumulative effect on natural gas consumptionover the period of this study.

• Provide certainty of air regulations to create aclear investment setting for industrial consumersand power generators, while maintaining thenation’s commitment to improvements in airquality.

– Provide certainty of Clean Air Act provisions.Congress should pass legislation providing cer-tainty around Clean Air Act provisions for sulfuroxides (SOx), nitrogen oxides (NOx), mercury,and other criteria pollutants. These provisionsshould recognize the overlapping benefits ofmultiple control technologies. The currentuncertainty in air quality rules and regulations isthe key impediment to investment in, and con-tinued operation of, industrial applications andpower generation facilities using fuels other thannatural gas. Congress should ensure that suchlegislation encourages emission-trading pro-grams as a key compliance strategy for any emis-sions that are limited by regulation.

– Propose reasonable, flexible mercury regulations.The Environmental Protection Agency’s December2003 proposed mercury regulations should provideadequate flexibility to meet proposed standards.These regulations should acknowledge the reduc-tions that will be achieved by way of other futurecompliance actions for SOx and NOx emissions,and provide phase-in timeframes that considerdemand pressure on natural gas.

– Reduce barriers to alternate fuels by New SourceReview processes. Performance-based regula-tions should meet the emission limits requiredwithout limitations on equipment used or fuelchoices. State and federal regulators shouldensure that New Source Review processes, andNew Source Performance Standards in general, donot preclude technologies and fuels other thannatural gas when the desired environmental effi-ciency can be achieved.

• Expedite hydroelectric and nuclear power plant reli-censing processes. FERC, the Nuclear RegulatoryCommission, and other relevant federal, state, region-al, and local authorities should expedite relicensingprocesses for hydroelectric and nuclear power genera-tion facilities. These authorities should fully consider

the increased future requirements for natural gas-based generation in the affected regions that couldarise from conditions of approval or denial of relicens-ing. In the case of denial, adequate phase-in time spe-cific to the fuel type of replacement resources shouldbe provided to bring alternative generation resourcesonto the grid to replace non-renewed facilities.

• Take action at the state level to allow fuel flexi-bility.

– Ensure alternate fuel considerations in Inte-grated Resource Planning. Where IntegratedResource Planning is conducted at the state regu-latory agency level, state commissions shouldrequire adequate cost/benefit analysis of addingalternate fuel capability to gas only fired capacity.

– Allow regulatory rate recovery of switchingcosts. State PUCs should provide rate treatmentto recover fuel costs and increased fuel operating& maintenance costs when units switch to lessexpensive alternate fuels as matter of practice andpolicy, since the fuel switching either directly, orindirectly benefits ratepayers by reducing gasprice, and / or volatility through fuel switching.

– Support fuel backup. State executive agenciesshould ensure policies of state permitting agen-cies encourage liquid fuel back up for gas-firedpower generation, and encourage a balancedportfolio of fuel choices in power generation andindustrial applications.

• Incorporate fuel-switching considerations inpower market structures. RTOs, IndependentSystem Operators, and tight Power Pools shouldensure bidding processes and cost caps provideappropriate price signals to generation units capableof fuel switching. FERC should ensure that whole-sale power markets, containing any capacity compo-nents, should have market rules facilitating pricingof alternate fuel capability.

Additional Demand Considerations

There are additional actions and policy initiativesthat could be undertaken to create a more flexible andefficient consumer environment for natural gas, whileassuring environmental goals are achieved.

• Permit Reviews. State environmental agencies, inconsultation with the U.S. Environmental Protec-tion Agency, should review existing alternate fuelpermits, and opportunities for peak-load reductionduring non-ozone season. All new permits should


have maximum flexibility to use alternate fuels dur-ing all seasons, recognizing the ozone season mayrequire some additional limitations. During ozoneseason, cap and trade systems should govern theeconomic choices regarding fuel choice to the maxi-mum extent possible.

• Forums to Address Siting Obstacles. With respectto coordination among multiple levels of govern-ment, federal agencies should consider facilitatingforums to address obstacles to constructing newpower generation and industrial capacity.Participants would include the relevant federal,state, and local siting authorities, as well as plantdevelopers and operators, industrial consumers,environmental non-governmental organizations,fuel suppliers, and the public. The objective of theseforums would be to address with stakeholders theimpact of siting decisions on natural gas markets.

• Potential Limits on Carbon Dioxide Emissions.Ongoing policy debates include discussion of car-bon reduction, including potential curbs on CO2emissions. Many actions would constitute the mar-ket’s response to such limitations, including shut-down and/or re-configuration of industrialprocesses, additional emissions controls includingcarbon sequestration or the shifting of manufactur-ing to other countries.

Natural gas has lower CO2 emissions than other carbon-based fuels. Therefore, natural gas combus-tion technologies are likely to be a substantial aspectof the market’s response to limitations on CO2 emis-sions in industrial processes and power generation.The most significant impact of CO2 emission curbswould likely be restrictions in operation of much of thecoal-fired power generation, since coal-combustionprocesses tend to emit the highest levels of CO2.Depending on the level of emission restrictions, therequirements for natural gas in power generationalone could increase substantially. Alternatives tonatural gas would be additional nuclear powerand/or coal-fired generation employing carbonsequestration technologies that are unproven on alarge scale. Renewable electric generation capacity islikely to play a growing role in the future, but has notdemonstrated the ability to have a large impact.

This study tested the impacts on natural gas demandand the resulting market prices, by performing sen-sitivity analyses; the impact on gas demand could besignificant, as discussed elsewhere in this study,

depending on the degree to which carbon intensitymight be reduced. Natural gas consumption forpower generation would clearly increase under anyCO2 reduction scheme during the time frame of thisstudy, placing enormous demand pressure on natu-ral gas. This would likely lead to much higher natu-ral gas prices and industrial demand destruction.

• DOE Research. With respect to governmentresearch, the NPC is supportive of DOE researchwhere it complements privately funded researchefforts. DOE and state energy offices should contin-ue to support research and commercialization ofwind, solar, biomass, and other renewable genera-tion technologies. DOE should continue to supportgovernment and industry partnership in fundingimprovements such as advanced turbines, clean coal,carbon sequestration, distributed generation andrenewable technologies, as well as efficient use ofnatural gas should also be supported.

The lower-48 states currently supply about 80% ofthe natural gas consumed in the United States.Imports, primarily from Canada, provide about 20%,with LNG currently accounting for about 1% of totalU.S. demand. While North America has very sizablenatural gas resources, supplies from them are unlikelyto meet projected demand growth. As a result, newsources of supply must enter the market, and govern-ment policies must remove impediments that inhibitdelivery of the additional supplies.

These new supply sources can be broadly character-ized as:

• Lower-48 resources that are currently restricted orface permitting impediments

• North American Arctic gas

• Increased global LNG imports.

Support for all new supply sources is required tomeet the expected growth in natural gas demand. Therecommended actions to facilitate development ofthese new supply sources are summarized below.


Recommendation 2: Increase supply diversity

Increase Access and Reduce PermittingImpediments to Development ofLower-48 Natural Gas Resources

Land-use policies of federal, state, and local govern-ments have not kept pace with technological advancesthat allow for exploration and production while pro-tecting environmentally sensitive areas by reducing thenumber and size of onshore drilling sites and offshoreproduction facilities.

In addition, the federal government has continuedto set federal lands off-limits to development throughlegislation, executive orders, and regulatory andadministrative decisions. Moreover, an increasinglycomplex and costly maze of statutory and regulatoryrequirements effectively places a significant portion ofadditional lands off-limits to development, eventhough they are technically available for leasing.

The trend toward increased land restrictions and set-asides has been especially troublesome in the RockyMountain area. The NPC estimates that 25% of theremaining technical resource in the lower-48 underliesthe Rocky Mountain area, and that 29% (69 TCF) is cur-rently off-limits to exploration and development, eitherdue to statutory leasing withdrawals or to the cumulativeeffect of conditions of approval associated with explo-ration and development activities. Set asides are com-mon in the OCS, where virtually the entirety of theAtlantic and Pacific coasts are off limits due to executiveorder and most of the Eastern Gulf of Mexico is off lim-its due to administrative decisions. Most recently, furtherrestrictions were set in place when the original bound-aries of the 2001 OCS Lease Sale 181 were reduced toinclude only 25% of the originally proposed acreage.

Experience shows that natural gas development inareas similar to those restricted in the United States canbe undertaken with appropriate environmental safe-guards. The use of state-of-the-art drilling and pro-duction technologies plays a key role in thosedevelopments. Mountainous areas of western Canada,which face fewer federal and provincial barriers toaccess, have been successfully developed without com-promising the environment. The OCS of EasternCanada is being successfully and safely developed, andthe governments of British Columbia and Canada arereviewing the potential to open offshore WesternCanada for exploration and development.

The NPC recognizes and supports the obligations ofstate and federal governments to protect endangered

species, historical resources, and the environment. Atthe same time, the NPC sees the need for governmentto balance those considerations with the need toincrease supplies of natural gas.

The following public-policy recommendations aredesigned to foster balance by streamlining processes,improving communications, enhancing cooperation,acknowledging proven technological advances, andreducing unnecessary costs and delays for the indus-try and the various government agencies and non-governmental organizations involved with addressingthese issues. The recommendations are segregatedinto onshore and offshore.

Onshore – Increase Access (ExcludingDesignated Wilderness Areas and NationalParks) and Reduce Permitting Costs/Delays50% over Five Years

The following recommendations will reduce permit-ting response time by streamlining processes, insti-tuting performance metrics, clarifying statutoryauthority, and ensuring adequate agency resourcing.

• Improve government land-use planning. Gov-erning agencies should use Reasonable ForeseeableDevelopment scenarios as planning tools ratherthan to establish surface disturbance limitations.Land use planning and project monitoring shouldbe a priority in order to facilitate timely plan revi-sions and project permitting.

• Expedite leasing of nominated and expired tracts.The federal government should expedite the leasingof nominated tracts and expired leases. This can befacilitated by use of existing planning documentsand reducing requirements for extraneous environ-mental analysis where appropriate.

• Expand use of categorical exclusions or sundrynotices as alternatives to processes imposed by theNational Environmental Policy Act (NEPA). Everysurface disturbance activity requires environmentalanalysis prior to permitting. NEPA costs and delayscan be reduced through the use of categorical exclu-sions or sundry notices instead of environmentalassessments for minimal disturbance activities andthrough improvement of data sharing and coordina-tion by state and federal land management agencies.

• Streamline and expedite permitting processes.The permitting process should be streamlined by


establishing performance goals for each office,reducing on-site inspections, increasing use ofsundry notices in lieu of Application for Permit toDrill (APD), and using dedicated teams to supporthigh workload field offices. This should be contin-uously monitored and refined by efficient and com-prehensive reporting, benchmarking, and bestpractices programs within the Bureau of LandManagement and Forest Service, etc.

• Establish cultural resource report standards andeliminate duplicate survey requirements. This isthe most frequent cause of delays and expense forAPD and right-of-way approvals. Significant costreductions and time savings can be realized by elim-inating duplicate surveys, developing clear standardsfor determining site significance, and establish clearcultural report review requirements among govern-ing agencies.

• Establish qualification requirements and technicalreview procedures for nomination of endangeredspecies. There currently exists no qualificationrequirements to nominate a species for listing, andonce nominated, these species are given the sameprotection as listed endangered species. This resultsin delays to land management planning and projectpermitting until a ruling on the nominated species.It is recommended that this process be changed toestablish qualification requirements and technicalreview procedures to prevent such unwarranteddelays.

• Fund and staff federal agencies at levels, and inmanners, appropriate for timely performance ofresponsibilities. Federal land management agenciesneed to ensure adequate resources to efficiently han-dle responsibilities for updating land use plans,administering the NEPA process, processing leaseand permit applications, and resolving appeals andprotests in a timely manner. The Bureau of LandManagement should consider the formation of ded-icated teams to assist field offices with high permit-ting workloads.

Offshore – Lift Moratoria on Selected Areas ofthe Federal OCS by 2005

Resources in the Eastern Gulf of Mexico and off theAtlantic and Pacific coasts are currently not accessible

due to leasing moratoria. The following recommenda-tions are proposed for these stranded resources:

• Lift, in a phased manner, moratoria on selectedOCS areas having high resource-bearing potential.Federal and coastal state governments, working withindustry and other stakeholders, should develop a planto identify current moratoria areas of the Eastern Gulfof Mexico and Atlantic and Pacific Coasts containing ahigh resource potential, with a view toward lifting themoratoria in a phased approach beginning in 2005.

• Update resource estimates for MMS-administeredareas. The federal government (Minerals Manage-ment Service) should coordinate the development ofupdated estimates of natural gas resources underly-ing the OCS submerged lands and identify the datagathering activities that could be undertaken toimprove the technical support for this estimate.

Currently accessible areas of the Gulf of Mexico pro-vide the United States with 23% of its natural gas sup-ply. The following recommendations are proposed toensure the continued supply of this critical resource:

• Ensure continued access to those OCS areas identi-fied in the 2002-2007 5-Year Leasing Program.

• Ensure that Marine Protected Areas are meetingtheir intended purposes. Regulatory requirementsfor protection of marine species should be based on thebest available scientific analysis to avoid inappropriateor unnecessary action having uncertain benefit to theintended species. Lease stipulations and operationalmeasures should be practical, cost effective, and aimedto achieve minimal delays in ongoing operations.

• Require federal and state joint development ofCoastal Zone Management (CZM) Plans. Ensurethat federal and state authorities improve coordinateddevelopment and review of CZM Plans to under-stand the impact on federally authorized and regu-lated OCS activities. If a state alleges that a proposedactivity is inconsistent with its CZM Plan, it shouldbe required to specifically detail the expected effects,demonstrate why mitigation is not possible, andidentify the best available scientific information andmodels which show that each of the effects are “rea-sonably foreseeable.” The Secretary of Commerceshould not approve state CZM Plans if such imple-mentation would effectively ban or unreasonablyconstrain an entire class of federally authorized andregulated activities, such as gas drilling, production,and transportation.


Enact Enabling Legislation in 2003 for an Alaska Gas Pipeline

The Arctic regions of Alaska and NorthwesternCanada contain significant volumes of discovered gasresources, which have the potential to supply NorthAmerica with 8% of projected demand in 2015. Whilethese resources were discovered over 30 years ago, sev-eral hurdles (costs, permitting, state fiscal certainty,market risks) have prevented their development.Currently pending enabling legislation, which at aminimum would provide regulatory certainty, createsan opportunity to take action and to ensure the legisla-tive requirements of such a massive infrastructureproject are met.

The projections in this study are generally favorablefor development of Arctic resources. Based on theseprojections, the NPC has assumed that both theMackenzie Delta pipeline and the Alaska pipeline areconstructed in a “success case” time period, withMackenzie gas initiating production in 2009 and Alaskain 2013. The timetable for Alaska gas is very aggressive,and can only be met with prompt government action.

Infrastructure projects of this magnitude require thefollowing:

• Congress should enact enabling legislation in 2003for an Alaska gas pipeline. Passage of this legisla-tion in 2003 is required to support deliveries of thisgas to the market in 2013. Council members andPrudhoe Bay producers agree that Congress shouldimmediately enact legislation that provides regula-tory certainty to such a project.

• Canadian agencies should develop and implementa timely regulatory process. The various govern-ments in Canada (federal, territorial, provincial) andthe First Nations should continue to work coopera-tively to develop and implement a timely regulatoryprocess. An efficient process must be in place inearly 2004 to support a 2009 Mackenzie gas projectstart-up and a 2013 Alaska gas pipeline project start-up.

• Alaska needs to provide fiscal certainty for theproject. The state of Alaska should provide fiscalcertainty to project sponsors in a manner that issimple, clear, not subject to change, and that canimprove project competitiveness. Such action by theAlaska legislature in 2004 is required to support a2013 project start-up.

• Governments should refrain from potentiallyproject-threatening actions. Governments shouldavoid imposing mandates or additional restrictionsthat could increase costs and make it more difficultfor a project to become commercially viable.

• Infrastructure improvements incidental to Alaskagas pipeline construction must be planned in a time-ly and coordinated manner. The U.S. and Canadiangovernments – federal, state, provincial, and territor-ial – should study and/or consult with one anotherand industry participants and affected communities toassess contemplated infrastructure improvements insupport of Arctic gas development in advance of thetime when these improvements are needed.

Process LNG Project Permit ApplicationsWithin One Year

The North American resource base has met the nat-ural gas demands of Canada, Mexico, and the UnitedStates to date. However, this is not expected to contin-ue and increased imports of LNG will be required tomeet growing demand. LNG provides access to theglobal supply of natural gas, which has been estimatedto contain over 30 times the resource volume of NorthAmerica. Advances in liquefaction and transportationtechnologies have driven down the unit cost of LNG by30% over the past decade and LNG is now viewed ascost competitive with domestic supplies. To meetfuture demand, the NPC is projecting LNG importswill grow to become 14-17% of the U.S. natural gassupply by 2025. This will require the construction ofseven to nine new regasification terminals and expan-sions of three of the four existing terminals.

This aggressive outlook for LNG import terminalconstruction will require streamlined permitting andconstruction to achieve the projected buildup.Expediting the approval process throughout all agen-cies (federal, state, and local) is critical to overcome themany obstacles that may surface, including local oppo-sition. Leveraging off the recent positive shifts byFERC (positive changes on regulatory process, activeleadership role in recent reactivation of Cove Point andElba Island, and implementation of Memorandums ofUnderstanding [MOUs] among federal agencies work-ing together) and changes made to regulatory policiesin late 2002 governing both onshore and offshore LNGimport terminals, will provide a springboard forimpacting positive changes down through the locallevel. The goal of the following recommendations is to


reduce the time required for LNG facility permitting toone year.

• Agencies must coordinate and streamline their per-mitting activities and clarify positions on new termi-nal construction and operation. Project sponsorscurrently face multiple, often-competing state andlocal reviews that lead to permitting delays. A coordi-nated effort among federal, state, and local agenciesled by FERC would reduce permitting lead time.Similarly, streamlining the permitting process by shar-ing data and findings, holding concurrent reviews, andsetting review deadlines would provide greater cer-tainty to the overall permitting process. FERC shouldfurther clarify its policy statement on new terminals soas to be consistent with corresponding regulationsunder the Deep Water Port Act, including timing forthe NEPA review process and commercial terms andconditions related to capacity rights.

• Fund and staff regulatory agencies at levels neces-sary to meet permitting and regulatory needs in atimely manner. The expected increase in the num-ber of terminal applications will require higher lev-els of government support (federal, state, and local)to process and avoid delays. Additional agencyfunding/staffing will also be required once these newterminals become operational, particularly to sup-port the large increase in LNG tanker traffic.

• Update natural gas interchangeability standards.Standards for natural gas interchangeability in com-bustion equipment were established in the 1950s.The introduction of large volumes of regasified LNGinto the U.S. supply mix requires a re-evaluation ofthese standards. FERC and DOE should championthe new standards effort to allow a broader range ofLNG imports. This should be conducted with par-ticipation from LDCs, LNG purchasers, process gasusers, and original equipment manufacturers(OEMs). DOE should fund research with these par-ties in support of this initiative.

• Undertake public education surrounding LNG.The public knowledge of LNG is poor, as demon-strated by perceptions of safety and security risks.These perceptions are contributing to the publicopposition to new terminal construction and jeop-ardizing the ability to grow this required supplysource. Industry advocacy has begun, but a moreaggressive/coordinated effort involving the DOEand non-industry third parties is required.Emphasis should focus on understandings, safety,

historical performance, and the critical role thatLNG can play in the future energy supply.

• LNG industry standards should be reviewed andrevised if necessary. In order to promote the high-est safety and security standards and maintain theLNG industry’s safety record established over thepast forty years of operations, FERC, the CoastGuard, and the U.S. Department of Transportationshould undertake the continuous review and adop-tion of industry standards for the design and con-struction of LNG facilities, using internationallyproven technologies and best practices.

Additional Supply Considerations

There are additional actions and policy initiatives thatcould be undertaken to potentially enhance supplysources. Among those are the role played by tax and otherfiscal incentives or packages, and the desirability of addi-tional government-sponsored research spending.

Two strongly held views of fiscal incentives emergedduring the study team discussions. Supporters of suchincentives believe additional production would resultfrom pursuit of marginal opportunities and/or highcost supply alternatives, helping to ease the tight sup-ply/demand balance. Others believe market forces areand will be sufficient to stimulate additional invest-ment without the need for tax-related incentives orsubsidies. Potential fiscal incentives such as tax creditsfor nonconventional resource development, low-Btugas, stripper oil well and deep gas drilling incentives,and an Alaska pipeline fiscal package were discussed,but the NPC makes no recommendation in this regard.

With respect to government research, the NPC issupportive of a role for DOE in upstream research,particularly where it complements privately fundedresearch efforts. DOE’s natural gas research programhas a significant role in technical studies and relatedwork that support public policy decision-makingregarding natural gas supply. DOE currently spendsabout $50 million per year on jointly sponsored natu-ral gas technology research. This represents 53% of thefunding for oil and gas research, but only 9% of thefunds directed at fossil energy programs in total. TheNPC believes DOE should evaluate whether this levelof funding is appropriate in relation to other DOE pro-grams in light of the increasing challenges facing natu-ral gas. Further discussion of this issue is included inthe Technology Section of the Supply Task Groupreport.


Although the United States and Canada have anextensive pipeline, storage, and distribution network,additional infrastructure and increased maintenancewill be required to meet the future needs of the naturalgas market. The recommended actions listed below arerequired to ensure efficient pipeline, storage, and dis-tribution systems.

Federal and State Regulators Should ProvideRegulatory Certainty by Maintaining aConsistent Cost Recovery and ContractingEnvironment Wherein the Roles and Rules areClearly Identified and Not Changing.

Regulators must recognize that aging infrastructurewill need to be continuously maintained and upgradedto meet increasing throughput demand over the studyperiod. They must also recognize that large investmentswill be required for the construction of new infrastruc-ture. To make the kinds of investments that will berequired, operators and customers need a stable invest-ment climate and distinguishable risk/reward opportu-nities. Changes to underlying regulatory policy, afterlong-term investments are made, increase regulatoryand investment risk for both the investor and cus-tomers.

Complete Permit Reviews of MajorInfrastructure Projects within a One-YearPeriod Using a “Joint Agency Review Process.”Projects that Connect Incremental Supply andEliminate Market Imbalances Should Be theHighest Priority and Be Expedited.

Where available supply is constrained, FERC shouldexpedite timely infrastructure project approvals thatwill help mitigate the current supply/demand imbal-ance. Longer term, new project reviews should beexpedited via continuing enhancement and increasedparticipation in a Joint Agency Review Process, similarto that which FERC has utilized recently. A JointAgency Review would require the up-front involve-ment by all interested/concerned parties includingappropriate jurisdictional agencies. This will allow thedecision process to proceed to approval and imple-

mentation more accurately, more timely, and at loweroverall cost. The final FERC record should resolve allconflicts. The areas of greatest concern in this regardare requirements of the U.S. Army Corps of Engineers,Coastal Zone Management Act, and Section 401 of theClean Water Act, all of which could hinder the orderlyimplementation of FERC certificates. This processmust also assure that a project, which has used andsuccessfully exited this process, may proceed per thedirection received and will not be delayed by non-participating parties or other external regulatory stan-dards or processes. This suggestion is a more-specificrendering of the 1999 NPC study’s fifth recommenda-tion: “Streamline processes that impact gas develop-ment.” The NPC supports legislation that accom-plishes the “Joint Agency Review Process” as describedabove. Regulators at federal, state, and local levels, withcooperation of all participating parties, should estab-lish processes and timelines that would complete theregulatory review and approval process within 12months of filing.

Regulatory Policies Should Address theBarriers to Long-Term, Firm Contracts forEntities Providing Service to Human NeedsCustomers.

Many LDCs will not enter into long-term contracts intoday’s market out of fear that regulators may subse-quently deem them imprudent in the future. Similarly,power producers, especially those that provide peakingservice, are reluctant to contract for firm pipeline serv-ice because charges for firm service cannot be economi-cally justified in power sales. As discussed in Finding 9of this report, this practice is impairing the investmentin infrastructure. The result is that regulatory practicesthat limit long-term contracts inhibit efficient marketsand discourage the development and enhancement ofpipeline infrastructure. The regulatory process mustallow markets to transmit the correct price signals andenable market participants to respond appropriately.Regulators should encourage, at all levels of regulation,policies that endorse the principles of reliability andavailability of the natural gas commodity. All regula-tory bodies should recognize the importance of long-term, firm capacity contracts for entities providingservice to human needs customers and remove impedi-ments for parties to enter into such contracts.


Recommendation 3: Sustain and enhancenatural gas infrastructure

FERC Should Allow Operators to ConfigureTransportation and Storage Infrastructure andRelated Tariff Services to Meet ChangingMarket Demand Profiles.

At the interstate level, FERC should continue toallow and expand flexibility in tariff rate and serviceofferings and continue to allow market-based ratesfor storage service where markets are shown to becompetitive so that all parties can more accuratelyvalue services and make prudent contracting deci-sions. To ensure that existing and future transmis-sion, distribution, and storage facilities can beadapted to meet the significantly varying load pro-files of increased gas-fired generation, FERC andstate regulators need to allow and encourage opera-tors to optimize existing and proposed pipeline andstorage facilities. In some cases, this will require asignificantly more flexible facilities design basedupon peak hourly flow requirements, i.e., a modifica-tion to existing facilities to provide for optimizingstorage injections in off-peak hours or in shouldermonths.

Regulators Should Encourage CollaborativeResearch into More Efficient and LessExpensive Infrastructure Options.

Funding for collaborative industry research anddevelopment is in the process of switching from anational tariff surcharge-funded basis to voluntaryfunding. Because of the benefits of reduced costs, sys-tem reliability, integrity, safety and performance, DOEshould continue funding for collaborative research.Regulators need to encourage and remove impedi-ments regarding cost recovery of prudently incurredR&D expenses by the operators who fund necessarycollaborative infrastructure research.

North American natural gas markets are relativelyefficient and effective but can be improved.Government should allow market forces to work inaddressing the efficiency of markets, particularly asrelated to liquidity. Recommendations to improve the

market’s efficiency and effectiveness are summarizedbelow.

Improve Transparency of Price Reporting

Federal and state regulators should support trans-parency in market transactions by encouraging marketparticipants to report transactions voluntarily to pricereporting services. The Council recognizes and sup-ports the FERC’s ongoing efforts to improve markettransparency and voluntary price reporting.

Expand and Enhance Natural Gas Market DataCollection and Reporting

• DOE’s Energy Information Administration shouldreduce the lag in their reported natural gas dataseries by one month, with a target of storage dataone month in arrears and two months for supplyand demand data. EIA should coordinate effortswith state and other federal agencies (MMS) toimprove data-collecting processes. Involvement ofthe MMS to provide timely production data is criti-cal, given the key role Gulf of Mexico productionplays in the total U.S. supply.

• DOE/EIA should extend the weekly natural gas stor-age survey to encompass all storage fields currentlysurveyed monthly to ensure adequate data necessaryto analyze the changing nature of peak demands inwinter and power-driven demand in the summer.The current survey method is predicated on reser-voir size and omits too many salt dome facilitieswith their high cycling capability.

Stewardship of Recommendations

In order to monitor the progress of implementingthe NPC study recommendations, it is proposed thatthe DOE lead a workshop by May 2004 with govern-ment stakeholders and industry representatives. Thisworkshop would review the steps taken for each ofthe study recommendations and identify additionalactions required to achieve the objectives of thestudy.

It is also proposed that the DOE lead a workshop byyear-end 2004 to review actual supply and demandperformance and compare with the study outlook.This workshop would highlight any performance devi-ations from the study projections and identify poten-tial implications for any such changes.


Recommendation 4: Promote efficiency of natural gas markets

Future Work and Studies

The NPC study was a comprehensive analyticalreview of the North American natural gas market,including detailed assessments of supply sources,demand outlooks, and infrastructure requirements.While conducting the study, opportunities for addi-tional activities were identified that could build on thestudy analysis and position the NPC in the eventanother major study of North American natural gas isundertaken. Areas for future work include the following.

Resource Base Assessment

• Rockies Nonconventional Assessment. There cur-rently exist significant differences between publishedassessments of the Rockies nonconventionalresource. This is the region of the onshore lower-48states with the largest remaining resource potentialand also the largest range of uncertainty. It is pro-posed that a study be initiated in 2004, involving theDOE, USGS, and industry, to better understand thedifferences in assessments and see if a more consis-tent assessment can be developed.

• Resource Assessment Methodology. Resourceassessments are conducted by many organizationsusing various methodologies. The resource is gener-ally categorized as proved reserves, future apprecia-tion of the proved reserves in producing fields, andundiscovered resource potential. It is proposed thata study be initiated in 2004, involving the DOE,USGS, MMS, and industry to improve the under-standing of the various methodologies with anobjective of establishing a preferred approach forfuture assessments. This would include methodolo-gies for assessing both the technical and commercialresource base.

• Resource Base Collaboration. The USGS and MMSconduct periodic assessments of the U.S. resourcebase. During development of the NPC studyresource base, the benefits of industry and govern-ment collaborating on such assessments was a keylearning and it is proposed that such collaborationscontinue for future updates to improve alignment.In addition, since the last complete assessment of theU.S. resource base by the USGS is from 1995, it issuggested that the USGS establish a new compre-hensive reference assessment utilizing the recentregional updates.

• DOE/EIA Energy Outlooks. The DOE’s EIA con-ducts annual energy outlooks for the United States,

utilizing a methodology with common componentsto the NPC study. It is proposed that appropriatefindings from the NPC study be incorporated intofuture annual energy outlooks to improve alignmentof outlooks. Initial collaboration is currently under-way and is expected to continue past the completionof the study.

Econometric Modeling Efforts

As part of the study, a modeling team was created toconstruct a comprehensive dynamic equilibriummodel of the North American natural gas and powermarkets. This work advanced the NPC’s ability tomodel the natural gas market. To build on theseefforts, the following are proposed:

• Model Availability. Work is expected to continue bythe modeling team beyond the completion of thestudy to finalize the modeling effort and to make themodel available to NPC members and potentiallythe DOE if desired.

• Data Maintenance. Extensive efforts went intobuilding the supply components of the model. It isproposed that the USGS assume responsibility formaintaining the resource assessments and supplycurves in the model as updates become available.

Gas and Power Demand Data Collection andReporting for Industrial Processes and PowerGeneration

• EIA Surveys. The EIA should conduct two annualsurveys, one for power generation and one forindustrial applications. These surveys should tar-get the underlying attributes of the industry’s phys-ical ability to switch fuel and its actual practice inswitching. Units that can switch should be catego-rized. For example, the EIA should modify itsForm 860 to:

– Reflect most recent date any alternate fuel wasconsumed for purposes other than testing andwhich of the listed fuels was consumed

– Indicate whether alternate fuel usage is limited bypermit; and if so, the approximate number ofhours capable of being used annually

– Specify oil storage capability and average inven-tory when it is categorized as the alternate fuel.

• North American Reliability Council ReliabilityAssessments. The North American Reliability


Council should add natural gas supply issues to itsregional assessments for reliability purposes.

– Alternate fuel capabilities should be identifiedand reported.

– Gas-fired only capacity should be identified as topercentage of megawatt capacity with firm trans-portation contracted.

LNG Global Assessment

Given the importance of LNG in North America’snatural gas future, DOE should sponsor a follow-on

study to assess the worldwide market dynamics forLNG, and the inter-relationships with NorthAmerican supply and demand. Work should focuson developing a better understanding of the resourcebases, prospects for development of various overseassupplies, cost competitiveness, and the possible rolefor government policies to encourage market-drivendevelopment. The LNG summit planned by DOE forthis fall would be an appropriate starting point forsuch an effort, which should aim for a Fall 2004delivery.


SUMMARY - APPENDIX A A-1

APPENDIX A

SUMMARY - APPENDIX AA-2


DESCRIPTION OF THE NATIONAL PETROLEUM COUNCIL

In May 1946, the President stated in a letter to the Secretary of the Interior that he had been impressed by the contri-bution made through government/industry cooperation to the success of the World War II petroleum program. Hefelt that it would be beneficial if this close relationship were to be continued and suggested that the Secretary of theInterior establish an industry organization to advise the Secretary on oil and natural gas matters.

Pursuant to this request, Interior Secretary J. A. Krug established the National Petroleum Council (NPC) on June 18,1946. In October 1977, the Department of Energy was established and the Council was transferred to the new de-partment.

The purpose of the NPC is solely to advise, inform, and make recommendations to the Secretary ofEnergy on any matter, requested by the Secretary, relating to oil and natural gas or the oil and gas industries. Matters that the Secretary of Energy would like to have considered by the Council are submitted in theform of a letter outlining the nature and scope of the study. The Council reserves the right to decide whether it willconsider any matter referred to it.

Examples of studies undertaken by the NPC at the request of the Secretary of Energy include:

The NPC does not concern itself with trade practices, nor does it engage in any of the usual trade association activi-ties. The Council is subject to the provisions of the Federal Advisory Committee Act of 1972.

Members of the National Petroleum Council are appointed by the Secretary of Energy and represent all segments ofthe oil and gas industries and related interests. The NPC is headed by a Chair and a Vice Chair, who are elected bythe Council. The Council is supported entirely by voluntary contributions from its members.

•Factors Affecting U.S. Oil & Gas Outlook (1987)

• Integrating R&D Efforts (1988)

•Petroleum Storage & Transportation (1989)

• Industry Assistance to Government – Methods for Providing Petroleum Industry Expertise During Emergencies (1991)

•Short-Term Petroleum Outlook – An Examination of Issues and Projections (1991)

•Petroleum Refining in the 1990s – Meeting the Challenges of the Clean Air Act (1991)

•The Potential for Natural Gas in the United States (1992)

•U.S. Petroleum Refining – Meeting Requirements for Cleaner Fuels and Refineries (1993)

•The Oil Pollution Act of 1990: Issues and Solutions (1994)

•Marginal Wells (1994)

•Research, Development, and Demonstration Needs of the Oil and Gas Industry (1995)

•Future Issues – A View of U.S. Oil & Natural Gas to 2020 (1995)

• Issues for Interagency Consideration – A Supplement to the NPC’s Report: Future Issues – A View of U.S. Oil & Natural Gas to 2020 (1996)

•U.S. Petroleum Product Supply – Inventory Dynamics (1998)

•Meeting the Challenges of the Nation’s Growing Natural Gas Demand (1999)

•U.S. Petroleum Refining – Assuring the Adequacy and Affordability of Cleaner Fuels (2000)

•Securing Oil and Natural Gas Infrastructures in the New Economy (2001).



MEMBERSHIP

2002/2003

Jacob AdamsPresidentArctic Slope Regional Corporation

George A. Alcorn, Sr.PresidentAlcorn Exploration, Inc.

Conrad K. AllenPresidentNational Association of Black Geologists and Geophysicists

Robert J. Allison, Jr.Chairman, President and Chief Executive OfficerAnadarko Petroleum Corporation

Robert O. AndersonRoswell, New Mexico

Philip F. AnschutzPresidentThe Anschutz Corporation

Gregory L. ArmstrongChairman and Chief Executive OfficerPlains All American

Robert G. ArmstrongPresidentArmstrong Energy Corporation

Gregory A. ArnoldPresident and Chief Operating OfficerTruman Arnold Companies

Ralph E. BaileyChairman and Chief Executive OfficerAmerican Bailey Inc.

Robert W. BestChairman of the Board, President and Chief Executive OfficerAtmos Energy Corporation

M. Frank BishopExecutive DirectorNational Association of State Energy Officials

Alan L. BoeckmannChairman and Chief Executive OfficerFluor Corporation

Carl E. Bolch, Jr.Chairman and Chief Executive OfficerRacetrac Petroleum, Inc.

Donald T. BollingerChairman of the Board and Chief Executive OfficerBollinger Shipyards, Inc.

John F. BookoutHouston, Texas

Wayne H. BrunettiChairman, President and Chief Executive OfficerXcel Energy Inc.

Philip J. BurguieresChief Executive OfficerEMC Holdings, L.L.C.

Victor A. BurkManaging PartnerOil & Gas DivisionDeloitte & Touche LLP

Frank M. Burke, Jr.Chairman and Chief Executive OfficerBurke, Mayborn Company, Ltd.



Karl R. ButlerPresident and Chief Executive OfficerICC Energy Corporation

Thos. E. CappsChairman, President and Chief Executive OfficerDominion

Robert B. CatellChairman and Chief Executive OfficerKeySpan

Clarence P. Cazalot, Jr.PresidentMarathon Oil Company

Luke R. CorbettChairman and Chief Executive OfficerKerr-McGee Corporation

Michael B. CoulsonPresidentCoulson Oil Group

Gregory L. CraigPresidentCook Inlet Energy Supply

William A. CustardPresident and Chief Executive OfficerDallas Production, Inc.

Robert DarbelnetPresident and Chief Executive OfficerAAA

Charles D. DavidsonChairman, President and Chief Executive OfficerNoble Energy, Inc.

Claiborne P. DemingPresident and Chief Executive OfficerMurphy Oil Corporation

Cortlandt S. DietlerPresident and Chief Executive OfficerTransMontaigne Oil Company

Dan O. DingesChairman, President and Chief Executive OfficerCabot Oil & Gas Corporation

David F. DornChairman EmeritusForest Oil Corporation

E. Linn Draper, Jr.Chairman, President and Chief Executive OfficerAmerican Electric Power Co., Inc.

John G. DrosdickChairman, President and Chief Executive OfficerSunoco, Inc.

Archie W. DunhamChairman of the BoardConocoPhillips

W. Byron DunnPresident and Chief Executive OfficerLone Star Steel Company

Daniel C. EckermannPresident and Chief Executive OfficerLeTourneau, Inc.

James C. EllingtonChairmanThe Energy Council

James W. EmisonChairman and Chief Executive OfficerWestern Petroleum Company

Ronald A. EricksonChief Executive OfficerHoliday Companies

Sheldon R. EriksonChairman of the Board, President and Chief Executive OfficerCooper Cameron Corporation



Stephen E. EwingPresident and Chief Operating OfficerDTE Energy Gas

John G. FarbesPresidentBig Lake Corporation

Claire Scobee FarleyChief Executive OfficerRandall & Dewey, Inc.

G. Steven FarrisPresident and Chief Executive OfficerApache Corporation

William L. FisherBarrow Chair in Mineral Resources Department of Geological Sciences andDirector of the Jackson School of GeoscienceUniversity of Texas at Austin

James C. FloresChairman and Chief Executive OfficerPlains Exploration & Production Company

Eric O. FornellManaging Director and Group ExecutiveGlobal Natural Resources GroupJ. P. Morgan Securities Inc.

Joe B. FosterNon-executive ChairmanNewfield Exploration Company

Robert W. FriVisiting ScholarResources For the Future Inc.

Murry S. GerberPresident and Chief Executive OfficerEquitable Resources, Inc.

James A. GibbsChairmanFive States Energy Company

Rufus D. GladneyChairmanAmerican Association of Blacks in Energy

Lawrence J. GoldsteinPresidentPetroleum Industry Research Foundation, Inc.

Charles W. GoodyearChief Executive OfficerBHP Billiton Plc

Bruce C. GottwaldChairman of the BoardEthyl Corporation

Andrew GouldChairman and Chief Executive OfficerSchlumberger Limited

S. Diane GrahamChairman and Chief Executive OfficerSTRATCO, Inc.

William E. GreeheyChairman of the Board and Chief Executive OfficerValero Energy Corporation

Robbie Rice GriesPresidentAmerican Association of Petroleum Geologists

James T. HackettPresident and Chief Operating OfficerDevon Energy Corporation

Frederic C. HamiltonChairmanThe Hamilton Companies

Christine HansenExecutive DirectorInterstate Oil and Gas Compact Commission

Angela E. HarrisonChairman and Chief Executive OfficerWELSCO, Inc.



Lewis Hay, IIIChairman, President and Chief Executive OfficerFPL Group

Frank O. HeintzPresident and Chief Executive OfficerBaltimore Gas and Electric Company

John B. HessChairman, President and Chief Executive OfficerAmerada Hess Corporation

Jack D. HightowerPresident and Chief Executive OfficerCelero Energy LLC

Jerry V. HoffmanChairman, President and Chief Executive OfficerBerry Petroleum Company

Roy M. HuffingtonChairman of the Board and Chief Executive OfficerRoy M. Huffington, Inc.

Dudley J. HughesPresidentHughes South Corporation

Ray L. HuntChairman of the BoardHunt Oil Company

Hillard HuntingtonExecutive DirectorEnergy Modeling ForumStanford University

Frank J. IarossiChairmanAmerican Bureau of Shipping & Affiliated Companies

Ray R. IraniChairman and Chief Executive OfficerOccidental Petroleum Corporation

Eugene M. IsenbergChairman and Chief Executive OfficerNabors Industries, Inc.

Francis D. JohnChairman, President and Chief Executive OfficerKey Energy Services, Inc.

A. V. Jones, Jr.ChairmanVan Operating, Ltd.

Jon Rex JonesChairmanEnerVest Management Company, L. C.

Jerry D. JordanPresidentJordan Energy Inc.

Fred C. JulanderPresidentJulander Energy Company

John A. KanebChief Executive OfficerGulf Oil Limited Partnership

W. Robert KeatingCommissionerDepartment of Telecommunications and EnergyCommonwealth of Massachusetts

Bernard J. KennedyChairman EmeritusNational Fuel Gas Company

James W. KeyesPresident and Chief Executive Officer7-Eleven, Inc.

Richard D. KinderChairman and Chief Executive OfficerKinder Morgan Energy Partners, L.P.

Susan M. LandonPetroleum GeologistDenver, Colorado



Stephen D. LaytonPresidentE&B Natural Resources

Virginia B. LazenbyChairman and Chief Executive OfficerBretagne G.P.

Kathy Prasnicki LehneFounder, President and Chief Executive OfficerSun Coast Resources, Inc.

David J. LesarChairman of the Board, President and Chief Executive OfficerHalliburton Company

James D. LightnerChairman, President and Chief Executive OfficerTom Brown, Inc.

Michael C. LinnPresidentLinn Energy, LLC

Daniel H. LopezPresidentNew Mexico Institute of Mining and Technology

Thomas E. LoveChairman and Chief Executive OfficerLove’s Country Stores, Inc.

William D. McCabeVice PresidentEnergy ResourcesThermoEnergy Corporation

Aubrey K. McClendonChairman of the Board and Chief Executive OfficerChesapeake Energy Corporation

W. Gary McGilvrayPresident and Chief Executive OfficerDeGolyer and MacNaughton

Cary M. MaguirePresidentMaguire Oil Company

Steven J. MalcolmPresident and Chief Executive OfficerThe Williams Companies, Inc.

Timothy M. MarquezChief Executive OfficerMarqon Energy L.L.C.

Frederick R. MayerChairmanCaptiva Resources, Inc.

F. H. MerelliChairman, President and Chief Executive OfficerCimarex Energy Co.

C. John MillerChief Executive OfficerMiller Energy, Inc.

Merrill A. Miller, Jr.Chairman, President and Chief Executive OfficerNational Oilwell, Inc.

Herman Morris, Jr.President and Chief Executive OfficerMemphis Light, Gas & Water Division

Robert A. MosbacherChairmanMosbacher Energy Company

James J. MulvaPresident and Chief Executive OfficerConocoPhillips

John Thomas MunroPresidentMunro Petroleum & Terminal Corporation

David L. MurfinPresidentMurfin Drilling Co., Inc.

Marquez Energy L.L.C.



Mark B. MurphyPresidentStrata Production Company

William C. Myler, Jr.PresidentThe Muskegon Development Company

Gary L. NealeChairman, President and Chief Executive OfficerNiSource Inc.

J. Larry NicholsChairman of the Board and Chief Executive OfficerDevon Energy Corporation

John W. B. NorthingtonVice PresidentNational Environmental Strategies Inc.

Erle NyeChairman of the Board and Chief ExecutiveTXU Corp.

Christine J. OlsonChairman and Chief Executive OfficerS. W. Jack Drilling Company

David J. O'ReillyChairman of the Board and Chief Executive OfficerChevronTexaco Corporation

C. R. PalmerChairman of the BoardRowan Companies, Inc.

Mark G. PapaChairman and Chief Executive OfficerEOG Resources, Inc.

Paul H. ParkerVice PresidentCenter for Resource Management

Robert L. Parker, Sr.Chairman of the BoardParker Drilling Company

A. Glenn PattersonPresident and Chief Operating OfficerPatterson–UTI Energy Inc.

Ross J. PillariPresidentBP America Inc.

L. Frank PittsOwnerPitts Energy Group

Richard B. PrioryChairman, President and Chief Executive OfficerDuke Energy Corporation

Caroline QuinnMount Vernon, Illinois

Keith O. RattiePresident and Chf Executive OfficerQuestar Corporation

Lee R. RaymondChairman and Chief Executive OfficerExxon Mobil Corporation

John G. RicePresident and Chief Executive OfficerGE Power Systems

Corbin J. Robertson, Jr.PresidentQuintana Minerals Corporation

Robert E. RoseChairman of the BoardGlobalSantaFe Corporation

Henry A. Rosenberg, Jr.Chairman of the BoardCrown Central Petroleum Corporation

Robert J. RoutsFormer President and Country ChairmanShell Oil Company

Former Chairman and

Keith O. RattieChairman, President and

Chief Executive OfficerQuestar Corporation



Mark A. RubinExecutive DirectorSociety of Petroleum Engineers

Robert SantistevanDirectorSouthern Ute Indian Tribe Growth Fund

S. Scott SewellPresidentDelta Energy Management, Inc.

Bobby S. ShackoulsChairman, President and Chief Executive OfficerBurlington Resources Inc.

Scott D. SheffieldChairman, President and Chief Executive OfficerPioneer Natural Resources Company

Matthew R. SimmonsChairman and Chief Executive OfficerSimmons and Company International

Sam R. SimonPresident and Chief Executive OfficerAtlas Oil Company

Bob R. SimpsonChairman and Chief Executive OfficerXTO Energy Inc.

Bruce A. SmithChairman, President and Chief Executive OfficerTesoro Petroleum Corporation

Charles C. Stephenson, Jr.Chairman of the BoardVintage Petroleum, Inc.

J. W. StewartChairman, President and Chief Executive OfficerBJ Services Company

James H. StoneChairman of the BoardStone Energy Corporation

Carroll W. SuggsNew Orleans, Louisiana

Patrick F. TaylorChairman and Chief Executive OfficerTaylor Energy Company

James Cleo Thompson, Jr.PresidentThompson Petroleum Corporation

Gerald TorresAssociate Dean for Academic Affairs University of Texas School of Law andVice ProvostUniversity of Texas at Austin

Diemer TruePartnerTrue Companies, Inc.

H. A. True, IIIPartnerTrue Oil Company

Paul G. Van WagenenChairman, President and Chief Executive OfficerPogo Producing Company

Randy E. VelardePresidentThe Plaza Group

Thurman VelardeAdministratorOil and Gas AdministrationJicarilla Apache Tribe

Philip K. Verleger, Jr.PKVerleger, L.L.C.

Vincent ViolaChairman of the BoardNew York Mercantile Exchange

Joseph C. Walter, IIIPresidentWalter Oil & Gas Corporation

L. O. WardChairman and Chief Executive OfficerWard Petroleum Corporation



Wm. Michael Warren, Jr.Chairman, President and Chief Executive OfficerEnergen Corporation

J. Robinson WestChairman of the BoardThe Petroleum Finance Company

Michael E. WileyChairman, President and Chief Executive OfficerBaker Hughes Incorporated

Bruce W. WilkinsonChairman of the Board and Chief Executive OfficerMcDermott International, Inc.

Charles R. WilliamsonChairman of the Board and Chief Executive OfficerUnocal Corporation

Mary Jane WilsonPresident and Chief Executive OfficerWZI Inc.

Brion G. WiseChairman and Chief Executive OfficerWestern Gas Resources, Inc.

William A. WiseRetired ChairmanEl Paso Corporation

Donald D. WolfChairman of the Board and Chief Executive OfficerWestport Resources Corp.

George M. YatesPresident and Chief Executive OfficerHarvey E. Yates Company

John A. YatesPresidentYates Petroleum Corporation

Daniel H. YerginChairmanCambridge Energy Research Associates

Henry ZarrowVice Chairman

Sooner Pipe & Supply Corporation

Henry ZarrowVice Chairman

Sooner Pipe & Supply Corporation

SUMMARY - APPENDIX B B-1

STUDY GROUP ROSTERSSUMMARY

NPC Committee on Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-2

Coordinating Subcommittee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-5

Financial Team . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-7

Price Volatility Team . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-7

Modeling Team . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-8

Communications Team. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-9

Demand Task Group. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-10

Economics and Demographics Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . B-12

Power Generation Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-12

Residential and Commercial Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . B-13

Industrial Utilization Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-13

Supply Task Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-15

Resource Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-16

Technology Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-19

Environmental/Regulatory/Access Subgroup. . . . . . . . . . . . . . . . . . . . . . . B-19

LNG Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-21

Arctic Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-22

Transmission & Distribution Task Group . . . . . . . . . . . . . . . . . . . . . . . . . . . B-23

Transmission Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-24

Distribution Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-25

Storage Subgroup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-26

Additional Study Participants

The National Petroleum Council wishes to acknowledge the numerous other individuals andorganizations who participated in some aspects of the work effort through workshops, outreachmeetings and other contacts. Their time, energy, and commitment significantly enhanced thestudy and their contributions are greatly appreciated.

APPENDIX B

Supplemental Modeling Team

SUMMARY - APPENDIX BB-2


COMMITTEE ON NATURAL GAS

CHAIR

Bobby S. ShackoulsChairman of the Board, President and Chief Executive OfficerBurlington Resources Inc.

VICE CHAIR, DEMAND

Robert B. CatellChairman and Chief Executive OfficerKeySpan

VICE CHAIR, SUPPLY

Lee R. RaymondChairman and Chief Executive OfficerExxon Mobil Corporation

GOVERNMENT COCHAIR

Robert G. CardUnder Secretary of Energy

VICE CHAIR, MIDSTREAM

Richard D. KinderChairman and Chief Executive OfficerKinder Morgan Energy Partners, L.P.

SECRETARY

Marshall W. NicholsExecutive DirectorNational Petroleum Council

* * *


Conrad K. AllenPresidentNational Association of Black Geologists and Geophysicists

Robert J. Allison, Jr.Chairman, President and Chief Executive OfficerAnadarko Petroleum Corporation

Alan L. BoeckmannChairman and Chief Executive OfficerFluor Corporation

Wayne H. BrunettiChairman, President and Chief Executive OfficerXcel Energy Inc.

Thos. E. CappsChairman, President and Chief Executive OfficerDominion

Clarence P. Cazalot, Jr.PresidentMarathon Oil Company

Luke R. CorbettChairman and Chief Executive OfficerKerr-McGee Corporation

E. Linn Draper, Jr.Chairman, President and Chief Executive OfficerAmerican Electric Power Co., Inc.

Archie W. DunhamChairman of the BoardConocoPhillips


NPC COMMITTEE ON NATURAL GAS

Stephen E. EwingPresident and Chief Operating OfficerDTE Energy Gas

William L. FisherBarrow Chair in Mineral Resources Department of Geological Sciences andDirector of the Jackson School of GeoscienceUniversity of Texas at Austin

Eric O. FornellManaging Director and Group ExecutiveGlobal Natural Resources GroupJ. P. Morgan Securities Inc.

Robert W. FriVisiting ScholarResources For the Future Inc.

James A. GibbsChairmanFive States Energy Company

Andrew GouldChairman and Chief Executive OfficerSchlumberger Limited

James T. HackettPresident and Chief Operating OfficerDevon Energy Corporation

Lewis Hay, IIIChairman, President and Chief Executive OfficerFPL Group

Frank O. HeintzPresident and Chief Executive OfficerBaltimore Gas and Electric Company

Ray R. IraniChairman and Chief Executive OfficerOccidental Petroleum Corporation

Jon Rex JonesChairmanEnerVest Management Company, L. C.

Jerry D. JordanPresidentJordan Energy Inc.

Fred C. JulanderPresidentJulander Energy Company


W. Gary McGilvrayPresident and Chief Executive OfficerDeGolyer and MacNaughton

Steven J. MalcolmPresident and Chief Executive OfficerThe Williams Companies, Inc.

James J. MulvaPresident and Chief Executive OfficerConocoPhillips

Gary L. NealeChairman, President and Chief Executive OfficerNiSource Inc.

J. Larry NicholsChairman of the Board and Chief Executive OfficerDevon Energy Corporation

Erle NyeChairman of the Board and Chief ExecutiveTXU Corp.

Christine J. OlsonChairman and Chief Executive OfficerS. W. Jack Drilling Company

David J. O'ReillyChairman of the Board and Chief Executive OfficerChevronTexaco Corporation



Mark G. PapaChairman and Chief Executive OfficerEOG Resources, Inc.

Paul H. ParkerVice PresidentCenter for Resource Management

Robert L. Parker, Sr.Chairman of the BoardParker Drilling Company

Ross J. PillariPresidentBP America Inc.

Keith O. RattiePresident and Chief Executive OfficerQuestar Corporation

John G. RicePresident and Chief Executive OfficerGE Power Systems

Robert E. RoseChairman of the BoardGlobalSantaFe Corporation

Robert J. RoutsFormer President and Country ChairmanShell Oil Company

S. Scott SewellPresidentDelta Energy Management, Inc.

Matthew R. SimmonsChairman and Chief Executive OfficerSimmons and Company International

J. W. StewartChairman, President and Chief Executive OfficerBJ Services Company

Diemer TruePartnerTrue Companies, Inc.

Vincent ViolaChairman of the BoardNew York Mercantile Exchange

Wm. Michael Warren, Jr.Chairman, President and Chief Executive OfficerEnergen Corporation

J. Robinson WestChairman of the BoardThe Petroleum Finance Company

Charles R. WilliamsonChairman of the Board and Chief Executive OfficerUnocal Corporation

William A. WiseRetired ChairmanEl Paso Corporation

Daniel H. YerginChairmanCambridge Energy Research Associates

Keith O. RattieChairman, President and

Chief Executive OfficerQuestar Corporation



COORDINATING SUBCOMMITTEEOF THE


CHAIR

Jerry J. LangdonExecutive Vice President and Chief Administrative OfficerReliant Resources, Inc.

ASSISTANT TO THE CHAIR

Byron S. WrightVice PresidentStrategy and Capacity PricingEl Paso Pipeline Group

GOVERNMENT COCHAIR

Carl Michael SmithAssistant SecretaryFossil EnergyU.S. Department of Energy

ALTERNATE GOVERNMENT COCHAIR

James A. SlutzDeputy Assistant SecretaryNatural Gas and Petroleum TechnologyU.S. Department of Energy

SECRETARY

John H. Guy, IVDeputy Executive Director

National Petroleum Council


Keith BarnettVice PresidentFundamental AnalysisAmerican Electric Power Co., Inc.

Mark A. BorerExecutive Vice PresidentDuke Energy Field Services

Jon C. ColeVice PresidentBusiness Development and MarketingENSCO International Inc.

V. W. HoltVice PresidentOnshore U.S.BP America Production Inc.

Robert G. Howard, Jr.Vice PresidentNorth America UpstreamChevronTexaco Corporation

John Hritcko, Jr.Vice PresidentShell NA, LNG, Inc.Shell US Gas & Power Company


Paul D. KoonceSenior Vice PresidentPortfolio ManagementDominion Energy, Inc.

Patrick J. KuntzVice PresidentNatural Gas and Crude Oil SalesMarathon Oil Company

Paul D. KoonceChief Executive OfficerPortfolio ManagementDominion Energy, Inc.


Storage Management & System DesignKinder Morgan Inc.

Energy PolicyKeySpan

William N. StrawbridgeSenior Advisor

ExxonMobil Production Company

Mark T. MaasselVice PresidentRegulatory & Governmental PolicyNiSource Inc.

David J. ManningSenior Vice PresidentCorporate AffairsKeySpan

Thomas B. NuszVice PresidentAcquisitionsBurlington Resources Inc.

John E. OlsonSenior Vice President and Director of ResearchSanders Morris Harris

Scott E. ParkerPresidentNatural Gas Pipeline Company of America

Mark L. PeaseVice PresidentU.S. Onshore & OffshoreAnadarko Petroleum Corporation

Mark A. SikkelVice PresidentExxonMobil Production Company

Andrew K. SotoAdvisor to the ChairmanFederal Energy Regulatory Commission

Lee M. StewartSenior Vice PresidentGas TransmissionSouthern California Gas Company and San Diego Gas & Electric CompanySempra Energy Utilities

Lawrence H. TowellVice President, AcquisitionsKerr-McGee Corporation

Rebecca W. WatsonAssistant SecretaryLand and Minerals ManagementU.S. Department of the Interior

Dena E. WigginsGeneral CounselProcess Gas Consumers Group

Michael ZenkerDirectorNorth American Natural GasCambridge Energy Research Associates

SPECIAL ASSISTANTS

Ronald L. BrownVice PresidentStorage Management & System DesignKinder Morgan Inc.

Harlan ChappelleStaff Consultant – Energy PolicyKeySpan

William N. StrawbridgeSenior Advisor

ExxonMobil Production Company

COORDINATING SUBCOMMITTEE


COORDINATING SUBCOMMITTEE’S FINANCIAL TEAM

LEADERJohn E. Olson

Senior Vice President andDirector of Research

Sanders Morris Harris

Ronald S. BarrAdvisorExxonMobil Gas & Power Marketing Company

J. Michael BodellManagerStrategic Planning and Market AnalysisMidstream & TradeUnocal Corporation

Mark J. FinleySenior EconomistBP America Inc.

Edward J. GilliardSenior AdvisorPlanning and AcquisitionsBurlington Resources Inc.

Marianne S. KahChief EconomistConocoPhillips


John LutostanskiAssistant TreasurerExxonMobil Chemicals

Gary B. RennieVice PresidentTrading AnalyticsBP Energy Company

Barton D. SchouestManaging DirectorBanque BNP Paribas


COORDINATING SUBCOMMITTEE ‘S PRICE VOLATILITY TEAM

LEADERRonald S. Barr

AdvisorExxonMobil Gas &

Power Marketing Company

Keith BarnettVice PresidentFundamental AnalysisAmerican Electric Power Co., Inc.


COORDINATING SUBCOMMITTEE’S PRICE VOLATILITY TEAM



COORDINATING SUBCOMMITTEE’S SUPPLEMENTAL MODELING TEAM

LEADERAndrew J. Slaughter

Senior Economics Advisor – EP AmericasShell Exploration & Production Company

Meg O’Connor GentleManagerEconomics and ForecastingAnadarko Petroleum Corporation

Michael S. HuppSenior Energy Market AnalystDominion Resources

Kenneth B. Medlock, IIIVisiting Professor, Department of Economics and Energy Consultant to the James A. Baker III Institute for Public PolicyRice University

Walter C. RieseConsulting GeologistReservoir/Wells Assurance GroupOnshore U.S. Business UnitBP America Production Company

Gary H. TsangDevelopment PlannerExxonMobil Development Company

Loring P. WhiteExploration AdvisorExxonMobil Exploration Company

Seth S. RobertsRisk Manager – EnergyDow Hydrocarbons and Resources Inc.

Andrew J. SlaughterSenior Economics Advisor – EP AmericasShell Exploration & Production Company

Alan R. WigginsDirectorGas and Power Regulatory AffairsConocoPhillips

Leslie J. DemanDirectorFundamental Research and AnalysisShell Trading Gas & Power


Donald R. KnopEconomic and Planning ConsultantWilliams Gas Pipelines

COORDINATING SUBCOMMITTEE’S PRICE VOLATILITY TEAM


COORDINATING SUBCOMMITTEE’S COMMUNICATIONS TEAM

LEADERBrian W. Miller

DirectorU.S. Government and International Affairs

BP America Inc.

G. David BlackmonManagerCorporate AffairsBurlington Resources Inc.


Ben J. DillonManagerGovernemnt AffairsShell Exploration & Production Company

Kathleen E. EcclestonCommunications SpecialistMarathon Oil Corporation

Gina M. GibbsPublic Affairs ManagerDow Chemical Company


Bryan S. LeeCommunications SpecialistOffice of External AffairsFederal Energy Regulatory Commission

Mark R. MaddoxPrincipal Deputy Assistant SecretaryFossil EnergyU.S. Department of Energy

Megan K. MurphySpecial AssistantNatural Gas and Petroleum TechnologyU.S. Department of Energy

Sarah G. NovoselAssistant CounselFederal PolicyAmerican Electric Power Company

Kyle M. SawyerConsultantStrategyEl Paso Pipeline Group

Tricia L. ThompsonFederal Issues Advisor–UpstreamExxon Mobil Corporation

William F. WhitsittPresidentDomestic Petroleum Council


Ben J. DillonManagerGovernment AffairsShell Exploration & Production Company



DEMAND TASK GROUPOF THE


CHAIR

David J. ManningSenior Vice PresidentCorporate AffairsKeySpan



GOVERNMENT COCHAIR


ALTERNATE GOVERNMENT COCHAIR

Wade W. MurphyExecutive AssistantNatural Gas & Petroleum TechnologiesOffice of Fossil EnergyU.S. Department of Energy

SECRETARY

Benjamin A. Oliver, Jr.Senior Committee Coordinator

National Petroleum Council

Barry D. AndersonOperations ManagerEnergy Marketing & TradingFlorida Power & Light Company

Dennis M. BaileyDirectorEnergy PurchasingPPG Industries Incorporated

Keith BarnettVice PresidentFundamental AnalysisAmerican Electric Power Co., Inc



Mark S. CrewsDirectorSouthern Company

Leslie J. DemanDirectorFundamental Research & AnalysisShell Trading Gas & Power




Lee W. GoochVice PresidentNatural GasPCS Administration (U.S.A.), Inc.

R. William JewellBusiness Vice President – EnergyThe Dow Chemical Company



Diane G. LeopoldManaging DirectorBusiness Planning & Market AnalysisDominion Energy, Inc.

Charles W. LindermanDirectorEnergy Supply PolicyAlliance of Energy Suppliers(A Division of the Edison Electric Institute)

Ronald G. LukasVice PresidentTrading ServicesKeySpan

Steven W. MillerDirectorProject EvaluationSan Diego Gas & Electric

Vance C. MullisAssistant to the President and Chief Executive OfficerSouthern Company Gas


Charles Greer RossmannSenior Research EconomistResearch and Environmental AffairsSouthern Company

Mark C. SchroederVice PresidentRegulatory AffairsEl Paso Merchant Energy Group

Loren K. StarcherProject ManagerPGS – Power ProjectsExxonMobil Gas & Power Marketing Company

Jone-Lin WangDirectorNorth American Electric PowerCambridge Energy Research Associates


Byron S. WrightVice PresidentStrategy and Capacity PricingEl Paso Pipeline Group

DEMAND TASK GROUP



DEMAND TASK GROUP’S POWER GENERATION SUBGROUP

LEADERKeith BarnettVice President

Fundamental AnalysisAmerican Electric Power Co., Inc.

Barry D. AndersonOperations ManagerEnergy Marketing & TradingFlorida Power & Light Company

Robert W. AndersonEconomistBonneville Power Administration

Lane T. MahaffeyDirectorCorporate PlanningSeminole Electric Cooperative, Inc.


DEMAND TASK GROUP’S ECONOMICS AND DEMOGRAPHICS SUBGROUP

LEADERLeslie J. Deman

DirectorFundamental Research and Analysis

Shell Trading Gas & Power







Charles Greer RossmannSenior Research EconomistResearch and Environmental AffairsSouthern Company

Alan R. WigginsDirectorGas and Power Regulatory AffairsConocoPhillips

Byron S. WrightVice President

Strategy and Capacity PricingEl Paso Pipeline Group



DEMAND TASK GROUP’S INDUSTRIAL UTILIZATION SUBGROUP

LEADERDena E. WigginsGeneral Counsel

Process Gas Consumers Group

Dennis M. BaileyDirectorEnergy PurchasingPPG Industries Incorporated

Joseph G. BaranManagerStrategic Sourcing, EnergyPPG Industries Incorporated

Peggy R. ClaytorSenior Government Affairs SpecialistThe Timken Company



LEADERRonald G. LukasVice President

Trading ServicesKeySpan

Leslie J. DemanDirectorFundamental Research and AnalysisShell Trading Gas & Power



Laura E. TandyManagerStrategic PlanningKeySpan



Loren K. StarcherProject ManagerPGS – Power ProjectsExxonMobil Gas & Power Marketing Company

Jone-Lin WangDirectorNorth American Electric PowerCambridge Energy Research Associates

Lane T. MahaffeyDirectorCorporate PlanningSeminole Electric Cooperative, Inc.

DEMAND TASK GROUP’S RESIDENTIAL AND COMMERCIAL SUBGROUP


Terence J. BrennanPlanning AssociateFeedstock and EnergyExxonMobil Chemical Company




Terence J. BrennanPlanning AssociateFeedstock and EnergyExxonMobil Chemical Company


Keith S. ClausonDirectorNatural Gas Services and ProcurementAlcoa Incorporated

R. William JewellBusiness Vice President – EnergyThe Dow Chemical Company

Vince J. KwasniewskiValue Chain AnalystBP Feedstocks Americas Business UnitBP

Richard O. NotteVice PresidentEnergy ServicesAlcoa Primary Metals


Barney J. SumrallSenior Commercial Manager, Energy

The Dow Chemical Company

Peggy R. ClaytorSenior Government Affairs SpecialistThe Timken Company



Keith S. ClausonDirectorNatural Gas Services and ProcurementAlcoa Incorporated

DEMAND TASK GROUP’S INDUSTRIAL UTILIZATION SUBGROUP



SUPPLY TASK GROUPOF THE


CHAIR

Mark A. SikkelVice PresidentExxonMobil Production Company


William N. StrawbridgeSenior AdvisorExxonMobil Production Company

GOVERNMENT COCHAIR

Elena S. MelchertProgram ManagerOil & Gas ProductionOffice of Fossil EnergyU.S. Department of Energy

SECRETARY

John H. Guy, IVDeputy Executive DirectorNational Petroleum Council

* * *



G. David BlackmonManagerCorporate AffairsBurlington Resources Inc.

Randall L. CouchGeneral ManagerEngineering & TechnologyAnadarko Petroleum Corporation

David J. CrowleyVice President, MarketingTODCO



John Hritcko, Jr.Vice PresidentShell NA, LNG, Inc.Shell US Gas & Power Company

Patrick J. KuntzVice PresidentNatural Gas and Crude Oil SalesMarathon Oil Company

Ryan M. LanceVice President, Lower 48ConocoPhillips

Mark O. ReidVice PresidentOffshore Exploitation/DevelopmentEl Paso Production Company

Robert D. SchilhabManagerAlaska Gas DevelopmentExxonMobil Production Company


Andrew J. SlaughterSenior Economics Advisor – EP AmericasShell Exploration & Production Company

Brent J. SmolickVice President and Chief EngineerBurlington Resources Inc.

Robert W. StancilChief GeologistAnadarko Petroleum Corporation

SUPPLY TASK GROUP’S RESOURCE SUBGROUP

LEADER

Gerry A. WorthingtonProject Lead

North America Resource AssessmentExxonMobil Exploration Company

George A. Alcorn, Jr.Vice PresidentAlcorn Development Company

R. Marc BustinGeoscientistDepartment of Earth and Ocean SciencesThe University of British Columbia

Audis C. ByrdManagerGlobal TechnologyHalliburton Energy Services

Randall D. ClarkVice PresidentMarketing and Business DevelopmentNabors Drilling USA, LP

Thierry M. DeCortGeophysicist/GeoscientistResource EvaluationMinerals Management ServiceU.S. Department of the Interior

Glynn EllisTeam LeaderRegional Gulf of Mexico ExplorationEPX-W GOM Greenfield ExplorationShell Exploration & Production Company

SUPPLY TASK GROUP

Gary C. StoneRegional Geology CoordinatorExxonMobil Exploration Company

Chad A. TidwellStrategy ManagerBP America Production Inc.

Gerry A. WorthingtonProject LeadNorth America Resource AssessmentExxonMobil Exploration Company

Gene A. AydinianGeoscientistExxonMobil Production Company

Kenneth J. BirdGeologist/GeoscientistEarth Surface Processes TeamGeologic DivisionU.S. Geological SurveyU.S. Department of the Interior


L. Wayne ElsnerSenior GeologistGeology and Reserves GroupAlberta Energy and Utilities Board

Gary M. ForsthoffAsset AdvisorMid-Continent Business UnitChevronTexaco Production Company

James B. FraserGeneral ManagerExplorationBurlington Resources Inc.

J. Michael GatensPetroleum EngineerMGV Energy Ltd.

Meg O’Connor GentleManagerEconomics and ForecastingAnadarko Petroleum Corporation

Mitchell E. HenryGeoscientistEnergy Resources TeamU.S. Geological Survey

Matthew HumphreysGeologistBusiness DevelopmentMarathon Oil Company

Kenneth B. Medlock, IIIVisiting Professor, Department of Economics and Energy Consultant to the James A. Baker III Institute for Public PolicyRice University

George PinckneyTeam LeaderNorth Heavy Oil GeoscienceExxonMobil Canada Ltd.

Richard M. ProcterSenior AnalystCanadian Gas Potential Committee

Richard W. MittlerPrincipal GeologistBusiness DevelopmentEl Paso Production Company

Richard D. NehringPresidentNehring Associates

Harry E. Newman, Jr.Operations Support ManagerDrilling TechnicalExxonMobil Development Company

Michael A. OestmannChief GeoscientistPermian Gas Asset ManagerPure Resources, Inc.

Lee E. PetersenGeoscientistTechnology and Exploration PlanningAnadarko Petroleum Corporation

J. David HughesGeoscientistGeological Survey of CanadaNatural Resources Canada

Peter A. LarabeeGeoscientistUpstream Technical ComputingExxonMobil Exploration Company

Mitchell E. HenryGeoscientistEnergy Resources TeamU.S. Geological SurveyU.S. Department of the Interior

R. Curtis PhillipsSenior Professional Petroleum EngineerStrategic Planning–Business DevelopmentKerr-McGee Corporation

Robert C. MiliciResearch GeologistEastern Energy Resources TeamU.S. Geological SurveyU.S. Department of the Interior

Robert A. MeneleyGeoscientistIndependent ConsultantCanadian Gas Potential Committee

Ray A. MissmanReservoir EngineerExxonMobil Production Company


Christopher J. SchenkSupervisor/GeoscientistU.S. Geological Survey

Pulak K. RayChief GeologistMinerals Management ServiceU.S. Department of the Interior

Mark O. ReidVice PresidentOffshore Exploitation/DevelopmentEl Paso Production Company

Eugene G. RhodesConsultant GeologistBusiness DevelopmentEl Paso Production Company

Walter C. RieseConsulting GeologistReservoir/Wells Assurance GroupOnshore U.S. Business UnitBP America Production Company

Earl J. RitchieVice President and General ManagerHouston DivisionEOG Resources, Incorporated

Robert T. RyderGeoscientistU.S. Geological Survey

Gary C. StoneRegional Geology CoordinatorExxonMobil Exploration Company

Gary H. TsangDevelopment PlannerExxonMobil Development Company

Loring P. WhiteExploration AdvisorExxonMobil Exploration Company

James B. WixtedTechnical DirectorDomestic Business DevelopmentEl Paso Production Company

Rob H. WoronukPresidentGasEnergy Strategies Inc.

Steven T. SchlotterbeckSenior Vice PresidentProduction ManagementEquitable Production Company

Kirk W. SherwoodGeologistMinerals Management ServiceU.S. Department of the Interior

Robert W. StancilChief GeologistAnadarko Petroleum Corporation

Lisa Marie SchronkDevelopment EngineerProject, Planning & Systems/

Cost & ScheduleExxonMobil Development Company

Grant D. ZimbrickGeoscientist

Assessment Core GroupExxonMobil Exploration Company

SUPPLY TASK GROUP’S RESOURCE SUBGROUP

U.S. Department of the Interior

U.S. Department of the Interior

Matthew A. SabiskyPlanning AdvisorExxonMobil Production Company

Consulting Geologist


SUPPLY TASK GROUP’S TECHNOLOGY SUBGROUP

LEADERRobert G. Howard, Jr.

Vice PresidentNorth America Upstream

ChevronTexaco Corporation

Peter S. AronstamDirector of TechnologyBaker Hughes Incorporated

Lana B. BilleaudOpportunity Assessment ManagerInternational Marketing and BusinessChevronTexaco Global Gas

Audis C. ByrdManagerGlobal TechnologyHalliburton Energy Services

Sheng DingReservoir EngineerEl Paso Energy Corporation

Gerard A. GabrielManagerTechnology Applications DivisionExxonMobil Upstream Research Company

Morris R. HastingManaging PartnerLandmark Graphics Corporation

Stephen A. HolditchSchlumberger FellowSchlumberger Oil Field Service


Kent F. PerryAssistant DirectorTight Sands and Gas Processing ResearchGas Research Institute

Jack C. RawdonEngineering AdvisorProduction OperationsDominion Exploration and Production, Inc.

David E. ReeseReservoir Engineering Fellow

Reservoir SciencesConocoPhillips

SUPPLY TASK GROUP’S ENVIRONMENTAL/REGULATORY/ACCESS SUBGROUP

LEADERG. David Blackmon

ManagerCorporate Affairs

Burlington Resources Inc.

Fernando BlackgoatUpstream Safety, Health and Environment AdvisorExxonMobil Production Company

Walter D. CruickshankDeputy DirectorMinerals Management ServiceU.S. Department of the Interior

LEADERG. David Blackmon

ManagerCorporate Affairs

Burlington Resources Inc.

Druann D. BowerVice PresidentPetroleum Association of Wyoming

David R. BrownManagerRegulatory AffairsHealth, Safety and EnviromentBP America Production Company

Norma L. CalvertGeneral ManagerState Government AffairsMarathon Oil Company

Bonnie L. CarsonEnvironmental EngineerO&G Environmental Consulting

Jeffrey S. ChapmanEnvironmental AdvisorUpstream Safety, Health and EnvironmentExxonMobil Production Company

J. Keith CouvillionLand ConsultantChevronTexaco Corporation

Wm. Dean CrandellProgram ManagerFluid MineralsForest ServiceU.S. Department of Agriculture


Claire M. MoseleyExecutive DirectorPublic Lands Advocacy

Neil R. LatimerEnvironmental AdvisorExxonMobil Production Company

Randall P. MeabonRegulatory CoordinatorRegulatory and Government ComplianceMarathon Oil Company



H. William HochheiserProgram ManagerOil and Gas Environmental ResearchOffice of Fossil EnergyU.S. Department of Energy

Gary L. HolsanOwner and ManagerGary Holsan Environmental Planning

John S. HullDirectorMarket IntelligenceChevronTexaco Global Trading

Erick V. KaarlelaManagerNational Energy OfficeBureau of Land ManagementU.S. Department of the Interior

Walter D. CruickshankDeputy DirectorMinerals Management ServiceU.S. Department of the Interior

Timothy A. DeinesPlanning ManagerWorldwide ProductionMarathon Oil Company

Eileen D. DeyRegulatory Compliance SupervisorMid-Continent DivisionBurlington Resources Oil & Gas Company, LP

Ben J. DillonManagerGovernment AffairsShell Exploration & Production Company

Robert J. SandilosSenior Government Relations AdvisorChevronTexaco Upstream

ENVIRONMENTAL/REGULATORY/ACCESS SUBGROUP

Environment


Edward J. ShawSpecial Assistant to the DirectorMinerals Management ServiceU.S. Department of the Interior

ENVIRONMENTAL/REGULATORY/ACCESS SUBGROUP

Kermit G. WitherbeeDeputy Group ManagerFluids GroupBureau of Land ManagementU.S. Department of the Interior

SUPPLY TASK GROUP’S LNG SUBGROUP

LEADERJohn Hritcko, Jr.Vice President

Shell NA, LNG, Inc.Shell US Gas & Power Company

Jayraj C. AminBusiness DevelopmentGlobal LNGBP

Karen N. BaileyManagerLNG Market DevelopmentExxonMobil Gas and Power Marketing

Sara J. BanaszakDirectorGas & PowerThe Petroleum Finance Company

James G. BuschDirectorEnergy Policy and RegulationGas and Power North AmericaBP Energy

Geoffrey C. CouperVice PresidentGlobal LNGSempra Energy Trading Corporation

David FrancoBusiness Developer, LNGConocoPhillips

Harvey L. HarmonConsultantShell US Gas & Power, LLC

Richard A. LammonsProject ManagerInternational GasChevronTexaco Overseas Petroleum

Geoff K. MitchellManaging DirectorMerrimack Energy Group

Raj K. MohindrooManagerLNG New VenturesConocoPhillips




COLEADERSKenneth J. KonradSenior Vice PresidentAlaska GasBP Exploration Alaska Inc.

Joseph P. MarushackVice PresidentANS Gas DevelopmentConocoPhillips

Robert D. SchilhabManager

Alaska Gas DevelopmentExxonMobil Production Company

* *

Allan F. DriggsProject ManagerBasin StudiesAnadarko Petroleum Corporation


Angie L. KellyMarketing AnalystInternational CommercialDevelopmentAnadarko Petroleum Corporation

Richard J. LuckasavitchTechnical ManagerMackenzie Gas ProjectImperial Oil Resources

Michael J. McCarthyStaff Planning AdvisorAlaska Gas Development GroupExxonMobil Production Company

Colleen M. MukavitzCommercial ManagerAlaska Natural GasConocoPhillips

Randy J. OttenbreitDevelopment ExecutiveMackenzie Gas ProjectImperial Oil Resources

Steven P. SchwartzVenture ManagerNorth American West Coast LNGChevronTexaco Exploration & Production Company

David E. Van TuylCommercial Manager

Alaska GasBP America Production Inc.

SUPPLY TASK GROUP’S ARCTIC SUBGROUP

COLEADERSKenneth J. KonradSenior Vice PresidentAlaska GasBP Exploration Alaska Inc.

Joseph P. MarushackVice PresidentANS Gas DevelopmentConocoPhillips

Robert D. SchilhabManager

Alaska Gas DevelopmentExxonMobil Production Company

* *

Allan F. DriggsProject ManagerBasin StudiesAnadarko Petroleum Corporation


Angie L. KellyMarketing AnalystInternational CommercialDevelopmentAnadarko Petroleum Corporation


Michael J. McCarthyStaff Planning AdvisorAlaska Gas Development GroupExxonMobil Production Company

Colleen M. MukavitzCommercial ManagerAlaska Natural GasConocoPhillips

Randy J. OttenbreitDevelopment ExecutiveMackenzie Gas ProjectImperial Oil Resources

Steven P. SchwartzVenture ManagerNorth American West Coast LNGChevronTexaco Exploration & Production Company

David E. Van TuylCommercial Manager

Alaska GasBP America Production Inc.



Angie L. KellyMarketing AnalystInternational Commercial DevelopmentAnadarko Petroleum Corporation



TRANSMISSION & DISTRIBUTION TASK GROUPOF THE


CHAIR

Scott E. ParkerPresidentNatural Gas Pipeline Company of America



GOVERNMENT COCHAIR


SECRETARY

Benjamin A. Oliver, Jr.Senior Committee CoordinatorNational Petroleum Council

* * *

Stephen C. AllemanManagerBusiness OptimizationConocoPhillips

Steven D. BeckerVice PresidentGas DevelopmentTransCanada Pipelines Limited

James J. ClearyPresidentANR Pipeline Company

Dawn M. ConstantinLeaderTerm Fundamental AnalysisBP North America Gas & Power

Richard C. DanielSenior Vice PresidentEnCana Corporation


Jeffrey A. HolliganRegulatory ConsultantBP Energy Company


Terrance L. McGillVice PresidentCommerical Activity & Business DevelopmentEnbridge (U.S.) Inc.

Joseph L. RatiganVice President and Principal ConsultantPB Energy Storage Services, Inc.

Bradford D. ReeseSenior Vice President Northern Development and Co-Chief Executive Officer Foothills PipelineDuke Energy Gas Transmission – Canada


Terrance L. McGillVice PresidentCommerical Activity & Business DevelopmentEnbridge (U.S.) Inc.


Patrick A. JohnsonDirectorStrategy DepartmentEl Paso Corporation

TRANSMISSION & DISTRIBUTION TASK GROUP’S TRANSMISSION SUBGROUP

LEADERPatrick A. Johnson

DirectorStrategy DepartmentEl Paso Corporation

Michael K. AndersonAssociateStrategic InitiativesColumbia Gulf Transmission Co.

Nathan W. AndersonPrincipal StrategistEastern Pipeline GroupEl Paso Corporation

Sara J. BanaszakDirectorGas & PowerThe Petroleum Finance Company

Steven D. BeckerVice PresidentGas DevelopmentTransCanada Pipelines Limited

George R. FindlingManagerCommercial DevelopmentConocoPhillips Gas & Power


Carl W. LevanderVice PresidentRegulatory & Strategic InitiativesColumbia Gas Transmission Corp.

Francis C. PilleyDirectorGas StrategyTransCanada Pipelines Limited


Stephen T. RiesterTransportation AdvisorExxonMobil Gas Marketing Company


J. Gregory SnyderProject LeaderBusiness Planning and Market AnalysisDominion Energy, Inc.


TRANSMISSION & DISTRIBUTION TASK GROUP


James J. ClearyPresidentANR Pipeline Company

Dawn M. ConstantinLeaderTerm Fundamental AnalysisBP North America Gas & Power

George R. FindlingManagerCommercial DevelopmentConocoPhillips Gas & Power




Walter M. SimmonsVice President, Strategic PlanningGas Pipeline GroupKinder Morgan Inc.

Byron S. WrightVice-President

Strategy and Capacity PricingEl Paso Pipeline Group



Stephen T. RiesterTransportation AdvisorExxonMobil Gas Marketing Company


TRANSMISSION & DISTRIBUTION TASK GROUP’S DISTRIBUTION SUBGROUP

LEADERMark T. MaasselVice President

Regulatory and Governmental PolicyNiSource Inc.

Donald M. FieldExecutive Vice PresidentPeoples Energy Corporation

Randolph S. FriedmanManagerGas SupplyNW Natural Gas Company

Leonard J. PhillipsManagerGas OperationsMemphis Light, Gas & Water Division

Glen R. SchwalbachAssistant Vice PresidentCorporate PlanningWisconsin Public Service Corporation

Francis C. PilleyDirectorGas StrategyTransCanada Pipelines Limited


Carl W. LevanderVice PresidentRegulatory & Strategic InitiativesColumbia Gas Transmission Corp.



TRANSMISSION & DISTRIBUTION TASK GROUP’S STORAGE SUBGROUP

LEADERRonald L. Brown

Vice PresidentStorage Management & System Design

Kinder Morgan Inc.

Mark D. CourtneyVice President, OriginationFalcon Gas Storage

Richard C. DanielSenior Vice PresidentGas StorageEnCana Corporation

Richard J. GentgesDirectorReservoir ServicesEl Paso Pipeline Group

David J. NightingaleGeneral Manager Storage Services & Producer Services andVice President Market Hub Partners, LPDuke Energy Gas Transmission




William A. TrapmannTeam LeaderNatural Gas Analysis TeamOffice of Oil and GasEnergy Information AdministrationU.S. Department of Energy

SUMMARY - ACRONYMS AND ABBREVIATIONS AC-1

APD application for permit to drill

BCF billion cubic feet

BCF/D billion cubic feet per day

Btu British thermal unit

CNG compressed natural gas

CO2 carbon dioxide

DOE U.S. Department of Energy

EEA Energy and Environmental Analysis, Inc.

EIA Energy Information Administration

FERC Federal Energy Regulatory Commission

GDP Gross Domestic Product

GW gigawatts

LDC local distribution company

LNG liquefied natural gas

MACT Maximum Achievable ControlTechnology

MM million

MMBtu million British thermal units

MMCF million cubic feet

MMCF/D million cubic feet per day

MMS Minerals Management Service

MOUs Memorandums of Understanding

NEPA National Environmental Policy Act

NGL natural gas liquid

NGPA National Gas Policy Act

NOx nitrogen oxides

NPC National Petroleum Council

OCS Outer Continental Shelf

PIFUA Powerplant and Industrial Fuel Use Actof 1978

PUC Public Utility Commission

RTOs Regional Transmission Organizations

SOx sulfur oxides

TCF trillion cubic feet

USGS United States Geological Service

WCSB Western Canadian Sedimentary Basin

ACRONYMS AND ABBREVIATIONSSUMMARY

SUMMARY - GLOSSARY GL-1

AccessThe legal right to drill and develop oil and naturalgas resources, build associated production facilities,and build transmission and distribution facilities oneither public and/or private land.

BasisThe difference in price for natural gas at two differ-ent geographical locations.

Capacity, PeakingThe capacity of facilities or equipment normallyused to supply incremental gas or electricity underextreme demand conditions. Peaking capacity isgenerally available for a limited number of days atmaximum rate.

Capacity, PipelineThe maximum throughput of natural gas over aspecified period of time for which a pipeline systemor portion thereof is designed or constructed, notlimited by existing service conditions.

City GateThe point at which interstate and intrastate pipelinessell and deliver natural gas to local distribution com-panies.

CogenerationThe sequential production of electricity and usefulthermal energy from the same energy source, such assteam. Natural gas is a favored fuel for combined-cycle cogeneration units, in which waste heat is con-verted to electricity.

CommercialA sector of customers or service defined as non-manufacturing business establishments, includinghotels, motels, restaurants, wholesale businesses, retailstores, and health, social, and educational institutions.

Compressed Natural Gas (CNG)Natural gas cooled to a temperature below 32°F andcompressed to a pressure ranging from 1,000 to3,000 pounds per square inch in order to allow thetransportation of large quantities of natural gas.

Cost RecoveryThe recovery of permitted costs, plus an acceptablerate of return, for an energy infrastructure project.

Cubic FootThe most common unit of measurement of gas vol-ume; the amount of gas required to fill a volume ofone cubic foot under stated conditions of tempera-ture, pressure, and water vapor.

Distribution LineNatural gas pipeline system, typically operated by alocal distribution company, for the delivery of natu-ral gas to end users.

ElectricA sector of customers or service defined as generation,transmission, distribution, or sale of electric energy.

End-UserOne who actually consumes energy, as opposed toone who sells or re-sells it.

FERC (Federal Energy Regulatory Commission)The federal agency that regulates interstate gaspipelines and interstate gas sales under the NaturalGas Act.

Firm CustomerA customer who has contracted for firm service.

Firm ServiceService offered to customers under schedules or con-tracts that anticipate no interruptions, regardless ofclass of service, except for force majeure.

GLOSSARYSUMMARY

Fuel SwitchingSubstituting one fuel for another based on price andavailability. Large industries often have the capabil-ity of using either oil or natural gas to fuel theiroperation and of making the switch on short notice.

Fuel-Switching CapabilityThe ability of an end-user to readily change fuel typeconsumed whenever a price or supply advantagedevelops for an alternative fuel.

GigawattsOne billion watts.

Henry HubA pipeline interchange near Erath, Louisiana, wherea number of interstate and intrastate pipelines inter-connect through a header system operated by SabinePipe Line. The standard delivery point for the NewYork Mercantile Exchange natural gas futures con-tract.

IndustrialA sector of customers or service defined as manufac-turing, construction, mining, agriculture, fishing,and forestry.

Liquefied Natural Gas (LNG)The liquid form of natural gas, which has beencooled to a temperature –256°F or –161°C and ismaintained at atmospheric pressure. This liquefac-tion process reduces the volume of the gas byapproximately 600 times its original size.

Load ProfilesGas usage over a specific period of time, usually dis-played as a graphical plot.

Local Distribution Company (LDC)A company that obtains the major portion of its nat-ural gas revenues from the operations of a retail gasdistribution system and that operates no transmis-sion system other than incidental connections with-in its own or to the system of another company. AnLDC typically operates as a regulated utility withinspecified franchise area.

Marketer (natural gas)A company, other than the pipeline or LDC, thatbuys and resells gas or brokers gas for a profit.Marketers also perform a variety of related services,including arranging transportation, monitoringdeliveries and balancing. An independent marketeris not affiliated with a pipeline, producer or LDC.

New FieldsA quantification of resources estimated to exist out-side of known fields on the basis of broad geologic

knowledge and theory; in practical terms, these arestatistically determined resources likely to be discov-ered in additional geographic areas with geologiccharacteristics similar to known producing regions,but which are as yet untested with the drillbit.

Nonconventional GasNatural gas produced from coalbed methane, shales,and low permeability reservoirs. Development ofthese reservoirs can require different technologiesthan conventional reservoirs.

Peak-Day DemandThe maximum daily quantity of gas used during aspecified period, such as a year.

Peak ShavingMethods to reduce the peak demand for gas or elec-tricity. Common examples are storage and use ofLNG.

Proved ReservesThe most certain of the resource base categoriesrepresenting estimated quantities that analysis ofgeological and engineering data demonstrate withreasonable certainty to be recoverable in futureyears from known reservoirs under existing eco-nomic and operating conditions; generally, these gasdeposits have been “booked,” or accounted for asassets on the SEC financial statements of theirrespective companies.

Regional Transmission Organization (RTO)Voluntary organization of transmission owners,transmission users, and other entities interested incoordinating transmission planning, expansion, anduse on a regional and interregional basis.

ResidentialThe residential sector is defined as private householdestablishments which consume energy primarily forspace heating, water heating, air conditioning, light-ning, refrigeration, cooking, and clothes drying.

RevenueThe total amount money received by a firm fromsales of its products and/or services.

ShipperOne who contracts with a pipeline for transporta-tion of natural gas and who retains title to the gaswhile it is being transported by the pipeline.

TerawattsOne trillion watts.

WattThe common U.S. measure of electrical power.

SUMMARY - GLOSSARYGL-2

1625 K STREET NWWASHINGTON DC 20006


Balancing Natural Gas Policy Vol-1 Summary (NPC, 2003)

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