Future of

The

Natural 

Gas

AN INTERDISCIPLINARY MIT STUDY
MIT Study on the Future of Natural Gas iii

Foreword and Acknowledgements 

The Future of Natural Gas is the fourth in a 

series of MIT multidisciplinary reports examining the role of various energy sources that may 

be important for meeting future demand under 

carbon dioxide (CO2) emissions constraints. In 

each case, we explore the steps needed to enable 

competitiveness in a future marketplace conditioned by a CO2 emissions price or by a set of 

regulatory initiatives. This report follows an 

interim report issued in June 2010.

The first three reports dealt with nuclear power 

(2003), coal (2007) and the nuclear fuel cycle 

(2010 and 2011). A study of natural gas is more 

complex than these previous reports because 

gas is a major fuel for multiple end uses — 

electricity, industry, heating — and is increasingly 

discussed as a potential pathway to reduced oil 

dependence for transportation. In addition, 

the realization over the last few years that the 

producible unconventional gas resource in the 

U.S. is very large has intensified the discussion 

about natural gas as a “bridge” to a low-carbon 

future. Recent indications of a similarly large 

global gas shale resource may also transform the 

geopolitical landscape for gas. We have carried 

out the integrated analysis reported here as 

a contribution to the energy, security and 

climate debate. 

Our primary audience is U.S. government, 

industry and academic leaders, and decision 

makers. However, the study is carried out with 

an international perspective. 

This study is better as a result of comments and 

suggestions from our distinguished external 

Advisory Committee, each of whom brought 

important perspective and experience to our 

discussions. We are grateful for the time they

invested in advising us. However, the study is the 

responsibility of the MIT study group and the 

advisory committee members do not necessarily 

endorse all of its findings and recommendations, 

either individually or collectively. 

Finally, we are very appreciative of the support 

from several sources. First and foremost, we 

thank the American Clean Skies Foundation. 

Discussions with the Foundation led to the 

conclusion that an integrative study on the 

future of natural gas in a carbon-constrained 

world could contribute to the energy debate in 

an important way, and the Foundation stepped 

forward as the major sponsor. MIT Energy 

Initiative (MITEI) members Hess Corporation 

and Agencia Naçional de Hidrocarburos 

(Colombia), the Gas Technology Institute (GTI), 

Exelon, and an anonymous donor provided 

additional support. The Energy Futures Coalition supported dissemination of the study 

results, and MITEI employed internal funds and 

fellowship sponsorship to support the study as 

well. As with the advisory committee, the 

sponsors are not responsible for and do not 

necessarily endorse the findings and recommendations. That responsibility lies solely with the 

MIT study group. 

We thank Victoria Preston and Rebecca 

Marshall-Howarth for editorial support and 

Samantha Farrell for administrative support. 
MIT Study on the Future of Natural Gas v

Study Participants

ERNEST J. MONIZ — CHAIR 

Cecil and Ida Green Professor of Physics 

and Engineering Systems, MIT 

Director, MIT Energy Initiative (MITEI) 

HENRY D. JACOBY — CO-CHAIR 

Professor of Management, MIT 

ANTHONY J. M. MEGGS — CO-CHAIR 

Visiting Engineer, MITEI 

STUDY GROUP 

ROBERT C. ARMSTRONG 

Chevron Professor, Department of Chemical 

Engineering, MIT 

Deputy Director, MITEI 

DANIEL R. COHN 

Senior Research Scientist, Plasma Science 

and Fusion Center, MIT 

Executive Director, Natural Gas Study 

STEPHEN R. CONNORS 

Research Engineer, MITEI 

JOHN M. DEUTCH 

Institute Professor, 

Department of Chemistry, MIT 

QUDSIA J. EJAZ 

Postdoctoral Associate, MITEI 

JOSEPH S. HEZIR 

Visiting Engineer, MITEI 

GORDON M. KAUFMAN 

Morris A. Adelman Professor of Management 

(Emeritus), MIT 

MELANIE A. KENDERDINE 

Executive Director, MITEI 

FRANCIS O’SULLIVAN 

Research Engineer, MITEI 

SERGEY PALTSEV 

Principal Research Scientist, Joint Program on 

the Science and Policy of Global Change, MIT 

JOHN E. PARSONS 

Senior Lecturer, Sloan School of Management, MIT 

Executive Director, Joint Program on the 

Science and Policy of Global Change and 

Center for Energy and Environmental 

Policy Research, MIT

IGNACIO PEREZ-ARRIAGA 

Professor of Electrical Engineering, 

Comillas University, Spain 

Visiting Professor, Engineering Systems Division, MIT 

JOHN M. REILLY 

Senior Lecturer, Sloan School of Management, MIT 

Co-Director, Joint Program on the Science 

and Policy of Global Change, MIT 

CAROLYN SETO 

Clare Boothe Luce Postdoctoral Fellow, 

Department of Chemical Engineering, MIT 

MORT D. WEBSTER 

Assistant Professor, Engineering Systems 

Division, MIT 

YINGXIA YANG 

MITEI 

STUDY CO-CHAIRS 
vi MIT STUDY ON THE FUTURE OF NATURAL GAS

CONTRIBUTING AUTHORS 

GREGORY S. MCRAE

Professor of Chemical Engineering (Emeritus), 

MIT 

CAROLYN RUPPEL 

Visiting Scientist, Department of Earth, 

Atmospheric and Planetary Sciences, MIT 

GRADUATE RESEARCH ASSISTANTS 

SARAH FLETCHER

JOHN MICHAEL HAGERTY

Exelon – MIT Energy Fellow

ORGHENERUME KRAGHA

TOMMY LEUNG

Cummins – MIT Energy Fellow

PAUL MURPHY

Total – MIT Energy Fellow

ANIL RACHOKONDA

KAREN TAPIA-AHUMADA

GTI – MIT Energy Fellow

IBRAHIM TOUKAN 

Constellation – MIT Energy Fellow 

DOGAN UCOK

YUAN YAO
MIT Study on the Future of Natural Gas vii

Advisory Committee Members

THOMAS F. (MACK) MCLARTY, III — 

CHAIRMAN

President & CEO, McLarty Associates

DENISE BODE

CEO, American Wind Energy Association

RALPH CAVANAGH

Senior Attorney and Co-Director of Energy Program, 

Natural Resource Defense Council

SUNIL DESHMUKH

Founding Member, Sierra Club India 

Advisory Council

JOSEPH DOMINGUEZ

Senior Vice President, Exelon Corporation

RON EDELSTEIN

Director, Regulatory and Government Relations, 

GTI

NEAL ELLIOTT

Associate Director for Research, American

 Council for an Energy-Efficient Economy

JOHN HESS

Chairman and CEO, Hess Corporation

JAMES T. JENSEN

President, Jensen Associates

SENATOR (ret.) J. BENNETT JOHNSTON

Chairman, Johnston Associates

VELLO A. KUUSKRAA

President, Advance Resources International, Inc.

MIKE MING

Oklahoma Secretary of Energy

THEODORE ROOSEVELT IV

Managing Director & Chairman, Barclays Capital 

Clean Tech Initiative 

OCTAVIO SIMOES

Vice President of Commercial Development, 

Sempra Energy

GREG STAPLE

CEO, American Clean Skies Foundation

PETER TERTZAKIAN

Chief Energy Economist and Managing Director, 

ARC Financial

DAVID VICTOR

Director, Laboratory on International Law 

and Regulation, University of California, San Diego

ARMANDO ZAMORA

Director, ANH-Agencia Nacional De Hidrocarburos

While the members of the advisory committee provided invaluable perspective and advice to the study group, 

individual members may have different views on one or more matters addressed in the report. They are not 

asked to individually or collectively endorse the report findings and recommendations.

MIT Study on the Future of Natural Gas xiii

Abstract

Natural gas is finding its place at the heart of the 

energy discussion. The recent emergence of 

substantial new supplies of natural gas in the 

U.S., primarily as a result of the remarkable 

speed and scale of shale gas development, has 

heightened awareness of natural gas as a key 

component of indigenous energy supply and has 

lowered prices well below recent expectations. 

This study seeks to inform discussion about the 

future of natural gas, particularly in a carbonconstrained economy.

There are abundant supplies of natural gas in 

the world, and many of these supplies can be 

developed and produced at relatively low cost. 

In North America, shale gas development over 

the past decade has substantially increased 

assessments of resources producible at modest 

cost. Consequently, the role of natural gas is 

likely to continue to expand, and its relative 

importance is likely to increase even further 

when greenhouse gas emissions are constrained. 

In a carbon-constrained world, a level playing 

field — a carbon dioxide (CO2) emissions price 

for all fuels without subsidies or other preferential policy treatment —maximizes the value to 

society of the large U.S. natural gas resource. 

There are also a number of key uncertainties: 

the extent and nature of greenhouse gas emission 

mitigation measures that will be adopted; the 

mix of energy sources as the relative costs of fuels 

and technologies shift over time; the evolution 

of international natural gas markets. We explore 

how these uncertainties lead to different outcomes and also quantify uncertainty for natural 

gas supply and for the U.S. electricity fuel mix.

The environmental impacts of shale development 

are challenging but manageable. Research and 

regulation, both state and Federal, are needed to 

minimize the environmental consequences.

The U.S. natural gas supply situation has 

enhanced the substitution possibilities for 

natural gas in the electricity, industry, buildings, 

and transportation sectors.

In the U.S. electricity supply sector, the cost 

benchmark for reducing carbon dioxide emissions 

lies with substitution of natural gas for coal, 

especially older, less efficient units. Substitution 

through increased utilization of existing combined 

cycle natural gas power plants provides a relatively low-cost, short-term opportunity to reduce 

U.S. power sector CO2 emissions by up to 20%, 

while also reducing emissions of criteria pollutants and mercury. 

Furthermore, additional gas-fired capacity will 

be needed as backup if variable and intermittent 

renewables, especially wind, are introduced on a 

large scale. Policy and regulatory steps are needed 

to facilitate adequate capacity investment for 

system reliability and efficiency. These increasingly important roles for natural gas in the 

electricity sector call for a detailed analysis of the 

interdependencies of the natural gas and power 

generation infrastructures.

The primary use of natural gas in the U.S. 

manufacturing sector is as fuel for boilers and 

process heating, and replacement with new 

higher efficiency models would cost-effectively 

reduce natural gas use. Natural gas could also 

substitute for coal in boilers and process heaters 

and provide a cost-effective alternative for 

compliance with Environmental Protection 

Agency (EPA) Maximum Achievable Control 

Technology standards. 

In the residential and commercial buildings 

sector, transformation of the current approach to 

efficiency standards to one based on full fuel 

cycle analysis will enable better comparison of 

different energy supply options (especially 
xiv MIT STUDY ON THE FUTURE OF NATURAL GAS

natural gas and electricity). Efficiency metrics 

should be tailored to regional variations in 

climate and electricity supply mix.

Within the U.S. market, the price of oil (which 

is set globally) compared to the price of natural 

gas (which is set regionally) is very important 

in determining market share when there is the 

opportunity for substitution. Over the last 

decade or so, when oil prices have been high, 

the ratio of the oil price to the natural gas price 

has been consistently higher than any of the 

standard rules of thumb. If this trend is robust, 

use of natural gas in transportation, either 

through direct use or following conversion to a 

liquid fuel, could in time increase appreciably.

The evolution of global gas markets is unclear. 

A global “liquid” natural gas market is beneficial to U.S. and global economic interests and, 

at the same time, advances security interests 

through diversity of supply and resilience to 

disruption. The U.S. should pursue policies that 

encourage the development of such a market, 

integrate energy issues fully into the conduct of 

U.S. foreign policy, and promote sharing of 

know-how for strategic global expansion of 

unconventional gas production.

Past research, development, demonstration, and 

deployment (RDD&D) programs supported with 

public funding have led to significant advances 

for natural gas supply and use. Public-private 

partnerships supporting a broad natural gas 

research, development, and demonstration 

(RD&D) portfolio should be pursued.
Chapter 1: Overview and Conclusions 1

Chapter 1: Overview and Conclusions 

PURPOSE AND OUTLINE OF THE STUDY

Despite its vital importance to the national 

economy, natural gas has often been overlooked, 

or at best taken for granted, in the debate about 

the future of energy in the U.S. Over the past 

two or three years this has started to change, and 

natural gas is finding its place at the heart of the 

energy discussion.

There are a number of reasons for this shift. 

The recent emergence of substantial new supplies of natural gas in the U.S., primarily as a 

result of the remarkable speed and scale of shale 

gas development, has heightened awareness of 

natural gas as a key component of indigenous 

energy supply and lowered prices well below 

recent expectations. Instead of the anticipated 

growth of natural gas imports, the scale of domestic production has led producers to seek new 

markets for natural gas, such as an expanded role 

in transportation. Most importantly for this 

study, there has been a growing recognition that 

the low carbon content of natural gas relative to 

other fossil fuels could allow it to play a significant role in reducing carbon dioxide (CO2) emissions, acting as a “bridge” to a low-carbon future.

Within this context, the MIT study of The Future 

of Natural Gas seeks to inform the discussion 

around natural gas by addressing a fundamental 

question: what is the role of natural gas in a 

carbon-constrained economy? 

In exploring this question, we seek to improve 

general understanding of natural gas, and 

examine a number of specific issues. How much 

natural gas is there in the world, how expensive 

is it to develop, and at what rate can it be produced? We start from a global perspective, and 

then look in detail at U.S. natural gas resources, 

paying particular attention to the extent and cost 

of shale gas resources, and whether these supplies can be developed and produced in an 

environmentally sound manner.

Having explored supply volumes and costs, we 

use integrated models to examine the role that 

natural gas could play in the energy system under 

different carbon-constraining mechanisms or 

policies. It is important to recognize that the study 

does not set out to make predictions or forecasts 

of the likelihood or direction of CO2 policy in the 

U.S. Rather, we examine a number of different 

scenarios and explore their possible impacts on 

the future of natural gas supply and demand.

Natural gas is important in many sectors of the 

economy — for electricity generation, as an 

industrial heat source and chemical feedstock, 

and for water and space heating in residential 

and commercial buildings. Natural gas competes 

directly with other energy inputs in these sectors. 

But it is in the electric power sector — where 

natural gas competes with coal, nuclear, hydro, 

wind and solar — that inter-fuel competition is 

most intense. We have, therefore, explored in 

depth how natural gas performs in the electric 

power sector under different scenarios. We have 

also taken a close look at the critical interaction 

between intermittent forms of renewable energy, 

such as wind and solar, and gas-fired power as a 

reliable source of backup capacity.

We look at the drivers of natural gas use in the 

industrial, commercial and residential sectors, 

and examine the important question of whether 

natural gas, in one form or another, could be a 

viable and efficient substitute for gasoline or diesel 

in the transportation sector. We also examine the 

possible futures of global natural gas markets, and 

the geopolitical significance of the ever-expanding 

role of natural gas in the global economy. Finally, 

we make recommendations for research and 

development priorities and for the means by 

which public support should be provided.
2 MIT STUDY ON THE FUTURE OF NATURAL GAS

HIGH-LEVEL FINDINGS

The findings and recommendations of the 

study are discussed later in this chapter, and 

covered in detail in the body of this report. 

Nevertheless, it is worth summarizing here 

the highest level conclusions of our study:

1. There are abundant supplies of natural gas 

in the world, and many of these supplies 

can be developed and produced at relatively 

low cost. In the U.S., despite their relative 

maturity, natural gas resources continue to 

grow, and the development of low-cost and 

abundant unconventional natural gas 

resources, particularly shale gas, has a 

material impact on future availability 

and price.

2. Unlike other fossil fuels, natural gas plays 

a major role in most sectors of the modern 

economy — power generation, industrial, 

commercial and residential. It is clean and 

flexible. The role of natural gas in the world 

is likely to continue to expand under almost 

all circumstances, as a result of its availability, 

its utility and its comparatively low cost.

3. In a carbon-constrained economy, the 

relative importance of natural gas is likely 

to increase even further, as it is one of the 

most cost-effective means by which to 

maintain energy supplies while reducing 

CO2 emissions. This is particularly true in 

the electric power sector, where, in the U.S., 

natural gas sets the cost benchmark against 

which other clean power sources must 

compete to remove the marginal ton of CO2.

4. In the U.S., a combination of demand 

reduction and displacement of coal-fired 

power by gas-fired generation is the lowestcost way to reduce CO2 emissions by up to 

50%. For more stringent CO2 emissions 

reductions, further de-carbonization of the 

energy sector will be required; but natural 

gas provides a cost-effective bridge to such a 

low-carbon future. 

5. Increased utilization of existing natural gas 

combined cycle (NGCC) power plants 

provides a relatively, low-cost short-term 

opportunity to reduce U.S. CO2 emissions 

by up to 20% in the electric power sector, 

or 8% overall, with minimal additional 

capital investment in generation and no 

new technology requirements.

6. Natural gas-fired power capacity will play 

an increasingly important role in providing 

backup to growing supplies of intermittent 

renewable energy, in the absence of a 

breakthrough that provides affordable 

utility-scale storage. But in most cases, 

increases in renewable power generation 

will be at the expense of natural gas-fired 

power generation in the U.S.

7. The current supply outlook for natural gas 

will contribute to greater competitiveness 

of U.S. manufacturing, while the use of 

more efficient technologies could offset 

increases in demand and provide costeffective compliance with emerging environmental requirements.

8. Transformation of the current approach 

to appliance standards to one based on full 

fuel cycle analysis will enable better comparison of different energy supply options 

in commercial and residential applications.

9. Natural gas use in the transportation sector 

is likely to increase, with the primary 

benefit being reduced oil dependence. 

Compressed natural gas (CNG) will play 

a role, particularly for high-mileage fleets, 

but the advantages of liquid fuel in transportation suggest that the chemical conversion of gas into some form of liquid fuel may 

be the best pathway to significant market 

penetration.
Chapter 1: Overview and Conclusions 3

10. International gas trade continues to grow 

in scope and scale, but its economic, 

security and political significance is not yet 

adequately recognized as an important 

focus for U.S. energy concerns.

11. Past research, development, demonstration 

and deployment (RDD&D) programs 

supported with public funding have led to 

significant advances for natural gas supply 

and use.

BACKGROUND

The Fundamental Characteristics 

of Natural Gas

Fossil fuels occur in each of the three fundamental states of matter: in solid form as coal; 

in liquid form as oil and in gaseous form as 

natural gas. These differing physical characteristics for each fuel type play a crucial part in 

shaping each link in their respective supply 

chains: from initial resource development and 

production through transportation, conversion 

to final products and sale to customers. Their 

physical form fundamentally shapes the 

markets for each type of fossil fuel.

Natural gas possesses remarkable qualities. 

Among the fossil fuels, it has the lowest carbon 

intensity, emitting less CO2 per unit of energy 

generated than other fossil fuels. It burns cleanly 

and efficiently, with very few non-carbon 

emissions. Unlike oil, natural gas generally 

requires limited processing to prepare it for 

end use. These favorable characteristics have 

enabled natural gas to penetrate many markets, 

including domestic and commercial heating, 

multiple industrial processes and electrical 

power. 

Natural gas also has favorable characteristics 

with respect to its development and production. 

The high compressibility and low viscosity of 

natural gas allows high recoveries from conventional reservoirs at relatively low cost, and also 

enables natural gas to be economically recovered from even the most unfavorable subsurface 

environments, as recent developments in shale 

formations have demonstrated. 

These physical characteristics underpin the 

current expansion of the unconventional 

resource base in North America, and the 

potential for natural gas to displace more 

carbon-intensive fossil fuels in a carbonconstrained world.

On the other hand, because of its gaseous form 

and low energy density, natural gas is uniquely 

disadvantaged in terms of transmission and 

storage. As a liquid, oil can be readily transported over any distance by a variety of means, 

and oil transportation costs are generally a small 

fraction of the overall cost of developing oil 

fields and delivering oil products to market. This 

has facilitated the development of a truly global 

market in oil over the past 40 years or more.

By contrast, the vast majority of natural gas 

supplies are delivered to market by pipeline, and 

delivery costs typically represent a relatively large 

fraction of the total cost in the supply chain. 

These characteristics have contributed to the 

evolution of regional markets rather than a 

truly global market in natural gas. Outside 

North America, this somewhat inflexible 

pipeline infrastructure gives strong political 

and economic power to those countries that 

control the pipelines. To some degree, the 

evolution of the spot market in Liquefied 

Natural Gas (LNG) is beginning to introduce 

more flexibility into global gas markets and 

stimulate real global trade. The way this trade 

may evolve over time is a critical uncertainty 

that is explored in this report. 
4 MIT STUDY ON THE FUTURE OF NATURAL GAS

The Importance of Natural Gas in the 

Energy System

Natural gas represents a very important, and 

growing, part of the global energy system. 

Over the past half century, natural gas has 

gained market share on an almost continuous 

basis, growing from some 15.6% of global 

energy consumption in 1965 to around 24% 

today. In absolute terms, global natural gas 

consumption over this period has grown from 

around 23 trillion cubic feet (Tcf) in 1965 to 

104 Tcf in 2009, a more than fourfold increase.

Within the U.S. economy, natural gas plays a 

vital role. Figure 1.1 displays the sources and uses 

of natural gas in the U.S. in 2009, and it reveals a 

number of interesting features that 

are explored in more detail in the body of this 

report. At 23.4 quadrillion British thermal units 

(Btu)1

, or approximately 23 Tcf, gas represents a 

little under a quarter of the total energy supply 

in the U.S., with almost all of this supply now 

coming from indigenous resources. Perhaps of 

more significance, is the very important role that 

natural gas plays in all sectors of the economy, 

with the exception of transport. Very approximately, the use of natural gas is divided evenly 

between three major sectors: industrial, residential and commercial, and electric power. The 3% 

share that goes to transport is almost all associated with natural gas use for powering oil and 

gas pipeline systems, with only a tiny fraction 

going into vehicle transport. 

In the Residential and Commercial sectors, 

natural gas provides more than three-quarters 

of the total primary energy, largely as a result 

of its efficiency, cleanliness and convenience 

for uses such as space and hot water heating. 

It is also a major primary energy input into the 

Industrial sector, and thus the price of natural 

gas has a very significant impact on the competitiveness of some U.S. manufacturing 

industries. While natural gas provided 18% of 

the primary fuel for power generation in 2009, 

Figure 1.1 Sources and Use of Primary Energy Sources in the U.S. with Natural 

Gas Highlighted (quadrillion Btu), 2009

Source: EIA, Annual Energy Outlook, 2009

Supply Sources Demand Sources

Petroleum

Natural Gas

Coal

Renewables

Nuclear

35.3

19.7

7.7

8.3

Transportation

Industrial

Residential &

Commercial

Electric 

Power

23.4

27.0

18.8

10.6

38.6

72%

22%

1%

5%

94%

3%

41%

7%

11%

48%

11%

17%

22%

1%

1%

1%

3%

40%

76%

18%

30%

3%

35%

32%

7%

100%

53%

9%

12% 26%

93%

<1%

94.6 Quads

Percent of Source Percent of Sector
Chapter 1: Overview and Conclusions 5

it provided 23% of the produced electricity, 

reflecting the higher efficiency of natural gas 

plants. As will be seen later in this report, 

natural gas-fired capacity represents far more 

than 23% of total power generating capacity, 

providing a real opportunity for early action in 

controlling CO2 emissions.

A Brief History of Natural Gas in the U.S.

The somewhat erratic history of natural gas 

in the U.S. over the last three decades or so 

provides eloquent testimony to the difficulties 

of forecasting energy futures, particularly for 

natural gas. It also serves as a reminder of the 

need for caution in the current period of 

supply exuberance.

The development of the U.S. natural gas market 

was facilitated by the emergence of an interstate 

natural gas pipeline system, supplying local 

distribution systems. This market structure was 

initially viewed as a natural monopoly and was 

subjected to cost-of-service regulation by both 

the Federal government and the states. Natural 

gas production and use grew considerably 

under this framework in the 1950s, 1960s and 

into the 1970s.

Then came a perception of supply scarcity. 

After the first oil embargo, energy consumers 

sought to switch to natural gas. However, the 

combination of price controls and tightly 

regulated natural gas markets dampened 

incentives for domestic gas development, 

contributing to a perception that U.S. natural 

gas resources were limited. In 1978, convinced 

that the U.S. was running out of natural gas, 

Congress passed the Power Plant and Industrial 

Fuel Use Act (FUA) that essentially outlawed 

the building of new gas-fired power plants. 

Between 1978 and 1987 (the year the FUA was 

repealed), the U.S. added 172 Gigawatts (GW) 

of net power generation capacity. Of this, 

almost 81 GW was new coal capacity, around 

26% of today’s entire coal fleet. About half of 

the remainder was nuclear power. 

By the mid 1990s, wholesale electricity markets 

and wellhead natural gas prices had been 

deregulated; new, highly efficient and relatively 

inexpensive combined cycle gas turbines had 

been deployed and new upstream technologies 

had enabled the development of offshore 

natural gas resources. This contributed to the 

perception that domestic natural gas supplies 

were sufficient to increase the size of the U.S. 

natural gas market from around 20 Tcf/year to 

much higher levels. New gas-fired power 

capacity was added at a rapid pace.

Between 1989 after the repeal of the FUA and 

2009, the U.S. added 306 GW of generation 

capacity, 88% of which was gas fired and 4% 

was coal fired.2

 Today, the nameplate capacity of 

this gas-fired generation is significantly underutilized, and the anticipated large increase in 

natural gas use has not materialized.

By the turn of the 21st century, a new set of 

concerns arose about the adequacy of domestic 

natural gas supplies. Conventional supplies 

were in decline, unconventional natural gas 

resources remained expensive and difficult to 

develop and overall confidence in gas plummeted. Natural gas prices started to rise, becoming more closely linked to the oil price, which 

itself was rising. Periods of significant natural 

gas price volatility were experienced.

This rapid buildup in natural gas price, and 

perception of long-term shortage, created 

economic incentives for the accelerated development of an LNG import infrastructure. Since 

2000, North America’s rated LNG capacity has 

expanded from approximately 2.3 billion cubic 

feet (Bcf)/day to 22.7 Bcf/day, around 35% of 

the nation’s average daily requirement.

This expansion of LNG capacity coincided with 

an overall rise in the natural gas price and the 

market diffusion of technologies to develop 

affordable unconventional gas. The gamechanging potential of these technologies, 

combined with the large unconventional 
6 MIT STUDY ON THE FUTURE OF NATURAL GAS

resource base, has become more obvious over 

the last few years, radically altering the U.S. 

supply picture. We have once again returned to 

a period where supply is seen to be abundant. 

New LNG import capacity goes largely unused 

at present, although it provides a valuable 

supply option for the future.

These cycles of perceived “feast and famine” 

demonstrate the genuine difficulty of forecasting the future and providing appropriate policy 

support for natural gas production and use. 

They underpin the efforts of this study to 

account for this uncertainty in an analytical 

manner. 

Major Uncertainties

Looking forward, we anticipate policy and 

geopolitics, along with resource economics and 

technology developments, will continue to play 

a major role in determining global supply and 

market structures. Thus, any analysis of the 

future of natural gas must deal explicitly with 

multiple uncertainties:

s The extent and nature of the greenhouse gas 

(GHG) mitigation measures that will be 

adopted: the U.S. legislative response to the 

climate threat has proved quite challenging. 

However, the Environmental Protection 

Agency (EPA) is developing regulations 

under the Clean Air Act, and a variety of 

local, state and regional GHG limitation 

programs have been put in place. At the 

international level, reliance upon a system of 

voluntary national pledges of emission 

reductions by 2020, as set out initially in the 

Copenhagen Accord, leaves uncertainty 

concerning the likely structure of any future 

agreements that may emerge to replace the 

Kyoto Protocol. The absence of a clear 

international regime for mitigating GHG 

emissions in turn raises questions about the 

likely stringency of national policies in both 

industrialized countries and major emerging 

economies over coming decades.

s The likely technology mix in a carbonconstrained world, particularly in the power 

sector: the relative costs of different technologies may shift significantly in response 

to RD&D, and a CO2 emissions price will 

affect the relative costs. Moreover, the technology mix will be affected by regulatory and 

subsidy measures that will skew economic 

choices.

s The ultimate size and production cost of the 

natural gas resource base, and the environmental acceptability of production methods: 

much remains to be learned about the performance of shale gas plays, both in the U.S. and 

in other parts of the world. Indeed, even higher 

risk and less well-defined unconventional 

natural gas resources, such as methane 

hydrates, could make a contribution to 

supply in the later decades of the study’s 

time horizon.

s The evolution of international natural gas 

markets: very large natural gas resources are 

to be found in several areas outside the U.S., 

and the role of U.S. natural gas will be 

influenced by the evolution of this market — 

particularly the growth and efficiency of 

trade in LNG. Only a few years back, U.S. 

industry was investing in facilities for substantial LNG imports. The emergence of the 

domestic shale gas resource has depressed 

this business in the U.S., but in the future, 

the nation may again look to international 

markets.

Of these uncertainties, the last three can be 

explored by applying technically grounded 

analysis: lower cost for carbon capture and 

sequestration (CCS), renewables and nuclear 

power; producible resources of different levels 

and regional versus global integrated markets. 

In contrast, the shape and size of GHG mitigation measures is likely to be resolved only 

through complex ongoing political discussions 

at the national level in the major emitting 

countries and through multilateral negotiations. 
Chapter 1: Overview and Conclusions 7

The analysis in this study is based on three 

policy scenarios:

1. A business-as-usual case, with no significant 

carbon constraints; 

2. GHG emissions pricing, through a capand-trade system or emissions tax, leading 

to a 50% reduction in U.S. emissions below 

the 2005 level, by 2050.

3. GHG reduction via U.S. regulatory 

measures without emissions pricing: a 

renewable portfolio standard and measures 

forcing the retirement of some coal plants.

Our analysis is long term in nature, with 

a 2050 time horizon. We do not attempt to 

make detailed short-term projections of 

volumes, prices or price volatility, but rather 

focus on the long-term consequences of the 

carbon mitigation scenarios outlined above, 

taking into account the manifold uncertainties 

in a highly complex and interdependent 

energy system.

MAJOR FINDINGS AND 

RECOMMENDATIONS

In the following section we summarize the 

major findings and recommendations for each 

chapter of the report.

Supply

Globally, there are abundant supplies of 

natural gas, much of which can be developed 

at relatively low cost. The mean projection of 

remaining recoverable resource in this report 

is 16,200 Tcf, 150 times current annual global 

natural gas consumption, with low and high 

projections of 12,400 Tcf and 20,800 Tcf, 

respectively. Of the mean projection, approximately 9,000 Tcf could be developed economically with a natural gas price at or below $4/

Million British thermal units (MMBtu) at the 

export point. 

Unconventional natural gas, and particularly 

shale gas, will make an important contribution 

to future U.S. energy supply and CO2 emissionreduction efforts. Assessments of the recoverable volumes of shale gas in the U.S. have 

increased dramatically over the last five years, 

and continue to grow. The mean projection of 

the recoverable shale gas resource in this report 

is approximately 650 Tcf, with low and high 

projections of 420 Tcf and 870 Tcf, respectively. 

Of the mean projection, approximately 400 Tcf 

could be economically developed with a natural 

gas price at or below $6/MMBtu at the wellhead. 

While the pace of shale technology development 

has been very rapid over the past few years, 

there are still many scientific and technological 

challenges to overcome before we can be 

confident that this very large resource base is 

being developed in an optimum manner.

Although there are large supplies, global conventional natural gas resources are concentrated 

geographically, with 70% in three countries: 

Qatar, Iran and Russia. There is considerable 

potential for unconventional natural gas supply 

outside North America, but these resources are 

largely unproven with very high resource 

uncertainty. Nevertheless, unconventional 

supplies could provide a major opportunity for 

diversification and improved security of supply 

in some parts of the world.

The environmental impacts of shale development are challenging but manageable. Shale 

development requires large-scale fracturing 

of the shale formation to induce economic 

production rates. There has been concern that 

these fractures can also penetrate shallow 

freshwater zones and contaminate them with 

fracturing fluid, but there is no evidence that 

this is occurring. There is, however, evidence 

of natural gas migration into freshwater zones 

in some areas, most likely as a result of substandard well completion practices by a few 

operators. There are additional environmental 
8 MIT STUDY ON THE FUTURE OF NATURAL GAS

challenges in the area of water management, 

particularly the effective disposal of fracture 

fluids. Concerns with this issue are particularly 

acute in regions that have not previously 

experienced large-scale oil and natural gas 

development, especially those overlying the 

massive Marcellus shale, and do not have a 

well-developed subsurface water disposal 

infrastructure. It is essential that both large and 

small companies follow industry best practices; 

that water supply and disposal are coordinated 

on a regional basis and that improved methods 

are developed for recycling of returned fracture 

fluids.

Natural gas trapped in the ice-like form known 

as methane hydrate represents a vast potential 

resource for the long term. Recent research is 

beginning to provide better definition of the 

overall resource potential, but many issues 

remain to be resolved. In particular, while there 

have been limited production tests, the longterm producibility of methane hydrates 

remains unproven, and sustained research 

will be required.

MAJOR RECOM MENDATIONS

Government-supported research on the 

fundamental challenges of unconventional 

natural gas development, particularly 

shale gas, should be greatly increased 

in scope and scale. In particular, support 

should be put in place for a comprehensive 

and integrated research program to 

build a system-wide understanding of 

all subsurface aspects of the U.S. shale 

resource. In addition, research should be 

pursued to reduce water usage in fracturing 

and to develop cost-effective water 

recycling technology. 

A concerted coordinated effort by industry 

and government, both state and Federal, 

should be organized so as to minimize the 

environmental impacts of shale gas 

development through both research and 

regulation. Transparency is key, both 

for fracturing operations and for water 

management. Better communication of 

oil- and gas-field best practices should 

be facilitated. Integrated regional water 

usage and disposal plans and disclosure of 

hydraulic fracture fluid components should 

be required.

The U.S. should support unconventional 

natural gas development outside U.S., 

particularly in Europe and China, as a means 

of diversifying the natural gas supply base.

The U.S. government should continue to 

sponsor methane hydrate research, with a 

particular emphasis on the demonstration 

of production feasibility and economics.

U.S. Natural Gas Production, Use and 

Trade: Potential Futures

In a carbon-constrained world, a level playing 

field — a CO2 emissions price for all fuels 

without subsidies or other preferential policy 

treatment — maximizes the value to society of 

the large U.S. natural gas resource. 

Under a scenario with 50% CO2 reductions to 

2050, using an established model of the global 

economy and natural gas cost curves that 

include uncertainty, the principal effects of the 

associated CO2 emissions price are to lower 

energy demand and displace coal with natural 

gas in the electricity sector. In effect, gas-fired 

power sets a competitive benchmark against 

which other technologies must compete in a lower 

carbon environment. A major uncertainty that 

could impact this picture in the longer term is 

technology development that lowers the costs 

of alternatives, in particular, renewables, 

nuclear and CCS. 
Chapter 1: Overview and Conclusions 9

A more stringent CO2 reduction of, for example, 80% would probably require the complete 

de-carbonization of the power sector. This 

makes it imperative that the development of 

competing low-carbon technology continues 

apace, including CCS for both coal and natural 

gas. It would be a significant error of policy to 

crowd out the development of other, currently 

more costly, technologies because of the new 

assessment of the natural gas supply. Conversely, it would also be a mistake to encourage, 

via policy and long-term subsidy, more costly 

technologies to crowd out natural gas in the 

short to medium term, as this could significantly increase the cost of CO2 reduction. 

The evolution of global natural gas markets is 

unclear; but under some scenarios, the U.S. 

could import 50% or more of its natural gas 

by 2050, despite the significant new resources 

created in the last few years. Imports can 

prevent natural gas-price inflation in future 

years.

MAJOR RECOM MENDATIONS

To maximize the value to society of the 

substantial U.S. natural gas resource base, 

U.S. CO2 reduction policy should be designed 

to create a “level playing field,” where all 

energy technologies can compete against 

each other in an open marketplace 

conditioned by legislated CO2 emissions 

goals. A CO2 price for all fuels without 

long-term subsidies or other preferential 

policy treatment is the most effective way 

to achieve this result. 

In the absence of such policy, interim energy 

policies should attempt to replicate as 

closely as possible the major consequences 

of a “level playing field” approach to carbonemissions reduction. At least for the near 

term, that would entail facilitating energy 

demand reduction and displacement of 

some coal generation with natural gas. 

Natural gas can make an important 

contribution to GHG reduction in coming 

decades, but investment in low-emission 

technologies, such as nuclear, CCS and 

renewables, should be actively pursued 

to ensure that a mitigation regime can be 

sustained in the longer term.

Natural Gas for Electric Power

In the U.S., around 30% of natural gas is 

consumed in the electric power sector. Within 

the power sector, gas-fired power plants play 

a critical role in the provision of peaking 

capacity, due to their inherent ability to respond 

rapidly to changes in demand. In 2009, 23% of 

the total power generated was from natural gas, 

while natural gas plants represented over 40% 

of the total generating capacity.

In a carbon-constrained world, the power 

sector represents the best opportunity for a 

significant increase in natural gas demand, in 

direct competition with other primary energy 

sources. Displacement of coal-fired power by 

gas-fired power over the next 25 to 30 years is 

the most cost-effective way of reducing CO2

emissions in the power sector.

As a result of the boom in the construction 

of gas-fired power plants in the 1990s, there 

is a substantial amount of underutilized NGCC 

capacity in the U.S. today. In the short term, 

displacement of coal-fired power by gas-fired 

power provides an opportunity to reduce CO2

emissions from the power sector by about 20%, 

at a cost of less than $20/ton of CO2 avoided. 

This displacement would use existing generating 

capacity, and would, therefore, require little in 

the way of incremental capital expenditure for 

new generation capacity. It would also significantly reduce pollutants such as sulfur dioxide 

(SO2), nitrous oxide (NOX), particulates and 

mercury (Hg). 
10 MIT STUDY ON THE FUTURE OF NATURAL GAS

Natural gas-fired power generation provides the 

major source of backup to intermittent renewable supplies in most U.S. markets. If policy 

support continues to increase the supply of 

intermittent power, then, in the absence of 

affordable utility-scale storage options, additional natural gas capacity will be needed to 

provide system reliability. In some markets, 

existing regulation does not provide the 

appropriate incentives to build incremental 

capacity with low load factors, and regulatory 

changes may be required.

In the short term, where a rapid increase in 

renewable generation occurs without any 

adjustment to the rest of the system, increased 

renewable power displaces gas-fired power 

generation and thus reduces demand for 

natural gas in the power sector. In the longer 

term, where the overall system can adjust 

through plant retirements and new construction, increased renewables displace baseload 

generation. This could mean displacement of 

coal, nuclear or NGCC generation, depending 

on the region and policy scenario under 

consideration. For example, in the 50% CO2

reduction scenario described earlier, where 

gas-fired generation drives out coal generation, 

increased renewable penetration as a result of 

cost reduction or government policy will 

reduce natural gas generation on a nearly 

one-for-one basis.

MAJOR RECOM MENDATIONS

The displacement of coal generation with 

NGCC generation should be pursued as 

the most practical near-term option for 

significantly reducing CO2 emissions from 

power generation.

In the event of a significant penetration 

of intermittent renewable production in 

the generation technology mix, policy and 

regulatory measures should be developed 

to facilitate adequate levels of investment 

in natural gas generation capacity to ensure 

system reliability and efficiency. 

END USE GAS DEMAND 

In the U.S., around 32% of all natural gas 

consumption is in the Industrial sector, where 

its primary uses are for boiler fuel and process 

heat; and 35% of use is in the Residential and 

Commercial sectors, where its primary application is space heating. Only 0.15% of natural gas 

is used as a vehicle transportation fuel.

Industrial, Commercial and Residential

Within the Industrial sector, there are opportunities for improved efficiency of the Industrial 

boiler fleet, replacing less-efficient natural gas 

boilers with high-efficiency, or super-high 

efficiency boilers with conversion efficiencies up 

to 94%. There are also opportunities to improve 

the efficiency of natural gas use in process 

heating and to reduce process heating requirements through changes in process technologies 

and material substitutions.

Our analysis suggests that conversion of 

coal-fired boilers in the Industrial sector to 

high-efficiency gas boilers could provide a 

cost-effective option for compliance with new 

hazardous air pollutant reductions and create 

significant CO2 reduction opportunities at 

modest cost, with a potential to increase natural 

gas demand by up to 0.9 Tcf/year.

Natural gas and natural gas liquids (NGLs) are 

a principal feedstock in the chemicals industry 

and a growing source of hydrogen production 

for petroleum refining. Our analysis of selected 

cases indicates that a robust domestic market 

for natural gas and NGLs will improve the 

competitiveness of manufacturing industries 

dependent on these inputs.

Natural gas has significant advantages in the 

Residential and Commercial sectors due in part 

to its cleanliness and life cycle energy efficiency. 

However, understanding the comparative 

cost-effectiveness and CO2 impacts of different 

energy options is complex. Comparison of 
Chapter 1: Overview and Conclusions 11

end use or “site” energy efficiencies can be 

misleading, since it does not take into account 

full system energy use and emissions (such as 

the efficiency and emissions of electricity 

generation). However, quantitatively accounting for the full system impacts from the “source” 

can be challenging, requiring a complex 

end-to-end, full fuel cycle (FFC) analysis that 

is not generally available to the consumer 

or to the policy maker.

Consumer and policy maker choices are further 

complicated by the influence of local climatic 

conditions and regional energy markets. The 

primary energy mix of the regional generation 

mix fundamentally affects “site versus source” 

energy and emissions comparisons. And the 

local climate has a major influence on the best 

choice of heating and cooling systems, particularly the appropriate use of modern space 

conditioning technologies such as heat pumps. 

Consumer information currently available to 

consumers does not facilitate well-informed 

decision making.

Expanded use of combined heat and power 

(CHP) has considerable potential in the Industrial and large Commercial sectors. However, 

cost, complexity and the inherent difficulty of 

balancing heat and power loads at a very small 

scale make residential CHP a much more 

difficult proposition.

MAJOR RECOM MENDATIONS

Improved energy efficiency metrics, which 

allow consumers to accurately compare 

direct fuel and electricity end uses on a full 

fuel cycle basis, should be developed. 

Over time, these metrics should be tailored 

to account for geographical variations in the 

sources of electric power supply and local 

climate conditions.

Transportation

The ample domestic supply of natural gas has 

stimulated interest in its use in transportation. 

There are multiple drivers: the oil-natural gas 

price spread on an energy basis generally favors 

natural gas, and today that spread is at historically high levels; an opportunity to lessen oil 

dependence in favor of a domestically supplied 

fuel, including natural gas-derived liquid fuels 

with modest changes in vehicle and/or infrastructure requirements and reduced CO2

emissions in direct use of natural gas. 

Compressed natural gas (CNG) offers a significant opportunity in U.S. heavy-duty vehicles 

used for short-range operation (buses, garbage 

trucks, delivery trucks), where payback times 

are around three years or less and infrastructure 

issues do not impede development. However, 

for light passenger vehicles, even at 2010 

oil-natural gas price differentials, high incremental costs of CNG vehicles lead to long 

payback times for the average driver, so significant penetration of CNG into the passenger 

fleet is unlikely in the short term. Payback 

periods could be reduced significantly if the 

cost of conversion from gasoline to CNG could 

be reduced to the levels experienced in other 

parts of the world such as Europe.

LNG has been considered as a transport fuel, 

particularly in the long-haul trucking sector. 

However, as a result of operational and infrastructure considerations as well as high incremental costs and an adverse impact on resale 

value, LNG does not appear to be an attractive 

option for general use. There may be an 

opportunity for LNG in the rapidly expanding 

segment of hub-to-hub trucking operations, 

where infrastructure and operational challenges 

can be overcome.
12 MIT STUDY ON THE FUTURE OF NATURAL GAS

Energy density, ease of use and infrastructure 

considerations make liquid fuels that are stable 

at room temperature a compelling choice in the 

Transportation sector. The chemical conversion 

of natural gas to liquid fuels could provide an 

attractive alternative to CNG. Several pathways 

are possible, with different options yielding 

different outcomes in terms of total system CO2

emissions and cost. Conversion of natural gas 

to methanol, as widely practiced in the chemicals industry, could provide a cost-effective 

route to manufacturing an alternative, or 

supplement, to gasoline, while keeping CO2

emissions at roughly the same level. Gasoline 

engines can be modified to run on methanol 

at modest cost.

MAJOR RECOM MENDATIONS

The U.S. government should consider 

revision to its policies related to CNG 

vehicles, including how aftermarket CNG 

conversions are certified, with a view to 

reducing up-front costs and facilitating 

CNG-gasoline capacity.

The U.S. government should implement an 

open fuel standard that requires automobile 

manufacturers to provide tri-flex fuel 

(gasoline, ethanol and methanol) operation 

in light-duty vehicles. Support for methanol 

fueling infrastructure should also be 

considered.

Infrastructure

The continental U.S. has a vast, mature and 

robust natural gas infrastructure, which 

includes: over 300,000 miles of transmission 

lines; numerous natural gas-gathering systems; 

storage sites; processing plants; distribution 

pipelines and LNG import terminals.

Several trends are having an impact on natural 

gas infrastructure. These include changes in 

U.S. production profiles, with supplies generally 

shifting from offshore Gulf of Mexico back to 

onshore; shifts in U.S. population, generally 

from the Northeast and Midwest to the South 

and West and growth in global LNG markets, 

driven by price differences between regional 

markets.

The system generally responds well to market 

signals. Changing patterns of supply and 

demand have led to a significant increase in 

infrastructure development over the past few 

years with West to East expansions dominating 

pipeline capacity additions. Infrastructure 

limitations can temporarily constrain production in emerging production areas such as the 

Marcellus shale — but infrastructure capacity 

expansions are planned or underway. Demand 

increases and shifts in consumption and 

production are expected to require around 

$210 billion in infrastructure investment over 

the next 20 years.

Much of the U.S. pipeline infrastructure is 

old — around 25% of U.S. natural gas pipelines 

are 50 years old or older — and recent incidents 

demonstrate that pipeline safety issues are a 

cause for concern. The Department of Transportation (DOT) regulates natural gas pipeline 

safety and has required integrity management 

programs for transmission and distribution 

pipelines. The DOT also supports a small 

pipeline safety research program, which seems 

inadequate given the size and age of the pipeline infrastructure.

Increased use of natural gas for power generation has important implications for both 

natural gas and electric infrastructures, including natural gas storage. Historically, injections 

and withdrawals from natural gas storage have 

been seasonal. Increased use of natural gas for 

power generation may require new highdeliverability natural gas storage to meet more 

variable needs associated with power generation.
Chapter 1: Overview and Conclusions 13

MAJOR RECOM MENDATIONS

Analysis of the infrastructure demands 

associated with potential shift from coal to 

gas-fired power should be undertaken.

Pipeline safety technologies should be 

included in natural gas RD&D programs.

END USE EMISSIONS VERSUS 

SYSTEM-WIDE EMISSIONS 

When comparing GHG emissions for different 

energy sources, attention should be paid to the 

entire system. In particular, the potential for 

leakage of small amounts of methane in the 

production, treatment and distribution of coal, 

oil and natural gas has an effect on the total 

GHG impact of each fuel type. The modeling 

analysis in Chapter 3 addresses the system-wide 

impact, incorporating methane leakage from 

coal, oil and natural gas production, processing 

and transmission. In Chapter 5 we do not 

attempt to present detailed full-system accounting of CO2 (equivalent) emissions for various 

end uses, although we do refer to its potential 

impact in specific instances. 

The CO2 equivalence of methane is conventionally based on a Global Warming Potential 

(GWP)3

 intended to capture the fact that each 

GHG has different radiative effects on climate 

and different lifetimes in the atmosphere. 

In our considerations, we follow the standard 

Intergovernmental Panel on Climate Change 

(IPCC) and EPA definition that has been widely 

employed for 20 years. Several recently published 

life cycle emissions analyses do not appear to be 

comprehensive, use common assumptions or 

recognize the progress made by producers to 

reduce methane emissions, often to economic 

benefit. We believe that a lot more work is 

required in this area before a common understanding can be reached. Further discussion 

can be found in Appendix 1A.

MAJOR RECOM MENDATIONS

The EPA and the U.S. Department of Energy 

(DOE) should co-lead a new effort to review, 

and update as appropriate, the methane 

emission factors associated with natural 

gas production, transmission, storage 

and distribution. The review should have 

broad-based stakeholder involvement and 

should seek to reach a consensus on the 

appropriate methodology for estimating 

methane emissions rates. The analysis 

should, to the extent possible: (a) reflect 

actual emissions measurements; (b) address 

fugitive emissions for coal and oil as well as 

natural gas; and (c) reflect the potential for 

cost-effective actions to prevent fugitive 

emissions and venting of methane.

MARKETS AND GEOPOLITICS

The physical characteristics of natural gas, 

which create a strong dependence on pipeline 

transportation systems, have led to local 

markets for natural gas – in contrast to the 

global markets for oil.

There are three distinct regional gas markets: 

North America, Europe and Asia, with more 

localized markets elsewhere. The U.S. gas 

market is mature and sophisticated, and 

functions well, with a robust spot market. 

Within the U.S. market, the price of oil, (which 

is set globally) compared to the price of natural 

gas (which is set regionally) is very important 

in determining market share when there is the 

opportunity for substitution. Over the last 

decade or so, when oil prices have been high, 

the ratio of the benchmark West Texas Intermediate oil price to the Henry Hub natural gas 

price has been consistently higher than any of 

the standard rules of thumb. 
14 MIT STUDY ON THE FUTURE OF NATURAL GAS

International natural gas markets are in the 

early stages of integration, with many impediments to further development. While increased 

LNG trade has started to connect these markets, they remain largely distinct with respect 

to supply patterns, pricing and contract structures, and market regulation. If a more integrated market evolves, with nations pursuing 

gas production and trade on an economic basis, 

there will be rising trade among the current 

regional markets and the U.S. could become 

a substantial net importer of LNG in future 

decades. 

Greater international market liquidity would 

be beneficial to U.S. interests. U.S. prices for 

natural gas would be lower than under current 

regional markets, leading to more gas use in the 

U.S. Greater market liquidity would also 

contribute to security by enhancing diversity 

of global supply and resilience to supply 

disruptions for the U.S. and its allies. These 

factors ameliorate security concerns about 

import dependence. 

As a result of the significant concentration of 

conventional gas resources globally, policy and 

geopolitics play a major role in the development of global supply and market structures. 

Consequently, since natural gas is likely to play 

a greater role around the world, natural gas 

issues will appear more frequently on the U.S. 

energy and security agenda. Some of the 

specific security concerns are: 

s .ATURAL GAS DEPENDENCE INCLUDING THAT

of allies, could constrain U.S. foreign policy 

options, especially in light of the unique 

American international security 

responsibilities. 

s .EW MARKET PLAYERS COULD INTRODUCE

impediments to the development of 

transparent markets. 

s #OMPETITION FOR CONTROL OF NATURAL GAS

pipelines and pipeline routes is intense in 

key regions. 

s ,ONGER SUPPLY CHAINS INCREASE THE VULNER


ability of the natural gas infrastructure. 

MAJOR RECOM MENDATIONS

The U.S. should pursue policies that 

encourage the development of an efficient 

and integrated global gas market with 

transparency and diversity of supply.

Natural gas issues should be fully integrated 

into the U.S. energy and security agenda, 

and a number of domestic and foreign 

policy measure should be taken, including:

t JOUFHSBUJOH FOFSHZ JTTVFT GVMMZ JOUP UIF

conduct of U.S. foreign policy, which will 

require multiagency coordination with 

leadership from the Executive Office of 

the President; 

t TVQQPSUJOH UIF FõPSUT PG UIF *OUFSOBUJPOBM

Energy Agency (IEA) to place more attention on natural gas and to incorporate the 

large emerging markets (such as China, 

India and Brazil) into the IEA process as 

integral participants; 

t TIBSJOH LOPXIPX GPS UIF TUSBUFHJD

expansion of unconventional resources; 

and

t BEWBODJOH JOGSBTUSVDUVSF QIZTJDBM BOE

cyber-security as the global gas delivery 

system becomes more extended and 

interconnected. 
Chapter 1: Overview and Conclusions 15

RD&D

There are numerous RD&D opportunities to 

address key objectives for natural gas supply, 

delivery and end use:

s IMPROVE THE LONG
TERM ECONOMICS OF RESOURCE

development as an important contributor to 

the public good;

s REDUCE THE ENVIRONMENTAL FOOTPRINT OF

natural gas production, delivery and use;

s EXPAND CURRENT USE AND CREATE ALTERNATIVE

applications for public policy purposes, such 

as emissions reductions and diminished oil 

dependence;

s IMPROVE SAFETY AND OPERATION OF NATURAL GAS

infrastructure;

s IMPROVE THE EFlCIENCY OF NATURAL GAS CONVERsion and end-use so as to use the resource 

most effectively.

Historically, RD&D funding in the natural gas 

industry has come from a variety of sources, 

including private industry, the DOE, and 

private/public partnerships. In tandem with 

limited tax credits, this combination of support 

played a major role in development of unconventional gas. It has also contributed to more 

efficient end-use, for example in the development of high-efficiency gas turbines. 

Today government funded RD&D for natural 

gas is at very low levels. The elimination of 

rate-payer funded RD&D has not been compensated by increased DOE appropriations 

or by a commensurate new revenue stream 

outside the appropriations process. The total 

public and public-private funding for natural 

gas research is down substantially from its peak 

and is more limited in scope, even as natural 

gas takes a more prominent role in a carbonconstrained world.

While natural gas can provide a cost-effective 

bridge to a low carbon future, it is vital that 

efforts continue to improve the cost and 

efficiency of low or zero carbon technologies 

for the longer term. This will require sustained 

RD&D and subsidies of limited duration to 

encourage early deployment.

MAJOR RECOM MENDATIONS

The Administration and Congress should 

support RD&D focused on environmentally 

responsible domestic natural gas supply. 

This should entail both a renewed 

DOE program, weighted towards basic 

research, and a complementary industryled program, weighted towards applied 

research, development and demonstration, 

that is funded through an assured funding 

stream tied to energy production, delivery 

and use. The scope of the program should 

be broad, from supply to end-use. 

Support should be provided through RD&D, 

and targeted subsidies of limited duration, 

for low-emission technologies that have the 

prospect of competing in the long run. This 

would include renewables, carbon capture 

and sequestration for both coal and gas 

generation, and nuclear power.
16 MIT STUDY ON THE FUTURE OF NATURAL GAS

CONCLUSION

Over the past few years, the U.S. has developed 

an important new natural gas resource that 

fundamentally enhances the nation’s long-term 

gas supply outlook. Given an appropriate 

regulatory environment, which seeks to place 

all lower carbon energy sources on a level 

competitive playing field, domestic supplies 

of natural gas can play a very significant role 

in reducing U.S. CO2 emissions, particularly 

in the electric power sector. This lowest cost 

strategy of CO2 reduction allows time for the 

continued development of more cost-effective 

low or zero carbon energy technology for the 

longer term, when gas itself is no longer 

sufficiently low carbon to meet more stringent 

CO2 reduction targets. The newly realized 

abundance of low cost gas provides an enormous potential benefit to the nation, providing 

a cost effective bridge to a secure and low 

carbon future. It is critical that the additional 

time created by this new resource is spent 

wisely, in creating lower cost technology 

options for the longer term, and thereby 

ensuring that the natural gas bridge has 

a safe landing place in a low carbon future.

NOTES

1One quadrillion Btu (or “quad”) is 1015 or 

1,000,000,000,000,000 British thermal units. Since 

one standard cubic foot of gas is approximately 

1,000 Btu, then 1 quad is approximately 1 Tcf 

of gas.

2

EIA 2009 Annual Energy Review, Figure 45.

3

Global-warming potential (GWP) is a relative 

measure of how much heat a given greenhouse gas 

traps in the atmosphere.
Chapter 2: Supply 17

Chapter 2: Supply

INTRODUCTION AND CONTEXT

In this chapter, we discuss various aspects of 

natural gas supply: how much natural gas exists 

in the world; at what rate can it be produced 

and what it will cost to develop. Following the 

introduction and definitions, we look at production history, resource volumes and supply costs 

for natural gas — first from a global perspective, 

and then focusing in more detail on the U.S., 

paying particular attention to the prospects for 

shale gas. We then discuss the science and 

technology of unconventional gas, the environmental impacts of shale gas development and 

finally the prospects for methane hydrates.

NATURAL GAS AND THE

RECOVERY PROCESS

The primary chemical component of natural gas 

is methane, the simplest and lightest hydrocarbon molecule, comprised of four hydrogen (H) 

atoms bound to a single carbon (C) atom. In 

chemical notation, this is expressed as CH4

(the symbol for methane). Natural gas may 

also contain small proportions of heavier 

hydrocarbons: ethane (C2

H6); propane (C3H8) 

and butane (C4

H10); these heavier components 

are often extracted from the producing stream 

and marketed separately as natural gas liquids 

(NGL). In the gas industry, the term “wet gas” 

is used to refer to natural gas in its raw unprocessed state, while “dry gas” refers to natural gas 

from which the heavier components have been 

extracted.

Thermogenic1

 natural gas, which is formed by 

the application, over geological time, of enormous 

heat and pressure to buried organic matter, 

exists under pressure in porous rock formations 

thousands of feet below the surface of the earth. 

It exists in two primary forms: “associated gas” is 

formed in conjunction with oil, and is generally 

released from the oil as it is recovered from the 

reservoir to the surface — as a general rule the 

gas is treated as a by-product of the oil production process; in contrast, “non-associated gas” is 

found in reservoirs that do not contain oil, and is 

developed as the primary product. While associated gas is an important source, the majority of 

gas production is non-associated; 89% of the gas 

produced in the U.S. is non-associated.

Non-associated gas is recovered from the formation by an expansion process. Wells drilled into 

the gas reservoir allow the highly compressed 

gas to expand through the wells in a controlled 

manner, to be captured, treated and transported 

at the surface. This expansion process generally 

leads to high recovery factors from conventional, 

good-quality gas reservoirs. If, for example, the 

average pressure in a gas reservoir is reduced 

from an initial 5,000 pounds per square inch 

(psi) to 1,000 psi over the lifetime of the field, 

then approximately 80% of the Gas Initially In 

Place (GIIP) will be recovered. This is in contrast 

to oil, where recovery factors of 30% to 40% are 

more typical.

Gas is found in a variety of subsurface locations, 

with a gradation of quality as illustrated in the 

resource triangle in Figure 2.1.
18 MIT STUDY ON THE FUTURE OF NATURAL GAS

Conventional resources exist in discrete, 

well-defined subsurface accumulations (reservoirs), with permeability2

 values greater than 

a specified lower limit. Such conventional 

gas resources can usually be developed using 

vertical wells, and generally yield the high 

recovery factors described above.

By contrast, unconventional resources are 

found in accumulations where permeability is 

low. Such accumulations include “tight” 

sandstone formations, coal beds (coal bed 

methane or CBM) and shale formations. 

Unconventional resource accumulations tend 

to be distributed over a larger area than conventional accumulations and usually require 

advanced technology such as horizontal wells 

or artificial stimulation in order to be economically productive; recovery factors are much 

lower — typically of the order of 15% to 30% 

of GIIP. The various resource types are shown 

schematically in Figure 2.2.

Adapted from Holditch 2006

Figure 2.1 GIIP as a Pyramid in Volume and Quality. Conventional reservoirs are at the 

top of the pyramid. They are of higher quality because they have high permeability 

and require less technology for development and production. The unconventional 

reservoirs lie below the conventional reservoirs in this pyramid. They are more 

abundant in terms of GIIP but are currently assessed as recoverable resources — and 

commercially developed — primarily in North America. They have lower permeability, 

require advanced technology for production and typically yield lower recovery factors 

than conventional reservoirs. 

Conventional 

Resources

Unconventional 

Resources

High-Quality

Reservoirs

Low-Quality

Reservoirs

Tight Gas

Sands

Coal Bed

Methane Shale Gas

Methane Hydrates

Volume

Increasing 

Technology/Decreasing Recovery Factor
Chapter 2: Supply 19

RESOURCE DEFINITIONS

The complex cross-dependencies between 

geology, technology and economics mean that 

the use of unambiguous terminology is critical 

when discussing natural gas supply. In this 

study, the term “resource” will refer to the sum 

of all gas volumes expected to be recoverable in 

the future, given specific technological and 

economic conditions. The resource can be 

disaggregated into a number of sub-categories; 

specifically, “proved reserves,” “reserve growth” 

(via further development of known fields) and 

“undiscovered resources,” which represent gas 

volumes that are expected to be discovered in 

the future via the exploration process. 

Figure 2.3 illustrates how proved reserves, 

reserve growth and undiscovered resources 

combine to form the “technically recoverable 

resource,” that is, the total volume of natural 

gas that could be recovered in the future, 

using today’s technology, ignoring economic 

constraints.

Figure 2.2 Illustration of Various Types of Gas Resource

Land surface

Coal bed methane

Conventional

associated gas

Tight sand

gas

Sandstone

Seal

Gas-rich shale

Conventional

non-associated

gas

Schematic geology of natural gas resource

Oil

Source: U.S. Energy Information Administration

Gas resources are an economic concept — a function 

of many variables, in particular the cost of exploration, 

production and transportation relative to the price 

of sale to users. 
20 MIT STUDY ON THE FUTURE OF NATURAL GAS

The methodology used in analyzing natural gas 

supply for this study places particular emphasis 

in two areas:

1. Treating gas resources as an economic 

concept — recoverable resources are a 

function of many variables, particularly the 

ultimate price that the market will pay. A set 

of supply curves has been developed using 

the ICF3

 Hydrocarbon Supply Model with 

volumetric and fiscal input data supplied by 

ICF and MIT. These curves describe the 

volume of gas that is economically recoverable for a given gas price. These curves form 

a primary input to the integrated economic 

modelling in Chapter 3 of this report.

2. Recognizing and embracing uncertainty — 

uncertainty exists around all resource 

estimates due to the inherent uncertainty 

associated with the underlying geological, 

technological, economic and political 

conditions. The analysis of natural gas 

supply in this study has been carried out 

in a manner that frames any single point 

resource estimate within an associated 

uncertainty envelope, in order to illustrate 

the potentially large impact this everpresent uncertainty can have.

The volumetric data used as the basis of the 

analysis for both the supply curve development 

and the volumetric uncertainty analysis was 

compiled from a range of sources. In particular, 

use has been made of data from work at the 

United States Geological Survey (USGS), the 

Potential Gas Committee (PGC), the Energy 

Information Agency (EIA), the National 

Petroleum Council (NPC) and ICF International. 

Figure 2.3 Modified McKelvey Diagram, Showing the Interdependencies between 

Geology, Technology and Economics and Their Impacts on Resource Classes; Remaining 

Technically Recoverable Resources Are Outlined in Red Increasing Economic Viability Sub-economic Economic

Technically

Recoverable

Technically

Unrecoverable

Unconfirmed

Discovered/Identified

Undiscovered

Increasing Geologic Knowledge

Confirmed

Reserves

Cumulative

Production

Inferred

Reserves/

Reserve

Growth

Undiscovered

Technically

Recoverable

Resources
Chapter 2: Supply 21

GLOBAL SUPPLY

Production Trends

Over the past two decades, global production 

of natural gas has grown significantly, rising 

by almost 42% overall from approximately 

74 trillion cubic feet (Tcf )4

 in 1990 to 105 Tcf 

in 2009. This is almost twice the growth rate 

of global oil production, which increased by 

around 22% over the same period. Much of the 

gas production growth has been driven by the 

rapid expansion of production in areas that 

were not major gas producers prior to 1990. 

This trend is illustrated in Figure 2.4, which 

shows how growth in production from regions 

such as the Middle East, Africa and Asia & 

Oceania has significantly outpaced growth in 

the traditional large producing regions, including North America and Eurasia (primarily 

Russia).

Figure 2.5 compares the 1990 and 2009 annual 

production levels for the 10 largest gas-producing 

nations (as defined by 2009 output). In addition 

to demonstrating the overwhelming scale of 

the United States and Russia compared to other 

producing countries, this figure illustrates the 

very significant growth rates in other countries. 

The substantial growth of new gas producing 

countries over the period reflects the relative 

immaturity of the gas industry on a global 

basis outside Russia and North America, the 

expansion of gas markets and the rise in global 

cross-border gas trade.

Between 1993 and 2008, global cross-border gas 

trade almost doubled, growing from around 

18 Tcf (25% of global supply) to around 35 Tcf 

(32% of global supply). Most of the world’s gas 

supply is transported from producing fields to 

market by pipeline. However, the increase in 

global gas trade has been accelerated by the 

growing use of Liquefied Natural Gas (LNG), 

which is made by cooling natural gas to around 

-162°C. Under these conditions, natural gas 

becomes liquid, with an energy density 600 

times that of gas at standard temperature and 

pressure — and it can be readily transported 

over long distances in specialized ocean-going 

Figure 2.4 Trends in Annual Global Dry Gas Production by Region between 1990 and 2009 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

120

100

80

60

40

20

0

Tcf of Gas

S. & C. America

Africa

Europe

Middle East

Asia & Oceania

North America

Eurasia

Source: MIT; U.S. Energy Information Administration
22 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 2.5 Comparison of 1990 and 2009 Natural Gas Production Levels for the Top 10 

Natural Gas Producing Nations (as defined by 2009 output)

0

5

10

15

20

25

United States

Russia

Canada

Iran

Norway

Quatar

China

Algeria

Netherlands

Saudi Arabia

1990

2009

Tcf of Gas

Source: MIT; U.S. Energy Information Administration

Figure 2.6 Global Cross-Border Gas Trade

0

5

10

15

20

25

30

35

8.0

26.4

3.0

14.8

1993 2008

LNG

Pipeline

Tcf of Gas

Source: MIT; U.S. Energy Information Administration
Chapter 2: Supply 23

LNG tankers. Over this 15-year period, global 

gas trade doubled, while LNG trade increased 

even more rapidly, as shown in Figure 2.6.

RESOURCES5

Global natural gas resources are abundant. The 

mean remaining resource base is estimated to 

be 16,200 Tcf, with a range between 12,400 Tcf 

(with a 90% probability of being exceeded) and 

20,800 Tcf (with a 10% probability of being 

exceeded). The mean projection is 150 times 

the annual consumption in 2009. With the 

exception of Canada and the U.S., this estimate 

does not include any unconventional supplies. 

The global gas supply base is relatively immature; outside North America only 11% of the 

estimated ultimately recoverable conventional 

resources have been produced to date.

Figure 2.7 depicts the estimated remaining 

recoverable gas resources, together with estimated uncertainty,6

 broken down by regions as 

defined by the Emissions Prediction and Policy 

Analysis (EPPA) model employed in Chapter 3 

of this report. Figure 2.8 depicts the geographical distribution of EPPA regions, together with 

the mean resource estimate for each region. 

The resources are comprised of three major 

components defined above: reserves, reserve 

growth and yet-to-find resources. For the U.S. 

and Canada, we have also included a fourth 

category, unconventional resources. As discussed 

later, due to the very high levels of uncertainty 

at this stage, we have not included unconventional resource estimates for other regions. 

Source: MIT analysis based on data and information from: Ahlbrandt et al. 2005; United States Geological 

Survey 2010; National Petroleum Council 2003; United States Geological Survey n.d.; Potential Gas Committee 

1990; Attanasi & Coburn 2004; Energy Information Administration 2009

Figure 2.7 Global Remaining Recoverable Gas Resource by EPPA Region, with Uncertainty

Tcf of gas

0 1,000 2,000 3,000 4,000 5,000 6,000

0.0

0.2

0.4

0.6

0.8

1.0

Middle East

Russia

United States

Africa

Central Asia and

Rest of Europe

Canada

Rest of Americas

EU27 and Norway

Dynamic Asia

Brazil

Rest of East Asia

Australia and Oceania

China

Mexico

India

Reserve Growth (Mean)

Total Reserves

Conventional Undiscovered Gas (Mean)

Unconventional Gas (Mean)

Low

RRR

High

RRR
24 MIT STUDY ON THE FUTURE OF NATURAL GAS

Although resources are large, the supply base is 

concentrated geographically, with an estimated 

70% in only three regions: Russia, the Middle 

East (primarily Qatar and Iran) and North 

America (where North American resources 

also include unconventional gas). By some 

measures, global supplies of natural gas are 

even more geographically concentrated than oil 

supplies. Political considerations and individual 

country depletion policies play at least as big a 

role in global gas resource development as 

geology and economics, and dominate the 

evolution of the global gas market.

Figure 2.8 Map of EPPA Regions, and Mean Resource Estimates

Middle East [4670 TCF]

Russia [3410 TCF]

United States [2150 TCF]

Africa [1050 TCF]

Eastern Europe and Central Asia [940 TCF]

Rest of East Asia [240 TCF]

Austria and Oceania [225 TCF]

China [210 TCF]

India/Mexico [95/50 TCF]

Japan [~0 TCF]

Canada [820 TCF]

Rest of Americas [800 TCF]

EU27 and Norway [720 TCF]

Dynamic Asia [480 TCF]

Brazil [350 TCF]

Source: EPPA, MIT
Chapter 2: Supply 25

SUPPLY COSTS7

Figure 2.9 depicts a set of global supply curves, 

which describe the resources of gas that can be 

developed economically at given prices at the 

point of export.The higher the price, the more 

gas will ultimately be developed. Much of the 

global supply can be developed economically 

with relatively low prices at the wellhead or the 

point of export.8

 However, the cost of delivering 

this gas to market is generally considerably 

higher. 

In contrast to oil, the total cost of delivering gas 

to international markets is strongly influenced 

by transportation costs, either via long-distance 

pipeline or as LNG. Transportation costs will 

obviously be a function of distance, but by way 

of illustration, resources that can be economically 

developed at a gas price of $1 or $2/million 

British thermal units (MMBtu) may well require 

an additional $3 to $5/MMBtu of transport costs 

to get to their ultimate destination. These high 

transportation costs are also a significant factor 

in the evolution of the global gas market.

Figure 2.10 depicts the mean gas supply curves 

for those EPPA regions that contain significant 

gas resources. Again, this illustrates the significant 

concentration of gas resources in the world. 

In contrast to oil, the total cost of getting gas 

to international markets is strongly influenced 

by the cost of transportation — a significant factor 

in the evolution of the global gas market.

Figure 2.9 Global Gas Supply Cost Curve, with Uncertainty; 2007 Cost Base

20.00

18.00

16.00

14.00

12.00

10.00

8.00

6.00

4.00

2.00

0

Breakeven gas price at point of export:

$/MMBtu

Tcf of gas

0 3,000 6,000 9,000 12,000 15,000 18,000

Low

Mean

High

Example LNG value chain

costs incurred during 

gas delivery

$/MMBtu

Liquefaction $2.15

Shipping $1.25

Regasi!cation $0.70

Total $4.10

15000

20000

0.0

0.2

0.4

0.6

0.8

1.0

Low

12,400

High

20,800

Volumetric uncertainty around

mean of 16,200 Tcf

Source: MIT; ICF Global Hydrocarbon Supply Model
26 MIT STUDY ON THE FUTURE OF NATURAL GAS

UNCONVENTIONAL RESOURCES9

Outside of Canada and the U.S., there has been 

very little development of the unconventional 

gas supply base — indeed there has been little 

need when conventional resources are so 

abundant. But due to this lack of development, 

unconventional resource estimates are sparse 

and unreliable. 

Based on an original estimate by Rogner10, 

there may be of the order of 24,000 Tcf of 

unconventional GIIP outside North America. 

Applying a nominal 25% recovery factor, this 

would imply around 6,000 Tcf of unconventional recoverable resources. However, these 

global estimates are highly speculative, almost 

completely untested and subject to very wide 

bands of uncertainty. There is a long-term need 

for basin-by-basin resource evaluation to 

provide credibility to the GIIP estimates and, 

most importantly, to establish realistic estimates 

of recoverable resource volumes and costs11.

Given the concentrated nature of conventional 

supplies and the high costs of long-distance 

transportation, there may be considerable 

strategic and economic value in the development 

of unconventional resources in those regions 

that are currently gas importers, such as Europe 

and China. It would be in the strategic interest 

of the U.S. to see these indigenous supplies 

developed. As a market leader in this technology, the U.S. could play a significant role in 

facilitating this development.

RECOMMENDATION

U.S. policy should encourage the strategic 

development of unconventional gas 

supplies in regions which currently depend 

on imported gas, in particular, Europe 

and China.

0 500 1,000 1,500 2,000 2,500 3,000 3.500 4,000 4,500 5,000

$20.00

$15.00

$10.00

$5.00

$0

Africa

Australia 

and Oceania

Brazil

China

Dynamic Asia

Europe

India

Mexico

Middle East

Rest of Americas

Rest of East Asia

Rest of Europe 

and Central Asia

Russia

Breakeven Gas Price

$MMBtu

Africa

Australia 

and Oceania

Brazil

China

Dynamic Asia

Europe

India

Mexico

Middle East

North America

Rest of Americas

Rest of East Asia

Rest of Europe 

and Central Asia

Russia

Figure 2.10 Global Gas Supply Cost Curve by EPPA Region; 2007 Cost Base

Source: MIT; ICF Global Hydrocarbon Supply Model
Chapter 2: Supply 27

UNITED STATES SUPPLY

Production Trends

There is significant geographical variation in 

U.S. natural gas production levels. For the 

purposes of this discussion of U.S. production, 

we will use the U.S. EIA pipeline regions 

(Figure 2.11).

Natural gas production in the U.S. has traditionally been associated with the Southwest 

region and the Gulf of Mexico. However, 

significant production also takes place in Alaska 

and in the Central region. In the case of Alaska, 

the vast majority of the gas is associated with 

oil production on the North Slope, and due to 

the lack of an export mechanism, this gas is 

re-injected to enhance recovery from Alaskan 

oil fields. These gas production volumes are 

therefore not included in the national gas 

production figures reported by the EIA. Small 

volumes of gas are exported from Alaska to 

Japan as LNG.

Figure 2.12 illustrates the regional breakdown 

of dry natural gas production in the U.S. since 

2000. Some level of production occurs in 

all eight regions, but the dominance of the 

Southwest, Gulf of Mexico and Central regions 

is clearly shown. The dynamics of the production levels across these major regions have 

differed appreciably over the past decade. In the 

Southwest, the largest gas producing region, 

annual production levels remained relatively 

flat at about 9.3 Tcf from 2000 to 2005. Since 

2005, output from the region has increased, 

growing by 21% to 11.4 Tcf in 2008. Much of 

this growth in the latter half of the decade is the 

result of rapid expansion in the production of 

gas from shale plays. 

Figure 2.11 EIA Natural Gas Pipeline Regions for the L48 States; the State of Alaska and 

the U.S. Offshore Territory in the Gulf of Mexico Form Two Additional Regions

Central

Western

WA

Southwest

Midwest Northeast

Southeast

ME

VT

NH

MA

RI

CT

DE

PA

NY

NJ

WV MD VA

MN

WI

MI

OH IL IN

KY

SC

TN

MS AL GA

FL

NC

LA

NM AR OK

TX

IA

KS MO

NE

SD

MT ND

WY

UT

CO

OR

ID

AZ

CA

NV

Source: U.S. Energy Information Administration
28 MIT STUDY ON THE FUTURE OF NATURAL GAS

Since 2000, the Central region has seen the 

greatest percentage growth in production 

among U.S. regions. Annual dry gas output has 

risen from 2.6 Tcf to 4.5 Tcf, an overall increase 

of 75%. Unlike the Southwest region, production from the Central region has grown continuously since 2000, with output increasing 

from all resource types. In marked contrast, gas 

output from offshore fields in the Gulf of 

Mexico has fallen dramatically from approximately 5 Tcf in 2000 to 2.4 Tcf in 2008, the 

result of fewer new wells being brought online 

in the Gulf to replace those older wells that are 

now in decline or have been taken off production. This decline is an indication of the 

maturity of the conventional resource base 

in the Gulf of Mexico.

PRODUCTION TRENDS BY RESOURCE

TYPE IN THE UNITED STATES

In a global context, U.S. gas production by type 

is extremely diverse. Both conventional and 

unconventional gas output is significant, with 

the contribution of unconventional gas growing 

steadily year-on-year. 

Figure 2.13a plots contributions to production 

from conventional, unconventional and 

associated gas. This breakdown illustrates the 

marked shift towards unconventional resources 

that has been a feature of gas production in the 

U.S. over the past decade and more. In 2000, 

the combined gross production of conventional 

and associated gas in the L48 states was 14.6 Tcf 

(71% of total output). By 2009, the combined 

conventional and associated output had fallen 

to 11.4 Tcf (52% of the total). In concert with 

this fall in conventional and associated gas 

production, there has been continuous expansion in the production of unconventional gas, 

with approximately 4.5 Tcf more unconventional gas being produced in 2009 than in 2000.

Figure 2.12 Regional Breakdown of Annual Dry Gas Production in the U.S. between 

2000 and 2009

Source: MIT; U.S. Energy Information Administration

Tcf of Gas

0

2

4

6

8

10

12

14

16

18

20

22

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Western

Southwest

Southeast

Northeast

Midwest

GOM

Central

Alaska
Chapter 2: Supply 29

Historically, tight gas has been the most significant source of unconventional gas production 

in the U.S., and is likely to remain so for some 

time. Tracking tight gas production can be 

difficult because it can exist in a continuum 

with conventional gas. However, a review of 

output from known tight plays shows a growth 

in annual output from 4.5 Tcf to 5.6 Tcf 

between 2000 and 2009, an increase from 21% 

to 25% of total gross production as shown in 

Figure 2.13b. Commercial production of CBM 

began at the end of the 1980s, and grew substantially during the 1990s from an output of 

0.2 Tcf in 1990 to 1.3 Tcf in 1999. This growth 

moderated during the last decade, with 2009 

CBM output standing at 1.92 Tcf or 9% of 

the total.

Aside from the fall in conventional production, 

the most striking feature of the gas production 

in the U.S. this past decade has been the 

emergence of shale gas. Although shale 

resources have been produced in the U.S. since 

1821, the volumes have not been significant. 

This situation changed fundamentally during 

the past decade as technological advances 

enabled production from shales previously 

considered uneconomical. Expansion in shale 

gas output is illustrated in Figures 2.13a and 

2.13b. From 2000 to 2009, the contribution of 

shale gas to overall production grew from 0.1 

Tcf, or less than 1%, to 3.0 Tcf, or nearly 14%. 

This growth is all the more remarkable in 

that 80% of it was driven by one play, the 

Barnett shale, located in Texas’ Fort Worth 

Basin. Activity in other shale plays has also 

been increasing, with appreciable volumes 

now being produced from the Fayetteville and 

Woodford shales in the Arkoma Basin, the 

Haynesville shale in the East Texas Basin and 

as of the end of 2009, the Marcellus shale in the 

Appalachian Basin.

Figure 2.13a Breakdown by Type of 

Annual Gross Gas Production in the L48 

U.S. between 2000 and 2009

Figure 2.13b Percentage Breakdown by 

Type of Gross Gas Production in the L48 

U.S. in 2000 and 2009

Source: MIT; HPDI production database

Tcf of Gas

2001 2003 2005 2007 2009 2000 2009

55% 41%

16%

7%

21%

1%

11%

9%

14%

25% Shale

CBM

Tight

Associated

Conventional

0

5

10

15

20

25
30 MIT STUDY ON THE FUTURE OF NATURAL GAS

U.S. RESOURCES12

Table 2.1 illustrates mean U.S. resource estimates from a variety of resource assessment 

authorities. These numbers have tended to 

grow over time, particularly as the true potential of the unconventional resource base has 

started to emerge over the past few years.

For this study, we have assumed a mean 

remaining resource base of around 2,100 Tcf. 

This corresponds to approximately 92 times the 

annual U.S. consumption of 22.8 Tcf in 2009. 

We estimate the low case (with a 90% probability of being met or exceeded) at 1,500 Tcf, and 

the high case (with a 10% probability of being 

met or exceeded) at 2,850 Tcf.

Around 15% of the U.S. resource is in Alaska, 

and full development of this resource will 

require major pipeline construction to bring 

the gas to market in the L48 states. Given the 

abundance of L48 supplies, development of the 

pipeline is likely to be deferred yet again, but 

this gas represents an important resource for 

the future.

In the L48, some 55% to 60% of the resource 

base is conventional gas, both onshore and 

offshore. Although mature, the conventional 

resource base still has considerable potential. 

Around 60% of this resource is comprised of 

proved reserves and reserve growth, with the 

remainder — of the order of 450 to 500 Tcf — 

from expected future discoveries.

NPC USGS/MMS PGC ICF

(2003) (Various Years) (2006) (2008) (2009)

L48

Conventional 691 928

966

869

693

Tight 175 190 174

Shale 35 85 616 631

CBM 58 71 108 99 65

Total L48 959 1,274 1,074 1,584 1,563

Alaska

Conventional 237 357

194

194 237

Tight – –

Shale – – – –

CBM 57 18 57 57 57

Total Alaska 294 375 251 251 294

U.S.

Conventional 929 1,284

1,160

1,063

930

Tight 175 190 174

Shale 35 85 616 631

CBM 115 89 165 156 122

Total U.S. 1,254 1,648 1,325 1,835 1,857

Proved Reserves 184 245 204 245 245

Total (Tcf) 1,438 1,893 1,529 2,080 2,102

Source: National Petroleum Council 2003; United States Geological Survey 2010; Minerals Management Service 2006; 

Potential Gas Committee 2007; Potential Gas Committee 2009; Energy Information Administration 2009

Table 2.1 Tabulation of US Resource Estimates by Type, from Different Sources
Chapter 2: Supply 31

Figure 2.14a represents the supply curves for 

the aggregate of all U.S. resources, depicting the 

mean estimate and the considerable range of 

uncertainty. Figure 2.14b illustrates the mean 

supply curves, broken down by resource type. It 

clearly shows the large remaining conventional 

resource base, although it is mature and some of 

it will require high gas prices to become economical to develop. These curves assume current 

technology. In practice, future technology 

development will enable these costs to be driven 

down over time, allowing a larger portion of the 

resource base to be economically developed.

Figure 2.14b also demonstrates the considerable potential of shale supplies. Using a 2007 

cost base, a substantial portion of the estimated 

shale resource base is economic at prices 

between $4/MMBtu and $8/MMBtu. As we see 

in the current U.S. gas markets, some of the 

shale resources will displace higher-cost conventional gas in the short to medium term, 

exerting downward pressure on gas prices.

Despite the relative maturity of the U.S. gas 

supply, estimates of remaining resources have 

continued to grow over time — with an accelerating trend in recent years, mainly attributable to 

unconventional gas, especially in the shales.

The PGC, which evaluates the U.S. gas resource 

on a biannual cycle, provides perhaps the best 

historical basis for looking at resource growth 

over time. According to this data, remaining 

resources have grown by 77% since 1990, 

despite a cumulative production volume during 

that time of 355 Tcf.

As a subset of this growth process, the application of horizontal drilling and hydraulic 

fracturing technology to the shales has caused 

resource estimates to grow over a five-year 

period from a relatively minor 35 Tcf (NPC, 

2003), to a current estimate of 615 Tcf (PGC, 

2008), with a range of 420 to 870 Tcf. This 

Figure 2.14a Volumetric Uncertainty of U.S. Gas 

Supply Curves; 2007 Cost Base

40.00

36.00

32.00

28.00

24.00

20.00

16.00

12.00

8.00

4.00

0

Breakeven Gas Price

$/MMBtu

Tcf of gas

0 500 1,000 1,500 2,000 2,500 3,000

Low

Mean

High

0

500

1000

1500

2000

2500

3000

0.0

0.2

0.4

0.6

0.8

1.0

Don’t Use This One, has all data, real one is on “chart to cut”

Figure 2.14b Breakdown of Mean U.S. Gas Supply 

Curve by Type; 2007 Cost Base

40.00

36.00

32.00

28.00

24.00

20.00

16.00

12.00

8.00

4.00

0

Breakeven Gas Price

$/MMBtu

Tcf of gas

0 100 200 300 400 500 600 700 800 900 1,000

Conventional

Tight

Shale

CBM

0

200

400

600

800

1000

1200

0.0

0.2

0.4

0.6

0.8

1.0

Don’t Use This One

Source: MIT; ICF North American Hydrocarbon Supply Model Source: MIT; ICF North American Hydrocarbon Supply Model
32 MIT STUDY ON THE FUTURE OF NATURAL GAS

According to Potential Gas Committee data, U.S. 

natural gas remaining resources have grown by 77% 

since 1990, a testament to the power of technology, 

and an illustration of the large uncertainty inherent 

in all resource estimates.

resource growth is a testament to the power 

of technology application in the development 

of resources, and also provides an illustration 

of the large uncertainty inherent in all resource 

estimates. 

The new shale plays represent a major 

contribution to the resource base of the U.S. 

However, it is important to note that there is 

considerable variability in the quality of the 

resources, both within and between shale plays. 

This variability in performance is incorporated 

in the supply curves on the previous page, as 

well as in Figure 2.15. Figure 2.15a shows initial 

production and decline data from three major 

U.S. shale plays, illustrating the substantial 

differences in average well performance 

between the plays. Figure 2.15b shows a probability distribution of initial flow rates from the 

Barnett formation. While many refer to shale 

development as more of a “manufacturing 

process,” where wells are drilled on a statistical 

basis — in contrast to a conventional exploration, development and production process, 

where each prospective well is evaluated on an 

individual basis — this “manufacturing” still 

occurs within the context of a highly variable 

subsurface environment.

Figure 2.15a Illustration of Variation in Mean 

Production Rates between Three Shale Plays

9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

0

Production Rate

Mcf/day (30-day average)

Year

Haynesville

Marcellus

Barnett

0 1 2 3 4 5

0.0

0.2

0.4

0.6

0.8

1.0

Figure 2.15b Illustration of Variation in Initial 

Production Rates of 2009 Vintage Barnett Wells

0.12

0.10

0.08

0.06

0.04

0.02

0

IP Rate Probability

(Barnett 2009 Well Vintage)

IP Rate

Mcf/day

(30-day avg)

0 1,000 2,000 3,000 4,000 5,000

IP Rate Probability

(Barnett ’09 Well Vintage)

0.0

0.2

0.4

0.6

0.8

1.0

Source: MIT analysis; HPDI production database and various 

industry sources

Source: MIT analysis; HPDI production database and various 

industry sources
Chapter 2: Supply 33

This high level of variability in individual well 

productivity clearly has consequences with 

respect to the variability of individual well 

economic performance.13 This is illustrated in 

Table 2.2, which shows the variation in breakeven gas price as a function of initial productivity for the five major U.S. shale plays. The P20 

30-day initial production rate represents the 

rate that is equaled or exceeded by only 20% of 

the wells completed in 2009; the P80 represents 

the initial rate equaled or exceeded by 80% of 

completed wells.

Another major driver of shale economics is the 

amount of hydrocarbon liquid produced along 

with gas. The results in Table 2.2 assume dry 

gas with no liquid co-production; however, 

some areas contain wet gas with appreciable 

amounts of liquid, which can have a considerable effect on the breakeven economics — particularly if the price of oil is high compared to 

the price of gas. 

The liquid content of a gas is often measured 

in terms of the “condensate ratio,” expressed in 

terms of barrels of liquid per million cubic feet 

of gas (bbls/MMcf). Figure 2.16 shows the 

change in breakeven gas price for varying 

condensate ratios in a typical Marcellus well,14

assuming a liquids price of $80/bbl. It can be 

seen that for a condensate ratio in excess of 

approximately 50 bbls/MMcf in this particular 

case, the liquid production alone can provide 

an adequate return on the investment, even if 

the gas were to realize no market value. 

Barnett Fayetteville Haynesville Marcellus Woodford

IP

Mcf/d

BEP

$/Mcf

IP

Mcf/d

BEP

$/Mcf

IP

Mcf/d

BEP

$/Mcf

IP

Mcf/d

BEP

$/Mcf

IP

Mcf/d

BEP

$/Mcf

P20 2700 $4.27 3090 $3.85 12630 $3.49 5500 $2.88 3920 $4.12

P50 1610 $6.53 1960 $5.53 7730 $5.12 3500 $4.02 2340 $6.34

P80 860 $11.46 1140 $8.87 2600 $13.42 2000 $6.31 790 $17.04

Table 2.2 Full-Cycle 2009 Well Vintage P20, P50 and P80 30-Day Average Initial 

Production (IP) Rates and Breakeven Prices (BEP) for Each of the Major U.S. Shale Plays 

Assuming Mid Case Costs

Source: MIT analysis
34 MIT STUDY ON THE FUTURE OF NATURAL GAS

The effects described above create an interesting dynamic in U.S. gas supply. Gas prices have 

been driven to low levels in 2009 and 2010, at 

least in part as a result of the abundance of 

relatively low-cost shale gas. Meanwhile oil 

prices, determined by global market forces, 

have remained high. This has led producers to 

seek liquid rich gas plays, such as certain areas 

of the Marcellus or the Eagle Ford play in Texas, 

where condensate ratios can be well in excess of 

100 bbl/MMcf. These plays then enable more 

gas production, even at low gas prices, thus 

putting further downward pressure on gas 

prices.

In addition to understanding the resource 

volumes, it is important to understand the 

contribution that the new shale resources could 

make to the overall production capacity within 

the U.S. 

Figure 2.17 indicates how production from the 

top five shale plays might grow, if drilling were 

to continue at 2010 levels for the next 20 years. 

This illustrates the very significant production 

potential of the shale resource.15 The current 

rapid growth in shale production can continue 

for some time — but in the longer run production growth tapers off as high initial production rates are offset by high initial decline rates, 

and the quality of drilling prospects declines as 

the plays mature.

The large inventory of undrilled shale acreage, 

together with the relatively high initial productivity of many shale wells, allows a rapid 

production response to any particular drilling 

effort, provided that all wells can be completed 

and tied in. However, this responsiveness will 

change over time as the plays mature, and 

significant drilling effort is required just to 

maintain stable production against relatively 

high inherent production decline rates.

Figure 2.16 Estimated Breakeven Gas Price ($/MMBtu) for a Mean Performing 2009 

Vintage Marcellus Shale Well, with Varying Condensate Ratio (bbl/MMcf), Assuming 

a Liquids Price of $80/bbl

Breakeven gas price

$/MMBtu

Condensate Ratio

bbl/MMcf

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

0 5 10 15 20 25 30 35 40 45 50

Source: MIT analysis
Chapter 2: Supply 35

UNCONVENTIONAL GAS SCIENCE 

AND TECHNOLOGY16

Each unconventional gas resource type — 

tight gas, CBM and shale — presents it own 

production challenges, although they also share 

some common characteristics. In particular, all 

three types have low intrinsic permeability 

within the rock matrix itself — and thus 

require enhancement of the connectivity 

between the reservoir and the wellbore to 

enable gas flow at commercial rates. A second 

common characteristic is that the resources 

tend to be distributed over large geographical 

areas, saturating pore space often hundreds of 

square kilometres in areal extent, rather than 

within the tightly defined boundaries of 

conventional gas reservoirs. This means that 

exploration risk is very low; the challenges lie 

in achieving commercial production rates.

Shale resources represent a particular challenge, 

because of their complexity, variety and lack of 

long-term performance data. In conventional 

reservoirs, there is a long history of production 

from a wide variety of depositional, mineralogical and geomechanical environments, such 

that analogues can be developed and statistical 

predictions about future performance can be 

developed. This is not yet the case in the shale 

plays.

Gas shales refer to any very fine-grained rock 

capable of storing significant amounts of gas. 

Gas may be present as free gas stored in the 

natural fracture and macroporosity, adsorbed 

onto the kerogen17 and internal surfaces of the 

pores or dissolved in the kerogen and bitumen. 

The highly variable definition of gas shales has 

led to uncertainty in defining controlling 

factors that constitute an economic development. Values of the key parameters used in 

identifying potential shale resources vary 

widely between shale plays, making it difficult 

to apply analogues and expand shale gas 

exploration and development outside established basins. 

Figure 2.17 Potential Production Rate that Could Be Delivered by the Major U.S. Shale 

Plays up to 2030 — Given 2010 Drilling Rates and Mean Resource Estimates

30

25

20

15

10

5

0

Bcf/da

y

 2000 2005 2010 2015 2020 2025 2030

Marcellus

Haynesville

Woodford

Barnett

Fayetteville

0.0

0.2

0.4

0.6

0.8

1.0

Source: MIT analysis
36 MIT STUDY ON THE FUTURE OF NATURAL GAS

Production in shales is a multi-scale and 

multi-mechanism process. Fractures provide 

the permeability for gas to flow, but contribute 

little to the overall gas storage capacity. The 

porosity of the matrix provides most of the 

storage capacity, but the matrix has very low 

permeability. Gas flow in the fractures occurs 

in a different flow regime than gas flow in the 

matrix. Because of these differing flow regimes, 

the modeling of production performance in 

fractured shale formations is far more complex 

than for conventional reservoirs, and scaling 

modeling results up to the field level is very 

challenging. This in turn makes it difficult to 

confidently predict production performance 

and devise optimal depletion strategies for 

shale resources.

Production behavior in shale wells is marked 

by a rapid decline from initial production rates, 

as seen in Figure 2.15a. Early gas production 

is dominated by free gas depleted from the 

fractures and the macroporosity. This rapid 

initial decline is followed by a long term, much 

slower decline. As the pressure is lowered, gas 

desorbs from the organic matter in the matrix 

and diffuses into the fracture system. During 

this stage, desorption and diffusion through 

the matrix drive production. The long-term 

production behavior of a shale gas well is 

dependent on the time scale of flow from the 

matrix relative to flow in the fracture network.

In addition to the complexities of modelling 

performance, core analysis techniques developed for conventional gas, CBM and tight 

gas do not work well in shale reservoirs, 

because they implicitly assume that the same 

production mechanisms are applicable. The 

determination of initial parameters such as 

permeability, porosity and initial gas-in-place 

can be misleading, contributing to uncertainty 

in resource size and production performance.

In order to ensure the optimal development of 

these important national assets, it is necessary 

to build a comprehensive understanding 

of geochemistry, geological history, multiphase 

flow characteristics, fracture properties and 

production behavior across a variety of shale 

plays. It is also important to develop tools 

that can enable the scaling up of pore-level 

physics to reservoir-scale performance prediction, and make efforts to improve core analysis 

techniques to allow accurate determination 

of the recoverable resource.

RECOMMENDATION

The U.S. Department of Energy (DOE) 

should sponsor additional Research and 

Development (R&D), in collaboration with 

industry and academia, to address some 

of the fundamental challenges of shale 

gas science and technology, with the goal 

of ensuring that this national resource is 

exploited in the optimal manner.

Resource assessment

It is in the national interest to have the best 

possible understanding of the size of the U.S. 

natural gas resource. For conventional reservoirs, statistically based resource assessment 

methodologies have been developed and tested 

over many years. In contrast, the assessment 

methodology for the “continuous” unconventional resources is less well developed. There 

would be real benefit in improving the methodology for unconventional resource assessments.

RECOMMENDATION

The USGS should continue, and even 

accelerate, its efforts to develop improved 

assessment methodologies for 

unconventional resources.
Chapter 2: Supply 37

Technology

The development of unconventional resources 

in general, and shale resources in particular, has 

been enabled by the application of existing 

technology — horizontal drilling and hydraulic 

fracturing — in a new setting. The objective is 

to create very large surface areas in the formation that are in communication with the 

wellbore. Horizontal wells place 4,000 feet or 

more of well directly into the formation, while 

multistage fracturing along the horizontal 

section then creates additional surface area in 

communication with the wellbore.

Improvements in drilling and fracturing 

performance are currently rapid, coming from 

improved know-how rather than specific 

technology breakthroughs. The repetitive nature 

of the shale drilling and completion process 

provides an ideal environment for continuous 

improvement of drilling and completion times, 

and fracturing performance. These improvements can serve to enhance well economics and 

increase the ultimate resource base. 

There are a number of areas of technology 

development that could enhance unconventional gas recovery in the longer term:

s $RILLING  UNCONVENTIONAL RESOURCES REQUIRE

a high well density for full development. 

Technology that can reduce well costs and 

increase wellbore contact with the reservoir 

can make a significant impact on costs, 

production rates and ultimate recovery. 

Multi-lateral drilling, whereby a number of 

horizontal sections can be created from a 

single vertical wellbore, and coiled tubing 

drilling to decrease costs represent potential 

options for future unconventional gas 

development.

s #/2

 enhanced recovery — simultaneous 

recovery of natural gas while sequestering 

CO2

 provides an interesting, although as yet 

unproven, possibility for enhancing gas 

recovery while reducing environmental 

footprint. In enhanced CBM production, CO2

injected into the reservoir preferentially 

displaces methane molecules, allowing for 

enhanced gas production while storing CO2

permanently in the subsurface. While pilot 

projects have successfully demonstrated 

enhanced recovery from this technique, there 

are significant challenges associated with 

making this a commercial-scale process.

s 3EISMIC TECHNIQUES  MICRO
SEISMIC TECHniques are now commonly used to estimate 

the length and orientation of induced 

fractures in the reservoir during fracturing 

operations; this technique is useful for 

improving fracturing effectiveness. At a more 

macroscopic level, there is a need to develop 

seismic techniques that allow the characterisation of large areas, to identify formation 

“sweet spots,” natural fracture orientation 

and other properties that would be invaluable 

in improving overall resource development.

SHALE GAS ENVIRONMENTAL CONCERNS

Background 

The rapid development of shale gas resources 

in the U.S. over the past few years has aroused 

concern, and a perception in some quarters that 

this development is causing significant environmental problems. A good deal of attention has 

been focused on the high-volume hydraulic 

fracturing that is an essential component of 

shale gas development, with a major concern 

being that the fracturing process risks injecting 

toxic fracture fluids into shallow groundwater 

aquifers, which are in many cases the source of 

potable water for public use. More broadly, 

there are concerns about water management 

and in particular the proper disposal of potentially toxic wastewater from the fracturing 

procedure.

These concerns have led to restrictions on 

drilling in some areas and proposed regulatory 

action. Activity is currently restricted in potentially productive areas of the Marcellus shale in 

the Delaware River Basin, New York State and 

Pennsylvania State Forest land. The U.S. 
38 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 2.18 Typical Shale Well Construction (Not to Scale)

High Quality

Reservoirs

Low Quality

Reservoirs

Tight Gas

Sands Shale Gas

Marcellus

Haynesville

Woodford

Barnett

Fayetteville

Conductor Casing

Surface Casing

Cement

Drilling Mud

Cement

Intermediate Casing

Production Casing

Production Tubing Kickoff Point

100 —

1000 —

2000 —

7100 —

Production Zone

Salt Water Zone

Aquifer

Feet Below Surface

Source: Based on Modern Shale Gas Development in the United States – a Primer

Environmental Protection Agency (EPA) 

is conducting an extensive review of hydraulic 

fracturing, and legislation in the form of the 

Fracturing Responsibility and Awareness of 

Chemicals (FRAC) Act was introduced in the 

2009–2010 Congress.18

The Shale Drilling and Completion Process

In order to appreciate the risks associated with 

shale development, and to understand appropriate risk mitigation techniques, it is helpful to 

understand the major steps involved in well 

construction: 

1. Well permitting — states require an 

operator to obtain a permit to drill a well.

2. Well site construction — typically involves 

cleaning and grading an area of around 

four acres in the case of a single well site, or 

five to six acres in the case of a multi-well site.

3. Drilling and casing — as shown in 

Figure 2.18, casing is cemented into the well 

at various stages in order to maintain the 

integrity of the wellbore, and to ensure that 

fluids within the various strata are contained 

within those strata. The drilling and casing 

process usually entails several stages:

 (i) Drill and set conductor casing — large 

diameter casing set at shallow depths.

 (ii) Drill through shallow freshwater zones, 

set and cement surface casing — the 

most critical phase with respect to the 

protection of groundwater resources.

 (iii)Drill and cement intermediate casing.

 (iv) Drill and cement production casing.
Chapter 2: Supply 39

4. Perforate and fracture the well, usually in 

multiple stages. 

5. Flowback fracture fluid.

6. Place well into production.

Potential Risks

With over 20,000 shale wells drilled in the last 

10 years, the environmental record of shale gas 

development has for the most part been a good 

one. Nevertheless, it is important to recognize 

the inherent risks of the oil and gas business 

and the damage that can be caused by just one 

poor operation; the industry must continuously 

strive to mitigate risk and address public 

concerns. Particular attention should be paid 

to those areas of the country which are not 

accustomed to oil and gas development, and 

where all relevant infrastructure, both physical 

and regulatory, may not yet be in place. In this 

context, the Marcellus shale, which represents 

35% to 40% of the U.S. shale resource, is the 

primary concern.

Within the stages of well construction outlined 

above, the primary risks are as follows:

1. Contamination of groundwater aquifers 

with drilling fluids or natural gas while 

drilling and setting casing through the 

shallow zones.

2. On-site surface spills of drilling fluids, 

fracture fluids and wastewater from 

fracture flowbacks.

3. Contamination as a result of inappropriate 

off-site wastewater disposal.

4. Excessive water withdrawals for use in 

high-volume fracturing.

5. Excessive road traffic and impact on air 

quality.

Before examining these risks in more detail, 

it is instructive to look at data that attempt to 

summarize available information on recorded 

incidents relating to gas well drilling in the U.S. 

L48 onshore. It is beyond the scope of this 

study to examine multiple state archives to 

review individual well incident reports. Instead, 

to provide a high-level view we have extracted 

and combined the results from a number of 

reports that have reviewed drilling-related 

incidents in the U.S. over the past few years. 

Table 2.3 indicates the results of this analysis, 

while Appendix 2E provides a fuller description 

of the data set. The data set does not purport 

to be comprehensive, but is intended to give a 

sense of the relative frequency of various types 

of incidents.

With over 20,000 shale wells drilled in the last 10 years, 

the environmental record of shale gas development 

has for the most part been a good one — but it is 

important to recognize the inherent risks and the 

damage that can be caused by just one poor operation.

Type of Incident Number Reported Fraction of Total

Groundwater contamination by natural gas or drilling fluid 20 47%

On-site surface spills 14 33%

Off-site disposal issues 4 9%

Water withdrawal issues 2 4%

Air quality 1 2%

Blowouts 2 4%

Table 2.3 Widely Reported Incidents Involving Gas Well Drilling; 2005 – 2009
40 MIT STUDY ON THE FUTURE OF NATURAL GAS

Of the 43 widely reported incidents, almost half 

appear to be related to the contamination of 

shallow water zones primarily with natural gas. 

Another third of reported incidents pertain to 

on-site surface spills. In the studies surveyed, 

no incidents are reported which conclusively 

demonstrate contamination of shallow water 

zones with fracture fluids.

The Fracturing Process

The fracturing process entails the pumping of 

fracture fluids, primarily water with sand 

proppant and chemical additives, at sufficiently 

high pressure to overcome the compressive 

stresses within the shale formation for the 

duration of the fracturing procedure. Each 

stage is typically of the order of a few hours. 

The process increases formation pressure above 

the critical fracture pressure, creating narrow 

fractures in the shale formation. The sand 

proppant is then pumped into these fractures 

to maintain a permeable pathway for fluid flow 

after the fracture fluid is withdrawn and the 

operation is completed.

The fracturing process itself poses minimal risk 

to the shallow groundwater zones that may 

exist in the upper portion of the wellbore. As 

described previously, multiple layers of cement 

and casing protect the freshwater zones as the 

fracture fluid is pumped from the surface down 

into the shale formation. This protection is 

tested at high pressures before the fracturing 

fluids are pumped downhole. Once the fracturing process is underway, the large vertical 

separation between the shale sections being 

fractured and the shallow zones prevents the 

growth of fractures from the shale formation 

into shallow groundwater zones. Table 2.4 

describes the typical separations in the major 

shale plays; in all but one case there are several 

thousand feet of rock — typically sandstones 

and shales, many of which have very low 

permeability — separating the fractures shale 

formation and the groundwater zones. It 

should be noted here that only shallow zones 

contain potable water; as depths increase, the 

salinity of the groundwater increases to the 

point that it has no practical utility.

A recently published report summarizes the 

results of a large number of fracturing operations in the Barnett and the Marcellus shales 

(Fisher, 2010). Figure 2.19 illustrates these 

results for the Marcellus shale, showing that in 

all cases the highest growth of the fractures 

remains separated from the groundwater 

aquifers by thousands of feet of formation.

Basin Depth to Shale (ft) Depth to Aquifer (ft)

Barnett 6,500–8,500 1,200

Fayetteville 1,000–7,000 500

Marcellus 4,000–8,500 850

Woodford 6,000–11,000 400

Haynesville 10,500–13,500 400

Table 2.4 Separation Distance between Gas Shales and Shallow Freshwater Aquifers 

in Major Plays
Chapter 2: Supply 41

The physical realities of the fracturing process, 

combined with the lack of reports from the 

many wells to date of fracture fluid contamination of groundwater, supports the assertion that 

fracturing itself does not create environmental 

concerns. However, this simple statement does 

not address the full range of environmental 

concerns listed earlier:

1. Leakage of natural gas or drilling fluids 

into shallow zones: this appears to be the 

most common cause of reported incidents, 

and it is generally associated with drilling 

and setting the surface casing. There are 

three potential risks during this phase of 

operation: (1) overweight drilling mud 

causing some drilling fluid leakage into 

groundwater zones; (2) unexpected 

encounters with shallow gas zones with the 

possibility of gas migration into groundwater zones and (3) poor quality cementing of 

the surface casing, allowing a potential fluid 

pathway into the groundwater zones during 

subsequent operations. The protection of 

groundwater aquifers is one of the primary 

objectives of state regulatory programs, and 

it should be emphasized that good oil field 

practice, governed by existing regulations, 

should provide an adequate level of protection from these problems. 

 Nevertheless, regulations vary by state, as a 

function of local conditions and historical 

precedent — best practice involves setting 

cement all the way to surface, and conducting pressure tests and cement-bond logs 

to ensure the integrity of the surface casing. 

A detailed comparison of state-by-state 

regulation would facilitate the widespread 

adoption of best practice.

RECOMMENDATION

Conduct an inter-state regulatory 

review and, within constraints of local 

considerations, adopt best practice for 

drilling and high-volume hydraulic 

fracturing.

Figure 2.19 Fracture Growth in the Marcellus; Marcellus Shale Mapped Fracture 

Treatments (TVD)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Depth (ft)

1 51 101 151 201 251 301 351

Frac Stages (Sorted on Perf Midpoint)

Deepest Aquifier

Depth fracTOP

perfTOP

Perf Midpoint

perfBTM

fracBTM

PA

OH

WV

Source: Pinnacle Halliburton Service, Kevin Fisher, Data Confirm Safety of Well Fracturing from July 2010
42 MIT STUDY ON THE FUTURE OF NATURAL GAS

2. On-site surface spills: the drilling and 

completion process involves the handling 

of many thousands of barrels of fluids 

on-site, in particular drilling mud and 

fracture fluids. Spills can occur as a result 

of failure of equipment such as pumps and 

hoses; in addition, there is potential for 

overflow of tanks and surface pits. Issues 

will arise if the volume of spilled material is 

such that local waterways could be contaminated. These issues are not specifically 

associated with the fracturing process, and 

avoiding spills is a normal part of good 

oil field management practice. The high 

volumes of fluid associated with shale 

fracturing may increase spill potential.

 Again, state regulations stipulate the 

requirements for protecting surface waters 

against leaks and spills, with regulation 

varying from state to state.

 Shale fracture fluid or “slickwater,” is 

largely composed of water, which generally 

constitutes over 99% of the liquid component. As described in Table 2.5, a number 

of additives are mixed in with the water to 

increase the effectiveness of the fracturing 

 operation — these additives will vary as a 

function of the well type and the preferences of the operators. While there has 

been concern about the transparency of 

information as regards the make-up of 

these additives, there has been considerable 

progress on this issue. Although precise 

formulations remain proprietary, information is now becoming available for all the 

chemical compounds contained within the 

fluids.

In addition to greater transparency about the 

compounds, there is also progress towards 

elimination of the toxic components from 

the additives. 

RECOMMENDATION

Require the complete disclosure of all 

fracture fluid components. 

RECOMMENDATION

Continue efforts to eliminate toxic 

components of fracture fluids.

Purpose Chemical Common Use

clean up damage from initial 

drilling, initiate cracks in rock

HCl swimming pool cleaner

gel agents to adjust viscosity guar gum thickener in cosmetics, 

toothpaste, sauces

viscosity breakers ammonium persulfate, potassium, 

sodium peroxydisulfate

bleach agent in detergent and 

hair cosmetics

biocides gluteraldehyde, 2,2-dibromo3-

nitrilophopionamide

medical disinfectant

surfactant isopropanol glass cleaner, antiperspirant

corrosion inhibitor n, n-dimethylformamide pharmaceuticals

clay stabilizer potassium chloride low sodium table salt substitute

Table 2.5 Typical Fracture Fluid Additives

Source: Kaufman et al. 2008
Chapter 2: Supply 43

3. Off-site wastewater disposal — another 

potential issue is the disposal of waste from 

fracturing operations, in particular the 

fracture fluid and formation water that is 

returned from the well when it is backflowed upon completion of the fracturing 

operation, prior to start of production. 

Typically, less than 100% of the injected 

fluid will be recovered, and it will generally 

be mixed with some volume of displaced 

formation brine. This fluid must be disposed of appropriately.

 Every year the onshore U.S. industry safely 

disposes of approximately 18 billion barrels 

of produced water. By comparison, a 

high-volume shale fracturing operation 

may return around 50 thousand barrels of 

fracture fluid and formation water to the 

surface. The challenge is that these volumes 

are concentrated in time and space.

 The optimum method for disposal of oil 

field wastewater is injection into a deep 

saline aquifer through an EPA regulated 

Underground Injection Control (UIC) 

water disposal well. Problems can occasionally arise if there are insufficient wastewater 

disposal wells, as appears to be the case in 

Pennsylvania. Waste can be disposed of at 

wastewater treatment plants, but problems 

can arise if the fluid for disposal is of high 

salinity or contains other contaminants19; 

this may cause the effluent from the 

treatment plant to exceed desired limits.

 Much effort is now focused on addressing 

this issue where disposal problems exist. 

One approach is to recycle the flow-back 

fluid: using the flow-back fluid from one 

well as a component in the fracture fluid 

of the next well. This has the additional 

advantage of reducing the total amount 

of water that must be imported to site. 

In addition, techniques are also being 

developed to clean up wastewater prior 

to disposal. 

4. Water withdrawal — large quantities of 

water, typically of the order of 100,000 

barrels, are required for high-volume 

hydraulic fracturing, and this has raised 

concerns about the impact on local water 

resources. 

 While there may be temporary impacts on 

local resources, the overall impact is small, 

as can be seen when the volumes are placed 

in the context of total water usage. Table 2.6 

looks at water usage for shale gas operations as a fraction of total water usage in a 

number of major shale plays — in all cases 

shale development water usage represents 

less than 1% of total water usage in the 

affected areas.
44 MIT STUDY ON THE FUTURE OF NATURAL GAS

Indeed, the “water intensity” of shale gas 

development, at around 1 gallon of water 

consumed for every MMBtu of energy produced, is low compared to many other energy 

sources. By way of contrast, several thousand 

gallons of water per MMBtu of energy produced can be used in the irrigation of corn 

grown for ethanol.

Nevertheless, careful planning and coordination is necessary to ensure that episodic water 

withdrawals do not disrupt local supply 

sources.

RECOMMENDATION

Prepare integrated regional water usage 

and disposal plans for the major shale areas. 

RECOMMENDATION

Undertake collaborative R&D to reduce 

water usage and develop cost-effective 

water recycling.

5. Road traffic and environmental disturbance — oil and gas operations have 

the potential to be disruptive to local 

communities in the field development 

phase of well drilling and completion, 

particularly in those areas not accustomed 

to routine oil field operations. As indicated 

in Table 2.7, the large volumes of water 

involved in fracturing operations can create 

high volumes of road traffic.

 It should be emphasized that the large 

number of traffic movements shown on 

this table are really worst-case numbers. In 

particular, re-use of flowback wastewater 

can and does significantly reduce the road 

traffic associated with hauling water, which 

represents much of the traffic movement. 

Furthermore, large-scale operators are also 

using pipelines to transport water to site, 

further reducing the amount of road traffic 

very substantially.

Play

Public 

Supply

Industrial/

Mining Irrigation Livestock Shale Gas

Total 

Water Use 

(Bbbls/yr)

Barnett

TX 82.7% 3.7% 6.3% 2.3% 0.4% 11.1

Fayetteville

AR 2.3% 33.3% 62.9% 0.3% 0.1% 31.9

Haynesville

LA/TX 45.9% 13.5% 8.5% 4.0% 0.8% 2.1

Marcellus

NY/PA/WV 12.0% 71.7% 0.1% <0.1% <0.1% 85.0

Table 2.6 Comparative Water Usage in Major Shale Plays

Source: ALL Consulting
Chapter 2: Supply 45

In conclusion, it is clear that oil and gas 

development is not without risk to the natural 

environment. State and Federal regulations are 

designed to mitigate those risks. However, 

though not the result of risks inherent to the 

fracturing of shale gas wells, operational errors 

and poor drilling practice do result in a significant number of incidents. Implementation of 

the recommendations described above, 

together with rigorous enforcement of all 

applicable regulations, should reduce the 

number of incidents and ensure that shale 

development can proceed with minimum 

impact on the environment.

METHANE HYDRATES20

Methane hydrates are not considered in the 

resource estimates and supply curves described 

above, as they are still at a very early stage in 

terms of resource definition and understanding. Nevertheless, gas hydrates could represent 

a significant long-term resource option, possibly in North America but particularly in some 

other parts of the world.

Methane hydrates are an ice-like form of 

methane and water stable at the pressuretemperature conditions common in the shallow 

sediments of permafrost areas and continental 

margins. Globally, the total amount of methane 

sequestered in these deposits probably exceeds 

100,000 Tcf, of which ~99% occurs in ocean 

sediments. Most of this methane is trapped in 

highly disseminated and/or low saturation 

methane hydrates that are unlikely to ever be 

a commercially viable gas source. An estimated 

10,000 Tcf may be technically recoverable from 

high-saturation gas hydrate deposits (Boswell 

and Collett, 2010), primarily concentrated in 

permeable (likely sand-rich) sediments.

Activity 1 Rig, 1 Well 2 Rigs, 8 Wells

Pad and Road Construction 10 – 45 10 – 45

Drilling Rig 30 60

Drilling Fluid and Materials 25 – 50 200 – 400

Drilling Equipment (casing, drill pipe, etc.) 25 –50 200 – 400

Completion Rig 15 30

Completion Fluid and Materials 10 – 20 80 – 160

Completion Equipment (pipe, wellhead, etc.) 5 10

Fracturing Equipment (pump trucks, tanks, etc.) 150 – 200 300 – 400

Fracture Water 400 – 600 3,200 – 4,800

Fracture Sand 20 – 25 160 – 200

Flowback Water Disposal 200 – 300 1,600 – 2,400

Total 890 – 1,340 5,850 – 8,905

Table 2.7 Truck Journeys for a Typical Shale Well Drilling and Completion

Source: NTC Consulting
46 MIT STUDY ON THE FUTURE OF NATURAL GAS

To date, there have been few formal quantitative assessments of methane sequestered in gas 

hydrates at regional scales. A recent assessment 

of in-place resources in northern Gulf of 

Mexico yielded 6,717 Tcf (median) for sands 

(Frye, 2008), and other assessments based on 

similar methodology are expected soon for the 

U.S. Atlantic Margin and other U.S. margins. 

The only assessment of technically recoverable 

methane hydrates ever completed calculated 

85.4 Tcf (median) for permafrost-associated 

gas hydrates on the Alaskan North Slope 

(Collett et al., 2008). Outside the U.S., the only 

formal assessment covers ~10% of the area 

associated with a certain gas hydrates seismic 

marker in the Nankai Trough and yielded 20 

Tcf methane in-place in the high saturation 

section (Fujii et al., 2008).

Figure 2.20 USGS Database of Locations at which Gas Hydrate Has Been Recovered (circles) or Strongly 

Inferred Based on Drilling-Based Evidence (squares) from Permafrost Areas (black labels) or from Depths 

Greater than 50 m below the Seafloor (white labels). The color-coding refers to the primary (outer symbol) 

and, where relevant, the secondary (inner symbol) type of gas hydrate reservoir, using terminology from 

the gas hydrate resource pyramid (Figure 2.21 in MITEI report). Academic drill sites where deep gas hydrate 

was recovered but for which reservoir type has not been determined are designated by ODP/DSDP.

Source: Ruppel, C., Collett, T. S., Boswell, R., Lorenson, T., Buczkowski, B., and Waite, W., 2011, A new global gas hydrate drilling map based on reservoir 

type, Fire in the Ice, DOE-NETL Newsletter, May edition, vol. 11(1), 13–17.
Chapter 2: Supply 47

Several research challenges remain before gas 

hydrate assessments become routine. The 

greatest need is geophysical methods that can 

detect gas hydrates and constrain their in situ

saturations more reliably than seismic surveys 

alone and less expensively than direct drilling 

and borehole logging. Electromagnetic (EM) 

methods have shown some promise in deep 

marine settings, but refinements in seismic 

techniques (e.g., full waveform inversions, 

seismic attribute analysis) may yet prove even 

more useful than routinely combining EM and 

seismic surveys.

Methane hydrates are unlikely to reach commercial viability for global markets for at least 

15 to 20 years. Through consortia of government, industry and academic experts, the U.S., 

Japan, Canada, Korea, India, China and other 

countries have made significant progress on 

locating and sampling methane hydrates. 

No short-term production test has ever been 

attempted in a marine gas hydrate setting, but 

several short-term tests (few hours to a few 

days) have been completed in permafrostassociated wells in the U.S. and Canadian 

Arctic. Before 2015, the first research-scale, 

long-term (several months or longer) production tests could be carried out by the U.S. DOE 

on the Alaskan North 

Slope and by the 

Japanese MH21 project 

for Nankai Trough 

deepwater gas hydrates. 

The goals of these tests 

are to investigate the 

optimal mix of production techniques to 

sustain high rates of gas flow over the lifetime 

of a well and to assess the environmental 

impact of production of methane from gas 

hydrates. 

Producing gas from methane hydrates requires 

perturbing the thermodynamic stability 

conditions to drive dissociation (breakdown) 

of the deposits into their constituent gas and 

water. The gas can then be extracted using 

well-established production methods. Depressurization of the formation is the preferred 

technique for driving gas hydrate dissociation 

Figure 2.21 The Methane Hydrate Resource Pyramid, After Boswell and Collett (2006)

Marcellus

Haynesville

Woodford

Barnett

Fayetteville

e.g., 85 Tcf technically recoverable

on Alaskan North Slope

(Collett et al., 2008)

e.g., 6,717 Tcf in-place Northern

Gulf of Mexico sands

(Frye, 2008)

Arctic (permafrost-associated)

sand reservoirs

Marine shales

(low permeability)

Massive sea!oor/shallow

hydrates at seeps

Non-sand marine reservoirs

(including fracture !lling)

Marine sand reservoirs

0	 Increasing in-place resources

0	 Decreasing reservoir quality

0	 Decreasing resource estimate accuracy

0	 Increasing production challenges

0	 Likely decreasing recovery factor

Source: After Boswell and Collett (2006)

Methane hydrates are unlikely 

to reach commercial viability 

for global markets for at least 

15 to 20 years.
48 MIT STUDY ON THE FUTURE OF NATURAL GAS

since it yields a relatively sustainable and 

well-controlled flow of gas. Thermal stimulation through direct heating or injection of 

heated fluids can be used to drive episodic 

dissociation during longer-term depressurization, but requires significant energy expenditure. Injection of inhibitors (e.g., seawater 

or some chemicals) can also dissociate gas 

hydrates in the formation, although this 

technique has numerous disadvantages and is 

unlikely to be practical at large scales. A final 

production method will be tested on the 

Alaskan North Slope in 2012 by ConocoPhillips 

and could in theory produce methane as well as 

sequester CO2

: CO2 injected into methane 

hydrate deposits should liberate methane while 

simultaneously trapping the CO2

 within stable 

gas hydrates (Yezdimer et al., 2002; Farrell et al., 

2010). 

At present, most conventional oil and gas 

producers avoid intersecting gas hydrate 

deposits to prevent long-term damage to 

the borehole due to unintended dissociation. 

Producing gas from methane hydrates will 

instead require targeted drilling into highsaturation deposits and careful management 

of potentially large amounts of co-produced 

water. The depths at which gas hydrate occurs 

are shallower than those associated with 

(deepwater) conventional gas, rendering gas 

hydrate well control less of a challenge. Gas 

hydrate dissociation is also a self-regulating 

process in most cases, so there is little danger 

of runaway dissociation. Changes in bulk 

sediment volume and sediment strength are 

expected if high-saturation gas hydrates are 

dissociated, but the impact of these changes 

will depend on many factors, including the 

geologic setting, the depth of the deposits and 

the fate of produced water. In short, the risks 

associated with gas production from methane 

hydrates located beneath permafrost or deep 

within marine sediments are either largely 

known from existing gas operations or considered manageable.

RECOMMENDATION

Continue methane hydrates research 

program to develop methods for remote 

detection of highly concentrated deposits; 

conduct formal resource assessments; 

and prove the resource potential through 

long-term production testing.
Chapter 2: Supply 49

APPENDICES

2A: Additional resource data tables and maps

2B: Methodology for creating resource ranges

2C: Additional supply curves and background 

information

2D: Shale gas economics

2E: Analysis of reported gas drilling incidents

SUPPLEMENTARY PAPERS 

ON MITEI WEBSITE:

SP 2.1 Natural Gas Resource Assessment 

Methodologies – Dr. Qudsia Ejaz

SP 2.2 Background Material on Natural 

Gas Resource Assessments with 

Major Resource Country Reviews – 

Dr. Qudsia Ejaz

SP 2.3 Role of Technology in Unconventional 

Gas Resources – Dr. Carolyn Seto

SP 2.4 Methane Hydrates – 

Dr. Carolyn Ruppel
50 MIT STUDY ON THE FUTURE OF NATURAL GAS

REFERENCES

Ahlbrandt, Thomas S., Ronald R. Charpentier, 

T. R. Klett, James W. Schmoker, Christopher J. 

Schenk and Gregory F. Ulmishek. Global 

Resource Estimates from Total Petroleum 

Systems. AAPG, 2005.

ALL Consulting: Water and Shale Gas Development; Presentation to National Association of 

Royalty Owners Annual Conference; October 

2010.

Attanasi, E. D., and T. C. Coburn. “A bootstrap 

approach to computing uncertainty in inferred 

oil and gas reserve estimates.” Natural Resources 

Research 13, no. 1 (2004): p. 45–52.

Boswell, R., and T. Collett, 2006. The gas 

hydrates resource pyramid: Fire in the Ice, 

Methane Hydrate Newsletter, U.S. Department 

of Energy, Office of Fossil Energy, National 

Energy Technology Laboratory, Fall Issue, 

p. 5–7. http://www.netl.doe.gov/technologies/

oil-gas/publications/Hydrates/Newsletter/

HMNewsFall06.pdf#page=5

Boswell, R., and T. Collett. “Current Perspectives 

on Gas Hydrate “Resources”. Energy Environ. 

Sci., 2011. doi: 10.1039/C0EE00203H.

Cadmus Group; Preliminary Analysis of 

Recently Reported Contamination; Prepared 

for: Drinking Water Protection Division 

(DWPD) Office of Ground Water and Drinking 

Water (OGWDW) U.S. Environmental Protection Agency (EPA) Hydraulic Fracturing; 

September 2009.

Collett, T., W. Agena, M. Lee, M. Zyrianova, 

T. Charpentier, D. Houseknecht, T. Klett, 

R. Pollastro and C. Schenk. Assessment of 

Gas Hydrate Resources on the North Slope. U.S. 

Geological Survey Factsheet. United States 

Geological Survey, 2008.

Energy Information Administration. U.S. Crude 

Oil, Natural Gas and Natural Gas Liquids 

Reserves Report. Energy Information Administration, February 2009. http://www.eia.doe.gov/

oil_gas/natural_gas/data_publications/crude_

oil_natural_gas_reserves/cr.html.

Farrell, H., Boswell, R., Howard, J., and Baker, 

R., 2010, CO2

-CH4 exchange in natural gas 

hydrate reservoirs: potential and challenges, in 

DOE-NETL Fire in the Ice, Methane Hydrate 

Newsletter, March 2010, p. 19–21. http://www.

netl.doe.gov/technologies/oil-gas/publications/

Hydrates/Newsletter/MHNews_2010_03.

pdf#page=19

Fisher, Kevin; Data Confirm Safety of Well 

Fracturing; The American Oil and Gas 

Reporter; July 2010.

Frye, M. Preliminary evaluation of in-place 

Gas Hydrate Resources: Gulf of Mexico Outer 

Continental Shelf. Minerals and Management 

Services, 2008.

Fujii, T., T. Saeiki, T. Kobayashi, T. Inamori, M. 

Hayashi, O. Takano, T. Takayama, T. Kawasaki, 

S. Nagakubo, M. Nakamizu and K. Yokoi, 2008. 

Resource assessment of methane hydrate in the 

Nankai Trough, Japan, Offshore Technology 

Conference, Houston, TX, Paper 19310.

Ground Water Protection Council; ALL 

Consulting; Modern Shale Gas Development 

in the United States: A Primer; U.S. Department of Energy; National Energy Technology 

Laboratory.

Kaufman, P., Penny, G. S., Paktinat, J.: Critical 

evaluations of additives used in shale slickwater 

fracs. Paper SPE 119900 presented at the 

2008 SPE Shale Gas Production Conference, 

Ft. Worth TX, 16–18 November 2008.

Minerals Management Service. Assessment of 

Undiscovered Technically Recoverable Oil and 

Gas Resources of the Nation’s Outer Continental 

Shelf, 2006 (Summary Brochure). Minerals 

Management Service, February 2006.

National Petroleum Council. Balancing Natural 

Gas Policy – Fueling the Demands of a Growing 

Economy. National Petroleum Council, 

September 2003.
Chapter 2: Supply 51

NTC Consultants: Impact on Community 

Character of Horizontal Drilling and High 

Volume Hydraulic Fracturing in Marcellus 

Shale and Other Low-Permeability Gas 

Reservoirs; September 2009.

New York State Department of Environmental 

Conservation Division of Mineral Resources; 

Supplemental Generic Environmental Impact 

Statement on the Oil, Gas and Solution Mining 

Regulatory Program; Well Permit Issuance 

for Horizontal Drilling and High-Volume 

Hydraulic Fracturing to Develop the Marcellus 

Shale and Other Low-Permeability Gas Reservoirs; September 2009.

Potential Gas Committee. Potential Supply of 

Natural Gas in the United States – Report of the 

Potential Gas Committee (December 31, 2006). 

Potential Supply of Natural Gas in the United 

States. Potential Gas Agency, Colorado School 

of Mines; November 2007.

———. Potential Supply of Natural Gas in 

the United States – Report of the Potential Gas 

Committee (December 31, 2008). Potential 

Supply of Natural Gas in the United States. 

Potential Gas Agency, Colorado School of 

Mines; December 2009.

———. Potential Supply of Natural Gas in 

the United States – Report of the Potential Gas 

Committee (December 31, 2008) – Advance 

Summary. Potential Supply of Natural Gas 

in the United States. Potential Gas Agency, 

Colorado School of Mines; June 2009.

Reservoir Research Partners and Tudor 

Pickering & Holt; Frac Attack: Risk, Hype 

and Financial Reality of Hydraulic Fracturing 

in the Shale Plays; July 2010.

Rogner, H. H. “An Assessment of World 

Hydrocarbon Resources.” Annual Review of 

Energy and the Environment, 22, no. 1 (1997): 

p. 217–262.

United States Geological Survey. “National Oil 

and Gas Assessment, USGS-ERP,” 2010. http://

energy.cr.usgs.gov/oilgas/noga/index.html.

———. “World Petroleum AssessmentInformation, Data and Products, USGS-ERP,” 

n.d. http://certmapper.cr.usgs.gov/rooms/

we/index.jsp.

Vidas, E.H., Hugman, R.H. & Haverkamp, D.S., 

1993. Guide to the Hydrocarbon Supply Model: 

1993 Update. Gas Research Institute, Report

GRI-93/0454.

Watershed; Craig Michaels, Program Director; 

James L. Simpson, Senior Attorney; William 

Wegner, Staff Scientist; Fractured Communities – 

Case Studies of the Environmental Impacts of 

Industrial Gas Drilling; September 2010.

Yezdimer, E., Cummings, P., Chalvo, A., 2002. 

“Extraction of methane from its gas clathrate 

by carbon dioxide sequestration – determination 

of the Gibbs Free Energy of gas replacement and 

molecular simulation.” J. Phys. Chem A., 106 

p. 7982–7987.
52 MIT STUDY ON THE FUTURE OF NATURAL GAS

NOTES

1Thermogenic gas is formed by the application of 

heat and pressure on organic matter; natural gas 

can also be formed through a biogenic process, 

in which microbial action in an anaerobic (oxygen 

free) environment creates methane from organic 

matter — for example, in swamps, land-fills and 

shallow formations. This chapter of the report 

is focused on thermogenic gas.

2

Permeability is a measure of the ability of a porous 

medium, such as that found in a hydrocarbon 

reservoir, to transmit fluids, such as gas, oil or 

water, in response to a pressure differential across 

the medium. In petroleum engineering, 

permeability is usually measured in units of 

millidarcies (mD). Unconventional formations, 

by definition, have permeability less than 0.1mD.

3

ICF International is a consulting firm whose 

services were used in preparation of supply curves 

for this study. 

4In the US, natural gas volumes are typically 

measured in Standard Cubic Feet (Scf), where the 

volume is measured at a temperature of 60°F and 

a pressure of one atmosphere (14.7 pounds per 

square inch). 1 trillion cubic feet (Tcf) = 

1,000,000,000,000 (or 1012) Scf. Outside North 

America, natural gas volumes are typically 

measured in cubic meters. 1 cubic meter 5 35.3 

cubic feet. 

5Appendix 2A provides additional maps and 

detailed data tables concerning gas resource 

estimates. Supplementary Paper SP 2.2 

“Background Material on Natural Gas Resource 

Assessments with Major Resource Country 

Reviews,” by Dr. Qudsia Ejaz, published on the 

MITEI website, provides additional material.

6Appendix 2B provides details on the methodology 

used to create the uncertainty estimates shown in 

this chapter.

7Appendix 2C provides further details of cost curves 

prepared for this study.

8Supply curves shown here are based on oil field 

costs in 2007. There has been considerable oil field 

cost inflation, and some recent deflation, in the last 

10 years. We have estimated cost curves on a 2004 

base (the end of a long period of stable costs) and 

a 2007 base (reasonably comparable to today’s 

costs, 70% higher than the 2004 level, and 

continuing to decline).

9

Appendix 2A contains further details on global 

unconventional resources.

10Rogner, “An Assessment of World Hydrocarbon 

Resources”, 1997.

11At the time of writing, new more detailed estimates 

of global unconventional resources are starting to 

be published. See, for example, World Shale Gas 

Resources: An Initial Assessment of 14 Regions 

Outside the United States. Produced by Advanced 

Resources International (ARI) for the U.S. EIA 

April 2011.

12Appendix 2A provides additional maps and 

detailed data tables concerning gas resource 

estimates.

13Appendix 2D contains a detailed discussion of the 

economic performance of the major U.S. shale 

plays.

14These are illustrative calculations only, not based 

on actual “wet” well performance. The calculations 

assume that well performance, costs, etc., are 

unchanged by increasing levels of liquids production. In practice, gas production may be affected 

by liquid co-production.

15This is not a forecast of production — but rather 

an illustration of the production potential at an 

assumed drilling rate and assuming a median 

estimate of resources.

16A detailed discussion of the science and technology 

of unconventional gas resources can be found in 

the Supplementary Paper SP 2.3 “Role of 

Technology in Unconventional Gas Resources,” by 

Dr. Carolyn Seto, published on the MITEI website.

17Kerogen and bitumen are comprised of organic 

matter that occurs in hydrocarbon source rocks, 

formed from the application of heat and pressure 

to buried organic material over geological time. 

Kerogen is insoluble in normal organic solvents, 

while bitumen is soluble.

18The Fracture Responsibility and Awareness of 

Chemicals (FRAC) Act of 2009 proposed to 

regulate fracturing under the Underground 

Injection Control provisions of the Safe Water 

Drinking Act, and to mandate full disclosure of the 

chemical constituents of all fracture fluid additives. 

The Bill did not make it out of Committee during 

the 2009–2010 session of Congress.

19Flowback fluid can contain: dissolved solids 

(chlorides, sulfates, and calcium); metals (calcium, 

magnesium, barium, strontium) suspended solids; 

mineral scales (calcium carbonate and barium 

sulfate); acid producing bacteria and sulfate 

reducing bacteria; friction reducers; iron solids 

(iron oxide and iron sulfide); dispersed clay fines, 

colloids and silts; acid gases (carbon dioxide, 

hydrogen sulfide); radionuclides (New York 

Generic Environmental Impact Statement).

20A detailed discussion of methane hydrates can be 

found in the Supplementary Paper SP 2.4 

“Methane Hydrates,” by Dr. Carolyn Ruppel, 

published on the MITEI website.
Chapter 3: System Studies 53

Chapter 3: U.S. Gas Production, Use and 

Trade: Potential Futures

INTRODUCTION

As discussed in other sections of this report, 

many factors will influence the future role of 

natural gas in the U.S. energy system. Here we 

consider the most important of these: Greenhouse 

Gas (GHG) mitigation policy; technology 

development; size of gas resources; and global 

market developments. And we examine how 

they will interact to shape future U.S. gas use, 

production and trade over the next few decades. 

We investigate the importance of these factors 

and their uncertainties by applying established 

models of the U.S. and global economy (see 

Box 3.1). Alternative assumptions about the 

future allow us to create a set of scenarios that 

provides bounds on the future prospects for gas 

and illustrate the relative importance of different 

factors in driving the results. 

The conditions explored include the High, 

Mean and Low ranges of gas resource estimates 

described in Chapter 2. We show the impacts of 

various policy alternatives, including: no new 

climate policy; a GHG emission reduction target 

of 50% by 2050, using a price-based policy (such 

as a cap-and-trade system or emissions tax) and 

an emissions policy that uses a set of non-price 

regulatory measures. 

Several assumptions have a particularly important effect on the analysis. Long-term natural 

gas supply curves, distinguishing the four gas 

types for the U.S. and Canada, are drawn from 

Chapter 2. U.S. economic growth is assumed 

to be 0.9% per year in 2005 to 2010, 3.1% in 

2010 to 2020 (to account for recovery) and 2.4% 

for 2020 to 2050. 

BOX 3.1 GLOBAL AND U.S. ECONOMIC 

MODELS

Projections in this section were made using the 

MIT Emissions Prediction and Policy Analysis 

(EPPA) model and the U.S. Regional Energy 

Policy (USREP) model.1 Both are multi-region, 

multi-sector representations of the economy 

that solve for the prices and quantities of 

energy and non-energy goods and project 

trade among regions. 

The core results for this study are simulated 

using the EPPA model — a global model with 

the U.S. as one of its regions. The USREP model 

is nearly identical in structure to EPPA, but 

represents the U.S. only — segmenting it into 

12 single and multi-state regions. In the USREP 

model, foreign trade is represented through 

import supply and export demand functions, 

broadly benchmarked to the trade response in 

the EPPA model. Both models account for all 

Kyoto gases. 

The advantage of models of this type is their 

ability to explore the interaction of those 

factors underlying energy supply and demand 

that influence markets. The models can 

illustrate the directions and relative magnitudes of influences on the role of gas, providing a basis for judgments about likely future 

developments and the effects of government 

policy. However, results should be viewed in 

light of model limitations. Projections, especially over the longer term, are naturally 

subject to uncertainty. Also, the cost of 

technology alternatives, details of market 

organization and the behavior of individual 

industries (e.g., various forms of gas contracts, 

political constraints on trade and technology 

choice) are beneath the level of model aggregation. The five-year time step of the models 

means that the effects of short-term price 

volatility are not represented. 
54 MIT STUDY ON THE FUTURE OF NATURAL GAS

Influential cost assumptions are shown in 

Table 3.1. The first column contains technology 

costs imposed in the main body of the analysis, 

as documented in Appendix 3A. The rightmost column shows values to be employed in 

sensitivity tests to be explored later, where we 

vary the costs of competing generation technologies (nuclear, coal and gas with carbon 

capture and storage and renewables). The 

intermittent renewables (wind and solar) are 

distinguished by scale. At low penetration 

levels, they enter as imperfect substitutes for 

conventional electricity generation, and the 

estimates of the levelized cost of electricity 

(LCOE4

) apply to early installations when 

renewables are at sites with access to the best 

quality resources and to the grid, and storage or 

backup is not required. Through the elasticity 

of substitution, the model imposes a gradually 

increasing cost of production as their share 

increases, to be limited by the cost with backup. 

These energy sector technologies, like others in 

the model, are subject to cost reductions over 

time through improvements in labor, energy 

and (where applicable) land productivity. 

The potential role of compressed natural gas 

in vehicles is considered separately, drawing on 

estimates of the cost of these vehicles from 

Chapter 5 of this report. 

We also consider two possible futures for 

international gas markets: one where they 

continue in their current pattern of regional 

trading blocs and an alternative where there 

develops a tightly integrated global gas market 

similar to that which now exists for crude oil. 

Reference Sensitivity

Coal 5.4

Advanced Natural Gas (NGCC) 5.6

Advanced Nuclear2 8.8 7.3

Coal/Gas with CCS3 9.2/8.5 6.9/6.6

Renewables

Wind 6.0

Biomass 8.5

Solar 19.3

Substitution elasticity 

(Wind, Biomass, Solar)

1.0 3.0

Wind+Gas Backup 10.0

Table 3.1 Levelized Cost of Electricity (2005 cents/kWh)

Source: EPPA, MIT
Chapter 3: System Studies 55

To explore the future of U.S. gas use in a 

carbon-constrained world, we analyze three 

scenarios of greenhouse control, with very 

different implications for the energy sector as a 

whole. Scenario 1 establishes a baseline, with no 

GHG policy measures beyond those in place 

today. Emissions grow by some 50% over the 

period, as shown in Figure 3.1. Scenarios 2 and 

3 are constructed to span a wide range of 

possible approaches to climate policy, and 

potential effects on gas use. Scenario 2 assumes 

that a price-based policy is imposed on all U.S. 

GHG emissions with a target of a 50% reduction by 2050, as can be seen in Figure 3.1. 

Scenario 3 imposes no economy-wide target, 

but considers two measures proposed for the 

electric power sector: a renewable energy 

standard and measures to force retirement of 

coal-fired power plants. As seen in Figure 3.1, 

this scenario of a regulatory approach essentially stabilizes U.S. GHG emissions, yielding 

only about 10% increase by 2050.

Figure 3.1 U.S. Greenhouse Gas Emissions under Alternative Scenarios

10,000

8,000

6,000

4,000

2,000

0

Mt CO2e

Year

2010 2020 2030 2040 2050

8000

10000

0.0

0.2

0.4

0.6

0.8

1.0

Haynesville Woodford Fayetteville Barnett

Policy (net of carbo

Policy (incl. carbon

No Policy Regulatory Price-Based

1.00.80.60.40.20.0

Source: EPPA, MIT

THE ROLE OF U.S. CLIMATE POLICY — THREE ALTERNATIVE SCENARIOS 
56 MIT STUDY ON THE FUTURE OF NATURAL GAS

Scenario 1 — No Additional GHG 

Mitigation Policy

Unless gas resources are at the Low end of the 

resource estimates in Chapter 2, domestic gas 

use and production are projected to grow 

substantially between now and 2050. This result 

is shown in Figure 3.2, from EPPA model 

simulations, on the assumption that global gas 

markets remain fragmented in regional trading 

blocs. Under the Mean resource estimate, U.S. 

gas production rises by around 40% between 

2005 and 2050, and by a slightly higher 45% 

under the High estimate. It is only under the 

Low resource outcome that resource availability 

substantially limits growth in domestic production and use. In that case, gas production and 

use plateau around 2030 and are in decline 

by 2050. 

The availability of shale gas resources has a 

substantial effect on these results. If the Mean 

estimate for other gas resources is assumed, and 

this same projection is made omitting the shale 

gas component of supply, U.S. production 

peaks around 2030 and declines to its 2005 level 

by 2050. 

Given the continued existence of regional 

trading blocs for gas, there is little change in 

the role played by imports and exports of gas. 

Imports (mainly from Canada) are roughly 

constant over time, though they increase when 

U.S. resources are Low. Exports (principally to 

Mexico) are also maintained over the period 

and grow somewhat if U.S. gas resources are 

at the High estimate.

Imports Production–Exports Exports

45

40

35

30

25

20

15

10

5

0

Tcf

Barnett

 2020 2030 2040 2050

 L M H L M H L M H L M H

Marcellus

Year

0.0

0.2

0.4

0.6

0.8

1.0

7.0 6.9 6.8

8.6

8.0 7.9 10.9

9.2 8.7

15.5

10.4

9.5

Figure 3.2 U.S. Gas Use, Production and Imports & Exports (Tcf), and U.S. Gas Prices 

above Bars ($/1000 cf) for Low (L), Mean (M) and High (H) U.S. Resources. No Climate 

Policy and Regional International Gas Markets

Source: EPPA, MIT
Chapter 3: System Studies 57

Gas prices (2005 U.S. dollars), shown at the top 

of the bars in Figure 3.2, rise gradually over 

time as the lower-cost resources are depleted; 

the lower the resource estimate, the higher the 

prices. The difference in prices across the range 

of resource scenarios is not great for most 

periods. In 2030, for example, the High 

resource estimate yields a price 2% below that 

for the Mean estimate, while the Low resource 

condition increased the price by 7%. The 

difference increases somewhat over time, 

especially for the Low resource case. By 2050, 

for example, the price is 8% lower if the High 

resource conditions hold, but 50% higher if 

domestic resources are at the Low estimate. 

Underlying these estimates are developments 

on the demand side. Under Mean resources, 

electricity generation from natural gas would 

rise by about 70% over the period 2010 to 2050 

though coal would continue to dominate, with 

only a slightly growing contribution projected 

from nuclear power and renewable sources 

(wind and solar). National GHG emissions rise 

by about 40% from 2005 to 2050. More detailed 

results for the scenarios with Mean resources 

are provided in Appendix 3B.

Scenario 2 — Price-Based Climate Policy

An incentive (or price) based GHG emissions 

policy that establishes a national price on GHG 

emissions serves to level the emissions reduction playing field by applying the same penalty 

to emissions from all sources and all uses. 

The policy explored here gradually reduces 

total U.S. GHG emissions, measured in CO2

equivalents (CO2

-e)5, to 50% below the 2005 

level by 2050. The scenario is not designed to 

represent a particular policy proposal and no 

provision is included for offsets. 

While measures taken abroad are not of direct 

interest for this study, such policies or the lack 

of them will affect the U.S. energy system 

through international trade. If the U.S. were to 

pursue this aggressive GHG mitigation policy, 

we assume that it would need to see similar 

measures being taken abroad. Thus, a similar 

pattern of reductions is assumed for other 

developed countries, with lagged reductions 

in China, India, Russia, Mexico and Brazil that 

start in 2020 on a linear path to 50% below 

their 2020 levels by 2070. The rest of the 

developing countries are assumed to delay 

action to beyond 2050. We assume no emissions trading among countries. 

The broad features of 

U.S. gas markets under 

the assumed emissions 

restriction are not 

substantially different 

from the no-policy 

scenario, at least through 2040 (Figure 3.3). 

Gas production and use grows somewhat more 

slowly, reducing use and production by a few 

Trillion cubic feet (Tcf) in 2040 compared with 

the case without climate policy. After 2040, 

however, domestic production and use begin 

to fall. This decline is driven by higher gas 

prices, Carbon Dioxide (CO2

) charge inclusive, 

that gas users would see. The price reaches 

about $22 per thousand cubic feet (cf) with 

well over half of that price reflecting the CO2

charge. While gas is less CO2

 intensive than coal 

or oil, at the reduction level required by 2050, 

its CO2

 emissions are beginning to represent 

an emissions problem. 

However, even under the pressure of the 

assumed emissions policy, total gas use is 

projected to increase from 2005 to 2050 even 

for the Low estimate of domestic gas resources. 

Even under the pressure of an 

assumed CO2 emissions policy, 

total U.S. gas use is projected 

to increase up to 2050.
58 MIT STUDY ON THE FUTURE OF NATURAL GAS

A major effect of the economy-wide, pricebased GHG policy is to reduce energy use 

(Figure 3.4). The effect in the electric sector is 

to effectively flatten demand, holding it near its 

current 4 Trillion killowatt hour (TkWh) level 

(Figure 3.4a). Based on the cost assumptions 

underlying the simulation (see Appendix 3A) 

nuclear, Carbon Capture and Storage (CCS) and 

renewables are relatively expensive compared 

with generation from gas. Conventional coal is 

driven from the generation mix by the CO2

prices needed to meet the economy-wide 

emissions reduction targets. Natural gas is the 

substantial winner in the electric sector: the 

substitution effect, mainly gas generation for 

coal generation, outweighs the demand reduction effect. For total energy (Figure 3.4b) the 

demand reduction effect is even stronger, 

leading to a decline in U.S. energy use of nearly 

20 quadrillion (1015) British thermal units (Btu). 

The reduction in coal use is evident, and oil and 

current-generation biofuels (included in oil) 

begin to be replaced by advanced biofuels. 

Because national energy use is substantially 

reduced, the share represented by gas is projected to rise from about 20% of the current 

national total to around 40% in 2040. 

Figure 3.3 U.S. Gas Use, Production and Imports & Exports (Tcf), and U.S. Gas Prices 

($/1000 cf) for Low (L), Mean (M) and High (H) U.S. Resources, Price-Based Climate Policy 

and Regional International Gas Markets. Prices are shown without (top) and with 

(bottom) the emissions charge.

Imports Production–Exports Exports

45

40

35

30

25

20

15

10

5

0

Tcf 2020 2030 2040 2050

 L M H L M H L M H L M H

Year

6.6

9.6

6.5

9.5

6.4

9.4

7.9

13.7

7.5

13.3

7.4

13.2

10.0

18.5

8.6

17.3

8.2

16.9

11.6

23.6

8.8

21.9

8.3

21.8

Source: EPPA, MIT
Chapter 3: System Studies 59

Under this policy scenario, the U.S. emissions 

price is projected to rise to $106 per ton CO2

-e 

in 2030 and to $240 by 2050. The macroeconomic effect is to lower U.S. Gross Domestic 

Product (GDP) by 1.7% in 2030 and 3.5% in 

2050. (Other measures of cost are provided in 

Appendix 3A.) A selection of resulting U.S. 

domestic prices is shown in Figure 3.5. Natural 

gas prices, exclusive of the CO2

 price, are 

reduced slightly by the mitigation policy, but 

the price inclusive of the CO2

 charge is greatly 

increased (Figure 3.5a). The CO2

 charge is 

nearly half of the user price of gas.6

Even in the No-Policy case, electricity prices 

are projected to rise by 30% in 2030 and about 

45% over the period to 2050 (Figure 3.5b). 

The assumed emissions mitigation policy is 

projected to cause electricity prices to rise by 

almost 100% in 2030 and by two and one-half 

times by 2050 compared with current prices.

Reduced Use

Gas CCS

Coal CCS

Renew

Hydro

Nuclear

Gas

Oil

Coal

TkWh

Year

2010 2015 2020 2025 2030 2035 2040 2045 2050

7

6

5

4

3

2

1

0

3.4a Electric Sector (TkWh)

Figure 3.4 Energy Mix under a Price-Based Climate Policy, Mean Natural Gas Resources

Reduced Use

Renew

Hydro

Nuclear

Gas

Biofuel

Oil

Coal

qBtu

Year

2010 2015 2020 2025 2030 2035 2040 2045 2050

140

120

100

80

60

40

20

0

3.4b Total Energy Use (qBtu)

Source: EPPA, MIT
60 MIT STUDY ON THE FUTURE OF NATURAL GAS

As noted earlier, a set of alternative cost 

assumptions was explored for low-carbon 

technologies in the electricity sector, including 

less costly CCS, nuclear and renewables 

(Table 3.1). 

Of these, the biggest impact on gas 

use in electricity results from low-cost 

nuclear generation. Focusing on 2050, 

when the effects of alternative assumptions are the largest, a low-cost nuclear 

assumption reduces annual gas use in 

the electric sector by nearly 7 Tcf. 

Economy-wide gas use falls by only 

about 5 Tcf, however, because the resulting 

lower demand for gas in electricity leads to 

a lower price and more use in other sectors 

of the economy. 

Lower-cost renewables yield a reduction in gas 

use in the electric sector by 1.8 Tcf in 2030, 

but total gas use falls by only 1.2 Tcf. In 2050, 

a difference in gas use is smaller, 0.5 Tcf and 0.1 

Tcf respectively, as availability of cheaper renewables displaces nuclear power which by that time 

starts to replace gas in the electric sector. With 

less-costly CCS, gas use increases in the electric 

sector by nearly 3 Tcf. This is because both 

gas generation with CCS and coal generation 

with CCS become economic and share the lowcarbon generation market (with about 25% of 

electricity produced by gas with CCS by 2050 

and another 25% by coal with CCS). Gas use 

in the economy as a whole increases even more, 

by 4.2 Tcf.7

Many other combinations of technological 

uncertainties could be explored. For example, 

a breakthrough in large-scale electric storage 

would improve the competitiveness of intermittent sources. A major insight to be drawn 

from these few model experiments, however, is 

that, under a policy based on emissions pricing 

to mitigate greenhouse gas emissions, natural 

gas is in a strong competitive position unless 

competing technologies are much less expensive than we now anticipate. 

The biggest projected 

impact on gas use in 

electricity results 

from an assumption 

of low-cost nuclear 

generation.

Figure 3.5 U.S. Natural Gas and Electricity Prices under Alternative Policy Scenarios, Mean Gas Resources

0.30

0.25

0.20

0.15

0.10

0.05

0.00

3.5b Electricity Prices ($/kWh)

$/kWh

Year

2000 2010 2020 2030 2040 2050 2060

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.0

0.2

0.4

0.6

0.8

1.0

Haynes

Policy (net of 

No Policy Priced-Based Policy

25

20

15

10

5

0

3.5a Natural Gas Prices ($/1000 cf)

$/1000 cf

Year

2000 2010 2020 2030 2040 2050 2060

0

5

10

15

20

25

0.0

0.2

0.4

0.6

0.8

1.0

Haynesville Woodford Fayetteville Barnett

Policy (net of carbon) Policy (incl. carbon)

No Policy Price-Based Policy (net of carbon)

Price-Based Policy (incl. carbon)

Source: EPPA, MIT
Chapter 3: System Studies 61

The simulations shown in Figures 3.3–3.5 do 

not include the Compressed Natural Gas (CNG) 

vehicle. When this policy case is repeated with 

this technology included, applying optimistic 

cost estimates drawn from Chapter 4 of this 

report, the result depends on the assumption 

about the way competing biofuels, and their 

potential indirect land-use effects, are accounted. 

Even with advanced biofuels credited as a 

zero-emissions option, however, CNG vehicles 

rise to about 15% of the private vehicle fleet by 

2040 to 2050. They consume about 1.5 Tcf of gas 

at that time which, because of the effect of the 

resulting price increase on other sectors, adds 

approximately 1.0 Tcf to total national use.8

Some U.S. regions that have not traditionally 

been gas producers have significant shale gas 

resources, and the extent to which these 

resources are developed is material to the 

patterns of production and distribution of gas 

in the U.S. To identify regional patterns of 

production and use within the U.S., we apply 

the USREP model and 

report results for seven 

regions of the country 

for 2006 and 2030 under 

the 50% climate policy 

target and the Mean gas 

resources (Figure 3.6). 

Gas production increases 

most in those regions 

with the new shale 

resources — by more 

than 78% in the Northeast region (New England 

through the Great Lakes States) and by about 

50% in the South Central area that includes 

Texas. In regions without new shale resources, 

Some U.S. regions that have 

not traditionally been gas 

producers do have significant 

shale gas resources, and the 

extent to which these resources 

are developed is material to the 

patterns of production and 

distribution of gas in the U.S.

Figure 3.6 Natural Gas Production and Consumption by Region in the U.S., 

2006 and 2030, Price-Based Policy Scenario, Mean Gas Resources

MOUNTAIN NORTH CENTRAL

SOUTH CENTRAL

NORTH EAST

SOUTH EAST

WEST

ALASKA

0.3 – 2.7 = -2.4

0.3 – 2.9 = -2.6

5.1 – 2.0 = 3.1

4.3 – 1.8 = 2.5

0.5 – 0.4 = 0.1

0.3 – 0.2 = 0.1

11.6 – 6.6 = 5.0

12.2 – 4.5 = 7.7

0.4 – 1.2 = -0.8

0.2 – 2.1 = -1.9 0.9 – 6.2 = -5.3

1.6 – 7.2 = -5.6

0.7 – 2.5 = -1.8

0.9 – 4.2 = -3.3

FLORIDA

GEORGIA

SOUTH 

CAROLINA

NORTH CAROLINA

VIRGINIA

WISCONSIN

OHIO

PENNSYLVANIA

MAINE

VERMONT

INDIANA

ILLINOIS WEST

VIRGINIA

KENTUCKY

TENNESSEE

ALABAMA

MISSISSIPPI

MICHIGAN

MICHIGAN

NEW HAMPSHIRE

NEW YORK

MASSACHUSETTS

RHODE ISLAND

CONNECTICUT

NEW JERSEY

DELAWARE

MARYLAND

KANSAS

NEBRASKA

MISSOURI

MINNESOTA

NEW MEXICO OKLAHOMA

COLORADO

MONTANA

NEVADA

WYOMING

IDAHO

UTAH

ARIZONA

CALIFORNIA

WASHINGTON HAWAII

OREGON

ALASKA

TEXAS

ARKANSAS

LOUISIANA

NORTH

DAKOTA

SOUTH DAKOTA

IOWA

Production – Consumption < 0 (Net Imports) Year 2006

Production – Consumption > 0 (Net Imports) Year 2030

Figures refer to annual production and consumption in Tcf. Source: USREP, MIT 
62 MIT STUDY ON THE FUTURE OF NATURAL GAS

production changes little, showing slight 

increases or decreases. In the Northeast, the 

production increase comes close to matching 

the projected growth in gas use. 

The most substantial potential need for additional interregional gas flows, on the regional 

definition of Figure 3.6, is from the Texas/South 

Central region which increases net exports by a 

combined 2.7 Tcf, with shipment to other 

regions except the Northeast.9

 Compared to the 

2030 interregional flows absent climate policy, 

the assumed emissions target lowers the need 

for new capacity largely because of the expansion of supply in the Northeast.

Scenario 3 — Regulatory Emissions 

Reductions 

If emissions reductions are sought by regulatory and/or subsidy measures, with no price on 

emissions, many alternatives are available. 

Among the most obvious measures that could 

have a direct impact on CO2

 emissions would 

be those requiring renewable energy and one 

encouraging a phase-out of existing coal-fired 

power plants. 

To explore this prospect, we formulate a 

scenario with a renewable energy standard 

(RES) mandating a 25% share of electric 

generation by 2030, and holding at that level 

through 2050, and measures to force retirement 

of coal-fired power plants starting in 2020, so 

that coal plants accounting for 55% of current 

production are retired by 2050. Mean gas 

resources are assumed, as are the reference 

levels of all technology costs. This case results 

in approximately a 50% reduction in carbon 

emissions in the electricity sector by 2050, but 

it does not provide incentives to reduction in 

non-electric sectors so these measures only 

hold total national GHG emissions to near the 

2005 level, as shown in Figure 3.1. 

One evident result of these mitigation measures 

is that the reduction in energy demand is less 

than under the assumed price-based policy, 

either in the electric sector (Figure 3.7a) or in 

total energy (Figure 3.7b). Also, the measures 

represented here achieve less emissions reduction in the electricity sector than does the 

price-based policy. In the price-based policy, 

reductions in the electricity sector are about 

70% by 2050, even though the national target 

is only a 50% reduction, because it is less costly 

to abate there than in the rest of the economy. 

The difference in total national energy use is 

more dramatic (Figure 3.7b compared with 

Figure 3.4b) because the all-sector effect of the 

universal GHG price is missing. 

Among the most obvious measures that could have 

a direct impact on CO2 emissions would be those 

requiring renewable energy and one encouraging 

a phase-out of existing coal-fired power plants.
Chapter 3: System Studies 63

These regulatory measures yield a projection 

of total U.S. gas use very similar to that under 

a no-policy assumption, shown in Figure 3.2. 

Under the Mean resource estimate the 2050 

level is almost identical between the two 

scenarios (see Appendix 3B), and the figure 

would look essentially the same for the High 

and Low cases as well. Also, U.S. natural gas 

prices are essentially the same with these 

regulatory measures as in the case without 

additional GHG-policy shown in Figure 3.5a 

(again see Appendix 3B for a comparison). 

Electricity prices do differ from the no-policy 

scenario, however, as higher generation costs 

are passed along to consumers. The result is 

presented in Figure 3.8, where by 2050 the coal 

and renewable regulations raise the electricity 

price by 50% over its level without GHG policy.

Figure 3.7 Energy Mix under a Regulatory Policy, Mean Gas Resources

Reduced Use

Renew

Hydro

Nuclear

Gas

Oil

Coal

TkWh

Year

2010 2015 2020 2025 2030 2035 2040 2045 2050

7

6

5

4

3

2

1

0

3.7a Electric Sector (TkWh)

Reduced Use

Renew

Hydro

Nuclear

Gas

Oil

Coal

qBtu

Year

2010 2015 2020 2025 2030 2035 2040 2045 2050

140

120

100

80

60

40

20

0

3.7b Total Energy Use (qBtu)

Source: EPPA, MIT
64 MIT STUDY ON THE FUTURE OF NATURAL GAS

In this case, the effects on natural gas, compared 

to a no-policy assumption, are concentrated in 

the electric sector as the non-electric sectors 

face roughly the same gas price in both cases. 

In the electric sector, the forced expansion of 

renewables tends to squeeze out gas-based 

electric generation, particularly in the early 

decades of the period, while the reduction in 

coal use opens up opportunities for gas. The 

net result is a pattern of gas use over time not 

different from the no-policy case, as noted 

earlier. Naturally, the net impact on gas use in 

the electric sector depends on the stringency of 

the two regulatory measures and their relative 

pace of implementation, and compared to the 

assumed price-based approach, they have the 

potential to reduce the use of gas in the sector. 

Nonetheless, for this regulatory scenario, like 

the more ambitious policy-based case, U.S. 

natural gas demand remains resilient, continuing to make a major contribution to national 

energy use. 

Natural gas remains resilient under a wide range of 

potential approaches to U.S. climate policy.

Source: EPPA, MIT

Figure 3.8 Electricity Prices ($/kWh) under No-Policy and 

Regulatory Scenarios, Mean Gas Resources

0.25

0.20

0.15

0.10

0.05

0.00

Year

2000 2010 2020 2030 2040 2050 2060

$/kW

h

0.25

0.30

0.0

0.2

0.4

0.6

0.8

1.0

Haynesville Woodford Fayetteville Barnett

Policy (net of carbon) Policy (incl. carbon)

No Policy Regulatory Policy

Regulatory Policy 1.0 0.8 0.6 0.4 0.2 0.0
Chapter 3: System Studies 65

Currently world gas trade is concentrated in three 

regional markets: North America; Europe — 

served by Russia and Africa; and Asia — with 

a link to the Middle East. There are significant 

movements of gas within each of these markets, 

but limited trade among them. 

Different pricing structures hold within these 

regional markets. For some transactions, prices 

are set in liquid competitive markets; in others 

they are dominated by contracts linking gas 

prices to prices of crude oil and oil products. 

As a result, gas prices can differ substantially 

among the regions. 

These relatively isolated, regionalized markets 

could be sustained for many more decades. 

On the other hand, it is possible that LNG or 

pipeline transport could grow, linking these 

three regions, with the effect of increasing 

interregional gas competition, loosening price 

contracts tied to oil products and moderating 

the price deviations among the regions. 

Such a process could go in many directions 

depending on the development of supply 

capacity by those nations with very large 

resources (mainly Russia and countries in the 

Middle East) or perhaps the expansion of 

non-conventional sources elsewhere. To the 

extent the structure evolves in this direction, 

however, there are major implications for U.S. 

natural gas production and use. 

To investigate the end-effect of possible evolution of an integrated global market akin to 

crude oil, we simulate a scenario where market 

integration and competition lead to equalization of gas prices among markets except for 

fixed differentials that reflect transport costs. 

In this scenario, gas suppliers and consumers 

are assumed to operate on an economic basis. 

That is, no effective gas cartel is formed, and 

suppliers exploit their gas resources for maximum national economic gain. 

Projected effects on U.S. production and trade 

are shown in Figure 3.9 for the 50% reduction 

and High, Mean and Low gas resources cases. 

This result may be compared with the Regional 

Markets case shown in Figure 3.3. 

In 2020, U.S. net imports are lowered to 1.6 Tcf 

(versus 4.1 Tcf in the Regional Markets case). 

Because in the Integrated Global Market 

scenario the EPPA model resolves for the net 

trade only, a decrease in net imports might be 

interpreted as a potential for small gas exports 

from the U.S. while keeping imports constant. 

Beginning in the period 2020 to 2030, the cost 

of U.S. gas begins to rise above that of supplies 

from abroad and the U.S. becomes more 

dependent on imports of gas. In the Mean 

resource case, the U.S. depends on imports for 

about 50% of its gas by 2050 and U.S. gas use 

rises to near the level in the no-policy case, 

because prices are lower. As the emergence of 

an integrated global market would lead ultimately to greater reliance on imports, U.S. gas 

use — and prices — are much less affected by 

the level of domestic resources. Thus, the 

development of a highly integrated international market, with decisions about supply and 

imports made on an economic basis, would 

have complex effects: it would benefit the U.S. 

economically, limiting the development of 

domestic resources but would lead to growing 

import dependence.

THE ROLE OF INTERNATIONAL GAS MARKETS 
66 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 3.9 U.S. Gas Use, Production and Imports & Exports (Tcf) and U.S. Gas Prices 

($/1000 cf) for Low (L), Mean (M) and High (H) U.S. Resources, Price-Based Climate Policy 

and Global Gas Markets. Prices are shown without (top) and with (bottom) the 

emissions charge.

Imports Production

45

40

35

30

25

20

15

10

5

0

Tcf 2020 2030 2040 2050

 L M H L M H L M H L M H

Year

5.1

8.1

5.1

8.1

5.1

8.1

5.8

11.5

5.7

11.4

5.6

11.3

6.6

14.5

6.4

14.3

6.2

14.2

7.3

17.2

7.0

17.0

6.8

16.9

Source: EPPA, MIT

In the Regional Markets case, global demand 

for gas increases from the current demand of 

about 100 Tcf, to about 150 Tcf by 2050. In the 

Integrated Global Markets scenario, gas availability increases globally, reducing gas prices, 

and as a result, gas demand rises to about 

190 Tcf in 2050. Figure 3.10 shows the 

projected increase in gas use. In the Regional 

Markets case, gas use in U.S. and Asia grows 

by around 50% from 2010 to 2050, while in 

Europe and countries of the former Soviet 

Union it increases by about 35%. Assumption 

of an Integrated Global Market changes the 

growth in Asia to 135%, while U.S. and 

European use grows by about 70%. A growth 

in the Rest of the World (ROW) is mostly 

driven by an increase in the gas usage in the 

Middle East and the rest of Americas, where 

assumptions about the different market 

structures affect the results to a lesser degree. 
Chapter 3: System Studies 67

Possible international gas trade flows that are 

consistent with U.S. and global demand under 

the Regional and Integrated Global Markets 

cases are shown in Figure 3.11. Under Regional 

Market conditions (Figure 3.11a), we can see 

that trade flows are large within gas market 

regions but small among them. To avoid a 

cluttered map, small trade flows (less than 

1 Tcf) are not shown. Except for the “Middle 

East to Europe” flow of 1.8 Tcf, interregional 

movements among the three regions specified 

above are less than 0.6 Tcf in any direction 

in 2030. 

Trade flows can be particularly sensitive to the 

development of transportation infrastructure 

and political considerations, and so projections 

of bilateral trade in gas are highly uncertain. 

The Regional Markets case tends to increase 

trade among partners where trade already 

exists, locking in patterns determined in part 

by historical political considerations. 

If a highly integrated Global Market is assumed 

to develop (Figure 3.11b), a very different 

pattern of trade emerges. The U.S. is projected 

to import from the Middle East as well as from 

Canada and Russia, and movements from the 

Middle East to Asia and Europe would increase 

implying a substantial expansion of LNG — 

facilities. Russian gas would begin to move into 

Asian markets, via some combination of 

pipeline transport and LNG. 

Figure 3.10 Gas Use (Tcf) in Regional Markets (reg) and Integrated Global Markets (gl) 

scenarios for USA, Asia, Europe and former Soviet Union (EUR+FSU) and the Rest of the 

World (ROW)

200

180

160

140

120

100

80

60

40

20

0

Tcf 2020 2030 2040 2050

 reg gl reg gl reg gl reg gl

Year

USA EUR & FSU Asia ROW

Source: EPPA, MIT
68 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 3.11 Major Trade Flows of Natural Gas among the EPPA Regions in 2030, No New Policy (Tcf)

3.11a Regional Markets

Source: EPPA, MIT

Source: EPPA, MIT

3.11b Global Market
Chapter 3: System Studies 69

The precise patterns of trade that might 

develop to 2030 and beyond will be influenced 

by the economics of the energy industry, as 

captured by the EPPA model, and also by 

national decisions regarding gas production, 

imports and transport infrastructure. Therefore, the numbers shown are subject to a 

number of uncertainties, prominent among 

which is the willingness of Middle East and 

Russian suppliers to produce and export on the 

modeled economic basis.10 If potential supplies 

are not forthcoming, then global prices would 

be higher and the U.S. would import less than 

projected and perhaps increase exports. The 

broad insight to be drawn is nonetheless 

evident: to the degree that economics are 

allowed to determine the global gas market, 

trade in this fuel is set to increase over coming 

decades, with implications for investment and 

potential concerns about import dependence. 

The assumptions about the gas markets also 

affect the carbon price and GDP impacts in the 

GHG mitigation scenario. While the difference 

is small initially (in 2030, a U.S. carbon price is 

decreased from $106 to $103 per ton CO2

-e and 

U.S. GDP loss is decreased from 1.7% to 1.6%), 

it grows over time (in 2050, a U.S. carbon price 

is decreased from $240 to $180 and U.S. GDP 

loss is decreased from 3.5% to 2.6%).

LONGER-TERM PROSPECTS FOR GAS 

UNDER DEEPER EMISSIONS CUTS 

While current investment and policy decisions 

appropriately focus on a shorter horizon, policy 

decisions related to atmospheric stabilization of 

GHG concentrations inevitably involve a very 

long-term perspective. Though gas frequently 

is touted as a “bridge” to the future, continuing 

effort is needed to prepare for that future, lest 

the gift of greater domestic gas resources turn 

out to be a bridge with no landing point on the 

far bank. 

To explore this issue, we conducted model 

simulations extending the horizon to 2100 

assuming GHG emissions cuts that deepen to 

80% below 2005 levels. The result is that, until 

gas with CCS begins to penetrate after 2060, the 

cost of CO2

 emissions from gas generation 

becomes too high to support its use in generation (Figure 3.12). Nuclear is cheaper than coal 

or gas with CCS for much of the period and so 

it expands to meet the continuing electricity 

demand. Different cost assumptions well within 

the range of uncertainty would lead to a 

different mix of low-CO2

 generation sources, 

but the picture for gas without CCS would 

remain the same. 

Figure 3.12 Energy Mix in Electric Generation under a Price-Based Climate Policy, 

Mean Natural Gas Resources and Regional Natural Gas Markets (TkWh)

Reduced Use

Renew

Hydro

Nuclear

Gas CCS

Gas

Oil

Coal CCS

Coal

TkWh

Year

2010 2020 2030 2040 2050 2060 2070 2080 2090 2100

8

7

6

5

4

3

2

1

0

Source: EPPA, MIT
70 MIT STUDY ON THE FUTURE OF NATURAL GAS

One implication of this longer-term experiment is that while we might rely on plentiful 

supplies of domestic gas in the near term, this 

must not detract us from preparing for a future 

with even One implication of this longer-term 

experiment is that while we might rely on 

plentiful supplies of domestic gas in the near 

term, this must not detract us from preparing 

for a future with even greater GHG emissions 

constraints. Barriers to the expansion of 

nuclear power or coal and/or gas generation 

with CCS must be resolved over the next few 

decades so that over time these energy sources 

will be able to replace natural gas in power 

generation. Without such capability, it would 

not be possible to sustain an emissions mitigation regime.

CONCLUSIONS 

The outlook for gas over the next several 

decades is in general very favorable. In the 

electric generation sector, given the unproven 

and relatively high cost of other low-carbon 

generation alternatives, gas could well be the 

preferred alternative to coal. 

A multi-sector GHG pricing policy would 

increase gas use in generation but reduce its use 

in other sectors, on balance increasing gas use 

substantially from the present level. A regulatory approach, applied to renewable and coal 

use in the electric sector, could lead to even 

greater growth in gas use while having a more 

limited effect on national GHG emissions. 

Most important, in all cases studied — no new 

climate policy and a wide range of approaches 

to GHG mitigation — natural gas is positioned 

to play a growing role in the U.S. energy economy.

International gas resources are likely less costly 

than those in the U.S. except for the lowest-cost 

domestic shale resources, and the emergence of 

an integrated global gas market could result in 

significant U.S. gas imports. 

The shale gas resource is a major contributor 

to domestic resources but far from a panacea 

over the longer term. Under deeper cuts in CO2

emissions, cleaner technologies are needed. 

Gas can be an effective bridge to a lower CO2

emissions future but investment in the development of still lower CO2

 technologies remains an 

important priority. 

To the degree that economics are allowed to determine 

the global gas market, trade in this fuel is set to increase 

over coming decades, with implications for investment 

and import dependence.
Chapter 3: System Studies 71

NOTES

1Citations to documentation of the EPPA model and 

features related to this study are provided in Paltsev, 

S., H. Jacoby, J. Reilly, O. Kragha, N. Winchester, J. 

Morris and S. Rausch, 2010: The Future of U.S. 

Natural Gas Production, Use, and Trade. MIT Joint 

Program on the Science and Policy of Global 

Change, Report 186, Cambridge, MA. The USREP 

model is described by Rausch, S., G. Metcalf, J. Reilly 

and S. Paltsev, 2010: Distributional Impacts of 

Alternative U.S. Greenhouse Gas Control Measures. 

MIT Joint Program on the Science and Policy of 

Global Change, Report 185, Cambridge, MA. 

2Reference costs from the U.S. EIA (see Appendix 

3A). The lower sensitivity estimate is based on 

Update of the 2003 Future of Nuclear Power: An 

Interdisciplinary MIT study, Massachusetts 

Institute of Technology, Cambridge, MA. 

3

Reference costs from the U.S. EIA (see Appendix 

3A). The lower sensitivity estimate for coal with 

CCS draws on The Future of Coal: An Interdisciplinary MIT study, Massachusetts Institute of 

Technology, Cambridge, MA; that for gas with CCS 

comes from McFarland, J., S. Paltsev and H. Jacoby, 

2009: Analysis of the Coal Sector under Carbon 

Constraints, Journal of Policy Modeling, 31(1), 

404–424. 

4LCOE is the cost per kWh that over the life of the 

plant fully recovers operating, fuel, capital and 

financial costs. 

5

CO2 equivalent emissions for all greenhouse gases 

are calculated using 100-year global warming 

potentials (GWPs). See Appendix 1A for discussion. 

The simulations in this chapter account for fugitive 

methane emissions from the gas supply system.

6Because of the limited opportunities for gas-oil 

substitution the current price premium in the 

U.S. of oil products over gas (on an energy basis) 

is maintained and even grows over time. One 

substitution option not modeled here is the 

possibility of conversion of gas to liquids, which 

might become economic and perhaps be further 

stimulated by security concerns, even though 

making no contribution to CO2 reduction. Such a 

development would raise U.S. gas use and prices, 

and lower oil demand with some moderating effect 

on the world oil price. 

7For more details about sensitivity tests see Paltsev, 

S., H. Jacoby, J. Reilly, Q. Ejaz, F. O’Sullivan, 

J. Morris, S. Rausch, N. Winchester and O. Kragha. 

2010: The Future of U.S. Natural Gas Production, 

Use and Trade, MIT Joint Program on the Science 

and Policy of Global Change, Report 186, 

Cambridge, MA. 

8Substitution for motor fuel is the likely target of 

possible expansion of gas-to-liquids technology 

(see Chapter 4). Its market penetration would 

depend on competition not only with oil products 

but also with direct gas use, biofuels and electricity 

which reduce CO2 emissions while liquids from gas 

would not.

9Gas production and use with the USREP model is 

somewhat lower than the EPPA projection. 

Compared to EPPA, the USREP model has the 

advantage of capturing inter-regional differences in 

coal and gas prices, and better reflecting differences 

in renewable costs among regions, but it does not 

represent foreign trading partners. This variation 

introduced by the different model structures is well 

within the range of other uncertainties.

10For additional scenarios about the long-term 

prospects for Russian natural gas, see Paltsev S., 

(2011). Russia’s Natural Gas Export Potential up 

to 2050. MIT Joint Program on the Science and 

Policy of Global Change Report (forthcoming).

Chapter 4: Electricity 73

Chapter 4: Electric Power Generation 

The low-carbon emissions and low capital cost 

of natural gas generation compared to other 

fossil fuel generation, combined with abundant 

gas supplies and current relatively low prices, 

make natural gas an attractive option in a 

carbon-constrained environment, such as that 

contemplated in the analysis in Chapter 3. In 

addition to its increasingly important role as a 

primary fuel for electricity generation, natural 

gas will continue to perform a unique function 

in the power sector by providing both baseload 

power and the system flexibility that is required 

to meet variation in power demand and supply 

from intermittent sources. 

The focus of this chapter is on the role of natural 

gas in helping to reduce CO2

 emissions from the 

power sector and the interaction of gas use with 

projected growth in wind and solar generation.

Natural gas provides flexibility to the power system 

largely through the three types of generation 

technologies: highly efficient natural gas combined cycle (NGCC) units, steam turbines, and 

gas turbines. Gas turbines are generally used to 

meet peak demand levels and to handle weather, 

time of day, seasonal and unexpected changes in 

demand. NGCCs and steam turbines can act as 

baseload or intermediate-load units, although 

the majority of gas capacity in the U.S. now 

operates in load-following (intermediate) or 

peaking service. 

Currently, natural gas is second only to coal in 

total generation, fueling 23% of U.S. electricity 

production. Natural gas, however, has the highest 

percentage of nameplate1

 generation capacity of 

any fuel, at 41% compared to 31% for coal, which 

is the next highest (Figure 4.1). This difference 

between nameplate capacity and generation is 

INTRODUCTION

Figure 4.1 % Nameplate Capacity Compared to % Net Generation, U.S., 2009*

% Nameplate Capacity % Net Generation

41

0

10

20

30

40

50

23

6

1

30

44

9

7

9

20

5 4

<1 <1

Natural Gas

Percentage (%)

Petroleum Coal Hydroelectric Nuclear Other

Renewables

Other

*Numbers are rounded

Source: MIT from EIA data
74 MIT STUDY ON THE FUTURE OF NATURAL GAS

BOX 4.1 MODELS EMPLOYED TO EXAMINE 

THE U.S. ELECTRICITY SYSTEM

The MARKAL (MARKet ALlocation) model of 

the U.S. electricity sector enables a granular 

understanding of generation technologies, 

time-of-day and seasonal variations in electricity demand and the underlying uncertainties 

of demand. It was originally developed at 

Brookhaven National Laboratory (L.D. Hamilton, 

G. Goldstein, J.C. Lee, A. Manne, W. Marcuse, 

S.C. Morris, and C-O Wene, “MARKAL-MACRO: 

An Overview,” Brookhaven National Laboratory, 

#48377, November 1992). The database for the 

U.S. electric sector was developed by the 

National Risk Management Laboratory of the 

U.S. Environmental Protection Agency (EPA). 

The Renewable Energy Deployment System 

(ReEDS) model is used to project capacity 

expansions of generation, incorporating transmission network impacts, associated reliability 

considerations and dispatch of plants as operating reserves. It also captures the stochastic nature 

of intermittent generation as well as temporal 

and spatial correlations in the generation mix 

and demand. It has been developed by the 

National Renewable Energy Laboratory (NREL) 

(J. Logan, P. Sullivan, W. Short, L. Bird, T.L. James, 

M. R. Shah, “Evaluating a Proposed 20% National 

Renewable Portfolio Standard,” 35 pp. NREL 

Report No. TP-6A2-45161, 2009). 

The Memphis model realistically simulates the 

hourly operation of existing generation plants 

in the presence of significant volumes of wind 

and solar generation. It was developed by the 

Institute for Research in Technology of Comillas 

University (Madrid, Spain) for the Spanish 

Electricity Transmission System Operator (Red 

Eléctrica de España) to integrate renewable 

energies. (A. Ramos, K. Dietrich, J.M. Latorre, L. 

Olmos, I.J. Pérez-Arriaga, “Sequential Stochastic 

Unit Commitment for Large-Scale Integration of 

RES and Emerging Technologies,” 20th International Symposium of Mathematical Programming (ISMP) Chicago, IL, USA, August 2009. 

http://www.iit.upcomillas.es/~aramos/ROM.htm

explained in part by the overbuilding of 

NGCC units in the mid-1990s. It also shows 

that NGCC units are operating well below 

their optimum operating value. Finally, it 

highlights the unique role of gas and steam 

turbines, which in 2009 had an average 

capacity factor of 10% (see Table 4.1). This 

low-capacity factor illustrates the peaking 

function of these units, particularly the gas 

turbines, that are routinely used only to meet 

peak demand levels and which, absent breakthroughs in storage, are essential for following 

time-varying electricity demand and accommodating the intermittency associated with 

wind and solar power. 

Historically, because of its higher fuel price 

compared with nuclear, coal and renewables, 

natural gas has typically had the highest 

marginal cost and has been dispatched after 

other generation sources. Consequently, natural 

gas has set the clearing price for electricity in 

much of the country. Lower natural gas prices, 

the opportunities created by abundant 

relatively low-cost supplies of unconventional 

shale gas, increased coal costs and impending 

environmental regulations that will add to the 

cost of coal generation are, however, changing 

the role of gas in power generation. 

The Emissions Prediction and Policy Analysis 

(EPPA) model employed in Chapter 3 is 

designed to study multi-sector, multi-region 

effects of alternative policy and technology 

assumptions, and as a result it only approximates the complexities of electric system 

dispatch. In this chapter, we analyze in greater 

depth two of the cases studied there, employing 

a more detailed model of the electric sector — 

MARKAL (see Box 4.1). This model is also 

used to further explore the implications of 

uncertainty in fuel and technology choices as 

they influence natural gas demand in this 

sector, extending the uncertainty analysis in 

Chapter 3 which considers only the uncertainty in gas resources. 
Chapter 4: Electricity 75

This chapter then considers two questions 

about gas use in U.S. power generation: 

(1) What is the potential for reducing CO2

 by 

changing the current generation dispatch order2

to favor NGCC over coal generation? (2) What 

will be the effect of increased penetration of 

wind and solar generation on natural gas 

power generation?

To answer the first question it is important to 

understand NGCC utilization patterns. NGGC 

units are designed to be operated at capacity 

factors of up to around 85% rather than the 

current national average of 42%. This suggests 

possible opportunities for displacing some coal 

with gas generation, thereby lowering CO2

emissions from the sector. We examine how 

much of this capacity could actually be applied 

to this purpose without diminishing system 

reliability. An important by-product of such 

a change, also analyzed, would be associated 

reductions in criteria pollutant emissions.

To explore the second question, the interaction 

between intermittent renewables and natural 

gas use is analyzed from two viewpoints: one 

in the short term when additional intermittent 

capacity is introduced into a system with other 

sources fixed; and the other in the longer term

when the overall supply structure has time to 

adjust to growth in intermittent capacity. In 

this regard, we note that, at a more granular 

level than is presented in Table 4.1, wind 

turbines have an average capacity factor of 

27%, solar thermal, 19%, and solar PV, 14%, 

and gas combustion turbines and steam 

turbines (used to balance load) have average 

capacity factors of 5% and 14%, respectively.3

Study of these two questions is approached 

with the use of two additional electric sector 

models, each designed to simulate the power 

system and its operations in detail over a range 

of conditions and timescales (see Box 4.1), 

enabling the following analyses:

s !N EXAMINATION OF RELIABILITY AND TRANSMISsion constraints, which helps to isolate and 

understand the total generation required at 

points in time to meet demand for electricity 

and maintain operating reserve capacity and 

adequate installed capacity margins. We 

employ ReEDS for this analysis, which uses 

multiple time periods for any given year and 

reports results by geographic regions. 

s !N EXPLORATION OF ANNUAL SCENARIOS AT THE

hourly level, which takes into consideration 

details of real-time problems, such as uncertainty and variability in demand and in 

generation patterns for intermittent technologies, and start-up and shut-down 

characteristics for plant cycling. Here we use 

the Memphis model.

Coal Petroleum Natural 

Gas CC

Natural 

Gas Other Nuclear HydroelectricConventional

Other

Renewables

All Energy

Sources

64 8 42 10 90 40 34 45

Table 4.1 2009 Average Capacity Factors by Select Energy Source, U.S. (numbers rounded)

Source: EIA, Table 5.2, Average Capacity Factors by Energy Source
76 MIT STUDY ON THE FUTURE OF NATURAL GAS

ELECTRICITY SYSTEM OVERVIEW

The electricity system is complex; this overview 

of how the system works, including the regimes 

under which power plants operate and the 

hierarchy of decision-making that influences 

the capacity and generation mixes, is intended 

to enhance the understanding of the implications of the modeling and analysis discussed 

later in the chapter. 

Electricity is produced from diverse energy 

sources, varied technologies and at all scales. 

Sources for electric generation include a mix of 

renewables (sun, wind, hydro resources, among 

others), fossil fuels (oil, natural gas, coal) and 

uranium. As such, the generation of electricity 

comprises a variety of technologies with the 

type of fuel being used, and characterized by a 

wide range of investment and operating costs. 

Conventional power plants are operated under 

different regimes, mainly depending on their 

variable operating costs and operating 

flexibility.4

s Baseload plants are characterized by expensive 

capital costs and low variable costs, and they 

are operated most of the time during the year. 

They tend to be inflexible plants as they 

cannot easily change their operational level 

over a wide usage.

s Peaking plants are characterized by low 

capital costs and higher variable costs, and 

they are operated a few hours per year when 

the electric load is the highest. They can be 

characterized as flexible plants because of 

their quick operating response.

s Intermediate plants have variable costs that 

fall in between those of peaking and baseload 

technologies, and they are operated accordingly. They can be characterized as cycling 

plants, i.e., plants that operate at varying levels 

during the course of the day and perhaps 

shut down during nights and weekends.

The expansion planning and operation of 

electric power systems involve several decisions 

at different timescales, generally based on 

economic efficiency and system reliability 

criteria. This process has a hierarchical structure, 

where the solutions adopted at higher levels are 

passed on to the lower levels incorporating 

technical or operational restrictions at that level:5

s Long-term decisions are part of a multi-year 

process (3 years up to 10 or more years) that 

involves investments in generation and 

network required to expand the system.

s Medium-term decisions are taken once the 

expansion decisions have been made. They 

are part of an annual process (up to 3 years) 

that determines the generation unit and grid 

maintenance schedule, fuel procurement 

and long-term hydro resource scheduling.

s Short-term decisions are a taken on a weekly 

time frame. They determine the hourly 

production of thermal and hydroelectric 

plants for each day of the week (or month), 

subject to availability of the plants and to 

hydro production quotas determined at the 

upper decision level, and considering not 

only variable operating costs, but also the 

technology’s own technical characteristics 

such as start-up and shut-down cost and 

conditions, a plant’s technical minima and 

ramping times. In addition, these short-term 

decisions are subject to generating reserve 

capacity needed to immediately respond to 

unexpected events.

s Real-time decisions involve the actual operation of the system (seconds to minutes). They 

involve the economic dispatch of generation 

units, the control of frequency so that 

production and demand are kept in balance 

at all times, while maintaining the system 

components within prescribed safe tolerances 

of voltages and power flows, accounting also 

for possible contingencies.
Chapter 4: Electricity 77

Finally, meeting reliably the consumption of 

electric power at all times requires having both 

adequate installed capacity and secure operation procedures. A reliable operation involves 

using ancillary services at different levels, 

maintaining sufficient capacity in reserve 

(quick-start units, spinning reserves) and with 

enough flexibility to respond to deviations in 

the forecast of demand or intermittent generation, and to unexpected events, such as the 

sudden loss of lines or generation plants.

THE ROLE OF GAS GENERATION

UNDER A CO2 LIMIT

The EPPA model simulations in Chapter 3 

provide insights into both the economy-wide 

use of natural gas and its market share in 

electric power under various assumptions 

about greenhouse gas (GHG) mitigation. 

Application of the MARKAL model, with its 

greater electric sector detail, provides a check 

on the adequacy of the EPPA approximations 

for the power sector. MARKAL considers a 

more complete listing of the generation alternatives, and it addresses the variation in the 

level of electricity demand, as a result of the 

diurnal, weekly and seasonal cycles (which 

EPPA only roughly approximates). This variation is important because different technologies 

are needed to run different numbers of hours 

per year — a pattern that changes over years 

with demand growth and new investment. Also, 

the MARKAL model allows for a more complete exploration of uncertainty in gas use in 

the power sector. 

For consistency with the analysis in Chapter 3, 

certain MARKAL inputs are taken from the 

EPPA model results, including electricity 

demand, supply curves for natural gas and coal 

and the reference costs of generation technologies. Also, two of the same policy cases are 

considered: Scenario A, which assumes no new 

GHG policy; and Scenario B, which imposes 

a Price-Based mitigation measure. For the 

Price-Based case, a cap on CO2

 emissions for 

the electric sector in MARKAL is set based on 

the results for that scenario in Chapter 3.

The underlying technology mix computed 

by the more-detailed electric sector model can 

be illustrated by annual load duration curves, 

which show the mix of generation dispatched 

at different times to meet changes in the level 

of electricity demand in the contiguous U.S. 

electric system over the course of a year. These 

curves for the year 2030, with and without 

a policy of carbon constraints, are shown in 

Figure 4.2. In the absence of a carbon policy 

(Panel a), generation from hydro, coal and 

nuclear occur at all times of the year while 

generation from wind and hydro are supplied 

whenever they are available.6

Without a carbon policy (Panel a), natural gas 

generation from combined cycle and steam 

turbines occurs for less than half of the time 

over the course of the year during periods of 

higher demand; and natural gas combustion 

turbines are used for only a few hours per year 

at the peak demand hours. 

Under the carbon price policy (Panel b), NGCC 

technology largely substitutes for coal to 

provide baseload generation along with nuclear 

generation.
78 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 4.2 Time blocks approximation to the Load Duration Curve for the (a) No Policy 

and (b) 50% Carbon Reduction Policy Scenarios in 2030. Three seasons have been considered: summer, winter and spring/autumn. Within each season, there are four blocks: 

peak time, daytime PM, daytime AM, and nighttime, as shown in the graphs. The peak 

time block is very narrow. 

Source: MIT analysis

0

0 2000 4000 Hours 6000 8000

200

400

600

800

1000

1200

800

1000

700

750

950

850

900

Summer Winter Spring & Autumn

Solar

Oil

Landfill

Geothermal

Diesel

Biomass

Municipal Waste

Gas Steam

Gas Combustion Turbine

Gas Combined Cycle

Wind

Coal Steam

Hydro

Nuclear

0 2000 4000 Hours 6000 8000

Summer Winter Spring & Autumn

0

200

400

600

800

1000

700

600

650

750

800

4.2a

4.2bGW GW
Chapter 4: Electricity 79

The change over time in the energy mix in the 

electric sector is shown in Figure 4.3 for both 

the No Policy and the Price-Based cases. In the 

No Policy case, under reference assumptions for 

fuel prices, electricity demand and technology 

costs — and mean gas resources — these results 

show the same pattern of increasing gas use as 

the simulation studies in Chapter 3. The gas use 

in this sector in 2025 is essentially the same in 

the two studies. Toward the end of the simulation period, MARKAL projects one-quarter to 

one-third more gas-based generation than 

EPPA, though gas generation is still small 

relative to coal. 

Under the Price-Based policy the overall 

pattern of change remains the same as in EPPA: 

coal is forced out and replaced by gas. In the 

period to 2025 MARKAL projects a more rapid 

phase-out of coal than does EPPA, in part 

because MARKAL is a forward-looking model 

and sees higher prices in the future whereas the 

recursive dynamic (myopic) EPPA model does 

not. Farther out in time coal is no longer in the 

mix, and under a continuously tightening CO2

constraint conventional gas generation begins 

to be replaced by non-carbon generation sources 

such as nuclear, renewables and/or coal or gas 

with carbon capture and sequestration (CCS). 

The EPPA model expands nuclear generation 

whereas MARKAL introduces natural gas with 

CCS, yielding about a one-quarter greater level 

of gas use. The outlook for gas in this sector is 

consistently positive across the two studies, and 

the difference in details of load dispatch is to be 

expected for models of such different mathematical structure, and well below the level of 

uncertainty in either (see Figure 4.3).

Source: MIT Analysis

Figure 4.3 Future Energy Mix in Electricity Sector

Figure 4.3a With No Climate Policy Figure 4.3b With Price-Based Climate Policy

Others

Renewable

Hydro

Nuclear

Natural Gas

Coal

0

1

2

3

4

5

6

7

Electricity generation (TkWh)

2010 2015 2020 2025 2030 2035 2040 2045 2050 2010 2015 2020 2025 2030 2035 2040 2045 2050

0

1

2

3

4

5

6

7

Electricity generation (TkWh)
80 MIT STUDY ON THE FUTURE OF NATURAL GAS

The systems studies in Chapter 3 consider only 

uncertainty in the estimates of gas resources 

(Figures 3.2, 3.3 and 3.0). Applying the 

MARKAL model and the reference assumptions 

discussed above, a study was carried out of the 

effect on gas use of uncertainties not only in 

resources but in other prices, electricity 

demand and technology costs. The same two 

cases were considered: No Policy; and the 

Price-Based policy. Here we describe results for 

a 50% confidence interval: i.e., a 25% chance 

of gas use above the high level as shown, and a 

25% chance of use below the low level. Details 

of the analysis are provided in Appendix 4B.

By 2030, with no additional mitigation policy, 

the gas demand by the electric sector runs 

17% above and 19% below the mean value of 

6.3 trillion square feet (Tcf) (50% confidence 

interval). The main factors leading to this range 

are the demand for electricity, the prices of 

natural gas and coal and the costs of new 

technologies, in particular the cost of new coal 

steam and IGCC technologies. 

Under the Price-Based policy the uncertainty is 

substantially greater, ranging from 47% above 

to 42% below the mean value of 12.8 Tcf (50% 

confidence interval). The main influence 

behind this greater uncertainty is in the costs of 

technologies that might substitute at large scale 

for fossil-based generation, such as wind, solar 

and advanced nuclear generation technologies. 

The share of natural gas in the generation mix 

is a result of the interplay between technologies 

that both compete with and complement each 

other at the same time as they supply different 

segments of demand over the year. 

The uncertainty ranges given here are intended 

to caution the reader against giving too much 

weight to the actual numbers in future projections in this chapter and elsewhere in the 

report. Rather, the critical insights are about the 

trends and relationships, which are more robust 

across a wide range of possible futures.

NEAR-TERM OPPORTUNITIES FOR

REDUCING CO2 EMISSIONS BY 

ENVIRONMENTAL DISPATCH 

Near-term opportunities for CO2 emission 

reductions in the power sector are limited by 

the current generation mix and transmission 

infrastructure, the cost of renewables and other 

low-emission sources and technologies, as well as 

the lag times associated with siting and building 

any new generation capacity. The re-ordering of 

generation between coal and gas units (modeled 

here as a form of environmental dispatch forced 

by a CO2

 constraint7) may be the only option for 

large-scale CO2

 emissions reduction from the 

power sector which is both currently available 

and relatively inexpensive. 

As noted, the current fleet of NGCC units has 

an average capacity factor of 41%, relative to 

a design performance of approximately 85%. 

An electric system requires capacity to meet 

peak demands occurring only a few hours per 

year, plus an operating reserve, so the system 

always includes some generation units that run 

at capacity factors below their design value. 

However, the U.S. has enough spare capacity 

in other technologies to allow dispatching more 

NGCC generation, displacing coal and reducing CO2

 emissions, without major capital 

investment. An additional benefit of this 

approach would be to substantially reduce 

emissions of air pollutants such as sulfur 

dioxide (SO2

), nitrogen oxide (NOx), mercury 

(Hg) and particulates.

NGCC Potential if Fully Dispatched

Figure 4.4 suggests the scale and location of the 

potential for shifting among generation units. 

Plotted there is the geographic distribution of 

fully-dispatched NGCC potential (FDNP), 

defined as the difference between the electricity 

that would be produced by NGCC plants at 

an 85% capacity factor and their actual 2008 

generation. Figure 4.4 also shows the geographic 

distribution of coal generation, divided into 
Chapter 4: Electricity 81

Figure 4.4 Scale and Location of Fully Dispatched NGCC Potential (FDNP) 

and Coal Generation (MWh, 2008)

Source: USREP, MIT 

less and more efficient units where a “less 

efficient” unit is defined as one with a heat rate 

over 10,000 Btu/kWh.

In many regions FDNP generation matches 

well with less efficient coal capacity, suggesting 

opportunities for displacing emissions-intensive 

units, while other locations show few such 

opportunities. For example, Southeastern states 

such as Texas, Louisiana, Mississippi, Alabama 

and Florida appear to have relatively larger 

opportunities, while those in Midwestern states 

such as Illinois, Indiana and Ohio are relatively 

smaller.

Possible Contribution of NGCC Capacity 

to a CO2

 Reduction Goal 

Figure 4.4 represents only the average potential 

available over the course of the year, aggregated 

by state, therefore providing an upper limit of 

the substitution potential; it does not equate 

to “surplus” generation capacity. For this 

discussion, “surplus” is defined as the amount 

of NGCC generation that can be used over the 

course of one year to replace coal while respecting 

transmission limits, operation constraints and 

demand levels at any given time.
82 MIT STUDY ON THE FUTURE OF NATURAL GAS

To account for a number of system characteristics that may better identify the range of 

opportunities for fuel substitution, we apply 

the ReEDS model (see Box 4.1). This model is 

well suited for examination of reliability and 

transmission constraints, demand fluctuations 

and reserve capacity margins that will limit 

these opportunities. Also, as noted, ReEDS 

reports results by geographic regions.8

This enables us to identify opportunities to 

change the fuel dispatch order nationwide, 

and provides insights into five regions of the 

country: the Electric Reliability Council of 

Texas (ERCOT), Midwest Independent Transmission Operator (MISO), PennsylvaniaNew Jersey-Maryland (PJM), New England 

(ISO-NE) and Florida Reliability Coordinating 

Council (FRCC). Each region has different 

generation costs, fuel mixes and ability 

to trade electricity:

s %2#/4 IS ESSENTIALLY ELECTRICALLY ISOLATED

from the rest of the country; 

s -)3/ AND 0*- ARE HEAVILY INTERCONNECTED

they import and export electricity from each 

other, but have a relatively small amount of 

NGCC surplus; 

s )3/
.% AND &2## HAVE SURPLUS .'##

but New England has relatively little coal 

generation, whereas Florida has a significant 

percentage of inefficient coal capacity that 

might be a candidate for displacement. 

We analyze the potential for a version of 

environmental dispatch by running the ReEDS 

model for the year 2012 in three scenarios: CO2

unconstrained, a 10% reduction in U.S. electric 

sector CO2

 emissions, and a 20% reduction. Runs 

for the year 2012 are used because the model does 

not invest in new capacity in this time period; as 

such, CO2

 reductions are attributable to shift of 

generation among existing units. 

Figure 4.5 illustrates the changes in generation 

by technology under the three scenarios. In the 

20% CO2

 reduction scenario, the NGCC fleet 

has an average capacity factor of 87%, displaces 

Source: MIT Analysis

Figure 4.5 Generation by Technology under Various CO2 Constraints, U.S.9, 2012

Coal Gas-CC

0

500

1,000

1,500

2,000

2,500

20.0

Base Case 10% CO2 Reduction 20% CO2 Reduction

Generation (TWh)

Wind

Nuclear Hydroelectric Other*
Chapter 4: Electricity 83

about one-third of 2012 coal generation 

(700 terawatt-hours (TWh)) and increases gas 

consumption by 4 Tcf.9

In Figure 4.5, as the carbon constraint 

increases, most of the electricity generation by 

technology does not change. Coal and natural 

gas are the exceptions: as the carbon constraint 

increases, coal generation significantly declines, 

and NGCC proportionally increases.

Although NGCC displacement of coal generation is nearly one-for-one at the national level, 

the change in generation and emissions is not 

uniform across regions. Figure 4.6 shows 

regional results, comparing coal generation in 

the absence of a CO2

 target to surplus NGCC 

generation in a 20% reduction scenario. 

In Figure 4.6, the left bars represent the amount 

of regional coal generation absent carbon 

constraints, using ReEDS 2012 forecasts. This is 

the “business as usual” scenario. The right bars 

represent the amount of additional NGCC 

generation that is available for dispatch in the 

current system after satisfying all system requirements. This additional amount of generation is 

calculated as the difference between the NGCC 

generation dispatched in the base case and in the 

20% CO2

 reduction scenario. The largest 

potential for substitution of NGCC for coal 

generation is in PJM, although in both PJM 

and MISO coal continues to dominate.

A closer look at how the imposition of a CO2

limit would shift generation among units can 

be seen in the revised unit dispatch at different 

demand levels. For this analysis, we look at 

ERCOT, a system that is isolated from the rest 

of the U.S. and, in our re-dispatch scenarios, 

has regional percentage of CO2

 reductions that 

tracks national reductions. Because of these 

similarities to the country, and because of the 

greater availability of operations information 

from ERCOT, an analysis of ERCOT, using 

Source: MIT Analysis

Figure 4.6 NGCC and Coal Generation in Select Regions under a 20% CO2 Constraint, 

U.S., 2012

Coal (base case) Gas Surplus

0

100

200

300

400

500

600

20.0

16: MISO 23: PJM 32: ISO-NE

Generation (TWh)

21: ERCOT 29: FRCC
84 MIT STUDY ON THE FUTURE OF NATURAL GAS

ReEDS provides additional details about fuel 

switching on a more granular timescale. 

Figure 4.7 illustrates how existing capacity 

would be dispatched to meet 2012 projected 

demand for the highest peak, average and low 

demand situations, with and without the CO2

target to force a change in unit dispatch.10 The 

figure shows an unconstrained base case and 

a case with a 20% CO2

 reduction. The average 

profile shows the generation dispatch for all 

technologies across an entire year (8,760 hours), 

not a single time slice. 

In Figure 4.7, the red line represents 17 time 

periods of demand for the year, sorted from 

greatest to least demand. The bar graphs to the 

right of the nameplate capacity bar show the 

dispatch profile in those time periods under 

two carbon scenarios: no reduction and 20% 

reduction. 

Not surprisingly, the results indicate that the 

greatest opportunities for displacement of coal 

generation exist during average and low 

demand periods. Figure 4.7 also shows that coal 

generation is dispatched in every time period, 

indicating that not enough NGCC surplus 

exists in ERCOT to completely displace coal; 

Figure 4.7 Changes in Dispatch Order to Meet ERCOT’s 2012 Demand Profile, with and without 

a 20% CO2

 Constraint

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Oil-Gas-Steam Turbine 

Natural Gas – Combustion Turbine 

Natural Gas – Combined Cycle

Coal

Wind

Hydro

Nuclear

MW

Annual load duration curve

Bar graphs 

represent

dispatch pro

Nameplate

capacity

Super peak demand – 40 hrs total

Late summer afternoons

Average annual dispatch

profile – over 8,760 hrs

Low demand – 736 hrs total

Typical spring nights

Base Fuel 

Switch

Base Fuel 

Switch

Base Fuel 

Switch

Source: MIT Analysis
Chapter 4: Electricity 85

conversely, surplus NGCC capacity exists and 

can displace some coal capacity in all demand 

periods examined, even during the super peak, 

although the amount is small. 

Effect of System Re-Dispatch 

on Criteria Pollutants

The Clean Air Act (CAA) requires power plant 

controls on SO2

, NOx, particulates and Hg. 

According to the EPA, “60% of the uncontrolled power plant units are 31 years or older, 

[some] lack advanced controls for SO2

 and 

NOx, and approximately 100 gigawatts (GW) 

out of total of [more than 300] GW of coal are 

without SO2

 scrubbers.” 11

Table 4.2 contains results from ReEDS under 

the three scenarios that indicate the potential 

effects of the CO2

 constraint (also shown) on 

emissions of SO2

, NOx and Hg. (The model 

does not project particulate emissions, which 

also would be reduced.) While ReEDS does not 

fully model the trading markets for SO2

 and 

NOx, it makes a reasonable approximation by 

capping national emissions levels and making 

economically efficient dispatch decisions under 

these constraints. In all three simulations the 

cap for SO2

 emissions is based on the 2005 

Clean Air Interstate Rule (CAIR) interpolated 

for 2012.12

Changes to the dispatch order of generation, 

from coal to gas, would lower prices in the SO2

market, and might even yield a reduction in 

national emissions below the CAIR limit, as 

shown with a 4% change in Case 2. Importantly, the reductions in NOx and Hg emissions 

could be substantial, by as much as one-third 

under the more stringent CO2

 limit. 

Table 4.3 shows the corresponding emissions 

profiles by region for CO2

 and Hg. (ReEDS does 

not provide adequate regional detail for SO2

and NOx). Each region acts in its own best 

economic interests under the given constraints. 

And, because of variation in generation costs, 

installed capacity and transmission differences 

between regions, some regions have comparative advantage dispatching less CO2

 intensive 

generation. Depending on the regulatory 

structure, regions with these advantages may 

produce more electricity, export it and/or sell 

credits (assuming a cap-and-trade approach); 

and regions which typically deploy technologies 

that are more CO2

 intensive take opposite 

actions. This leads to uneven emissions effects 

on individual regions.

A 20% emissions reduction in electric sector 

CO2

 emissions through coal-to-gas displacement would represent mitigation of 8% of the 

U.S. total. The ReEDS model does not provide 

Base Case Case 1 – 

10% CO2

Reduction

Case 2 – 

20% CO2

Reduction

% Reduction 

from 

Base Case 

for Case 1

% Reduction 

from 

Base Case 

for Case 2

CO2 (million metric tons) 2,100 1,890 1,680

SO2 (million tons) 5.66 5.66 5.46 — 4%

NOx (million tons) 4.66 3.92 3.16 16% 32%

Hg (tons) 48 40 32 17% 33%

Source: MIT analysis

Table 4.2 National Emissions for CO2-Reduction Scenarios
86 MIT STUDY ON THE FUTURE OF NATURAL GAS

an accurate estimate of the national economic 

cost of this option, but an approximation can 

be made by comparing the break-even CO2

price at which the cost of NGCC generation 

equals the cost of coal generation, given their 

different variable operations and maintenance 

costs, heat rates and CO2

 emissions rates.13

The result is an implicit cost of about $16 per 

ton CO2

. 

More analysis is required to determine whether, 

because of the geographic differences between 

NGCC and coal units, some new transmission 

infrastructure may be necessary. Nonetheless, 

a more complete analysis is very likely to prove 

the cost of this option to be low compared to 

most other mitigation options. For example, 

one estimate of the per-ton CO2

 emissions 

avoidance cost estimate to retrofit a typical 

sub-critical coal plant with post-combustion 

CSS is $74 per ton.14

It should also be noted that coal-to-gas fuel 

switching is already occurring. According to the 

Energy Information Agency (EIA), “The increase 

in delivered coal prices and the decrease in 

delivered natural gas prices, combined with 

surplus capacity at highly efficient gas-fired 

combined-cycle plants resulted in coal-to-gas 

fuel switching. Nationwide, coal-fired electric 

power generation declined 11.6 percent from 

2008 to 2009, bringing coal’s share of the 

electricity power output to 44.5 percent, the 

lowest level since 1978.” 15

In sum, there is sufficient surplus NGCC 

capacity to displace roughly one-third of U.S. 

coal generation, reducing CO2

 emissions from 

the power sector by 20% and yielding a major 

contribution to control of criteria pollutants. 

This would require an incremental 4 Tcf per 

year of natural gas, which corresponds to a cost 

of $16 per ton of CO2

. Currently there is no 

national price on CO2

, but there are both 

regional programs and federal regulatory 

activities underway. 

RE COMMENDATION

The displacement of coal generation with 

NGCC generation should be pursued as 

the most practical near-term option for 

significantly reducing CO2

 emissions from 

power generation. 

Base Case MISO ERCOT PJM FRCC ISO-NE

CO2 (million metric tons) 543 153 446 67.2 19

Hg (tons) 13.4 2.77 11 1.32 0.138

Case 2 – 20% CO2 Reduction

CO2 (million metric tons) 394 121 351 78.9 25.4

Hg (tons) 9.30 1.43 7.58 1.13 0.10

% Hg reduction 31% 48% 31% 14% 27%

Source: MIT Analysis

Table 4.3 Emissions of Select Regions Before and After Re-Dispatch, 2012

There is sufficient surplus NGCC capacity to 

displace roughly one-third of U.S. coal generation, 

reducing CO2 emissions from the power sector 

by 20% and yielding a major contribution to 

control of criteria pollutants. This would require 

an incremental 4 Tcf per year of natural gas, which 

corresponds to a cost of $16 per ton of CO2. 
Chapter 4: Electricity 87

INTERMITTENT RENEWABLE ELECTRICITY 

SOURCES AND NATURAL GAS DEMAND

In this section, we explore the impacts of the 

introduction of significant amounts of intermittent wind and solar electricity generation 

on natural gas generation and overall natural 

gas demand.

This analysis first explores the short-term effects

of intermittent wind and solar generation on 

gas generation and demand, a scenario which 

assumes that the capacity from technologies 

— other than wind or solar — is fixed. Some 

European countries already approximate this 

situation, where substantial volumes of wind 

or solar generation have been installed during 

the last few years. Also in some U.S. states, the 

proportion of intermittent generation exceeds 

10% and the dispatch of existing conventional 

generation units has had to adjust accordingly. 

We then turn to longer-term impacts, where 

the deployment of intermittent generation 

is assumed to take place gradually, possibly 

in response to government policies that, for 

example, set a mandatory target for renewable 

generation. Over time, capacity additions and 

retirements of other technologies are made as 

the system adjusts to intermittent generation. 

Effects in the Short Term

To elucidate the short-term effects, we use: 

s A  PROJECTED GENERATION PORTFOLIO AS THE

base case, obtained from the ReEDS CO2

Price-Based policy scenario (see Box 4.1); and 

s THE -EMPHIS MODEL SEE "OX 	 APPLIED TO

daily dispatch patterns for ERCOT which, as 

noted earlier, is an isolated system that can be 

studied without the complicating influence of 

inter-regional transmission. 

With this 2030 generation portfolio as our 

reference point, we examine the daily dispatch 

patterns of all generation technologies, including natural gas, when greater or lesser levels of 

wind or solar electricity generation are made 

available to be dispatched and the capacities 

of the other technologies are held constant. 

Wind generation. The results for varying levels 

of wind generation are seen in:

s &IGURE A THE BASE CASE WHICH IS A representative day for ERCOT; 

s &IGURE B WHEN WIND PRODUCES half the 

amount of generation as in the base case; and

s &IGURE C WHERE WIND PRODUCES twice the 

amount of generation as in the base case.
88 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 4.8 Impact of Wind on a One-Day Dispatch Pattern for ERCOT

60,000

50,000

40,000

30,000

20,000

10,000

0

Production (MW)

h01h02h03h04h05h06h07h08h09h10h11h12h13h14h15h16h17h18h19h20h21h22h23h24

4.8b Wind 0.5

60,000

50,000

40,000

30,000

20,000

10,000

0

Production (MW)

h01h02h03h04h05h06h07h08h09h10h11h12h13h14h15h16h17h18h19h20h21h22h23h24

4.8c Wind 2.0

60,000

50,000

40,000

30,000

20,000

10,000

0

Production (MW)

h01h02h03h04h05h06h07h08h09h10h11h12h13h14h15h16h17h18h19h20h21h22h23h24

Hydro

Solar

Gas GT

Gas CCGT

Gas CCGT CCS

Biomass

Coal

Wind

Nuclear

4.8a Wind Base Case

Hydro

Solar

Natural Gas – 

Gas Turbine

Natural Gas – 

Combined Cycle

Integrated 

Gasi!cation 

Combined Cycle 

with CCS

Biomass

Coal

Wind

Nuclear

Source: MIT Analysis
Chapter 4: Electricity 89

In Figure 4.8a, the base case depicts the estimated existing contribution from wind in 

ERCOT in 2030. The nighttime load (roughly 

hours 01 through 04) is met by nuclear and 

coal baseload plus wind generation. There is 

no appreciable output from gas between hours 

01 and 04 because it has higher variable costs 

than nuclear and coal and it gets dispatched 

last. Natural gas also has the flexibility to cycle. 

In hours 05 through 23, when overall demand 

increases during the early morning and 

decreases in the late evening, NGCC generation 

adjusts to match the differences in demand. 

As depicted in Panel 4.8b, when less wind 

is dispatched, the NGCC capacity is more 

fully employed to meet the demand, and the 

cycling of these plants is significantly reduced. 

The baseload plants continue to generate at 

full capacity. 

In Panel 4.8c with twice as much wind as the 

base case, natural gas generation is reduced 

significantly; the gas capacity that is actually 

used is forced to cycle completely. Baseload 

coal plants are also forced to cycle because 

of the relatively low nighttime demand; coal 

plant cycling can increase CO2

, SO2 and NOx 

emissions.16

Solar Generation. Like wind, for solar there 

are figures depicting: a base case in ERCOT 

(Figure 4.9a); a case where solar provides half 

the amount of generation as the base case 

(Figure 4.9b); and a case where solar provides 

twice the generation seen in the base case 

(Figure 4.9c).

The pattern with solar is somewhat different 

than for wind. The solar generation output 

basically coincides with the period of high 

demand, roughly between hours 06 and 22. 

As seen in the base case Figure 4.9a, this is also 

when NGCC capacity gets dispatched. The 

natural gas plants are used more when solar 

output is less (see Figure 4.9b). Conversely, 

when solar is used more, less gas is dispatched 

(see Figure 4.9c). 

The baseload plants are largely unaffected and 

cycling is not a problem for them, since there is 

no intermittent solar-based generation during 

the low-demand night hours. 

In sum, our short-term analysis shows that the 

most significant impacts of a quick deployment 

of additional wind or solar at any given future 

year will most likely be both a reduction in 

production from, and an increase in cycling of, 

gas-fueled NGCC plants; there is a less significant 

fall in production for the much-less-employed, 

single-cycle gas turbines and steam gas units.

The displacement of gas is greater for solar than 

for wind, since solar production has a stronger 

correlation with demand than does wind 

generation.

Large wind penetrations may also displace 

some coal production and result in some 

cycling of these plants. No impact on nuclear 

production is expected with the average U.S. 

technology mix. 

[In the short term]....the most significant impacts 

of a quick deployment of additional wind or solar ...

will most likely be both a reduction in production 

from, and an increase in cycling of, gas-fueled 

NGCC plants....
90 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 4.9 Impact of Solar CSP (no storage) on One-day Dispatch Pattern for ERCOT

60,000

50,000

40,000

30,000

20,000

10,000

0

Production (MW)

h01h02h03h04h05h06h07h08h09h10h11h12h13h14h15h16h17h18h19h20h21h22h23h24

Hydro

Solar

Gas GT

Gas CCGT

Gas CCGT CCS

Biomass

Coal

Wind

Nuclear

4.9b Solar Base Case x 0.5

Solar

Hydro

Biomass

Gas – GT

Gas – CCGT CCS

Gas – CCGT

Coal – IGCC CCS 

Coal – Old Biomass

Coal – Old NoScrub

Wind

Nuclear

60,000

50,000

40,000

30,000

20,000

10,000

0

Production (MW)

h01h02h03h04h05h06h07h08h09h10h11h12h13h14h15h16h17h18h19h20h21h22h23h24

4.9c Solar Base Case x 2.0

Solar

Hydro

Biomass

Gas – GT

Gas – CCGT CCS

Gas – CCGT

Coal – IGCC CCS 

Coal – Old Biomass

Coal – Old NoScrub

Wind

Nuclear

60,000

50,000

40,000

30,000

20,000

10,000

0

Production (MW)

h01h02h03h04h05h06h07h08h09h10h11h12h13h14h15h16h17h18h19h20h21h22h23h24

Hydro

Solar

Gas GT

Gas CCGT

Gas CCGT CCS

Biomass

Coal

Wind

Nuclear

4.9a Solar Base Case

Solar

Hydro

Biomass

Gas – GT

Gas – CCGT CCS

Gas – CCGT

Coal – IGCC CCS 

Coal – Old Biomass

Coal – Old NoScrub

Wind

Nuclear

Source: MIT Analysis
Chapter 4: Electricity 91

Effects in the Long Term

To explore the effects of the penetration of 

intermittent generation over the long term, 

we examine two policy scenarios, both with a 

system expansion to 2050 and a target leading 

to a 70% reduction of CO2

 emissions in the 

U.S. power sector. 

We look at two different versions of the 70% 

reduction case because the means by which 

the target is implemented — through different 

mitigation policy instruments — has an effect 

on how the system responds to more or less 

expensive renewable generation. The two policy 

instruments we examine are:

s THE IMPOSITION OF A CO2

 price to achieve 

the CO2

 emissions reduction target; and 

s THE IMPOSITION OF AN emissions constraint

to achieve the same target.

We then analyze how the electric system, and 

gas use over time, would differ if the capital 

costs of solar or wind generation capacity were 

higher or lower than the reference levels for the 

two base cases. Again the ReEDS model is 

employed.17

In the ReEDs simulations of both policy 

scenarios, the generation mix evolves over time, 

similar to that shown in Chapter 3, Figures 3.4a 

and 3.4b. During the early-to-middle decades 

of the simulation period the dominant event is 

the substitution of coal generation by NGCC 

units. At the same time, wind generators, with 

gas turbine back-up, begin to be deployed as 

a baseload technology.18

This combination of wind production and 

flexible generation capacity competes with 

potential new nuclear capacity and also erodes 

NGCC production. Wind impacts the preferred 

new baseload generation technology, the one 

that is most economic but for which expansion 

is not subject to environmental or other limits. 

Late in the period, conventional coal production 

has been replaced, economically-competitive 

wind resources start becoming exhausted and 

nuclear plus some solar penetration begins. 

CO2

 Price-Based Case. In the CO2 Price-Based 

case, the nature of the system adjustments in 

these simulations can be illustrated using an 

example of the changes that would be brought 

about by lower-cost wind capacity. First, the 

increased intermittent renewable generation 

needs to be accompanied by flexible back-up 

capacity, albeit with low utilization levels. In 

the U.S., spare capacity of gas-fueled plants is 

enough to meet this requirement initially, but 

eventually additional investment is needed 

(gas turbines in these scenarios).

As this combination of new intermittent renewable and flexible electricity plants grows, it 

starts to replace the expansion and utilization 

of baseload generation technologies, nuclear 

or fossil generation with CCS (coal without 

CCS has already been forced out of the system 

by its CO2

 emissions). However, these classic 

baseload technologies are not increasing; 

therefore, the low-cost renewable capacity plus 

flexible generation increases in baseload and 

even in mid-merit service, at the expense of 

gas generation. 
92 MIT STUDY ON THE FUTURE OF NATURAL GAS

This interaction can be illustrated with a 

summary of what happens in the base case 

system for the ERCOT region when different 

renewable costs are simulated, therefore 

changing the intermittent generation penetration levels. 

The results in Figure 4.10 are plotted to highlight the way cumulative gas generation 

changes with different assumptions about 

wind-generation costs and the corresponding 

wind-generation levels. The figure shows the 

total generation in TWh by type of generation 

technology over the simulation period from 

2005 to 2050 and assumes the underlying 

emissions target is imposed by a CO2

 price. 

It illustrates that the displacement of gas by 

wind takes place through changed patterns of 

investment and generation over many years. 

As Figure 4.10 shows, increased cumulative 

wind generation, as a consequence of lower 

wind investment costs, or an aggressive renewable portfolio standard, has a direct impact on 

the new investment and associated production 

by natural gas, equal to almost one TWh of 

reduced natural gas generation for one TWh 

of wind output. This happens because NGCC 

is the technology that is most vulnerable to 

wind competition, both before and after coal 

has been driven out of the market. It should 

also be noted that, while the cumulative 

generation of gas turbines (Gas-CT in Figure 

4.10) does not change enough to show in the 

graph, gas turbine capacity actually increases 

substantially to support the additional wind 

contribution. 

Source: MIT Analysis

Figure 4.10 Cumulative Generation in ERCOT in the Period 2005–2050 for All Technologies Given 

Alternative Levels of Wind Penetration (TWh) 

5,000

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

0

 250 450 650 850 1,050 1,250 1,450 1,650

Wind (Gen)

Nuclear (Gen)

Coal Old Scrubbed

Coal Old Unscrubbed

Oil-Gas Steam

Gas-CC

Gas-CT 

Hydro

Utility PV

TWh
Chapter 4: Electricity 93

In Figure 4.10, the horizontal axis is cumulative 

wind output, the vertical axis is the cumulative 

output for all technologies, including wind 

(if the two axes were plotted to the same scale 

the function for wind would be a 45 ̊ line). The 

base-case level of wind generation is indicated 

with a vertical line, so that output to the right 

of that point results from lower capital costs 

and the output to the left results from higher 

capital costs.

Figure 4.10 also shows that the difference in 

cumulative generation by the other technologies is not much affected by changes in the 

contribution of wind generation. It should be 

repeated that this is a result for ERCOT. The 

differences in generation mix in other regions 

will vary, though viewed at the national level 

the pattern is very similar to that shown here.19

CO2

 Cap Case. The result differs somewhat if 

emissions mitigation is accomplished by a CO2

cap instead of a price. The fixed CO2

 constraint 

implies that an increment in wind output that 

displaces NGCC production and investment 

also reduces the need for other low-CO2

baseload capacity to reduce the emissions. 

Cheaper wind creates slack under the emissions 

constraint, which may be filled by whatever is 

the cheapest generation source. In some 

simulations, this cheap generation comes from 

otherwise almost-idle coal-fired plants. Thus, 

as a minor perverse effect, under the CO2

constraint more wind can imply a small 

increment of additional coal production — 

a condition that does not occur when coal 

is burdened by a CO2

 price. 

The case of solar generation without storage 

is similar to wind in many respects. However, 

since the production profile of solar has a high 

level of coincidence with the daily demand and 

has a more stable pattern, an increment in solar 

generation does not require back-up from 

flexible gas plants as much as wind does. In fact, 

solar can partially fulfill a peaking plant role.

In summary, our analysis of gradual and 

sustained “long term” penetration of wind and 

solar shows that large-scale penetration of wind 

generation, when associated to flexible natural 

gas plants, will assume a mostly baseload role, 

and will reduce the need for other competing 

technologies such as nuclear, coal or even 

gas-fueled combined cycles, if expansion with 

coal and nuclear technologies does not take place 

because of economic, environmental or any 

other reasons. This effect is less pronounced in 

the case of the solar technology, because of its 

characteristic daily production pattern. 

Although our analysis has been limited to a few 

alternative scenarios, we can observe a consistent pattern for the impact of intermittent 

renewable generation: We see that an increase 

of wind or solar output systematically results 

in a proportionally significant reduction of 

natural gas fueled production, while, at the 

same time, the total installed capacity of flexible 

generation (typically also natural gas fueled 

plants) is maintained or increased.

Precise numerical estimations and any second 

order impacts are heavily dependent on the 

specific energy policy instruments and the 

assumptions on the future costs of fuels and 

technologies. 

Our analysis shows that a gradual and sustained 

“long term” substantial penetration of wind, when 

associated with flexible natural gas plants, will 

assume a mostly baseload role, and will reduce the need 

for other competing technologies such as nuclear, coal 

or even gas-fueled combined cycles. This effect is less 

pronounced in the case of solar.
94 MIT STUDY ON THE FUTURE OF NATURAL GAS

The detailed operational analysis of plausible 

future scenarios with large presence of wind 

and solar generation reveals the increased need 

for natural gas capacity (notable for its cycling 

capability and lower capital cost) to provide 

reserve capacity margins. This does not however necessarily translate into a sizeable utilization of these gas plants. 

Additional Implications

In deregulated wholesale markets with substantial penetration of renewables, the volatility of 

marginal prices can be expected to increase. 

Also, mid-range technologies, of which NGCC 

is the most likely candidate, will see their 

output reduced. The uncertainty regarding the 

adequate technology mix, and the economics of 

such a mix under the anticipated future prices 

and operating conditions, raises concern about 

attracting sufficient investment in gas-fueled 

plants under a competitive market regime. 

This issue is presently being addressed by 

several European countries with significant 

penetration of wind generation, where the 

patterns of production of NGCC and single 

cycle gas turbines and also of some baseload 

technologies, have already had major impacts. 

Similar situations are developing in some parts 

of the U.S. Presently there is no consensus on 

a suitable regulatory response to this situation, 

which could include enhancements of any 

capacity mechanisms such as those already 

in place in most U.S. wholesale markets, new 

categories of remunerated ancillary services 

or other instruments. 

RE COMMENDATION

In the event of a significant penetration of 

intermittent renewable production in the 

generation technology mix, policy and 

regulatory measures should be developed 

to facilitate adequate levels of investment 

in natural gas generation capacity to ensure 

system reliability and efficiency. 

Although limited in scope, our analysis shows 

the diversity and complexity of the impacts that 

a significant penetration of intermittent 

generation (mostly wind and solar, in practice) 

have on the technology mix and the operation 

of any considered power system. The possible 

future emergence of electricity storage options, 

as well as enhanced demand responsiveness, 

will also affect the need for flexible generation 

capacity, which is presently fueled by natural 

gas. The level and volatility of future energy 

prices will determine the volume and nature of 

investment in future generation under market 

conditions. Other regulatory frameworks 

should also be considered. 

These complicated implications and trade-offs 

cannot be spelled out without the help of 

suitable computer models. The accuracy of 

the estimates of future fuel utilization and the 

adequate technology mix critically depends 

on the performance of these models. Unfortunately, the state-of-the-art computer models 

that simulate and optimize the capacity expansion and the operation of power systems and 

electricity markets — such as ReEDS or Memphis — are still in a development phase and fall 

short of the requirements to incorporate 

intermittent generation, storage and demand 

response realistically, under a variety of energy 

policies and regulatory environments. 
Chapter 4: Electricity 95

RE COMMENDATION

A comprehensive appraisal of the economic, environmental and reliability 

implications of different levels of significant penetration of renewable 

generation should be performed for power systems with different generation 

technology portfolios and under different energy policy scenarios. 

The information obtained from this appraisal should inform a central piece 

in the design of energy policies that contemplate mandating large amounts 

of solar or wind generation. 

Additional efforts should be made to expand or develop the sophisticated 

computation electric system models that are needed for this task. 
96 MIT STUDY ON THE FUTURE OF NATURAL GAS

NOTES

1Nameplate capacity is the nominal, maximum 

instantaneous output of a power plant.

2Absent other considerations, generation units are 

normally dispatched in economic merit order, i.e., 

those with lower variable operating costs first.

3

Channele Wirmin, EIA, private communication. 

4Steinhurst, W., The Electric Industry at a Glance, 

Nuclear Regulatory Research Institute, 2009.

5

Electric Power Research Institute, A Primer on 

Electric Power Flow for Economists and Utility 

Planners, 1995; Pérez-Arriaga, I., Rudnick H., 

Rivier, M., Chapter One: Electric Energy Systems, 

An Overview.

6Hydroelectric generation, shown in Figure 4.2 

as constant over demand periods, will in fact tend 

to be concentrated in particular seasons and peak 

periods of the day. The MARKAL model does not 

represent this detail, though its inclusion would 

have only a small effect on the figure as it aggregates all the national hydroelectric facilities.

7The same change in unit dispatch could be 

approached using various forms of direct 

regulation, options not studied here.

8The ReEDS model captures key characteristics of 

the electricity network’s transmission constraints 

and reliability requirements by splitting the country 

into 134 geographic partitions. Each partition 

balances demand and supply of electricity by 

independently generating, importing, and 

exporting electricity. Collectively, subsets of these 

balancing areas constitute the independent system 

operators (ISOs) and regional transmission 

organizations (RTOs). 

9As noted in the introduction of this section, the 

expected maximum capacity factor for an NGCC 

plant is 85%. The EIA projects that this could 

increase to 87% by 2016 (http://www.eia.doe.gov/

oiaf/aeo/pdf/2016levelized_costs_aeo2010.pdf). 

The average fleet capacity factor of 87% from 

ReEDS for the 20% CO2 reduction scenario 

approaches the upper generation threshold of the 

country’s current NGCC fleet.

10Although the trend for NGCC displacement of 

coal generation remains the same for this updated 

scenario, these results are numerically different 

than the results presented in the interim report. 

The interim report showed opportunities for coal 

displacement in all time periods. The difference 

stems from assumptions about how much NGCC 

capacity exists in ERCOT. The NGCC capacity 

numbers used for this 2012 simulation are more 

conservative, and projected forward from 2006 

EIA capacity and generation data (2006 is the start 

year for ReEDS).

11Presentation, “Reducing Pollution from Power 

Plants,” Gina McCarthy, Assistant Administrator, 

U.S. EPA Office of Air and Radiation, October 29, 

2010. 

12For a variety of reasons, deployment of required 

controls has been delayed, largely by court findings 

of legal flaws in various rulemakings. The New 

Transport Rule, which will replace Clean Air 

Interstate Rule (CAIR) in place today, is expected 

to be finalized in mid-2011 and will be implemented over time, with most coverage finalized 

by 2014. The Transport Rule will cover SO2 and 

NOx. EPA released a proposed rule for mercury 

emissions from coal and oil-fired power plants in 

March, 2011 and plans to finalize the rule by the 

end of the year. A final rule on CO2 for power 

plants is expected sometime in 2012. 

13This break-even price assumes a NGCC 

variable O&M cost of $3.20/MWh, fuel price 

of $5.38/mmBtu, heat rate of 6.04 mmBtu/MWh, 

and CO2 emissions of 0.053 tons/mmBtu. For coal, 

the calculation assumes a variable O&M cost of 

$4.30/MWh, fuel price of $2.09/mmBtu, heat 

rate of 10 mmBtu/MWh, and CO2 emissions of 

0.098 tons/mmBtu. The cost of NGCC and coal 

generation break-even when the sum of the variable 

O&M cost and price per ton CO2 multiplied by the 

amount of CO2 emitted are equal to each other, for 

the respective fuels. Start-up and shut-down costs, 

ramp rates, associated changes in emissions, and 

other costs that have not been fully modeled are 

not included in this calculation.

14MIT Energy Initiative’s report on Retrofitting 

of Coal-Fired Power Plants for CO2 Emissions 

Reductions, Cambridge, MA, 2009 (http://web.mit.

edu/mitei/docs/reports/meeting-report.pdf).

15EIA AEO 2010.
Chapter 4: Electricity 97

16See Bentek study, How Less Became More: Wind, 

Power and Unintended Consequences In the 

Colorado Energy Market, April 2010.

17See “Impact of intermittent renewable electricity 

generation on the technology mix and fuel 

consumption in the U.S. power system.” Yuan Yao, 

Ignacio J. Pérez-Arriaga. CEEPR (Center for 

Energy and Environmental Policy Research), MIT, 

May 2011. 

18The ReEDS simulations of this level of mitigation 

show a greater penetration of renewable generation than do the results of the EPPA model shown 

in Chapter 3, but the difference is not an important influence on the insights to be drawn from 

these calculations.

19Details of these cases are provided by Yao and 

Pérez-Arriaga, op cit. 

Chapter 5: Demand 99

Chapter 5: Demand 

INTRODUCTION

Natural gas is attractive for a variety of end-use 

applications because it is:

s CLEAN BURNING

s SUBSTANTIALLY LESS CARBON INTENSIVE THAN COAL

AND OIL

s EFlCIENT WITH AN AVERAGE ENERGY EFlCIENCY OF

 DELIVERED TO THE BURNER TIP

s mEXIBLE WITH USE AT SMALL AND LARGE SCALES AND

RESPONSIVE TO DEMAND CHANGES AND

s VERSATILE

!S SHOWN IN &IGURE  DOMESTIC NATURAL GAS

SUPPLY IS CURRENTLY DIVIDED ALMOST EVENLY AMONG

THE RESIDENTIALCOMMERCIAL INDUSTRIAL AND

ELECTRIC POWER GENERATION MARKETS AND HAS A

SUBSTANTIAL MARKET SHARE IN EACH 4HIS PATTERN

HAS CHANGED OVER TIME PRINCIPALLY BECAUSE OF

THE SUBSTANTIAL INCREASE IN NATURAL GAS USE FOR

ELECTRICITY GENERATION OVER THE LAST  YEARS AS SEEN

IN &IGURE  A TREND THAT IS LIKELY TO CONTINUE

/N THE OTHER HAND NATURAL GAS PLAYS A MINIMAL

ROLE IN THE 53 VEHICULAR TRANSPORTATION SECTOR

COMPRISING ONLY AROUND  OF THE ENERGY USE

.ATURAL GAS USE FOR TRANSPORTATION IS MAINLY TO

POWER GAS TRANSPORT IN PIPELINES

Figure 5.1 Natural Gas End-Use Markets (2009)

Coal

Petroleum

Electricity

Natural Gas 

Renewable

Residential/Commercial

Industrial

Transportation

Total

Natural Gas

Supply

(22.8 TCF)

Electric Power

Generation

2.9%

32.4%

30.2%

34.5%

93.9%

8.9% 46.5%

40.8%

2.6%

3.4%

0.1%

0.3%

34.9% 35.7%

6.3% 9.3%

13.8%

3.5%

3OURCE %)!
100 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 5.2 Historical Trends in End-Use Consumption

3OURCE %)! Annual Energy Review 2009

0

2

4

6

8

10

12

Residential/Commercial

Industrial

Transportation

Electric Power

Consumption (Tcf)

19701975198019851990199520002005

CHAPTER OVERVIEW

7E HAVE ANALYZED A SET OF KEY ISSUES IN EACH

OF THESE SECTORS WITH A VIEW TOWARD POSSIBLE

SIGNIlCANT INCREASES OR DECREASES IN NATURAL

GAS USE OPPORTUNITIES FOR EMISSIONS REDUCTIONS

AND REDUCTION OF OIL DEPENDENCE IN THE

TRANSPORTATION SECTOR

s )N THE INDUSTRIAL SECTOR OVER  OF THE TOTAL

ANNUAL SUPPLY OF  4RILLION CUBIC FEET 4CF	 OF

NATURAL GAS lRES BOILERS AND PROVIDES PROCESS

HEAT SO WE FOCUS OUR ANALYSIS ON EFlCIENCY

IN THESE USES AND ON THE EMISSIONS REDUCTION

OPPORTUNITIES FROM COAL DISPLACEMENT

.ATURAL GAS AND .ATURAL 'AS ,IQUIDS .',S	

ALSO PLAY AN IMPORTANT ROLE AS CHEMICAL

FEEDSTOCK AN ISSUE OF IMPORTANCE TO DOMESTIC

RETENTION OF MANUFACTURING ACTIVITY

s )N THE RESIDENTIALCOMMERCIAL SECTOR ELECTRICITY AND NATURAL GAS COMPETE AS THE TWO MAJOR

SOURCES OF ENERGY SUPPLY )N THE 53 ABOUT

 OF ELECTRICITY AN ENERGY CARRIER	 AND

 OF GAS A THERMAL ENERGY SOURCE	

IS USED IN BUILDINGS %FlCIENCY IN DELIVERING

energy services to buildings and institutions 

WILL BE AN IMPORTANT DIFFERENTIATOR AND OUR

ANALYSIS FOCUSES ON TWO ISSUES END
TO
END

EFlCIENCY OF ELECTRICITY AND GAS AND THE

OPPORTUNITIES FOR NATURAL GAS COMBINED


HEAT
AND
POWER DELIVERY SYSTEMS

s &OR THE TRANSPORTATION SECTOR OUR ANALYSIS

FOCUSES ON THE POTENTIAL FOR NATURAL GAS TO

DISPLACE OIL AND REDUCE GREENHOUSE GAS '('	

EMISSIONS BOTH THROUGH DIRECT USE AND

INDIRECTLY THROUGH CONVERSION TO LIQUID FUELS
Chapter 5: Demand 101

NATURAL GAS IN THE INDUSTRIAL 

SECTOR

)NDUSTRIAL DEMAND FOR NATURAL GAS WAS  4CF

IN  REPRESENTING  OF TOTAL 53 NATURAL

GAS USE /F THIS TOTAL  4CF WAS USED IN OIL AND

GAS lELD PRODUCTION AND PROCESSING OPERATIONS

LEAVING A NET TOTAL OF  4CF DELIVERED TO lNAL

CUSTOMERS FOR )NDUSTRIAL END
USE APPLICATIONS

.ATURAL GAS ACCOUNTS FOR  OF TOTAL ENERGY

USED IN INDUSTRY PETROLEUM PRODUCTS ARE THE

PRIMARY SOURCE OF ENERGY AND COAL USE IS ALSO

SIGNIlCANT

-ANUFACTURING COMPRISES ABOUT  OF TOTAL

53 INDUSTRIAL NATURAL GAS USE THE REMAINING

 COMPRISES NON
MANUFACTURING USES SUCH AS

MINING 3IX INDUSTRIES ACCOUNT FOR  OF TOTAL

MANUFACTURING DEMAND AS SHOWN IN &IGURE 2

)N THIS SECTION WE lRST PRESENT AN OVERVIEW

OF TRENDS IN NATURAL GAS USE AND EFlCIENCY IN

MANUFACTURING AND PROJECTIONS OF FUTURE

DEMAND DISCUSSING THE INTERACTION AMONG

CHANGES IN OUTPUT CHANGES IN FUEL MIX AND

CHANGES IN END
USE EFlCIENCY 7E IDENTIFY

INDUSTRIAL BOILERS AND PROCESS HEATING AS THE

TWO PRINCIPAL USES OF NATURAL GAS AS A FUEL AND

DISCUSS OPPORTUNITIES FOR CHANGES IN DEMAND

ASSOCIATED WITH IMPROVED EFlCIENCY AS WELL AS

FUEL SWITCHING 7E ALSO DISCUSS POTENTIAL FOR

EFlCIENCY GAINS IN PROCESS HEATING AS WELL AS

RESEARCH DEVELOPMENT AND DEPLOYMENT

2$$	 OPPORTUNITIES

Figure 5.3 Natural Gas Use by U.S. Manufacturing Industry Sector

“All Other” includes:

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Food

11%

Petroleum

& Coal

Products

14%

Chemicals

29%

Nonmetallic

Mineral

Products

8%

Primary

Metals

11%

All Other

19% Paper

8%

3OURCE %)! -%#3
102 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 5.4 Trends in U.S. Industrial Natural Gas Consumption and Intensity 

3OURCE %)! "%!

Natural Gas Consumption and Efficiency 

Trends

3INCE  INDUSTRIAL NATURAL GAS USE DECLINED

BY  OR ABOUT  4CFYEAR THE ONLY END
USE

SECTOR TO DO SO

&IGURE  SHOWS THAT THIS DECLINE HAS BEEN

STEADY NOTWITHSTANDING VOLATILITY IN NATURAL GAS

PRICES 4HE INTENSITY OF NATURAL GAS USE IE THE

quantity of natural gas used per dollar value of 

SHIPMENTS	 DECLINED BY MORE THAN TOTAL USE

INDICATING THAT THE REDUCTION WAS DUE TO A

COMBINATION OF INCREASED EFlCIENCY OF USE AND

A SHIFT TO LESS ENERGY
INTENSIVE ACTIVITIES 7E

ESTIMATE THAT NATURAL GAS CONSUMPTION HAS

DECLINED AT AN AVERAGE ANNUAL RATE OF  WHILE

NATURAL GAS INTENSITY HAS DECLINED AT AN AVERAGE

ANNUAL RATE OF  OVER THIS PERIOD

&OR ENERGY
INTENSIVE INDUSTRIES WE ESTIMATE

THAT THE COST OF NATURAL GAS AS A PERCENTAGE OF

VALUE OF SHIPMENTS CAN RANGE FROM  FOR THE

FOOD PRODUCTS INDUSTRY	 TO AS MUCH AS  IN

THE CASE OF NITROGEN
BASED FERTILIZERS )N OTHER

INDUSTRY SECTORS THAT ARE LESS ENERGY INTENSIVE

WE ESTIMATE THE COST OF NATURAL GAS IN THE RANGE

OF ONLY  TO  OF THE VALUE OF SHIPMENTS

.OTWITHSTANDING THE LOW RATIOS OF NATURAL GAS

COSTS TO VALUE OF SHIPMENTS IN MANY MANUFACTURING INDUSTRIES VOLATILITY IN THE PRICE OF

NATURAL GAS COULD HAVE A SIGNIlCANT IMPACT ON

THE COMPETITIVE POSITION OF THOSE INDUSTRIES

THAT OPERATE IN GLOBAL MARKETS

3EVERAL FACTORS CONTRIBUTE TO THE PRICE ELASTICITY

OF GAS IN THIS SECTOR (IGHER NATURAL GAS PRICES

PARTICULARLY IN RELATION TO PRICES ABROAD CAN

LEAD TO REDUCED MANUFACTURING OUTPUT !LSO

rising prices provide incentives for increased 

ENERGY EFlCIENCY MEASURES AND FUEL SWITCHING

&ALLING PRICES HAVE AN OPPOSITE EFFECT ON

INDUSTRY OUTPUT AND FUEL SWITCHING

Industrial Consumption (Tcf) and

Industrial Price ($/MMBtu)

Natural Gas Intensity (MMcf/$)

0

1

2

3

4

5

6

7

8

9

10

0.0

0.5

1.0

1.5

2.0

2.5

NG Consumption (Tcf)

NG Industrial Price ($/MM)

NG Intensity (MMcf/$)

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Chapter 5: Demand 103

#OST SAVINGS RESULTING FROM ENERGY EFlCIENCY

GAINS ARE INCREASINGLY VIEWED AS A BUSINESS

OPPORTUNITY SINCE THE SAVINGS mOW DIRECTLY TO

THE BOTTOM LINE .EW ENERGY
EFlCIENT CAPITAL

INVESTMENTS CAN OFFER ATTRACTIVE RETURNS ON

INVESTMENT COMPETING WITH OTHER CORPORATE

CAPITAL INVESTMENT OPPORTUNITIES ! RECENT

STUDY CONDUCTED FOR THE 0EW #ENTER ON 'LOBAL

#LIMATE #HANGE DOCUMENTED THE NEXUS

BETWEEN BUSINESS PROlTABILITY IMPROVED ENERGY

EFlCIENCY AND #/2 EMISSIONS REDUCTIONS )T

SHOWED THAT COMPANIES DO BEST IN REDUCING

ENERGY USE WHEN THEY SET AGGRESSIVE ENERGY

REDUCTION TARGETS CLOSELY MONITOR PROGRESS

HAVE ACTIVE TOP MANAGEMENT INVOLVEMENT AND

TAKE A COMPREHENSIVE APPROACH TO ANALYZING

ENERGY EFlCIENCY OPPORTUNITIES FROM MANUFACTURING TO MARKETING3

4HESE GENERAL PATTERNS ARE REmECTED IN THE 53

%NERGY )NFORMATION !DMINISTRATION %)!	

!NNUAL %NERGY /UTLOOK !%/ 	 4HE !%/

 PROJECTS NATURAL GAS DEMAND IN THE )NDUSTRIAL SECTOR TO REBOUND TO PRE
 LEVELS IN

EXCESS OF  4CFYEAR BY  4HE NET INCREASE IS

ATTRIBUTED TO CONTINUED RECOVERY FROM THE

RECESSION INCREASED COMBINED HEAT AND POWER

#(0	 AND DEMAND RESPONSE TO LOWER NATURAL

GAS PRICES PARTLY OFFSET BY CONTINUED GAINS IN

ENERGY EFlCIENCY 4HE !%/  PROJECTS THE

AVERAGE ANNUAL GROWTH IN NATURAL GAS DEMAND IN

INDUSTRY AT  THROUGH  ABOUT HALF OF THE

PROJECTED GROWTH RATE OF  IN THE VALUE OF

INDUSTRY SHIPMENTSREmECTING A CONTINUING

DECLINE IN NATURAL GAS INTENSITY

4HE ECONOMIC MODELING ANALYSIS THAT UNDERLIES

THE RESULTS PRESENTED IN #HAPTER  SHOWS A

SIMILAR PATTERN OF )NDUSTRIAL GAS DEMAND OVER

COMING DECADES 5NDER THE ASSUMPTION OF

NO ADDITIONAL POLICY ON '('S 53 )NDUSTRIAL

GAS DEMAND GROWS OVER THE PERIOD TO 

AND BEYOND /N THE OTHER HAND UNDER THE

PRICE
BASED POLICY EXPLORED IN #HAPTER  WHICH

REDUCES NATIONAL '(' EMISSIONS TO  OF

 LEVELS BY  TOTAL INDUSTRY GAS DEMAND

DECLINES OVER THE NEXT TWO DECADES AS GAS USE

SHIFTS TOWARDS ELECTRIC GENERATION AND AWAY

FROM OTHER END USES )N THE MOST ENERGY


INTENSIVE 53 MANUFACTURING INDUSTRIES GAS

USE REMAINS ROUGHLY CONSTANT AT THE  LEVEL

SUBSTANTIALLY BELOW THE NO
POLICY PROJECTION

(OWEVER BECAUSE OF MODELED mEXIBILITY IN THIS

INDUSTRY SEGMENT THE VALUE OF DOMESTIC OUTPUT

IS ONLY SLIGHTLY BELOW THAT IN THE NO
POLICY CASE

Principal Uses of Natural Gas as a Fuel 

and as a Chemical Feedstock

.ATURAL GAS IS USED IN 53 MANUFACTURING BOTH

AS A FUEL AND AS A CHEMICAL FEEDSTOCK 4HE TWO

PRIMARY FUEL USES ARE IN BOILERS AND PROCESS

HEATING AND THE TWO PRIMARY FEEDSTOCK USES OF

NATURAL GAS ARE IN AMMONIA .(3	 MANUFACTURING AND HYDROGEN (2	 PRODUCTION &IGURE 

SHOWS THAT PROCESS HEATING ACCOUNTS FOR  OF

MANUFACTURING NATURAL GAS CONSUMPTION WITH

BOILERS CONVENTIONAL AND COMBINED HEAT AND

POWER	 ACCOUNTING FOR AN ADDITIONAL  4HESE

TWO APPLICATIONS TOTAL  4CFYEAR OR OVER

THREE
FOURTHS OF TOTAL NATURAL GAS USED IN MANUFACTURING AND OVER  OF TOTAL INDUSTRIAL USE	

AND THUS PROVIDE THE FOCUS FOR OUR ANALYSIS

Figure 5.5 U.S. Manufacturing Natural Gas Use by End-Use 

Application 

CHP/Cogen

14%

Conventional

Boiler Use

22%

Process Heating

42%

HVAC

6%

Feedstock

7%

Other/Not Reported

7%

Machine

Drive

2%

3OURCE %)! -%#3
104 MIT STUDY ON THE FUTURE OF NATURAL GAS

Natural Gas Use in Industrial Boilers

)NDUSTRIAL BOILERS BOTH CONVENTIONAL AND #(0

CONSUMED  4CF OF NATURAL GAS IN 

ACCOUNTING FOR  OF TOTAL NATURAL GAS IN

MANUFACTURING7 7E EXAMINE TWO POTENTIAL

DRIVERS AFFECTING DEMAND FOR NATURAL GAS IN

BOILERS MODERNIZATION OF THE CURRENT NATURAL

GAS BOILER mEET WITH MORE EFlCIENT UNITS AND

REPLACEMENT OF COAL BOILERS WITH NEW NATURAL

GAS BOILERS /UR ANALYSIS IS SUMMARIZED IN THE

DISCUSSION THAT FOLLOWS A MORE DETAILED DISCUSSION IS PROVIDED IN !PPENDIX !

)NDUSTRIAL BOILERS ARE USED TO PROVIDE STEAM AND

HOT WATER IN ALL MANUFACTURING INDUSTRIES WITH

THE FOUR LARGEST APPLICATIONS IN CHEMICALS 	

FOOD PROCESSING 	 PAPER 	 AND

PETROLEUM AND COAL PRODUCTS 	 4HERE IS

STRONG COMPETITION AMONG BOILER FUELS IN THE

ENERGY INTENSIVE INDUSTRIES THAT EMPLOY LARGER

BOILERS AND HAVE READY ACCESS TO ALTERNATIVE FUEL

SUPPLIES .ATURAL GAS IS THE PREDOMINANT BOILER

FUEL IN OTHER MANUFACTURING INDUSTRIES WHICH

TYPICALLY EMPLOY SMALLER BOILERS AND DO NOT HAVE

THE SAME OPPORTUNITIES FOR USE OF BY
PRODUCTS

AND WASTE FUELS

/UR ANALYSIS IS BASED ON A  -ILLION "RITISH

THERMAL UNITS --"TU	HOUR BOILER

 WHICH IS

relatively large for natural gas boilers but 

COMPARABLE TO MANY COAL BOILERS !S A SENSITIVITY ANALYSIS WE ALSO ANALYZED A SMALLER SIZE

BOILER  --"TUHOUR	

Modernization of the Natural Gas Industrial 

Boiler Fleet

-OST EXISTING NATURAL GAS BOILERS HAVE BEEN IN

SERVICE FOR DECADES AND EXPERIENCE LOW TURNOVER

RATES /N AVERAGE THE EXISTING mEET OF PRE


BOILERS HAS AN AVERAGE ENERGY EFlCIENCY IN THE

RANGE OF  TO 9 4HESE BOILERS REJECT

WASTE HEAT IN THE EXHAUST GASES THIS HEAT IS

COMPRISED OF THE LATENT HEAT THAT CAN BE RECOVERED FROM CONDENSING THE WATER VAPOR INTO

A LIQUID AS WELL AS THE SENSIBLE HEAT CONTAINED

IN THE EXHAUST

)N  THE $EPARTMENT OF %NERGY $/%	 SET

MINIMUM ENERGY EFlCIENCY STANDARDS FOR NEW

NATURAL GAS BOILERS IN THE RANGE OF  TO 

DEPENDING UPON BOILER SIZE AND BOILER TECHNOLOGY .EW BOILERS MEET THIS STANDARD THROUGH

THE USE OF ADDITIONAL HEAT RECOVERY SYSTEMS

IE CONDENSING TECHNOLOGY	 TO CAPTURE THE

LATENT HEAT AND A PORTION OF THE SENSIBLE HEAT IN

THE EXHAUST GASES)N ADDITION USE OF ECONOMIZERS

ALLOWS FOR WASTE HEAT TO BE RECOVERED BY PRE


HEATING THE BOILER FEED WATER 4HESE IMPROVEMENTS CAN BOOST OVERALL ENERGY EFlCIENCY TO THE

 TO  LEVEL &URTHER TECHNOLOGY ADVANCES

ENTERING THE MARKETPLACE INCLUDE MULTI
STAGE

COMBUSTION SYSTEMS  WHICH ALSO REDUCE ./X

A MIXTURE OF NITRIC OXIDE AND NITROGEN DIOXIDE

EMISSIONS	  AND ADVANCED CONDENSERS AND

AIR PRE
HEATING SYSTEMS 4HESE hSUPERv EFlCIENT

BOILERS CAN ACHIEVE EFlCIENCIES IN THE RANGE OF

 TO 

7E COMPARED THE NET PRESENT VALUE .06	

OF THE PRE
TAX COST OF REPLACING AN EXISTING

 --"TUHOUR NATURAL GAS BOILER WITH EITHER

A HIGH
EFlCIENCY OR SUPER
HIGH
EFlCIENCY UNIT

7E ESTIMATE THAT REPLACEMENT OF CURRENT NATURAL

GAS BOILERS WITH HIGH
EFlCIENCY MODELS WOULD

AT A  DISCOUNT RATE YIELD A REDUCTION OF 

IN ANNUALIZED COSTS ON A PRE
TAX BASIS 2EPLACEMENT WITH SUPER
HIGH
EFlCIENCY BOILERS WOULD

YIELD ANNUALIZED SAVINGS OF  ! SENSITIVITY

ANALYSIS ON SMALLER SIZE NATURAL GAS BOILERS

IE  --"TUHOUR	 YIELDS SIMILAR RESULTS

4HE PAYBACK PERIODS FOR THESE BOILER REPLACEMENTS RANGE FROM  TO  YEARS BASED ON

 ACTUAL INDUSTRIAL NATURAL GAS PRICES AND

ASSUMING NO INCREASE IN NATURAL GAS PRICES OVER

THIS PERIOD (IGHER NATURAL GAS PRICES WOULD

IMPROVE THE RESULTS LOWER NATURAL GAS PRICES

WOULD REDUCE THE PROJECTED ANNUALIZED SAVINGS

AND EXTEND THE PAYBACK PERIOD
Chapter 5: Demand 105

4HE COST ESTIMATES ARE FOR EQUIPMENT ONLY

INSTALLATION COSTS WILL REDUCE THESE RETURNS

SOMEWHAT !LSO IN PARTICULAR INSTANCES THE

ATTRACTIVENESS OF BOILER MODERNIZATION WILL

DEPEND ON OTHER FACTORS SUCH AS THE REMAINING

BOOK VALUE OF EXISTING BOILERS THAT A lRM MIGHT

WRITE OFF THE AVAILABILITY OF INVESTMENT CAPITAL

THE RETURN ON INVESTMENT IN BOILER MODERNIZATION RELATIVE TO OTHER OPPORTUNITIES AND THE

AVAILABILITY OF TAX INCENTIVES SUCH AS ACCELERATED

DEPRECIATION OR INVESTMENT TAX CREDITS #ONSIDERING ALL THESE FACTORS HOWEVER IT APPEARS

THAT REPLACEMENT WILL BE COST EFFECTIVE IN

MANY INSTALLATIONS

4WO SCENARIOS CAN PROVIDE AN INDICATION OF THE

IMPACT ON NATURAL GAS CONSUMPTION 	 A

REPLACEMENT OF  OF CURRENT NATURAL GAS

INDUSTRIAL BOILER CAPACITY WITH HIGH
EFlCIENCY

NATURAL GAS BOILERS WOULD REDUCE DEMAND FOR

NATURAL GAS BY  "ILLION CUBIC FEET "CF	

ANNUALLY WHILE 	 A REPLACEMENT OF  OF

CURRENT NATURAL GAS BOILER CAPACITY WITH SUPER


HIGH
EFlCIENCY NATURAL GAS BOILERS WOULD REDUCE

DEMAND BY  "CF ANNUALLY 4HE REDUCTION IN

CARBON DIOXIDE #/2	 EMISSIONS RANGES FROM

ABOUT  TO OVER  TONS PER YEAR PER

BOILER

F I N D I N G 

Replacement of existing industrial natural 

gas boilers with higher efficiency models 

could cost-effectively reduce natural gas 

demand and reduce GHG emissions.

RECOMMENDATION

The DOE should review the current energy 

efficiency standards for commercial and 

industrial natural gas boilers and assess 

the feasibility of setting a more stringent 

standard.

Replacement of Existing Coal Industrial Boilers 

with Efficient Natural Gas Boilers 

! #/2 EMISSIONS REDUCTION REQUIREMENT COULD

LEAD TO A SIGNIlCANT LEVEL OF REPLACEMENT OF

EXISTING COAL BOILERS BY NATURAL GAS !BSENT A

CARBON CONSTRAINT A POTENTIAL DRIVER FOR FUEL

SWITCHING OF COAL BOILERS TO NATURAL GAS IS THE

ESTABLISHMENT OF .ATIONAL %MISSIONS 3TANDARDS

FOR (AZARDOUS !IR 0OLLUTANTS .%3(!03	

BASED ON THE APPLICATION OF MAXIMUM ACHIEVABLE CONTROL TECHNOLOGY -!#4	

/UR ANALYSIS IS BASED ON THE &EBRUARY  

%0! -!#4 EMISSIONS STANDARDS FOR MERCURY

(G	 METALS DIOXIN ACID GASES AND OTHER

HAZARDOUS AIR POLLUTANTS EMITTED FROM INDUSTRIAL

BOILERS AND PROCESS HEATERS /N -AY  

%0! ADMINISTRATOR *ACKSON ISSUED A STAY OF THE

NEW STANDARDS TO ALLOW FOR ADDITIONAL REVIEW

AND COMMENT

.ATURAL GAS BOILERS BECAUSE OF THE CLEAN


BURNING NATURE OF THE FUEL ARE NOT SUBJECT TO

NEW EMISSIONS REDUCTION REQUIREMENTS /N THE

OTHER HAND THREE SUBCATEGORIES OF COAL BOILERS

UTILIZING DIFFERENT TECHNOLOGIES  STOKER

mUIDIZED BED AND PULVERIZED COAL COMBUSTION 

ARE SUBJECT TO NEW STANDARDS FOR THE CONTROL OF

PARTICULATE MATTER ACID GASES TOXIC CHEMICALS

AND (G !CHIEVING THESE EMISSION STANDARDS

WILL REQUIRE THE INSTALLATION OF WET SCRUBBERS

AND FABRIC lLTERS )NSTALLATION OF ACTIVATED

CARBON INJECTION FOR CONTROL OF (G EMISSIONS

ALSO MAY BE REQUIRED IN SOME INSTANCES

4HE %0! ECONOMIC ANALYSIS SUPPORTING THE

NEW -!#4 STANDARDS ASSUMED THAT EXISTING

COAL BOILERS WOULD RETROlT POST
COMBUSTION

CONTROLS 4HE %0! CONSIDERED AND REJECTED FUEL

SWITCHING AS A CONTROL OPTION PRIMARILY BECAUSE

OF ASSUMED HIGH NATURAL GAS PRICES  PER

--"TU FOR INDUSTRIAL DELIVERY IN 	 AND

ASSUMED  LOSS OF EFlCIENCY FROM REPLACEMENT OF BURNERS IN EXISTING BOILERS
106 MIT STUDY ON THE FUTURE OF NATURAL GAS

7E PERFORMED AN ANALYSIS USING CURRENT

NATURAL GAS PRICE ASSUMPTIONS COMPARING FOUR

POSSIBLE COMPLIANCE OPTIONS FOR COAL BOILERS

	 RETROlT OF POST
COMBUSTION CONTROLS USING

%0! COST ASSUMPTIONS	 	 RETROlT OF NATURAL

GAS BURNERS WITHIN THE EXISTING COAL BOILER WITH

%0! EFlCIENCY ASSUMPTIONS	 	 REPLACEMENT

OF THE EXISTING COAL
lRED BOILER WITH A HIGH


EFlCIENCY NATURAL GAS BOILER AND 	 REPLACEMENT OF THE EXISTING COAL BOILER WITH ONE OF THE

NEW SUPER
HIGH
EFlCIENCY NATURAL GAS BOILER

TECHNOLOGIES

/UR ANALYSIS INDICATES THAT REPLACEMENT OF COAL

BOILERS WITH EFlCIENT OR SUPER
EFlCIENT NATURAL

GAS BOILERS IS COST COMPETITIVE WITH RETROlTTING

POST
COMBUSTION CONTROLS 4HE .06 COST AT A

 DISCOUNT RATE OF HIGH
EFlCIENCY NATURAL

GAS BOILERS IS SLIGHTLY HIGHER THAN THE .06 COST

OF POST
COMBUSTION CONTROLS WHILE THE .06 OF

SUPER
EFlCIENT BOILERS IS SLIGHTLY LOWER THAN THE

COST OF RETROlTTING 4HE HIGHER ENERGY EFlCIENCY

PERFORMANCE LEVELS OF NEW NATURAL GAS BOILERS

AT CURRENT GAS PRICES MAKE BOILER REPLACEMENT

AN ATTRACTIVE OPTION .EITHER FACTOR WAS CONSIDERED IN THE %0! ANALYSIS

4HE RESULTS OF THIS ANALYSIS ARE SENSITIVE TO TWO

ASSUMPTIONS 	 THE ESTIMATES OF CAPITAL

EQUIPMENT COST FOR RETROlTTING POST
COMBUSTION

CONTROLS FOR COAL AND 	 THE RELATIVE PRICES OF

COAL AND NATURAL GAS /UR ANALYSIS USES THE %0!

CAPITAL COST ASSUMPTIONS FOR INSTALLATION OF

POST
COMBUSTION CONTROLS IE WET SCRUBBERS

AND FABRIC lLTERS AT EXISTING COAL BOILERS	 &OR

COAL BOILERS THAT MAY REQUIRE ADDITIONAL CONTROLS TO ACHIEVE -!#4 LIMITS FOR (G EMISSIONS

COSTS WOULD INCREASE SUBSTANTIALLY MAKING THE

OPTIONS FOR REPLACEMENT WITH NATURAL GAS BOILERS

MUCH MORE COST EFFECTIVE 4HE COMPARATIVE

RESULTS ALSO ARE SENSITIVE TO THE PRICE DIFFERENTIAL

BETWEEN NATURAL GAS AND COAL "ASED ON ACTUAL

AVERAGE DELIVERED PRICES IN  THE PRICE OF

NATURAL GAS WAS ON AVERAGE HIGHER THAN COAL

BY --"TU ! LOWER PRICE DIFFERENTIAL

IE A SMALLER PRICE SPREAD BETWEEN NATURAL GAS

AND COAL	 WOULD MAKE CONVERSION TO NATURAL GAS

MORE ATTRACTIVE A LARGER PRICE DIFFERENTIAL WOULD

MAKE CONTINUED USE OF COAL MORE ATTRACTIVE

4HE POTENTIAL IMPACT OF REPLACING INDUSTRIAL

COAL BOILERS WITH NEW HIGH
EFlCIENCY NATURAL

GAS BOILERS IS SIGNIlCANT 4HE %)! -ANUFACTURING

%NERGY #ONSUMPTION 3URVEY -%#3	 DATA

SHOW THAT INDUSTRIAL COAL BOILERS AND PROCESS

HEATERS CURRENTLY USE  TRILLION "TU OF COAL

EACH YEAR #ONVERSION OF THIS CAPACITY TO NATURAL

GAS WOULD INCREASE DEMAND FOR NATURAL GAS

BY  4CFYEAR 4HE ACTUAL RATE OF MARKET

PENETRATION WOULD DEPEND UPON INDIVIDUAL

FACILITY ANALYSES

2EPLACEMENT OF EXISTING COAL BOILERS WITH NEW

EFlCIENT NATURAL GAS BOILERS IN ORDER TO MEET

-!#4 REQUIREMENTS COULD REDUCE ANNUAL #/2

EMISSIONS BY  TO  TONS PER YEAR

PER BOILER 7E ESTIMATE THAT EVEN IF THE .06

COST OF BOILER REPLACEMENT WITH NATURAL GAS IS

SLIGHTLY MORE EXPENSIVE THAN RETROlTTING

POST
COMBUSTION CONTROLS ASSIGNING THIS

INCREMENTAL COST TO THE #/2 REDUCTIONS WOULD

YIELD AN INCREMENTAL COST FOR #/2 reduction 

OF ABOUT TON

FINDING

Replacement of existing industrial coal 

boilers and process heaters with new, 

efficient natural gas boilers could be a 

cost-effective alternative for compliance 

with the EPA MACT Standards. Fuel 

switching has the potential to increase 

demand for natural gas while achieving 

substantial CO2 emissions reductions at 

a modest incremental cost. 
Chapter 5: Demand 107

Natural Gas Use in Manufacturing Process 

Heating

4HE USE OF SOME FORM OF PROCESS HEATING IS

UBIQUITOUS ACROSS VIRTUALLY ALL MANUFACTURING

SECTORS ACCOUNTING FOR  4CF OF NATURAL GAS

CONSUMPTION IN  OR  OF ALL MANUFACTURING GAS USE AND NEARLY ONE
THIRD OF TOTAL

INDUSTRIAL USE	 4HREE MANUFACTURING INDUS


TRIES  COAL PRODUCTS 	 PRIMARY METALS

	 AND CHEMICALS 	  COMPRISE OVER

HALF OF PROCESS HEATING DEMAND FOR NATURAL GAS

0ROCESS HEATING INVOLVES THE TRANSFER OF HEAT

ENERGY TO MATERIALS IN A MANUFACTURING PROCESS

THROUGH CONDUCTION CONVECTION OR RADIATION

INVOLVING DIRECT OR INDIRECT CONTACT WITH STEAM

OR ANOTHER HOT mUID 0ROCESS HEATING IS AN

INTEGRAL STEP IN THE MANUFACTURING OF A VARIETY

OF PRODUCTS INCLUDING METALS RUBBER PLASTIC

CONCRETE GLASS AND CERAMICS 0ROCESS HEATING

CONDITIONS CAN VARY WIDELY BY TEMPERATURE

EG SEVERAL HUNDRED TO SEVERAL THOUSAND

DEGREES &AHRENHEIT	 BY THROUGHPUT RATES

EG SHORT OR LONG CONTACT PERIODS	 AND BY TYPE

OF PROCESS EG BATCH OR CONTINUOUS	 .ATURAL

GAS AND ELECTRICITY ARE THE TWO PRIMARY SOURCES

OF ENERGY FOR PROCESS HEAT

4HE $/%
SPONSORED COLLABORATIONS INVOLVING

.ATIONAL ,ABORATORIES AND INDUSTRY HAVE

IDENTIlED FOUR BEST MANAGEMENT APPROACHES TO

IMPROVING ENERGY EFlCIENCY IN PROCESS HEATING

	 IMPROVE THE EFlCIENCY OF THE COMBUSTION

PROCESS 	 REDUCE HEAT LOSSES IN THE PROCESS OF

TRANSPORTING AND TRANSFERRING PROCESS HEAT 	

IMPROVE THE OVERALL RATE OF HEAT TRANSFER FROM

THE PROCESS HEAT MEDIUM TO THE PRODUCT AND

	 RECOVER A PORTION OF THE RESIDUAL WASTE

HEAT 4HE $/% REPORTS THAT APPLICATION OF

MANY OF THE IDENTIlED BEST MANAGEMENT

PRACTICES CAN IMPROVE EFlCIENCY OF PROCESS

HEATING TYPICALLY IN A RANGE OF UP TO  WITH

SOME MEASURES SUCH AS PREHEATING COMBUSTION

AIR INCREASING EFlCIENCY BY  OR MORE 4HESE

MEASURES TYPICALLY RESULT IN PAYBACKS WITHIN A


MONTH PERIOD

)MPLEMENTATION OF PROCESS HEATING EFlCIENCY

IMPROVEMENTS HAVE TO BE CAREFULLY INTEGRATED

WITH PROCESS OPERATING PARAMETERS SO AS NOT TO

IMPAIR PERFORMANCE FOR EXAMPLE HEAT RECOVERY

AND INTEGRATION CAN MAKE PROCESS CONTROL MORE

DIFlCULT 7ELL
DESIGNED PROCESS HEATING

IMPROVEMENTS CAN ACTUALLY ENHANCE PROCESS

PERFORMANCE AND REDUCE ENVIRONMENTAL

EMISSIONS 4HE 0EW #ENTER REPORT on industry 

CASE STUDIES HIGHLIGHTED SEVERAL SUCH EXAMPLES

	 INSTALLATION OF OVEN DRAFT CONTROLS AT &RITO


,AY TORTILLA CHIP OPERATIONS NOT ONLY SAVED

NATURAL GAS BUT ALSO IMPROVED THE QUALITY OF

THE CHIPS 	 WASTE HEAT RECOVERY FROM THE

INCINERATION OF EXHAUST GASES FROM PAINTING

OPERATIONS AT A 4OYOTA MANUFACTURING FACILITY

ALSO ENABLED THE PLANT TO REPLACE CENTRALIZED

STEAM GENERATION WITH A DISTRIBUTED HOT WATER

SUPPLY SYSTEM AND 	 REPLACEMENT OF EXISTING

ETHYLENE FURNACES AT THE $OW #HEMICAL &REEPORT 48 FACILITY FOR COMPLIANCE WITH ./X

EMISSIONS REQUIREMENTS ALSO IMPROVED PROCESS

HEATING EFlCIENCY BY  AND REDUCED #/2

EMISSIONS BY  TONSYEAR

3IGNIlCANT REDUCTIONS IN DEMAND FOR PROCESS

HEATING MAY REQUIRE CHANGES IN THE UNDERLYING

MANUFACTURING PROCESSES THEMSELVES 4HESE

COULD INCLUDE THE SUBSTITUTION OF MEMBRANE

SEPARATION FOR TEMPERATURE
BASED SEPARATIONS

MORE SELECTIVE CATALYSTS THAT REDUCE REACTION

TEMPERATURES AND GREATER PROCESS INTEGRATION

4HE STEEL INDUSTRY ACHIEVED SIGNIlCANT REDUCTIONS IN PROCESS HEATING REQUIREMENTS AS A RESULT

OF DEPLOYMENT OF CONTINUOUS CASTING MACHINES

AND ADVANCES IN NEAR
NET
SHAPE CASTING THAT

MINIMIZE THE NEED FOR FOLLOW
UP FORMING

OPERATIONS )N THE CHEMICALS INDUSTRY $OW AND

"!3& DEPLOYED THE WORLDS lRST COMMERCIAL


SCALE PLANT TO CONVERT HYDROGEN PEROXIDE TO

PROPYLENE OXIDE REDUCING ENERGY USE BY 

AND WASTEWATER PRODUCTION BY 2ESEARCH

IS UNDERWAY TO DEVELOP NEW CATALYSTS THAT

WOULD ACHIEVE THE OXIDATIVE COUPLING OF METHANE TO CONVERT METHANE TO ETHYLENE REPLACING

THE ENERGY INTENSIVE CRACKING PROCESS /THER

POSSIBLE NEW APPROACHES IN THE CHEMICALS
108 MIT STUDY ON THE FUTURE OF NATURAL GAS

INDUSTRY INVOLVE THE UTILIZATION OF BIOMASS

FEEDSTOCK MATERIALS TO REPLACE CONVENTIONAL

HYDROCARBON FEEDSTOCK BIO
PROCESSING TECHNOLOGIES THAT MAY REQUIRE LESS PROCESS HEATING

OR BOTH

&INALLY PRODUCT SUBSTITUTION OFFERS OPPORTUNITIES FOR REDUCTIONS IN DEMAND FOR NATURAL GAS

3UCH EXAMPLES INCLUDE NEW CEMENTS NANO


MATERIALS AND BIOMIMETIC MATERIALS THAT REQUIRE

LESS ENERGY TO PRODUCE THAN CURRENT MATERIALS

FINDING

The potential for significant reductions in 

the use of natural gas for process heating 

lies in a shift to new manufacturing process 

technologies that use less energy-intensive 

processes and materials.

RD&D Opportunities in Energy-Efficient 

Technologies 

Additional opportunities for advances in 

INDUSTRIAL TECHNOLOGIES LIE IN THE NEXUS OF ENERGY

EFlCIENCY ENVIRONMENTAL QUALITY AND ECONOMIC

COMPETITIVENESS!DVANCES IN ENERGY
EFlCIENT

PROCESS TECHNOLOGIES ARE WELL INCENTIVIZED BY

NORMAL INDUSTRY ECONOMICS DUE TO THE POTENTIAL

TO ALSO IMPROVE PROlTABILITY THROUGH EITHER

PRODUCT IMPROVEMENTS OR COST REDUCTION

"ECAUSE THESE ADVANCES ALSO PROVIDE IMPORTANT

CONTRIBUTIONS TO 53 ENERGY SECURITY AND

ENVIRONMENTAL POLICY GOALS THE $/% HAS

HISTORICALLY PLAYED AN IMPORTANT ROLE 5NDER THE

FORMER )NDUSTRIES OF THE &UTURE 0ROGRAM THE

$/% SERVED AS THE CONVENER OF INDUSTRY WORKING

GROUPS THAT DEVELOPED TECHNOLOGY ROADMAPS

4HE $/% THEN FUNDED SELECTED 2$$ PROJECTS

CONSISTENT WITH THE ROADMAPS &OR EXAMPLE THE

DEVELOPMENT OF THE h3UPER "OILERv DESCRIBED

EARLIERIN THIS CHAPTER WASTHE RESULT OF AN )NDUSTRIAL

#OMBUSTION 4ECHNOLOGY 2OADMAP PREPARED BY

A $/%
FORMED INDUSTRY WORKING GROUP IN 

4HE $/% SUBSEQUENTLY COST SHARED AN 2$

EFFORT WITH THE 'AS 4ECHNOLOGY )NSTITUTE '4)	 A

NOT
FOR
PROlT 2$ ORGANIZATION 4HE PARTNERSHIP

WAS SUBSEQUENTLY EXPANDED TO INCLUDE OTHER

SPONSORING AND PERFORMING ENTITIES INCLUDING

#LEAVER
"ROOKS )NC WHICH SERVED AS THE

COMMERCIALIZATION PARTNER

!  EVALUATION OF THE $/% /FlCE OF

)NDUSTRIAL 4ECHNOLOGIES /)4	 2$ PROGRAM

BY THE .ATIONAL !CADEMY OF 3CIENCES CONCLUDED

THAT hxTHE /)4 INDUSTRIAL PROGRAMS ARE COST


EFFECTIVE AND HAVE PRODUCED SIGNIlCANT ENERGY

ENVIRONMENTAL AND PRODUCTIVITY BENElTS FOR

BOTH THE INDUSTRIAL SECTOR AND THE COUNTRYv

4HE !CADEMY REPORT IDENTIlED FOUR LESSONS

FROM THE /)4 EXPERIENCE 	 THE VALUE OF /)4

AS A CATALYST FOR CONVENING INDUSTRY 	 THE

ADVANTAGES OF EARLY AGREEMENT ON GOALS AND

METRICS FOR SUCCESS 	 THE IMPORTANCE OF

NON
ENERGY BENElTS TO INDUSTRY AS A DRIVER FOR

THE ADOPTION OF TECHNOLOGY AND 	 THE SIGNIlCANCE OF DEMONSTRATION AS A MEANS OF PROMOTING TECHNOLOGY ADOPTION 4HE #/2 EMISSION

REDUCTION BENElTS OF $/% /)4 SUPPORTED

TECHNOLOGIES AND ACTIVITIES UNDERTAKEN SINCE

 HAVE BEEN ESTIMATED AT  MILLION METRIC

TONS OF CARBON EQUIVALENT --4#E	

%ARLY IN THE LAST DECADE TERMINATION OF THE

)NDUSTRIES OF THE &UTURE 0ROGRAM WAS PROPOSED

ON THE ASSUMPTION THAT MARKET FORCES SHOULD

DRIVE THE SIZE AND PACE OF FUTURE ENERGY EFlCIENCY IMPROVEMENTS IN INDUSTRY 4HE 0RESIDENTS lSCAL  BUDGET PROPOSES TO REPLACE THE

)NDUSTRIES OF THE &UTURE 0ROGRAM WITH A SUITE OF

NEW MANUFACTURING 2$ INITIATIVES AND A NEW

CRITICAL MATERIALS INNOVATION HUB FOCUSING

MORE ON PRE
COMPETITIVE 2$ TARGETED TO

TRANSFORMATIONAL CHANGES IN MANUFACTURING

TECHNOLOGIES
Chapter 5: Demand 109

FINDING

Industrial energy efficiency RD&D programs 

supported by the DOE have historically 

led to significant improvements in energyefficient technologies: technologies that 

also achieved significant reductions in CO2

emissions while improving the economic 

competitiveness of manufacturing. 

RECOMMENDATION

The DOE should continue to play a role 

in accelerating the development of new 

technologies that can improve energy 

efficiency. The DOE should again serve 

as a convener of industry technology 

working groups to develop roadmaps 

for future energy-efficiency technology 

improvements. Based on these roadmaps, 

the DOE should develop a federally funded 

RD&D portfolio consisting of applied precompetitive R&D as well as transformational 

approaches. The DOE RD&D portfolio 

should encompass both industry-specific 

technologies in energy-intensive industries 

and crosscutting technologies applicable 

across a broad spectrum of manufacturing 

industries.

CHP Systems for Industrial Applications

)N MOST CASES INDUSTRIAL BOILER AND PROCESS

HEATING INSTALLATIONS TYPICALLY SUPPORT A SINGLE

APPLICATION 4HE MODIlCATION OF CURRENT PROCESS

HEATING AND INDUSTRIAL BOILERS TO ENABLE #(0

APPLICATIONS COULD HAVE A SIGNIlCANT IMPACT ON

NATURAL GAS DEMAND

)NSTALLATION OF #(0 SYSTEMS DOES NOT NECESSARILY

INCREASE THE EFlCIENCY OF THE PROCESS HEAT OR

STEAM SYSTEM NOR DOES IT GENERATE ELECTRICITY

MORE EFlCIENTLY THAN A LARGE
SCALE CENTRAL STATION

POWER PLANT 4HE ATTRACTIVENESS OF #(0 STEMS

FROM THE INCREASE IN OVERALL SYSTEM EFlCIENCY

THAT CAN BE ACHIEVED BY OBTAINING BOTH ELECTRIC

POWER GENERATION AND STEAM GENERATION FROM A

SINGLE ON
SITE SYSTEM #(0 RESULTS IN INCREASED

DEMAND FOR NATURAL GAS AT THE INDUSTRIAL POINT OF

USE SITE WITH SOME OFFSETTING REDUCTION IN

DEMAND FOR FUELS AT CENTRAL STATION POWER

GENERATION FACILITIES &ROM AN ENERGY SYSTEMS

STANDPOINT THE IMPROVEMENT IN OVERALL ENERGY

EFlCIENCY HAS TO TAKE INTO ACCOUNT THE REDUCTION

IN PURCHASED ELECTRICITY WHICH REDUCES DEMAND

FOR ELECTRICITY FROM THE GRID

4HE FEASIBILITY OF #(0 APPLICATIONS IN MANUFACTURING APPLICATIONS DEPENDS UPON THE ABILITY

TO MATCH THE QUANTITY AND QUALITY OF THE STEAM

OR HOT WATER PRODUCED FROM THE #(0 SYSTEM

WITH THE INDUSTRIAL END
USE REQUIREMENTS FOR

HEAT AND POWER &OR INDUSTRIAL APPLICATIONS

#(0 SYSTEMS ARE DESIGNED TO MEET HEAT LOADS

because it is easier to balance electricity generaTION AND LOAD WITH THE ELECTRICAL GRID )F THE

LEVEL OF ELECTRICITY GENERATION IS LESS THAN THE

MANUFACTURING LOAD THE FACILITY PURCHASES THE

REMAINDER FROM THE GRID IF #(0 ELECTRICITY

GENERATION EXCEEDS ELECTRICAL LOAD THE EXCESS IS

SOLD BACK INTO THE GRID -ATCHING #(0 SYSTEMS

TO HEAT AND POWER LOADS AT SMALLER SCALE SUCH AS

INSTITUTIONAL COMMERCIAL AND RESIDENTIAL

APPLICATIONS IS MORE CHALLENGING AS DISCUSSED

LATER IN THIS CHAPTER

4HE %)! REPORTED THAT  "CF OF NATURAL GAS

WAS USED FOR INDUSTRIAL #(0 IN  REPRESENTING  OF TOTAL INDUSTRIAL NATURAL GAS USE 4HE

%)! !%/  PROJECTS AN INCREASE OF 

IN ELECTRICITY GENERATED FROM END
USER #(0

SYSTEMS BY  7HILE THIS WOULD IMPLY AN

INCREASE IN NATURAL GAS USE OF ABOUT  4CF PER

YEAR BY  THIS INCREASE IS ESSENTIALLY OFFSET BY

OTHER ENERGY
EFlCIENCY GAINS IN THE )NDUSTRIAL

SECTOR SO THAT THE %)! PROJECTION SHOWS RELATIVELY mAT DEMAND FOR NATURAL GAS IN THE INDUSTRY SECTOR FROM THE PERIOD  TO  )N
110 MIT STUDY ON THE FUTURE OF NATURAL GAS

ADDITION INCREASED DEMAND IN THE )NDUSTRIAL

SECTOR FOR #(0 ALSO WOULD MITIGATE INCREASES

IN DEMAND FOR GRID
SUPPLIED ELECTRICITY

Natural Gas Use as a Chemical Feedstock

!BOUT  OR  4CF OF NATURAL GAS DEMAND

IN MANUFACTURING IS FOR USE AS A FEEDSTOCK FOR

THE PRODUCTION OF HYDROGEN AND AMMONIA

(YDROGEN IS USED EXTENSIVELY IN THE PETROLEUM


RElNING INDUSTRY TO UPGRADE PETROLEUM PRODUCTS AND AMMONIA IS PRIMARILY USED IN THE

MANUFACTURE OF FERTILIZER PRODUCTS )N ADDITION

.ATURAL 'AS ,IQUIDS .',S	 WHICH CONSIST

PRIMARILY OF ETHANE AND PROPANE ARE KEY

FEEDSTOCK MATERIALS FOR MANUFACTURING OF

A VARIETY OF CHEMICAL PRODUCTS

/UR DETAILED ANALYSIS OF CHEMICAL FEEDSTOCK

ISSUES IS PRESENTED IN !PPENDIX " 4HE ANALYSIS

INDICATES THAT LOWER NATURAL GAS PRICES MAKE THE

OPERATION OF CURRENT DOMESTIC AMMONIA MANUFACTURING CAPACITY MORE COMPETITIVE IN THE

GLOBAL MARKET!MMONIA IS THE KEY INTERMEDIATE

STEP IN THE MANUFACTURING OF A VARIETY OF NITROGENOUS FERTILIZER PRODUCTS 7E ALSO ESTIMATE THAT

DUE TO CURRENT PETROLEUMNATURAL GAS PRICE

SPREADS .',S WILL HAVE SIGNIlCANT COST ADVANTAGE RELATIVE TO NAPHTHA IN THE DOMESTIC MANUFACTURING OF ETHYLENE %THYLENE IS AN INTERMEDIATE

PRODUCT IN THE MANUFACTURING OF POLYETHYLENE

POLYVINYL CHLORIDE AND OTHER PLASTICS 7E HAVE

NOT ESTIMATED CHANGES IN 53 NATURAL GAS

DEMAND ASSOCIATED WITH POTENTIAL CHANGES IN

GLOBAL MARKET COMPETITIVENESS OF THESE COMMODITIES THIS IS DEPENDENT UPON OTHER FACTORS

SUCH AS GLOBAL DEMAND PROJECTIONS AND CAPITAL

INVESTMENT PLANS WHICH ARE OUTSIDE THE SCOPE OF

OUR ANALYSIS

4HE DEMAND FOR .',S FOR DOMESTIC ETHYLENE

PRODUCTION WILL INCENTIVIZE INCREASED PRODUCTION

OF .',S FROM DOMESTIC NATURAL GAS RESOURCES

THAT ARE RELATIVELY hWETv IE HIGHER .', CONTENT	 4HE IMPLICATIONS FOR .', PROCESSING AND

INFRASTRUCTURE ARE DISCUSSED FURTHER IN #HAPTER 

ON )NFRASTRUCTURE AND IN !PPENDIX "

COMMERCIAL AND RESIDENTIAL 

APPLICATIONS OF CHP SYSTEMS

3MALLER
SCALE #(0 SYSTEMS ARE AVAILABLE FOR

APPLICATIONS IN 2ESIDENTIAL AND #OMMERCIAL

SETTINGS 4HERE IS A WIDE VARIETY OF TECHNOLOGY

OPTIONS FOR SMALLER
SCALE #(0 SYSTEMS INCLUDING

FUEL CELLS GAS TURBINES MICRO
TURBINES AND

RECIPROCATING ENGINES SUCH AS THE 3TIRLING

ENGINE	 %XCEPT FOR FUEL CELLS THESE TECHNOLOGIES

RELY ON THE COMBUSTION OF FOSSIL FUEL TO PRODUCE

HEAT LATER CONVERTED INTO MECHANICAL ENERGY TO

DRIVE THE GENERATOR THAT PRODUCES ELECTRICITY

&UEL CELLS ARE BASED ON ELECTROCHEMICAL CONVERSION OF THE CHEMICAL ENERGY STORED IN HYDRO


CARBON FUELS INTO WATER AND ELECTRIC ENERGY

4HE CHOICE OF #(0 TECHNOLOGY FOR A PARTICULAR

APPLICATION WILL DEPEND ON THE DIFFERENT CHARAC


TERISTICS OF THE TECHNOLOGY AND HOW THEY MATCH

END
USE REQUIREMENTS 

s .ATURAL GAS MICRO
TURBINES HAVE RELATIVELY

HIGH CAPITAL COSTS BUT HAVE LOWER MAINTENANCE

COSTS THAN OTHER TECHNOLOGIES -ICRO
TURBINES

HAVE A HIGH
QUALITY EXHAUST THAT CAN BE USED

TO INCREASE THE PRODUCTION OF HIGH
PRESSURE

STEAM FOR OTHER HIGH
TEMPERATURE APPLICATIONS

(OWEVER TURBINES ARE SENSITIVE TO CHANGES IN

AMBIENT AIR CONDITIONS AND HAVE A POOR

EFlCIENCY AT PART
LOAD CONDITIONS

s 2ECIPROCATING ENGINES HAVE LOW INVESTMENT

COSTS GOOD PART
LOAD PERFORMANCE AND QUICK

START
UPS 4HEIR PRINCIPAL DISADVANTAGES

INCLUDE HIGH MAINTENANCE COSTS HIGH NOISE

LEVELS AND HIGH AIR EMISSIONS AND

s &UEL CELLS HAVE HIGH INITIAL CAPITAL COSTS BUT

ARE VIRTUALLY EMISSIONS FREE AT THE POINT OF

END USE QUIET AND EFlCIENT OVER A RANGE

OF LOADS

!DDITIONAL DETAILS ON PERFORMANCE CHARACTERISTICS AND COST DATA OF #(0 TECHNOLOGIES ARE

PROVIDED IN !PPENDIX #
Chapter 5: Demand 111

! CRITICAL PARAMETER IN ASSESSING THE FEASIBILITY

OF A #(0 SYSTEM IS THE ABILITY TO MATCH THE

HEAT
TO
POWER RATIO (02	 OF THE #(0 SYSTEM

WITH THE POWER AND HEATING LOADS !S THE SIZE OF

THE APPLICATION BECOMES SMALLER MATCHING THE

(02 CHARACTERISTICS OF THE #(0 SYSTEM TO LOAD

BECOMES A GREATER CHALLENGE SINCE IT WILL

DEPEND ON THE #(0 SYSTEMS TECHNICAL CHARACTERISTICS AND ITS SUITABILITY TO MEET THE VARIATION

IN THE CUSTOMERS HEAT AND POWER
LOAD REQUIREMENTS )N 2ESIDENTIAL APPLICATIONS MICRO
#(0S

HAVE VERY SMALL ELECTRICAL CAPACITIES LESS THAN


KILOWATT ELECTRIC K7
E		 WITH DIFFERENT

EFlCIENCY AND (02 VALUES DEPENDING ON THE

CONVERSION TECHNOLOGY &UEL CELLS OFFER THE

HIGHEST ELECTRICAL EFlCIENCY FOLLOWED BY

RECIPROCATING ENGINES AND 3TIRLING ENGINES "Y

COMPARISON 3TIRLING ENGINES HAVE A RELATIVELY

HIGH HEAT OUTPUT PER UNIT OF ELECTRICAL GENERATION IE HIGH (02	 FOLLOWED BY RECIPROCATING

ENGINES AND WITH A RELATIVELY LOW (02 FOR FUEL

CELL TECHNOLOGIES22

4O GAIN FURTHER INSIGHT ON THESE TRADE
OFFS WE

PERFORMED AN ANALYSIS OF SEVERAL SCENARIOS FOR

APPLICATION OF #(0 SYSTEMS IN SMALLER
SCALE

)NSTITUTIONAL AND 2ESIDENTIAL APPLICATIONS 7E

CHOSE THE -)4 CAMPUS AS A CASE STUDY FOR #(0

APPLICATION IN AN )NSTITUTIONAL MARKET 4HE -)4

#(0 SYSTEM CONSISTS OF A  MEGAWATT ELECTRIC

-7E	 GAS TURBINE COMBINED WITH A (EAT

2ECOVERY 3TEAM 'ENERATOR (23'	 TO GENERATE

STEAM FROM THE TURBINE EXHAUST GAS 4HE -)4

#(0 SYSTEM PROVIDES ABOUT  TO  OF THE

CAMPUS ELECTRICAL LOAD AND THE MAJORITY OF THE

CAMPUS STEAM REQUIREMENTS 4HE GAS TURBINE

HAS BEEN USED MOSTLY AS BASELOAD POWER WITH

THE REMAINDER OF ELECTRICITY PURCHASED FROM

THE GRID 4HE REMAINING STEAM LOAD NOT SERVED

BY THE #(0 SYSTEM IS MET WITH CONVENTIONAL

BOILERS 7E ANALYZED THE COSTS OF THE -)4

#(0 SYSTEM RELATIVE TO A NO
#(0 OPTION IE

PURCHASING ALL ELECTRICITY FROM THE GRID AND

GENERATING ALL CAMPUS STEAM REQUIREMENTS FROM

BOILERS /UR ANALYSIS SHOWED THAT INSTALLATION OF

A #(0 SYSTEM PROVIDED A PRESENT VALUE COST

SAVINGS OF ABOUT  AT A DISCOUNT RATE OF 

WITH A CORRESPONDING REDUCTION OF ABOUT 

IN #/2 EMISSIONS23 /UR lNDINGS ARE DESCRIBED

IN MORE DETAIL IN !PPENDIX #

!NOTHER POTENTIAL APPLICATION FOR #(0 IS IN

DISTRICT HEATINGCOOLING SYSTEMS $ISTRICT

HEATINGCOOLING IS A SYSTEM FOR DISTRIBUTING HEAT

IN THE FORM OF STEAM OR HOT WATER	 OR CHILLED

WATER GENERATED IN A CENTRALIZED LOCATION FOR

RESIDENTIAL OR COMMERCIAL SPACE HEATINGCOOLING

AND HOT WATER APPLICATIONS $ISTRICT HEATING IS

USED EXTENSIVELY IN A NUMBER OF %UROPEAN

COUNTRIES FOR INDUSTRIAL COMMERCIAL AND

RESIDENTIAL APPLICATIONS &OR EXAMPLE OVER SIX

IN TEN HOMES IN $ENMARK ARE SERVED BY DISTRICT

HEATING MARKET PENETRATION IS 

OR MORE IN 0OLAND 3WEDEN AND %STONIA AND

GEOTHERMAL
BASED DISTRICT HEATING SERVES 

OF )CELANDS RESIDENCES 53 EXPERIENCE IS MUCH

MORE LIMITED AND FOCUSED ON INSTITUTIONAL

USERS 7HILE THE 53 CURRENTLY HAS OVER 

DISTRICT HEATINGCOOLING SYSTEMS ABOUT 

SERVE HOSPITALS AND UNIVERSITY CAMPUSES SUCH

AS THE -)4 CAMPUS USED AS A CASE STUDY IN OUR

ANALYSIS	 4HE 53 ALSO  URBAN UTILITY DISTRICT

HEATING SYSTEMS SERVING ABOUT  BILLION

SQUARE FEET OF COMMERCIAL SPACE -OST 53

DISTRICT HEATING SYSTEMS ARE SINGLE
PURPOSE

SYSTEMS BUT THERE IS GROWING INTEREST IN #(0

SYSTEMS FOR THIS PURPOSE 4O STIMULATE THIS

MARKET THE $/% COST
SHARED SEVERAL NEW #(0

DISTRICT HEATING PROJECTS USING FUNDS FROM THE

!MERICAN 2ECOVERY AND 2EINVESTMENT !CT

!22!	 !S THE -)4 CASE STUDY ILLUSTRATES

THE MARKET OPPORTUNITIES FOR EXPANDED #(0

DISTRICT HEATING SYSTEMS ARE PROMISING

7E ALSO EXAMINED THE FEASIBILITY OF #(0

SYSTEMS FOR RESIDENTIAL APPLICATIONS IN .EW

%NGLAND !S ILLUSTRATED IN &IGURE  THERE IS A

CONSIDERABLE MISMATCH BETWEEN ELECTRICITY AND

HEATING REQUIREMENTS $URING WINTER THE HEAT

LOAD IS SIGNIlCANTLY HIGHER THAN THE POWER

LOAD WHILE DURING SUMMER THE POWER LOAD

IS SIGNIlCANTLY HIGHER DUE TO DEMAND FOR

AIR
CONDITIONING
112 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 5.6 Hourly Energy Load Profile for One Type of Residential Customer in New England – Sample for 

one day during Winter and Summer 

3OURCE -)4%) Energy load [kWh per hour]

Energy load [kWh per hour]

0

5

10

15

20

25

0

5

10

15

20

25

0.0

1.0

2.0

3.0

4.0

0.0

1.0

2.0

3.0

4.0

Winter Summer

1 3 5 7 9 11 13 15 17 19 21 23

Hour

1 3 5 7 9 11 13 15 17 19 21 23

Hour

Electric load [kW-e] Heat load [kW-th] Electric load [kW-e] Heat load [kW-th]

/UR ANALYSIS SHOWS THAT THE ENERGY ENVIRONMENTAL AND ECONOMIC BENElTS OF A #(0

residential application varied greatly depending 

UPON THE CUSTOMER ENERGY MANAGEMENT

STRATEGY $ESIGNING AND OPERATING A 2ESIDENTIAL

#(0 SYSTEM TO FOLLOW HEAT LOADS WAS ECONOMICALLY COMPETITIVE WITH THE GREATEST BENElT

DURING THE WINTER SEASON /PERATING THE #(0

SYSTEM TO FOLLOW ELECTRICITY REQUIREMENTS WAS

NOT ECONOMICALLY ATTRACTIVE BECAUSE THE #(0

SYSTEM WOULD PRODUCE LARGE QUANTITIES OF EXCESS

HEAT DURING SUMMER MONTHS SIGNIlCANTLY

REDUCING OVERALL PERFORMANCE OF THE SYSTEM

&INALLY FOR THE RESIDENTIAL APPLICATIONS A

TECHNOLOGY SUCH AS FUEL CELLS WITH A RELATIVELY

LOW (02 WAS MORE ATTRACTIVE THAN AN ALTERNATIVE ENGINE
BASED TECHNOLOGY WITH HIGHER (02

4HE RELATIVE HIGH ELECTRIC EFlCIENCY OF FUEL CELLS

MAKES THIS TECHNOLOGY COMPETITIVE FOR MEETING

ELECTRICAL LOADS 4HE DETAILED RESULTS OF THE

-)4 AND .EW %NGLAND 2ESIDENTIAL CASE STUDIES

ARE DESCRIBED IN GREATER DETAIL IN !PPENDIX #

FINDING

Matching heat and power loads for 

residential and other small-scale 

applications poses a significant challenge 

to the feasibility of small-scale CHP systems 

based on current technologies.

NATURAL GAS DEMAND IN BUILDINGS

4HE RESIDENTIALCOMMERCIAL SECTORS ACCOUNT FOR

OVER  OF TOTAL ENERGY CONSUMPTION IN THE

53 ALMOST EXCLUSIVELY IN BUILDINGS 7HILE

THESE TWO SECTORS REPRESENT OVER TWO
lFTHS OF

OVERALL ENERGY DEMAND THEY ACCOUNT FOR MORE

THAN  OF THE NATIONS NATURAL GAS DEMAND

WHEN THE NATURAL GAS USED TO GENERATE ELECTRICITY

FOR BUILDINGS IS ADDED TO THE DIRECT USE OF

NATURAL GAS IN HOMES AND BUSINESSES27

7ITHIN THE RESIDENTIALCOMMERCIAL SECTORS THE

DIRECT USE OF FUELS SUCH AS NATURAL GAS FUEL OIL AND

LIQUID PETROLEUM GAS ,0'	 ARE CONCENTRATED IN

THERMAL END USES ESPECIALLY SPACE HEATING AND
Chapter 5: Demand 113

HOT WATER &IGURE  SHOWS THE BREAKDOWN OF

ENERGY CONSUMPTION FOR MAJOR END USES IN THE

RESIDENTIALCOMMERCIAL SECTORS /F PARTICULAR NOTE

ARE THE DIFFERENCES BETWEEN ELECTRICITY AND DIRECT

FUEL CONSUMPTION ACROSS DIFFERENT END USES AND

HOW THIS INmUENCES NOT ONLY THE SALES OF ELECTRICITY NATURAL GAS AND OTHER FUELS BUT OVERALL ENERGY

CONSUMPTION ONCE ELECTRICITY CONVERSION LOSSES

ARE INCLUDED!S CAN BE SEEN ELECTRICITY AND FUEL

SALES  OFTEN CALLED hSITE ENERGYv MASKS

OVERALL ENERGY CONSUMPTION SINCE ONLY ABOUT A

THIRD OF ENERGY CONSUMED IN POWER GENERATION

BECOMES ELECTRICITY SOLD TO THE CONSUMER

Comparing the Efficiency of Space 

Conditioning and Hot Water Technologies

7HEN CONSIDERING POLICIES TO COST
EFFECTIVELY

REDUCE ENERGY CONSUMPTION AND #/2 EMISSIONS

IN BUILDINGS IT IS IMPORTANT TO CONSIDER BOTH THE

END USE AND THE ENERGY CARRIER 4HIS IS ESPECIALLY

TRUE WHEN LOOKING AT APPLIANCES AND BUILDING

ENERGY SYSTEMS THAN CAN BE RUN ON EITHER

ELECTRICITY OR FUELS SUCH AS NATURAL GAS 5NTIL

RECENTLY BUILDINGS COMMONLY HAD SEPARATE

SYSTEMS FOR HEATING AND COOLING "OILERS OR

FURNACES FOR HEATING CAN RUN ON NATURAL GAS OIL

AND ,0'!S SHOWN IN &IGURE  SPACE COOLING

WHICH USUALLY INCLUDES HUMIDITY CONTROL EG

AIR
CONDITIONING !#		 IS ALMOST EXCLUSIVELY

ELECTRICITY BASED ALTHOUGH LARGE #OMMERCIAL !#

SYSTEMS ARE AVAILABLE THAT RUN ON NATURAL GAS AND

IN THE PAST GAS
lRED !# SYSTEMS FOR THE RESIDENTIAL SECTOR HAVE BEEN COMMERCIALLY AVAILABLE

)N THE LAST SEVERAL DECADES HEAT PUMP SYSTEMS

HAVE BECOME MUCH MORE COMMON ! HEAT

PUMP IS ESSENTIALLY AN AIR CONDITIONER THAT CAN

RUN BACKWARDS DELIVERING EITHER HOT OR COLD AIR

TO A BUILDINGS INTERIOR -OST HEAT PUMP

SYSTEMS ARE AIR
SOURCE HEAT PUMPS USING

EXTERNAL AIR AS THE TEMPERATURE RESERVOIR FROM

WHICH TO PROVIDE HEATING OR COOLING 4HIS IS

SUFlCIENT FOR REGIONS THAT EXPERIENCE MILD

WINTERS BUT NOT WHERE TEMPERATURES GET VERY

LOW FOR VERY LONG

Figure 5.7 2006 Breakdown of Building Energy Consumption in the Residential and 

Commercial Sectors 

0

1

2

3

4

5

6

Electricity (Balance of Primary Energy)

Electricity (Retail Sales)

Renewable Fuels

LPG

Oil

Natural Gas

[% of Sector Energy Consumption using

Total Electricity Primary Energy]

(% of Sector Energy Consumption using

only Electricity Sales (e.g., Site Energy))

[15.8%]

(23.4%)

Space 

Heating

Space 

Cooling

Water

Heating

Lighting Electronics Other

Equipment

[15.9%]

(11.0%)

[6.2%]

(9.4%)

[24.8%]

(16.9%)

[11.2%]

(07.6%)

[26.1%]

(31.7%)

0

1

2

3

4

5

6

Electricity (Balance of Primary Energy)

Electricity (Retail Sales)

Renewable Fuels

LPG

Oil

Natural Gas

[% of Sector Energy Consumption using

Total Electricity Primary Energy]

(% of Sector Energy Consumption using

only Electricity Sales (e.g., Site Energy))

Space 

Heating

Space 

Cooling

Water

Heating

Lighting Electronics Appliances

[13.0%]

(07.9%)

[12.4%]

(15.5%)

[11.6%]

(07.1%)

[9.1%]

(5.6%)

2006: Total Quads – Commercial Sector 

2006: Total Quads – Residential Sector 

[27.4%]

(19.6%)

[26.5%]

(44.4%)

3OURCE $/% Buildings Energy Data Book /CT 	
114 MIT STUDY ON THE FUTURE OF NATURAL GAS

'ROUND SOURCE OR GEOTHERMAL	 HEAT PUMPS

WHICH USE THE TEMPERATURE OF THE EARTH INSTEAD

OF THE AIR TO PROVIDE HEATING AND COOLING

OVERCOME THIS COLD WINTER PROBLEM (OWEVER

THIS COMES AT A SIGNIlCANT INCREASE IN INSTALLED

COSTS SINCE AN EXTERNAL HEAT EXCHANGE LOOP

NEEDS TO BE INSTALLED IN THE GROUND OUTSIDE THE

BUILDING 4HE COST OF THIS HEAT EXCHANGER CAN

VARY SIGNIlCANTLY DEPENDING ON THE TYPE OF

GROUND SOURCE HEAT PUMP SOIL TYPE AND

TEMPERATURE

(OT WATER SYSTEMS ARE MORE STRAIGHTFORWARD

SINCE THE SEASONALITY OF USE IS LESS OF A FACTOR

#OMMON SYSTEMS USE THE HEAT FROM FUEL

COMBUSTION OR ELECTRIC RESISTANCE HEATING TO

KEEP A TANK OF WATER AT THE DESIRED TEMPERATURE

2ECENTLY HEAT PUMP HOT WATER SYSTEMS HAVE

ENTERED THE MARKET AS HAVE INSTANTANEOUS OR

TANKLESS	 WATER HEATERS

&OR ALL OF THESE SYSTEMS WHETHER FURNACES

CENTRAL !# HEAT PUMPS OR HOT WATER HEATERS

THE DIFFERENTIAL EQUIPMENT AND LIFE
CYCLE COSTS

OF SYSTEMS ARE IMPORTANT FACTORS TO BUILDERS

HOMEOWNERS AND POLICY MAKERS AS BUILDERS

SEEK TO MINIMIZE INSTALLED COSTS CONSUMERS

SEEK TO MINIMIZE OPERATING COSTS AND POLICY

MAKERS SEEK TO MINIMIZE SOCIAL COSTS INCLUDING

EFFECTS ON THE ENVIRONMENT "ALANCING ALL THESE

FACTORS IS CHALLENGING ESPECIALLY WHEN COMPARING SYSTEMS THAT USE DIFFERENT ENERGY CARRIERS IN

particular electricity versus natural gas and 

OTHER hDIRECTv USE FUELS

!S DESCRIBED IN MORE DETAIL IN !PPENDIX $

THERE IS A BROAD RANGE OF EFlCIENCY METRICS FOR

FURNACES AIR CONDITIONERS HEAT PUMPS AND HOT

WATER HEATERS THAT OFFER LITTLE GUIDANCE TO CON


SUMERS WHEN TRYING TO COMPARE TECHNOLOGIES

ACROSS FUEL TYPES %VEN HEAT PUMPS WHICH PROVIDE BOTH SPACE HEATING AND !# HAVE DIFFERENT

EFlCIENCY METRICS DEPENDING ON WHETHER THEY

ARE IN HEATING OR COOLING MODE OR USE OUTSIDE

AIR VERSUS THE TEMPERATURE OF THE EARTH AS A HEAT

SOURCESINK &OR FURNACES AIR CONDITIONERS AND

AIR SOURCE HEAT PUMPS THESE EFlCIENCY METRICS

ARE ALSO hAVERAGEDv ACROSS REFERENCE HEATING OR

COOLING SEASONS AND SO DO NOT INFORM INDIVIDUAL CONSUMERS ABOUT HOW THEY MIGHT PERFORM

LOCALLY %VEN THIS ROUGH SEASONAL ADJUSTMENT

IS NOT POSSIBLE FOR GROUND
SOURCE HEAT PUMPS

SINCE BASELINE GROUND TEMPERATURE INFORMATION

IS NOT AVAILABLE !ND SO GROUND SOURCE HEAT

PUMP MANUFACTURERS REPORT AN OPTIMAL AND

SUBSTANTIALLY HIGHER COEFlCIENT OF PERFORMANCE

THAN REPORTED FOR AIR
SOURCE HEAT PUMPS

4O ALLOW COMPARISON WE NORMALIZE THESE

DIVERSE EFlCIENCY METRICS FOR SELECT 2ESIDENTIAL

APPLIANCES AND SPACE CONDITIONING SYSTEMS IN

4ABLE 29 4HIS TABLE FOCUSES ON THE 2ESIDENTIAL

SECTOR SINCE IT IS LARGER IN BOTH OVERALL SIZE AND

THE NUMBER OF SYSTEMS IN THE lELD AND ALSO

BECAUSE IT IS AN AREA WHERE POLICIES INCLUDING

APPLIANCE EFlCIENCY AND BUILDING STANDARDS

MAY OVERCOME MARKET INERTIA ESPECIALLY AS IT

PERTAINS TO EQUIPMENT VERSUS LIFE
CYCLE COST

CALCULATIONS FOR SMALLER LESS EXPERIENCED

CONSUMERS

4ABLE  SHOWS THE h3EASONAL #O
EFlCIENT OF

0ERFORMANCEv 3#/0	 FOR A RANGE OF 2ESIDENTIAL

HEATING COOLING AND HOT WATER SYSTEMS ACROSS A

RANGE OF COMMERCIALLY AVAILABLE SYSTEMS INCLUDING hLOWv ENERGY EFlCIENCY SYSTEMS HIGHER

EFlCIENCY h%NERGY 3TARv SYSTEMS MINIMUM

EFlCIENCY TO QUALIFY AS AN %NERGY 3TAR SYSTEM	

AND A BEST
AVAILABLE ENERGY EFlCIENCY SYSTEM

4HE 3#/0 IS SIMPLY THE RATIO OF THE AMOUNT

OF USEFUL ENERGY PROVIDED DIVIDED BY THE AMOUNT

OF RETAIL ENERGY FUEL OR ELECTRICITY	 CONSUMED

&OR DIRECT THERMAL SYSTEMS SUCH AS FURNACES

THE EFlCIENCY OR 3#/0 WILL BE LESS THAN ONE

(OWEVER FOR !# AND HEAT PUMP SYSTEMS WHERE

THE ELECTRICITY MOVES HEAT BETWEEN THE INSIDE

AND OUTSIDE INSTEAD OF CONSUMING THE ELECTRICITY

AS HEAT THE AMOUNT OF USEFUL ENERGY CAN BE

SUBSTANTIALLY GREATER THAN THE hTHERMAL VALUEv

OF ELECTRICITY RESULTING IN 3#/0S IN THE RANGE

OF TWO AND A HALF TO SEVEN
Chapter 5: Demand 115

Site Energy Efficiency (SCOP*) Sourceto-Site 

Efficiency

Full-Fuel-Cycle Efficiency (FFC)

Low Energy 

Star

Best Low Energy 

Star

Best

Heating System Type

Electric Furnaces 0.95 — 0.99 0.32 0.31 — 0.32

Oil-Fired Furnaces 0.78 0.83 0.95 0.88 0.69 0.73 0.84

Gas-Fired Furnaces 0.78 0.90 0.98 0.92 0.72 0.83 0.90

Air Source Heat Pumps† 2.30 2.40 5.20 0.32 0.74 0.77 1.67

Ground Source Heat Pumps‡ 2.50 3.30 4.80 0.32 0.80 1.06 1.54

Cooling System Type

Central AC† 3.81 4.25 6.74 0.32 1.22 1.37 2.17

Air Source Heat Pumps† 3.81 4.25 4.98 0.32 1.22 1.37 1.60

Ground Source Heat Pumps‡ 2.55 4.13 6.57 0.32 0.82 1.33 2.11

Hot Water System Type

Electric Storage Tank 0.92 — 0.95 0.32 0.30 — 0.31

Oil-Fired Storage Tank 0.51 — 0.68 0.88 0.45 — 0.60

Gas-Fired Storage Tank 0.59 0.62 0.70 0.92 0.54 0.57 0.64

Electric Heat Pump Tank 0.92 2.00 2.35 0.32 0.30 0.64 0.76

Electric Instantaneous 0.93 — 0.99 0.32 0.30 — 0.32

Gas-Fired Instantaneous 0.54 0.82 0.94 0.92 0.50 0.75 0.87

Table 5.1 Site vs. Source Energy Efficiency of Residential Heating, Cooling and Hot Water Systems

3OURCE -)4%) 
#/0 FOR 'ROUND 3OURCE (EAT 0UMP 3YSTEMS †3PLIT 3YSTEMS ‡#LOSED ,OOP 3YSTEMS

-ORE IMPORTANTLY 4ABLE  SHOWS THE DIFFERENCE

BETWEEN hSITEv 3#/0	 AND hSOURCEv &ULL
&UEL


#YCLE &&#		 ENERGY EFlCIENCIES &&# EFlCIENCIES

ACCOUNT FOR ALL THE ENERGY USED TO EXTRACTRElNE

CONVERT AND TRANSPORT THE FUEL TO THE END USER AS

WELL AS THE EFlCIENCY OF THE END
USE EQUIPMENT

!LMOST ALL BUILDING ENERGY EQUIPMENT IS SOLD ON

THE BASIS OF END USE OR hSITEv ENERGY EFlCIENCY

(OWEVER LOOKING AT SITE OR END
USE EFlCIENCY

ALONE MASKS LARGE ENERGY CONVERSION LOSSES

PARTICULARLY THOSE FROM GENERATING ELECTRICITY

&&# EFlCIENCY COMBINES THESE SOURCE
TO
SITE

LOSSES WITH END
USE ENERGY CONSUMPTION

&IGURE  SHOWS THE h3OURCE TO 3ITEv ENERGY

LOSSES OF BRINGING ENERGY TO THE CONSUMER!LL

FUELS WHETHER COAL OR NATURAL GAS FOR POWER

GENERATION OR OIL AND NATURAL GAS FOR HOUSEHOLD

USE CONSUME SOME ENERGY IN THE EXTRACTION

PROCESSING AND BULK TRANSPORTATION OF FUEL

4HERE IS ALSO ADDITIONAL ENERGY USE OR LOSSES IN

THE DELIVERY OF ELECTRICITY AND FUELS TO THE RETAIL

CUSTOMER SUCH AS THE TRANSMISSION AND DISTRIBUTION 4$	 OF ELECTRICITY DISTRIBUTION SYSTEMS

FOR NATURAL GAS OR TRUCK DELIVERY OF HOME HEATING

OIL 4HE BIGGEST DIFFERENCE COMES IN THE CONVERSION LOSSES ASSOCIATED WITH ELECTRICITY PRODUCTION

7HEN THESE ARE ALL ADDED TOGETHER SOURCE TO SITE

LOSSES FOR ELECTRICITY ARE  COMPARED TO 

FOR NATURAL GAS AND  FOR HOME HEATING OIL

4HESE hSOURCE TO SITEv LOSSES ARE THEN COMBINED

WITH END
USE ENERGY EFlCIENCIES TO CALCULATE THE

&&# EFlCIENCIES AS SHOWN IN 4ABLE 
116 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 5.8 Combined Source to Site Energy Efficiencies for Delivering Coal and Natural 

Gas-Fired Generation Versus Oil and Natural Gas to End-Use Customers

Source to Site — Coal-Fired Generation Source to Site — Natural Gas-Fired Generation

Source to Site — Home Heating Oil Source to Site — Direct-Use Natural Gas

100 100

100 100

Extraction Processing Transport Generation

Avg

Coal

Avg

Gas

T&D Extraction Processing Transport Generation T&D

Extraction Processing Transport

No

Generation

Extraction Processing Transport Equivalent Distribution

No

Generation

Equivalent

New Coal 36 33

Distribution

90 89 89

96

98 97 97 94 93 96

31 29

37 39

New Gas 47

44

93 92 94 97

3OURCE '4) AND %)!

FINDING

Source-to-site energy losses should be 

considered when choosing among energy 

options, especially ones that use different 

energy carriers.

)N  A .ATIONAL 2ESEARCH #OUNCIL REPORT

RECOMMENDED THAT THE $/% MOVE TO THE &&#

APPROACH IN SETTING ENERGY EFlCIENCY AND

APPLIANCE STANDARDS ESPECIALLY WHEN THERE

ARE MULTIPLE FUEL CHOICES )N  THE $/%

INITIATED A RULEMAKING PROCESS TO MOVE TOWARD

THE &&# APPROACH IN THE DESIGN OF EFlCIENCY

standards for appliances and space conditionING AND HOT WATER SYSTEMS

4HE MAIN COMPARISON TO DRAW FROM 4ABLE 

IS THAT ALTHOUGH HEAT PUMP SYSTEMS AS WELL AS

CENTRAL AIR CONDITIONERS HAVE SIGNIlCANTLY

HIGHER SITE ENERGY EFlCIENCIES WHEN ROUGHLY

TWO
THIRDS LOSSES IN ELECTRICITY GENERATION AND

TRANSMISSION ARE INCLUDED THESE GAINS EFFECTIVELY DISAPPEAR EXCEPT FOR THE MOST EFlCIENT

SYSTEMS 4HUS IMPROVED EFlCIENCY INFORMATION

IS NEEDED TO ALLOW CONSUMERS TO ACCURATELY

COMPARE THE OVERALL ENERGY EFlCIENCY AND COST

effectiveness of direct fuel and electricity end 

USES 4HIS IS ESPECIALLY TRUE FOR SPACE CONDITIONING AND HOT WATER SYSTEMS
Chapter 5: Demand 117

RECOMMENDATION

Improved energy efficiency metrics that 

provide an FFC comparison of energy 

efficiency should be incorporated into 

national standard setting activities. 

The improved metrics should include 

both FFC efficiency and cost-to-consumer 

factors.

Looking Beyond Equipment Efficiency 

Standards

&&# AND END
USE EFlCIENCIES ALONE ARE NOT

ENOUGH TO DETERMINE WHICH BUILDING ENERGY

SYSTEMS WILL HAVE THE LOWEST COST TO THE CONSUMER 4HE COST EFFECTIVENESS OF SPACE CONDITIONING AND OTHER TECHNOLOGIES IS A MIX OF

EQUIPMENT EFlCIENCY AND FUEL COSTS EQUIPMENT

COSTS INCLUDING OPERATION AND MAINTENANCE

COSTS	 AS WELL AS THE DUTY
CYCLE OF THE SYSTEM

&OR EXAMPLE A LESS EFlCIENT ELECTRIC FURNACE

MAY BE MORE COST EFFECTIVE ON A TOTAL COST
TO


CONSUMER BASIS IN REGIONS WHERE IT GETS COLD

ONLY OCCASIONALLY ELECTRICITY PRICES ARE LOW OR

THE HOUSING UNIT IS NOT OCCUPIED YEAR
ROUND

4HE DEPTH AND DURATION OF A REGIONS HEATING

AND COOLING SEASONS HAVE A DRAMATIC IMPACT ON

THE APPLICABILITY AND OVERALL COST EFFECTIVENESS

OF DIFFERENT ENERGY TECHNOLOGIES (EATING AND

COOLING DEGREE DAYS ARE A ROUGH ESTIMATE OF

A REGIONS ANNUAL HEATING AND COOLING NEEDS

AND COMPARE THE DAILY AVERAGE TEMPERATURE

TO A REFERENCE TEMPERATURE USUALLY & IN THE

53	 &OR EXAMPLE .EW 9ORK #ITY AND 3T ,OUIS

HAVE  FEWER HEATING DEGREE DAYS THAN

-INNEAPOLIS
3T 0AUL (OWEVER 3T ,OUIS IS

CONSIDERABLY WARMER THAN .EW 9ORK #ITY WITH

ALMOST HALF AGAIN AS MANY COOLING DEGREE DAYS

$IFFERENT REGIONS OF THE 53 AND EVEN DIFFERENT

LOCATIONS WITHIN STATES HAVE VERY DIFFERENT

HEATING AND COOLING REQUIREMENTS AND SO GENERIC

APPLIANCE EFlCIENCY STANDARDS MAY NOT PROVIDE

ENOUGH INFORMATION TO MAKE THE BEST CHOICE

!S SUCH NO CITY IS hTYPICALv AND THEREFORE

TAILORED INFORMATION IS NEEDED IN ORDER FOR

CONSUMERS ARCHITECTS BUILDERS AND OTHERS TO

MAKE BETTER CHOICES !DD TO THIS INFORMATION

ABOUT REGIONAL BUILDING STOCK AGE AND EFlCIENCY AND DEMOGRAPHIC FACTORS AND THE NEED

FOR A MORE NUANCED APPROACH TO DESIGNING COST


EFFECTIVE LOW
CARBON BUILDING ENERGY POLICIES

BECOMES MORE PRONOUNCED

FINDING

Energy efficiency metrics alone are not 

sufficient to inform consumers about the 

most energy efficient and cost-effective 

options for meeting household energy 

needs in different regions.

!LTHOUGH h%NERGY 'UIDEv LABELS FOR APPLIANCES

SUCH AS HOT WATER HEATERS AIR CONDITIONERS AND

HEAT PUMPS ARE COMMONPLACE IN RETAIL ESTABLISHMENTS COMPARATIVE ENERGY AND LIFE
CYCLE

COST INFORMATION IS FAR FROM PROMINENT IN STORES

AND ON MAJOR RETAILERS WEBSITES EVEN WHEN

PERFORMING HEAD
TO
HEAD COMPARISONS OF

SIMILAR PRODUCTS

 RECOMMENDATION

In addition to improved efficiency metrics 

for comparing appliances and building 

energy technologies, there is a need to 

inform consumers and developers as well 

as state and local regulators about the 

cost-effectiveness and suitability of various 

technologies, relative to local conditions. 
118 MIT STUDY ON THE FUTURE OF NATURAL GAS

FFC Efficiency and CO2 Emissions

7HEN CONSIDERING CLIMATE POLICY THE SITUATION

BECOMES EVEN MORE COMPLEX 7HILE THE CARBON

content of retail fuels is reasonably consistent 

ACROSS THE 53 THIS IS NOT SO FOR ELECTRICITY

WHERE REGIONAL DIFFERENCES IN THE MIX OF GENERATION CAN SUBSTANTIALLY IMPACT THE #/2 EMISSIONS

ASSOCIATED WITH ELECTRICITY USE 4ABLE  SHOWS

HOW SOURCE
TO
SITE EFlCIENCY FACTORS AND #/2

EMISSIONS RATES CHANGE ACROSS THE CONTINENTAL

53 %FlCIENCY AND EMISSIONS FACTORS ARE ALSO

SHOWN BY .ORTH !MERICAN %LECTRIC 2ELIABILITY

#ORPORATION .%2#	 REGION

)N ALL CASES SOURCE
TO
SITE #/2 EMISSIONS FROM

DIRECT COMBUSTION OF FUELS ARE SUBSTANTIALLY

LOWER THAN FROM THE USE OF ELECTRICITY 2EGIONS

WITH GREATER CONCENTRATIONS OF COAL
lRED GENERATION COMMONLY HAVE both HIGHER SOURCE
TO
SITE

LOSSES AS WELL AS HIGHER CARBON CONTENT FUELS!LSO

INCLUDED IN 4ABLE  ARE THE PRE
COMBUSTION

#/2 EMISSIONS FROM THE EXTRACTION PROCESSING

AND TRANSPORTATION OF BULK FUELS 4HE SOURCE
TO


SITE EFlCIENCY FACTORS FOR ELECTRICITY IN 4ABLE 

VARY BY 
 TO  AROUND THE NATIONAL

AVERAGE OF  -OST OF THIS IS DUE TO THE FUEL

MIX ESPECIALLY THE MIX OF COAL VERSUS NATURAL GAS

NUCLEAR AND HYDROPOWER IN EACH .%2# REGION

4HESE DIFFERENCES BECOME MAGNIlED IN A MEASURE OF #/2 EMISSIONS PER UNIT OF GENERATION

WHERE IN 	 THE #/2 content of electricity 

VARIED BY  TO 
 AROUND THE NATIONAL

AVERAGE OF  LB #/2 PER -7H

Table 5.2 Retail Electricity and Fuel — Source-to-Site Efficiencies and CO2 Emissions 

3OURCE %NERGY AND %MISSIONS &ACTORS FOR "UILDING %NERGY #ONSUMPTION 'AS 4ECHNOLOGY )NSTITUTE 

Regional Site-to-Source and CO2

Emissions Factors by NERC Region (2005)

Source-toSite EfficiencyCO2 Emissions (lb CO2/MWh) ∆% from 

Precomb. Generation US Avg. T&D Combined

United States Average US 0.32 54 1,329 86 1,469 –

Midwest Reliability Organization MRO 0.28 55 1,824 120 1,999 36.1

Southwest Power Pool SPP 0.30 63 1,751 114 1929 31.3

Reliability First Corporation RFC 0.31 38 1,427 94 1,559 6.1

Florida Reliability Coordinating Council FRCC 0.33 99 1,319 91 1,508 2.6

SERC Reliability Corporation SERC 0.31 45 1,369 90 1,504 2.4

Texas Regional Entity TRE 0.32 74 1,324 87 1,485 1.1

Western Electricity Coordinating Council WECC 0.38 51 1,033 57 1,142 -22.3

Northeast Power Coordinating Council NPCC 0.33 85 876 61 1,022 -30.4

Primary Residential Fuels Precomb. Distribution Combustion Combined

Distillate Oil US 0.89 107 4 550 661 -55.0

Liquid Petroleum Gas US 0.89 74 4 476 553 -62.3

Natural Gas US 0.92 36 5 404 444 -69.8
Chapter 5: Demand 119

3PACE CONDITIONING AND HOT WATER HEATING

SYSTEMS HAVE A BROAD RANGE OF END USE AND &&#

EFlCIENCIES AND THE GEOGRAPHIC ATTRIBUTES OF

HEATING AND COOLING DEMANDS AND HOW ELECTRICITY IS GENERATED CAN DRAMATICALLY IMPACT

OVERALL ENERGY CONSUMPTION AND #/2 EMISSIONS

4ABLE  PUTS THIS INFORMATION TOGETHER &OR

 -7H OF h5SEFUL %NERGY $EMANDv  HEATING OR COOLING DELIVERED INSIDE THE BUILDING 

THE TABLE SHOWS HOW MUCH RETAIL SITE	 AND

PRIMARY SOURCE	 ENERGY WAS NEEDED AS WELL AS

HOW MUCH TOTAL #/2 WAS EMITTED 4HIS INFORMATION IS SHOWN AT BOTH THE NATIONAL LEVEL AND

FOR SELECT .%2# REGIONS WHERE EMISSIONS ARE

HIGH OR LOW AND THERE ARE LARGE HEATING OR

COOLING SEASONS

4HE RESULTS IDENTIFY THE DANGERS OF A hONE SIZE

lTS ALLv APPROACH %VEN MOVING TO GENERIC &&#

EFlCIENCY AND EMISSIONS METRICS HIDES IMPORTANT DIFFERENCES &OR #/2 EMISSIONS GAS
lRED

FURNACES AND AIR
SOURCE HEAT PUMPS HAVE

ROUGHLY EQUIVALENT #/2 EMISSIONS USING

NATIONAL AVERAGES 7HEN WE LOOK AT HIGHER

EMISSIONS .%2# REGIONS SUCH AS THE 3OUTHWEST

0OWER 0OOL 300	 WHICH COVERS PARTS OF

+ANSAS /KLAHOMA 4EXAS AND NEIGHBORING

STATES THE ELECTRIC
FUELED OPTIONS HAVE SUB


STANTIALLY HIGHER #/2 EMISSIONS %VEN GROUND


SOURCE HEAT PUMPS WITH HIGHER #/0

EFlCIENCIES	 RESULT IN HIGHER #/2 EMISSIONS

THAN THE DIRECT USE OF NATURAL GAS IN REGIONS

WHERE ELECTRIC SECTOR #/2 EMISSIONS ARE HIGH

Table 5.3 Combined Energy and Emissions Impacts of Using FFC Efficiency for Select NERC Regions 

for Energy Star Appliances 

Energy Consumption (MWh) Full Fuel Cycle CO2 Emissions (Ton CO2)

Useful Site FFC National MRO NPCC SPP TRE

Heating System Type

Electric Furnaces 100 101.0 314.2 74 114 49 104 75

Oil-Fired Furnaces 100 120.5 136.7 45

Gas-Fired Furnaces 100 111.1 120.7 27

Air Source Heat Pumps† 100 41.7 129.6 31 47 20 43 31

Ground Source Heat Pumps‡ 100 30.3 94.3 22 34 15 31 23

Cooling System Type

Central AC† 100 23.5 73.2 17 27 11 24 17

Air Source Heat Pumps† 100 23.5 73.2 17 27 11 24 17

Ground Source Heat Pumps‡ 100 24.2 75.3 18 27 12 25 18

Hot Water System Type

Electric Storage Tank 100 105.3 327.4 77 119 51 109 78

Oil-Fired Storage Tank 100 147.1 166.9 55

Gas-Fired Storage Tank 100 161.3 175.2 39

Electric Heat Pump Tank 100 50.0 155.5 37 56 24 52 37

Electric Instantaneous 100 101.0 314.2 74 114 49 104 75

Gas-Fired Instantaneous 100 122.0 132.5 29


#/0 FOR 'ROUND 3OURCE (EAT 0UMP 3YSTEMS †3PLIT 3YSTEMS ‡#LOSED ,OOP 3YSTEMS

3OURCE -)4%)

4ON #/2 -7H 5SEFUL %NERGY	
120 MIT STUDY ON THE FUTURE OF NATURAL GAS

SUCH AS THE -IDWEST 2ELIABILITY /RGANIZATION

-2/	 #ONVERSELY IN REGIONS WHERE ELECTRIC

POWER COMES FROM CLEANER SOURCES INCLUDING

NATURAL GAS LIKE THE .ORTHEAST 0OWER #OORDINATING #OUNCIL .0##	 HEAT PUMP SYSTEMS

HAVE BETTER #/2 EMISSIONS RATES THAN THE DIRECT

USE OF NATURAL GAS  ALTHOUGH AIR
SOURCE HEAT

PUMPS MAY NOT BE APPLICABLE THROUGHOUT THE

ENTIRE .ORTHEAST

F I N D I N G 

Use of equipment-based FFC efficiency and 

national average energy demand and CO2

emissions metrics alone are not sufficient 

to inform policy makers and consumers of 

the comparative cost and environmental 

benefits of competing appliances and 

building energy systems.

RECOMMENDATION

More detailed and targeted approaches 

are needed to develop combined costand emissions-effective strategies for 

meeting future energy and emissions 

goals on a local and regional basis. State 

and Federal agencies should collaborate 

with the building industry and equipment 

manufacturers to provide clear and 

accurate information to consumers.

4HE lNDINGS REGARDING &&# EFlCIENCY THE

COMPARATIVE DUTY
CYCLES OF SPACE CONDITIONING

AND OTHER TECHNOLOGIES PLUS THE #/2 burdens 

of different fuels including regional differences 

IN POWER GENERATION IDENTIFY THE NEED TO

DEVELOP MORE TAILORED ENERGY POLICIES FOR

TRANSFORMING THE 2ESIDENTIAL SECTOR AND BY

EXTENSION ALL BUILDINGS 4HIS INCLUDES TOTAL

BUILDING ENERGY PERFORMANCE AND NOT JUST &&#

EFlCIENCIES COST
EFFECTIVENESS AND THE EMISsions-effectiveness of space conditioning and 

HOT WATER SYSTEMS &OR POLICY MAKERS THIS

SHOULD ALSO INCLUDE LOCAL AND REGIONAL BUILDING

STOCK TRENDS INCLUDING BUILDING RETROlTS AND

NEW CONSTRUCTION

4HE EFlCIENCIES FOR THE BEST HEATING COOLING

AND HOT WATER TECHNOLOGIES ARE ALREADY VERY

HIGH SO THERMODYNAMICALLY WE CANNOT EXPECT

MUCH IMPROVEMENT 4HEREFORE POLICIES AFFECTING 2$$ IN THIS AREA WOULD REASONABLY FOCUS

ON MANUFACTURING COST
REDUCTIONS AND LOCAL

CAPACITY BUILDING FOR hPLUG
AND
PLAYv INSTALLATION OF NEW SYSTEMS IN BOTH RETROlT AND NEW

BUILD APPLICATIONS !S MENTIONED ABOVE THIS

ALSO NEEDS A PUBLIC EDUCATION AND AWARENESS

COMPONENT FOCUSING ON HOW WELL VARIOUS

TECHNOLOGIES MATCH LOCAL CONDITIONS AS WELL AS

THE DEVELOPMENT OF WELL
TRAINED LOCAL PRACTI


TIONERS ABLE TO SPECIFY INSTALL AND MAINTAIN

COST
 AND EMISSION
EFFECTIVE BUILDING ENERGY

SYSTEMS

DEMAND FOR NATURAL GAS 

AS A TRANSPORTATION FUEL

4HE 4RANSPORTATION SECTOR POSES A DUAL CHALLENGE IN A CARBON
CONSTRAINED FUTURE &IRST THE

4RANSPORTATION SECTOR IS RESPONSIBLE FOR ABOUT A

THIRD OF #/2 EMISSIONS FROM THE 53 ECONOMY

3ECOND THE 4RANSPORTATION SECTOR IS CURRENTLY

ALMOST WHOLLY DEPENDENT ON OIL AS A TRANSPORTATION FUEL MAKING IT VERY CHALLENGING TO REDUCE

THOSE EMISSIONS TO ANY SIGNIlCANT EXTENT 4HE

CONCENTRATION OF RESOURCES IN THE -IDDLE %AST

AND THE LARGE BALANCE OF PAYMENT DElCIT CREATED

BY ABOUT  MILLION BARRELS PER DAY BPD	 OF

53 OIL IMPORTS CONSPIRE TO MAKE OIL USE IN THE

4RANSPORTATION SECTOR A MAJOR ENERGY SECURITY

PROBLEM AS WELL )N THIS SECTION OF THE CHAPTER

WE LOOK AT HOW THESE TWO CHALLENGES MIGHT BE

TACKLED TO BOTH REDUCE THE OIL DEPENDENCY OF

TRANSPORTATION IN THE 53 AND TO REDUCE THE

#/2 EMISSIONS THAT GO WITH IT

Natural gas is garnering attention for its 

POTENTIAL TO ADDRESS THESE CHALLENGES IN AN

ECONOMICALLY ATTRACTIVE WAY .ATURAL GAS

PRODUCES SIGNIlCANTLY LESS #/2 THAN OIL WHEN
Chapter 5: Demand 121

COMBUSTED )T IS ALSO AN ABUNDANT DOMESTIC

RESOURCE WITH A PRICE THAT ON AN ENERGY EQUIVALENT BASIS IS SUBSTANTIALLY LOWER THAN THAT OF OIL

#ONSEQUENTLY THERE IS THE POSSIBILITY FOR

SUBSTANTIAL ENERGY SECURITY AND ENVIRONMENTAL

BENElTS TO BE GAINED BY THE PENETRATION OF

NATURAL GAS INTO THE 4RANSPORTATION SECTOR

!BOUT  4CF OF NATURAL GAS PER YEAR  SLIGHTLY

LESS THAN  OF CURRENT 53 CONSUMPTION 

COULD DISPLACE APPROXIMATELY  MILLION BPD 

ABOUT  OF CURRENT 53 CONSUMPTION

7E EXPLORE THIS OPPORTUNITY IN TWO WAYS DIRECT

USE OF COMPRESSED NATURAL GAS #.'	 AND

LIQUElED NATURAL GAS ,.'	 IN VEHICLES AND

INDIRECT USE THROUGH CONVERSION OF NATURAL GAS

TO LIQUID FUELS 4HE ATTRACTION OF THE INDIRECT

PATHWAY IS THE POTENTIAL TO CAPITALIZE ON THE

large-scale liquid fuel infrastructure in place 

AND TO USE CURRENT VEHICLES OR VEHICLES VERY

SIMILAR TO THOSE ON THE ROAD TODAY

Global Natural Gas Vehicle Market 32

4HERE ARE APPROXIMATELY  MILLION NATURAL GAS

VEHICLES .'6	 ON THE ROAD WORLDWIDE OF

WHICH MORE THAN  ARE OPERATED ON #.'

THE REST BEING ,.'
POWERED TRUCKS #.'

VEHICLES ARE A SMALL FRACTION ON THE ORDER OF

 OF THE CLOSE TO  MILLION VEHICLES ON THE

ROAD WORLDWIDE 4HE .'6 WORLD MARKET IS

PREDOMINATELY COMPRISED OF LIGHT
DUTY VEHICLES

CONSISTING OF CARS AND LIGHT TRUCKS 	 WITH A

SMALLER NUMBER OF BUSES 	 AND TRUCKS 	

4HE MAJORITY OF THE LIGHT
DUTY .'6S ARE BI
FUEL

VEHICLES WITH THE ABILITY TO OPERATE ON #.'

OR GASOLINE

4HE LARGEST LIGHT
DUTY .'6 MARKETS ARE FOUND

IN !SIA 0AKISTAN AND )RAN	 AND 3OUTH !MERICA

!RGENTINA AND "RAZIL	 WHERE GOVERNMENT

POLICIES SUPPORT THE USE OF .'6S .ATURAL GAS

CAPABLE VEHICLES CONSTITUTE AROUND  OF THE

VEHICLES IN !RGENTINA AND  IN 0AKISTAN

%UROPE HAS ABOUT ONE MILLION #.' VEHICLES

WHEREAS THERE ARE ONLY APPROXIMATELY 

LIGHT
DUTY #.' VEHICLES IN THE 53

CNG-Powered Vehicles

#.'
POWERED VEHICLES USE SPARK
IGNITION

ENGINES THAT ARE BASICALLY THE SAME AS THOSE

USED IN GASOLINE
POWERED VEHICLES 4HEY CAN

BE FACTORY
PRODUCED OR AFTERMARKET CONVERSIONS

OF GASOLINE VEHICLES 4HE #.' IS STORED IN

HIGH
PRESSURE TANKS EG AT  PSI	 TO OBTAIN

SUFlCIENT ENERGY DENSITY FUEL ENERGY PER

VOLUME	 %VEN WITH STORAGE AT HIGH PRESSURE

THE RANGE OF A #.' VEHICLE FOR A GIVEN TANK SIZE

IS ONLY ABOUT ONE
QUARTER THAT OF GASOLINE 5SE

OF #.' REQUIRES A NEW FUELING INFRASTRUCTURE

THAT WOULD REQUIRE SUBSTANTIAL ADDITIONAL

INVESTMENT

"ECAUSE OF THE LOWER CARBONHYDROGEN RATIO OF

METHANE RELATIVE TO GASOLINE THE #/2 EMISSIONS

FROM THE COMBUSTION OF NATURAL GAS ARE APPROXIMATELY  OF THOSE OF GASOLINE FOR A GIVEN

AMOUNT OF ENERGY PRODUCTION 4HUS ON AN

ENERGY BASIS AT THE POINT OF USE THE #/2

EMISSIONS ARE REDUCED BY AROUND  RELATIVE

TO THE USE OF GASOLINE FOR THE SAME ENGINE

EFlCIENCY /N A LIFE
CYCLE BASIS THIS ADVANTAGE IS

REDUCED BECAUSE THE '(' EMISSIONS IN PRODUCTION AND DISTRIBUTION INCLUDING METHANE

LEAKAGE ARE GREATER FOR NATURAL GAS THAN FOR OIL

PRODUCTS AS DISCUSSED IN !PPENDIX !33 

4HE #.' VEHICLE MARKET SEGMENTS IN THE 53

THAT ARE LIKELY TO OFFER AN ATTRACTIVE PAYBACK

PERIOD IN THE NEAR TERM INVOLVE HIGH MILEAGE

USE 4HESE INCLUDE SHORT
RANGE HEAVY
DUTY

VEHICLES EG URBAN BUSES DELIVERY TRUCKS	 AND

HIGH MILEAGE LIGHT
DUTY VEHICLES PRIMARILY mEET

VEHICLES SUCH AS TAXIS BUSINESS AND GOVERNMENT VEHICLES	 4HESE TWO MARKET SEGMENTS

PRESENTLY HAVE A TOTAL POTENTIAL ASSUMING

 PENETRATION IN THESE SEGMENTS	 OF
122 MIT STUDY ON THE FUTURE OF NATURAL GAS

 4CFYEAR  EQUIVALENT TO  MILLION BPD

3HORT
RANGE HEAVY
DUTY VEHICLES ARE PARTICULARLY ATTRACTIVE FOR #.' BECAUSE THEY OPERATE

WITH LOW MILEAGE PER GALLON RESULTING IN

SUBSTANTIAL FUEL COST SAVINGS

FINDING

At present gasoline-CNG fuel price spreads, 

U.S. heavy-duty vehicles used for shortrange operation (buses, garbage trucks, 

delivery trucks) have attractive payback 

times (around three years or less).

Payback times for U.S. light-duty vehicles 

are attractive provided they are used in 

high-mileage operation (generally in fleets) 

and have a sufficiently low incremental 

cost — a representative number is around 

$5,000 for a payback time of three years or 

less. This condition is presently not met.

!LTHOUGH #.' IS SUBSTANTIALLY CHEAPER THAN

GASOLINE ON AN ENERGY BASIS ITS USE REQUIRES

SIGNIlCANT ADDITIONAL UPFRONT VEHICLE COSTS

4HUS A KEY FACTOR IN #.' VEHICLE MARKET

PENETRATION IS A SUFlCIENTLY SHORT TIME TO

COMPENSATE THE HIGHER COST OF A #.' VEHICLE

WITH LOWER
PRICED NATURAL GAS )N THE 53

INCREMENTAL COSTS ARE HIGH PARTICULARLY FOR

AFTERMARKET CONVERSIONS 4HE ONLY FACTORY


PRODUCED #.' VEHICLE IN THE 53 IS THE

(ONDA '8 WHICH PRESENTLY HAS AN INCREMENTAL

COST RELATIVE TO AN EQUIVALENT GASOLINE VEHICLE

OF ABOUT  AND MAY BE COMPARED TO THE

PREMIUM OF ABOUT  FOR THE %UROPEAN 67

0ASSAT 43) %CO
FUEL 4HE (ONDA '8 OFFERS ONLY

NATURAL GAS OPERATION AND THEREBY HAS RECEIVED

A TAX SUBSIDY NOT GIVEN TO FACTORY
PRODUCED

VEHICLES PROVIDING BI
FUEL OPERATION )N CONTRAST67 %CO
FUEL AND &IAT VEHICLES PRODUCED

IN %UROPE DO OFFER BI
FUEL OPERATION INCREASING

mEXIBILITY WHICH IS CRUCIAL FOR NON
mEET USERS

!FTERMARKET CONVERSIONS ARE AVAILABLE FOR A

WIDE RANGE OF 53 CARS AND LIGHT TRUCKS AND

PROVIDE BI
FUEL OPERATION (OWEVER COSTS ARE

APPROXIMATELY  PER VEHICLE WITH lRMS

CARRYING OUT THE CONVERSIONS POINTING TO 53

%0! CERTIlCATION PROCEDURES FOR THE HIGH

EXPENSE )N CONTRAST CONVERSIONS ARE BEING

PROVIDED FOR AROUND  PER VEHICLE IN

3INGAPORE

FINDING

Experience in other countries indicates 

the potential for substantial reduction 

of incremental costs for U.S. factory and 

aftermarket converted CNG vehicles.

Table 5.4 Illustrative Payback Times in Years for CNG Light-Duty Vehicles for Average and 

High Mileage Use, Low and High Incremental Vehicle Cost and Fuel Price Spread between 

Gasoline and CNG on a Gallon of Gasoline Equivalent (gge) Basis. Assumes 30 miles 

per gallon. 

12,000 mile per year 35,000 miles per year

Fuel 

Price 

Spread

Incremental Cost $3,000 $10,000 $3,000 $10,000 

$0.50/gge 15 50 5.2 17

$1.50/gge 5 17 1.8 5.9

3OURCE -)4%)
Chapter 5: Demand 123

4ABLE  ILLUSTRATES THE EFFECTS OF VARIOUS FACTORS

ON PAYBACK TIME FOR LIGHT
DUTY VEHICLES 4HE

FUEL PRICE SPREAD OF GGE SHOWN IN THE

TABLE WOULD BE ASSOCIATED WITH A GALLON

PUMP PRICE FOR GASOLINE AND RESIDENTIAL GAS AT

THE CONSUMER LEVEL OF --"TU 0AYBACK

TIME IS THE INCREMENTAL COST DIVIDED BY THE

YEARLY FUEL COST SAVINGS 3TUDIES HAVE SHOWN THAT

PAYBACK TIMES OF AROUND THREE YEARS OR LESS ARE

NEEDED FOR SUBSTANTIAL MARKET PENETRATION

&OR THE REPRESENTATIVE HIGH
MILEAGE USE CASE

OF  MILESYEAR A THREE
YEAR PAYBACK TIME

COULD BE OBTAINED WITH A 53 PRICE SPREAD OF

GGE AND AN INCREMENTAL VEHICLE COST OF

AROUND 

&OR PRESENT #.' VEHICLE COSTS AND 53 FUEL

PRICE SPREADS THE PAYBACK TIMES ARE GENERALLY

UNATTRACTIVE FOR THE AVERAGE MILEAGE USE 

MILESYEAR	 MARKET SEGMENT FOR LIGHT
DUTY

VEHICLES THIS MARKET SEGMENT REPRESENTS OVER

 OF LIGHT
DUTY VEHICLE FUEL USE 2EDUCTION

OF THE INCREMENTAL COST TO BELOW  ALONG

WITH GGE FUEL PRICE SPREAD WOULD BE

NEEDED FOR A THREE
YEAR PAYBACK TIME 4HE

RATE OF PENETRATION OF AVERAGE MILEAGE #.'

VEHICLES EVEN IF ECONOMIC WILL DEPEND ON

THE PROVISION OF AN ADEQUATE PUBLIC REFUELING

INFRASTRUCTURE THOUGH HOME REFUELING OF #.'

VEHICLES COULD AUGMENT PUBLIC FACILITIES

4ABLE  DOES NOT INCLUDE THE EFFECT OF A PENALTY

ON CARBON EMISSIONS OR A SUBSIDY &OR THE ILLUSTRATIVE CASE IN THE TABLE THE USE OF #.' RATHER THAN

GASOLINE REDUCES #/2 EMISSIONS AT THE VEHICLE BY

ABOUT  TONYEAR FOR THE AVERAGE MILEAGE

 MILESYEAR	 LIGHT
DUTY VEHICLE %VEN

FOR A #/2 PRICE AS HIGH AS TON THE IMPACT

ON PAYBACK TIME IS SMALL

)F THE GASOLINE
#.' PRICE SPREAD WERE TO

INCREASE BEYOND THE PRESENT LEVEL THE PAYBACK

TIME FOR THE AVERAGE MILEAGE #.' VEHICLE COULD

DECLINE AND SUPPORT GREATER PENETRATION IN THIS

LARGE MARKET SEGMENT ! SIGNIlCANT INCREASE IN

THE SPREAD COULD OCCUR EITHER THROUGH AN

INCREASED OIL
NATURAL GAS PRICE SPREAD A VERY

HIGH #/2 PRICE ANDOR AVAILABILITY OF NATURAL

GAS FOR #.' VEHICLES AT LOWER THAN RESIDENTIAL

RATES 5SING OPTIMISTIC COST ESTIMATES FOR #.'

VEHICLES THE CARBON POLICY SCENARIO EXPLORED IN

#HAPTER  PROJECTS A  PENETRATION INTO THE

PRIVATE VEHICLE mEET BY  TO  2ECENTLY

ENACTED STATE LOW
CARBON FUEL STANDARDS

EG #ALIFORNIA	 MIGHT PROVIDE ADDITIONAL

MOTIVATION FOR THE MARKET PENETRATION

OF .'6S

%VOLUTIONARY TECHNOLOGY COULD INCREASE THE

FUEL EFlCIENCY OF BI
FUEL ENGINES BY  TO

 PROVIDING AN EFlCIENCY LEVEL COMPARABLE

TO A DIESEL ENGINE  4HIS COULD INCREASE THE

value of natural gas in reducing oil dependence 

AND '(' GENERATION (IGHER EFlCIENCY NATURAL

GAS
POWERED SPARK
IGNITION ENGINES ALSO HAVE

THE POTENTIAL TO REDUCE THE COST AND INCREASE THE

POWER OF ,.'
POWERED TRUCKS

RECOMMENDATION

The U.S. should consider revision to its 

current policies related to CNG vehicles, 

including how aftermarket CNG conversions 

are certified, with a view to reducing 

upfront costs and facilitating bi-fuel CNGgasoline capability.

LNG-Powered Long-Haul Trucks

,.' IS BEING PURSUED AS A FUEL FOR TRUCK

APPLICATIONS PARTICULARLY LONG
HAUL TRUCKING

BECAUSE FOR A GIVEN TANK SIZE IT CAN PROVIDE A

RANGE OF CLOSE TO TWO AND HALF TIMES THAT OF

#.' AND AROUND  OF THAT OF DIESEL FUEL

/N VEHICLE ,.' IS STORED AT VERY LOW TEMPERATURE 
#	 IN A DOUBLE
WALLED TANK WITH A

VACUUM BETWEEN THE WALLS TO PROVIDE THERMAL

INSULATION /VER TIME THE ,.' WARMS THE

METHANE GAS BOILS AND EVENTUALLY A PRESSURE

RELIEF VALVE MUST BE OPENED IF THE TANK IS NOT

RElLLED WITHIN A RELATIVELY LIMITED PERIOD OF

TIME ABOUT A WEEK	 4HIS FEATURE CONSTRAINS

THE USE OF ,.' TO VEHICLES THAT HAVE REGULAR
124 MIT STUDY ON THE FUTURE OF NATURAL GAS

FREQUENT RElLLS ,.' IS IN LIMITED USE IN THE

53 IN DRAYAGE TRUCKS IN THE PORTS OF ,ONG

"EACH AND ,OS !NGELES AND IN GARBAGE TRUCKS

IN SEVERAL CITIES

4HE '(' ADVANTAGE OF ,.' IS LOWER THAN

#.' BECAUSE OF THE ENERGY LOSS IN LIQUEFACTION

AND METHANE EMISSIONS IN FUELING AND OPERATION ! REPRESENTATIVE '(' EMISSION REDUCTION

RELATIVE TO DIESEL FOR THE SAME ENGINE EFlCIENCY

IS  TO  !S WITH THE #.'
GASOLINE

COMPARISON NOTED EARLIER IN THE CHAPTER THIS

MODEST '(' ADVANTAGE WOULD BE SUBSTANTIALLY

REDUCED OR POSSIBLY ELIMINATED IF STATED ON A

LIFE
CYCLE BASIS INCLUDING THE FUGITIVE EMISSIONS

OF METHANE IN PRODUCTION AND DISTRIBUTION /F

COURSE THE OIL DISPLACEMENT BENElTS REMAIN

4HE CURRENT INCREMENTAL COST OF AN ,.'

LONG
HAUL TRUCK IS AROUND  %VEN IF THE

PAYBACK TIME IS ACCEPTABLE IT IS ABOUT FOUR

YEARS AT LATE  NATURAL GAS AND OIL PRICES	

THIS HIGH INCREMENTAL COST CAN BE AN IMPEDIMENT TO MARKET PENETRATION !N ADDITIONAL

FACTOR IS THAT THE RESALE VALUE PARTICULARLY IN THE

INTERNATIONAL MARKET WHERE MANY USED TRUCKS

ARE SOLD IS LIKELY TO BE SUBSTANTIALLY REDUCED

!NOTHER CHALLENGE MAY BE ASSURING THAT RELIABILITY WILL NOT BE ADVERSELY AFFECTED BY OPERAtional issues related to cryogenic fuel storage in 

A TANK WITH VACUUM THERMAL INSULATION MANUFACTURING ISSUES A COLLISION OR EXTENDED USE MAY

REDUCE THE ABILITY OF THE TANK TO STORE ,.'

CRYOGENICALLY	 )F THE INTEGRITY OF THE VACUUM IS

COMPROMISED AND ,.' WARMS METHANE GAS

BOILS OFF INCREASING PRESSURE IN THE TANK 4HE

RELIEF VALVE IS USED TO VENT THE BOILED
OFF

METHANE AND COOL THE REMAINING METHANE !

FURTHER CHALLENGE IS THE NEED FOR A NEW FUELING

INFRASTRUCTURE THAT IS MORE EXPENSIVE AND

COMPLEX THAN THE DIESEL FUELING INFRASTRUCTURE

4HE !MERICAN 4RUCKING !SSOCIATION REPRESENTING CONCERNS OF THE USER COMMUNITY HAS STATED

THAT NATURAL GAS
POWERED TRUCKS ARE CURRENTLY

NOT A VIABLE SOLUTION FOR MOST LONG
HAUL

TRUCKING OPERATIONS FOR THESE TECHNICAL REASONS

AND BECAUSE OF THE CONCERN THAT THE HIGH COST OF

,.' FUELING INFRASTRUCTURE WILL LIMIT COMPETITION IN THE ON
ROAD ,.' FUEL SUPPLY LNGPOWERED TRUCKS MAY ALSO FACE COMPETITION FROM

OTHER ALTERNATIVES TO DIESEL FUEL SUCH AS METHANOL AS DISCUSSED IN THE NEXT SECTION

)NDUSTRY IS WORKING ON REDUCING THE INCREMENTAL COST AND IMPROVING OPERATIONAL FEATURES

RELATED TO THE USE OF A CRYOGENICALLY STORED FUEL

)T IS LIKELY THAT A SIGNIlCANT COST REDUCTION CAN

BE MADE PARTICULARLY IN THE COST OF THE ENGINE

)N ADDITION USE OF ,.'
POWERED LONG
HAUL

TRUCKS IS SIGNIlCANTLY LESS CHALLENGING IN THE

GROWING AREA OF TRANSPORTING GOODS BETWEEN

COMPANY
OWNED HUBS 4HESE HUBS COULD HAVE

THEIR OWN ,.' FUELING STATIONS 4HIS IS A

MODEST MARKET SEGMENT WHICH PRESENTLY

ACCOUNTS FOR LESS THAN  OF LONG
HAUL DIESEL

FUEL CONSUMPTION )T HAS A MARKET POTENTIAL

 MARKET PENETRATION	 OF LESS THAN  4CF

PER YEAR 7ITH INCREASED USE OF HUBS IN LONG


DISTANCE TRUCKING AND REDUCED RANGE REQUIREMENTS THERE MAY BE OPPORTUNITIES FOR USE OF

#.' AS WELL AS ,.' 4HESE OPPORTUNITIES

COULD BE ENHANCED BY BI
FUEL CAPABILITY WITH

GASOLINE AS A RANGE EXTENDER

FINDING

The deployment of LNG-powered, longhaul trucks presently faces operational 

limitations due to the use of onboard fuel 

storage at very low temperature (-162 C ̊); 

the need for a new fueling infrastructure 

that ensures competitive pricing; a high 

incremental cost; and a likely lower 

resale value particularly in the important 

international market. These challenges are 

mitigated by use in the relatively modest 

market of hub-to-hub transport.
Chapter 5: Demand 125

Conversion to Liquid Fuels

!NOTHER ROUTE FOR NATURAL GAS PENETRATION INTO

TRANSPORTATION MARKETS COULD BE THROUGH

CONVERSION INTO A ROOM TEMPERATURE	 LIQUID

FUEL THAT COULD BE BLENDED WITH OR REPLACE	

CURRENT LIQUID FUELS DIESEL GASOLINE AND

ETHANOL	 !S ILLUSTRATED IN &IGURE  A RANGE OF

LIQUID FUELS CAN BE PRODUCED FROM NATURAL GAS

BY THERMOCHEMICAL CONVERSION TO A SYNTHESIS

GAS FOLLOWED BY CATALYTIC CONVERSION TO THE LIQUID

FUEL 4HESE FUELS INCLUDE METHANOL ETHANOL

MIXED ALCOHOLS METHANOL ETHANOL AND OTHERS	

AND DIESEL -ETHANOL CAN IN TURN BE CONVERTED

INTO GASOLINE OR INTO DIMETHYL ETHER $-%	 A

CLEAN
BURNING FUEL FOR DIESEL ENGINES

4HE CHOICES AMONG THESE MULTIPLE PATHWAYS TO

liquid fuels depend on several criteria involving 

ENGINE REQUIREMENTS AND FUELING INFRASTRUCTURE

$IESEL AND GASOLINE ARE DROP
IN FUELS WITH

REGARD TO CURRENT ENGINE TECHNOLOGY AND FUELING

INFRASTRUCTURE BUT REQUIRE MORE PROCESSING

FROM NATURAL GAS FEEDSTOCK THAN OTHER ROUTES

SUCH AS METHANOL PRODUCTION MAKING THE

CONVERSION LESS EFlCIENT AND MORE COSTLY

-ETHANOL IS LESS COSTLY FOR CONVERSION BUT

REQUIRES MODEST CHANGES TO ENGINES IT IS

MORE CORROSIVE THAN GASOLINE	 AND THE FUELING INFRASTRUCTURE METHANOL AND ETHANOL ARE

HYDROSCOPIC	 THAT HAS BEEN DEVELOPED FOR A

PETROLEUM
BASED SYSTEM $-% REQUIRES MODERATE PRESSURE FOR STORAGE AS A LIQUID SIMILAR

TO PROPANE	 /VERALL SYSTEM OPTIMIZATIONS ARE

NEEDED TO GUIDE CHOICES

Our detailed analysis is for natural gas converSION TO METHANOL 4HERE IS CONSIDERABLE EXPERIENCE FOR BOTH CONVERSION TO METHANOL AND FOR

USE OF METHANOL IN VEHICLES INCLUDING HIGH


PERFORMANCE )NDY  CARS	 4HE EFlCIENCY OF

CONVERSION OF NATURAL GAS INTO METHANOL MIXED

ALCOHOLS AND $-% IS CONSIDERABLY HIGHER THAN

THAT FOR THE CONVERSION OF NATURAL GAS INTO DIESEL

AND GASOLINE

!MONG THE PROCESSES SHOWN IN &IGURE  THE

ONE THAT HAS BEEN OPERATED AT LARGE INDUSTRIAL

SCALE OVER A LONG PERIOD WITH WELL
ESTABLISHED

COSTS IS METHANE
TO
METHANOL CONVERSION

MAINLY AS A FEEDSTOCK FOR CHEMICAL PRODUCTION39 -ETHANOL IS AN ALCOHOL THAT CAN BE USED

LIKE ETHANOL IN MIXTURES WITH GASOLINE IN SPARK


IGNITION ENGINES AND CAN BE EMPLOYED IN HEAVY


DUTY AS WELL AS LIGHT
DUTY VEHICLES 7ITH THE

energy loss during conversion of natural gas to 

METHANOL TAKEN INTO ACCOUNT THE WELL
TO
WHEELS

#/2 EMISSIONS FROM USING NATURAL GAS DERIVED

METHANOL IS SLIGHTLY LOWER THAN GASOLINE

'(' EMISSIONS COULD BE SOMEWHAT HIGHER THAN

GASOLINE IF METHANE EMISSIONS ARE INCLUDED 4HE

production cost of natural gas conversion to 

DIESEL FUEL IS PROJECTED TO BE AROUND  HIGHER

THAN METHANOL ON AN ENERGY
EQUIVALENT BASIS

)N ADDITION '(' EMISSIONS WOULD BE INCREASED

BY MORE THAN  RELATIVE TO NATURAL GAS DERIVED

METHANOL

Figure 5.9 Conversion of Natural Gas to Liquid Fuels 

3OURCE -)4%)

Natural Gas Reformer Synthesis Gas

Diesel

Ethanol

Mixed Alcohols

Methanol

DME

Gasoline

Natural Gas to Liquid Fuels

Catalyst
126 MIT STUDY ON THE FUTURE OF NATURAL GAS

-ETHANOL USED IN THE 53 IS MAINLY IMPORTED

FROM THE #ARIBBEAN AND 3OUTH !MERICA AT

COMPARABLE PRICES OVER THE PERIOD  TO 

TO GASOLINE ON AN ENERGY
EQUIVALENT BASIS

7ITH DEPLOYMENT OF NEW PLANTS USING EXISTING

TECHNOLOGY METHANOL COULD BE PRODUCED FROM

53 NATURAL GAS AT A COST LESS THAN 53 GASOLINE

PRICE IN  OF AROUND GALLON EXCLUDING

THE TAX	 4ABLE  SHOWS AN ILLUSTRATIVE PROJECTION OF METHANOL PRODUCTION COSTS )T IS BASED

ON A  ENERGY CONVERSION EFlCIENCY OF

NATURAL GAS INTO METHANOL AND A CONTRIBUTION

OF AMORTIZED CAPITAL AND OPERATING COSTS OF

GGE OF METHANOL PRODUCTION  5NDER

THESE ASSUMPTIONS THE SPREAD BETWEEN GASOLINE

PRICE AND METHANOL COST IS AROUND GGE 4HE

COST ADVANTAGE OF METHANOL AT THE FUELING

STATION IS REDUCED BY AROUND GGE DUE TO

HIGHER COST PER UNIT ENERGY OF TRANSPORTING

METHANOL TO FUELING STATIONS 4HE PRODUCTION

COST OF METHANOL AT THIS ASSUMED NATURAL GAS

PRICE WOULD BE LOWER THAN THE COST OF CORN


BASED ETHANOL BY MORE THAN GGE

FINDING

With deployment of plants using current 

technology, on an energy-equivalent basis, 

methanol could be produced from U.S. 

natural gas at a lower cost than gasoline 

at current oil prices. 

-ETHANOL CAN BE USED IN SPARK
IGNITION ENGINES

WITH VERY LOW EMISSIONS OF ./X AND OTHER

POLLUTANTS THROUGH USE OF STATE
OF
THE
ART

THREE
WAY CATALYTIC CONVERTERS )T HAS A HIGH


OCTANE NUMBER THAT ENABLES HIGH
EFlCIENCY

ENGINE OPERATION -ETHANOL HAS THE DISADVANTAGE OF BEING ABLE TO PROVIDE ONLY AROUND HALF

OF THE RANGE OF GASOLINE FOR A GIVEN TANK SIZE

WHICH WOULD BE MITIGATED BY METHANOL


GASOLINE MIXTURES

-ETHANOL USE WAS DEMONSTRATED IN THE 53 IN

THE EARLY S IN SOME  VEHICLES

)NTEREST WANED IN THE MID
S HOWEVER DUE

TO FALLING OIL PRICES AND THE ASCENDENCY OF

ETHANOL IN LOW
CONCENTRATION BLENDS DRIVEN BY

STRONG POLITICAL SUPPORT FROM THE FARM STATES

)N ADDITION AVERSION TO METHANOL MAY HAVE

DEVELOPED FROM ITS ASSOCIATION WITH -4"%

-ETHYL 4ERTIARY "UTYL %THER	 AN ADDITIVE TO

GASOLINE THAT CONTAMINATED GROUND WATER FROM

LEAKS IN UNDERGROUND TANKS AND THAT UNLIKE

METHANOL PRODUCED AN UNPLEASANT TASTE IN

WATER AT VERY LOW CONCENTRATIONS 4HE TOXICITY

OF METHANOL IS SIMILAR TO GASOLINE -ETHANOL IS

SOLUBLE IN WATER AND IS BIODEGRADABLE

-ETHANOL COULD BE USED IN TRI
mEXIBLE
FUEL

LIGHT
DUTY AND HEAVY
DUTY	 VEHICLES IN A

MANNER SIMILAR TO PRESENT ETHANOL
GASOLINE

mEX FUEL VEHICLES WITH MODEST INCREMENTAL

VEHICLE COST 4HESE TRI
mEX
FUEL VEHICLES COULD

BE OPERATED ON A WIDE RANGE OF MIXTURES OF

METHANOL ETHANOL AND GASOLINE &OR LONG


DISTANCE DRIVING GASOLINE COULD BE USED IN THE

mEX
FUEL ENGINE TO MAXIMIZE RANGE 0RESENT

ETHANOL
GASOLINE mEX
FUEL VEHICLES IN THE 53

ARE SOLD AT THE SAME PRICE AS THEIR GASOLINE

COUNTERPARTS !DDING METHANOL CAPABILITY TO

Table 5.5 Illustrative Methanol Production Costs, Relative to Gasoline (excluding taxes) 

at $2.30 per Gallon 

3OURCE -)4%)

Natural Gas Price Methanol Production 

Cost, per gge

Cost Reduction Relative 

to Gasoline, per gge

$4/MMBtu $1.30 $1.00

$6/MMBtu $1.60 $0.70

$8/MMBtu $2.00 $0.30
Chapter 5: Demand 127

A FACTORY  ETHANOL BLEND %	 VEHICLE TO

CREATE TRI
mEX FUEL CAPABILITY WOULD REQUIRE AN

AIRFUEL MIXTURE CONTROL TO ACCOMMODATE AN

EXPANDED FUELAIR RANGE WITH ADDITION OF AN

ALCOHOL SENSOR AND WOULD RESULT IN AN EXTRA COST

OF  TO  MOST LIKELY AT THE LOWER END OF

THAT RANGE WITH SUFlCIENT PRODUCTION

FINDING

Methanol could be used in tri-flex-fuel lightduty vehicles with a modest incremental 

vehicle cost (likely to be $100 to $200 more 

than an ethanol-gasoline flex-fuel vehicle). 

It could also be used to power long-haul 

trucks in mixtures with gasoline, and could 

provide both vehicle and fuel cost savings. 

Barriers to methanol use include the lack 

of incentives for vehicle conversion and 

provision of distribution infrastructure.

0RESENTLY NO FACTORY
PRODUCED mEX
FUEL

VEHICLES IN THE 53 ARE EQUIPPED FOR mEX
FUEL

OPERATION WITH METHANOL 2EMOVING THIS

BARRIER THROUGH THE ADOPTION OF AN OPEN FUEL

STANDARD IS A KEY REQUIREMENT FOR METHANOL USE

TO BE PURSUED ON A LEVEL PLAYING lELD /PEN FUEL

STANDARD LEGISLATION THAT HAS BEEN UNDER

CONSIDERATION WOULD REQUIRE AUTOMOBILE

MANUFACTURERS TO PRODUCE AN INCREASING

NUMBER OF VEHICLES THAT COULD OPERATE ON A MIX

OF THE THREE FUELS 2EQUIRING THIS mEX
FUEL

CAPABILITY COULD BE A COST
EFFECTIVE WAY TO LEVEL

THE PLAYING lELD FOR LIQUID FUELS

and increase opportunities for reducing oil 

DEPENDENCE

RECOMMENDATION

The U.S. government should implement 

an open fuel standard that requires 

automobile manufacturers to provide 

tri-flex-fuel operation in light-duty vehicles. 

It should also consider methanol fueling 

infrastructure subsidies similar to those 

given to the fueling infrastructure for 

ethanol.

-ETHANOL CAN BE USED AS A FUEL FOR HEAVY
DUTY

VEHICLES IN A RANGE OF MIXTURES WITH GASOLINE

5SE OF METHANOL AS AN ALTERNATIVE TO DIESEL FOR

HEAVY
DUTY VEHICLES IS NOW POSSIBLE BY USE OF

TURBOCHARGED SPARK
IGNITION ENGINES OPERATING

AT HIGH COMPRESSION RATIO AND HIGH LEVELS OF

TURBO PRESSURE BOOSTING 4HESE ENGINES CAN

PROVIDE COMPARABLE OR POSSIBLY BETTER EFlCIENCY

THAN DIESEL ENGINES ALONG WITH COMPARABLE OR

GREATER TORQUE AT LOWER VEHICLE COST AND WITH

LOWER EMISSIONS AND MORE POWER An illusTRATIVE COMPARISON FOR A METHANOL
GASOLINE

MIXTURE OF  METHANOL VS DIESEL FOR A

LONG
HAUL TRUCK SUGGESTS A VEHICLE COST SAVING OF

MORE THAN  FROM LESS EXPENSIVE EXHAUST

TREATMENT AND A LESS COSTLY FUEL
INJECTION SYSTEM	

AND A FUEL SAVING OF SOME YEAR

5SE OF METHANOL AS A TRANSPORTATION FUEL FACES

A NUMBER OF CHALLENGES 4HEY INCLUDE THE

lNANCIAL RISK FOR PRIVATE INVESTMENT IN 53

METHANOL PRODUCTION PLANTS THE DEMAND FOR

METHANOL AS A TRANSPORTATION FUEL COULD BE

REDUCED BY A DECLINE IN OIL PRICES AND DOMESTIC

NATURAL GAS PRICES ARE VOLATILE )N ADDITION

INCENTIVES ARE LACKING FOR BUILDING METHANOL

CAPABILITY INTO VEHICLES AND INCURRING THE COSTS

OF ADDITIONAL INFRASTRUCTURE SUCH AS PUMPS IN

FUELING STATIONS )T IS LIKELY THAT SOME FORM OF

GOVERNMENT ASSISTANCE WOULD BE NECESSARY TO

FACILITATE THIS OPTION AT LARGE SCALE
128 MIT STUDY ON THE FUTURE OF NATURAL GAS

)N SUMMARY WHILE USE OF METHANOL AS A

TRANSPORTATION FUEL HAS SUBSTANTIAL COST AND

'(' ADVANTAGES RELATIVE TO OTHER NATURAL GAS

DERIVED LIQUID FUELS IT REQUIRES SOME INFRA


STRUCTURE MODIlCATION AND FACES SUBSTANTIAL

ACCEPTANCE BARRIERS !T SUFlCIENTLY HIGH OIL

PRICES THE DROP
IN FUEL AND ACCEPTANCE ADVANTAGES OF NATURAL GAS DERIVED GASOLINE MAY MAKE

IT A BETTER CANDIDATE THAN METHANOL .ATURAL

GAS DERIVED DIESEL COULD ALSO BECOME

ECONOMICALLY ATTRACTIVE

FINDING

If the present oil to natural gas price 

spread is sustained, there will be materially 

increased opportunities for use of natural 

gas-based transportation fuels.

FINDING

The potential for natural gas to reduce 

oil dependence could be increased by 

conversion into room temperature liquid 

fuels that can be stored at atmospheric 

pressure. Of these fuels, methanol is the 

only one that has been produced for a long 

period at large industrial scale. Methanol 

has the lowest cost and lowest GHG

emissions, but requires some infrastructure 

modification and faces substantial 

acceptance challenges. Natural gas derived 

gasoline and diesel have the advantage 

of being drop-in fuels, but carry a higher 

conversion cost.

RECOMMENDATION

The U.S. government should carry out a 

transparent comparative study of natural 

gas derived diesel, gasoline and methanol, 

and possibly natural gas derived ethanol, 

mixed alcohol and DME, with each other 

and with oil-derived fuels and biofuels. The 

study should include cost analysis, vehicle 

requirements, infrastructure requirements 

and health and environmental issues. It also 

should include discussion of R&D needs for 

more efficient and lower-cost production. 
Chapter 5: Demand 129

NOTES



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4RANSPORTATION &UELv -3 4HESIS -)4 *UNE 
130 MIT STUDY ON THE FUTURE OF NATURAL GAS

334HERE IS LARGE RANGE OF UNCERTAINTY OF THE EFFECT OF

METHANE EMISSIONS 7ITHIN THIS RANGE OF

UNCERTAINTY THE '(' REDUCTION ADVANTAGE OF #.'

RELATIVE TO GASOLINE COULD BE REDUCED FROM  TO

AROUND 

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TO TRANSPORTATION FUEL TAXES )F CURRENT TAXES WERE

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ASSUMPTIONS WOULD LEAD TO ABOUT A GGE

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WITH WATER WITH CONCENTRATIONS AS HIGH AS 

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DIESEL PRICE SPREAD

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EFlCIENCY - IS  METHANOL AND  GASOLINE

BY VOLUME AND HAS A RANGE OF AROUND X THE

RANGE OF DIESEL FOR A GIVEN FUEL TANK SIZE
Chapter 6: Infrastructure 131

Chapter 6: Infrastructure

In the United States, the availability, reliability 

and price of natural gas are inextricably linked 

to its production and delivery infrastructure. 

As seen in Figure 6.1, major components of the 

system include inter-state and intra-state transmission pipelines, storage facilities, liquefied 

natural gas (LNG) regasification terminals and 

gas processing units, all of which establish the 

link between gas producers and consumers. 

This system is both mature and robust. 

This chapter will describe and discuss:

s 4RENDS WITH IMPLICATIONS FOR THE 53 NATURAL

gas infrastructure; 

s 4HE COMPONENTS AND SUB
SECTORS COMPRISING

the natural gas infrastructure, with a focus on 

pipelines, LNG import terminals, processing 

and storage; 

s .EW AND PROPOSED ENVIRONMENTAL REGULATIONS

affecting the natural gas infrastructure; and

s 3PECIlC GAS INFRASTRUCTURE ISSUES ASSOCIATED

with the development of the Marcellus shale. 

Figure 6.1 Schematic of the U.S. Natural Gas Infrastructure

Image modified from CHK
132 MIT STUDY ON THE FUTURE OF NATURAL GAS

TRENDS AFFECTING U.S. NATURAL GAS 

INFRASTRUCTURE 

Several trends are altering the landscape of U.S. 

gas markets with implications for infrastructure 

needs and requirements. These include: changing production profiles; shifts in demand/

consumption patterns; and the growth of 

LNG markets.

Changing Production Profiles

As described in Chapter 2, production from 

large onshore shale basins is shifting the focus 

of U.S. production from the Central and 

Western Gulf of Mexico (GOM), where it has 

been for the last two decades, back to onshore 

regions. While GOM production declined by 

42% between 2004 and 2008, onshore production in the lower 48 states (L-48) increased by 

22% over the same time period.1

Areas with the most marked production 

increases include the relatively immature Rocky 

Mountains, where production increased 103% 

between 1998 and 2007; and parts of Eastern 

Texas, where production increased by 177% 

over the same time period. This shift is 

expected to be more pronounced as production 

increases from the Marcellus shale, concentrated in New York and Pennsylvania, with 

additional production potential in Ohio and 

West Virginia.

Shifts in Demand Patterns

There has also been a shift in U.S. gas demand 

patterns over the last decades, associated in part 

with relative population shifts to the South and 

West from the Northeast and Midwest, the two 

regions in the country where population as a 

percent of total U.S. population has declined. 

Population growth has been especially pronounced in the Western U.S., where the population increased by 42% between 1980 and 2008. 

This growth, coupled with stricter air quality 

regulations, has led to increased demand for gas 

in the West, where gas consumption has 

outpaced population growth, increasing by 

68% in the last three decades. In the Northeast, 

environmental concerns and a shift away from 

oil in power generation and home heating has 

led to increased gas consumption; between 

1980 and 2008 the population in the Northeast 

U.S. increased by 19% but gas consumption 

increased by 50%.2

These demand increases, largely for residential, 

commercial and electricity uses, have been 

accompanied by a reduction in demand from 

industrial customers; this is illustrated by the 

relative decline in gas consumption in the 

Southwest U.S., largely Texas, the only region of 

the country where gas consumption in absolute 

terms and as a percentage of the U.S. total 

actually dropped. This 15% decline in consumption over the last three decades can be attributed 

in part to high natural gas prices over the last 

several years which drove refineries, and ammonia and other chemical plants offshore.3

The U.S. and LNG Markets

Growing gas demand and significant differences in gas prices between global regions has 

increased the desirability of a global gas market. 

As seen in Chapter 3, gas prices are significantly 

lower under an Emissions Prediction and Policy 

Analysis (EPPA) scenario where there is a 

relatively unconstrained global market in natural 

gas compared to the current regionalized 

market. While the U.S. represents around 24% 

of global gas consumption, its engagement in 

the development of a global LNG market is 

tempered by dramatic increases in the U.S. 

producible gas resource base, largely enabled by 

the affordable production of new unconventional gas resources. 
Chapter 6: Infrastructure 133

Currently, the U.S. permits proprietary access 

to LNG suppliers for new regasification terminals; this would allow the developer of a 

regasification facility to give preference to the 

import of its own LNG or the LNG of its 

affiliates at that point of entry.4

 This policy 

decision was made to incentivize construction 

of substantial import infrastructure in the U.S. 

creating opportunites for increased global 

LNG trade. 

GHG EMISSIONS FROM THE NATURAL GAS 

INFRASTRUCTURE

Natural gas is the cleanest burning fossil fuel, 

enhancing its desirability as a fuel option in a 

carbon-constrained environment. As a fossil 

fuel, however, natural gas also emits greenhouse 

gases (GHG), including CO2

 emissions from 

gas combustion and CO2

 and methane emissions from the gas system, including production, processing, transmission and distribution.

According to EPA inventories released in 2010, 

in 2008 GHG emissions from natural gas 

systems were 126 teragrams (one teragram is 

equivalent to one million metric tons) of CO2

equivalents (CO2

e), less than 2% of total CO2

equivalent emissions from energy sources and 

activities. Of this total, 96 teragrams of CO2

e 

were CH4

 emissions; the remainder are from 

non-combustion CO2

. The draft EPA inventory, 

released in late February 2011, doubled the 

EPA’s estimates of methane emissions from gas 

systems for 2008. A breakout of EPA’s estimated 

emissions from gas systems is seen in Figure 6.2 

(from EPA’s revised draft inventory estimates 

also discussed in Appendix 1A). 

Methane leaks from gas systems, particularly 

at the levels indicated by the new EPA estimates, 

could prompt efforts to capture those emissions 

for both environmental and business reasons. 

Reducing emissions from well completions 

can, for example, create value for producers 

and can have a very short payback period 

(3 to 8 months).5

 While many larger producers 

and pipelines have already deployed relatively 

inexpensive methane detection and capture 

technologies and are able to realize profits from 

use of these technologies, smaller producers 

may need new, more affordable technologies 

to detect and capture methane emissions. 

The EPA has also issued a final rule on mandatory reporting of GHG emissions from natural 

gas systems, after the Supreme Court determined the EPA could regulate GHGs as air 

Field 

Production

134.2

Transmission 

and Storage 

43.4

Processing

37.1

Distribution

29.9

Figure 6.2 Estimated CO2e Emissions from Natural Gas Systems

Source: EPA Draft GHG Emissions 
134 MIT STUDY ON THE FUTURE OF NATURAL GAS

pollutants and the EPA issued an endangerment 

rule in 2010, indicating that GHGs posed a 

threat to public health and welfare. This rule 

would require reporting from well pad equipment both onshore and offshore, gas processing, pipelines, city gates, LNG import and 

export facilities, underground storage and 

compressor stations. The rule covers annual 

reporting of CO2

, methane, and nitrous oxide 

emissions from facilities emitting 25,000 metric 

tons of CO2

e per year or more. The EPA 

estimates the cost to the industry of implementing the rule to be $61 million for natural 

gas and oil systems (the EPA does not separate 

gas from oil) and $20 million a year in subsequent years in 2006 dollars. 

The EPA has deferred direct emitter identification until confidentiality issues can be resolved. 

All other elements of the rule are now in effect.6

The EPA estimates that this will affect around 

2,800 facilities. The EPA is careful to point out 

that the 25,000 metric ton limit will exclude 

small businesses from the requirements of the 

rule. It is unclear how many small producers 

would be exempt by the emissions limit. 

Although the EPA recently postponed deadlines 

for mandatory emissions reporting, the ultimate 

regulation of GHGs by the EPA implied in the 

promulgation of this rule could have major 

impacts on gas system operations, particularly 

on production, transmission and storage, if the 

estimates in Figure 6.2 are reasonably accurate. 

EPA recently extended the deadline for application of best available monitoring methods for 

gas systems.

COMPONENTS OF THE NATURAL GAS 

INFRASTRUCTURE 

To move gas from production to demand 

centers over the next 20 years, it is estimated by 

the Interstate Natural Gas Association of 

American (INGAA) that the U.S. and Canada 

will need approximately 28,900 to 61,900 miles 

of additional transmission and distribution 

natural gas pipelines depending on assumptions for gas demand — its base case identifies 

almost 38,000 miles of pipelines with the 

regional distribution depicted in Figure 6.3.7

INGAA also projects a need for 371 to 598 

billion cubic feet (Bcf) of additional storage 

capacity, a 15% to 20% increase over current 

levels and consistent with the rate of additions 

between 2005 and 2008.8

Canada, 4.7

Southwest, 8.6

Central, 8.4 Midwest, 3.3

West, 2.2

Northeast, 2.7

Arctic, 1.0

Southeast, 4.6

O!shore, 2.2

Figure 6.3 U.S./Canada Pipeline Capacity Additions, 2009–2030 (in 1,000 of miles)

Source: INGAA, 2009 
Chapter 6: Infrastructure 135

There will also be additional requirements for 

gas processing, especially in light of the changes 

in production patterns in the U.S. Investment 

requirements by sector for gas infrastructure 

between now and 2030 are summarized in 

Table 6.1.9

 Note that these figures assume 

success in bringing arctic gas to the L-48 from 

Alaska and the Mackenzie delta; the Alaska gas 

pipeline has remained illusory for the last two 

decades and its realization remains uncertain. 

There are several federal and state agencies 

involved in siting gas pipelines and other gas 

infrastructure. The Federal Energy Regulatory 

Commission (FERC) regulates interstate pipeline construction while states regulate intra-state 

pipeline construction. Other federal agencies 

play significant roles in construction permitting, 

including the EPA, the Fish and Wildlife Service, 

and the Office of Pipeline Safety (OPS) at the 

Department of Transportation (DOT); the 

OPS regulates the safety of pipeline operations 

over the infrastructure’s lifespan, starting with 

up-front safety certifications for permitting by 

FERC. The EPA ensures that a pipeline development project meets federal environmental 

guidelines. The Coast Guard and Maritime 

Administration (MARAD) at the Department 

of Homeland Security have responsibility for 

offshore LNG facilities. In addition to these 

federal agencies, there is a range of state entities 

involved in the permitting process. 

The long lead times required to site and build 

gas infrastructure, driven in part by these 

complex regulatory decision-making structures 

for gas infrastructure siting, not only add to the 

cost, but mean that many of the additions and 

expansions we are seeing today were originally 

contemplated as much as a decade ago. This 

highlights the ongoing tension between the 

needs of policy makers and regulators for more 

accurate data and information on supply and 

demand trends and patterns, the associated 

infrastructure needs, and the status of technology development; and the inherent uncertainties and risks that accompany investment in 

natural gas infrastructure across the supply 

chain. 

Table 6.1 Total Expected Gas Pipeline, Midstream and LNG Expenditures, 2009–2030 

(billions $)

Source: INGAA, 2009

Region Transmission Storage Gathering Processing LNG Total %

Canada 33.0 0.4 1.2 1.0 - 35.5 17

Arctic 24 - 1.0 3.5 - 25.5 14

Southwest 27.6 1.3 4.2 7.5 0.4 41.1 20

Central 24.8 0.2 0.7 4.8 - 30.5 15

Southeast 15.4 1.4 0.4 2.3 1.3 20.8 10

Northeast 10.1 1.0 2.3 1.6 - 15.1 7

Midwest 12.9 0.4 0.2 - - 13.4 6

Western 8.7 0.5 0.1 1.0 - 10.4 5

Offshore 6.3 - 7.8 - - 14.1 7

Total 162.8 5.2 18.0 21.7 1.8 209.5 100

Percentage 78 2 9 10 1.0 100
136 MIT STUDY ON THE FUTURE OF NATURAL GAS

The U.S. Natural Gas Pipeline Network

The U.S. natural gas pipeline network includes: 

s 'ATHERING PIPELINES AT OR ADJACENT TO

production sites; 

s )NTER
STATE AND INTRA
STATE TRANSMISSION

pipelines which move processed gas over long 

distances from production sites to major 

centers of demand; and 

s 3MALLER DIAMETER DISTRIBUTION PIPELINES

which carry natural gas on to end users. 

In this discussion, we focus largely on transmission pipelines additions, although safety, which 

is briefly discussed, is also an important issue 

for distribution pipelines and to some degree, 

for gathering pipelines as well. 

Pipeline Additions. Major changes in U.S. gas 

markets have prompted significant additions to 

the country’s pipeline network over the last 

several years. Between 2005 and 2008, for 

example, pipeline capacity additions totaled 

over 80 billion cubic feet per day (Bcfd), 

exceeding those from the previous four-year 

period by almost 100%. Additions of 44.5 Bcfd 

in 2008 alone exceeded total additions in the 

five-year period between 1998 and 2002. The 

rate of additions in 2009, while slower than in 

the previous several years, was still brisk with 

3,000 miles of pipelines added. Figure 6.410

highlights major inter-state pipeline additions 

over the 11-year period from 1998 to 2008. 

The largest single addition to the pipeline system 

between 2005 and 2008 was the Rocky Mountain 

Express pipeline (REX) with a capacity of 

1.8 Bcfd. This pipeline has effectively linked 

Western producer markets to Eastern consumer 

markets. Other notable additions include Gulf 

Crossing (1.4 Bcfd) and Midcontinent Express 

(1.2 Bcfd), both taking gas from the shale 

regions in Texas and Oklahoma to Alabama and 

Mississippi; and two expansions to move gas 

into the Southeast U.S., the 1.6 Bcfd Gulf South 

Southeast Expansion; and the 1 Bcfd Southeast 

Supply header.11

The largest regional capacity increase in this 

time frame was from the Southwest region to 

the Southeast, where almost 6.7 Bcfd of pipeline capacity was added, in part to move shale 

supplies to markets. Capacity to move supply 

from the Midwest to the Northeast increased by 

1.5 Bcfd, a 30% jump, followed by exports from 

the Central to Western U.S., at 1.4 Bcfd. 

West-to-East expansions are contributing to 

major changes in the general direction of 

pipeline flows in the U.S., which have historically moved from south to north. 2030 forecasts 

suggest the need for an additional 20% of 

interregional transport capacity.12 While 

forecasts and historical pipeline expansions 

offer a portrait of a robust and adequate 

response to growth in gas demand, the potential for large increases in gas-fired power 

generation, either for fuel substitution from gas 

to coal or as firming power for intermittent 

renewable generation, could increase the need 

for gas pipeline infrastructure. 

Figure 6.4 depicts total pipeline capacity and 

directional flows; the circled areas highlight 

additions between 1998 and 2008, with volumes 

added and directions indicated by the key in 

the lower right-hand corner. 

Major changes in U.S. gas markets have prompted 

significant additions to the U.S. pipeline network 

over the last several years. Between 2005 and 2008, 

pipeline capacity additions totaled over 80 Bcfd, 

exceeding those from the previous four-year period 

by almost 100%.
Chapter 6: Infrastructure 137

In Chapter 4 we discuss the need for increased 

gas peaking units to firm intermittent renewable generation even though their capacity 

factors would most likely be very low. Similarly, 

recent analysis by the INGAA Foundation 

suggests that in the event of large-scale penetration of intermittent renewable generation, gas 

pipelines may need to dedicate firm capacity 

to provide service to backup generators even 

though this capacity would be used infrequently and the per-unit cost of the infrastructure is likely to be very high.13 The INGAA study 

also forecasts an incremental delivery capacity 

requirement of around 5 Bcfd of gas for new 

firming generation though utilization would be 

only around 15%, with implied transportation 

costs that could be around six times more than 

full-rate utilization costs.14

Pipeline Safety. Recent gas pipeline explosions 

in California and Pennsylvania, which caused 

loss of life and property, underscore pipeline 

safety as an ongoing issue. There is a range of 

reasons for pipeline accidents, from pipeline/

construction defects to third-party accidents 

to corrosion. Figure 6.5 shows the number of 

incidents by type of pipeline over the last 20 years. 

According to statistics compiled by the DOT, 

corrosion is the most common cause of leakage 

for transmission pipelines, and third-party 

excavation incidents are the most common cause 

of leakage for distribution pipelines.15 Leakage 

is responsible for most serious incidents. 

The DOT’s Pipeline and Hazardous Materials 

Safety Administration (PHMSA) has the primary federal responsibility for ensuring gas 

pipeline safety. In 2003, the PHMSA implemented a rule that required an integrity 

management program (IMP) for transmission 

Figure 6.4 Major Additions to Natural Gas Transportation Capacity 1998–2008

Source: Presentation of James Tobin, EIA, Major Changes in Natural Gas Transportation Capacity, 1998–2008, November, 2011.

West-to-East expansions are contributing 

to major changes in the general direction 

of pipeline flows in the U.S.
138 MIT STUDY ON THE FUTURE OF NATURAL GAS

pipelines. This rule required operators to test 

transmission pipeline integrity in highly 

populated areas by 2012. Between 2003 and 

2009, after the implementation of the rule, 

there were six total fatalities; tragically, there 

were 10 fatalities in 2010 from the explosion 

and fire in San Bruno, California. 

As noted, distribution pipelines are responsible 

for the largest number of serious gas pipeline 

safety incidents. Distribution pipelines also 

pose more difficult problems for integrity 

management compared to transmission 

pipelines as they are much smaller in diameter, 

are shorter, include a significant amount of 

plastic pipe, and have major branching of pipes 

to serve end use customers. A PHMSA rule for 

distribution pipelines, which went into effect in 

February 2010, requires IMPs to be implemented 

by August 2011. While plans are required, they 

will reflect the different challenges of distribution 

pipeline safety compared to transmission 

pipelines; they will likely be less prescriptive 

and will also cover the operator’s entire area, 

compared to the requirements for transmission 

pipelines to cover only “high consequence areas.”

The DOT has noted the lack of incentives for 

distribution pipeline operators to assess the 

safety of distribution pipelines, writing that 

“...there are no robust market signals or 

incentives to prompt operators to thoroughly 

assess the condition of the pipelines or to 

implement integrity management programs.”16

Also, according to the U.S. Department of 

Energy’s (DOE) Office of Fossil Energy almost 

one-quarter of U.S. gas pipelines are more than 

50 years old.17 In addition, demand for natural 

gas is expected to increase over the next couple 

of decades. 

Finally, existing pipeline safety research programs within the federal government are small 

and the task of ensuring the integrity of the 

306,000 miles of transmission pipelines and 

1.2 million miles of distribution pipelines is 

both large and essential. The PHMSA identifies 

$33.25 million in federal funding for pipeline 

Reduced 

Gas CCS

Coal CCS

Renew

Hydro

Nuclear

Gas

Oil

Coal

Gathering, 10

Transmission, 132

Electric Power Industrial Commercial

Vehicles Lease, Plant and Pipeline

Residential

Distribution, 830

Figure 6.5 Serious Gas Pipeline Incidents by Pipeline Type, 1991–2010

Source: PHMSA

Existing pipeline safety research programs 

within the federal government and within 

industry are small and the task of ensuring the 

integrity of the 306,000 miles of transmission 

pipelines and 1.2 million miles of distribution 

pipelines is enormous and essential. 
Chapter 6: Infrastructure 139

safety technology development since 2002, around 

$4 million per year (Table 6.2). The PMHSA 

also identifies $16.94 million in “strengthening 

standards” research and $29.98 million in 

“knowledge document” research; the last two 

categories could be characterized as “regulator’s 

science.”

IMPs are necessary but may not be sufficient to 

meet safety needs. The gas industry noted the 

need for additional transmission and distribution R&D in a 2007 report.18 Specific focus 

areas could include: 

s )MPROVING THE MONITORING AND ASSESSMENT

of system integrity;

s %NHANCING SYSTEM mEXIBILITY AND THROUGHPUT

and reliability;

s 2EDUCING THE INCIDENCE AND COST OF SUBSURFACE

damage;

s )MPROVING THE CAPABILITY OF COST
EFFECTIVE

construction, maintenance and repair; and

s )MPROVING DATA QUALITY AND TIMELINESS FOR

system, operation, planning and regulatory 

acceptance and mitigating environmental 

issues.19

Pipelines and Regional Prices. With respect 

to pipelines and regional prices, in general, the 

difference between daily prices at regional hubs 

compared to Henry Hub prices (the market 

center in Louisiana that serves as the price 

point for New York Mercantile Exchange 

(NYMEX) futures contract) is the basis differential or “basis.” The basis differentials are often 

small, reflecting the short-run variable cost of 

transporting gas or of displacing shipments of 

gas to one market center instead of another. 

Occasionally, when transportation bottlenecks 

are long term, the basis differentials become 

large and reflect the different prices at which 

demand is being rationed in the different 

locations. 

A differential that greatly exceeds the cost of 

transportation suggests system bottlenecks.

According to FERC, Rockies tight gas and 

Marcellus shale will compete with traditional 

supplies from the Gulf of Mexico. FERC 

anticipates that this new supply will help 

moderate severe basis spikes on peak demand 

days in the winter.20

Source: PHMSA Web site

Category PHMSA Industry Total

Damage Prevention $2.79 $2.33 $5.12

Pipeline Assessment and Leak 

Detection

$25.08 $32.77 $57.86

Defect Characterization and 

Mitigation

$0.80 $1.20 $2.00

Improved Design, Construction 

and Materials

$4.58 $5.40 $9.98

Grand Totals: $33.25 $39.37 $72.62

Table 6.2 PHMSA Technology Research 2002–present (in millions of $)
140 MIT STUDY ON THE FUTURE OF NATURAL GAS

The relationship of the price differential to 

infrastructure is observed in the basis differentials at the Cheyenne and Algonquin hubs 

before and after the opening of the REX pipeline, which is now moving gas supplies from the 

region to Eastern markets (Figure 6.6). These 

fairly dramatic changes demonstrate how 

alleviating pipeline infrastructure bottlenecks 

can incentivize production and lower consumer 

prices overall.

Before the construction of the REX pipeline, 

natural gas transportation out of the Rockies 

region was very constrained, leading to lower 

gas prices than those at most of the other 

natural gas market centers. As of November 

2009, REX had the capacity to move 1.8 Bcfd 

of natural gas from the Rockies to Ohio, then 

to the Northeast. As noted, REX was the largest 

addition in the U.S. pipeline system between 

2005 and 2008 and has effectively joined 

Western producer markets with eastern consumer markets, a long-time goal of Rocky 

Mountain producers. This pipeline has had a 

major impact on gas flows in the Midwest and 

has reduced the basis differential at both the 

Algonquin and Cheyenne hubs. 

Natural Gas Processing

Each year in the U.S. some 530 natural gas 

processing plants process around 16 trillion 

cubic feet (Tcf) of raw natural gas. These 

facilities have an average capacity factor of 

around 68%. Natural gas often requires processing because gas in its raw form can contain 

impurities which may include sulfur, CO2

, water 

...alleviating pipeline infrastructure 

bottlenecks can incentivize production 

and lower consumer prices overall.

Figure 6.6 Impacts of 2008 Pipeline Capacity Expansion on Regional Prices 

and Average Basis 

Source: Bentek, Beast in the East, 2010
Chapter 6: Infrastructure 141

and other contaminants that need to be removed 

before transport through pipelines to demand 

centers. Removing impurities such as sulfur, 

CO2

 and water to produce pipeline-quality gas is 

the primary role of such processing facilities.21

Understandably, gas processing units are largely 

located in gas-producing regions of the country. 

Currently, around 82% of gas-processing 

capacity is in six states: Louisiana, Texas, 

Wyoming, Kansas, New Mexico and Oklahoma.

As noted, gas production is increasing dramatically and production patterns in the U.S. are 

changing. The need for gas processing additions 

is likely to be more pronounced in regions 

where gas production is relatively immature, 

such as in the Uinta Basin of Eastern Utah and 

the Piceance Basin of Western Colorado. Gas 

processing is very limited in the Marcellus Shale 

Basin where, for example, Western Pennsylvania 

and Northern West Virginia combined have 

530 million cubic feet (Mmcf) of processing 

capacity, with 435 Mmcf of planned processing 

additions and a new 37,000 bpd fractionation 

plant.22

Gas processing units also produce natural gas 

liquids (NGLs) from heavier hydrocarbons 

contained in unprocessed “wet” gas. If there are 

sufficient quantities of NGLs, the market 

conditions are right, and the processing facility 

has the capacity to both treat and separate 

NGLs from gas streams, consumer products 

can be produced, including ethane, propane, 

butane and pentanes. These products can add 

value for gas producers, especially important in 

a low gas price environment. In 2009, the U.S. 

gas industry produced 714 million barrels of 

NGLs, a 16% increase over the 2005 levels of 

production. 

Natural Gas Storage

Natural gas is stored in underground storage 

facilities to help meet seasonal demand fluctuations, accommodate supply disruptions and 

provide operational flexibility for the gas 

system, including power plants. Gas storage 

is also used to hedge price variations. 

There are around 400 storage facilities in the 

L-48 owned by 80 corporate entities and 

managed by 120 operators. Depleted reservoirs 

account for most storage facilities (82%), 

followed by aquifers (9%), with salt caverns 

making up the remainder. Working gas storage 

capacity nationwide in 2009 was around 4.2 

Tcf, which represents about 20% of annual gas 

production. Over 53% of this capacity is found 

in just five states: Michigan, Illinois, Louisiana, 

Pennsylvania and Texas.23

There has been a great deal of interest in the 

relationship between storage and short-term 

price volatility. In 2005, the FERC chairman 

noted that gas storage capacity had increased 

only 1.4% in almost two decades, while U.S. 

natural gas demand had risen by 24% over the 

same period, and speculated that there was a 

link to the record levels of price volatility that 

were being experienced.24 In 2006, FERC issued 

Order 678 which, among other things, sought 

to incentivize the building of more storage by 

changing its regulations on market power 

requirements for underground storage. Since 

the order was issued, total storage capacity has 

increased by 169 Bcf, or 2% of overall storage 

capacity. This compares to a 1% increase in the 

previous three-year period. 

There is also growing interest in high-deliverability gas storage. Storage facilities are classified 

as either baseload or peakload facilities. 

Baseload storage facilities, most often in depleted 

reservoirs, typically support long-term seasonal 

requirements primarily for commercial, residential and industrial customers. These facilities 

are large and are designed to provide steady 

supply over long periods of time; their injections 

(typically over 214 days, April to Oct) and 

withdrawals (151 days, Nov to Mar) are slow.25
142 MIT STUDY ON THE FUTURE OF NATURAL GAS

The operational characteristics of baseload 

storage may be inadequate as storage needed for 

gas-fired power generation where gas demand 

varies greatly, not just by season but daily and 

hourly. Managing this variability is especially 

important, for example, when, as seen under 

the carbon price scenario in Chapter 2, natural 

gas becomes a more critical component of the 

generation mix. Also, gas peaking units serve as 

backup for intermittent renewables which may 

have relatively low load. This type of demand 

also requires greater variability in storage withdrawals than is found in baseload storage units. 

High-deliverability storage provides an option 

for handling high-demand variability associated 

with an increased role or natural gas in power 

generation.26 High-deliverability storage, 

typically in salt caverns, is only about 5% of 

overall gas storage, although capacity increased 

36% between 2005 and 2008, compared to 

3% for all gas storage.27 More important than 

capacity, however, is the withdrawal period. 

Table 6.3 highlights the much shorter, multicycle capabilities of salt formation storage 

facilities compared to depleted reservoirs and 

aquifer storage.28

Salt caverns are typically located in the Gulf 

Coast region and are not found in many areas 

of increased gas demand, where geology limits 

both baseload and peakload storage options; 

this is particularly true in the Northeast, the 

West (areas of high gas demand for power 

generation) and parts of the desert Southwest.

The growing use of natural gas for power 

generation, including the potential near-term 

displacement of coal with Natural Gas Combined Cycle (NGCC) generation and increased 

penetration of intermittent renewables, discussed in detail in Chapter 4, underscores the 

growing interdependencies of the gas and 

electric infrastructures. This growing relationship between gas and power infrastructures is 

highlighted by the increased need for highdeliverability gas storage to match the growth 

in gas-fired power generation. The degree to 

which this interdependency stresses both the 

gas and power infrastructures and creates 

conditions where the infrastructures and related 

contracting, legal and regulatory structures may 

be inadequate is not fully understood.

[The] growing relationship between the gas and 

power infrastructures is highlighted by the increased 

need for high-deliverability gas storage to match the 

growth in gas-fired power generation associated with 

fuel. The degree to which this interdependency 

stresses both the gas and power infrastructures and 

creates conditions where the infrastructures and 

related contracting, legal and regulatory structures 

may be inadequate is not fully understood.

Table 6.3 Gas Storage Facility Operations

Source: FERC Staff Report

Type Cushion Gas Injection Period 

(Days)

Withdrawal Period 

(Days)

Depleted Reservoir 50% 200–250 100–150

Aquifer Reservoir 50%–80% 200–250 100–150

Salt Cavern 20%–30% 20–40 10–20
Chapter 6: Infrastructure 143

RECOMMENDATION

A detailed analysis of the growing 

interdependencies of the natural gas and 

power generation infrastructures should 

be conducted. This should include analysis 

of the system impacts of increased use 

of natural gas for power generation and 

the degree to which this stresses the 

infrastructure or creates conditions where 

storage may be inadequate to meet power 

generation needs. 

LNG Infrastructure

LNG regasification terminals are the last link in 

a long supply chain that enables international 

trade in natural gas and U.S. LNG imports. 

In 2000, the U.S. had four LNG regasification 

facilities with a combined capacity of 2.3 Bcfd.29

High natural gas prices in the first decade of the 

21st century, coupled with concerns about 

declines in domestic supplies and reserves, 

sparked a wave of construction of new LNG 

regasification terminals and expansions of 

existing ones. North America now has 22.8 Bcfd 

of LNG regasification-rated capacity either 

operating or under construction (with original 

planning expectations of capacity factors of 

around 50%), 89% of which is in the U.S. 

These facilities are expensive. The EIA estimated in 2003 that a typical new regasification 

terminal would cost $200 to $300 million for 

a sendout capacity from 183 to 365 Bcf (3.8 to 

7.7 million tons) per year of natural gas but 

acknowledged a wide variation in cost, which 

is very site specific. 30

In 2009, U.S. consumption of imported LNG 

was 1.2 Bcfd, leaving most of this new capacity 

unused and the investment stranded. Demand 

is, however, geographically uneven. The Everett 

import facility in Boston, for example, meets 

around half of New England’s gas demand. 

Gulf Coast terminals however have been forced 

to seek authorization to re-export gas.31 On a 

positive note, the large excess of import capacity provides options for supply diversity in the 

event of unexpected shortfalls in indigenous 

supply. Also, LNG supplies initially intended for 

U.S. markets have been diverted to other 

countries, with European importers and 

consumers, including some key U.S. allies, as 

the main beneficiaries.

Federal Policy and LNG. During the last 

decade, federal policy facilitated the expansion 

of LNG import capacity. In 2002, as already 

noted, FERC issued the so-called Hackberry 

decision which aided investment in LNG 

import capacity by allowing LNG developers 

proprietary access to import facilities. To 

address delays in LNG import terminal siting 

associated with jurisdictional conflicts, the 

Energy Policy Act of 2005 granted FERC 

exclusive jurisdiction over permitting of 

onshore LNG regasification facilities, clarifying 

federal primacy in this process. Later that year, 

FERC, in an effort to expedite siting of LNG 

facilities, established mandatory pre-filing 

procedures designed to help resolve NEPA and 

other community issues prior to the filing of a 

formal application with FERC by the developer 

to site a regasification facility.32 These statutory 

and regulatory actions helped enable the 

permitting of substantial additional regasification capacity in the U.S. Together with additional volumes from Canada and Mexico, 

48.65 Bcfd was licensed to supply U.S. markets 

(but not all of this capacity was built). 

These actions by FERC and other agencies 

illustrate a willingness on the part of the federal 

government to expedite the building of energy 

infrastructure in order to achieve a policy 

objective; in this instance, adequate and affordable supplies of natural gas were deemed to be 

in the public interest as it was widely believed at 

the time that North American gas production 

had peaked and that imports would be necessary to affordably meet demand. 
144 MIT STUDY ON THE FUTURE OF NATURAL GAS

This unused capacity has prompted facility 

owners and investors to explore opportunities 

for using them as export as well as import 

terminals; this would require the building of 

substantial new liquefaction infrastructure. 

Cheniere, the owner of the Sabine regasification 

facility for example, has entered into non-binding agreements with two potential purchasers 

of LNG volumes, and is seeking funding to 

build four LNG trains at the site. The U.S. DOE 

recently approved a permit for export of LNG 

from this project to free trade agreement 

countries only and FERC has initiated an 

environmental review of the proposal. Others 

such as Dominion at Cove Point are reviewing 

export opportunities as well. 

INFRASTRUCTURE NEEDS AND THE 

DEVELOPMENT OF THE MARCELLUS 

SHALE 

As noted in Chapter 2, the natural gas production profile of the U.S. has been altered by the 

ability to produce natural gas from large U.S. 

shale basins. The Marcellus shale may be the 

largest contiguous shale basin in the world, 

underlying significant acreage in New York, 

Ohio, Pennsylvania and West Virginia, but it is 

also the least developed of major U.S. shale 

basins. These Northeastern and Midwestern 

states are generally more densely populated and 

less accustomed to natural gas production than 

Texas, Oklahoma, Arkansas and Louisiana, the 

locations of other major producing shale 

basins. Production in these other basins will 

continue to alter U.S. gas supply forecasts 

regardless of the development of the Marcellus. 

Its sheer size, its under-development, its unique 

environmental issues and its proximity to 

major demand centers and the associated 

consumer benefits warrants a brief discussion 

of some key infrastructure issues affecting the 

development of the Marcellus.

The economics of shale production and the size 

of the Marcellus shale basin have created 

enormous interest in the development and 

production of this vast resource. The location 

of Marcellus production in the Northeast, with 

the resulting lower transportation costs to this 

market, could translate into lower gas prices for 

the region’s consumers, who have typically 

relied on LNG imports, and Canadian and 

GOM gas via pipeline. 

Figure 6.7 Average Transportation Costs to Northeast Markets ($ per Mmcf)

Source: Bentek, Beast in the East, 2010

0.50

0.40

0.30

0.20

0.10

0.00

0.21

0.41

611

0.42

0.37

Million Barrels

 Marcellus Southeast/Gulf Canada Rockies
Chapter 6: Infrastructure 145

It could also shift GOM gas movements to 

the southeast, an attractive option for the 

region’s consumers who are on the highpriced end of the Western coal supply chain. 

Figure 6.7 shows the average and typical 

transportation costs for producing regions 

supplying Northeast markets.33

The Marcellus, however, needs substantial 

infrastructure additions to move its gas to 

markets. There are three transmission pipelines to serve the region either under construction or certified for construction with 

a combined capacity of over 1 Bcfd, and 

another 4.8 Bcfd of planned additions to 

existing pipelines. These additions are essential: Marcellus producers estimated that, as 

of early 2010, less than half of the 1,100 wells 

drilled in the Pennsylvania Marcellus had 

pipeline access.34

It is expected that planned investments in 

pipelines, which are in the several billion dollar 

range, will also drive investments in underground storage. This is critical for the region as 

the geology of the Northeast precludes significant storage in this key demand region, which 

could create a storage bottleneck when moving 

gas from points West to Northeastern markets, 

particularly in the peak demand months in the 

winter. 

There is also wet gas in the Marcellus, particularly in Southwestern Pennsylvania. The 

condensate and NGLs from wet gas enhance 

the economics of production, assuming favorable market conditions and adequate infrastructure to move NGL products to markets. 

A significant percentage of this wet gas in the 

Marcellus requires processing to provide 

pipeline quality gas. The shortage of processing 

capacity and outlets for wet gas products could 

place constraints on the production of pipeline 

quality gas, and could effectively shut-in 

significant gas production in the Marcellus. If 

all planned gas processing capacity additions 

for the Marcellus were to come on-line, on 

schedule, the region would have 800 million 

cubic feet per day (Mmcfd) of gas processing 

capacity by 2012. Also, two NGL pipeline 

projects have been proposed from Pennsylvania 

to Chicago and Ontario which could ease the 

pressure for NGL outlets. Planned pipeline 

expansions appear to be adequate. 

Finally, of major interest and concern is the 

development of a water disposal infrastructure 

to mitigate the environmental impacts associated with wastewater from drilling which 

includes flowback water and produced water. 

Water disposal options in the Marcellus are 

limited. Strict regulations and complicated 

geology, particularly in Northeast Pennsylvania, 

limit the development of disposal wells close to 

drilling sites. There is extremely limited pretreatment capacity in the region and the 

climate is not conducive to evaporation 

options. Minimizing flowback water, on-site 

treatment options, water reuse, and new local 

and regional water treatment facilities are 

needed to reduce the environmental impacts of 

flowback and produced water and water 

transport. 

Minimizing flowback water, on-site treatment 

options, water re-use, and new local and regional 

water treatment facilities are all necessary in 

managing the environmental impacts of flowback and 

produced water, water transport, and the stress on 

existing water treatment facilities in the region. 
146 MIT STUDY ON THE FUTURE OF NATURAL GAS

NOTES

1EIA, Table 5a, U.S. Gas Supply, Consumption and 

Inventories.

2EIA, U.S. Census data.

3

Bernstein Research report, Natural Gas: Method in 

the Madness, February, 2009.

4CRS Report, Liquefied Natural Gas (LNG) in U.S. 

Energy Policy: Issues and Implications, May 2004, 

the so-called “Hackberry decision”, “...allowed 

terminal developers to secure proprietary terminal 

access for corporate affiliates with investments in 

LNG supply.” Terminals that existed at the time of 

the ruling in 2002 were exempted. Congress 

codified Hackberry in the 2005 Energy Policy Act. 

5

EPA Methane to Markets presentation, 

International Workshop on Methane Emissions 

Reduction Technologies in the Oil and Gas 

Industry, Lake Louise, 14-16 September 2009.

6See EPA Web site, Petroleum and Natural Gas 

Greenhouse Gas (GHG) Reporting Rule (40 CFR 

Part 98), EPA Climate Change Division.

7http://www.ingaa.org/cms/15.aspx, Dec 17 2009, 

38,000 is base case for gas demand.

8http://www.ingaa.org/cms/15.aspx, Dec 17 2009, 

ranges represent high and low cases in forecasts.

9Ibid, high gas demand case.

10November 2008, Presentation of James Tobin, EIA, 

Major Changes in Natural Gas Transportation 

Capacity, 1998–2008.

11Bentek, The Beast in the East: Energy Market 

Fundamentals Report, March 19th, 2010.

12Ibid.

13INGAA Foundation study, Firming Renewable 

Electric power Generators: Opportunities and 

Challenges for Natural Gas Pipeline, March 16, 

2011.

14Ibid.

15Serious incident is defined on PHMSA Web site as 

an event involving a fatality or injury requiring 

hospitalization. 

16PHMSA-Research and Special Programs 

Administration, U.S. Department of Transportation 

Web site, 2004-19854.

17See DOE Fossil of Energy Web site, Transmission, 

Storage and Distribution program description, as of 

January 23, 2009.

18American Natural Gas Foundation study, Research 

and Development in Natural Gas Transmission and 

Distribution, March 2007. 

19Ibid.

20FERC Northeast Natural Gas Market, Overview 

and Focal Points.

21EIA report, Natural Gas Processing: the Crucial 

Link Between Natural Gas Production and Its 

Transportation Market, January, 2006.

22Bentek, The Beast in the East: Energy Market 

Fundamentals Report, March 19th, 2010.

23EIA Table 14, Underground Storage Capacity by 

State, December 2009.

24December 15, 2005, Statement by FERC chairman 

Joe Kelliher on the Notice of Proposed Rulemaking 

Announcement on Natural Gas Storage Pricing 

Reform. 

25FERC Staff Report, Current State of and Issues 

Concerning Underground Natural Gas Storage, 2004.

26INGAA Foundation Web site notes that, 

“additional conventional storage will be needed to 

meet growing seasonal demands and high 

deliverability storage will be required to serve 

fluctuating daily and hourly power plant loads.”

27EIA, Table Underground Natural Gas Storage by 

Storage Type.

28FERC Staff Report, Current State of and Issues 

Concerning Underground Gas Storage, 2004.

29Gas Technology Institute, LNG Sourcebook, 2004.

30EIA Report #:DOE/EIA-0637, December 2003.

31FERC report, State of the Markets, 2009.

32FERC order 665’s discussion of pre-filing 

procedures noted that it is “desirable to maximize 

early public involvement to promote the widespread dissemination of information about 

proposed projects and to reduce the amount of 

time required to issue an environmental impact 

statement (EIS).”

33Bentek, The Beast in the East: Energy Market 

Fundamentals Report, March 19th, 2010.

34Ibid.
Chapter 7: Geopolitics 147

Chapter 7: Markets and Geopolitics 

As we have seen in Chapter 3, there are substantial economic benefits to a global natural gas 

market. Geology, geography and historical 

market and geopolitical arrangements have, 

however, limited the development of a global 

market that links supply centers to major 

demand centers, which would have significant 

energy security ramifications. 

At present, trade is centered in three distinct 

regional gas markets — North America, Europe 

(including Russia and North Africa) and Asia 

with links to the Persian Gulf (see Figure 3.11). 

Each has a different market structure resulting 

from the degree of market maturity, the sources 

of supply, the dependence on imports and other 

geographical and political factors. Importantly, 

these regional markets set natural gas prices in 

different ways. In general, the U.S. has gas-on-gas 

competition and open access to pipeline transportation, and manages risk through spot and 

derivatives markets. The European market relies 

more heavily on long-term contracts with price 

terms based on a mix of competing fuels, e.g., 

fuel oil, and pipeline access is restricted. Asia uses 

crude oil as a benchmark for natural gas prices 

and favors long-term contracts; this structure has 

kept LNG prices in Europe and Asia high relative 

to other regions. These market features, along 

with the availability of domestic natural gas 

resources and geopolitical interests, establish the 

boundary conditions for the development of 

global natural gas markets, at the same time that 

significant price disparities between regions 

create greater interest in such a market. 

This regionalized and varied structure of natural 

gas markets stands in contrast to the global oil 

market, and it is instructive to understand the 

fundamentals of the difference between oil and 

natural gas markets. The physical characteristics 

of oil — a very high energy density at normal 

conditions of temperature and pressure — make 

it readily transportable over long distances, 

by a variety of means, at moderate cost. This has 

allowed the development over time of a global 

oil market, where multiple supply sources serve 

multiple markets at transparent spot prices, with 

price differences largely attributed to transportation costs and oil quality. Notwithstanding 

dependence on imports, the diversity and 

robustness of this marketplace adds significantly 

to security of supply for consumers and to 

security of markets for producers. 

In comparison, natural gas markets are smaller 

and less mature, and the physical characteristics 

of natural gas constrain transportation options. 

Unlike oil, transportation costs — whether for 

pipeline gas or liquefied natural gas (LNG) — 

constitute a significant fraction of the total 

delivered cost of natural gas. Also, because of 

the relative immaturity of natural gas markets, 

compared to oil, and the very high upfront 

capital costs, long-term contracts have been 

necessary to underwrite the cost of infrastructure development and to ensure a market for 

the supplier. 

Pipeline gas accounts for almost 80% of today’s 

interregional gas trade (a share that is expected 

to decline as the LNG trade grows). Pipelines 

may transit many countries. The number of 

parties involved in a multi-national pipeline 

project can slow project development considerably and political instability in host or transit 

nations raises security of supply issues. Also, 

cross-border pipelines must invariably comply 

with multiple and dissimilar legal and regulatory 

regimes, further complicating pipeline construction and operations. Finally, the strong mutual 

interests of buyers and sellers in cross-border 

pipeline projects are not fully shared by transit 

nations, such as Ukraine for Russian supply 

to Western Europe. 
148 MIT STUDY ON THE FUTURE OF NATURAL GAS

The U.S. natural gas market functions well, with 

infrastructure development more or less keeping pace 

with changing market needs. 

Pipelines have a distinct economic advantage 

over LNG for shorter distances but LNG gains 

advantage over longer distances and is a key 

enabler of a global gas market. LNG offers the 

potential for a greater diversity of suppliers and 

markets, both key ingredients for increased 

reliability and energy security. Also, LNG is 

generally contracted between a single buyer and 

seller, simplifying contract negotiations and 

transport routes. However, the investment 

required for capacity expansions of each link in 

the LNG supply chain is considerable; since 

minimizing investment risk is a fundamental 

driver for developing global LNG markets, 

longer-term contracts are favored. 

The geological realities of natural gas resources 

are similar to those of oil in terms of the degree 

of concentration of conventional resources, 

with Russia, Iran and Qatar having the largest 

conventional natural gas resource base (see 

Chapter 2). As with oil, at issue is the extent to 

which major resource holders, over time, will 

manipulate supply and prices to advance 

political and/or economic objectives in ways that 

are detrimental to the U.S. and its allies. Consequently, the future structure of these markets 

and the degree of integration that may develop 

have both economic and security implications. 

Several factors could lead to greater market 

integration and diversity of supply: 

s THE COMPETITION FOR SUPPLY FROM REGIONS THAT

can serve multiple major markets, such as the 

Caspian; 

s GROWTH IN ,.' TRADE AND THE DEVELOPMENT

of a market in which cargoes seek favorable 

prices, a trend that has been seen in the 

Atlantic basin; and

s DEVELOPMENT OF MAJOR UNCONVENTIONAL GAS

resources could diversify supply in strategic 

locations such as Europe and China, with 

mixed implications for market integration. 

Of course, there are many unknowable factors 

that can impede market integration, including 

the geopolitical aims of current and future 

natural gas exporters. 

MARKET STRUCTURES 

The U.S. Market

The U.S. natural gas market is the most mature 

of the world’s three major regional markets. 

Significant exploitation of natural gas began in 

the latter half of the 19th century centered in 

Appalachia, with much larger production and 

consumption starting in the 1920s after discoveries in the Southwest. This expansion was 

aided by advances in pipeline technology, 

eventually creating a continent-wide, integrated 

natural gas market. 

The regulatory institutions governing the 

natural gas markets in the U.S. have undergone 

their own historical evolution. New Deal 

initiatives in the 1930s broke the control of the 

holding companies over local utilities and 

established the Federal Power Commission as a 

regulator of the interstate sale and shipment of 

natural gas. The Natural Gas Act of 1938 and its 

subsequent amendments provided federal 

eminent domain authority for the construction 

of new interstate natural gas pipelines and 

natural gas storage. These policies facilitated 

the robust growth of a continent-wide network. 

Initially, long-term contracts were the rule. 

There was no single benchmark price for 

natural gas in the U.S. This changed with the 

passage of the Natural Gas Policy Act of 1978, 

which gradually led to the removal of price 

controls on the interstate sale of natural gas in 

the U.S. Starting in 1985, ceilings were removed 
Chapter 7: Geopolitics 149

on the sale of new natural gas and the Federal 

Energy Regulatory Commission (FERC) issued 

a series of Orders between 1985 and 1993 that 

served to create an open and transparent 

continent-wide market in natural gas. This 

market-based focus was extended to natural 

gas storage in the Energy Policy Act of 2005. 

A robust spot market has developed in the U.S. 

and Canada, with prices set by the forces of 

supply and demand. Contracts continue to play 

a role, albeit diminished, in the market, where 

price clauses typically reference the spot 

market. This expansion has been supported by 

an expanded pipeline network and associated 

midstream gas facilities. The U.S. natural gas 

market functions well, with infrastructure 

development more or less keeping pace with 

changing market needs (see Chapter 6). 

At present, North America is largely selfsufficient in natural gas, and this situation is 

likely to continue for some time, as indicated 

in Chapter 3. The substantial surplus of LNG 

import capacity, discussed in Chapter 6, 

effectively provides backup capacity in the event 

of unanticipated supply shortfalls or high prices. 

It should also be noted that the U.S. exports 

natural gas. LNG exports from Alaska to Japan 

have been in place for 40 years, but are likely 

to face additional competition in the Asian 

market, particularly as the Cook Inlet production tapers off. Part of this competition may 

come from Canada, which has a large shale gas 

resource. The Department of Energy (DOE) 

has approved an application to export LNG 

from a Gulf of Mexico (GOM) facility. The U.S. 

also exports natural gas by pipeline to Mexico 

and Canada, although with a significant net 

import from Canada. Especially since passage 

of the North American Free Trade Agreement 

(NAFTA), there has been increased North 

American energy market integration. 

The large Canadian shale gas resource adds to 

the diversity of supply within the functioning 

North American market. 

U.S. Oil and Natural Gas Prices

There have been long-running discussions 

about the relationship between oil and natural 

gas prices; these have intensified as the ratio of 

oil to natural gas prices reached historic highs 

over the last year. This growing spread could 

have enormous implications for U.S. natural 

gas markets and is especially critical for gas 

producers, industrial gas users and the use of 

natural gas as a transportation fuel. For CNG 

or LNG vehicles, a low natural gas price relative 

to oil is essential for a reasonable payback 

period because the vehicle capital cost is 

appreciably higher (see Chapter 5). In this 

chapter, we explore the history of these prices 

and price movements in the U.S. market during 

the preceding decades.

Oil prices have hovered around $100/barrel (bbl) 

for much of the last year while the U.S. Henry 

Hub (HH) price has been consistently below 

$5/MMBtu, for a ratio at or above 20. (We 

caution the reader that this ratio involves two 

different quantities; it is normally stated in 

terms of the price for a barrel of oil, about 

6 MMBtu, in relation to the price for a 1 MMBtu 

of natural gas because these are the benchmarks 

in commodity markets.) A common assumption is that opportunities for substituting oil for 

natural gas, and vice versa, will equilibrate the 

prices. A simple energy equivalency argument 

would pin the price of a barrel of oil at about 

six times the natural gas price, but this simple 

energy-equivalence argument is unlikely to be 

accurate because oil and natural gas undergo 

different processing, distribution and storage 

for different end uses. A number of “rules of 

thumb” have emerged. An empirical rule that 

is often invoked sets the crude oil/gas price 

ratio at 10. Others are based on the competition 

between natural gas and distillate fuel oil or 

between natural gas and residual fuel oil, using 

typical ratios of fuel oil and crude oil prices. 
150 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 7.1 Log Values of the Natural Gas and Oil Spot Prices, 1991–2010 (2010 dollars) Log Natural Gas Price

Log Oil Price

Jan-91Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99Jan-00Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06Jan-07Jan-08Jan-09Jan-10

Natural Gas

Oil

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Figure 7.1 shows the (natural) logarithm of the 

HH natural gas price and the West Texas 

Intermediate (WTI) crude oil price (the 

logarithms are used so that the same percentage 

change in price appears the same irrespective of 

the price) over the period 1991 to 2010. It is 

clear in Figure 7.1 that no simple rule of thumb 

can fully capture the relationship between the 

natural gas and oil prices. The natural gas price 

is approximately twice as volatile as the oil 

price, and short-run swings in both prices are 

overlayed on top of whatever long-run relationship may exist. A more detailed statistical analysis by Ramberg and Parsons confirms this point 

even after incorporating key exogenous factors 

affecting the natural gas price, such as seasonality, storage levels, shut-in production and the 

vagaries of weather.1

 Nevertheless, they also 

find that it is possible to identify a statistically 

significant relationship between the two 

price series.

Figure 7.2 shows the data of Figure 7.1 as a set 

of WTI and HH price pairs along with the 

simple rules of thumb indicated above.2

 Over 

this time period, the oil and natural gas prices 

each spanned a wide range, and the ratio of the 

WTI and HH prices ranged from about 5 to 20. 

None of the simple rules of thumb reproduce 

the principal trends over the full range of oil 

prices. However, it is interesting that, during the 

period 1991 to 2010, the oil/natural gas price 

ratio consistently exceeded 10, sometimes 

substantially, when the WTI price was above 

$80/bbl. As already noted, the ratio is close to 

20 in the first half of 2011. Should these price 

ratios persist at high oil prices, the opportunities for opening up the transportation fuels 

market to natural gas would be enhanced. 
Chapter 7: Geopolitics 151

During the period 1991 to 2010, the oil/gas price ratio 

consistently exceeded 10, sometimes substantially, 

when the WTI price was above $80/barrel...

Should these price ratios persist at high oil prices, 

the opportunities for opening up the transportation 

fuels market to natural gas would be enhanced.

Figure 7.2 Price Benchmarks Versus Observed Prices 1991–2010 Natural Gas Price, 2010 $/MMBtu

0

5

10

15

20

25

30

0 25 50 75 100 125 150

Oil Price, 2010$/bbl

Burner Tip Distillate

Energy Content

Burner Tip Resid

10-to-1

Best Fit

Observed Prices

Figure 7.2 charts natural gas prices as a function of oil prices. The four straight lines show the four pricing rules-ofthumb. Using the ordering of the lines at the right of the figure, the top line is the burner-tip parity rule based on 

natural gas competing with distillate fuel oil, the second line is the energy-content equivalence rule, the third line 

is the burner-tip parity rule based on natural gas competing with residual fuel oil, and the fourth line is the 10-to-1 

rule. The slightly curved line is the best-fit line calculated from a statistical analysis incorporating a number of 

additional variables and dynamics. The scatterplot of data points are the actual price combinations observed over 

the 1991 to 2010 period. All observed prices are quoted in real terms in 2010 dollars.

Using a relationship that is linear in the logarithm of prices, and accounting for a number 

of additional variables moving the natural gas 

price, Ramberg and Parsons derive a best-fit 

that can be approximated as

with the WTI and HH prices in dollars. This 

relationship is also shown in Figure 7.2 (solid 

line, labeled “best fit” relationship) and captures, 

to some extent, the increasing price ratio with 

increasing oil price. However, their analysis also 

confirms that the “best fit” relationship has 

shifted towards higher oil/gas price ratios in 

recent years.2

European and Asian Markets

The European natural gas market developed 

later than that in the U.S. The initial impetus 

came with the discovery of the Groningen fields 

in the Netherlands starting in 1959. In the early 

1960s, Algeria began LNG shipments to the 

U.K., then to France. Small quantities of 

PHH

PWTI = IO 70

PWTI
152 MIT STUDY ON THE FUTURE OF NATURAL GAS

natural gas from the Soviet Union flowed into 

the other countries of Europe beginning with 

Austria in 1968. 

The current structure of Europe’s natural gas 

markets is shaped by the 1973 Organization 

of the Petroleum Exporting Countries (OPEC) 

oil embargo. The European reaction was to 

explicitly tie the delivered price of natural gas 

to the price of crude oil or crude products. This 

limits the development of a deep and liquid 

spot natural gas market in Europe. 

Currently, almost half the natural gas for 

Organization for Economic Cooperation and 

Development (OECD) Europe is imported, 

mostly by pipeline from Russia and North 

Africa, sometimes traversing other countries. 

LNG also supplies parts of Europe and is 

especially important to Spain and Portugal, 

which are on the far end of the Russian pipeline 

system. 

The long supply chains into Europe, the 

prevalence of pipeline gas and the relative 

inflexibility of the markets create much more 

significant security of supply concerns than are 

experienced in North America. Diversification 

of supply is a high priority. However, even 

though the U.S. is not significantly dependent 

on imports, American security interests can be 

strongly affected by the energy supply concerns 

of its allies. 

There have been moves in the EU to liberalize 

gas markets, starting with the U.K. in 1986. As 

part of a larger energy market liberalization 

effort, the EU in 1998 sought to create common 

rules for an internal natural gas market. The 

result has been the development of a small spot 

market on the European continent. Ultimate 

success will depend upon the future course of 

the EU’s regulatory reform. Progress is slow. 

Industrialized Asia led the way in setting LNG 

prices through oil-indexed long-term contracts 

and remains bound to this market structure. 

This does not appear likely to change in the 

near term. With limited indigenous conventional natural gas resources, industrialized Asia 

and the emerging economies in that region are 

almost totally dependent on imported LNG 

from Southeast Asia, Australia and the Middle 

East. This dependence places a high premium 

on security of supply, which is reflected in the 

region’s dependence on long-term, relatively 

high-priced contracts indexed to oil. 

The indexation of natural gas contract prices 

to the oil price was a necessary innovation to 

enable long lead-time contracts to partially 

accommodate fluctuating energy prices. But oil 

is an imperfect index for natural gas, as seen 

in our discussion of U.S. prices. Since the spot 

market oil and natural gas price relationship 

does not match any simple formula, an oilindexed contract price cannot mimic very well 

the spot natural gas price; oil indexed prices are 

out of sync with the value of marginal deliveries 

of natural gas, sometimes being too high and 

other times too low. Therefore they cannot give 

the right signals for consumption of natural 

gas, inhibiting efficient use of the resource. In 

order for both buyers and sellers to capture the 

full value of natural gas resources, it is essential 

for long-term contracts to reflect the specific 

supply and demand conditions of natural gas, 

meaning a liquid market in gas spot deliveries. 

Absent this, buyers and sellers have not been 

able to do better than index contracts to the 

liquid oil price. Encouragement of the expansion of a liquid market in spot natural gas 

deliveries in Asia is in the interest of buyers 

and sellers and other parties in the value chain. 

As the use of natural gas grows throughout 

industrialized Asia and Europe, the opportunity 

is ripe to realize the establishment of a spot 

market. This would make it possible to switch 

long-term contracts from a price linked to spot 

oil markets to a price linked to spot natural gas 

markets. In turn this will create the opportunity 

for the expanded use of natural gas and improve 

the possibility for international linkage. Nevertheless, the path to a spot market is likely to be 
Chapter 7: Geopolitics 153

complex and slow, and long-term contracts 

operating side by side with the spot market will 

be necessitated by the capital requirements of 

very long pipelines and LNG infrastructure.

Finally, we note that domestic markets in some 

major supplier countries, such as Russia, 

operate with very large subsidies. This leads to 

inefficient use that impacts volumes of natural 

gas available for export. 

IMPLICATIONS OF MARKET INTEGRATION 

Extrapolating from the lessons learned from 

the North American market, an interconnected 

delivery system combined with price competition are essential features of a “liquid” market. 

This system would include a major expansion 

of LNG trade with a significant fraction of the 

cargoes arbitraged on a spot market, similar to 

today’s oil markets. 

As described in Chapter 3, the Emissions 

Prediction and Policy Analysis (EPPA) model 

was used to investigate the consequences of 

global natural gas prices differentiated only by 

transportation costs (which are appreciable for 

long distances between buyer and seller). We 

emphasize that this is not a prediction that such 

a market will emerge, but rather an exploration 

of the implications of global market integration. For the U.S., with the median expectations 

for both North American and global gas 

resources, the U.S. becomes a substantial net 

importer of gas in future decades in an integrated market and long-term domestic prices 

are lower than in the regionalized market 

structure. Also, greater diversity of supply is 

seen for all the major markets in this scenario. 

Clearly other scenarios could result from 

changes in resource estimates or from geopolitical realities.

In addition, a functioning integrated market 

can help overcome disruptions, whether 

political in origin or caused by natural disasters. An example of this was seen in the U.S. oil 

markets, which recovered quickly following the 

2005 hurricanes in no small part because of 

international market adjustments. 

Overall, a “liquid” global natural gas market 

would be beneficial to U.S. and global economic 

interests and, at the same time, it would 

advance security interests through diversity 

of supply and resilience to disruption. These 

factors moderate security concerns about 

import dependence. 

DIVERSITY OF SUPPLY

As already noted, the distribution of conventional natural gas resources is highly concentrated, with Russia, Iran and Qatar being the 

largest resource holders. Indeed the global 

market scenario of Chapter 3, referenced above 

with regard to U.S. import possibilities, shows 

Russia and the Middle East becoming major 

suppliers to all three of the major regional 

natural gas markets — the U.S., Europe and 

industrialized and emerging Asia. The recent 

experience of Europe (curtailment of Russian 

natural gas) and the uncertain political future 

in the Middle East are a cause of concern, 

especially in Europe and Asia because of 

their large demand and limited or declining 

production.

Long-term contracts operating 

side by side with the spot market 

will be necessitated by the capital 

requirements of very long pipelines 

and LNG infrastructure.

Extrapolating from the lessons learned from the 

North American market, an interconnected delivery 

system combined with price competition are 

essential features of a “liquid” market.
154 MIT STUDY ON THE FUTURE OF NATURAL GAS

Figure 7.3 Global Shale Opportunities: Technically Recoverable Shale Reserves and 2009 Consumption (Tcf)

Source: : EIA/ARI, 2011

As has already happened in the U.S., unconventional resources could change the picture 

dramatically. The Energy Information Administration (EIA) recently released “World Shale 

Gas Resources: An Initial Assessment”.3

 This 

report, prepared by Advanced Resources 

International (ARI), presents estimates for 

potential shale gas development in 48 basins in 

32 countries outside the U.S. It does not include 

regions with large conventional resources, such 

as Russia and the Middle East, since these seem 

unlikely to develop the shale resource in the 

near future. Even with this restriction, the 

estimate is for 5,760 Trillion cubic feet (Tcf), 

which is a substantial fraction of the approximately 16,000 Tcf mean estimate of global 

resources discussed in Chapter 2. None of these 

shale resources was included in the global 

estimate or in the trade models of Chapter 3. 

ARI acknowledges that the estimates may have 

considerable uncertainty at this time, and will 

be refined over time as the shale resources are 

investigated by an increasing number of 

industry players. 

The distribution of these shale resources is also 

interesting. Figure 7.3 shows some of the 

results 3

 along with the current annual natural 

gas use in those countries. Pertinent to the 

discussion above, France and Poland are each 

estimated to have around 180 Tcf, and China 

over 1,200 Tcf. 

The scale of the global shale gas resource is a 

potential game-changer...the trade flows in a global 

market could be affected substantially...and the 

leverage of MRHs to follow politically motivated 

strategies would presumably be diminished.
Chapter 7: Geopolitics 155

These resources dwarf annual use and therefore 

present the possibility of exports that significantly affect import requirements for their 

regional natural gas markets. How this plays 

out remains uncertain; for example, while 

Poland intends to pursue production aggressively, France has declared a moratorium 

because of concerns about environmental 

impact. Nevertheless, the trade flows in a global 

market could be affected substantially if the 

global shale gas resource is developed at scale 

over the next decade or so, and the leverage of 

MRHs to follow politically motivated strategies 

would presumably be diminished.

Conventional natural gas finds, even if not on 

the scale of the apparent shale resource, can 

also impact diversity and security of supply 

when they occur in strategic locations. A recent 

example (2009 and 2010) is the large offshore 

finds in the eastern Mediterranean Levantine 

basin. The expectation is for more than 25 Tcf 

of resource in the Israeli economic zone. 

Inevitably there will be issues to be resolved 

involving the maritime borders of Israel, 

Lebanon, Gaza and Cyprus. Nevertheless, it 

appears that the security of supply for Israel, 

which currently uses about 0.2 Tcf of natural 

gas per year, has been transformed by the offshore natural gas finds. In particular, it offers 

the possibility of greatly reduced oil dependence 

through direct or indirect use in transportation.

NATURAL GAS SECURITY CONCERNS 

AND RESPONSES 

Energy supply generates security concerns 

when an economy is exposed to sudden disruptions that cannot be addressed by substitution 

of alternative primary energy sources. It should 

be noted that any source can be replaced with 

sufficient time and investment. For example, 

security concerns led France to make a strategic 

decision to base its electricity supply on nuclear 

power. Restricted access to oil led World War II-era 

Germany and Apartheid-era South Africa to 

large coal conversion to liquid fuel programs. 

For natural gas, the end use with the most difficulty for adjustment to a sudden disruption 

is space heating. This was seen in January 2009 

when Russian natural gas to Europe was cut off 

because of a dispute with Ukraine, a key pipeline 

transit country from Russia to Europe. Although 

the U.S. is not at risk of natural gas supply 

disruptions because of the large North American resource and production infrastructure, 

the vulnerability of key allies is itself a security 

concern. Furthermore, the opportunity to 

substitute natural gas for oil as a transportation 

fuel feedstock improves resilience to “oil shocks.”

Transparent markets with diverse supply, 

whether global in reach or within large regions 

that encompass both major suppliers and large 

demand centers, do much to alleviate security 

risks. Nevertheless, the anticipated growth in 

gas use, combined with the geological realities 

of conventional gas resources, inevitably will 

produce continuing concerns, such as: 

1. Natural gas dependence could constrain 

U.S. foreign policy options. U.S. freedom 

of action in foreign policy is tied to global 

energy supply. Iran, for example, presents 

many security challenges in the Middle East 

and is in confrontation with the West over 

a developing nuclear weapons capability. 

However its oil exports and its potential 

for natural gas exports set up conflicting 

objectives for the U.S. and its allies: altering 

Iran’s behavior, yet not risking supply 

interruptions of the oil and (eventually) 

natural gas markets. Such situations threaten 

allied cohesion in foreign policy.

 Specifically, the U.S., with its unique international security responsibilities, can be 

constrained in pursuing collective action if 

its allies are limited by energy security 

vulnerabilities.4

 The natural gas cutoff to 

Europe demonstrated Russia’s market power 
156 MIT STUDY ON THE FUTURE OF NATURAL GAS

A global “liquid” natural gas market is beneficial to 

U.S. and global economic interests and, at the same 

time, advances security interests through diversity 

of supply and resilience to disruption.

 in a situation where key allies have inadequate alternative supplies and insufficient 

short-term substitution possibilities in a key 

sector. Russia has argued that the Ukraine 

dispute was commercial, that Ukraine 

should not have blocked transshipments 

and that it is a reliable supplier. However, 

the fact that they were selectively moving 

towards market prices in some Former 

Soviet Union states and not others suggested 

political motivations for the disruption. 

In any event, security implies removing or 

minimizing vulnerabilities, so U.S. support 

and encouragement of shale gas development, alternative pipeline supplies (e.g., 

from the Caspian region) and transparent 

LNGs markets with a robust LNG infrastructure should be viewed as favoring 

U.S. security interests.

2. New market players could introduce 

impediments to the development of transparent markets. The new large consuming 

economies, such as China and India, are 

increasingly seeking bilateral arrangements 

that include non-market concessions. Such 

arrangements have the potential to influence 

long-term political alignments, move away 

from open, transparent natural gas markets 

and work against the interests of consuming 

nations as a whole. Major natural gas 

producers have shown some interest in 

forming a cartel to control supply, but this 

movement is not yet very advanced.5

 Global 

shale gas developments would make such a 

cartel very difficult to implement effectively.

3. Competition for control of natural gas 

pipelines and pipeline routes is intense in 

key regions. Control of pipeline routes gives 

natural gas suppliers tremendous leverage 

over consuming nations, and competition 

for these routes is often a “high stakes game.” 

The landlocked Caspian region, which 

possesses large oil and gas resources, provides 

an important example of the geopolitical 

complexity that can develop. Decades ago, 

the Caspian was surrounded by only the 

USSR and Iran, and the legacy natural gas 

pipeline infrastructure is entirely through 

Russia. The Russia-Ukraine-Europe natural 

gas delivery cutoff of 2009 spurred Europe to 

further its intentions to explore pipeline 

routes out of the Caspian Sea region to 

Europe while avoiding Russia. This mirrors 

the earlier construction of the Baku-TbilisiCeyhan (BTC) oil pipeline that took an 

East-West route from Azerbaijan to Georgia 

to Turkey, but the gas pipeline is more 

complicated precisely because of the physical 

characteristics of oil and natural gas and the 

resulting transportation options. The BTC oil 

pipeline can use ships to cross the Caspian 

for supply from Kazakhstan and ships to 

export the oil from Turkey. On the other 

hand, the proposed Nabucco pipeline from 

Baku to Austria is thousands of kilometers 

long and crosses Romania, Bulgaria and 

Hungary just from Turkey to the Austrian 

hub. Furthermore, supply from the 

Eastern side of the Caspian, particularly 

Turkmenistan, is crucial for supplying 

sufficient natural gas volumes, but a subsea 

pipeline to Baku faces complications because 

of unresolved seabed jurisdictional disputes. 

Yet another complication is competition for 

Turkmen natural gas from China, which has 

already begun supply through a very long 

pipeline to Shanghai. Not surprisingly, the 

competition and competing political pressures on the governments in Central Asia and 

the Caspian region over pipelines out of the 

region is intense. It is unclear how this will 

be resolved.
Chapter 7: Geopolitics 157

 While the Caspian presents a particularly 

complex situation, long pipelines crossing 

multiple countries inherently raise transshipment concerns. Another example is the 

proposed Iran-Pakistan-India pipeline. For a 

summary, see “Natural Gas and Geopolitics: 

From 1970 to 2040”.6

4. Longer supply chains increase the vulnerability of the natural gas infrastructure. As 

supply chains multiply and lengthen, these 

infrastructures have become increasingly 

vulnerable to both malevolent attacks and 

natural disasters. Pipelines, processing 

facilities, LNG terminals and tankers are 

“soft targets,” i.e., easy to locate and destroy, 

usually undefended and vulnerable to 

attacks, including cyber attacks. 

As the use and trade of natural gas grow over 

the coming decades, with an uncertain global 

market structure, U.S. policy makers must be 

well informed and manage the interrelationship 

between natural gas markets, both domestic 

and international, and security in order to limit 

adverse effects on U.S. and allied foreign policy. 

RECOMMENDATIONS

1. The U.S. should sustain North American 

energy market integration and support 

development of a global “liquid” natural gas 

market with diversity of supply. A corollary 

is that the U.S. should not erect barriers to 

natural gas imports or exports. 

 Robust global LNG trade and progress 

toward spot pricing of cargoes, especially 

in Asia, are necessary for establishment 

of a global natural gas market. 

2. A federal multi-agency coordinating body 

should be established to better integrate 

domestic and international implications 

of natural gas market developments with 

foreign and security policy. 

 Numerous agencies (Energy, State, Treasury, 

Defense, Commerce, etc.) have a major stake 

in this integration, so the Executive Office of 

the President must exercise the necessary 

convening power and leadership. To be 

successful, strong energy policy support for 

the coordinating group must be established 

in the Department of Energy. This is in 

accord with the recommendation for a 

Quadrennial Energy Review issued by the 

President’s Council of Advisors on Science 

and Technology.7

3. The IEA should be supported in its efforts 

to place greater emphasis on natural gas and 

security concerns. 

 To do so meaningfully, it must bring the 

large emerging natural gas-consuming 

economies (such as China, India, Brazil) 

into the IEA process as integral participants. 

The process should promote open and 

transparent energy markets, including the 

natural gas market. 

 A global natural gas market may lead, as in 

the U.S., to lower natural gas prices relative 

to oil. If this in turn stimulates more substitution of natural gas for oil in the transportation fuels market, IEA’s core mission of 

advancing energy security will be advanced.

A federal multi-agency coordinating body should 

be established to better integrate domestic and 

international implications of natural gas market 

developments with foreign and security policy.
158 MIT STUDY ON THE FUTURE OF NATURAL GAS

NOTES

1

David J. Ramberg and John E. Parsons, MIT Center 

for Energy and Environmental Policy Research 

report 10-017, November 2010.

2

ibid.

3

World Shale Gas Resources: An Initial Assessment, 

prepared by ARI for the U.S. EIA, April 2011, 

www.eia.gov/analysis/studies/worldshalegas.

4

National Security Consequences of U.S. Oil 

Dependency; J. Deutch and J. Schlesinger, chairs, 

D. Victor, project director; Council of Foreign 

Relations Independent Task Force Report No. 58 

(2006).

5

What is the Gas Exporting Country Forum (GECF) 

and what is its objective?, EIA 2009; 

http://www.eia.doe.gov/oiaf/ieo/cecf.html.

6

Natural Gas and Geopolitics: From 1970 to 2040, 

D. Victor, A. Jaffe, and M. Hayes, editors, 

Cambridge University Press, 2006.

7

Report to the President on Accelerating the Pace 

of Change in Energy Technologies through an 

Integrated Federal Energy Policy, President’s 

Council of Advisors in Science and Technology, 

November 2010, www.whitehouse.gov/ostp/pcast.

4. The U.S. should continue to provide 

diplomatic and security support for the 

siting, construction and operation of global 

natural gas pipelines and LNG facilities that 

promote its strategic interests in diversity 

and security of supply and global gas 

market development. 

5. The U.S. government, in concert with the 

private sector, should seek to share 

experience in the characterization and 

development of global unconventional 

natural gas resources in strategic locations. 

This includes strengthening the Global 

Shale Gas Initiative (GSGI).

 Global shale gas resources at the several 

thousand Tcf scale have the potential to be 

game-changers with regard to the market 

and security issues discussed in this chapter. 

The U.S. has a strong interest in seeing this 

development and, to date, has been by far 

the leader in exploiting unconventional 

natural gas resources. The GSGI is led by 

the Department of State, with support from 

the Departments of Interior, Energy and 

Commerce and from the Environmental 

Protection Agency. It provides assistance 

as requested on resource assessments; 

production and investment potential; 

and business and regulatory issues. China, 

India, Jordan and Poland are working with 

the GSGI.

 The experience of states in regulating 

environmental performance of shale gas 

production should also be brought to bear 

through the GSGI.

6. The U.S. should take the lead in international 

cooperation to reduce the vulnerability of 

natural gas infrastructure; help set security 

standards for facilities and operations; and 

provide technical assistance for sharing 

threat information, joint planning and 

exercises for responding to incidents. 
Chapter 8: RD&D 159

Chapter 8: Analysis, Research, Development 

and Demonstration 

Natural gas is well positioned, with current 

technology, to play an increasingly important role 

in serving society’s clean energy needs over the 

next decades, assuming a policy “level playing 

field.” As seen in the analysis of Chapter 3, this 

is especially so in a carbon-constrained world, 

wherein the pathway to significant CO2 emissions 

reductions has three major components:

s THROUGHOUT THE ANALYSIS PERIOD SIGNIlCANT

demand reduction relative to business-as-usual, 

including reductions arising from more 

efficient buildings, industrial processes and 

transportation technologies;

s natural gas as an extended “bridge” to a very 

low carbon future, principally by displacing 

the more carbon-intensive fossil fuels — coal 

and oil;

s in the longer term, “zero-carbon” technologies

as the dominant energy supply, which may 

include fossil fuel combustion with CO2

capture and sequestration.

Continuing research, development and demonstration (RD&D) will play an important role in 

determining the interplay of these components 

over time, especially as RD&D affects the relative 

costs of various technologies and fuels. While 

such cost reduction requirements are particularly 

acute for the zero-carbon technologies, RD&D 

that lowers cost and minimizes environmental 

impact is important for all three components. 

Indeed such technological progress can facilitate 

policy implementation that accelerates CO2

emissions reduction, just as policy and regulation can stimulate technology development.

In addition to prudence with regard to greenhouse gas (GHG) emissions, another important 

energy policy driver is reduced oil dependence. 

The analysis of Chapter 5 presented multiple 

pathways for natural gas substitution for oil in 

the transportation sector. Once again, the 

research challenges are to lower costs and 

increase flexibility of use.

FINDING

There are numerous RD&D opportunities to 

address key objectives for natural gas supply, 

delivery and use:

t JNQSPWF UIF MPOHUFSN FDPOPNJDT PG

resource development as an important 

contributor to the public good; 

t SFEVDF UIF FOWJSPONFOUBM GPPUQSJOU PG

natural gas production, delivery and use;

t FYQBOE DVSSFOU VTF BOE DSFBUF BMUFSOBUJWF

applications for public policy purposes, 

such as emissions reductions and 

diminished oil dependence;

t JNQSPWF TBGFUZ BOE PQFSBUJPO PG OBUVSBM

gas infrastructure; 

t JNQSPWF UIF FöDJFODZ PG OBUVSBM HBT

DPOWFSTJPO BOE FOEVTF TP BT UP VTF UIF

resource most effectively.

The fact that natural gas serves multiple sectors 

in competition with other primary fuels implies 

that many end-use efficiency RD&D programs 

will not be specific to natural gas (e.g., technology development for improving overall building 

energy efficiency). Similarly, there are many 

common elements of the technology base both 
160 MIT STUDY ON THE FUTURE OF NATURAL GAS

for oil and gas exploration and production, 

such as advanced drilling technologies (e.g., 

nanoparticle drilling fluids) and for CO2

sequestration following fossil fuel combustion 

(e.g., the science of CO2 sequestration and 

monitoring, novel capture technologies and 

hydrogen-rich operation of combustion 

turbines). Robust RD&D programs in all of 

these areas are very important for the future of 

natural gas and should be supported by public 

and private funding, but our discussion in this 

chapter will be confined to areas that are 

uniquely tailored to production and use of the 

natural gas resource and that promise to have 

significant impact.

It is worth reiterating that, while we focus on 

natural gas-specific technologies, the overall 

publicly-funded energy RD&D program should 

have a strong portfolio dedicated to the first 

and third components identified above: 

demand reduction and zero emissions technologies. Notwithstanding the overall desirability of a level playing field, and in anticipation 

of a carbon emissions charge, support should be 

provided through RD&D and targeted subsidies 

of limited duration, for very low-emission 

technologies that have the prospect of complementing and competing with natural gas in the 

longer term. This would include efficiency, 

renewables, CO2 sequestration for both coal 

and natural gas generation and nuclear power.

NATURAL GAS RESEARCH NEEDS 

AND OPPORTUNITIES

Relative to the role of natural gas in the energy 

sector, the Department of Energy (DOE), the 

lead government funder of energy RD&D, has 

historically had very small programs dedicated 

to natural gas exploration, production, transportation and use. This is evident in Table 8.1, 

which shows Congressionally-appropriated and 

Administration-requested amounts in recent 

years. In the early years of the DOE, in response 

to the oil shocks of the 1970s, the agency 

supported research and characterization work 

for unconventional natural gas reservoirs, and 

this provided an important foundation for 

subsequent RD&D and development of the 

unconventional natural gas industry (a point 

to be discussed later in the chapter). However, 

the DOE focus on natural gas RD&D was not 

sustained for a variety of reasons, including 

a fairly robust public-private partnership 

(the Gas Research Institute (GRI)) that was 

dedicated to natural gas RD&D across the value 

chain. The Royalty Trust Fund (RTF) indicated 

in Table 8.1 is an example of a more recent 

public-private partnership dedicated specifically 

to exploration and production, with public 

funding legislatively mandated as a very small 

fraction of Federal royalties on oil and gas 

production. Administration proposals to 

eliminate even this funding, made by both the 

previous and current Administrations, highlight the lack of agreement on the need for and 

role of publicly-funded natural gas RD&D.

Our perspective is rooted in the importance to 

society of wise use of the major unconventional 

natural gas resource that has been fully appreciated only recently. This resource is important 

both for addressing GHG emission challenges 

and for energy security, and the public has an 

interest in its effective and responsible production and its efficient use. Clearly, the increasingly 

prominent role of natural gas in the energy mix 

creates an impetus for increased private sector 

RD&D, when the benefits of such activities can 

be readily appropriated. This is happening to 

some degree for the upstream as the major oil 

and oil service companies move more strongly 

into unconventional resources. Nevertheless, 

there will be a need for public and public-private 

funding of research with longer and/or more 

uncertain payback periods than will attract 

private funding. In addition, there are important 

research needs for natural gas transportation 

and end-use in addition to production. Priority 

RD&D areas specific to natural gas follow.
Chapter 8: RD&D 161

Improving the Economics of Resource 

Development

Analysis and Simulation of Gas Shale 

Reservoirs. Our discussion of supply in 

Chapter 2 demonstrates the importance of 

shale gas to the overall supply curves but also 

noted the potential for substantially higher 

resource production. DOE R&D funding should 

be aimed at the basic science that governs shale 

formations. Such a program could help develop 

a better understanding of the physics that 

underlies fluid flow and storage in gas shales; 

facilitate the development of more accurate 

reservoir models and simulation tools; and 

develop imaging tools and models for characterizing the geologic, geochemical and geophysical shale rock properties. The models should 

be able to predict the short-term and long-term 

behavior of induced and natural fractures in an 

integrated fashion. Practical 3-D models can 

improve reservoir management. Better resource 

characterization will enable assessment of 

resource play potential and well performance 

based on petrophysical measurements.

Improved microseismic formation mapping 

will advance optimization of real-time fracture 

treatments. At the macroscopic scale, new 

seismic techniques should be developed to 

identify “sweet spots” and natural fracture 

orientation. Publicly funded research in these 

areas will promote transparency into the 

effective use of the critical shale resource.

Methane Hydrates. The Chapter 2 discussion 

also indicates the potential for major methane 

resources from economic hydrates production. 

More basic research issues need to be resolved 

for methane hydrates than for other natural gas 

sources. RD&D might usefully focus on: the 

systematic remote detection of highly concentrated deposits; long-term production tests, 

particularly in permafrost-associated hydrates; 

and geo-hazard modeling to determine the 

impact of extracting free natural gas on the 

stability of associated hydrate-bearing sediments. 

The longest production test to produce natural 

gas from forced dissociation of methane 

hydrate deposits had only a six-day duration 

due to the nature of the experiment, financial 

concerns and other issues. The technology and 

expertise to conduct a long-term production 

test exist today. Financial and logistical barriers 

have been the major impediments to completing such a test in permafrost-associated 

hydrates. Determining the degree of safety and 

environmental risk associated with production 

from natural gas hydrates will require that 

appropriate data be collected during and after 

long-term production tests that are conducted 

over the next few years. Many of the safety and 

environmental issues will have to be addressed 

by modeling that takes into account a range 

of potential risks, including blowouts; 

co-production of CO2, water and gasses;

FY08 FY09 FY10 FY11 (Req) FY12 (Req)

Gas Hydrate Technologies 14.9 14.6 15.0 17.51 10.0

Effective Environmental 

Protection

5.0 4.9 2.8 0.0 0.0

Total Natural Gas Technologies 19.8 19.4 17.8 0.0 0.0

Royalty Trust Fund 50.0 50.0 50.0 0.0 0.0

Total Government Spending 69.8 69.4 67.8 17.5 10.0

Table 8.1 DOE Gas Technologies RD&D Program Funding ($ Million)

Source: FY 2009 – 2012 DOE Budget Request to Congress.2
162 MIT STUDY ON THE FUTURE OF NATURAL GAS

borehole, formation and/or seafloor destabilization; and warming and potential thawing 

of permafrost.

Methane hydrates are a good candidate, sometime in the future, for another public-private 

success story of the type illustrated in Box 8.1 

for coalbed methane (CBM), i.e., a combination of government funding for resource 

characterization, public-private partnership 

for technology transfer and synergistic, timelimited financial incentives to advance commercial deployment. As the majors move into 

today’s unconventional resources and apply 

their research capacity, methane hydrates could 

be thought of as “tomorrow’s unconventional 

resource.”

Reducing the Environmental Footprint of 

Natural Gas Production, Delivery and Use

Water. As discussed in Chapter 2, a comprehensive program is needed to address issues of 

water use and backflow and produced water 

in unconventional gas production. Such a 

program could lead to: improved treatment, 

handling, re-use and disposal of fluids; more 

sustainable and beneficial use of produced 

water; and more effective stimulation techniques that require less water and other fluids 

to be injected into the subsurface. Nearly 

complete recycle of flowback frac water is 

an important goal. Some of the key water 

treatment needs include removal of polymers, 

control of suspended solids and scale control. 

Basic research on novel approaches is appropriate for public support.

Natural Gas Combined-Cycle with CCS.

Chapter 4 highlighted the importance of 

natural gas in an electricity system with large 

amounts of variable and intermittent sources. 

If CO2 emission constraints are severe enough 

to require the capture of CO2 from natural gas 

as well as coal plants, it will be important to 

understand the cycling characteristics and 

possibilities for natural gas power plants with 

CCS. This need will be ameliorated if inexpensive large-scale storage solutions are developed, 

but a research program to understand cycling 

capabilities at different time scales for natural 

gas generation would be prudent.

Fugitive Emissions. Methane emissions in 

natural gas production, transportation and 

use are not well understood. Research is needed 

for developing technologies and methodologies 

for reliably detecting and measuring such 

emissions. This may have significant monetary 

consequences in a world where CO2 emissions 

are priced. Furthermore, the economic value of 

the methane implies that capture of the natural 

gas emissions for beneficial use merits development of improved technologies and methods. 

The DOE and EPA should co-lead a new effort 

to review, and update as appropriate, the 

methane and other GHG emission factors 

associated with fossil fuel production, transportation, storage, distribution and end-use. These 

results are important for overall energy policy, 

as discussed in Chapter 1. 
Chapter 8: RD&D 163

Box 8.1 Unconventional Gas: Public/Private Partnerships and Tax Incentives

The interplay of early DOE funding, industry-matched GRI applied RD&D and synergistic 

policy incentives had a material impact on U.S. unconventional natural gas development. 

This is illustrated in Figures 8.1 and 8.2 for CBM and shale, respectively.3

 The DOE funding 

was focused on reservoir characterization and basic science. GRI implemented industry-led 

technology roadmaps leading to demonstration. This overlapped with a time-limited tax 

credit put in place for wells drilled from 1980 to 1992, with their production eligible for the 

credit through 2002. The results of this multi-pronged approach to public-private RD&D 

and deployment are particularly striking for CBM. For shale, the program is credited with 

laying a foundation by developing new logging techniques, reservoir models and stimulation 

technologies. See Appendix 8.A.

Figure 8.1 CBM RD&D Spending and Supporting Policy Mechanisms

14

12

10

8

6

4

2

0

Program Budget

(Millions of dollars in 1999 dollars)

Annual CBM Production (Tcf)/

Value of Tax Credits ($/Mcf)

Year

1976197719781979198019811982198319841985198619871988198919901991199219931994199519961997199819992000200120022003200420052006200720082009

CBM Production Eligible Gas DOE Spending GRI Spending Tax Credits

2.50

2.00

1.50

1.00

0.50

0.00

Figure 8.2 Shale Gas RD&D Spending and Supporting Policy Mechanisms

40

35

30

25

20

15

10

5

0

Annual Program Budget

(Millions of dollars in 1999 dollars)

Annual Shale Gas Production (Tcf)/

Tax Credits ($/Mcf)

Year

1976197719781979198019811982198319841985198619871988198919901991199219931994199519961997199819992000200120022003200420052006200720082009

Shale Gas Production DOE Spending GRI Spending Tax Credits

3.50

2.00

1.50

1.00

0.50

0.00

2.50

3.00
164 MIT STUDY ON THE FUTURE OF NATURAL GAS

Expanding Current Use and Creating 

Alternate Applications for Natural Gas

Power Generation. As seen in Chapter 3, 

natural gas use in the power sector is expected 

to increase substantially. Growth will be 

especially important under CO2 emissions 

constraints, since natural gas substitution for 

coal is, along with demand reduction, the least 

costly response in the near-to-intermediate 

term. We also saw in Chapter 4 that natural gas 

capacity is likely to increase substantially in 

response to a greater deployment of wind and 

solar, and transmission constraints and natural 

gas infrastructure are both central considerations for such a development (Chapter 6). 

Advanced analysis and simulation tools are 

needed for the converged electricity and gas 

sectors. Such tools will be invaluable for 

informing technically-grounded energy policies 

and regulations. The model/simulation tools 

need to incorporate several features, including:

s DEVELOPMENT OF BETTER HYBRID MODELS FOR

integrating power sector top-down and 

bottom-up approaches;

s INTEGRATED UNDERSTANDING OF POWER SYSTEM

operation and natural gas distribution 

requirements with large penetration of 

intermittent sources, distributed generation, 

and smart grids;

s BOTH NEAR
TERM AND LONG
TERM PLANNING TOOLS

for electricity and gas capacity planning and 

infrastructure development.

Mobility. As noted in Chapter 5, natural gas 

currently plays a very small role in transportation. In the U.S., it is used almost exclusively for 

fleets with high mileage and small geographical 

area driving requirements. However, the strong 

desire to reduce oil dependence, together with 

today’s historically large spread between oil and 

natural gas prices, has led to an examination of 

natural gas as a material alternative transportation fuel. This can be accomplished either 

through direct use in combustion engines or 

through conversion to a liquid fuel.

For light-duty vehicles, extensive simulations of 

the safety and environmental performance of 

vehicles retrofit for CNG operation should be 

carried out with a view to streamlining regulations and lowering cost, to bring U.S. conditions more in line with the certified retrofit 

costs elsewhere. 

There are multiple pathways to natural gasderived liquid transportation fuels (methanol, 

ethanol, mixed alcohols, DME, diesel, gasoline, 

etc). Various fuels and fuel combinations can be 

used in appropriately modified internal combustion engines, including optimization for 

increasing efficiency by use of alcohol fuels and 

DME. Different fuels will have different fueling 

infrastructure requirements. The DOE should 

support a comprehensive end-to-end analysis, 

supported by engineering data, of the multiple 

pathways. The analysis would include an 

assessment of costs; vehicle requirements; 

environment, health and safety effects; and 

technology development needs. This information will be important for guiding energy policy 

and the introduction of oil alternatives.

Improving Conversion Processes

Industry has often been at the forefront of 

energy-efficiency improvements because of the 

direct impact on the bottom line, but significant additional opportunities lie at the nexus 

of energy efficiency, environmental quality and 

economic competitiveness. Some process 

improvements may require substantial changes 

in manufacturing, such as novel membranes for 

separations, more selective catalysts-by-design 

for synthesis or improved systems integration 

for reduced process heating requirements. In 

the chemicals industry, the promise of biomass 

feedstocks and new bioprocessing technologies 

is attracting considerable interest and needs 

further RD&D. Yet another opportunity would 

be development of new process technologies 
Chapter 8: RD&D 165

for low-temperature separation methods. Such 

developments can substantially reduce natural 

gas requirements and improve industrial 

competitiveness.

The potential for significant reductions in the 

use of natural gas for industrial process heating 

lies in a shift to new manufacturing process 

technologies that require less process heat or 

utilize new, less energy-intensive materials 

(Chapter 5).

The DOE should support pre-competitive 

research in these areas and also use its convening power to bring together energy-intensive 

industry sectors to identify opportunities for 

lowering energy needs, emissions and costs. 

Roadmaps for future energy-efficiency technology improvements would be developed 

through this public-private collaboration. This 

is essentially the role played in the past by the 

Industries of the Future Program, and something like it should be re-created. Crosscutting 

technologies applicable across a broad spectrum of manufacturing industries (such as 

materials for extreme environments and 

separation technologies) would also be identified and should be included in a new DOE 

program.

Improving Safety and Operations 

of Natural Gas Infrastructure

Pipeline safety, discussed in Chapter 6, is an 

increasingly critical issue because of the age 

of much of the natural gas transmission and 

distribution system. There is a strong public 

interest in this area, but the federal program 

is small. Public-private partnership is appropriate for:

s IMPROVING MONITORING AND ASSESSMENT

of system integrity;

s ENHANCING SYSTEM RELIABILITY AND RESILIENCE

s REDUCING THE INCIDENCE AND COST OF SUBSURFACE

damage;

s LOWERING COST OF CONSTRUCTION MAINTENANCE

and repair;

s IMPROVING DATA QUALITY

s MINIMIZING THE ENVIRONMENTAL FOOTPRINT

In addition, the DOE should support novel 

concepts focusing on in-line inspections, 

corrosion prevention and protection and 

anticipatory maintenance. 

Modeling and simulation tools should be 

developed in the public domain for analysis of 

the growing interdependency of the natural gas 

and power generation infrastructures. These are 

needed to support analysis of the system 

impacts of increased use of natural gas for 

power generation and associated infrastructure 

stresses and vulnerabilities, particularly with 

respect to changes in storage and deliverability 

requirements.

Improving the Efficiency of Natural Gas Use

We saw in Chapter 5 that, in addition to power 

generation and industrial use, the other major 

use of natural gas is for space conditioning 

and appliances in residential and commercial 

buildings. Lower-cost, gas-fired, instantaneous 

hot water heaters are an example of an appliance improvement that can significantly reduce 

natural gas consumption. Similarly, lower-cost 

high-efficiency heat pumps for appropriate 

climates can economize on natural gas used 

for space heating. Advances in these and other 

building energy technologies are a good target 

for public-private partnerships.

Combined heat and power was seen in Chapter 5 

to offer significant system efficiency, emissions 

and economic benefits, especially for larger 

installations (Megawatt scale). This should be 

encouraged. However, micro-CHP (kilowatt 

scale) will need a substantial breakthrough to 

become economic. Micro-CHP technologies 

with low heat-to-power ratios will yield greater 

benefits for many regions, and this suggests 
166 MIT STUDY ON THE FUTURE OF NATURAL GAS

sustained research into kW-scale, hightemperature, natural gas fuel cells. Basic 

research into new nano-structured materials 

will be central to such programs.

FUNDING AND MANAGEMENT 

OF NATURAL GAS RD&D

Given the importance of natural gas in a 

carbon-constrained world, and the opportunities indicated above for improved utilization of 

the resource, an increase is in order in the level 

of public and public-private RD&D funding 

indicated in Table 8.1. However, the budgetary 

pressures facing the Administration and 

Congress dim the prospects for additional 

appropriations in the next several years. To 

discuss an alternate path forward, it is important to understand the history that led to the 

current low level of research support. A more 

detailed description of natural gas RD&D funding is given in Appendix 8.A.

The DOE natural gas research funding history 

is summarized in Figure 8.3. Between 1978 

and 2010, the total expenditure was just over 

$1 billion. Major elements have included:

s ASSESSING AND CHARACTERIZING UNCONVENTIONAL

natural gas resources (especially shale) in the 

early years of DOE operations;

s SMALL BUT CONSISTENT SUPPORT FOR RESEARCH

on environmental protection;

s AN EXPLORATION AND PRODUCTION PROGRAM

focusing on advanced drilling, completion 

and stimulation;

s DEVELOPMENT OF HIGH
TEMPERATURE HIGH


efficiency, low NOx gas turbines in collaboration with industry during the 1990s, with 

nearly $300 million of DOE support (see 

Appendix 8.B);

s METHANE HYDRATES RESEARCH DURING THE LAST

decade.

Apart from the funding increase to support the 

cost-shared advanced turbine development, the 

program has averaged about $24 million/year.

This low funding level must be viewed in the 

context of parallel public-private approaches to 

natural gas research funding and management. 

The Federal Energy Regulatory Commission 

(FERC) exercised an authority to require a 

surcharge on interstate pipeline gas volumes 

to support consumer-focused RD&D for the 

natural gas industry. The FERC-approved 

surcharge in 1978 was equal to 0.12 cents per 

Mcf, rising to 1.51 cents per Mcf a decade later.4

This led to a research fund in excess of $200 

million/year for an extended period, yielding 

over $3 billion over the life of the surcharge. 

The GRI was established in 1976 as a private 

non-profit research organization charged 

with managing the funds. It was required to 

have a Board of Directors representing the 

natural gas industry, industrial consumers and 

the public and to submit a research plan 

annually for FERC approval. Important features 

of this approach were applied research and 

development closely connected to industry 

operational and technology needs, a broad 

RD&D portfolio from production to end-use, 

and the ability to make long-term commitments 

and attract cost-sharing based on an assured 

funding stream. GRI programs leveraged 

substantial industry matching funds.

Clearly, the GRI funding was substantially 

greater than the DOE’s. Joint portfolio planning 

was performed regularly to ensure that the 

programs were complementary. Box 8.1 shows 

the interplay between the early DOE support 

for unconventional natural gas RD&D, the 

sustained GRI effort to work with industry in 

developing and demonstrating unconventional 

natural gas production technology and a 

synergistic time-limited tax credit for unconventional production. There has been a considerable and continuing return on a relatively 

modest RD&D investment.
Chapter 8: RD&D 167

However, in the wake of pipeline deregulation, 

the surcharge was ended. In a regulated environment, the surcharge was easily passed on 

by the pipeline companies to ratepayers. After 

pipelines became common carriers in 1992, 

large gas consumers could contract directly 

with natural gas producers. In this new marketplace, the surcharge, although small, became a 

competitive issue. The combination of “bottom 

line” pressures associated with competitive 

markets, the tendency of state regulators to 

eschew rate increases in competitive markets 

and a number of “free riders” (primarily 

intrastate pipelines in Texas that did not pay 

the surcharge) resulted in phaseout of the 

surcharge between 2000 and 2004. The GRI 

ended as a research management organization 

through a merger, in 2000, with the Institute 

for Gas Technology to form the Gas Technology 

Institute (GTI). The GTI managed the phaseout 

of the FERC-approved program and today 

serves as a research-performing non-profit 

organization. Its budget is substantially less 

than that of GRI.

The Energy Policy Act of 2005 established the 

Royalty Trust Fund (RTF) to support a 10-year 

$500 million research program (see Table 8.1) 

with a narrower research scope than had been 

the case for GRI: the Ultra-Deepwater and 

Unconventional Natural Gas and Other Petroleum Resources Research Program. It is focused 

exclusively on exploration and production, 

including associated environmental impacts. 

The RTF draws its funding from a small fraction 

of royalties paid to the Federal government 

for oil and gas production leases of Federal 

on-shore and off-shore tracts. The program 

structure has many similarities to that of GRI: 

75% of the funds are managed by a non-profit 

Figure 8.3 DOE Natural Gas Research Funding History

80

60

40

20

0

Spending (Millions of Nominal $)

NG Prices ($/Mcf Nominal)

Year

19781980198219841986198819901992199419961998200020022004200620082010

10

8

6

4

2

0

Eastern Gas Shales Project

Methane from Coal

Gas from Oil Shale

Infrastructure

Environmental and Advanced Research

Capital Equipment

Infrastructure

Natural Gas Prices

Western Gas Sands Project

Geopressured Aquifers

Exploration and Production

Advanced Turbine Systems

Utilization

Gas Hydrates

Congressionally-directed Projects

Source: DOE Office of Fossil Energy. 
168 MIT STUDY ON THE FUTURE OF NATURAL GAS

research management organization, the 

Research Partnership to Secure Energy for 

America (RPSEA); an annual program plan is 

approved by the Federal government, in this 

case the DOE; there are specific industry 

cost-sharing requirements; in principle, the 

mandatory funding allows for long-term stable 

funding of projects in collaboration with 

industry. Unfortunately, the advantages of 

stable funding have been more difficult to 

capture in this case since, as seen in Table 8.1, 

there have been persistent attempts to 

terminate the program.

FINDING

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RD&D program was not compensated 

by increased DOE appropriations or 

CZ UIF 35' 5IF UPUBM QVCMJD BOE QVCMJD

private funding for natural gas research 

is down substantially from its peak and 

is more limited in scope, even as natural 

gas takes a more prominent role in 

B DBSCPODPOTUSBJOFE XPSME

The GRI and the RTF research models highlight 

the value of federally-sanctioned alternative 

research models, with industry-led portfolios 

and dedicated multi-year funding mechanisms, 

in those cases specifically for natural gas 

RD&D. This value is derived primarily from: 

consistent funding over time; significant 

opportunities for industry input in program 

development and technical project reviews; 

and active collaboration between government, 

industry, academic institutions, the national 

labs and non-governmental organizations. 

GRI also had a significant analytical unit, used 

widely by industry and policy makers until 

it was eliminated in 2001, as the surcharge 

funding started phasing out. Such a role is not 

easily incorporated into the DOE applied 

energy offices.

Recently, the President’s Council of Advisors on 

Science and Technology (PCAST) put forward 

a set of recommendations for federal energy 

research and policy that draws upon this 

experience.5

 The PCAST first recommends an 

overall annual funding level for energy research 

programs of around $16 billion, an increase of 

$10 to $11 billion over the DOE funding level. 

To be effective, PCAST observed that the 

funding must be “long-term, stable and have 

broad enough bipartisan support to survive 

changes of Administration” and, recognizing 

the intense pressures on the annual domestic 

discretionary budget, recommended further 

that the additional funding be found largely 

through “new revenue streams,” analogous to 

the FERC surcharge or the RTF. The PCAST 

further suggested that there is value in the 

external management of a portion of these 

funds, with strong industry input particularly 

for the development and demonstration phases, 

allowing the DOE to focus on its core strengths 

of funding basic and translational research and 

to serve an oversight role for the externally 

managed funds. These recommendations would 

extend the alternative models for funding and 

managing natural gas research to the entire 

energy RD&D portfolio and carry a certain 

degree of irony given the demise of GRI 

stimulated by deregulation and the continuing 

pressures on the RTF.
Chapter 8: RD&D 169

RECOM MENDATION

The Administration and Congress should 

support RD&D focused on environmentally 

responsible, domestic natural gas supply. 

This should entail both a renewed DOE 

program, weighted towards basic research, 

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program, weighted towards applied RD&D, 

that is funded through an assured funding 

stream tied to energy production, delivery 

and use. In particular, the RTF should be 

continued and increased in its allocation 

commensurate with the promise and 

challenges of unconventional natural gas. 

Furthermore, consideration should be given 

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research model for natural gas 

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170 MIT STUDY ON THE FUTURE OF NATURAL GAS

NOTES

1

In FY 2011, a new methane hydrates program will 

be initiated by the DOE Office of Basic Energy 

Sciences under the Geosciences Research program. 

2

FY 2009 – FY 2012 DOE Budget Request to 

Congress. 

3

DOE Office of Budget. FY 1978 to FY 1996, DOE 

Budget Requests to Congress; Gas Research 

Institute 1979–1983 to 1994–1998, Research and 

Development Plans. Chicago, Ill., Gas Research 

Institute. 

4

Process Gas Consumers Group, Petitioner, v. 

Federal Regulatory Energy Commission, 

Respondent. American Gas Association, Interstate 

Natural Gas Association of America, Fertilizer 

Institute, Gas Research Institute, Georgia Industrial 

Group, Intervenors. No. 88-1109. United States 

Court of Appeals, District of Columbia.

5

President’s Council of Advisors on Science and 

Technology, Report to the President on Accelerating 

the Pace of Change in Energy Technologies 

Through an Integrated Federal Energy Policy, 

November, 2010.