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worldwatch report 184

saya kitasei

Powering the Low-Carbon Economy:

The Once and Future Roles of Renewable Energy

and Natural Gas

worldwatch inst itute


Powering the Low-Carbon Economy:

The Once and Future Roles of Renewable Energy

and Natural Gas

saya kitasei

lisa mast ny, editor

© Worldwatch Institute, 2010Washington, D.C.

ISBN 978-1-878071-97-2

Printed on paper that is 50 percent recycled, 30 percent post-consumer waste, process chlorine free.

The views expressed are those of the author and do not necessarily represent those of the Worldwatch Institute; of its directors, officers, or staff;

or of its funding organizations.

On the cover: The SEGS IV power plant in the middle of the solar array, California.Photograph, Sandia National Laboratory

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The report is also available at www.worldwatch.org.

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Less Carbon, More Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

The Rise of Renewable Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

The Renaissance of Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Natural Allies in the 21st-Century Grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

A Bridge to Somewhere . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Catalyzing the Low-Carbon Transition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Endnotes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Figures, Tables, and Sidebars

Figure 1. Average Annual Growth in Global Electricity Generation, by Fuel, 2004–08 . . . . . 9

Figure 2. Share of Wind and Solar in Total Electricity Generation, Selected Countries and Regions, 1990–2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Figure 3. Share of Global Installed Capacity of Selected Energy Storage Technologies . . . 14

Figure 4. Estimated Levelized Cost of Backup Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Figure 5. Share of Global Primary Energy Use, by Energy Source, 1965–2009 . . . . . . . . . . 17

Figure 6. Natural Gas Share of Primary Energy Use, by Region, 2009 . . . . . . . . . . . . . . . . 17

Figure 7. Levelized Cost of Electricity of Selected Plant Technologies . . . . . . . . . . . . . . . . . 18

Figure 8. U.S. Natural Gas Prices, 1976–2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Figure 9. Global Liquefied Natural Gas Exports, Total and as Share of Natural Gas Consumption, 2001–09 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Figure 10. Lifecycle Greenhouse Gas Emissions from Coal and Natural Gas Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Figure 11. Sample ERCOT (Texas) Load Curve, July 8–14, 2009 . . . . . . . . . . . . . . . . . . . . . 23

Figure 12. Levelized Cost of Electricity and Carbon Dioxide Emissions for Selected Baseload Power Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Figure 13. U.S. Methane Emissions by Source, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Table 1. Observed Costs Associated with Distributed Generation in the United States . . . 28

Table 2. Performance Characteristics of CHP Technologies . . . . . . . . . . . . . . . . . . . . . . . . . 28

Sidebar 1. Addressing the Environmental Risks of Unconventional Gas Production . . . . . 20

Sidebar 2. Wind Integration Hits Turbulence in Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Table of Contents

This report was much improved by the valuable input and insights of numerous experts in the energy field, including Joel Bluestein, Jacques de Jong, Arjan Dikmans, Michael Eckhart, Jenny Fordham, Gary Groninger, Rich Haut, Jerry Hinkle, Fred Julander, Dan Kammen, Vello Kuuskraa, Dan LeFevers, Nick Lenssen, Jack Lewnard, Brannin McBee, Yvonne McIntyre, Mike Ming, Frans Nieuwenhout, Thorsten Schneiders, Martin Schöpe, Greg Staple, Frauke Thies, Jim Torpey, Paul Van Den Oosterkamp, Rich Ward, and Bill Williams.

Very special thanks go to my colleagues at the Worldwatch Institute. Senior Energy Advisor Heidi VanGenderen provided tireless feedback and moral support throughout my work on the Natural Gas and Sustainable Energy Initiative. Senior Fellow Janet Sawin’s thorough review and thoughtful suggestions strengthened the report immensely. I also thank Climate and Energy Pro-gram members Alexander Ochs, Haibing Ma, and Sam Shrank for their careful reviews; Annette Knoedler for her cheerful and skillful execution of expert interviews; and Andrew Eilbert, Camille Serre, Pierce Boisclair, and Meera Bhaskar for their research support.

Worldwatch’s Director of Communications Russell Simon and Director of Publications and Marketing Patricia Shyne provided outreach support, independent designer Lyle Rosbotham was responsible for the report’s layout, and Corey Perkins saved my work from mysterious technologi-cal problems on numerous occasions. I am deeply indebted to Senior Editor Lisa Mastny, whose energy and patience have carried this report from start to finish. I am incredibly grateful for the guidance and support of Worldwatch President Christopher Flavin. I could not have written this report without his mentorship and trust. Any remaining errors are my own.

Finally, I want to thank MAP Royalty, especially Jane Woodward and Peggy Propp, whose sup-port for my fellowship made this work possible.

Saya Kitasei is the lead researcher and program manager of the Worldwatch Institute’s Natural Gas and Sustainable Energy Initiative (NGSEI). She is co-author of the NGSEI reports The Role of Natural Gas in a Low-Carbon Economy (with Christopher Flavin), Addressing the Environmental Risks of Shale Gas Development (with Mark Zoback and Brad Copithorne), and How Energy Choices Affect Fresh Water Supplies: A Comparison of U.S. Coal and Natural Gas (with Emily Grubert).

Saya graduated from Stanford University in 2009 with an M.A. in Russian, East European, and Eurasian Studies and a B.S. in Earth Systems. While at Stanford, she received an Undergraduate Research Fellowship to construct a stable isotope record of the Early Oligocene with Robert Dun-bar’s Stable Isotope Lab, an Ernest Hollings Fellowship to research sea-surface change and razor clams with the U.S. National Oceanic and Atmospheric Administration in Alaska, and a Depart-ment of Education FLAS scholarship to study advanced Russian at Moscow State University. After graduating, she interned with the Center for American Progress Energy Opportunity team and the Climate Institute in Washington, D.C. Saya began her MAP fellowship with Worldwatch in time to help launch the NGSEI at an event at the United Nations Climate Conference in Copenhagen in December 2009.

Acknowledgments

About the Author

4 Powering the Low-Carbon Economy www.worldwatch.org

5www.worldwatch.org Powering the Low-Carbon Economy

O ver the past decade, renewable energy and natural gas have emerged as potential cornerstones of a low-carbon power sector. Wind

and solar resources are abundant and can be converted into electricity using technologies that emit no greenhouse gases. Natural gas offers a cleaner alternative to coal that can deliver sharp, immediate reductions in carbon dioxide emis-sions from the power sector—if new supplies can be produced responsibly.

Important synergies between renewable energy and natural gas will allow for reduced dependence on coal, speeding the transition to a low-carbon economy. These synergies emerge when the power system is considered holistically, rather than with the one-solution-for-one-prob-lem approach that electricity system operators have employed historically.

Natural gas can be used in a range of efficient, flexible, and scalable generating technologies, making it a natural partner for variable renew-able energy sources such as wind and solar power. Because these renewable resources vary by the season, day, and even hour, wind and solar power plants cannot always generate electricity when it is needed, as other types of power plants can. Meanwhile, the coal and nuclear steam turbines that form the backbone of most electricity sys-tems today are very slow to turn up and down and become much less efficient when they are running at less than full power. The inflexibility of these plants limits the amount of variable gen-eration that the electricity grid can absorb.

Thanks to growing policy support for renew-able energy, the costs of many renewables are falling, and renewable energy has started to penetrate power markets in a significant way. In

2008, the share of the world’s electricity gener-ated from wind and solar power surpassed 1 percent, more than double the contribution in 2004. In some countries and regions, the share is considerably higher: several states in northern Germany now generate more than 30 percent of their electricity from wind energy alone, and two U.S. states generate more than 8 percent. In Den-mark, wind power represents about 20 percent of total generation.

Yet the world could be generating much more renewable power than it is. The global installed capacity of wind and solar power is now grow-ing by 30–50 percent per year. But electricity systems with growing shares of variable genera-tion are sometimes unable to accommodate all of the power that is available, especially at times when demand is low. Although some regions are able to store limited amounts of excess electricity for later use or to share the power with neighbor-ing regions, many system operators are forced to “curtail” or turn down wind and solar generators in such situations. Natural gas power plants can increase the grid’s flexibility as a whole and pro-vide dedicated backup generation to individual wind and solar plants.

Renewable energy and natural gas can also power a transition away from inefficient central-ized power. Natural gas power plants come in a range of scales, allowing them to generate elec-tricity in both centralized and distributed power systems. Distributed power, produced from small generators located near electricity consumers, can reduce the expense and efficiency losses associ-ated with long-distance transmission. Small solar, wind, and natural gas-fired cogeneration plants (also known as combined heat and power, or CHP, plants) can be integrated directly into dis-

Summary


Four key mechanisms can enable the combi-nation of renewable energy and natural gas to displace coal and provide needed reductions in power-sector emissions. First, air pollutants such as nitrogen oxide, sulfur dioxide, and mercury must be tightly regulated. Second, a cost must be attached to emitting carbon dioxide. Third, electricity system operators should allow wind and solar plants to balance their own output with on-site resources. And finally, the markets on which system operators purchase electricity must be highly responsive, allowing them to react to fluctuations in electricity supply and demand as rapidly as possible.

Working together, renewable energy and natu-ral gas can accelerate the decarbonization of the world’s electricity system and form the founda-tion of tomorrow’s low-carbon economy.

tribution lines and networked together to create a diffuse, flexible, local, and low-carbon grid.

In order to play a sustainable role in a low-car-bon future, natural gas itself can and must decar-bonize. At the chemical level, natural gas consists primarily of methane, a molecule that can be produced or synthesized from a variety of renew-able sources. Landfills and organic processes can create methane that otherwise enters the atmo-sphere, where it acts as a greenhouse gas some 25 times more potent than carbon dioxide. This methane or “biogas” can be used interchange-ably with natural gas, and capturing and utiliz-ing it can mitigate greenhouse gas emissions. In the future, methane supplies could be decarbon-ized further by blending in hydrogen gas, a zero-carbon fuel that can be produced from water through electrolysis using renewable energy.

Summary


In June 2010, carbon dioxide (CO2), the greenhouse gas contributing the most to human-induced climate change, reached concentrations of 392 parts per million in

the Earth’s atmosphere, a 5.5 percent increase over 2000 and a 10.1 percent increase over 1990.1* A host of indicators, including increasing surface temperatures over land and sea, reced-ing glaciers and sea ice, rising sea levels, wors-ening ocean acidification, and changing hydro-logic cycles, demonstrates that the past century’s growth in CO2 concentrations is affecting and altering the global climate.2

By some measures, prospects for addressing climate change seem dimmer in 2010 than they have at any time in the last decade, with the foun-dering of international climate negotiations in Copenhagen, Denmark, in December 2009, and the U.S. Senate’s failure to launch climate legisla-tion that would have capped CO2 emissions from the world’s largest economy. Meanwhile, despite a global recession, the economies of China and India continue to grow, consuming increasing amounts of fossil fuels and emitting ever more greenhouse gases.

Yet despite the failure of top-down approaches to curb greenhouse gas emissions at the interna-tional level and in some major emitting coun-tries, concerns about local pollution and energy security, as well as a growing carbon conscience in society, are continuing to drive progress toward a low-carbon economy. Over the past two years, renewable energy and natural gas (the cleanest fossil fuel in terms of CO2, sulfur diox-ide, nitrogen oxides, particulate matter, and mer-cury) have weathered the recession well, while

dirtier fuels have watched their market shares erode, particularly in the power sector.

The single most important opportunity for reducing global CO2 emissions lies in revolution-izing how the world generates electricity. Public electricity and heat† production was responsible for 25 percent of global CO2 emissions in 2005, up from 23 percent in 2000 and only 12 percent in 1970.3 Emissions from electricity production have grown faster over the past four decades than those from any other source, including transpor-tation. Much of the growth in power- and heat-sector emissions over the past decade has resulted from the explosion of major emerging economies such as China and India. If these countries are to develop sustainably, the groundwork for low-car-bon power systems must be laid now.

Fortunately, the major sources of emissions in the power sector tend to be few, large, and centralized, making immediate reductions easier and cheaper to regulate and enforce than in many other sectors of the energy economy.4 Moreover, many of the technologies and resources required to develop a low-carbon power sector are already commercially available, although underutilized. Wind and solar power are growing especially rap-idly: in 2005, these and other renewable power technologies (excluding large hydropower) gener-ated 5 percent of the world’s electricity, and their global potential is much higher.5 The German Aerospace Center (DLR) estimates that by 2030, 13 of the world’s 20 largest economies could gen-erate 40 percent or more of their electricity from

Less Carbon, More Power

* Endnotes are grouped by section and begin on page 36.

† This statistic includes public heat generation such as might be produced by a cogeneration district heating system; however, heat represents only a small share of the total. This report focuses on the dominant contributor, electricity.

8 Populat ion, Cl imate Change, and Women’s L ives www.worldwatch.org


its extraction can be addressed. And in some countries, renewable biogas is diversifying and de-carbonizing the gas supply.

Market forces and the growing imperative to reduce energy-sector emissions will eventu-ally drive an energy transition. But as energy expert Peter Fox-Penner writes, “The choice is not whether we make these changes, but whether we make them well or poorly, costly or cost-effectively, quickly or at a tortured, halting pace. Mother Nature’s timetable for…safe decarbon-ization is not negotiable.”7

In recent years, the growth of renewable energy and natural gas has created stiff compe-tition for the large share of electricity currently produced from coal. But competition between renewable energy and natural gas is counterpro-ductive. Although the notion that natural gas could be central to a low-carbon transition is controversial, natural gas and renewable energy offer complementary strengths to a low-carbon economy. Strategic deployment of both can reduce the cost and accelerate the timing of an energy transition that is behind schedule when measured by the uncompromising clock of cli-mate change.

renewable energy—a share that could exceed 50 percent in all 20 countries by 2050.6

But realizing such high penetrations of renew-able power around the world will require pro-found changes to the electricity sector. Three key elements of this transition are: shifting away from inflexible baseload coal power plants; diversify-ing the sources of electricity supply; and decen-tralizing power generation. Together with the efficiency gains that can come with new trans-mission and distribution infrastructure, more modern power plant technology, and “smart” end-user appliances, these three elements can be the cornerstones of an accelerated transition to a low-carbon economy. Done right, this transi-tion can lower emissions from sectors that are expected to become increasingly electrified, such as buildings and transportation.

Natural gas is a critical partner in meeting these goals. Market and technological developments in recent years have the potential to make natural gas an abundant, accessible, and affordable alternative to coal in the coming decades. Because natural gas can be used in a range of efficient, flexible, and scalable applications, it is a natural partner for renewable energy in a low-carbon future—as long as the environmental risks associated with


A

The Rise of Renewable Energy

world’s electricity grids in 2009 alone was more than double the capacity installed in the entire 20th century.4 In the past two years, wind power has accounted for a greater share of new elec-tric generating capacity in Europe than any other generating technology.5 Wind energy generated 340 billion kilowatt-hours (kWh), or 2 percent of the world’s electricity, in 2009, and in many regions it is now cost-competitive with coal-fired electricity.6

Offshore wind power has even larger poten-tial in many parts of the world and is poised for rapid growth over the next decade. By late June 2010, Europe had installed a total of 2.4 GW of offshore wind capacity and had an additional 4.0 GW under construction—including the United Kingdom’s 300 megawatt (MW) Thanet plant, the world’s largest offshore wind farm, which began operation in September 2010.7 In July, the

t the turn of this century, renewable energy* began taking shape as a viable solution to the environmental and energy security concerns that plague

fossil fuels. Solar photovoltaic (PV) cells, origi-nally developed to power satellites and space sta-tions, were starting to enter the grid-connected power market and could be found on some roof-tops. A handful of solar thermal power plants were generating electricity in Italy and south-ern California. Wind energy, long a presence in Denmark, Germany, and Spain, was better established, but the technology had scarcely pen-etrated global markets.1

Today, just 10 years later, wind turbines have become a familiar and iconic fixture in many regions, from the panhandle of Texas to the waters off Shanghai. In marked contrast to fossil fuels, renewable energy (excluding hydropower) has achieved average annual growth rates of more than 20 percent for the last five years, with solar power averaging more than 40 percent.2 (See Figure 1.) The remarkable surge of renewables, which broke records even as the global financial crisis drove the first drop in global primary energy consumption this millennium (in 2009), has been one of the decade’s greatest success stories.

The global installed capacity of wind tur-bines has grown from 17 gigawatts (GW) in 2000 to 159 GW in 2009, an increase of more than 800 percent.3† The wind capacity added to the

* Renewable energy can refer to a range of resources, including hydrokinetic energy, solar energy, wind energy, geothermal energy, waste, biomass, biofuels, and biogas. This report focuses on solar and wind energy, the two most rapidly growing sources of renewables in the power sector.† Units of measure throughout this report are metric unless common usage dictates otherwise.

Perc

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Source: IEA

-10

0

10

20

30

40

50

Oil

Nuclea

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ro

Geothe

rmal

Coal

Natural

Gas

Biomas

sWind So

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-1.5 -0.1

3.3 3.6 3.66.3 7.3

27.0

42.7

Figure 1. Average Annual Growth in Global Electricity Generation, by Fuel, 2004–08



has been tapped to build in the deserts of China’s Inner Mongolia.14

After a decades-long hiatus, interest in con-centrating solar thermal power (CSP), a technol-ogy that concentrates sunlight with fields of mir-rors to heat a fluid and spin a turbine, has revived in recent years. Global capacity grew to 613 MW by the end of 2009.15 In 2010, California permit-ted its first solar thermal projects in two decades, a total of 2.7 GW, and between March 2009 and March 2010 Spain added 220 MW of new CSP.16 Meanwhile, a 2.0 GW solar thermal project built by ESolar is expected to join the PV project of similar scope planned for Inner Mongolia.17 CSP has a significant advantage over solar PV, which generates electricity only when the sun is shin-ing, because it can store heat in a medium such as molten salt or mineral oil to extend generation hours after the sun has set.18

Additional electricity is being produced from other renewable sources. Geothermal energy pow-ered 11 GW of capacity and generated more than 67 billion kWh of power in 2009. Solid biomass contributes a further 54 GW of power capacity and is now being combusted or “co-fired” along with coal and natural gas in conventional power plants. The use of biogas—a biologically derived gas composed mainly of methane—in power gen-eration has also risen. Hydropower, the world’s largest source of renewable energy, still comprises the vast majority of global renewable energy gen-eration: global capacity reached 980 GW in 2009, or roughly one-fifth of the world’s total installed generating capacity.19

Like the power sector, transportation has increased its reliance on renewable energy in the past decade. Fuels produced from organic material such as corn and sugar cane have become common alone or blended with gasoline and diesel in the United States, Europe, South America, and Asia. In Brazil, sugarcane etha-nol has displaced half of the country’s gasoline consumption.20 In 2009, global production of ethanol reached 76 billion liters, and biodiesel production reached 17 billion liters.21 How-ever, significant uncertainty surrounds biofuels, with many analysts concluding that the land-use change associated with shifting to biofuel crops would increase greenhouse gas emissions enough

102 MW Donghai Bridge Wind Farm, China’s first offshore wind power plant, began transmit-ting electricity to the national grid.8

Globally, the technically recoverable wind energy resource is an estimated 570 quadrillion Btu, significantly greater than the just over 450 quadrillion Btu of total global primary energy consumption in 2008.9 Yet wind resources pale in comparison to energy available from the sun, estimated at more than 1,500 quadrillion Btu.10 Although solar PV cells remain costly compared to wind turbines, they are quickly becoming less expensive and are now the world’s fastest grow-ing power technology. By the end of 2009, more than 21 GW of grid-connected PV cells were installed worldwide—a 100-fold increase in capacity since 2000.11

Although most solar PV cells are applied in relatively small, decentralized installations—often on the roofs of buildings or on brownfield sites in urban areas—large, utility-scale power plants are starting to be built as well. U.S. energy services company SunEdison announced plans in March 2010 to build Europe’s largest PV plant in Rovigo, Italy—a 72 MW installation.12 And PV manufacturer SunPower has received a contract to develop a 250 MW PV power plant in San Luis Obispo, California.13 Both of these plants could be dwarfed, however, by a 10-year, 2,000 MW PV project that another U.S. company, First Solar,

The Lillgrund Wind Farm, Sweden’s largest offshore installation.

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Although a few governments had created policies designed to promote the development of renew-able resources, the concept was novel enough in the year 2000 that U.S. President Bill Clinton in his State of the Union address called vaguely for “a major tax incentive to business for the produc-tion of clean energy.”27

Just 10 years later, a robust policy toolbox is available to governments that want to promote renewable energy. Such policies have mush-roomed in the past few years. Feed-in tariffs requiring utilities to purchase renewable energy generated by any producer at cost-based prices now exist in at least 50 countries and 25 states or provinces.28 And 10 countries and 46 states and provinces worldwide have renewable electric-ity standards or quotas, which set targets for the share of their electricity generation or capacity coming from renewable sources.29

Growing numbers of states and countries also provide tax credits, loans, and grants to renew-able energy developers, as well as subsidies in the residential, industrial, and commercial sec-tors.30 Many governments seized the opportunity presented by the recent economic downturn to build substantial renewable energy spending into stimulus packages. The United Nations Environ-ment Programme was among many voices calling for a “global Green New Deal”—a strategy for both combating climate change and creating new industries and jobs in the 21st century.31 Total “green stimulus” allocations for renewable energy and energy efficiency as of mid 2010 amounted to some $188 billion, more than 90 percent of which had yet to be spent.32*

The costs of wind and solar power remain a key barrier to more rapid penetration of these energy sources; however, supportive policies as well as public and private research and devel-opment have helped drive down prices. Private investment in new renewable power capacity has grown over the past decade as well, exceeding investment in new conventional power capacity since 2008.33

Although renewable energy is emerging as a competitive alternative to fossil fuels in Europe

to negate the carbon savings that these fuels offer over their petroleum-based counterparts at the point of use.22

Liquid fuels—whether petroleum, liquefied natural gas (LNG), or biofuels—are no longer the only choice for use in most vehicles. Com-pressed gases such as natural gas and methane produced from landfills and biomass are proving to be a practical, cleaner, and less expensive alter-native to petroleum fuels in some parts of the world. Pakistan, for example, had some 2.3 mil-lion natural gas vehicles on the road in 2009.23 Several companies are developing vehicles pow-ered by hydrogen fuel-cells and even solar-pow-ered hydrogen home-fueling stations, although dedicated hydrogen vehicles remain some years from being commercial.24

Renewable energy can also be used to fuel transportation via electricity generation. As hybrid-electric and plug-in hybrid vehicles become cheaper, lighter, and more efficient, a growing share of the transportation sector is likely to be electrified. The addition of this new load to the electric grid will tie transportation-related emissions to the generation mix, increasing the urgency of decarbonizing the power sector.

Electrification may increase in the space heating and cooling sectors as well.25 Renew-able alternatives, such as biomass boilers, solar water heaters, and geothermal heat pumps, are being used to provide buildings with heat and hot water in many parts of the world. But the markets for heating and cooling have lagged behind those for electricity and transportation in adopting renewable energy. Renewables, espe-cially solar energy, have the potential to increase off-grid access to heating, cooling, and hot water, especially in regions that lack the pipeline infrastructure that distributes natural gas (the developed world’s cleaner alternative to oil and coal in heating buildings). China already has 105 gigawatts-thermal (GWth) of solar water heating capacity installed—70 percent of global capac-ity—providing hot water to more than 70 mil-lion households.26

The rapid growth of wind and solar energy over the past decade could not have occurred without support from strong policies at the local, state, national, and international levels.

* All dollar amounts are expressed in U.S. dollars unless indicated otherwise.



30 percent of their electricity from wind.38

While these have been heady years for renew-ables, their rapid penetration into energy mar-kets has revealed key challenges that must be addressed. Certain types of renewable energy resources, such as biomass, geothermal, and hydropower, are available constantly and can be integrated into the grid as baseload power plants. But the use of these energy sources may be con-strained by land use and other environmen-tal concerns or by a scarcity of sites with large resources.

By contrast, the sun and the wind offer the most ubiquitous forms of renewable, zero-emis-sions energy, and they both will be needed in significant quantities in any low-carbon future. But the best solar and wind energy resources are distributed unevenly in space and time, which can present difficulties to utilities that must deliver power when and where it is needed. Many of the best solar and wind resources are found in remote locations, requiring the construction of new transmission lines that are expensive and that can be very challenging to site.

The sun and wind are also variable energy resources, meaning that they do not provide energy steadily throughout the season, day, or even hour. Utility operators currently have lim-ited ability to ramp them up or down in response to fluctuating demand. Solar energy is available only during daylight hours, generally peaking around noon. Demand for electricity also tends to peak at mid-day, so solar farms can provide peaking power that is backed up, or “firmed,” by the quick-response power plants that utilities usually use to provide peaking power.

Wind, on the other hand, tends to be greatest during the night, when demand for electricity is generally lowest.39 To balance a sudden increase in wind or another energy resource, system opera-tors must reduce output from other power plants. Some regions have “must-take” provisions that require utilities to purchase any renewable power that is generated, regardless of whether such pur-chases minimize costs. China, Germany, Spain, and the Canadian province of Ontario all have feed-in tariffs that include must-take clauses.40

Yet sometimes a surge in wind may over-whelm a system’s ability to accept the power,

and North America, the true transformative potential of renewables lies in the develop-ing world, where the creation of a clean energy economy can avoid a fossil fuel-dependent devel-opment pathway and the security and envi-ronmental problems that this entails. Develop-ing countries are now home to more than half of global renewable electricity capacity. China, India, and Brazil rank among the strongest wind, solar, and bioenergy markets and also boast robust domestic renewables industries. Four of the top 10 wind turbine manufacturers, respon-sible for nearly 30 percent of global production in 2009, are Chinese or Indian.34 In 2007, China was estimated to be the world’s largest manufac-turer of PV cells, after having barely been a player in 2003.35

Globally, the share of wind and solar energy in total power generation remains small, but in some countries and states aggressive renewable energy policies have led to penetration levels exceeding 10 percent. Denmark generated 19 per-cent of its electricity from wind energy alone in 2008, and Spain and Germany produced 11 and 7 percent, respectively, of their electricity from wind and solar combined that year.36 (See Figure 2.) The U.S. states of Iowa and Minnesota gener-ated 8 percent of their electricity from wind in 2008, although wind and solar comprised only 1 percent of total U.S. electricity production.37

Some German states already produce more than

Perc

ent

Source: EIA

1990 1993 1996 1999 2002 2005 2008

Denmark 19%

Spain 11%

Iowa 8%

Germany 7%

India 1.9%U.S. 1.3%

China 0.4%

0

5

10

15

20

Figure 2. Share of Wind and Solar in Total Electricity Generation, Selected Countries and Regions, 1990–2008



Renewable Energy Laboratory on the feasibil-ity of integrating 30 percent wind and 5 percent solar power into the western United States found that, “Large amounts of wind in a small area may lead to challenging operational issues, but larger balancing areas can better accommodate the vari-ability from high wind and solar penetration.”43

In many cases, expanding load-balancing areas

requires the construction of new long-distance transmission lines that can be used to import and export electricity when there are sudden drops or spikes in wind and solar generation. The abil-ity to trade electricity across national borders, for example, is a critical assumption in a recent study by Germany’s federal environmental agency that analyzed the feasibility of completely decarboniz-ing that country’s power system by 2050.44

As wind and solar power play an even larger role in electric grids, energy storage will be needed to retain excess power for times of high demand. For nearly a century, hydroelectric pumped-storage has helped utilities balance vari-able loads, with current global capacity stand-ing at more than 123 GW, or 98.3 percent of all installed energy storage capacity.45 (See Figure 3.) In the United States, some 3 percent of all kilo-watt-hours delivered spend some time in storage, and the shares in Europe and Japan are closer to 10 and 15 percent, respectively.46

creating a situation of over-generation. In such cases, operators currently have two main options: (1) to export excess wind generation, and (2) to shut off or “curtail” wind generators. A third option, storing excess generation for later use, is possible today only in certain regions and at a limited scale, although the development of new energy storage technologies could enable large-scale storage in the coming decades.

Denmark, for example, is unique in being able to export its excess electricity to Norway and Sweden, where it is then stored in large pumped hydro plants and sold back to Denmark when prices are high.41 Denmark benefits from having access to a nearby market that is large enough to absorb (and store) its surplus power. The con-struction of additional transmission and inter-connections among power systems may enable more regions to follow Denmark’s example, but for now most operators must force wind genera-tors to reduce or “curtail” their output when it is not needed.

The U.S. state of Texas is a case in point. Whereas most of the continental United States is linked to one of two huge, interconnected grids, most of Texas is on an isolated grid that prevents it from importing or exporting electricity. As of mid-2009, this grid had about 8 GW of wind capacity but could accommodate only some 4.5 GW due to transmission constraints. Between December 2008 and July 2009, Texas curtailed between 500 MW and 1 GW—and occasionally up to 3 GW—of wind power daily, in many cases more than 30 percent of its daily aggregate wind output.42 The state’s wind turbines, in short, were unable to realize their full potential.

One basic technological improvement that will aid the integration of variable renewable energy is better wind and solar forecasting. The more accurately that utilities are able to antici-pate large changes in net load (the difference between electricity demand and solar and wind generation), the better they can plan on balanc-ing it using the rest of their generating fleet.

Another way to reduce the variability that comes with the expansion of wind and solar power is by increasing the geographic area and diversity of renewable resources within an elec-tricity system. A recent study by the U.S. National

The Desert Sky Wind Farm in West Texas.

Edw

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Jack

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energy storage (CAES), another storage technol-ogy, exist in Germany and the U.S. state of Ala-bama. Using a compressor during off-peak hours, CAES systems pump air into underground for-mations, where it is stored at high pressure until it is heated using natural gas and used to drive a high-temperature combustion turbine during peak hours. Although underground CAES appli-cations are constrained by geology as well, they can have capacities in the hundreds or thousands of megawatts. Smaller above-ground systems using steel tanks or other vessels could be used for smaller-scale, distributed compressed air stor-age but are not yet commercially available.50

Off-peak electricity can also be used to create hydrogen gas from water using an electrolyzer. This hydrogen could be used to power a com-bustion turbine or a proton exchange membrane (PEM) fuel cell. These technologies are cur-rently cost competitive with batteries for electric-ity storage, but are double or more the price of pumped hydro storage, CAES, or backup genera-tion from natural gas combustion turbines.51 (See Figure 4.)

Additional technologies, such as flywheels, superconducting magnetic energy storage (SMES), and ultracapacitors, are being tested to provide energy storage over much shorter time-frames than pumped hydro or compressed air—a characteristic that is useful for supplying rapid-response load “regulation,” power quality, and grid stabilization.52 Plug-in electric vehicles could

During off-peak hours, pumped storage plants use cheap electricity to pump water to higher elevations, and then use that water to drive tur-bines at peak hours when electricity is expen-sive. Although pumped storage involves a net loss in electricity generated, the price differential between the kilowatt-hours it uses and those it sells can be sufficient to make it profitable.47 The arbitrage opportunities created by this peak/off-peak price differential, along with the demand for storage from wind and solar power plants, are attracting new innovation and investment in other areas of the energy storage field as well.

Wind plants from Hawaii to Ireland are begin-ning to test battery systems that can store their excess power for lean times. Xcel Energy, the larg-est wind purchaser in the United States, recently tested the use of a 1 MW sodium sulfate battery coupled with an 11.5 MW wind plant in Min-nesota and found the battery to be effective in balancing or firming modest amounts of wind, although additional testing was recommended and the technology remains some years from being commercial.48 Still, some analysts believe that recently developed batteries, which have reported efficiencies of more than 90 percent, could provide affordable storage that is competi-tive with pumped storage, which can deliver only about 70–85 percent of the electricity it con-sumes and is constrained by geology and envi-ronmental concerns.49

Two examples of utility-scale compressed air

Source: Lin

Other 1.7%

Molten Salt 0.1%

Other 0.1%

PumpedHydro98.3%

Batteries0.4%

CompressedAir

0.4%

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Figure 3. Share of Global Installed Capacity of Selected Energy Storage Technologies



duce. But as solar and especially wind power are deployed in ever-greater quantities, utili-ties must find additional flexibility in the grid to accommodate this development and deploy-ment period, which could take years to decades. Fortunately, a range of efficient natural gas power plants is poised to play this role today, balancing renewable resources while displacing dirtier elec-tricity generated by an aging coal fleet.

serve as an enormous, diffuse system of batteries for electricity storage as well, charging from the grid during off-peak hours at night and with-drawing or returning power to the grid whenever the vehicles are plugged in.

In addition to innovations that improve grid reliability on the supply side, new technologies are enabling operators to manage the demand side as well. Historically, electricity has been sup-plied when and where it is needed in response to demand that is oblivious to price. But new “smart grid” technologies and infrastructure being tested in locations from the island nation of Malta to Boulder, Colorado, will make it easier for consumers to change their electricity usage in response to prices or other signals.53 Advanced metering and a range of smart appliances can display and react to real-time price informa-tion from utilities. Smart grid systems also allow operators to better visualize the grid, moni-tor distributed generation and storage, control transmission and distribution lines, and balance increasingly variable loads.

Better forecasting, expanded transmission, improved energy storage, demand response, and other elements of a smarter, leaner grid will play a large role in mitigating the variability and uncertainty that wind and solar energy intro-

Compressed airenergy storage

Pumped hydro

Natural gascombustion turbine

Hydrogencombustion turbine

NaS battery

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0.0 0.2 0.4 0.6 0.8 1.0

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$0.14

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$0.28

$0.50

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Figure 4. Estimated Levelized Cost of Backup Electricity


R

The Renaissanceof Natural Gas

be transported cheaply in rail cars or tankers with little additional infrastructure, natural gas has rel-atively high transport costs. For most of the 20th century, it was transported exclusively through pipelines in a compressed gaseous form (CNG), necessitating significant investment in pipe-line infrastructure. More recently, technological advances have permitted suppliers to liquefy nat-ural gas and transport it in cryogenic tankers. Liq-uefied natural gas (LNG) requires special export and import terminals, which are expensive to con-struct and have in some cases met with opposi-tion due to concerns about their vulnerability to fires as well as their aesthetic and environmental impacts. LNG also has higher upstream emissions than CNG because of the fuel requirements for transporting it over long distances.

Historically, to finance construction of the pipeline infrastructure needed to distribute natu-ral gas, suppliers entered into long-term contracts with customers for the purchase of the gas. These contracts generally linked the price of natural gas to the price of oil (the product whose share of the heating market natural gas producers hoped to undercut) and included take-or-pay clauses that required customers to pay for a minimum amount of natural gas, whether they needed it or not. Long-term contracts also provided custom-ers with supply security and a degree of insula-tion from price fluctuations.5

During the last century, suppliers in North America and Europe developed robust pipeline networks to transport and distribute natural gas, which was then used, among other applica-tions, to generate electricity, to provide heat for buildings and industry, and as a feedstock in the petrochemicals industry. Asian countries such as Japan, South Korea, and Taiwan, which are

ecent developments have positioned natural gas for a renaissance. Tectonic shifts in the energy arena are trans-forming a natural gas landscape that

has been dominated historically by three rela-tively isolated markets in North America, Europe, and industrialized Asia. Natural gas is now becoming a truly global market, characterized (as with renewable energy) by greater geographic diversity of both supply and demand.

More abundant and diverse supplies of natural gas worldwide have reduced consumers’ concerns about the price volatility and limited availability of the fuel, renewing interest in the environmen-tal advantages that natural gas can provide. Of all major fossil fuels, natural gas burns most cleanly, emitting a fraction of the carbon dioxide, nitro-gen oxide, sulfur dioxide, mercury, and other pol-lutants that coal and oil release.1 Natural gas also can be used in a range of efficient power plant, vehicle, and heating applications.2

As a result, natural gas is being re-examined for its potential to supply baseload electricity, compet-ing with cheap kilowatts available from coal power plants. Between the insatiable Chinese demand that helped drive the slow but steady growth in coal prices over the last decade and the expectation that stricter emissions regulation will make coal plants more expensive to operate, natural gas is starting to look like a good deal for many utilities.3

Fifty years ago, natural gas played a modest role in the global energy economy compared to coal and oil. But over the last half-century, natu-ral gas’s share of global primary energy use has increased from 16 to 24 percent, while oil and coal’s combined share fell from 79 to 64 percent.4 (See Figure 5.)

Unlike solid and liquid fossil fuels, which can


The Renaissance of Natural Gas

gas. The first is the wide availability of inex-pensive coal in much of the world. Although modern natural gas power plants can be built more quickly and cheaply than any other type of utility-scale power plant, the cost of running a natural gas plant is much more sensitive to the price of the fuel than for other plant types.15 (See Figure 7.) When the price of natural gas is high, as it was during much of 2005–08, power system operators use natural gas plants primarily

large natural gas consumers but have very limited domestic supplies, must import virtually all of their natural gas as LNG, most of which they still secure through oil-linked long-term contracts rather than via pipeline.6

Because of the large costs associated with building pipelines, natural gas is much less com-monly used in the residential, commercial, and power sectors of developing countries. Even coun-tries that are rich in natural gas may not be able to afford the infrastructure required to utilize it. As a result, there is a wide disparity in the share of natural gas in the energy mix in different parts of the world, ranging from 47 percent in the Middle East to only 5 percent in China and India.7 (See Figure 6.) Significant differences in natural gas dependence exist within regions as well: in Africa, for example, Algeria and Egypt rely on natural gas for over half of their primary energy use, whereas South Africa’s natural gas use is negligible.8

Nigeria is home to the eighth largest natural gas reserves in the world and produced an esti-mated 1.3 trillion cubic feet (tcf) in 2008.9 But it consumed only 430 billion cubic feet (bcf), mostly in the power sector.10 It vented or flared an additional 670 bcf—enough to supply Nor-way and Poland combined—because it lacked the means to transport it to end-users nation-wide.11 Globally, nearly 5 tcf of natural gas was flared in 2008, equivalent to about 5 percent of global consumption.12

Although Nigeria is seeking to increase its gas exports as LNG and through a newly constructed pipeline to Ghana, its situation resembles that of many major gas producers in the Middle East, where natural gas is frequently reinjected into the ground to enhance oil production rather than being sold or flared.13 This application is in part a result of the high price of oil relative to natural gas, but the relative lack of distribution infrastructure has also severely limited the use of natural gas in this gas-rich region of the world. Nevertheless, the International Energy Agency (IEA) projects that Middle Eastern demand for natural gas could increase rapidly over the next two decades.14

Aside from transportation and distribution infrastructure limitations, three other major factors have hindered greater use of natural

Perc

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Figure 5. Share of Global Primary Energy Use, by Energy Source, 1965–2009

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Figure 6. Natural Gas Share of Primary Energy Use, by Region, 2009



Although North America is largely self-suf-ficient in natural gas, and Asian gas consum-ers can now purchase LNG from a wide range of suppliers, the entry of China and India into global energy markets has raised concern about the sufficiency of natural gas supplies to satisfy a growing world appetite. In 2001, at a time when natural gas prices (and the fortunes of major gas producers such as Russia) were on the rise, a group of 11 nations began meeting as the Gas Exporting Countries Forum, informally known as “the OPEC of natural gas.”19 The group’s stated mission is to “identify and promote mea-sures and processes necessary to ensure that Member Countries derive the most value from their gas resources,” a goal that many analysts have interpreted as an intention to become a natural gas cartel.20

Since the end of 2008, however, the world has experienced a natural gas glut. Although the global recession and the contraction in com-modity markets have contributed significantly to keeping natural gas prices low over the past two years, the discovery of new supplies in “uncon-ventional” reservoirs has transformed the game in a more fundamental way, and could keep prices low in the years ahead. Energy expert Dan Yergin and his colleagues at Cambridge Energy Research Associates have described unconven-tional gas as “the most significant energy innova-tion so far this century—and one that, because of its scale, requires a reassessment of expectations for energy development.”21

Improved technology is at the core of the natural gas renaissance. In the 1970s, gas produc-ers in the United States began to develop “tight sands” using hydraulic fracturing, a method of injecting a mixture of water, sand, and chemicals into rock formations at high pressure to stimu-late microfractures and increase the formations’ porosity and permeability long enough for natu-ral gas molecules to flow into a wellbore. Since the 1970s, tight sands have grown to account for more than 30 percent of all natural gas produc-tion in the United States, and U.S. natural gas producers and service companies have become world leaders in developing these and other unconventional reservoirs, including coalbed methane and organic-rich shale.22

to generate intermediate and peak demand elec-tricity, relying on cheaper electricity, often coal, to meet the bulk of baseload demand.

Second, such price volatility, which can be affected greatly by external events (see Figure 8), has also left utility operators leery of becom-ing too dependent on natural gas.16 Jim Rogers, CEO of Duke Energy, one of the largest utilities in the United States, infamously likened natural gas to “crack cocaine” for the electric power sec-tor—implying that it is all too easy to develop a habit for modern natural gas plants, which can be built cheaply and quickly, but hard to avoid withdrawal when price spikes make these plants prohibitively expensive to run.17

A third major factor that has hindered greater use of natural gas is energy security concerns, as the resource has been concentrated historically in only a few countries. Europe, particularly Central and Eastern Europe, remains highly dependent on natural gas imported from Russia. Rising nat-ural gas prices over the past decade enabled Rus-sia to leverage its control over Europe’s natural gas supplies for political ends. One resulting price dispute with Ukraine in January 2009 left hun-dreds of thousands of Europeans without heat for days, prompting European Union officials to seek means to reduce the region’s vulnerability to interruptions in imports from Russia.18

2008

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Figure 7. Levelized Cost of Electricity of Selected Plant Technologies



Barack Obama and Hu Jintao announced the launch of a U.S.-China Shale Gas Resource Initia-tive, a program designed to apply U.S. shale gas expertise to assess China’s potential.28 Chinese progress since then has been brisk: Royal Dutch Shell and PetroChina announced a joint venture in China’s Sichuan province that same month, and PetroChina’s parent company CNPC is part-nering with Canadian producer Encana in Cana-da’s Montney and Horn River Shales.29

These projects are all part of what industry consultant Wood Mackenzie has called Chi-na’s “race for supply”—a wide-ranging search to secure new sources of natural gas and other resources to meet rising energy demand.30 With urbanization and industrialization pushing up energy demand in the residential and industrial sectors, and with concerns about the environ-mental impacts of old coal plants prompting new emphasis on natural gas in the power sector, the Chinese government is deliberately priori-tizing a heavier reliance on natural gas. In June 2010, the country’s National Energy Adminis-tration announced that the 12th Five-Year Plan (2011–15) aims to double the share of natural gas in China’s energy consumption from its current level of 4 percent.31

Natural gas demand is growing rapidly in India as well, where the power sector is antici-pated to be the largest driver of future mar-ket growth.92 Indian energy company Reliance Industries sealed two deals in 2010 to acquire

Hydraulic fracturing, as well as horizontal drilling techniques that increase the volume of a rock formation that can be developed by a single well, have unlocked vast new reservoirs of natural gas from low-porosity, gas-rich sedimentary rock formations that were previously uneconomical to develop. However, concern about the poten-tial environmental impacts of these approaches is widespread. Better regulation and adherence to industry best practices are needed to address the risks of water contamination, air pollution, and other community impacts.23 (See Sidebar 1.)

Organic-rich shales are currently the main driver of optimism and production growth in natural gas. In its 2010 Annual Energy Outlook, the U.S. Energy Information Administration (EIA) estimated the technically recoverable U.S. shale gas resource to be 347 trillion cubic feet, 30 percent higher than the EIA’s 2009 estimate.24 Although the United States and Canada are far ahead of the rest of the world in identifying and developing shale gas, it is not likely to remain a North American phenomenon for long. Major potential shale gas resources have been identified in Africa, Australia, China, India, Europe, and South America, and the first wells were fractured in 2010 in the Poland, Tunisia, and the United Kingdom.25

For Poland, which currently imports 52 per-cent of its natural gas from Russia, the advent of economically exploitable domestic shale gas resources could spell the end of a heredi-tary dependence on Russian natural gas giant Gazprom. Coal is responsible for 58 percent of Poland’s primary energy consumption, and substantial shale gas development could offer a cleaner alternative for the nation’s power sector.26 Hungary, Germany, and Ukraine, also believed to have as-yet undeveloped unconventional gas resources, could see similar opportunities. In 2010, the U.S. State Department launched the Global Shale Gas Initiative (GSGI) to promote the sharing of lessons learned by U.S. regula-tors and members of the natural gas industry with their counterparts in countries that are just beginning to explore for and develop unconven-tional natural gas resources.27

China, too, is eager to develop its unconven-tional gas reserves. In November 2009, Presidents

2010

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1976 1981 1986 1991 1996 2001 2006 20110

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12Height of commodity boom

Hurricane Katrina

Beginning of Iraq WarCalifornia energy crisis

Figure 8. U.S. Natural Gas Prices, 1976–2010



imports began in 2004, although the country’s actual LNG imports in 2009 were only 445 bcf, equivalent to 24 percent of domestic natural gas consumption.34

The growth in LNG trade will affect global natural gas markets significantly. Anticipating increases in both prices and demand, natural gas exporters and importers around the world set off

more than 800 square kilometers in the Marcel-lus Shale—an enormous, gas-rich sedimentary basin underlying much of Appalachia in the eastern United States—and the Indian govern-ment plans in 2011 to auction leases in Indian states suspected to hold shale gas reserves.33 India is also investing in LNG import capacity, which has grown to 1.5 tcf per year since LNG

Sidebar 1. Addressing the Environmental Risks of Unconventional Gas Production

Over the past decade, the application of two drilling technologies—horizontal drilling and hydraulic fracturing—to low-porosity rock formations such as deep organic-rich shales, tight sands, and coalbed methane deposits has dramatically increased estimates of technically recoverable natural gas around the world. Scaling up production of these resources involves environmental risks that must be addressed if new supplies of natural gas are to be extracted sustainably.

Improper well construction, including the use of faulty cement and steel tubing or “casing,” can lead to well blow-outs and contamination of ground water by methane, chemicals used during hydraulic fracturing, and highly saline water from deep rock formations. Several tools are available to drilling operators that can detect poor well construc-tion before hydraulic fracturing begins or natural gas begins to be produced, including cement bond logs and negative pressure tests, which test the integrity of the cement and casing. While hydraulic fracturing is being performed, opera-tors can use microseismic monitoring to detect the extent of the underground microfractures and ensure that these do not extend beyond the target formation.

At the surface, fracturing fluid chemicals, as well as the liquid and solid waste produced from natural gas wells after drilling and hydraulic fracturing, must be stored, transported, and disposed of safely to avoid leaks and spills of potentially toxic substances into surface and ground water. Creating containment structures around the wellpad, using closed steel tanks instead of open pits to store materials, and monitoring storage units and pipelines holding and transporting fluids at and away from the drilling site are important precautions against leaks and spills. In addition, public disclosure of the chemicals used in hydraulic fracturing is important to enable government and health profes-sionals to react swiftly and appropriately in case of exposure or contamination.

Horizontal drilling and hydraulic fracturing are water-intensive activities and can require millions of liters of water per well. Treating and recycling waste water on-site reduces the amount of fresh water required for hydraulic fractur-ing while also lowering the burden on wastewater disposal facilities and the risks of leaks and spills associated with transporting the fluids offsite. Drilling operators should also work with communities to manage the timing and volume of their water intake so it does not interfere with competing demands for water supplies.

The process of extracting natural gas releases emissions of greenhouse gases and other pollutants from compres-sors, pumps, and other equipment on the wellpad, as well as from trucks used to transport materials to and from the drilling site. Methane, a potent greenhouse gas, can be released during natural gas production, transport, and distri-bution. Careful monitoring of equipment and infrastructure and the installation of emissions control technologies are among many steps that operators can take to reduce emissions and air pollution from natural gas systems.

Finally, developing natural gas, as with any energy resource, affects the communities in which it occurs. During the days and weeks that a well takes to drill and be fractured, truck traffic, noise and light pollution, and use of public re-sources increase. Operators must work with local stakeholders to minimize the negative impacts of gas development activities on a community’s resources and quality of life.

Strict regulatory standards and oversight of well construction and operation are essential to ensuring drilling safety and environmental and community protection. In the United States, where regulation of well construction and opera-tion is left largely to the states, recent incidents of water contamination and other accidents relating to improper well construction suggest that not all states are adequately regulating and enforcing the protection of public resources during natural gas extraction. The U.S. Environmental Protection Agency is currently studying hydraulic fracturing’s po-tential impacts on water quality, and environmental advocates in New York and Pennsylvania are pushing for moratoria on shale gas drilling until the study’s results are released in late 2012.

Source: See Endnote 24 for this section.



supercritical coal plants do on a lifecycle basis, and with many world governments putting a price on carbon, natural gas stands to pick up signifi-cant market share from coal in the power sector over the next few decades.42 (See Figure 10.)

The shift from coal to natural gas is happen-ing all over the world as communities pursue low-carbon electricity and as utilities, weigh-

an unprecedented boom in construction of new liquefaction and regasification plants before the recent recession sent prices plummeting.35 Over-all, LNG trade has grown steadily over the last decade, both in absolute volume and as a share of global natural gas consumption.36 (See Figure 9.) The IEA predicts that this share will continue to grow, driven in large part by increased exports from Africa, Australia, Latin America, and the Middle East.37

Although LNG typically has been sold in oil-linked long-term contracts, especially to Japan and South Korea, a growing amount is now being sold on spot markets, which allow LNG shipments to seek the highest bidder on a truly global market. This decade’s divergence in oil and natural gas prices (U.S. spot natural gas prices at their peak reached the equivalent of only about $80 per barrel of oil, while oil prices have been well over $100 per barrel) has greatly increased the differential between contract prices and spot prices—a trend that is encouraging consumers in Europe and Asia to buy more of their natural gas on spot markets.38 During 2009, major Euro-pean gas distributors E.ON and Eni renegotiated contracts with Russia’s Gazprom to reduce their exposure to oil-linked prices.39 India has also rebelled against high long-term contract prices for LNG, shifting its attention instead to cheaper LNG shipments on the spot market.40

With the current natural gas glut driving up competition for natural gas markets for the fore-seeable future, some exporters risk losing the market power they enjoyed under a paradigm of limited import options, binding long-term con-tracts, and oil-linked prices. Last year, the Gas Exporting Countries Forum prioritized a study on how to preserve oil-linked prices in natu-ral gas contracts—prices that during 2009 were roughly double the European spot market price of natural gas.41

Aside from increasing supplies and fall-ing prices, a major political factor is expected to dramatically increase the demand for natural gas: concern about the sizable negative climate, environmental, and public health impacts associ-ated with traditional coal power plants. Modern natural gas combined-cycle (NGCC) plants emit about 50 percent less CO2 than new advanced

Expo

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Figure 9. Global Liquefied Natural Gas Exports, Total and as Share of Natural Gas Consumption, 2001–09

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IGCC = Integrated Gasification Combined Cycle; NGCC = Natural Gas Combined Cycle; Imported LNG = liquefied natural gas from Trinidad and Tobago; Domestic NG = U.S. compressed natural gas from combination of a) onshore conventional gas, b) onshore associated gas, c) offshore gas, d) Barnett Shale, and e) various coalbed methane fields.

Figure 10. Lifecycle Greenhouse Gas Emissions from Coal and Natural Gas Power Plants



tory certainty on power plant emissions. Ana-lysts estimate that if all coal-fired power plants in the United States were required to install sul-fur dioxide scrubbers to meet federal emissions standards, a growing number of small coal plants would cease to be economic to operate, and coal-fired electricity generation could fall almost 10 percent between 2009 and 2015.43 Governments from New Delhi to Denver have announced plans to retire old coal plants in favor of new natural gas capacity.44

Aside from the environmental problems asso-ciated with coal power plants—which include emissions of ozone precursors, particulate matter, and mercury as well as issues surrounding coal mining and coal ash disposal—these facilities are plagued by another serious flaw: they make poor partners for variable renewable electricity sources such as wind and solar power. Thus, displacing coal with natural gas can not only deliver emis-sions savings, but also strengthen the grid’s abil-ity to accommodate greater variability.

ing the low construction costs of natural gas power plants against the high construction costs and anticipated additional costs of compliance with environmental regulations associated with coal plants, opt to take their chances on stable natural gas prices rather than wait for regula-

An LNG terminal in Shizuoka, Japan, with Mt. Fuji in the background.

Tnk3

a


Natural Allies in the 21st-Century Grid

ariability has traditionally been one of the most important challenges facing

utilities. Demand for electricity varies throughout the year, week, day, and even

hour as millions of appliances are switched on and off, thermostats are adjusted, and house-holds, businesses, and factories come to life in the morning and shut down at night. Power-system operators manage a portfolio of power plants, adjusting generation in real time using com-puter-based software so that it always equals the sum of demand, or “load.” Failure to balance load and generation can result in brownouts, black-outs, or power surges that can damage utility- or customer-owned equipment.

To meet demand, a system operator works like a sports coach, drawing from a large team of generating units. Each player or power plant has a particular skill set that is useful for different situations during a game. Some players may sit on the bench for most or all of the season but are available “just in case.”

The backbone of a generating portfolio has traditionally consisted of coal, nuclear, or geother-mal steam turbine power plants, whose large size and low operating costs make them well suited to provide large quantities of cheap “baseload” electricity. Operators generally run such plants all the time at their maximum capacity, interrupting generation only for planned or forced mainte-nance. Turning these plants on and off is a pon-derous process that can take days, and reducing or increasing plant load within its design minimum and maximum levels is slow and reduces plant efficiency.1 Nevertheless, as data from Texas’s elec-tric grid (ERCOT) demonstrate, many utilities regularly cycle steam-turbine plants, including those powered by coal. (See Figure 11.)

As load increases during the day, operators bring on “intermediate” plants. Unlike basel-oad plants, load-following plants are designed to be “ramped,” or throttled up and down. In the United States, natural gas combined-cycle plants are typically used as load-following plants, with utilities dispatching them in order of ascending cost. Not all electricity systems are organized this way, however: in India, which currently has lim-ited access to natural gas, generators tend to rely more on coal-fired power plants for intermediate as well as baseload generation.2

Finally, operators will use “peaking” plants—usually natural gas-fired simple-cycle com-bustion turbines—to provide electricity when demand is highest. Although any plant can be forced to cycle up and down, plants ramp at dif-

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Figure 11. Sample ERCOT (Texas) Load Curve, July 8–14, 2009

V



in the same range of technologies as natural gas.Wind and solar add an additional layer of

variability to the system operator’s task. As the share of demand met from these variable sources rises, managing the power grid will require a range of new technologies, policies, and infrastructure. Although many regions have begun the transition to renewable energy, the sequencing of this transition has posed chal-lenges in some areas. The installation of new wind and solar power capacity has outstripped the development of transmission, new sources of firming generation, and enabling technolo-gies such as energy storage, demand response, and the smart grid.

As a result, some early adopters of wind and solar energy have encountered unexpected fric-tion between their 21st-century renewable elec-tricity and the 20th-century grid. For example, in places where wind power is a “must-take” resource and the grid includes a large share of coal-fired capacity, such as the U.S. state of Colorado, a sudden surge in wind generation could require utilities to rapidly ramp down coal plants, presenting challenges for balancing power generation efficiently.5 (See Sidebar 2.) Natural gas plants, in contrast, whether combined-cycle or simple-cycle gas turbines or reciprocating engines, have much faster ramping capabili-ties and operate more efficiently at partial loads, making them much better suited to accommo-date surges in wind generation.

Gas Offers Flexibility to the Grid

The integration of variable renewable energy presents challenges to utilities that generate most of their baseload energy from coal power plants. Unlike coal, natural gas can be used in a remarkably wide range of generating technolo-gies, from steam turbines and combined-cycle plants to combustion turbines, reciprocating engines, and fuel cells. Because of these plants’ diverse characteristics, utilities can use natu-ral gas to generate baseload, load-following, or peaking power. Moreover, with the exception of natural gas steam turbines, which have been ren-dered more or less obsolete by the invention of much more efficient combined-cycle plants, nat-ural gas power plants can be built more quickly

ferent rates, sacrifice various degrees of efficiency when they are operating below their full capac-ity, and have minimum design loads—points below which they must be turned off completely. Peakers are typically less efficient than load-following plants but can achieve the most rapid cold starts, ramp most quickly, and operate rela-tively efficiently at minimum loads.

Natural gas-fired combustion turbines, essen-tially large jet engines, are the most common plants used as peakers and can start in about 10 minutes.3 Recently, some utilities looking for even more rapid response have invested in natu-ral gas-fired reciprocating engines, which can reach full output from a cold start in less than five minutes and lose less efficiency than both combined-cycle and gas-turbine plants when they are operated at less than full load.4

Intermediate and peaking plants may be used to provide “spinning reserve” to a grid—gen-eration that is essentially kept idling in case the grid has an immediate need for power due to an unpredicted spike in demand or a sudden loss of power from another plant. These resemble team players who warm up in case they are needed. A range of other ancillary services, such as “non-spinning reserve” (generators that can achieve cold starts in less than 10 minutes) and “regulation” (generators that can turn up or down to compensate for generators that pro-duce more or less than they are scheduled for and keep the electricity system’s voltage in the right range) also help keep the players working together smoothly.

Renewable electricity fits into this conven-tional fossil fuel-based paradigm at different levels. Hydroelectric power plants can respond rapidly, so they can be used to provide baseload, intermediate, or peaking power. Pumped storage units in particular are designed, like any energy storage technology, to return power to the grid during peak hours. Geothermal plants, which are expensive to site and build but one of the cheapest power sources to operate, are usually used for baseload power. Biomass is used most commonly in steam turbines, either combusted alone or co-fired with coal. Biogas, which may be produced from anaerobic digesters, biomass gasifiers, or captured from landfills, can be used



the Los Angeles Department of Water and Power, using a combination of its natural gas generation and transmission resources to back up the vari-able generation it will purchase from the Windy Point Wind Farm in Washington State. Announc-ing the contract, Calpine’s chief commercial offi-cer commented that it “demonstrates the critical role natural gas generation will play in integrat-ing renewable generation into the marketplace and helping California’s load-serving entities meet their renewable energy needs.”7 In the past few years, Finnish power plant manufacturer Wärtsila has supplied reciprocating engine power plants to provide flexibility to systems from Col-orado to Texas, describing their product as “the wind enabler.”8

and with lower capital costs than coal plants. Although natural gas has been considered a

cleaner alternative to coal for decades, the flex-ibility that it offers to electricity portfolios con-stitutes an additional critical way that it can con-tribute to a low-carbon energy economy. For the near future, natural gas is one of the most cost effective and widely available ways to store and provide energy to balance or firm wind and solar energy on a large scale, facilitating their penetra-tion into the energy system.6

Some power producers are already exploring innovative ways to use natural gas plants to back up variable renewable energy. The California-based Calpine Corporation recently signed a con-tract to provide up to 270 MW of firm power to

Sidebar 2. Wind Integration Hits Turbulence in Colorado

In 2007, the U.S. state of Colorado strengthened its renewable portfolio standard (RPS) to require utilities to gener-ate 20 percent of their retail electricity sales from renewable energy by 2020. With government support, along with excellent wind resources along the Rocky Mountains, Colorado’s wind energy industry was flourishing. Some 776 MW of new wind turbines were installed in 2007, increasing the state’s total wind capacity by 169 percent, and by 2008 the state was already generating an average of 6 percent of its electricity from wind alone.

But Colorado faces challenges in integrating renewable energy efficiently into its power mix. Just after four in the morning on July 2, 2008, winds began to pick up over part of the state. That morning, regional wind turbines were pro-viding a modest 5 percent share of the power generated, around 200 MW, to the Public Service Company of Colorado (PSCO), the state’s largest electric utility. Over the next 90 minutes, however, wind generation quadrupled to about 800 MW, then fell rapidly to around 200 MW. The entire wind event was over by 8 a.m.

Wind power is treated as a “must-take” resource in Colorado, which means that system operators had to turn down other power plants—such as coal and natural gas—to make room for the unexpected wind generation. In recent de-cades, the share of coal in Colorado’s electricity generation has declined from 92 percent in 1990 to only 65 percent in 2008, yet coal plants still provide the bulk of baseload power generation; meanwhile, natural gas’s share has increased from 4 percent to 25 percent. But at 4 a.m. on July 2, when power demand was low, natural gas accounted for only 10 percent of generation, while coal made up 60 percent. As a result, the surge in available wind power forced PSCO to rapidly ramp down at least four coal plants and then ramp them up again to accommodate the additional generation in the low-demand hours between 4 a.m. and 7 a.m.

Coal power plants, virtually all of which use steam turbines to generate power, are not designed to ramp up and down quickly. Steam turbines take days to reach full power from a cold start. Natural gas combined-cycle plants, by contrast, can typically achieve a cold start in about three hours, and they ramp up and down at a rate of about 7 percent of their capacity per minute. Steam turbines also become much less efficient when they are operated at less than full capacity, or “partial load.” Combined-cycle power plants, simple-cycle combustion turbines, and reciprocating engines all lose less of their efficiency as they are ramped down to partial loads.

Rapid cycling of coal plants could, at least in some cases, also lead to a spike in emissions penalties. U.S. coal power plants are generally fitted with some sort of emissions control technology to remove sulfur dioxide, nitrogen ox-ides, and other pollutants from plants’ flue gases, and these technologies are designed to be operated with plants that are running at full capacity. Emissions monitoring data from the U.S. Environmental Protection Agency reveals that in some cases, plants experience spikes in emissions rates after being cycled. When plants are cycled down or up more rapidly than their design ramp rates, emissions control devices may be temporarily overwhelmed.




Gas-Renewable Hybrids Combine Strengths

Some engineers have sought to mitigate the intermittency of solar energy through inter-ventions at the plant level. Concentrating solar power (CSP) in particular lends itself to a range of hybrid generation configurations because it utilizes a steam turbine to convert solar radiation to electricity. Hybrids offer a range of benefits: for example, natural gas-solar hybrids avoid the extra cost of generators, transmission, and per-mitting that separate solar and natural gas plants would require.9

The Solar Energy Generating System (SEGS) plants, nine parabolic-trough CSP plants built in southern California between 1985 and 1991, use natural gas to generate backup steam for the plants.10 In 2008, the plants’ steam turbines generated over 746 GWh of electricity, only 11 percent of which came from natural gas.11 The remaining 665 GWh constituted 77 percent of all grid-connected solar powered generation in the United States that year.12

Although using natural gas to provide backup power for the steam turbines of solar thermal plants is relatively inefficient—the SEGS plants achieved an average efficiency of just 24 percent when burning natural gas in 2008—it nonethe-less enables solar thermal plants to produce reli-able electricity throughout the day.13 According

to one solar energy expert, the SEGS plants “have not missed one hour of peak output in their life-time.… When Mt. Pinatubo blew ash into the sky, they just burned a little more gas.”14

Morocco recently built a 470 MW hybrid solar-natural gas combined-cycle plant using a technology called Integrated Solar Combined Cycle (ISCC).15 This plant combines heat from a 20 MW solar thermal field with waste heat from the plant’s gas turbine to power a steam turbine. Egypt and Algeria also both plan to build ISCC plants.16

The potential synergies between CSP and con-ventional steam turbines have also created interest in the feasibility of grafting solar thermal fields onto existing coal or natural gas power plants, using the steam they produce to replace steam that otherwise would be generated by burning fossil fuels. In southern Florida, the FPL Group utility is constructing a two-square-kilometer, 75 MW CSP plant to be added to an existing 3.8 GW power plant powered primarily by natural gas.17 The approximate cost of the addition was $476 million.18 The Electric Power Research Institute is investigating options for adding solar thermal capacity onto existing coal power plants in New Mexico and North Carolina.19

Despite growing interest in such hybrids, CSP is limited to sites with large, flat areas, plenty of direct sunlight, and the ability to get land permits and build transmission lines. It can also require large amounts of water for cooling, although many new CSP plants are being designed to use dry cooling systems that enable them to operate in water-poor areas such as northern Africa and the U.S. Southwest.20

Because wind and solar PV create electric-ity without an intermediate steam turbine, fewer examples exist at the plant level of hybrids that pair these renewables technologies with conven-tional power plant technology. One Colorado-based company, Hybrid Wind Turbines, has developed a hybrid natural gas-wind turbine sys-tem that uses natural gas to run a ground-based turbo-compressor, where the compressed air drives a turbo air motor to drive the generator.21 This technology was announced only recently, however, and it remains to be seen whether it can provide a cost-effective means of firming genera-

Cleaning solar panels at the recently built ISCC plant in Morocco.

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percent increase over 2008.25 Small wind power allows residential, commercial, and light indus-trial users, both on and off the grid, to create renewable electricity, but it still suffers from the intermittency issues that plague industrial-scale wind power. In 2009, about 20 percent of turbines in the 50–100 kW range were sold for wind-diesel hybrid systems, which use diesel backup generators to firm variable power from off-grid wind in remote areas.26

One of the biggest strengths of solar PV is its ability to be installed at a range of scales on resi-dential and commercial rooftops, with virtually no additional land required. This makes it useful for densely populated areas. The average size of PV projects has increased in recent years, leav-ing very small off-grid systems with only about 5 percent of the global PV market.27 Yet although estimates still place rooftop PV costs at over 30 cents per kWh, even with tax incentives avail-able in the United States, small off-grid PV has already reached parity with fossil fuels in many remote regions of the world.28 (See Table 1.) Like their utility-scale cousins, small PV installations generate variable energy and must be firmed with additional power from the grid, or from wind turbines, backup generators, or battery storage systems if they are not grid-connected.

tion from existing and new wind farms.Another Colorado company is taking a dif-

ferent approach to firming variable wind power with flexible natural gas generation at the plant level. Altresco proposes to co-locate a combi-nation of combined-cycle, gas-turbine, and reciprocating-engine generators with a wind plant. These diverse generators would be inte-grated with a micro-grid that can balance load internally, creating a dispatchable, heterogeneous power plant that could be run at capacity fac-tors similar to baseload coal and nuclear plants. These high capacity factors, together with wind’s low fuel costs and natural gas’s low capital costs, result in levelized costs that could be competitive with current baseload electricity prices—all while emitting only a third less CO2 than natural gas combined cycle alone.22 (See Figure 12.)

Gas and Renewables Scale Down

Unlike coal or nuclear power, natural gas lends itself to a range of scalable generating technolo-gies that could form the backbone of an efficient distributed energy system. Electricity planners can reduce the need for building new high-volt-age transmission lines by relying increasingly on distributed generation (DG): power sources that are smaller than 10–20 MW and that are con-nected to local distribution networks rather than to the high-voltage transmission grid.

These “micropower” generators produce electricity close to or at its point of use, mini-mizing the losses associated with long-distance transmission while reducing the system’s vulner-ability to blackouts, terrorist attacks, or other sudden losses in generation.23 Micropower adds geographic versatility to systems dominated by large, centralized power plants, as small generat-ing units can be sited closer to demand centers and can deliver power to areas that have little or no access to the grid.24

Both wind and solar energy can be used to provide micropower. Off-grid as well as grid-connected small wind turbines (with capaci-ties of 100 kW or less) have proven popular in the United States, China, and parts of Europe. Although these turbines still represent a marginal share of the global wind market, an estimated 43 MW of capacity was installed last year—a 10

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Figure 12. Levelized Cost of Electricity and Carbon Dioxide Emissions for Selected Baseload Power Options



of its power from CHP plants in 2008, but state and federal government support for cogeneration and distributed generation through renewable portfolio standards and other policies will likely increase this penetration.31

Of the five main technologies that can be used in CHP applications of different sizes—steam turbines, reciprocating engines, gas turbines, microturbines, and fuel cells—only steam tur-bines can run on solid fuels such as coal or bio-mass. The rest usually use natural gas or, in some cases, a liquid fuel such as gasoline, diesel, etha-nol, or a gasified solid fuel. As in conventional applications, steam turbines in CHP applications suffer from long start-up times, making them poorly suited to firm variable renewable genera-tion. By contrast, gas turbines and microturbines used for CHP can be started in less than an hour, and reciprocating engines require only 10 sec-onds to start, making them the most responsive generating technology. Fuel cells, which pro-duce the least emissions and noise and have high efficiencies even at partial loads, start even more slowly than steam turbines, and therefore cur-rently are most commonly used to provide basel-oad power.32 (See Table 2.)

Microturbines, reciprocating engines, and fuel cells all can be used in applications smaller than 0.5 MW, suitable for distributed genera-tion in the commercial and residential sectors. A growing number of power companies is becom-ing interested in micro-CHP, systems of less than 1 kilowatt in capacity that can be installed in the basement of single or multi-family homes. In 2009, 20,930 micro-CHP units were sold around the world, representing 38 MW of capacity.33

The cheapest distributed generation option available currently for natural gas is combined heat and power (CHP), or cogeneration. CHP plants simultaneously produce electric and ther-mal energy, most typically by combusting a fuel to drive a generator and capturing the result-ing waste heat for heating, cooling, or other uses. Compared to conventional generation with a separate boiler for heat, CHP systems generally offer substantial efficiency and emissions savings. For example, the IEA estimates that the average global efficiency of traditional fossil fuel power generation is 35–37 percent, with conversion losses from thermal production accounting for the bulk of the efficiency lost. Because CHP sys-tems capture and use some of that wasted heat, they can achieve efficiencies of 75–80 percent— and even 90 percent in the most modern plants.29

The combination of fuel savings and emis-sions reductions is a powerful argument for shifting to cogeneration where possible. Several European countries already generate more than 30 percent of their power using CHP systems, and Denmark’s share has surpassed 50 percent.30 The United States generated less than 7 percent

Table 2. Performance Characteristics of CHP TechnologiesTechnology Fuels Capacity Start-up Time

(megawatts)Steam Turbine All 0.5–250 1 hr to 1 dayReciprocating Engine Natural gas, biogas, propane, landfill gas 0.01–5 10 secGas Turbine Natural gas, biogas, propane, oil 0.5 –250 10 min to 1 hrMicroturbine Natural gas, biogas, propane, oil 0.03–0.25 60 secFuel Cell Hydrogen, natural gas, propane, methanol 0.005–2 3 hrs to 2 days


Table 1. Observed Costs Associated with Distributed Generation in the United States Natural Natural Rooftop Small Gas Gas Technology PV Wind Micro-CHP Fuel Cell

cents per kilowatt-hourObserved Cost, including current tax credits 33.9 20.2 9.2 19.1




For densely populated areas with robust natu-ral gas distribution infrastructure, such as in the United States, Europe, and parts of Asia, a shift toward energy systems powered by decentralized rooftop PV, small wind, and natural gas-powered micro-CHP that is networked by a smart grid would offer efficiency gains, emissions reduc-tions, and reduced need for new long-distance transmission, as well as thousands of jobs for the installation, integration, and maintenance of its components.

To enable global power systems to incorporate a growing amount of wind and solar generation effectively, a fundamental shift in our approach to electricity is necessary. Whereas system opera-tors in the 20th century employed a “one-tool-for-one-problem” style for balancing the supply and demand of electricity, 21st-century utilities must take a more systemic approach, optimiz-ing the reliability, economics, and environmental performance of their grids as a whole.

Japan is currently the world’s largest market for micro-CHP technology, installing more than 90,000 microturbine ECOWILL units based on Honda engine technology in the last decade.34 Micro-CHP is also attracting interest in the United Kingdom and Germany, where Volkswa-gen has contributed its natural gas engine tech-nology to the new EcoBlue micropower plants, part of a proposed smart, decentralized power system known as “SchwarmStrom.”35 Starting in Hamburg, the system will comprise 100,000 plants in residents’ basements, networked to cre-ate what will effectively be a 2 GW power plant. German energy supplier LichtBlick plans to mar-ket the EcoBlue units for 5,000 Euros ($6,800) each. The system’s flexibility is designed to accommodate Germany’s growing share of vari-able renewable energy.36 Micro-CHP installations in the United States have so far been low, but sev-eral products are now available, and federal and state incentives could stimulate future growth.


T

A Bridge to Somewhere

most flexible fossil fuel.1 But even the CO2 that natural gas emits will one day be too great for the world’s climate system. So far, natural gas has accounted for only some 10 percent of the CO2

vented to the atmosphere since 1860; but even-tually, as it supplants oil and coal, natural gas could become the largest producer of this potent greenhouse gas.2 If natural gas resources prove as abundant as some geologists now believe, this energy source may ultimately follow the fate of coal—phased out for environmental reasons long before the resource is exhausted.

LichtBlick, the architect of Germany’s SchwarmStrom concept for decentralized power, is all too sensitive to this reality. Germa-ny’s renewable energy capacity has more than doubled since 2000, and the country’s overall energy consumption has begun to decline, due in large part to a strong national commitment to dramatically reducing CO2 emissions and to the economic reality that renewables are now the single most dynamic component of the German economy.3 A 2010 study by Germany’s federal environmental agency projects that the country can generate 100 percent of its electricity needs from renewables by 2050 without sacrificing its current quality of life.4 As LichtBlick considers these shifts in Germany’s energy economy, the company has announced a long-term strategy of replacing its natural gas-powered genera-tion units with biogas, a renewable source of methane.5

At the chemical level, natural gas consists pri-marily of methane, a molecule made up of one carbon atom and four hydrogen atoms. Meth-ane is the simplest and most ubiquitous hydro-carbon, produced over millions of years from ancient organic matter trapped in rock forma-

he basic principles and structures that underlie the global energy economy have demonstrated remarkable resil-ience over the last century, despite

growing awareness of the fact that dependence on fossil fuels poses serious challenges to energy security, economic stability, the environment, and climate. The construction of tomorrow’s energy infrastructure—from pipelines and transmission lines to power plants and the new grid-control technologies that will increase efficiency, reli-ability, and customer responsiveness—must be undertaken with long time horizons in mind.

Over the next century, as innovation contin-ues to drive down costs for renewable energy and energy storage and as new policies make it increasingly expensive to emit carbon dioxide, natural gas extracted from fossil reservoirs could cease to be competitive as a source of baseload power. Some argue that natural gas is needed as a bridge fuel to a low-carbon energy economy; others, however, make the case that the dan-ger of relying on any fossil fuel is too great, and that no bridge is needed to ease the transition from today’s high-carbon world to a low-carbon future.

Given the inertia that characterizes energy systems, if governments invest in a low-carbon future built upon renewable energy and natural gas, whether their energy economies are mature or emerging, they must ensure that natural gas does not prove to be a “bridge to nowhere.” Yet to stay relevant in the long run, natural gas itself must decarbonize.

Relative to coal and oil, natural gas (and in particular its primary component, methane) has been called the “prince of hydrocarbons,” refer-ring to its stature as the cleanest burning and



to southern California’s Eastern Municipal Water District, which will power the plants with bio-gas produced onsite in an anaerobic digester.12 National Grid, a gas-and-electric utility serving New York, New Hampshire, Massachusetts, and Rhode Island, recently estimated that these states had a combined technical potential to produce 268 bcf per year of biogas and other renewable gas—equivalent to 16 percent of these states’ cur-rent demand for natural gas.13 The American Gas Association has estimated that the United States as a whole has upward of 1 tcf per year of untapped biogas potential.14

In 2004, 14 countries launched the interna-tional Methane to Markets Partnership to iden-tify and develop potential projects to capture and use methane from agriculture, coal mines, land-fills, and oil and gas systems.15 Mexico, for exam-ple, estimates that its agricultural sector produces methane equivalent to 40,000 gigagrams of CO2 every year—methane that contributes to climate forcing if it is not captured.

Renewable natural gas, whether produced in biomass gasifiers or anaerobic digesters, repre-sents the lowest-cost option to decarbonize dis-persed end-users of natural gas, such as houses that use natural gas for heating, according to an analyst at the Gas Technology Institute.16 Rather than requiring any adjustment to infrastructure and the point of consumption, biogas can be pro-cessed and fed directly into existing natural gas

tions, and generated within hours by anaerobic organisms that live in environments that range from marshes to landfills to the digestive tracts of cows. Methane can also be synthesized, most commonly through coal gasification. Molecules of methane are versatile: besides being energy carriers, they are simple building blocks that can be used to manufacture chemicals, fertilizers, and even hydrogen gas.

Methane is also a potent greenhouse gas, with a climate-forcing impact per gram that is some 25 times greater than CO2 over 100 years, and 72 times greater than CO2 over 20 years.6 As a con-sequence, extracting fossil fuels (whether coal, petroleum, or natural gas) releases methane that might otherwise remain locked underground—whereas capturing and using methane that is emitted naturally by livestock and landfills results in a net reduction in greenhouse gases. These sources make up the majority of methane emis-sions (55 percent); by comparison, the natural gas fuel cycle accounts for 17 percent, and coal mining for 12 percent.7 (See Figure 13.)

Biogical methane (biomethane) can be pro-duced from organic matter using two mecha-nisms: anaerobic digesters and biomass gasifiers. Both convert organic waste streams or dedicated biomass to a methane-rich gas and create addi-tional energy or revenue for landfills or farms. Europe has created strong incentives for the pro-duction of biomethane in the agricultural sec-tor. In particular, Germany is home to 30 times the number of anaerobic digesters as the United States, thanks in part to active engagement by farmers in lobbying for clean energy support from the government.8 The federal environ-ment agency’s aggressive scenario for a 100-per-cent renewable power sector by 2050 includes 11 terawatt-hours (or 2 percent) from biogas.9 As anaerobic digesters have proliferated worldwide, some projects have even applied for certification under the Kyoto Protocol’s Clean Development Mechanism.10

Biogas is moving ahead in the United States as well, albeit more slowly. Many states allow power generated from landfill gas or biogas to be counted toward renewable portfolio standards.11 In September 2010, FuelCell Energy announced the sale of 600 kilowatts of fuel cell power plants

Source: EPA

Livestock33%

Landfills22%

Natural GasSystems17%

Coal Mining and Abandoned Underground Coal Mines, 13%

Petroleum Systems, 5%

Wastewater Treatment, 4%

Forest Land, 2%Rice Cultivation, 1%Stationary Combustion, 1%Mobile Combustion, 1%Other, 1%

Figure 13. U.S. Methane Emissions by Source, 2008



manufacturer, creates 20 percent less CO2 when combusted in a vehicle engine or power plant and can deliver improved performance char-acteristics.19 Hydrogen for use in combination with natural gas is already being produced and piloted in countries such as India, where urban air-quality problems have forced regional and national governments to seek alternatives to die-sel in public transit vehicles.20

One day, renewable electricity might be used to power biomass gasification and anaerobic digestion of organic material into biogas, and steam reformation of biogas into hydrogen, com-pleting the transformation of methane into a truly sustainable prince of hydrocarbons.

transport and distribution pipelines.A well-to-wheels analysis conducted by the

California Air Resources Board concludes that biogas is currently one of the least carbon-inten-sive alternative fuels, representing carbon sav-ings over liquid biofuels and compressed natural gas.17 Fleet vehicles that are converted to run on natural gas could seamlessly switch to biogas. In 2005, Sweden began testing the world’s first bio-gas-powered train.18

Beyond biogas, natural gas can also be decar-bonized by adding hydrogen gas in quantities of up to 20 percent by volume. Hydrogen pro-duces no carbon emissions when it is com-busted, and the resulting gas, marketed under the name “Hythane” by one Colorado-based


Catalyzing the Low-Carbon Transition

The most fundamental step toward decar-bonizing the energy system is placing a price on carbon dioxide. Unless the environmental exter-nalities associated with burning fossil fuels are reflected in the price of electricity, decisions by utilities and regulators will continue to ignore the very different contributions that different power plants make to climate change. If cost is to con-tinue to be the main determinant of the order in which power plants are turned on, it must internalize the serious environmental externali-ties associated with burning fossil fuels. The car-bon price determined by the European Union’s Emissions Trading Scheme (EU-ETS) has, along with other climate policies, already begun to incentivize fuel switching from coal to natural gas and renewable energy in the power sectors of European countries such as Spain, where the past decade has seen a sharp rise in the share of natu-ral gas and renewable energy accompanied by a decline in the share of coal.3

Today, although many governments have cre-ated renewable energy targets and tax incentives to stimulate the construction of renewable energy, solar and wind power continue to face barri-ers in regulatory regimes that were not originally designed to accommodate and promote variable generation. In 2009, for example, the Bonneville Power Administration (BPA), the major transmis-sion provider in the U.S. Pacific Northwest, ruled that wind generators must pay a wind-integration rate of about $5.70 per megawatt-hour to com-pensate BPA for the cost of accommodating the increasing wind in its load. Historically, the costs of additional reserves for load balancing had been passed on to customers such as municipalities or public utility districts. The decision also gave BPA the ability to curtail wind generation if this

low-carbon energy system built on a partnership of renewable energy and natural gas does not depend on the uncertain arrival of new technologies.

But it will require a paradigm shift. The 20th-century energy economy is built around large, centralized power plants operated by utilities that turn their generating assets on and off to balance consumer demand. This approach, and the sys-tems on which it is built, will need to change.

Utilities currently have an incentive to dis-patch the least-expensive power first, regardless of its environmental impact. Their priorities have been and will continue to be the reliability of the system and profitability of their operations. With many utilities able to pass the cost of building new capacity on to consumers—and not hav-ing to pay for many of the environmental dam-ages that these plants cause—there has been little incentive for utilities to favor less carbon-inten-sive energy sources over coal plants that have cheap operating costs and relatively inexpensive and stable fuel prices.

Yet stricter regulations on sulfur dioxide, nitro-gen oxides, and mercury emissions from power plants, as well as efforts in many countries and states to put a price on CO2 emissions, are driving utilities in Europe and North America to recon-sider plans for new coal power plants, and even to consider closing existing plants. In the United States, the EIA projects that coal will fall from 18 percent of total new capacity constructed in 2009 to 10 percent in 2013, whereas natural gas will rise from 42 percent to 82 percent.1 Even in Europe, where many policymakers are leery of relying too heavily on natural gas for energy security reasons, in 2009 nearly three times as much new natural gas capacity was built as coal.2

A



generation overwhelmed BPA’s ability to accom-modate a surge. At the same time, BPA agreed to improve operations to reduce the cost of integrat-ing wind in the future. And it decided to offset the wind-integration rate for wind generators that self-supply some or all of the wind-balancing ser-vices their plants necessitate.4

The challenges facing BPA are not unique and offer a valuable lesson: integrating variable renewable energy requires transmission providers to make operational changes in order to ensure that the increased variability can be accommo-dated. To avoid curtailing a valuable low-car-bon source of power, electricity portfolios must reduce their dependence on inflexible baseload coal plants and substitute flexible natural gas capacity that can firm wind and solar generation.

Two key mechanisms can help electricity systems and system operators adapt to growing shares of variable renewable energy by increasing grid flexibility:

First, utilities should increase the granularity with which electricity prices are determined and signaled to generators. In the past, when grids relied on more conventional generating tech-nologies that could be dispatched at will, utilities could generally set prices and generating sched-ules on an hourly basis, correcting for any minor load imbalances with a range of expensive ancil-lary services. With growing amounts of wind and solar generation coming online today, however, hourly increments hamper operators from fine-tuning their generation when renewable electric-ity supplies deviate from forecasts.

In many regions, system operators now deter-mine prices and schedule generation every five to fifteen minutes, allowing them to use more accurate wind and solar forecasts and orchestrate their generating fleet in close to real time. Mov-ing to sub-hourly markets can improve utilities’ abilities to react to variable generation, and it can also incentivize a shift to more flexible natural gas generators that can be deployed in less than an hour. In the United States, regions with sub-hourly energy markets have been able to integrate higher percentages of wind energy than their neighbors with hourly markets.5

Second, allowing wind and solar plants to bal-ance their own output with on-site resources,

whether they be natural gas generators or energy storage, will allow them to generate power when they are needed. Co-locating remote renewable plants with natural gas generators will increase the utilization and improve the economics of any new power transmission lines that must be built. Allowing renewable energy and natural gas coop-eration at the plant level before reaching electric-ity markets will give renewable power producers the chance to avoid a portion of the integration costs that their products introduce.

Another important component of a low-car-bon transition is improving the efficiency of the grid. Aside from replacing aging transmission infrastructure, significant efficiency gains can be delivered by generating more electricity closer to the point of use, including in power plants that capture and use the waste heat they generate. Dis-tributed generation and cogeneration (or CHP) reduce the congestion and transmission losses on long-distance transmission lines and can be com-patible with a range of small-scale renewable and natural gas-based technologies. Many existing U.S. state renewable portfolio standards already qualify cogeneration to meet renewable targets, and some even have separate quotas for distrib-uted generation.

Newer, smarter grid infrastructure is essen-tial to the success of a low-carbon transition. The European Union has been especially aggres-sive in promoting smart grids. A 2009 electricity directive requires smart meters to be installed in 80 percent of homes where they are deemed to be cost effective by 2020.6 In 2009, the European Commission also announced the allocation of !2 billion ($2.7 billion) of public and private invest-ment to enable 50 percent of Europe’s networks to operate as smart grids.7 The United States has committed $11.4 billion in combined public and private sector funding to smart grid projects as part of the 2009 American Reinvestment and Recovery Act.8

Shifting financing to low-carbon energy is critical for developing nations as well. Accord-ing to the Bank Information Center, the World Bank Group lent a record $4.4 billion for coal projects in the 2010 fiscal year, primarily for the construction of a 4.8 GW supercritical coal plant in South Africa.9 In FY2009, the World Bank



Group spent only $3.1 billion—its all-time high. A comparatively modest $740 million went to the development of natural gas markets and power generation.

The World Bank has defended these deci-sions by arguing that its primary mission is to increase access to energy services. Yet it is not clear that coal investments are the best way to achieve this goal. Over the next decade, the cost of renewables and micropower technologies are expected to decline significantly, while the cost of coal will rise as emissions regulations tighten and as carbon begins to be priced. In some coun-tries, including China, India, and South Africa, domestic coal reserves once thought to be abun-dant could be exhausted in less than 50 years if production rates continue to increase. As the U.S. and European experiences have demon-strated, large amounts of coal power in a region’s generation mix can inhibit the integration of variable renewable energy sources—sources that will become more attractive as they achieve greater cost reductions and as carbon constraints become tighter.

Finally—but equally importantly—if natural gas is to play a constructive role in the world’s low-carbon future, regulations and industry practices must ensure that it is extracted respon-sibly, with sufficient protection for water, air, land, and other resources in the communities where it is produced. These new supplies can truly change the game for global ambitions for low-carbon energy—but only if they can be extracted with minimal risk to the environment.

To reduce global greenhouse gas emissions, the world must transform the power sector as rapidly

as possible. Although many technologies have the potential to play a role in the future energy economy, including carbon capture and seques-tration, flexible nuclear reactors, scalable energy storage, and smart grid infrastructure and con-trols, most of these are at least 10 years away from being commercially viable. But the low-carbon transition must begin today. Renewable energy and natural gas, deployed as part of an integrated approach, can reduce coal dependence, deliver emissions reductions, and catalyze the transition to the low-carbon economy—starting now.

A micro-turbine and micro-CHP test bench, Institute for Solar Energy Technologies (ISET), Germany.

© IS

ET


Endnotes


1. U.S. Department of Commerce, National Oceanic and Atmospheric Administration, Earth System Research Laboratory, “Recent Mauna Loa CO2,” www.esrl.noaa.gov/gmd/ccgg/trends, viewed 24 October 2010.

2. D. Arndt, M. Baringer, and M. Johnson, eds., State of the Climate in 2009, special supplement, Bulletin of the American Meteorological Society, vol. 91, no. 7 (2009), pp. S1–S224; United Nations Environment Programme (UNEP), Climate Change Science Compendium 2009, www.unep.org/compendium2009, viewed 24 October 2010.

3. Calculations based on data from European Commis-sion, Joint Research Centre/Netherlands Environmen- tal Assessment Agency (PBL), “Emission Database for Global Atmospheric Research (EDGAR),” http://edgar.jrc .ec.europa.eu, viewed 24 October 2010.

4. Jon Creyts et al., Reducing U.S. Greenhouse Gas Emis-sions: How Much at What Cost? (New York: McKinsey & Company U.S. Greenhouse Gas Abatement Mapping Ini-tiative, December 2007).

5. UNEP and Bloomberg New Energy Finance, Global Trends in Sustainable Energy Investment 2010 (Nairobi: 2010), Figure 16.

6. Wolfram Krewitt et al., Renewable Energy Deployment Potentials in Large Economies, prepared for REN21 (Stutt-gart: Institute of Technical Thermodynamics, German Aerospace Center (DLR), 2008), pp. 8, 18–37.

7. Peter Fox-Penner, Smart Power: Climate Change, the Smart Grid, and the Future of Electric Utilities (Washing-ton, DC: Island Press, 2010), p. 211.


1. Lester Brown et al., State of the World 2000 (New York: W.W. Norton & Company, 2000), p. 148.

2. Figure 1 based on International Energy Agency (IEA), Energy Statistics of Non-OECD Countries (2010 Edition), available from http://wds.iea.org/wds/, viewed 12 Novem-ber 2010.

3. Saya Kitasei, “Wind Power Growth Continues to Break Records Despite Recession,” Vital Signs Online (Washington, DC: Worldwatch Institute, 2010).

4. Calculated based on Global Wind Energy Council, Global Wind 2009 Report (Brussels: March 2010).

5. REN21, Renewables 2010 Global Status Report (Paris: 2010), p. 17, note 33.

6. Ibid.

7. European Wind Energy Association, The European Offshore Wind Industry – Key Trends and Statistics: 1st half 2010 (Brussels: 20 July 2010); “300 MW Offshore Wind Farm Pushes UK Capacity over 5 GW,” PowerGenWorld-wide.com, 23 September 2010.

8. Manuela Zoninsein, “Climate Offshore Development Blows Past U.S.,” New York Times, 7 September 2010.

9. Technical wind potential from Thomas Johansson et al., “The Potentials of Renewable Energy,” Thematic Back-ground Paper for International Conference for Renewable Energies, Bonn, Germany, January 2004; global primary energy consumption from BP, Statistical Review of World Energy June 2010 (London: 2010).

10. Calculation based on Johansson et al., op. cit. note 9.

11. REN21, op. cit. note 5. Ryan Wiser et al., Tracking the Sun: The Installed Cost of Photovoltaics in the U.S. from 1998-2007 (Berkeley, CA: Lawrence Berkeley National Laboratory, February 2009).

12. SunEdison, “SunEdison to Build Europe’s Largest Solar Power Plant in Rovigo, Italy,” press release (Rovigo, Italy: 11 March 2010).

13. “SunPower Adds 40-MW to California Valley Solar Ranch,” RenewableEnergyWorld.com, 3 May 2010.

14. Todd Woody, “Pasadena’s ESolar Lands 2,000-Mega-watt Deal in China,” Los Angeles Times, 9 January 2010.

15. REN21, op. cit. note 5.

16. Stephen Lacey, “392 More MW of CSP Approved,” RenewableEnergyWorld.com, 23 September 2010; Susan Kraemer, “Recovery Act Propels 3 GW of Solar Projects to Front in California,” CleanTechnica.com, 31 August 2010; California Energy Commission, “Large Solar Energy Proj-ects,” www.energy.ca.gov/siting/solar/index.html, viewed 24 September 2010; REN21, op. cit. note 5.

17. Woody, op. cit. note 14.

18. U.S. National Renewable Energy Laboratory (NREL), “Parabolic Trough Thermal Energy Storage Technology,” www.nrel.gov/csp/troughnet/thermal_energy_storage.html, viewed 14 September 2010.

19. Calculation based on REN21, op. cit. note 5, p. 16.


Group, December 2009); Lisa Mastny, ed., Renewable Energy and Energy Efficiency in China: Current Status and Prospects for 2020 (Washington, DC: Worldwatch Institute, 2010), p. 24.

41. Danish Energy Agency, “Monthly Statistics,” www.ens.dk/en-US/Info/FactsAndFigures/Energy_statistics_and_indicators/Monthly_Statistic/Sider/Forside.aspx, viewed 26 October 2010; Jenny Mandel, “DOE Promotes Pumped Hydro as Option for Renewable Power Storage,” New York Times, 15 October 2010; Sawin and Moomaw, op. cit. note 35, p. 136.

42. Electric Reliability Council of Texas (ERCOT), Plan-ning and Operations Information, available at http://plan ning.ercot.com/; S. Fink et al., Wind Energy Curtailment Studies: May 2008–May 2009 (Golden, CO: NREL, Octo-ber 2010).

43. NREL, op. cit. note 39.

44. Jochen Flasbarth, Umwelt Bundes Amt, personal com-munication with author, 8 September 2010.

45. Figure 3 based on Janice Lin, “Imperative of Energy Storage for Meeting California’s Clean Energy Needs,” presentation for the California Senate Energy, Utilities and Communications Committee (Sacramento, CA: Califor-nia Energy Storage Alliance, 22 June 2010), p. 34.

46. Rahul Walawalkar and Jay Apt, Market Analysis of Emerging Electric Energy Storage Systems, prepared for DOE, National Energy Technology Laboratory (Washing-ton, DC: July 2008).

47. Jim Eyer and Garth Corey, Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment Guide (Albuquerque, NM: Sandia National Laboratories, February 2010).

48. J. Himelic and F. Novachek, Sodium Sulfur Battery Energy Storage and Its Potential to Enable Further Integra-tion of Wind, Data Collection and Analysis Report (Mile-stone 5) (Denver: Xcel Energy, 7 July 2010).

49. Matthew Wald, “Pushed Along by Wind, Power Stor-age Grows,” New York Times, 27 July 2010.

50. D. Steward et al., Lifecycle Cost Analysis of Hydro-gen Versus Other Technologies for Electrical Energy Storage (Golden, CO: NREL, November 2009), p. 37; Eric Wesoff, “EPRI on Renewable Energy: Compressed Air Energy Storage,” GreenTechMedia.com, 14 January 2010.

51. Figure 4 based on the following: natural gas gas tur-bine estimates based on Lazard, “Levelized Cost of Energy Analysis – Version 3.0” (New York: June 2009), using Lazard’s low-end assumptions for gas turbines, which represent a GE 7FA turbine. The natural gas combus-tion turbine figure is a levelized cost of electricity using a 20 percent capacity factor assumption, included for sake of comparison. Natural gas prices are assumed to be $6 per million Btu. Calculations assume a natural gas price for compressed air energy storage system and natural gas combustion turbine of $7 per million Btu; a capacity fac-tor for a natural gas combustion turbine of 20 percent; and a cost of purchasing off-peak electricity for storage of $0.025–$0.06 per kWh. Estimates reflect conserva-tive estimates for current technologies, rather than using projections based on estimated technology improvement.

20. Ibid., p. 24.

21. Ibid.

22. See, for example, T. Hertel et al., “Effects of Maize Ethanol on Global Land Use and Greenhouse Gas Emis-sions: Estimating Market Mediated Responses,” BioScience, vol. 60, no. 3 (2009), pp. 223–31.

23. U.S. Department of Energy (DOE), Alternative Fuels and Advanced Vehicles Data Center, “Natural Gas Vehicle Emissions,” www.afdc.energy.gov/afdc/vehicles/natural_gas_emissions.html, viewed 27 September 2010; Interna-tional Association for Natural Gas Vehicles, “Natural Gas Vehicle Statistics,” www.iangv.org/tools-resources/statis tics.html, updated December 2009.

24. Honda Worldwide, “Honda Begins Operation of New Solar Hydrogen Station,” press release (Torrance, CA: 27 January 2010).

25. Juha Kiviluoma and Gustavo Collantes, “Electrifica-tion of Energy,” Workshop Report (Boston: Harvard Uni-versity John F. Kennedy School of Government, 23 April 2008).

26. REN21, op. cit. note 5, p. 56.

27. U.S. President Bill Clinton, “State of the Union 2000” (Washington, DC: 27 January 2000).


29. Ibid.

30. Ibid.

31. United Nations Environment Programme, “‘Global Green New Deal’ – Environmentally Focused Investment Historic Opportunity for 21st Century Prosperity and Job Creation,” press release (London/Nairobi: 22 October 2008).

32. REN21, op. cit. note 5, p. 27.


34. Kitasei, op. cit. note 3.

35. Janet Sawin and William Moomaw, “An Enduring Energy Future,” in Worldwatch Institute, State of the World 2009: Into a Warming World (New York: W.W. Norton & Company, 2009); Sonal Patel, “China: A World Power-house,” POWER Magazine, 1 July 2010.

36. Figure 2 based on generation data from DOE, Energy Information Administration (EIA), “International Energy Statistics,” http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=12, viewed 27 Sep-tember 2010, and from EIA, “State Data Tables,” Electric Power Annual 2008, http://eia.gov/cneaf/electricity/epa/epa_sprdshts.html, viewed 26 October 2010.

37. EIA, “State Data Tables,” op. cit. note 36.

38. Sawin and Moomaw, op. cit. note 35, p. 137.

39. NREL, Western Wind and Solar Integration Study (Golden, CO: 2010). Figure 3 from North American Elec-tric Reliability Corporation, Accommodating High Levels of Variable Generation (Princeton, NJ: April 2010).

40. DB Climate Change Advisors, Paying for Renewable Energy: TLC at the Right Price (Frankfurt: Deutsche Bank

Endnotes


Endnotes

16. Figure 9 based on EIA, “U.S. Natural Gas Wellhead Price (Dollars per Thousand Cubic Feet),” www.eia.gov/dnav/ng/hist/n9190us3m.htm, viewed 27 September 2010.

17. Marianne Lavelle, “Plenty of Gas, But No Easy Fix for U.S. Energy Challenge,” National Geographic News, 16 March 2010.

18. James Kanter, “Uphill Road for Europe to Kick Rus-sian Gas Habit,” New York Times, 17 July 2009.

19. Gas Exporting Countries Forum (GECF) Web site, www.gecforum.com.qa, viewed 23 August 2010.

20. GECF, “Mission of GECF,” www.gecforum.org/gecf/web.nsf/web/aboutgecf_mission, viewed 13 November 2010; Marcel Dietsch, “The Next Global Energy Cartel,” Forbes, 10 December 2009.

21. Daniel Yergin et al., Fueling North America’s Energy Future: The Unconventional Natural Gas Revolution and the Carbon Agenda (Cambridge, MA: IHS CERA, 2010), p. ES-1.

22. EIA, Annual Energy Outlook 2009 (Washington, DC: March 2009); EIA, Annual Energy Outlook 2010 Early Release Overview (Washington, DC: 14 December 2009); EIA, Natural Gas Navigator, “Coalbed Methane Produc-tion,” http://tonto.eia.doe.gov/dnav/ng/ng_prod_coal bed_s1_a.html, viewed 24 February 2010; EIA, Natural Gas Navigator, “Shale Gas Production,” http://tonto.eia .doe.gov/dnav/ng/ng_prod_shalegas_s1_a.htm, viewed 24 February 2010.

23. For more on the techniques used to extract natural gas from unconventional reservoirs, the risks they pose to the environment, and the best technologies and prac-tices that can mitigate those risks, see Mark Zoback, Saya Kitasei, and Brad Copithorne, Addressing the Environmen-tal Risks from Shale Gas Development (Washington, DC: Worldwatch Institute, July 2010). Sidebar 1 from idem.

24. EIA, Natural Gas Year-In-Review 2009 (Washington, DC: July 2010).

25. “A New Energy Source for Britain?” Channel 4 News, 26 July 2010; Maciej Martewicz, “PCNiG Starts First Pol-ish Shale Gas Well, Seeking to Cut Russia Dependence,” Bloomberg.com, 9 July 2010; “Polish Shale Gas: Boon or Bane?” The Economist, 18 August 2010; “North Africa Gets First Shale Gas Frac Job,” Oil & Gas Journal, 30 August 2010.

26. BP, op. cit. note 4.

27. U.S. Department of State, “Global Shale Gas Initia-tive,” press release (Washington, DC: 20 August 2010).

28. The White House, “Fact Sheet: U.S.-China Shale Gas Resource Initiative,” press release (Washington, DC: 17 November 2010).

29. John Donovan, “Shell, PetroChina to Develop Shale Gas in Sichuan,” Wall Street Journal, 27 November 2009.

30. “Analysis: Shale Gas to Help Meet China’s Energy Demand,” Rigzone.com, 3 August 2010.

31. “China to Double Natural Gas Weighting over 5 Years,” China Daily, 19 June 2010.

32. EIA, “India,” Country Analysis Brief, www.eia.doe.gov/

Hydrogen is assumed to be produced through electrolysis from off-peak electricity. Pumped hydro, compressed air energy storage, nickel cadmium, and sodium sulfur bat-tery costs are based on Steward et al., op. cit. note 50.

52. Eyer and Corey, op. cit. note 47.

53. Ariel Schwartz, “Malta to Become First Smart Grid Island,” CleanTechnica.com, 5 February 2009; Xcel Energy, “Smart Grid City,” http://smartgridcity.xcelenergy.com, viewed 18 November 2010. For a good conceptual over-view of the smart grid, see Peter Fox-Penner, Smart Power: Climate Change, the Smart Grid, and the Future of Electric Utilities (Washington, DC: Island Press, 2010) and DOE, The Smart Grid: An Introduction (Washington, DC: 2008).


1. Christopher Flavin and Saya Kitasei, The Role of Natu-ral Gas in a Low-Carbon Energy Economy (Washington, DC: Worldwatch Institute, April 2010).

2. Ibid.

3. Steve James, “Coal-to-gas Switching? Utilities Have Power,” Reuters, 18 August 2010.

4. Figure 5 based on BP, Statistical Review of World Energy June 2010 (London: 2010).

5. Anthony Melling, Natural Gas Pricing and Its Future: Europe as the Battleground (Washington, DC: Carnegie Endowment for International Peace, 2010).

6. U.S. Department of Energy (DOE), Energy Informa-tion Administration (EIA), “Korea,” Country Analysis Brief, http://eia.gov/cabs/South_Korea/NaturalGas.html, viewed 14 October 2010; EIA, “Japan,” Country Analysis Brief, http://eia.gov/cabs/Japan/NaturalGas.html, viewed 14 October 2010; EIA, “Taiwan,” www.eia.doe.gov/emeu/cabs/taiwan.html, viewed 18 November 2010.

7. Figure 6 based on BP, op. cit. note 4.

8. BP, op. cit. note 4.

9. Ibid.; EIA, “Nigeria,” Country Analysis Brief, www.eia.doe.gov/cabs/Nigeria/NaturalGas.html, viewed 21 August 2010.

10. EIA, op. cit. note 9.

11. BP, op. cit. note 4; EIA, op. cit. note 9.

12. World Bank, Global Gas Flaring Reduction, “Esti-mated Flare Volumes from Satellite Data, 2005-2008,” http://go.worldbank.org/G2OAW2DKZ0, viewed 27 Octo-ber 2010.

13. International Energy Agency (IEA), World Energy Outlook 2009 (Paris: 2009), p. 485.

14. IEA, World Energy Outlook 2010 (Paris: 2010), p. 8.

15. Figure 7 data are Worldwatch estimates based on the following: Lazard, “Levelized Cost of Energy Analysis – Version 3.0” (New York: June 2009), www.cleanenergy.org/images/factsheets/Lazard2009_LevelizedCostofEnergy.pdf, viewed 27 September 2010; Stan Kaplan, Power Plants: Characteristics and Costs (Washington, DC: Congress-ional Research Service, 13 November 2008); Bill Williams, Altresco, communication with author, 10 June 2010.


Endnotes

Company of Colorado training manual, cited in BEN-TEK Energy, How Less Became More: Wind, Power and Unintended Consequences in the Colorado Energy Market (Evergreen, CO: 16 April 2010). PSCO is an operating utility owned by Xcel Energy, a utility holding com-pany; Colorado generation figures from EIA, “1990-2008 Net Generation by State by Type of Producer by Energy Source (EIA-906),” in Electric Power Annual 2008,” www.eia.gov/cneaf/electricity/epa/epa_sprdshts.html; 7 percent of capacity from Northwest Power Planning Council, “Natural Gas Combined-Cycle Gas Turbine Power Plants” (Portland, OR: 8 August 2002; partial loads from Gary Groninger, Wärtsila North America, communication with author, 29 October 2010.

6. Natural gas gas turbine estimates based on Lazard, “Levelized Cost of Energy Analysis – Version 3.0” (New York: June 2009), using Lazard’s low-end assumptions for gas turbines, which represent a GE 7FA turbine. Capac-ity factors are assumed to be 25 percent for gas turbines and 55 percent for natural gas combined cycle. Natural gas prices are assumed to be $6 per million Btu. Calculations assume a natural gas price for compressed air energy stor-age system and natural gas combustion turbine of $7 per million Btu; a capacity factor for a natural gas combustion turbine of 20 percent; and a cost of purchasing off-peak electricity for storage of $0.025–$0.06 per kWh. Estimates reflect conservative estimates for current technologies, rather than using projections based on estimated technol-ogy improvement. Hydrogen is assumed to be produced through electrolysis from off-peak electricity. Pumped hydro, compressed air energy storage, nickel cadmium, and sodium sulfur battery costs are based on D. Steward et al., Lifecycle Cost Analysis of Hydrogen Versus Other Tech-nologies for Electrical Energy Storage (Golden, CO: NREL, November 2009), p. 37.

7. Calpine Corporation, “Calpine Corporation to Sell Wind-Based Firm Power Product,” press release (Houston: 11 January 2010).

8. Mikael Backman, “The Wind Enabler,” In Detail (Wärtsila Technical Journal), vol. 1 (2010).

9. Ibid.

10. U.S. National Renewable Energy Laboratory (NREL), “U.S. Parabolic Trough Power Plant Data,” www.nrel.gov/csp/troughnet/power_plant_data.html, viewed 2 Septem-ber 2010.

11. Worldwatch calculations based on EIA, “Form EIA-923” (Washington, DC: 2008).

12. Ibid.

13. Ibid.

14. Fred Morse, quoted in Michael Kanellos, “Solar and Gas: Together at a Power Plant Near You,” GreentechMe-dia.com, 1 June 2009.

15. “CSP Hybrid Plant Opened in Morocco,” Renew-ableEnergyFocus.com, 23 June 2010.

16. NREL, “Concentrating Solar Power Projects by Coun try,” www.nrel.gov/csp/solarpaces/by_country.cfm, viewed 2 September 2010; Algeria from Abengoa Solar, “ISCC,” www.abengoasolar.com/corp/web/en/technolo gies/concentrated_solar_power/iscc/index.html, viewed 2

emeu/cabs/India/NaturalGas.html, viewed 23 August 2010.

33. Christopher Helman, “India’s Ambani Grabs More U.S. Shale Gas,” Forbes.com, 5 August 2010; Ajay Modi, “India Plans to Launch Shale Gas Auction in August 2011,” Business-Standard.com, 26 July 2010.

34. EIA, op. cit. note 32; BP, op. cit. note 4.

35. IEA, op. cit. note 14, pp. 432–43.

36. Figure 10 based on BP, Statistical Review of World Energy (London: 2002–2010).

37. IEA, op. cit. note 14, pp. 432–43.

38. WTI-Cushing, Oklahoma spot prices from EIA, Petroleum Navigator, http://tonto.eia.doe.gov/dnav/pet/pet_pri_spt_s1_d.htm, viewed 16 April 2010; Henry Hub Contract 1 futures price from EIA, Natural Gas Navigator, http://tonto.eia.doe.gov/dnav/ng/ng_pri_fut_s1_d.htm, viewed 16 April 2010.

39. Judy Dempsey, “European Energy Giants Seek Lower Prices from Gazprom,” New York Times, 24 February 2010.

40. “India Lures LNG Spot Cargoes as Asia, Europe Cut Imports,” Financial Express, 23 April 2009; EIA, op. cit. note 32.

41. Andrew Kramer, “Russian Will Lead Gas Exporting Alliance,” New York Times, 9 December 2009.

42. Figure 10 based on R. James et al., Life Cycle Analysis: Power Studies Compilation Report (Washington, DC: DOE, National Energy Technology Laboratory, October 2010).

43. Rebecca Smith, “Power Companies Burn More Coal, Less Gas,” Wall Street Journal, 13 September 2010.

44. Office of Governor Bill Ritter, Jr., “Gov. Ritter Signs Historic Clean Air-Clean Jobs Act,” press release (Denver: 19 April 2010); “Delhi to Convert Coal Plants to Natural Gas,” ClimateWire.com, 22 January 2010.


1. Figure 11 based on 15-minute load data from the Electric Reliability Council of Texas (ERCOT), Planning and Operations Information, available at http://planning .ercot.com.

2. Rakesh Sarin, “An Optimal Power Generation Mix for India,” Wärtsila Technical Journal, January 2010.

3. Steve Blankinship, “Gas Turbines Adapt to Dynamic Market Conditions,” PowerGenWorldwide.com, 1 April 2008.

4. Dennis Finn, “Plains End – The World’s Largest Natu-ral Gas-fuelled Power Plant using Reciprocating Engines,” Twentyfour7, March 2007; Gary Groninger, Wärtsilä, com-munication with author, 8 October 2010.

5. Sidebar 2 based on the following sources: Colorado House of Representatives, House Bill 07-1281, “Concern-ing Increased Renewable Energy Standards” (Denver: 2004); capacity figures from U.S. Department of Energy (DOE), Energy Information Administration (EIA), “Form EIA-860” (Washington, DC: 2009); wind share of 2008 generation from American Wind Energy Associa-tion (AWEA), Annual Wind Report 2009 (Washington, DC: 2009); July 2008 example is from a Public Service


Endnotes

2. Ibid.

3. German Federal Ministry of the Environment (BMU), Erneuerbare Energien in Zahlen (Berlin: June 2010).

4. Thomas Klaus et al., Energieziel 2050: 100 Percent Strom aus Erneuerbaren Quellen (Berlin: July 2010).

5. Volkswagen Group, “Volkswagen and LichtBlick Agree [on] Energy Partnership,” press release (Salzgitter/Ham-burg: 9 September 2009).

6. Intergovernmental Panel on Climate Change, Climate Change 2007: Synthesis Report (Geneva: 2007).

7. Figure 13 derived from U.S. Environmental Protection Agency, U.S. Greenhouse Gas Inventory 2010 (Washington, DC: 2010).

8. Wilson Hambrick et al., Beyond Biofuels: Renewable Energy Opportunities for U.S. Farmers (Washington, DC: Heinrich Böll Stiftung, May 2010).

9. Klaus, et al., op. cit. note 4.

10. “Mexico Profile: Animal Waste Management Methane Emissions,” presentation to Agriculture Subcommittee of Methane to Markets Partnership, April 2008.

11. Database of State Incentives for Renewable Energy (DSIRE) Web site, www.dsireusa.org, viewed 27 Septem-ber 2010; REN21, Renewables 2010 Global Status Report (Paris: 2010).

12. “Biogas Fuel Cell CHP Plant for US Wastewater Site,” PowerGenWorldwide.com, 9 September 2010.

13. National Grid, “Renewable Gas – Vision for a Sustain-able Gas Network” (Waltham, MA: 2010).

14. QSS Group Inc., Biogas for Transportation Use: A 1998 Perspective (Fairfax, VA: July 1998).

15. Methane to Markets Partnership, “About the Part-nership,” www.methanetomarkets.org/about/index.aspx, viewed 27 September 2010.

16. Jack Lewnard, Gas Technology Institute, communica-tion with author, 16 July 2010.

17. California Air Resources Board, “Lifecycle Analy-sis Workgroup, Detailed California-Modified GREEET Pathway for Transportation Fuels,” www.arb.ca.gov/fuels/lcfs/072009lcfs_biogas_cng.pdf, viewed 27 September 2010.

18. Tim Franks, “Cows Make Fuel for Biogas Train” BBC News Online, 24 October 2005.

19. Hythane Company, “About Hythane,” www.hythane.com/about.html, viewed 27 September 2010.

20. Eden Energy Ltd., “Eden Signs Agreement with Major Indian Companies for First Commercial Sized Hythane Demonstration Project in India,” press release (Perth, Aus-tralia: 24 February 2010).


1. Rebecca Smith, “Turning Away from Coal,” Wall Street Journal, 13 September 2010.

2. Ibid.

3. Ralf Wagner, E.ON Ruhrgas, “The Impact of the EU

Sep tem ber 2010; Egypt from NREL, “ISCCS Al Kuraymat,” www.nrel.gov/csp/solarpaces/project_detail.cfm/projectID =65, viewed 2 September 2010.

17. Jad Mouawad, “The Newest Hybrid Model,” New York Times, 4 March 2010.

18. NREL, “Martin Next Generation Solar Energy Center,” www.nrel.gov/csp/solarpaces/project_detail.cfm/projectID =45, viewed 2 September 2010.

19. Peter Fairley, “Cutting Coal Use with Sunshine,” MIT Technology Review, 10 February 2009.

20. DOE, Concentrating Solar Power Commercial Appli ca-tion Study: Reducing Water Consumption of Concentrating Solar Power Electricity Generation (Washington, DC: 2010).

21. Hybrid Wind Turbines Web site, www.hybridturbines.com, viewed 5 September 2010.

22. Bill Williams, Altresco, communication with author, 19 May, 3 June, 8 June, and 11 June 2010. Figure 12 based on Lazard, op. cit. note 6; Stan Kaplan, Power Plants: Characteristics and Costs (Washington, DC: Congressional Research Service, 13 November 2008).

23. Peter Fox-Penner, Smart Power: Climate Change, the Smart Grid, and the Future of Electric Utilities (Washing-ton, DC: Island Press, 2010)

24. Seth Dunn, Micropower: The Next Electrical Era (Washington, DC: Worldwatch Institute, July 2000).

25. AWEA, 2010 Small Wind Turbine Global Market Study (Washington, DC: 2010).

26. Ibid.

27. REN21, Renewables 2010 Global Status Report (Paris: 2010), p. 20.

28. Ibid. Table 1 based on estimates in Fox-Penner, op. cit. note 23, pp. 113–18.

29. International Energy Agency (IEA), Cogeneration and District Energy (Paris: 2009).

30. Ibid.

31. Cogeneration share based on EIA, op. cit. note 11.

32. Table 2 based on U.S. Environmental Protection Agency, Catalog of CHP Technologies (Washington, DC: December 2008), p. 8.

33. “Global Sales of Micro-CHP Devices Down in Japan, Up in Germany,” PowerGenWorldwide.com, 20 July 2010.

34. Takahiro Kasuh, “Development Strategies Toward Promotion and Expansion if Residential Fuel Cell Micro-Chp System in Japan,” undated, at www.igu.org/html/wgc2009/papers/docs/wgcfinal00801.pdf.

35. Volkswagen Group, “Volkswagen and LichtBlick Agree [on] Energy Partnership,” press release (Salzgitter/Ham-burg: 9 September 2009).

36. Ibid.


1. Christopher Flavin and Nicholas Lenssen, Power Surge: Guide to the Coming Energy Revolution (New York: W.W. Norton & Company, 1994), p. 113.


7. “Commission Cautious on Smart Grids,” EurActiv.com, 16 April 2010.

8. U.S. Department of Energy, Office of Electricity Delivery and Energy Reliability, “Smart Grid Investment Grant Awards,” www.oe.energy.gov/recovery/1249.htm, viewed 27 September 2010.

9. Heike Mainhardt-Gibbs, “World Bank Group Energy Sector Financing Update” (Washington, DC: Bank Infor-mation Center, September 2010).

Endnotes

ETS on Power – The Price to Be Paid for CO2 Abatement,” presented at NARUC meeting, Dallas, TX, 3 December 2009.

4. Stoel Rives LLP, “A Change in the Wind’s Direction: BPA Issues Final Record of Decision in 2010 Rate Case,” RenewableEnergyWorld.com, 28 July 2009.

5. Michael Milligan and Brendan Kirby, Market Charac-teristics for Efficient Integration of Variable Generation in the Western Interconnection (Golden, CO: U.S. National Renewable Energy Laboratory, August 2010).

6. “EU Strikes Deal on Energy Market Liberalization,” EurActiv.com, 25 March 2009.


AAfrica, 17f, 19, 21, 26Alabama, 14Algeria, 17, 26Altresco, 27American Gas Association, 31anaerobic digesters, 31ancillary services, 24Annual Energy Outlook (EIA), 19Asia, 10, 16–18, 21, 29Australia, 19, 21

BBank Information Center, 34battery storage systems, 14, 15fbiodiesel, 10biogas, 10, 24, 31biomass

annual growth in generation, 9fbiomethane and, 31electricity generation from, 10grid infrastructure and, 12heating and cooling sectors, 11supply and demand considerations, 24

Bonneville Power Administration (BPA), 33–34Brazil, 10

CCAES (compressed air energy storage), 14, 15fCalifornia, 9–10, 26, 31California Air Resources Board, 32Calpine Corporation, 25Cambridge Energy Research Associates, 18Canada, 12, 19Central America, 17f, 21China

CO2 emissions and, 7coal reserves in, 35feed-in tariffs in, 12National Energy Administration, 19natural gas and, 17f, 18–19renewable energy in, 12fshale gas and, 19solar energy and, 10–11wind energy and, 10

CHP (combined heat and power), 28, 28f, 34Clean Development Mechanism (Kyoto Protocol), 31Clinton, Bill, 11CNG (compressed natural gas), 11, 16CNPC (China National Petroleum Corporation), 19CO

2 emissions, 7, 21, 30–31coal

annual growth in generation, 9fCO2 emissions, 21global energy use, 17fgreenhouse gas emissions from, 21flevelized cost of electricity from, 18f, 27fmethane emissions from mining, 31fnatural gas and, 17–18, 21–22in Poland, 19projected reserves, 35supply and demand considerations, 23–24in Texas ERCOT load curve, 23fwind energy and, 25

Colorado, 15, 24–27, 32CSP (concentrating solar power), 10, 26

DDenmark

CHP systems, 28climate negotiations in, 7energy storage and, 13renewable energy in, 12fwind energy in, 9

developing countries, renewable energy in, 12distributed generation, 12, 17, 27–29, 34DLR (German Aerospace Center), 7–8Donghai Bridge Wind Farm (China), 10Duke Energy, 18

EEcoBlue micropower plants, 29Egypt, 17, 26Electric Power Research Institute (EPRI), 26electricity generation

adapting systems, 34average annual growth by fuel, 9ffrom biogas, 10from biomass, 10CO2 emissions and, 7

Index


feed-in tariffs in, 12natural gas and, 19renewable energy in, 12fsolar energy and, 35fwind energy and, 9

Ghana, 17Global Shale Gas Initiative (GSGI), 19government policies/regulations, 11, 20, 33greenhouse gas emissions

biofuel crops and, 10CO2 and, 7, 21coal plants and, 21f, 25government regulations on, 33methane and, 31natural gas extraction and, 20NGCC plants and, 21f

HHawaii, 14heating and cooling, 7, 11horizontal drilling, 19–20Hu Jintao, 19Hungary, 19Hybrid Wind Turbines, 26hydraulic fracturing, 18–20hydrogen, 14, 15f, 32hydropower

annual growth, 9felectricity generation from, 10global energy use, 17fgrid infrastructure and, 12levelized cost of, 15fsupply and demand considerations, 24

Hythane, 32

IIndia

CO2 emissions and, 7coal reserves in, 35energy supply and demand considerations, 23natural gas and, 17f, 18–21renewable energy in, 12f

infrastructure considerations, 12–13, 16–17Institute for Solar Energy Technologies (ISET), 35fIntegrated Solar Combined Cycle (ISCC), 26International Energy Agency (IEA), 17, 21, 28International Methane to Markets Partnership, 31Iowa, 12fIreland, 14Italy, 9–10

JJapan

CHP technology, 29energy supply and demand considerations, 13LNG and, 21, 22fnatural gas and, 16–17

energy storage and, 13from geothermal energy, 10from hydropower, 10renewable energy share in, 8in selected countries, 12fsmart grid technologies, 15, 34supply and demand considerations, 23–24trading across borders, 13transportation and, 11, 14–15

electrolyzers, 14Encana, 19energy use, 10, 17f, 23–24Energy Information Administration (EIA), 19, 33energy storage, 13–14, 14fEni, 21Environmental Protection Agency, 20, 25environmental risks, 19–20E.ON, 21ERCOT (Electric Reliability Council of Texas), 23fESolar, 10ethanol production, 10EU-ETS (European Union Emission Trading Scheme),

33Europe

biofuels and, 10biomethane and, 31CHP systems, 28–29energy storage and, 10micropower generators and, 27natural gas and, 16, 17f, 18, 21, 33shale gas and, 19solar energy and, 10wind energy and, 9

European Commission, 34European Union, 18, 33–34

Ffeed-in tariffs, 11–12Finland, 25First Solar, 10Florida, 26flywheels, 14forecasting energy requirements, 13Fox-Penner, Peter, 8FPL Group, 26FuelCell Energy, 31

GGas Exporting Countries Forum, 18, 21Gas Technology Institute, 31Gazprom, 19, 21geothermal energy, 9f, 10–12, 23–24German Aerospace Center (DLR), 7–8Germany

biomethane and, 31CAES technology, 14CHP technology, 29feasibility study in, 13

Index


supply and demand considerations, 18–21transportation sector and, 11, 17, 32wind energy and, 25–27

net load, 13New Hampshire, 31New Mexico, 26New York, 31NGCC (natural gas combined cycle)

CO2 emissions, 21efficiencies of, 25greenhouse gas emissions, 21flevelized cost of electricity from, 18f, 27fsupply and demand considerations, 23–24in Texas (ERCOT) load curve, 23f

Nigeria, 17non-spinning reserve, 24North America, 16, 17f, 18–19North Carolina, 26Norway, 13, 17nuclear energy

annual growth, 9fglobal energy use, 17flevelized cost of electricity from, 18fsupply and demand considerations, 23in Texas (ERCOT) load curve, 23f

OObama, Barack, 19offshore wind power, 9–10oil consumption, 9f, 17f, 21

PPakistan, 11peaking plants, 23–24PEM (proton exchange membrane) fuel cells, 14PetroChina, 19Poland, 17, 19Public Service Company of Colorado (PSCO), 25

Rreciprocating engines, 24–25, 27–28regulation (ancillary service), 24Reliance Industries, 19–20renewable energy

definition, 9in developing countries, 12DLR on, 7–8government policies and, 11natural gas and, 8rise of, 9–15transportation and, 10–11

Rhode Island, 31Rogers, Jim, 18Royal Dutch Shell, 19Russia, 18–19, 21

SSchwarmStrom, 29

KKyoto Protocol, 31

LLatin America, 17f, 21LichtBlick, 29, 30LNG (liquified natural gas)

Asian countries and, 17–18CNG comparison, 16global exports, 21fIndia and, 20–21in Japan, 21, 22fnatural gas markets and, 20–21, 21fNigeria and, 17supply and demand considerations, 20–21transportation sector and, 11

MMalta, 15Massachusetts, 31methane

biogas and, 10coalbed deposits, 18, 20emissions by source, 31fnatural gas production and, 20, 30–31

Mexico, 31micropower generators, 27, 29microseismic monitoring, 20Middle East, 17f, 21Minnesota, 12, 14Morocco, 26, 26fmust-take provisions, 12, 25

NNational Energy Administration (China), 19National Grid, 31natural gas

annual growth, 9fbackground information, 16–17as bridge fuel, 30–32CO2 emissions, 30coal production and, 17–18, 21–22cost sensitivity, 17–18distribution generation for, 17, 27–29, 28fenergy security considerations and, 18, 33environmental risks, 20grid flexibility and, 24–25global energy use, 17finfrastructure requirements, 16–17levelized cost of electricity from, 15f, 18f, 27fLNG (liquefied natural gas), 20–21, 21fmethane emissions, 31fprice volatility, 17–18, 19frenaissance of, 16–22renewable energy and, 8renewable-natural gas hybrids, 25–26scalable generating technologies, 27–29share of energy use, 17

Index


United Statesbiofuels and, 10biogas in, 31CHP systems, 28–29CSP plants, 26micropower generators and, 27natural gas and, 18renewable energy in, 12fshale gas and, 19–20supply and demand considerations, 13wind energy and, 33–34

U.S. National Renewable Energy Laboratory (NREL), 13

U.S. State Department, 19

VVolkswagen, 29

WWärtsila, 25Washington (U.S. state), 25wind energy

annual growth, 9fbackground information, 9BPA on, 33–34in Colorado, 24–25cost considerations, 11forecasting requirements, 13levelized cost of electricity from, 18f, 27fmicropower generators and, 27natural gas and, 25–27offshore wind power, 9–10solar energy comparison, 10storage considerations, 14supply and demand considerations, 12–13, 24technically recoverable, 10in Texas ERCOT load curve, 23f

Wood Mackenzie, 19World Bank Group, 34–35

XXcel Energy, 14

YYergin, Dan, 18

security, natural gas and, 18, 33shale gas, 18–19smart grid, 15, 34SMES (superconducting magnetic energy storage), 14sodium sulfate battery, 14solar energy

annual growth of generation, 9fbackground information, 9cleaning panels, 26fcost considerations, 11, 18distribution considerations, 12forecasting requirements, 13heating and cooling sectors, 11Institute for Solar Energy Technologies, 35flevelized cost of electricity from, 18fmicropower generators and, 27in selected countries, 12solar photovoltaic cells, 10supply and demand considerations, 12, 24technically recoverable, 10wind energy comparison, 10

Solar Energy Generating System (SEGS), 26South Africa, 17, 35South America, 10, 17f, 19South Korea, 16–17, 21Spain, 9–10, 12, 12f, 33spinning reserve, 24steam turbines, 5, 23, 25–26, 28stimulus packages, 11sugarcane ethanol, 10SunEdison, 10SunPower, 10Sweden, 10f, 13, 32

TTaiwan, 16–17Texas, 13, 13f, 23fThanet plant (United Kingdom), 9transportation sector, 10–11, 14–15, 17, 32Tunisia, 19

UUkraine, 18–19ultracapacitors, 14United Kingdom, 9–10, 19, 29United Nations Environment Programme (UNEP), 11

Index

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Powering the Low-Carbon Economy:The Once and Future Roles of

Renewable Energy and Natural Gas

Natural gas provides a natural complement to variable renewable energy sources such as wind and solar power. It is the cleanest fossil fuel, emitting less than half the carbon dioxide and a fraction of the smog-forming pollutants that coal power plants do. Moreover, it can be used in a variety of efficient, flexible, and scalable generating technologies, enabling it to back up wind and solar generation on a range of time and geographic scales.

If new supplies can be produced responsibly, natural gas can deliver immediate reductions in carbon emissions from the power sector. Methane, the main component of natural gas, already is being captured from landfills and other renewable sources, which can contribute a growing share of natural gas supplies in the decades ahead.

As renewable energy and natural gas become more economical, their share in global power generation markets is increasing at the expense of coal. Working together, renewable energy and natural gas can facilitate a rapid decarbonization of the power sector and provide the foundation for a low-carbon energy future—starting now.

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