Center for Climate and Energy Solutions
Many individuals, companies, and organizations contributed to the development of this report. The Center for Climate and Energy Solutions (C2ES) wishes to acknowledge all those who volunteered their time and expertise, including James Bradbury of the World Resources Institute and the many members of the C2ES Business Environmental Leadership Council that provided comments and guidance throughout the research process. We would also like to thank the American Clean Skies Foundation and the American Gas Association for their generous support of the project.
Recent technological advances have unleashed a boom in U.S. natural gas production, with expanded supplies and substantially lower prices projected well into the future. Because combusting natural gas yields fewer greenhouse gas emissions than coal or petroleum, the expanded use of natural gas offers significant opportunities to help address global climate change. The substitution of gas for coal in the power sector, for example, has contributed to a recent decline in U.S. greenhouse gas emissions. Natural gas, however, is not carbon-free. Apart from the emissions released by its combustion, natural gas is composed primarily of methane (CH4), a potent greenhouse gas, and the direct release of methane during production, transmission, and distribution may offset some of the potential climate benefits of its expanded use across the economy.
This report explores the opportunities and challenges in leveraging the natural gas boom to achieve further reductions in U.S. greenhouse gas emissions. Examining the implications of expanded use in key sectors of the economy, it recommends policies and actions needed to maximize climate benefits of natural gas use in power generation, buildings, manufacturing, and transportation (Table ES-1). More broadly, the report draws the following conclusions:
It is essential to maintain fuel mix diversity in the power sector. Too much reliance on any one fuel can expose a utility, ratepayers, and the economy to the risks associated with commodity price volatility. The increased natural gas and renewable generation of recent years has increased the fuel diversity of the power sector (by reducing the dominance of coal). In the long term, however, concern exists that market pressures could result in the retirement of a significant portion of the existing nuclear fleet, all of which could be replace by natural gas generation. Market pressures also could deter renewable energy deployment, carbon capture and storage, and efficiency measures. Without a carbon price, the negative externalities associated with fossil fuels are not priced by society, and therefore there will be less than optimal investment and expansion of zero-carbon energy sources.
Instead of being thought of as competitors, however, natural gas and renewable energy sources such as wind and solar can be complementary components of the power sector. Natural gas plants can quickly scale up or down their electricity production and so can act as an effective hedge against the intermittency of renewables. The fixed fuel price (at zero) of renewables can likewise act a hedge against potential natural gas price volatility.
It is important to encourage the efficient direct use of natural gas in buildings, where natural gas applications have a lower greenhouse gas emission footprint compared with other energy sources. For thermal applications, such as space and water heating, onsite natural gas use has the potential to provide lower-emission energy compared with oil or propane and electricity in most parts of the country. Natural gas for thermal applications is more efficient than grid-delivered electricity, yielding less energy losses along the supply chain and therefore less greenhouse gas emissions. Consumers need to be made aware of the environmental and efficiency benefits of natural gas use through labeling and standards programs and be incentivized to use it when emissions reductions are possible.
The efficient use of natural gas in the manufacturing sector needs to be continually encouraged. Combined heat and power systems, in particular, are highly efficient, as they use heat energy otherwise wasted. Policy is needed to overcome existing barriers to their deployment, and states are in an excellent position to take an active role in promoting combined heat and power during required industrial boiler upgrades and new standards for cleaner electricity generation in coming years. For efficiency overall, standards, incentives, and education efforts are needed, especially as economic incentives are weak in light of low natural gas prices.
Natural gas-related technologies, such as microgrids, microturbines, and fuel cells, have the potential to increase the amount of distributed generation used in buildings and manufacturing. These technologies can be used in configurations that reduce greenhouse gas emissions when compared with the centralized power system as they can reduce transmission losses and use waste heat onsite. To realize the potential of these technologies and overcome high upfront equipment and installation costs, policies like financial incentives and tax credits will need to be more widespread, along with consumer education about their availability.
The greatest opportunity to reduce greenhouse gas emissions using natural gas in the transportation sector is through fuel substitution in fleets and heavy-duty vehicles. Passenger vehicles, in contrast, likely represent a much smaller emission reduction opportunity even though natural gas when combusted emits fewer greenhouse gases than gasoline or diesel. The reasons for this include the smaller emission reduction benefit (compared to coal conversions), and the time it will take for a public infrastructure transition. By the time a passenger fleet conversion to natural gas would be completed, a new conversion to an even lower-carbon system, like fuel cells or electric vehicles, will be required to ensure significant emissions reductions throughout the economy.
Transmission and distribution pipelines must be expanded to ensure adequate supply for new regions and to serve more thermal loads in manufacturing, homes, and businesses. Increased policy support and innovative funding models, particularly for distribution pipelines, are needed to support the rapid deployment of this infrastructure.
By Meg Crawford and Janet Peace, C2ES
Recent technological advances have unleashed a boom in natural gas production, a supply surplus, and a dramatically lower price. The ample supply and lower price are expected to continue for quite some time, resulting in a relatively stable natural gas market. As a consequence, interest in expanding the use of natural gas has increased in a variety of sectors throughout the economy, including power, buildings, manufacturing, and transportation. Given that combusting natural gas yields lower greenhouse gas emissions than that of burning coal or petroleum, this expanded use offers significant potential to help the United States meet its climate change objectives. Expanded use of gas in the power sector, for example, has already led to a decrease in U.S. greenhouse gas emissions because of the substitution of gas for coal. It is important to recognize, however, that natural gas, like other fossil fuel production and combustion, does release greenhouse gases. These include carbon dioxide and methane; the latter is a higher global warming greenhouse gas. Accordingly, a future with expanded natural gas use will require diligence to ensure that potential benefits to the climate are achieved. This report explores the opportunities and challenges, sector by sector throughout the U.S. economy, and delves into the assortment of market, policy, and social responses that can either motivate or discourage the transition toward lower-carbon and zero-carbon energy sources essential for addressing climate change.
Throughout its history, the United States has undergone several energy transitions in which one dominant energy source has been supplanted by another. Today, as the country seeks lower-carbon, more affordable, domestically sourced fuel options to meet a variety of market, policy, and environmental objectives, the United States appears poised for another energy transition. Past energy transitions, for example, from wood to coal, took place largely without well-defined policies and were not informed by other big-picture considerations. Transitions of the past were largely shaped by regional and local economic realities and only immediate, local environmental considerations. The potential next energy transition can be more deliberately managed to achieve economic and environmental goals. The United States possesses the technological capacity and policy structures to do this. This report outlines, sector by sector, those technological options and policy needs.
The history of energy consumption in the United States from 1800 to 2010 moved steadily from wood to coal to petroleum (Figure 1). In the latter half of the 19th century, coal surpassed wood as the dominant fuel. Around 1950, petroleum consumption exceeded that of coal.
Petroleum still reigns supreme in the United States; however, due to a number of factors including improving fuel economy standards for vehicles, its use since 2006 is in decline. At the same time, for reasons that this report explores in depth, natural gas use is on the rise. As these trends continue, it is entirely possible in the coming decades that natural gas will overtake petroleum as the most popular primary energy source in the United States.1
Natural gas already plays a large role in the U.S. economy, constituting 27 percent of total U.S. energy consumption in 2012. Unlike other fossil fuels, natural gas has applications in almost every sector, including generating electricity; providing heat and power to industry, commercial buildings, and homes; powering vehicles; and as a feedstock in the manufacture of industrial products.
By all accounts, the existing increase in natural gas supply appears very certain, and the large domestic supply is expected to keep natural gas prices relatively low in the near to medium term. Furthermore, the domestic supply already has and is forecasted to deliver substantial benefits to the U.S. economy, providing jobs and increasing the gross domestic product. The primary uncertainties for the natural gas market are how quickly the expanded use will occur and the specific ways in which specific sectors of the economy will be affected. This report delves into the assortment of market, policy, and social responses that can motivate or discourage this transition. It places this energy transition firmly in the context of the closely related climate impacts of different types of energy use, and explores the interplay between economic opportunities and the pressing need to dramatically reduce the economy’s emissions of greenhouse gases.
The expanding use of natural gas is already reducing emissions of carbon dioxide (CO2), the primary greenhouse gas, at a time in which the U.S. economy is growing. In 2011, total U.S. CO2 emissions were down by nearly 9 percent from peak levels of 6,020 million metric tons in 2007. This decrease is due to a number of factors, of which the increased use of natural gas in the power sector is prominent. Demand is increasing as new and significantly more efficient natural gas power plants have been recently constructed, existing natural gas power plants are being used more extensively, and fuel-substitution from coal to natural gas is taking place. Compared to coal, natural gas is considered relatively clean because when it is burned in power plants, it releases about half as much CO2 (and far fewer pollutants) per unit of energy delivered than coal. As the fraction of electric power generated by coal has fallen over the last six years and been replaced mostly by natural gas-fueled generation and renewables, total U.S. CO2 emissions have decreased.
According to several sources, including the U.S. Energy Information Administration (EIA), additions in electric power capacity over the next 20 years are expected to be predominantly either natural gas-fueled or renewable (discussed further in chapter 4 of this report). Therefore, as coal’s share of generation continues to diminish, the implications for climate in the near and medium term are reduced CO2 emissions from the power sector. Further reductions in CO2 emissions are possible if natural gas replaces coal or petroleum in other economic sectors. In addition, wider use of distributed generation technologies in the manufacturing, commercial, and residential sectors, namely natural gas-fueled combined heat and power (CHP) systems, has great potential to significantly reduce U.S. CO2 emissions.
Source: Energy Information Administration, “Annual Energy Review,” Table 1.3. September 2012. Available at: http://www.eia.gov/totalenergy/data/annual/index.cfm#summary
Note: Wood, which was the dominant fuel in the United States for the first half of the 19th century, was surpassed by coal starting in 1885. Coal as the dominant fuel was surpassed by petroleum in 1950. Within one to two decades, natural gas might surpass petroleum as the dominant energy provider.
In the long term, however, the United States cannot achieve the level of greenhouse gas emissions necessary to avoid the serious impacts of climate change by relying on natural gas alone. Also required is the development of significant quantities of zero-emission sources of energy, which economic modeling shows will require policy intervention. Since many of these energy sources, such as wind and solar, are intermittent and current energy storage technology is in its infancy, natural gas will likely also be needed in the long term as a reliable, dispatchable backup for these renewable sources.
Crucially, natural gas is primarily methane, which is itself a very potent greenhouse gas. Methane is about 21 times more powerful in its heat-trapping ability than CO2 over a 100-year time scale. With increased use of natural gas, the direct releases of methane into the atmosphere throughout production and distribution have the potential to be a significant climate issue. Regulations have already been promulgated by the Environmental Protection Agency (EPA) that address this key issue. For example, “green completion” rules for production will require all unconventional wells to virtually eliminate venting during the flow-back stage of well completion through flaring or capturing natural gas. Releases need to be carefully managed, and EPA regulation of the natural gas sector will ensure that the climate benefits from transitioning to natural gas are truly maximized.
To examine the possible ways in which this energy transition might unfold and the potential implications for the climate, the Center for Climate and Energy Solutions and researchers at The University of Texas prepared 9 discussion papers looking at individual economic sectors, natural gas technologies, markets, infrastructure, and environmental considerations. Then, two workshops brought together dozens of respected thought leaders and stakeholders to analyze the potential to leverage natural gas use to reduce greenhouse gas emissions. Stakeholders included representatives of electric and natural gas utilities, vehicle manufacturers, fleet operators, industrial consumers, homebuilders, commercial real estate operators, pipeline companies, independent and integrated natural gas producers, technology providers, financial analysts, public utility and other state regulators, environmental nonprofits, and academic researchers and institutions.
This report is the culmination of these efforts. First, it provides background on natural gas and the events leading to the present supply boom. Next, it lays out the current and projected U.S. natural gas market, including the forecast price effects during the transition. It details the relationship between natural gas and climate change and then explores the opportunities and challenges in the power, buildings, and manufacturing sectors. It looks at technologies for on-site (distributed) electricity generation using natural gas, followed by prospects for increasing natural gas consumption in the transportation sector. Finally, the report examines the state of natural gas infrastructure and the barriers to its needed expansion.
This report offers insight into ways to lower the climate impact of natural gas while increasing its use in the electric power, buildings, manufacturing, and transportation sectors, and looks at infrastructure expansion needs and what future technologies may portend for low-emission natural gas use. This report is the product solely of the Center for Climate and Energy Solutions (C2ES) and may not necessarily represent the views of workshop participants, the C2ES Business Environmental Leadership Council or Strategic Partners, or project sponsors.
Natural gas is a naturally occurring fossil fuel consisting primarily of methane that is extracted with small amounts of impurities, including CO2, hazardous air pollutants, and volatile organic compounds. Most natural gas production also contains, to some degree, heavier liquids that can be processed into valuable byproducts, including propane, butane, and pentane.
Natural gas is found in several different types of geologic formations (Figure 2). It can be produced alone from reservoirs in natural rock formations or be associated with the production of other hydrocarbons such as oil. While this “associated” gas is an important source of domestic supply, the majority (89 percent) of U.S. gas is extracted as the primary product, i.e., non-associated.2
With relatively recent advances in seismic imaging, horizontal drilling, and hydraulic fracturing, U.S. natural gas is increasingly produced from unconventional sources such as coal beds, tight sandstone, and shale formations, where natural gas resources are not concentrated or are in impermeable rock and require advanced technologies for development and production and typically yield much lower recovery rates than conventional reservoirs.3 Shale gas extraction, for example, differs significantly from the conventional extraction methods. Wells are drilled vertically and then turned horizontally to run within shale formations. A slurry of sand, water, and chemicals is then injected into the well to increase pressure, break apart the shale to increase permeability, and release the natural gas. This technique is known as hydraulic fracturing or “fracking.”
Source: Energy Information Agency, “Schematic Geology of Natural Gas Resources,” January 2010. Available at: http://www.eia.gov/oil_gas/natural_gas/special/ngresources/ngresources.html
Notes: Gas-rich shale is the source rock for many natural gas resources, but, until now, has not been a focus for production. Horizontal drilling and hydraulic fracturing have made shale gas an economically viable alternative to conventional gas resources.
Conventional gas accumulations occur when gas migrates from gas rich shale into an overlying sandstone formation, and then becomes trapped by an overlying impermeable formation, called the seal. Associated gas accumulates in conjunction with oil, while non-associated gas does not accumulate with oil.
Tight sand gas accumulations occur in a variety of geologic settings where gas migrates from a source rock into a sandstone formation, but is limited in its ability to migrate upward due to reduced permeability in the sandstone.
Coalbed methane does not migrate from shale, but is generated during the transformation of organic material to coal.
The remarkable speed and scale of shale gas development has led to substantial new supplies of natural gas making their way to market in the United States. The U.S. EIA projects that by 2040 more than half of domestic natural gas production will come from shale gas extraction and that production will increase by 10 trillion cubic feet (Tcf) above 2011 levels (Figure 3). The current increase was largely unforeseen a decade ago. This increase has raised awareness of natural gas as a key component of the domestic energy supply and has dramatically lowered current prices as well as price expectations for the future. In recent years, the abundance of natural gas in the United States has strengthened its competitiveness relative to coal and oil, has expanded its use in a variety of contexts, and has raised its potential for reducing greenhouse gas emissions and strengthening U.S. energy security by reducing U.S. reliance on foreign energy supplies.
U.S. natural gas markets have only been truly open and competitive for about 20 years, when U.S. gas markets were deregulated and price controls were removed in the early 1990s. Before that time, government regulation controlled the price that producers could charge for certain categories of gas placed into the interstate market (the wellhead price) as well as pipeline access to market and in some cases specific uses of natural gas. The results were price signals that periodically resulted in supply shortages and little incentive for increased production. Since deregulation, price fluctuations have been pronounced, ranging from less than $2 to more than $10 per thousand cubic feet (Mcf) (Figure 4). Periods of high market prices have resulted from changes in regulation, weather disruptions, and broader trends in the economy and energy markets—but also from perceptions of abundance or scarcity in the market. A number of supply-side factors also affect prices, including the volume of production added to the market and storage availability to hedge against production disruptions or demand spikes. Looking forward, the average wellhead price is expected to be much less volatile and remain below $5 per Mcf through 2026 and rise to $6.32 per Mcf in 2035, as production gradually shifts to resources that are less productive and more expensive to extract.4
Since 1999, U.S. proven reserves of natural gas have increased every year, driven mostly by shale gas advancements.5 In 2003, the National Petroleum Council estimated U.S. recoverable shale gas resources at 35 Tcf.6 In 2012, the EIA put that estimate closer to 482 Tcf out of an average remaining U.S. resource base of 2,543 Tcf,7 and in 2011, the Massachusetts Institute of Technology’s mean projection estimate of recoverable shale gas resources was 650 Tcf out of a resource base of 2,100 Tcf.8 By comparison, annual U.S. consumption of natural gas was 24.4 Tcf in 2011.9 So, these estimates represent nearly 100 years of domestic supply at current levels of consumption.10
Source: Energy Information Administration, “Annual Energy Outlook 2013 Early Release” December 2012. Available at http://www.eia.gov/forecasts/aeo/er/executive_summary.cfm
Rising natural gas prices after deregulation offered new economic incentives to develop unconventional gas resources. Advances in the efficiency and cost-effectiveness of horizontal drilling, new mapping tools, and hydraulic fracturing technologies—enabled by investments in research and development from the Department of Energy and its national labs along with private sector innovations—have led to the dramatic increase in U.S. shale gas resources that can be economically recovered.
Even as supply estimates have increased, the cost of producing shale gas has declined as more wells are drilled and new techniques are tried. In one estimate, approximately 400 Tcf of U.S. shale gas can be economically produced at or below $6 per Mcf (in 2007 dollars).11 Another estimate suggests that nearly 1,500 Tcf can be produced at less than $8 per Mcf, 500 Tcf at less than $8 per Mcf, and 500 Tcf at $4 per Mcf.12
Shale gas developments are fundamentally altering the profile of U.S. natural gas production (Figure 3). Since 2009, the United States has been the world’s leading producer of natural gas, with production growing by more than 7 percent in 2011—the largest year-over-year volumetric increase in the history of U.S. production.13 The proportion of U.S. production that is shale gas has steadily increased as well. In the decade of 2000 to 2010, U.S. shale gas production increased 14-fold and comprised approximately 34 percent of total U.S. production in 2011.14 From 2007 to 2008 alone, U.S. shale gas production increased by 71 percent.15 Shale gas production is expected to continue to grow, estimated to increase almost fourfold between 2009 and 2035, when it is forecast to make up 47 percent of total U.S. production.16 The geographic distribution of shale gas production is also shifting to new geologic formations with natural gas potential, called “plays,” such as the Barnett shale play in Texas and the Marcellus shale play in the Midwest (Figure 5).17 Natural gas is currently produced in 32 states and in the Gulf of Mexico, with 80.8 percent of U.S. production occurring in Texas, the Gulf of Mexico, Wyoming, Louisiana, Oklahoma, Colorado, and New Mexico in 2010. An increasing percentage of production is coming from states new on the scene, including Pennsylvania and Arkansas. This new geography of production has particularly large impacts for the development of natural gas infrastructure, as examined in chapter 9.
Source: Energy Information Administration, “Natural Gas Prices,” 2013. Available at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
These dramatic increases in production, in combination with a weak economy and the accompanying decrease in demand for energy, are reflected in unexpectedly low and less volatile market prices, prices that encourage energy consumers to look at new uses for the fuel. Yet uncertainties remain that could hinder future development and production. For one thing, very low prices may result in producers temporarily closing down wells, particularly if the associated liquids produced along with the gas are not sufficient to make up for low natural gas prices and make well production economically viable.18 In the long term, the dynamic nature of natural gas supply and demand will determine the price levels and volatility. Of particular importance is the extent and speed of demand expansion, a topic explored in the following section.
Just as supply has implications for the price path of natural gas, so does the demand. Natural gas is consumed extensively in the United States for a multitude of uses: for space and water heating in residential and commercial buildings, for electricity generation and process heat in the industrial sector, and as industrial feedstock, where natural gas constitutes the base ingredient for such varied products as plastic, fertilizer, antifreeze, and fabrics.19 In 2012, natural gas use constituted roughly one-quarter of total U.S. primary energy consumption and was consumed in every sector of the U.S. economy (Figure 6). Total U.S. consumption of natural gas grew from 23.3 Tcf in 2000 to 25.4 in 2012.20 Within the overall growth, consumption in several sectors held steady, while consumption in the industrial sector declined (due to increased efficiency and the economic slowdown) and consumption in the power sector grew at an annual average rate of 3.5 percent.
Source: Energy Information Administration, “Lower 48 States Shale Plays,” May 2011. Available at: http://www.eia.gov/oil_gas/rpd/shale_gas.pdf
In the U.S. power sector in 2010, natural gas fueled 23.9 percent of the total generation. From 2000 to 2010, electricity generation fueled by natural gas grew at a faster rate than total generation (5.1 percent versus 0.8 percent per year) (Figure 7). This growth can be attributed to a number of factors, including low natural gas prices in the early part of the decade that made natural gas much more attractive for power generation. In addition, gas-fired plants are relatively easy to construct, have lower emissions of a variety of regulated pollutants than coal-fired plants, and have lower capital costs and shorter construction times than coal-fired plants. Transportation has remained the smallest sectoral user of natural gas, with natural gas vehicles contributing to a significant percentage of the total fleet only among municipal buses and some other heavy-duty vehicles.
Source: Energy Information Administration, “Natural Gas Consumption by End Use,” 2013. Available at http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm
In contrast to oil, which is widely traded across national boundaries and over long distances, natural gas has been primarily a domestic resource. The low density of natural gas makes it difficult to store and to transport by vehicle (unless the gas is compressed or liquefied). (See chapter 8 for an extended discussion of liquefied and compressed natural gas.) Natural gas is therefore transported via pipelines that connect the natural gas wells to end consumers. Trade patterns tend to be more regional (particularly in the United States), and prices tend to be determined within regional markets. On the world stage, resources are concentrated geographically. Seventy percent of the world’s gas supply (including unconventional resources) is located in only three regions—Russia, the Middle East (primarily Qatar and Iran), and North America. Within the United States, 10 states or regions account for nearly 90 percent of production: Arkansas, Colorado, Gulf of Mexico, Louisiana, New Mexico, Oklahoma, Pennsylvania, Texas, Utah, and Wyoming. Significant barriers exist to establishing a natural gas market that is truly global. While most natural gas supplies can be developed economically with relatively low prices at the wellhead or the point of export,21 high transportation costs—either via long-distance pipeline or via tankers for liquefied natural gas (LNG)—have, until recently, constituted solid barriers to establishing a global gas market.
In 2011, net imports of natural gas, delivered via pipeline and LNG import facilities, constituted only 8 percent of total U.S. natural gas consumption (1.9 Tcf), the lowest proportion since 1993.22 Of this amount, about 90 percent came from Canada.23 (By contrast, 45 percent of U.S. oil consumption was imported in 2011, of which 29 percent came from Canada.24) Net imports of natural gas have decreased by 31 percent since 2007, with U.S. production growing significantly faster than U.S. demand. These trends and greater confidence in U.S. domestic gas supply suggest that prices between crude oil and gas will continue to diverge, establishing a new relationship that may fundamentally change the way energy sources are used in the United States.
Although most of the world’s gas supply continues to be transported regionally via pipeline, the global gas trade is accelerating because of the growing use of LNG. Natural gas, once liquefied,25 can be transported by tanker to distant destinations and regasified for use. Between 2005 and 2010, the global market for LNG grew by more than 50 percent,26 and LNG now accounts for 30.5 percent of global gas trade.27 From 2009 to 2011 alone, global capacity for gas liquefaction increased by almost 40 percent, with global LNG trade set to rise by 30 percent by 2017.28
Source: Energy Information Administration, “Natural Gas Consumption by End Use,” 2013. Available at http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm
In the United States, prospects for exports of LNG depend heavily on the cost-competitiveness of U.S. liquefaction projects relative to those at other locations. During 2000 to 2010, new investments were made in the United States in infrastructure for natural gas importation and storage, prompted by lower supply expectations and higher, volatile domestic prices. Since 2000, North America’s import capacity for LNG has expanded from approximately 2.3 billion cubic feet (Bcf) per day to 22.7 Bcf per day, around 35 percent of the United States’ average daily requirement.29 However by 2012, U.S. consumption of imported LNG had fallen to less than 0.5 Bcf per day, leaving most of this capacity unused.30 The ability to make use of and repurpose existing U.S. import infrastructure—pipelines, processing plants, and storage and loading facilities—would help reduce total costs relative to “greenfield,” or new, LNG facilities. Given natural gas surpluses in the United States and substantially higher prices in other regional markets, several U.S. companies have applied for export authority and have indicated plans to construct liquefaction facilities.31
The EIA projects that the United States will become a net exporter of LNG in 2016, a net pipeline exporter in 2025, and a net exporter of natural gas overall in 2021. This outlook assumes continuing increases in use of LNG internationally, strong domestic natural gas production, and relatively low domestic natural gas prices.32 In contrast, a study done by the Massachusetts Institute of Technology presents another possible scenario in which a more competitive international gas market could drive the cost of U.S. natural gas in 2020 above that of international markets, which could lead to the United States importing 50 percent of its natural gas by 2050.33 Yet while increased trade in LNG has started to connect international markets, these markets remain largely distinct with respect to supply, contract structures, market regulation, and prices.
The increase in domestic production (supplies) of natural gas, low prices, and forecasts of continued low prices have not gone unnoticed. The implications for energy consumption are far-reaching and extend across all sectors of the economy. This report examines how each sector may take advantage of this energy transformation and evaluates the greenhouse gas emission implications of each case.
By Michael Webber, The University of Texas at Austin
Given technology developments that have fundamentally altered the profile of U.S. natural gas production and recent low prices that have pushed demand for natural gas in all sectors of the economy, the importance of natural gas relative to other fuels is growing. If recent trends continue, it seems likely that natural gas will overtake petroleum as the most-used primary energy source in the United States. in the next one to two decades.
Such a transition will be enabled (or inhibited) by a mixed set of competing price pressures and a complicated relationship with lower-carbon energy sources that will trigger an array of market and cultural responses. This chapter seeks to layout some of the key underlying trends while also identifying some of these different axes of price tensions (or price dichotomies). These trends and price tensions will impact the future use of natural gas in all of the sectors analyzed later in this report.
For a century, oil and natural gas consumption trends have tracked each other quite closely. Figure 1 shows normalized U.S. oil and gas consumption from 1920 to 2010 (consumption in 1960 is set to a value of 1.0). These normalized consumption curves illustrate how closely oil and gas have tracked each other up until 2002, at which time their paths diverged: natural gas consumption declined from 2002 to 2006, while petroleum use grew over that time period. Then, they went the other direction: natural gas consumption grew and oil production dropped. That trend continues today, as natural gas pursues an upward path, whereas petroleum is continuing a downward trend.
The growing consumption of natural gas is driven by a few key factors:
By contrast, the trends for petroleum and coal are moving downwards. Petroleum use is expected to drop as a consequence of price pressures and policy mandates. The price pressures are triggered primarily by the split in energy prices between natural gas and petroleum (discussed in detail below). The mandates include biofuels production targets (which increase the production of an alternative to petroleum) and fuel economy standards (which decrease the demand for liquid transportation fuels). At the same time, coal use is also likely to drop because of projections by the EIA for price doubling over the next 20 years and environmental standards that are expected to tighten the tolerance for emissions of heavy metals, sulfur oxides, nitrogen oxides, particulate matter, and CO2.
Petroleum use might decline 0.9 percent annually from the biofuels mandates themselves. Taking that value as the baseline, and matching it with an annual growth of 0.9 percent in natural gas consumption (which is a conservative estimation based on trends from the last six years, plus recent projections for increased use of natural gas by the power and industrial sectors), indicates that natural gas will surpass petroleum in 2032, two decades from now, as depicted in Figure 2. A steeper projection of 1.8 percent annual declines in petroleum matched with 1.8 percent annual increase in natural gas consumption sees a faster transition, with natural gas surpassing petroleum in less than a decade.
Source: Energy Information Agency, “Annual Energy Review 2010” Technical Report, 2011.
Note: U.S. oil and gas consumption from 1920 to present day (normalized to a value of 1 in 1960) shows how oil and gas have tracked each other relatively closely until 2002, after which their paths diverge. Since 2006, natural gas consumption has increased while petroleum consumption has decreased.
While such diverging rates might seem aggressive, they are a better approximation of the trends over the last six years than the respective 0.9 percent values. An annual decline in petroleum of 1.8 percent is plausible through a combination of biofuels mandates (0.9 percent annual decline), higher fuel economy standards (0.15 percent annual decline), and price competition that causes fuel-switching from petroleum to natural gas in the transportation (heavy-duty, primarily) and industrial sectors (0.75 percent annual decline). Natural gas growth rates of 1.8 percent annually can be achieved by natural gas displacing 25 percent of diesel use (for on-site power generation and transportation) and natural gas combined-cycle power plants displacing 25 percent of 1970s and 1980s vintage coal-fired power plants by 2022. While this scenario is bullish for natural gas, it is not implausible, especially for the power sector, whose power plants face retirement and stricter air quality standards. Coupling those projections with reductions in per-capita energy use of 10 percent (less than 1 percent annually) over that same span imply that total energy use would stay the same.
These positive trends for natural gas are not to say it is problem-free. Environmental challenges exist for water, land, and air. Water challenges are related to quality (from risks of contamination) and quantity (from competition with local uses and depletion of reservoirs). Land risks include surface disturbance from production activity and induced seismicity from wastewater reinjection. Air risks are primarily derived from leaks on site, leaks through the distribution system, and flaring at the point of production. Furthermore, while natural gas prices have been relatively affordable and stable in the last few years, natural gas prices have traditionally been very volatile. However, if those economic and environmental risks are managed properly, then these positive trends are entirely possible.
Source: Energy Information Agency, “Annual Energy Review 2010” Technical Report, 2011.
Note: Natural gas might pass petroleum as the primary fuel source in the United States within one to two decades, depending on the annual rate of decreases in petroleum consumption and increases in natural gas consumption. Historical values plotted are from EIA data.
In light of the looming transition to natural gas as the dominant fuel in the United States, it is worth contemplating the complicated pricing relationship that natural gas in the United States has with other fuels, market factors, and regions. It turns out that there are several relevant price dichotomies to keep in mind:
The tensions along these price axes will likely play an important role in driving the future of natural gas in the United States and globally.
One of the most important recent trends has been the decoupling of natural gas and petroleum prices. Figure 3 shows the U.S. prices for natural gas and petroleum (wellhead and the benchmark West Texas Intermediate (WTI) crude at Cushing, Oklahoma respectively) from 1988 to 2012.34, 35 While natural gas and petroleum prices have roughly tracked each other in the United States for decades, their trends started to diverge in 2009 as global oil supplies remained tight, yet shale gas production increased. This recent divergence has been particularly stark, as it’s driven by the simultaneous downward swing in natural gas prices and upward swing in petroleum prices. For many years, the ratio in prices (per million BTU, or MMBTU) between petroleum and natural gas oscillated nominally in the range of 1–2, averaging 1.6 for 2000–2008. However, after the divergence began in 2009, this spread became much larger, averaging 4.2 for 2011 and, remarkably, achieving ratios greater than 9 spanning much of the first quarter of 2012 (for example, natural gas costs approximately $2/MMBTU today, whereas petroleum costs $18/MMBTU).
This spread is relatively unprecedented and, if sustained, opens up new market opportunities for gas to compete with oil through fuel-switching by end-users and the construction of large-scale fuel processing facilities. For the former, these price spreads might inspire institutions with large fleets of diesel trucks (such as municipalities, shipping companies, etc.) to consider investing in retrofitting existing trucks or ordering new trucks that operate on natural gas instead of diesel to take advantage of the savings in fuel costs. For the latter, energy companies might consider investing in multi-billion dollar gas-to-liquids (GTL) facilities to convert the relatively inexpensive gas into relatively valuable liquids.
Another important trend has been the decoupling of U.S. and global prices for natural gas. Figure 4 shows the U.S. prices for natural gas (at Henry Hub) compared with European Union and Japanese prices from 1992 to 2012.36, 37, 38, 39 In a similar fashion as discussed below, while natural gas prices in the U.S. and globally (in particular, the European Union and Japan) have tracked each other for decades, their price trends started to diverge in 2009 because of the growth in domestic gas production. In fact, from 2003–2005, U.S. natural gas prices were higher than in the EU and Japan because of declining domestic production and limited capacity for importing liquefied natural gas (LNG). At that time, and for the preceding years, the U.S. prices were tightly coupled to global markets through its LNG imports setting the marginal price of gas.
Consequently, billions of dollars of investments were made to increase LNG import capacity in the United States That new import capacity came online concurrently with higher domestic production, in what can only be described as horribly ironic timing: because domestic production grew so quickly, those new imports were no longer necessary, and much of that importing capacity remains idle today. In fact, once production increased in 2009, the United States was then limited by its capacity to export LNG (which is in contrast to the situation just a few years prior, during which the United States was limited by its capacity to import gas), so gas prices plummeted despite growing global demand. Thus, while the United States was tightly coupled to global gas markets for well over a decade, it has been decoupled for the last several years. At the same time, the European Union and Japan are tightly coupled to the world gas markets, (with the European Union served by LNG and pipelines from the Former Soviet Union, and Japan served by LNG). How long these prices remain decoupled will depend on U.S. production of natural gas, U.S. demand for natural gas, and the time it takes for these isolated markets to connect again. In fact, LNG terminal operators are now considering the investment of billions of dollars to turn their terminals around so that they can buy cheap natural gas in the U.S. that they can sell at higher prices to the EU and Japan. Once those terminals are turned around, these geographically-divergent market prices could come back into convergence.
Sources: Energy Information Administration, U.S. Natural Gas Prices, Tech. rep., April 2, 2012. Available at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
Energy Information Administration, Cushing, OK WTI Spot Price FOB (Dollars per Barrel), Tech. rep., April 4, 2012. Available at: http://tonto.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=RWTC&f=M
Note: While natural gas and petroleum prices have roughly tracked each other in the U.S. for decades, their price trends started to diverge in 2009.
Another axis to consider for natural gas prices is the tension between the price at which we have abundant supply, and the price at which we have abundant demand. These levels have changed over the years as technology improves and the prices of competing fuels have shifted, but it seems clear that there is still a difference between the prices that consumers wish to pay and producers wish to collect. In particular, above a certain price (say, somewhere in the range of $4–8/MMBTU, though there is no single threshold that everyone agrees upon), the United States would be awash in natural gas. Higher prices make it possible to economically produce many marginal plays, yielding dramatic increases in total production. However, at those higher prices, the demand for gas is relatively lower because cheaper alternatives (nominally coal, wind, nuclear and petroleum) might be more attractive options. At the same time, as recent history has demonstrated, below a certain price (say, somewhere in the range of $1–3/MMBTU), there is significant demand for natural gas in the power sector (as an alternative to coal) and the industrial sector (because of revitalized chemical manufacturing, which depends heavily on natural gas as a feedstock). Furthermore, if prices are expected to remain low, then demand for natural gas would increase in the residential and commercial sectors (as an alternative to electricity for water heating, for example) and in the transportation sector (to take advantage of price spreads with diesel, as noted above).
Sources: BP, “BP Statistical Review of World Energy,” Tech. rep., June 2011, Available at: http://bp.com/statisticalreview
Energy Information Administration, Henry Hub Gulf Coast Natural Gas Spot Price, Tech. rep., April 6, 2012. Available at: http://tonto.eia.gov/dnav/ng/hist/rngwhhdm.htm
Energy Information Administration, Price of Liquefied U.S. Natural Gas Exports to Japan, Tech. rep., April 6, 2012. Available at: http://www.eia.gov/dnav/ng/hist/n9133ja3m.htm
YCharts, European Natural Gas Import Price, Tech. rep., April 6, 2012. Available at: http://ycharts.com/indicators/europe_natural_gas_price
Note: While natural gas prices in the U.S. and globally (EU and Japan) have tracked each other for decades, their price trends started to diverge in 2009.
The irony here is that it is not clear that the prices at which there will be significant increases in demand will be high enough to justify the higher costs that will be necessary to induce increases in supply, and so there might be a period of choppiness in the market as the prices settle into their equilibrium. Furthermore, as global coal and oil prices increase (because of surging demand from China and other rapidly-growing economies), the thresholds for this equilibrium are likely to change. As oil prices increase, natural gas production will increase at many wells as a byproduct of liquids production, whether the gas was desired or not. Since the liquids are often used to justify the costs of a new well, the marginal cost of the associated gas production can be quite low. Thus, natural gas production might increase even without upward pressure from gas prices, which lowers the price threshold above which there will be abundant supply. At the same time, coal costs are increasing globally, which raises the threshold below which there is abundant demand. Hopefully, these moving thresholds will converge at a stable medium, though it is too early to tell. If the price settles too high, then demand might retract; if it settles too low, the production might shrink, which might trigger an oscillating pattern of price swings.
Another axis of price tension for natural gas is whether high prices or low prices are better for achieving environmental goals such as reducing the energy sector’s emissions and water use. In many ways, high natural gas prices have significant environmental advantages because they induce conservation and enable market penetration by relatively expensive renewables. In particular, because it is common for natural gas to be the next fuel source dispatched into the power grid in the United States, high natural gas prices trigger high electricity prices. Those higher electricity prices make it easier for renewable energy sources such as wind and solar power to compete in the markets. Thus, high natural gas prices are useful for reducing consumption overall and for spurring growth in novel generation technologies.
However, inexpensive natural gas also has important environmental advantages by displacing coal in the power sector. Notably, by contrast with natural gas prices, which have decreased for several years in a row, prevailing coal prices have increased steadily for over a decade due to higher transportation costs (which are coupled to diesel prices that have increased over that span), depletion of mines, and increased global demand. As coal prices track higher and natural gas prices track lower, natural gas has become a more cost-effective fuel for power generation for many utility companies. Consequently, coal’s share of primary energy consumption for electricity generation has dropped from 53 percent in 2003 to less than 46 percent in 2011 (with further drops in the first quarter of 2012), while the share fulfilled by natural gas grew from 14 percent to 20 percent over the same span. At the same time, there was a slight drop in overall electricity generation due to the economic recession, which means the rise of natural gas came at the expense of coal, rather than in addition to coal. Consequently, for those wishing to achieve the environmental goals of dialing back on power generation from coal, low natural gas prices have a powerful effect.
These attractive market opportunities are offset in some respects by the negative environmental impacts that are occurring from production in the Bakken and Eagle Ford shale plays in North Dakota and Texas. At those locations, significant volumes of gases are flared because the gas is too inexpensive to justify rapid construction of the pricey distribution systems that would be necessary to move the fuel to markets.40, 41 Consequently, for many operators it ends up being cheaper in many cases to flare the gas rather than to harness and distribute it.
And, thus, the full tension between the “environmental price” of gas is laid out: low prices are good because they displace coal, whereas high prices are good because they bring forward conservation and renewable alternatives. This price axis will be important to watch from a policymaker’s point of view as time moves forward.
One of the historical criticisms of natural gas has been its relative volatility, especially as compared with coal and nuclear fuels, which are the other major primary energy sources for the power sector. This volatility is a consequence of large seasonal swings in gas consumption (for example, for space and water heating in the winter) along with the association of gas production with oil, which is also volatile. Thus, large magnitude swings in demand and supply can be occurring simultaneously, but in opposing directions. However, two forces are mitigating this volatility. Firstly, because natural gas prices are decoupling from oil prices (as discussed in above), one layer of volatility is reduced. Many gas plays are produced independently of oil production. Consequently, there is a possibility for long-term supply contracts at fixed prices. Secondly, the increased use of natural gas consumption in the power sector, helps to mitigate some of the seasonal swings as the consumption of gas for heating in the winter might be better matched with consumption in the summer for power generation to meeting air conditioning load requirements.
Between more balanced demand throughout the year and long-term pricing, the prospects for better stability look better. At the same time, coal, which has historically enjoyed very stable prices, is starting to see higher volatility because its costs are coupled with the price of diesel for transportation. Thus, ironically, while natural gas is reducing its exposure to oil as a driver for volatility, coal is increasing its exposure.
While natural gas is enjoying a period of relatively stable and low prices at the time of this writing, there are several prospects that might put upward pressure on the long-term prices. These key drivers are: 1) increasing demand, and 2) re-coupling with global markets.
As discussed above, there are several key forcing functions for higher demand. Namely, because natural gas is relatively cleaner, less carbon-intensive, and less water-intensive than coal, it might continue its trend of taking away market share from coal in the power sector to meet increasingly stringent environmental standards. While this trend is primarily driven by environmental constraints, its effect will be amplified as long as natural gas prices remain low. While fuel-switching in the power sector will likely have the biggest overall impact on new natural gas demand, the same environmental and economic drivers might also induce fuel-switching in the transportation sector (from diesel to natural gas), and residential and commercial sectors (from fuel oil to natural gas for boilers, and from electric heating to natural gas heating). If cumulative demand increases significantly from these different factors but supply does not grow in a commensurate fashion, then prices will move upwards.
The other factor is the potential for re-coupling U.S. and global gas markets. While they are mostly empty today, many LNG import terminals are seeking to reverse their orientation, with an expectation that they will be ready for export beginning in 2014. Once they are able to export gas to EU and Japanese markets, then domestic gas producers will have additional markets for their product. If those external markets maintain their much higher prevailing prices (similar to what is illustrated in Figure 4), re-coupling will push prices upwards.
Each of these different axes of price tensions reflects a different nuance of the complicated, global natural gas system. In particular, they exemplify the different market, technological and societal forces that will drive—and be driven by—the future of natural gas.
Overall, it is clear that natural gas has an important opportunity to take market share from other primary fuels. In particular, it could displace coal in the power sector, petroleum in the transportation sector, and fuel oil in the commercial and residential sectors. With sustained growth in demand for natural gas, coupled with decreases in demand for coal and petroleum because of environmental and security concerns, natural gas could overtake petroleum to be the most widely used fuel in the United States within one to two decades. Along the path towards that transition, natural gas will experience a variety of price tensions that are manifestations of the different market, technological and societal forces that will drive—and be driven by— the future of natural gas. How and whether we sort out these tensions and relationships will affect the fate of natural gas and are worthy of further scrutiny.
By Joseph Casola, Daniel Huber, and Michael Tubman, C2ES
Natural gas is a significant source of greenhouse gas emissions in the United States. Approximately 21 percent of total U.S. greenhouse gas emissions in 2011 were attributable to natural gas.42 When natural gas is combusted for energy, it produces carbon dioxide (CO2), which accounts for most of greenhouse gas emissions associated with this fuel. Natural gas is composed primarily of methane (CH4), which has a higher global warming potential than CO2. During various steps of natural gas extraction, transportation, and processing, methane escapes or is released to the atmosphere. Although this represents a relatively smaller portion of the total greenhouse gas emissions associated with natural gas production and use, vented and leaked or “fugitive” emissions can represent an opportunity to reduce greenhouse gas emissions, maximizing the potential climate benefits of using natural gas.
Total methane emissions from natural gas systems (production, processing, storage, transmission, and distribution) in the United States have improved during the last two decades, declining 13 percent from 1990 to 2011, driven by infrastructure improvements and technology, as well as better practices adopted by industry. This has occurred even as production and consumption of natural gas has grown. Methane emissions per unit of natural gas consumed have dropped 32 percent from 1990 to 2011. Since 2007, methane emissions from all sources have fallen almost 6 percent, driven primarily by reductions of methane emissions from natural gas systems. Nevertheless, given its impact on the climate, emphasis on reducing methane emissions from all sources must remain a high priority. This chapter discusses the differences between methane and CO2, emission sources, and state and federal regulations affecting methane emissions.
On a per-mass basis, methane is more effective at warming the atmosphere than CO2. This is represented by methane’s global warming potential (GWP), which is a factor that expresses the amount of heat trapped by a pound of a greenhouse gas relative to a pound of CO2 over a specified period of time. GWP is commonly used to enable direct comparisons between the warming effects of different greenhouse gases. By convention, the GWP of CO2 is equal to one.
The GWP of a greenhouse gas (other than CO2) can vary substantially depending on the time period of interest. For example, on a 100-year time frame, the GWP of methane is about 21.43 But for a 20-year time frame, the GWP of methane is 72.44 The difference stems from the fact that the lifetime of methane in the atmosphere is relatively short, a little over 10 years, when compared to CO2, which can persist in the atmosphere for decades to centuries.
Since models that project future climate conditions are often compared for the target year of 2100, it is often convenient to use 100-year GWPs when comparing emissions of different greenhouse gases. However, these comparisons may not accurately reflect the relative reduction in radiative forcing (the extent to which a gas traps heat in the atmosphere) arising from near-term abatement efforts for greenhouse gases with short lifetimes. Whereas near-term reductions in CO2 emissions provide reductions in radiative forcing benefits spread out over a century, near-term abatement efforts for methane involve a proportionally larger near-term reduction in radiative forcing. In light of potential climate change over the next 50 years, the control of methane has an importance that can be obscured when greenhouse gases are compared using only their 100-year GWPs. Accordingly, reducing methane emissions from all sources is important to efforts aimed at slowing the rate of climate change.
On average, natural gas combustion releases approximately 50 percent less CO2 than coal and 33 percent less CO2 than oil (per unit of useful energy) (Figure 1). In addition, the combustion of coal and oil emits other hazardous air pollutants, such as sulfur dioxides and particulate matter. Therefore, the burning of natural gas is considered cleaner and less harmful to public health and the environment than the burning of coal and oil.
The U.S. Energy Information Administration (EIA) has projected that U.S. energy-related CO2 emissions will remain more than 5 percent below their 2005 level through 2040, a projection based in large part on the expectation that: 1) natural gas will be steadily substituted for coal in electricity generation as new natural gas power plants are built and coal-fired power plants are converted to natural gas, and 2) state and federal programs that encourage the use of low-carbon technologies will continue.45 The EIA predicts that natural gas—fired electricity production in the United States will increase from 25 percent in 2010 to 30 percent in 2040, in response to continued low natural gas prices and existing air quality regulations that affect coal-fired power generation.
Source: Environmental Protection Agency, Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011. 2013. Chapter 3 and Annex 2. Available at: http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html
Notes: CO2 content for petroleum has been calculated as an average of representative fuel types (e.g., jet fuel, motor gasoline, distillate fuel) using 2011 data.
This graphic does not account for the relative efficiencies of end-use technologies.
In 2011, natural gas systems contributed approximately one-quarter of all U.S. methane emissions (Figure 2), of which over 37 percent are associated with production.46 In the production process, small amounts of methane can leak unintentionally. In addition methane may be intentionally released or vented to the atmosphere for safety reasons at the wellhead or to reduce pressure from equipment or pipelines. Where possible, flares can be installed to combust this methane (often at the wellhead), preventing much of it from entering the atmosphere as methane but releasing CO2 and other air pollutants instead.
Source: Environmental Protection Agency, Draft U.S. Greenhouse Gas Inventory Report, 2013. Available at: http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html
These methane emissions are an important, yet not well understood, component of overall methane emissions. In recent years greenhouse gas measurement and reporting requirements have drawn attention to the need for more accurate data. This uncertainty can be seen in the revisions that have accompanied sector emission estimates. Just recently for example, EPA revised downward the estimated level of methane emissions attributable to production of natural gas. In 2010, it estimated about 58 percent of methane emission in the natural gas system came from production. In 2013, EPA reduced that number to 37 percent. A major reason for this revision was a change in EPA’s assumption about emission leakage rates. Based on EPA’s GHG inventory data, the assumed leakage rate for the overall natural gas system was revised downward from 2.27 percent in 2012 to 1.54 percent in 2013.47 Independent studies have estimated leak rates ranging from 0.71 to 7.9 percent.48, 49, 50 EPA and others are trying to better understand the extent of leakage and where this leakage is occurring.
Given the climate implications of methane, considerable effort is also being focused on reducing leakage and methane emissions overall. According to EPA, methane emissions from U.S. natural gas systems have declined by 10 percent between 1990 and 2011 even with the expansion of natural gas infrastructure.51 This decline is largely the result of voluntary reductions including greater operational efficiency, better leakage detection, and the use of improved materials and technologies that are less prone to leakage.52 In particular, the EPA’s Natural Gas Star Program has worked with the natural gas industry to identify technical and engineering solutions that minimize emissions from infrastructure, including zero-bleed pneumatic controllers, improved valves, corrosion-resistant coatings, dry-seal compressors, and improved leak-detection and leak-repair strategies. The EPA has tracked methane reductions associated with its Natural Gas STAR program (Figure 3) and estimates that voluntary actions undertaken by the natural gas sector reduced emissions by 94.1 billion cubic feet (Bcf) in 2010. Notably, many of the solutions identified by this voluntary program have payback periods of less than three years (depending on the price of natural gas).53 The success of the Natural Gas STAR program further highlights the importance of understanding where emission leakage is occurring because without accurate data, it is difficult to prioritize reduction efforts or make the case for technologies and processes like those highlighted by the program.
Regulations applicable to methane leakage and venting from natural gas operations have been implemented at both the federal and state level. Although air pollution from natural gas production has been regulated in various forms since 1985 (e.g., toxic substances such as benzene and volatile organic compounds that contribute to smog formation), over the past few years, due to the recent increase in natural gas production and the use of new extraction methods (particularly hydraulic fracturing), natural gas operations have come under renewed scrutiny from policy-makers, non-governmental organizations, and the general public. In response to potential environmental and climate impacts from increased natural gas production including deployment of new technologies, new state and national rules are being developed.
Source: Environmental Protection Agency, “Accomplishments,” July 2012. Available at http://www.epa.gov/gasstar/accomplishments/index.html
EPA released new air pollution standards for natural gas operations on August 16, 2012. The New Source Performance Standards and National Emissions Standards for Hazardous Air Pollutants are the first federal regulations to specifically require emission reductions from new or modified hydraulically fractured and refractured natural gas wells. The New Source Performance Standards require facilities to reduce emissions to a certain level that is achievable using the best system of pollution control, taking other factors into consideration, such as cost.54 Under the National Emissions Standards for Hazardous Air Pollutants program, EPA sets technology-based standards for reducing certain hazardous air pollutant emissions using maximum achievable control technology. The regulations target the emission of volatile organic compounds, sulfur dioxide, and air toxics, but have the co-benefit of reducing emissions of methane by 95 percent from well completions and recompletions.55
Among several emission controls, these rules also require the use of “green completions” at natural gas drilling sites, a step already mandated by some jurisdictions and voluntarily undertaken by many companies. In a “green completion,” special equipment separates hydrocarbons from the used hydraulic fracturing fluid, or “flowback,” that comes back up from the well as it is being prepared for production. This step allows for the collection (and sale or use) of methane that may be mixed with the flowback and would otherwise be released to the atmosphere. The final “green completion” standards apply to hydraulically fractured wells that begin construction, reconstruction, or modification after August 23, 2011, estimated to be 11,000 wells per year. The “green completion” requirement will be phased-in over time, with flaring allowed as an alternative compliance mechanism until January 1, 2015.
While the “green completion” regulations are expected to reduce methane emissions from natural gas wells, concern has been expressed that the regulations do not apply to onshore wells that are not hydraulically fractured, existing hydraulically fractured wells until such time as they are refractured, or oil wells, including those that produce associated natural gas.56 However, geologic and market barriers may limit the applicability of this type of rule to other sources of natural gas.
Source: Resources for the Future. “A Review of Shale Gas Regulations by State.” July 2012. Available at: http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx
Numerous states have also implemented regulations that address venting and flaring from natural gas exploration and production. Some states with significant oil and gas development, such as Colorado, North Dakota, Ohio, Pennsylvania, Texas, and Wyoming, already have venting and/or flaring requirements in place. For example, Ohio requires that all methane vented to the atmosphere be flared (with the exception of gas released by a properly functioning relief device and gas released by controlled venting for testing, blowing down, and cleaning out wells). North Dakota allows gas produced with crude oil from an oil well to be flared during a one-year period from the date of first production from the well. After that time period, the well must be capped or connected to a natural gas gathering line.57 These regulations may be changed or upgraded as the national “green completion” rules come into effect. Maps produced by Resources for the Future, show the diversity of state regulations that apply to venting and flaring in natural gas development in 31 states (Figures 4 and 5).
Source: Resources for the Future. “A Review of Shale Gas Regulations by State.” July 2012. Available at: http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx
The climate implications associated with the production and use of natural gas differ from other fossil fuels (coal and oil). Natural gas combustion yields considerably lower emissions of greenhouse gases and other air pollutants; however, when methane is released directly into the atmosphere without being burned—through accidental leakage or intentional venting—it is about 21 times more powerful as a heat trapping greenhouse gas than CO2 when considered on a 100-year time scale. As a result, considerable effort is underway to accurately measure methane emission and leakage. Policy-makers should continue to engage all stakeholders in a fact-based discussion regarding the quantity and quality of available emissions data and what steps can be taken to improve these data and accurately reflect the carbon footprint of all segments of the natural gas industry. To that end, additional field testing should be performed to gather up-to-date, accurate data on methane emissions. Policy-makers have begun to create regulations that address methane releases, but a better understanding and more accurate measurement of the emissions from natural gas production and use could potentially identify additional cost-effective opportunities for emissions reductions along the entire natural gas value chain.
By Doug Vine, C2ES
The U.S. power industry produces electricity from a variety of fuel sources (Figures 1 and 2). In 2012, coal-fueled generation provided a little more than 39 percent of all electricity, down from 50 percent in 2005. Nuclear power provided around 19 percent of net generation. Filling the gap left by the declining use of coal, natural gas now provides nearly 29 percent of all electricity and renewables, including wind and large hydroelectric power, provide about 12 percent. Petroleum-fueled generation is in decline, providing less than 1 percent of electricity in 2012.
Natural gas use in the power sector during the 1970s and 1980s was fairly consistent and low, contributing a declining share of total electricity generation as coal and nuclear power’s share of total electricity significantly increased. In 1978, in response to supply shortages (the result of government price controls), Congress enacted the Power Plant and Industrial Fuel Use Act.58 The law prohibited the use of oil and natural gas in new industrial boilers and new power plants, with the goal of preserving the (thought to be) scarce supplies for residential customers.59 As a consequence, the demand for natural gas declined during the 1980s, contributing to an oversupply of gas for much of the decade. The falling natural gas demand and prices spurred the repeal in 1987 of sections of the Fuel Use Act that restricted the use of natural gas by industrial users and electric utilities.60 (For an overview of key policies impacting natural gas supply, see Appendix A). Continued low natural gas prices in the 1990s stimulated the rapid construction of gas-fired power plants.61 In the early 2000s, the building boom in natural gas-fired generation was tempered somewhat by price spikes, although natural gas-fired generating capacity continues to be added more than any other fuel type. Since 1990, electricity generation from natural gas has increased from around 11 percent to 29 percent of the total net generation in 2012 (Figure 1). In 2006, natural gas surpassed nuclear power’s share of the total generation mix, and in April 2012, natural gas and coal each contributed a little more than 32 percent of total generation.
Source: Energy Information Administration, “Electricity Net Generation: Total (All Sectors). Table 7.2a,” March 2013. Available at: http://www.eia.gov/totalenergy/data/monthly/#electricity
This chapter explores the combination of factors driving change in the power sector. It examines the advantages and disadvantages of natural gas use, the competitive nature of alternative energy sources, and the synergy between natural gas and renewable energy generation. Finally, it explores relevant policy options that could lower greenhouse gas emissions in the sector.
Source: Energy Information Administration, “March 2013 Monthly Energy Review. Table 7.2b. Electricity Net Generation: Electric Power Sector,” Available at: http://www.eia.gov/totalenergy/data/monthly/#electricity
From the perspective of an electrical system operator, a power plant owner, or an environmental perspective, natural gas-fueled power generation has many advantages. Natural gas can provide baseload, intermediate, and peaking electric power, and can thus meet all types of electrical demand. It is an inexpensive, reliable, dispatchable source of power that is capable of supplying firm backup to intermittent sources such as wind and solar.62 Natural gas power plants can be constructed relatively quickly, in as little as 20 months.63 Air emissions are significantly less than those associated with coal generation, and compared to other forms of electric generation, natural gas plants have a small footprint on the landscape. However, even though combustion of natural gas produces lower greenhouse gas emissions than combustion of coal or oil, natural gas does emit a significant amount of carbon dioxide (CO2), and its direct release into the atmosphere, as discussed in chapter 3, adds quantities of a greenhouse gas many times more potent than CO2. Finally, natural gas-fired power plants must be sited near existing natural gas pipelines, or else building new infrastructure may significantly increase their cost.
Natural gas-fired combined-cycle electricity generation (see Appendix B for a list of power plant technologies) is projected to be the least expensive generation technology in the near and mid-term, taking into account a range of costs over an assumed time period. These costs include capital costs, fuel costs, fixed and variable operation/maintenance costs, financing costs, and an assumed utilization rate for the type of generation plant (Figure 3). The availability of various incentives including state or federal tax credits can also impact the cost of an electricity generation plant, but the range of values shown in Figure 3 do not incorporate any such incentives. Based purely on these market forces, utilities looking at their bottom lines and public utility commissions looking for low-cost investment decisions will favor the construction of natural gas-fired technologies in the coming years.
For each unit of energy produced, a megawatt-hour (MWh) of natural gas-fired generation contributes around half the amount of CO2 emissions as coal-fired generation and about 68 percent of the amount of CO2 emissions from oil-fired generation (Table 1).
Source: Energy Information Administration, “Annual Energy Outlook 2013,” April 15, 2013. Available at: http://www.eia.gov/forecasts/aeo/MT_electric.cfm#cap_addition
Note: Price in 2011 cents per kilowatt-hour.
GENERATION FUEL TYPE
Source: Environmental Protection Agency, “Clean Energy—Air Emissions,” 2012. Available at: http://www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html
While combustion of natural gas produces lower greenhouse gas emissions than combustion of coal or oil, natural gas does emit a significant amount of carbon dioxide (CO2). In 2011, the power sector contributed about 33 percent of all U.S. CO2 emissions.64 Since 2005, total greenhouse gas emissions from the electricity sector have decreased, even as net electricity generation has remained steady, a result of natural gas-fired electricity generation displacing petroleum- and coal-fired generation and an increase in the use of renewable generation. In 2012, CO2 emissions from power generation were at their lowest level since 1993 (Figure 4).
There is strong evidence that the trends toward more natural gas in the power sector will continue in the near and medium term. With natural gas prices expected to stay relatively low and stable and the increasing likelihood of a carbon-constrained future, natural gas has become the fuel of choice for electricity generation by utilities in the United States.65, 66 In 2012, the electric power industry planned to bring 25.5 gigawatts (GW) of new capacity on line, with 30 percent being natural gas-fired (and the remainder being 56 percent renewable energy and 14 percent coal.67 Between 2012 and 2040, the U.S. electricity system will need 340 GW of new generating capacity (including combined heat and power additions), given rising demand for electricity and the planned retirement of some existing capacity.68 Natural gas-fired plants will account for 63 percent of cumulative capacity additions between 2012 and 2040 in the Energy Information Administration (EIA) Annual Energy Outlook 2013 reference case, compared with 31 percent for renewables, 3 percent for coal, and 3 percent for nuclear (Figure 5).
Source: Energy Information Administration, “Monthly Energy Review,” Table 12.6, March 27, 2013. Available at: http://www.eia.gov/forecasts/archive/aeo11/index.cfm
Source: Energy Information Administration, “Annual Energy Outlook 2013,” April 15, 2013. Available at: http://www.eia.gov/forecasts/aeo/MT_electric.cfm#cap_addition
Federal tax incentives and state programs will contribute substantially to renewables’ competitiveness in the near term.69 For example, with the wind production tax credit, wind generation is expected to increase more than 18 GW from 2010 to 2015. Similarly with the solar investment tax credit, utility and end-use solar capacity additions are forecast to increase by 7.5 GW through 2016.70 In addition to federal incentives, state energy programs mandate increased renewable energy capacity additions in thirty-eight states. These states have set standards specifying that electric utilities deliver a certain amount of electricity from renewable or alternative energy sources. Increasing the deployment of zero-carbon energy technologies such as renewables, nuclear, and carbon capture and storage needs to be a priority in order for the United States (and the rest of the world) to address climate change.
Since 1990 the share of generation from natural gas has increased from around 11 percent to 29 percent of the total net generation in 2012 (Figure 1), substantially increasing the diversity of the fuel mix. Natural gas-fired generation is expected to constitute just over 27 percent of the total generation mix in 2020, rising to 30 percent in 2035.71 Fuel diversity is an important consideration for utilities looking to reduce their reliance on any particular energy source, as too much reliance on any one fuel can expose utilities or other power generation owners to the risks associated with price volatility. From a national perspective, fuel diversity is projected by EIA to remain about the same through 2040 with no single fuel being dominant.72 Two things could change this outlook, however. One is a scaling back or reversal of the state and federal policies supporting zero-carbon generation, such as state renewable portfolio standards and federal tax incentives.73 The other is a change in the outlook for the U.S. nuclear generation fleet. Competitive pressures from low natural gas prices have already caused one small, older (1974) plant—the 586 MW Kewaunee plant in Wisconsin—to announce its closure (even though its operating license does not expire until 2033).74 Should more nuclear generation follow suit, these would likely be replaced by natural gas-fired generation. Given that 19 percent of U.S. electricity comes from nuclear power, there is concern that replacing these with natural gas and decreasing the emphasis on renewable energy deployment would push the U.S. power sector into a situation where fuel diversity is significantly reduced.
Beyond the increased use of lower-emitting fuels in the traditional, centralized power-generation system, certain fundamental changes in where and how electricity is generated have the potential to dramatically reduce greenhouse emissions from the sector. These opportunities and challenges are detailed below and are crucial if long-term emission reductions are to be made.
Generating electricity at or near the site where it is used is known as distributed generation. A common example is solar panels on the rooftops of homes and businesses, but natural gas is also used in conjunction with distributed generation technologies. For example, natural gas combined heat and power (CHP) systems in industrial, commercial, and residential settings are becoming a more commonplace type of distributed generation.
Traditionally, the power sector functions with centrally located power stations generating large quantities of electricity, which is transported to end users via electrical transmission and distribution lines. With distributed generation systems (also referred to as on-site generation or self-generation, and described in more detail in chapter 7), smaller quantities of electricity are generated at or near the location where it will be consumed, obviating the need for long electrical transmission lines. Additionally, natural gas CHP systems (discussed in more detail in chapter 6) are able to use waste heat from electricity production for practical purposes. Switching from a primarily centrally generated power generation system to a more efficient distributed system that captures waste heat avoids electrical transmission losses, requires less electricity to be generated, and uses less fossil fuel in aggregate, and therefore lowers greenhouse gas emissions.
For a host of practical and economic reasons, centralized power generation will not be going away in the near or medium term. Basically, there are three categories of natural gas-fueled central power station: steam turbines, combustion turbines, and combined-cycle power plants (Appendix B). Each of these plant types has an average thermal efficiency. Thermal efficiency measures how well a technology converts the fuel energy input (heat) into electrical energy output (power). A higher thermal efficiency, other things being equal, indicates that less fuel is required to generate the same amount of electricity, resulting in fewer emissions. Steam turbines have the lowest efficiency at around 33 to 35 percent. Combustion turbines are around 35 to 40 percent efficient, and combined-cycle plants have thermal efficiencies in the range of 50 to 60 percent.
More efficient designs should be considered as new natural gas-fired capacity is added to the power sector. The Electric Power Research Institute (EPRI) asserts that it is technologically and economically feasible to improve the thermal efficiencies of steam turbine technology by 3 percent, increase combustion turbines to 45 percent efficient, and construct combined-cycle plants with 70 percent efficiency by 2030.75 Higher thermal efficiencies translate into less fuel required to generate the same amount of electricity. EPRI’s 2009 analysis estimates a potential CO2 emissions reduction in 2030 of 3.7 percent from the power sector as a result of increasing the efficiency of new and existing fossil fuel-fired generation.76
In a carbon-constrained future, and with natural gas potentially playing a greater role in the future of the total generation mix natural gas plants with carbon capture and storage capability will need to be deployed to ensure greenhouse gas emissions are reduced over the long term. Carbon capture and storage projects have already been initiated, and several projects are planned in the next several years to demonstrate the feasibility of the technology, such as the Texas Clean Energy Project and the Kemper County integrated-gasification, combined-cycle (IGCC) project.77 To date, these projects have been undertaken almost exclusively in conjunction with coal-fired power plants or industrial sources.78 However, one international project in Norway, set to begin in 2012, endeavors to capture CO2 from a natural gas CHP plant (similar to a combined-cycle plant) and sequester the CO2 in an underground saline formation.79
In addition to sequestering CO2 in saline formations, CO2 is currently being injected into oil wells as part of tertiary, or enhanced, oil production (CO2-EOR).80 This storage option has the added benefit of providing an economic incentive, that is, compensation from the oil-field operator to the captured-CO2 provider. In 2011, the National Enhanced Oil Recovery Initiative (NEORI) was formed to help realize CO2-EOR’s full potential as a national energy security, economic, and environmental strategy. In addition, NEORI suggests federal- and state-level action to support CO2-EOR.81
For power plant operators, the economics of switching from coal to natural gas ultimately depend on underlying fuel prices, which in turn depend on individual location, operational and reliability requirements, and environmental regulations. In mid-2011, natural gas prices fell below coal prices on a dollar-per-energy-output basis. As the gap between the two fuels widened, the share of natural gas-fired power generation increased. However, by July 2012, natural gas prices had rebounded above $3.10 per thousand cubic feet, the cost point for coal at the time. Accordingly, coal-fired generation increased relative to natural gas-fired generation.82 Future fuel substitution will depend on the variable prices of both coal and natural gas.
Competitive electric power markets, in some form, exist in 43 states. In competitive power markets, electricity is bid into the market based on production costs. Typically, fuel cost is the main driver of production cost, but fuel costs can vary depending on a plant’s location. Other factors such as plant efficiency will also affect production cost, with newer more efficient plants able to bid into the market at lower prices than older plants. Renewable technologies such as hydro and wind have the lowest production costs (Figure 6), and can be bid into a market at near zero dollars. Next in the merit or price order is nuclear power, followed by lignite, a cheaper, softer coal with a high moisture content. Hard coal plants and natural gas combined-cycle plants are in the middle of the supply curve or bid stack. Finally, natural gas combustion turbine plants and oil and diesel plants are the most expensive plants to run and are basically only used during times of peak demand. Electricity system operators employ a least-cost dispatch methodology. The point at which the quantity of electricity demanded at any point in time crosses the price-ordered supply curve is known as the marginal generator, and this sets the market price. Coal- or natural gas-fired plants are the marginal generator in most competitive power markets. Even though other suppliers such as wind and nuclear have bid into the market at a price lower than the marginal generator, all units receive the marginal or market price for that time period.
Lower natural gas prices and greater quantities of low variable cost renewables are contributing to lower prices in competitive electricity markets. Current and forecast low natural gas prices were cited as one of the reasons behind the recently announced decision to shut down a 556 megawatt (MW) Wisconsin-based nuclear power station.83 Additionally, there is evidence to suggest that lower natural gas prices suppress the development of renewables.84 In this situation, government policies are undoubtedly necessary to ensure that zero-carbon generation sources are a growing, rather than declining, share of the U.S. energy mix.
There is a complicated relationship between natural gas and renewables in the power sector, stemming from two aspects: 1) competition in the dispatch order between natural gas and renewables, and 2) the potential to produce renewable forms of natural gas.
For the most part, the relationship between natural gas and renewables is interpreted as competition in the power sector, by which renewables are seen as a threat to natural gas because they push natural gas-fired power plants off the bid stack. This phenomenon occurs because the power markets take bids on marginal costs rather than all-in costs. Because the marginal cost of wind is zero, it bids zero (or negative in some cases, reflecting the effect of production tax credits for wind power). Consequently, it is a price-taker in the markets, and it displaces the highest bidders, which are the price-setters. Historically, those price-setters are natural gas power plants, and so wind power displaces natural gas. Consequently, the relationship between gas and wind is one of rivalry. Natural gas interests audibly complain about this rivalry, with the criticism that policy supports for wind give it an unfair advantage in this competition. Renewable energy supporters counter that natural gas interests are not required to pay for their pollution (which is a form of indirect subsidy) and have enjoyed government largesse in one form or another for many decades.
Despite the perception that wind and natural gas are vicious competitors in a zero-sum game where the success of one must come at the demise of the other, the relationship is actually more nuanced. In fact, wind and gas benefit from each other because they both mitigate each other’s worst problems. For wind, intermittency is a problem, and for natural gas, price volatility has been a problem historically. It turns out that the ability for natural gas power plants to serve as rapid response firming power is an effective hedge against wind’s intermittency. And, it turns out the fixed fuel price (at zero) of wind farms is an effective hedge against natural price volatility. Thus, they are complementary partners in the power markets.
Almost all natural gas used today comes from geologic reserves formed many millions of years ago. Therefore, many people seeking a long-term sustainable energy option reject natural gas automatically because it is widely considered a fossil fuel that has a finite resource base. It is important to note that there are also renewable forms of natural gas, known as biogas or biomethane. This form of gas is mostly methane (CH2) with a balance of CO2, and is created from the anaerobic decomposition of organic matter. While renewable natural gas is a small fraction of the overall gas supply, it is not negligible. For example, landfill gas is already an important contributor to local fuel supplies at the local scale. And, recent studies have noted that the total potential supply available from wastewater treatment plants and anaerobic digestion of livestock waste is over 1 quadrillion British thermal units annually in the United States, which is more than 10 percent of the amount of renewable energy consumed in the United States in 2011.85, 86, 87
Source: Adapted from Rawls, Patricia, U.S. Department of Energy: National Energy Technology Laboratory, “The PJM Region: A GEMSET Characterization for DOE.” December 13, 2002. Available at http://www.netl.doe.gov/energy-analyses/pubs/200220DecPJMregionHandout.pdf
Significant policy decisions affecting the U.S. power sector today include regulations to address the interstate air pollution transport, the National Emissions Standards for Hazardous Air Pollutants, and the proposed New Source Performance Standards issued by the U.S. Environmental Protection Agency (EPA). For electricity generation plants to comply with the Cross State Air Pollution Rule and National Emissions Standards for Hazardous Air Pollutants, they will need to install pollution control technologies, a requirement that will affect coal-fired plants in particular.88 PJM, the operator of the world’s largest wholesale electricity market, located in the eastern United States, predicts that approximately 14 GW of coal-fired generation (out of an installed capacity of 78.6 GW of coal-fired generation) could be retired by 2015, largely due to these rules.89 Questions have been raised about the implications of these retirements on the electricity system’s capacity and ability to meet demand and specifically reserve margins. Reserve margins are the spare capacity that electricity system or market operators are required to maintain above the projected peak loads in order to ensure system reliability. While reserve margins appear sufficient in the short run, new, reliable baseload generation will be required in the next 10 to 20 years to fill the gap.
In late March 2012, EPA proposed CO2 pollution standards for new electric power plants as part of its New Source Performance Standards program. The proposed standard is 1,000 pounds of CO2 per megawatt-hour, and under this new standard all new power plants would need to match the CO2 emissions performance currently achieved by highly efficient natural gas combined-cycle power plants. While new efficient natural gas, nuclear, or renewable energy plants would meet this standard easily, new coal-fired power plants could meet the standard only by capturing and permanently sequestering their greenhouse gas emissions using carbon capture and storage technologies. If adopted, this standard would favor new natural gas-fired generation over coal in the future.90
In the past few years, there has also been some interest in a federal-level renewable portfolio standard and, more recently, in a broader federal clean energy standard. Whereas a renewable portfolio standard typically credits only 100 percent-renewable generation such as wind, solar, geothermal, or new hydro power, a clean energy standard would create a mechanism to credit “cleaner” electricity generation as well, that is, generation that emits some CO2 although less than a reference power plant technology such as a generic coal power plant. Under a clean energy standard proposal, credits would be available to new and incremental (upgrades and improvements to) natural gas-fired generation, natural gas with carbon capture and storage, and other relatively cleaner forms of electricity production.91 Indiana and West Virginia have alternative energy portfolio standards, similar to a renewable portfolio standard; however, these standards allow natural gas-fueled generation to be a part of their clean energy goals. In this way, some policy-makers have recognized that there are significant emissions benefits to natural gas use.
There is a need, however, to continue moving the power generation sector to even cleaner generation (zero-emission sources), to reduce CO2 emissions to levels that will stave off the worst effects of climate change.
A price on carbon is a highly effective policy that can provide an incentive for zero-emission sources but it is not the only option. Tax credits for renewable generation, carbon capture and storage, nuclear loan guarantees, and policies that promote energy efficiency are all being used, to some extent, in the United States to acccelerate the deployment of low-carbon energy.
Market forces are driving greater use of natural gas in the power sector, and the inherent qualities of natural gas combustion are leading to lower greenhouse gas emissions. Adoption of distributed generation technologies, more efficient technology, and carbon capture and storage with natural gas have the potential to lower greenhouse gas emissions further. Market forces are joined by policy decisions, enacted and pending, that impact coal-fired generation and will further discourage its use. In addition, some states’ alternative energy portfolios count natural gas-fueled generation toward their medium-term clean energy goals.
Low natural gas prices are having an impact on the diversity of the fuel mix used in electricity generation. In the near term, the diversity of the fuel mix is increasing as fuel-switching from coal to natural gas proceeds; however, in the long term, a sustained low natural gas price may discourage investment in nuclear generation and renewables. Policy is necessary to ensure that the percentage of zero carbon-emission power generation is growing sufficiently to mitigate the most dangerous effects of climate change.
The Natural Gas Act of 1938 establishes federal authority over interstate pipelines, including the authority to set “just and reasonable” rates. It also establishes a process for companies seeking to build and operate interstate pipelines. Oversight of The Act is given to the Federal Power Commission.
Natural gas price controls eventually lead to scarcity and shortage.
In response to supply shortages, Congress enacts the Power Plant and Industrial Fuel Use Act. The law prohibits the use of natural gas in new industrial boilers and new electric power plants. The goal is to preserve “scarce” supplies for residential customers.
The Federal Power Commission is replaced by the Federal Energy Regulatory Commission, which issues Order 436, intended to provide for open access to interstate pipelines that would offer transportation service for gas owned by others.
President Reagan signs into law the repeal of the remaining Fuel Use Act restrictions and incremental pricing, believing that the country’s natural gas resources should be free from regulatory burdens, which some saw as costly and counterproductive.
On April 3rd, trading on natural gas futures begins at the New York Mercantile Exchange.
The Energy Policy Act 2005 is passed, a bill exempting fluids used in the natural gas extraction process of hydraulic fracturing from protections under the Clean Air Act, Clean Water Act, Safe Drinking Water Act, and Comprehensive Environmental Response, Compensation, and Liability Act. The Act exempts companies drilling for natural gas from any requirement to disclose the chemicals involved in fracking operations, normally required under federal clean water laws. The proposed Fracturing Responsibility and Awareness of Chemicals Act would repeal these exemptions.
Tough pollution limits (Cross State Air Pollution Rule) and limits on mercury, sulfur oxides (SOx), and nitrogen oxides (NOx) emissions (National Emissions Standards for Hazardous Air Pollutants) begin to drive older inefficient coal plants out of the market.
A proposed Federal Clean Energy Standard credits natural gas relative to a coal reference power plant.
New Source Performance Standard for CO2 is proposed by EPA.
A common method of generating electricity is with steam turbines (Figure B-1). A power plant uses a combustible fuel—coal, oil, natural gas, wood waste—or nuclear fission to heat water in a boiler, which creates steam. The high-temperature, high-pressure steam is piped toward turbine blades, which move and rotate the attached turbine shaft, spinning a generator, where magnets within wire coils produce electricity.92 Steam units have a relatively low efficiency. Only about 33 to 35 percent of the thermal energy used to generate the steam is converted into electrical energy, and the remaining heat is left to dissipate. Baseload electricity generation commonly relies on large coal- and nuclear-powered steam units on the order of 500 to 1000 MW or greater, as they can supply low-cost electricity nearly continuously.
Combustion turbines are another widespread technology for centralized power generation (Figure B-2). In a combustion turbine, compressed air is ignited by burning fuel (e.g., diesel, natural gas, propane, kerosene, or biogas) in a combustion chamber. The resulting high-temperature, high-velocity gas flow is directed at turbine blades, which spin a turbine driving the air compressor and the electric power generator. Combustion turbine plants are typically operated to meet peak load demand, as they can be switched on relatively quickly. Another advantage is their ability to be a firm backup to intermittent wind and solar power on the grid, if needed. The typical size is 100 to 400 MW, and their thermal efficiency is slightly higher than steam turbines at around 35 to 40 percent.
A basic combined-cycle power plant combines a combustion turbine and a steam turbine in one facility (although there are other possible configurations) (Figure B-3). Combined-cycle plants waste considerably less heat than does either turbine alone. As combustion turbines became more advanced in the 1950s, they began to operate at ever-higher temperatures, which created increasing amounts of exhaust heat.93 In a combined-cycle power plant, this waste heat is captured and used to boil water for a steam turbine generator, thereby creating additional generation capacity from the same amount of fuel. Combined-cycle plants have thermal efficiencies in the range of 50 to 60 percent. Historically, they have been used as intermediate power plants, supporting higher daytime loads; however, newer plants are providing baseload support. Cutting edge natural gas combined-cycle power plants are coming online with thermal efficiencies at 61 percent with a correspondingly smaller emission of greenhouse gases; these plants are able to cycle on and off more frequently (than most of the installed power plant fleet) to more efficiently complement intermittent renewable generation.94
By Fred Beach, The University of Texas at Austin
In 2009, the U.S. buildings sector accounted for about 41 percent of primary energy consumption.95 Energy was delivered to more than 113 million residences and 4.8 million commercial and institutional buildings by four primary means: electricity, natural gas, district heat, and fuel oil. In both residential and commercial building sectors, natural gas and electricity have been the dominant fuel sources over the last 30 years. In the residential sector the proportion of electricity used has grown rapidly compared to other energy sources, largely driven by the proliferation of home electronics (Figure 1). In 2003 in the commercial sector, electricity and natural gas accounted for 87 percent of all energy used (Figure 2).96 In 2011, residential and commercial buildings accounted for 34 percent of greenhouse gas emissions in the United States. Among fuels typically used in residential and commercial buildings, electricity usage accounted for 74 percent of carbon dioxide (CO2) emissions from fossil fuel combustion, which accounts for the majority of greenhouse gas emissions from the buildings sector. Natural gas and other fuel combustion accounted for the remaining 26 percent.97
Source: Energy Information Administration, “Residential Energy Consumption Survey 2005, Table US3,” 2005. Available at: http://www.eia.gov/consumption/residential/data/2005/c&e/summary/pdf/tableus3.pdf
The fuel mix in the buildings sector heavily influences its greenhouse gas emissions. Natural gas consumed on site has relatively low emissions compared with the average emissions associated with liquefied petroleum gas (propane), fuel oil, or electricity. Electricity in particular typically has emissions far above those of natural gas. In 2011, more than 40 percent of U.S. electricity production came from coal-fired power plants, which create more CO2 per unit of energy delivered than natural gas, propane, and fuel oil used on site.98 Coal-fired electricity also produces sulfur dioxide (SO2), nitrogen oxides (NOX), and mercury, which are associated with environmental damage and harmful health effects.
Source: Energy Information Administration, “Overview of Commercial Buildings, 2003,” 2003. Available at: http://www.eia.gov/emeu/cbecs/cbecs2003/overview1.html
Because of the significant amounts of primary energy and greenhouse gas emissions associated with electricity generation and consumption, and the relatively higher greenhouse gas emissions footprint associated with fuel oil, switching from inefficient electricity or fuel oil to high-efficiency natural gas in buildings can yield significant emission reductions. This chapter provides an overview of energy consumption in residential and commercial buildings, which is driven by climate zone, business needs and activities, building size, and, in large part, consumer behavior. It explains why consideration of primary and “source-to-site” energy, a measure of energy consumption that occurs prior to consumer energy use on site, contributes to a more complete picture of energy consumed and emissions emitted. Accordingly, this chapter makes use of the concept of full-fuel-cycle efficiency, which is the appropriate energy and efficiency metric with which to compare consumer fuel choices and consequences for greenhouse gas emissions. It demonstrates how using natural gas appliances could lead to dramatic reductions in fuel consumption and greenhouse gas emissions. Finally, the chapter looks at how policy support, including efficiency programs, consumer information, and innovative funding models, can help to overcome the barriers to increased natural gas access and utilization in the buildings sector.
There are strong regional variations in the types of energy available to and used in buildings. A significant factor affecting energy use is where a building is located. Homes in colder climates tend to consume more energy, driven by heating (often called thermal) requirements. Nationally, 61 percent of residential energy is used for space heating and water heating (41 percent and 20 percent, respectively), while air conditioning (space cooling) consumes only 8 percent. Overall, thermal uses are dominant in all regions of the country (Figure 3). In the commercial sector as well, the dominant energy uses are thermal loads (space and water heating), followed by lighting (Figure 4).
Energy use among U.S. commercial buildings is quite diverse. Among commercial buildings, significant variation exists in the purpose and size of buildings, energy use, and emission profiles. Office space is the largest energy consumer, consuming 719 trillion Btu of electricity on site. Educational facilities are the second largest commercial consumer, using 371 trillion Btu of electricity on site. These two types of commercial buildings account for 36 percent of all the electricity used in buildings. Because they rely on relatively inefficient grid-delivered electricity rather than on-site generation (see below), they also have the highest emissions profiles.99
Commercial buildings vary in terms of energy intensity, measured in Btu consumption per square foot. The three most energy-intensive building sectors are food service, food sales, and health care, which use 258, 200 and 188 Btu per square foot per year, respectively.100 While 84 percent of food service square footage is served by natural gas, only 60 percent of food sales square footage uses this fuel. The food service sector requires a large amount of thermal energy for cooking and cleaning, while energy use for food sales is predominantly for refrigeration. Thermal demands for in-patient healthcare are also heavy, with large amounts of food preparation, water heating, and cleaning. With these demands, 95 percent of building stock used for in-patient health care is served by natural gas, while only 59 percent of outpatient health care facilities use natural gas where are there are lower thermal loads.101
Building size also plays an important role in energy consumption and fuel source. Commercial buildings of more than 100,000 square feet account for only 2 percent of the total number of buildings, but they account for more than 34 percent of total floor space and more than 40 percent of total energy use (Figure 5). Clearly, this segment exhibits a higher concentration of high energy consumption, while being less fragmented in ownership than smaller buildings. Among large buildings of over 100,000 square feet, 77 percent use natural gas for space heating.102, 103 The predominance of natural gas for heating in the largest of buildings, food service, and in-patient hospitals can be directly attributed to the greater overall efficiency and lower cost of natural gas over electricity for thermal applications such as space heating, water heating, and cooking.
Source: Energy Information Administration, “Annual Energy Review 2009,” Table US12. Available at http://www.eia.gov/consumption/residential/data/2009/#consumption-expenditures
The types of activities carried out in commercial buildings also influence the type of energy used. Office buildings tend to utilize electricity rather than natural gas because many of their primary loads, such as lighting, elevators, personal computers, servers, scanners, and printers, cannot be served by natural gas. Lodging, health care, and food service, in contrast, can more easily use natural gas for cooking, hot water, cleaning, and laundry, and, consequently, they use proportionally more natural gas than office buildings.
Local climate plays a large role in determining what type of energy is used, and how. The majority of commercial (and residential) buildings are located in colder climate zones (zones 1 to 4), which encompass much of the country except for the Deep South and the Southwest. In colder zones, winters are cold enough for frequent, substantial space heating, and the average amount of energy needed to heat a building during the winter, measured in heating degree days, is two to four times the average amount of energy needed to cool a building during the summer (measured in cooling degree days) (Figure 6). Still, space and water heating account for the greatest energy use in buildings regardless of climate zone (Figures 3 and 4).
Source: Energy Information Administration, Commercial Buildings Energy Consumption Survey 2009, “Building Characteristics,” Table E1a. Available at: http://www.eia.gov/emeu/cbecs/cbecs2003/detailed_tables_2003/detailed_tables_2003.html#consumexpen03
The prevalence of natural gas access and use in homes varies across U.S. climate zones, even though natural gas is a more efficient fuel choice for thermal loads. Natural gas appliances tend to be underrepresented in use, even when there is access to the fuel. In the two coldest regions in the country, natural gas is the preferred fuel for heating water in 23.7 million homes, while electricity is used in 10.8 million homes. The numbers suggest that nearly all of the homes using gas for space heating are also using it for water heating.104 Nationwide, the story is different. Forty percent of households with natural gas access used electric appliances for space heating, water heating, or both in 2009, and that number has increased in recent years, with a four-million-household increase in residences with natural gas access using electric space heating.105
In warmer climates, natural gas use is less common than electricity for space heating—12.3 million residences use natural gas compared with 16.5 million using electricity.106 However, natural gas and electricity are equally popular for water heating with an even split at 16 million homes each.107 In these areas, more than 3 million homes had access to natural gas (as indicated by water heating usage) but did not use it for space heating.
Source: Energy Information Administration, “Natural Gas Consumption and Conditional Energy Intensity by Building Size for All Buildings, 2003” Table C31. Available at: http://www.eia.gov/consumption/commercial/data/archive/cbecs/cbecs2003/detailed_tables_2003/2003set16/2003html/c31a.html
Appliances, such as clothes dryers, ovens, and cooktops, are available in either electric, natural gas, propane, or fuel oil models, with electric and natural gas models being the most common by far (Figure 7). Nationwide, electric dryers outnumber gas models 4 to 1 (71.8 million compared to 17.5 million). For cooking appliances, whether ovens or cooktops, the ratio is almost 2 to 1 (68.1 million homes use electricity and 38.4 million use natural gas).108 In theory, the use of these appliances should be independent of climate zone variations since they operate within the heated and cooled space of homes. Yet, natural gas appliances are significantly underrepresented in all climate zones.109
In the two coldest regions, zones 1 and 2, natural gas is the dominant space heating fuel, heating 24.8 million homes in 2005. In contrast, only 5.6 million homes used electric space heating in the same year (Figure 4).110 Nationally, natural gas is also the chief fuel source for heating in commercial buildings. In 2003 in colder climate zones, it provided heat for 69 to 75 percent of all commercial floor space, but only 47 percent in zone 5, the warmest region.111
Building energy consumption can be measured in terms of fuel use on site: kilowatts of electricity, cubic feet of gas, and gallons of propane or fuel oil. This site energy is the total of all energy consumed at a building as measured by the electric and natural gas meters as it enters the building and/or by fuel oil or propane delivery. However, site energy does not tell the full energy story, because energy, whatever the source, must be extracted and delivered to the point of use, incurring losses along the way that are not reflected in the readings on customers’ meters or delivery bills. As discussed in chapter 4, fossil fuels, such as coal or natural gas, are most often used to generate electricity. The term “source-to-site” generally refers to the total energy consumed in the course of extracting, processing, and delivering a unit of energy to a building, and in the case of electricity, energy associated with generation, transmission, and distribution. In other words, source-to-site efficiency is the energy required—accounting for losses—to bring usable energy to the consumer. Source-to-site efficiency varies widely by fuel. Often, direct fuel consumption has much higher source-to-site efficiencies compared with electricity, where energy is lost in the conversion and transmission of primary fuels to electrical energy. To assess the efficiency of total energy use, the source-to-site efficiency must be multiplied by the efficiency of the end-use appliances and equipment—the site efficiency. Combining source-to-site efficiency and site efficiency leads to the third—important and often overlooked—measure of efficiency, full-fuel-cycle efficiency.
Source: Energy Information Administration, “U.S. Climate Zones,” 2004. Available at http://www.eia.gov/emeu/recs/climate_zone.html
Electricity generation has the lowest source-to-site efficiency of all energy types. Centralized electricity generation and distribution through power lines is on average 32 percent efficient in the United States. The process of generating electricity incurs substantial losses, such that for every unit of electricity registered at a building’s meter, three times the amount of primary energy was required to generate and distribute it. The majority of energy losses occur at the power plant, especially at cooling towers that emit waste heat into the atmosphere in the form of steam. The Western Electricity Coordinating Council, which covers the western United States, has the highest efficiency, at 38 percent, primarily due to its high percentage of hydropower, which has a higher conversion efficiency than coal- or natural gas-fired generation. The Midwest Reliability Council region in the Upper Midwest has the lowest efficiency, at 28 percent, due to a large percentage of coal plants using older, less efficient technology.112 Transmission and distribution over power lines results in additional losses and reduces the source-to-site efficiency even further, by roughly an additional 7 percent, with longer lines experiencing greater losses. In total, up to two-thirds of the fuel that is burned for electricity production is wasted. In addition to providing no useful work in the economy, it releases significant greenhouse gas emissions in the process.
Source: Energy Information Administration, “Residential Energy Consumption Survey 2009,” Table HC3.1, Available at: http://www.eia.gov/consumption/residential/data/2009/
The production and distribution of natural gas, fuel oil, and propane also have inefficiencies. These fuels must be extracted from the ground, processed or refined to remove impurities and other liquids and gases, and finally transported to the building. During each of these steps, energy is used and a small amount of energy is lost but, in total, these losses are considerably less than the losses associated with electricity production and distribution. The source-to-site efficiency of natural gas is approximately 92 percent, around three times higher than the source-to-site efficiency of centrally generated electricity.113 Other fuels commonly consumed onsite in residential buildings, fuel oil and propane, are also much more efficient than electricity. The average source-to-site efficiency of fuel oil is about 88 percent, and of propane, about 89 percent.114
Considering the source-to-site efficiency of different fuels offers a more accurate comparison of the fuel used in buildings. For example, in 2008, the total site consumption by residential and commercial buildings was 9.37 quadrillion Btu for electricity and 8.28 quadrillion Btu for natural gas. However, the amounts of primary energy consumed differed dramatically between electricity and natural gas, because of their different source-to-site efficiencies (compare Figures 8 and 9). About three times as much primary energy is used to generate and transmit electricity than is ultimately consumed onsite in buildings.
The relative efficiencies of on-site fuel use and grid-supplied electricity have major consequences for the greenhouse gas emissions associated with the U.S. building stock. Only accounting for site energy consumption misses energy losses and resulting greenhouse gas emissions associated with energy production and delivery. These losses account for a significant portion of total greenhouse gas emissions from the residential and commercial sector and should be accounted for when comparing fuel options. The use of grid-supplied electricity is growing, while direct natural gas consumption by residential and commercial buildings remains relatively flat. Increasing the amount of natural gas instead of electricity used in buildings would require fewer resources to provide the same amount of on-site energy and would lower the greenhouse gas emissions per unit of useful energy consumed.
Once energy is delivered to a building, it is used in an appliance or piece of equipment that has its own distinct efficiency level. Taken together, the source-to-site efficiency of the fuel delivered and the site efficiency of its use give a more complete picture of the total efficiency of consumer fuel and appliance choice and the resulting emissions. Source-to-site efficiency considered along with site efficiency yields an appliance’s full-fuel-cycle efficiency.
To find the full-fuel-cycle efficiency of an appliance or piece of equipment, the efficiency of the source-to-site energy is multiplied by the efficiency of the appliance and associated equipment. For example, energy efficiency standards established in 2012 by the Department of Energy (DOE) for water heaters with storage tanks are 93 percent for electric-resistance units and 62 percent for natural gas models.115 However, when these models’ respective source-to-site efficiency is factored in, their full-fuel-cycle efficiencies are 30 percent for the electric model and 75 percent for the natural gas model. Therefore, despite the higher site efficiency rating of the electric-resistance water heater, it requires the use of significantly more primary energy and leads to the emission of more greenhouse gases than does the natural gas appliance for the same level of output in the building. Consequently, electric-resistance water heaters consume roughly twice the primary energy of the natural gas models.
Source efficiencies and site efficiencies can vary even further. Minimum efficiency standards for appliances promulgated by DOE are continuing to push the site efficiency ratings of new appliances higher. While this discussion compares widely used electric and natural gas water heaters, newer technologies such as electric heat-pump water heaters are also available that are two to three times more efficient than the conventional electric-resistance models analyzed here,116 and solar water heating technologies offer high full-fuel-cycle efficiencies and can be a cost-effective option.117 Furthermore, the source efficiencies and associated greenhouse gas emissions vary, because of the regional differences in source efficiency of power generation. It is clear that, despite geographic variation, a natural gas water heater yields significant energy savings compared with an electric-resistance water heater in every North American Electric Reliability Corporation Region in the country (Figure 10).118
In addition to the energy savings delivered by the higher full-fuel-cycle efficiency of appliances using natural gas, there is also a large difference in greenhouse gas emissions. Residential energy use has been a growing contributor to CO2 emissions for the last two decades, and the trend is expected to continue (Figure 11).119 The negative consequences in terms of emissions of this upward trend in electricity use are exacerbated by the low average efficiency of grid electricity and the high average carbon fuel intensity of the U.S. electricity generation portfolio. Furthermore, given the high level of coal use in U.S. electricity production, increased electricity use leads to significant increases in sulfur dioxide, nitrogen oxides, and mercury emissions, where pollution controls are not in place.
Greenhouse gas emissions can be reduced by switching from lower-efficiency fuels and appliances such as an electric-resistance water heater to higher efficiency fuels and appliances such as a natural gas water heater. However, the reductions will vary by region. The relative percentage reductions of greenhouse gas emissions by switching appliances or fuels is a combination of the full-fuel-cycle efficiency of the appliances and the CO2-emission intensity of the electricity generation portfolio in a given region. The varied carbon intensities of electric generation in each North American Reliability Council (NERC) region offer different relative benefits from switching an electric-resistance water heater to a natural gas model (Figure 12). The relative benefits are most clearly demonstrated in the following examples. In the NERC region overseen by the Northeast Power Coordinating Council in the northeast United States and Eastern Canada, where a large percentage of the electricity comes from less carbon-intensive hydroelectric and nuclear power, switching from an electric to natural gas water heater results in CO2 reductions of 30 percent. By contrast, the same switch results in emissions reductions of 70 percent in the Midwest Reliability Organization region in the Midwest where substantial amounts of older coal-fired power generation contributes to a significantly more carbon-intensive electric generation mix.
Source: Gas Technology Institute, “Source Energy and Emission Factors for Building Energy Consumption” 2009, Tech. rep., Natural Gas Codes and Standards Research Consortium, American Gas Foundation. Available at: http://www.aga.org/SiteCollectionDocuments/KnowledgeCenter/OpsEng/CodesStandards/0008ENERGYEMISSIONFACTORSRESCONSUMPTION.pdf
Source: Gas Technology Institute, “Source Energy and Emission Factors for Building Energy Consumption” 2009, Tech. rep., Natural Gas Codes and Standards Research Consortium, American Gas Foundation. Available at: http://www.aga.org/SiteCollectionDocuments/KnowledgeCenter/OpsEng/CodesStandards/0008ENERGYEMISSIONFACTORSRESCONSUMPTION.pdf
An average U.S. home using natural gas for space heating, water heating, cooking, and clothes drying is responsible for substantially fewer greenhouse gas emissions than homes using other fuel sources (Figure 13). In this example, natural gas use produces an average of 44 percent fewer emissions than electricity use.120 Such a difference in energy use and CO2 emissions is true for all energy uses in buildings where natural gas is an alternative to grid electricity as well as the direct use of propane and fuel oil. The two main factors determining the efficiency and emissions benefits from appliance to appliance are the full-fuel-cycle efficiency of the appliance and the emission-intensity of the primary fuel.
Emissions associated with natural gas use compared with electricity are lower for CO2 and some pollutants. Considering the lower emissions of natural gas and its higher full-fuel-cycle efficiency, residential natural gas use results in 40 to 65 percent lower emissions of CO2, 90 to 98 percent lower emissions of SO2, and 50 to 88 percent lower emissions of NOX. Residential natural gas use is free of any mercury emissions.121
Source: Source: American Gas Association, “A Comparison of Energy Use, Operating Costs, and CO2 Emissions of Home Appliances,” October 20, 2009. Available at: http://www.aga.org/Kc/analyses-and-statistics/studies/demand/Pages/Comparison-Energy-Use-Operating-Costs-Carbon-Dioxide-Emissions-Home-Appliances.aspx
Note: Assumes fuel used for space heating, water heating, cooking, and clothes drying. All appliances are assumed to meet federal minimum efficiency standards. The fuel oil home assumes electricity is used for cooking and clothes drying. The new home assumes a one-story single-family detached home with 2,072 square feet of conditioned space and 4,811 heating degree days.
Natural gas can provide a means to increase a building’s total full-fuel-cycle efficiency and decrease its emissions profile in many cases. This improvement is most readily achieved in thermal applications, such as natural gas space heating and water heating. While buildings with older natural gas- or oil-fired boilers and furnaces can improve their efficiency and lower their emissions by upgrading to newer models, greater emission reductions may be achieved by removing electric appliances and replacing them with models using natural gas. While natural gas appliances have a comparable or slightly lower site efficiency than electric-resistance appliances, natural gas is often, on a full-fuel-cycle basis, two to three times more efficient than electricity.122
Significantly greater benefits can be realized when grid power is replaced by power produced on site. Combined heat and power (CHP) systems provide a means for buildings with high electrical demand to increase their efficiency and reduce emissions. A CHP system uses a fuel such as natural gas to generate electricity on site, capturing waste heat to meet on-site thermal loads (Table 1). (For a more extensive treatment of CHP see chapter 6.) Fuel cells and micro-turbine technologies provide another means for buildings to generate their own electrical power on site using natural gas. The waste heat generated by these devices can then be used for space heating, water heating, and other thermal loads to raise the overall full-fuel-cycle efficiency of these devices to greater than 80 percent.123 (These technologies and others are explained in chapter 7.)
The potential for CHP in commercial settings may be quite large, with office buildings/retail, education buildings, and hospitals having the greatest potential (Figure 14). However, practical limits on thermal load matching and the utilization of waste heat may affect the potential of different building types. Hospitals are an ideal application, but hotels and other commercial buildings may be more difficult—though not impossible. The use of CHP microturbines has gained acceptance primarily in in-patient hospitals, hotels, and resorts. These facilities have large electrical loads and nearly as high thermal loads, for space heating, water heating, cooking, and laundry. These large and year-round thermal loads (in the case of all but space heating) provide a ready use for the waste thermal energy provided by the microturbine, allowing them to operate at near peak efficiency not only around the clock but 365 days per year. Nevertheless, there are many challenges to commercial CHP operations. To expand commercial CHP potential, policy is needed to support advanced technologies and innovative business models in this arena.
10 MW Natural Gas CHP
10 MW Photovoltaic Array
10 MW Wind Farm
Centralized Natural Gas Combined Cycle Power Plant (10 MW Portion)
Annual Capacity Factor
Annual Useful Heat
Annual Energy Savings
Annual CO2 Savings
Source: ICF International 2012
Notes: A 10 MW Gas Turbine CHP –is assumed to have 30 percent electric efficiency and 70 percent total efficiency.
Electricity generation onsite is assumed to displace grid-supplied electricity generation of 9,720 Btu/kWh, with emissions of 1,745 lbs. CO2/MWh; includes assumed 6 percent transmission and distribution losses.
Thermal generation on-site is assumed to displace an 80 percent efficient onsite natural gas boiler.
Source: ICF International 2012
Technological advances in gas-fired equipment are also needed. More affordable tank-less water heaters and combination space and water heating appliances can help reduce the market barriers to natural gas. Demonstration and deployment of such technologies can help natural gas utilities design the next generation of gas efficiency programs, provide whole-building solutions, and make natural gas service more attractive to customers and builders.
Current efficiency programs and federal efficiency codes and standards reduce greenhouse gas emissions from buildings in two important ways: by reducing the overall amount of energy used in buildings and by improving the baseline efficiency of specific appliances, equipment, and building stock. A third strategy could be to encourage the use of certain fuels, taking into account the total energy consumption of an appliance, the fuel used (full-fuel-cycle efficiency), and the associated greenhouse gas emissions. Historically, efficiency programs and standards have not considered full-fuel-cycle efficiency or the emissions reductions that could be achieved comparing across fuel types, although this is beginning to change, as in the case of appliance labeling described later in this chapter.
At the broadest level, increasing the overall efficiency of new and existing buildings reduces the amount of fuel used of any type and is therefore beneficial. Energy efficiency minimizes energy use, and thus lowers greenhouse gas emissions. The United States has made remarkable progress in this regard. Energy use in buildings between 1972 and 2005 increased at less than half the rate of growth of gross domestic product, despite the growth in home size and the increased demand for energy from air conditioning and electronic equipment. But although great strides have been made, numerous untapped opportunities exist for further reductions in energy use and greenhouse gas emissions. Many of these require only modest levels of investment. Advances such as energy-efficient building designs and appliances provide quick payback to consumers through reduced energy bills. For example, new wall designs can minimize heat loss in buildings by as much as 50 percent by reducing the amount of framing used and by optimizing the use of insulated materials. The result is a diminished need for space heating—the largest energy use in a home.124
Building codes for new construction can improve the efficiency of buildings by ensuring that new technologies and methods are used that will reduce a building’s energy use. Although new buildings constitute only 2 to 3 percent of the existing building stock in any given year, new construction practices have a compounding impact over time.125 New construction can more easily incorporate novel energy efficiency technologies and is therefore often a harbinger of future trends. New building technologies are often introduced in the new construction market and then spill over into the arena of retrofits and renovation. Building codes can even affect a building’s fuel options, for example, by encouraging or discouraging natural gas access by facilitating or slowing the approval of new, easier-to-install and less expensive indoor natural gas piping materials.126
Low adoption rates for building codes are a barrier to the development of higher efficiency and lower emissions buildings. For example, in 1992 the commercial building code requirements of the Federal Energy Policy Act, which were based on 1989 industry standards, were met by only five states. By 2008, 40 states had statewide commercial building codes that met or exceeded the 1989 federal standards, but only 27 met the higher standards issued by DOE in 2004. This lead/lag effect in the setting and meeting of standards is indicative of a non-owner-operated building market that still places operating costs at a lower priority than construction costs. However, federal requirements are not the only drivers. California, for example, has set standards higher than those of the federal government, and some utilities, such as Austin Energy in central Texas, have worked with city governments to push standards and building codes beyond the industry norm.
Traditionally, building codes have been designed to look at the overall on-site energy usage of buildings. Accordingly, they are typically fuel-neutral, favoring neither natural gas nor electric appliances. As a result, building codes do little to take into consideration the full-fuel-cycle climate impacts of electricity versus natural gas and other fuels. Likewise, Leadership in Energy and Environmental Design (LEED) standards fail to take into account the relative full-fuel-cycle efficiencies of electricity, natural gas, and other fuels. LEED standards, developed by the U.S. Green Building Council, have been adopted by many municipalities, school districts, counties, and states for their new buildings, leading to an exponential growth in the number of LEED-certified buildings.127 However, the U.S. Green Building Council is investigating ways to take these benefits into account, with particular focus on performance standards and nationwide applicability.
DOE is required by law to set minimum efficiency standards for appliances, and currently has standards that cover appliances and equipment responsible for 82 percent of home energy use and 67 percent of commercial energy use.128 Appliance standards, first instituted in the 1980s and repeatedly strengthened since then, have greatly contributed to reducing appliance energy use and associated greenhouse gas emissions. However, appliance standards are based on the site efficiency of the appliance and do not consider the efficiency of the fuel. While this works well to encourage improved efficiency for each type of appliance, it does have implications for efficiency labeling programs and the ability of consumers to compare the true environmental performance of appliances using differing energy sources.
Labeling programs such as ENERGY STAR strive to inform consumers about the energy consumption and energy cost implications associated with use of each appliance. ENERGY STAR uses a market-based approach having four parts: 1) using the ENERGY STAR label to clearly identify which products, practices, new homes, and buildings are the most energy efficient; 2) empowering decision-makers by making them aware of the benefits of products, homes, and buildings that qualify for ENERGY STAR, and by providing tools to assess energy performance and guidelines for efficiency improvements; 3) helping retail and service companies to easily offer energy-efficient products and services; and 4) partnering with other energy efficiency programs to leverage national resources and maximize impacts. The Environmental Protection Agency (EPA) estimates that in 2012 the ENERGY STAR program helped avoid more than 150 million tons of greenhouse gas emissions through encouraging the purchase of efficient products, with the amount of avoided greenhouse gas emissions increasing annually.129
While appliance labeling efforts like ENERGY STAR have educated consumers about the annual operating costs and site efficiency of appliances, current labels do not accurately or sufficiently connect consumers’ economic interests with the environmental impacts of appliance use. Specifically, current labels do not inform consumers of the full-fuel-cycle efficiency of appliance models because the efficiency calculations are based on the appliance standards program, which again is based on site efficiency. As a result, consumers cannot compare the true quantity of energy required by each appliances or the true climate implications associated with using that appliance.
In 2009, the National Research Council released a report that recommended the gradual conversion of current labeling efforts to ones that would take full-fuel-cycle efficiencies into consideration. Full-fuel-cycle labeling will certainly be more challenging because it will require more data and analysis from appliance manufacturers, and the efficiency of an appliance will vary by geographical location because of different regional climates and power generation fuel mixes. However, as discussed earlier in this chapter, such information is essential to understanding the total amount of energy required to operate an appliance and the associated greenhouse gas emissions and will better equip consumers to make more informed choices when evaluating their appliance options.130 In June 2011, DOE took the first steps toward a more regionalized labeling program with standards for furnaces and central air conditioning units that had a variable regional component.131 In addition, in August 2012, DOE issued a policy amendment stating that it would begin consideration of full-fuel-cycle efficiency in setting future appliance standards and would work with the Federal Trade Commission to educate consumers about the full fuel cycle.132
While no appliance standards based on the full fuel cycle have yet been issued, if the success of current appliance standards and related labeling are any indication, moving to standards and labels based on full-fuel-cycle efficiency could move consumers to purchase appliances that use significantly less energy and provide a significant benefit to the climate.
In addition to having labels for appliances, EPA’s ENERGY STAR program also assesses the efficiency of buildings and provides labels that allow comparison of energy usage across buildings. To be an ENERGY STAR-certified building, a variety of energy performance standards must be met and these differ by facility type. EPA provides tools to assess energy systems and management, building design, and a host of energy-related benchmarks to help building owners, architects, and even prospective tenants assess and make public the energy and cost implications of a building. In contrast to the appliance program, the ENERGY STAR program for commercial buildings does use primary or full-fuel-cycle efficiency to compare energy usage across building types.
Utility-based financial incentive programs have been used since the early 1980s, when it became clear that information and education alone produced only limited energy and demand savings. Utilities have offered rebates, low-interest loans, and direct installation programs, and these have led to the accelerated market penetration of many energy-efficient building products such as attic insulation and high-efficiency appliances. However, these programs represent only a partial solution because not all states or all utilities offer such programs. More importantly, these incentives are based on site efficiency and are fuel-specific—since buildings are often served by separate electric and natural gas utilities, meaning that while incentive programs can encourage the efficient site use of a fuel, they do not allow consumers to compare fuel options based full-fuel-cycle efficiency. Thus, most utility-based incentive programs miss an opportunity to help consumers further reduce emissions.
The emissions benefits of natural gas use in homes and businesses will require greater access to the fuel for and within buildings. In 2005, 71 percent of U.S. homes had access to natural gas, and yet only 61 percent of U.S. homes made use of natural gas in an appliance. In addition, only 54 percent of new homes constructed in 2010 had natural gas service installed, and this access was primarily for heating and not necessarily for other natural gas appliances.133 Similarly, in commercial buildings approximately half had natural gas access in 2003 (49 percent) and, as with homes, the use was primarily for heating.134
Annual consumption of natural gas in the residential sector has been declining since 1996 in spite of a growing residential customer base (Figure 15). Analysis by the Energy Information Administration suggests that the cause of this decrease is a combination of historically high natural gas prices from 2000 to 2009, which discouraged consumers from buying natural gas model appliances, a general migration of Americans to warmer climate zones with lower thermal loads, and an increase in home construction standards and appliance efficiency that reduced the amount of fuel consumed for the same purposes.135
Source: Energy Information Administration, “Trends in U.S. Residential Natural Gas Consumption,” 2010. Available at: http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2010/ngtrendsresidcon/ngtrendsresidcon.pdf
The United States has, as a policy, pursued universal residential access to electricity for decades. Through taxpayer-funded rural electrification programs and customer-funded electric utility grid extension programs, the United States has achieved greater than 99.5 percent residential access to public or private electricity.136 The same policy has not been implemented for natural gas.
When municipalities approve planning and development for new buildings, electric utility access is almost universally required through developer or utility funding, or a combination of the two. In contrast, running natural gas lines in new developments is often viewed as merely an option, and, as such, only 54 percent of new homes have natural gas access. In many cases, the decision is determined by financial analysis conducted by a local gas distribution company, or the combination local electric and gas utility, based on narrow first-cost criteria with little concern for the occupants’ energy efficiency, operating cost, or greenhouse gas emissions. Prospective building owners often have little participation in this decision process. If the decision is made not to supply natural gas, retrofitted access to and within the building is significantly more expensive.
Even when natural gas infrastructure has been included in a new residential development, a homeowner may still be unable to choose how natural gas will be used in her home. Often, during architectural design and construction, the builder decides which appliances will have natural gas lines run to them, thereby “locking in” the decision and limiting consumer choice. In cases where the homeowner enters the process prior to construction, he may be offered a choice of appliance fuel options, but choosing natural gas may come at a cost premium for both the appliance and the cost of running the gas lines. In this choice, one between higher up-front costs of purchasing a home with gas appliances, on the one hand, and a lower long-term cost of operation (subject to gas prices), on the other, the immediacy of a slightly lower purchase price for electric appliances may prevail, even as low natural gas prices may lead to consumer savings in just a few years when compared to electric models.
Natural gas access, regulation, and price play important roles in residential fuel choice. The trend over the last decade, toward a lower percentage of new homes using natural gas, will have a long-term effect. Even though the trend was likely influenced by temporarily high gas prices, it effectively locks out the option for these “all electric” homeowners to benefit economically from what may be several decades of low natural gas prices as well as to benefit environmentally by lowering greenhouse gas emissions.
Moving beyond infrastructure constraints, an essential component shaping residential fuel choice is public education. For nearly a century, industry and government have portrayed electricity as a clean and efficient fuel, and it is—on site at the point of use.137 Perceptions of natural gas are similarly affected by public opinion and government policy that focus on the point of use, which has not received the promotional policy that electricity has. This point-of-use perception is reinforced by the way in which most people interact with electricity and natural gas in their everyday lives: flipping a switch, turning on a burner, and paying a monthly bill. They rarely see or understand the generation side of electricity, the power plant, or the extraction and transportation of natural gas. Generally, the public has little basis for comparisons among fuels on issues of health, the environment, and the economy. Moreover, culture and family history can be important drivers of consumer choice, as individuals may be most comfortable with appliance types that they grew up with. Public education is critical for helping consumers understand the issues of efficiency and emissions and how they relate to common life choices, and to know what questions to ask when purchasing an appliance, renting an apartment, or buying a home.
A significant barrier to the increased use of natural gas is the high percentage of non-owner-occupied commercial buildings, particularly office and warehouse floor space. On a floor-space basis, 49 percent of private commercial buildings are owner-occupied and 51 percent are non-owner-occupied.138 Non-owner-occupied buildings are designed and built by real-estate developers who then rent or lease the space to tenants. The “for lease” building sector is extremely competitive, and rental cost per square footage is a key metric in attracting renters. In addition to paying rent, tenants may also pay utility or maintenance costs that may increase each year because of rising operating expenditures. Energy costs are a meaningful portion of these operating expenditures, but for billing purposes they are often combined with other costs, such as labor, water, and snow removal. Therefore, it can be difficult for tenants to discern specific financial benefits of energy efficiency upgrades, leaving building owners without a financial incentive to make such upgrades. This situation prevents lower operating costs from being reflected in market rental prices, since only exceptionally sophisticated tenants consider long-term gains from efficiency in rental decisions. In new buildings, owners’ focus on achieving low rental costs can drive builders to prioritize construction cost over operating costs. This approach can preclude the installation of high-efficiency and lower-emission systems, including those that use natural gas on site for both electricity generation and heating applications.139
When energy efficiency upgrades are proposed for existing, occupied buildings, building owners may have the opportunity to recover capital outlays according to the terms of the leases. Most leases allow the installation of energy savings equipment or systems with cost recovery through amortization of the improvement over the life of the equipment installed. However, if a tenant does not renew her lease, a newly signed tenant cannot be charged the amortization; therefore, a portion of the cost of the project cannot be recovered. Since rents are based largely on market conditions and not by the operating costs incurred by the building owner, before owners undertake an energy efficiency project, they must evaluate what portion of the tenant base might leave before the project costs are recovered and what enduring benefits might accrue to the owner.140
Some low-cost energy efficiency upgrades can be treated as repair costs and added to the operating expenses within an existing lease. These stand-alone efficiency projects are very often subsidized with incentives from utilities. Projects of this nature usually have relatively short payback periods. The tenants see the benefit of the improvements very quickly, and the owner can justify the expense to the tenant regardless of whether the lease is renewed.141
In 2003, 46 percent of commercial buildings were owner-occupied, meaning they are designed and constructed for the owner’s own use.142 Compared to owners of leased buildings, owner-operators are more inclined to factor in the operating costs of their buildings because they have a long-term interest in the building and are concerned less with competitive rental markets. Therefore, they tend to install more energy-efficient systems and subsystem components as long as these have a payback period of 10 years or less. The government owners of 635,000 public buildings in the United States in 2003 share this focus on long-term operational costs and the advantage of higher efficiency systems; they may also have legal mandates or executive orders to reduce energy use and/or greenhouse gas emissions.143 Owners constructing new buildings or performing retrofits, when faced with longer-term decisions about energy use and costs, will see expanded natural gas use as an attractive option, and large numbers of owner-occupied and government buildings using natural gas instead of electricity could yield significant emission reductions.
This chapter identified the full-fuel-cycle efficiency benefits and lower greenhouse gas emissions of the direct use of natural gas when compared to electricity, particularly for thermal loads. There is significant potential for increased direct use of natural gas in homes and businesses both in terms of increased access to new buildings and additional applications within buildings that already have access. In order for this potential to be fully realized, building standards, appliance standards, and appliance labels must take full-fuel-cycle energy use and associated emissions into account, and greater attention must be given to consumer education, regulatory changes, and increased access.
By Michael Tubman, C2ES
With prospects for cheap, abundant natural gas in the near and medium term virtually certain, demand for natural gas from manufacturing industries is expected to grow. In 2010, natural gas supplied 30 percent of the U.S. manufacturing sector’s direct energy use, for combustion as well as non-combustion uses.144 The U.S. Energy Information Administration forecasts that natural gas use in the industrial sector will increase by 16 percent between 2011 and 2025, from 6.8 to 7.8 trillion cubic feet.145 Recent estimates indicate that $45 billion in new investment has recently occurred in chemical manufacturing alone. Lower natural gas prices are likely to provide a real economic advantage to U.S. manufacturing in the near and medium term.
The entire industrial sector (manufacturing and non-manufacturing industries combined) consumed 32 percent of all natural gas in the United States in 2011. This energy use emitted 401 million metric tons of carbon dioxide (CO2).146 This chapter examines the role of natural gas in the manufacturing sector today as well as its likely expansion, given forecasts of low and stable prices. With a resurgent and changing manufacturing sector comes the opportunity to reduce these emissions. This chapter also looks at promising strategies for reducing emissions include replacing older, less efficient industrial boilers and expanding the use of combined heat and power (CHP) systems.
The manufacturing sector includes diverse industries such as bulk chemicals, oil refining, and the production of steel, aluminum, cement, glass, paper, and food. It does not include the industrial activities of mining, construction, and oil and gas extraction. Natural gas usage within these industries varies significantly. It is used for heating and cooling; for process heat to melt glass, process food, preheat metals, and dry various products; and for on-site electricity generation (fueling boilers and turbines). Natural gas is also used as a feedstock (a material input) to make chemical products, fertilizers, plastics, and other materials.147
Overall, the largest direct use of energy by the manufacturing sector is for process heating, the production of heat directly from fuel sources, electricity, or steam that is used to heat raw material inputs during manufacturing. Natural gas is the dominant fuel used to generate heat, and process heating accounts for 42 percent of the natural gas use in the industrial sector overall (Figure 1). In 2010, process heating using all fuel sources produced 315.4 million metric tons of CO2, which represents 40 percent of the CO2 emissions for the entire manufacturing sector.148
Industrial boilers generating heat and steam are another large consumer of natural gas. Eighty-three percent of boilers run on natural gas, and they consume 22 percent of this fuel used in manufacturing.149 While some are fueled by coal or other fuel, the dominant fuel source is natural gas. Boilers are commonly used for a variety of purposes by chemical manufacturers, food processors, pulp and paper manufacturers, and the petroleum- and coal-derivatives industries (including chemicals, coke, and coal tar) (Figure 2).150
Source: Energy Information Administration, “Manufacturing Energy Consumption Survey,” June 2009, Tables 2.2 and 5.2. Available at http://www.eia.gov/emeu/mecs/mecs2006/2006tables.html
CHP—also known as cogeneration—is a third major use of natural gas in the manufacturing sector.151 Natural gas is used to generate electricity on site, with the waste heat being captured and used for a variety of industrial purposes, greatly increasing the efficiency of the system overall. Additional efficiencies and emission reductions are also achieved through avoided transmission losses.152 In 2010, 14 percent of natural gas used in manufacturing was consumed by CHP and other power systems. Natural gas is the most common fuel used for CHP systems. Nationwide, the added efficiencies of these systems avoid the emission of 35 million metric tons of CO2equivalent annually.153
Feedstock is raw material used as an input in manufacturing for creating value-added products. Natural gas production and its byproducts provide feedstock for the bulk chemicals industry, constituting a non-combustion use of natural gas. Methane—pure natural gas—is the source for hydrogen used in industrial processes, in fuel cells, and in the production of ammonia. Liquids extracted in association with natural gas, including ethane, propane, and butane, are processed and transformed to become other intermediate and final products including adhesives, insulation, paint, plastics, and vinyl.154 Chemical companies are the largest consumers of natural gas-associated liquids, and they commonly use up to two-thirds of their delivered natural gas as feedstock.155
Source: Energy Information Administration, “Manufacturing Energy Consumption Survey,” June 2009, Tables 2.2 and 5.2. Available at http://www.eia.gov/emeu/mecs/mecs2006/2006tables.html
The emissions implications of using natural gas as a feedstock are very different from its other uses because feedstock use transforms hydrocarbon molecules into other products, rather than burning them. When natural gas is used as a feedstock, therefore, very low greenhouse gases emissions are produced. These low-emitting uses are enhancing U.S. competitiveness in the manufacturing sector. Whereas U.S. companies are reliant on low-cost natural gas liquids as a feedstock, European competitors use more expensive, oil-based naphtha.156 In 2010, for example, domestic ethane sold at half the price of imported naphtha in Europe, and, consequently, U.S. chemical manufacturers have reaped a competitive advantage in international markets for intermediate and final goods.157
Increased availability and low prices of natural gas have significant implications for domestic manufacturing. Large manufacturers dependent on natural gas for production are vulnerable to resource availability and price volatility. Accordingly, they have historically been concerned about policies or technologies that may impact these factors. Recently, abundant supply and low prices have led to greater confidence and an increase in domestic manufacturing, creating new jobs and economic value.158 Numerous companies have cited natural gas supply and price in announcing plans to open new facilities in the chemicals, plastics, steel, and other industries in the United States,159 including $41.6 billion worth of industrial investments that are planned between 2012 and 2018. One analysis has noted that the number of firms disclosing the positive impact of new gas resources for facility power generation and feedstock use increased substantially just between 2008 and 2011.160 In 2010, exports of basic chemicals and plastics increased 28 percent from the previous year, yielding a trade surplus of $16.4 billion.161 Continued low natural gas prices could have significant long-term economic benefits. A study by the American Chemistry Council estimates that a 25 percent increase in ethane supplies, for example, could yield a $32.8 billion increase in U.S. chemical production.162
EIA’s Annual Energy Outlook 2013 Early Release of projections to 2040 reflects the expected increase in industrial natural gas demand. Total industrial consumption of natural gas for heat and power is projected to rise by 19 percent between 2010 and 2021 before increasing at a slower rate through 2040 (Figure 3). Efficiency measures are forecasted keep the amount of natural gas used per dollar of output declining over the same period (Figure 4).
Total industrial consumption of feedstock (natural gas liquids) is projected to rise by 23 percent between 2010 and 2023 before declining from peak levels (Figure 5). Feedstock growth will be tempered by long-term changes in the natural gas market, including higher prices and international competition in chemicals manufacturing and future energy efficiency improvements expected to offset increased demand for feedstock while maintaining output levels (Figure 6). The use of CHP is projected to increase by 113 percent over the same period (Figure 7). Increases in the use of on-site electricity generation through CHP systems would partially reduce facilities’ reliance on grid-supplied electricity while providing heat for industrial uses. CHP systems are designed to balance heat production with electric power needs within a facility; electricity can be bought from the grid if needed, or sold to the grid if there is excess on-site production.163
Sources: Energy Information Administration, “Annual Energy Outlook 2013 Early Release,” 2013. Available at: http://www.eia.gov/forecasts/aeo/er/pdf/tbla2.pdf
These changes in the manufacturing sector will have mixed impacts on greenhouse gas emissions. Absolute increases in natural gas used for heat and power operations are likely to increase total emissions coming from the sector. However, improvements in energy efficiency and especially the substantial deployment of CHP operations will allow the manufacturing sector to increase output with relatively smaller increases in the amount of natural gas input.
Even as the manufacturing sector expands, opportunities exist to reduce its emission intensity—the amount of CO2 emitted per unit of output. Replacement of lower-efficiency boilers and greater deployment of CHP systems are ways to reduce emission intensity while using more natural gas.
Improving the efficiency of industrial boilers is one such opportunity to reduce emission intensity. Boilers tend to have a low turnover rate, and older units are typically less efficient than newer ones. The pre-1985 fleet of boilers has an average efficiency of 65 to 70 percent, while new boilers have efficiency rates of 77 to 82 percent, and new, super-high-efficiency units can reach efficiencies of up to 95 percent.164
Analysis performed by the Massachusetts Institute of Technology found that replacing older natural gas boilers with high-efficiency or super-high-efficiency units would decrease CO2 emissions by 4,500 to 9,000 tons or more per year per boiler. The analysis also found a strong economic incentive to make these replacements, highlighting annualized monetary savings of 20 percent (given certain assumptions, including 2010 natural gas prices) with a payback period for the new equipment of 1.8 to 3.6 years.165
While natural gas is the most commonly used fuel source for industrial boilers, 17 percent of boilers use coal or other fuels (Figure 2). Because of the air pollutants released from coal-fired boilers, these boilers are now subject to the U.S. Environmental Protection Agency (EPA) 2012 Maximum Achievable Control Technology standard (also known as the Boiler MACT). This standard requires the largest and highest-emitting boilers at industrial facilities, typically coal-fired boilers, to meet numeric pollution limits for the emission of air toxics, although it does not specifically require reductions in greenhouse gas emissions.166 An analysis was performed to determine the results of replacing the Boiler MACT-affected coal boilers with efficient or super-high-efficiency natural gas boilers (natural gas boilers are not regulated under the new rule because of their already low emissions of the specified air toxics). This analysis found that replacement of coal boilers with natural gas boilers would reduce annual CO2 emissions by 56 to 59 percent, or about 52,000 to 57,000 tons per year per boiler.167
Increasing the use of CHP also has the potential to reduce emissions produced in the manufacturing sector. An Oak Ridge National Laboratory study in 2008 calculated that increasing CHP’s share of total U.S. electricity generation capacity from 9 percent in 2008 to 20 percent by 2030 would lower U.S. CO2 emissions by 600 million metric tons compared with business as usual.168 A study by McKinsey & Company in 2009 estimated that the potential exists for an additional 50.4 gigawatts of CHP capacity by 2020, which would avoid an estimated 100 million metric tons of CO2 emissions per year compared with business as usual. Additionally, this study found that 70 percent of the potential cost-effective CHP capacity was through large-scale industrial cogeneration systems greater than 50 megawatts (MW).169
CHP units at industrial facilities have the added benefit of bolstering system reliability during a period of transition in the electric sector. Recent years have seen a wave of announced coal plant retirements, and power generation from natural gas-fueled CHP units could make up for some of this lost generation—with lower emissions than centralized coal power plants. A study from the American Council for an Energy-Efficient Economy found that natural gas-fueled CHP at industrial facilities could quickly and cost-effectively replace some of the electric power from retiring coal plants. In South Carolina and Kansas, it could replace all of the expected lost capacity, while in industrial, coal-dependent states such as Ohio and North Carolina, it could replace 16 and 56 percent of lost capacity, respectively.170
Figure 8 compares conventional, centralized power generation augmented with a boiler (left side) with a CHP system (right side). Each system is required to provide 30 units of electricity and 45 units of usable heat. However, the power station and boiler together require 154 units of fuel, and the CHP system requires only 100 units of fuel. Therefore, the power station is 49 percent efficient and the CHP unit is 75 percent efficient. At least 7 percent of the electricity delivered from the conventional power station to the industrial facility is lost during transmission. Although most of the losses occur as primary fuel-to-electricity conversion heat losses at the power plant, this heat is unable to be captured for useful purposes. Consequently, a boiler is required on the industrial site to create the necessary heat, which consumes additional fuel. In contrast, the CHP system is able to generate the electricity and heat together with far fewer losses. Since less fuel is required, overall emissions are lower. Some operations also use waste heat in an absorptive chiller to provide cooling services as well. Such operations are referred to as trigeneration or combined cooling, heating, and power. These operations offer even greater efficiencies and opportunities for emissions reductions.
Source: Environmental Protection Agency, “Efficiency Benefits,” 2012. Available at: http://www.epa.gov/chp/basic/efficiency.html
Although CHP systems have dramatically higher efficiencies than grid power combined with simple natural gas combustion, and they result in much lower greenhouse gas emissions, barriers currently limit their application. Electric utilities often cite safety concerns as a barrier to deployment, specifically, perceived risks related to electricity being added to the grid outside of the central power plant. For example, some utilities cite the concern that miscommunication could occur between CHP operators and the utilities in the event of an emergency such as a storm causing downed power lines, which utilities say could lead to dangerous situations in which their line workers are not certain whether lines are energized or not. In addition, utilities may be concerned about risk and liability involved as their employees could be affected by safety and technical decisions of CHP operators, decisions they are concerned could be made independently of utilities.171 Other concerns have to do with CHP systems’ potential need for backup power. Many utilities are concerned about the need to provide backup power to industrial facilities if CHP systems are taken offline or are otherwise unavailable. For utilities, the ability to provide backup power requires capacity; to pay for investments in new or maintenance of existing capacity, utilities often charge CHP operators higher rates than other customers and additional interconnection fees to compensate for these necessary investments.
From the standpoint of industry, technical and economic considerations also may need to be taken into account when considering the installation of a CHP system. Some facilities may face shortages of trained CHP installers and operators. Another challenge is that CHP retrofits can be costly. Installation is easier during new construction or a major redesign of a facility. Lastly, some industrial users may face difficulties finding buyers for excess heat or power not needed for their own use. However, if buyers are found, the project may be not only environmentally sound, but economically viable as well.
Current regulatory and electric utility policies have inhibited the growth of CHP capacity, with its attendant climate benefits, because they prevent the alignment of financial interests between electricity producers and energy consumers. Power sector regulation in many states leads utilities to view CHP as unprofitable.172 This negative view of CHP is often reflected in regulations established by public utility commissions that do not encourage new CHP deployment. However, innovative policy approaches can overcome this conflict between competing goals among utilities and CHP operators. One approach is decoupling, removing or modifying the link between a utility’s volume of sales and its profits. Decoupling makes it profitable for utilities to encourage CHP systems.173 Another potential policy solution is a lost-revenue adjustment policy, which compensates utilities through a charge on customer bills for revenues lost because efficiency measures were effective.174, 175 State incentives can also encourage the use of CHP. State-level policies include standardizing grid-interconnection guidelines, offering tax incentives, and including CHP as a compliance mechanism for the state’s clean-energy standards.176 Some states have enacted these policies, and, as with many state-led policies, there is a diversity of approaches to (and success with) their implementation.177
An example of a state working to overcome barriers to CHP deployment is Ohio. The U.S. Department of Energy (DOE) estimates Ohio has a potential CHP capacity of up to 8,000 MW if CHP systems are installed and limited from selling power into the broader power market, and up to 11,000 MW if sales into the market are allowed. However, despite this vast potential, by 2011 only 766 MW of CHP was installed in the state.178 Many of the boilers in Ohio will be affected by the new EPA 2012 Boiler MACT rule, making them candidates for upgrades or complete conversions to CHP systems. At the same time, new CHP facilities have the potential to address state regulators’ concerns about several announced coal plant retirements affecting system reliability. In response to the benefits of CHP systems in Ohio at this time and to this technology’s current underutilization, the Public Utilities Commission of Ohio launched a pilot project with DOE to encourage installation of CHP systems. This project identifies candidate systems and assists in the dialogue between potential CHP operators, utilities, and the electric market operator to facilitate installations while working to overcome regulatory and other barriers.179 In 2012, the state legislature also added CHP systems as a qualifying resource in the state’s clean-energy standard.180
The increased availability of low-priced natural gas has had positive economic impact on U.S. manufacturing and sector expansion is expected to continue. Given that natural gas is a feedstock and a fuel source for this industry, the efficient use of natural gas needs to be continually encouraged. Options to increase efficiency include the replacement of older boilers with more efficient ones and the expansion of CHP. CHP systems are highly efficient, as they use heat energy otherwise wasted. Policy is needed to overcome barriers to expanded deployment. States are in an excellent position to take an active role in promoting CHP when required industrial boiler upgrades and new standards for cleaner electricity generation are implemented.
By Doug Vine, C2ES
Distributed generation is the production of electricity from smaller sources at or near the location where the energy will be consumed. Slightly more than 6.5 percent of electricity in the United States is generated at distributed locations outside of central generation plants.181 Distributed generation using natural gas has a number of potential benefits, including the potential to capture heat associated with electricity generation that can be put to use on site. When waste heat is captured and used and/or highly efficient generation technologies are used, distributed generation decreases the total demand for primary fuels, thereby decreasing greenhouse gas emissions.
This chapter explores the potential climate-related benefits of distributed generation technologies as they apply to the residential and commercial sectors. (For a discussion of combined heat and power (CHP) systems in the manufacturing sector, see chapter 6.) The chapter discusses three major technologies for distributed generation: microgrids, fuel cells, and microturbines. Next, it explores policies that encourage the deployment of these technologies, and, lastly, it discusses barriers to deployment.
Electricity is the most widely used form of energy by residential and commercial buildings on a primary-energy basis (Figure 1). Since the majority of electricity generation emits greenhouse gases, it makes sense to consider technologies with lower emissions. Several promising technologies make use of natural gas as the primary fuel, and many of these technologies could significantly reduce greenhouse gas emissions from electricity use in the residential and commercial sectors. Distributed generation technologies either can be placed on site at a home or business or can be located a short distance away, serving several buildings together. While the majority of existing natural gas-fueled distributed generation technologies are not as efficient as central generation, the ones discussed in this chapter are highly efficient, can be used in highly-efficient configurations with CHP, and/or facilitate the deployment of renewable energy sources. Distributed generation technologies that supply power to multiple locations include microgrids. On-site or end-use technologies include natural gas-fueled electricity (and heating) devices such as fuel cells and microturbines, which can also be used as small CHP systems.
In 2010, natural gas-fueled electricity comprised approximately 54 percent of the total net U.S. distributed generation (Figure 2). These figures are for industrial and commercial sector distributed generation only and represent approximately 3.5 percent of the total electricity generated in that year.
Source: Energy Information Administration, Residential Energy Consumption Survey, 2009. Available at http://www.eia.gov/consumption/residential/data/2009/
Source: Source: Energy Information Administration, Residential Energy Consumption Survey, 2009. Available at http://www.eia.gov/consumption/residential/data/2009/
Distributed generation has many advantages over centralized electricity generation, including end-users’ access to waste heat, easier integration of renewable energy, heightened reliability of the electricity system, reduced peaking power requirements, lower greenhouse gas emissions, and less vulnerability to terrorism due to more geographically dispersed, smaller power plants.182 In addition, producing electricity closer to where it is used reduces the amount of electricity lost as it is delivered over long distances from power stations to end users. Annual electricity transmission and distribution losses in the United States average about 7 percent of the electricity transmitted.183 Lowering transmission (or line) losses means less electricity generation (less fuel and fewer emissions) is required to serve the same electrical demand.
Generally, natural gas-fueled distributed generation technologies are not as efficient in producing electricity as natural gas-fired generation from the grid. In general, distributed generation only improves efficiency and reduces greenhouse gas emissions when it includes CHP. By definition, distributed generation is physically located close to loads, so use of heat is often an option. However, CHP requires tight matching, in space and especially in time, between power generation and thermal loads. This matching can make CHP technologies difficult to effectively install. Nevertheless, where possible, this technology is significantly more efficient and should be deployed.
One increasingly employed distributed generation technology is the microgrid. A microgrid is a small power system composed of one or more electrical generation units that can be operated either in conjunction with or independently from the central power system (Figure 3).184 Microgrids can serve a small grouping of buildings. Additionally, microgrids offer the potential to integrate renewable sources of electricity with fossil fuel-based backup power; they are able to integrate distributed, dispatchable natural gas-fueled electricity (or CHP systems) with local renewable power and energy storage. Furthermore, since the electricity is generated close to where it will be used, it becomes feasible to use the waste heat in a productive manner, such as for heating water or space in nearby homes and businesses. Microgrids can be particularly attractive if new or upgraded long-distance electricity transmission cannot be developed in a timely or cost-effective fashion.185
Fuel cells are another promising distributed generation technology. Natural gas-powered fuel cells use natural gas and air to create electricity and heat through an electrochemical process rather than combustion.186 First, natural gas is converted into hydrogen gas inside the fuel cell in a process known as reformation. When the hydrogen passes across the anode of the fuel cell stack (Figures 4 and 5), electricity, heat, water, and carbon dioxide (CO2) are created.
Source: Siemens, “The Business Case for Microgrids,” 2011. Available at: http://www.energy.siemens.com/us/pool/us/energy/energy-topics/smart-grid/downloads/The%20business%20case%20for%20microgrids_Siemens%20white%20paper.pdf
Note: Individual microgrid elements will vary.
Source: ClearEdge Power
Fuel cell technology has been around for many decades; it has been used by the National Aeronautics and Space Administration on space projects for nearly 50 years. Commercially available fuel cells operate in a wide range of climates, from very cold to very warm (-20° to 110°F), and they have electrical efficiencies of around 40 to 60 percent (Table 1). They are quiet devices with a fairly small footprint. The only greenhouse gas emitted is a pure stream of CO2, which could allow for capture and sequestration. Despite these benefits, skeptics question the durability, cost (see below) and reliability of fuel cells. In the past, materials have corroded within months or a few years. Bloom Energy estimates that its current devices will have a 10-year life as long as the fuel stacks are replaced at least twice. However, since Bloom’s introduction is recent, there are currently no operational fuel cell systems that have approached this age.187
There are many types of fuel cells, each with its unique chemistry, operating temperature, catalyst, and electrolyte.188 Phosphoric acid fuel cells, molten carbonate fuel cells, and solid oxide fuel cells, among others, have been commercialized for stationary electrical power generation. Since many units operate at high temperatures and contain corrosive materials, a key concern is their durability or stack life. For example, natural gas-fueled phosphoric acid fuel cells operate at temperatures of around 450°F, and solid oxide fuel cells operate at temperatures of about 1,800°F.189 Phosphoric acid fuel cells are the most durable type in the less-than-one megawatt (MW) range and have a demonstrated stack life of more than 10 years, although designs of many other fuel cell types are improving rapidly.190
Source: ClearEdge Power
Notes: 1) Fuel Processor: Converts natural gas fuel to hydrogen. 2) Fuel Cell Stack: Generates direct current (DC) power from hydrogen and air. 3) Power Conditioner: Converts DC power to high-quality alternating current (AC) power 4) Heat Recovery: On-board heat exchangers for recovering useful thermal energy.
ClearEdge Power and Bloom Energy are among a handful of manufacturers of stationary fuel cells. Their main products are described below for illustrative purposes. There are an additional half-dozen or so manufacturers of non-stationary fuel cells (fuel cells for vehicles).
ClearEdge Power, based in Oregon and established in 2003, manufactures refrigerator-sized fuel cell units that generate baseload or backup electric power as well as provide useable heat for hot water and/or space heating in a CHP configuration. These units are scalable to suit the energy requirements of individual homes, apartment buildings, hotels, and other commercial businesses, and can be installed indoors or outdoors. They have efficiencies of up to 90 percent. They are 50 to 60 percent efficient in natural gas conversion to electricity, in addition to providing useful heat. Therefore, they require considerably less natural gas to generate the same amount of energy provided from a combination of centrally generated electricity and a heating appliance.191 In February 2013, ClearEdge Power acquired UTC Power, an early pioneer in fuel cell research that conducted experiments with many types of fuel cells beginning in the late 1950s.192 Stationary fuel cell products from UTC Power, now ClearEdge Power, are deployed in residential, commercial, and industrial applications around the world.193
Source: Bloom Energy
Bloom Energy, based in California and founded in 2001, markets energy servers that consist of arrays of fuel cell boxes in various sizes that must be installed outdoors (Figure 6). The energy servers are scalable and are used by large corporate customers such as Wal-Mart, eBay, and FedEx, and not residential consumers.194 These servers achieve conversion efficiencies above 60 percent. These are very high-temperature devices, but the heat is not used for water or space heating. The average emissions are 773 pounds of CO2 per megawatt-hour (MWh), which is just below the average U.S. natural gas power plant at 800 to 850 pounds of CO2/MWh.195, 196
Microturbines are small combustion turbines approximately the size of a refrigerator with individual unit outputs of up to 500 kilowatts (kW).197 These devices can be fueled by natural gas, hydrogen, propane, or diesel. In a cogeneration configuration (Figure 7), the combined thermal-electrical efficiency can be as high as 90 percent.198 Like fuel cells, microturbines can achieve much higher energy efficiencies, because the electricity is generated close to the location where it will be used, and the heat byproduct can be captured and utilized on site or nearby.
Total Efficiency for CHP system
Residential, Commercial, Industrial
Source: Clear Edge, Bloom Energy
Source: Capstone Turbine Corporation
Microturbines are an established technology, and there are more than 20 companies worldwide involved in the development and commercialization of microturbines for distributed generation applications.
Los Angeles-based Capstone Turbine Corporation is a global market leader in the commercialization of microturbines.199 The company offers individual units in the range of 30 kW to 200 kW, and greater quantities of power can be achieved by using multiple units, with electrical efficiencies from 25 to 35 percent (Figure 8). Using the heat produced by a microturbine for water or space heating, space cooling (in conjunction with absorption chillers) and/or process heating or drying, increases the efficiency of these units to 70 to 90 percent.200 Capstone products service the commercial and industrial sectors, and they have installations all over the world, including universities, a winery, and a 35-story office tower in New York City (Figure 9).201
Source: Capstone Turbine Corporation
Flex Energy, also headquartered in California, is Capstone’s main competitor. Its 250 kW microturbine has an electrical efficiency of 30 percent, and it too provides useful heat energy, which when used would improve the overall efficiency of the system.202 Flex Energy and Capstone microturbines can use low-quality and unrefined natural gas, making them capable of generating electricity at landfills and hydraulic fracturing sites.203 Using unrefined natural gas at a well site for power requirements can reduce the need for diesel power generation and utilize natural gas that may have been flared otherwise.
Source: Capstone Turbine Corporation
Micro Turbine Technology, a company in the Netherlands, is developing a 3 kW electrical with 15 kW thermal microturbine CHP for homes and small businesses that is expected to be ready for market in early 2013.204
At 31 percent average electrical efficiency, much lower than a modern natural gas combined-cycle plant or fuel cell (both around 50 percent), microturbines produce 1,290 pounds of CO2/MWh, about 50 percent higher emissions than a modern combined-cycle plant.205 However, due to their ability to capture and use waste heat onsite, they are capable of achieving thermal efficiencies of up to 85 percent. When this heat is captured and used, the total efficiency of the system offsets the lower efficiency of electricity generation part of the system, reducing overall greenhouse gas emissions per MWh. Additional strengths of microturbines include their compact size, small number of moving parts, generally lower noise than other engines, and long maintenance intervals. Weaknesses include parasitic load loss from running a natural gas compressor and loss of power output and efficiency with higher ambient temperatures and elevation.206 According to U.S. Environmental Protection Agency data, at an 80°F outdoor air temperature, the microturbines are about 3 percent less efficient than at a 50°F outdoor air temperature.207
There are even smaller systems than the microturbines discussed that can provide CHP to individual residential units. At less than 50 kW, these microCHP units are small enough to provide electric power for a residential or commercial building while also supplying heat for thermal applications or absorption cooling (Figure 10). Common in Europe and Japan, microCHP is rare in the United States. These small units may use a variety of engine types, including combustion, steam, Brayton, and Stirling.208 For example, the WhisperGen, developed in New Zealand, is a microCHP technology based on the Stirling engine. The company is currently headquartered in Spain, where the product is being marketed to European customers. The washing machine-sized technology is designed to produce hot water and space heating. Under normal operation the unit will provide around 1 kW of electrical power.209 Other companies, such as Japan’s Honda, also offer microCHP units to consumers.210
Total Efficiency for CHP system
Source: Capstone, Flex Energy, MTT
Source: Fuel Cell Today
Although these new technologies have great potential to use less primary energy and to reduce greenhouse gas emissions from energy use in the residential and commercial sectors, there are some hurdles to overcome. Higher upfront capital costs hinder investment in distributed generation technologies overall. In addition, utility regulations often do not encourage, and in some case actively discourage, distributed generation technologies.
Some state and federal incentive programs help home- and business-owners with upfront costs. At least 10 states provide financial incentives for self-generation.211, 212 The federal Investment Tax Credit, designed to help defray capital expenditure costs, applies to fuel cells, CHP, and microturbines for use in the commercial, industrial, utility, and agricultural sectors.213
Another potential incentive for consumer investment in on-site energy generation is net metering. Net metering allows customers to receive retail prices for their excess generation; the electricity meter turns backwards (literally or digitally) when the site generates more electricity than it consumes.214 Forty-three states and the District of Columbia have rules enabling net metering.215 Eligible generation technologies vary. Fuel cells using any fuel type often qualify, and CHP sometimes qualifies, although less often.
Sites using distributed generation often rely on a grid interconnection as a source of backup power. Establishing a connection between an on-site system and the power grid can be difficult, confusing for the on-site operator, and lengthy. Standard interconnection rules greatly simplify this process, establishing clear and uniform processes and technical requirements that apply to all utilities within a state. These rules reduce uncertainty and prevent delays that installers and operators of distributed generation systems can encounter when obtaining approval for electric grid connection, and thus make the prospect of installing a system less daunting to newcomers.216 As of April 2012, 34 states had interconnection standards for fuel cells, and 29 states had such standards for microturbines.217
A final area where policies could encourage the installation of more distributed generation systems pertains to utility charges. As mentioned above, distributed generation systems rely on a grid connection for backup power during outages, whether scheduled or emergency. Standby rates are charges levied by utilities when a distributed generation system must purchase all of its power from the grid. These charges generally include an energy charge, reflecting the actual energy provided, and a demand charge, which is a way for the utility to recover its costs in maintaining the capacity to meet the facility’s peak demand whenever that may be required. Utilities often argue that the demand charges act as a strong incentive for system owners to manage their peak demand. However, the likelihood of unplanned outages during times of peak demand is very low, and the use of demand charges likely discourages the expansion of distributed generation. Regulators should carefully weigh the discouraging effect of demand charges against the substantial benefits of distributed generation, including increased system reliability, reduced distribution losses, and the climate benefits of the higher system efficiencies.218
A variety of factors converge to discourage potential owners of distributed generation systems. First, consumers are largely unfamiliar with these technologies. Moreover, they are not compelled to search for innovative strategies to generate energy. Their utility bills are stable, due to low wholesale electricity prices (a result of lower natural gas prices). Local building and fire codes may also provide disincentives or even make it impossible for consumers to consider distributed generation. And the limited availability of many distributed generation products in the United States is a barrier to even those with natural gas access.219
Even if these hurdles are removed, the cost of many distributed generation technologies can be a barrier. According to the National Institute of Building Sciences, microturbine capital costs were $700 to $1,100 per kW in 2010, with installation costs adding 30 to 50 percent of the total installed cost. Combining heat recovery technology to units increased the cost by $75 to $350 per kW. A future cost below $650 per kW may be possible with future economies of scale.220 Fuel cells could be cost-competitive with grid electricity if they were to reach an installed cost of $1,500 or less per kW; however, the current installed, unsubsidized cost is at least $4,000 per kW.221 Nevertheless, a combination of state and federal incentives, low natural gas prices, and high grid-electricity prices could result in a 100 kW energy server making economic sense, as shown in an analysis by Seattle City Light (Figure 11). Similarly, natural gas microCHP units could be cost competitive with a 1.5- to two-year payback period at an installed cost of $1,500 for a 1 kW unit.222
To realize the potential of distributed generation technologies, policies such as financial incentives and tax credits will need to be more widespread. Additionally, net metering, grid interconnection requirements, and standby rate issues will need to be worked through. Also, low consumer awareness and higher costs of these emerging technologies will slow their deployment. Finally, utilities may perceive distributed generation technologies as a threat, as they have the potential to capture a large share of utilities’ electricity sales business. Nevertheless, some supporters of distributed generation have claimed that their technology will replace the grid and have designed their business strategies accordingly.223
Source: Seattle City Light, “Integrated Resource Plan.” 2010. Available at: http://www.seattle.gov/light/news/issues/irp/docs/dbg_538_app_i_5.pdf
By Fred Beach, The University of Texas at Austin
Historically, natural gas has not been widely used as an energy source for transportation; rather, the sector has long been dominated by petroleum use. In 2010 (Figure 1), the U.S. transportation sector used 27.47 quadrillion British thermal units (Btu) of energy, of which 25.59 quadrillion came from petroleum and just 0.72 quadrillion came from natural gas—93 percent and 3 percent of the sector, respectively.224 Natural gas used in the transportation sector resulted in the emission of just 40.1 million metric tons of carbon dioxide equivalent (CO2e) in 2010, out of a total 1,746 million metric tons emitted by all fuel sources in the transportation sector.225 As in other sectors of the economy, fuel substitution from other fossil fuels to natural gas in some parts of the transportation sector has the potential to yield climate benefits. In addition, it would benefit U.S. national security by decreasing reliance on the global oil market. Although the potential for natural gas use is less in the transportation sector than in others, the potential does exist, primarily for medium- and heavy-duty trucks as well as fleet vehicles and buses.
Source: Energy Information Administration, “Annual Energy Review,” Table 2.1e. October 2011. Available at: http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb0201e
A main driver of the increased interest natural gas fleets and passenger vehicles is the relative abundance and low price of domestic natural gas in comparison to oil. On April 30, 2012, the national average price of diesel fuel was $4.07 per gallon and gasoline cost $3.83 per gallon,226 while a gasoline-gallon-equivalent of natural gas cost only $2.09.227 On the same day, the price of petroleum was $104.87 per barrel,228 and the price of natural gas was only $12 on an energy-equivalent basis.229 In recent years, oil prices rose while natural gas prices decreased, creating an ever-widening gulf (Figure 2). This differential has made natural gas vehicles increasingly economical.230
This chapter looks at the currently available natural gas technologies for vehicles. Next, it explores the barriers to adoption for various types of vehicles. Finally, it examines the potential implications of broader direct use of natural gas in the transportation sector for greenhouse gas emissions.
A variety of available vehicle technologies allow natural gas to be used in light-, medium-, and heavy-duty vehicles. Most commonly, natural gas is used in a highly pressurized form as compressed natural gas (CNG) or as liquefied natural gas (LNG). While CNG and LNG are ultimately burned in the vehicle, natural gas can also power vehicles in other ways. Natural gas can be converted into liquid fuel such as gasoline and diesel (distinct from LNG) that can be used in conventional internal combustion engines, reformed into hydrogen for use in fuel-cell vehicles, or be used to generate electricity for electric vehicles. Despite the existence of these technologies, only about 117,000 of the more than 250 million vehicles on the road in 2010 (about 0.05 percent) were powered directly by natural gas.231 The majority of natural gas-powered vehicles are buses and trucks.232
CNG is the most common natural gas fuel used in transportation today. There were 115,863 compressed-natural gas vehicles on U.S. roads in 2010, using 988 fueling sites.233 The majority is found in larger transportation fleets. Although Honda offers a CNG passenger vehicle, only 4,000 vehicles were scheduled for production in 2012.234 Public transit buses are the largest users of natural gas in the transportation sector, with about one-fifth of buses running on CNG or LNG. Some commercial fleets use natural gas-powered trucks, including thousands of trucks at FedEx, UPS, and AT&T.235, 236 Waste Management has the largest fleet of natural gas vehicles in the country with 1,700 trucks that can run partially on biogas supplied from its own landfill assets.237 The low cost and environmental benefits of this biogas are encouraging the company to continue conversions and to open some of its refueling infrastructure to the public.
To a lesser extent than CNG vehicles, vehicles powered by LNG (primarily heavy-duty trucks) are also used on U.S. roads and a fueling infrastructure has begun to develop. LNG is created by chilling natural gas to -260°F at normal pressures, at which point it condenses into a liquid that occupies 0.0017 percent of the volume of the gaseous form.238 The conversion of natural gas to LNG removes compounds such as water, carbon dioxide (CO2), and sulfur compounds from the raw material, leaving a purer methane product whose combustion results in less air pollution.239 The stable, non-corrosive form also makes LNG more easily transportable, and it can be moved by ocean tankers or trucks.240 Use of LNG requires large, heavy, and highly insulated fuel tanks to keep the fuel cold, which adds a significant cost to the vehicle.241 Today, LNG is mainly used as a replacement for diesel fuel in heavy-duty trucks because they can accommodate this hefty storage system and can use LNG fueling infrastructure currently limited to trucking routes.242 In 2010, there were only 40 public and private LNG refueling sites,243 serving 3,354 LNG vehicles.244 Recently, the Clean Energy Fuels network launched the development of an interstate LNG refueling network, mainly taking advantage of existing diesel fueling stations along highways and trucking distribution centers. Seventy stations were opened in 2012, with plans for 70 to 80 more in 2013.245
Source: Energy Information Administration, “Annual Energy Outlook 2012 Early Release,” 2012. Available at: http://www.eia.gov/oiaf/aeo/tablebrowser/#release=EARLY2012&subject=0-EARLY2012&table=7-EARLY2012®ion=0-0&cases=full2011-d020911a,early2012-d121011b
CNG and LNG are less dense forms of energy than conventional gasoline and diesel fuel (Figure 3), requiring vehicles running on them to have larger fuel tanks in order to store the same amount of energy. CNG requires special storage because the gas is compressed to less than 1 percent of its volume at standard atmospheric pressure.246 Vehicles use cylindrical storage tanks capable of fuel pressures of up to 3,600 pounds per square inch. These tanks are significantly larger and heavier than conventional gasoline or diesel fuel tanks, and their placement in passenger vehicles can take up valuable passenger or trunk space.247, 248 The energy density of CNG is so low that CNG vehicles with ranges greater than 300 miles are unlikely to be produced unless current space and weight limitations are overcome. Therefore, CNG is primarily suitable for fleet passenger vehicles, municipal buses, and other vehicles where travel distances are shorter. The greater energy density of LNG, however, makes it practical for long-haul tractor-trailers that can accommodate larger fuel tanks.249 Despite being less energy-dense than gasoline or diesel, both CNG and LNG can be an attractive fuel source for certain applications, from both an economic and environmental perspective.
Source: Energy Information Administration, “Annual Energy Outlook 2010 with Projections to 2035,” 2010. Available at: http://www.eia.gov/oiaf/aeo/otheranalysis/aeo_2010analysispapers/factors.html
Natural gas also plays a role in supplying fuel cell vehicles (see chapter 7 for a discussion of stationary fuel cells in distributed generation). Fuel cells produce electricity through an electrochemical process rather than through combustion, resulting in heat and water and far lower emissions of greenhouse gases and other pollutants. Fuel cells are fueled by hydrogen, and the most common source of hydrogen today is natural gas. Hydrogen can be extracted on board the vehicle using a reformer, or it can be externally extracted and subsequently added to the vehicle.250 Today, no light-duty fuel cell vehicles are commercially available in the United States, although there are certain test vehicles on the road as well as rudimentary hydrogen fueling infrastructure in California.251 Companies are working to introduce fuel cell vehicles to the market. In the United States, Hyundai plans to build 1,000 fuel cell vehicles for distribution in 2013,252 and Toyota has suggested that production costs are decreasing such that it should be able to sell fuel cell vehicles for $50,000 by 2015.253
While CNG and LNG are today the most common forms of natural gas fuels in vehicles, other available technologies could increase the use of natural gas in the broader transportation system. Gas-to-liquids technology refines natural gas into gasoline or diesel hydrocarbons, which can be used in existing vehicles and moved through existing infrastructure. Gas-to-liquids products have energy densities similar to those of traditionally produced gasoline and diesel, properties that allow for better engine performance and potentially fewer emissions of greenhouse gases and regulated pollutants,254 although more empirical study is needed on emissions.
Conversion technologies typically require 10 thousand cubic feet (Mcf) of natural gas to produce one barrel of oil-equivalent product output, such as diesel, naphtha, and other petrochemical products.255 Using $4 per Mcf of natural gas as inputs to this conversion, the outputs are equivalent to $40 per barrel of oil-equivalent. Gas-to-liquids products have been produced at facilities elsewhere in the world, and new facilities in the United States are being developed. Several companies are considering gas-to-liquids facilities on the Gulf Coast because of favorable natural gas supplies and current domestic prices.256
Source: California Air Resources Board, “Proposed Regulation to Implement the Low Carbon Fuel Standard,” March 5, 2009. Table ES-8. Available at: http://www.arb.ca.gov/fuels/lcfs/030409lcfs_isor_vol1.pdf
Notes: The carbon intensities compared above were calculated specifically for California’s Low Carbon Fuel Standard program using the GREET model.
Results from the GREET model rely on the assumptions included in the model. Other models may use other assumptions and yield different results. Models are useful for insights, but their results depend on the assumptions made.
Natural gas also plays a role in electric vehicles, which are becoming more common on U.S. roads. These vehicles use electricity from the electrical grid, which is increasingly powered by natural gas as a fuel source. From January 2011 to December 2012, Americans purchased more than 60,000 plug-in electric vehicles, including Chevrolet Volts, Nissan LEAFs, and Toyota plug-in Priuses.257 Additionally, plug-in electric vehicles are now available from BMW, Ford, Tesla, Mitsubishi, and Daimler.258 When fueled by electricity generated by a combined-cycle natural gas power plant, such natural gas-powered electric vehicles offer significant efficiency and emissions benefits over conventional diesel- or gasoline-powered vehicles.259
Transportation accounts for more than 25 percent of U.S. greenhouse gas emissions and is an important focus of U.S. emission reduction efforts. Natural gas emits fewer greenhouse gases than gasoline or diesel when combusted or used in fuel cells (Figure 4). Fuel Cells offer the greatest potential emission reduction benefit but today are also the most expensive. CNG offers the next largest greenhouse gas reduction potential and can be used in many transportation options including fleets, heavy-duty vehicles and passenger vehicles. The barriers and potential for emission reductions associated with fuel switching to natural gas in major segments of the transportation sector are described below.
Buses produce a very small share of overall greenhouse gases, contributing only 1 percent of emissions from on-road vehicle transportation in 2011, but as previously mentioned, they are the most common use of natural gas in vehicles today.260 In contrast, long-haul tractor-trailers play a more important role in U.S. energy consumption and greenhouse gas emissions. These vehicles account for two-thirds of all fuel consumption for freight trucks (medium- and heavy-duty trucks), and freight trucks’ emissions are increasing more rapidly than those of other transportation sources. Over time, freight trucks will likely account for an even larger percentage of the sector’s greenhouse gas emissions, as they will take on a greater portion of deliveries for consumer products, using more vehicles for just-in-time shipping and taking advantage of lower labor costs and changing land use patterns.261 Consequently, reducing the carbon intensity of freight trucks will be critical to reducing transportation sector greenhouse gas emissions, and increased natural gas use is one opportunity to do so.
Significant barriers exist for the expansion of natural gas use in medium- and heavy-duty vehicles. Currently, trucks utilizing CNG or LNG have shorter ranges, fewer refueling options, and lower resale value than traditional diesel-powered trucks. A diesel truck with a 150-gallon tank and a 6 to 7 miles-per-gallon fuel economy can travel about 1,000 miles on one tank, which is significantly more than its natural gas-powered counterparts. Depending on the mounting of the cylindrical storage tanks, CNG trucks can travel between 150 miles and 400 miles between fueling, while LNG trucks can travel around 400 miles.262
The limited availability of fueling infrastructure also hampers the deployment of natural gas-powered trucks, and better infrastructure is required for greater use.263 In May 2012, there were 1,047 fueling stations for CNG and 53 fueling stations for LNG in the United States, and 53 percent of the CNG stations and 57 percent of the LNG stations were closed to the public.264 Also, speed of fueling can be a barrier to deployment in certain fleet types, as the more common and less expensive fueling technology requires long filling times. On-time delivery operations of trucking fleets may not be able to accommodate long filling. Slow filling is more appropriate for trucks such as waste trucks or buses that may idle for long periods overnight or between uses.265
Fuel pricing differentials are a clear driver for natural gas conversions in the transportation sector since fuel costs are a significant portion of the overall operating budgets for fleet owners. Medium-duty trucks use about 6,000 gallons of fuel per year, while heavy-duty trucks use about 18,000 gallons. At $3.50 per gallon of diesel fuel, annual fuel costs are $21,000 for a medium-duty truck and $63,000 for a heavy-duty truck. Natural gas fuel costs are substantially lower than diesel fuel. At a price of $2.80 per diesel gallon equivalent—a typical price for LNG or retail CNG—annual fuel costs would fall to $16,800 per medium-duty truck and $50,400 per heavy-duty truck. At a slow-fill CNG cost of $1.00 per diesel-gallon-equivalent, costs drop to less than one-third the cost of diesel, to $6,000 per medium-duty truck and $18,000 per heavy-duty truck. These fuel savings offer great incentives for fuel-switching.266
However, fleet economics are often more complex, extending beyond just fuel costs. Natural gas trucks are about $30,000 to $50,000 more expensive than their diesel counterparts, a substantial additional capital cost. Adoption of natural gas trucks also requires fleet owners to invest in additional maintenance capacity for natural gas vehicles, requiring investments in new materials and job training. Complying with standards for maintaining natural gas trucks, such as those required under Occupational Safety and Health Administration regulations for compressed gases, adds costs.267 These costs may further rise as regulations for this nascent industry develop and change. Resale value of natural gas trucks is another important factor for some fleet owners. Trucks from some large fleets may be resold in as little as three to four years, often to smaller trucking companies that may not be able to use natural gas vehicles due to a lack of available infrastructure or a skilled workforce. As a consequence, even with the potential fuel savings, many fleet owners may have little economic incentive to switch to natural gas trucks.
The cost-benefit ratio of CNG vehicles for fleet owners depends on the many variables inherent in the composition and use of vehicle fleets and the costs of refueling infrastructure. For fleet owners, range requirements may not be a significant issue, since fleet vehicles travel regular and known paths. Refueling can take place at a centralized facility or along a set route.268 The U.S. Department of Energy’s National Renewable Energy Laboratory conducted research into three different types of CNG fleets that might be used by municipal governments—transit buses, school buses, and refuse trucks—and possible refueling infrastructures. This segment was targeted based on the potential for long-term cost-effectiveness, consistency of operational costs, lower greenhouse gas emissions, and other factors.269 The research led to the creation of a model for fleet profitability that highlighted the importance of fleet size and vehicle miles driven in calculating the cost and benefits of CNG vehicles. It estimated payback periods of three to 10 years that were sensitive to the costs related to refueling stations and vehicle conversion, operations, and maintenance.
This model includes the cost of building and operating centralized fleet-specific refueling infrastructure and thus avoids the “chicken versus egg” refueling quandary that is challenging to non-municipal fleet applications, such as small private trucking operations. The lack of a public CNG refueling infrastructure hinders fleet owners’ decisions to convert heavy-duty vehicles to CNG. Conversely, the low numbers of heavy-duty vehicles converted to CNG dampens private and public sector investor motivation to build CNG refueling infrastructure. Were it not for the lack of a public refueling infrastructure, the rationale for fleet owners to convert heavy-duty vehicles would be much more compelling, as their high annual miles driven provide a much quicker return on the upfront cost of vehicle conversion than do the annual miles driven of municipal fleet vehicles.
Source: Regional Plan Association, “Maps,” 2012. Available at: http://www.america2050.org/maps/
One approach that may help to overcome the vehicle-conversion-versus-refueling-infrastructure hurdle is to focus on one subset of the high-mileage, heavy-duty tractor-trailer industry segment, namely, intercity (as opposed to interstate) transport. In intercity regions with areas of high tractor-trailer usage, a very small number of public CNG refueling stations can serve a large number and percentage of the heavy-vehicle transportation segment. The United States has 11 “Megaregions” where tractor-trailers travel tens of thousands of miles annually but never leave the confines of a relatively small geographic area (Figure 5). Natural gas infrastructure can be built out in these Megaregions, such as through the proposed Texas Clean Transportation Triangle (Figure 6). Nearly 75 percent of the intrastate heavy and medium transport in Texas occurs within the triangle, making it an excellent candidate for CNG infrastructure.270 Nominal public refueling infrastructure for CNG vehicles in the 11 Megaregions could also prove sufficient to service the interstate CNG tractor-trailer segment for a significant portion of the nation and create enough consumer demand to encourage the installation of refueling capability throughout the nation’s network of commercial truck stops.
Passenger vehicles account for nearly three-fifths of the total energy use and greenhouse gas emissions in the transportation sector. The lower price of natural gas and the energy security benefits of reducing U.S. consumption of oil have both contributed to recent interest in using natural gas in passenger vehicles.
Source: Gladstein, Neandross & Associates / America’s Natural Gas Alliance
Potential barriers to wider deployment of natural gas-powered passenger vehicles include lack of access to refueling sites and the vehicles’ limited ranges.271 Home refueling is one way to potentially increase the number of refueling sites. While there are 159,006 retail gasoline stations in the United States,272 more than 65 million U.S. homes have natural gas service.273 Home refueling of a CNG vehicle requires the installation of a wall-mounted electric compressor to deliver the low-pressure gas from the residential system into the high-pressure CNG vehicle tank. The compressors are small and unobtrusive, but require several hours to fill the vehicle’s tank.274 Home refueling options may, in addition to providing lower fuel prices, persuade some consumers to consider purchasing CNG passenger cars or to convert existing ones from gasoline-powered cars. Yet, home fueling infrastructure has remained expensive. Home fueling appliances, such as Phil, can cost more than $4,000,275 not including the construction and permitting costs of extending home natural gas pipe access to the garage or carport. Other barriers to adoption exist. CNG vehicles, when compared with conventional gasoline vehicles, have a reduced range because of CNG’s lower energy density (the maximum range of the Honda Civic GX NG is 248 miles),276 higher up-front costs, and smaller trunk capacity.
Fleets including taxis, business, and government vehicles may offer the greatest potential for natural gas use in passenger vehicles. In 2012, 22 states signed a memorandum of understanding to jointly solicit automaker proposals to produce seven categories of natural gas vehicles for purchase by state, local, and municipal fleets. The intention of this joint effort is to stimulate the market for natural gas vehicles and eventually expand opportunities for market growth in the private sector for passenger natural gas vehicles, as well as to decrease the fleets’ associated air pollution.277 Combined, the barriers associated with the deployment of light-duty natural gas vehicles are noticeably larger and more costly than those associated with CNG- and LNG-powered heavy-duty vehicles.
Increased use of these vehicles offers significant potential benefits to U.S. energy security. Energy security is the adequacy and resiliency of the energy system as it relates to energy production, delivery, and consumption. The U.S. transportation sector relies on a global oil market that is currently dominated by an oligopoly—the Organization of the Petroleum Exporting Countries (OPEC)—as well as national oil companies. OPEC’s ability to constrain supplies results in oil prices higher than a competitive market would produce. Monopoly power, combined with oil price shocks, mean that the U.S. economy loses hundreds of billions of dollars per year in productivity. Researchers at the Oak Ridge National Laboratory estimate that the combined total of these costs has surpassed $5 trillion (in 2008 dollars) since 1970.278 Moreover, most experts believe that rising demand in emerging market economies coupled with supply-side challenges can be expected to lead to future volatility in oil prices, which would be highly damaging for U.S. consumers and businesses. Replacing oil with domestically produced natural gas would have significant benefits for U.S. energy security.
The transportation sector has long relied on petroleum fuels for the vast majority of its energy needs. While utilizing natural gas as a fuel source in this sector offers greenhouse benefits, in total these benefits are less likely than in other sectors of the economy, given the difficulty, cost and speed of converting passenger vehicles to natural gas. Moreover, in the near and medium term, fuel economy for gasoline-powered passenger vehicles is set to rise due to new Corporate Average Fuel Efficiency Standards, which could reduce the emissions advantage of natural gas vehicles. Hybrid and electric passenger vehicles are also becoming more common, and given the widespread availability of electricity compared to the availability of natural gas, they require less infrastructure investment than do natural gas vehicles. These factors indicate that, considering the need for substantial long-term reductions in greenhouse gas emissions from the transportation sector, by the time a fleet conversion to natural gas would be completed for passenger vehicles, a new conversion to an even lower-carbon fuel will be required. A passenger vehicle fleet conversion to natural gas would be short-lived and yield a low return on investment from a climate perspective.279
As in other sectors of the economy, fuel substitution from other fossil fuels to natural gas in some parts of the transportation sector has the potential to yield climate benefits. In addition, it would benefit U.S. national security by decreasing our reliance on a global oil market dominated by outside forces. Although the potential for natural gas use is less in the transportation sector than in others, the potential does exist, primarily for medium- and heavy-duty trucks as well as fleet vehicles and buses.
By Michael Tubman, C2ES
The United States has the world’s most extensive infrastructure for transporting natural gas from production and importation sites to consumers all over the country. This transport infrastructure is made up of three main components: gathering pipelines, transmission pipelines, and distribution pipelines.280 Though fundamentally similar in nature, each type of pipeline is designed for a specific purpose, operating pressure and condition, and length. These components are linked in networks to form the U.S. natural gas infrastructure system (Figure 1).
Rising demand for natural gas in the electric power, manufacturing, buildings, and transportation sectors requires significant expansion of the natural gas infrastructure system if these sectors are to reap the potential cost savings and energy security benefits. Increased use of natural gas, when substituted for other fuels, also can significantly reduce greenhouse gas emissions, as long as methane leakage emissions from natural gas systems are minimized. This chapter describes the elements of the U.S. natural gas system and how they function together. Next, it highlights the regional natural gas flows from producing basins to areas of consumption. Then, it discusses the critical issue of methane emissions. Finally, it explores the barriers to infrastructure development and outlines recent innovations in funding models.
Source: American Gas Association, “About Natural Gas,” 2013. Available at: http://www.aga.org/Kc/aboutnaturalgas/Pages/default.aspx
Almost all natural gas consumed in the United States is produced in North America, from onshore or offshore wells or, to a much lesser extent, biogas production sites. Natural gas first enters the transport network through gathering pipelines that collect it from the point of production, most commonly the wellhead at the point of extraction, and carry it to processing facilities. Gathering pipelines are usually short and small in diameter and operate at low pressures. In 2011, there were almost 20,000 miles of gathering pipelines in the United States, originating at more than 460,000 wellheads.281
Once gathered from well sites, natural gas is processed to remove impurities such as sulfur and carbon dioxide (CO2) and is dehydrated to remove any water. It is then piped to where there is consumer demand, often hundreds of miles away, through transmission pipelines. Large-diameter (20- to 42-inch), high-pressure transmission pipelines, often called interstate pipelines or trunk lines, efficiently move the gas over vast distances. In 2011, there were 304,087 miles of transmission pipeline in the United States.282 To ensure pressure in the pipeline and keep the natural gas flowing, compressor stations are placed every 40 to 100 miles. These stations apply pressure to the gas and often filter the gas again to maintain purity. Meters are placed along transmission pipelines to monitor the flow, and valves located at regular intervals can be used to stop flow if needed.283
At various points along the gathering and transmission networks, natural gas can be stored temporarily underground in depleted oil or natural gas fields, aquifers, and salt caverns. Storage is used to enhance supply reliability and serves as a physical hedge against the seasonality of natural gas demand. Traditionally, excess supplies of natural gas are stored during the summer and then withdrawn to serve heating demand during the winter or when there are unforeseen supply disruptions. However, as natural gas demand has increased for power generation, including for cooling needs in the summer months, the seasonality of natural gas demand has diminished to some extent. Natural gas can also be stored when purchased at low prices and withdrawn when prices rise, to be sold or consumed. In 2010, there were 400 storage facilities across the United States.284
To reach homes and businesses, natural gas leaves the transmission pipeline network and enters the “city gate station,” where local distribution companies (local gas utilities) add odorant and lower the pressure before distributing it to residential and commercial customers. Local distribution companies move the gas through a series of larger distribution pipelines, called mains, throughout their service territory, and individual service lines branch off of the mains to reach each consumer. Natural gas regulators, devices in homes and commercial buildings, accept the incoming gas from the highly pressured pipelines and employ a series of valves to lower the pressure of the gas to meet appliance specifications. Distribution pipelines are much smaller pipelines, often only 0.5 to 2 inches in diameter, with pressures at a small fraction of those of the larger transmission pipelines. They may be made of plastic, which is less likely to leak than metal. Distribution networks used by local distribution companies are extensive, having more than 2 million miles of main and individual service pipelines as of 2011.285
Together, these components of natural gas infrastructure comprise an important asset that provides access to energy for all sectors of the economy. However, it is a large, dispersed asset that is mostly out of sight. Gathering and transmission pipelines are often in remote locations, while distribution pipelines, though located near the customers they serve, are buried underground. Some pipelines exist within rights-of-way occupied by other users, such as roads or private property, and pipelines often cross local, state, and even national boundaries. These factors make monitoring and regulating pipelines the responsibility of multiple jurisdictions and many levels of government.
Pipelines are regulated by both the federal and state governments. In 2007, 81 percent of natural gas in the United States flowed through transmission pipelines that cross state boundaries. The Federal Energy Regulatory Commission regulates the rates and services of these interstate pipelines as well as the construction of new interstate pipelines. Other pipelines located within states (intrastate pipelines) are regulated by state regulatory commissions. State regulatory commissions regulate both transmission lines and local distribution companies for pipeline siting, construction, operation, and expansion, as well as consumer rate structure.286
The federal government also regulates and enforces pipeline safety through the Department of Transportation, which works closely with state governments on pipeline inspection and safety protocols. Corrosion and defects can lead to leaks that have serious safety and environmental implications. Visual inspection of natural gas infrastructure is difficult, and complete replacements are nearly impossible given the vast extent of the network and its location underground. Instead, robotic inspection tools, often called “pigs,” can be sent through pipelines to detect leaks, check pipeline conditions, and monitor for weaknesses.287
The capacity, extensiveness, and flow direction of existing natural gas infrastructure varies across the country, reflecting historical supply and demand for the fuel as well as disparate state and local policies that enabled infrastructure expansion. Gathering line networks are most extensive from wellheads in traditional gas-producing states such as Texas, Oklahoma, and Louisiana, and most existing intrastate transmission lines take the fuel from those states to manufacturers and consumers in the Midwest and Northeast (Figure 2).
Recent supply increases, lower prices, and increased demand have all led to a need for expanded infrastructure, including gathering, transmission, and distribution pipelines that can bring natural gas to users and may allow natural gas to replace higher-carbon fuel sources and achieve climate benefits. Changes in supply and demand will require that 28,000 to 61,900 miles of new pipelines be constructed in North America by 2030, and $108 to $163 billion worth of investment will be needed. Additional storage capacity of 371 to 598 billion cubic feet (Bcf) will also be needed over the same time period, at a cost of $2 to $5 billion.288 Current trends in natural gas supply and demand indicate that expansion is likely to fall on the higher ends of these estimates.
Infrastructure needs related specifically to shale gas are growing across the country, reflecting the location of the shale gas resources. Significant investments related to shale gas have been made in states such as Texas and Louisiana that have historically been supply states for conventional gas deposits. Significant additional infrastructure expansion is also needed in parts of the country that have not historically produced natural gas but have been traditional destinations, such as Ohio, Pennsylvania, North Dakota, and West Virginia. Furthermore, new sources of biogas need infrastructure to collect, process, and either transport the gas to existing transmission infrastructure or use it on site. Although the potential of renewable biogas to reduce greenhouse gas emissions is large, further research is needed to ensure that it can be processed properly and safely added to the existing system, which was built specifically to withstand the constituents of geologically formed natural gas.289 In sum, several of the new supply sources require new infrastructure, and in other cases, existing infrastructure may be repurposed and deployed to bring new sources to market. As more new sources are tapped, the existing transmission pipeline infrastructure must continue to be creatively deployed and expanded to serve regional market needs.
Source: Interstate Natural Gas Association of America and PennWell
Similarly, local distribution networks will need to be expanded, with new demand for natural gas appliances, industrial uses, distributed generation, and vehicle fueling in homes and businesses. Investments are necessary in new mains, service lines, meters, and regulators that can service new customers. Indirect investments will also be required to enhance the capacity of the overall system, including for control rooms, main reinforcements, and improved flow design.290
In 2011, methane emissions from transmission pipelines and storage totaled 44 million metric tons of CO2 equivalent (CO2e), while emissions from distribution networks totaled 27 million metric tons CO2e.291 These figures have been fairly consistent over time as network expansion has been offset by better system management (including leak detection), more energy-efficient technology, and the replacement of equipment with new materials that are less subject to leakage, including replacing cast iron and steel pipe with plastics. 292, 293 While methane emissions from natural gas infrastructure are a very small portion of the nation’s total greenhouse gas emissions (Figure 3 and Figure 4), methane is a potent greenhouse gas, as described in chapter 3. Given methane’s potency, it is critical to reduce leakage to ensure that its climate benefits are maximized when compared with other fossil fuels that it may replace.294
Source: Environmental Protection Agency, “U.S. Greenhouse Gas Inventory Report,” 2013. Available at: http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2011-Chapter-3-Energy.pdf
Throughout the transportation of the fuel from gathering at the well to distribution to end-use consumers, there is potential for methane to leak into the atmosphere. Potential leakage points include production wells, valves, compressor stations, faulty seals, pressure regulators, and even broken pipes. Because methane leakage and accumulation can be an important safety issue, natural gas operators have robust safety programs in compliance with federal and state pipeline safety requirements to detect and repair leaks that pose safety risks. Methane emissions that do not pose safety concerns nevertheless can have significant implications for the climate and for the relative benefits of substituting natural gas for other fuel sources. At natural gas storage facilities, methane emissions may leak from compressors and dehydrators. At the local distribution level, methane emission leakage can occur at city gate station valves, seals, and pressure regulators, or from the joints of cast iron or unprotected steel pipe.295 The majority of all greenhouse gas emissions from natural gas infrastructure are due to leaked emissions.296
Source: Environmental Protection Agency, “U.S. Greenhouse Gas Inventory Report,” 2013. Available at: http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2011-Chapter-3-Energy.pdf
In addition to leaked emissions, methane can be intentionally released or vented as part of the production process at the wellhead or to reduce pipeline pressure. For safety and environmental reasons, however, intentionally-released methane is often burned off in a process called flaring. Flaring combusts the methane on site, forming CO2, a less potent, though very significant, greenhouse gas.297 (The climate implications of CO2 and methane are compared in chapter 3.) Flaring of methane most often occurs when natural gas is found as a byproduct or co-product of other fossil fuel production and insufficient gathering pipeline infrastructure or market incentives exist to take the natural gas to market. In 2012 in Texas, where gathering pipeline networks are well developed, less than 1 percent of the natural gas produced was flared.298 In North Dakota, where oil production from the Bakken Shale formation is a much newer phenomenon, almost 32 percent of the associated natural gas is flared, primarily because of a lack of gathering infrastructure.299 With relatively low natural gas prices, there is less economic incentive for companies to build gathering infrastructure and monetize the resource.
In August 2012, a new federal requirement to minimize venting and flaring was established as part of the Environmental Protection Agency’s New Source Performance Standards for oil and gas wells. The new regulations require that all new natural gas wells flare rather than vent, and as of 2015 use “green completion” technology that will allow excess natural gas from the well completion process to be taken to market. Many natural gas producers already use such technology.300 However, for the “green completion” rule to apply to the gathering of natural gas from the Bakken Shale or other primarily oil production sites, it would have to be expanded from its present form (see the discussion of “green completion” rules in chapter 3).
Many technologies and process improvements can reduce methane emissions from natural gas infrastructure. The federal Natural Gas STAR program, for example, has worked with industry to identify technical and engineering solutions to vented, leaked, and combustion-related emissions, including zero-bleed pneumatic controllers, improved valves, corrosion-resistant coatings, and dry-seal compressors, as well as improved leak detection and repair strategies. The solutions identified by this voluntary program often have payback periods of less than three years, depending on the price of natural gas. Participants in Natural Gas STAR reported that methane emissions from infrastructure were reduced by 15.9 Bcf in 2010, and overall, a total of 276.5 Bcf of greenhouse gases have been avoided since the program began in 1993.301 Local distribution companies have reduced emissions from their low-pressure networks by continuing to replace cast iron and steel pipes with inexpensive and durable plastic pipes; however, this plastic is not strong enough to be used in high-pressure transmission lines.302
As other chapters in this report explain, natural gas may be used to reduce greenhouse gas emissions in multiple sectors of the economy, including electric power, manufacturing, buildings, and transportation. While new pipelines are being built every day, there is a dramatic need for new pipeline investment to move new sources of natural gas supply to new regions and new users. Distribution pipeline networks, in particular, are challenged by financial and other barriers to expansion and improvement.
For local distribution networks, the cost of expansion varies considerably depending on whether the network is being expanded to new or existing communities, the density of the neighborhood, and the terrain. For new distribution pipelines in urban areas, challenges include costly repairs of overlaying roads and landscaping, negotiations with entities holding surface and other subsurface rights-of-way, and public inconveniences. Accordingly, new urban pipelines can cost five times as much as rural ones.303 Costs can be lowered when buildings are designed and constructed to be ready for natural gas access; retrofitting existing buildings with internal piping and hook-ups to natural gas supplies is more expensive.
Funding local distribution networks can be challenging and is typically dealt with through a formal regulatory proceeding called a rate case where public utility commissions determine allowable utility rates based on factors including utility operation costs, depreciation, investment, and consumer needs. Traditionally, expansion costs are considered during the rate case proceedings, but costs can only be recovered after investments are made. This time lag discourages or prevents utilities from investing in infrastructure. State-level regulatory innovations have provided some policy options to overcome these investment challenges. Some states, such as Nevada, allow the use of a deferred accounting mechanism so that costs can be better aligned temporally with ratemaking cases before state regulatory commissions. Seven southern states, including Texas, have decoupled gas consumption and cost recovery to create what is known as a “rate stabilization method.” This method allows rates to adjust annually for infrastructure replacement and construction rather than simply the amount of natural gas throughput.304
Funding models that can foster greater access to natural gas are being explored throughout the country. For example, in North Carolina, rules established by the public utilities commission allow for dedicated funds for new distribution pipelines. A local distribution company may petition the public utilities commission to establish a Natural Gas Expansion Fund to help pay for the otherwise economically infeasible expansion of distribution pipelines. Additional money may be added to the Natural Gas Expansion Fund, including refunds from natural gas suppliers to the local distribution company, expansion surcharges, and other resources, and then, with approval by the public utilities commission, the company may pay for the specified distribution pipeline construction projects.305 In 2011, the Vermont Public Service Board approved a plan by Vermont Gas Systems to use $17.6 million previously planned for ratepayer refunds to instead support expansion of its distribution network over four years, although these funds will cover only part of the needed finance.306 This plan transferred some of the costs of expansion onto existing customers and offered the reduction of statewide greenhouse gas emissions as one rationale.307 A 2012 law passed by the Maine Legislature authorizes the Finance Authority of Maine to issue up to $275 million in loans and $55 million in bonds for natural gas distribution system expansions. The funds will be available only if the applicant contributes at least 25 percent of the expected cost of the project.308 Municipal utilities can also offer innovative solutions. For example, the municipal natural gas utility in Sunrise, Florida, will install main and service lines to neighborhoods at no cost as long as 25 percent of residents commit to installing a natural gas space or water heater, range, or clothes dryer within six months. Natural gas piping within the homes must be paid for by residents.309
Other innovative policy mechanisms are being developed to pay to upgrade and replace existing pipelines. Some states, such as Colorado, authorize tracker mechanisms allowing rates to change in response to the utility’s operating costs and conditions outside of a complex rate case proceeding, specifically in response to federal and state safety requirements. A similar process outside the rate case in states such as Kentucky permits temporary surcharges for partial program cost recovery. The Georgia Public Services Commission has permitted Atlanta Gas Light Company to institute a surcharge on customer bills throughout its service territory to help fund pipeline replacement, improvement, and pressure increases through the Georgia Strategic Infrastructure Development and Enhancement (STRIDE) Program. The Georgia Public Services Commission reviews the surcharge and related plans every three years, thereby eliminating the need for rate cases and associated regulatory lag. Also, from 2009 to 2012, a pilot program called the Customer Growth Program was paid for through the STRIDE surcharge. It helped fund new pipeline construction and extensions, including strategic development corridors to regions far removed from existing Atlanta Gas Light Company infrastructure. It also helped overcome the barrier of high upfront costs for new natural gas pipelines.310 However, the STRIDE program has not been renewed. The Atlanta Gas Light Company Universal Service Fund can also be used to pay for distribution pipeline expansion, and its monies may contribute up to 5 percent of Atlanta Gas Light Company’s capital budget during a fiscal year.
Beyond questions of funding, pipelines are affected by a number of project-specific requirements and regulations at the federal, state, and local levels. These requirements pertain to route selection, siting, and project approval by regulatory agencies that may all be affected by environmental, safety, community, operation, construction timing, and cost concerns. The size of the challenge for any individual project will vary significantly depending on the pipeline and the jurisdictions it crosses.311 For natural gas to realize its climate benefits, infrastructure projects must meet these requirements, allowing the system to expand for greater low-emission use across the economy.
Natural gas is transported from areas of production to final consumers through networks of gathering pipelines, transmission pipelines, and distribution pipelines. These extensive networks are necessary to provide opportunities for low-emission end uses of natural gas. Given the recent surge in natural gas supply, the new source regions, and new uses, infrastructure must rapidly adapt. Gathering pipelines must be brought to more points of production, including areas where associated gas can be captured for use. Transmission pipelines must be expanded to ensure adequate supply can reach new regions of the country. Distribution pipeline networks must be built out to serve more manufacturing facilities, homes, and businesses. Increased policy support and innovative funding, particularly for distribution pipelines, are needed to support the rapid deployment of this infrastructure.
Natural gas plays a role in all sectors of the U.S. economy, constituting 27 percent of total U.S. energy use in 2012. Its prominence is expected to grow as the supply boom unleashed by new drilling technologies continues in coming decades. Expectations of sustained abundance and correspondingly low and relatively stable natural gas prices are sparking widespread interest in additional ways that this domestic energy resource can replace oil and coal as the major fuel undergirding a growing economy. Indeed, natural gas is projected to displace petroleum as the dominant fuel used in the United States within a few decades.
In these early days of this energy transition, it is imperative to set a course for using this increasingly abundant domestic resource in ways that help meet, rather than aggravate, the challenge of climate change. This report examines ways that natural gas can be leveraged to reduce greenhouse gas emissions across a growing economy and reaches three crosscutting conclusions.
First, substitution of natural gas for other fossil fuels can contribute to U.S. efforts to reduce greenhouse gas emissions in the near to mid-term, even as the economy grows. At the beginning of 2013, energy sector emissions are at the lowest levels since 1994, in part because of the substitution of natural gas for coal in the power sector. Substitution of natural gas for coal, petroleum, and grid-supplied electricity is underway in other parts of the economy and will bring similar benefits to the climate and air quality. In the buildings sector, for example, a large reduction in emissions is possible through greater direct use of natural gas in an array of more efficient appliances and expanded use of CHP. The manufacturing sector also has a significant opportunity to reduce emissions even as it expands. Manufacturers can increase their consumption of natural gas as feedstock and an energy source, while reducing the emissions intensity of production. Finally, in the transportation sector, natural gas fuel substitution can reduce greenhouse gas emissions when used in fleets and heavy-duty vehicles.
Second, in the long term, the United States cannot achieve the reduction in greenhouse gas emissions necessary to address the serious challenge of climate change by relying on fuel substitution to natural gas alone. Low-carbon investment must be dramatically expanded. Zero-emission sources of energy such as wind, nuclear, and solar are critical, as are the use of carbon capture and storage technologies at fossil fuel plants and continued improvements in energy efficiency. Given that many renewable energy sources are intermittent, natural gas can serve as a complementary and reliable backup. In addition, because fossil fuels will likely be part of the energy fuel mix for the foreseeable future, carbon capture and storage will need to be deployed. Without a price on carbon emissions, alternative policy support will be needed to ensure optimal investment in zero-carbon energy sources and technologies.
Third, direct releases of methane into the atmosphere must be minimized. The primary component of natural gas is methane, which is a very potent greenhouse gas. Total methane emissions from natural gas systems in the United States have improved during the last two decades, declining 13 percent from 1990 to 2011. Nevertheless, given its impact on the climate, especially in the short term, it is important to better understand and more accurately measure the greenhouse gas emissions from natural gas production and use in order to achieve emissions reductions along the entire natural gas value chain.
The basis for these cross-cutting conclusions is a detailed examination of the current and potential role of natural gas in major sectors of the economy. Sector-specific conclusions and recommendations include:
Expanded use of natural gas has improved fuel diversity in the power sector. From 2003 to 2012, the share of primary energy consumption from coal for electricity generation dropped from 53 percent to 37 percent, while the share fulfilled by natural gas grew from 14 percent to 29 percent. Accordingly, the fuel mix in electricity generation has become more diverse in recent years. However, concern exists that some regions may become too dependent upon natural gas in the long term, especially as market pressures affect nuclear and renewable energy generation. Too much reliance on any one fuel can expose utilities, ratepayers, and the economy to the risks associated with commodity price volatility. Furthermore, natural gas-fired generation should not displace investment in zero-carbon generation, carbon capture and storage, and energy efficiency measures. If this occurs, the United States will not be able to meet its long-term goals for reducing greenhouse gas emissions.
Natural gas can be complementary with renewable energy. Instead of being thought of as competitors, natural gas and renewable energy sources such as wind and solar can be complementary components of the power sector. Natural gas plants have the ability to quickly scale up or down their electricity production and so can act as an effective hedge against the intermittency of renewables. The fixed fuel price (at zero) of renewables can likewise act as a hedge against potential natural gas price volatility. Low natural gas prices can also help facilitate an increase in renewable energy in some regions. In order for this mutually beneficial relationship to flourish, carefully designed policy that allows the addition of both sources to the grid in a complementary fashion must come into play and be encouraged by public utility commissions. Natural gas plants expansion should be leveraged to enable the expansion of renewable generation.
Natural gas can increase the overall efficiency of buildings through use of equipment with higher full-fuel-cycle efficiency. Thermal applications of natural gas in buildings have a lower greenhouse gas emission footprint compared with other fossil energy sources. Natural gas for thermal applications is more efficient than grid-delivered electricity, yielding less energy losses along the supply chain and therefore fewer greenhouse gas emissions. Information and incentives should be modified to inform consumers of the environmental benefits of natural gas use and to encourage its increased use when it has the potential to reduce greenhouse gas emissions—particularly its direct use in buildings and manufacturing settings. At present, labeling, building codes, and economic incentives are not aligned to maximize the use of natural gas in low-emitting ways.
Aligning incentives is particularly important in the building sector, as consumers and developers seeking to minimize up-front cost often do not realize that operating costs and environmental costs may be much higher for electric appliances. In addition, although current energy efficiency programs aim to reduce greenhouse gas emissions from appliances and buildings in two important ways—by setting standards and efficiency labeling programs—these standards are based solely on site efficiency, which is reflected in the energy and cost savings identified on efficiency labels. But efficiency labels based only on site efficiency do little to educate consumers about the total energy needed to power appliances and the greenhouse gases associated with that energy and, as such, often steer consumers toward electric appliances even if a natural gas appliance may be more efficient overall and produce fewer greenhouse gas emissions. It is important, therefore, that the source-to-site efficiency of an appliance also be taken into consideration, and in regions with fossil fuel-dominated grid electricity, natural gas appliances should be encouraged.
The efficient use of natural gas in the manufacturing sector needs to be encouraged. Replacing old coal-fired boilers with more efficient natural gas boilers can yield significant emissions benefits. CHP systems should also be deployed to make use of waste heat and avoid transmission losses. The incentives for CHP are often not properly aligned. Specifically, while CHP has significant environmental benefits, it can significantly decrease the demand for grid-supplied electricity, which can impact the rate base remaining on the grid. Policies are needed to overcome this and other barriers to expanded CHP deployment. States are in an excellent position to take an active role in promoting CHP during required industrial boiler upgrades and new standards for cleaner electricity generation in coming years.
Distributed generation technologies can offer options for using natural gas and reducing emissions. Distributed generation technologies, such as microgrids, microturbines, and fuel cells, can be used in configurations that reduce greenhouse gas emissions when compared with the centralized power system because they can reduce transmission losses and use waste heat onsite. Distributed generation has many other advantages over centralized electricity generation, including end-users’ access to waste heat, easier integration of renewable energy, heightened reliability of the electricity system, reduced peaking power requirements, and less vulnerability to terrorism due to more geographically dispersed, smaller power plants. To realize the potential of these technologies and overcome high upfront equipment and installation costs, policies like financial incentives and tax credits need to be more widespread, along with consumer education about their availability.
Fuel substitution in fleets and heavy-duty vehicles offers the greatest opportunity to reduce greenhouse gas emissions in the transportation sector. Passenger vehicles, in contrast, likely represent a much smaller emission reduction opportunity even though natural gas emits fewer greenhouse gases than gasoline or diesel when combusted. The reasons for this include the smaller emission reduction benefit (compared to coal conversions), and the time it will take for a public infrastructure transition. By the time a passenger fleet conversion to natural gas could be completed, a new conversion to an even lower-carbon system, like fuel cells or electric vehicles, will be required to ensure significant emissions reductions throughout the economy.
Natural gas infrastructure expansion is needed to ensure access for low-emitting uses. New domestic supplies of natural gas require significant investment in infrastructure. Additional gathering and transmission pipeline capacity is needed in parts of the country that have not historically produced natural gas but have been traditional destinations, such as Ohio, Pennsylvania, North Dakota, and West Virginia. Expanded distribution pipeline networks are needed to serve greater numbers of commercial, industrial, and residential natural gas customers throughout the U.S. Moreover, expanding natural gas delivery systems within homes and businesses that have existing access will be necessary to support a greater number of end-use applications, such as natural gas-fueled space and water heating. Innovative funding models and support are needed to make the expansion and upgrading of natural gas infrastructure economically feasible for customers and utilities.
In the coming years, abundant natural gas will play an increasingly prominent role across all sectors of the U.S. economy. Increased availability of natural gas can yield economic opportunities and lower greenhouse gas emissions. Yet, natural gas is not carbon-free. A future with expanded natural gas use will require diligence to ensure that potential benefits to the climate are achieved.
Note: EIA’s estimated technically recoverable resource of U.S. shale gas was reduced from 827 Tcf in 2010 to 482 Tcf in 2011. The decline mostly reflects changes in the assessment for the Marcellus shale, from 410 Tcf to 141 Tcf, based on better data provided from the rapid growth in drilling in the Marcellus over the past two years.
Note: In addition to the Barnett, since 2005 producers have begun intensively developing plays in the Woodford, north of the Barnett in Texas and Oklahoma; the Fayetteville in Arkansas; and the Haynesville in Louisiana/East Texas. During this time, development also began in the Marcellus Shale of the eastern United States.
Note: Natural gas and natural gas liquids are a principal feedstock in the chemicals industry and a growing source of hydrogen production for petroleum refining. Natural gas liquids products can add value for gas producers, especially important in a low-price environment. The liquid content of a gas—the “condensate ratio”—is expressed as barrels of liquid per million cubic feet of gas (bbls/MMcf). In a typical Marcellus well, assuming a liquids price of $80/bbl for a condensate ratio in excess of approximately 50 bbls/MMcf, the liquid production alone can provide an adequate return on the investment, even if the gas were to realize no market value.
This report provides an overview of natural gas production, the climate implications of expanded natural gas use, potential uses and benefits in key sectors, and related infrastructure issues.
The Center for Climate and Energy Solutions (C2ES) is an independent non-profit, non-partisan organization promoting strong policy and action to address the twin challenges of energy and climate change. Launched in 2011, C2ES is the successsor to the Pew Center on Global Climate Change.