Energy & Technology
- Natural gas plays an important role in nearly every sector of the U.S. economy, constituting 27 percent of primary energy consumption (second only to oil) and slightly more than 27 percent of electricity generation in 2013.
- Combustion of natural gas emits about half as much carbon dioxide as coal and 30 percent less than oil, and far fewer pollutants, per unit of energy delivered.
- Natural gas combustion is responsible for approximately 21 percent of U.S. greenhouse gas emissions annually; venting and other fugitive methane releases from natural gas systems produced around 2 percent of total emissions.
- Globally, natural gas combustion accounted for 20.2 percent of the world’s CO2 emissions from fossil fuels in 2011.
- The United States has enough natural gas to last nearly 85 years at current consumption rates (about 26.0 trillion cubic feet (Tcf) per year); the U.S. Energy Information Administration estimates technically recoverable reserves in excess of 2,200 Tcf.
Figure 1. Geological Formations Bearing Natural Gas
Natural gas is a naturally occurring fossil fuel consisting primarily of methane and small amounts of impurities such as carbon dioxide. It may also contain heavier liquids (also known as natural gas liquids) that can be processed into valuable byproducts including ethane, propane, butane and pentane. As illustrated in the above graphic, natural gas is found in several different types of geologic formations. Historically, natural gas has been conventionally extracted from large reservoirs and often produced in conjunction with oil. Technological advances in the areas of horizontal drilling and hydraulic fracturing have made it easier and cheaper to obtain gas from smaller unconventional sources including non-porous sand (tight sands), coal seams (coal bed methane) and most recently from very fine grained sedimentary rock called shale (shale gas), known in the industry as shale plays.
Shale gas extraction 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, together referred to as hydraulic fluid, is then injected into the well to increase pressure and break apart the shale so that the gas is released. This technique is known as hydraulic fracturing or “fracking.”
An assessment of 137 shale gas basins in 41 countries suggest that shale gas resources, which have recently provided a major boost to U.S. natural gas production, are also available in other world regions. The 2013 study reported 6.634 Tcf of technically recoverable shale gas resources in 41 foreign countries, compared with 665 Tcf in the United States.
Figure 2. Global Natural Gas Basins
Natural gas is used extensively in the United States, for generating electricity, for space and water heating in residential and commercial buildings, and as industrial feedstock, providing the base ingredient for such varied products as plastic, fertilizer, anti-freeze and fabrics.
Figure 3. U.S. Natural Gas Consumption by Sector
In the residential buildings sector, almost 95 percent of natural gas is used for space and water heating, with cooking and clothes drying making up the remainder. In the commercial buildings sector, space and water heating comprise the majority of natural gas use (63 percent), but other uses – including cogeneration (the use of natural gas to generate electricity and useful heat), also known as combined heat and power – compose one-third of natural gas usage. Chemicals and petroleum products, which includes refining, account for the largest shares of natural gas consumption in energy industries.
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Compared to other fossil fuels, natural gas is considered relatively “clean” because when it is burned it releases fewer harmful pollutants. Compared to coal or oil, natural gas combustion releases smaller quantities of particulate matter, nitrogen oxides, and sulfur dioxide. The combustion of natural gas also emits about half as much carbon dioxide as coal. However, methane itself is a potent GHG, more than 20 times more powerful in terms of its heat-trapping ability than CO2, though it is shorter lived in the atmosphere. Sources of methane emissions include landfills and coal mines as well as digestion by cows and other ruminant animals. Emissions from equipment leaks, process venting and disposal of waste gas streams are known as fugitive emissions.
Table 1: Fossil Fuel Emissions Levels (Pounds per Billion Btu of Energy Input)
Source: U.S. Energy Information Administration, Natural Gas Issues and Trends (1998)
Currently, natural gas combustion-related emissions account for about 21 percent of total U.S. greenhouse gas emissions, while fugitive methane releases from natural gas systems (production, processing, transmission, storage, and distribution) represent 2 percent of the total. Globally, natural gas combustion accounted for 20.2 percent of the world’s CO2 emissions in 2011.
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Since 2000, U.S. proved reserves of natural gas have increased more than 80 percent, driven mostly by shale gas advancements. As a result, in 2013 the United States had the fourth largest proved reserves of natural gas in the world, at 308 Tcf. Russia had the largest reserves at 1,688 Tcf, followed by Iran at 1,187 Tcf, and Qatar at 890 Tcf.
As at the end of 2012, the Potential Gas Committee estimated that the total assessed U.S. shale gas resource was 1,073 Tcf. This represented approximately 48 percent of the United States' total traditional gas resource of 2,225 Tcf. Total technically recoverable resources, which also include coalbed gas resource of 158 Tcf, were 2,384 Tcf. This represents an increase of around 25 percent from the previous assessment in 2010.
Natural Gas Production
Total domestic dry natural gas production in 2013 was 24.3 Tcf. This figure represents the remainder from a total gross withdrawal of 30.2 Tcf of product, after venting and flaring, removal of non-hydrocarbon gases such as CO2, removal of natural gas liquids and other losses. From 2007 to 2012, shale gas production grew at an annual rate of nearly 52 percent. Natural gas is produced in 33 states and in the Gulf of Mexico. According to the EIA, Texas, the Gulf of Mexico, Pennsylvania, Wyoming, Louisiana, Oklahoma, Colorado and New Mexico account for 83.3 percent of U.S. production in 2012. The geography of U.S. natural gas production is changing with an increasing percentage of production coming from other states like Pennsylvania and Arkansas. From 2010 to 2012, natural gas production increased fourfold in Pennsylvania; the state was responsible for more than 9 percent of U.S. production in 2012.
Development of fracking technology has created the present boom in natural gas production. This technology was initially funded in the 1970s through the U.S. Department of Energy and with more than 20 years of federal tax credits (1980 – 2002).
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Figure 4. U.S. Shale Plays
The U.S. natural gas pipeline network is a highly integrated transmission and distribution grid that can transport natural gas to and from nearly any location in the contiguous 48 states. Interstate and intrastate pipelines deliver natural gas to local distribution companies, directly to some large industrial end users and electricity generators, and to interconnections with other pipelines. The network consists of more than 210 pipeline systems with nearly 306,000 miles of pipe, and 1,400 compressor stations that maintain network pressure and assure continuous forward movement of supplies. To support the seasonal peaking demand of natural gas, there are 414 underground natural gas storage facilities in the pipeline network for additional winter heating demand. There are three types of underground storage facilities: depleted natural gas or oil fields, aquifers and salt caverns. Additionally, there are 49 locations where natural gas can be imported or exported at the Canadian and Mexican borders. In response to earlier expectations of natural gas import needs, there are eight liquefied natural gas (LNG) import facilities in the United States, which are now underused. With the recent increase in domestic natural gas production, the U.S. Federal Energy Regulatory Commission (FERC) has authorized three export terminals. One terminal in Sabine, LA is under construction and is expected to begin operations before 2017, while the others in Hackberry, LA and Freeport, TX are not yet under construction. There are dozens of other proposed and potential terminals that are in various stages of the permitting process.
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Natural gas consumption made up a little more than 24 percent of total global energy use in 2013. The EIA estimated that world natural gas demand climbed to 120 Tcf in 2012, up 3.1 percent from 2011. According to the International Energy Agency, electric power generation remains the main driver behind global natural gas demand growth.
Natural gas use constituted about 27 percent of total U.S. primary energy consumption in 2013. Total U.S. natural gas consumption grew from 23.3 Tcf in 2000 to 26.0 Tcf in 2013. A decline in annual consumption in the industrial sector during this earlier portion of this period has almost been erased, while growth in the electric power sector continues - this sector grew at an annual average rate of 3.5 percent.
Figure 5. U.S. Natural Gas Consumption by Sector, 2000 – 2013 (Tcf)
In 2013, natural gas fueled 27.4 percent of total U.S. electricity generation. From 2000 to 2013, natural gas electricity generation grew at a faster rate than total electricity generation (4.9 percent per year versus 0.5 percent per year). This growth can be attributed to a number of factors, including low natural gas prices in the early part of the decade. Additionally, gas-fired plants are relatively easy to construct, have lower emissions compared to other fossil fuels, and have lower capital costs and shorter construction times compared to coal power plants. More information about natural gas fired electricity generation can be found on the Center’s Natural Gas Techbook page.
The market for natural gas is similar to other commodities. Generally, when demand goes up, producers respond with increased exploration, drilling and production. However, significant supply increases do not happen overnight. It takes time to study the geology, acquire leases, drill wells and connect to pipelines (or build new pipelines). This expansion can take many months or years. As a result, there is often a lag in bringing new supply to market, which can cause price volatility and spikes. Conversely, oversupply (or expectations of low price), result in less exploration. Even with a lower price, many producers are reluctant to halt extraction due to the geologic characteristics of wells that make it difficult to stop and restart production. In addition, since gas is often produced along with oil or natural gas liquids, stopping the flow of natural gas means stopping the flow of oil and natural gas liquids, which may not make financial sense. Another market driver is that gas is often sold on a contractual basis, and a producer may be legally bound to produce a specific quantity of natural gas.
Natural gas markets across the world are segmented, that is, natural gas pipeline systems connect distinct regions of the world, for example, the United States is connected to Canada and Mexico while the United Kingdom is connected to the North Sea and Europe. Natural gas prices are determined within these regional markets based on the available regional supply and demand patterns. A general upward trend in world natural gas prices began in the early 2000s as demand for the product began to exceed supply. Following the global recession of 2008 – 2009 a fairly wide spread in world natural gas prices developed (Figure 6).
Figure 6: World Natural Gas Prices (USD/MMBtu)
Prices in the U.S. and Canadian markets have plummeted due to the abundant supply of North American shale gas. Asian markets have seen higher gas prices due to increasing demand in China, South Korea and Japan. Europe has also seen higher prices as a result of increased demand as well as periodic Russian supply disruptions from 2005 – 2009.
Supply and demand responses, the seasonal nature of demand (residential winter heating or summer cooling through increased electric power generation requirements), or cold weather and hurricane-driven supply disruptions, have all contributed to natural gas price volatility in the United States in the last decade (Figure 7). In 2001, several years of declining productive capacity and increasing demand resulted in a sharp winter price spike. Prices spiked again in 2005 in the wake of hurricanes Rita and Katrina, which temporarily curtailed supplies from the Gulf of Mexico. Prices remained high relative to historic norms, peaking along with other energy commodities in 2008. Since then, average annual wellhead prices in the U.S. have gone down. Two factors – an abundance of shale gas and the slow pace of economic recovery following the recession – have contributed to sustained low prices.
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Figure 7: U.S. Natural Gas Monthly Average Wellhead Prices (USD/MMBtu)
While most of the world’s gas supply is transported regionally via pipeline, global gas trade has accelerated with the growing use of liquefied natural gas. To maximize the quantity of natural gas that can be transported, the gas is liquefied at an export facility. First, the liquefaction process involves the removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons. Then, the natural gas is condensed into a liquid by cooling it to approximately -162°C (-260 °F). Liquefied natural gas (LNG) takes up 1/600th the volume of natural gas in the gaseous state. Once liquefied, the LNG can be transported by tanker and regasified for use in other markets at an LNG import terminal. Between 2005 and 2011, the liquefied natural gas market grew by more than 70 percent, but the volume of LNG trade has been relatively flat for the past 3 years (2011 to 2013) at around 240 million metric tons (MT) (approximately 11 Tcf). In 2013, Japan was responsible for 37 percent of global LNG imports; its nuclear fleet has been temporarily shutdown as a result of the Fukushima disaster, and it is relying much more heavily on natural gas for its energy consumption. Global gas liquefaction capacity was 290.7 MT in 2013, and is expected to increase more than 100 MT by 2018 with Australia adding 62 MT and poised to become the world's largest exporter.
With surplus domestic supply and substantially higher prices in other regional markets, several U.S. companies have applied to the relevant agencies for permission to export liquefied natural gas with Houston-based Cheniere Energy being the first company to win approval for its Sabine Pass facility in 2012, followed by Freeport LNG and Cameron LNG.
Prospects for U.S. liquefied natural gas exports depend significantly on the cost-competitiveness of U.S. liquefaction projects relative to those at other locations. Over much of the last decade, lower supply expectations and higher, volatile prices prompted new investments in U.S. natural gas import and storage infrastructure. Since 2000, North America’s import capacity has expanded from approximately 2.3 Bcf/day to 22.7 Bcf/day, around 35 percent of the United States’ average daily requirement. Yet as of 2009, U.S. consumption of imported liquefied natural gas was less than 0.3 Bcf/day, leaving most of this capacity unused. The ability to use and repurpose existing U.S. import infrastructure—pipelines, processing plants, storage and loading facilities—will help reduce total costs relative to new facilities. While liquefied natural gas makes up a small portion of U.S. imports, it is important in other parts of the world. The majority of the gas trade in the Asia Pacific region is in the form of LNG imports to Japan, South Korea, China, India and Taiwan from Qatar, Malaysia, Australia, and Indonesia (Figure 8).
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Figure 8: Major International Natural Gas Trade Flows (Billion Cubic Meters)
According to the EIA’s International Energy Outlook, natural gas is expected to be the world’s fastest growing fossil fuel, with consumption increasing at an average rate of 1.5 percent per year to 2040. Growth in natural gas is expected to occur in every region and is most concentrated in developing countries, where demand increases more than twice as fast as in developed countries.
In the United States, shale gas production is expected to more than double over the next 25 years (Figure 9), and production of natural gas is expected to exceed consumption before 2020. As a consequence, the EIA in its 2014 Annual Energy Outlook Reference Scenario expects U.S. natural gas prices to remain below $5/MMBtu through at least the early 2020s.
Figure 9. U.S. Natural Gas Production, 1990 – 2040 (Tcf)
The forecast of an abundance of domestic natural gas, coupled with recent regulatory actions taken by the U.S. Environmental Protection Agency (EPA) with regard to the electric power sector (Mercury rule, Cross-State Air Pollution Rule, and New Source Performance Standard for CO2 from new power plants) have led to natural gas becoming the dominant choice for planned electricity generating capacity. Moreover, the abundance of natural gas has somewhat mitigated industrial concerns about using the fuel as a feedstock to manufacture products such as plastics and fertilizers.
The rapid growth of shale gas has also increased scrutiny of the potential environmental and health effects of hydraulic fracturing. As a result, several states have taken action either to regulate hydraulic fracturing or to issue a temporary moratorium while they explore the issue further. In addition to state action, the U.S. Department of Interior proposed new rules for regulating natural gas drilling on federal lands in 2012, and the EPA has undertaken a Hydraulic Fracturing Study Plan to study the relationship between hydraulic fracturing and drinking water.
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- Natural Gas Initiative:
- Climate Techbook: Natural Gas.
- Bluestein, Joel (2008). Coverage of Natural Gas Emissions & Flows Under a GHG Cap-and-Trade Program, Pew Center on Global Climate Change.
- Claussen, Eileen. Climate Policy and Natural Gas: A Bridge to a Lower GHG Future. 2008 October 6. American Gas Association Executive Conference.
- BP’s Statistical Review of World Energy 2011
- Shell’s Natural Gas
- BPC’s Task Force on Ensuring Stable Natural Gas Markets. 2011 March 22.
- Ratner, Michael. Global Natural Gas: A Growing Resource. Congressional Research Service (CRS). R41543. 2010 December 22.
- EIA’s Natural Gas Overview
- FracFocus Chemical Disclosure Registry
- RFF’s Abundant Shale Gas Resources: Long-Term Implications for U.S. Natural Gas Markets. RFF Discussion Paper 10-41. 2010 August.
- IEA’s Natural Gas Overview
- MIT’s The Future of Natural Gas. 2011 July.
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I recently responded to a question on the National Journal blog, "Should Congress extend the production tax credit for wind energy or let it expire at year's end?"
Innovative financing program helps South Carolina homeowners save money through energy efficiency retrofits
An innovative energy-financing program has helped customers of South Carolina rural electric cooperatives to undertake energy efficiency retrofits for their homes, substantially reducing their energy use and saving money.
Through on-bill financing (OBF), customers pay back the cost of the retrofit through monthly installments on their electricity bill. This strategy helps to expand access to costly energy retrofits to low-income residents and makes the financial benefits immediately apparent. If monthly energy savings are greater than or equal to the loan repayment, then OBF will be “bill neutral” and result in the same or lower monthly electricity bills . In addition, the financial obligation of OBF is tied to the electricity meter of each house and can be passed on to subsequent owners and residents; thus, customers only pay for the energy retrofits for as long as they live there.
A preliminary review of South Carolina’s pilot program, called “Help my House,” found that the 125 participating households are projected to save an average of $400 each year after loan repayments. Energy use could be reduced by thirty-five percent, or approximately 11,000 kilowatt-hours each year. The retrofits, which included improvements to insulation, sealing, and heating, ventilation, and air-conditioning (HVAC) systems, cost an average of $7,200, with projected simple payback periods of 5.86 years. In addition, ninety-six percent of participants reported satisfaction with the efficiency installations and rated their homes as more comfortable after the retrofit.
The program was launched in 2011 by the Central Electric Power Cooperative, which supplies wholesale electricity to 20 rural South Carolina electric cooperatives, and the Electric Cooperatives of South Carolina, the co-ops’ marketing and policy partner, with support from the Environmental and Energy Study Institute. A full-scale OBF energy-efficiency program implemented by South Carolina cooperatives could save an estimated $270 million per year in electricity costs and create more than 7,000 jobs after 20 years, according to an analysis by Coastal Carolina University.
South Carolina utilities were authorized to offer OBF through the passage of Senate Bill 1096 in 2010. The bill eliminated the need for credit checks by tying the financial obligation to the meter rather than to the individual borrower, and allowed utilities to disconnect power if loan repayments are not made. Utilities in 22 other states offer OBF, with supporting state legislation in Illinois, Hawaii, Oregon, California, Kentucky, Georgia, Michigan, and New York.
In addition, “Help my House” was funded by a $740,000 loan from the U.S. Department of Agriculture’s (USDA) Rural Utility Service (RUS), which supports the development of electric, water, and telecommunications services in rural regions. This was the first time RUS funded an energy efficiency initiative, but more cooperatives around the country may follow South Carolina’s example. On July 17 USDA proposed a rule that would create a new RUS program to provide up to $250 million in loans for energy efficiency improvements. The proposed Energy Efficiency and Conservation Loan Program would allow rural electric cooperatives to provide energy efficiency retrofits, including those funded by OBF programs, audits, renewable energy systems, and more.
For more information:
Help My House Pilot Program – Summary Report
Environmental and Energy Study Institute – Fact Sheet
Thirteen percent of Americans say they follow science; 65 percent say they follow sports.
Representatives of Major League Baseball, the National Football League, the National Hockey League and NASCAR gathered at the White House yesterday for a half-day conference on “Greening the Games.” The panelists talked about the fact that sports stadiums and arenas across the United States are cultural icons – think Fenway Park, Wrigley Field, the Superdome – and that they offer an extraordinary opportunity for an education in sustainability.
I recently responded to a question on the National Journal blog, "Does climate change cause extreme weather like the heat waves much of the country has been enduring for the past few weeks?"
Below are the comments C2ES submitted on June 25, 2012, on EPA's proposed greenhouse gas emissions standard for new power plants.
Comments of the Center for Climate and Energy Solutions on
Standards of Performance for Greenhouse Gas Emissions for
New Stationary Sources: Electric Utility Generating Units;
United States Environmental Protection Agency
(77 Fed. Reg. 22392 (April 13, 2012))
Docket ID No. EPA-HQ-OAR-2011-0660; FRL-9654-7
This document constitutes the comments of the Center for Climate and Energy Solutions (C2ES) on the proposed standards of performance for greenhouse gas (GHG) emissions for new electric utility generating units (Proposal), proposed by the U.S. Environmental Protection Agency (EPA) and published in the Federal Register on April 13, 2012. C2ES is an independent nonprofit, nonpartisan organization dedicated to advancing practical and effective policies and actions to address our global climate change and energy challenges. As such, the views expressed here are those of C2ES alone and do not necessarily reflect the views of members of the C2ES Business Environmental Leadership Council (BELC). In addition, the comments made in this document pertain to new sources in the specific industrial sector addressed by the Proposal and may not be appropriate for other industrial sectors or for existing electric utility generating units.
Preference for Market-based Policy
C2ES believes market-based policies—such as emissions averaging among companies, a cap-and-trade system, an emissions tax, or a clean energy standard with tradable credits – would be the most efficient and effective way of reducing GHG emissions and spurring clean energy development and deployment. Properly-designed market-based policies create an appropriate division of labor in addressing climate change, with the law establishing the overarching goal of reducing GHG emissions, and private industry determining how best to achieve that goal. Under market-based policies, the government neither specifies a given company’s emission level nor requires the use of any given technology—both of these questions are determined by the company itself.
Beyond providing an incentive for the use of best available technologies, market-based policies provide a direct financial incentive for inventors and investors to develop and deploy lower-cost, clean energy technologies, and leave the private market to determine technology winners and losers. Market-based policies can be designed to minimize transition costs for companies and their customers in moving from high-emitting technologies to low-emitting technologies; to prevent manufacturers in countries without GHG limits from using this as a competitive advantage over U.S. manufacturers; and to reverse any regressive impacts of increased energy prices. At the federal level, market-based policies have been used to reduce sulfur dioxide emissions at a fraction of the originally estimated cost, while at the state level they have been used successfully in renewable energy programs and cap-and-trade programs.
However, enactment of federal legislation that would establish a comprehensive market-based policy to reduce GHG emissions does not appear imminent. Given the urgency of addressing the rising risks that climate change poses to U.S. economic, environmental and security interests, C2ES believes that in the absence of Congressional action to reduce greenhouse gas emissions, EPA must proceed using its existing authorities under the Clean Air Act.
The Context of the Proposal
The Proposal is consistent with the EPA’s authority to implement the Clean Air Act, as interpreted by the U.S. Supreme Court. On April 2, 2007, in the case of Massachusetts v. EPA, the court found that the harms associated with climate change are serious and well recognized, the EPA has the authority to regulate CO2 and other GHGs under the existing Clean Air Act, and, although enacting regulations may not by itself reverse global warming, that is not a reason for EPA not to act in order to “slow or reduce” global warming.
The Court required that the EPA determine whether GHG emissions from new motor vehicles cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare. The EPA released a draft Technical Support Document (TSD) in 2008 that provided technical analysis of the potential risks of GHGs for human health and welfare and contribution of human activities to rising GHG concentrations, and adopted a final endangerment finding in December 2009. The finding explained and documented the determination that (1) the ambient concentration of six key GHGs—CO2, methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)—contribute to climate change, which results in a threat to the public health and welfare of current and future generations, and (2) emissions from motor vehicles contribute to the ambient concentration of the GHGs.
The EPA’s endangerment finding did not, by itself, impose any restrictions on any entities. It was, however, a required step in the EPA’s process of regulating GHG emissions. The EPA has already issued several requirements pertaining to GHG emissions—two as a consequence of the endangerment finding, and two in response to specific Congressional mandates regarding the reporting of GHG emissions.
Reporting CO2 emissions from power plants. Under section 821 of the Clean Air Act Amendments of 1990, the EPA requires power plants to monitor their CO2 emissions and report the data to the EPA, which makes the data available to the public. Under this provision, power plants have been reporting their CO2 emissions since the early 1990s, and the data have been made publicly available through the EPA’s website.
GHG Reporting Rule. As part of the Fiscal Year 2008 Consolidated Appropriations Act, signed into law in December 2007, the EPA was ordered to publish a rule requiring public reporting of GHG emissions from large sources. The GHG Reporting Program database was published for the first time in January 2012, and consisted of data reported under the rule.
Vehicle tailpipe standards. The first and most direct result of the Supreme Court’s ruling in Massachusetts V. EPA and the EPA’s subsequent endangerment finding was the EPA’s promulgation of GHG emissions standards for vehicles. In April 2010, the EPA and the U.S. Department of Transportation issued a joint regulation to establish new light-duty vehicle standards for Model Year (MY) 2012 to MY 2016; in August 2011, they issued the final rulemaking for heavy-duty vehicles for MY 2014-2018; and in November 2011, they issued a joint proposal for light-duty vehicle standards for MY 2017 to MY 2025.
New Source Review/Best Available Control Technology. Under the Clean Air Act, major new sources or major modifications to existing sources must employ technologies aimed at limiting air pollutants. Once GHGs were regulated as air pollutants through the vehicle tailpipe standard, the requirement that new or modified sources must use “best available control technology” (BACT) for GHGs also took effect. In November 2010, the EPA released guidance to be used by states in implementing BACT requirements for GHG emissions from major new or modified stationary sources of air pollution. Under the BACT guidance, covered facilities are generally required to use the most energy-efficient technologies available, rather than install particular pollution control technologies. More than a dozen facilities have received permits under the program.
The Proposal is the first GHG standard proposed by the EPA under the New Source Performance Standard provision of the Clean Air Act. Electric power plants account for about one-third of U.S. GHG emissions—nearly twice the contribution of light-duty vehicles.
Comments on the Proposal
C2ES has some concerns with the Proposal, as discussed below. If the concerns are adequately addressed, C2ES supports moving the rule forward.
The EPA should set the emissions standard at a level that can be reliably achieved by currently available technology under reasonably expected operating conditions.
The technology on which the standard in the Proposal is based is natural gas combined cycle (NGCC). It is imperative that the EPA set the GHG emissions standard at a level and in a form that can be reliably achieved by currently available NGCC technology under the full range of reasonably expected operating conditions. A recent study raises questions about the extent to which currently available NGCC units can reliably achieve the standard in the Proposal. In order to maximize the efficiency of the overall interconnected electric system – and often to minimize the overall GHG emissions – it is sometimes necessary to run a particular plant at less than peak efficiency. The standard should reflect this reality.
C2ES agrees that, as proposed, the standard should not cover simple cycle combustion turbines and biomass-fueled boilers.
The standard must be consistent with the advancement of carbon capture and storage technology.
Carbon capture and storage (CCS) is not one of the technologies on which the Proposal’s standard is based. Rather, CCS is a method by which a facility could potentially comply with the NGCC-based standard.
CCS operations have been built at scale in other industrial sectors, but not yet in the electricity sector. The first commercial-scale U.S. power plant with CCS is currently under construction. Power companies are planning several additional CCS projects, some of which will be in conjunction with enhanced oil recovery (EOR). CCS power projects that would supply captured CO2 to EOR are in the planning stages in Texas, Mississippi, California, North Dakota, and Kentucky for the 2014—2020 timeframe. Several more power companies have had plans to build CCS operations that did not go forward primarily because of the cost of CCS and the uncertainty with respect to CO2 emission regulation and legislation.
The Proposal offers an alternative compliance mechanism in which a coal power plant could be operated for 10 years without CCS, followed by 20 years with CCS. While the standard and the alternative compliance mechanism could make it easier for public utility commissions to approve proposals to build coal power plants with CCS, given the current cost and limited demonstration and deployment of CCS technologies, these alone may not be enough to surmount the challenge of financing a plant with CCS. (Please see the discussion of CCS under “Related Matters” below.)
More concerning is the possibility that the standard could inadvertently inhibit the advancement of CCS. For example, one intermediate step in demonstrating the compatibility of CCS with large-scale electricity generation might be to capture and sequester only a fraction of the CO2 from a large coal plant – which might not be allowed under the Proposal. C2ES suggests that the EPA consider mechanisms by which CCS demonstration projects and other operations important to the advancement of CCS could go forward.
Given the unique circumstances of electricity generation today, it is on balance appropriate to set a standard that does not differentiate between fuel types for new power plants. A non-differentiated standard may not, however, be appropriate for other industry sectors or existing sources in this sector.
Perhaps the most novel aspect of the Proposal is that it does not issue separate NSPS for coal and natural gas. Under the Clean Air Act, section 111(b)(2), the EPA “may distinguish among classes, types and sizes within categories of new sources for the purpose of establishing [NSPS] standards.” (Emphasis added.) It has in fact typically been the case that Clean Air Act regulations have established separate air pollution standards for coal- and natural gas-fired power plants. While this differentiation is authorized, however, it is not required by the Clean Air Act. Because the proposed rule would apply to new units only, and because prospective owners have options in selecting the designs of their units, fuel switching (i.e., replacing coal use at existing plants with natural gas) would not be required by the rule.
Moreover, recent developments having nothing to do with GHG regulation, such as the availability of inexpensive natural gas and the regulation of other pollutants, have created conditions under which the GHG emissions intensity of electricity generation is declining. Aside from a small number of facilities far along in the planning process and specifically exempt from the Proposal, no new construction of conventional coal plants is currently foreseen at recent forward market natural gas prices through 2020 (when the Clean Air Act requires that the rule be reevaluated). The Proposal reflects the projections of independent analysts with regard to the future of new coal and natural gas electricity generation. For this reason, the Office of Management and Budget estimates that there will be no cost for industry compliance with the Proposal as compared with the status quo.
That said, it is important to recognize that widely fluctuating natural gas prices are a recent memory, and that, while the majority of independent analysts currently project an abundant and inexpensive supply of natural gas for decades to come, this forecast may prove wrong. Issuing a standard that in effect prohibits the construction of new high-emitting coal plants (i.e., those not using CCS) therefore poses risks – as would issuing a standard that allows the construction of such plants. If the construction of new high-emitting coal plants is effectively prohibited and natural gas prices rise higher than currently foreseen, electricity rates could face an upward pressure. On the other hand, allowing the construction of new high-emitting coal plants could lock in the emissions of those plants for decades to come, exacerbating the challenges the United States faces in reducing its GHG emissions and increasing the risks and costs of dangerous anthropogenic climate change.
On balance, C2ES believes the best choice in implementing the NSPS requirement for new power plants is to issue one standard, regardless of fuel type, but with a mechanism that allows for technological innovation (as discussed above). This should be accompanied by heavy federal investment in low-emitting technologies, including CCS, with the goal of maintaining a diverse set of energy sources in generating the nation’s electricity.
Finally, while the establishment of one emission standard regardless of fuel type may be appropriate with respect to new facilities in the power sector, it may not be appropriate for existing facilities in the power sector or for other sectors for which the EPA may issue regulations.
The United States needs a comprehensive energy strategy that delivers a diverse set of affordable low-emitting sources of electricity.
C2ES believes that as a matter of national policy and economic common sense, it is imperative to enhance energy diversity through programs that advance low-emitting uses of coal and natural gas; nuclear power; renewable energy; and efficiency in generation, transmission and end-use.
In particular, the United States needs an effective strategy for demonstrating CCS and making it inexpensive enough to use on future coal and natural gas power plants. Coal- and natural gas-fired generation will likely be predominant sources of electricity in the United States and most of world’s other major economies for decades to come. It will therefore be essential to advance CCS to the point that its use is economical in the context of electricity generation.
A CCS strategy should include a major research, development and demonstration effort, and subsidies to actively encourage the use of CCS with new and existing natural gas and coal power plants so that the technology can travel down the learning curve. C2ES strongly supports, among other measures, the federal grant programs that have allowed the construction of the previously-mentioned CCS projects. Another option is to establish a trust fund to support demonstration projects at commercial scale for a full range of systems applicable to U.S. power plants. CO2-enhanced oil recovery (CO2-EOR), a practice in which oil producers inject CO2 into wells to draw more oil to the surface, presents an important opportunity to advance CCS while boosting domestic oil production and reducing CO2 emissions. A coalition, co-convened by C2ES, has called for a federal tax credit for capture and pipeline projects to deliver CO2 from industrial and power plants to operating wells. (Note that the recommended tax credit is focused on plant and pipeline operators, rather than EOR operators.)
In addition to investing in CCS, it should be a national priority to invest in and otherwise advance a range of low-emitting energy technologies—for economic, as well as environmental, reasons. The diversity of energy sources used in electricity generation has been a valuable hedge against the unpredictable volatility of the various fuel sources, including natural gas. An electricity sector that increasingly relies on any single fuel would create unintended risks for our economy.
C2ES urges the EPA to move forward with the GHG NSPS for existing power plants, and to do so in a way that builds on existing state programs and allows states to use flexible market-based measures to implement the standards.
As mentioned, C2ES believes market-based policies would be the best way of reducing GHG emissions and spurring clean energy development and deployment. In the absence of a legislated solution, there appears to be an opportunity to utilize market-based policies in the regulation of GHG emissions from existing power plants.
Under section 111(d) of the Clean Air Act, the EPA, in concert with the states, is required to establish GHG emission standards for existing stationary sources—including existing power plants, which account for about one-third of U.S. GHG emissions today. The EPA has, in fact, entered into a settlement agreement under which it will implement section 111(d) for existing power plants. C2ES urges the EPA to move forward in implementing section 111(d) in a manner that can utilize market-based policies as soon as practicable.
Over the next few years, power plant owners will have to make billions of dollars’ worth of decisions about retrofitting, retiring, and replacing a large number of older, carbon-intensive coal plants in light of pending non-climate air, water, and waste regulations. Not knowing what GHG standards these existing facilities will have to meet presents facility owners with enormous uncertainty, greatly complicating and even delaying their decisions, ultimately at the expense of electricity rate payers. Because the Proposal addresses only new sources, this uncertainty pertains even to reconstruction or modification of existing sources. The Proposal mitigates some of the regulatory uncertainty faced by the power sector, but not all.
At the same time, several northeastern states already have an operational regional cap-and-trade program for CO2 from power plants (the Regional Greenhouse Gas Initiative), California is implementing an economy-wide GHG cap-and-trade program, and several states have renewable energy standards, alternative energy standards, or other programs that are effective in reducing the average GHG emission rate across all sources, as well as the overall level of GHG emissions.
C2ES strongly prefers that Congress establish a comprehensive, national market-based GHG reduction policy that would cover both new and existing sources and help to reduce this patchwork quilt of state and regional regulation. In the absence of such legislation, however, C2ES recommends that, in implementing section 111(d) for existing power plants, the EPA issue GHG emission rate-based performance standards in a manner that allows for averaging, banking and trading among sources, giving states the flexibility to adopt various market-based policies that will meet or outperform the standard.
3. Matthew J. Kotchen and Erin T. Mansur, “How Stringent is the EPA’s Proposed Carbon Pollution Standard for New Power Plants?” University of California Center for Energy and Environmental Economics, April 2012.
As Rio+20 negotiators rush to complete a consolidated text of outcomes before heads of state begin arriving tomorrow, participants at hundreds of side events are calling on business and government to take stronger action on clean energy, poverty elimination, food security, oceans, sustainable cities, green technology development, education, and more.
On Sunday at the U.S. Center pavilion, C2ES and the Global Environment Facility (GEF) convened a panel of companies, small-business innovators, and business representatives highlighting the critical roles played by each in promoting low-carbon innovation and sustainable development.
One of the centerpieces of this month’s Rio+20 summit is an important initiative called Sustainable Energy for All (SE4All). C2ES is pleased to be contributing to this initiative as a founding member of a new global partnership aimed at improving energy efficiency and curbing greenhouse gas emissions through the use of information and communication technologies.
Led by UN Secretary General Ban Ki-moon, SE4All recognizes the dual energy challenges facing the global community. We need to rapidly expand access to affordable energy for the 1.3 billion people who now lack even basic services, but do so in an environmentally sustainable manner that doesn’t put their health at risk or threaten the climate stability of our planet.
Opportunities for low-carbon innovation are growing, driven by policy changes, market shifts, and continued growth in energy demand, particularly in developing countries. This Sunday in Rio de Janeiro, ahead of the UN’s “Rio+20” Conference on Sustainable Development, C2ES will have a chance to share what it’s learned about low-carbon innovation with partners from around the world.
With the Global Environment Facility (GEF), we will convene a panel of companies (Johnson Controls, DuPont), small-business innovators (from the Cleantech Open), and government and business representatives (from UNIDO and ABDI) to share stories and lessons from the front lines of clean-tech entrepreneurship. The event, to be held at the U.S. Center pavilion, will examine the keys to successful low-carbon innovation, and the benefits for climate mitigation and adaptation, energy security, resource efficiency, and job creation.