Energy & Technology
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.
- The transportation sector uses natural gas in a variety of forms including: as compressed natural gas, as liquefied natural gas, through gas-to-liquids technologies, in fuel cells, or as a generation fuel for electricity for electric vehicles.
- Depending on the type of natural gas or fuel cell vehicle, greenhouse gas reductions can be between 28 and 55 percent as compared to gasoline- and diesel-powered engines.
- Greater replacement of petroleum-based fuels with natural gas could contribute to reduced petroleum imports and increased national energy independence.
- Natural gas vehicles currently offer lower fuel costs; however, there are higher up-front vehicle and infrastructure costs.
|Figure 1: Energy Sources in the US Transportation Sector 2010|
|Source: Energy Information Agency, 2011|
Natural gas is the most flexible of the three primary fossil fuels (coal, petroleum, natural gas) used in the United States and accounted for 25 percent of the total energy consumed nationwide in 2009. In spite of the major roles that natural gas plays in electricity generation as well as in the residential, commercial, and industrial sectors, it is not commonly used for transportation. In total, as illustrated in Figure 1, the U.S. transportation sector used 27.51 quadrillion British thermal units (Btus) of energy in 2010, of which 25.65 quadrillion Btus came from petroleum and just 0.68 quadrillion Btus came from natural gas (93 percent and 3 percent of the sector, respectively), Natural gas used in the transportation sector resulted in the emission of around 34.5 million metric tons of carbon dioxide equivalent (CO2e) in 2009.
A variety of vehicle technologies available today 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 combusted in the vehicle, it can also power vehicles in other ways. It can be converted into liquid fuel that can be used in conventional vehicles, power fuel cell vehicles, or be used in the production of 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 .05%), were powered directly by natural gas (not including electric vehicles). Of these, the majority of natural gas vehicles are buses and trucks. The recent relative cost differential between natural gas and oil as a fuel source, however, has increased interest in expanding the use of natural gas beyond just buses and trucks, thus representing a much broader market opportunity.
A Variety of Natural Gas Transportation Technologies Are Available
Of all natural gas powered vehicles, CNG is the most common form of natural gas used in transportation today. There were 114,270 CNG vehicles on U.S. roads in 2009 using 873 CNG fueling sites. Although Honda offers a CNG passenger vehicle, only 4,000 vehicles are scheduled for production in 2012, and sales figures are not available. CNG vehicles are most commonly found in larger transportation fleets, at present. Public transit buses, for example, are the largest users of natural gas in the transportation sector, with about one fifth of buses running on CNG or LNG. Other fleets also use natural gas trucks, including thousands of trucks at Waste Management, FedEx, UPS and AT&T.
|Figure 2: Light-Duty, Trucks, and Buses in the U.S. in 2010|
Note: Trucks include single-unit, 2-axle, 6-tires or more trucks and combination tractor trailers.
CNG is natural gas compressed to less than 1 percent of its standard atmospheric pressure volume. As a consequence of its highly pressurized state, CNG requires special handling and storage. In vehicles, CNG requires cylindrical storage tanks, which are significantly larger than conventional fuel and keep the fuel at pressures of up to 3,600 pounds per square inch. Given the size requirement of these tanks, their placement in passenger vehicles, can take up valuable passenger or trunk space.
Like CNG, but to a lesser extent, LNG vehicles (mainly heavy-duty trucks) are also used on U.S. roads and a budding fueling infrastructure has begun to develop. Approximately 3,176 LNG vehicles were in use in the United States in 2009 using 40 public and private refueling sites, 32 of which were in California. Liquefied natural gas is created by chilling it to -260 degrees Fahrenheit at normal pressures, at which point it condenses into a liquid 0.0017 percent the volume of the gaseous form. The conversion of natural gas to LNG removes compounds such as water, CO2 and sulfur compounds from the raw material leaving a purer methane product, whose combustion results in fewer air emissions. The stable, non-corrosive form also makes LNG more easily transportable such that it can be moved by ocean tankers or trucks. Use of LNG requires large, heavy, and highly insulated fuel tanks to keep the fuel cold, which adds a significant incremental cost to the vehicle. Today, LNG is mainly used as direct replacement for diesel in heavy-duty trucks because they are able to accommodate this hefty storage system and use LNG fueling infrastructure currently limited to trucking routes.
Both CNG and LNG are less dense forms of energy than conventional diesel fuel, which requires vehicles using these fuels to have larger fuel tanks to store the same amount of energy, as seen in Figure 3. The energy density of CNG is so low that CNG vehicles with ranges of greater than 300 miles are unlikely to be produced due to space and weight limitations. CNG is often thought about as 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 more practical for long-haul tractor-trailers that can accommodate larger fuel tanks. Despite these lower energy densities, both CNG and LNG can be an attractive fuel source for certain applications from an economic and environmental perspective.
|Figure 3: Comparison of Natural Gas Energy Density Compared to Diesel|
|Source: Energy Information Administration, 2010|
While CNG and LNG are today the most common forms of natural gas fuels in vehicles, other technologies are available that could increase the use of natural gas in the broader transportation system. One such technology converts natural gas into diesel or gasoline, which can be both used in the existing vehicle fleet and moved through existing infrastructure. Gas-to-liquids (GTL) technology transforms natural gas hydrocarbons into gasoline or diesel hydrocarbons and the resulting products have similar energy density as traditionally-produced diesel properties that allow for better engine performance and potentially.
Conversion technologies typically require 10 million cubic feet (mcf) of gas to produce one barrel of oil-equivalent product output, which may include diesel, naphtha, and other petrochemical products. At $4 per mcf of natural gas, that is equivalent to $40 per barrel of oil equivalent. GTLs have been produced at facilities around the world, and the development of new facilities in the United States is underway. Several companies are said to be in various stages of analysis for GTL facilities on the Gulf Coast because of natural gas supplies and current domestic prices.
Natural gas also plays a role in supplying fuel cell vehicles. Fuel cells produce electricity through an electrochemical process, rather than through combustion, resulting in heat and water and far fewer GHGs or other pollutants. Fuel cells are fueled by hydrogen, and the most common source of that 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 vehicles as fuel. 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. Several companies have concept cars that are powered by fuel cells, while 14 companies are working to introduce commercially-available fuel cell vehicles and infrastructure in Japan. In the United States, Hyundai plans to build 1,000 fuel cell vehicles for distribution in 2013 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. Several other companies plan to offer fuel cell vehicles by 2015 as well.
Electric vehicles are another type of vehicle becoming more common on U.S. roads, and these vehicles use electricity from the U.S. electrical grid, which is increasingly powered by natural gas as a fuel source. As of April 2012, Americans had purchased over 25,000 plug-in electric vehicles, including Chevrolet Volts, Nissan LEAFs, and Toyota Plug-in Priuses. PEVs are also now available from BMW, Ford, Mitsubishi, and Daimler. By the end of 2012, other models will be offered by automotive startups Coda and Tesla. When fueled by a combined cycle natural gas power plant, such “natural gas-powered electric vehicles” offer significant efficiency and GHG emission benefits over conventional diesel- or gasoline-powered vehicles.
Increased CNG Use in Heavy Duty Vehicle Fleets
While fuel pricing differentials clearly provide a market opportunity for natural gas in the transport sector, significant expansion barriers exist for CNG and LNG vehicles. CNG and LNG trucks currently offer less range, refueling options and resale value than traditional diesel-powered trucks. A diesel truck with a 150-gallon tank and a 6 to 7 mpg fuel economy can travel about 1,000 miles on one tank, which is significantly more than its natural gas counterparts. Depending on the mounting of the cylindrical tanks, CNG trucks can travel 150 miles or 400 miles between fueling. LNG trucks can travel 400 miles. The limited availability of fueling infrastructure also hampers deployment of natural gas trucks, and better infrastructure is a requirement for greater use. However, fleet owners are often not faced with the same constraints that passenger vehicles owners are. Range requirements may not be as significant an issue, as fleet vehicles travel regular and known paths. Refueling can also take place at a centralized facility or along a set route.
|Figure 4: Megaregions in the United States|
|Source: Regional Plan Association, 2012|
Nevertheless, the profitability of CNG vehicle projects depends on the many variables inherent in fleet vehicle composition and use and refueling infrastructure costs. NREL conducted research into three different types of notional CNG fleets and refueling infrastructures that might be used by municipal governments: transit buses, school buses, and refuse trucks. This segment was targeted by NREL based on “the advantages of CNG, including long-term cost-effectiveness, more-consistent operational costs, increased energy security, reduced greenhouse gas emissions, reduced local air pollution, and reduced noise pollution.” NREL’s 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 between 3 and 10 years that were sensitive to the costs related to refueling stations, vehicle conversion, operations, and maintenance.
This model, like others, includes the cost of building and operating centralized fleet refueling infrastructure and thus avoids the “chicken versus egg” refueling quandary that is challenging to non-fleet applications. If it were not for the lack of a public CNG refueling infrastructure, the decision 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 fleet vehicles. One approach that may help to overcome the vehicle conversion versus refueling infrastructure hurdle is to focus on a subset of the high mileage, heavy-duty, tractor-trailer industry segment, namely, intercity transport as opposed to interstate.
In intercity regions with high tractor-trailer industry usage areas, a very small number of public CNG refueling stations can serve a large number and percentage of the heavy vehicle transportation segment. As illustrated in Figure 4, the United States has eleven “Megaregions” where tractor-trailers travel tens of thousands of miles annually, but never leave the confines of a relatively small geographic area. Natural gas infrastructure can be built out in these Megaregions, such as through the Texas Clean Transportation Triangle strategic plan shown in Figure 5. Nearly 75 percent of Texas intrastate heavy and medium transport occurs within the triangle, making it an excellent candidate for CNG infrastructure. Nominal public CNG vehicle refueling infrastructure in the eleven 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 CNG refueling capability throughout the nation’s network of commercial truck stops.
|Figure 5: Texas Clean Transportation Triangle|
|Source: Greater Houston Natural Gas Vehicle Alliance, 2010|
Passenger Natural Gas Vehicles
While there are 159,006 retail gasoline stations in the United States in 2010, more than 65 million U.S. homes currently have natural gas service. 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 vehicles tank. Home refueling of CNG private vehicles, in addition to lower fuel prices may persuade some consumers to consider purchasing CNG passenger cars or to convert existing ones over from gasoline. However, other barriers to adoption exist. When compared with conventional gasoline vehicles, CNG vehicles have reduced range because of CNG’s lower energy density (Honda says the maximum range of the Civic GX NG is 248 miles), higher up-front costs, and a smaller trunk capacity. The lack of a large national CNG refueling infrastructure is also a barrier.
Electric vehicles are now available nationwide from multiple major automakers and are being marketed at passenger vehicle drivers. Great attention is paid to these vehicles throughout the public and private sectors because of the perceived opportunity they present to issues related to energy security, the environment, and the economy. However, market growth is highly uncertain due to policy, economic, and technical challenges. The C2ES-led An Action Plan to Integrate Plug-in Electric Vehicles with the U.S. Electrical Grid identified challenges and opportunities to PEV deployment including the need for a consistent regulatory framework for PEVs nationwide, the optimization of private and public investments in PEV infrastructure, and consumer education. To a great extent, the plan’s actions must be implemented for the electric vehicle market to compete with conventional vehicles without providing unwarranted public support.
Price Plays a Pivotal Role
A main driver of the discussion of these increased uses of 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 diesel fuel price was $4.07 per gallon and gasoline was $3.83, while a gasoline gallon equivalent of natural gas was $2.09. This price differential primarily results from the differential between the price of petroleum and natural gas, which on the same day were $104.87 per barrel for oil and $12 per energy equivalent of natural gas. In recent years, oil prices have risen while natural gas prices have decreased, creating an ever widening gulf between the two prices, as seen in Figure 6. This differential makes natural gas vehicles increasingly economical from the perspective of fuel costs.
|Figure 6: Oil price as a multiple of natural gas prices|
|Source: Energy Information Administration, 2012|
Emissions Implications of Natural Gas Vehicles
Depending on the type of natural gas technology used, natural gas vehicles offer a significant potential to reduce GHG emissions when compared to traditional gasoline and diesel vehicles. Figure 7 compares the total carbon intensity of diesel with gasoline LNG, CNG, and hydrogen from natural gas as determined by the California Air Resources Board for the purposes of California’s low carbon fuels standard, showing reductions in carbon intensity – up to 55 percent in the case of fuel cell vehicles. While natural gas fuels offer GHG emission reductions when compared to traditional transportation fuels, it is currently difficult to determine the precise carbon intensity of GTL products, as the technologies involved in production are in early stages of development and the emissions factors are not clear. While there are process emissions from GTL production, the CO2 emitted from facilities is pure and as such are a good candidate for carbon capture, utilization, and sequestration.
|Figure 7: Full lifecycle, total carbon intensity of selected transportation fuel options|
Note: Accounting is for California Low Carbon Fuels Standard program.
Depending on the source of electricity, electric vehicle operation can be responsible for much lower greenhouse gas emissions than nearly all conventional vehicles available today on a well-to-wheels basis. A discussion of the increasing role of natural gas in the power sector is to be found in the paper Natural Gas in the Power Sector.
|Figure 8: Transportation GHG Emissions by Source in 2010|
|Source: Environmental Protection Agency, 2012|
In the near term, the effects of natural gas vehicle use on emissions will depend on the type of vehicles in which it is used, and the relative emissions levels from sources in 2010 is illustrated in Figure 8. Long-haul tractor-trailers account for two-thirds of all fuel consumption for freight trucks (medium- and heavy-duty trucks). In total, freight trucks emissions are increasing more rapidly than other transportation sources and will account for a greater percentage of the sector’s GHG emissions over time, as trucking is taking 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. As such, reducing the carbon intensity from freight trucks will be critical to reducing transportation sector GHG emissions and increased natural gas use is one opportunity. Buses, meanwhile, are a very small share of overall GHGs, only 0.06 percent of on-road vehicle transportation emissions in 2003, despite the more common use of CNG buses.
Reductions of conventional air pollutants from natural gas vehicles are also notable. A 2001 study conducted by the Department of Energy’s National Renewable Energy Laboratory (NREL) found that natural gas vehicles in the United Parcel Service CNG fleet emitted 95 percent less particulate matter, 75 percent less carbon monoxide, 49 percent less nitrogen oxides and 7 percent less volatile organic compounds than their diesel-powered equivalents. This study is encouraging; however, emission reductions vary across vehicle application, age, and type of engine replaced. This complexity also extends to maintenance and operation cost comparisons between CNG-fueled vehicles and their diesel or gasoline equivalents. However, on average, there is little difference in maintenance costs as some applications run slightly higher and others slightly lower.
There are several ways in which natural gas use can be expanded in vehicular transportation. Each of them offers potential improvements in some combination of operating cost and reduced emissions, and all of them offset the use of petroleum, resulting in greater reliance on domestic fuel sources and enhanced energy security. There are, however, significant barriers to natural gas vehicles becoming a substantial part of the petroleum-fuels dominated transportation sector.
- Electric utilities are showing an overwhelming preference for building new natural gas power plants.
- Distributed or locally generated electricity has lower greenhouse gas (GHG) emissions relative to centralized generation because of avoided transmission losses.
- Significant improvements in power plant thermal efficiencies are feasible by 2030.
- Environmental rules are driving coal plant retirement, providing an opportunity for other forms of baseload generation.
|Figure 1: Electricity Generation Additions by Fuel Type 2010 – 2035 (GW)|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
With the increasing likelihood of a carbon-constrained future, cleaner than coal emissions and forecasts of sustained low prices, natural gas has become the fuel of choice for electricity generation by utilities in the United States. In 2012, the electric power industry planned to bring 23.5 GW of new capacity on line with 37 percent being natural gas-fired (20 percent wind, 18 percent coal, 12 percent solar, 5 percent nuclear, and 8 percent other sources, including hydro, geothermal and biomass). With growing electricity demand and the planned retirement of 39 GW of existing capacity, 223 GW of new generating capacity (including end-use combined heat and power) will be needed between 2010 and 2035. Natural-gas-fired plants account for 60 percent of capacity additions between 2010 and 2035 in the EIA Annual Energy Outlook 2011 Reference case, compared with 25 percent for renewables, 11 percent for coal-fired plants, and 3 percent for nuclear. Note that Federal tax incentives and state energy programs contribute to renewables competitiveness in the 2010 – 2015 time period. For example, with the Production Tax Credit in place until December 2012, wind generation capacity increases more than 18 GW from 2010 – 2015, and with the Investment Tax Credit in place until December 2016, utility and end-use solar capacity additions are forecast to increase by 6.3 GW (7.5 GW through 2016).
Natural Gas as a Fuel for Electric Power
Natural gas can provide baseload, intermediate and peaking electric power. It is a reliable source of power that is capable of supplying firm back-up to intermittent wind and solar. Additionally, natural gas power plants can be constructed relatively quickly, in as little as 20 months. Compared to other forms of electric generation natural gas plants have a small footprint from a land use perspective. However, even though natural gas combustion emits fewer GHGs than coal or oil, it still emits a significant amount of CO2. It is also important to stress that natural gas-fired electrical plants must be sited near existing natural gas pipelines; otherwise the cost of building this infrastructure must be taken into account.
Greenhouse Gas Emissions
The electricity sector contributes about 40 percent of all U.S. carbon dioxide emissions. All other things being equal, a megawatt-hour of natural gas-fired generation contributes around half the amount of CO2 emissions from coal-fired generation and about 68 percent of the amount of CO2 emissions from oil-fired generation. Natural gas-fired generation CO2 emissions levels are still significant, especially when compared to the near-zero emissions of nuclear, hydro, wind, geothermal, and solar power.
|Table 1: Average Fossil Fuel Power Plant Emission Rates (lbs/MWh)|
|Source: U.S. Environmental Protection Agency, 2000|
Centralized Power Generation
Central power stations create large quantities of electricity, which are then transported to end-users via electrical transmission and distribution lines. There are three categories of central power station technologies in which natural gas is a fuel that can be used to generate the electricity. In the order of their historical development, they are: steam turbines, combustion turbines (CT) and combined cycle (CC) power plants. Each plant type has an associated average thermal efficiency. Thermal efficiency measures how well a technology converts the fuel input energy (heat) into electrical energy (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 - 35 percent. Combustion turbines are around 35 - 40 percent efficient and combined cycle plants have thermal efficiencies in the range of 50 - 60 percent. For more information about these three technologies see Appendix A.
Distributed Generation (DG)
With distributed generation systems (also referred to as self-generation), as contrasted to central power station generation described above, smaller quantities of electricity are generated at or near the location where it will be consumed, obviating the need for long electrical transmission lines. The potential benefits include: increased electric system reliability, reduction of peak power requirements, and reduction in vulnerability to terrorism. However, from a greenhouse gas (GHG) perspective, the primary advantage of distributed generation is that there are fewer losses in the transmission of the electric power, both in the bulk transmission system and in the local electrical distribution networks. Lowering line losses means less electricity generation (less fuel and fewer emissions) is required to serve the same electrical demand.
In the bulk transmission system (the backbone of the central power station system), line losses depend primarily on the line voltage, line load, weather, altitude and the distance travelled; the higher the line voltage the fewer losses that a line will experience. For example, a 765kV line, the highest voltage currently used in the bulk transmission system, electrical losses are on the order of 0.6 to 1.1 percent for a 1000 MW line load travelling 100 miles in normal weather. A 345kV line under the same conditions would see a loss on the order of 4.2 percent. Since most local distribution companies operate below 35kV, higher losses can be expected in the local distribution network.
Examples of DG that would utilize natural gas include microturbines (CT or CC) located on-site for commercial and residential application, and combined heat and power (CHP) for industry. CHP also has additional efficiency benefits beyond those from DG (see companion paper - Natural Gas in the Industrial Sector). Higher capital costs are believed to prevent investment in DG technologies and the State of California, among others, provides incentives for self-generation.
Future Technology – Supply Side Efficiency
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. 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 as a result of increasing the efficiency of new and existing fossil-fueled generation.
Policy in Play
Arguably, the most significant policy decisions affecting the U.S. electric power sector today are the Cross State Air Pollution Rule (CSAPR), National Emissions Standards for Hazardous Air Pollutants (NESHAP), and proposed New Source Performance Standards (NSPS) issued by the U.S. Environmental Protection Agency (EPA). The installation of pollution control retrofits will be essential to comply with CSAPR and NESHAP, affecting electric generating units, and coal-fired units in particular. PJM, operator of the world’s largest wholesale electricity market in the Eastern U.S., 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 EPA rules. Reserve margins, the spare capacity that electricity system or market operators are required to maintain above projected peak loads to ensure system reliability appear sufficient in the short run. However, new, reliable baseload generation will be required in the next ten to twenty years to fill the gap.
Additionally, in late March 2012, the EPA proposed CO2 pollution standards for the new electric power plants as part of its NSPS program. Under the proposed standard (1,000 pounds of CO2 per MWh), all new power plants would need to match the CO2 emissions performance currently achieved by highly efficient natural gas combined cycle (NGCC) power plants. New coal-fired power plants could meet the standard by capturing and permanently sequestering their GHG emissions using carbon capture and storage (CCS) technologies. If adopted, this standard would favor new natural gas-fired generation in the future.
In the past few years, there has been interest in a Federal level Renewable Portfolio Standard (RPS). Most recently, there has been some interest in a broader Federal Clean Energy Standard (CES). A CES is a policy requiring that a certain portion of electricity sold by an electric utility come from “clean energy” sources. Whereas an RPS typically credits only 100 percent renewable generation like wind turbines, solar, geothermal or new hydro, a CES creates a mechanism to credit “cleaner” electricity generation, that is, generation that creates less CO2. Therefore, new and incremental (upgrades and improvements to) natural gas-fired generation, along with natural gas with carbon capture and storage (CCS), among other cleaner forms of electricity production would be eligible to receive clean energy credits.
Natural Gas in the Electricity Market
In 1978, in response to supply shortages (the result of government price controls), Congress enacted the Power Plant and Industrial Fuel Use Act (FUA). The law prohibited the use of oil and natural gas in new industrial boilers and new electric power plants. The goal was to preserve "scarce" supplies for residential customers. During the early 1980s, the demand for natural gas declined substantially, which contributed to a significant oversupply of gas for much of the decade. Falling natural gas demand and prices finally spurred the repeal in 1987 of sections of the FUA that restricted the use of natural gas by industrial users and electric utilities. Low natural gas prices in the 1990s stimulated the rapid construction of gas-fired power plants. Since 1990, natural gas has been gaining market share with electricity generation from this source increasing from around 11 percent to 23 percent of the total net generation in 2010, as illustrated in Figure 2.
|Figure 2: Electricity Net Generation: Electric Power Sector (GWh)|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
As a result of increased natural gas-fired electricity generation displacing fuel oil and coal-fired generation, total GHG emissions from the electricity sector have decreased since 2000, as shown in Figure 3, while net electricity generation has increased around 9 percent over the same period.
|Figure 3: Emissions: Electric Power Sector (MMT CO2)|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
According to the latest Energy Information Administration (EIA) Annual Energy Outlook (AEO), natural gas-fired generation is expected to be just over 25 percent of the total generation mix in 2020, rising to 27 percent in 2035.
Fuel diversity is an important consideration for utilities looking to reduce their reliance on any particular energy source. The trend away from coal toward greater reliance on natural gas creates a potential fuel diversity risk, especially considering the volatile price history of natural gas. Coal will continue to be a significant source of electricity in some regions and for some utilities, but other utilities look increasingly likely to be getting nearly all of their baseload generation from only two sources: natural gas and nuclear power.
|Figure 4: Estimated Levelized Cost of New Generation Resource, 2016|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
Levelized cost (Figure 4) represents the present value of the total cost of building and operating a generating plant over an assumed financial life and duty cycle, converted to equal annual payments and expressed in terms of real dollars to remove the impact of inflation. It reflects overnight capital cost, fuel cost, fixed and variable O&M cost, financing costs, and an assumed utilization rate for each plant type. The availability of various incentives including state or federal tax credits can also impact the calculation of levelized cost. The values shown in the figure below do not incorporate any such incentives. Natural gas-fired combined-cycle generation technologies are projected to be the least expensive options in the coming years. 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, leading to a greater reliance on natural gas in the coming years.
Natural Gas with Carbon Capture and Storage
In a carbon-constrained future, and with natural gas potentially playing a much greater role in the future of the total generation mix, it makes sense to consider a natural gas plant with carbon capture and storage (CCS) capability. CCS projects have already been initiated and several projects are planned in the next several years to demonstrate the feasibility of the CCS technology. To date, these projects have been undertaken almost exclusively in conjunction with coal-fired power plants or industrial sources. However, one international project in Norway, set to begin in 2012, endeavors to capture CO2 from a natural gas combined heat and power (CHP) plant (similar to a combined cycle plant) and sequester the CO2 in an underground saline formation.
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). 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.
3. PJM Interconnection. “Coal Capacity at Risk for Retirement in PJM: Potential Impacts of the Finalized EPA Cross State Air Pollution Rule and Proposed National Emissions Standards for Hazardous Air Pollutants,” August 26, 2011.
by Michael E. Weber, The University of Texas at Austin
- Within one to two decades, natural gas might surpass petroleum as the dominant energy source in the United States.
- A period of price choppiness may occur as U.S. natural gas prices settle to a new equilibrium.
- As a marginal power producer, high natural gas prices trigger high electricity prices that make it easier for renewable energy sources to compete.
- Low natural gas prices encourage the replacement of coal in the power sector.
- The relationship between natural gas and wind is nuanced, as they mitigate each other’s worst problems—winds’ variability and natural gas’ price volatility.
- Renewable forms of natural gas, biogas or biomethane, have a potential domestic supply of over 1 quadrillion British thermal units (Btus) annually.
Energy transitions are a way of life. And, it seems that the United States is undergoing another one of those transitions as it seeks lower-carbon, more affordable, domestically-sourced fuels to meet a variety of market and policy objectives. The brief history of energy consumption in the U.S. from 1800 to 2010 is depicted in Figure 1, revealing that we have already experienced several energy transitions. Wood as our dominant fuel in the first half of the 19th century was surpassed by coal starting in 1885.
Coal as our dominant fuel was surpassed by petroleum in 1950. Whether another such a transition is underway is yet to be seen. But, if recent trends continue, then it seems likely that another transition will occur in the coming one to two decades as natural gas overtakes petroleum to be the most popular primary energy source in the U.S. Such a transition will be enabled (or inhibited) by a mixed set of competing price pressures and a complicated relationship with renewables that will trigger an array of market and cultural responses. This article seeks to layout some of the key underlying trends while also identifying some of these different axes of price tensions (or price dichotomies).
|Figure 1: Total U.S. Energy Consumption, 1800 to 2010|
Note: Wood, which was the dominant fuel in the U.S. 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.
Source: Energy Information Agency 2010
Natural Gas Could Become Dominant in the U.S. Within One to Two Decades
While petroleum still reigns supreme today, within one to two decades, natural gas might surpass it as the dominant energy provider. In fact, recent trends suggest that another transition is already underway. In particular, while petroleum and coal consumption have dropped steadily since 2006, natural gas consumption has increased.
For a century, oil and natural gas consumption trends have tracked each other quite closely. Figure 2 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:
- It has flexible use across many sectors, including direct use on-site for heating and power; use at power plants; use in industry; and growing use in transportation.
- It has lower emissions (of pollutants and greenhouse gases) per unit of energy than coal and petroleum.
- It is less water-intensive than coal, petroleum, nuclear and biofuels.
- Domestic production meets almost all of the annual U.S. consumption.
|Figure 2: U.S. Oil and Gas Consumption from 1920 to 2010|
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.
Source: Energy Information Agency 2010
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 6 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. 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.
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–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 (< 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.
There are Six Price Dichotomies with Natural Gas
In light of the looming transition to natural gas as the dominant fuel in the U.S., it is worth contemplating the complicated pricing relationship that natural gas in the U.S. has with other fuels, market factors, and regions. It turns out that there are several relevant price dichotomies to keep in mind:
- Natural Gas vs. Petroleum Prices,
- U.S. vs. Global Prices,
- Prices for Abundant Supply vs. Prices for Abundant Demand,
- Low Prices for the Environment vs. High Prices for the Environment,
- Stable vs. Volatile Prices, and
- Long-Term vs. Near-Term Prices.
The tensions along these price axes will likely play an important role in driving the future of natural gas in the U.S. and globally.
|Figure 3: U.S. Oil and Gas Consumption and Projections|
Note: Natural gas might pass petroleum as the primary fuel source in the U.S. 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.
Source: Energy Information Agency 2010
Decoupling of Natural Gas and Petroleum Prices
One of the most important recent trends has been the decoupling of natural gas and petroleum prices. Figure 4 shows the U.S. prices for natural gas and petroleum (wellhead, and WTI Cushing, respectively) from 1988 to 2012. While natural gas and petroleum prices have roughly tracked each other in the U.S. 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.
|Figure 4: U.S. Oil and Gas Prices 1988 to 2012|
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.
Decoupling of U.S. and Global Prices
Another important trend has been the decoupling of U.S. and global prices for natural gas. Figure 5 shows the U.S. prices for natural gas (at Henry Hub) compared with EU and Japanese prices from 1992 to 2012. In a similar fashion as the discussion in Section 3.1, while natural gas prices in the U.S. and globally (in particular, the EU 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 U.S. 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 U.S. was then limited by its capacity to export LNG (which is in contrast to the situation just a few years prior, during which the U.S. was limited by its capacity to import gas), so gas prices plummeted despite growing global demand. Thus, while the U.S. 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 EU and Japan are tightly coupled to the world gas markets, (with the EU 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 investing 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 should come back into convergence.
|Figure 5: Natural Gas Prices in Japan, the E.U. and U.S., 1992 to 2012|
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.
Sources: BP 2010, EIA 2012—Henry Hub Gulf Coast Natural Gas Spot Price and Price of Liquefied U.S. Natural Gas Exports to Japan, and Ycharts 2012
Prices for Abundant Supply vs. Prices for Abundant Demand
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 U.S. 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).
The irony here is that it’s 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.
Low Prices for the Environment vs. High Prices for the Environment
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 marginal power producer in the U.S., 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. 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.
Stable vs. Volatile Prices
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 Section 3.1), 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.
Long-Term vs. Near-Term Price
While natural gas is enjoying a period of relatively stable and low prices at the time of this writing in 2012, 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 5), re-coupling will push prices upwards.
Concluding Comments on Price Dichotomies
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.
The Complicated Relationship of Natural Gas and Renewables
In addition to the complex pricing landscape described earlier, there is also 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 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 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 is a problem. 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 edge against natural price volatility. Thus, they are complementary partners in the power markets.
Furthermore, many people seeking a long-term sustainable energy option will often reject natural gas automatically because it is widely considered a fossil fuel that has a finite resource base. While most reserves of natural gas were formed many millions of years ago (and thus comprise a finite fossil resource), 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 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 BTU annually in the United States.
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. These tensions are exacerbated by the complicated relationship between natural gas and renewables. How and whether we sort out these tensions and relationships will affect the fate of natural gas and are worthy of further scrutiny.
5. EIA, Henry Hub Gulf Coast Natural Gas Spot Price, Tech. rep., Energy Information Administration, U.S. Department of Energy, Available at: http://tonto.eia.gov/dnav/ng/hist/rngwhhdm.htm (April 6, 2012).
6. EIA, Price of Liquefied U.S. Natural Gas Exports to Japan, Tech. rep., Energy Information Administration, U.S. Department of Energy, Available at: http://www.eia.gov/dnav/ng/hist/n9133ja3m.htm (April 6, 2012).
7. YCharts, European Natural Gas Import Price, Tech. rep., Available at: http://ycharts.com/indicators/europe_natural_gas_price (April 6, 2012).
- The industrial sector directly consumed 27 percent of natural gas in the United States in 2010.
- Newly abundant and low-cost domestic sources provide economic benefits to industry using the fuel for power, heat, and as a feedstock.
- The Energy Information Agency projects total natural gas consumption for industrial heat and power to rise by 6.25 percent between 2012 and 2021 before declining to lower but steady levels through 2035, and it projects natural gas feedstock use to rise by 25 percent between 2012 and 2035.
- Boiler upgrades and replacements can offer measurable reductions in greenhouse gas emissions through efficiency improvements as well as displacing coal with gas.
- Combined heat and power systems offer the potential to efficiently use natural gas while reducing greenhouse gas emissions.
- Many industrial activities are energy- and emissions-intensive, but some uses of natural gas as a feedstock emit very few greenhouse gases.
|Figure 1: Natural Gas Use in the Industrial Sector (Industry Overall)|
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
Overall, the largest direct use of energy by the industrial sector is for process heating, which is the production of heat directly from fuel sources, electricity, or steam to heat raw material inputs during manufacturing. In 2010 process heating using all fuel sources produced 315.4 million metric tons of C02e, which was 40 percent of the total emissions for the industrial sector. 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 (see Figure 1).
Industrial boilers for heat and steam are another significant user of natural gas, and, 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 manufactures, food processors, pulp and paper manufactures, and the petroleum and coal derivatives industries (including chemicals, coke, and coal tar). Twenty-two percent of the natural gas used in manufacturing is consumed in boilers. As with process heating, industrial boilers are dependent on natural gas, with 83 percent of boilers running on the fuel (Figure 2).
Often, power generation and process heating can be more efficiently accomplished by coproducing heat and power from a single unit with technology commonly called combined heat and power (CHP). Additional efficiencies and emission reductions are also achieved through the generation of electricity onsite, because it avoids transmission loss. In 2010, 14 percent of natural gas used in manufacturing was consumed by CHP and other power systems. As illustrated in Figure 2, natural gas dominates the fuel used for CHP. Nationwide, the added efficiencies of CHP systems avoid the annual emission of 35 million metric tons of CO2e.
|Figure 2: Direct Consumption of Fuels in the Industrial Sector|
CHP & Other Power
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
For the chemicals industry, natural gas also serves a unique function, providing a chemical feedstock in the form of methane and liquids found in the natural gas, including ethane, propane, and butane. These liquids, especially ethane, are processed and transformed to become additional intermediate and final products. Chemical companies are particularly heavy users of natural gas as a feedstock and may consume up to two-thirds of their delivered natural gas for this purpose. While U.S. companies are reliant on low-cost natural gas liquids as a feedstock, European competitors use more expensive, oil-based naphtha. In 2010, for example, domestic ethane sold at half the price of imported naphtha in Europe, and, consequently, U.S. chemical manufactures have reaped a competitive advantage in international markets for intermediate and final goods. 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 combusting them. Consequently, when natural gas is used as a feedstock, very few greenhouse gases are emitted.
Potential for Expanded Use in the Industrial Sector
Increased availability and low prices of natural gas have significant implications for domestic manufacturing, which has historically been concerned about supply availability and price volatility. Recently, abundant supply and low prices have led to an increase in domestic manufacturing, creating new jobs and economic value. 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. In the past few years, the number of firms disclosing the positive impact of new gas resources for facility power generation and feedstock use to the Securities and Exchange Commission has increased substantially. In 2010, exports of basic chemicals and plastics increased 28 percent from the previous year, yielding a trade surplus of $16.4 billion. If the expectation that low prices will continue is correct, these economic benefits would be significant over the long term. A study by the American Chemistry Council, for instance, estimates that a 25 percent increase in ethane supplies would yield a $32.8 billion increase in U.S. chemical production. Industry, however, needs more than just abundance and low prices to maintain use of natural gas. Price stability is necessary to encourage long-term investments in industry, and increased natural gas supplies also have the potential to stabilize prices.
|Figure 3: CHP versus Conventional Production|
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
Potential for Industrial Sector Emission Reductions
If supply remains robust and prices low and stable, the U.S. industrial sector is likely to reap substantial economic benefits from the increased availability of low-cost natural gas. Even as the sector expands, there are opportunities to reduce its emission intensity. Improving the efficiency of industrial boilers is one such opportunity. Boilers tend to have a low turnover rate, and very often older units are less efficient than newer ones. The pre-1985 fleet of boilers has an efficiency rate of between 65 percent and 70 percent; while new boilers have efficiency rates of between 77 percent and 82 percent and new, super–high-efficiency units can reach efficiency rates of up to 95 percent.
A Massachusetts Institute of Technology (MIT) analysis 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 of 1.8 to 3.6 years for the new equipment.
|Figure 4: Projected Natural Gas Consumption (2009-2035) in…|
Projected Total Industrial Consumption of Natural Gas for Heat and Power
Projected Energy Consumption of Natural Gas for Heat and Power per Dollar of Shipments
Projected Total Industrial Consumption of Natural Gas Liquids Feedstock
Projected Energy Consumption Natural Gas Liquids Feedstock per Dollar of Shipments
Projected Total Industrial CHP Generation for All Fuels through 2035
|Source: EIA AEO 2012 Early Release, 2012|
While natural gas is the most commonly used fuel source for industrial boilers, 17 percent of boilers use coal or other fuels, as shown in Figure 2. Because of the air pollutants from these coal-fired boilers, these boilers are now subject to the Environmental Protection Agency’s (EPA) 2012 Mercury and Air Toxics Standards. MIT conducted a separate analysis to determine the results of replacing the affected coal boilers with efficient or super-high-efficiency natural gas boilers (these natural gas boilers are not regulated under the new EPA rule). This analysis found that replacement with natural gas boilers would reduce annual CO2 emissions by about 52,000 to 72,000 tons per year per boiler.
Increasing the use of CHP also has potential to reduce emissions. A 2008 Oak Ridge National Laboratory (ORNL) study analyzed the total U.S. energy system and 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. GHG emissions by 600 million metric tons of CO2 compared to business as usual. Another study, by McKinsey & Company in 2009, sought to estimate the potential for expanding CHP by 2020 through net present value-positive investments. McKinsey estimated that the potential exists in the United States for an additional 50.4 GW of CHP capacity by 2020, which would avoid an estimated 100 million metric tons of CO2 emissions per year compared to business as usual. McKinsey found that 70 percent of the potential cost-effective incremental CHP capacity was through large-scale industrial cogeneration systems greater than 50MW.
While CHP results in few GHG emissions, barriers currently limit its application. Utilities often cite safety concerns as a barrier to deployment, particularly a fear of miscommunication between CHP operators and utilities in the event of an emergency, which utilities say could lead to dangerous situations where line workers are not certain whether lines are energized or not. Utilities may also have concerns about liability and risk associated with the interconnection between CHP operations and the grid, as utility employees may be affected by safety and technical decisions of CHP operators made independent of utilities. Like issues of safety, many utilities are concerned about the need to provide backup power to industrial facilities in case CHP systems are taken offline or are otherwise unavailable. For utilities, the ability to provide backup power to these facilities requires investments in capacity, and to pay for this capacity, utilities often charge higher, discriminatory rates and interconnection fees to CHP operators to compensate for these necessary investments.
In addition to these concerns, regulatory and corporate policies have inhibited the growth of CHP capacity. Power sector regulation in many states leads many utilities to view CHP as unprofitable and, accordingly, discourages its use. However, some innovative policy approaches can overcome this problem. One approach is decoupling, which eliminates the connection between utility sales volume and profitability. By doing so, decoupling makes CHP measures profitable to utilities, and, therefore, more likely to gain their support. Another potential policy solution is the implementation of lost-revenue adjustment policy, which compensates utilities for revenues lost because of efficiency measures. It allows utilities to collect a charge from customers to account for efficiency-related revenue losses. Lost-revenue adjustment policies also have the potential to encourage CHP. Other policy options include state incentives designed to encourage the use of CHP. State-level policies include standardizing interconnection guidelines, tax incentives, and inclusion of CHP as a compliance mechanism for clean energy standards. Some states have enacted these policies, but, as with many state-led policies, there is a diversity of approaches to, and success with, implementation.
- Natural gas plays an important role in nearly every sector of the U.S. economy, constituting 25 percent of energy consumption (second only to oil) and roughly one fifth of electricity generation.
- Combustion of natural gas emits about half as much CO2 as coal and 30 percent less than oil, and far fewer pollutants, per unit of energy delivered.
- Advances in the efficiency and cost-effectiveness of production technologies have dramatically increased the amount of North American shale gas resources that can be economically recovered. Since 1999, U.S. proven reserves of natural gas have increased every year.
- Abundant supply, low prices, and other favorable characteristics have enabled natural gas to penetrate many markets, expanded its use, and raised its potential for reducing greenhouse gas emissions. Yet uncertainties remain about the future of prices, supply, markets, policies, and the ability to leverage natural gas to reduce U.S. emissions.
|Figure 1: U.S. Natural Gas Consumption by Sector, 2010|
|Source: U.S. Energy Information Administration, 2011|
Natural gas is a naturally occurring fossil fuel consisting primarily of methane and small amounts of impurities such as carbon dioxide (CO2). It may also contain heavier liquids that can be processed into valuable byproducts including propane, butane and pentane. Natural gas plays a vital role in the U.S. economy, constituting 25 percent of total U.S. energy consumption—second only to oil—and roughly one fifth of all U.S. electricity generation. Unlike other fossil fuels, natural gas plays an important role in almost every sector, in applications including generating electricity, providing heat and power to industry, buildings, homes and vehicles, and as a feedstock in the manufacture of products such as fertilizers. Natural gas is responsible for approximately 16 percent of U.S. greenhouse gas (GHG) emissions annually, most of which (90 percent) are associated with combustion, with the remainder from venting and other fugitive methane releases (8 percent) and from removing CO2 during processing (2 percent). Combustion of natural gas produces substantially less CO2 and far fewer pollutants per unit of energy delivered than coal and oil.
Natural gas is produced from reservoirs in natural rock formations or associated with production from other hydrocarbon reservoirs such as oil fields. While this “associated” gas is an important source of domestic supply, the majority (89 percent) of U.S. gas is developed as the primary product. With recent technology advances, U.S. natural gas is increasingly produced from more unconventional sources, such as coal beds, tight sandstone and shale formations that require advanced technologies for development and production and typically yield much lower recovery rates than conventional reservoirs.
Despite these initial hurdles, substantial new supplies of natural gas are making their way to market in the United States, primarily due to the remarkable speed and scale of shale gas development. This increase has raised awareness of natural gas as a key component of domestic energy supply and has dramatically lowered both current prices and price expectations for the future. In recent years, the abundance of natural gas in the United States has improved its competitiveness relative to coal and oil, has expanded its use in a variety of contexts, and raised its potential for strengthening U.S. energy security and reducing GHG emissions.
|Figure 2: U.S. Natural Gas Price History, 1976-2012|
|Source: Energy Information Administration, U.S. Department of Energy, 2012|
A History of Volatility
The erratic history of natural gas prices in the United States illustrates the difficulty of forecasting natural gas futures and the need for caution during periods of excess supply (Figure 2). Four major price spikes in the U.S. market occurred in the first decade of this century alone. By 2001, several years of declining productive capacity and increasing demand resulted in a sharp price spike. Demand eased thereafter largely due to an economic downturn, but relatively tight supplies produced a gradual return to higher prices in the first half of the decade. Prices spiked again sharply 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, prices have fallen dramatically due to the economic recession and the rapid growth of shale and other unconventional gas resources. In December 2011, prices were down 70 percent from record-high prices just three years before, to $3.14 per thousand cubic feet (mcf) from $10.79/mcf.
U.S. natural gas markets have only been truly open and competitive for about 20 years, when U.S. gas markets were deregulated in the early 1990s. Over that time, price fluctuations have been pronounced, ranging from less than $2/mcf to more than $10/mcf. Periods of high market prices result from changes in regulation, weather disruptions, and broader trends in the economy and energy markets—but also from perceptions of abundance or scarcity. A number of supply-side factors can also affect prices, including production and storage levels.
Looking forward, the average wellhead price is expected to remain below $5/mcf through 2023 and rise to $6.52/mcf in 2035 as production gradually shifts to resources that are less productive and more expensive. Due to the weak U.S. economic recovery and abundance of unconventional gas resources, prices are not expected to reach pre-recession levels until after 2035. But uncertainty remains about future price stability, which can discourage long-term investment for both natural gas producers and large consumers.
Game Changing Technology
The higher natural gas prices of the preceding decade triggered renewed interest in developing unconventional gas resources. Advances in the efficiency and cost-effectiveness of horizontal drilling, new mapping tools, and hydraulic fracturing technologies—enabled by investments in R&D and demonstration from the Department of Energy and national labs—have dramatically increased the amount of North American shale gas resources that can be economically recovered. Since 1999, U.S. proven reserves of natural gas have increased every year, driven mostly by shale gas advancements. In 2003, the National Petroleum Council estimated U.S. recoverable shale gas resources at 35 trillion cubic feet (tcf). Today, the EIA puts that estimate closer to 482 tcf out of an average remaining U.S. resource base of approximately 2,543 tcf. MIT’s mean projection estimates recoverable shale gas resources at 650 tcf out of a resource base of 2,100 tcf. These estimates represent nearly 100 years of domestic demand at current consumption levels.
|Figure 3: Type of Gross Gas Production in United States, 2000 and 2009|
|Source: MIT, 2011 Note: CBM is coalbed methane.|
Even as supply estimates have increased, the cost of producing shale gas has declined as more wells are drilled and new techniques are tested. In one estimate, approximately 400 tcf of U.S. shale gas can be economically produced at or below $6 per million British thermal unit (MMBtu) (in 2007 dollars). In another estimate, almost 1,500 tcf can be produced at prices below $8/MMBtu and 500 tcf at $4/MMBtu. By comparison, annual U.S. consumption of natural gas currently totals approximately 22 tcf.
These 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. In the decade 2000-2010, U.S. shale gas production increased 14-fold and now comprises approximately 22 percent of total U.S. production. From 2007 to 2008 alone, U.S. shale gas production increased by 71 percent. Remarkably, 80 percent of that expansion has been driven by one resource, the Barnett shale in Texas. Shale gas production is expected to grow further by almost fourfold from 2009 to 2035, and is forecast to make up 47 percent of total U.S. production.
These dramatic changes are reflected in unexpectedly low and less volatile market prices (Figure 2, above), which are also due in part to the economic recession. Yet uncertainties remain which may impact future development and production. Very low prices may result in producers shutting in wells, particularly if the amount of natural gas liquids produced along with the gas is not sufficient to enhance the breakeven economics. The extent to which current assessments accurately capture the economically recoverable resource base, the cost of producing and delivering shale gas, and the availability of pipeline and processing infrastructure have also been difficult to predict.
Policy in Play for Shale Gas
Oil and gas industry operations, including the injection of hydraulic fracturing fluids, are exempt from regulation under the federal Safe Drinking Water Act. But in view of the speed and scale of shale gas development, U.S. regulators are taking steps to ensure that adequate environmental protections exist for air emissions, land use, and water impacts. At the federal level, the U.S. Environmental Protection Agency (EPA) is conducting a comprehensive review of hydraulic fracturing, and legislation promoting improved transparency and management practices—the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act—was introduced in the 2009-2010 Congress. Draft rules from the EPA to regulate air emissions from oil and gas operations (expected to be released April 17) may also address gas leakages from conventional oil and gas wells, unconventional shale wells, storage tanks and compressor stations. The U.S. Department of Energy’s Secretary of Energy Advisory Board (SEAB) developed several specific recommendations for reducing the environmental impact and improving the safety of shale gas production, to be implemented by the DOE, EPA, and the U.S. Department of the Interior (DOI). The DOI is likely to propose creating new rules for natural gas drilling on federal lands, and the EPA has undertaken a study of the relationship between hydraulic fracturing and drinking water.
Several states—such as Arkansas, California, Colorado, Louisiana, Maryland, New York, Pennsylvania, Texas, and Wyoming—have taken action or are considering action to regulate hydraulic fracturing, to require public disclosure of the chemicals used in hydraulic fracturing operations, or to temporarily suspend shale gas development activities while they explore the issue further. The outcome of these activities may mean reduced environmental impacts and improved safety, but also a heavier regulatory burden for producers.
Use and Emissions
Among fossil fuels, natural gas has the lowest carbon intensity, generally requires limited processing for end use, and burns efficiently with fewer air pollutants (particulates, nitrogen oxides, sulfur dioxide, lead and mercury). These favorable characteristics have enabled natural gas to penetrate many markets. No one sector dominates natural gas consumption—the electric power, industrial, residential, and commercial sectors are all significant end users. In the residential and commercial building sectors, natural gas provides more than three-quarters of primary energy, largely due its efficiency and convenience for such uses as space and hot water heating. The abundance of U.S. natural gas supply has also raised interest in its expanded use in electric power and even in the transportation sector, either directly as a fuel or indirectly as power generation for electric vehicles. This diversity of uses has created real or perceived competition among sectors and customer segments for access to natural gas supplies.
The combustion of natural gas not only emits CO2, but methane—which is emitted through venting and fugitive releases during processing, transmission or storage—is itself a potent GHG that is 23 times more powerful than CO2 in terms of its heat-trapping ability. In light of the abundance of natural gas and its strategic importance to the U.S. fuel mix, several studies are seeking to generate a comprehensive “lifecycle” assessment of the GHG emissions associated with natural gas production and use, including efforts by the U.S. Environmental Protection Agency (EPA), the Environmental Defense Fund, and Cornell University. In addition to GHG emissions, the use of hydraulic fracturing in natural gas development has important impacts for other environmental issues, including land use, groundwater contamination, and water consumption.
A Fragmented Market
In contrast to oil, natural gas has been primarily a domestic energy resource; trade patterns tend to be more regional (particularly in the United States); and prices determined within regional markets. Resources are concentrated geographically: 70 percent of the world’s gas supply is located in only three regions—Russia, the Middle East (primarily Qatar and Iran) and North America (when including unconventional resources). In the United States, natural gas is produced in 32 states and the Gulf of Mexico, with ten areas accounting for nearly 90 percent of production: Arkansas, Colorado, Gulf of Mexico, Louisiana, New Mexico, Oklahoma, Pennsylvania, Texas, Utah and Wyoming. Moreover, due to its low density, natural gas is difficult both to store and to transport by vehicle unless compressed or liquefied. Thus, pipelines connect well sites to end consumers, sometimes served by local distribution companies in between. While much of the global gas supply can be developed economically with relatively low prices at the wellhead or the point of export, in contrast to oil, high transportation costs—either via long-distance pipeline or via tankers as liquefied natural gas (LNG)—are a significant barrier to establishing a global gas market.
In 2010 natural gas constituted 29 percent of U.S. energy production and almost 90 percent was consumed domestically. (By contrast, 49 percent of U.S. oil consumption was produced domestically in 2010.) In 2010 net imports, delivered via pipeline and liquefied natural gas (LNG) import facilities, constituted only 10.8 percent of total U.S. natural gas consumption (3.7 tcf), the lowest proportion since 1993. Of this amount, about 88 percent came from Canada. Net imports of natural gas have decreased 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.
An Integrated Global Market?
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 (LNG). Natural gas, once liquefied, can be transported by tanker and regasified for use in other markets. Between 2005 and 2010, the LNG market grew by more than 50 percent and LNG now accounts for 30.5 percent of global gas trade. Global gas liquefaction capacity increased by almost 40 percent over just the past two years, and is expected to increase by an additional one-third over the next five years. With surplus domestic supply and substantially higher prices in other regional markets, several U.S. companies have applied to relevant agencies for export authority and have indicated plans to install liquefaction facilities.
Prospects for U.S. LNG 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 LNG import capacity has expanded from approximately 2.3 billion cubic feet (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 LNG was 1.2 Bcf/day, leaving most of this capacity unused. The ability to make use of and repurpose existing U.S. import infrastructure—pipelines, processing plants, storage and loading facilities—would help reduce total costs relative to “greenfield,” or new, LNG facilities.
Looking forward, global LNG trade is expected to increase. The U.S. Energy Information Administration (EIA) projects that world liquefaction capacity will more than double from 8 tcf in 2008 to 19 tcf in 2035. Most of the projected increase comes from the Middle East and Australia, where a number of new liquefaction projects are expected to be operational within the next decade. Several LNG export projects have been proposed for western Canada and for the United States to convert underutilized LNG import facilities to liquefaction and export facilities. EIA projects the United States will become a net exporter of LNG in 2016, a net pipeline exporter in 2025, and an overall net exporter of natural gas in 2021. This outlook reflects increased use of LNG in markets abroad, strong domestic natural gas production, and relatively low U.S. natural gas prices. An MIT study presents another possible scenario, in which a more liquid international gas market could drive the cost of U.S. gas in 2020 above that of international markets, which in turn could lead to the U.S. importing 50 percent of its gas by 2050. Yet while increased LNG trade has started to connect international markets, these markets remain largely distinct with respect to supply, contract structures, market regulation, and prices.
Over the long term, greater international market liquidity could have several effects on the U.S. natural gas market and prices. Under low (i.e., less than 5 percent) export levels, relatively low domestic prices for natural gas would lead to expanded U.S. gas use. But more substantial export levels could drive up U.S. natural gas prices by diverting domestic surplus to the other areas of the world, where prices can be 3 to 4 times higher. Large gas-dependent industrial users, especially if they compete with producers from countries with access to low-cost natural gas, would likely be particularly hard hit by price run ups in the U.S. market. If a global market leads to significant price volatility, as has been the case with the oil market, it could discourage investment in new gas-based infrastructure or cause disruption in gas-reliant industries.
1. Unconventional resource accumulations tend to be distributed over a larger area than conventional resources, require greater pressure for extraction (have “low permeability”), and usually require advanced technologies and techniques such as horizontal wells or artificial stimulation in order to be economically productive.
3. In economic terms, the supply of natural gas is often referred to as reserves and is classified with two primary categories, proven and unproven. Proven reserves are those that are economically recoverable from known resources using currently available technology. Unproven reserves are those considered not economically or technically recoverable or somehow not producible for regulatory reasons.
5. U.S. Department of Energy, Energy Information Administration, “Annual Energy Outlook 2012: Early Release Overview,” January 23, 2012, Report Number DOE/EIA-0383ER(2012), page 9. Note that EIA’s estimated technically recoverable resource (TRR) 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.
8. Massachusetts Institute of Technology Energy Initiative, “The Future of Natural Gas: An Interdisciplinary MIT Study,” June 2011. 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.
9. Natural gas and natural gas liquids (NGLs) are a principal feedstock in the chemicals industry and a growing source of hydrogen production for petroleum refining. NGL 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. MIT Energy Initiative, “The Future of Natural Gas: An Interdisciplinary MIT Study,” June 2011, page 33.
11. A set of global supply curves describing the gas resources that can be developed economically at given prices is provided in MIT Energy Initiative, “The Future of Natural Gas: An Interdisciplinary MIT Study,” June 2011, page 25.
12. The liquefaction process for natural gas involves removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons. The natural gas is then condensed into a liquid by cooling it to approximately -162°C (-260 °F). The energy density of LNG is 60 percent that of diesel fuel.
13. Each terminal needs permits from the U.S. Environmental Protection Agency, the U.S. Federal Energy Regulatory Commission, and export authorization from the U.S. Department of Energy. Houston-based Cheniere Energy Inc. won approval to be the first company to export natural gas from the lower 48 states. See Saqib Rahim, “Cheniere Walks Financial Tightrope as It Banks on LNG Export Boom,” Energywire, March 27, 2012. Available at http://eenews.net/public/energywire/2012/03/27/1