U.S. States & Regions

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Highlights

• Greenhouse gases from the electric power sector can be reduced through more efficient electric generation technologies and by increasing the quantity of distributed generation, which is the generation of electricity at or near to where it will be consumed.
• In 2010, 67.7 percent of the primary energy produced, primarily at centralized electricity power stations, for the residential and commercial building sector was lost during generation and transmission. The majority of the energy loss occurs during the conversion of a fuel into electricity and is in the form of heat loss. Electricity is also lost during transmission and distribution; and on average about 7 percent of the electricity generated in the United States is lost during transmission.
• Increased direct use of natural gas in commercial and residential space heating and cooling, water heating, cooking as well as wet (clothes) cleaning could replace less efficient electricity end use.
• Increased use of higher efficiency distributed generation technology (e.g., natural gas-fueled solid-oxide fuel cells and microturbines) by residential and commercial end-users would result in less primary energy demand and fewer greenhouse gases emissions.
• High upfront capital costs are likely to discourage investment in new generation technologies, especially at a time when low natural gas prices are putting downward pressure on energy bills. Several states, however, provide financial incentives for residential and commercial consumers who install distributed generation systems, and the federal Investment Tax Credit helps to defray capital costs for commercial entities, 30 percent of the cost or up to $3,000/kW.[1]

Introduction

Technological advances in the exploration and production of natural gas have dramatically increased the quantity of economically recoverable reserves in the United States. The U.S. Energy Information Agency (EIA) estimates that there is enough natural gas to last more than 90 years at current consumption rates. The growing supply has put downward pressure on natural gas prices, making it an attractive and affordable energy source. Therefore, it is likely that natural gas consumption will increase in all sectors.

In 2010, residential and commercial buildings used natural gas for nearly 21 percent of their energy requirements (Figure 1). Electricity, created from various energy sources, is 61 percent of the natural gas was used in the residential sector and 39 percent was used in the commercial sector (Figure 1). Out of these totals, natural gas was used for 69 percent of residential and 50 percent of commercial space heating needs (Figure 2 and Figure 3). The other direct uses of natural gas are water heating, cooking, wet cleaning (clothes washing and drying) and space cooling to a much lesser extent. the most used energy form in these sectors.

Lower prices increase the likelihood of even greater use of natural gas for space heating and water heating, displacing home heating oil and some electricity use. Additionally, there will likely be renewed interest in natural gas air conditioning

systems, which are a very small portion of the current market (Figure 3). Future direct use of natural gas in the residential and commercial sector will probably be very different from today, particularly with regard to electricity generation. New distribution and end use generation technologies have the potential to change the way residential and commercial users approach natural gas, and many of these ways will significantly reduce greenhouse gases. Distribution technologies include distributed generation and microgrids. End use technologies include specific natural gas-fueled electricity devices like fuel cells and microturbines.

Distributed Generation

Distributed generation systems (also referred to as self-generation) consist of smaller electricity generating units located at or near where the electricity will be consumed. In the commercial and industrial sectors, where the majority of distributed generation occurs, natural gas-fueled electricity comprised approximately 54 percent of the total net generation in 2010, followed by renewable sources at around 22 percent and coal-fired generation at nearly 13 percent.

Distributed generation has many benefits compared to centralized electricity generation including: end user access to waste heat, increased electric system reliability, reduced peaking power requirements, reduced greenhouse gas emissions and reduced vulnerability to terrorism.[2] These benefits derive, in large part, because distributed generation technologies are better able to utilize more of the energy in the fuel. In 2010, 67.7 percent of the primary energy used for electricity generated for the residential and commercial building sector was lost during generation and transmission.[3] Converting primary energy at a central power station into electricity produces a large quantity of heat energy, which generally is not captured for productive use and is therefore lost. Additional energy is lost as the electricity is delivered from power stations to end users. U.S. annual electricity transmission and distribution losses average about 7 percent of the electricity that is transmitted.[4]

Line losses depend on the following factors: line voltage, line load, weather, altitude and the distance travelled; the higher the line voltage the fewer losses that a line will experience.[5] For example, for 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.[6] A 345kV line under the same conditions would see a loss on the order of 4.2 percent.[7] Since most local distribution companies operate below 35kV[8], losses as high as 10 to 15 percent are possible in these networks.[9] Not all of these local line losses are the result of transmission physics. Some losses result from meter inaccuracies and energy theft; although it is difficult to quantify these losses, and they are highly variable from region to region. All else equal, higher line loads, higher ambient temperatures or longer distances travelled, all lead to higher line losses.

New Ways to Generate Electricity

Microgrids

One distributed generation technology that is increasingly being examined is natural gas powered microgrids. A microgrid is a small power system composed of one or more generation units that can be operated in conjunction with or independently from the bulk transmission system.[10] Microgrids offer the potential to more readily integrate distributed renewable and non-renewable power with energy storage. Also, since the electricity is generated closer to where it will be used, it becomes feasible to use the waste heat in a productive manner, such as heating water or space in nearby homes and businesses. Microgrids can also be particularly attractive if new or upgraded long-distance transmission cannot be developed in a timely or cost-effective fashion.[11]

Fuel Cells

Source: Nationalgrid 2012

Fuel cells are another distributed generation technology. Natural gas fuel cells use natural gas and air to create electricity and heat through an electrochemical process rather than combustion.[12] First, natural gas is converted into hydrogen gas inside the fuel cell in a process known as reformation. When the hydrogen passes across the anode of the fuel cell stack (Figures 6 and 7), electricity, heat, water and carbon dioxide are created. As long as there is fuel, air and heat, the process continues producing energy.

Although there are many types of fuel cells, the type of fuel cell described here and the type of fuel cell that is generally being commercialized for distributed electricity generation is referred to as a solid oxide fuel cell (SOFC). Natural gas-fueled solid oxide fuel cells operate at temperatures about 1,800°F.[13]

ClearEdge Power, based in Oregon and established in 2003, manufactures refrigerator-sized fuel cell microCHP (micro combined heat and power) units that generate baseload or backup electric power as well as provide useable heat for hot water and/or space heating.[14] These units are scalable to suit the energy requirements of individual homes, apartment buildings, hotels or other commercial businesses, and can be installed indoors or outdoors. These units are up to 90 percent efficient; 50 – 60 percent efficient in natural gas conversion to electricity plus useful heat. Therefore, they require less natural gas to

Figure 6: Fuel Cell Stack

Source: U.S. Department of Energy 2011

Figure 7: How Fuel Cells Work

Source: ClearEdge Powe 2011

Fuel Cell Energy is a Connecticut based manufacturer of fuel cells for commercial, industrial, government and utility operations.[19] The company was an early pioneer in fuel cell research and conducted experiments with many types of fuel cells beginning in the 1970s.[20] Their Direct Fuel Cell (DFC) product range generate between 300kW and 2.8 MW, and are currently delivering power at more than 50 installations around the world with electricity conversion efficiencies up to 47 percent.[21]

Figure 8: Bloom Energy Server Outdoor Installation

Source: Bloom Energy 2012

Source: Clear Edge, Bloom Energy, Fuel Cell Energy

Fuel cell technology has been around for a long time; it has been used by NASA on space projects for nearly 50 years. Commercially available SOFCs are capable of operation at very cold and very warm climates (-4° to 113° C), and they have electrical efficiencies around 50 percent.[22]^,[23] They are quiet devices that require a fairly small footprint to operate, and the pure CO₂ emissions allow for easy sequestration. Despite these benefits, skeptics question the durability and reliability of fuel cells. In the past, materials have corroded within months or a few years. Bloom Energy estimates that its current devices will have a 10-year life as long as the fuel stacks are replaced at least twice. However, due to their recent introduction, there are currently no operational fuel cell systems that have approached this age.[24]

Microturbines

Microturbines are small combustion turbines approximately the size of a refrigerator with outputs up to 500kW.[25] These devices can be fueled by natural gas, hydrogen, propane or diesel. In a cogeneration configuration (Figure 10), the combined thermal electrical efficiency can reach as high as 90 percent.[26] Not unlike fuel cells, these devices are able to achieve much higher efficiencies than central power stations since the electricity is generated close to the source where it will be used, and the heat byproduct can be captured and utilized on site or nearby.

Figure 9: Microturbine Schematic

Source: Electric Power Research Institute 2003

Los Angeles-based Capstone Turbine Corporation is a global market leader in the commercialization of microturbines.[27] The company offers individual units in the range of 30kW to 200kW, although greater quantities of power can be achieved by using multiple units, with electrical efficiencies from 25 to 35 percent. Using the heat produced by a microturbine for water or space heating, space cooling (in conjunction with absorption chillers) and/or process heating or drying, increases the efficiency of these units to 70 to 90 percent.[28] Capstone products service the commercial and industrial sectors, and they have installations all over the world, including universities, a winery and 35-story office tower in New York City.[29]

Flex Energy, also headquartered in California, is Capstone’s main competitor. Its 250kW microturbine offering has an electrical efficiency of 30 percent, and it too provides useful heat energy.[30] Flex Energy microturbines can use low quality and unrefined natural gas, making them capable of generating electricity at landfills and hydraulic fracturing sites.[31]

Micro Turbine Technology (MTT), a company in the Netherlands, is currently developing a 3kW electrical with 15kW thermal microCHP for homes and small businesses, which is expected to be ready for market in late 2012 or early 2013.[32]

At 31 percent average electrical efficiency, much lower than a modern natural gas combined cycle plant or fuel cell (both around 50 percent), microturbines produce 1,290 pounds of CO₂/MWh.[33] However, due to their ability to capture and utilize waste heat on-site, they are capable of achieving thermal electrical efficiencies greater than 80 percent. Additional strengths of microturbines include: compact size, small number of moving parts, generally lower noise than other engines, and long maintenance intervals; weaknesses include parasitic load loss from running a natural gas compressor and loss of power output and efficiency with higher ambient temperatures and elevation.[34] According to U.S. Environmental Protection Agency (EPA) data, at 80°F outdoor air temperature, the microturbines are about 3 percent less efficient than at 50°F outdoor air temperature.[35]

Table 2: Microturbine Summary

Stirling Engines

The WhisperGen, developed in New Zealand, is a microCHP technology based on the Stirling engine. The company is currently headquartered in Spain, where the product is being marketed to European customers. The washing-machine sized microCHP technology is designed to produce hot water and space heating. However, under normal operation the unit will provide around 1kW of electrical power.[36]

Policies to Incentivize Deployment of New Technologies

While there is significant potential for new technologies to use less primary

Source: Capstone, Flex Energy, MTT

Figure 11: WhisperGen MicroCHP

Source: WhisperGen User Manual 2007

Net metering programs serve as an important incentive for consumer investment in on-site energy generation.[40] Net metering allows an electricity meter to turn backwards when the site generates electricity in excess of its demand, enabling customers to receive retail prices for their excess generation. 43 states and the District of Columbia have rules supporting net metering.[41] Eligible generation technologies vary; however, fuel cells using any fuel type often qualify and cogeneration or CHP qualifies to a lesser extent.

Grid interconnection provides a source of backup power for sites using distributed generation. According to the EPA, standard interconnection rules establish clear and uniform processes and technical requirements that apply to utilities within a state.[42] These rules reduce uncertainty and prevent time delays that distributed generation systems can encounter when obtaining approval for electric grid connection.[43] As of April 2012, 34 states had interconnection standards for fuel cells and 29 states had such standards for microturbines.[44]

Standby rates are charges levied by utilities when a distributed generation system experiences a scheduled or emergency outage, and then must rely on power purchased from the grid.[45] These charges are generally composed of an energy charge, which reflects the actual energy provided, and a demand charge, which attempts to recover the costs to the utility of providing capacity to meet the peak demand of the facility.[46] Utilities often argue that demand charges act as a strong incentive for system owners to manage their peak demand.[47] The use of demand charges can discourage use of distributed generation. The likelihood of unplanned outages during times of peak demand is low. When approving demand charges regulators should consider the benefits of distributed generation, including increased system reliability and reduced distribution losses, in addition to utilities’ capacity requirements.[48]

Barriers to Deployment

Consumer unfamiliarity with distributed generation technologies will likely slow their deployment. Also, stable utility bills due to low wholesale electricity prices (a result of lower natural gas prices) and, in the short term, uncertainty around the future growth of business activity will probably not motivate consumers and businesses to consider adopting new technologies.

Consumer awareness of low natural gas prices may be spurring those without access (infrastructure and physical connections) to seek how they can gain access to natural gas. Those with access may be considering the costs of owning, operating and maintaining electrical and natural gas appliances, including natural gas distributed generation technologies.

Fuel cells could be cost competitive if they reach an installed cost of $1,500 or less per kilowatt; but, the current installed, unsubsidized cost is approximately $4,000+ per kilowatt.[49] Nevertheless, an analysis by Seattle City Light, shows that with a combination of California state and federal subsidies as well as low natural gas prices, the Bloom 100kW energy server could make economic sense for California companies with high monthly energy bills.[50]

Figure 12: Bloom Energy Server Cost Depends on Gas Price and Subsidies

Source: Seattle City Light 2010

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Highlights

• There were more than 4.8 million commercial buildings in the United States in 2003.
• Space heating and lighting are the largest uses of energy in commercial buildings, representing 38 percent and 20 percent of total site use respectively.
• The choice of electricity or natural gas use within the sector is dependent on building use, size, and geographic location.
• Health care and educational buildings use natural gas more commonly than other commercial building types.

Introduction

Energy is delivered to 4.8 million commercial and institutional buildings in the United States via four primary means: electricity, natural gas, district heat, and fuel oil. Electricity and natural gas accounted for 87 percent of all commercial energy in 2003 (Figure 1). 2003 was the last time that the US Energy Information Administration (EIA) conducted the Commercial Building Energy Consumption Survey (CBECS) and the next survey is scheduled to begin in April 2013. The latest survey collected data on nearly 7,000 buildings that were selected to statistically represent the more than 4.8 million commercial buildings in the U.S.[1] The commercial building sector is not dominated by any one building type or use. Office buildings are the most common type (as defined by floor space), followed by mercantile, warehouse and storage, and education. Small buildings (1,000 to 5,000 square feet) account for more than half of all buildings (as defined by the number of buildings) but only 10 percent of total energy use. Energy use in these buildings varies substantially, reflecting the diversity of size, purpose, and location. For example, buildings used for health care are very energy intensive, consuming 9 percent of total energy, but accounting for just 3 percent of buildings. Conversely, warehouse and storage buildings account for 14 percent of floor space but only 7 percent of total energy.

Figure 1: U.S. Commercial Energy Consumption by Source, 2003

Source: EIA 2003

Figure 2: U.S. Commercial Energy Consumption by Use, 2003

Source: EIA 2003

Building activity also influences the type of energy used. Office buildings tend to utilize electricity rather than natural gas because many of their primary loads such as lighting, elevators, personal computers and servers, scanners, printers, and others cannot be served by natural gas. Lodging, health care, and food service, in contrast can more easily use natural gas for cooking, hot water, cleaning, and laundry. Consequently, these facilities use proportionally more natural gas than office buildings.

In the residential energy sector, space and water heating are the two largest energy loads. In the commercial sector, space heating and lighting are the two largest energy loads (Figure 2). The third largest energy use is roughly shared between water heating, space cooling, ventilation, and refrigeration.

Of course, Figures 1 and 2 represent an average for the country across all commercial segments, building types, sizes, ages, and climate zones. Climate plays a large role in determining what type and how energy is used; the majority of commercial buildings reside in colder climate zones (zones 1 to 4), which includes much of the country except for the Deep South and the arid Southwest. In these zones, winters are cold enough for frequent, substantial space heating, and the average amount of energy needed to heat a building during the winter, measured in Heating Degree Days (HDDs), is two to four times the average amount of energy needed to cool a building during the summer, measured in Cooling Degree Days (CDDs) (Figure 3).[2] For space heating, natural gas is the predominate fuel in colder climate zones, providing heat for 69 to 75 percent of all floor space in the coldest zones but dropping to 47 percent in zone 5, the warmest region.[3] Therefore, natural gas is the lead fuel source for heating in commercial buildings nationally.

Electricity is nearly ubiquitous in commercial buildings throughout the United States, but natural gas use is closely correlated to specific commercial sectors. The three most energy intensive sectors (in Btu per square foot) are food service, food sales, and health care, which use 258, 200, and 188 Btu per square foot respectively.[4] While 84 percent of food service square footage is served by natural gas, for food sales, that figure is only 60 percent. This difference is due to the large amount of thermal energy required in cooking and cleaning in the food service sector, while food sales energy use is predominantly for refrigeration. Likewise, 95 percent of in-patient health care building stock is served by gas due to food preparation, hot water, and cleaning demands, while only 59 percent of outpatient health care facilities use gas.[5]

Figure 3: U.S. Climate Zones, Heating Degree Days vs. Cooling Degree Days

Source: US EIA 2004

Table 1: Number of Buildings & Total Consumption by Size, 2003

Source: US EIA CBECs 2003

Commercial Building Emissions Profiles

As discussed in the paper “Natural Gas Use in the Residential Sector,” Full Fuel Cycle (FFC) efficiency and associated emissions analysis provides a true baseline comparison when evaluating the energy and emissions impacts of commercial buildings powered by different fuel sources. Due to the 32 percent average efficiency of grid-delivered electricity and the predominance of fossil-fuel-fired power plants in the United States, buildings that rely on grid electrical power for the majority of their energy use have the highest emissions profiles. Office space is the largest electricity consumer, responsible for the consumption of 2,170 trillion Btu of fuel needed to deliver the 719 trillion Btu of electricity these buildings consumed. Education is the second largest, responsible for the consumption of 1,121 trillion Btu of energy needed to deliver 371 trillion Btu of consumed electricity. These two type of commercial buildings account for 36 percent of all the electricity used in buildings and because they rely on grid-delivered electricity rather than on-site generation they also have the highest emissions profiles.[7]

In 2008, the Energy Information Administration reported that buildings consumed 40 percent of the country’s primary energy resources and 74 percent of its electricity.[8] Figure 4 shows that for 2008, the site consumption of gas and electricity by residential and commercial buildings was 8.28 and 9.37 quadrillion Btu respectively for a total site consumption of 17.65 quadrillion Btu. However, the losses associated with generating and delivering the 9.37 quadrillion Btu of electricity were more than 20 quadrillion Btu.[9] If grid-supplied electricity use continues to grow and natural gas use remains flat, as forecast by the EIA, growth in total energy consumed by buildings will be three times that of the growth in electricity consumed.

Commercial and residential energy use has been a growing contributor to CO₂ emissions for the last two decades, and the trend is forecast to continue, as shown in Figure 5.[10] This trend is being driven not only by the increase in electricity use, but also by the low average efficiency of on-grid electricity and the high average carbon fuel intensity of the U.S. electricity generation portfolio. Additionally, the high level of coal use in U.S. electricity production, leads to significant increases in sulfur dioxide (SO₂), nitrogen oxides (NO_X), and mercury emissions with increased electricity use.

Figure 4: Residential and Commercial Energy Use Trends

Source: EIA Annual Energy Outlook 2009

Figure 5: Combined Residential and Commercial CO2 Emission Trends

Source: EIA Annual Energy Outlook 2009

Natural gas use provides a means to increase a building’s total FFC efficiency and decrease its emissions profile. This improvement is most readily achieved in thermal applications, such as natural gas space heating and water heating. In these uses, while natural gas has a comparable or slightly lower site efficiency than electrical appliances, natural gas is two to three times more efficient than electricity, on an FFC basis.[11] Buildings with older natural gas- or oil-fired boilers and furnaces can also improve their efficiency and lower their emissions by upgrading to newer models.

Combined heat and power operations (CHP) also provide a means for buildings that have primarily electrical demand to make efficiency gains and emission reductions, as explained in the paper “Natural Gas in the Industrial Sector.” Modern solid oxide fuel cell (SOFC) and micro-turbine technologies provide a means for buildings to generate their own electrical power, on site, with natural gas, at FFC electrical efficiencies as high as 50 percent. The waste heat generated by these devices can then be used for space heating, water heating, and other thermal loads to raise the overall FFC efficiency of the devices to greater than 80 percent.[12] These technologies and others are explained in the paper “Distributed Generation and Emerging Natural Gas Technologies.”

The use of micro-turbines operating in CHP mode has gained acceptance primarily in the in-patient hospital, hotel, and resort sectors. These facilities have large electrical loads and nearly comparable thermal loads for space heating, water heating, cooking, and laundry. These large and year round (in the case of all but space heating) thermal loads provide a ready use for the waste thermal energy provided by the micro-turbine. This allows them to operate at near peak efficiency not only around the clock but also year round.

Barriers to Natural Gas Access and Efficiency in the Commercial Sector

There are several barriers to increased use of natural gas in commercial buildings. One of the largest may be the high percentage of non-owner-occupied buildings and its influence in construction of commercial buildings. A large percentage of office and warehouse floor space is designated as non-owner operated. These buildings are designed and built by real-estate developers who then rent or lease the space to tenants. On a floor space basis, 49 percent of private commercial buildings are owner-occupied and 51 percent are non-owner-occupied.[13] The “for lease” building sector is extremely competitive and rental cost per square footage is a key metric in attracting renters. The focus on least cost development can drive builders to prioritize construction cost over minimizing operating costs (especially if operating costs are paid for by tenants and not building owners). This approach can preclude installation of high efficiency and lower emission systems that use fuel, on site, for electricity generation and heating applications.

Owner-operators, those who design and construct buildings for their own use, on the other hand, are more inclined to factor in operating costs of the buildings they construct and thus tend to install more energy efficient systems and subsystem components. This focus on the longer term operational costs of buildings and the advantage of higher efficiency systems is true in public and institutional buildings as well.

Figure 6: Growth of LEED Certified Space

Source: U.S. Green Building Council 2010

Commercial building codes, or lack thereof, are also a barrier to the development of higher efficiency and lower emissions buildings. In 1992, the building code requirements of the Federal Energy Policy Act, which were based on 1989 industry standards, were met by only five states. By 2008, 40 states had statewide commercial building codes that met or exceeded the 1989 Federal standards, but only twenty-seven met the higher standards issued by the Department of Energy in 2004. This lead/lag effect in the setting and meeting of standards is indicative of a non-owner-operated building market that still places operating costs at a lower priority than construction costs. Federal requirements, however, are not the only drivers. California for example, has sets standards higher than the federal government and some utilities such as Austin Energy in central Texas, have worked with the Austin city government to push standards and building codes beyond the industry norm. In both examples, it appears that civic concern and location have made a difference.

There is also some evidence that the introduction of non-government building standards such as the Leadership in Energy and Environmental Design (LEED) standards, developed and promoted by the U.S. Green Building Council, are helping to educate the real estate industry and potential tenants on the financial benefits of focusing on long-term operating and environmental costs. Many municipalities, school districts, counties and states have adopted LEED standards for their new buildings leading to an exponential growth in the number of LEED certified buildings, as shown in Figure 6.[14] This practice is having a spillover effect in the “build to suit” and lease markets as well. LEED, or similar, certifications are now often seen as a minimum requirement in building quality by potential renters and are being recognized by owners as contributing to increased resale value.

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Highlights

• Greenhouse gas (GHG) emissions from natural gas infrastructure totaled 72.3 million metric tons of carbon dioxide equivalent (CO2e) in 2010, 1.06 percent of total U.S. emissions.
• Natural gas infrastructure can reduce emissions directly, through lower emissions from equipment and leaks, or indirectly, by providing natural gas access to consumers to replace of higher-emitting fuels, such as coal, petroleum, and home-heating oil.
• In order to leverage natural gas to reduce GHG emissions, natural gas must be accessible where it can have the most impact for fuel switching and electricity replacement.

• Natural gas infrastructure includes long-lived capital assets and expanded deployment faces significant financial, environmental, pipeline location siting, and regulatory.

Figure 1: U.S. Natural Gas System

Source: Pipeline & Hazardous Materials Safety Administration 2011

Introduction

The United States has the world’s most extensive infrastructure for transporting natural gas from production and importation sites to consumers all over the country. This transport infrastructure^[1] is made up of three main components: gathering pipelines, transmission pipelines, and distribution pipelines. Though fundamentally similar in nature, each of these components is designed for a specific purpose, operating pressure and condition, and length. These components are linked together in networks, as illustrated in Figure 1, to form our natural gas infrastructure system. Increasing demand for natural gas in the power, transportation, and industrial sectors as well as in residential and commercial buildings requires significant system expansion to take advantage of potential greenhouse gas (GHG) emission reductions, cost savings, and energy security benefits, while at the same time minimizing methane leakage.

Almost all natural gas used in the United States is produced in North America, from onshore or offshore wells, or to a much lesser extent, biogas production sites. It first enters the transport network through gathering pipelines which collect natural gas from the point of production or importation and transport it to processing facilities. Gathering pipelines are usually short, small in diameter, operate at low pressures and are used to transport natural gas from the wellhead to processing facilities. In 2011, there were 19,662 miles of gathering pipelines in the United States originating at over 460,000 wellheads.^[2] Most renewable biogas from landfills or animal waste is currently used onsite. It may also be carried by the transport system, but further research is needed to ensure that it can be processed properly and safely added to the existing system, which was built to withstand the constituents of geologically-formed natural gas.^[3]

At various points along the gathering and transmission networks, natural gas can be stored temporarily underground in depleted oil or natural gas fields, aquifers, and salt caverns. This storage is used to avoid temporary imbalances between supply and demand on the network, such as during a relatively warm winter with unexpectedly low demand for natural-gas generated power. In 2007, there were 400 of these storage facilities in existence.

To reach homes and businesses, natural gas leaves the transmission pipeline network and enters the “city gate station”, where local distribution companies (LDCs, local gas utilities) add odorant, and lower the pressure before distributing it to residential and commercial customers. Local distribution companies move the gas through a series of main pipelines throughout the LDC service territory with individual service lines that branch off of the main lines to reach each consumer. Natural gas “regulators” are devices in homes and businesses that accept the incoming gas from the highly-pressured pipelines and employ a series of valves to lower the pressure of the gas to meet appliance specifications. Distribution pipelines are much smaller pipelines, often only 0.5 to 2 inches in diameter, with pressures at only a fraction of those of larger transmission pipelines. They may be made of plastic, which is less likely to leak than metal. Although made up of narrow pipes, the distribution networks utilized by LDCs are extensive, with more than 2 million miles of main and individual service pipelines in 2011.^[6]

Together these components of natural gas infrastructure comprise an important asset that provides access to energy for all sectors of the economy. However,  it is  a large, dispersed asset, that is often out of sight – either buried or in remote locations and often crossing state lines. Sometimes they exist within rights-of-way also occupied by other users, like roads or private property. These factors make monitoring and regulation of pipelines complex.

Pipelines are regulated by both the federal and state governments. In 2007, 81 percent of natural gas in the United States flowed through transmission pipelines that cross state boundaries. The Federal Energy Regulatory Commission (FERC) regulates the rates and services of these interstate pipelines, as well as the construction of new interstate pipelines. Other pipelines located within states (intrastate pipelines) are regulated by state regulatory commissions. State regulatory commissions regulate both transmission lines and local distribution companies for pipeline siting, construction, expansion, and rate structure.^[7]

The federal government also regulates and enforces pipeline safety through the Department of Transportation, which works closely with state governments on pipeline inspection and safety protocols. Corrosion and defects can lead to leaks with serious safety and environmental implications. Visual inspection of natural gas infrastructure is difficult and complete replacements are nearly impossible given the extent of the network and the underground location. Instead, robotic inspection tools, often called “pigs,” can be sent through pipelines to detect leaks, check pipeline conditions, and monitor for weaknesses.^[8]

Figure 2: U.S. Natural Gas Supply Basins Relative to Major Natural Gas Pipeline Transportation Corridors, 2008

Source: Energy Information Administration 2012

Regional Differences in Infrastructure and Expansion

Existing natural gas infrastructure reflects historical supply and demand for the fuel (explored in the other papers of this Initiative) and so varies across the country. Gathering line networks are most extensive from wellheads in traditional producing states like Texas, Oklahoma, and Louisiana, and most existing intrastate transmission lines are designed to take the fuel from those states to manufacturers and consumers in the Midwest and Northeast. The relative flow of natural gas through existing pipelines is illustrated in Figure 2.

Recent supply increases, lower prices and increased demand have all led to a need for expanded infrastructure, including gathering, transmission, and distribution pipelines, which can bring natural gas to users that may replace existing higher carbon fuel sources and achieve climate benefits. In a 2009 study, ICF International estimated that new changes in supply and demand will require that 28,000 to 61,900 miles of new pipelines be constructed in North America by 2030, and $108 to $163 billion worth of investment. ICF’s analysis suggested additional storage capacity of 371 to 598 Bcf will be needed over the same time period, at a cost of $2 to $5 billion.^[9] Current trends in natural gas supply and demand indicate that expansion is likely to fall on the higher ends of the ICF study.^[10]

Similarly, new demand for natural gas appliances, industrial use, distributed generation and vehicle fueling in homes and businesses will also likely increase the need to expand local distribution networks. Investments are necessary in new mains, service lines, meters, and regulators that can service new customers. Indirect investments will also be required to enhance the capacity of the overall system, including for control rooms, main reinforcements, and improved flow design.^[11]

Direct Emissions Reductions from Natural Gas Infrastructure

Natural gas is primarily composed of methane, a highly flammable and very potent GHG. Throughout the transportation of the fuel from gathering at the well to distribution to end-use consumers, there is potential for methane to leak into the atmosphere from production wells, valves, compressor stations, faulty seals, pressure regulators and even broken pipes. While methane leakage and accumulation can be an important safety issue, unintentional leakage can also have significant implications for the climate and for the relative benefits of substituting natural gas for other fuel sources. The methane released into the atmosphere unintentionally in this fashion is referred to as a “fugitive emission.” At natural gas storage facilities, emissions may come from compressors and even dehydrators. At the local distribution level, fugitive emissions escape at the city gate stations from valves, seals and pressure regulators.^[12] While some CO₂, methane, and nitrogen oxides (NO_X) can also be emitted by compressors that often combust small amounts of natural gas for their energy, fugitive emissions make up the majority of all GHG emissions from natural gas infrastructure.^[13]

In addition to fugitive emissions, methane can also be intentionally released or vented as part of the production process at the wellhead, or to reduce pipeline pressure. For safety and environmental reasons though,  methane is often burned off in a process called “flaring,” rather than venting. Flaring essentially combusts the methane on site forming CO₂, a less potent GHG.^[14] Flaring of methane most often occurs when gas is found as a byproduct or co-product of other fossil fuels and insufficient gathering pipeline exist to take natural gas to market. In Texas, where gathering pipeline networks are well developed, in 2012 less than 1 percent of the natural gas produced is flared whereas in North Dakota, production of gas associated with the Bakken Shale formation results in almost 32 percent of the gas being flared, primarily due to a lack of infrastructure to transport the natural gas.^[15] Venting and flaring at natural gas production sites were the subject of Environmental Protection Agency New Source Performance Standards for oil and gas wells in August 2012. The new regulations require that new wells utilize “green completion” technology that will allow excess natural gas from the well completion process to be taken to market, rather than flared.^[16]

In 2010, methane emissions from transmission pipelines and storage totaled 43.8 million metric tons of CO₂e, while emissions from distribution networks totaled 28.5 million metric tons. These figures have been fairly consistent over time as network expansion has been offset by better system management (including leak detection), more energy efficient technology, and equipment replacement with new materials that are less subject to leakage. While methane emissions from natural gas infrastructure are a very small portion of the nation’s total GHG emissions, (Figure 3 and Figure 4), methane is a potent greenhouse gas, with 37 times the radiative forcing of CO₂, and an effective lifetime of 12 years. With these properties, reduction of leakage to the atmosphere is vital to ensuring that natural gas use has climate benefits when compared to other fossil fuels it may replace.^[17]

Figure 5: U.S. Methane Emission Sources, 2010

Source: Environmental Protection Agency 2012

Fortunately, there are many technologies and process improvements that can reduce the methane emissions from natural gas infrastructure. The federal Natural Gas Star program, for example, has worked with industry to identify technical and engineering solutions to fugitive and combustion-related emissions from infrastructure equipment including zero bleed pneumatic controllers, improved valves, corrosion-resistant coatings, dry seal compressors, as well as improved leak detection and repair strategies. The solutions identified by this voluntary program often have payback periods of less than three years, depending on the price of natural gas. Infrastructure sector participants in Natural Gas Star have reported that methane emission were reduced by 15.9 Bcf in 2010 and over all, a total of 276.5 Bcf of GHG have been reduced since the program began in 1993.^[19] For local distribution companies, the increased use of inexpensive and durable plastic pipes has also reduced emissions from these low-pressure networks, although the material is not strong enough to be used in high-pressure transmission lines.^[20]

Barriers to Infrastructure Development

Other papers in our C2ES-UT Natural Gas series have examined how natural gas may be used to reduce emissions in the power, industrial, and transportation sectors, as well as in commercial and residential buildings. Expanded uses of natural gas require an expanded infrastructure and an expansion faces significant hurdles. Like many other types of infrastructure, pipelines are long-lived capital assets with complicated financing and economics. Interstate transmission pipelines have rates of return that are regulated by FERC. Large transmission pipelines must also line up project finance or debt to fund construction, which may be complicated by intricacies of individual projects, including the contracts for supply and demand of the carried natural gas as well as the specific physical needs of pipeline construction.^[21]

For local distribution networks, the costs of expansion and upgrades vary considerably depending on whether the network is being expanded to new or existing communities, the density of the neighborhood, and the terrain. For new distribution pipelines to be built in urban areas, they must contend with a variety of challenges, including costly repairs of overlaying roads and landscaping, negotiations with surface and other subsurface rights-of-way holders, and public inconveniences. Accordingly, new urban pipelines can cost five times as much as rural ones.^[22] Costs can be lowered when buildings are designed and constructed ready for natural gas access. Retrofitting buildings is more expensive when preparations are not made for internal building piping and hook-ups to natural gas supplies, should they be added later.

At the same time, the financing of these LDC investments holds its own challenges. Traditionally, expansion costs are based on a regulated ratemaking where the costs are only recovered after the investment is made. This situation creates a lag between when investments are made and when they can be paid for. State-level innovation has provided some policy options to overcome financing challenges. Some states, like Colorado, authorize tracker mechanisms allowing rates to change in response to operating costs and conditions. Others, like Georgia, permit surcharges for cost recovery., Some, like Nevada, allow the use of a deferred accounting mechanism so that costs can be better aligned with ratemaking cases before state regulatory commissions. Seven southern states, like Texas, have decoupled gas consumption and cost recovery to create what is known as a “rate stabilization method.”^[23]

Pipelines are also impacted by a number of other project-specific requirements and regulations at the federal, state, and local levels. These requirements pertain to route selection, siting, and project approval by regulatory agencies that may all be affected by environmental, safety, community, operation, construction timing, and cost concerns. The size of the challenge for any individual project may vary significantly depending on the pipeline and the jurisdictions it crosses. For natural gas to realize its climate benefits, these barriers to expanding our gas infrastructure must be overcome.^[24]