Air Quality Issues in Natural Gas Systems
Released: 2013-04-16T00:00:00

Background

Congressional interest in U.S. energy policy has focused in part on ways through which the United States could secure more economical and reliable fossil fuel resources both domestically and internationally. Recent expansion in natural gas production, primarily as a result of new or improved technologies (e.g., hydraulic fracturing) used on unconventional resources (e.g., shale, tight sands, and coal-bed methane), has made natural gas an increasingly significant component in the U.S. energy supply. While the practice of hydraulic fracturing is not new, relatively recent innovations have incorporated processes such as directional drilling, high-volume slick-water injection, and multistage fractures to get to previously unrecoverable resources. As a result, the United States has again become the largest producer of natural gas in the world. The U.S. Energy Information Administration (EIA) projects unconventional gas activity to more than double from 2010 to 2040, and forecasts that it will make up almost 80% of total U.S. natural gas production by 2040. In addition, some analysts believe that by significantly expanding the domestic gas supply, the exploitation of new unconventional resources has the potential to reshape energy policy at national and international levels—altering geopolitics and energy security, recasting the economics of energy technology investment decisions, and shifting trends in greenhouse gas (GHG) emissions.

Many in both the public and private sector have advocated for the increased production and use of natural gas because the resource is domestically available, economically recoverable, and considered a potential "bridge" fuel to a less polluting and lower GHG-intensive economy. Natural gas is cleaner burning than its hydrocarbon rivals, emitting, on average, about half as much carbon dioxide as coal and one-quarter less than oil when consumed in a typical electric utility plant. Further, natural gas combustion emits no mercury—a persistent, bioaccumulative neurotoxin—virtually no particulate matter, and less sulfur dioxide and nitrogen oxides, on average, than either coal or oil. For these reasons, pollution control measures in natural gas systems have traditionally received less attention relative to those in other hydrocarbon industries. However, the recent increase in natural gas production, specifically from unconventional resources, has raised a new set of concerns regarding environmental impacts. These concerns centered initially on water quality issues, including the potential contamination of groundwater and surface water from hydraulic fracturing and related production activities. They have since incorporated other issues, such as water management practices (both consumption and discharge), land use changes, induced seismicity, and air pollution. The new set of questions about hydraulic fracturing in unconventional reservoirs has led, in part, to various grassroots movements, some political opposition, and calls for additional regulatory actions, moratoria, and/or bans at the local, state, and federal levels.

Currently, the development of natural gas in the United States is regulated under a complex set of local, state, and federal laws that addresses many—but not all—aspects of exploration, production, and distribution. State and local authorities are responsible for virtually all of the day-to-day regulation and oversight of natural gas systems. The organization of this oversight within each gas-producing jurisdiction varies considerably. In general, each state has one or more regulatory agencies that may permit wells, including their design, location, spacing, operation, and abandonment, and may regulate for environmental compliance. With respect to pollution controls, state laws may address many aspects of water management and disposal, air emissions, underground injection, wildlife impacts, surface disturbance, and worker health and safety.

Furthermore, several federal statutes address pollution control measures in natural gas systems; and, where applicable, these controls are largely implemented by state and local authorities. For example, the Clean Water Act (CWA) regulates surface discharges of water associated with natural gas drilling and production, as well as contaminated storm water runoff from production sites. The Safe Drinking Water Act (SDWA) regulates the underground injection of wastewater from crude oil and natural gas production, and the underground injection of fluids used in hydraulic fracturing if the fluids contain diesel fuel. The Clean Air Act (CAA) limits emissions from associated engines and gas processing equipment, as well as some natural gas extraction, production, and processing activities.

The Natural Gas Industry

Natural gas is a nonrenewable fossil fuel that is used both as an energy source (for heating, transportation, and electricity generation) and as a chemical feedstock (for such varied products as plastic, fertilizer, antifreeze, and fabrics). Raw natural gas is commonly recovered from geologic formations in the ground through drilling and extraction activities by the oil and gas industry. This industry includes operations in the extraction and production of crude oil and natural gas, as well as the processing, transmission, and distribution of natural gas. For both operational and regulatory reasons, the sector is commonly separated into four major segments: (1) crude oil and natural gas production, (2) natural gas processing, (3) natural gas transmission and storage, and (4) natural gas distribution (see Figure 1 ). This report uses these basic categories to track the various activities in natural gas systems, including the operations, emissions, and regulations discussed below. While the focus of this report is on the production sector, it also highlights air quality issues in other sectors, where appropriate. Below is a brief outline of the crude oil and natural gas industry. For more detail regarding specific activities or equipment, see the glossary of terms provided in Table C -1 .

Production (Upstream). Production operations include the wells and all related processes used in the extraction, production, recovery, lifting, stabilization, separation, and treating of oil and/or natural gas (including condensate). Production operations span the initial well drilling, hydraulic fracturing, well completion, and workover activities and cover all the portable non-self-propelled apparatus associated with those operations. Production sites include not only the ''pads'' where the wells are located, but also the stand-alone sites where oil, condensate, produced water, and gas from several wells may be separated, stored, and treated, as well as the low pressure, small diameter, gathering pipelines and related components that collect and transport the oil, gas, and other materials and wastes from the wells to the refineries or natural gas processing plants.

Processing (Midstream). Natural gas is primarily made up of methane. However, in its raw state, natural gas is a mixture of various hydrocarbons and may contain trace amounts of other chemical substances that must be removed before distribution. The additional hydrocarbons are often referred to as natural gas liquids (NGL). They are sold separately and have a variety of different uses. Raw natural gas may also contain water vapor, nonhydrocarbon compounds, and other chemical substances. Processing operations are used to separate out the additional components from raw natural gas to produce ''pipeline quality'' or "dry" natural gas for consumption.

Transmission and Storage (Downstream) . Dry natural gas leaves the processing segment and enters the transmission segment. Pipelines in the natural gas transmission segment can be interstate pipelines, that carry natural gas across state boundaries, or intrastate pipelines, that transport the gas within a single state. While interstate pipelines may be of a larger diameter and operate at a higher pressure, the basic components are the same. To ensure that the natural gas flowing through any pipeline remains pressurized, compressor stations are required at regular intervals. Further, to ensure proper load balancing during the delivery and receipt of natural gas, the transmission segment often includes storage facilities, typically consisting of both man-made and natural sites, such as depleted gas reservoirs and/or salt dome caverns.

Distribution . The distribution segment is the final step in delivering natural gas to customers. The natural gas enters the distribution segment from delivery points located on interstate and intrastate transmission pipelines and then flows to business and household customers. Nationwide, natural gas distribution systems consist of thousands of miles of pipes, including mains and service lines to the customers. Distribution systems also include compressor and metering stations, which allow companies to both move and monitor the natural gas in the system. The delivery point where the natural gas leaves the transmission segment and enters the distribution segment is often called the ''citygate.'' Typically, the citygate serves as the transfer point of ownership from producers to utilities.

Air Quality Issues in Natural Gas Systems

Raw natural gas is a mixture of various hydrocarbons (primarily methane) and may contain trace amounts of other chemical substances that must be removed before distribution. Air pollutants associated with the natural gas industry may be emitted through the release of natural gas vapors (either purposefully or accidently), the combustion of natural gas (either for use or for safety/disposal), the combustion of other fuel resources (for process heat, power, and electricity), and the discharge of particulate matter during construction, transportation, and associated operations. Sources of emissions include pad, road, and pipeline construction; drilling, completion, and flowback activities that occur during the development of a well; and gas processing and transmission equipment such as controllers, compressors, dehydrators, pipelines, and storage vessels. Pollutants include, most prominently, methane and volatile organic compounds, of which the natural gas industry is one of the highest emitting industrial sectors in the United States. Pollutants also include nitrogen oxides, sulfur dioxide, particulate matter, and various forms of hazardous air toxics, including n-hexane, the BTEX compounds (i.e., benzene, toluene, ethylbenzene, and xylene), and hydrogen sulfide.

Emissions

Natural gas systems release air emissions in several ways. This report categorizes these emissions into three types: fugitive , combusted , and associated .

Fugitive . Fugitive refers to the natural gas vapors that are released to the atmosphere during industry operations. Fugitive emissions can be either intentional (i.e., vented) or unintentional (i.e., leaked). Intentional emissions are releases that are designed specifically into the system: for example, emissions from vents or blow-downs used to guard against over-pressuring; or gas-driven equipment used to regulate pressure, store, or transport the resource. Conversely, unintentional emissions are releases that result from uncontrolled leaks in the system: for example, emissions from routine wear, tear, and corrosion; improper installation or maintenance of equipment; or the overpressure of gases or liquids in the system. Fugitive natural gas is primarily a mixture of low molecular-weight hydrocarbon compounds that are gaseous in form at normal conditions. While the principal component of natural gas is methane (CH 4 ), it may contain smaller amounts of other hydrocarbons, such as ethane, propane, and butane, as well as heavier hydrocarbons. These nonmethane hydrocarbons include types of volatile organic compounds (VOCs), classified as ozone (i.e., smog) precursors, as well as, in some cases, hazardous (i.e., toxic) air pollutants (HAPs). Nonhydrocarbon gases, such as carbon dioxide (CO 2 ), helium (He), hydrogen sulfide (H 2 S), nitrogen (N 2 ), and water vapor (H 2 O), may also be present in any proportion to the total hydrocarbon content. The chemical composition of raw natural gas varies greatly across resource reservoirs, and the gas may or may not be "associated" with crude oil resources. When natural gas is found to be primarily methane, it is referred to as "dry" or "pipeline quality" gas. When natural gas is found bearing higher percentages of heavier hydrocarbons, nonhydrocarbon gases, and/or water vapor, it is commonly referred to as "wet," "rich," or "hot" gas. Similarly, quantities of VOCs, HAPs, and H 2 S can vary significantly depending upon the resource reservoir. VOC and HAP compositions typically account for only a small percentage of natural gas mixtures; however, this ratio increases the "wetter" the gas. Natural gas mixtures with a higher percentage of H 2 S are generally referred to as "sour" or "acid" gas.

Combusted. Combusted refers to the byproducts that are formed from the burning of natural gas during industry operations. Combusted emissions are commonly released through either the flaring of natural gas for safety and health precautions or the combustion of natural gas for process heat, power, and electricity in the system (e.g., for compressors, dehydrators, and other machinery). The chemical process of combusting natural gas releases several different kinds of air pollutants, including carbon dioxide (CO 2 ), carbon monoxide (CO), nitrogen oxides (NO x ), and trace amounts of sulfur dioxide (SO 2 ) and particulate matter (PM). Flaring is a means to eliminate natural gas that may be impracticable to use, capture, or transport. As with venting, the primary purpose of flaring is to act as a safety device to minimize explosive conditions. Gas may be flared at many points in the system; however, it is most common during the drilling and well completion phases. Natural gas combustion is generally considered a greater pollution control mechanism than the venting of natural gas, because the process serves to incinerate many of the VOCs and HAPs that would otherwise be released directly into the atmosphere. Similarly, natural gas combustion is generally considered as "cleaner" than other fossil fuel combustion with respect to various criteria pollutants and greenhouse gas (GHG) emissions.

Associated. Associated refers to secondary sources of emissions that arise from associated operations in natural gas systems. Associated emissions may result from the combustion of other fossil fuels (i.e., other than the natural gas stream) to power equipment, machinery, and transportation, as well as the associated release of dust and particulate matter from construction and road use. Associated emissions have the potential to contribute significantly to air pollution.

The focus of this report is on fugitive and combusted natural gas emissions. While there may be significant emissions from the natural gas sector as a result of the combustion of other fossil fuels for process heat, power, and transportation, as well as the associated release of particulate matter from construction and road use, the primary focus of this report is on air quality issues related to the resource itself (i.e., the fugitive release of natural gas and its combustion during operations). It is this release of natural gas—and the pollutants contained within it—that makes air quality considerations in the crude oil and natural gas sector unique from other industrial-, construction-, and transportation-intensive sectors.

Sources

Natural gas systems include many activities and pieces of equipment that have the potential to emit air pollutants. Most of these emissions sources are common to both conventional and unconventional natural gas development.

Drilling. Fugitive natural gas and other air pollutants may escape to the atmosphere during initial drilling operations through the circulation of drilling fluids back to the surface. Further, emissions from combusted natural gas—including CO 2 , NO x , and potentially SO 2 —may also be released at the well site due to both engine combustion and flaring activities. These include "well test flaring," which occurs during the drilling and testing of oil and gas wells, and "solution gas flaring," which occurs during the disposal of associated gas produced along with crude oil (as is the case currently with oil production in the Bakken formation).

Well Completions. Well completions contain several processes which have the potential to emit air pollutants. For example, hydraulic fracturing uses pressurized fluids containing any combination of water, proppant, and added chemicals to penetrate and produce natural gas from tight formations (e.g., shale, sand, or coal formations). The process requires a high rate, extended flowback period to expel fracture fluids and solids from the well. Gas may escape with these fluids during flowback or impoundment, allowing emissions of methane and VOCs to be released to the atmosphere. Conversely, if the flowback gas is captured, separated from the fluids, and flared, emissions of nitrous oxides and carbon dioxide may be released to the atmosphere. EPA estimates that well completions involving hydraulic fracturing can vent substantially more natural gas—approximately 230 times more—than well completions not involving hydraulic fracturing, if not controlled by reduction equipment. Other sources from industry and academia estimate these emissions levels differently, in part because the data are limited.

Compressors. There are many locations throughout the natural gas sector where compression is required to move gas along the pipeline. This is accomplished by different machinery such as combustion turbines, reciprocating internal combustion engines, and electric motors. Both the turbine-powered centrifugal compressors and the reciprocating internal combustion compressors may use a small portion of the natural gas they compress to fuel the turbine. Both are potential sources of fugitive VOCs and methane emissions as well as significant sources of combusted emissions. Centrifugal compressors require seals around the rotating shaft to prevent gases from escaping where the shaft exits the casing. The seals in some compressors use oil (e.g., "wet seal compressors"), and they commonly vent the absorbed gas to the atmosphere when they are purged. Reciprocating compressors, on the other hand, leak natural gas throughout the course of their normal operation, with the highest volume of gas loss associated with worn down piston rod packing systems. Using dry-seal centrifugal systems or periodically replacing worn down rod packing systems are the most effective ways of controlling emissions from gas-driven compressors. Conversely, where available, electric motors can be used to operate compressors. This type of compression does not require the use of any of the natural gas from the pipeline, but it does require a source of electricity.

Controllers. Pneumatic controllers are automated instruments widely used in the natural gas sector for maintaining pressure, temperature, and flow rate conditions in the system. In many situations, the pneumatic controllers make use of the available high-pressure natural gas in the system to regulate these conditions. In these "gas-driven" pneumatic controllers, natural gas may be released intermittently with every valve movement or continuously from the valve control pilot. Gas driven pneumatic controllers are typically characterized as either "high-bleed" or "low-bleed," where a high-bleed device releases at least 6 cubic feet of gas per hour. Conversely, "non-gas driven" pneumatic controllers use sources of power other than pressurized natural gas, greatly reducing levels of emissions. Examples include solar, electric, and instrument air.

Storage Vessels. After being separated from the natural gas stream, crude oil, condensate, and produced water are typically stored in fixed-roof storage vessels. These vessels, which are operated at or near atmospheric pressure conditions, can release various emissions to the atmosphere as a result of working, breathing, and flash losses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid is transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained gases or a portion of the liquid to vaporize or flash. Typically, the larger the pressure drop, the more flash emissions will occur in the storage stage. The two ways of controlling tanks with significant emissions are to install vapor recovery units (VRU) or to route the emissions from the tanks to control devices (i.e., flares).

Dehydrators. Once natural gas has been separated from any liquid materials or products (e.g., crude oil, condensate, or produced water), residual entrained water is removed from the natural gas by dehydration. One of the most widely used natural gas dehydration processes is glycol dehydration. Glycol dehydration is an absorption process in which a liquid absorbent (glycol) directly contacts the natural gas stream and absorbs both the entrained water vapor as well as a number of selected hydrocarbons, including BTEX, n-hexane, and other HAPs. During the recirculation stages, the hydrocarbons are boiled off along with the water and are either vented to the atmosphere or directed to a control device.

General Equipment and Pipeline Leaks. Fugitive emissions can emanate from valves, pump seals, flanges, compressor seals, pressure relief valves, open-ended lines, and other process and operation components at any point during operations. Leaks may be due to routine wear, tear, and corrosion; improper installation or maintenance; or the overpressure of gases or liquids in the system. Because of the large number of valves, pumps, and other components within a natural gas production, processing, or transmission facility, equipment leaks collectively can be a significant source of emissions. Further, there are over 300,000 miles of transmission pipelines alone in the United States, and these pieces of equipment exist throughout the system.

Workovers, Maintenance, and Upsets. Periodically, wells require restimulation workovers or routine maintenance—such as the unloading of liquids or blowdowns—in order to reestablish productive gas flows. These activities, depending upon their methods, may release significant amounts of fugitives into the atmosphere. Further, all activities are susceptible to occasional upsets and accidental losses.

Pollutants

Through provisions in the Clean Air Act (CAA), the U.S. Environmental Protection Agency (EPA) classifies air pollutants under several different categories, including the following:

Criteria Pollutants . Common emissions that can harm human health or the environment, or cause property damage, including ground-level ozone (i.e., smog), nitrogen oxides, sulfur dioxide, carbon monoxide, particulate matter, and lead, Hazardous Air Pollutants . Toxic chemicals that are known or suspected to cause cancer or other serious health effects, such as reproductive diseases or birth defects, Greenhouse Gas Pollutants . Chemical compounds that trap heat in the atmosphere and contribute to the forcing of climate change.

The "Criteria" and "Hazardous Air Pollutant" categories are identified and regulated under specific provisions of the CAA. In contrast, greenhouse gases may be regulated under several different ones. The natural gas industry produces emissions from each of these categories, some of which may overlap (e.g., benzene is a volatile organic compound [VOC]; and it is considered both a ground-level ozone-producing criteria pollutant and a carcinogenic hazardous air pollutant [HAP]). See Figure 2 for a comparison of air pollution emissions from the natural gas industry against those of other U.S. industrial sectors.

Methane (CH 4 ) . Methane—the principal component of natural gas—is both a precursor to ground-level ozone formation (i.e., smog) and a potent greenhouse gas (GHG), albeit with a shorter climate-affecting time horizon than carbon dioxide. Every process in natural gas systems has the potential to emit methane. EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-201 1 (published April 15, 2013) estimates 2011 methane emissions from "Natural Gas Systems" to be 358 billion standard cubic feet (bscf), or 1.5% of the industry's gross national production that year. In 2011, natural gas systems represented nearly 25% of the total methane emissions from all domestic sources and accounted for about 2% of all GHG emissions in the United States. In each year since 1990, natural gas systems were cited as being the single largest contributor to U.S. anthropogenic (i.e., man-made) methane emissions. Because of methane's effects on climate, EPA has found that it, along with five other well-mixed greenhouse gases, endangers public health and welfare within the meaning of the Clean Air Act.

Volatile Organic Compounds (VOCs )—A Ground-L evel Ozone (O 3 ) Precursor. The crude oil and natural gas sector is currently one of the largest sources of VOC emissions in the United States, accounting for approximately 12% of VOC emissions nationwide (and representing 67% of VOC emissions released by industrial source categories). VOCs—in the form of various hydrocarbons—are emitted throughout a wide range of natural gas operations and equipment. The interaction between VOCs and NO x in the atmosphere contributes to the formation of ozone (i.e., smog). EPA quantifies several health effects associated with exposure to ozone, including premature death, heart failure, chronic respiratory damage, and premature aging of the lungs. Ozone may also exacerbate existing respiratory illnesses, such as asthma and emphysema, or cause chest pain, coughing, throat irritation, and congestion.

Nitrogen Oxides (NO x )—A Ground-Level Ozone (O 3 ) Precursor. Significant amounts of NO x are emitted at natural gas sites through the combustion of natural gas and other fossil fuels (e.g., diesel). This combustion occurs during several activities, including (1) the flaring of natural gas during drilling and well completions, (2) the combustion of natural gas to drive the compressors that move the product through the system, and (3) the combustion of fuels in engines, drills, heaters, boilers, and other production, construction, and transportation equipment. In addition to ozone formation (see VOCs description above), current scientific evidence links short-term NO x exposures with adverse respiratory effects including airway inflammation in healthy people and increased respiratory symptoms in people with asthma.

Carbon Monoxide (CO). Similar to NO x , CO is emitted from combustion processes in stationary and mobile sources. CO can cause harmful health effects by reducing oxygen delivery to the body's organs (like the heart and brain) and tissues.

Sulfur Dioxide (SO 2 ) . SO 2 is emitted from crude oil and natural gas production and processing operations that handle and treat sulfur-rich, or "sour," gas. Current scientific evidence links short-term exposures to SO 2 with an array of adverse respiratory effects including bronchoconstriction and increased asthma symptoms.

Particulate Matter (PM). PM may occur from dust or soil entering the air during well-pad construction, traffic on access roads, and diesel exhaust from drilling machinery, vehicles, and other engines. PM is linked to respiratory and cardiovascular problems, including aggravated asthma attacks, chronic bronchitis, decreased lung function, heart attacks, and premature death.

Hazardous Air Pollutants (HAPs). HAPs, also known as air toxics, are those pollutants that are known or suspected to cause cancer or other serious health effects, such as reproductive diseases, or birth defects. Of the HAPs emitted from natural gas systems, VOCs are the largest group, and typically evaporate easily into the air. The most common HAPs in natural gas systems are n-hexane, the BTEX compounds (benzene, toluene, ethylbenzene, and xylenes), and hydrogen sulfide. HAPs are found primarily in natural gas itself, and are emitted from equipment leaks and from various processing, compressing, transmission, distribution, or storage operations. They are also a byproduct of fuel combustion and may be components in various chemical additives.

The Clean Air Act and the Federal Role in Air Quality Issues in Natural Gas Systems

The Clean Air Act (CAA) seeks to protect human health and the environment from emissions that pollute ambient, or outdoor, air. It requires the U.S. Environmental Protection Agency (EPA) to establish minimum national standards for air emissions from various source categories (sources in the "Crude Oil and Natural Gas Production," and the "Natural Gas Transmission and Storage" sectors are included under these categories), and assigns primary responsibility to the states to assure compliance with the standards. EPA has largely delegated day-to-day responsibility for CAA implementation to all 50 states, including permitting, monitoring, inspections, and enforcement; and in many cases, states have further delegated program implementation to local governments. Sections of the CAA which are most relevant to air quality issues in the natural gas industry are discussed below. Some of the regulations implementing these sections have been revised by federal air standards promulgated by EPA on August 16, 2012. The paragraphs below summarize relevant sections of the CAA prior to these revisions. For a summary of the 2012 air standards and their relationship to the prior ones, see the subsequent section, " 2012 Federal Air Standards for Crude Oil and Natural Gas Systems ," as well as Appendix A .

Prior Federal Air Standards and Other Rules for Crude Oil and Natural Gas Systems

National Ambient Air Quality Standards (NAAQS). Section 109 of the CAA requires EPA to establish NAAQS for air pollutants that may reasonably be anticipated to endanger public health or welfare, and whose presence in ambient air results from numerous or diverse sources. Using this authority, EPA has promulgated NAAQS for sulfur dioxide (SO 2 ), particulate matter (PM 2.5 and PM 10 ), nitrogen dioxide (NO 2 ), carbon monoxide (CO), ozone, and lead. States are required to implement specified air pollution control plans to monitor these pollutants and ensure the NAAQS are met, or "attained." Additional measures are required in areas not meeting the standards, referred to as "nonattainment areas." "Nonattainment" findings for ground-level ozone, nitrogen oxides, and sulfur dioxide in areas with crude oil and natural gas production may result in states establishing specific pollution controls that could affect the industry.

Permits. The 1990 CAA Amendments add Title V (i.e., "5"), which requires major sources of air pollution to obtain operating permits. Primary responsibility for Title V permitting has been delegated by EPA to state and local authorities. Sources subject to the permit requirements generally include new or modified sources that emit or have the potential to emit 100 tons per year of any regulated pollutant, plus new or existing "area sources" that emit or have the potential to emit lesser specified amounts of hazardous air pollutants. In "nonattainment" areas, the permit requirements may include sources which emit as little as 50, 25, or 10 tons per year of VOCs, depending on the severity of the region's nonattainment status ("serious," "severe," or "extreme" respectively). A Title V permit must, among other things, list all emissions limitations and standards applicable to the source, ensure that monitoring and recordkeeping are sufficient to demonstrate compliance, and require the payment of fees. Currently, most crude oil and natural gas production activities upstream from the processing plant are not classified as "major sources" under EPA Title V operating permits.

Greenhouse Gas Reporting. In the FY2008 Consolidated Appropriations Act ( H.R. 2764 ; P.L. 110-161 ), Congress directs EPA to develop regulations that establish a mandatory GHG reporting program that applies to emissions that are "above appropriate thresholds in all sectors of the economy." EPA issued the Mandatory Reporting of Greenhouse Gases Rule (MRR) which became effective on December 29, 2009, and included reporting requirements for facilities and suppliers in 32 source categories. Affected facilities in the petroleum and natural gas industry include onshore petroleum and natural gas production, offshore petroleum and natural gas production, natural gas processing, natural gas transmission compressor stations, underground natural gas storage, liquefied natural gas (LNG) storage, LNG import and export terminals, and natural gas distribution. The rule requires petroleum and natural gas facilities that emit 25,000 metric tons or more of carbon dioxide (CO 2 ) equivalent per year to report annual fugitive emissions of methane and CO 2 from equipment leaks and venting, and annual combusted emissions of CO 2 , methane, and nitrous oxide from gas flaring, from stationary and portable equipment involved in onshore petroleum and natural gas production, and from stationary equipment involved in natural gas distribution. Since methane is the most prominent emission from upstream oil and gas activities, and since the rule requires producers to aggregate emissions from all commonly controlled wells and their associated equipment (e.g., compressors, generators, piping, and storage tanks), many facilities may likely be required to report GHG emissions in coming years. EPA estimates that the rule covers 85% of the total GHG emissions from most of the U.S. petroleum and natural gas industry with approximately 2,800 facilities reporting. On February 5, 2013, EPA released for the first time GHG data for crude oil and natural gas systems collected under industry reporting. Further to this, many states have their own GHG reporting requirements independent of the 2009 federal rules (e.g., the Regional GHG Initiative, the Western Climate Initiative, and California).

New Source Performance Standards (NSPS). Section 111 of the CAA requires EPA to promulgate regulations establishing emissions standards that are applicable to new, modified, and reconstructed sources—if such sources cause or contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. A performance standard reflects the degree of emission limitation achievable through the application of the ''best system of emission reduction'' (BSER) which EPA determines has been adequately demonstrated. As new technology advances are made, EPA is required to revise and update NSPS applicable to designated sources.

The following federal NSPS may apply to crude oil and natural gas systems (some parts have been rewritten by the August 16, 2012, standards; see the next section and Appendix A for further discussion):

40 C.F.R. Part 60, Subpart JJJJ—Standards of Performance for Stationary Spark Ignition (SI) Internal Combustion Engines (ICE). Subpart JJJJ applies to manufacturers, owners, and operators of SI ICE, which affects new, modified, and reconstructed stationary SI ICE (i.e., generators, pumps, and compressors), combusting any fuel (i.e., gasoline, natural gas, LPG, landfill gas, digester gas etc.), except combustion turbines. The applicable emissions standards are based on engine type, fuel type, and manufacturing date. The regulated pollutants are NO x , CO, and VOCs, and there is a sulfur limit on gasoline. Subpart JJJJ applies to facilities operating spark ignition engines at compressor stations; 40 C.F.R. Part 60, Subpart IIII—Standards of Performance for Stationary Compression Ignition (CI) ICEs. Subpart IIII applies to manufacturers, owners, and operators of CI ICE (diesel), which affects new, modified, and reconstructed (commencing after July 11, 2005) stationary CI ICE (i.e., generators, pumps, and compressors), except combustion turbines. The applicable emissions standards (phased in Tiers with increasing levels of stringency) are based on engine type and model year. The regulated pollutants are NO x , PM, CO, and non-methane hydrocarbons (NMHC), while the emissions of sulfur oxides (SO x ) are reduced through the use of low sulfur fuel. Particulate emissions are also reduced by standards. Subpart IIII applies to facilities operating compression ignition engines at compressor stations; 40 C.F.R. Part 60, Subpart KKK—Standards of Performance for Equipment Leaks of VOCs from Onshore Natural Gas Processing Plants. Subpart KKK applies to gas processing plants that are engaged in the extraction of natural gas liquids from field gas and contains provisions for VOCs leak detection and repair (LDAR) (this section was revised by the 2012 air standards); 40 C.F.R. Part 60, Subpart LLL—Standards of Performance for Onshore Natural Gas Processing: SO 2 Emissions. Subpart LLL governs emissions of SO 2 from gas processing plants, specifically gas sweetening units (which remove H 2 S and CO 2 from sour gas) and sulfur recovery units (which recover elemental sulfur) (this section was revised by the 2012 air standards); and 40 C.F.R. Part 60 Subpart Kb—Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for which construction, reconstruction, or modification commenced after July 23, 1984.

National Emission Standards for Haz ardous Air Pollutants (NESHAPs ). Section 112 of the CAA requires EPA to promulgate regulations establishing standards to control emissions of hazardous air pollutants (HAPs). NESHAPs are applicable to both new and existing sources of HAPs, and there are NESHAPs for both "major" sources and "area" sources of HAPs. A "major" source of HAPs is one with the potential to emit in excess of 10 tons per year (tpy) of any single HAPs or 25 tpy of two or more HAPs combined. Conversely, an "area" source of HAPs is a stationary source of HAPs that is not major. The aim is to develop technology-based standards which require levels met by the best existing facilities (commonly referred to as maximum achievable control technology, or MACT, standards). The pollutants of concern in the oil and gas sector are primarily the BTEX compounds, formaldehyde, and n-hexane.

The following federal NESHAPs may apply to crude oil and natural gas systems (some parts have been rewritten by the August 16, 2012, standards; see the next section and Appendix A for further discussion):

40 C.F.R. Part 63, Subpart ZZZZ—National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines (RICE); 40 C.F.R. Part 63, Subpart H—National Emission Standards for Organic Hazardous Air Pollutants for Equipment Leaks. Subpart H applies to equipment that contacts fluids with a HAPs concentration of 5%; 40 C.F.R. Part 63, Subpart HH—NESHAPs from Oil and Natural Gas Production Facilities. Subpart HH controls air toxics from oil and natural gas production operations and contains provisions for both major sources and area sources of HAPs. Emission sources affected by this regulation are tanks with flash emissions (major sources only), equipment leaks (major sources only), and glycol dehydrators (major and area sources) (this section was revised by the 2012 air standards); 40 C.F.R. Part 63, Subpart HHH—NESHAPs from Natural Gas Transmission and Storage Facilities. Subpart HHH controls air toxics from natural gas transmission and storage operations. It affects glycol dehydrators located at major sources of HAPs (this section was revised by the 2012 air standards); and 40 C.F.R. Part 61, Subpart V—National Emission Standard for Equipment Leaks (Fugitive Emission Sources). Subpart V applies to equipment that contacts fluids with a volatile HAPs concentration of 10%.

2012 Federal Air Standards for Crude Oil and Natural Gas Systems

On January 14, 2009, two non-governmental organizations filed a complaint under the citizen suit provision of the CAA, alleging that EPA failed to meet its obligations under CAA Sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the NSPS and the NESHAPs with respect to the "Crude Oil and Natural Gas Production" source category. On February 4, 2010, the U.S. Court of Appeals for the D.C. Circuit entered a consent decree requiring EPA to sign proposed standards and/or determinations not to issue standards by January 31, 2011 (modified to July 28, 2011), and to take final action by November 30, 2011 (modified to April 17, 2012). EPA proposed a new set of air standards for the "Crude Oil and Natural Gas Production" sector and the "Natural Gas Transmission and Storage" sector on July 28, 2011, and held three public hearings for the proposal. After several court-agreed extensions, the final rules establishing the new standards were signed by the Administrator on April 17, 2012, were published in the Federal Register on August 16, 2012, and became effective on October 15, 2012. A summary of the 2012 federal air standards is provided below. For a detailed comparison of the 2012 federal air standards against the prior federal air standards, see Appendix A .

2012 NSPS for Crude Oil and Natural Gas Systems

The 2012 NSPS for the "Crude Oil and Natural Gas Production" and the "Natural Gas Transmission and Storage" source categories regulate volatile organic compounds (VOCs) emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers, storage vessels, and leaking components at onshore natural gas processing plants, as well as sulfur dioxide (SO 2 ) emissions from onshore natural gas processing plants. Prior to the 2012 standards, processing plants were the only source category regulated at the federal level. The 2012 standards include the following:

Gas W ells. The rule covers any gas well that is "an onshore well drilled principally for production of natural gas" and is "hydraulically fractured." Oil wells (i.e., wells drilled principally for the production of crude oil) or conventional gas wells (i.e., wells drilled without hydraulic fracturing for the production of natural gas) are not subject to the rule. For fractured and refractured gas wells, the rule requires owners/operators to use "reduced emissions completions"—also known as "REC" or "green completions"—to reduce VOCs emissions during well completions. A REC is defined by EPA as "a well completion following fracturing or refracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere" (see graphic in Figure 3 ). To provide industry enough time to order and manufacture the necessary REC equipment, the NSPS establishes two phases for compliance. Owners and/or operators may use either REC or completion combustion devices (e.g., flaring) until January 1, 2015. After January 1, 2015, REC will be required. The rule exempts exploratory, delineation, and low-pressure gas wells from the REC requirement, stipulating the use of completion combustion devices instead.

Storage V essels. The rule requires individual storage vessels in the crude oil and natural gas production segment and the natural gas processing, transmission, and storage segments with emissions equal to or greater than 6 tons per year (tpy) to achieve at least 95% reduction of uncontrolled VOCs emissions. Certain C ontrollers. The rule sets a natural gas bleed rate limit of 6 standard cubic feet per hour (scfh) for individual, continuous bleed, natural gas-driven pneumatic controllers located between the wellhead and the point at which the gas enters the transmission and storage segment. For individual, continuous bleed, natural gas-driven pneumatic controllers located at natural gas processing plants, the rule sets a natural gas bleed limit of zero scfh. Certain C ompressors. The rule requires a 95% reduction of VOCs emissions from wet seal centrifugal compressors located between the wellhead and the point at which the gas enters the transmission and storage segment. The rule also requires measures intended to reduce VOCs emissions from reciprocating compressors located between the wellhead and the point where natural gas enters the natural gas transmission and storage segment. Owners and/or operators of these compressors must replace the rod packing systems within the compressors based on specified usage or time. Onshore Natural Gas P rocessing P lants. The rule revises the existing NSPS requirements for leak detection and repair (LDAR) to reflect the procedures and leak thresholds established in the NSPS for equipment leaks of VOCs emissions in the synthetic organic chemicals manufacturing industry. This rule also revises the existing NSPS requirements for SO 2 emission reductions based on sulfur feed rate and sulfur content of gas.

2012 NESHAPs for Crude Oil and Natural Gas Systems

The 2012 rules revise the NESHAPs for glycol dehydration unit process vents and leak detection and repair (LDAR) requirements and retain the existing NESHAPs for storage vessels. The 2012 standards include the following:

Glycol D ehydration U nits . The rule establishes MACT standards for "small" glycol dehydration units, which were unregulated under the initial NESHAPs. Covered glycol dehydrators now include those with an actual annual average natural gas flow rate less than 85,000 standard cubic meters per day (scmd) or actual average benzene emissions less than 0.9 megagrams per year (Mg/yr), and they must meet unit-specific limits for benzene, toluene, ethylbenzene, and xylene (collectively, "BTEX"). Leak Detection and R epair . The rule lowers the leak definition for valves at natural gas processing plants from 10,000 parts per million (ppm) to 500 ppm for major sources at crude oil and natural gas production facilities, thus requiring the application of LDAR procedures at this level.

Effects of the 2012 Federal Air Standards on State Attainment Planning and Permitting

With the release of the 2012 air standards for the crude oil and natural gas production, transmission, and storage sectors, EPA constituted a federally required minimum level of control for various source categories. States have the flexibility to put their own programs in place or implement existing programs as long as they are at least as protective as the federal standards.

Attainment Planning. EPA has designated attainment and nonattainment areas for the 2008 ozone National Ambient Air Quality Standards (NAAQS). Some of these areas have significant crude oil and natural gas activities. States with ozone nonattainment areas are required to submit modified state implementation plans (SIP) in 2015 and to attain the standard by 2015 and 2018 for areas classified as "marginal" and "moderate," respectively. A few areas classified as "serious" nonattainment must attain by 2021. As the 2012 air standards may likely help states make progress in attaining the ozone NAAQS in nonattainment areas where there is significant well development, states are allowed to include the federal NSPS as a federally enforceable strategy in their nonattainment SIP. States may "take credit" for the NSPS in their SIP towards meeting two requirements: (1) the 2012 standards are expected to achieve 95% control of VOCs emissions from new gas wells, making it easier for states to obtain the overall reduction in emissions they need to attain the ozone NAAQS without adding any federal or state permitting requirements; and (2) SIPs in "moderate" and "serious" areas must also show "reasonable further progress" in controlling emissions in the years before they attain the ozone NAAQS. In most areas, states may choose to measure this progress relative to emissions in 2011. In areas that had wells drilled in 2011 and will continue to have more wells drilled in the years ahead, the 95% control from the NSPS may provide emission reductions that can be credited toward the reasonable further progress requirement. In areas that had no or few wells drilled in 2011 but that will see drilling activity in the future, the 95% control from the NSPS may ensure that emissions from new well development do not impede meeting the reasonable further progress requirement.

Permitting. The 2012 NSPS regulates all new and modified gas wells whether or not they attain existing thresholds that define a "major source" for pre-construction permit and Title V operating permit purposes. In the absence of the NSPS, some hydraulically fractured gas wells could have emissions above these thresholds in some ozone nonattainment areas. Wells complying with the 2012 NSPS, however, most likely will not trigger major source permitting thresholds. Wells complying with the 2012 NSPS may also have emissions low enough to avoid needing a minor source permit from the state, as the NSPS provides a path (i.e., REC) for existing wells that are refractured to avoid falling under the scope of the NSPS at all, thereby avoiding any automatic requirement to get a state minor source permit. Nevertheless, states may still include modified wells in their minor source permitting rules if they choose.

Reported Costs and Benefits of the 2012 Federal Air Standards

Natural gas is a product of—and thus a source of revenue for—the oil and gas industry. It is also a main source of pollution for the industry when it is emitted into the atmosphere. Due to this unique linkage, pollution abatement has the potential to translate into economic benefits for the industry, as producers can offset compliance costs with the value of natural gas and condensate recovered and sold at market. EPA reports the environmental and the economic benefits of the 2012 air standards as follows:

VOC s R e ductions of 190,000 to 290,000 Tons A nnually. VOCs emissions reductions of nearly 95% from hydraulically fractured gas wells are expected to help reduce ground-level ozone (i.e., smog) in areas where crude oil and natural gas production occurs. Air Toxics R educ tions of 12,000 to 20,000 Tons A nnually. The 2012 rules are intended to protect against potential cancer risks from emissions of several air toxics, including the BTEX compounds. Methane R eductions of 1.0 Million to 1.7 Million Short Tons A nnually. (Equivalent to 19 to 33 million metric tons of CO 2 equivalent (CO 2 e).) While not targeted by the 2012 rules, methane reductions from new and modified well completions and other activities would yield an additional environmental co-benefit. Industry Costs of $170 Million A nnually. EPA estimates the rule will cost producers about $170 million annually in 2015 (in 2008$). Industry and third party sources have estimated anywhere from $450 million to over $2.8 billion, depending upon assumptions regarding the number of wells subject to compliance, the cost of REC equipment and rentals, and the number and cost of completion combustion requirements. Net Cost Savings for Industry of $11 Million to $19 M illion. EPA estimates that compliance costs would be offset by the sales of the captured methane and natural gas liquids, resulting in a net gain of $11 million to $19 million in 2015. EPA's cost-benefit analysis, as put forth in its Regulatory Impact Analysis for the proposed air standards, has been critiqued as both too high and too low by industry and environmental stakeholders, respectively. Industry stresses that the economic analyses must include the full variety of conditions (e.g., the full range of VOCs content found across different reservoirs) in upstream production activities to support all the costs of compliance with the proposed rule; and that the analysis does not fully take into account the effect that operational standards (i.e., the requirements for additional green completions and other abatement equipment) will have on the production and growth of the industry in the near term. Industry claims that fluctuations in the market price of recovered products may also serve to further depress EPA's revenue estimates. Conversely, environmental stakeholders argue that the costs of control used by EPA are conservative estimates and do not properly account for the full social and environmental benefits created by the capture of methane.

Agency Reconsideration of the 2012 Federal Air Standards

On April 12, 2013, EPA announced proposed amendments to the 2012 federal air standards for the oil and gas sector. The proposed rule reconsiders certain issues related to implementation of the storage vessel provisions and adjusts compliance dates to allow more time for the availability of control devices. In summary, the proposed rule grants reconsideration of the following: (1) an extension to the implementation date for the storage vessel provisions (from October 15, 2013, to April 15, 2014, for new and modified sources after April 12, 2013); (2) definition of "storage vessel" (to clarify that it refers only to vessels containing crude oil, condensate, intermediate hydrocarbon liquids, or produced water); (3) definition of "storage vessel affected facility" (to include the 6 tpy VOC emission threshold); (4) requirements for storage vessels constructed, modified, or reconstructed during the period from the NSPS proposal date, August 23, 2011, to April 12, 2013 (to remove the requirement for control devices and to require instead notification to regulatory agencies by October 15, 2013, of the existence and location of the vessels); (5) an alternative mass-based standard for storage vessels after extended periods of low uncontrolled emissions (to include a sustained uncontrolled VOC emission rate of less than 4 tpy as an alternative emission limit to the 95% control in the final NSPS under specified circumstances).

Issues for Congressional Consideration

The expansion of both industry production and government regulation of natural gas systems has sparked discussion on a number of outstanding issues. Some of the more significant debates involving air quality concerns are outlined in the sections below.

The Regulatory Role of Federal, State, and Local Governments

According to EPA, the 2012 federal air standards are designed to provide minimum requirements for emissions of air pollutants from the crude oil and natural gas sector that can both protect human health and the environment and allow for continued growth in production. However, some believe that state and local governments are better positioned to develop these emission standards. They claim that states can more readily address the regional and state-specific character of many crude oil and natural gas activities, including differences in geology, hydrology, climate, topography, industry characteristics, development history, state legal structures, population density, and local economics, and the effects these components have on air quality. They argue that federal rules add unnecessary and often repetitive requirements on the industry, which may increase project costs and delays with little added benefit. Others, attesting to the "patchwork" of state and local requirements, support the need for the federal government to institute minimum standards for emissions that are consistent, predictable, and reach across state lines. They claim a federal standard would extend regulatory certainties to the industry and would best ensure health and environmental protections for all stakeholders. They also contend that many state laws and state agencies are still gaining experience with unconventional oil and natural gas development, and that industry is operating under insufficient and outdated rules. In light of these considerations, Congress may choose to re-examine proposed and/or existing federal requirements apropos of existing state and local regulations, or introduce new federal requirements if deemed necessary.

Currently, states lead the day-to-day permitting, monitoring, and enforcement of crude oil and natural gas development, and any federal requirements that might apply have typically been delegated to the states. In general, each state has one or more regulatory agencies that may permit wells, including their design, location, spacing, operation, and abandonment, and may regulate for environmental compliance, including water management and disposal, air emissions, underground injection, wildlife impacts, surface disturbance, and worker health and safety. The organization of regulatory agencies within the various oil and gas producing states varies considerably. In many cases, state agencies were established initially to provide a structure to facilitate—not regulate—oil and gas development. These facilitatory agencies served primarily to provide a central state system for administering resource claims and mediating disputes. In some instances, these agencies have taken on oversight activities for environmental protection. In other instances, they have operated alongside a separate agency that has been mandated to prevent environmental pollution and public health impacts.

For example, Colorado provides multiple state agencies with different authorities to regulate industry operations. The Colorado Department of Public Health and Environment (CDPHE) and the Colorado Department of Natural Resources maintain separate but complementary oversight of industry operations. Colorado's Air Quality Control Commission (under CDPHE) has regulations to address emissions from tanks, engines, compressors, and associated equipment. Colorado's Oil and Gas Conservation Commission has regulations pertaining to such issues as well completions, odors, noise, and drill rig setbacks. Conversely, Pennsylvania's Department of Environmental Protection (DEP) Office of Oil and Gas Management is responsible for all statewide oil and gas programs. The office manages activities both to facilitate the exploration, development, and recovery of Pennsylvania's oil and gas reservoirs while also overseeing the protection of the commonwealth's natural resources and environment. The office develops policy and programs for the regulation of oil and gas development pursuant to the commonwealth's Oil and Gas Act, the Coal and Gas Resource Coordination Act, and the Oil and Gas Conservation Law. It oversees the oil and gas permitting and inspection programs, develops statewide regulation and standards, conducts training programs for industry, and works with the Interstate Oil and Gas Compact Commission and the Technical Advisory Board.

All crude oil and natural gas producing states have laws in place related to oil and gas development. Most state requirements are written into rules or regulations. Requirements may also be added to permits on a case-by-case basis as a result of findings from environmental reviews, on-the-ground inspections, public comments, or commission hearings. For example, emissions from oil and gas development in Colorado are governed primarily by statutory provisions of the Oil and Gas Conservation Act (Colo. Rev. Stat. §34-60-100, et seq.), Colorado's Air Pollution and Prevention Control Act (§25-7-100, et seq.), and Water Quality Control Act (§25-8-100, et seq.). In other states, such as Montana or Texas, emissions from oil and gas development are addressed most prominently during permitting, registration, and authorization activities (e.g., Montana Department of Environmental Quality, Air Quality Permits [MAQP], under Rule 17.8.752, and Montana Registration Requirements, under Rule 17.8.1711[1][a]; or Texas Commission on Environmental Quality, Permit by Rule [PBR], Standard Permit, and New Source Review [NSR] Permit, under Title 30, Texas Administration Code, Chapter 116, et seq. ) .

Most state oil and gas regulations were written well before unconventional natural gas development became widespread. A number of major gas producing states have recently revised regulations, with particular focus on emerging areas of concern, including disclosure of hydraulic fracturing chemicals, well construction and operation to prevent aquifer contamination, and management of waste from flowback and produced water. Similarly, many states and counties have some regulatory structures to address air quality issues based on each jurisdiction's individual circumstance. Some states and counties have adopted relatively stringent standards, while others have not. Some have rules proposed or are in the process of revising or implementing them. Others are considering rolling back existing regulations. EPA's 2012 federal air standards were drawn primarily from existing requirements found in the state codes of Colorado and Wyoming. For a comparison of EPA's 2012 air standards for source categories in the crude oil and natural gas industry to those from selected states, see Table A -4 of this report.

Critics of federal oversight maintain that the states have long regulated oil and gas exploration and production and are best positioned to continue to do so as they have established governing structures and trained staff in place. They argue that a distant federal bureaucracy unfamiliar with local conditions is rarely the best entity to ensure environmental needs are balanced with economic growth and job creation. They claim that states can more readily address the regional and state-specific character of many crude oil and natural gas activities, including differences in geology, hydrology, climate, topography, industry characteristics, development history, state legal structures, population density, and local economics. Critics argue that federal rules add unnecessary and often repetitive requirements on the industry, which may increase project costs and delays with little added benefit. They claim federal rules would require increased federal resources and skilled staff to administer regulations for oil and gas development (or, as is sometimes the case, to administer federal requirements redundantly alongside existing state programs). They contend that a well-run state permitting and regulatory program can adjust more quickly, is better positioned to meet the challenges presented by constantly developing technologies, and can effectively administer rules across private, state, and federal lands.

Others note that it has neither been the practice nor the intention of EPA to administer regulations for oil and gas development at the state level. However, seeing the patchwork mix of state and local requirements, they have called for the federal government to institute a minimum nationwide standard for emissions from the crude oil and natural gas sector. Proponents of federal oversight contend that many state laws and state agencies are still gaining experience with unconventional oil and natural gas development, and that industry is operating under insufficient and outdated rules. They claim that many of the agencies that regulate development at the state level are underfunded and understaffed, are tasked with the dual purposes of developing the state's resources and protecting the state's environment, and thus, are caught between policing and promoting the industry. They suggest that state agencies and state regulators are often overwhelmed by oil and gas companies, which are generally national or international in scope, and start with the advantage of sheer size. They point to examples where state regulators have failed to seek large penalties for violations or track enforcement data, and cite statistics that show 40% of state drilling regulators have industry ties. A 2012 report, released by a non-governmental environmental organization, surveyed active oil and gas wells in six states and summarized the findings as follows: (1) over half (or close to 350,000 active wells in 2010) are operating with no independent inspections to determine whether they are in compliance with state rules; (2) when inspections do uncover rule violations, the violations often are not formally recorded; (3) when violations are recorded, they result in few penalties; (4) when penalties are assessed, they provide little incentive for companies to not offend again (noting that no state assessed annual fines that added up to the average value of a single gas well, about $2.9 million).

Covered Sources and Pollutants

The 2012 federal air standards focus primarily on the upstream sectors of the oil and gas industry and cover only some of the pollutants and potential sources of emissions. The standards regulate emissions of VOCs from some, but not all, of the equipment and activities at onshore natural gas well sites, gathering and boosting stations, and processing plants. Similarly, the standards regulate emissions of SO 2 from sweetening units at some natural gas processing plants, as well as HAPs from some dehydration units and storage facilities in the sector. Some pollutants from natural gas systems remain uncovered by any federal law or regulation, and critics point specifically to methane emissions from the midstream and downstream sectors, as well as hydrogen sulfide, as the most significant omissions. The scope of the 2012 federal standards are the result of several factors, including (1) EPA-conducted cost-benefit and risk analyses, (2) stakeholder comments provided to the agency during rulemaking, and (3) statutory limitations placed upon the agency by provisions in the CAA. In light of these considerations, Congress may decide to re-examine ways in which oversight activities address the most significant pollutants and point sources.

While the 2012 air standards for crude oil and natural gas systems are more detailed and comprehensive than previous standards, several pollutants and sources in the sector remain uncovered.

The 2012 standards do not directly cover emissions of the following pollutants in the sector: methane, nitrogen oxides, particulate matter, and hydrogen sulfide (although reductions in some of these pollutants may occur as a co-benefit of VOCs and SO 2 reductions). Many observers have noted, however, that the 2012 standards, as written, use natural gas emissions as a surrogate for VOCs and H 2 S/SO 2 emissions. Some argue that basing standards on the volume of natural gas emissions as opposed to the content of VOCs in the gas does not adequately account for the geographic variability of VOCs within the resource (e.g., EPA calculated cost effectiveness based on a national average of 3.7% VOCs by volume [18% by weight] for natural gas streams; however, many streams may produce little or no VOCs). Critics of the rule maintain that requiring standards for natural gas emissions as opposed to VOCs content essentially regulates the industry for methane as opposed to VOCs. From this perspective, requiring an operational standard (e.g., reduced emissions completions) instead of a performance standard (e.g., a VOCs threshold) may impose unnecessary compliance costs in some instances. The 2012 standards do address the smaller volume of VOCs in natural gas streams after the processing stage by exempting many activities and pieces of equipment in the transmission, storage, and distribution sectors of the industry.

Further, the 2012 standards do not cover emissions from the following sources in the sector: all oil wells; all off-shore sources; all coal-bed methane production facilities; all field engines, drilling rig engines, and turbines; well-head and transmission and storage segment compressors; well-head activities such as liquids unloading; all heater-treaters; all pneumatic devices other than controllers; storage vessels such as skid-mounted, mobile, well cellars, sumps, and produced water ponds; and LDAR for non-processing plant facilities. Additionally, the 2012 standards do not cover VOCs or SO 2 emissions from existing sources, unless they are classified as HAPs. Finally, the 2012 standards assume non-gas-driven controllers cannot replace gas-driven controllers as "best system of emission reduction" (BSER) for regulatory purposes; low-bleed controllers cannot replace high-bleed controllers as BSER; centrifugal compressors cannot replace reciprocating compressors as BSER; and vapor recovery units cannot replace combustion devices as BSER. Many of these sources may still emit significant quantities of pollutants; however, EPA has determined that standards on these sources are either technically or economically unfeasible.

Major Source Aggregation

The 2012 federal air standards exempt well completions, pneumatic controllers, compressors, and storage vessels from "major source" determination with respect to CAA Title V permit requirements. Viewed at the component level, these smaller "emissions units" at natural gas facilities may not generate enough pollution on their own to be classified as "major sources." However, it may be possible that an entire natural gas operation (e.g., a well site, a field, or a station) is a "major source" (i.e., one that emits typically 10 tons to 250 tons per year, depending upon the pollutant and the area's attainment status). Determining which equipment and activities should be grouped together, or "aggregated," in the crude oil and natural gas sector for permitting purposes remains an open issue for the states, the courts, EPA, and the regulated entities. In light of these considerations, Congress may further assess EPA's requirements for major source categories in upstream oil and gas activities.

The past few decades have seen several developments in the evaluation of crude oil and natural gas facilities at multiple locations for possible aggregation into a single source for permitting purposes. The ability of EPA and the state permitting authorities to aggregate multiple operations into a single major source permit is founded upon the definition of "stationary source" within the CAA. The CAA defines a "stationary source" as "any building, structure, facility, or installation which emits or may emit any air pollutant." Alabama Power Co. v. Costle established boundaries on the scope of a source such that "(1) it must carry out reasonably the purposes of New Source Review/Prevention of Significant Deterioration (NSR/PSD); (2) it must approximate a common sense notion of 'plant'; and (3) it must avoid aggregating pollutant-emitting activities that as a group would not fit within the ordinary meaning of 'building,' 'structure,' 'facility,' or 'installation.'" In response, in the 1980 revisions to the PSD regulations, EPA clarified that emissions from operations may be aggregated and considered a single major source for PSD permitting if they meet each of the following three criteria: (1) the sources are located on one or more "contiguous or adjacent" properties, (2) the sources are under common control of the same person (or persons under common control), and (3) the sources belong to a single major industrial grouping (same two digit major Standard Industrial Classification (SIC) code). Only if all three criteria are met will the CAA permitting authority aggregate the operations into a single NSR/PSD permit. After the 1990 CAA Amendments created the Title V Operating Permit Program, this three-factor analysis was extended to Title V major source permitting.

The source definition established by EPA was intended to aggregate only "major projects that would cause air quality deterioration" but "avoid review of projects that would not increase deterioration significantly." EPA has recently addressed the issue of CAA source determinations in the oil and gas industry in a 2009 guidance document from the EPA Office of Air and Radiation (the "McCarthy Memo"). The McCarthy Memo withdrew earlier guidance from EPA which concluded that the three prong aggregation analysis for oil and gas activities should begin by looking at and focusing most heavily on the proximity of the surface locations. This emphasis on proximity may have been a result of previous actions by EPA that interpreted "contiguous and adjacent" as meaning "functionally interdependent" (e.g., sources connected by pipelines, conveyors, roads, and other means by which materials and products or intermediate products are transferred between them). The McCarthy Memo attempted to negotiate a path between the broad mandate of "functional interdependence" and the more narrow use of "proximity." It recognized that source determinations in the oil and gas industry continue to be complex, and re-emphasized that the regulations list all three criteria to be used in the analysis. It then acknowledged that there would be cases in which proximity is the "overwhelming factor," but the agency is not going to pre-judge that by using a simplified approach, and that "reasoned decision-making" of each of the relevant factors needs to occur on a case-by-case basis.

EPA's three prong aggregation analysis for oil and gas activities was recently challenged in the case of Summit Petroleum Corp. v. EPA before the U.S. Court of Appeals for the 6 th Circuit. In an August 7, 2012, decision, the 6 th Circuit rejected 2-1 the agency's "functional interrelationship" analysis used to support its definition of "adjacency," vacating EPA's determination that a Michigan natural gas plant and its production wells constitute a single major source. Further, on October 29, the court issued an order denying EPA's motion to rehear the case. The denial cements the appellate court's ruling, remanding the issue back to EPA, and ordering the agency to conduct a new analysis of the Michigan facilities using physical proximity as the sole basis for determining adjacency. In response, EPA has stated that relying on physical proximity alone may lead both to "absurd results" and increased regulatory burdens under the NSR and PSD programs. The agency announced that it plans to implement the 6 th Circuit's ruling solely in the 6 th Circuit states of Michigan, Ohio, Tennessee, and Kentucky.

Contrary to this, source determinations for NESHAPs in the sector are clearly outlined in the CAA. In Section 112(n)(4), Congress specifically exempted upstream oil and gas operations from aggregation in several ways. First, with respect to the "major source" category, Section 112(n)(4) of the CAA provides that, notwithstanding the general definition of "major source,"

emissions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in a contiguous area or under common control, to determine whether such units or stations are major sources, and in the case of any oil or gas exploration or production well (with its associated equipment), such emissions shall not be aggregated for any purpose under this section.

Second, with respect to the "area source" category, Section 112(n)(4) provides that

the Administrator shall not list oil and gas production wells (with its associated equipment) as an area source category under subsection (c), except that the Administrator may establish an area source category for oil and gas production wells located in any metropolitan statistical area or consolidated metropolitan statistical area with a population in excess of 1 million, if the Administrator determines that emissions of hazardous air pollutants from such wells present more than a negligible risk of adverse effects to public health.

At the time, the 101 st Congress (1990) found that

oil and gas wells, and associated equipment and gas processing, have generally very low emissions of air toxics. Furthermore, these operations are typically located in remote areas, with wells and equipment widely dispersed geographically, rather than concentrated in a single area. For these reasons, it is very unlikely that oil and gas sources would present a significant risk to human health and it is not expected that this source category would need to be a listed category designated for regulation.

In response, EPA wrote in the 1999 preamble that the definition of facility should "lead to an aggregation of emissions in major source determinations that is reasonable, consistent with the intent of the Act, and easily implementable." Consequently, EPA determined it was not appropriate to aggregate crude oil and natural gas facilities at that time.

Measurement of Emissions

The 2012 federal air standards are based on EPA's emission estimates for the crude oil and natural gas sector. While emissions from certain activities and equipment lend themselves to credible estimates, others—specifically fugitive emissions from production activities such as hydraulically fractured well completions, flowback, and produced water ponds—are more difficult to evaluate, have fewer data available, and remain under considerable debate. Currently, the primary source of information on emissions from the sector is a methane study published in 1996 by EPA and the Gas Research Institute (GRI). EPA annually calculates industry emissions using the methodology derived from this report, and while many of the factors have been representative over the period of 1992 to the present, several have been recalculated due to new information. EPA's inventory has been criticized by industry groups and other sources, many of which have put forth competing, and sometimes conflicting, estimates over the past few years. At this time, a comprehensive national inventory that directly measures the quantity and composition of fugitive emissions from natural gas systems does not exist. Until there is an adequate and reliable assessment of industry-wide emissions, the benefits, costs, and basis for regulation may remain uncertain. In light of these considerations, Congress may examine ways in which to best facilitate more comprehensive and technically accurate emissions estimates.

By definition, "fugitive" emissions are those which are elusive and transitory. Thus, the single greatest difficulty in estimating emissions from natural gas systems is acquiring comprehensive and consistent measurement data. Currently, the most comprehensive study of emissions in the industry is more than a decade old, uses emissions factors and activity levels to calculate data, and focuses primarily on methane. EPA has initiated a more detailed inventory of the oil and gas sector's GHG emissions (i.e., methane and CO 2 ) under the agency's GHG Reporting Rule, and the first data for major sources were released in February 2013. National emissions inventories for criteria and hazardous air pollutants, however, are distinct from GHG inventories and are complicated by the fact that concentrations of these chemicals vary geographically across resource reservoirs. A few states have begun the process of acquiring emissions inventories from upstream production activities (e.g., Texas, Pennsylvania, California, and Colorado, as well as a national survey to be conducted by the University of Texas at Austin), but few have presented or harmonized this information. There are also many examples of local emissions inventories, commissioned by a range of stakeholders—from regional and municipal agencies to community groups and academic institutions. None are fully consistent with shared measurement practices and each use different techniques for their data collection. It is for these reasons that the first recommendation in the report released by the U.S. Secretary of Energy Advisory Board Shale Gas Production Subcommittee is to "immediately launch projects to design and rapidly implement measurement systems to collect comprehensive methane and other emissions data."

Currently, the primary source of information on emissions in the natural gas industry is a methane study published in 1996 by EPA and the Gas Research Institute (GRI). At the time, the EPA/GRI study was conducted to assess the GHG emissions from various U.S. industrial sectors to assist in data analysis for the Intergovernmental Panel on Climate Change and emissions reporting for U.S. commitments to the United Nations Framework Convention on Climate Change. The study focuses on 1992 (as a base year) and uses three primary methodologies to generate emissions factors from over 100 different sources within the industry. The methods include (1) "component measurement," wherein emissions are measured directly from a large number of randomly selected pieces of equipment to determine an average emission factor for each type; (2) "tracer gas," wherein facility-wide emissions are calculated by releasing a tracer gas at a known and constant rate near the facility and measuring the downwind concentrations of the tracer and methane; and (3) "leak statistics," wherein emissions are measured for a large number of pipeline leaks to determine an average emissions rate per leak as a function of pipe material, age, operating pressure, and environmental characteristics. Total industry emissions are then estimated by multiplying these emissions factors by the activity levels for each system component (i.e., the number of wellheads, compressors, processing plants, miles of pipeline in operation, and other components) across the entire industry. The EPA/GRI study estimates that the industry emitted 314 ± 105 billion standard cubic feet (bscf) of methane in 1992 (i.e., 127 ± 42 million metric tons of carbon dioxide equivalent [MMtCO 2 e], or 1.42% ± 0.47% of the industry's gross national production that year). Roughly 60% of the industry's methane emissions are estimated to be from fugitive sources, about 30% from venting, and about 8% from combustion. Results of the EPA/GRI study, by source categories, are reported in Table 1 .

EPA annually calculates emissions estimates for the industry using the methodology from the 1996 EPA/GRI study. Since its publication, activity data for some of the components in the system have been updated based on publicly available information. For other sources where annual activity data are not available or have not been reported by industry, EPA has developed a set of industry activity factor drivers to assist in modeling. While many of the emissions factors modeled by the EPA/GRI study were considered representative over the period of 1992 to the present, several factors have been re-calculated since publication. Most notably, emissions factors for gas well cleanups, condensate storage tanks, and centrifugal compressors have been revised due to new information. Emissions factors for gas well completions in unconventional resources with hydraulic fracturing—which were not industry practice at the time of the EPA/GRI study—have also been added to the inventory. With these revisions, EPA estimates that the industry emitted 247.7 million metric tons of carbon dioxide equivalent (MMtCO 2 e) greenhouse gases in 2010, of which 215.4 MMtCO 2 e was methane (i.e., 532 bscf of methane, or 2.4% of the industry's gross national production that year).

The emissions estimates EPA uses for hydraulically fractured well completions and re-completions come from data provided by industry sources at several EPA Natural Gas STAR technology transfer workshops between 2004 and 2007. Using the reported data in its 2010 Background Technical Support Document, Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry , EPA creates separate categories for conventional and unconventional well completions, and increases its estimate of methane emissions from both categories from 0.02 metric tons per well completion to 0.71 metric tons per conventional well and 177 metric tons per unconventional well (or 37 thousand cubic feet [Mcf]/completion and 9,175 Mcf/completion respectively). EPA assumes a 3-10 day flowback period with an uncontrolled release of methane. Further, EPA assumes that 51% of the fugitive emissions from hydraulically fractured well completions are flared—and the rest vented—based upon state and local regulations for control devices that are currently in place.

EPA's methodology for estimating methane emissions from hydraulically fractured well completions has been criticized by a number of sources. A detailed critique of EPA's numbers can be found in IHS CERA's 2011 report, Mismeasuring Methane: Estimating Greenhouse Gas Emissions from Upstream Natural Gas Development. CERA's main concerns involve the small sample size for emissions data and the unsupported assumptions on venting practices. Further, several industry sources have reported competing emissions estimates, including the American Petroleum Institute and the America's Natural Gas Alliance (which list total industry emissions at half of EPA's estimate due to a re-calculation of emissions factors and activity levels for liquids unloading and re-fractured well completions), URS (which estimates emissions of 765 Mcf of gas on a per well basis compared to EPA's 9,175 Mcf), and Devon Energy Company (which reports data from eight of its operators demonstrating that flowback periods last on average only 3.5 days compared to EPA's estimated 3-10 days). As with any self-selected and self-reported survey, it is difficult to determine how representative these samples are of overall industry practice.

Other published studies use different methodologies for the calculation of leakage (e.g., satellite observations, ambient measurements, and dispersion modeling). A National Oceanographic and Atmospheric Administration (NOAA) study analyzes daily air samples collected at the Boulder Atmospheric Observatory in Weld County in northeastern Colorado and concludes that fugitive natural gas emissions from drilling operations range from 2.3% to 7.7% of industry's gross annual production. The study uses an extensive data set of ambient concentrations of methane and related hydrocarbons in the vicinity of oil and gas operations in the region, along with the known emissions profiles for these gases from oil and gas operations, to infer the emissions from the industry. In December 2012, the research team reported updated Colorado data that support the earlier work, as well as preliminary results from a field study in the Uinta Basin of Utah suggesting even higher rates of methane leakage at 9% of the total production.

On February 5, 2013, the industry-reported dataset for GHG emissions collected under EPA's Greenhouse Gas Reporting Program (GHGRP) was released for the first time for crude oil and natural gas systems. The data show 2011 GHG emissions from over 1,800 facilities in the crude oil and natural gas sector, including production, processing, transmission, and distribution. In total, these facilities accounted for GHG emissions of 225 MMtCO 2 e. Of note in the reporting: (1) The crude oil and natural gas sector is the second-largest stationary source of U.S. GHG emissions, behind power plants; (2) CO 2 emissions from the crude oil and natural gas sector account for 142 MMtCO 2 e, and methane emissions account for 83 MMtCO 2 e; (3) Onshore crude oil and natural gas production is the largest contributor, covering approximately 41% of reported emissions; (4) Emissions from onshore production facilities are primarily methane (such as leaks from equipment and vented emissions) while emissions from natural gas transmission and processing facilities are primarily CO 2 (such as combustion emissions associated with compressors); and (5) While the total emissions of CO 2 e reported by industry is consistent with the total emissions previously reported by EPA's national inventory, the ratio of CO 2 to methane emissions is notably different, with more CO 2 (and less methane) reported by the industry than estimated by EPA. The agency has instituted a multi-step data verification process for the GHGRP and intends to review the data on an ongoing basis, anticipating that the overall data quality will increase over time as facilities become familiar with the calculation methods and begin using more direct measurement.

Using the data reported by industry under comments to the 2012 air standards as well as under the GHG Reporting Program, EPA again revised its calculations for the sector in its Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011 , released April 15, 2013. For the 2011 inventory, EPA revisits its calculations for liquid unloading—the process of flushing excess water from a drilling well which the agency had estimated contributed as much as 51% of the total CH 4 emissions from the sector (an estimate that was disputed by many industry operators) and makes other changes, including its count of the number of active wells and its methodology for estimating emissions from hydraulic fracturing and refracturing well completions. With these revisions, EPA estimates that the industry emitted 177.0 MMtCO 2 e greenhouse gases in 2011, of which 144.7 MMtCO 2 e was methane (i.e., 358 bscf of methane, or 1.5% of the industry's gross national production that year).

As debate continues over the level of methane emissions from natural gas production activities, a full assessment of VOCs, HAPs, hydrogen sulfide, and other aromatic hydrocarbons becomes even more complicated, since the concentrations of these chemicals can vary greatly from reservoir to reservoir. Thus, an accurate assessment of the levels of VOCs, SO 2 , and HAPs emissions from various production activities would require not only an accurate measurement of natural gas emissions but a full accounting of the component compositions of the gas across the geographic variability of the resource.

Impacts of Emissions

The 2012 federal air standards are based on EPA's expectations that the avoided emissions under the rules would result in improvements in air quality and reductions in health effects associated with exposure to HAPs, ozone, and methane. However, the relationship between air pollution from natural gas systems and its impacts on human health and the environment has never been fully quantified and assessed. EPA acknowledges this shortcoming in the rule's proposal, stating that a full quantification of health benefits for the 2012 standards could not be accomplished due to the "unavailability of data and the lack of published epidemiological studies correlating crude oil and natural gas production to respective health outcomes." Various stakeholders assert that the lack of published and peer-reviewed literature makes it challenging to scientifically assess the impacts of natural gas operations. Some contend that this uncertainty argues against additional pollution controls at this time. Others maintain that the relevant question for determining whether pollution controls are necessary is whether natural gas systems impact an area's ability to attain air quality standards (NAAQS). In light of these considerations, Congress may wish to evaluate whether existing requirements are adequate to address concerns over the human health and environmental impacts of oil and gas activities, or, if different requirements are necessary.

Quantifying the extent to which crude oil and natural gas systems contribute to air pollution is a complicated task, due in part to the difficulties in modeling the direct and indirect impacts of emissions reductions from a single industrial sector on the greater environment. Although there are many different methodologies that can be used to assess emissions from the industry, each is burdened with unique disadvantages. Thus, while science has demonstrated that emissions of VOCs and NO x contribute to the generation of ground-level ozone (i.e., smog), emissions of various organic air toxics can pose a threat to human health, and emissions of methane produce ground-level ozone and force climate change, comprehensive epidemiological studies correlating the emissions from natural gas systems to specific long-range and cumulative health outcomes are virtually nonexistent. It should be noted that such studies are generally difficult, rare, and expensive to conduct, requiring data that are typically absent or inadequate for assessment (e.g., precise and accurate estimates of emissions, fate and transport, and exposure levels, as well as impacts data on relatively large populations of exposed individuals over long durations of time). More common, instead, are localized studies or anecdotal reports—by stakeholders who live and work near oil and gas operations—of general air quality issues such as haze, odor, or ill health. These studies are countered by industry and/or agency reports that present information on recommended practices, regulatory compliance, and a history of monitored and reported environmental stewardship.

Various stakeholders assert that the lack of published and peer-reviewed literature makes it challenging to scientifically assess the impacts of oil and gas drilling operations. The Centers for Disease Control and Prevention warns that the science on the impacts of natural gas drilling on health and the environment is "not yet clear," stating that there is "not enough information to say with certainty whether shale gas drilling poses a threat to public health," and that "more research is needed for us to understand public health impacts from natural gas drilling and new gas drilling technologies." Similarly, a recent report by GAO examines the available studies of air quality at shale gas development sites and finds that they are "generally anecdotal, short-term, and focused on a particular site or geographic location." Thus, they "do not provide the information needed to determine the overall cumulative effect that shale oil and gas activities have on air quality." GAO concludes that "the cumulative effect shale oil and gas activities have on air quality will be largely determined by the amount of development and the rate at which it occurs, and the ability to measure this will depend on the availability of accurate information on emission levels. However ... data on the severity or amount of pollutants released by oil and gas development, including the amount of fugitive emissions, are limited." It is for these reasons that the final recommendation in the report released by the U.S. Secretary of Energy Advisory Board Shale Gas Production Subcommittee is to advise federal, regional, state, and local jurisdictions "to place greater effort on examining [the] cumulative impacts" from "drilling and production operations, support infrastructure (pipelines, road networks, etc.) and related activities [which] can overwhelm ecosystems and communities."

Some federal, state, and local agencies have embarked upon or are considering further investigation into the human health and environmental impacts of oil and gas production. These include the U.S. Department of Health and Human Services, and the states of Colorado and Maryland, among others. Examples of published studies on the human health and environmental impacts of oil and gas production are as follows:

Ozone

Many studies report that at each stage of natural gas production, VOCs—including BTEX and other hydrocarbons—and methane can escape and mix with nitrogen oxides from the exhaust of diesel-fueled equipment, and, in the presence of sunlight, produce ground-level ozone (i.e., smog). Several areas of the country with heavy concentrations of drilling suffer from serious ozone problems.

For example, new oil and gas development has begun across sections of the Rocky Mountains that may be connected to the rise in ozone pollution. A 2005 Western Governors' Association report finds that crude oil and natural gas production operations released more than 430,000 tons of VOCs in Colorado, New Mexico, Utah, Wyoming, and Montana in 2002. The report projects that operations in these states would more than double their VOCs emissions in 15 years, releasing more than 965,000 tons annually by 2018. This release would equal the average amount of VOCs emitted annually from approximately 50,000 gas stations or by more than 25 million passenger cars, each driven 12,500 miles. A 2008 analysis by the Colorado Department of Public Health and Environment concludes that smog forming emissions from Colorado's crude oil and natural gas operations exceed vehicle emissions for the entire state. In 2009, the governor of Wyoming recommended that the state designate Wyoming's Upper Green River Basin as an ozone nonattainment area. An extended assessment by the Wyoming Department of Environmental Quality finds the state's ozone pollution problems are "primarily due to local emissions from oil and gas ... development activities: drilling, production, storage, transport, and treating." Recently, northeastern Utah recorded unprecedented ozone levels in the Uintah Basin, with more than 68 exceedances of the federal health standard during the first three months of 2010, and over 24 exceedances during the winter of 2011. The Bureau of Land Management identifies oil and gas activities in the region as the primary cause of the ozone pollution. Further, a 2009 study concludes that numerous "Class I areas" in the Rocky Mountain region—a designation reserved for national parks, wilderness areas, and other such lands—are likely to be impacted by increased ozone pollution as a result of oil and gas development, including Mesa Verde National Park and Weminuche Wilderness Area in Colorado and San Pedro Parks Wilderness Area, Bandelier Wilderness Area, Pecos Wilderness Area, and Wheeler Peak Wilderness Area in New Mexico. These areas are all near concentrated oil and gas development in the San Juan Basin. However, the evidence linking oil and gas development directly to high ozone levels in the region remains inconclusive. Researchers caution that many factors can contribute to the Rocky Mountains' ozone problems. For example, uniform snow cover reflects and concentrates sunlight, boosting ozone levels, as do temperature inversions that trap pollutants in mountain basins. In support of this point, the interim findings of the 2012 Uintah Basin Winter Ozone & Air Quality Study, released in August 2012, report that there were no exceedances of the eight-hour ozone standard for the basin in 2012, even though higher levels of ozone precursors and VOCs were measured in the region (the lack of sunlight-reflecting snowpack in 2012 is suggested as a possible reason).

As another example, the Dallas-Fort Worth area in Texas is home to substantial oil and gas development. Of the nine counties surrounding the Dallas-Fort Worth area that EPA has designated as "nonattainment" for ozone, five contain significant oil and gas development. A 2009 study finds summertime emissions of smog-forming pollutants from oil and gas operations in the Dallas-Fort Worth area exceed emissions from all motor vehicles in the area. A 2012 study finds that emissions from natural gas compressor stations and flares contribute to significant amounts of ground-level ozone and formaldehyde in the Dallas-Fort Worth area, estimating that a single natural gas processing facility in the Barnett shale area could add as much as 3 parts per billion (ppb) to the hourly average ambient ozone. Still, the evidence linking oil and gas development directly to high ozone levels in the region remains inconclusive. In 2009 and 2010, the Texas Commission on Environmental Quality (TCEQ) conducted several large, in-depth surveys of air quality in the six counties surrounding Fort Worth. The TCEQ study identifies a 15% drop in the 8-hour ozone design value, despite a 10-fold increase in natural gas production in the region over the past decade. TCEQ attributes at least part of this reduction to the state's NO x control strategies as well as the prevailing winds.

Air Toxics

Other studies (e.g., epidemiological studies) focus on the human health impacts of hazardous air pollutants (HAPs) known or suspected to be released by crude oil and natural gas operations. A 2011 survey of existing literature on the topic reported that of the known chemicals used and/or found in natural gas operations, approximately 37% of the chemicals are volatile and may become airborne. The study further noted that if exposures exceed certain levels, over 89% of these chemicals can harm the eyes, skin, sensory organs, respiratory tract, gastrointestinal tract, or liver; 81% can cause harm to the brain and nervous system; 71% can harm the cardiovascular system and blood; and 66% can harm the kidneys. Overall, the hazardous air pollutants produce a profile that displays a higher frequency of health effects than the water soluble chemicals. In addition, because they vaporize, not only can they be inhaled, but they can be ingested or absorbed through the skin, increasing the chance of exposures.

Several studies report that sources of HAPs in the oil and gas industry may be numerous. Data from the State of Colorado suggest that there may be more than 26 individual sources of HAPs in the oil and gas sector, including "venting, dehydration, gas processing, compression, leaks from equipment (fugitive emissions), open-pit waste ponds, and land application of volatile wastes." A study of HAPs emissions from natural gas related sources within the city of Fort Worth, TX, documents the following for HAPs emissions: 0.02 to 2 tons per year (tpy) from well pads (including emissions from equipment leaks, produced water and condensate storage and loading, and lift compressors); 0.9 to 8.8 tpy from well pads with compressors; 10 to 25 tpy from compressor stations (including emissions from combustion at the compressor engines or turbines, equipment leaks, storage tanks, glycol dehydrators, flares, and condensate and/or wastewater loading); 47 tpy on average from processing facilities (including emissions from equipment leaks, storage tanks, separator vents, glycol dehydrators, flares, condensate and wastewater loading, compressors, amine treatment and sulfur recovery units); and 0.4 tpy on average from saltwater treatment facilities.

Although oil and gas development generally has not occurred in densely populated areas, this is not always the case, particularly with respect to recent expansion in unconventional resources. Several local, state, and national health agencies have expressed concerns about the health impacts of HAPs emissions from oil and gas facilities, including the Center for Disease Control and Prevention (CDC), the Agency for Toxic Substances and Disease Registry (ATSDR), the Association of Occupational and Environmental Clinics (AOEC) and the Pediatric Environmental Health Specialty Unit (PEHSU), the Colorado School of Public Health, the Town of Dish, Texas, the City of Fort Worth, Texas, and the City of Houston, Texas. In particular, the ATSDR investigation was spurred by community health complaints such as dizziness, nausea, respiratory problems, and eye and skin irritation to more severe concerns including cancer. The investigation identifies elevated cancer risk at one site and recommends further investigation into HAPs emissions and risks at all the sites. Similarly, the Colorado School of Public Health identifies air pollution from the crude oil and natural gas activities as contributing to acute and chronic health problems for those living near natural gas drilling sites, stating that "exposures to air pollutants during well completion activities present the greatest potential for health effects." The CSPH analysis, based on three years of monitoring, finds a number of air toxics near the wells including benzene, toluene, ethylbenzene, and xylene.

However, critics have taken issue with the Colorado School of Public Health and other studies for a number of reasons including the use of (1) out of date data, (2) unrealistic estimates of emissions from sources, (3) overly conservative risk assessments when viewed in context, and (4) poor study design and input assumptions (e.g., the use of ambient collection methodology in a region populated with other emission sources such as roads, highways, and other industries). In support of this point, other studies have reported little or no health effects from the sector. For example, in 2012, the Houston-based Plains Exploration and Production Company (PXP) released a report that said hydraulic fracturing operations at the Inglewood oil field in the Baldwin Hills area in Los Angeles County posed "no public health or environmental threats." Similarly, in a review of health studies conducted by the Energy Institute at the University of Texas at Austin and published in February 2012, the authors conclude that "none of the studies reviewed ... showed a clear link between shale gas activities and documented adverse health effects, [and] that the gas industry has been using hydraulic fracturing for over 50 years, but the studies examined ... did not find any direct evidence for health impacts on workers in the industry or the public living near oil and gas industry activity." Further, many industry sources have argued that the standards promulgated under the 1999 Crude Oil and Natural Gas Production NESHAPs have demonstrated protection of public health with an ample margin of safety. Critics of EPA's regulatory requirements for air toxics have also expressed concern with the agency's decision to make significant and substantive changes to the agency's residual risk procedures, changes which they assert result in risk estimates between 100 and 1,000 times higher than actual. The contested procedures include (1) the consideration of risk from the total facility, (2) the consideration of risk across selected social, demographic, and economic groups within the population living near the facility, (3) the consideration of the hypothetical risk associated with the level of emissions allowed by the MACT standard, and (4) unreasonable assumptions concerning exposure points, times, and durations.

Greenhouse Gases

Finally, other studies focus on the impact of greenhouse gas emissions from crude oil and natural gas operations. Many of these studies advocate for the increased production and use of natural gas as a substitute for other fossil fuel resources because it is domestically available, economically recoverable, and considered a potential "bridge" fuel to a less polluting and lower GHG-intensive economy. However, when fugitive emissions of methane from all sectors of the industry are factored into the total life-cycle assessment of the resource, the advantage of natural gas over other fossil fuels is less clear. EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-20 11 (published April 15, 2013) estimates natural gas systems emitted 144.7 million metric tons of carbon dioxide equivalent (MMtCO 2 e) of methane in 2011, a 10% decrease from 1990 emissions, and 32.3 MMtCO 2 e of non-combustion CO 2 in 2011, a 14% decrease from 1990 emissions. EPA cites improvements in management practices and technology, along with the replacement of older equipment, as helping to stabilize emissions of CO 2 . The decrease in methane emissions is the result of a decrease in emissions from transmission and storage due to increased voluntary reductions and a decrease in distribution emissions due to a decrease in unprotected pipelines. However, natural gas systems in 2011 were cited as being the single largest contributor to U.S. anthropogenic (i.e., man-made) methane emissions, representing nearly 25% of the total methane emissions from all domestic sources and accounting for about 2% of all GHG emissions in the United States. Some recent studies (outlined below) argue that expanding the production and use of natural gas could actually exacerbate rather than help mitigate global warming because methane's global warming potential (GWP) is as much as 20—if not 50—times more potent than carbon dioxide, depending upon the time interval used to express warming impacts. These studies suggest that if significant amounts of methane were to leak during the production of natural gas, the climate forcing of methane could cancel out or even outweigh any benefit gained from switching away from oil or coal combustion processes.

Many of the published and publicly available life-cycle GHG emissions assessments of natural gas rely on the 1996 EPA/GRI emissions factors for methane leakage in the industry. EPA's recently updated emissions estimates suggest that leakage from natural gas systems is approximately 1.5% of gross national production. EPA has neither calculated nor stated whether these revisions negate the apparent advantage natural gas has over oil or coal when it comes to climate change. But some researchers, most notably Robert Howarth of Cornell University, have argued that they would. Howarth estimates that emissions from natural gas leakage are likely to be in the range of 3.6% to 7.9% of gross national production over the entire natural gas life-cycle (which includes production, processing, transmission, storage, and distribution). He estimates leakage at the wellhead during both well completion and production to be between 2.2% and 3.8%. At these rates, "the footprint of shale gas is at least 20% greater [than coal] and perhaps more than twice as great on the 20-year horizon and is comparable when compared over 100 years." Others, however, argue that Howarth's analysis is flawed, claiming that he significantly overestimates the fugitive emissions associated with unconventional gas extraction, undervalues the contribution of "green technologies" (e.g., REC) to reducing these emissions, bases the comparison between gas and coal on heat rather than electricity generation (almost the sole use of coal), and assumes a time interval (i.e., 20 years) over which to compute the relative climate impact of gas compared to coal, thus failing to capture the contrast between the long residence time of CO 2 and the short residence time of methane in the atmosphere.

The controversy has led to a number of life-cycle GHG assessments comparing natural gas to coal. Most use the emissions measurement data from the 1996 EPA/GRI study as a starting point for their assumptions. For example: Wigley (2011) considers the effects of methane leakage, changes in radiative forcing due to changes in the emissions of sulfur dioxide and carbonaceous aerosols, and differences in the efficiency of electricity production between coal- and gas-fired power generation, to find, on balance, "these factors more than offset [natural gas's] reduction in warming due to reduced CO 2 emissions" such that "when gas replaces coal there is additional warming out to [the year] 2050 with an assumed leakage rate of 0%, and out to 2140 if the leakage rate is as high as 10%." Hultman (2011), however, estimates that for electricity generation, the GHG impacts of shale gas are 11% higher than those of conventional gas, and only half that of coal for standard assumptions. Fulton (2011) concludes that U.S. gas-fired electricity generation emits 47% less GHG than coal using the IPCC's 100-year global warming potential index for methane, instead of the 20-year index used by Howarth. Jiang (2011) estimates that emissions from coal-fired electric generation are so much greater than gas-combustion plants that a fuel switch would reduce climate-forcing emissions as long as leakage in a natural gas system is less than 14% (using the IPCC 100-year GWP) or 7% (using the IPCC 20-year GWP). Alvarez (2012), however, in an assessment similar to Jiang's, concludes that leakage in the natural gas system would only need to be 3.2% before the overall lifecycle emissions estimates for natural gas electricity generation surpassed those of coal in the near term. Further, powering vehicles with natural gas rather than gasoline would not strike the same balance in the near term unless gas producers bring their leakage rate down to a maximum of 1.6%; and replacing diesel with natural gas would cause greater near-term climate impacts unless leak rates were under 1.0%. Alvarez stresses that the climatic effect of replacing other fossil fuels with natural gas may vary widely depending upon the examined time horizon (e.g., 20, 100, or 500 years), the end-use sector (e.g., electricity generation or transportation) and the fuel replaced (e.g., coal, gasoline, or diesel).

Cost Benefit Analysis of Federal Standards

Natural gas is a product of—and thus a source of revenue for—the oil and gas industry. It is also a main source of pollution from the industry when it is emitted into the atmosphere. Due to this unique linkage, pollution abatement has the potential to translate into economic benefits for the industry, as producers may be able to offset compliance costs with the value of natural gas and its byproducts recovered and sold at market. To capitalize on these incentives, many recovery technologies have been incorporated into industry practices, and have thus served as the basis for several local, state, and federal regulations. The 2012 federal air standards require natural gas producers to use recovery technologies to capture approximately 95% of the methane and VOCs that escape into the air as a result of hydraulic fracturing operations. The agency estimates that the equipment and the activities required to comply with the 2012 standards will cost producers about $170 million a year, but calculates that incorporating the sale of recovered products into the cost will result in an estimated net gain of about $11 million to $19 million a year. The industry disagrees with these estimates and counters with compliance cost estimates at more than $2.5 billion annually. Third parties, such as Bloomberg Government, project a net cost between $316 million and $511 million, or, approximately 1% of industry's annual revenue. All estimates are based on assumptions regarding the quantity of captured emissions, the cost and availability of capital equipment, and the market price for natural gas. In light of these considerations, Congress may opt to examine ways in which to best align the costs of requirements with sustainable resource expansion, industry growth, and job creation.

EPA estimates the 2012 air standards would yield a cost savings of $11 million to $19 million in 2015, as pollution abatement costs would be offset by the value of natural gas and condensate recovered and sold at market. EPA's annual cost estimates include (1) cost of capital, (2) operating and maintenance costs, (3) cost of monitoring, inspection, recordkeeping and reporting (MIRR), and (4) associated product recovery credits. All costs are reported in 2008 dollars, and calculated as follows: The total estimated net annual cost to industry to comply with the final amendments in the Crude Oil and Natural Gas Production NESHAPs is approximately $3.3 million. The total estimated net annual cost in the Natural Gas Transmission and Storage NESHAPs is approximately $180,000. The total estimated net annual cost to industry to comply with the final NSPS is approximately $170 million; and, when revenues from additional product recovery are considered, the final NSPS is estimated to result in a net annual engineering cost savings of approximately $15 million. EPA assumes that producers will be paid $4/Mcf for the recovered gas at the wellhead and $70 per barrel for recovered condensate, with about 43 million Mcf (i.e., 43 billion cubic feet) of natural gas and 160,000 barrels of condensate recovered by control requirements in 2015. Further, EPA estimates that the operation cost of 3-10 days of hydraulic fracturing with reduced emissions completions would be $700 to $6,500 per day with an additional $3,500 per well for flare equipment, for an average incremental cost of using the abatement technology of $33,237 per completion. EPA annualizes the cost using a 7% discount rate.

The American Petroleum Institute (API), in its comments to EPA on the proposed regulation, included a consultant's report that projects compliance costs of more than $2.5 billion annually after accounting for incremental sales of the fuel. API estimates the cost of flaring emissions to be $90,000 per well, and the operation cost of using (i.e., renting and setting up) reduced emissions completions to be $180,000 per completion. API reports that only 300 REC sets are currently in existence, with the capacity to produce only 4,000 wells a year. Working with EPA's projection that there would be 25,000 new or modified hydraulically fractured wells completed annually, API argues that the equipment prescribed to conduct reduced emission completions would not be available in time to comply with the rule schedule. Further, API contends that EPA's cost analyses are based on "average model facilities" that do not represent all equipment and compliance costs and fail to identify when the controls are no longer economic. At the time of the proposed rule, API's consultant claimed that the proposed air standards could create "a significant slowdown in unconventional resource development ... resulting in less reserve additions, less production, lower royalties to the Federal government and private landowners, and lower severance tax payments to state governments. The delays in drilling result in delays in production, which result in the delays in the economic benefits associated with that production." Other industry commentators have gone further by stating that the full burden of regulations would fall squarely upon the producers, because economic incentives dictate that producers are currently capturing and selling all economically recoverable natural gas. EPA's rule would "divert investments from capital and energy development into regulatory compliance efforts, and impose onerous notification, record keeping, monitoring, reporting, and performance testing requirements that industry will necessarily incur costs to keep up with."

In the final Regulatory Impact Assessment issued in April 2012, EPA examines the compliance costs for slightly more than 11,000 hydraulically fractured wells that would be drilled in unconventional formations, and nearly 1,500 that would be re-fractured to stimulate production. Of those, approximately 6,600 are assumed to be using reduced emissions completions voluntarily or under state/local regulations, and an additional 12% would be classified as exploratory, delineation, or low-pressure wells exempt from the 2012 standards, leaving about 4,600 that would be compelled to use REC as a result of federal regulation. API, however, claims that most large producers in the natural gas sector are currently using REC where feasible and "where it makes economic sense." Chesapeake Energy, the number two U.S. gas producer, has said it limits emissions on "a very high percentage" of its wells. Fourth-ranked Devon Energy has stated it uses REC for 91% of its wells. A survey of nine API members working in 29 drilling areas reported their members doing REC on 70% of their wells. America's Natural Gas Alliance (ANGA) submitted a survey to EPA of eight unidentified production companies that report using REC on 93% of their wells in 2011. As with any self-selected and self-reported survey, it is difficult to determine how representative these samples are of overall industry practice.

A comparative report by Bloomberg Government—using slightly different values to analyze the available data on affected wells, compliance costs, products recovered, and market prices—calculates that the costs would fall somewhere in between both EPA's and API's projections. In their analysis, the regulation would generate an initial $125 million in spending on new equipment and $383 million in annual rental and service fees beginning in 2015. Factoring in product recovery, the total net costs of compliance would fall between $316 million and $511 million per year depending upon the market price of natural gas—or, more than twice the amount estimated by EPA and less than half that projected by API. This increase would account for approximately 0.5% to 0.7% of the industry's 2011 gas sales, which they determined "may cause a slight reduction in drilling activity." Bloomberg Government noted that EPA's analysis assumed natural gas prices 40% above levels at the time and estimates that prices would need to rise to $10/Mcf to make the value of recovered products equal to the compliance costs.

Relevant Legislation in the 113th Congress

Legislation in the 113 th Congress to amend the Clean Air Act to address emissions from crude oil and natural gas production activities includes the following:

The BREATHE Act. On March 14, 2013, Representative Jared Polis (D-CO-2) and 40 co-sponsors introduced H.R. 1154 , a bill "to amend the Clean Air Act to eliminate the exemption for aggregation of emissions from oil and gas development sources, and for other purposes." Dubbed the Bringing Reductions to Energy's Airborne Toxic Health Effects Act, or BREATHE Act, the proposed bill would amend the CAA to (1) include hydrogen sulfide in the list of hazardous air pollutants, and (2) repeal the exemption on aggregating emissions from any oil or gas sources for any purpose relating to hazardous air pollutant emission standards. The bill was referred to the House Committee on Energy and Commerce on March 14, 2013.

Conclusion

U.S. natural gas production has grown markedly in recent years. This growth is due in large part to increased activities in unconventional resources brought on by technological advance. Many have advocated for the increased production and use of natural gas in the United States for economic, national security, and environmental reasons. They argue that natural gas is the cleanest-burning fossil fuel, with fewer emissions of carbon dioxide, nitrogen oxide, sulfur dioxide, particulate matter, and mercury than its hydrocarbon rivals (e.g., coal and oil) on a per-unit-of-energy basis. For these reasons, many have looked to natural gas as a "bridge" fuel to a less polluting and lower greenhouse gas-intensive economy. However, the recent expansion in natural gas production in the United States has given rise to a new set of concerns regarding human health and environmental impacts, including impacts on air quality.

To address air quality and other environmental issues, the oil and gas industry in the United States has been regulated under a complex set of local, state, and federal laws. Currently, state and local authorities are responsible for virtually all of the day-to-day regulation and oversight of natural gas systems, and many states have passed laws and/or have promulgated rules to address air quality issues based on local needs. Further to this, organizations like the State Review of Oil and Natural Gas Environment Regulations (STRONGER) are available to help states assess the overall framework of environmental regulations supporting oil and gas operations in their regions. At the federal level, EPA has promulgated minimum national standards for VOCs, SO 2 , and HAPs for some source categories in the crude oil and natural gas sector. The federal air standards focus primarily on the production and processing sectors of the industry, and were drawn, in part, from existing requirements found in the state codes of Colorado and Wyoming. Further to this, many producers in the crude oil and natural gas sector have set forth a series of recommended practices. These practices are sustained by the economic incentives provided by capturing the fugitive releases of natural gas and its byproducts to be sold at market. Several voluntary partnerships sponsored by various federal and international agencies also serve to facilitate recommended practices for emissions reductions in the oil and gas industry. EPA's Natural Gas STAR Program, the Global Methane Initiative (formerly the Methane to Markets Partnership), and the World Bank Global Gas Flaring Reduction Partnership are three such programs.

Many believe that air standards similar to those promulgated by Colorado, Wyoming, and the federal government are sufficient to control VOC, SO 2 , and HAP emissions from the natural gas production sector. Some argue that the cost of compliance with state and federal air standards could affect industry profits, thereby reducing economic interest to invest and slowing production activities. Others are concerned that some pollutants and some emission sources remain unregulated by any standard, including methane, hydrogen sulfide, oil wells, offshore wells, conventional gas wells, and most operations downstream of the gas processing plant. Debate over the costs of compliance, covered sources and pollutants, and the proper regulatory institutions (i.e., local, state, or federal) continues. Complicating these debates is the fact that a comprehensive national inventory that directly measures the quantity and composition of fugitive emissions from natural gas systems does not exist. This is due to many factors, including costs and technical uncertainties. But, until there is an adequate and reliable assessment of industry-wide emissions, the benefits, costs, and basis for regulation may remain uncertain.

Appendix A. Federal Air Standards for Crude Oil and Natural Gas Systems

Appendix B. Composition of Fugitive and Combusted Natural Gas Emissions

Fugitive Natural Gas

Fugitive natural gas is primarily a mixture of low molecular-weight hydrocarbon compounds that are gases at surface pressure and temperature conditions. While the principal component of natural gas is methane (CH 4 ), it may contain smaller amounts of other hydrocarbons, such as ethane, propane, and butane, as well as trace amounts of heavier hydrocarbons. Non-hydrocarbon gases, such as carbon dioxide (CO 2 ), helium (He), hydrogen sulfide (H 2 S), nitrogen (N 2 ), and water vapor (H 2 O), may also be present in any proportion to the total hydrocarbon content (see Table B -1 ).

Combusted Natural Gas

Combusted natural gas releases carbon dioxide (CO 2 ), carbon monoxide (CO), nitrogen oxides (NOx), and trace amounts of sulfur dioxide (SO 2 ), particulate matter (PM), uncombusted methane (CH 4 ), VOCs, and HAPs. Combusted natural gas is generally regarded as "cleaner" than other fossil fuels with respect to various criteria pollutants and greenhouse gas (GHG) emissions (see EPA's and EIA's data comparisons in Table B -2 ). Coal, fuel oil, and petroleum-based transportation fuels are composed of more complex long-chain hydrocarbon molecules, with higher carbon ratios, and may contain higher nitrogen and sulfur contents as well as increased amounts of ash and particulate matter. By comparison, the combustion of natural gas releases minimal amounts of sulfur dioxide and nitrogen oxides, virtually no ash or particulate matter, and lower levels of carbon dioxide, carbon monoxide, and other reactive hydrocarbons. While comparisons among the emission profiles of natural gas, coal, fuel oil, and transportation fuels are useful in certain contexts, it should be noted that these comparisons are not wholly substitutable, as end-uses of the fuels vary across sectors and pollution control mechanisms are in place for many of the fuels' combustion activities.

Appendix C. Glossary of Terms