Shale Maps

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To create the maps below, RFF staff and outside experts reviewed state statutes, regulations, permitting guidelines, and other documents, along with independent reports. Experts and regulators in the states were also contacted to review the findings.

The maps show only uniform, state-level regulation in force as of March 1, 2013, except for New York, which is treated as if the proposed rules in its 2011 Supplemental Generic Environmental Impact Statement were currently in place. Local and federal regulations are not included.

Read more.

Site Development and Preparation (4)
Site Development and Preparation

Site development and preparation begins before an operator selects an area for drilling. Many companies perform pre-drilling examinations such as seismic and water quality tests before finalizing the site choice. The operator must first ensure that the location adheres to siting rules, including any setback restrictions, which regulate the distance between wells and other entities like schools, homes, streams, and water wells that are thought to merit special protection. Most states have uniform well spacing requirements that limit the number of wells in an area, but these rules do not indicate how far wells must be from specific features. Thus, states enact setback restrictions to avoid environmental impacts and community disruption. Once a site has been selected, the land must be cleared—usually two acres, but up to twelve depending on the location and number of wells on the pad. All of the requisite equipment and materials are brought to the site at this time. An impoundment is often built to hold freshwater, which is either trucked or piped to the location in preparation for drilling.
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- Pre-Drilling Water Well Testing
  Pre-Drilling Water Well Testing
  
  This map shows states that require operators to test nearby water wells before drilling shale gas wells. Pre-drilling water well testing establishes the baseline water quality for an area prior to drilling activity. The majority of states’ regulations do not mention baseline water well testing. Some states do require testing within a specific distance from the proposed gas well, given as a radius from the wellhead (the average radius is about ½ mile). Most of these states require operators to test two wells within the specified radius. Colorado and Ohio require testing in certain areas or under certain conditions. For instance, the Wattenberg field in Colorado (part of the Niobrara play) is the only zone in that state that requires pre-drilling water well testing. Pennsylvania regulations do not require pre-drilling testing, but such testing is necessary for operators to defend suits alleging groundwater contamination. API best practice is to test samples from any source of water located near the well (determined based on anticipated fracture length) before drilling or hydraulic fracturing.
  
  Last updated September 24, 2012
  
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  Pre-Drilling Water Well Testing
- Water Withdrawals
  Water Withdrawals
  
  Hydraulic fracturing requires large amounts of water. This map shows state regulations on freshwater withdrawals. In a few cases, water withdrawals are regulated by interstate river basin commissions, whose regulations are not reflected on this map. Most of the states surveyed (21) require general permits for surface water and/or groundwater withdrawals. However, several states do not require permits for withdrawals below a certain threshold (shown on the map in gallons per day, GPD).
  
  Pennsylvania requires a water management plan covering the full life cycle of the water used in shale gas production, including the location and amount of the withdrawal and an analysis of the impact of the withdrawal on the body of water from which it came. Louisiana recommends that groundwater used for drilling or fracturing be taken from the Red River Alluvial aquifer. Six states require water withdrawals to be registered and reported, and three states require permits in addition to registration and reporting. Kentucky specifically exempts the oil and gas industry from water withdrawal requirements.
  
  API best practices say that “consultation with appropriate water management agencies is a must,” and “whenever practicable operators should consider using non-potable water for drilling and hydraulic fracturing.”
  
  Last updated September 24, 2012
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  Water Withdrawls
- Setback Restrictions from Buildings
  Setback Restrictions from Buildings
  
  This map shows state regulations that set a minimum distance between wells and buildings. More than half of surveyed states (17) have such building setback restrictions, ranging from 100 to 1,000 feet, with an average of 261 feet. “Other setback restrictions” refers to states that either have setback restrictions from structures other than residential and other buildings or measure setbacks from equipment other than the wellhead.
  
  In some states, setback restrictions apply to all “occupied dwellings,” while in other states, the requirements pertain only to specific structures like schools, hospitals, and churches. Setbacks may be greater in urban areas in some states (for example, Ohio and Colorado). New Mexico and Arkansas measure setback restrictions from pits and tanks, respectively, but not from wells; California regulates the distance between wells and public streets, roads, or highways, but not buildings.
  
  API best practice is that, “when feasible, the wellsite and access road should be located as far as practical from occupied structures and places of assembly.”
  
  Last updated September 24, 2012
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  Setback Restrictions from Buildings
- Setback Restrictions from Water Sources
  Setback Restrictions from Water Sources
  
  This map shows state regulations that set a minimum distance between wells and water sources. Almost a third of states surveyed (9) have such setback restrictions from some body of water or water supply source; six of those have setback restrictions from municipal water supplies (measured from the well) ranging from 350 to 2,000 feet, with an average of 885 feet. “Other setback restrictions” refers to states that either have setback restrictions from entities other than municipal or other water sources or measure setbacks from equipment other than the wellhead.
  
  Michigan also has setback restrictions from municipal water sources that are measured from other pieces of equipment such as well separators and storage tanks, but not from the well, and vary depending on the type of water supply. Kansas, New York, Pennsylvania, and Ohio have additional setback restrictions from other water sources such as lakes, streams, and private water wells. New Mexico and Arkansas measure setback restrictions from pits and tanks, respectively, but not from wells.
  
  API best practice, where feasible, is to locate sites away from sensitive areas such as surface waters and freshwater wells. Also, “pits used for long term storage of fluids should be placed an appropriate distance from surface water to prevent unlikely overflows from reaching the surface water.”
  
  Last updated September 24, 2012
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  Setback Restrictions from Water Sources
Well Drilling and Production (9)
Well Drilling and Production

After the site is prepared and the drilling rig is set up, drilling can begin. As the well is drilled, casing must be put in place and cemented. Poor casing and cementing can provide a potential conduit for groundwater contamination, and most states therefore have detailed casing and cementing regulations. Once the surface casing is set and cemented, the well is drilled deeper and an intermediate string of casing is often set and cemented. When the wellbore is just above the production zone, the drill turns and drills horizontally. The production casing is then set and cemented.

To begin the hydraulic fracturing process, a fracture gun is detonated in the horizontal wellbore to create fractures in the casing, cementing, and rock, which are then propagated by the introduction of the fracturing fluid under high pressure. Fracturing fluid is composed of water, chemicals, and proppant (such as sand) that prop the fractures open to allow gas to flow up the wellbore. Before and during production, excess gas may be vented or flared if it cannot be stored or used commercially.

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- Natural Gas Wells and Shale Gas Production
  Natural Gas Wells and Shale Gas Production
  
  This map shows natural gas production by state, based on data from the U.S. Energy Information Administration. The shading indicates the number of producing natural gas wells (shale or conventional) in the state in 2010. The sizes of the red circles indicate each state’s amount of shale gas production in 2009. Production is measured in thousand cubic feet (MCF). Note that the well count data are for all natural gas wells, not just shale gas. Also note that shale gas production in many states has increased significantly in recent years. Table 1: Natural Gas Wells and Shale Gas Production shows the same data in table form.
  
  Last updated August 28, 2012
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  Natural Gas Wells and Shale Gas Production
- Cement Type Regulations
  Cement Type Regulations
  
  This map shows state regulations on the types of cement that can be used in well development. Class A Portland cement is the most commonly used type of cement for setting casing in place. Cement types vary by well and operator, and 11 states surveyed mandate specific types that must be used. Several states, including Michigan, require the cement mixture to be of a specific composition and volume that must be approved by the supervisor of the regulating agency. New York’s proposed legislation specifically mandates that cement would have to conform to API Specification 10A and contain a gas-block additive.
  
  API best practice is that appropriate API standards should be consulted in selection of cement, and “selected cements, additives, and mixing fluid should be laboratory tested in advance to ensure they meet the requirements of the well design.”
  
  Last updated September 24, 2012
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  Cement Type Regulations
- Casing and Cementing Depth
  Casing and Cementing Depth
  
  This map shows state minimums for casing and cementing depths. These regulations vary widely across states. Some states (14) set the regulation based on depth below the water table. Among these, the average required depth below the water table is about 65 feet, with a range of 30 to 500 feet. Ten of the states surveyed rely on well-specific determinations. In these instances, instead of a specific mandate, regulations often specify that “casing must be set and cemented to protect all freshwater bearing zones.” In Kansas, casing and cementing depth below the water table is determined by county, but the state requires at least 50 feet of surface casing. Alabama, California, Louisiana, Mississippi, and South Dakota regulate the minimum number of feet of casing that must be used, but not the depth below the water table. Virginia does not have regulations for casing and cementing depth.
  
  API best practice is a casing and cementing depth of 100 feet below the deepest underground source of drinking water encountered while drilling the well.
  
  Last updated September 24, 2012
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  Casing and Cementing Depth
- Surface Casing Cement Circulation Regulations
  Surface Casing Cement Circulation Regulations
  
  This map shows state regulations on cement circulation in surface casing. Cementing practices may be regulated in terms of compressive strength, type of cement, or circulation around casing. Circulation around casing refers to the process by which cement is pumped down the wellbore and up through the annulus on the outside of the casing, cementing it in place. Geology and state law help determine how high cement must be circulated around the casing. This map shows that 28 states surveyed require surface casing to be cemented through the length of the annular space to the surface.
  
  API best practice is “that the surface casing be cemented from the bottom to the top,” but where that is not possible, cementing across all underground sources of drinking water is recommended.
  
  Last updated September 24, 2012
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  Surface Casing Cement Circulation Regulations
- Intermediate Casing Cement Circulation Regulations
  Intermediate Casing Cement Circulation Regulations
  
  This map shows state regulations on cement circulation in intermediate casing. After the surface casing is set and cemented, an intermediate casing is often set and cemented as well. States may regulate which portions of the intermediate casing must be cemented—that is, how high the cement must be circulated in the annulus. Only four states require cement to be circulated to the surface of the intermediate casing, and three states have performance-based standards, directing operators to isolate and protect groundwater or hydrocarbon zones, but not telling them exactly how far cement must be circulated to achieve that. Seven states have specific regulations for how high cement must be circulated above the shoe or uppermost hydrocarbon zone. Ohio requires 500 feet above the casing seat, and Wyoming specifies 200 feet above a specific geologic layer.
  
  API recommends that sufficient cement be circulated around the intermediate casing to isolate all underground sources of drinking water and hydrocarbon zones. API best practice is that “if the intermediate casing is not cemented to the surface, at a minimum the cement should extend above any exposed underground sources of drinking water or any hydrocarbon bearing zone.”
  
  Last updated September 24, 2012
  
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  Intermediate Casing Cement Circulation Regulations
- Production Casing Cement Circulation Regulations
  Production Casing Cement Circulation Regulations
  
  This map shows which portions of the production casing must be cemented. Only two states require cement to be circulated to the surface, and five states have performance-based standards, directing operators to isolate and protect groundwater or hydrocarbon zones, but not telling them exactly how far cement must be circulated to achieve that. Twelve states have specific regulations for how high cement must be circulated above the shoe, true vertical depth, or uppermost hydrocarbon zone. Alabama, California, Georgia, and Louisiana stipulate that cement must reach 500 feet above the uppermost hydrocarbon zone; Colorado and Illinois mandate 200 and 250 feet, respectively, above the uppermost hydrocarbon zone; and Wyoming specifies 200 feet above the trona interval. Mississippi and North Carolina require cement to reach 500 feet above the shoe, and Texas requires cement to reach 600 feet above the shoe. Pennsylvania mandates cement circulation 500 feet from the true vertical depth, and Ohio requires 1,000 feet above the kickoff point.
  
  API states that best practice is to cement production casing to “at least 500 ft. above the highest formation where hydraulic fracturing will be performed.”
  
  Last updated September 24, 2012
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  Production Casing Cement Circulation Regulations
- Venting Regulations
  Venting Regulations
  
  This map shows state limitations on venting—the release of gas from the wellbore into the atmosphere. More than half of states surveyed (21) have some form of venting regulations, though these vary greatly across states. Some states have specific restrictions, such as the number of days that venting may occur, the amount of gas that may be vented, or the development phases during which gas may be vented. That is, some states specify that venting may be allowed during well cleanup, well testing, and emergencies, but at no other time. Some states have “aspirational standards,” which require operators to minimize gas waste or not to harm public health, but impose no effective requirement or standard. Louisiana prohibits venting unless it can be shown that the prohibition causes economic hardship.
  
  API suggests that all gas resources of value that cannot be captured and sold should be flared, but says that any venting should be restricted to a safe location and oriented downwind relative to the prevailing wind direction at the site.
  
  Last updated September 24, 2012
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  Venting Regulations
- Flaring Regulations
  Flaring Regulations
  
  This map shows state limitations on flaring—the burning of excess gas in stacks or flares. The majority of states surveyed (22) have some flaring regulations, though these vary greatly across states. Some states restrict the amount of gas that may be flared, the location of flares, or the development phases during which gas may be flared. That is, some states specify that flaring may be used during well cleanup, well testing, and emergencies, but at no other time. Several states mandate that gas be flared rather than vented.
  
  API suggests that all gas resources of value that cannot be captured and sold should be flared and recommends that flares be restricted to a safe location and oriented downwind relative to the prevailing wind direction at the site.
  
  Last updated September 24, 2012
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  Flaring Regulations
- Fracking Fluid Disclosure
  Fracking Fluid Disclosure
  
  This map shows state regulations requiring disclosure of the composition of fluids used for hydraulic fracturing. At the federal level, hydraulic fracturing is exempt from disclosure that would otherwise be required by the Safe Drinking Water Act, though the Department of the Interior recently proposed rules requiring frack fluid disclosure for wells drilled on public lands. Less than half of states surveyed (14) require disclosure of fluids used in the fracturing process. At least three states have proposed rules; two other states have some form of fluid disclosure regulations, but it is unclear whether they pertain to hydraulic fracturing. Illinois’s proposal would strengthen existing disclosure rules.
  
  The level of disclosure detail required also differs across states. Few states require disclosure of all chemicals used; even fewer require disclosure of additive volume and concentration. Pennsylvania, for example, requires the disclosure of percent by volume of each additive in the stimulation fluid, whereas Arkansas requires additives to be expressed as a percent by volume of the total hydraulic fracturing fluids and of the total additives used. All states with chemical disclosure requirements provide trade secret exemptions for chemicals considered “confidential business information.” Wyoming requires prior approval for use of benzene, toluene, ethylbenzene, and xylene (BTEX) compounds.
  
  API suggests that operators be prepared to disclose information on chemical additives and their ingredients and says that “the best practice is to use additives that pose minimal risk of possible adverse human health effects to the extent possible in delivering needed fracture effectiveness.”
  
  Last updated September 24, 2012
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  Fracking Fluid Disclosure
Flowback/Wastewater Storage and Disposal (5)
Flowback/Wastewater Storage and Disposal

During the fracturing process, between 1 and 7 million gallons of water per well is pumped down the wellbore, along with chemicals and proppant, to create the fractures from which the gas will flow. Although most of the water used remains underground, anywhere from 10 to 50 percent will flow back up and out of the wellbore. Flowback fluid and produced fluids, generally referred to as wastewater, require storage and disposal. Storage and disposal options vary by state and depend in large part on the chemical makeup of wastewater and geological conditions.

Photo: Argonne
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- Fluid Storage Options
  Fluid Storage Options
  
  This map shows state rules limiting pre- and post-fracturing fluid storage. Fluid storage needs vary over the course of the shale gas development process. Fracking fluids must be stored before being used, and post-fracturing flowback/wastewater, including fracturing fluid and produced water, must also be stored before disposal. Fluids are most commonly stored in pits and tanks; 9 surveyed states specifically address only pit storage, whereas 19 specifically mention both pits and tanks in their regulations.
  
  The map displays the storage information explicitly stated in a state’s regulations. If a state does not mention tank storage, for example, it would be categorized as “pits only,” though storage may be addressed otherwise in the permit. California mandates a closed-loop system in which fluids are not exposed to the elements at any point. Michigan allows pits to be used only for drilling fluids, muds, and cuttings; tanks must be used for produced water, completion fluids, and other liquid wastes, and in all areas zoned residential. Other storage options include ponds, sumps, containers, impoundments, and ditches.
  
  API best practice stipulates that “completion brines and other potential pollutants should be kept in lined pits, steel pits, or storage tanks.”
  
  Last updated September 24, 2012
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  Fluid Storage Options
- Freeboard Requirements
  Freeboard Requirements
  
  This map shows state freeboard requirements for fluid storage pits—that is, the amount of space in the pit between the maximum water level and the top of the pit. Freeboard is important for preventing overflow of fluids, particularly during and after intense rain. Of the 28 states that allow storage of fluids in pits, 16 have freeboard regulations, ranging from 1 to 3 feet. New Mexico differentiates between permanent and temporary pits in the amount of freeboard required: 3 feet and 2 feet, respectively. Oklahoma requires 1.5 feet of freeboard for temporary pits, 2 feet of freeboard for noncommercial pits, and 3 feet of freeboard for pits capable of holding more than 50,000 barrels. Montana’s requirements apply only to earthen pits or ponds that receive produced water containing more than 15,000 ppm total dissolved solids in amounts greater than 5 barrels per day on a monthly basis. California does not allow the use of pits for fluid storage, and thus freeboard requirements are not applicable.
  
  API best practice is that pits should be constructed with sufficient freeboard “to prevent overflow under maximum anticipated operating requirements and precipitation.”
  
  Last updated September 24, 2012
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  Freeboard Requirements
- Pit Liner Requirements
  Pit Liner Requirements
  
  This map shows state regulations on pit liners, which prevent fluids from seeping into the ground and potentially contaminating groundwater. Most of the states surveyed (19) that allow fluid storage in pits require pit liners. Of these states, 11 have specific regulations about the thickness of the liners, and several have other regulations such as permissible liner materials (for example, recompacted clay liners, soil mixture liners, and synthetic liners). Alabama, Montana, and Wyoming all have conditional requirements for pit liners, such as Alabama’s rule that liners are required only if the bottom of the pit is not above the seasonal high water table. Wyoming requires liners only if they are “necessary” to prevent contamination of surrounding ecosystems. California does not allow the use of pits for fluid storage, and thus pit liner requirements are not applicable.
  
  API best practice is that, “depending upon the fluids being placed in the impoundment, the duration of the storage and the soil conditions, an impound lining may be necessary to prevent infiltration of fluids into the subsurface.”
  
  Last updated September 24, 2012
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  Pit Liner Requirements
- Flowback/Wastewater Transportation Tracking
  Flowback/Wastewater Transportation Tracking
  
  This map shows state requirements for tracking flowback or wastewater. Wastewater that is not reused, recycled, or disposed of on-site is transported off-site, usually in trucks. The tracking of transported flowback or wastewater can be enforced either by requiring transporters to have permits or by requiring detailed recordkeeping of shipments, or both. Recordkeeping requirements often include the names of the operator and transporter, the date the wastewater was picked up, the location at which it was picked up, the location of the disposal facility or destination of the shipment, the type of fluid being transported, and the volume. Many states also stipulate the number of years that such records must be kept available to inspectors. Slightly more than half of the states surveyed (16) do not require tracking of transported flowback or wastewater. The rest (15) use permits, recordkeeping, or both to track the process. Colorado and Kansas require records to be kept of wastewater shipments but do not require transporters to be approved or permitted. In some cases, the onus is placed on the operator to ensure that all information is tracked and reported, whereas in other cases, the burden is on the transporter to do so.
  
  API best practice is that wastewater be transported “in enclosed tanks aboard DOT compliant tanker trucks or a dedicated pipeline system.”
  
  Last updated September 24, 2012
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  Flowback/Wastewater Transportation Tracking
- Underground Injection Wells for Flowback and Produced Water
  Underground Injection Wells for Flowback/Wastewater and Produced Water
  
  This map shows which states allow underground injection of produced water. Arkansas, Colorado, Ohio, Oklahoma, and Texas have recently experienced an increase in seismic activity near deep underground injection sites. As a result, many deep injection wells have been closed while further research is conducted. Almost all of the states surveyed (30) allow deep well injection as a form of wastewater disposal. North Carolina prohibits underground injection of fluids produced in the extraction of oil and gas wells. Arkansas has a moratorium on deep injection in a 600-square-mile area of the state where a fault may have been activated by wastewater injections in the area. Ohio recently followed a similar course of action, temporarily closing down several injection wells in an area where seismic activity has occurred. Fort Worth, Texas, has a moratorium on deep injection wells. For more information on other disposal options, see Table 2: Flowback/Wastewater Disposal Options.
  
  API best practice is that “disposal of flow back fluids through injection, where an injection zone is available, is widely recognized as being environmentally sound, is well regulated, and has been proven effective.”
  
  Last updated September 24, 2012
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  Underground Injection Wells for Flowback and Produced Water
Well Plugging and Abandonment (2)
Well Plugging and Abandonment

When a well is no longer producing, it must be permanently plugged and abandoned. However, many companies choose to temporarily abandon a well and bring it back into production when it is more economical to do so. Most states have detailed plugging and abandonment procedures to ensure that the well does not become a conduit for contamination through migration of fluids and gases from nearby wells being fractured.

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- Well Idle Time
  Well Idle Time
  
  This map shows state regulations limiting the length of time a well can remain idle—that is, not currently producing oil or gas. Most states (26) regulate the amount of time that a well is allowed to sit idle before it must receive official temporary abandonment status or be either permanently plugged and abandoned or brought back into production. The time ranges from 1 to 300 months, with an average of 24 months. Several states have a range of permitted idle times depending on whether the well is productive or nonproductive, or depending on the casing installed in the well. Oklahoma, for example, specifies that wells that have only a surface casing must be plugged within 90 days, whereas a well that was completed with production casing may remain inactive for 12 months.
  
  API does not have a recommended best practice for well idle time.
  
  Last updated September 24, 2012
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  Well Idle Time
- Temporary Abandonment
  Temporary Abandonment
  
  This map shows state regulations governing the temporary abandonment of wells. When a well is no longer producing at an economical rate, an operator may choose to stop production but not permanently plug the well. Such temporary abandonment is a formalized way of leaving a well idle. Most of the states surveyed (24) have temporary abandonment regulations, and typically, operators have to apply for a permit to temporarily abandon a well. In addition, states have a time limit attached to the temporary abandonment permit or approval, ranging from 3 to 60 months, with an average of 25 months. Operators can often apply for extensions, which also have an expiration date and can have renewal limits. Kansas, for example, will renew a temporary abandonment permit for up to 10 years. When a temporary abandonment permit expires, the well must be either permanently plugged and abandoned or brought back into production, or if permitted, an extension may be obtained. This map displays the initial duration of the temporary abandonment permit.
  
  API best practice is that when a well is temporarily abandoned, it “must be maintained in a condition where routine workover operations can restore a wellbore to service.”
  
  Last updated September 24, 2012
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  Temporary Abandonment
Well Inspection and Enforcement (3)
Well Inspection and Enforcement

Well inspection and enforcement varies greatly by region. The degree to which an agency is effective in inspecting well sites can depend on the number of inspectors, the enforcement budget, and the level of voluntary reporting that is required in that state, among many factors.

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- Accident Reporting Requirements
  Accident Reporting Requirements
  
  This map shows state requirements for reporting accidents at shale gas wells and the specific time or range of times in which accidents must be reported, which averages 14 hours. Most of the states surveyed (26) require reporting of accidents, such as spills, leaks, and fires. Several states offer different timelines depending on the severity of the spill. Louisiana and Virginia, for example, set a 24-hour timeline for spills that are not categorized as “emergencies.” New Jersey has a 2-hour reporting requirement if potable water supplies are affected and a 24-hour requirement if an underground source of drinking water is impacted. West Virginia does not provide a timeline but states that in case of an accident, the operator must give notice to the district oil and gas inspector or the chief. Typically, operators are then given a specific number of days thereafter to file a written report detailing the accident. On the map, a zero indicates that accidents must be reported immediately.
  
  API best practice is that “a spill or leak should be promptly reported.”
  
  Last updated September 24, 2012
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  Accident Reporting Requirements
- Number of Regulating State Agencies
  Number of Regulating State Agencies
  
  This map shows the number of state-level agencies with authority over aspects of shale gas development. Shale gas regulation can be complex, because multiple state agencies, often with overlapping jurisdictions, are involved, along with federal agencies, river basin commissions, and municipal governments. Natural resource or environmental agencies are usually the main regulators, but other agencies are often involved as well. New Jersey currently has a one-year moratorium on hydraulic fracturing and has not yet designated an agency to be responsible for regulating shale gas extraction in the event that it is legalized. The average number of state agencies is two, with a range of zero to six.
  
  Last updated September 24, 2012
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  Number of Regulating State Agencies
- Number of Wells per Inspector
  Number of Wells per Inspector
  
  This map shows the ratio of gas wells (unconventional and conventional) to inspectors in each state. The degree to which an agency is effective in inspecting well sites can depend on much more than this ratio, however. The stringency and complexity of state regulations (and therefore the complexity of inspections), the number and ages of drilled and producing wells, and other factors differ greatly among states.
  
  Note that well data are from 2010 but inspector data are generally more recent; given the speed of shale gas expansion, this mismatch means these ratios should be taken as estimates only. States with no oil and gas development at this time, such as New Jersey, may have zero inspectors because there are no wells to inspect. Many states are proposing to hire more inspectors, though some, like Arkansas, are in danger of losing inspectors due to a lack of funding.
  
  Last updated September 24, 2012
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  Number of Wells per Inspector
Other (4)
Other

This category includes maps showing state and local bans and moratoria as well as severance taxes in each state.
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- State and Local Bans and Moratoria
  State and Local Bans and Moratoria
  
  Several state and local governments have passed bans and moratoria on various parts of the horizontal drilling and hydraulic fracturing process. New York State, in addition to a statewide moratorium, has more than 50 local bans and moratoria. Several states with local or municipal bans are currently in litigation over the legality of local regulation of shale gas extraction. Two New York judges recently upheld local ordinances banning the practice, whereas a judge in West Virginia ruled a local ordinance unconstitutional and unenforceable. Texas and Colorado do not allow local or municipal bans, but several local governments in these states have passed moratoria on the shale gas development process. On the map, the New Jersey and Maryland numbers indicate the number of years the moratoria are set to run, beginning in January 2012 and June 2011, respectively. New Jersey’s ban is set to expire in December 2012 and Maryland’s in June 2014. In 2012, North Carolina passed legislation allowing horizontal drilling in principle, but drilling will not be allowed until a regulatory framework is in place, which should occur sometime in the next two years.
  
  Last updated September 24, 2012
  http://www.rff.org/PublishingImages/Centers/CEEP/Shale_Maps/Other/bans_and_moratoria.png
  State and Local Bans and Moratoria
- Severance Tax Calculation Method
  Severance Tax Calculation Method
  
  This map indicates the predominant calculation method that each state uses to determine severance taxes, taxes imposed on gas production. Each state has a different rate, and states use one of two methods to calculate the tax—either a percentage of the market value of the gas extracted or a fixed dollar amount per quantity extracted. Some states use a hybrid approach in which the percentage tax varies between different levels based on the gas price.
  
  In some states, severance taxes vary based on production levels, well characteristics, or other factors. For example, in Montana, the tax rate is 0.5 percent for the first 18 months of a well’s operation and 9 percent thereafter. In Utah, if the price of gas drops below $1.51 per MCF, the tax rate drops from 5 to 3 percent. In Colorado, the tax rate varies based on the taxpayer’s gross oil and gas income. Louisiana offers discounts for “incapable” wells; Montana offers a decreased rate for “nonworking interests”; Oklahoma lowers the tax according to the price of gas at market; and Texas can lower taxes for high-cost or inactive wells.
  
  Some states, such as Maryland and Virginia, leave severance taxes to local governments, though Maryland is debating a 4.5 percent statewide tax in addition to local taxes. Virginia limits local severance taxes to 1 percent.
  
  Pennsylvania does not have a severance tax but recently passed an “impact fee” that provides funds to the communities where drilling is occurring to alleviate the cost of burdens, such as road repairs, environmental damages, and other issues caused by drilling.
  
  Last updated September 24, 2012
  
  http://www.rff.org/PublishingImages/Centers/CEEP/Shale_Maps/Other/severance_tax_calc.png
  Severance Tax Calculation Method
- Severance Tax Rates in Percentage Terms
  Severance Tax Rates in Percentage Terms
  
  This map compares state severance tax rates as a percentage of the value of gas produced. Because states use different methods to calculate their taxes, to compare rates across states, it is necessary to convert fixed dollar amount taxes into percentage terms (or vice versa; see “Severance Tax Rates in ¢/MCF”). Here tax rates were converted into percentages based on the current gas price of $2.46 per MCF. For example, if a given state had a 5¢/MCF severance tax, it would effectively tax production at 2 percent at current gas prices. Based on this conversion, the national average tax is 4.5 percent. Because the current gas price is low by historical standards, one would expect those states with percentage taxes to have relatively low taxes in dollar terms compared with other states. But this is not the case—the average tax in percentage-tax states is more than 1.5¢/MCF greater than the national average.
  
  Last updated September 24, 2012
  http://www.rff.org/PublishingImages/Centers/CEEP/Shale_Maps/Other/severance_tax_perc.png
  Severance Taxes
- Severance Tax Rates in ¢/MCF
  Severance Tax Rates in ¢/MCF
  
  This map compares state severance tax rates in cents/MCF. Because states use different methods to calculate their taxes, to compare rates across states, it is necessary to convert percentage-based taxes into fixed dollar amounts (or vice versa; see “Severance Tax Rates in Percentage Terms ”). Here tax rates for states with percentage-based severance taxes were converted into ¢/MCF based on the current gas price of $2.46 per MCF. For example, if a given state had a 1 percent severance tax, its tax in dollar terms would be 2.46¢/MCF. Based on this conversion, the national average tax is about 11¢/MCF. Because the current gas price is low by historical standards, one would expect the states with fixed-dollar taxes to have relatively high taxes in percentage terms compared with other states. But this is not the case—the average tax in fixed-dollar-tax states is more than 2 percentage points lower than the national average.
  
  Last updated September 24, 2012
  http://www.rff.org/PublishingImages/Centers/CEEP/Shale_Maps/Other/severance_tax_MCF.png
  Severance Tax Rates in ¢/MCF