Permian Basin Information

All information herein is credited to the Texas Railroad Commission.

Map of active permits and wells currently carried on the oil proration schedule and gas proration schedule database in the Permian Basin. Click on map to view higher resolution image.

Texas Counties in the Permian Basin
Texas Counties in the Permian Basin. Click on map to view higher resolution image.


Updated: March 27, 2013

General Information | Statistics | Counties Affected | Tell Us What You Think Jurisdiction Information | Water Issues | FAQs

What is the Permian Basin?

The Permian Basin is an oil-and-gas-producing area located in West Texas and the adjoining area of southeastern New Mexico. The Permian Basin covers an area approximately 250 miles wide and 300 miles long. Various producing formations such as the Yates, San Andres, Clear Fork, Spraberry, Wolfcamp, Yeso, Bone Spring, Avalon, Canyon, Morrow, Devonian, and Ellenberger are all part of the Permian Basin, with oil and natural gas production ranging from depths from a few hundred feet to five miles below the surface. The Permian Basin remains a significant oil-producing area, producing more than 270 million barrels of oil in 2010 and more than 280 million barrels in 2011. The Permian Basin has produced over 29 billion barrels of oil and 75 trillion cubic feet of gas and it is estimated by industry experts to contain recoverable oil and natural gas resources exceeding what has been produced over the last 90 years. Recent increased use of enhanced-recovery practices in the Permian Basin has produced a substantial impact on U.S. oil production.

The Permian Basin is composed of more than 7,000 Railroad Commission (RRC) fields, and is best represented in RRC production figures as RRC districts 7C, 08, and 8A, covering 59 counties in West Texas (see list below). However, the majority of the current development in the Permian Basin may be attributed to certain specific fields. Please see the graphs in the section below for rankings and production/well counts for the top largest fields in the Permian Basin.


New Drilling Permits Issued (excluding amendments and recompletions):
Year Drilling Permits Issued
2005 4,435
2006 4,737
2007 4,703
2008 6,178
2009 3,323
2010 6,830
2011 9,235
2012 9,335

(Permit data obtained from RRC W-1 query on 03/27/2013.)

Please see graph below for additional information

Historical drilling permits

Crude Oil Production:
Year Oil Produced (million barrels)
2005 253
2006 252
2007 251
2008 260
2009 260
2010 270
2011 295
2012 312

(Production data obtained from RRC Production Data Query on 03/27/2013.)

Please see graph below for additional information

Top Permian Basin Operators
Total production by year
Oil production by year
Casinghead gas production by year
Condensate production by year
Gas well gas production by year

(Data for each graph obtained from RRC Production Data Query on 03/27/2013.)

Top Permian Basin Fields:
Top 10 highest producing fields (part 1 of 2) 
Top 10 highest producing fields (part 2 of 2)
Top 50 highest injection/disposal well counts
Top 50 highest oil well counts
Top 50 highest producing fields (cumulative historical total)
Top 50 highest producing fields (1993–2012)

(Well count and historical field data obtained from RRC proration schedule on 03/01/2013. Field production data obtained from RRC Production Data Query on 03/27/2013.)

Total cumulative oil production (1921 to present):
28,478,229,290 (approximately 29 billion barrels)

For calendar year 2012 (the most recent total production year available),the Texas Permian Basin’crude oil production accounts for 57 percent of Texas’ statewide total crude oil production or approximately 430 million barrels. For all Texas liquid production including crude oil and condensate (condensate is the liquid hydrocarbons produced with natural gas including butane, propane, etc.), the Permian Basin represents 51 percent of the total statewide Texas liquid production or approximately 509 million barrels of crude oil plus condensate), per current Commission production reports.  The Permian Basin accounts for 14 percent of the total annual U.S. oil production  or approximately 2 billion barrels according to data obtained from the U.S. Energy Information Administration .  Statewide, Texas’ annual crude oil production represents about 25 percent of the total U.S. oil production.

Wells carried on the RRC proration schedule:
Currently 133,000 total wells are carried on the proration schedule in the Permian Basin, 22,000 of which are listed as active injection/disposal wells and 82,000 of which are listed as active producing wells.  The RRC proration schedule is a list of oil and gas wells on schedule to produce and submit monthly production reports to the Commission.

Permian Basin Rig Count (data obtained from Baker Hughes Rig Count webpage):
Year Rig Count
2005 129
2006 158
2007 191
2008 218
2009 103
2010 237
2011 355
2012 415

(Data obtained from Baker Hughes Rig Count on 03/27/2013.)

In 2010 there were approximately 47,000 Oil & Gas related employees associated with activities in the Permian Basin according to data obtained from theTexas Workforce Commission.

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Permian Basin Counties


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What does the Railroad Commission have jurisdiction over and whom to contact?
The Railroad Commission regulates the exploration and production of oil and natural gas in Texas.  The Commission’s primary responsibilities include: preventing waste of oil and gas resources; protection of surface and subsurface water; and, ensuring all mineral interest owners have an opportunity to develop their fair share of the minerals underlying their property.
The RRC has provided an information page containing links to city, county, state, and federal governments within the Permian Basin area.
For further information, please contact our district offices.

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What does the Railroad Commission NOT have jurisdiction over and whom to contact?
The Railroad Commission does not have jurisdiction over roads, traffic, noise, odors, leases, pipeline easements, or royalty payments.
Roads and Traffic:  The Railroad Commission does not have jurisdiction over, and exercises no regulatory authority with respect to, private or public roads or road use.  Permits issued by the Commission for oil and gas exploration, production, and waste disposal do not limit any independent authority of a municipality, county or other state agencies with respect to road use.
The Texas Department of Transportation (TXDOT) oversees the construction and maintenance of state highways within their jurisdiction. In addition, TXDOT is responsible for issuing access permits to well sites from a roadway on the state highway system. Please review letter for specific access permit requirements. To contact the appropriate district office, please visit the Texas Department of Transportation, Local Information web site. For county or city contact information, please visit the Texas Association of Counties.
Noise:  The Commission has no statutory authority over noise or nuisance related issues. Noise and nuisance related issues are governed by local ordinances.
Odors and Air Contaminants: The Railroad Commission does not have regulatory authority over odors or air contaminants. However, for a well within the city limits, the city may enact ordinances regarding odors or other nuisances. In addition, the Texas Commission on Environmental Quality (TCEQ) has jurisdiction over odor and air contaminants. Please see
Oil and Gas Exploration and Surface Ownership: For general information pertaining to exploration and surface ownership, please visit the Oil and Gas Exploration and Surface Ownership web page.
Royalty payments:   For general information pertaining to leases and royalties, please visit the General Information Pertaining to Leases and Royalties web page.

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Top Questions Asked about the Permian Basin

Please click on the question to reveal the answer.

1. What is the minimum drilling distance for well locations and buildings and homes? How close to my house can a well be drilled?
The Railroad Commission does not regulate how close a gas or oil well can be drilled to a residential property. However, for a well within city limits, a city may enact ordinances regarding the proximity to dwellings or other structures. In addition, there is a law in the Municipal Code, Section 253.005(c), which provides: “A well may not be drilled in the thickly settled part of the municipality or within 200 feet of a private residence.” This rule may be accessed directly at Rule, 16 Texas Administrative Code (TAC) §3.76 provides that in counties with a population of more than 400,000 or a population of more than 140,000 adjacent to a county with a population of more than 400,000, a developer of the property may obtain Commission approval of a subdivision plan that limits drilling activity to designated drill sites of at least two acres for every 80 acres in the subdivision. This rule may be accessed directly at$ext.TacPage?sl=R&app=9&p_dir=&p_rloc=&p_tloc=&p_ploc=&pg=1&p_tac=&ti=16&pt=1&ch=3&rl=76Many mineral leases (which are private business contracts between an operator and a mineral owner) may also include clauses that define how close a well can be drilled to existing structures.
2. Explain why a surface location for horizontal wells is not required to be located on the same lease designated on the drilling permit?
Many wells are being drilled horizontally or their wellbores deviate from a surface location outside the lease to reach potential producing horizons that may be beneath city parks, water bodies or housing developments, where a surface location may not be desirable or available. It is not unusual for an operator to obtain surface rights from which to drill a well from an adjacent, more desirable location.
3. Explain why a surface location for a horizontal well can be located on a lease closer to a lease line than the field rules require?
The field rules for a horizontal well regulate specifically the “horizontal drainhole” which is defined in Rule 86 as “That portion of the wellbore drilled in the correlative interval, between the penetration point and the terminus.” The surface location, therefore, can be located anywhere on the lease since the surface location is not part of the horizontal drainhole.
4. What are the plastic lining requirements for drilling pits and water pits for hydraulic fracturing?
Railroad Commission rules require an operator to take precautions to prevent pollution of surface and subsurface water, but RRC rules do not include specific requirements for plastic liners in drilling pits and water pits for hydraulic fracturing. Many operators use liners in areas where the soil is permeable. Local governments also may require the use of lined pits.
5. What is the requirement for reporting production for a well after it has been completed, and how do I find out what has been reported?
Railroad Commission rules require an operator to file a well completion form with the Commission 30 days after completion of the well or 90 days after completion of the drilling operation, whichever is earliest. (16 TAC §3.16) Production must be filed monthly starting the month after the well begins producing. You can find production information on the RRC website by using the Production Data Query application or theProduction Permit Query application.
6. How long does the RRC allow an operator to flare gas from a new oil well completion until the gas is then connected to the pipeline?
Railroad Commission regulations generally allow gas (casinghead gas) to be released from an oil well for a period not to exceed ten (10) producing days after initial completion, recompletion, in another field, or workover operations in the same field. However, the Commission may grant exceptions to this rule under certain circumstances. See 16 TAC §3.32
7. What is the typical size, shape and restoration of a drilling location in the Permian Basin?
There are no standard location shapes or sizes; each rig has its own individual “footprint.” Texas law allows an operator the right to use as much of the surface as necessary to explore, drill and produce the minerals from a property. Mineral leases or local ordinances may limit the amount of surface that an operator may use and dictate restoration of the site.
8. What can be done about the stormwater runoff?
The Commission’s regulations ensure the quality of waters (and land) that could be potentially impacted by an oil and gas operator’s activity. The Commission’s current rules defines “pollution of surface or subsurface water” broadly: “The alteration of the physical, thermal, chemical, or biological quality of, or the contamination of, any surface or subsurface water in the state that renders the water harmful, detrimental, or injurious to humans, animal life, vegetation, or property, or to public health, safety, or welfare, or impairs the usefulness or the public enjoyment of the water for any lawful or reasonable purpose.”Please see 16 TAC §3.8.
9. What is law regarding ingress and egress using existing roads?
An operator has the right of ingress and egress to the property for the purpose of exploring, drilling and producing minerals. This right cannot be denied. However, it does not require surface owners to allow operators to use existing roads. Should disagreements occur, it is a civil issue that must be pursued by a surface owner and operators through the court system.
10. How will all this activity affect our property values?
The Commission does not have any regulatory authority over the impact on property value from drilling unless a violation of Commission rules related to the prevention of pollution of usable quality water occurs. However, you should not construe that to mean you do not have legal rights with respect to the quiet enjoyment of your home. You may wish to consult with an attorney in your area to fully understand your rights and remedies available to you.
11. When will they close the pit?
Railroad Commission regulations require that the operator empty and close a drilling pit within one year of cessation of drilling activities. The rules require the operator to empty a completion/workover pit within 30 days and to close the pit within 120 days completion/workover operations.
12. What are saltwater disposal wells?
To learn more about saltwater disposal wells, please read our FAQ’s concerning these types of wells.
13. Whom do I contact to file a complaint?
Please contact the appropriate RRC District Office. To locate the District office nearest to you, please see the following table cross referencing counties by district. Contact information for each district office can be found here:
14. What is the process a drilling company must go through to receive a drilling permit from the RRC?
To obtain a drilling permit from the RRC, an operator must have on file an active P-5 in accordance with Statewide Rule 1 (16 TAC §3.1) (SWR 1-Organization Report; Retention of Records; Notice Requirements), which identifies the operator and its officers. (Note: all RRC Rules are available on the Commission’s web page at the following link:$ext.ViewTAC?tac_view=4&ti=16&pt=1&ch=3&rl=Y The operator also must have the proper amount of financial assurance on file as required under Statewide Rule 78 (16 TAC §3.78), Fees and Financial Security Requirements.The operator must submit a site-specific Form W-1 (application to drill) with a plat to scale showing the requirements listed in Statewide Rule 5 (16 TAC §3.5) Application To Drill, Deepen, Reenter, or Plug Back.They must submit a Form P-12 (certificate of pooling authority), a plat identifying offset operators, a service list for notice, and any waivers where applicable.Permit Application Fees must be paid based on depth, exceptions and whether or not processing a permit application is expedited. These fees are in addition to Financial Security Requirements.
15. Do they have to show there is likely to be oil or gas in that area?
No, however, operators are required to have a legal mineral lease with the mineral owner, which gives them the right to extract the minerals, if any, under the surface land. In addition, they also may drill exploratory, test or service wells. Each type of well requires an RRC drilling permit.
16. Is an oil or gas operator required to perform an environmental study or something similar?
No, however, operators are required to follow all RRC regulations, which are designed to ensure protection of the public and the environment. As part of this requirement, they must obtain and file a “Water Board Letter” from the Groundwater Advisory Unit in the Oil & Gas Division that identifies the depth to which fresh water must be protected so the well can be designed to ensure protection of subsurface freshwater.
17. What factors are considered in reviewing a drilling permit application, and who specifically approves this application (district office supervisor? commissioners?)
Prior to permit approval, a check of all required data is conducted including, but not limited to, the following:
Survey name and distances from lease lines and between wells.Lease name, well number and operator nameDistances to nearest well, acreage and lease distances (relating to the field rules)Check for exceptions to rules 16 TAC §3.37 (Statewide Spacing Rule), §3.38 (Well Densities), §3.39 (Proration and Drilling Units: Contiguity of Acreage and Exception Thereto), §3.40 (Assignment of Acreage to Pooled Development and Proration Units).When exceptions to these above rules are requested, the RRC verifies that the correct documentation is attached.RRC staff checks to make sure all information on the plat matches the information above.RRC staff in the Drilling Permits Unit administratively approves or denies most regular permits and some exception to rules permits. However, protested permits regarding 16 TAC §3.37, most §3.38 permits, all §3.39 and §3.40 exception permits are set for hearing and will require Commissioner approval or disapproval..
18. How often are wells inspected?
Wells are not inspected on a set schedule. The frequency of a routine well/lease inspection is based on many factors including the type of well/operation, the location of the well in regard to public areas or sensitive environments, and the operator’s compliance record. The RRC prioritizes the inspections it performs with the highest priority being blowouts and emergency incidents, spills, surface casing cementing jobs, operator pluggings, mechanical integrity tests, and the H-15 program. Other actions that may trigger an inspection include a third-party complaint, notice to the Commission of a reportable incident (spill, fire, blowout), or notice of a specific job such as a casing job, plugging job, or mechanical integrity-test. During Fiscal Year 2011 (Sept. 1 through Aug. 31), the Commission oil and gas inspectors performed 114,878 inspections statewide.
19. What types of things do inspectors look for?
This depends on the type of well/operation. In general, the inspector will confirm compliance with all applicable RRC statewide rules with emphasis on rules related to public safety and protection of the environment. For example, an inspection of a lease might include an inspector noting whether proper signs are posted at the lease; is gas being flared illegally; or are there any spills or leaks from equipment or pits.
20. Can the RRC assist with mineral lease agreements?
No, with respect to entry into lease agreements and actions of individuals, please be advised that the Railroad Commission’s jurisdiction is limited to issues concerning the permitting and production from oil and gas wells in the State of Texas. The Commission has no jurisdiction over property interests or contractual rights, including issues regarding the validity of existing oil, gas and mineral leases and the conduct of individuals attempting to obtain leases. If you have a question concerning the validity of an existing lease or the actions taken by individuals in an attempt to secure the rights to develop the minerals within a particular area, you may wish to consult an attorney with expertise in oil and gas law.The Commission does maintain records on the reported production and disposition of all oil and gas produced from wells in the State. This information may be helpful in determining your interests and any development in the area surrounding your property. Additionally, the Commission also maintains records regarding the permitting of wells. These records include plats and other documents designating the acreage in a pooled unit. These records are required to obtain a drilling permit and to produce from a well after the well is completed.If you have the RRC Identification Number for a well (either a five digit number for oil wells or a six digit number for gas wells) you can obtain all reported production information from January 1993 to present and can obtain access to the permitting records at the Commission’s website For production information, please use the Commission’s Production Data Query application to get access to the on-line database for these records. For drilling permit information, please use the Commission’s Drilling Permit application to get access to the on-line database for these records.
21. I have heard about radiation issues associated with oil and gas activities. What are the issues and risks?
Subsurface formations may contain low levels of naturally-occurring radioactive materials such as uranium and thorium and their daughter products, radium 226 and radium 228. These materials, called Naturally Occurring Radioactive Materials or NORM, can be brought to the surface in the formation water that is produced with oil and gas operations. NORM in these produced waters typically consists of the radionuclides, radium 226 and 228. In addition, radon gas, a radium daughter may be found in produced natural gas. Because the levels typically are so low, the NORM in produced waters and natural gas is not a problem in Texas unless it becomes concentrated in some manner. Through temperature and pressure changes that occur in the course of oil and gas production operations, radium 226 and 228 found in produced waters may be deposited as scale in well tubulars and surface equipment. Concentrations of radium 226 and 228 may also occur in sludge that accumulates in oilfield pits and tanks. These solids become sources of oil and gas NORM waste. In gas processing activities, NORM generally occurs as radon gas in the natural gas stream. Radon decays to Lead-210, then to Bismuth-210, Polonium-210, and finally to stable Lead-206. Radon decay elements occur as a film on the inner surface of inlet lines, treating units, pumps, and valves principally associated with propylene, ethane, and propane processing streams. The highest risk of exposure to oil and gas NORM is not to the general public, but instead to workers employed to cut and ream oilfield pipe, remove solids from tanks and pits, and refurbish gas processing equipment.Regulatory programs for NORM are administered by both the Texas Department of State Health Services (DSHS) and the Railroad Commission (RRC). The DSHS regulates all activities, except disposal, involving management of NORM and NORM containing or contaminated materials. This includes jurisdiction over possession, use, transfer, transport, recycling, decontamination of equipment and facilities and/or storage of oil and gas NORM wastes, other than such activities when they occur at the site (e.g., lease, unit, or facility) where disposal of oil and gas NORM waste will occur. The DSHS’s radiological program protects the occupationally exposed as well as the public from unnecessary exposure to radiation. The DSHS regulations establish protection standards and requirements for management of NORM, other than disposal. The rules include exemption criteria for certain NORM containing or contaminated materials. Anyone managing NORM materials above the exemption levels must comply with certain standards.The RRC has jurisdiction over disposal of oil and gas NORM waste and the management of NORM waste at an oil and gas property to facilitate disposal at the site. The RRC’s rules were developed in consultation with the DSHS regarding protection of public health and the environment. The relation of exposure pathways and the health risks relative to those pathways was DSHS’s basis for adopting the regulatory exemption levels. Likewise, the adoption of oil and gas NORM waste disposal options is a result of evaluation of the risk relative to each disposal method.Each agency is responsible for enforcing its own rules; however agencies do communicate with each other on particular sites or issues as necessary and participate (along with the Texas Commission on Environmental Quality) in quarterly Texas Radiation Advisory Board (TRAB) meetings.For background on oil and gas NORM review the following link on our website:
22. What is Hydrogen sulfide (H2S) gas?
Hydrogen sulfide (H2S) is a potentially very deadly gas that can kill within minutes depending on its concentration levels. Hydrogen sulfide gas is encountered in many oil and gas producing formations in the state of Texas and, therefore, can be present at drilling locations, producing wells, tank batteries, production facilities, gas plants, sweetening plants, pipelines, etc. Rules and guidelines for these facilities can be found at For more information regarding H2S, please click on the following link.
23. Is H2S present in any of the Permian Basin fields?
Currently, approximately 2,000 out of the 7,000+ fields have been identified with H2S. A listing can be found at Applicable safety information can be found at

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