TITLE 165: CORPORATION COMMISSION

CHAPTER 10: OIL AND GAS CONSERVATION

Effective August 27, 2015

Last Amended

The Oklahoma Register

Volume 32, Number 23

August 17, 2015 publication

Pages 719 - 1510

This is not the official version of the Oklahoma Administrative code, 

however, the text of these rules is the same as the text on file in the 

Office of Administrative Rules. Official rules are available from the 

Office of Administrative Rules of the Oklahoma Secretary of State. 

This copy is provided as convenience for our customers.
[Blank Page] 
OAC 165:10 Corporation Commission

Eff. 8-27-15

- 1 -

CHAPTER 10. OIL AND GAS CONSERVATION

Subchapter Section

1. Administration . . . . . . . . . . . . . . . . . . . . . . . 165:10-1-1

3. Drilling, Developing, and Producing . . . . . . . . . . . . 165:10-3-1

5. Underground Injection Control . . . . . . . . . . . . . . . 165:10-5-1

7. Pollution Abatement . . . . . . . . . . . . . . . . . . . . 165:10-7-1

8. Commercial Recycling . . . . . . . . . . . . . . . . . . . . 165:10-8-1

9. Commercial Disposal Facilities . . . . . . . . . . . . . . . 165:10-9-1

10. Brownfields Program . . . . . . . . . . . . . . . . . . . . .165:10-10-1

11. Plugging and Abandonment . . . . . . . . . . . . . . . . . . 165:10-11-1

12. Procedures for the Seeping Natural Gas Program . . . . . . . 165:10-12-1

13. Determination of Allowables - Oil and Gas Wells . . . . . . 165:10-13-1

15. Oil Well Production and Allowables . . . . . . . . . . . . . 165:10-15-1

17. Gas Well Operations and Permitted Production . . . . . . . . 165:10-17-1

19. Natural Gas Policy Act Determination [REVOKED] 

21. Applications for Tax Exemptions. . . . . . . . . . . . . . . 165:10-21-1

23. Ratable Sharing of Revenue [REVOKED] 

24. Market Sharing . . . . . . . . . . . . . . . . . . . . . . . 165:10-24-1

25. Escrowed Accounts for Pooled Monies . . . . . . . . . . . . 165:10-25-1

27. Production Revenue Standards . . . . . . . . . . . . . . . . 165:10-27-1

29. Special Area Rules . . . . . . . . . . . . . . . . . . . . . 165:10-29-1

Appendix A. Allocated Well Allowable Table

Appendix B. Discovery Well Allowable Table

Appendix C. Table HD

Appendix D. List of NGPA Forms [REVOKED]

Appendix E. Schedule A Fines

Appendix F. Schedule B Fines

Appendix G. Implementation Fees (One-Time)

Appendix H. Calculations

Appendix I. Soil Loading Formulas

Appendix J. Dewatering Oil Allowable Table

[Authority: 52 O. S. §§ 86.2 through 320, 528 through 614]

[Source: Codified 12-31-91]
OAC 165:10 Corporation Commission

Eff. 8-27-15

- 2 -

[BLANK PAGE]
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 3 -

SUBCHAPTER 1. ADMINISTRATION 

PART 1. GENERAL PROVISIONS 

Section

165:10-1-1. Purpose 

165:10-1-2. Definitions 

165:10-1-3. Scope of rules 

165:10-1-4. Citation effective date 

165:10-1-5. Conservation Division [RESERVED] 

165:10-1-6. Duties and authority of the Conservation Division 

165:10-1-7. Prescribed forms 

PART 3. SURETY 

165:10-1-10. Operator's agreement; Category A and Category B surety 

165:10-1-11. Financial statement as surety 

165:10-1-12. Corporate surety bond 

165:10-1-13. Irrevocable commercial letter of credit 

165:10-1-14. Cashier's check, certificate of deposit, or other negotiable

 instrument 

165:10-1-15. Transfer of operatorship of wells 

165:10-1-16. Change of address 

PART 5. SPACING 

165:10-1-20. Spacing [RESERVED] 

165:10-1-21. General well spacing requirements 

165:10-1-22. Drilling and spacing units 

165:10-1-23. Extension of pool rules 

165:10-1-24. Permitted well locations within standard drilling and spacing

 units 

165:10-1-25. Replacement well 

165:10-1-26. Permitted producing well location within an enhanced recovery

 project 

165:10-1-27. Increased density well 

165:10-1-28. Geologic correlation chart 

PART 7. MARKET DEMAND 

165:10-1-35. Market demand [RESERVED] 

165:10-1-36. Regulation, classification, and naming of pools 

165:10-1-37. Determination of market demand 

PART 9. PURCHASERS AND TRANSPORTERS 

165:10-1-45. Purchasers and transporters [RESERVED] 

165:10-1-46. Reports of purchasers and/or transporters 

165:10-1-47. Gas volume reports to Conservation Division 

165:10-1-48. Common purchaser and carrier rules 

165:10-1-49. Filing of nominations

PART 1. GENERAL PROVISIONS 

165:10-1-1. Purpose

The rules of this Chapter were promulgated in furtherance of the public 

policy and statutory laws of the State of Oklahoma to prevent the waste of oil 

and gas, to assure the greatest ultimate recovery from the State's reservoirs, 

to protect the correlative rights of all interest owners, and to prevent 

pollution.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 4 -

165:10-1-2. Definitions

The following words and terms, when used in this Chapter, shall have the 

following meaning unless the context clearly indicates otherwise:

"Agent" means any person authorized by another person to act for him.

"Aquifer" means a geological formation, group of formations, or part of a 

formation that is capable of yielding a significant amount of water to a well 

or spring.

"Area of exposure" means an area within a circle constructed with the point 

of escape of poisonous gas (hydrogen sulfide) as its center and the radius of 

exposure as its radius.

"Associated gas" means any gas produced from a Commission ordered 

combination oil and gas reservoir in which allowed rates of production are 

based upon volumetric withdrawals.

"BS&W" means basic sediment and water which is that portion of fluids 

and/or solids that settle in the bottom of storage tanks and/or treating 

vessels and is unsaleable to the first purchaser in its present form. BS&W 

usually consists of water, paraffin, sand, scale, rust, and other sediments.

"Barrel" means 42 (U.S.) gallons at 60 F at atmospheric pressure.

"Basic sediment pit" means a pit used in conjunction with a tank battery 

for storage of basic sediment removed from a production vessel or from the 

bottom of an oil storage tank.

"Blowout" means the uncontrolled escape of oil or gas, or both, from any 

formation.

"Blowout preventer" means a heavy casinghead control fitted with special 

gates and/or rams which can be closed around the drill pipe or which 

completely closes the top of the casing.

"Blowout preventer stack" means the assembly of well control equipment 

including preventers, spools, valves, and nipples connected to the top of the 

casinghead.

"Business day" means a day that is not a Saturday, Sunday, or legal 

holiday.

"Carrier", or "transporter", or "taker" means any person moving or 

transporting oil or gas away from a lease or from any common source of supply.

"Casing pressure" means the pressure within the casing or between the 

casing and tubing at the wellhead.

"Choke manifold" means an assembly of valves, chokes, gauges, and lines 

used to control the rate of flow from the well when the blowout preventers are 

closed.

"Closure" means the practice of dewatering, trenching, filling, leveling, 

terracing, and/or vegetating a pit site after its useful life is reached in 

order to restore or reclaim the site to near its original condition.

"Commercial disposal well" means a well where the operator receives and 

disposes of produced water or any deleterious substance from multiple well 

owners/operators and receives compensation for these services and where the 

operator's primary business objective is to provide these services. 

"Commercial pit" is a disposal facility which is authorized by Commission 

order and used for the disposal, storage, and handling substances or soils 

contaminated by deleterious substances produced, obtained, or used in 

connection with drilling and/or production operations. This does not include 

a disposal well pit.

"Commercial recycling facility" means a facility that is authorized by 

Commission order to recycle materials defined as deleterious substances in OAC 

165:10-1-2. Such substances must undergo at least one treatment process and 

must be recycled into a marketable product for resale and/or have some 

beneficial use. This definition does not include the reuse of drilling mud 

that was previously utilized in drilling or plugging operations.

"Commercial soil farming" means the practice of soil farming or land 

applying drilling fluids and/or other deleterious substances produced, 

obtained, or used in connection with the drilling of a well or wells at an 

off-site location. Multiple applications to the same land are likely.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 5 -

"Commission" means the Corporation Commission of the State of Oklahoma.

"Common source of supply" or "pool" means "that area which is underlaid or 

which, from geological or other scientific data, or from drilling operations, 

or other evidence, appears to be underlaid by a common accumulation of oil 

and/or gas; provided that, if any such area is underlaid, or appears from 

geological or other scientific data or from drilling operations, or other 

evidence, to be underlaid by more than one common accumulation of oil or gas 

or both, separated from each other by strata of earth and not connected with 

each other, then such area shall, as to each said common accumulation of oil 

or gas or both, shall be deemed a separate common source of supply." [52. 

O.S.A. §86.1(c)].

"Completion/fracture/workover pit" means a pit used for temporary storage 

of spent completion fluids, frac fluids, workover fluids, drilling fluids, 

silt, debris, water, brine, oil scum, paraffin, or other deleterious 

substances which have been cleaned out of the wellbore of a well being 

completed, fractured, recompleted, or worked over.

"Condensate" means a liquid hydrocarbon which:

(A) Was produced as a liquid at the surface,

(B) Existed as gas in the reservoir, and

(C) Has an API gravity greater than or equal to fifty degrees, unless 

otherwise proven.

"Conductor casing" means a casing string which is often set and cemented at 

a shallow depth to support and protect the top of the borehole from erosion 

while circulating and drilling the surface casing hole.

"Conservation Division" means the Division of the Commission charged with 

the administration and enforcement of the rules of this Chapter.

"Contingency plan" is a written document which provides for an organized 

plan of action for alerting and protecting the public within an area of 

exposure following the accidental release of a potentially hazardous volume of 

poisonous gas such as hydrogen sulfide.

"Contractor" means any person who contracts with another person for the 

performance of prescribed work.

"Cubic foot of gas" means the volume of gas contained in one cubic foot of 

space at an absolute pressure of 14.65 pounds per square inch and at a 

temperature of 60F. Conversion of volumes to conform to standard conditions 

shall be made in accordance with Ideal Gas Laws corrected for deviation from 

Boyle's Law when the pressure at point of measurement is in excess of 200 

pounds per square inch gauge.

"Date of completion" means:

(A) For an oil well, the date that the well first produces oil into the 

lease tanks through permanent wellhead equipment.

(B) For a gas well, the date of completion of a gas well is the date 

that gas is capable of being delivered to a pipeline purchaser.

(C) For a well, which does not produce either oil or gas, is the date 

on which attempts to obtain production from the well cease.

"Day" means a period of 24 consecutive hours. For reporting purposes, it 

shall be from 7:00 a.m. to 7:00 a.m. the following day.

"Deleterious substances" means any chemical, salt water, oil field brine, 

waste oil, waste emulsified oil, basic sediment, mud, or injurious substance

produced or used in the drilling, development, production, transportation, 

refining, and processing of oil, gas and/or brine mining.

"Design mud weight" means the planned drilling mud weight to be used. This 

mud weight is used in the design of the casing strings.

"Design wellhead pressure" means the maximum anticipated wellhead pressure 

which is expected to be experienced on the inside of the casing string and on 

wellhead equipment. This pressure is used to design the casing string and to 

select wellhead equipment with sufficient working pressure rating.

"Development" means any work which actively looks toward bringing in 

production, such as erecting rigs, building tankage, drilling wells, etc.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 6 -

"Directional drilling" means intentional changing of the direction of the 

well from the vertical.

"Director of Conservation" means the person in official charge of the 

Conservation Division.

"Discharge" means the release or setting free by any spilling, leaking, 

pumping, pouring, emitting, emptying, or dumping of substances.

"Distressed well" means a well authorized by Commission order to produce at 

an unrestricted rate in the interest of public safety due to technical 

difficulties which temporarily cannot be controlled.

"Diverter" means a device attached to the wellhead to close the vertical 

access and direct any flow into a line away from the rig. Diverters differ 

from blowout preventers in that flow is not stopped but rather the flow path 

is redirected away from the rig.

"Duly authorized representative" means, for the purpose of underground 

injection well applications, that person or position having a responsibility 

for the underground injection well. 

"Emergency pit" means a pit used for the storage of excessive or 

unanticipated amounts of fluids during an immediate emergency situation in the 

drilling or operation of a well, such as a well blowout or a pipeline rupture. 

This does not include a spill prevention structure required by local, state, 

or federal regulations.

"Enhanced recovery operation" means the introduction of fluid or energy

into a common source of supply for the purpose of increasing the recovery of 

oil therefrom according to a plan which has been approved by the Commission 

after notice and hearing. 

"Enhanced recovery well" means a well producing in an enhanced recovery 

operation in accordance with Commission order.

"Exchangeable Sodium Percentage (ESP)" is the relative amount of the sodium 

ion present on the soil surface, expressed as a percentage of the total Cation 

Exchange Capacity (CEC). Since the determination of CEC is time consuming and 

expensive, a practical and satisfactory correlation between the Sodium 

Adsorption Ratio (SAR) and ESP was established. The SAR is defined elsewhere 

in this Section. ESP can be estimated by the following empirical formula:

ESP =

100 (-0.0126 + 0.01475 x SAR)

 1 + (-0.0126 + 0.01475 x SAR)

"Exempted aquifer" means an aquifer or its portion that meets the criteria 

in the definition of "underground source of drinking water" or in the 

definition of "treatable water", but which has been exempted according to the 

procedures in 165:5-7-28 and 165:10-5-14.

"Facility" means, for the purposes of 165:10-21-15, any building(s), parts 

of a building, equipment, property, or vehicles that are actively engaged 

in the 

reuse, recycling, or ultimate destruction of deleterious substances pursuant 

to 68 O.S. Supp. 1986, §2357.14-§2357.20.

"Field" means the general area underlaid by one or more common sources of 

supply.

"Flare pit" means a pit which contains flare equipment and which is used 

for temporary storage of liquid hydrocarbons which are sent to the flare but 

are not burned due to equipment malfunction. Flare pits may be used in 

conjunction with tank batteries or wells.

"Flowing well" means any well from which oil or gas is produced naturally 

and without artificial lifting equipment.

"Fresh water strata" means a strata from which fresh water may be produced 

in economical quantities.

"Gas" means any petroleum hydrocarbon existing in the gaseous phase.

(A) Casinghead gas means any gas or vapor, or both, indigenous to an 

oil stratum and produced from such stratum with oil.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 7 -

(B) Dry gas or dry natural gas means any gas produced in which there 

are no appreciable hydrocarbon liquids recoverable by separation at the 

wellhead.

(C) Condensate gas means any gas which is produced with condensate as 

defined as "condensate".

"Gas allowable" or "allowable gas" means the amount of natural gas 

authorized to be produced from any well by order of the Commission or as 

provided by statute.

"Gas lift" means any method of lifting liquid to the surface by injecting 

gas into the well bore from which production is obtained.

"Gas repressuring" means the injection of gas into a common source of 

supply to restore or increase the gas energy of a reservoir.

"GOR (Gas/Oil Ratio)" means the ratio of the gas produced in standard cubic 

feet to one barrel of oil produced during any stated period. Condensate and 

load oil excepted under 165:10-13-6 shall not be considered as oil for 

purposes of determining GOR.

"Hardship well" means a well authorized by Commission order to produce at a 

specified rate because reasonable cause exists to expect that production below 

said rate would damage the well and cause waste.

"Hydraulic fracturing operations" means operations on a well wherein fluid 

is applied for the express purpose of initiating or propagating fractures in a 

target geologic formation.

"Hydrogen sulfide gas (H2S)" means a toxic poisonous gas with a chemical 

composition of H2S which is sometimes found mixed with and produced with 

fluids from oil and gas wells.

"Hydrologically sensitive area" means a principal bedrock aquifer, the 

recharge or potential recharge area of a principal bedrock aquifer, or an 

unconsolidated alluvium or terrace deposit, according to the Oklahoma 

Geological Survey "Maps Showing Principal Groundwater Resources and Recharge 

Areas in Oklahoma" or other maps approved by the Commission.

"Hydrostatic head" or "hydrostatic pressure" means the pressure which 

exists at any point in the wellbore due to the weight of the column of fluid 

or gas above that point.

"Illegal gas" means gas which has been produced within the State from any 

well or wells in violation of any rule, regulation, or order of the 

Commission, as distinguished from gas produced within the State not in 

violation of any such rule, regulation, or order which is "legal gas".

"Illegal oil" means oil which has been produced within the State from any 

well or wells in violation of any rule, regulation or order of the Commission, 

as distinguished from oil produced within the State not in violation of any 

such rule, regulation, or order which is "legal oil".

"Intermediate casing" means the casing string or strings run after setting 

the surface casing and prior to setting the production string or liner.

"Kick" means the intrusion of formation liquids or gas that results in an 

increase in circulation pit volume. Without corrective measures, this 

condition can result in a blowout.

"Land application" is the application of deleterious substances and/or 

soils contaminated by deleterious substances to the land for the purpose of 

disposal or land treatment; also known as soil farming.

"Lease allowable" means the total of the allowables of the individual wells 

on the lease.

"Liner" means a length of casing used downhole as an extension to a 

previously installed casing string to case the hole for further drilling 

operations and/or for producing operations.

"Meter" means an instrument for measuring and indicating or recording the 

volumes of gases or liquids.

"Mud" means any mixture of water and clay or other material as the term is 

commonly used in the industry.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 8 -

"Multi-well system" means two or more wells that have intersecting wellbores or laterals.

"Multiple zone completion" means the completion of any well so as to permit 

the production from more than one common source of supply, with such common 

sources of supply completely segregated.

"Noncommercial pit" means an earthen pit which is located either on-site or 

off-site and is used for the handling, storage, or disposal of deleterious 

substances or soils contaminated by deleterious substances produced, obtained, 

or used in connection with the drilling and/or operation of a well or wells, 

and is operated by the generator of the waste. This does not include a 

disposal well pit.

"Normal pressure" means a formation pore pressure, proportional to depth, 

which is roughly equal to the hydrostatic pressure gradient of a column of 

salt water (.465 psi/ft).

"Off-site reserve pit" means a pit located off-site which is used for the 

handling, storage, or disposal of drilling fluids and/or cuttings.

"Oil" or "crude oil", means, for purposes of these regulations, any 

petroleum hydrocarbon, except condensate, produced from a well in liquid form 

by ordinary production methods.

"Oil allowable" or "allowable oil" means the amount of oil authorized to be 

produced from any well by order of the Commission.

"Operator" means the person who is duly authorized and in charge of the 

development of a lease or the operation of a producing property. 

"Overage" means the oil or gas delivered to a carrier, transporter, or 

taker in excess of the allowable set by the Commission for any given period.

"Owner" means the person or persons who have the right to drill into and to 

produce from any common source of supply, and to appropriate the production 

either for himself, or for himself and others.

"Person" means any natural person, corporation, association, partnership, 

receiver, trustee, guardian, executor, administrator, fiduciary, or 

representative of any kind, and shall include the plural.

"Plug" means the closing off, in a manner prescribed by the Commission, of 

all oil, gas, and waterbearing formations in any producing or nonproducing 

wellbore before such well is abandoned.

"Pollution" means the contamination of fresh water or soil, either surface 

or subsurface, by salt water, mineral brines, waste oil, oil, gas, and/or 

other deleterious substances produced from or obtained or used in connection 

with the drilling, development, producing, refining, transporting, or 

processing of oil or gas within the State of Oklahoma.

"Pool" See "common source of supply".

"Potential" means the properly determined capacity of a well to produce oil 

or gas, or both, under conditions prescribed by the Commission.

"Primary well" means a wellbore that, as part of a multi-well system, 

serves as the conduit through which oil and gas is produced to the surface.

"Producer" See "Operator" or "Owner".

"Production casing" means the casing string set above or through the 

producing zone of a well which serves the purpose of confining and/or 

producing the well production fluids.

"Productivity index" means the daily production of oil in barrels per unit 

pressure differential between the static reservoir pressure and the stabilized 

flowing pressure during flow at a stated rate.

"Proration period" means:

(A) The proration period for any well, other than an unallocated gas 

well, shall be one calendar month which shall begin at 7 a.m. on the 

first day of such month and end at 7 a.m. on the first day of the next 

succeeding month unless otherwise specified by order of the Commission.

(B) The proration period for any unallocated gas well shall be one 

calendar year which shall begin at 7:00 a.m. the first day of such year 

and end at 7:00 a.m. on the first day of the next succeeding year unless 

otherwise specified by order of the Commission.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 9 -

"Public area" means a dwelling place, a business, church, school, hospital, 

school bus stop, government building, a public road, all or any portion of a 

park, city, town, village, or other similar area that can reasonably be 

expected to be populated by humans.

"Public street" or "road" means any federal, state, county, or municipal 

street or road owned or maintained for public access or use.

"Public water supply well(s)" or "public water well(s)" means wells in a 

system for the provision to the public of water for human consumption through 

pipes or other constructed conveyances, and which wells are identified in a 

database maintained by the Oklahoma Department of Environmental Quality.

"Purchaser" or "transporter" means any person who acting alone or jointly 

with any person or persons, via his own, affiliated or designated carrier, 

transporter, or taker, shall directly or indirectly purchase, take, or 

transport by any means whatsoever or otherwise remove from any lease, oil or 

gas, and/or other hydrocarbons produced from any common source of supply in 

this State, excepting royalty portions from leases owned by that person.

"Radius of exposure" means that radius constructed with the point of escape 

of poisonous (hydrogen sulfide) gas as its starting point and its length 

calculated by use of the Pasquill-Gifford equations.

"Reclaimed water" means wastewater from municipal wastewater treatment 

and/or public water supply treatment plants that has gone through various 

treatment processes to meet specific water quality criteria with the intent of 

being used in a beneficial manner.

"Reclaimer" or "reclamation plant" includes any person licensed by the 

Oklahoma Tax Commission pursuant to 68 O.S.§1015.1 who reclaims or salvages or 

in any way removes or extracts oil from waste products associated with the 

production, storage, or transportation of oil including, but not limited to 

BS&W, tank bottoms, pit and waste oil, and/or waste oil residue.

"Recomplete" or "recompletion" means any operation to:

(A) Convert an existing well from an injection well or disposal well, 

to a producing well, or

(B) Add or change common sources of supply in an existing well.

"Recycling" is the reuse, processing, reclaiming, treating, neutralizing, 

or refining of materials and by-products into a product of beneficial use 

which, if discarded, would be deleterious substances.

"Recycling/reuse pit" means a pit which is used for the recycling or reuse 

of deleterious substances, is located off-site, and is operated by the 

generator of the waste.

"Re-enter" or "re-entry" is the act of entering a plugged well for the 

purpose of utilizing said well for the production of oil or gas, for the 

disposal of fluids therein, for a service well, or for the salvaging of tubing 

or casing therefrom.

"Regular mail" means first class United States Mail, postage prepaid, and 

includes hand delivery. Wherever in OAC 165:10 a person is directed to mail by 

regular mail, such directive shall not preclude mailing by restricted mail.

"Remediation pit" means a pit which is used for the handling, storage, or 

disposal of deleterious substances and/or soils contaminated by deleterious 

substances which are relocated to the pit for the purpose of remediating a 

site which is known to be or suspected to be causing pollution.

"Reserve pit" or "circulation pit" means a pit located either on-site or 

off-site which is used in conjunction with a drilling rig for the handling, 

storage, or disposal of drilling fluids and/or cuttings.

"Reservoir" See "common source of supply".

"Reservoir pressure" means the static or stabilized pressure in pounds per 

square inch existing at the face of the formation of an oil or gas well.

"Reuse" is the introduction (or reintroduction) into an industrial, 

manufacturing, or disposal process of a material which would otherwise be 

classified as a deleterious substance. A material will be considered "used or 

reused" if it is either:
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 10 -

(A) Employed as an ingredient (including use as an intermediate) in an 

industrial, manufacturing, or disposal process to make or recover a 

product.

(B) Employed in a particular function or application as an effective 

substitute for a commercial product or non-deleterious substance.

"Rotating head" means a rotating, pressure sealing device used in drilling 

operations utilizing air, gas, foam, or any other drilling fluid whose 

hydrostatic pressure is less than the formation pressure.

"Secretary" means the duly appointed and qualified Secretary, Assistant 

Secretary or Acting Secretary of the Commission, or any person appointed by 

the Commission to act as such Secretary during the absence, inability, or 

disqualification of the Secretary to act.

"Separator" means any apparatus for separating oil, gas, and water as they 

are produced from a well at the surface.

"Service well" means a well that, as part of a multi-well system, is used 

for drilling laterals, stimulation, or maintenance, or functions in any 

capacity other than as a conduit to the surface for the production of oil and 

gas.

"Slick spot" means a small area of soil having a puddled, crusted, or 

smooth surface and an excess of exchangeable sodium. The soil is generally 

silty or clayey, is slippery when wet, and is low in productivity.

"Slit trench" means a pit or bermed area at the drilling site used for the 

temporary storage of drilling fluids and/or cuttings to provide access for 

equipment to remove the contents off site.

"Sodium Adsorption Ratio (SAR)" means the index which indicates the 

relative abundance of sodium ions in solution as compared to the combined 

concentration of calcium and magnesium ions. It is calculated as follows:

 SAR = (Na ppm/23.0) 

 sq. root of [ {(Ca ppm/20.02) + (Mg ppm/12.16)} / 2] 

 where Na=Sodium

 Ca=Calcium

Mg=Magnesium

"Soil farming" means the application of oilfield drilling or produced 

wastes to the soil for the purpose of disposing of the waste without being a 

detriment to water or land; also known as land application.

"Spill containment pit" mean a permanent pit which is used for the emergency 

storage of oil and/or saltwater spilled as a result of any equipment 

malfunction.

"Subnormal pressure" means the formation pore pressure, proportional to 

depth, which is less than a hydrostatic pressure gradient of .465 psi/ft.

"Sulfide stress cracking" means the cracking phenomenon which is the result 

of corrosive action of hydrogen sulfide on susceptible metals under stress.

"Surface casing" means the first casing string designed and run to protect 

the treatable water formations and/or control fluid or gas flow from the well.

"Tank bottoms" means the liquids and/or solids in that portion of a storage 

facility below the sales line or connection that are unsaleable to the crude 

oil first purchaser in its present form. Tank bottoms may consist of a 

combination of several elements including, but not limited to, oil, BS&W, and 

treating fluids.

"Treatable water" means, for purposes of setting surface casing and other 

casing strings, subsurface water in its natural state, useful or potentially 

useful for drinking water for human consumption, domestic livestock, 

irrigation, industrial, municipal, and recreational purposes, and which will 

support aquatic life, and contains less than 10,000 mg/liter total dissolved 

solids or less than 5,000 ppm chlorides. Treatable water includes, but is not 

limited to, fresh water.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 11 -

"Trenching" means the practice of constructing trenches in or adjacent to a 

pit for the purpose of relocating all or a portion of the solids so as to 

facilitate closure.

"Truck wash pit" means a pit used for the temporary storage of fluids 

generated from the washing or cleaning of a motor vehicle, trailer or 

container used to transport or store deleterious substances.

"Ultimate destruction" means the treatment of a deleterious substance such 

that both its weight and volume remaining for disposal have been substantially 

reduced, and there is no demonstrated process or technology commercially 

available to further reduce its weight and volume and remove or reduce its 

harmful properties, if any. For the purposes of demonstrating a substantial 

reduction in weight and volume, any aqueous portion separated from the balance 

of a waste that meets drinking water standards or is evaporated into the 

ambient air shall count toward the weight and volume reduction.

"Underage" means the volume of allowable oil or gas not actually delivered 

to a carrier, transporter, or taker during any given proration period.

"Underground Source of Drinking Water (USDW)" means an aquifer or its 

portion which:

(A) Supplies any public water system; or

(B) Contains a sufficient quantity of ground water to supply a public 

water system; and

(i) Currently supplies drinking water for human consumption; or

(ii) Contains fewer than 10,000 mg/l total dissolved solids; and

(C) Is not an exempted aquifer.

"Unit operations" means a unit consisting of a portion of a lease, a lease, 

or more than one lease or portions thereof which covers contiguous lands 

containing one or more common sources of supply which has been approved by 

Commission order as a unit for the purpose of unitized management, after 

notice and hearing. 

"Vacuum" means pressure below the prevailing pressure of the atmosphere.

"Waste" means:

(A) As applied to the production of oil, in addition to its ordinary 

meaning, "shall include economic waste, underground waste, including 

water encroachment in the oil or gas bearing strata; the use of 

reservoir energy for oil producing purposes by means or methods that 

unreasonably interfere with obtaining from the common source of supply 

the largest ultimate recovery of oil; surface waste and waste incident 

to the production of oil in excess of transportation or marketing 

facilities or reasonable market demands." [52 O.S.A., 86.2]

(B) As applied to gas, in addition to its ordinary meaning, shall 

include economic waste; "the inefficient or wasteful utilization of gas 

in the operation of oil wells drilled to and producing from a common 

source of supply; the inefficient or wasteful utilization of gas in the 

operation of gas wells drilled to and producing from a common source of 

supply; the production of gas in such quantities or in such manner as 

unreasonably to reduce reservoir pressure or unreasonably to diminish 

the quantity of oil or gas that might be recovered from a common source 

of supply; the escape, directly or indirectly, of gas from oil wells 

producing from a common source of supply into the open air in excess of 

the amount necessary in the efficient drilling, completion or operation 

thereof; waste incident to the production of natural gas in excess of 

transportation and marketing facilities or reasonable market demand; the 

escape, blowing, or releasing, directly or indirectly, into the open 

air, of gas from well productive of gas only, drilled into any common 

source of supply, save only such as is necessary in the efficient 

drilling and completion thereof; and the unnecessary depletion or 

inefficient utilization of gas energy contained in a common source of 

supply." [52 O.S.A. §86.3]
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 12 -

(C) The use of gas for the manufacture of carbon black or similar 

products predominately carbon, except as specifically authorized by the 

Commission, shall constitute waste.

(D) The flaring of tail gas at gasoline, pressure maintenance, or 

recycling plants where a market is available.

"Waste oil" shall include, but not be limited to, crude oil or other 

hydrocarbons used or produced in the process of drilling for, developing, 

producing, or processing oil or gas from wells, oil retained on cuttings as a 

result of the use of oil-based drilling muds, or any residue from any oil 

storage facility on a producing lease or on a commercial disposal operation or 

pit. The term "waste oil" shall not include any refined hydrocarbons to which 

lead has been added.

"Waste oil residue" means that portion of waste oil remaining after 

treatment and after the saleable liquids and water have been extracted. Waste 

oil residue is a type of waste oil.

"Well log" or "well record" means a systematic, detailed and correct record 

of formations encountered in the drilling of a well.

[Source: Amended at 12 Ok Reg 2017, eff 7-1-95; Amended at 14 Ok Reg 2198, 

eff 7-1-97 (RM 97000002); Amended at 16 Ok Reg 842, eff 1-5-99 (emergency RM 

980000020); Amended at 16 Ok Reg 2190, eff 7-1-99 (980000034); Amended at 17 

Ok Reg 1860, eff 7-1-00 (RM 200000002); Amended at 24 OK Reg 1785, eff 7-1-07 

(RM 200700004); Amended at 25 OK Reg 2187, eff 7-11-08 (RM 200800003); Amended 

at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 29 Ok Reg 950, eff. 

7-1-12 (RM 201200005); Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002)

Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-1-3. Scope of rules

 All rules of general application in this Chapter promulgated to prevent 

waste, assure the greatest ultimate recovery from the reservoirs of this 

state, protect the correlative rights of all interests, and to prevent 

pollution shall be effective throughout the State of Oklahoma and be in force 

in all pools except as amended, modified, altered, or enlarged in specific 

individual pools by orders now in effect or hereafter issued by the 

Commission.

165:10-1-4. Citation effective date

(a) These rules shall be cited as OAC Title 165 Chapter 10 (OAC 165:10).

(b) The effective date of the rules of this Chapter is as set out below:

(1) Order No. 937 - Effective 06/16/15

(2) Order No. 1299 - Effective 08/20/17

(3) Order No. 1986 - Effective 01/05/22

(4) Order No. 6251 - Effective 04/12/33

(5) Order No. 6252 - Effective 04/15/33

(6) Order No. 6393 - Effective 07/19/33

(7) Order No. 6394 - Effective 07/20/33

(8) Order No. 7263 - Effective 04/10/34

(9) Order No. 8229 - Effective 10/31/33

(10) Order No. 17528 - Effective 01/24/45

(11) Order No. 19334 - Effective 10/24/46

(12) Order No. 29232 - Effective 10/06/54

(13) Order No. 30712 - Effective 09/09/55

(14) Order No. 44297 - Effective 04/01/61

(15) Order No. 47397 - Effective 12/01/61

(16) Order No. 53568 - Effective 12/08/63

(17) Order No. 53749 - Effective 01/03/64

(18) Order No. 62481 - Effective 05/11/66

(19) Order No. 62631 - Effective 06/01/66

(20) Order No. 63817 - Effective 10/04/66

(21) Order No. 64203 - Effective 11/10/66
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 13 -

(22) Order No. 64207 - Effective 12/01/66

(23) Order No. 65747 - Effective 05/05/67

(24) Order No. 66006 - Effective 06/08/67

(25) Order No. 66778 - Effective 09/05/67

(26) Order No. 67113 - Effective 10/09/67

(27) Order No. 67379 - Effective 11/06/67

(28) Order No. 69103 - Effective 06/01/68

(29) Order No. 69104 - Effective 06/01/68

(30) Order No. 69340 - Effective 07/01/68

(31) Order No. 70704 - Effective 01/03/69

(32) Order No. 75248 - Effective 07/01/69

(33) Order No. 77627 - Effective 01/01/70

(34) Order No. 78830 - Effective 01/01/70

(35) Order No. 78831 - Effective 01/01/70

(36) Order No. 79460 - Effective 04/01/70

(37) Order No. 79461 - Effective 04/01/70

(38) Order No. 80401 - Effective 06/01/70

(39) Order No. 80402 - Effective 06/01/70

(40) Order No. 81221 - Effective 08/01/70

(41) Order No. 81222 - Effective 08/01/70

(42) Order No. 83168 - Effective 01-01-71

(43) Order No. 84223 - Effective 04-01-71

(44) Order No. 84224 - Effective 04-01-71

(45) Order No. 84318 - Effective 03-29-71

(46) Order No. 85138 - Effective 06-01-71

(47) Order No. 85139 - Effective 06-01-71

(48) Order No. 87730 - Effective 01-01-72

(49) Order No. 87829 - Effective 01-01-72

(50) Order No. 93381 - Effective 10-05-72

(51) Order No. 93382 - Effective 10-05-72

(52) Order No. 94418 - Effective 01-01-73

(53) Order No. 96671 - Effective 04-01-73

(54) Order No. 87829 - Effective 01-01-72

(55) Order No. 94418 - Effective 01-01-73

(56) Order No. 102096 - Effective 01-01-74

(57) Order No. 109595 - Effective 01-01-75

(58) Order No. 117899 - Effective 03-01-76

(59) Order No. 128534 - Effective 03-01-77

(60) Order No. 128781 - Effective 03-01-77

(61) Order No. 138348 - Effective 03-01-78

(62) Order No. 151077 - Effective 03-23-79

(63) Order No. 161968 - Effective 01-03-80

(64) Order No. 164345 - Effective 03-17-80

(65) Order No. 164346 - Effective 02-14-80

(66) Order No. 164347 - Effective 02-14-80

(67) Order No. 165935 - Effective 04-01-80

(68) Order No. 185407 - Effective 03-09-81

(69) Order No. 185890 - Effective 03-16-81

(70) Order No. 187373 - Effective 04-02-81

(71) Order No. 211505 - Effective 03-30-82

(72) Order No. 228675 - Effective 01-01-83

(73) Order No. 230515 - Effective 01-01-83

(74) Order No. 230781 - Effective 01-01-83

(75) Order No. 246797 - Effective 01-01-84

(76) Order No. 250273 - Effective 01-01-84

(77) Order No. 250466 - Effective 01-01-84

(78) Order No. 260734 - Effective 07-01-84

(79) Order No. 290210 - Effective 01-09-86

(80) Order No. 292212 - Effective 02-10-86

(81) Order No. 299185 - Effective 06-12-86
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 14 -

(82) Order No. 302126 - Effective 10-08-86

(83) Order No. 303650 - Effective 10-02-86

(84) Order No. 304257 - Effective 10-16-86

(85) Order No. 305211 - Effective 11-07-86

(86) Order No. 311872 - Effective 05-06-87

(87) Order No. 312391 - Effective 05-14-87

(88) Order No. 310755 - Effective 06-01-87

(89) Order No. 313445 - Effective 06-12-87

(90) Order No. 313446 - Effective 07-09-87

(91) Order No. 313660 - Effective 06-17-87

(92) Order No. 313932 - Effective 06-25-87

(93) Order No. 314001 - Effective 06-27-87

(94) Order No. 313446 - Effective 07-09-87

(95) Order No. 315275 - Effective 08-19-87

(96) Order No. 320171 - Effective 12-21-87

(97) Order No. 320741 - Effective 01-08-88

(98) Order No. 320742 - Effective 01-08-88

(99) Order No. 321123 - Effective 01-21-88

(100) Order No. 323847 - Effective 05-01-88

(101) Order No. 325144 - Effective 05-02-88

(102) Order No. 326275 - Effective 06-27-88

(103) Order No. 326343 - Effective 06-01-88

(104) Order No. 326344 - Effective 06-01-88

(105) Order No. 327514 - Effective 07-01-88

(106) Order No. 327515 - Effective 07-01-88

(107) Order No. 329661 - Effective 08-26-88

(108) Order No. 329662 - Effective 08-26-88

(109) Order No. 329663 - Effective 08-26-88

(110) Order No. 334130 - Effective 01-04-89

(111) Order No. 337475 - Effective 03-31-89

(112) Order No. 337476 - Effective 03-31-89

(113) Order No. 339860 - Effective 05-07-89

(114) Order No. 341102 - Effective 08-25-89

(115) Order No. 341103 - Effective 08-14-89

(116) Order No. 346071 - Effective 03-29-90

(117) Order No. 346107 - Effective 03-30-90

(118) Order No. 355458 - Effective 03-20-91

(119) Order No. 355461 - Effective 03-20-91

(120) Order No. 355463 - Effective 03-20-91

(121) Order No. 355471 - Effective 03-21-91

(122) Order No. 364365 - Effective 06-25-92

(123) Order No. 364382 - Effective 06-25-92

(124) Order No. 368011 - Effective 05-23-93

(125) Order No. 372796 - Effective 06-25-93

(126) Order No. 381632 - Effective 07-11-94

(127) Order No. 381755 - Effective 07-11-94

(128) Order No. 387223 - Effective 10-20-94

(129) RM No. 950000023 - Effective 07-01-96

(130) RM No. 950000024 - Effective 07-01-96

(131) RM No. 950000025 - Effective 07-11-96

(132) RM No. 960000008 - Effective 07-01-96

(133) RM No. 960000009 - Effective 07-01-96

(134) RM No. 960000018 - Effective 10-15-96

(135) RM No. 970000002 - Effective 07-01-97

(136) RM No. 970000011 - Effective 07-01-98

(137) RM No. 970000025 - Effective 07-11-98

(138) RM No. 980000013 - Effective 07-15-98

(139) RM No. 980000016 Emergency, - Effective 03-30-98

(140) RM No. 980000017 Emergency, - Effective 03-30-98

(141) RM No. 980000020 Emergency, - Effective 01-05-99
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 15 -

(142) RM No. 980000033 - Effective 07-01-99

(143) RM No. 980000034 - Effective 07-01-99

(144) RM No. 980000035 - Effective 07-01-99

(145) RM No. 990000010 - Emergency, - Effective 12-28-99

(146) RM No. 200000002 - Effective 07-01-00

(147) RM No. 200000009 - Emergency, - Effective 11-02-00

(148) RM No. 200000009 - Permanent, - Effective 05-11-01

(149) RM No. 200100005 - Effective 07-01-01

(150) RM No. 200100006 - Effective 07-01-01

(151) RM No. 200100009 - Emergency, - Effective 01-14-02

(152) RM No. 200200017 - Effective 07-01-02

(153) RM No. 200300001 - Effective 07-01-03

(154) RM No. 200400006 - Effective 07-01-04

(155) RM No. 200600012 - Effective 07-01-06

(156) RM No. 200600013 - Emergency, - Effective 10-04-06

(157) RM No. 200700004 - Effective 07-01-07

(158) RM No. 200800003 – Effective 07-11-08

(159) RM No. 200900001 – Effective 07-11-09

(160) RM No. 201000003 – Effective 07-11-10

(161) RM No. 201100004 – Emergency, - Effective 05-19-11

(162) RM No. 201000007 – Effective 07-11-11

(163) RM No. 201200005 – Effective 07-01-12

(164) RM No. 201300001 - Effective 07-01-13

(165) RM No. 201400002 – Effective 09-12-14

[SOURCE: Amended at 16 Ok Reg 2206, eff 7-1-99 (RM 980000033); Amended at 19 

Ok Reg 1947, eff 7-1-02 (RM 200200017); Amended at 20 Ok Reg 1479, eff 4-24-03 

(emergency); Amended at Ok Reg 1543, eff 7-1-03 (RM 200300001); Amended at 25 

OK Reg 2187, eff 7-11-08 (RM 200800003); Amended at 27 Ok Reg 2128, eff. 7-11-

10 (RM 201000003); Amended at 28 Ok Reg 1949, eff. 7-11-11 (RM 201000007);

Amended at 29 Ok Reg 950, eff. 7-1-12 (RM 201200005); Amended at 30 Ok Reg 

1041, eff. 7-1-13 (RM 201300001)]; Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 

201400002); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-1-5. Conservation Division [RESERVED] 

165:10-1-6. Duties and authority of the Conservation Division 

(a) It shall be the duty of the Conservation Division to administer and 

enforce the statutes of this State and the rules, regulations, and orders of 

the Commission relating to the conservation of oil and gas and the prevention 

of pollution in connection with the exploration, drilling, producing, 

transporting, purchasing, processing, and storage of oil and gas, and to 

administer and enforce the applicable provisions of the Natural Gas Policy Act 

of l978. 

(b) The Conservation Division shall have the right at all times to go upon 

and inspect any oil and gas properties, pipelines, tank farms, refineries, and 

other processing plants and pump stations for the purpose of making any 

investigations or tests to ascertain whether the rules, regulations, and 

orders of the Commission are being complied with, and shall report to the 

Commission any violation thereof.

(c) The Conservation Division may require the testing or retesting of any 

oil, gas, injection, or disposal well upon 48-hour notice. Until the test is 

completed or excused, no allowable will be assigned the well and the purchaser 

or taker of oil or gas from such well shall not run oil or gas until 

authorized by the Conservation Division.

(d) The Director of the Conservation Division may administratively reclassify 

a well according to the gas-oil ratio as specified in 165:10-13-2 if the 

retesting of a well pursuant to this Section indicates a change in the 

original gas-oil ratio. This administrative reclassification shall only be 

used for allowable or priority purposes pursuant to 165:10-17-12. The 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 16 -

operator shall be notified in writing by the Conservation Division within 15 

days of the effective date of any change in classification.

(e) If the operator of the well which has been reclassified objects to said 

reclassification, he may file a written objection with the Conservation 

Division within 15 days of receiving notice of the reclassification. At the 

same time that the objection is filed, the operator shall file an application 

and notice setting cause for hearing with the Court Clerk Commission. The 

notice shall be published one time at least 15 days prior to the hearing in a 

newspaper of general circulation published in Oklahoma County and in a 

newspaper of general circulation published in each county in which lands 

embraced in the application are located. 

(f) The Conservation Division shall have access to all well records, wherever 

located. All companies, operators, drilling contractors, drillers, service 

companies, or other persons shall permit any authorized employee of the 

Commission to come upon any lease or property operated or controlled by them, 

and to inspect the records of wells; provided, that information so obtained

shall be confidential. Any person who attempts, by means of any threat or 

violence, to deter or prevent any authorized employee of the Commission from 

performing any duty hereunder shall be prosecuted to the fullest extent of the 

law.

(g) Upon request of the Conservation Division, service companies or other 

persons shall furnish and file reports and records showing gun perforating, 

hydraulic fracturing, cementing, shooting, chemical treatment, and all other 

service operations on any well. 

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92; Amended at 26 Ok Reg 2498, 

eff 7-11-09, (RM 200900001)]

165:10-1-7. Prescribed forms

(a) Required Conservation Division forms may be submitted to the Commission 

on forms supplied by the Commission or on xerographic copies of Commission 

forms or by operator computer generated forms. Operator computer generated 

forms will be printed from Commission designed files made available to 

operators via the electronic Bulletin Board Service (BBS), Internet (World 

Wide Web) or magnetic disk. Operator computer generated forms must contain 

the exact language and wording of Commission forms. Any alteration of 

Commission forms language and wording may subject the signature party and/or 

operator to perjury charges.

(b) The following Conservation Division forms are prescribed for filing 

purposes:

(1) Form 1000 - Notice of Intention to Drill application: Operator shall 

file Form 1000 before any oil, gas, injection, disposal, service well or 

stratigraphic test hole is drilled, recompleted, re-entered or deepened. 

Such notice shall include the name(s) and address(es) of the surface 

owner(s) of the land upon which the well is to be located. The Commission 

shall process the application and mail a copy of the permit to drill or reenter to the surface owner(s). Upon approval, the operator will have six 

months to commence the permitted operations. A six month extension may be 

granted without fee providing the Conservation Division staff determines 

that no material change of condition has occurred, if written request for 

such extension is received from the operator prior to the expiration of the 

original permit. Only one extension may be granted. A copy of the 

approved permit shall be posted at the well site. [Reference 165:10-3-1 and 

165:10-1-25 and OAC 165:10-7-31]

(2) Form 1000B - Application to Drill Deep Anode Groundbeds: Form 1000B 

is required to be filed for wells drilled for deep anode groundbeds as 

required by OAC 165:10-7-14. The purpose of Commission Form 1000B is to 

ensure groundwater is being protected in construction of the deep anode 

groundbed. [Reference 165:10-7-14]
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 17 -

(3) Form 1000S - Application for seismic operations: A permit for seismic 

operations must be obtained. The applicant must post a $50,000 bond with 

the Surety Department in the Oil and Gas Conservation Division. The 

application must also be accompanied with a pre-plat of the project area. 

[Reference 165:10-7-31]

(4) Form 1001 - Notification of Intention to Plug: Operator shall file 

notice on Form 1001, in duplicate, five days prior to plugging operations 

and shall notify the appropriate Conservation Division District Office 

before work is started. If the well is an exhausted producer, list OTC 

assigned county and lease number. If the Intent to Plug is cancelled, the 

operator shall notify the Commission by letter. [Reference 165:10-11-4 and 

165:10-11-6]

(5) Form 1001A - Notification of Spudding of New Well: Operator shall 

file a Form 1001A with the Conservation Division within 14 days of spudding 

a new well or reentering a previously plugged well. [Reference 165:10-3-2]

(6) Form 1002A - Well completion report: Operator shall furnish a 

complete well record on Form 1002A within 30 days after completion of 

operations to drill, recomplete, re-enter, or convert to injection or 

disposal well. Effective for both dry hole and/or producer. If well is an 

oil or gas producer, list OTC assigned county and lease number. Gas-oil 

ratio must be shown when Form 1002A is filed. List on a 24-hour basis both 

oil and gas. [Reference 165:10-3-25]

(A) Oil well: GOR less than 15,000:1

(B) Gas well: GOR 15,000:1 or more

(7) Form 1002B - Confidential Filing of Electric Logs: Operator shall 

file Form 1002B within 60 days from the earlier of the date of completion 

of the well or the date of the running of the last formation evaluation 

type wire line log to hold logs confidential for one year period. Optional 

extension for six months may be requested by operator in writing to the 

Technical Services Department of the Conservation Division. [Reference 

165:10-3-26]

(8) Form 1002C - Cementing Report to accompany Well Completion Report: 

Operator shall file Form 1002C with the Well Completion Report (Form 1002A) 

describing all cementing operations on surface, intermediate, and 

production casing strings, including multistage cementing jobs. The form 

shall be completed and signed by employees of both the operator and the 

cementing company. [Reference 165:10-3-4(i)]

(9) Form 1003 - Plugging Record: Operator will file Form 1003, in 

duplicate, within 30 days after plugging operations are completed. Both 

copies are to be mailed to the appropriate Conservation Division District 

Office. Form 1003 shall be completed and signed by employees of both the 

operator and the cementer. If a depleted producer, list OTC assigned county 

and lease number. [Reference 165:10-11-6 and 165:10-11-7]

(10) Form 1003A - Notice of Temporary Exemption from Well Plugging: Form 

1003A shall be filed with the appropriate Conservation Division District 

Office. [Reference 165:10-11-3 and 165:10-11-9]

(11) Form 1004 - Monthly Report of Unallocated Natural Gas Wells 

Production: Each operator of the required meter under 165:10-17-5 shall 

file a monthly well report on Form 1004 with the Commission of all natural 

gas volumes transferred through the meter for the preceding month, by the 

last day of the month following such transfer. List formation name plus 

OTC assigned county and lease number. If more than one meter, the operator 

of each shall file this form. [Reference 165:10-1-47]

(12) Form 1004B - Notice of Gas Purchase Curtailments: In any month 

wherein a first purchaser or first taker has a market demand/supply 

imbalance and must curtail purchases or takes in compliance with 165:10-17-

12, Form 1004B shall be filed by said first purchaser or first taker with 

the Conservation Division. [Reference 165:10-17-12]

(13) Form 1005 - Monthly Report of Purchasers (Gas: subject to field 

rules): [Reference 165:10-1-47 and 165:10-15-1]
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 18 -

(A) GAS: Each operator of the required meter or meters under 165:10-

17-5 shall complete computer-generated Form 1005, and return a copy to 

the Conservation Division indicating the gas amounts transferred through 

the meter for the preceding month on allocated and special allocated gas 

wells.

(B) OIL: Each first purchaser, or first taker of oil from wells and 

projects which are capable of producing in excess of their maximum 

assigned allowables, must complete computer-generated Form 1005 and 

return a copy to the Conservation Division indicating the amount of oil 

taken from each well or unit for the preceding month.

(14) Form 1006 - Surety bond for oil, gas, injection, or disposal wells: 

Prior to drilling and/or operating a well, the operator shall furnish the 

Conservation Division a surety bond ($25,000.00) or other present alternate 

surety, Form 1006A or 1006C. Operator must file the original copy only 

with a copy of the power of attorney from the bonding company. The name 

and address of the Oklahoma resident service agent shall be endorsed on the 

bond form. [Reference 165:10-1-10 and 165:10-1-12]

(15) Form 1006A - Financial Statement for oil, gas, injection or disposal 

wells: Prior to drilling and/or operating a well, the operator shall 

furnish the Conservation Division a verifiable financial statement (minimum 

net worth $50,000.00 within the State of Oklahoma) or other present 

alternate surety, Form 1006 or 1006C. Operator must file an original copy 

on Form 1006A, which must be updated annually from the last filing date. 

[Reference 165:10-1-10 and 165:10-1-11]

(16) Form 1006B - Operator Agreement to plug oil, gas, and service wells 

within the State of Oklahoma: Operator shall agree to plug well(s) in 

compliance with the Commission rules. This agreement must accompany the 

operator's elective choice of surety (Form 1006, 1006A, or 1006C). The 

operator is required to file a Form 1006B with the Conservation Division 

once every twelve (12) months. [Reference 165:10-1-10, 165:10-1-11, 

165:10-1-12, 165:10-1-13, and 165:10-1-14]

(17) Form 1006BR - Recycling, Reclaiming Operator’s Agreement to Close the 

Reclaiming Facility: Prior to operating a recycling or reclaiming facility 

the operator shall file an agreement to close the facility in compliance 

with OCC rules. This agreement must accompany the application for 

certification (Form 1020A). [Reference 165:10-8-5]

(18) Form 1006BR-A – Operator agreement to close hydrocarbon 

recycling/reclaiming facility: Operators of hydrocarbon 

recycling/reclaiming facilities are required to file agreements with the 

Commission concerning closure of such facilities. [Reference 165:10-8-5] 

(19) Form 1006BR-B - Surety for closure of hydrocarbon 

recycling/reclaiming facility: Operators of hydrocarbon 

recycling/reclaiming facilities are required to file surety with the 

Commission for closure and reclamation of such facilities. [Reference 

165:10-8-5]

(20) Form 1006BT-A – Operator's agreement to close, reclaim and remediate 

truck wash pit: Operators of truck wash pits are required to file 

agreements with the Commission regarding closure of such pits. [Reference 

165:10-7-33]

(21) Form 1006BT-B - Surety for closure of truck wash pits: Operators of 

truck wash pits are required to file surety with the Commission for 

closure, reclamation and remediation of such pits. [Reference 165:10-7-33]

(22) Form 1006C - Irrevocable commercial letter of credit: Prior to 

drilling and/or operating a well, the operator shall furnish the 

Conservation Division an irrevocable commercial letter of credit 

($25,000.00) or other present alternate surety, Form 1006A or 1006. 

Operator must file the original copy with the bank seal affixed. A letter 

of credit must be valid for at least a one year period. [Reference 165:10-

1-10 and 165:10-1-13]
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 19 -

(23) Form 1006D - Affidavit of well plugging costs: An operator may submit 

an affidavit on Form 1006D to the Conservation Division concerning the 

operator’s statewide plugging liability. The Commission may approve 

Category B surety in an amount less than $25,000.00 for an operator whose 

statewide plugging liability is less than $25,000.00. The Form 1006D must 

be properly executed by a duly licensed pipe pulling and well plugging 

company and such Form must be acceptable to the Conservation Division. 

[Reference 165:10-1-10, 165:10-1-12, 165:10-1-13 and 165:10-1-14]

(24) Form 1006S – Operator's agreement to plug seismic shot holes within 

the State of Oklahoma: Prior to commencing seismic operations the operator 

shall file an agreement to plug shot holes in accordance with Commission 

rules. This agreement must accompany the financial surety guarantee. 

[Reference 165:10-7-31]

(25) Form 1006SB - Surety bond for seismic shot hole plugging within the 

State of Oklahoma: Before commencing any seismic operation that requires 

the drilling of shot holes, those companies actually doing the work in the 

field must secure a bond in the amount of $50,000.00. Seismic companies 

must file the original Form 1006SB only with a copy of the power of 

attorney from the bonding company. The name and address of the Oklahoma 

resident service agent shall be endorsed on the bond form. Form 1000S 

shall be filed with the bond. [Reference 165:10-11-6 and 165:10-7-31]

(26) Form 1007A - IBM operator annual unallocated natural gas wells 

survey: Annual Survey Form 1007A will be furnished to all operators at the 

end of each calendar year in duplicate. The form shall be updated by the 

operator as of December 31 notifying the Commission of any new wells, wells 

sold (to whom and address), or abandoned since the last 1007A was filed. 

Original only shall be forwarded to Conservation Division by February 15th 

for the previous year's activity. List OTC assigned county and lease 

number (if not imprinted). [Reference 165:10-17-16]

(27) Form 1010 - Application for Cancelled Underage: Operator shall file, 

within 30 days for oil, and six months for special allocated and allocated 

gas from the date of cancellation, to reinstate cancelled underage; stating 

reason for this request and notifying all offset operators. List OTC 

assigned county and lease number. [Reference 165:10-13-10 and 165:10-17-9]

(28) Form 1011-Multi-Zone lease runs report: If there are two or more 

common sources of supply that are produced through a well or wells on the 

same lease or drilling and spacing unit and that are not commingled, 

production from each common source of supply shall be separately produced, 

measured and/or accounted for to the Commission. If one or more of the 

zones produced are classified as oil for allowable purposes, the operator 

is required to submit to the Conservation Division a multi-zone report on 

Form 1011 showing the production from each oil-bearing common source of 

supply on or before the last day of the succeeding proration period. 

[Reference 165:10-13-7]

(29) Form 1012 - Fluid Injection Report: Operators shall file Form 1012 

by April 1 of each year covering the previous calendar year (January 1 

through December 31) on all enhanced recovery projects, pressure 

maintenance projects, salt water disposal wells, LPG storage wells, 

authorized waterfloods and gas repressuring projects (commercial disposal 

wells will report two times per year by January 31 and July 31 for the 

previous six-month period) for each UIC well. The completed form will list 

well identification including API number, the Commission order number, 

injection volume and pressure, etc., as required on the form. No UIC well 

is to be operated for injection or disposal unless the Form 1012 is filed 

by the above dates. [Reference 165:10-5-7].

(30) Form 1013 - Application for adjusting an allowable for an Excessive 

Water Exemption or Reservoir Dewatering Oil Spacing unit: An operator in an 

unallocated oil pool may be permitted to produce at a full capacity 

allowable rate, provided that the water- oil ratio at the well is greater

than or equal to 3:1 as an excessive water exemption. To qualify for the 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 20 -

reservoir dewatering oil spacing unit allowable shown on Appendix J, the 

operator must provide data to show that the water - oil ratio is greater 

than 1:1. The operator shall submit a production test on Form 1013 to the 

Conservation Division. [Reference 165:10-15-1, 165:10-15-16, 165:10-15-17 

and 165:10-15-18].

(31) Form 1014 - Application for Permit to Use Earthen Pit, noncommercial 

disposal or enhanced recovery well pit used for temporary storage of 

saltwater, or pit associated with commercial disposal well surface 

facility: The operator of a proposed off-site reserve pit, recycling/reuse 

pit, spill containment pit, remediation pit, noncommercial disposal or 

enhanced recovery well pit used for temporary storage of saltwater, or pit 

associated with a commercial disposal well surface facility must submit 

Form 1014 in duplicate to the appropriate Conservation Division District 

Office for approval before constructing or using the pit. [Reference 

165:10-7-16, 165:10-7-20 and 165:10-9-3]

(32) Form 1014A – Commercial facility report: A report that operators of 

hydrocarbon recycling/reclaiming facilities, commercial pits, commercial 

soil farming sites and commercial recycling facilities are required to 

submit to the Manager of Pollution Abatement. [Reference 165:10-8-8, 

165:10-9-1, 165:10-9-2 and 165:10-9-4]

(33) Form 1014C - Chain of custody record/analysis request: Form 1014C is 

available for use by Commission personnel when samples are collected for 

submission to and analysis by a laboratory certified by the Oklahoma Water 

Resources Board or operated by the State of Oklahoma. 

(34) Form 1014CA - Compliance agreement for land application: Any person 

responsible for supervision of land application must submit a compliance 

agreement to the Commission. [Reference 165:10-7-19 and 165:10-7-26]

(35) Form 1014CR – Application for commercial recycling facility 

construction: After a Commission order is obtained, Form 1014CR must be 

submitted for approval to the Manager of Pollution Abatement prior to the 

construction of the commercial recycling facility authorized by the order. 

[Reference OAC 165:10-9-4]

(36) Form 1014CS - Application for Commercial Soil Farming: For a 

commercial soil farming site that has an order to operate, the operator 

shall submit a Form 1014CS to the Pollution Abatement Department for 

approval prior to commencing soil farming. [Reference 165:10-9-2]

(37) Form 1014D - Application for Surface Discharge or for reclaiming 

and/or recycling of produced water: Each application for surface discharge 

of produced water or for reclaiming and/or recycling of produced water must 

be submitted to the appropriate Conservation Division District Office on 

Form 1014D in quadruplicate. Applications will be processed within five 

business days. [Reference 165:10-7-17 or 165:10-7-32]

(38) Form 1014F - Application for permit to use flow back water pit with 

capacity in excess of 50,000 barrels: The operator of a proposed flow back 

water pit with a capacity in excess of 50,000 barrels must submit the Form 

1014F to and obtain the approval of the Manager of Field Operations or 

obtain the issuance of a Commission order before constructing or using the 

pit. [Reference 165:10-7-16]

(39) Form 1014HD - Notice for Disposal of Hydrostatic Test Water: 

Companies wishing to discharge water as required by OAC 165:10-7-17, used 

to test a pipeline, tank, etc. must submit a Form 1014HD to the appropriate 

Conservation Division District Office and the Pollution Abatement 

Department for prior approval. [Reference 165:10-7-17]

(40) Form 1014L - Surface Owner Permission for Land Application: Each 

application for land application must include an original Form 1014L, 

whereby the applicable surface owner gives permission for the applicant to 

land apply certain deleterious substances to a specific property. 

[Reference 165:10-7-17, 165:10-7-19 and 165:10-7-26]

(41) Form 1014LA – Designation of land application agent: A notarized 

affidavit designating any agent of an operator for land application must be 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 21 -

submitted to the Commission. [Reference 165:10-7-17, 165:10-7-19 and 

165:10-7-26]

(42) Form 1014LC – Letter of credit for land application: Persons who 

contract to land apply materials are required to file surety with the 

Commission. [Reference 165:10-7-10]

(43) Form 1014N - Application for Commercial Pit Construction: After a 

Commission order is obtained, Form 1014N must be submitted for approval by 

the Manager of Pollution Abatement prior to the construction of each 

commercial pit authorized by the order. [Reference 165:10-9-1]

(44) Form 1014P – Annual report for surface discharge: An annual report is 

required to be submitted to the Commission by April 1 of each year on Form 

1014P concerning surface discharges of produced water. Current (within 

three month) analyses of the produced water and soil from the discharge 

plot must be attached to the annual report. [Reference 165:10-7-17]

(45) Form 1014R – Post land application report: A post land application 

report shall be submitted by the operator or the operator’s agent to the 

Manager of Pollution Abatement within ninety (90) days of the completion of 

land application. [Reference 165:10-7-19 and 165:10-7-26]

(46) Form 1014RW – Application for permit to use reclaimed water in oil 

and gas operations: Each application for a permit to use reclaimed water 

in oil and gas operations must be submitted to the Manager of Field 

Operations on Form 1014RW. [Reference OAC 165:10-7-34]

(47) Form 1014S - Application for Land Application: Each application for 

land application of materials must be submitted to the Pollution Abatement 

Department on Form 1014S. An original and three copies are required. The 

applicant must be the operator of the well or other operator responsible 

for generating the waste to be land applied, except that a commercial pit 

operator may also apply in case of emergency or for the purpose of 

facilitating repair or closure, and the Oklahoma Energy Resources Board or 

its contractor may apply in cases where there is no responsible party. The 

Form 1014S shall be processed within five business days of submission of 

all required or requested information. [Reference 165:10-7-19 and 165:10-7-

26]

(48) Form 1014SB – Surety bond for land application: Persons who contract 

to land apply materials are required to file surety with the Commission. 

[Reference 165:10-7-10]

(49) Form 1014T – Application for permit to use truck wash pit: The 

operator of a proposed truck wash pit must submit Form 1014T to the Manager 

of Field Operations for the Conservation Division and obtain a permit 

before constructing or using the pit. [Reference 165:10-7-33]

(50) Form 1014W - Application for waste oil or drill cuttings use by 

County Commissioners: Application to apply waste oil, waste oil residue, 

crude oil contaminated soil or freshwater drill cuttings must be made by 

any Board of County Commissioners on Form 1014W. An original and one copy 

are required to be submitted to the appropriate District Manager. 

[Reference 165:10-7-22 and 165:10-7-28]

(45)

(51) Form 1014X - Application for waste oil or drill cuttings use by 

operators: Application to apply waste oil, waste oil residue, crude oil 

contaminated soil or freshwater drill cuttings must be made by any operator 

on Form 1014X. An original and one copy are required to be submitted to 

the appropriate District Manager. [Reference 165:10-7-27 and 165:10-7-29]

(52) Form 1015 - Application for Administrative Approval to Dispose of or 

Inject Water into Well(s) or to amend existing orders authorizing injection 

for enhanced recovery, saltwater disposal or LPG storage well(s): Applicant 

shall file an original of the application and one complete set of 

attachments with the Commission on Form 1015. When requesting approval to 

dispose of or inject water into wells, applicant will also furnish copies of 

the application on Form 1015 to the surface owner and with regard to 

injection or disposal wells with a requested injection rate of less than 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 22 -

five thousand barrels per day to each operator of a producing spacing unit 

or well within one-half (1/2) mile of the proposed noncommercial injection 

or disposal well location, and to each operator of a producing spacing unit 

or well within one (1) mile of either a proposed noncommercial injection or 

disposal well location with a requested injection rate of five thousand 

barrels per day or more or a proposed commercial disposal well location 

within five (5) days of the filing of the application and applicant will 

submit an affidavit of delivery or mailing to the Commission not later than 

five days after the application is filed. In addition, if the application 

involves a proposed horizontal injection or disposal well, a copy of the 

application for approval shall be served by the applicant within five (5) 

days of the date the application is filed by regular mail or delivered to 

each operator of a producing spacing unit or well within one-half (1/2) mile 

of the lateral of the proposed noncommercial injection or disposal well with 

a requested injection rate of less than five thousand barrels per day, and 

to each operator of a producing spacing unit or well within one (1) mile of 

the lateral of either a proposed noncommercial injection or disposal well 

with a requested injection rate of five thousand barrels per day or more or 

a proposed commercial disposal well. Further, if the application involves a 

proposed commercial disposal well, a copy of the application for approval 

shall be served within five (5) days of the date the application is filed by 

regular mail or delivered to each surface owner and surface lessee of record 

on each tract of land adjacent and contiguous to the site of the proposed 

well. Applicant shall file with the Commission proof of publication 

regarding the notice of application in an Oklahoma County newspaper and a 

county newspaper in which the well is located. [Reference 165:10-5-2, 

165:10-5-5, 165:5-7-27 and 165:5-7-30]

(53) Form 1015SI - Application for Permit for Simultaneous Injection Well: 

Operator shall file original and three copies with the Underground 

Injection Control Department on Form 1015SI. A copy of the form will also 

be supplied to the operator of any producing lease within one-half (1/2) 

mile of the proposed injection well. [Reference 165:10-5-15]

(54) Form 1015T - Application for Injection of Reserve Pit Fluids: Each 

application for the on-site injection of reserve pit fluids (i.e., drilling 

mud fluids or fracture fluids) used in drilling or well completion shall be 

filed with the Underground Injection Control Department by the well 

operator on Form 1015T. The original and three copies of the application 

and one complete set of attachments shall be furnished to the Underground 

Injection Control Department. A copy of the application will also be 

supplied to the land owner and the operator of any producing lease within 

one-half (1/2) mile of the proposed well. [Reference 165:10-5-13]

(55) Form 1015U - Unit-wide application for Injection: Optionally, the 

operator can file a unit-wide application for injection (Form 1015U) that 

fulfills all the requirements of 165:5-7-27 (b) through (e). Upon review 

and approval, the operator receives a unit-wide order that allows the 

operator to file an individual well application (Form 1015) and if it fits 

the unit-wide criteria, the UIC order can be issued immediately without an 

additional area of review, notice, or protest period. [Reference 165:5-7-

27]

(56) Form 1016 - Back Pressure Test for Natural Gas Wells: Operators 

and/or purchasers, on the Form 1016, will report all single-point and fourpoint potential tests as required by pool rule orders or general rules. 

List OTC assigned county and lease numbers and special allocated pool 

numbers, first date of sales, and complete flow data. [Reference 165:10-

17-6 and 165:10-17-7]

(57) Form 1017 - Guymon-Hugoton Field Gas Well Deliverability Tests: 

Operators and/or purchasers of gas in this field shall take deliverability 

tests between January 1 and August 31 of each year, and on the test sheet 

Form 1017 file the results with the Commission. List OTC assigned lease 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 23 -

number for each well. [Reference Orders No. 17867 and 87291 and 165:10-17-

9]

(58) Form 1019 - Guymon-Hugoton Field Acreage Statement for Gas Wells: A 

fact statement as to acreage attributable to each well shall be filed with 

the Commission on Form 1019 within 30 days of the well completion with a 

plat or map showing location of the well. List OTC assigned county and 

lease number. [Reference Order No. 17867 and 165:10-17-9]

(59) Form 1020A - Application for Certification for the Recycling, Reuse 

of Deleterious Substances: Applicant shall file an original Form 1020A 

with necessary attachments with the Pollution Abatement Department. Form 

1020A is filed prior to construction of facility or change of operator. 

[Reference 165:10-8-1 through 165:10-8-11]

(60) Form 1021 - Application for Priority Hardship Classification: The 

applicant shall file Form 1021 and the necessary attachments with the 

Technical Services Department for review prior to any hearing for priority 

one hardship classification. In addition, a formal application for hearing 

must be filed with the Court Clerk's Office of the Commission. [Reference 

165:10-17-12]

(61) Form 1021A - Application for limited deviation from the priority gas 

rules: The applicant shall file Form 1021A and the necessary attachments 

with the Technical Services Department for review prior to any hearing for

deviation from the priority gas rules. In addition, a formal application 

for hearing must be filed with the Court Clerk's Office of the Commission. 

[Reference 165:10-17-12]

(62) Form 1022 - Application to flare or vent gas: Operator shall file 

one copy of Form 1022 with the Technical Services Department of the 

Conservation Division listing OTC assigned county lease number. [Reference 

165:10-3-15]

(63) Form 1022A - Application to operate vacuum pump: Operator shall file 

one copy of Form 1022A with the required attachments with the Technical 

Services Department of the Conservation Division. [Reference 165:10-3-31]

(64) Form 1023 - Application for multiple completion, multichoke assembly 

or commingle completion: Operator will file the original and four copies 

of Form 1023 with the required attachments. List OTC assigned county and 

lease number. [Reference 165:10-3-35; 165:10-3-39; 165:10-3-37]

(65) Form 1024 - Packer setting affidavit: Operator will submit Form 1024 

as required. [Reference 165:10-3-35 and pertinent field rules]

(66) Form 1025 - Packer leakage test: Operator will submit Form 1025 as 

required. [Reference 165:10-3-35 and pertinent field rules]

(67) Form 1027 - Bottom hole pressure test: Operator, on the pink sheet 

of Form 1027, shall take BHP tests in the manner and during periods 

prescribed by special field rules. List OTC assigned county and lease 

numbers. [Reference Special Field Rules and 165:10-13-3]

(68) Form 1028 - Application for discovery oil allowable: Operator shall 

file Form 1028 with the required exhibits and tests within 30 days of 

completion of each new well in a discovery oil pool. [Reference 165:10-15-

7]

(69) Form 1029A - Production or potential test - oil only: Operator of 

each newly completed discovery oil well shall file a potential test Form 

1029A not later than 30 days after completion of the well. All tests, if 

requested, shall be witnessed by another operator. [Reference 165:10-15-7].

(70) Form 1030 - Application for allowable adjustment: Each operator or 

other interested parties desiring to adjust the allowable for a well or 

wells shall file Form 1030 for administrative review and approval. The 

allowable may be increased, decreased, or transferred as the evidence may 

indicate for the most efficient rate of production from the well or wells. 

[Reference 165:10-13-5, 165:10-13-8, 165:10-15-18 and 165:5-7-12]

(71) Form 1034 - Nominations and purchasers report: [Reference 165:10-1-

36, 165:10-1-37 and 165:10-1-46] Oil: Purchasers will furnish nomination 

data, actual runs from leases, stocks, and other information on Form 1034 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 24 -

to the Conservation Division not later than noon Friday of the week 

preceding each scheduled market demand hearing. On months in which no 

market demand hearing is held, Form 1034 shall be filed by the 20th of the 

month listing crude oil runs for the previous month on line 5 only. Any 

change in nominations from the previous hearing shall be so indicated on 

this monthly report.

(72) Form 1034-G – Gas nominations: Operators of natural gas wells in 

special allocated gas pools where well allowable calculations according to 

special allocated field rules are in effect shall file their pool 

nominations on Form 1034-G no later than one week prior to the market 

demand hearing. [Reference 165:10-1-36, 165:10-1-37, 165:10-1-49 and 

165:10-17-9].

(73) Form 1036 – Complaint Notice: Form 1036 may be issued by Commission 

personnel regarding alleged violations of Commission orders or rules, and 

specify a time period for compliance [Reference 165:10-3-17 and 165:10-7-

7].

(74) Form 1036A – Contempt Citation: Form 1036A may be issued by 

Commission personnel regarding the categories of rule violations appearing 

in Appendices E and F to this Chapter [Reference 165:10-3-17, 165:10-7-7 

and 165:10-7-9].

(75) Form 1040 - Monthly allocation schedule (gas): Monthly gas schedule 

Form 1040 will be forwarded to operators by the Conservation Division 

indicating the status of special allocated gas wells and their current 

allowables. Operators will inform the Conservation Division of errors, if 

any, found in Form 1040 as promptly as possible. Additionally, purchasers 

will receive the monthly schedule and shall return the production from each 

well as requested. [Reference 165:10-1-47]

(76) Form 1055 - Application for Pipe Pulling and Well Plugging License: 

No person shall contract to pull casing or plug oil, gas, injection, 

disposal, or other service wells, or contract to salvage casing therefrom, 

or purchase wells for the purpose of salvaging casing therefrom until a 

license has been secured from the Commission. [Reference 165:10-11-1]

(77) Form 1070 - Inventory of authorized existing enhanced recovery wells: 

Operators shall file reporting Form 1070 before injecting into any enhanced 

recovery well. [Reference 165:10-5-3]

(78) Form 1071 - Inventory of authorized existing disposal wells: 

Operators shall file the reporting Form 1071 before disposing into any 

disposal well. [Reference 165:10-5-3]

(79) Form 1072 - Notice of termination of injection: Within 30 days of 

the termination of injection Form 1072 must be filed. [Reference 165:10-5-

7]

(80) Form 1073 - Notice of transfer of well operatorship: The new 

operator shall file Form 1073 to notify the Conservation Division of any 

change of operation of any oil or gas well within 30 days after transfer of 

the well. [Reference 165:10-1-15]

(81) Form 1073I - Notice of transfer of well operatorship: The new 

operator shall file Form 1073I to notify the Underground Injection Control 

Section of any change of operation of any injection, disposal, enhanced 

recovery injection or hydrocarbon storage well within 30 days after 

transfer of the well. [Reference 165:10-5-10]

(82) Form 1075 - Mechanical integrity pressure test: A pressure or 

monitoring test must be performed on new and existing enhanced recovery 

injection wells and disposal wells. Information must be submitted on Form 

1075 and witnessed by a Field Inspector. Forms shall be submitted to the 

Conservation Division's Underground Injection Control Department. 

[Reference 165:10-5-6]

(83) Form 1081 - Mineral owners escrow account: Operator shall file, in 

quadruplicate, Form 1081 annually on anniversary date of first pooling 

order issued after effective date of Senate Bill 299 (7-1-84) and shall 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 25 -

include all applicable orders issued during the twelve-month reporting 

period. [Reference 165:10-25-1 through 165:10-25-10]

(84) Form 1085 - Complaint report: Form 1085 is used by Commission 

personnel to report violations of General Rules of the Commission and to 

report progress on ongoing remedial actions. Copies are sent to all 

parties concerned with investigation. Form 1085 combines and replaces old 

Forms 1034 and 1062. [Reference 165:10-7-7]

(85) Form 1139 - Application for gross production tax exemption: 

Operators shall file one copy of Form 1139 with the required attachments 

with the Technical Services Department of the Conservation Division. 

[Reference 165:10-21-75 through 165:10-21-80]

(86) Form 1534 - Application for tax rebate: Operators shall file one 

original of Form 1534 with the required attachments with the Technical 

Services Department of the Conservation Division. To obtain the tax 

exemption of the gross production tax, the operator shall forward a copy of 

the Commission approval to the Oklahoma Tax Commission, together with any 

other data required by that agency. [OTC Rule 10.030.03] [Reference 165:10-

21-23, 165:10-21-37, 165:10-21-57, 165:10-21-67 and 165:10-21-82.2]

(87) Form 1535 - Application for classification of reservoir dewatering 

project for exemption of sales tax on electricity used for such operations 

and application for state sales tax exemption for electricity sold for 

operations involving enhanced recovery methods on a spacing unit or lease: 

Operators shall file one original of Form 1535 with the required attachments 

with the Technical Services Department of the Conservation Division. To 

obtain the exemption of sales tax on the sale of electricity and associated 

delivery and transmission used for reservoir dewatering operations, or for a 

state sales tax exemption for electricity sold for operations involving 

enhanced recovery methods on a spacing unit or lease, the operator shall 

contact the Director’s Office, Taxpayer Assistance Division, Oklahoma Tax 

Commission, 2501 N. Lincoln Blvd., Oklahoma City, Ok. 73194. [Reference 

165:10-21-90 through 165:10-21-92 and 165:10-21-95 through 165:10-21-97]

(88) Form 2000BF - AAI Oversight Qualification: The Applicant shall file 

one (1) original of Form 2000BF with the Brownfields Program of the 

Conservation Division listing the qualifications as per AAI of each 

Environmental Professional who will work on the site. [Reference 165:10-10-1 

through 165:10-10-14]

(89) Form 2001BF - Brownfields Applicant Eligibility: The applicant shall 

file one (1) original of Form 2001BF with the Brownfields Program of the 

Conservation Division. This Form is filed to demonstrate applicant’s 

eligibility to be in the Brownfields program. [Reference 165:10-10-1 through 

165:10-10-14]

(90) Form 2002BF - Consent to Entry: The applicant shall file one (1) 

original of Form 2002BF with the Brownfields Program of the Conservation 

Division. This Form is the landowner's permission for applicant and their 

contractors to enter the property for assessment and cleanup work. Copies 

will be sent to all parties concerned with the assessment and/or cleanup. 

[Reference 165:10-10-1 through 165:10-10-14]

(91) Form 2003BF - Application for Brownfields Site Eligibility: The 

applicant shall file one (1) original of Form 2003BF with the Brownfields 

Program of the Conservation Division for all sites applicant is entering 

into the program. This Form provides necessary information on the site. 

[Reference 165:10-10-1 through 165:10-10-14]

(92) Form 2004BF - Application for Brownfields Site Assessment: The 

applicant shall file one (1) original of Form 2004BF with the Brownfields 

Program of the Conservation Division. This Form can be used by public, 

quasi-public, and non-profit entities to request a free Targeted Brownfields 

Assessment of a site that has been approved as eligible for the Brownfields 

program. [Reference 165:10-10-1 through 165:10-10-14]

(93) Form 2005BF - Brownfields Certificate of NFA: The Form 2005BF will be 

issued by the Commission to the Brownfields Applicant, after the Brownfields 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 26 -

staff has made a no further action (NFA) necessary decision. The applicant 

must file the Certificate of NFA in the office of the county clerk where the 

site is located, provide a copy to the landowner if the landowner is not the 

applicant, and submit a file-stamped copy to the Oklahoma Corporation 

Commission within 30 days. [Reference 165:10-10-1 through 165:10-10-14]

(94) Form 2006BF - Brownfields Certificate of Remediation Completion: The 

Form 2006BF will be issued by the Commission to the Brownfields Applicant, 

after the Brownfields staff has made a final inspection of the site and 

review of the project following a remedial action. The applicant must file 

the Certificate of Completion and any land use restrictions in the office of 

the county clerk where the site is located, provide a copy to the landowner 

if the landowner is not the applicant, and submit a file-stamped copy to the 

Oklahoma Corporation Commission within 30 days. [Reference 165:10-10-1 

through 165:10-10-14]

[SOURCE: Amended at 12 Ok Reg 2017, eff 7-1-95; Amended at 13 Ok Reg 2373, eff 

7-1-96; Amended at 13 Ok Reg 2381, eff 7-1-96; Amended at 14 Ok Reg 2198, eff 

7-1-97 (RM 970000002); Amended at 15 Ok Reg 2989, eff 7-15-98 (RM 980000013); 

Amended at 16 Ok Reg 2206, eff 7-1-99 (RM 980000033); Amended at 18 Ok Reg 226, 

eff 11-2-00 (emergency RM 200000009); Amended at 18 Ok Reg 1035, eff 5-11-01 

(permanent RM 200000009); Amended at 19 Ok Reg 1947, eff 7-1-02 (RM 200200017); 

Amended at 20 Ok Reg 1479, eff 4-24-03 (emergency);Amended at 20 Ok Reg 1543, 

eff 7-1-03 (RM 200300001); Amended at 25 OK Reg 2187, eff 7-11-08 (RM 

200800003); Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001); Amended at 

27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28 Ok Reg 1949, eff. 7-

11-11 (RM 201000007); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001)]; 

Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002); Amended at 32 Ok Reg 

767, eff. 8-27-15 (RM 201500001)]

PART 3. SURETY 

165:10-1-10. Operator's agreement; Category A and Category B surety

(a) "Any person who drills or operates any well for the exploration, 

development or production of oil or gas, or as an injection or disposal well, 

within this State, shall furnish in writing, on forms approved by the 

Corporation Commission, his agreement to drill, operate and plug wells in 

compliance with the rules and regulations of the Commission and the laws of this 

state, together with evidence of financial ability to comply with the 

requirements for plugging, closure of surface impoundments, removal of trash and 

equipment as established by the rules of the Commission and by law." [52 O.S. § 

318.1] Any operator violating this Section may be fined up to $500.00. To 

establish evidence of financial ability, the Commission shall require:

(1) Category A surety which shall include a financial statement listing 

assets and liabilities and including a general release that the information 

may be verified with banks and other financial institutions. The statement 

shall prove a net worth of not less than $50,000.00 in U.S. dollars; or

(2) Category B surety shall include an irrevocable commercial letter of 

credit, cash, a cashier's check, a certificate of deposit, bank joint custody 

receipt, other approved negotiable instrument, or a blanket surety bond. 

Except as provided in (3) of this subsection, the amount of such Category B 

surety shall be in the amount of $25,000.00 in U.S. dollars but may be set 

higher at the discretion of the Director of the Conservation Division. The 

Commission is authorized to establish Category B surety in an amount greater 

than $25,000.00 in U.S. dollars based upon the past performance of the 

operator and its insiders and affiliates regarding compliance with the laws 

of this state, and compliance with any rules promulgated thereto including 

but not limited to the drilling, operation and plugging of wells, closure of 

surface impoundments, or removal of trash and equipment. Any such Category B 

surety shall constitute an unconditional promise to pay and be in a form 

negotiable by the Commission.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 27 -

(3) The Commission may grant Category B surety in an amount less than 

$25,000.00 in U.S. dollars to an operator whose statewide well plugging 

liability is less than $25,000.00 in U.S. dollars. Said Category B surety 

shall be in an amount that is sufficient to cover the total estimated cost of 

properly plugging and abandoning each and every well, the operations for 

which, an operator is responsible. Statewide well plugging liability shall 

be documented by an affidavit filed on Form 1006D and shall be properly 

executed by a duly licensed pipe pulling and well plugging company and shall 

be approved by the Conservation Division. Said affidavit shall state, among 

other things, an estimated cost of plugging, closure, and removal operations 

for each well in accordance with 165:10-11-3 through 165:10-11-8 inclusively 

and shall be accompanied by a Form 1000 (Intent to Drill) if the estimate 

involves a proposed well or by a Form 1002A (Completion Report) if the 

estimate involves a well that is a producing, injection, or disposal well. 

The estimated cost shall not include any salvage value as to recoverable 

casing, tubing, or well head equipment. The total statewide well plugging 

liability of an operator utilizing this Category B surety shall be kept 

current and shall be increased as additional wells are added to the 

responsibility of the operator and may be decreased as included wells are 

plugged and abandoned, but in no event shall exceed $25,000.00 in U.S. 

dollars unless otherwise ordered by the Commission.

(b) Operators of record as of June 7, 1989, who do not have any outstanding 

contempt citations or fines and whose insiders or affiliates have no outstanding 

contempt citations or fines may post Category A surety.

(1) New operators, operators who have outstanding fines or contempt 

citations and operators whose insiders or affiliates have outstanding 

contempt citations or fines as of June 7, 1989, shall be required to post 

Category B surety. Operators who have posted Category B surety and have 

operated under this type surety and have no outstanding fines at the end of 

three years may post Category A surety.

(2) Operators using Category A surety who are assessed a fine of $2,000.00 

or more and who do not pay the fine within the specified time shall be 

required to post a Category B surety within 30 days of notification by the 

Commission.

(c) If a bond is required, the bond shall be executed by a corporate surety 

authorized to do business in this State and shall be renewed and continued in 

effect until the conditions have been met or release of the bond is authorized 

by the Commission.

(d) Irrespective of (a), (b), and (c) of this Section, for good cause shown 

concerning pollution or improper plugging of wells by an operator posting either 

Category A or Category B surety or by an insider or affiliate of such operator, 

the Commission, upon application of the Director of the Conservation Division 

after notice and hearing, may require the filing of additional Category B surety 

in an amount greater than $25,000.00 in U.S. dollars but not to exceed 

$100,000.00 in U.S. dollars. If the Commission has evidence that any person 

applying to the Commission for authority to operate may not possess a 

satisfactory compliance history with Commission rules, the Director of the 

Conservation Division may seek an order of the Commission, issued after 

application, notice, and hearing, determining whether the person should be 

authorized to operate.

(e) The agreement (Form 1006B-Operator’s Agreement to Plug Oil, Gas and Service 

Wells Within the State of Oklahoma) provided for in (a) of this Section shall 

provide that if the Commission determines, after notice and hearing, that the 

person furnishing the agreement has neglected, failed, or refused to plug and 

abandon, or cause to be plugged and abandoned, or replug any well or has 

neglected, failed or refused to close any surface impoundment or remove or cause 

to be removed trash and equipment in compliance with the rules of this Chapter, 

then the person shall forfeit from his bond, letter of credit, or negotiable 

instrument or shall pay to this State, through the Commission for deposit in the 

State Treasury, a sum equal to the cost of plugging the well, closure of any 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 28 -

surface impoundment, or removal of trash and equipment. The Commission may 

cause the remedial work to be done, issuing a warrant in payment of the cost 

thereof drawn against the monies accruing in the State Treasury from the 

forfeiture or payment. Any monies accruing in the State Treasury by reason of a 

determination that there has been a noncompliance with the provisions of the 

agreement (Form 1006B) or the rules and regulations of the Commission, in excess 

of the cost of remedial action ordered by the Commission, shall be credited to 

the Conservation Fund. The Commission shall also recover any costs arising from 

litigation to enforce this provision if the Commission prevails. Provided, 

before a person is required to forfeit or pay any monies to the State pursuant 

to this Section, the Commission shall notify the person at his last-known 

address of the determination of neglect, failure, or refusal to plug or replug 

any well, or close any surface impoundment, or remove trash and equipment, and 

said person shall have ten days from the date of notification within which to 

commence remedial operations. Failure to commence remedial operations shall 

result in forfeiture or payment as provided in this subsection. If the operator 

is a corporation, association, partnership, limited liability company or any 

entity other than an individual, the operator shall file as part of its Form 

1006B a complete list, in tabular form, of the names, addresses, telephone 

numbers, driver license numbers, and percentages of ownership of all officers, 

directors, partners or principals of the operator and the insiders and 

affiliates of the operator. The operator shall also file as part of its Form 

1006B the current names and addresses of all service agents of the operator and 

the operator’s insiders and affiliates. The operator is required to file a Form 

1006B with the Conservation Division every twelve (12) months.

(f) No person shall drill or operate any well, or receive an allowable, without 

complying with the provisions of this Section.

(g) The Commission shall shut in, without notice, hearing or order of the 

Commission, the wells of any such person violating the provisions of this 

Section and such wells shall remain shut in for noncompliance until the required 

evidence of Category B surety is obtained and verified by the Commission. No 

taker, transporter, or purchaser of oil or gas shall take, transport, or 

purchase oil or gas from the wells of any such drillers or operators after 

receiving a copy of the shut-in order or notice by certified mail of the 

issuance of such an order.

(h) If title to property or a well is transferred, the transferee shall furnish 

the evidence of financial ability to plug the well and close surface 

impoundments required by the provisions of this section, prior to the transfer.

(i) The following words, when used in this Section, shall have the following 

meaning:

(1) "Affiliate" means an entity which owns twenty percent (20%) or more of 

the operator, or an entity of which twenty percent (20%) or more is owned by 

the operator.

(2) "Insider" means officer, director, or person in control of the operator; 

general partners of or in the operator; general or limited partnership in 

which the operator is a general partner; spouse of an officer, director, or 

person in control of the operator; spouse of a general partner of or in the 

operator; corporation of which the operator is a director, officer, or person 

in control; affiliate, or insider of an affiliate as if such affiliate were 

the operator; or managing agent of the operator.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 13 Ok Reg 2373, eff 

7-1-96; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28 Ok 

Reg 1949, eff. 7-11-11 (RM 201000007)]

165:10-1-11. Financial statement as surety

(a) A plugging agreement shall be accompanied by surety. The surety 

requirement may be met by furnishing the operator's current financial statement 

(Form 1006A) to the Conservation Division, which shall be a full statement of 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 29 -

the operator’s assets and liabilities and shall reflect the operator’s total net 

worth of not less than $50,000.00 in U.S. dollars located in this State.

(b) The value of producing oil and gas leaseholds for which the financial 

statement stands as surety will be deducted from total net worth unless the 

financial statement is accompanied by the written appraisal of a recognized 

independent appraiser of oil and gas properties showing the fair market value of 

the leasehold interest owned by the operator.

(c) The Director of Conservation may require proof in the form of an appraisal 

or other proof of the fair market value of any asset listed in the financial 

statement, and the Director of Conservation may also require proof that the 

financial statement truly shows the net fair market value of all assets over and 

above all debts and encumbrances.

(d) A current financial statement shall be filed every twelve (12) months on 

Form 1006A.

(e) Only one operator’s name shall appear on each Form 1006A.

(f) Along with the Form 1006A, an operator is required to file a Form 1006B 

(Operator’s Agreement to Plug Oil, Gas and Service Wells Within the State of 

Oklahoma) with the Conservation Division.

(g) The Commission shall reject the operator’s Form 1006A if the operator fails 

to file the documentation required by this Section with the Conservation 

Division.

[SOURCE: Amended at 13 Ok Reg 2373, eff 7-1-96]

165:10-1-12. Corporate surety bond

(a) An operator may file a blanket surety bond in the principal amount of 

$25,000.00 in U.S. dollars on Form 1006 as surety. In the alternative, the 

operator may file a surety bond of a lesser amount but that is sufficient to 

cover the total estimated cost of properly plugging and abandoning each and 

every well, the operations for which, the operator is responsible. Said 

estimated cost shall be documented on Form 1006D (Affidavit of Well Plugging 

Cost) for each and every well. Said alternative surety bond shall be increased 

upward, but not to exceed $25,000.00 in U.S. dollars, as additional wells are 

added to the operator's responsibilities, unless otherwise ordered by the 

Commission.

(b) For purposes of (a) of this Section, an operator may file a surety bond 

issued by a corporation authorized to issue such bonds in the State of Oklahoma.

(c) The Conservation Division shall not accept a bond unless the surety agrees 

to give the Conservation Division six months written notice before cancellation 

of a bond prior to expiration of the bond and evidence furnished of acceptable 

alternate surety if required.

(d) Only one operator’s name shall appear on each Form 1006.

(e) Along with the Form 1006, an operator is required to file a Form 1006B 

(Operator’s Agreement to Plug Oil, Gas and Service Wells Within the State of 

Oklahoma) with the Conservation Division.

(f) The Commission shall reject the operator’s Form 1006 if the operator fails 

to file the documentation required by this Section with the Conservation 

Division.

[SOURCE: Amended at 13 Ok Reg 2373, eff 7-1-96]

165:10-1-13. Irrevocable commercial letter of credit

(a) At his option, an operator may file an irrevocable commercial letter of 

credit of a bank in the sum of $25,000.00 in U.S. dollars on Form 1006C as 

surety. In the alternative, the operator may file an irrevocable commercial 

letter of credit of a lesser amount but that is sufficient to cover the total 

estimated cost of properly plugging and abandoning each and every well, the 

operations for which, the operator is responsible. Said estimated cost shall be 

documented on Form 1006D (Affidavit of Well Plugging Cost) for each and every 

well. Said alternative irrevocable commercial letter of credit shall be 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 30 -

increased upward, but not to exceed $25,000.00 in U.S. dollars, as additional 

wells are added to the operator's responsibilities, unless otherwise ordered by 

the Commission.

(b) The letter of credit shall be for a term of not less than one year.

(c) The bank issuing the letter of credit shall endorse thereon that the letter 

of credit shall remain in effect until canceled or revoked by the bank or 

principal/operator upon six months notice in writing to the Conservation 

Division and evidence furnished of acceptable alternate surety if required.

(d) Only one operator’s name shall appear on each Form 1006C.

(e) Along with the Form 1006C, an operator is required to file a Form 1006B 

(Operator’s Agreement to Plug Oil, Gas and Service Wells Within the State of 

Oklahoma) with the Conservation Division.

(f) The Commission shall reject the operator’s Form 1006C if the operator fails 

to file the documentation required by this Section with the Conservation 

Division.

[SOURCE: Amended at 13 Ok Reg 2373, eff 7-1-96]

165:10-1-14. Cashier's check, certificate of deposit, or other negotiable 

instrument

(a) An operator may deposit cash, a cashier's check, a certificate of deposit, 

bank joint custody receipt, or other negotiable instrument in the amount of 

$25,000.00 in U.S. dollars as surety. In the alternative, the operator may 

deposit cash, a cashier's check, a certificate of deposit, bank joint custody 

receipt, or other negotiable instrument of a lesser amount but that is 

sufficient to cover the total estimated cost of properly plugging and abandoning 

each and every well, the operations for which, the operator is responsible. 

Said estimated cost shall be documented on Form 1006D (Affidavit of Well 

Plugging Cost) for each and every well. Said alternate amount shall be 

increased upward, but not to exceed $25,000.00 in U.S. dollars, as additional 

wells are added to the operator's responsibilities, unless otherwise ordered by 

the Commission. However, any instrument must constitute an unconditional 

promise to pay and be in the form negotiable by the Commission.

(b) A certificate of deposit shall be for a term of no less than three hundred 

sixty-five (365) days.

(c) Financial institutions issuing certificates of deposit pursuant to this 

Section shall do so in the following manner: “Oklahoma Corporation Commission 

or Oklahoma Corporation Commission and (Name of the Operator).” Financial 

institutions issuing the certificates of deposit shall retain the original 

documents and copies of the certificates of deposit shall be furnished to the 

Commission.

(d) Along with the negotiable instruments described in (a) of this Section, an 

operator is required to file a Form 1006B (Operator’s Agreement to Plug Oil, Gas 

and Service Wells Within the State of Oklahoma) with the Conservation Division.

(e) The Commission shall reject the negotiable instruments described in (a) of 

this Section if the operator fails to file the documentation required by this

Section with the Conservation Division.

[SOURCE: Amended at 13 Ok Reg 2373, eff 7-1-96]

165:10-1-15. Transfer of operatorship of wells

(a) Before the operations of a well can be transferred to a new operator, the 

following must be submitted:

(1) The new operator, or transferee, must comply with 165:10-1-10 before a 

change in operator is approved.

(2) Change of operator Form 1073 must be signed by both the transferor and 

transferee, with both stipulating that the facts presented are true and 

correct as to the area covered and the wells being transferred. Unless 

otherwise stated, the new operator assumes all responsibility for the wells 

specified within the boundaries of the outlined area. For transfers 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 31 -

involving more than ten (10) wells, a transferor and transferee may file a 

single Form 1073 with the Conservation Division indicating the transfer of 

multiple wells, provided that such multiple well transfer shall be 

accompanied by a well list containing the following information regarding 

each well being transferred:

(A) API number of the well;

(B) Well name and number;

(C) Legal location of the well, described by section, township and range.

(3) The well list may be provided in spreadsheet form, if possible, and may 

be filed in digital format specified by the Conservation Division. In lieu 

of the spreadsheet, the transferor and transferee, at their option, may file 

one Form 1073 indicating the transfer of multiple wells with an OCC Form 

1002A Completion Report attached for each well transferred. Upon review by 

the Conservation Division, it may require additional information from the 

transferor and/or the transferee to assist in identifying the specific 

well(s) being transferred. The additional information may include, but not 

be limited to, the quarter, quarter, quarter section calls, footages from the 

south and west quarter section lines, and the drilling and completion dates.

(4) The Conservation Division shall notify both the transferor and 

transferee of approval of the transfer of operatorship within thirty (30) 

days of the Conservation Division’s approval of said transfer.

(5) Compliance with 165:5-7-11 when and if operatorship was designated by 

orders of the Commission in pooling, increased density, and location 

exception applications.

(b) Before the operatorship of a well can be transferred to a new operator when 

the current or former operator is unavailable for signature, one of the 

following may be submitted as proof of operatorship:

(1) A certified copy of a recorded lease or assignment transferring all 

rights, title, and interest to the wells described on Form 1073 to the new 

operator.

(2) A certified copy of a journal entry of judgment rendered by a district 

court of Oklahoma having jurisdiction over the wells described on Form 1073 

vesting legal title to the new operator.

(3) A certified copy of bankruptcy proceeding by the federal district court 

having jurisdiction over the wells described on Form 1073.

(c) If an operator is not in compliance with an enforceable order of the 

Commission, the Conservation Division shall not approve any Form 1073 

transferring well(s) to said operator until the operator complies with the 

order. The transferor of the well(s) listed on the Form 1073 remains 

responsible for the well(s) until any transfer is approved by the Commission.

[SOURCE: Amended at 13 Ok Reg 2373, eff 7-1-96; Amended in Rule Making 

2000000002, eff 7-1-00]

165:10-1-16. Change of address

 Each operator of a well or other facility subject to a permit shall give 

written notice of his change of address. Such notice shall be sent to the 

Director of the Conservation Division. It shall be due within 30 days after 

changing address.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 13 Ok Reg 2373, eff 

7-1-96]

PART 5. SPACING

165:10-1-20. Spacing [RESERVED]

165:10-1-21. General well spacing requirements

 Any well drilled for oil or gas to an unspaced common source of supply the 

top of which is 2,500 feet or more in depth shall be located not less than 330 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 32 -

feet from any property line or lease line, and shall be located not less than 

600 feet from any other producible or drilling oil or gas well when drilling to 

the same common source of supply; provided and except that in drilling to an 

unspaced common source of supply the top of which is less than 2,500 feet in 

depth, the well shall be located not less than 165 feet from any property line 

or lease line and not less than 300 feet from any other producible or drilling 

oil or gas well in the same common source of supply; provided, however, that the 

depth to the top of the common source of supply in the original or discovery 

well shall be recognized as the depth to the top of the common source of supply 

for the purpose of this Section; provided further, when an exception to this 

Section is granted, the Commission may adjust the allowable or take such other 

action as it deems necessary for the prevention of waste and protection of 

correlative rights. 

[SOURCE: Amended at 28 Ok Reg 1949, eff 7-11-11 (RM 201000007)]

165:10-1-22. Drilling and spacing units

(a) The Commission may establish drilling and spacing units in any common 

source of supply as provided by law, and the special orders creating drilling 

and spacing units shall supersede the provisions of 165:10-1-21. It shall be 

the responsibility of any operator who proposes to drill a well to ascertain the 

existence and provisions of special spacing orders.

(b) The drilling of a well or wells into a common source of supply in an area 

covered by an application pending before the Commission seeking the 

establishment of drilling and spacing units is prohibited except by special 

order of the Commission. However, if an Intent to Drill (Form 1000) has been 

approved by the Commission and operations commenced prior to the filing of a 

spacing application, the operator shall be permitted to drill and complete the 

well without a special order of the Commission.

(c) Standard drilling and spacing units shall be either approximately square or 

rectangular; if rectangular, the drilling and spacing unit shall consist of two 

approximately square tracts.

(d) Standard square drilling and spacing units shall be those containing 

approximately 10, 40, 160, or 640 acres; standard rectangular units shall 

contain approximately 20, 80, or 320 acres. 

(e) The drilling and spacing units within any common source of supply of oil or 

gas shall be of approximately uniform size and shape. In a combination 

reservoir, the drilling and spacing units within the oil portion of the 

reservoir shall be of approximately uniform size and shape, and the drilling and 

spacing units within the gas portion of the reservoir shall be of approximately 

uniform size and shape; provided, however, the drilling and spacing units within 

the gas portion of a combination reservoir along the gas-oil contact line or 

transition zone may be of nonuniform size and shape.

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92]

165:10-1-23. Extension of pool rules

(a) Any application to establish pool rules for a common source of supply shall 

include the entire common source of supply.

(b) To extend pool rules to a drilling and spacing unit, an application shall 

be filed and notice provided in the same manner as required to establish pool 

rules. In the event that more than one set of pool rules are in effect within a 

field, the Commission shall extend the appropriate pool rules consistent with 

available geological and engineering reservoir information.

165:10-1-24. Permitted well locations within standard drilling and spacing 

units

(a) The permitted well location within any standard square drilling and spacing 

unit shall be the center of the unit. The permitted well locations within 

standard rectangular drilling and spacing units shall be the centers of 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 33 -

alternate square tracts constituting the units (alternate halves of the units); 

provided, however, a well will be deemed drilled at the permitted location if 

drilled within the following tolerance areas:

(1) Not less than 165 feet from the boundary of any standard 10-acre 

drilling and spacing unit or the proper square 10-acre tract within any 

standard 20-acre drilling and spacing unit.

(2) Not less than 330 feet from the boundary of any standard 40-acre 

drilling and spacing unit or the proper square 40-acre tract within any 

standard 80-acre drilling and spacing unit.

(3) Not less than 660-feet from the boundary of any standard 160-acre 

drilling and spacing unit or the proper square 160-acre tract within any 

standard 320-acre drilling and spacing unit.

(4) Not less than 1320 feet from the boundary of any standard 640-acre 

drilling and spacing unit.

(b) The proper square tract of a rectangular drilling and spacing unit 

established prior to January 1, 1971, for which a slot drilling pattern was 

prescribed, shall be the northeast quarter and the southwest quarter of the 

governmental section, quarter section, or quarter quarter section containing two 

abutting rectangular drilling and spacing units; provided, slot patterns may be 

established or re-established upon application, notice, and hearing where 

consistent with available geological and engineering information when necessary 

to prevent waste or protect correlative rights. 

(c) The permitted well location tolerance areas set out in (a) of this Section 

shall apply to each standard drilling and spacing unit heretofore or hereafter 

established, notwithstanding the provisions of any special order of the 

Commission prescribing a different permitted well location tolerance area; 

provided, however, this Section shall not affect any adjusted allowable or 

penalty applied to any well by special order of the Commission prior to the 

effective date of this Section, nor shall any well heretofore drilled within a 

then permitted tolerance area be deemed outside the permitted tolerance area by 

reason of this Section. 

(d) Wells drilled offpattern without first obtaining an exception after notice 

and hearing by the Commission are hereby prohibited from producing either oil or 

gas.

(e) Whenever permission is granted to drill a well at a location other than 

specified in this Chapter, the allowable or production therefrom, or both, may 

be adjusted for the protection of the correlative rights of all persons entitled 

to share in the common source of supply. 

(f) Unless the order granting a well location exception provides otherwise, the 

permission to drill the well at the excepted location shall expire twelve (12) 

months after the date of the order, unless a well was commenced at the excepted 

location on or before the expiration date. The order granting the well location 

exception will thereafter expire when the well is plugged, abandoned, or 

converted. 

(g) An application for an emergency order granting a well location exception 

may be granted if the applicant has obtained the written consent of the operator 

of each adjoining or cornering tract of land or drilling and spacing unit, 

currently producing from the same formation, toward which the well location is 

proposed to be moved. Provided, however, if the applicant is the operator of 

the well in an adjoining or cornering tract of land or drilling and spacing 

unit, currently producing from the same formation, toward which the well 

location is proposed to be moved, the applicant shall obtain the written consent 

of each working interest owner in such well. 

(1) Letters evidencing the written consent of off-set operators and working 

interest parties as described in this subsection shall be introduced and 

received into evidence at the time of the emergency hearing and reviewed. 

Copies of said letters shall be filed with the Court Clerk of the Commission. 

(2) If the written consent described in this subsection cannot be obtained, 

the applicant may send written notice to said non-consenting party giving 

that party at least five business days notice of the emergency hearing. If 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 34 -

said non-consenting party fails to appear, then the emergency application 

shall be considered and may be granted without the non-consenting party's 

written consent. The applicant shall file an affidavit of mailing with the 

Court Clerk to prove the mailing of the five day notice.

(h) If a spacing application is currently pending and the applicant or any 

party who owns the right to drill needs to commence a well prior to issuance of 

the spacing order, the applicant or party shall obtain an emergency order to 

commence such well and an emergency location exception order if: 

(1) The proposed well is offpattern according to the existing spacing for 

any formation involved, or 

(2) The well is offpattern according to 165:10-1-21 governing well patterns 

for unspaced areas. 

(i) Whenever an order permits an offpattern well with a percentage penalty, the 

order permitting said well may provide, at the request of a party entitled to 

notice in the cause, for said party to have the right, at his sole cost and 

risk, to attend and monitor the initial potential testing and all subsequent 

annual testing of the proposed offpattern well to ensure proper testing. If the 

order permits witnessing of tests as prescribed above, then the order shall 

further provide that at least five days prior to the initial potential testing 

and each subsequent annual testing of the proposed well, the operator of the 

well shall notify, in writing, all parties entitled to notice in the cause who 

requested to attend and monitor these tests of the date and time upon which said 

testing shall commence.

[Source: Amended at 28 Ok Reg 1949, eff 7-11-11 (RM 201000007); Amended at 32

Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-1-25. Replacement well

(a) Approval by the Conservation Division of a Notice of Intent to Drill (Form 

1000) for a second well to be drilled in a common source of supply in a single 

drilling and spacing unit as a replacement well may be permitted when:

(1) The replacement well is to be drilled at a location permitted for the 

common source of supply by either an order or rule of the Commission; and

(2) The operator of the replacement well is either the operator or a working 

interest owner in the original unit well; and

(3) The Notice of Intent to Drill for the replacement well is accompanied by 

an affidavit from the operator, stating that on completion of the second well 

as a commercial producer, the common source of supply in the first well shall 

be plugged off immediately. The affidavit shall be attached to Notice of 

Intent to Drill.

(b) A replacement well shall not receive an allowable to produce oil or gas 

from the same common source of supply as the first well until:

(1) Said common source of supply in the original well in the drilling and 

spacing unit is plugged off; or

(2) The Commission issues an order authorizing the replacement well as an 

increased density well for said common source of supply; or

(3) The Commission issues an order reforming the drilling and spacing units 

in said common source of supply thereby placing the original well and the 

replacement well in different drilling and spacing units for the common 

source of supply.

165:10-1-26. Permitted producing well location within an enhanced recovery 

project

 Any well drilled for or used for the production of oil or gas within any 

enhanced recovery project shall be located not less than 165 feet from the lease 

or project line, whichever is the outside boundary. 

165:10-1-27. Increased density well

 Upon application after notice and hearing, the Commission may issue an order 

permitting one or more additional wells within a drilling and spacing unit, if 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 35 -

each additional well will prevent or assist in preventing the various types of 

waste prohibited by statute or if each additional well will protect or assist in 

protecting the correlative rights of interest owners in said common source of 

supply.

165:10-1-28. Geological correlation chart

 The chart initially prepared by Phillips Petroleum and maintained by the 

Oklahoma City Geologic Society entitled "Geologic Section of Oklahoma and 

Northern Arkansas", along with ensuing revisions, shall be used as a guideline 

for stratigraphic nomenclature in all oil and gas conservation applications 

which are submitted to the Commission. 

PART 7. MARKET DEMAND

165:10-1-35. Market demand [RESERVED] 

165:10-1-36. Regulation, classification, and naming of pools

(a) When the Commission finds, upon notice and hearing, that oil or gas 

production from any source of supply exceeds the current market demand therefor 

or finds that the operation of the reservoir should be regulated in order to 

prevent waste, increase ultimate recovery, or protect correlative rights, the 

Commission shall thereupon promulgate appropriate pool rules to accomplish such 

objectives. Where any of the above findings are made by the Commission, the 

total production from the pool may be restricted and equitable allocation made 

to the various wells located therein, or the operation of the reservoir may be 

otherwise regulated and controlled to insure proper and adequate conservation.

(b) Any pool may be classified or reclassified by the Commission, upon hearing, 

as an oil pool, gas pool, combination pool, or condensate pool. All pool rules 

so promulgated shall be based on operating and technical data and shall be 

consistent with the characteristics attributable to each classification.

(c) All oil and gas pools in the State shall be named by the Commission.

165:10-1-37. Determination of market demand

(a) The Commission shall instruct the Director of Conservation to determine the 

reasonable market demand for oil, gas, and other hydrocarbon products produced 

in Oklahoma for consumption in and outside the State for the ensuing proration 

period(s) that can be produced from each common source of supply on a statewide 

basis without avoidable waste and with equitable participation in production and 

markets by all operators and other interested parties.

(b) Waste, in addition to its statutory and ordinary meaning, shall include but 

not be restricted to economic waste, underground waste, surface waste, and waste 

incident to the production of oil and gas in excess of the transportation or 

marketing facilities or reasonable market demand.

(c) Reasonable market demand shall include, but not be restricted to, the 

demand for oil, gas, and other hydrocarbons for reasonable current requirements 

for current consumption and use within and outside the State, with such 

adjustment as may be necessary upward or downward to maintain adequate 

aboveground stocks of crude oil and its products and underground stocks of 

natural gas, so as to provide a continuous supply of petroleum products to the 

consumer and essential strategic supplies for national defense.

(d) In determining the reasonable market demand, the Commission may consider:

(1) Any statement communicated to the Commission by any purchaser or taker 

of oil and gas, stating the amount of oil or gas produced from common sources 

of supply that such purchaser or taker contemplates or intends to purchase 

during the period of time involved; or in lieu thereof, the capacity of the 

purchaser's transportation or marketing facilities which will be, during the

time involved, available for transporting and/or marketing the oil or gas 

that may be produced from common sources of supply.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 36 -

(2) Official records, reports, and statistical information compiled and kept 

by the Conservation Division that can be utilized in determining reasonable 

market demand.

(3) Reports, facts, and materials by the Bureau of Mines or any other 

recognized authority that impartially reflects reasonable market demand.

(4) Sworn or unsworn statements of interested parties and any other evidence 

which the Commission may deem relevant to the determination of reasonable 

market demand.

(e) For purposes of periodic market demand hearings, the Manager of Production 

and Proration for the Conservation Division shall prepare exhibits summarizing 

the nominations from the various interested parties specified in (d) in this 

Section. Said exhibits shall be available for public inspection not less than 

five days before the hearing. At the time of hearing, if no one announces any 

objection to the introduction of said exhibits, then the exhibits shall be 

admitted into evidence without need for sponsoring testimony. 

(f) After the Commission has determined the amount of oil or gas to be produced 

from all oil and/or gas pools during the following proration period, the amount 

so determined will be allocated ratably and without discrimination among the 

various pools within the State.

PART 9. PURCHASERS AND TRANSPORTERS

165:10-1-45. Purchasers and transporters [RESERVED] 

165:10-1-46. Reports of purchasers and/or transporters

 Purchasers and/or transporters of oil, waste oil, or waste oil residue, 

including truckers, shall file reports with the Commission as follows:

(1) On or before the last day of the succeeding month, transporters shall 

file a report showing monthly takings by barrels from leases in all pools 

in the State, other than wells or leases as specified in (2), (3), (4), and 

(5) of this Section; a copy of the Gross Production Tax Report made to the 

Oklahoma Tax Commission will satisfy this requirement.

(2) A report on computer generated Form 1005 showing monthly takings by 

barrels from leases or wells with capacities greater than the maximum 

allowable determined by the appropriate rule governing the classification 

of the oil pool or order of the Commission. The report shall be filed on 

or before the last day of the succeeding month.

(3) Upon request, storage and nomination information shall be filed on 

Form 1034.

(4) All truck transporters hauling crude oil shall file a report showing 

the amount of all crude oil taken by them during the preceding proration 

period, and showing the source and the disposition of the crude oil, waste 

oil, or waste oil residue. The report shall be filed on or before the last 

day of the succeeding month.

(5) All truck transporters hauling crude shall provide their drivers with 

copies of standard run tickets which must be in the possession of the 

drivers at all times and which run tickets shall show the source and the 

disposition of crude oil, including but not limited to waste oil or waste 

oil residue.

165:10-1-47. Gas volume reports to Conservation Division 

(a) On or before the last day of the succeeding month, the person responsible 

for operating the required meter under 165:10-17-5 for each well classified as 

an unallocated gas well for allowable purposes shall report to the 

Conservation Division on Form 1004 the amount of gas in MCF which passed 

through the meter on a monthly basis.

(b) If a well classified as a gas well for allowable purposes is subject to 

special pool rules other than the Guymon-Hugoton or South Guymon Fields, the 

Conservation Division shall mail Form 1005 (Monthly Allocated Schedule) to the 
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 37 -

operator of record for each such well(s) on or before the 15th day of each 

month. The operator of record shall, in turn, complete said form by listing 

the gas volume sold on a monthly basis in MCF by well and return a copy to the 

Conservation Division on or before the last day of the month succeeding the 

sales.

(c) If a well classified as a gas well for allowable purposes is subject to 

the special pool rules for the Guymon-Hugoton or South Guymon Fields, the 

Conservation Division shall mail Form 1005 (Monthly Allocated Schedule) to the 

operator of record for each such well(s) on or before the tenth day of each 

month. The operator of record shall, in turn, complete said form by listing 

the gas volume sold, including gas bought by the landowner, on a monthly basis 

in MCF by well and return a copy to the Conservation Division on or before the 

15th day of the month succeeding the sales.

(d) If there is a split connection at the well site, then the operator of 

record measuring gas volumes shall be responsible for reporting the total 

volume sold for each well.

(e) If a well classified as a gas well for allowable purposes is subject to 

special pool rules (including the Guymon-Hugoton Field), the Conservation 

Division shall mail Form 1040 to each operator on or before the tenth day of 

the second succeeding month following the custody transfer indicating the 

reported volume of gas taken from each well.

(f) If a well classified as a gas well for allowable purposes is subject to 

multiple gas purchase contracts or interest owners taking their gas in kind, 

the producing owner shall report and account to the well operator all volumes 

sold and the identity of all purchasers on or before the last day of the 

following month after sale of such gas. The operator(s) of the required 

meter(s) under 165:10-17-5 shall report and account to the well operator all 

volumes of gas measured by such meter(s) on or before the last day of the 

following month after measurement. Failure to comply with this subsection 

will result in such gas production being ordered shut-in.

(g) Failure of an operator to timely file sales volumes on Form 1005 shall 

result in a zero allowable being assigned to the operator's wells for the 

month in which the sales volumes would have been used in calculating the field 

allowable. Allocation factors for a pool shall not be recalculated as a 

result of the filing of a late Form 1005.

[Source: Amended at 12 Ok Reg 2017, eff 7-1-95]

165:10-1-48. Common purchaser and carrier rules

(a) 52 O.S., l961, Sections 54, 55, 56, and 240 are hereby adopted as common 

purchaser and common carrier rules as fully as if set out verbatim herein.

(b) No person shall purchase, take, or transport any oil or gas in excess of 

the allowable fixed by the Commission, or, when notified by the Conservation 

Division, such oil or gas being produced in violation of any rule, regulation, 

or order of the Commission; provided, this Section shall not require splitting 

a tank.

165:10-1-49. Filing of nominations

 All operators of natural gas wells in special allocated gas pools where 

well allowable calculations according to special allocated field rules are in 

effect shall file their pool nominations on Form 1034-G not later than one 

week prior to the date of the market demand hearing.

(1) Nominations shall be restricted to the volume not to exceed the 

wellhead absolute open flow (WHAOF) times calendar days for each well in a 

pool. For wells in pools where the WHAOF is not utilized, the equivalent 

well deliverability or calculated rate of flow applicable to that 

particular pool may be used in lieu of the WHAOF. For wells exempt from 

testing, nominations shall be restricted to a volume not to exceed the 

well's minimum, double minimum, or special allowable time calendar days.
OAC 165:10-1 Corporation Commission

Eff. 8-27-15

- 38 -

(2) Operators shall attach to Form 1034-G a listing of each of their 

special allocated wells by pool, OTC Lease Number, API Number, well name 

and number, and location as recorded on Form 1040, plus the applicable 

WHAOF, deliverability, or rate of flow value as determined by the 

appropriate well test for that time period. Wells exempt from testing 

shall be indicated as test-exempt on the list.

(3) Failure of an operator to properly file nominations on Form 1034-G 

shall result in a zero allowable being assigned to the operator's wells for 

the month in which the nominations would have been used in calculating the

field allowable. Allocation factors for a pool shall not be recalculated 

as a result of the filing of a late Form 1034-G.

[Source: Amended at 12 Ok Reg 2017, eff 7-1-95; Amended at 26 Ok Reg 2498, 

eff 7-11-09 (RM 200900001)]
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 39 -

SUBCHAPTER 3. DRILLING, DEVELOPING, AND PRODUCING

PART 1. DRILLING 

Section

165:10-3-1. Required approval of notice of intent to drill, deepen, re-enter, 

or recomplete; Permit to Drill 

165:10-3-2. Notification of spudding of new well 

165:10-3-3. Well casing strings

165:10-3-4. Casing, cementing, wellhead equipment, and cementing reports

165:10-3-5. Underground storage

PART 3. COMPLETIONS 

165:10-3-10. Well completion operations

165:10-3-11. Swabbing and bailing 

165:10-3-12. Leakage prevention in producing oil and gas wells

165:10-3-13. Water pollution prevention in tanks; protection of migratory 

birds

165:10-3-14. Waste of oil or gas 

165:10-3-15. Venting and flaring 

165:10-3-16. Operation in hydrogen sulfide areas 

165:10-3-17. Well site and surface facilities 

PART 5. OPERATIONS 

165:10-3-25. Completion Reports

165:10-3-26. Well logs

165:10-3-27. Deviation from the vertical

165:10-3-28. Horizontal drilling

165:10-3-29. Oil storage

165:10-3-30. Use of gas for artificial lifting

165:10-3-31. Use of vacuum at the well head

PART 7. PRODUCTION 

165:10-3-35. Multiple zone production 

165:10-3-36. Multiple zone completions 

165:10-3-37. Control of multiply completed wells 

165:10-3-38. Testing of multiply completed wells 

165:10-3-39. Commingling of production 

165:10-3-40. Production of brine

PART 1. DRILLING

165:10-3-1. Required approval of notice of intent to drill, deepen, re-enter, or 

recomplete; Permit to Drill

(a) Permit to Drill.

(1) Except as provided in (1) of this Section, on temporary authorization to 

commence, the operator shall obtain for the well a Permit to Drill approved 

by the Conservation Division before:

(A) Spudding a well for the exploration for and production of oil or gas.

(B) Spudding a well for use as an injection, disposal, or service well.

(C) Re-entry into a plugged well.

(D) Recompletion of a well.

(E) Deepening an existing well.

(2) A Permit to Drill shall be valid only for each common source of supply 

listed on the permit.

(3) Any operator who drills, deepens or reenters a well without a permit to 

drill may be fined up to $1,000.00.

(b) Amended or additional Form 1000 requirements.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 40 -

(1) When required. If the Conservation Division has issued a Permit to 

Drill for a well, the operator of the well shall submit an amended Form 1000 

for the well and obtain an amended Permit to Drill before:

(A) Completing the well in a common source of supply which is not listed 

on the current unexpired Permit to Drill for the well.

(B) Recompleting the well in a common source of supply which is not 

listed on the current unexpired Permit to Drill for the well.

(C) Installing less surface casing than the amount approved on the 

unexpired Permit to Drill for the well.

(D) Deviating from an alternative casing and cementing procedure which 

the Conservation Division approved on the unexpired Permit to Drill for 

the well.

(E) Completing a well in a common source of supply at a subsurface 

location which does not correspond with the surface location on the most 

recently issued Permit to Drill for the well.

(2) Effect of amended or additional Permit to Drill on prior Permit to 

Drill. Each approved, amended, or additional Permit to Drill for a well 

cancels any previously issued Permit to Drill for the well.

(c) Expired or revoked Permit to Drill. If a Permit to Drill for a well 

expires or is revoked, the operator shall be subject to the requirements of (a) 

of this Section.

(d) Casing and cementing requirements. Each Permit to Drill shall list the 

minimum amount of surface casing to be used or an approved alternative casing 

and cementing program under 165:10-3-4.

(e) Spud report and well spacing requirements. In addition to complying with 

the requirement of obtaining a Permit to Drill, the operator shall comply with 

the following:

(1) The spud report requirement of 165:10-3-2.

(2) Any well spacing requirements applicable by order or rule of the 

Commission. Well spacing requirements do not apply to injection or disposal 

wells.

(f) Disposal of drilling fluids.

(1) The operator shall indicate on Form 1000 the proposed method(s) for 

disposal of drilling fluids. These methods shall include, but not be limited 

to:

(A) Evaporation/dewatering and leveling of the reserve pit.

(B) Soil farming.

(C) Recycling.

(D) Commercial off-site earthen pit disposal.

(E) Annular injection.

(F) Hauling to a facility or location other than a commercial earthen 

pit.

(2) If the method in (1)(F) in this subsection is used, the operator shall 

provide the location to which the drilling fluids are to be hauled.

(3) Issuance of the Permit to Drill shall not be construed as constituting 

approval of the disposal method(s) indicated. An operator who desires to 

dispose of drilling fluids through either evaporation/dewatering and leveling 

of the reserve pit, soil farming, commercial earthen pit disposal, or annular 

injection must comply with 165:10-7-16, 165:10-7-19 or 165:10-9-2, 165:10-9-

1, or 165:10-5-13 respectively.

4) If the proposed method for drilling fluid disposal is changed, the 

operator shall notify the appropriate Conservation Division District Office, 

either by telephone, facsimile or electronic mail, within twenty-four (24) 

hours after the change. An amended Form 1000 for the well shall not be 

required for a change in disposal method.

(g) Notice to surface owners.

(1) The operator shall include on each Form 1000 submitted to the 

Conservation Division, the name and address of each surface owner of record 

for the wellsite.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 41 -

(2) For each Permit to Drill other than a Permit to Drill for a 

recompletion, the Conservation Division shall mail by regular U.S. mail a 

copy of the Permit to Drill to each surface owner listed on the Form 1000.

(h) Disapproval for noncompliance with Commission order. If an operator is not 

in compliance with an enforceable order of the Commission, the Conservation 

Division shall not issue any Permit to Drill for the operator, until the 

operator complies with the order.

(i) Erroneous approval. Erroneous issuance of a Permit to Drill shall not 

excuse noncompliance with any order or rule of the Commission.

(j) Expiration.

(1) Six-month period. Except as provided in (2) of this subsection for 

expiration after submission of a completion report, a permit to drill shall 

expire six months from the date of issuance, unless drilling operations are 

commenced and thereafter continued with due diligence to completion.

(2) Six-month extension. A six month extension may be granted without fee 

providing the Conservation Division staff determines that no material 

change of condition has occurred, if written request for such extension is 

received from the operator prior to the expiration of the original permit. 

Only one extension may be granted.

(3) If Form 1002A is filed. If the operator of the well submits to the 

Conservation Division a Completion Report (Form 1002A) for the well, the 

Permit to Drill for the well shall expire on the date the Completion Report 

is approved by the Conservation Division.

(k) Posting of Permit to Drill at the wellsite. During any activity subject to 

this Section, the operator shall maintain at the wellsite an original or legible 

copy of the Permit to Drill for inspection by Commission personnel.

(l) Temporary authorization without approval of a Permit to Drill. In an 

emergency, the Manager of the Technical Services Department of the Conservation 

Division may temporarily authorize commencement of activities without a Permit 

to Drill for a period up to five business days.

(m) Limits of authority. A Permit to Drill does not grant the operator 

authority to produce, inject or dispose without the required permits or 

allowable assignment.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended in Rule Making 

980000033, eff 7-1-99; Amended at 24 OK Reg 1790 (RM 200700004), eff 7-1-2007; 

Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28 Ok Reg 

1949, eff. 7-11-11 (RM 201000007); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 

201500001)]

165:10-3-2. Notification of spudding of new well

(a) Except as provided in (c) of this Section, the operator of a new well shall 

file with the Conservation Division a Notice of Spudding of New Well on Form 

1001A within 14 days after spudding of the well.

(b) For the purposes of (a) of this Section, spudding of a new well refers to:

(1) The first boring of the portion of the hole intended to penetrate the 

base of treatable water or a common source of supply, whichever is shallower,

in the drilling of a well for the production of oil and gas or for use as an 

injection, disposal or service well.

(2) Reentry into a previously plugged well for purposes of producing oil and 

gas or for use as an injection, disposal or service well.

(c) Filing of a Notice of Spudding of a New Well on Form 1001A shall not apply 

to:

(1) Any workover operation to deepen, plug-back, or recomplete.

(2) An unplugged hole spudded before January 9, 1986.

(3) Recompletion attempts in an unplugged hole for which a Notice of 

Spudding of New Well has been filed.

(d) In addition to the notification of spudding a new well as required in (b) 

of this Section, the operator shall notify the district office no less than 24 

hours before the first boring of the hole for setting conductor pipe used for 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 42 -

the sole purpose of near surface stabilization of the borehole when such 

operations are not continuous with spudding operations as defined in (b) of 

this Section. The notification required by this subsection may be provided in 

person, by phone, or in writing, and any written notification may be submitted 

by mail, fax, e-mail or other electronic means.

[SOURCE: Amended at 24 OK Reg 1790 (RM 200700004), eff 7-1-2007; Amended at 26 

Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-3-3. Well casing strings

(a) Owners, operators, and drilling contractors shall comply with 165:10-3-4 

and 165:10-5-2. 

(b) In the event a rupture, break, or opening occurs in any casing string, the 

owner or operator shall take immediate action to repair it and shall report the 

occurrence either by telephone or by electronic mail to the appropriate 

Conservation Division District Office or the Manager of Pollution Abatement

within twenty-four (24) hours of discovery. The owner or operator shall also 

submit a written report to the appropriate Conservation Division District Office 

within ten (10) business days containing the following information:

(1) Name of party reporting, firm name, mailing address, telephone number 

and electronic mail address.

(2) Well name and legal description.

(3) Name of operator.

(4) Date of discovery of rupture, break or opening in the casing string.

(5) Description of circumstances associated with the discovery of a rupture, 

break or opening in the casing string.

(6) Actions taken or proposed to be taken to repair the rupture, break or 

opening in the casing string.

(c) Any owner or operator who fails to timely report the discovery of a 

rupture, break, or opening in any casing string may be fined up to $5,000.00, 

and the well shall be shut down until it is repaired or plugged.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 27 Ok Reg 2128, eff. 

7-11-10 (RM 201000003); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001)]

165:10-3-4. Casing, cementing, wellhead equipment, and cementing reports

(a) Scope.

(1) This Section governs the following:

(A) Surface casing and cementing requirements.

(B) Alternate casing and cementing procedure used instead of adequate 

surface casing and cement.

(C) Minimum cementing and testing requirements for intermediate and 

production casing.

(D) Minimum valve and blowout preventer requirements.

(E) Cementing reports.

(2) This Section shall apply to the following:

(A) Wells drilled or reentered for the production of oil, gas or brine.

(B) Wells drilled or reentered for disposal of oilfield wastes.

(C) Wells drilled for enhanced recovery injection.

(D) Wells drilled in subsurface gas storage units created by order of the 

Commission.

(E) Other oilfield related service wells.

(b) Effect on area rules.

(1) If any area rules promulgated by order of the Commission require less 

casing and cement than required by this Section, then this Section shall 

supersede the area rules.

(2) If an applicable area rule promulgated by order of the Commission has 

more stringent casing and cementing requirements than what are required by 

this Section, the Conservation Division shall enforce the area rules.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 43 -

(c) Surface casing and cementing requirements for wells listed in (a)(2) of 

this Section:

(1) Minimum surface casing requirements. Unless an alternate casing program 

is authorized by the Conservation Division or by an order of the Commission, 

suitable and sufficient surface casing shall be run and cemented from bottom 

to top with a minimum setting depth which is the greater of:

(A) Ninety feet below the surface, or

(B) Fifty feet below the base of treatable water.

(2) Penalty for noncompliance. An operator setting less than the required 

amount of surface casing or failing to remediate uncirculated cement before 

resuming operations may be fined up to $5,000.00.

(3) Exceptions to (c)(1). Operators having wells producing hydrocarbons 

which were in compliance with the surface casing requirements at the time of 

completion shall not be required to comply with (1) of this subsection.

(4) Well to be used for annular injection under 165:10-5-13. If the 

operator intends to dispose of drilling or stimulation fluids by annular 

injection, then the operator shall comply with 165:10-5-13 which requires a 

surface casing string to be set not less than 200 feet below the base of 

treatable water, unless a Commission order provides otherwise.

(5) Depth limitation on setting surface casing. The well operator shall run 

and cement the surface casing string required by this subsection before 

drilling the well more than 250 feet below the base of treatable water, 

unless otherwise approved on the Permit to Drill.

(6) Penalties. Operators failing to obtain permission to drill a well more 

than 250 feet below the treatable water, or to obtain permission for an 

alternate casing and cementing procedure may be fined up to $2,500.00.

(7) Cementing procedures.

(A) Approved methods. Except as provided in (B) of this paragraph for 

bradenhead cementing, cement shall be run by either the tubing and pump 

method, the pump and plug method, or the displacement method.

(B) Bradenhead cementing prohibited. Bradenhead cementing is prohibited 

without written permission from the appropriate Conservation Division 

District Office.

(C) Restrictions on stage cementing.

(i) Above 200 feet. Running cement through small tubulars is 

permitted above 200 feet in depth without special permission.

(ii) Below 200 feet. Below 200 feet in depth, the operator shall 

obtain permission from the appropriate Conservation Division District 

Office before using small tubulars to run cement.

(D) Steel casing required. For purposes of the surface casing 

requirements of this Section, surface casing shall be oil field grade 

steel casing.

(E) Witnessing of setting of surface casing. The operator shall give at 

least 24 hours notice by telephone, facsimile or electronic mail to the 

appropriate Conservation Division District Office or Field Inspector as to 

the time when surface casing will be run.

(F) Minimum cement setup time. The cement behind the surface casing 

shall set at least eight hours before further drilling.

(G) Down-hole testing of surface casing and cement. Before drilling the 

shoe of the surface casing, the operator shall test the surface casing 

using the procedure prescribed by (g) of this Section.

(H) Failure to circulate cement or fall back of cement behind surface 

casing.

(i) Verifying the top of cement. If no conductor string is set and 

the cement did not circulate to the surface or falls back more than 

five feet, the operator shall determine the top of the cement using a 

method approved by the District Manager or Field Inspector Supervisor.

(ii) Top of cement less than 200 feet from the surface. If the top of 

the cement is found less than 200 feet from the surface, the operator 

may circulate cement to surface using small tubulars.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 44 -

(iii) Top of cement greater than 200 feet from the surface. If a 

conductor string has been set and the cement has been found to be ten 

feet or more above the base of the conductor string, no corrective 

action is required. If no conductor string has been set and the top of 

the cement is greater than 200 feet from the surface, the operator 

shall perform a corrective cementing operation by circulating cement to 

the surface from a point 50 feet below the base of the treatable water 

or from the determined top of the cement, whichever is shallower. The 

District Manager or Field Inspector Supervisor may grant permission to 

circulate cement through small tubulars.

(I) Insufficient surface casing or mechanical failure. Within 24 hours 

after discovery of a problem with the surface casing or cement, the 

operator shall notify the appropriate Conservation Division District 

Office by telephone, facsimile or electronic mail of:

(i) Any mechanical failure of the surface casing or cement.

(ii) Discovery of a treatable water formation below the shoe of the 

surface casing.

(J) Penalty. An operator, failing to report a rupture, break, or opening 

in the surface casing, may be fined up to $1,000.00 and the well shut 

down.

(K) Notice. The District Manager or Field Inspector shall be given at 

least 24 hours notice by telephone, facsimile or electronic mail prior to 

any cementing operation in order that they may have the opportunity to 

witness.

(d) Alternate casing and cementing procedures.

(1) Requirement of approval on the Permit to Drill. Use of an alternative 

casing and cementing procedure instead of surface casing and cement required 

by (c) of this Section is prohibited without authorization on the Permit to 

Drill for the well.

(2) Disapproval. The Manager of Technical Department may not issue a permit 

for an alternate casing string and cementing procedure if one or more of the 

following conditions exist:

(A) The well will penetrate a known lost circulation zone.

(B) The treatable water bearing formation(s) will be endangered.

(C) The projected depth of the well is less than 100 feet from the top of 

any authorized secondary project or gas storage facility.

(3) Applicability of other casing and cementing standards. Alternate 

casing and cementing procedures under this subsection are subject to the 

provisions of (c)(7) of this Section.

(4) Alternate casing and cementing procedure.

(A) An operator having permission to run an alternate casing string may, 

for protection of the treatable water, drill the well to casing point and 

circulate cement to the surface, or circulate cement from a depth of 100 

feet below the base of treatable water to the surface after following the 

procedures set out in (f) of this Section.

(B) Oil based drilling mud shall be prohibited.

(C) If a well is completed using an alternate casing and cementing 

procedure, a bond log covering the interval from 100 feet below the base 

of the treatable water to the surface shall be required. The District 

Manager may waive this requirement. A completion attempt, in cases where 

the protection of treatable water is questionable, is strictly prohibited.

(D) Unless extended by the District Manager, the operator shall have 72 

hours after drilling and testing is completed to run production casing or 

plug the well. A minimum of 24 hours prior notice by telephone, facsimile 

or electronic mail must be given to the appropriate Conservation Division 

District Office prior to cementing operations so that a Field Inspector 

may have the opportunity to witness the cementing or plugging procedures. 

If the well is plugged and abandoned, procedures set out in (e) of this 

Section shall be followed.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 45 -

(E) In the event that casing is run and cement does not circulate to the 

surface, or falls back, the operator shall determine the top of the cement 

using a method approved by the District Manager.

(5) Remedial actions.

(A) If the top of the cement is less than 200 feet from the surface, the 

operator may circulate cement from that point to the surface using small 

tubulars or by perforating the casing at that point and circulating cement 

to the surface.

(B) If the top of the cement is greater in depth than 200 feet, the 

operator shall perforate the casing at the top of the cement and circulate 

cement to the surface, or with the written permission of the District 

Manager or Field Inspector Supervisor, use small tubulars.

(C) In the event that a conductor string had been set and the top of the 

cement is at least ten feet above the base of the conductor casing no 

remedial action is needed.

(D) Unless waived by the appropriate Conservation Division District 

Office, all corrective cementing operations shall be approved and 

witnessed by the Field Inspector.

(E) In wells where corrective actions were needed for casing or cementing 

problems, a completion attempt shall not be made without approval by the 

District Manager.

(e) Permanent well marker. In the event that the well is a dry hole and no 

casing has been run, then during the plugging of the well the operator shall run 

and cement from bottom to top at least one joint of casing at the surface not 

less than 25 feet in length for use as a permanent well marker. The casing used 

as a well marker shall be oil field grade steel casing with an outside diameter 

of at least seven inches. The top of the marker shall be three feet below the 

surface and be capped with a steel plate inscribed or embedded with the well 

number and date of plugging on the steel plate. An operator failing to run and 

cement the well marker as required may be fined up to $1,000.00 and shall, under 

the supervision of the Commission, replug the well.

(f) Minimum cement for additional casing strings. If additional casing other 

than surface casing is run, except for temporary purposes, it shall be run, set, 

and cemented with a calculated volume of cement sufficient to fill the annular 

space behind the casing string from the base of the casing string to a minimum 

height which is the greater of five percent of the depth to which the casing 

string is set, or a height of 200 feet. Any well approved for horizontal 

completion shall be cemented with a calculated volume of cement sufficient to 

fill the annular space behind the production casing string to isolate the 

producing formation. The Conservation Division may grant a variance to this 

requirement for a horizontal well upon request.

(g) Pressure testing of casing strings.

(1) Before drilling the cement plug in a casing string, the operator shall 

pressure test the installed casing for 30 minutes at a minimum pressure which 

is the lesser of the surface gauge pressure equal in pounds per square inch 

to 0.2 of the length of the casing in feet or 1500 psig.

(2) During the 30 minute test, if the surface pressure drops ten percent or 

more, the operator shall:

(A) Repair and retest the casing until the requirements of this 

subsection are met; or

(B) Plug the well according to the rules of this Chapter.

(h) Minimum wellhead equipment for drilling wells. All reasonable and prudent 

precautions shall be taken for keeping the well under control during drilling 

operations, including but not limited to the use of blowout preventers or other 

similar equipment with appropriate pressure fittings attached to properly 

cemented casing strings and the maintenance of mud-laden fluid of sufficient 

weight to provide proper well control. A blowout preventer or other equipment 

necessary to maintain control of the well shall be installed prior to drilling 

out of the surface casing. Blowout preventers and associated equipment shall be 

maintained in good working order. Blowout preventers shall be pressure tested 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 46 -

at regular intervals, not to exceed twenty-one days, to ensure proper operation. 

A function test shall be conducted on a routine basis during drilling operations 

to ensure that annular preventers and rams will operate properly. Alternate 

testing procedures may be approved by the District Manager. The rig personnel 

shall be trained in the use of blowout prevention equipment and well control 

procedures on the rig.

(i) Cementing reports.

(1) The operator of the well shall submit, attached to Form 1002A Completion 

Report, a Form 1002C Cementing Report describing all cementing operations on 

surface, intermediate, and production casing strings, including multistage 

cementing jobs.

(2) If additional cementing operations occur after submission of the 

Cementing Report, the operator shall submit an amended Form 1002C for the 

well.

(j) Surface casing requirements for re-entry wells. For a re-entry as defined 

by 165:10-1-2, casing and cementing requirements at the time of re-entry shall 

apply.

(k) Surface casing requirement for recompletions. For a recompletion as 

defined by 165:10-1-2, casing and cementing requirements applicable to wells 

commenced on the latter of the spud date or re-entry date for the well shall 

apply.

(l) Casing and cementing requirements for wells converted for injection or 

disposal. If a well is converted for use as an injection or disposal well, it 

shall be subject to the casing and cementing requirements of this Section 

effective at the time of conversion of the well.

(m) Casing and cementing requirements for wells penetrating unitized common 

sources of supply. Each newly drilled or re-entered well which penetrates a 

common source of supply in which enhanced recovery operations are being 

conducted shall be properly cased and cemented from not less than 100 feet below 

to not less than 100 feet above each unitized common source of supply to prevent 

migration of formation fluids and contain formation pressure. In the event the 

well is to be plugged without being cased, the well shall be properly cemented 

over the aforementioned interval(s) during plugging procedures.

(n) Insufficient surface casing and cement. When it has been determined that a 

treatable water-bearing formation has not been properly cased and cemented, the 

operator shall take such measures designated by the Director of Conservation or 

ordered by the Commission to protect any treatable water-bearing formation.

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92; Amended at 26 Ok Reg 2498, eff 

7-11-09 (RM 200900001); Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); 

Amended at 28 Ok Reg 1949, eff. 7-11-11 (RM 201000007); Amended at 29 Ok Reg 

950, eff. 7-1-12 (RM 201200005); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)

165:10-3-5. Underground storage

(a) Scope. This Section shall apply to all operations pertaining to the 

drilling, completion, recompletion, or remedial work on wells located within the 

boundaries of an underground storage facility as defined in (b)(4) of this 

Section.

(b) Definitions.

(1) "Underground storage" shall mean storage of natural gas in a subsurface 

stratum or formation of the earth.

(2) "Natural gas" shall mean gas either while in its natural state or after 

the same has been processed by removal therefrom of component parts not 

essential to its use for lights and fuel.

(3) "Storage operator" shall mean any person, firm, or corporation which 

operates an underground storage facility.

(4) "Underground storage facility" shall mean any subsurface stratum or 

formation of the earth used for underground storage. Provided that, in the 

case of a natural gas bearing subsurface stratum or formation, the 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 47 -

commercially producible native gas shall have been substantially depleted and 

the gas therein shall not be used primarily for the secondary recovery of oil 

in paying quantities from the subsurface stratum or formation.

(5) "Well" means a well drilled or bored or to be drilled or bored within 

the boundaries of an underground storage facility.

(6) "Well operator" shall be the person, firm, or corporation that is the 

operator of a well.

(7) "Major remedial work" shall mean any workover operations requiring wire 

line or pump truck services.

(8) "Good quality cement" means that cement that would obtain a compressive 

strength to prevent oil, gas, or water migration within an eight (8) hour 

period.

(c) Operational procedures.

(1) Before spudding a well within the boundaries of a gas underground 

storage facility, the well operator shall mail a copy of the Permit to Drill 

to the storage operator at the address listed at the Commission. The storage 

operator will inform the well operator of the estimated depth, thickness, and 

pressure of the underground storage facility at that location. Failure of 

the storage operator to provide the data to the well operator shall not be a 

cause to delay drilling, but the well operator is required to notify the 

storage operator, by phone a minimum of 24 hours prior to commencing drilling 

operations at a 24 hour telephone number furnished to the Commission by the 

storage operator.

(2) A well operator shall comply with the provisions of 165:10-3-4(c). 

Alternate casing programs shall not be permitted.

(3) Drilling rigs shall be equipped with a blowout preventer. The preventer 

shall be installed and tested at least 500 psig above the anticipated 

underground storage facility pressure before drilling below the base of the 

surface casing.

(4) The storage operator shall receive drilling reports daily and shall be 

notified at a 24 hour telephone number furnished to the Commission by the 

storage operator in ample time to witness any tests or logging operations 

from the surface to 500 feet below the base of the underground storage 

facility. Any abnormal conditions occurring during the drilling operation, 

such as abnormal pressures and/or lost circulation, shall be reported 

immediately to the storage operator.

(5) The well operator shall drill the well in such a manner as to prevent 

invasion of drilling fluids into, or the escape of natural gas from, the 

underground storage facility. The well operator shall be required to mud up 

at least 100 feet above the anticipated depth of the underground storage 

facility.

(6) If run, a copy of either an open hole porosity or resistivity well log 

run from the base of surface casing to total depth shall be promptly 

forwarded to the storage operator. At the option of the well operator, the 

logs submitted to the storage operator may be terminated 500 feet below the 

base of the underground storage facility. The storage operator shall be 

given prior notice of logging operations of the underground storage facility 

interval and has the option of witnessing the open hole logging operation.

(7) In the event that the well is noncommercial and is to be plugged and 

abandoned, the well operator shall place a cement plug using a good quality 

cement, covering from not less than 100 feet below the base to not less than 

100 feet above the top of the underground storage facility. The storage 

operator shall be given prior notice so as to have the option of witnessing 

the plugging operation. The field inspector may invoke the provisions of 

165:10-11-6 (l), (m), and (n).

(8) In the event that casing is run, the well operator will cause the 

underground storage facility interval to be covered with steel casing and be 

cemented from not less than 100 feet below the base to not less than 100 feet 

above the top of the underground storage facility using a good quality 

cement. The Commission field inspector for the area and storage operator 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 48 -

shall be given prior notice so as to have the option of witnessing the 

operation.

(9) The well operator shall be required to run a cement bond log through the 

underground storage facility formation before any completion attempts are 

made. The storage operator shall be given prior notice so that he will have 

the option of witnessing the logging operation and be furnished with a copy 

of the bond log from the top of cement to total depth or, at the option of 

the well operator, to 500 feet below the base of the underground storage 

facility. If the integrity of the bond log is questioned by the storage 

operator, the storage operator may, at its sole risk and expense, run 

additional logs. No completion work shall be permitted until the fact has 

been established, between the parties concerned, and the district manager of 

the Commission, that the integrity of the cement is sound and that the 

underground storage facility is isolated from the remainder of the bore hole. 

The remedial work, if needed to protect the storage reservoir, shall be at 

the risk and expense of the well operator.

(10) The storage operator shall be notified in ample time to witness 

completion, recompletion, or major remedial work operations. The well site 

shall be made accessible at all times to the storage operator and all 

information pertaining to the completion shall be forwarded daily to the 

storage operator. If the completion, recompletion, or major remedial 

operations attempt is to be made in any formation within 500 feet in depth to 

the underground storage facility, the proposed plan of completion shall be 

forwarded to the storage operator ten days prior to commencement of 

operations. The storage operator shall have five days after receipt of the 

proposed plan to forward any objection to the well operator. Completion 

operations, recompletion, or major remedial operations shall not be permitted 

until the matter is resolved.

(11) At any time that the storage operator shall reasonably believe that 

damage may be occurring to the underground storage facility or that gas may 

be escaping into any other formations or otherwise believe that a well may be 

compromising the integrity of the underground storage facility, the storage 

operator may request that the operator of the well conduct specific tests 

solely at the storage operator's risk and expense. If an agreement cannot be 

obtained between the parties concerned, the storage operator may bring the 

matter before the Corporation Commission for determination by application, 

notice, and hearing following the procedure set out in OAC 165:5-7.

(12) If tests establish that damage is occurring and/or that natural gas is 

escaping by the continued operation of the well, the well shall be shut down 

immediately and the remedial operation to rectify the condition shall be 

commenced within ten days, at the sole risk and expense of the well operator.

(13) All information furnished to the storage operator shall be kept 

confidential until released in writing by the well operator.

PART 3. COMPLETIONS

165:10-3-10. Well completion operations

(a) Hydraulic fracturing and acidizing. In the completion of an oil, gas, 

injection, disposal, or service well, where acidizing or fracture processes are 

used, no oil, gas, or deleterious substances shall be permitted to pollute any 

surface or subsurface fresh water.

(b) Notice of hydraulic fracturing operations.

(1) Notice shall be given by facsimile, electronic mail or regular mail at 

least 5 business days prior to the commencement of hydraulic fracturing 

operations on a horizontal well to operators of producing wells within 1/2 

mile of the completion interval of the subject well and which are completed 

in the same common source of supply as the horizontal well.

(2) Notice shall be given by telephone, facsimile or electronic mail to the 

appropriate Conservation Division District Office or Field Inspector at least 

48 hours prior to commencement of hydraulic fracturing operations on a well. 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 49 -

(3) Separate stages of a planned multi-stage hydraulic fracturing operation 

shall not constitute separate hydraulic fracturing operations for 

notification purposes.

(c) Chemical disclosure. Within 60 days after the conclusion of hydraulic 

fracturing operations on an oil, gas, injection, disposal, or service well that 

is hydraulically fractured, the operator must submit information on the 

chemicals used in the hydraulic fracturing operation to the FracFocus Chemical 

Disclosure Registry or, alternatively, submit the information directly to the 

Commission. If the chemical disclosure information is submitted directly to 

the Commission under this subsection, the Commission will post such information 

on the FracFocus Chemical Disclosure Registry.

(1) The submission required by this subsection must include the following 

information:

(A) the name of the operator;

(B) the API number of the well;

(C) the longitude and latitude of the surface location of the well;

(D) the dates on which the hydraulic fracturing operation began and 

ended;

(E) the total volume of base fluid used in the hydraulic fracturing 

operation; 

(F) the type of base fluid used;

(G) the trade name, supplier, and general purpose of each chemical 

additive or other substance intentionally added to the base fluid; and

(H) for each ingredient in any chemical additive or other substance 

intentionally added to the base fluid, the identity, Chemical Abstract 

Service (CAS) number, and maximum concentration. The maximum 

concentration for any ingredient must be presented as the percent by mass 

in the hydraulic fracturing fluid as a whole, and is not required to be 

presented as the percent by mass in any particular additive.

(2) For purposes of this subsection, the phrase “chemical additive or other 

substance intentionally added to the base fluid” refers to a substance 

knowingly and purposefully added to the base fluid and does not include 

trace amounts of impurities, incidental products of chemical reactions or 

processes, or constituents of natural materials.

(3) The operator is not responsible for inaccurate information provided to 

the operator by a vendor or service provider, but the operator is 

responsible for ensuring such information is corrected when any inaccuracy 

is discovered.

(4) If certain chemical information, such as the chemical identity, CAS 

number, and/or maximum concentration of an ingredient, is claimed in good 

faith to be entitled to protection as a trade secret under the Uniform Trade 

Secrets Act, 78 O.S. §§85-94, the submission to the FracFocus Chemical 

Disclosure Registry may note the proprietary nature of that chemical 

information instead of disclosing the protected information to the registry. 

The submission must include the name of the supplier, service company, 

operator, or other person asserting the claim that the chemical information 

is entitled to protection as a trade secret and provide the chemical family 

name or similar descriptor for the chemical if the chemical identity and CAS 

number are not disclosed. The Commission or the Director of the Oil and Gas 

Conservation Division may require the claimant to file with the Commission a 

written explanation in support of the claim.

(5) Nothing in this subsection restricts the Commission’s ability to obtain 

chemical information under the provisions of OAC 165:10-1-6 or other 

applicable Commission rules.

(6) This subsection applies to:

(A) horizontal wells that are hydraulically fractured on or after 

January 1, 2013; and

(B) other wells that are hydraulically fractured on or after January 1, 

2014.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 50 -

(d) Rule reference guide. References to Commission rules regarding management 

of hydraulic fracturing operations are as follows:

(1) Duties and authority of the Conservation Division (OAC 165:10-1-6).

(2) Required approval of notice of intent to drill, deepen, re-enter or 

recomplete; Permit to Drill (OAC 165:10-3-1). 

(3) Surface and production casing (OAC 165:10-3-3). 

(4) Casing, cementing, wellhead equipment and cementing reports (OAC 165:10-

3-4). 

(5) Swabbing and bailing (OAC 165:10-3-11).

(6) Leakage prevention in tanks; protection of migratory birds (OAC 165:10-

3-13).

(7) Well site and surface facilities (OAC 165:10-3-17).

(8) Completion reports (OAC 165:10-3-25). 

(9) Administration and enforcement of rules (OAC 165:10-7-2).

(10) Cooperation with other agencies (OAC 165:10-7-3). 

(11) Water quality standards (OAC 165:10-7-4).

(12) Prohibition of pollution (OAC 165:10-7-5).

(13) Protection of public water supplies (OAC 165:10-7-6).

(14) Informal complaints, citations, red tags and shut down of operations 

(OAC 165:10-7-7).

(15) Scheduled monetary fines (OAC 165:10-7-9). 

(16) Use of noncommercial pits (OAC 165:10-7-16). 

(17) Surface discharge of fluids (OAC 165:10-7-17).

(18) Discharge to surface waters (OAC 165:10-7-18).

(19) One-time land application of water-based fluids from earthen pits and 

tanks (OAC 165:10-7-19). 

(20) Noncommercial disposal or enhanced recovery well pits used for 

temporary storage of saltwater (OAC 165:10-7-20).

(21) Waste management practices reference chart (OAC 165:10-7-24).

(22) One-time land application of contaminated soils and petroleum 

hydrocarbon based drill cuttings (OAC 165:10-7-26). 

(23) Application of fresh water drill cuttings by County Commissioners (OAC 

165:10-7-28). 

(24) Application of freshwater drill cuttings by oil and gas operators (OAC 

165:10-7-29). 

(25) Application to reclaim and/or recycle produced water for surface 

activities related to drilling, completion, workover, and production 

operations from oil and gas wells (OAC 165:10-7-32). 

(26) Use of commercial pits (OAC 165:10-9-1). 

(27) Commercial soil farming (OAC 165:10-9-2). 

(28) Commercial recycling facilities (OAC 165:10-9-4). 

(29) Duty to plug and abandon (OAC 165:10-11-3). 

(30) Notification and witnessing of plugging (OAC 165:10-11-4). 

(31) Plugging and plugging back procedures (OAC 165:10-11-6). 

(32) Plugging record (OAC 165:10-11-7). 

(33) Review of environmental permit applications (OAC 165:5-1-15 through OAC 

165:5-1-19)

(34) Response to citizen environmental complaints (OAC 165:5-1-25 through 

OAC 165: 5-1-30). 

(35) Contempt (OAC 165:5-19-1 through OAC 165:5-19-2).

[Source: Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 29

Ok Reg 950, eff. 7-1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff. 8-27-15 

(RM 201500001)]

165:10-3-11. Swabbing and bailing

 In swabbing, bailing, or purging a well, all deleterious substances removed 

from the borehole shall be placed in adequate pits or tanks, and no such 

substances shall be permitted to pollute any surface and subsurface fresh water.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 51 -

165:10-3-12. Leakage prevention in producing oil and gas wells

 All wellhead connections, surface equipment, and tank batteries shall be 

maintained at all times so as to prevent leakage of oil, gas, saltwater, or 

other deleterious substances.

165:10-3-13. Water pollution prevention in tanks; protection of migratory 

birds

(a) Tanks for drilling mud or deleterious substances used in the drilling, 

completion, or recompletion of wells shall be constructed and maintained so as 

to prevent pollution of surface and subsurface fresh water.

(b) The protection of migratory birds shall be the responsibility of the 

operator. Therefore, the Conservation Division recommends that to prevent the 

loss of birds due to oil, all open top tanks containing oil on the surface be 

protected from access to birds. [See Advisory Notice 165:10-7-3(c)].

165:10-3-14. Waste of oil or gas

 Except as provided in 165:10-3-15, waste of oil, condensate, or gas as 

defined in 165:10-1-2, is hereby prohibited.

165:10-3-15. Venting and flaring

(a) Conditioning a producing well without a permit. An operator may blow down

a producing well without a permit for a period not to exceed 72 hours if:

(1) Blowing down the well is necessary for efficient operation of the well 

or unexpected circumstances are encountered;

(2) Blowing down the well will not damage any producing formation in the 

well; and

(3) The operator complies with the H2S requirements of 165:10-3-16.

(b) Gas volumes less than or equal to 50 mcf/d. An operator may vent or flare 

up to 50 mcf/d without a permit if:

(1) It is not economically feasible to market the gas;

(2) A suitable stand, line, or stack is used to prevent a hazard to people; 

and

(3) H2S content of gas exceeds 100 ppm, then the gas must be flared.

(c) Permit to vent or flare gas volumes in excess of 50 mcf/d.

(1) The Conservation Division may administratively grant a permit to vent 

or flare on a daily basis gas volumes in excess of 50 mcf/d, if:

(A) The operator applies for the permit on Form 1022;

(B) The application lists the location of the well and the maximum daily 

volume of gas to be vented or flared;

(C) It is not economically feasible to market the gas; and

(D) A suitable stack, stand, or line will be used to prevent a hazard to 

people or property.

(2) The operator shall file an amended application in the event that the 

amount of gas to be vented or flared exceeds the permitted volume.

(d) Temporary permit exemption for gas vented or flared during initial flowback 

from a newly completed or recompleted well. Gas vented or flared during initial 

flowback from a newly completed or recompleted well shall be exempt from the 

permit requirements of subsection (c) for a period not to exceed 14 days, 

commencing with the first date gas flow is in excess of 50 mcf/d, if:

(1) Combustible gas flow greater than 50 mcf/d is flared;

(2) Gas with H2S content in excess of 100 ppm is flared;

(3) The operator gives at least 48 hours notice by electronic mail or 

facsimile to the appropriate Conservation Division District Office or Field 

Inspector regarding the time when the venting or flaring of gas pursuant to 

this subsection will begin;

(4) It is not economically feasible to market the gas; and

(5) A suitable stack, stand, or line will be used to prevent a hazard to 

people or property.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 52 -

(e) Gas flared after initial flowback from a newly completed or recompleted 

well. Subsequent to the 14 day initial flowback period addressed in subsection 

(d), gas flared during flowback from a newly completed or recompleted well 

shall be exempt from the permit requirements in subsection (c) for an 

additional period not to exceed 30 days if:

(1) Gas volumes flared from the well are less than or equal to an average 

rate of 300 mcf/d over the 30 day period, and one or more of the following 

conditions applies:

(A) No appropriate takeaway structure exists;

(B) The well is an exploration well; or

(C) The quality of the gas to be flared is not pipeline acceptable. 

(2) Gas with H2S content in excess of 100 ppm must be flared.

(3) A suitable stack, stand, or line must be used to prevent a hazard to 

people or property.

(4) The well operator is required to maintain a daily log of gas volumes 

flared from the well during the 30 day period. The daily log must be 

preserved for 3 years subsequent to the conclusion of the 30 day period.

The log shall be produced upon request by an authorized representative of 

the Commission.

(5) If gas volumes greater than 300 mcf/d are to be flared during flowback 

from a newly completed or recompleted well subsequent to the initial 14 day 

period addressed in subsection (d), then the operator is required to obtain 

a permit as provided in subsection (c).

(f) Application for an order permitting venting or flaring. 

(1) If the Conservation Division denies a Form 1022 application for a well, 

the operator of a well may apply for an order permitting venting or flaring 

of gas.

(2) The application and notice shall be in accordance with OAC 165:5-7.

(3) Upon application, notice, and hearing, the Commission may grant or deny 

an application made pursuant to OAC 165:5-7.

[SOURCE: Amended in Rule Making 980000033; Amended at 31 Ok Reg 977, eff. 9-

12-14 (RM 201400002)]

165:10-3-16. Operation in hydrogen sulfide areas

(a) Applicability. Each operator who conducts operations as described in this 

subsection shall be subject to this Section and shall provide safeguards to 

protect the general public from the harmful effects of hydrogen sulfide:

(1) Operations including drilling, working over, producing, injecting, 

gathering, processing, transporting, and storage of hydrocarbon fluids that 

are part of, or directly related to, field production, transportation, and 

handling of hydrocarbon fluids that contain gas in the system which has 

hydrogen sulfide as a constituent of the gas to the extent as specified in 

(b) of this Section.

(2) This Section shall not apply to:

(A) Operations involving processing oil, gas, or hydrocarbon fluids which 

are either an industrial modification or products from industrial 

modifications, such as refining, petrochemical plants, or chemical plants.

(B) Operations involving gathering, storing, and transporting stabilized 

liquid hydrocarbons.

(C) Operations where the concentration of hydrogen sulfide in the 

system is less than 100 PPM.

(b) General provisions.

(1) Each operator shall determine the hydrogen sulfide concentration in the 

gaseous mixture in the operation or system. Tests shall be made in 

accordance with industry standards or other methods approved by the 

Commission.

(2) For all operations subject to this Section, the radius of exposure shall 

be determined, except in the cases of storage tanks, by the following 

Pasquill-Gifford equations or by other methods approved by the Commission
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 53 -

such as air dispersion models accepted or approved by the U.S. Environmental 

Protection Agency:

(A) For determining the location of the 100 ppm radius of exposure: x = 

[(1.589)(mole fraction H2S)(Q)] to the power of (.6258).

(B) For determining the location of the 300 ppm radius of exposure: x = 

[(0.6743) (mole fraction H2S) (Q)] to the power of (.6258).

(C) For determining the location of the 500 ppm radius of exposure: x = 

[(0.4546)(mole fraction H2S)(Q)] to the power of (.6258); Where: x =

radius of exposure in feet; Q = maximum volume determined to be available 

for escape in cubic feet per day; H2S = mole fraction of hydrogen sulfide 

in the gaseous mixture available for escape.

(3) The volume used as the escape rate in determining the radius of exposure 

shall be that specified below as is applicable:

(A) The maximum daily volume rate of gas containing hydrogen sulfide 

handled by that system for which the radius of exposure is calculated.

(B) For existing gas wells, the current adjusted open flow rate or the 

operator's estimate of the well's capacity to flow against zero backpressure at the well head shall be used.

(C) For new wells drilled in developed areas, the escape rate shall be 

determined by using the current adjusted open-flow rate of offset wells or 

the field average current adjusted open-flow rate, whichever is larger.

(D) The escape rate used in determining the radius of exposure shall be 

corrected to standard conditions of 14.65 psia and 60 Fahrenheit.

(4) For drilling of a well in an area where insufficient data exists to 

calculate a radius of exposure but where hydrogen sulfide may be expected, 

then a 100 ppm radius of exposure equal to 3,000 feet shall be assumed. 

A lesser-assumed radius may be considered upon written request setting out 

the justification for same.

(5) As used in this Section, a public area is defined as a dwelling place, 

business, church, school, hospital, school bus stop, government building, a 

public road, all or any portion of a park, city, town, village, or other 

similar area that can reasonably be expected to be populated by humans.

(6) As used in this Section, a public street or road is defined as any 

federal, state, county or municipal street or road owned or maintained for 

public access or use.

(7) Facilities where the 100 ppm radius of exposure extends into a public 

area shall use materials for new construction, or modification of or repairs 

to existing facilities, subsequent to the effective date of this paragraph, 

selected and manufactured so as to be resistant to hydrogen sulfide stress 

cracking under operating conditions for which their use is intended. 

(A) Other materials which are non-susceptible to hydrogen sulfide stress 

cracking, such as fiberglass and plastics, may be used in hydrogen sulfide 

service provided such materials have been manufactured and inspected in a 

manner which will satisfy applicable industry standards, specifications or 

recommended practices. 

(B) Existing facilities which are in operation prior to the effective 

date of paragraph (b)(7), above, and where there has been no failure of 

existing equipment attributed to hydrogen sulfide stress cracking, shall 

satisfy the requirements of paragraph (b)(7) until such time as the 

facility experiences a failure. 

(8) The handling and installation of materials and equipment used in hydrogen 

sulfide service are to be performed in such a manner so as to prevent 

hydrogen sulfide stress cracking. 

(c) Storage tank provision. Storage tanks which are utilized as a part of a 

production operation, and which are operated at or near atmospheric pressure and 

where the vapor accumulation has a hydrogen sulfide concentration that when 

measured one (1) foot above the open tank thief hatch exceeds 500 ppm, shall be 

subject to the following:
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 54 -

(1) It shall not be necessary to determine a radius of exposure for storage 

tanks as described in this Section.

(2) A warning sign shall be posted at the facility which shall meet the 

following requirements:

(A) A sign shall be located within 50 feet of the facility and be of 

sufficient size to be readable from the road or at the entrance to the 

facility.

(B) The warning sign shall state at a minimum that hydrogen sulfide has 

been found and could be present.

(C) Signs constructed to satisfy paragraph (c)(1) shall use the language 

"Caution, Poisonous Gas May Be Present" using black and yellow colors, or 

"Danger Poison Gas (Hydrogen Sulfide)" using red and white colors or 

equivalent language. Colors shall satisfy Table 1 of American National 

Standards Institute Standard 253.1-1967. Signs installed to satisfy 

paragraph (c)(1) must be compatible with Federal Occupational Safety and 

Health regulations.

(3) A wind indicator is to be located at the tank battery site so that it 

may be seen from the entrance to the site and from the storage tanks.

(4) Fencing as a security measure is required when storage tanks are located 

inside the populated limits of a townsite or city, where conditions cause the 

storage tanks to be exposed to the public. In other areas where storage tanks 

may be considered to be a danger the Commission may require a hearing to 

establish security measures.

(5) Vapor safety.

A flare, vapor recovery system or H2S stripping system shall be installed. 

(d) Drilling, completion, workover and production operations. All operators 

whose operations are subject to this Section, and where the 100 ppm radius of 

exposure is in excess of 50 feet, shall be subject to the following:

(1) Warning and marker provision.

(A) For aboveground and fixed surface facilities, the operator shall 

post, where permitted by law, clearly visible warning signs on access 

roads or public streets, or roads which provide direct access to 

facilities located within the area of exposure.

(B) In populated areas such as townsites and cities where the use of 

signs is not considered to be appropriate, an alternative warning plan may 

be approved upon written request to the Commission.

(C) For buried lines subject to this Section, the operator shall comply 

with the following:

(i) A marker sign shall be installed at public road crossings on both 

sides of the road as close to the pipeline as possible.

(ii) Marker signs shall be installed along the line, when it is 

located within a public area or along a public road, at intervals 

frequent enough in the judgment of the operator so as to provide 

warning to avoid the accidental rupturing of line by excavation.

(iii) The marker sign shall contain the name of the operator and a 24-

hour phone number (including area code), and shall indicate by the use 

of the words "Warning", "Caution", or "Danger" and "Poison Gas" that a 

potential danger exists. Markers installed in compliance with the 

regulations of the Federal Department of Transportation shall satisfy 

the requirements of this provision. Marker signs installed prior to 

June 12, 1987 shall be acceptable provided they are in good condition 

and indicate the existence of a potential hazard.

(D) In satisfying the sign requirement of this subsection, the following 

will be acceptable:

(i) Sign of sufficient size to be readable from the road or at the 

entrance to the facility.

(ii) New signs constructed to satisfy this subsection shall refer to 

(c)(2) of this Section.

(2) Security provision.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 55 -

(A) Unattended fixed surface facilities shall be protected from public 

access when located within one-forth (1/4) mile of a public area. This 

protection shall be provided by fencing and locking, or removal of 

pressure gauges and plugging of valve openings, or other similar means. 

For the purpose of this paragraph, surface pipeline shall not be 

considered as a fixed surface facility.

(B) For well sites, fencing as a security measure is required when a well 

is located inside populated limits of a townsite or city, where conditions 

cause the well to be exposed to the public. In other areas considered to 

be a danger, the Commission may require a hearing to establish security 

requirements.

(C) The fencing provision will be considered satisfied where the fencing 

structure is a deterrent to public access.

(e) Control and equipment safety; contingency plan.

(1) Applicability; radius of exposure. All operations subject to (a) of 

this Section shall be subject to (2) and (3) of this subsection, if any of 

the following conditions apply:

(A) The 100 ppm radius of exposure is in excess of 50 feet and includes 

any part of a "public area" except a public road.

(B) The 500 ppm radius of exposure is in excess of 50 feet and includes 

any part of a "public road".

(C) The 100 ppm radius of exposure is greater than 3,000 feet.

(2) Control and equipment safety provision. Operators subject to this 

subsection shall either install safety devices and maintain them in an 

operable condition, or shall establish written safety procedures designed to 

prevent the undetected continuing escape of hydrogen sulfide. Safety devices

should be tested annually and a record kept of such tests. All pressure 

relief safety valves located within the facility shall discharge into a flare 

system. 

(3) Contingency plan provision. A contingency plan provision shall be 

developed for each drilling, producing, well servicing, and plant operation 

that could reasonably result in accidental exposure of the public to a 

concentration of hydrogen sulfide in excess of 300 ppm. The operator should 

make appropriate contacts with any public agency listed in the contingency 

plan. The contingency plan shall provide an organized plan of action for 

alerting and protecting the public. The details of a contingency plan are 

determined largely by the time required for a potentially hazardous 

concentration of hydrogen sulfide to reach a public area and by the 

population density in the public area. A copy of the contingency plan should 

be maintained at the location which lends itself best to activation of the 

plan. A copy shall be submitted to the appropriate Conservation Division

District Office.

(A) The plan shall include instructions and procedures for alerting the 

general public and public safety personnel of the existence of an 

emergency.

(B) The plan shall include procedures for requesting assistance and for 

follow-up action to remove the public from an area of exposure.

(C) The plan shall include a call list which shall include the following 

as they may be applicable:

(i) Local supervisory personnel.

(ii) County Sheriff.

(iii) Department of Public Safety.

(iv) City Police.

(v) Ambulance Service.

(vi) Hospital.

(vii) Fire Department

(viii) Contractors for supplemental equipment.

(ix) District Commission Office.

(x) Local Department of Environmental Quality Office.

(xi) Other public agencies.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 56 -

(D) The plan shall include a plat detailing the area of exposure. The 

plat shall include the locations of private dwellings or residential 

areas, public facilities, such as schools, business locations, public 

roads, or other similar areas where the public might reasonably be 

expected within the area of exposure.

(E) The plan shall include provisions for advance briefing of occupied 

dwellings within the 300 ppm radius of exposure. The following provisions 

apply:

(i) The hazards and characteristics of hydrogen sulfide.

(ii) The necessity for an emergency action plan.

(iii) Possible sources of hydrogen sulfide within the area of

exposure.

(iv) Instructions for reporting a gas leak.

(v) The manner in which the public will be notified of an emergency.

(vi) Steps to be taken in case of an emergency.

(F) In a high density population area, or where the population density 

fluctuates or is difficult to ascertain, a reaction type of plan, in lieu 

of advance briefing for public notification, will be acceptable. The 

reaction plan option must be approved by the Commission.

(G) The plan shall include names and telephone numbers of residents 

within the area of exposure, except in cases where the reaction plan 

option has been approved by the Commission.

(H) The plan shall include a list of the names and telephone numbers of 

the responsible parties for each of the possibly occupied public areas, 

such as schools, churches, businesses, or other public areas or facilities 

within the area of exposure.

(f) Training and requirement provision. Each operator shall provide appropriate 

H2S training for its employees who will be onsite. This training should 

include:

(1) Hazards and characteristics of hydrogen sulfide.

(2) Effect on metal components of the system.

(3) Operations of safety equipment and life support systems.

(4) First aid in event of an employee exposure.

(5) Use and operation of H2S monitoring equipment.

(6) Emergency response procedures to include corrective actions, shut-down 

procedures, evacuation routes, and rescue methods.

(g) Injection of fluids. Injection of fluids containing hydrogen sulfide shall 

not be allowed under the conditions specified in this Section unless first 

approved by the Commission.

(h) Venting and flaring. 

(1) Venting and flaring of gas shall be conducted in accordance with OAC 

165:10-3-15.

(2) Flaring equipment in public areas shall be designed and installed so as 

to resist hydrogen sulfide stress cracking. Existing equipment which is in 

operation prior to the effective date of this paragraph, and where there has 

been no failure attributable to hydrogen sulfide stress cracking, shall 

satisfy the requirements of this paragraph until such time as the equipment 

experiences a failure. Materials used in any new construction, or 

modification of or repair to existing equipment subsequent to the effective 

date of this paragraph shall be selected and manufactured so as to be 

resistant to hydrogen sulfide stress cracking under the conditions for which 

the use of such materials is intended. 

(3) Flare systems shall be designed so as to eliminate restrictions and low 

points creating differential pressure drops in lines which could cause 

overpressuring of tank hatches. 

(4) Flare systems with insufficient pilot fuel gas supply are required to 

have an alternate fuel gas supply or automated ignition source. 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 57 -

(5) The flare tip shall be required to extend a safe distance from the tank 

as determined in accordance with API Standard 2000 or similar industry 

practice. 

(i) Other requirements. In addition to any other requirements of this Section, 

drilling and workover operations and processing plant sites where the 100 ppm 

radius of exposure is 50 feet or greater shall be subject to the following:

(1) Protective breathing equipment shall be maintained in good operating 

condition at two or more locations at the site.

(2) Wind direction indicators shall be installed at strategic locations at 

or near the site and be readily visible from the site.

(3) Automatic hydrogen sulfide detection and alarm equipment that will warn 

of the presence of hydrogen sulfide gas in harmful concentrations shall be 

utilized at the site.

(4) The appropriate Conservation Division District Office shall be notified 

of the intention to conduct a drill stem test of a formation containing 

hydrogen sulfide in sufficient concentration to meet the requirements of this 

Section.

(j) Accident notification. Operators shall immediately notify the appropriate 

Conservation Division District Office or field inspector of any accidental 

release of hydrogen sulfide gas of sufficient volume to present a public hazard 

and hydrogen sulfide related accident resulting in death or hospitalization of 

personnel.

(k) Exception provision. Any application for exception to the provisions of 

this Section should specify the provisions to which exception is requested, and 

set out in detail the basis on which the exception is to be requested.

(l) Referenced organizations and publications. The following organizations and 

publications are referenced in this Section:

(1) ANSI - American National Standards Institute 1430 Broadway, New York, 

New York 10018; Table I, Standard 253.1-1967.

(2) API - American Petroleum Institute 300 Corrigan Tower Building, Dallas, 

Texas 75201; Publication API RP-55 and API Standard 2000.

(3) EPA - U.S. Environmental Protection Agency, Office or Air Quality 

Planning and Standards, Technical Support Division, Research Triangle Park, 

North Carolina 27711; Screen 2 Model User’s Guide.

[SOURCE: Amended at 13 Ok Reg 2395, eff 7-1-96; Amended at 15 Ok Reg 2989, eff 

7-15-98 (RM 980000013); Amended at 24 Ok Reg 1784 (RM 200700004), eff 7-1-2007; 

Amended at 25 OK Reg 2187, eff 7-11-08 (RM 200800003); Amended at 27 Ok Reg 

2128, eff. 7-11-10 (RM 201000003)]

165:10-3-17. Well site and surface facilities

(a) Scope. This Section shall be applicable to all operators and owners of oil 

and gas wells, leases, secondary recovery units, converted or newly drilled 

saltwater disposal or injection wells, and re-entries or reworkings of the 

above; however, this Section does not cover pits used in connection with oil and 

gas operations (see 165:10-7-16).

(b) Removal of fire hazards. Any material that might constitute a fire hazard 

shall be removed a safe distance from the well location, tanks, and separator. 

All waste oil shall be burned or disposed of in a manner to avoid creating a 

fire hazard.

(c) Removal of surface trash.

(1) All surface trash, debris, and junk associated with the operations of 

the property shall be removed from the premises. Equipment and material that 

may be useable and related to the operations of the property are not 

considered trash, debris and junk. With written permission from the surface 

owner, the operator may, without applying for an exception to 165:10-3-17(b), 

bury all nonhazardous material at a minimum depth of three feet; cement bases 

are included.

(2) The appropriate Conservation Division District Office or field inspector 

may issue a Form 1036 for any alleged violation of this subsection. If the 
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 58 -

operator fails to remove trash, debris, and junk after written notice, the 

Commission may fine the operator up to $1,000.

(d) Required lease signs. Within 30 days after the completion of any producing 

oil or gas well subsequent to the effective date of this Section, a sign shall 

be posted and maintained at the location indicating no trespassing, no 

unauthorized personnel or similar language, showing the operator of the well and 

the operator's twenty-four hour emergency telephone number, name of the well, 

number of the well, legal description of the well and API number; provided, 

however, where more than one well is producing on a lease, the operator may post 

and maintain a sign at the principal lease entrance indicating no trespassing, 

no unauthorized personnel or similar language, the lease name, operator, the 

operator's twenty-four hour emergency telephone number, legal description, and 

number of wells, and on each well designate the number of the well and API 

number. Within 30 days after completion or recompletion of an enhanced recovery 

injection well or a disposal well subsequent to the effective date of this 

Section, a sign shall be posted and maintained at the well location indicating 

no trespassing, no unauthorized personnel or similar language, showing the 

operator of the well, the operator's twenty-four hour emergency telephone 

number, well name, well number, legal description of the well, API number and 

the Commission order number by which it was authorized. The legal description 

of each well completed on or after March 1, 1976, shall be posted at the well 

and shall describe the location of the well to the nearest quarter quarter 

quarter section and shall show the section, township, and range. On a 160-acre 

or larger drilling and spacing unit, a sign shall also be posted at the entrance 

to the well site. Upon the Commission's approval, after the effective date of 

this Section, of transfer to a new operator of a well completed or recompleted 

prior to the effective date of this Section, the operator must comply with all 

requirements in this Section. The appropriate Conservation Division District 

Office or field inspector may issue Form 1036A for failure to post a required 

sign. If an operator fails to post a sign as directed, the Commission may fine 

the operator $50.00 per violation; provided that total fines per incident shall 

not exceed $500.00 per lease.

(e) Notice of fire or blowout. In case of a fire or blowout, the well operator 

shall notify by telephone or electronic mail, as soon as possible, either the 

Conservation Division or the appropriate Conservation Division District Office.

(f) OTC numbers on stock tanks for oil and condensate.

(1) On all oil and gas producing leases, the first purchaser of crude oil or 

condensate shall print its name or affix the company logo and print or affix 

the OTC Gross Production Division Purchaser Reporting Number on at least one 

of the storage tanks from which marketable liquids are being delivered.

(2) On all oil and gas producing leases, the well operator shall print or 

affix the OTC Gross Production Division assigned Production Unit Number and 

the OTC Gross Production Division Operator Reporting Number on at least one 

of the tanks from which marketable liquids are being stored. In the case of 

an enhanced recovery or unitization operation where several OTC Gross 

Production Division assigned Production Unit Numbers exist for the wells in 

the unit, the word "unitized" shall be printed or affixed to one of the 

storage tanks from which marketable liquids are being delivered to the 

purchaser.

(3) The identification numbers required in this subsection shall always be 

clearly legible. All letters and numbers shall be a minimum of two inches in 

height. Any operator failing to post required information may be fined up to 

$50.00 per violation; provided that total fines per incident shall not exceed 

$500.00 per well. 

(g) OTC numbers on gas meter or meter house.

(1) On all gas producing leases, the operator of the well site gas meter 

required under 165:10-17-5 shall print or affix its name and OTC reporting 

number on the outside of the meter house or on the outside of the meter 

itself if no meter house exists.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 59 -

(2) The operator of the lease shall print its OTC lease number and operator 

reporting number on the meter house or on outside of the meter if no meter 

house exists.

(3) The identification required in this subsection shall always be clearly 

legible.

(h) Valve and seals on stock tanks. The operator shall install tank valves 

such that metal identification seals can be properly utilized. These seals 

shall be used on all delivery tank valves to lessen unauthorized movement of 

marketable products.

(i) Man-ways on frac tanks. Each frac tank used at the wellsite shall have 

protective man-ways to prevent persons from accidentally falling into the frac 

tank.

(j) Guy line anchors. All guy line anchors left buried for use in future 

operations of the well shall be properly marked by a marker of bright color not 

less than four feet in height and not greater than one foot east of the guy line 

anchor.

(k) Well site cleared. Within 90 days after a well is plugged and abandoned, 

the well site shall be cleared of all equipment, trash, and debris. Any foreign 

surface material is to be removed and the location site restored to as near to 

its natural state as reasonably possible, except by written agreement with the 

surface owner to leave the surface in some other condition. If the location 

site is restored but the vegetative cover is destroyed or significantly damaged, 

a bona fide effort shall be made to restore or re-establish the vegetative cover 

within 180 days after abandonment of the well.

(l) Restored surface. Within 90 days after a lease has been abandoned, surface 

equipment such as stock tanks, heater, separators, and other related items shall 

be removed from the premises. The surface shall be restored to as near to its 

natural state as reasonably possible, except by written agreement with the 

surface owner to leave the surface in some other condition. If the surface is 

restored but the vegetative cover is destroyed or significantly damaged, a bona 

fide effort shall be made to restore or re-establish the vegetative cover within 

180 days after abandonment of the lease.

(m) Leasehold roads. All leasehold roads shall be kept in a passable condition 

and shall be made accessible at all times for representatives and field 

inspectors of the Commission. At the time of abandonment of the property, the 

area of the road shall be restored to as near to its natural state as reasonably 

possible, except by written agreement with the surface owner to leave the 

surface in some other condition. If the road area is restored but the 

vegetative cover is destroyed or significantly damaged, a bona fide effort shall 

be made to restore or re-establish the vegetative cover within 180 days after 

abandonment of the property.

(n) Extension of time.

(1) An operator may request an extension of time required in (k), (l), and 

(m) of this Section for not more than six months by applying to the 

appropriate Conservation Division District Office and showing that there is 

no imminent danger to the environment and that one of the following 

conditions exists:

(A) That an agreement with the surface owners is not possible.

(B) That adverse weather conditions exist or existed.

(C) That the equipment needed to conform to (k), (l), and (m) of this 

Section was not or is not available.

(2) If approved by the District Manager, the extension shall be granted and 

the surface owner shall be notified by the operator. Any extension beyond 

six months shall require application, notice and hearing pursuant to OAC 

165:5-7-41.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended in Rule Making 

980000034; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001); Amended at 27 

Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 30 Ok Reg 1041, eff. 7-1-13 

(RM 201300001); Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002)]
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 60 -

PART 5. OPERATIONS

165:10-3-25. Completion Reports

(a) Initial Completion Report. A Completion Report shall be filed with the 

Commission on Form 1002A within 30 days after completion of operations 

regardless of whether or not the well was completed as a dry hole, producer, 

injection, disposal, or service well. An operator who fails to file a complete 

and correct Form 1002A Completion Report within the allotted time limit may be 

fined up to $250.00.

(b) Amended Completion Report. An amended Completion Report shall be filed 

with the Commission on Form 1002A within 30 days after completion of operations 

to reenter, re-complete and/or convert to injection or disposal well regardless 

of whether or not the well was completed as a dry hole, producer, injection, 

disposal, or service well.

(c) No allowable without Completion Report. The Conservation Division shall 

not assign an allowable to a well without an up-to-date Completion Report on 

file with the Conservation Division.

(d) A completion report for any well in a multi-well system shall reference 

the primary well. An amended completion report for the primary well in a 

multi-well system shall reference all other wells in the system.

[SOURCE: Amended at 9 OK Reg 2295, eff 6-25-92; Amended at 24 Ok Reg 1794 (RM 

200700004), eff 7-1-2007; Amended at 28 Ok Reg 1949, eff 7-11-11(RM 201000007)]

165:10-3-26. Well logs

(a) 60 days to submit well log(s). All well logs required by this Section 

shall be submitted to the Conservation Division within 60 days from the earlier 

of the date of completion of the well or the date that the last formation 

evaluation type well log was run. An operator who fails to properly submit 

formation evaluation type well logs, if run, may be fined up to $250.00.

(b) Formation evaluation type well logs. This Section does not require an 

operator to run a formation evaluation type well log. However, if an operator 

does run formation evaluation type well logs, the operator shall only be 

required under this Section to submit a resistivity log and a porosity log, if 

available. Resistivity and porosity logs include but are not limited to 

spontaneous potential, induction, laterolog, density, gamma ray, neutron and 

sonic logs.

(c) Other logs to be available upon request. Any other well logs, if 

available, shall be submitted to the Technical Services Department upon 

Commission order or special request of the Conservation Division.

(d) Requirements for submitting a copy of a log. A copy of a log submitted 

under this Section shall be in digital image or a legible finished paper copy, 

complete, in one piece and with the well's legal description noted on it. If 

there are separate runs for multiple casing strings, the operator shall submit 

the separate runs.

(e) Obtaining confidential treatment of well log(s).

(1) Unless the operator requests confidential treatment of a well log(s), 

any well log(s) submitted to the Conservation Division shall be available for 

public inspection.

(2) To obtain confidential treatment of a well log, the operator of the well 

shall:

(A) Place the well log(s) in a sealed envelope with a completed Form 

1002B attached to the envelope.

(B) Submit to the Technical Services Department of the Conservation 

Division the envelope with the log(s) and Form 1002B within 60 days from 

the earlier of:

(i) The completion date of the well, or

(ii) The date that the last formation evaluation log was run.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 61 -

(3) A confidential well log under (2)(B) of this Section, shall remain 

confidential for one year from the date the last log was run on the well. 

Upon written request, the Conservation Division may administratively extend 

the period of confidentiality for six months. Under no circumstances shall 

confidentiality be granted for a period in excess of 18 months from the date 

the last log was run on the well.

(f) No allowable before submission of well logs. The Conservation Division 

shall not assign an allowable to a well before the operator of the well submits 

to the Conservation Division any well log required to be submitted under (b) of 

this Section.

[SOURCE: Amended at 9 OK Reg 2295, eff 6-25-92; Amended at 28 Ok Reg 1949, eff 

7-11-11(RM 201000007); Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002)]

165:10-3-27. Deviation from the vertical

(a) Well location for purposes of well spacing. For purposes of the well 

spacing requirements of 165:10-1-21 and 165:10-1-24, the location of a well in a 

common source of supply is the closest point to the unit boundary where the 

wellbore intersects the common source of supply.

(b) Presumed bottom hole location. For purposes of review of Form 1000 

applications, the Conservation Division may presume that the location in a 

common source of supply of a well without a horizontal drainhole is the same as 

the surface location for the well unless:

(1) The operator submits a bottom hole survey, if the well has been drilled; 

or

(2) The operator complies with (c)(1) of this Section.

(c) Permitted and prohibited locations.

(1) Offpattern surface location; permitted subsurface location.

(A) The Conservation Division may approve a Form 1000 for a well to be 

commenced without a location exception at an offpattern surface location 

for a common source of supply when:

(i) The Form 1000 lists a subsurface location which is a permitted 

location for the common source of supply.

(ii) Issuance of a Permit to Drill is conditioned on the operator 

running a bottom hole survey within 30 days after reaching total depth 

and on the operator submitting the survey to the Conservation Division 

within 45 days after the well reaches total depth.

(B) The well shall not receive an allowable for the common source of 

supply until a bottom hole survey shows that the well is at a permitted 

location or until the operator obtains a location exception order for the 

subsurface location.

(2) Offpattern subsurface location.

(A) The Conservation Division shall not approve a Form 1000 without a 

location exception order for an offpattern subsurface location.

(B) Issuance of a Permit to Drill under (1) of this subsection does not 

permit an operator to have, without a location exception order, an 

offpattern subsurface location for a common source of supply.

(d) Required directional and bottom hole surveys. For good cause, the 

Commission may order an operator to run directional and/or bottom-hole surveys 

for a common source of supply in a well: 

(1) Upon application, notice, and hearing; or

(2) In any case involving the location of a well, upon motion of an affected 

party or upon the Commission's own motion.

[SOURCE: Amended at 24 Ok Reg 1794 (RM 200700004), eff 7-1-2007]

165:10-3-28. Horizontal drilling

(a) Scope. This Section affects a horizontal well with one or more laterals.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 62 -

(b) Definitions. The following words and terms, when used in this Section, 

shall have the following meaning, unless the context clearly indicates 

otherwise:

(1) "Associated common source of supply" shall mean a common source of 

supply which is subject to a drilling and spacing unit formed by the 

Commission and located in all or a portion of the lands in which the 

completion interval of a horizontal well is located, and which is immediately 

adjoining the shale common source of supply in which the completion interval 

of the horizontal well is located, and which is inadvertently encountered in 

the drilling of the lateral of such horizontal well when such well is drilled 

out of or exits, whether on one or multiple occasions, such shale common 

source of supply.

(2) "Completion interval" shall mean, for open hole completions, the 

interval from the point of entry to the terminus and, for cased and cemented 

completions, the interval from the first perforations to the last 

perforations.

(3) "Conventional reservoir" shall mean a common source of supply that is 

not an unconventional reservoir.

(4) "Date of first production" shall mean the date hydrocarbons are first 

produced from the horizontal well, whether or not production occurs during 

drilling, completion, or through permanent surface equipment.

(5) "Directional survey" shall mean that survey or report showing the 

location of any point of the wellbore as it relates to the surveyed surface 

location from the surface to the terminus of each lateral.

(6) "Horizontal component" shall mean the calculated horizontal distance 

from the point of entry to the terminus.

(7) "Horizontal well" shall mean a well drilled, completed, or recompleted 

with one or more laterals which, for at least one lateral, the horizontal 

component of the completion interval exceeds the vertical component of the 

completion interval and the horizontal component extends a minimum of 150 

feet in the formation.

(8) "Horizontal well unit" shall mean a drilling and spacing unit 

established by the Commission, after application, notice, and hearing, for a 

common source of supply into which a horizontal well has been or will be 

drilled.

(9) "Horizontal well unitization" shall mean a unitization for a shale 

reservoir created pursuant to 52 O.S. § 87.6 et seq.

(10) "Lateral" shall mean the portion of the wellbore of a horizontal well 

from the point of entry to the terminus.

(11) "Marmaton common source of supply" shall mean a common source of supply 

located within Texas and Beaver Counties and designated as the Marmaton by 

the Commission through rule or order.

(12) "Multiunit horizontal well" shall mean a horizontal well in a targeted 

reservoir wherein the completion interval of the well is located in more than 

one unit formed for the same targeted reservoir, with the well being 

completed in and producing from such targeted reservoir in two or more of 

such units.

(13) "Non-standard horizontal well unit" shall mean a horizontal well unit 

that is not a standard horizontal well unit.

(14) "Point of entry" shall mean the point at which the borehole of a 

horizontal well first intersects the top of the common source of supply.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 63 -

(15) "Shale reservoir" shall mean a common source of supply which is a 

shale formation that is so designated by the Commission through rule or 

order, and shall also include any associated common source of supply as 

defined in this subsection.

(16) "Standard horizontal well unit" shall mean a horizontal well unit that 

is a square 10-, 40-, 160-, or 640-acre tract or a rectangular 20-, 80-, or 

320-acre tract in accordance with OAC 165:10-1-22.

(17) "Targeted reservoir" shall mean any shale reservoir or any portion of 

the Marmaton common source of supply.

(18) "Terminus" shall mean the end point of the borehole of a horizontal 

well.

(19) "True vertical depth" shall mean that depth at the point of entry 

perpendicular to the surface as measured from the elevation of the kelly 

bushing on the drilling rig.

(20) "Unconventional reservoir" shall mean a common source of supply that is 

a shale or a coal bed. "Unconventional reservoir" shall also mean any other 

common source of supply designated as such by Commission order or rule.

(21) "Vertical component" shall mean the calculated vertical distance from 

the point of entry to the terminus of the lateral.

(c) General horizontal well requirements.

(1) Within 30 days after completion of a horizontal well, the operator shall 

show that the location of the completion interval complies with the 

applicable general rule, location exception order, or other order of the 

Commission by submitting the following to the Technical Services Department:

(A) A directional survey run in the horizontal well.

(B) A plat constructed from the results of the directional survey showing 

the completion interval.

(2) The completion interval of an oil and or gas horizontal well shall be 

located not closer than the minimum distance as set out below from any other 

oil or gas well completed in the same common source of supply except as 

authorized by a special order of the Commission:

(A) Three hundred feet from any other oil or gas well completed in the 

same common source of supply, the top of which is less than 2,500 feet in 

true vertical depth.

(B) Six hundred feet from any other oil or gas well completed in the same 

common source of supply, the top of which is 2,500 feet or more in true 

vertical depth.

(C) This paragraph does not apply to horizontal wells drilled in a unit 

created for secondary or enhanced recovery operations pursuant to 52 O.S. 

§ 287.1 et seq. or to horizontal wells drilled in a horizontal well 

unitization created pursuant to 52 O.S. § 87.6 et seq.

(3) The perforated interval of an oil or gas non-horizontal well shall be 

located not closer than the minimum distance as set out below from the 

completion interval of any oil or gas horizontal well completed in the same 

common source of supply, except as authorized by a special order of the 

Commission:

(A) Three hundred feet from any completion interval of any oil or gas 

horizontal well completed in the same common source of supply, the top of 

which is less than 2,500 feet in true vertical depth.

(B) Six hundred feet from any completion interval of any oil or gas 

horizontal well completed in the same common source of supply, the top of 

which is 2,500 feet or more in true vertical depth.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 64 -

(C) This paragraph does not apply to non-horizontal wells drilled in a 

unit created for secondary or enhanced recovery operations pursuant to 52 

O.S. § 287.1 et seq.

(d) Horizontal well requirements in an unspaced common source of supply. In a 

horizontal well drilled in a common source of supply in which the Commission has 

not established any drilling and spacing units or horizontal well units, the 

completion interval of a horizontal well may not be located closer to the 

boundaries of the applicable mineral estate, oil and gas leasehold estate, or 

voluntary unit than the minimum distance set out below except as authorized by a 

special order of the Commission:

(1) Not less than 165 feet when the top of the common source of supply is 

less than 2,500 feet in true vertical depth.

(2) Not less than 330 feet when the top of the common source of supply is 

2,500 feet or more in true vertical depth.

(e) Drilling and spacing units.

(1) A horizontal well may be drilled on any drilling and spacing unit.

(2) A horizontal well unit may be created in accordance with 165:10-1-22 and 

165:5-7-6. Such units shall be created as new units after notice and hearing 

as provided for by the Rules of Practice, OAC 165:5.

(3) The Commission may create a non-standard horizontal well unit covering 

contiguous lands in any configuration or shape deemed by the Commission to be 

necessary for the development of a conventional reservoir or an 

unconventional reservoir by the drilling of one or more horizontal wells. A 

non-standard horizontal well unit may not exceed 640 acres plus the 

tolerances and variances allowed pursuant to 52 O.S. § 87.1.

(4) A horizontal well unit may be established for a common source of supply 

for which there are already established non-horizontal drilling and spacing 

units, and said horizontal well unit may include within the boundaries 

thereof more than one existing non-horizontal drilling and spacing unit for 

the common source of supply. Upon the formation of a horizontal well unit 

that includes within the boundaries thereof one or more non-horizontal 

drilling and spacing units, the Commission shall provide that such horizontal 

well unit exists concurrently with one or more of such non-horizontal 

drilling and spacing units, and each such unit may be concurrently developed.

(f) Horizontal well location requirements for horizontal well units and 

horizontal well unitizations.

(1) Conventional reservoirs. In a conventional reservoir, the completion 

interval of a horizontal well in a horizontal well unit shall be located not 

less than the minimum distance from the unit boundary as follows:

(A) Not less than 165 feet from the boundary of any 10-, 20-, or 40-acre 

horizontal well unit.

(B) Not less than 330 feet from the boundary of any 80- or 160-acre 

horizontal well unit.

(C) Not less than 660 feet from the boundary of any 320- or 640-acre 

horizontal well unit.

(2) Unconventional reservoirs. In an unconventional reservoir, the 

completion interval of a horizontal well in a horizontal well unit shall be 

located not less than the minimum distance from the unit boundary as follows:

(A) Not less than 165 feet from the boundary of any 10-, 20-, or 40-acre 

horizontal well unit.

(B) Not less than 330 feet from the boundary of any 80-, 160-, 320-, or 

640-acre horizontal well unit.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 65 -

(3) Horizontal well unitizations. The completion interval of a horizontal 

well in a horizontal well unitization shall not be located less than 330 feet 

from the unit boundary.

(g) Alternative well location requirements. The Commission may establish well 

location requirements different from those provided in subsection (f) of this 

Section when necessary to prevent waste and protect correlative rights. These 

requirements may be established in the order creating a standard or nonstandard horizontal well unit or through a special rule of the Commission 

covering a conventional or unconventional reservoir in a designated geographic 

area. (see OAC 165:10, Subchapter 29, Special Area Rules).

(h) Allowable. 

(1) Horizontal oil well allowables may be established administratively using 

the standard allowables provided in Appendix A (Allocated Well Allowable 

Table) supplemented by the additional allowables provided in Appendix C 

(Table HD) to this Chapter.

(2) The allowable for a horizontal gas well shall be computed in the manner 

prescribed for a non-horizontal gas well in the same common source of supply.

(3) The allowable for a horizontal well unit or horizontal well unitization 

with multiple horizontal gas wells shall be the sum of the allowables for the 

separate horizontal gas wells. For this summation, the allowable for each 

horizontal gas well will be calculated as if it were the only well in the 

unit.

(4) The allowable for a multiunit horizontal well shall be allocated to each 

affected unit using the allocation factors determined in accordance with 52 

O.S. § 87.8(B)(1). 

(i) Pooling. Horizontal well units, horizontal well unitizations and multiunit 

horizontal wells may be pooled as provided in 52 O.S. § 87.1, 52 O.S. § 87.6 

et seq. and Commission Rules of Practice, OAC 165:5.

[Source: Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28

Ok Reg 1894, eff. 5-19-11 (emergency RM 201100004); Amended at 28 Ok Reg 1949, 

eff. 7-11-11 (RM 201000007); Amended at 29 Ok Reg 950, eff. 7-1-12 (RM 

201200005); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001); Amended at 31

Ok Reg 977, eff. 9-12-14 (RM 201400002); Amended at 32 Ok Reg 767, eff. 8-27-15

(RM 201500001)]

165:10-3-29. Oil storage

 Oil storage tanks shall be constructed so as to prevent leakage. Dikes or 

retaining walls, where necessary, shall be constructed, based on tank capacity 

and throughput, so as to prevent oil or deleterious substances from causing 

pollution and to ensure public safety.

[SOURCE: Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-3-30. Use of gas for artificial lifting

(a) Use of gas for artificial lifting of oil. Gas may be used for the 

artificial lifting of oil; provided, all gas returned to the surface with the 

oil is not vented or otherwise wasted

(b) The use of production. The use of production from one common source of 

supply to assist in lifting the production from another common source of supply 

by commingling the production from both common sources of supply in the tubing 

string shall be permitted when the operator has authority to commingle the 

production in the tubing.

(c) Use of artificial lift. Artificial lift, initial or subsequent, in 

conjunction with the separate orifice or choke assembly shall be governed by OAC 

165:10-3-37.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 66 -

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]

165:10-3-31. Use of vacuum at the well head. 

(a) Prohibited without a permit. Imposing a vacuum on an oil or gas bearing 

formation is prohibited without a permit from the Commission.

(b) Requirement. A vacuum shall not be approved unless it can be shown that 

use of a vacuum as permitted will prevent waste and protect correlative rights.

(c) Application for a permit. Each application for a permit requesting use of 

a vacuum on a common source of supply shall be filed with the Technical Services 

Department on Form 1022A. The following information shall accompany the 

application:

(1) A plat, color coded as to producing zone, showing the locations of all 

producing wells within one-half (1/2) mile of the well location.

(2) An electric well log of the subject well, if available; otherwise a 

drillers log concerning the subject well shall be provided.

(d) A copy of the application shall be served, by regular mail, or delivered 

to each operator of a producing leasehold within one-half (1/2) mile of the 

well location. An affidavit reflecting that the required notice was provided 

shall be filed within five (5) days of filing of the application.

(e) Notice is not required to be published if no written objection to the 

application is filed or if no hearing is required by the Commission pursuant to 

subsection (f), below.

(f) If a written objection to the application is filed within fifteen (15) 

days after the application is filed or if hearing is required by the 

Commission, then the application shall be set for hearing, and notice thereof 

shall be given in the same manner specified in OAC 165:5-7-1. If no objection 

is filed and the Commission does not require a hearing, the matter shall be 

reviewed administratively by the Director of the Oil and Gas Conservation 

Division or the Director’s designee. If the Oil and Gas Conservation Division 

denies an application, the applicant may request a hearing on said application.

(g) Records required to be kept by the operator.

(1) If an operator obtains a permit authorizing use of a vacuum, the 

operator shall make a record on a monthly basis of:

(A) The vacuum imposed in pounds per square inch or inches of mercury.

(B) The amount of gas, oil and water production per day from the well.

(2) Any record required to be kept under this Section shall be made 

available to the Oil and Gas Conservation Division upon request.

[SOURCE: Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003)]

PART 7. PRODUCTION

165:10-3-35. Multiple zone production

(a) Production from more than one common source of supply from a single well is 

hereby prohibited except as authorized by the Conservation Division.

(b) For the purpose of this Section, completion of a well so as to separately 

produce or account for the production from two or more common sources of supply 

shall be a multiple completion, and the production from more than one common 

source of supply without segregation of the production shall be commingling. 

(c) Any operator violating this Section shall be subject to a fine of $500.00. 

The Conservation Division may shut down a multiply completed well pending 

compliance with this Section.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended in Rule Making 

980000033, eff 7-1-99]

165:10-3-36. Multiple zone completions
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 67 -

(a) Each application for the approval of the multiple completion of a well 

shall be filed with the Technical Services Department on Form 1023.

(b) A copy of the application shall be mailed or delivered to each operator of a

producing leasehold within one-half (1/2) mile of the well location. The 

applicant shall file an affidavit of delivery or mailing not later than five (5) 

days after the application is filed. 

(c) If a written objection to the application is filed within fifteen (15) days 

after the application is filed, or if hearing is required by the Commission, the 

application shall be set for hearing and notice thereof shall be given as the 

Commission shall direct. If no objection is filed and the Commission does not 

require a hearing, the matter shall be reviewed administratively by the Director 

of Conservation or his designee. If the Conservation Division denies an 

application, the applicant may request a hearing on said application. 

[SOURCE: Amended at 16 Ok Reg 2206, eff 7-1-99 (RM 980000033); Amended at 24 Ok 

Reg 1795 (RM 200700004), eff 7-1-2007; Amended at 25 OK Reg 2187, eff 7-11-08 

(RM 200800003)]

165:10-3-37. Control of multiply completed wells

(a) Every multiply completed well shall be equipped, operated, produced, and 

maintained so that there will be no commingling of the production from separate 

common sources of supply in the well, except as hereinafter provided. The 

production from each common source of supply shall be separately accounted for 

or separately stored and measured on the lease. The production shall be 

measured by either:

(1) A positive displacement dump-type device;

(2) A continuous-flow measuring device; or

(3) A measuring device of any other type authorized by the Commission.

(b) Each application for the approval of production through a multiple choke 

assembly in a well shall be filed with the Technical Services Department on Form 

1023. The multiple choke assembly must be so designed and located in the 

wellbore as to prevent commingling within the common sources of supply, but to 

permit commingling in the tubing string through individual choke orifices. The 

commingled production shall be measured at the surface and allocated to each 

common source of supply.

(c) A copy of the application shall be mailed or delivered to each operator of a 

producing leasehold within one-half (1/2) mile of the well location. The 

applicant shall file an affidavit of delivery or mailing not later than five days 

after the application is filed. 

(d) If a written objection to the application is filed within 15 days after the 

application is filed, or if hearing is required by the Commission, the 

application shall be set for hearing and notice thereof shall be given as the 

Commission shall direct. If no objection is filed and the Commission does not 

require a hearing, the matter shall be reviewed administratively by the Director 

of Conservation or his designee. If the Conservation Division denies an 

application, the applicant may request a hearing on said application.

[SOURCE: Amended at 16 OK Reg 2206, eff 7-1-99 (RM 980000033); Amended at 24 Ok 

Reg 1795 (RM 200700004), eff 7-1-2007; Amended at 25 OK Reg 2187, eff 7-11-08 

(RM 200800003)]

165:10-3-38. Testing of multiply completed wells

The Conservation Division may at any time require a multiply completed well 

to be tested to determine the effectiveness of the separation of common sources 

of supply. The tests may be witnessed by representatives of the Conservation 

Division and may be witnessed by any offset operator. Testing procedures must 

be acceptable to a representative of the Conservation Division.

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 68 -

165:10-3-39. Commingling of production

(a) Commingling permit required.

(1) Commingling of production from a well from separate common sources of 

supply is prohibited without a permit. A permit shall be required when 

production is from more than one source of supply, without segregation of the 

production in the wellbore, or is produced separately in the wellbore and 

then combined together downstream of the wellhead prior to measurement. 

Commingling downstream of the wellhead shall require Form 1024 (Packer 

Setting Affidavit) and Form 1025 (Packer Leakage Test) to be filed and 

approved. The Commission may assess a fine up to $500.00 for non-permitted 

commingling either down hole or downstream prior to measurement.

(2) Each application for the approval of the commingling of a well shall be 

filed with the Technical Services Department on Form 1023. The following 

shall be filed with the application:

(A) A well log section with top and bottom of open intervals marked.

(B) A schematic of the proposed completion configuration of the well.

(C) A plat showing the locations of all wells producing from the same 

common sources of supply within one-half (1/2) mile radius of the subject 

well.

(3) A copy of the application shall be served, by regular mail, or delivered 

to each operator of a producing leasehold within one-half (1/2) mile of the 

well location. An affidavit of mailing shall be filed within five (5) days 

of filing of the application. No notice is required to be published. 

(4) If a written objection to the application for a commingling permit is 

filed within 15 days after the application is filed, or if hearing is 

required by the Commission, the application shall be set for hearing, and 

notice thereof shall be given as the Commission shall direct. If no 

objection is filed and the Commission does not require a hearing, the matter 

shall be reviewed administratively by the Director of Conservation or his 

designee. If the Conservation Division denies an application, the applicant 

may request a hearing on said application. 

(b) Restrictions.

(1) Commingling shall only be authorized when it would prevent waste and 

protect correlative rights.

(2) Commingling shall be prohibited where one producing zone is 

predominately gas and a second zone is predominately oil, unless the operator 

can verify in writing, submitted with the application, that no cross flow 

will occur resulting in reservoir damage.

(c) Commingled allowables.

(1) Single allowable for commingled production. Common sources of supply 

commingled under this Section receive a single allowable as if they 

constituted a single common source of supply in the wellbore.

(2) Gross daily allowable for commingled production. The gross daily 

allowable shall be based on the classification of the well as an oil or gas 

well for allowable purposes under OAC 165:10-13-2.

(A) Unallocated oil well (GOR < 15,000:1). The gross daily allowable 

shall be based on what would be the allowable if commingled production 

comes from the deepest commingled common source of supply.

(B) Unallocated gas well (GOR > 15,000:1). The gross daily allowable 

shall be a single unallocated gas allowable, as determined by OAC 165:10-

17-11(c). Upon request in a commingling application or in any other

appropriate application and upon proper notice thereof, the Commission may 

designate in a commingling permit or other appropriate order the specific 

gas formation, completed and producing in the applicable well, to which 

the allowable for such well is to be attributed when the Commission 

determines that such designation is necessary to prevent waste and to 

protect correlative rights.

(C) Special allocated gas pool. The gross daily allowable shall be based 

on what would be the allowable if the commingled production came from the 

special allocated gas pool in the well.
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 69 -

(3) Operator option if multiple pool rules exist. If more than one common 

source of supply under a commingling permit or appropriate order for a gas 

well is subject to gas pool rules, the order shall designate which set of 

pool rules is applicable for allowable purposes.

(4) Net daily allowable. The net daily allowable is the gross daily 

allowable under (3) of this subsection:

(A) Reduced accordingly by any penalty against any of the commingled 

common sources of supply under the permit or appropriate order.

(B) Reduced accordingly by any overage carried forward against a 

commingled common source of supply.

(C) Increased by any underage carried forward for the well under 

applicable allocated or special allocated pool rules.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 16 Ok Reg 2206, eff 

7-1-99 (RM 980000033); Amended at 24 Ok Reg 1796 (RM 200700004), eff 7-1-2007; 

Amended at 25 Ok Reg 2187, eff 7-11-08 (RM 200800003); Amended at 28 Ok Reg 

1949, eff 7-11-11 (RM 201000007)]

165:10-3-40. Production of brine

(a) All wells in excess of 300 feet in depth and producing brine for the 

extracting of minerals shall be under the full jurisdiction of the Conservation 

Division.

(b) The establishment of a unitized area for the purpose of efficient 

operations, prevention of waste, and the protection of correlative rights may be 

formed by following the procedures set out in 165:5-7-21

(c) Category B surety shall be a requirement for all brine producing wells or 

units. [See 165:5-7-21(f)]
OAC 165:10-3 Corporation Commission

Eff. 8-27-15

- 70 -

[Blank Page]
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 71 -

SUBCHAPTER 5. UNDERGROUND INJECTION CONTROL 

Section

165:10-5-1. Classification of underground injection wells 

165:10-5-2. Approval of enhanced recovery injection wells or disposal wells

165:10-5-3. Authorization for existing enhanced recovery injection wells and 

existing disposal wells 

165:10-5-4. Application for approval of enhanced recovery projects 

165:10-5-5. Application for approval of enhanced recovery injection and 

disposal operations 

165:10-5-6. Testing and monitoring requirements for enhanced recovery 

injection wells and disposal wells 

165:10-5-7. Monitoring and reporting requirements for wells covered by 

165:10-5-1

165:10-5-8. Liquid hydrocarbon storage wells 

165:10-5-9. Duration of underground injection well orders or permits 

165:10-5-10. Transfer of authority to inject 

165:10-5-11. Notarized reports 

165:10-5-12. Application for administrative approval for the subsurface 

injection of onsite reserve pit fluids 

165:10-5-13. Application for permit for one time injection of reserve pit 

fluids

165:10-5-14. Exempt aquifers

165:10-5-15. Application for permit for simultaneous injection well

165:10-5-1. Classification of underground injection wells

 Underground injection wells shall be classified as follows:

(1) Enhanced recovery injection well. An enhanced recovery injection well 

is a well which injects fluids to increase the recovery of hydrocarbons. 

(2) Disposal well. A disposal well is a well which injects, for purposes 

other than enhanced recovery, those fluids brought to the surface in 

connection with oil or natural gas production.

(3) Storage well. A storage well is a well used to inject, for storage 

purposes, hydrocarbons which are liquid at standard temperature and pressure.

(4) Simultaneous injection well. A well that injects or disposes of salt 

water at the same time it is producing oil and/or gas to the surface.

[SOURCE: Amended at 13 Ok Reg 2387, eff 7-1-96]

165:10-5-2. Approval of enhanced recovery injection wells or disposal wells

(a) The subsurface injection or disposal of any substance for any purpose is 

prohibited except upon approval of the Commission pursuant to 165:10-5-5 or 

165:10-5-12 and 165:10-5-13. This authorization may be conditioned upon the 

applicant taking corrective action to protect treatable water as specified by 

the Commission. The Commission may fine an operator up to $5,000.00 for any 

violation of this subsection.

(b) Except as provided in (c) and (d) in this Section, every well used for 

injection or disposal shall be cased and tested in accordance with 165:10-3-4 

and 165:10-5-6.

(c) The testing requirements of 165:10-5-6 shall not apply to wells permitted 

by Commission order for subsurface injection of onsite reserve pit fluids.

(d) The Conservation Division may approve a Form 1015 application to convert 

for injection or disposal an existing well which does not comply with 165:10-3-4 

if:

(1) The operator attaches to the Form 1015 application a description of an 

alternate method of protecting treatable water.

(2) The Conservation Division approves the proposed alternate method.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 72 -

(3) The application is filed in accordance with OAC 165:5-7 if a hearing is 

required.

(4) The application is not protested.

(e) Any newly drilled or newly converted injection or disposal well which is 

within one-half (1/2) mile of any public water supply well shall not be approved 

without notice and hearing, and the Commission shall not issue an order 

authorizing injection or disposal into said well until the applicant proves by 

substantial evidence that said well shall not pollute said water supply well. A 

commercial disposal well shall not be approved within a designated wellhead 

protection area.

[SOURCE: Amended at 9 Ok Reg 2295; Amended at 9 Ok Reg 2337, eff 6-25-92; 

Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001); Amended at 32 Ok Reg 767, 

eff 8-27-15 (RM 201500001)]

165:10-5-3. Authorization for existing enhanced recovery injection wells and

existing disposal wells

(a) Each enhanced recovery injection well authorized under order of the 

Commission on the effective date of this Section is an existing enhanced 

recovery injection well. Injection is prohibited in any existing enhanced 

recovery injection well unless the operator has included that well on a 

completed Form 1070 submitted to the Commission within one year following the 

effective date of this Section. Form 1070 (Inventory of Authorized Existing 

Enhanced Recovery Injection Wells) shall include each well name, location, 

authorizing Commission order number (including all orders authorizing 

exceptions), date of order, maximum authorized injection rate, and maximum 

authorized injection pressure. 

(b) Each disposal well being operated under order of the Commission on the 

effective date of this Section is an existing disposal well. Injection is 

prohibited in any existing disposal well unless the operator has included that 

well on a completed Form 1071 submitted to the Commission within one year 

following the effective date of this Section. Form 1071 (Inventory of 

Authorized Existing Disposal Wells) shall include each well name, location, 

authorizing Commission order number (including all orders authorizing 

exceptions), date of order, maximum authorized injection rate, and maximum 

authorized injection pressure. 

165:10-5-4. Application for approval of enhanced recovery projects

(a) An enhanced recovery project shall be permitted only by order of the 

Commission after notice and hearing. 

(b) The application for an order authorizing an enhanced recovery project shall 

contain the following: 

(1) The names and addresses of the operator or operators of the project.

(2) A plat showing the lease, group of leases, or unit included within the 

proposed project; the location of the proposed injection well or wells, and 

the location of all oil and gas wells including abandoned and drilling wells 

and dry holes; and the names of all operators offsetting the area encompassed 

within the project.

(3) The common source of supply in which all wells are currently completed.

(4) The name, description, and depth of each common source of supply to be 

affected.

(5) A log of a representative well completed in the common source of supply.

(6) A description of the existing or proposed casing program for injection 

wells and the proposed method of testing casing.

(7) A description of the injection medium to be used, its source, and the 

estimated amounts to be injected daily.

(8) For a project with an allocated pool, a tabulation showing recent gasoil ratio and oil and water production tests for each of the producing oil 

and gas wells.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 73 -

(9) The proposed plan of development of the area included within the 

project.

(c) A copy of the application and notice of hearing shall be mailed to the 

owner or owners of the surface of the land upon which the project is located and 

to each operator offsetting the project as shown on the application within five 

days after the application is filed. An affidavit of compliance with this 

Section shall be filed on or before the hearing.

165:10-5-5. Application for approval of enhanced recovery injection and

disposal operations

(a) Application. Each application for the approval of a newly drilled or 

newly converted injection well, disposal well, or commercial disposal well 

shall be filed with the UIC Department on Form 1015 and shall be verified by a 

duly authorized representative of the operator.

(b) Application. The application for the approval of an enhanced recovery 

injection or disposal well(s) shall be accompanied by:

(1) Plat.

(A) Noncommercial disposal well. A plat showing the location and total 

depth of the well(s) and each abandoned, producing or drilling well, and 

dry hole within one-quarter (1/4) mile of the enhanced recovery injection 

well or disposal well, and identifying the surface owner of the land on 

which the enhanced recovery injection or disposal well is to be located, 

and each operator of a producing spacing unit or well within one-half 

(1/2) mile of each enhanced recovery injection or disposal well with a 

requested injection rate of less than five thousand barrels per day, and 

each operator of a producing spacing unit or well within one (1) mile of 

each enhanced recovery injection or disposal well with a requested 

injection rate of five thousand barrels per day or more.

(B) Commercial disposal well. A plat showing the location and total 

depth of the well(s) and each abandoned, producing or drilling well and 

dry hole within one-half (1/2) mile of the disposal well, and identifying 

the surface owner of the land on which the disposal well is to be 

located, and each operator of a producing spacing unit or well within one 

(1) mile of each disposal well.

(2) Completion Report. If the well has been drilled, a copy of the 

Completion Report (Form 1002A) and any available electric or radioactivity 

log of the well.

(3) Schematic diagram. A schematic diagram of the well showing:

(A) The total depth or plugback depth of the well.

(B) The depth of the injection or disposal interval indicating both the 

top and bottom.

(C) The geological name of the injection or disposal zone.

(D) The depths of the tops and bottoms of the casing and cement to be 

used in the well.

(E) The size of the casing and tubing, and the depth of the packer.

(4) Proposed zone information. Information showing that injection into the 

proposed zone will not initiate fractures through the overlying strata which 

could enable the injection fluid or formation fluid to enter fresh water 

strata.

(A) When the fluid injection rate is 1,000 barrels per day or less, or 

equivalent rate for any fraction of twenty-four (24) hours, an overlying 

strata of at least 200 feet in thickness between the lowest base of fresh 

water and the top of the proposed interval of injection is considered 

sufficient evidence of fresh water protection.

(B) When the fluid injection rate is greater than 1,000 barrels per day 

or equivalent rate for any fraction of twenty-four (24) hours, an 

overlying strata of at least 500 feet in thickness between the lowest 

base of fresh water and the top of the proposed interval of injection is 

considered sufficient evidence of fresh water protection.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 74 -

(C) lf the overlying strata is less than required in (A) and (B) of this 

paragraph, the Commission may administratively approve injection provided 

a finding is made that such injection will not initiate fractures through 

the overlying strata into the fresh water strata. Applicant is required 

to furnish to the Commission, sworn evidence and data in support of such 

findings. The Commission, when issuing an order approving fluid 

injection, shall consider the following:

(i) Maximum injection rate.

(ii) Maximum surface injection pressure.

(iii) lnjection fluid.

(iv) The lithology and rock characteristics of the injection zones 

and overlying strata.

(5) Proposed operating data:

(A) Daily injection rates and pressures.

(B) Geologic name, depth, and location of injection fluid source.

(C) Qualitative and quantitative analysis of fresh water from two (2) or 

more fresh water wells within one (1) mile of the proposed enhanced 

recovery injection or disposal well showing location of wells and dates 

samples were taken, or statement why samples were not submitted. The 

analysis shall include at a minimum chloride, sodium, and total dissolved 

solids.

(D) Qualitative and quantitative analysis of representative sample of 

water to be injected. The analysis shall include at a minimum chloride, 

sodium, and total dissolved solids.

(c) Application for approval. A copy of the application for approval of 

injection or disposal of water or other substances in a well shall be served by 

the applicant within five (5) days of the date the application is filed by 

regular mail or delivered to the following:

(1) The owner of the surface of the land on which the proposed injection 

or disposal well is to be located;

(2) For a proposed commercial disposal well, to each surface owner and 

surface lessee of record on each tract of land adjacent and contiguous to 

the site of the proposed well;

(3) For a noncommercial injection or disposal well with a requested 

injection rate of less than five thousand (5,000) barrels per day, to each 

operator of a producing spacing unit or well within one-half (1/2) mile of 

such proposed well;

(4) For a noncommercial injection or disposal well with a requested 

injection rate of five thousand (5,000) barrels per day or more, or a 

commercial disposal well, to each operator of a producing spacing unit or 

well within one (1) mile of such proposed well; 

(5) For a noncommercial horizontal injection or disposal well with a 

requested injection rate of less than five thousand (5,000) barrels per day, 

to each operator of a producing spacing unit or well within one-half (1/2) 

mile of the lateral of such proposed well; and

(6) For a noncommercial horizontal injection or disposal well with a 

requested injection rate of five thousand (5,000) barrels per day or more, 

or a horizontal commercial disposal well, to each operator of a producing 

spacing unit or well within one (1) mile of the lateral of such proposed 

well.

(d) Notice of application. Notice of an application relating to injection, 

disposal or commercial wells shall be published one time for injection and 

noncommercial disposal wells and two times for a commercial disposal well in a 

newspaper of general circulation published in Oklahoma County, Oklahoma, and in 

a newspaper of general circulation published in each county in which land 

embraced in the application are located. The notice shall include:

(1) UIC tracking number.

(2) Name and address of applicant.

(3) Location of proposed well to nearest 10 acre tract.

(4) Well name.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 75 -

(5) The geological name of the injection formation.

(6) The top and bottom of the injection interval.

(7) Maximum injection pressures.

(8) Maximum BID or MCFID injection rate.

(9) The type of well (injection, disposal, commercial).

(e) Written objection. If a written objection to the application is filed 

within fifteen (15) days after the application is published for injection and 

noncommercial disposal wells or thirty (30) days after the last publication 

date for commercial disposal wells, or if hearing is required by the 

Commission, the application shall be set for hearing and notice thereof shall 

be given in the same manner as required for the filing of the application on 

the pollution docket. If no objection is filed and the Commission does not 

require a hearing, the matter shall be presented administratively to the 

Manager of Underground Injection Control who shall sign the permit.

(f) Surety requirements for commercial disposal well facilities.

(1) Any operator of a commercial disposal well facility shall file with the 

Manager of Document Handling for the Conservation Division an agreement to 

properly plug the well and reclaim the site upon termination of operations. 

The agreement shall be on forms available from the Conservation Division and 

shall be accompanied by surety. The agreement shall provide that if the 

Commission finds that the operator has failed or refused to comply with 

Commission rules or take remedial action as required by law and Commission 

rules, the surety shall pay to the Commission the full amount of the 

operator's obligation up to the limit of the surety.

(2) The Commission shall establish the amount of surety in the order or 

permit for the authority to operate a commercial disposal well facility. 

The amount of surety shall be based on factors such as the depth of the 

well, dimensions of the facility, and costs of plugging the well, 

reclamation, monitoring, plugging of monitor wells, any pit closure, 

trucking of any deleterious substances, remediation and earth work. The 

amount may be subject to change for good cause. The surety shall be 

maintained for as long as monitoring is required. The type of surety shall 

be a corporate surety bond, certificate of deposit, irrevocable commercial 

letter of credit, or other type of surety approved by order or permit of the 

Commission. Any type of surety that expires shall be renewed prior to 30 

days before the expiration date.

(3) Operators of commercial disposal well facilities authorized prior to 

the effective date of this subsection must either comply with this 

subsection or close such facilities within one (1) year of the effective 

date of this subsection.

(g) In addition to the requirements listed above, the Manager of Underground 

Injection Control may request the applicant to submit the following information 

as a prerequisite to approval of the application:

(1) For those wells included in OAC 165:10-5-5(b)(1) which penetrate the 

top of the injection interval, a tabulation of the wells indicating the 

following information, if available, from public records:

(A) Dates the wells were drilled.

(B) The present status of the wells.

(C) The identity of any abandoned well which was improperly plugged or 

remains unplugged.

(2) A list of the following information, if available, to the applicant:

(A) The shut-in bottom hole formation pressure in psi; or the stabilized 

shut-in surface pressure and fluid level in the proposed injection well.

(B) The permeability of the proposed injection zone expressed in 

millidarcies.

(C) The porosity of the proposed injection zone expressed as a 

percentage of pore volume.

(D) Documentation of the methods used to arrive at the data requested 

above.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 76 -

(h) Authorization of an enhanced oil recovery injection well or a disposal 

well or a commercial disposal well will expire and become null and void if no 

well completion report (Form 1002A) is filed or if no mechanical integrity test 

is performed pursuant to OAC 165:10-5-6 within six months from the date of 

completion or conversion of the well.

(i) In addition to the well construction requirements as set out in 165:10-3-

1, commercial saltwater disposal wells shall comply with the following 

requirements:

(1) At a minimum, the well shall be constructed with a wellhead, surface 

casing, production casing, tubing, and packer.

(2) The surface casing shall be set and cemented at least fifty (50) feet 

below the base of the treatable water bearing zone. The production casing 

will not be allowed to also serve as the surface casing.

(3) The production casing must be set and cemented through the injection 

zone with the cement circulated behind the casing to a height at least two 

hundred fifty (250) feet above the disposal zone. A cement bond log showing 

quality and placement of the cement must be furnished to and approved by the 

Commission before the well may be used for injection or disposal. The 

Manager of Underground Injection Control may approve the Arbuckle Formation 

for open hole completion.

(4) The annulus between the tubing and the casing must be open from the 

surface to the packer to allow for pressure testing and monitoring of the 

injection tubing and packer and the annulus filled with a packer fluid that 

protects against corrosion.

(5) The packer must be set at least within seventy-five (75) feet of the 

top of the perforations.

(6) Adequate gauges shall be installed on each annulus to allow proper 

monitoring of the disposal operation.

(7) Tubing must be internally coated or lined to prevent corrosion from 

injected fluids. PVC, Plastic Coated, Stainless Steel or Fiberglass will 

qualify.

(8) The packer must be either internally coated or stainless steel.

(9) Commercial disposal wells authorized with a positive injection pressure 

must be equipped with a down hole shut-off device with a seal divider 

installed between the packer and the tubing. A Stainless Steel Profile 

Nipple and an "ON-OFF" Tool will qualify under this Section.

(j) No Commercial disposal well will be permitted whose injection pressure 

approaches or exceeds the demonstrated frac gradient of the injection zones(s).

(k) All permitted injection zones must be completed for injection. 

Authorization for any zones not initially completed as an injection zone will 

expire within 60 days following initial completion or recompletion date.

(l) In the event the Commission has evidence that an applicant for a 

commercial disposal well may not possess a satisfactory compliance history with 

Commission rules, the Director of the Conservation Division may seek an order 

of the Commission, issued after application, notice, and hearing, determining 

whether the applicant should be authorized to operate such commercial disposal 

well.

[Source: Amended at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200600012, eff 7-1-2006; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001); 

Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 29 Ok Reg 

950, eff. 7-1-12 (RM 201200005); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001); Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002)]

165:10-5-6. Testing and monitoring requirements for enhanced recovery 

injection wells and disposal wells

(a) Mechanical integrity during injection. The operator of an injection, 

disposal or commercial disposal well must maintain mechanical integrity in 

order to continue operation of the well.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 77 -

(b) Initial pressure test requirements for wells permitted on or after 

December 2, 1981. 

(1) Mandatory initial mechanical test. Before commencement of operation, 

each well authorized for enhanced recovery injection or disposal by a 

Commission order issued on or after December 2, 1981, must pass an initial 

pressure test of the casing tubing annulus according to the minimum testing 

standards of (2) of this subsection, unless a Commission order permits other 

test procedures of the mechanical integrity of the well. Any operator 

failing to comply with initial mechanical integrity testing and reporting 

requirements may be fined up to $500.00.

(2) Minimum testing standards for initial tests. For each initial test 

required by (1) of this subsection, the minimum testing standards are:

(A) Witnessing of the test. The test shall be witnessed by an 

authorized representative of the Conservation Division. It shall be the 

responsibility of the well operator to secure the presence of the 

Commission representative.

(B) Down-hole equipment. Injection and disposal shall be through 

adequate tubing and packer.

(C) Aboveground extensions and fittings. Adequate aboveground 

extensions shall be installed in each annulus in the well. In addition, 

the operator shall install a one-fourth (1/4) inch female fitting, with 

cutoff valve to the tubing, so that the amount of injection pressure may 

be measured by the Commission representative using a gauge having a onefourth (1/4) inch male fitting.

(D) Packer setting depth under the order. The mechanical packer shall 

be set within 40 feet of the packer setting depth prescribed by the order 

permitting the well for injection or within 75 feet of the perforations 

of the injection zone(s) opened.

(E) Verification of packer setting depth. The Commission District 

Manager may require the operator of the well to verify the packer setting 

depth by running a wireline or other method approved by the Manager of 

the Underground Injection Control Department.

(F) Minimum testing pressure. Noncommercial disposal and injection 

wells shall be tested as follows:

(i) If the maximum authorized injection pressure for the well is less 

than 300 psig under the order permitting the well for injection, the 

minimum testing pressure shall be 300 psig.

(ii) If the maximum authorized injection pressure is greater than 300 

psig under the order permitting the well for injection, the minimum 

testing pressure shall be the lesser of 1000 psig or the maximum 

authorized injection pressure under the order permitting the well.

(G) Thirty minute minimum testing period. The minimum testing period 

shall be 30 minutes at the testing pressure.

(H) Ten percent maximum permitted bleed-off. The maximum permitted 

bleed-off during the testing period shall be ten percent of the maximum 

testing pressure used.

(I) Test report on Form 1075. The operators shall submit the results of 

the mechanical integrity test on Form 1075 within 30 days from the date 

the test is performed.

(J) Cement circulated above injection zone. The minimum cement height 

circulated above the injection or disposal zone in the annulus between 

the casing and the borehole shall be 250 feet.

(K) Packer setting depth. The packer must be set at a depth which is at 

least 50 feet below the depth of the top of cement behind the production 

casing.

(3) Alternative testing procedures. Operators can test at a maximum of 500 

psi if there is in place an automatic and continuous pressure monitor on the 

tubing-casing annulus that will shut-in the well if there is a pressure 

increase of 250 psi on the annulus. Application for this alternative test 

procedure shall be made in writing to the Manager of the UIC Department.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 78 -

(4) Use of fluid seal without a mechanical packer. Use of a fluid seal 

without a mechanical packer is prohibited.

(c) Initial pressure test requirements for wells permitted prior to December 

2, 1981.

(1) Mandatory initial pressure test or monitoring test.

(A) Each well authorized for enhanced recovery injection or disposal by 

Commission order issued prior to December 2, 1981, must pass an initial 

mechanical integrity test according to the minimum testing standards of 

(2) of this subsection.

(B) In lieu of casing test required in (A) of this paragraph, the 

operator shall monitor and record during actual injection the pressure in 

the casing-tubing annulus monthly and report the pressure annually on 

Form 1075. A measurable positive pressure must be maintained at the 

casing valve and be continuously measured to qualify.

(2) Minimum testing standards for initial mechanical integrity tests.

(A) Wells with casing-tubing annulus. The minimum testing standards 

of (b)(2) of this Section for an initial test of a well with a casing 

tubing annulus shall apply with the following modifications:

(i) The District Manager shall have the option to waive witnessing of 

the test.

(ii) If the test is not witnessed, the well operator shall submit 

documentation of the test to the Conservation Division within 30 days 

after the test on Form 1075.

(iii) The minimum testing pressure shall be 200 psig.

(B) Wells without a casing-tubing annulus or wells with perforations 

above the packer. The minimum testing standards for an initial test of 

a well without a casing-tubing annulus or wells with perforations above 

the packer are:

(i) Witnessing of the test. The test shall be witnessed by an 

authorized representative of the Conservation Division unless the 

District Manager for the Conservation Division waives the requirement 

of witnessing the initial test. It shall be the responsibility of the 

well operator to secure the presence of the commission representative 

for witnessing the test.

(ii) Documentation for unwitnessed tests. If the test is not 

witnessed, then the operator shall submit on Form 1075 documentation 

of the test to the Conservation Division within 30 days after the 

test.

(iii) Aboveground extensions and fittings. The operator shall 

install a one-fourth (1/4) inch female fitting, with cutoff valve to 

the tubing, so that the amount of injection pressure may be measured 

by the Commission representative using a gauge having a one-fourth 

(1/4) inch male fitting.

(iv) Setting depth for plug. For purposes of the test, a mechanical 

packer, retrievable bridge plug, or seating nipple plug shall be 

placed in the injection string not more than 75 feet above the top of 

the injection interval.

(v) Pressure testing of tubing string. The well operator shall 

pressure test the tubing string for at least 30 minutes. The minimum 

testing pressure shall be the greater of 300 psig, or the maximum 

authorized injection pressure provided that the actual working 

injection pressure for the well may be used instead of the maximum 

authorized injection pressure when necessary to prevent damage to the 

casing or packer.

(vi) Ten percent maximum permitted bleedoff. The maximum permitted 

bleedoff during the testing period shall be ten percent of the maximum 

testing pressure used.

(vii) Radioactive tracer survey. A radioactive tracer survey shall 

be run demonstrating that the injected fluid is going into the 

authorized zone when there is no cement bond log or cementing reports 
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 79 -

to demonstrate sufficient cement behind pipe to isolate the injection 

zone or to insure the packer is properly set.

(viii) Pressure test using a gas media. In lieu of a pressure test 

using a liquid testing media, the UIC Department may approve a 

mechanical integrity test using a gas media if it conforms to a method 

previously approved by the EPA.

(ix) Test report on Form 1075. The operator shall submit the results 

of the mechanical integrity test on Form 1075 to the Conservation 

Division within 30 days after the test.

(d) Subsequent mechanical integrity test requirements.

(1) Pressure tests.

(A) Disposal wells permitted for injection at volumes equal to or 

greater than 20,000 barrels per day. Unless a well has been approved by 

an order of the Commission for other testing procedures or monitoring, 

each disposal well permitted for injection at volumes equal to or greater 

than 20,000 barrels per day shall demonstrate mechanical integrity by

using one of the following methods:

(i) Conduct a pressure test of the casing tubing annulus at least 

once every year according to the minimum testing standards of (3) of 

this subsection, or

(ii) If a continuous pressure monitor is installed on the casing 

tubing annulus that will automatically notify the operator of a 

mechanical failure, then the well shall demonstrate mechanical 

integrity at least once every five years according to the minimum 

testing standards of (3) of this subsection.

(B) Disposal wells permitted for injection at volumes less than 20,000 

barrels per day and enhanced recovery injection wells. Unless a well has 

been approved by an order of the Commission for other testing procedures 

or monitoring, each disposal well permitted for injection at volumes less 

than 20,000 barrels per day, and each enhanced recovery injection well 

permitted for injection shall demonstrate mechanical integrity at least 

once every five years according to the minimum testing standards of (3) 

of this subsection.

(C) Penalty for noncompliance. Any operator failing to comply with 

periodic mechanical integrity testing and reporting requirements may be 

fined up to $500.00.

(2) Required retest if down-hole equipment is moved or replaced. After a 

well passes a pressure test required by this Section, if the operator moves 

the packer or replaces either the packer or the tubing, then the operator 

shall retest the well according to the minimum testing standards of (3) of 

this subsection.

(3) Minimum testing standards.

(A) Wells with casing-tubing annulus. For a five year test or retest 

required by this subsection, the minimum testing standards of (b)(2) of 

this Section shall apply to wells with casing-tubing annulus with the 

following modifications:

(i) The District Manager shall have the option to waive witnessing of 

the test.

(ii) If the test is not witnessed, the well operator shall submit 

documentation of the test to the Conservation Division within 30 days 

after the test.

(iii) The minimum testing pressure shall be:

(I) 200 psig for a noncommercial well.

(II) 300 psig or the authorized injection pressure, whichever is 

greater, for commercial disposal wells.

(B) Wells without a casing-tubing annulus or wells with perforations 

above the packer. For a five year test or retest required by this 

subsection, the minimum testing reporting standards of (c)(2)(B) of this 

Section, shall apply to wells without a casing-tubing annulus or wells 

with perforations above the packer.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 80 -

(C) Wells with automatic monitoring of positive tubing-casing 

pressure. Subsequent pressure tests will not be required if there is in 

place a pressure monitor on the annulus to demonstrate the maintenance of 

a certain, positive pressure. This monitor will be connected to an 

automatic alarm or a continuous chart recorder. Application for this 

alternative shall be made in writing to the Manager of the UIC 

Department. Monitoring records will be sent annually attached to Form 

1012 to the UIC Department.

(e) Monitoring requirements.

(1) Report on Form 1075. In lieu of a mechanical integrity test every five 

years, the operator of a well permitted for injection or disposal may 

demonstrate the mechanical integrity by:

(A) Monitoring and recording the injection rate, volume, and casingtubing annulus pressure monthly.

(B) Submitting to the Conservation Division the results of monthly 

monitoring for the calendar year on Form 1075 by the first day of April 

of the next calendar year.

(2) Required positive casing-tubing annulus pressure. A measurable 

positive pressure must be maintained at the casing valve and be continuously 

measured to qualify for mechanical integrity.

(f) Testing requirements for commercial disposal wells.

(1) Before commencement of operation. Before commencement of operation, 

each commercial disposal well must pass a pressure test of the casing tubing 

annulus.

(2) Minimum testing standards.

(A) The test shall be witnessed by an authorized representative of the 

Conservation Division.

(B) The well shall be tested at the maximum authorized injection 

pressure, but not less than 300 psig.

(C) The minimum testing period shall be thirty (30) minutes.

(D) The maximum allowable change in pressure during the testing period 

shall be ten percent (10%) of the testing pressure.

(E) The results of the test shall be submitted on Form 1075 within 30 

days from the date of the test.

(3) Subsequent mechanical integrity tests.

(A) The well shall be tested a minimum of every twelve (12) months.

(B) After a well passes a pressure test required by this Section, if the 

operator moves the packer or replaces the packer or tubing, then the 

operator shall notify the Commission and retest the well according to the 

minimum testing standards of (2) of this subsection.

(4) Alternative testing procedures. Operators can test at a maximum of 500 

psi if there is in place an automatic and continuous pressure monitor on the 

tubing-casing annulus that will shut-in the well if there is a pressure 

increase of 250 psig on the annulus. Application for this alternative test 

procedure shall be made in writing to the Manager of the UIC Department.

[SOURCE: Amended at 9 Ok Reg 2295; Amended at 9 Ok Reg 2337, eff 6-25-92; 

Amended at 11 Ok Reg 3691, eff 7-11-94; Amended at 13 Ok Reg 2387, eff 7-1-96; 

Amended in Rule Making 97000002, eff 7-1-97; Amended in Rule Making 200000002, 

eff 7-1-2000; Amended in Rule Making 200600012, eff 7-1-2006; Amended at 28 Ok 

Reg 1949, eff 7-11-11 (RM 201000007); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001); Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002)]

165:10-5-7. Monitoring and reporting requirements for wells covered by 165:10-

5-1

(a) Scope. This Section applies to:

(1) Notice of Initial Commencement of Disposal Operations.

(2) Report of Injection Projects, saltwater disposal wells and LPG storage 

wells on Form 1012.

(3) Notice of Voluntary Termination of Operations on Form 1072.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 81 -

(4) Notice of mechanical failure or down-hole problems on Form 1075.

(b) Notice of initial commencement of disposal operations. The operator of a 

well permitted as a disposal well in the Arbuckle formation shall give at least 

48 hours notice by electronic mail or facsimile to the Manager of Underground 

Injection Control regarding the time when initial disposal operations will 

begin.

(c) Report of enhanced recovery injection projects, saltwater disposal wells 

and LPG storage wells.

(1) Submit Form 1012. Each operator of a saltwater disposal well, LPG 

storage well or an authorized waterflood, pressure maintenance project, gas 

repressuring project, or other enhanced recovery project shall submit 

Form 1012 for every well to the Conservation Division as follows:

(A) Form 1012 shall be submitted by April 1st for the previous calendar 

year for all noncommercial wells.

(B) For commercial disposal wells Form 1012 shall be submitted by January 

31 and July 31 for the previous six-month period.

(2) Failure to submit Form 1012. Any operator who fails to submit the 

report on Form 1012 as required by (c)(1) of this Section may be fined up to 

$500.00 and:

(A) Injection into the project is prohibited until the operator submits 

Form 1012 for each injection well.

(B) The order or permit is subject to termination.

(3) Required monitoring.

(A) On a monthly basis, the operator of each enhanced recovery injection 

well and disposal well and LPG storage well shall monitor and record the 

injection rate and surface injection pressure for the well.

(B) On a daily basis, the operator of each well authorized for disposal 

into the Arbuckle formation shall monitor and record the volumes, the 

casing tubing annulus pressure and the surface injection pressure for the 

well. The operator must maintain the information required by this 

subparagraph for a minimum of three years. This information shall be 

produced upon request by an authorized representative of the Commission.

(4) All UIC wells. Saltwater disposal wells, injection wells and storage 

wells shall be reported on Form 1012 individually according to the order or 

permit authorizing disposal.

(d) Monitoring requirements for commercial disposal well.

(1) The operator of a commercial disposal well shall monitor and record the 

casing tubing annulus pressure and the injection pressure on a daily basis.

(2) The operator of a commercial saltwater disposal well shall make 

available upon request of the Commission a log of all loads of deleterious 

substances disposed at the well. The log shall be kept on file for a period 

of at least five (5) years. The log of record shall include at a minimum, 

the date and time the load was received, the volume, the legal description of 

the well and/or source, and the operator and/or owner of the source of the 

deleterious substance.

(e) Notice of voluntary termination.

(1) If an operator permanently terminates injection into a well, the 

operator shall submit to the Conservation Division Form 1072 within 30 days 

after termination of injection. Form 1072 shall state:

(A) The legal description of the well.

(B) The reason for termination.

(C) The status of other wells, if the well is in an enhanced recovery 

project.

(2) Submission of Form 1072 to permanently terminate injection shall 

terminate the authority under the order.

(f) Notice of mechanical integrity problem.

(1) Notice of mechanical failure or down-hole problem. When a mechanical 

problem occurs, then:

(A) The well operator shall notify the Field Inspector for Conservation 

within 24 hours after discovery of the problem.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 82 -

(B) Within five days after discovery of the problem, the well operator 

shall submit to the Manager of Underground Injection Control written 

notice of the failure and a plan to repair and/or retest the well.

(C) Repair shall be reported on the annual Form 1012 for the well.

(D) Any operator failing to timely notify the Commission may be fined up 

to $1,500.00.

(2) Shutdown.

(A) Administrative shutdown. The Conservation Division may shut down a 

well if a mechanical failure or down-hole problem indicates that injected 

substances are not or may not be entering the injection interval 

authorized by order of the Commission.

(B) Administrative authority to recommence injection.

(i) If a well is shut down under (2)(A) of this subsection, the well 

operator shall be responsible for proving to the satisfaction of the 

Manager of Underground Injection Control:

(I) The mechanical integrity of the well for injection.

(II) That the injected substances are going into and are confined 

to the permitted injection interval.

(ii) Upon submission of proper proof of the satisfactory capability of 

the well for injection, the Manager of Underground Injection Control 

may authorize recommencement of injection.

(C) Resolution of disputes by order of the Commission. In the event of a 

dispute between the Manager of Underground Injection Control and any 

person as to the suitability of a well for injection, the affected person 

may seek relief by order of the Commission. Upon application, notice, and 

hearing meeting the requirements of 165:5-7-27(c) and (d) for protested 

applications, the Commission may issue an order determining whether or not 

the well should be used for further injection.

(3) Notice of unreported repairs. Any prior unreported repair of the well 

shall be reported on the next annual Form 1012 to be submitted to the Manager 

of the UIC Department.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 11 Ok Reg 3691, eff 

7-11-94; Amended at 13 Ok Reg 2389, eff 7-1-96; Amended at 26 Ok Reg 2498, eff 

7-11-09 (RM 200900001); Amended at 27 Ok Reg 2128, eff 7-11-10 (RM 201000003); 

Amended at 28 Ok Reg 1949, eff 7-11-11 (RM 201000007); Amended at 30 Ok Reg 

1041, eff. 7-1-13 (RM 201300001); Amended at 31 Ok Reg 977, eff. 9-12-14 (RM 

201400002); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-5-8. Liquid hydrocarbon storage wells

 Authorization for storage wells will be granted by order of the Commission 

after notice and hearing, provided there is a finding that the proposed 

operation will not endanger fresh water strata. 

165:10-5-9. Duration of underground injection well orders or permits

(a) Subject to 165:10-5-10, authorization of injection into enhanced recovery 

injection wells and disposal wells shall remain valid for the life of the well, 

unless revoked by the Commission for just cause or lapses and becomes null and 

void under the provisions of 165:10-5-5(g).

(b) An order granting underground injection may be modified, vacated, amended, 

or terminated during its term for cause. This may be at the Commission's 

initiative or at the request of any interested person through the prescribed 

complaint procedure of the Conservation Division. All requests shall be in 

writing and shall contain facts or reasons supporting the request.

(c) An order may be modified, vacated, amended, or terminated after notice and 

hearing if:

(1) There is a substantial change of conditions in the enhanced recovery 

injection well or the disposal well operation, or there are substantial 

changes in the information originally furnished. 
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 83 -

(2) Information as to the permitted operation indicates that the cumulative 

effects on the environment are unacceptable.

(d) If an operator fails to complete or convert a well as approved by the 

Conservation Division within eighteen (18) months after the effective date of 

the order or permit authorizing injection into the well, then the order or 

permit authorizing injection into the well shall expire.

[Source: Amended at 11 Ok Reg 3691, eff 7-11-94; Amended at 26 Ok Reg 2498, eff 

7-11-09 (RM 200900001)]

165:10-5-10. Transfer of authority to inject

(a) An order authorizing an enhanced recovery well(s), salt water disposal 

well, commercial salt water disposal well, or hydrocarbon storage well(s) shall 

not be transferred from one operator to another without the following:

(1) Notice in writing to the Commission on Form 1073I. For transfers 

involving more than ten (10) wells, a transferor and transferee may file a 

single Form 1073I with the Conservation Division indicating the transfer of 

multiple wells, provided that such multiple well transfer shall be 

accompanied by a well list containing the following information for each well 

transferred:

(A) API number of the well;

(B) Well name and number;

(C) Legal location of the well, described by section, township and 

range; and

(D) The Commission Order number(s) authorizing the injection, disposal, 

or hydrocarbon storage activity.

(2) The well list may be provided in spreadsheet form, if possible, and may 

be filed in digital format specified by the Conservation Division. In lieu 

of the information listed in subparagraphs (a)(1)(A) through (D), the 

transferor and transferee, at their option, may file one Form 1073I 

indicating the transfer of multiple wells with an OCC Form 1002A Completion 

Report attached for each well transferred. Upon review by the Conservation 

Division, it may require additional information from the transferor and/or 

the transferee to assist in identifying the specific well(s) being 

transferred. The additional information may include, but not be limited to, 

the quarter, quarter, quarter section calls, footages from the south and west 

quarter section lines, and the drilling and completion dates, and initial 

injection, disposal or storage dates.

(3) Notice in writing to the Commission on Form 1075 demonstrating that a 

mechanical integrity test was performed within one year prior to the date of 

transfer. For commercial disposal wells, the Mechanical Integrity Test shall 

be conducted within 30 days prior to the date of transfer.

(4) The performance of the mechanical integrity test required in (a)(2) of 

this subsection shall not apply to any operator transfer when the following 

conditions are present:

(A) The interest of the currently designated operator is transferred to 

its subsidiary or parent company, or a subsidiary of a parent company;

(B) The interest of the currently designated operator is transferred to a 

surviving or resulting corporation or business entity due to, 

respectively, a merger, consolidation or reorganization involving the 

transferor and transferee. As used in this subparagraph, "business 

entity" means a domestic or foreign partnership, whether general or 

limited; limited liability company; business trust; common law trust, or 

other unincorporated business; or

(C) The currently designated operator undergoes a name change. The 

relief afforded by this subparagraph is not applicable to situations where 

the name change involves the following conditions:

(i) The assignment of a new Federal Employer Identification number by 

the Internal Revenue Service to the new company;
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 84 -

(ii) The name change is accompanied by a change in the majority of 

partners in a partnership;

(iii) The name change is associated with a divorce between a husband 

and wife when the husband and wife comprise a partnership;

(iv) The name change is associated with the death of one spouse in a 

partnership comprised of a husband and wife;

(v) The name change involves a sole proprietorship; or

(vi) The name change is associated with such other circumstances where 

the Commission determines upon application, notice and hearing that the 

relief provided in this subparagraph is not applicable, or that an 

exception to any exclusion should be granted.

(vii) As used in this subparagraph, the term "partnership" means a 

domestic or foreign partnership, whether general or limited.

(b) The Commission shall, within 30 days therefrom, return a copy of Form 

1073I to the new and previous operator, designating approval or denial of the 

transfer of authority to inject for the subject well(s).

[SOURCE: Amended at 13 Ok Reg 2390, eff 7-1-96; Amended in Rule Making 97000002, 

eff 7-1-97; Amended in Rule Making 200000002, eff 7-1-00]

165:10-5-11. Notarized reports

 In lieu of notarization, all Conservation Division reports shall contain the 

following statement signed and dated by the responsible party representing the 

entity which is submitting the report:

"I declare that I have knowledge of the contents of this report, which was 

prepared by me or under my supervision and direction, with the data and facts 

stated herein to be true, correct, and complete to the best of my knowledge 

and belief".

165:10-5-12. Application for administrative approval for the subsurface 

injection of onsite reserve pit fluids 

 Except upon a case-by-case approval of the Commission pursuant to 165:10-5-

13, the subsurface injection of reserve pit fluids is prohibited into:

(1) A newly drilled well which is to be plugged and abandoned, or

(2) The casing annulus of:

(A) A well being drilled.

(B) A recently completed well.

(C) A well which has been worked over.

165:10-5-13. Application for permit for one time injection of reserve pit 

fluids

(a) General.

(1) Injection of reserve pit fluids shall be limited to injection of only 

those fluids generated in the drilling, deepening, or workover of the 

specific well for which authorization is requested.

(2) An annular injection site shall be inspected by a duly authorized 

representative of the Commission prior to injection. 

(3) The applicant shall file with the Underground Injection Control an 

affidavit of delivery or mailing not later than five days after the 

application is filed. 

(4) An operator who disposes of drilling fluid into the surface casing or 

annulus without approval from the Manager of Pollution Abatement may be fined 

up to $2,500.00.

(b) Criteria for approval.

(1) Casing string injection may be permitted if the following conditions are 

met and injection will not endanger treatable water: 

(A) Surface casing injection may be authorized provided that surface 

casing is set and cemented at least 200 feet below the base of treatable 

water, except as otherwise provided by the Commission; or
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 85 -

(B) Intermediate casing injection may be authorized provided that 

intermediate casing is set at least 200 feet below the base of treatable 

water, except as otherwise provided by the Commission.

(2) Injection pressure shall be limited so that vertical fractures will not 

extend to the base of treatable water.

(3) Required form and attachments. Each application for annular injection 

shall be submitted to the UIC Department on Form 1015T in quadruplicate. The 

forms must be properly completed and signed. Attached to one copy of the 

form shall be the following:

(A) Affidavit of mailing a copy of the Form 1015T or Form 1000 to the 

landowner and to each operator of a producing lease within 1/2 mile of the 

subject well.

(B) Cement Bond Log of subject well (if run).

(4) Expiration of the permit. The permit shall expire on its own terms 

three months after the date of issuance of the permit.

(c) Emergency authority to inject into the annulus. The Manager of the UIC 

Department may grant emergency authority to inject pit fluids into the annulus 

provided an imminent environmental endangerment exists.

(d) Protest period. If no protest is received within 15 days of the mailing of 

Form 1015T, the application shall be submitted for administrative approval. If 

a protest is received within the protest period, the operator shall, within 30 

days, set and give proper notice of a date for hearing on the Pollution Docket 

before an Administrative Law Judge.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 13 Ok Reg 2390, eff 

7-1-96; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003)]

165:10-5-14. Exempt aquifers

(a) Upon application after notice and hearing, the Commission may issue an 

order designating an underground source of drinking water (USDW) as an exempted 

aquifer if the USDW:

(1) Does not currently serve as a source of drinking water.

(2) Cannot now and has no reasonable future prospect of serving as a source 

of drinking water because:

(A) It is mineral, hydrocarbon or geothermal energy producing source; or

(B) It is situated at a depth or location which makes recovery of water 

for drinking water purposes economically or technologically impractical; 

or

(C) It is so contaminated that it would be economically or 

technologically impractical to render that water fit for human 

consumption.

(b) For purposes of 165:10-3-4 and 165:10-5-2 through 165:10-5-13, an exempted 

aquifer shall not be considered as productive of treatable water.

(c) Each application under subsection (a) of this Section shall comply with 

165:5-7-28.

(d) Each order designating a USDW as an exempted aquifer shall be subject to 

approval by the U.S. Environmental Protection Agency.

165:10-5-15. Application for permit for simultaneous injection well.

(a) General.

(1) Simultaneous injection of salt water without a valid permit from the 

Underground Injection Control Department may result in the assessment of a 

fine up to $5,000 per day of operation.

(2) A simultaneous injection facility shall be inspected by a representative 

of the commission prior to operation.

(b) Criteria for approval.

(1) Simultaneous injection may be permitted if the following conditions are 

met and injection will not adversely affect offsetting production nor 

endanger treatable water.

(A) Injection zone is located below the producing zone in the borehole.
OAC 165:10-5 Corporation Commission

Eff. 8-27-15

- 86 -

(B) Injection pressure is limited to less than the local fracture 

gradient.

(C) If injection is by gravity flow, no Area of Review will be required.

(D) If injection is by positive pump pressure, a 1/4 mile Area of Review 

will be required. If unplugged or mud-plugged boreholes are located 

within the 1/4 mile radius, the operator of the proposed simultaneous 

injection well will be required to reconcile these boreholes prior to a 

permit being issued.

(E) Simultaneous injectors must meet the requirements of 165:10-3-4 as 

they apply to producing wells.

(F) Simultaneous injectors may be authorized to accept produced water 

from other wells. The UIC Department will determine on a case-by-case 

basis whether such a well warrants designation as a simultaneous injector, 

or whether the well requires a Commission order.

(2) Required form and attachments. Each application for simultaneous 

injection shall be submitted to the UIC Department on Form 1015SI in 

quadruplicate. The forms must be properly completed and signed. Attached to 

one copy of the application form shall be the following:

(A) Affidavit of mailing a copy of the completed Form 1015SI to each 

operator of a producing lease within 1/2 mile of the subject well.

(B) Schematic diagram of the well showing all casing and tubing strings, 

packers, perforations and pumps.

(3) Monitoring, testing and reporting requirements for simultaneous 

injection wells.

(A) Upon receiving a permit, operator shall file an amended Completion 

Report Form 1002A within 30 days of recompletion.

(B) Mechanical integrity will be demonstrated by filing annual reports of 

surface casing pressure, production casing pressure and fluid level.

(C) Annual Report Form 1012 shall be submitted prior to April 1 of each 

year for the previous calendar year.

(4) If no protest is received within 15 days of the mailing of Form 1015SI, 

the application shall be submitted for administrative approval. If a protest 

is received within the protest period, the operator shall, within 30 days, 

set and give proper notice of a date for hearing on the Pollution Docket 

before an Administrative Law Judge.

(c) Expiration of the permit. The permit shall expire on its own terms if the 

subject well is not recompleted or if a revised Form 1002A is not submitted 

within 180 days from the date on the permit.

[SOURCE: Added at 13 Ok Reg 2391, eff 7-1-96; Amended at 28 Ok Reg 1949, eff 7-

11-11 (RM 201000007)]
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 87 -

SUBCHAPTER 7. POLLUTION ABATEMENT 

PART 1. GENERAL PROVISIONS 

Section

165:10-7-1. Pollution abatement [RESERVED]

165:10-7-2. Administration and enforcement of rules 

165:10-7-3. Cooperation with other agencies 

165:10-7-4. Water quality standards 

165:10-7-5. Prohibition of pollution 

165:10-7-6. Protection of public water supplies 

165:10-7-7. Informal complaints, citations, red tags, and shut down of 

operations 

165:10-7-8. Inspection and enforcement [RESERVED]

165:10-7-9. Scheduled monetary fines

165:10-7-10. Registration for land application of deleterious substances

PART 2. ANODE GROUNDBEDS

165:10-7-14. Anode groundbeds

PART 3. STORAGE AND DISPOSAL OF FLUIDS 

165:10-7-15. Drilling or seismic activity near superfund sites or hazardous 

waste facilities

165:10-7-16. Use of noncommercial pits 

165:10-7-17. Surface discharge of fluids 

165:10-7-18. Discharge to surface waters 

165:10-7-19. Land application of water-based fluids from earthen pits, tanks

and pipeline construction

165:10-7-20. Noncommercial disposal or enhanced recovery well pits used for 

temporary storage of saltwater

165:10-7-21. Refining and processing of oil and gas 

165:10-7-22. Permits for County Commissioners to apply waste oil, waste oil 

residue, or crude oil contaminated soil to roads

165:10-7-23. Disposal of waste oil 

165:10-7-24. Waste management practices reference chart

165:10-7-25. One-time land application of water-based fluids from tanks or 

other containment vessels [REVOKED]

165:10-7-26. Land application of contaminated soils and petroleum 

hydrocarbon based drill cuttings

165:10-7-27. Application of waste oil, waste oil residue, or crude oil 

contaminated soil by oil and gas operators and pipeline 

companies

165:10-7-28. Application of freshwater drill cuttings by County 

Commissioners

165:10-7-29. Application of freshwater drill cuttings by oil and gas 

operators

165:10-7-30. Enhanced recovery project surface facilities [REVOKED]

165:10-7-31. Seismic and stratigraphic operations

165:10-7-32. Application to reclaim and/or recycle produced water for surface 

activities related to drilling, completion, workover, and 

production operations from oil and gas wells

165:10-7-33. Use of truck wash pits

165:10-7-34. Use of reclaimed water in oil and gas operations
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 88 -

PART 1. GENERAL PROVISIONS

165:10-7-1. Pollution abatement [RESERVED]

165:10-7-2. Administration and enforcement of rules

(a) The Manager of Pollution Abatement shall supervise and coordinate the 

administration and enforcement of the rules of this Subchapter under the 

direction of the Director of Conservation and the Commission.

(b) Site assessments and remediation projects for petroleum and produced water 

pollution should adhere to the general practices appearing in the Oil and Gas 

Conservation Division’s Guardian Guidance document including the Guidelines and 

Numerical Criteria for New or Historic Produced Water/Brine Spills Appendix. 

Any alternative plan shall be approved by the Manager of Pollution Abatement 

prior to implementation.

(c) Specific areas of Conservation Division jurisdiction to which Pollution 

Abatement rules apply:

(1) Field operations for geologic and geophysical exploration for oil, gas 

and/or brine, including seismic shot holes, stratigraphic test holes or 

other test wells.

(2) Exploration, drilling, development, production or processing of oil, 

gas and/or mineral brine at the lease site.

(3) The exploration, drilling development and operation of wells used in 

connection with the recovery, injection, or disposal of mineral brines 

including construction, operation, maintenance, closure and abandonment of 

the facilities and activities.

(4) Reclaiming and/or recycling facilities associated with the exploration, 

drilling, development, production or transportation of oil and/or gas 

(including the processing of saltwater, crude oil, natural gas condensate, 

tank bottoms or basic sediment from crude oil tanks, pipelines, pits and 

equipment).

(5) Underground injection control pursuant to the federal Safe Drinking 

Water Act and 40 CFR parts 144 through 148 for Class II injection wells, 

Class V wells used for the recovery, injection or disposal or mineral brines 

as defined in the Oklahoma Brine Development Act.

(6) Tank farms for storage of crude oil and petroleum products located 

outside the boundaries of refineries, petrochemical manufacturing plants, 

natural gas liquid extraction plants, or other facilities that are not 

subject to the jurisdiction of the Oklahoma Department of Environmental 

Quality.

(7) Construction and operation of pipelines and associated rights-of-way, 

equipment, facilities or buildings used in the transportation of oil, gas, 

petroleum, petroleum projects, anhydrous ammonia or mineral brine, or in the 

treatment of oil, gas or mineral brine during the course of transportation 

[not including pipelines in natural gas liquids extraction plants, 

refineries, or reclaiming facilities other than those specified in OAC 

165:10-7-4(c)(6)].

(8) The handling, transportation, storage and disposition of saltwater,

drilling fluids, mineral brines, waste oil and other deleterious substances 

produced from or obtained or used in connection with the drilling, 

development, production, and operation of oil and gas wells at any facility 

or activity specifically subject to Commission jurisdiction or other oil and 

gas extraction facilities and activities.

(9) Spills of deleterious substances associated with facilities and 

activities specified in OAC 165:10-7-4(c)(8) or otherwise associated with 

oil and gas extraction and transportation activities.

(10) Groundwater protection for activities subject to the jurisdictional 

areas of environmental responsibility of the Commission.

(d) Monitoring of sites. Before consideration for closure by the Conservation 

Division or the Commission, the responsible party shall monitor a remediation 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 89 -

project subject to implementation of the water quality standards for a period 

of one (1) year, unless:

(1) Otherwise provided by Commission order, or

(2) As directed by the Manager of Pollution Abatement or designated 

Conservation Division staff.

(e) Public participation; Resolution of complaint or disagreement with 

Conservation Division staff.

(1) In any case where the Conservation Division determines the need for 

public participation in the resolution of a pollution complaint involving 

the implementation of the water quality standards or other issues relating 

to pollution, the Conservation Division may file an application and notice 

of hearing to request resolution of the complaint by adjudicative hearing 

and Commission order.

(2) In any case where a pollution complaint involving the implementation of 

the water quality standards or other issues relating to pollution cannot be 

resolved administratively between the responsible party and the complainant 

or because of a disagreement with the Conservation Division’s manager of 

Pollution Abatement, Manager of Field Operations, or other Conservation 

Division staff, regarding the complaint, the responsible party or the 

complainant may file an application and notice of hearing to request 

resolution of the complaint by adjudicative hearing and Commission order.

[SOURCE: Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-7-3. Cooperation with other agencies

(a) The rules of this Subchapter shall not be construed as modifying the 

rights, obligations, or duties of any person under any law of this State or 

under any order, rule, or regulation of the Oklahoma Water Resources Board, 

State Department of Health, Oklahoma Wildlife Conservation Commission, State 

Board of Agriculture, Department of Environmental Quality, or any other agency 

of this State with respect to the pollution of fresh water.

(b) Whenever a written complaint against any person is filed with the 

Commission alleging pollution as prohibited by 165:10-7-5, the Manager of 

Pollution Abatement shall immediately initiate such action as may be necessary 

or appropriate to abate the pollution.

(c) OPERATORS TAKE NOTE: Federal statutes, such as the Bald Eagle Protection 

Act (16 U.S.C. Sections 668-668d), the Migratory Bird Treaty Act (16 U.S.C. 

Sections 703-711), the Endangered Species Act (16 U.S.C. Sections 1531-1542), 

and the Lacey Act Amendments of 1981 (16 U.S.C. Sections 3371-3378), dictate 

substantial fines and penalties for persons who allow birds of certain species 

to become fatally injured due to incidental contact with oil or oil byproducts. These fines may be levied upon persons allowing such fatalities to 

occur, whether accidental or not. Misdemeanor and felony convictions may 

include imprisonment. Information on affected bird species, regulations under 

these Acts, and measures which can be taken to prevent such occurrences, such 

as the netting or covering of open-topped tanks and pits which contain oil or 

oil by-products, can be obtained from the U.S. Fish and Wildlife Service 

Office in Oklahoma City or the nearest Oklahoma Department of Wildlife Office.

(d) Operators drilling in the Arbuckle-Simpson Aquifer. The Arbuckle-Simpson 

Aquifer located in Pontotoc, Murray, and Johnston Counties has unique and 

unusual hydrogeologic conditions. Any operator intending to drill in this 

area should contact the Technical Services Department of the Oil and Gas 

Conservation Division prior to filing an intent-to-drill. The Technical 

Services Department may request a technical meeting prior to approval of an 

intent-to-drill to determine if additional protection of this aquifer is 

necessary.

[SOURCE: Amended at 23 Ok Reg 2229, eff 7-1-06 (RM 200600012); Amended 

at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 90 -

165:10-7-4. Water quality standards 

(a) Scope. The Commission hereby adopts the State water quality standards 

established and promulgated by the Oklahoma Water Resources Board (OWRB) or its 

successors effective October 7, 1987, and additions and revisions as lawfully 

published in the Oklahoma Register effective as provided by statute. The 

Commission’s Oil and Gas Conservation Division (Conservation Division) shall 

implement the water quality standards with regard to its particular

jurisdictional areas as referred to in 165:10-7-2(c).

(b) General considerations.

(1) The primary goal of the implementation of the water quality standards 

in the context of a remediation project subject to Commission jurisdiction 

shall be the protection and/or restoration of the beneficial use of the 

land, the soil and any surface or subsurface waters of the State adversely 

impacted or impaired by pollution from a Commission regulated site or 

facility.

(2) A remediation project utilizing the water quality standards shall 

adhere to the general practices appearing in the Conservation Division's 

Oklahoma Water Quality Standards Implementation Plan (WQSIP).

(3) Where appropriate, a remediation project utilizing the water quality 

standards shall follow the use support assessment protocols (OWRB-OAC 

785:46-7) as specified in Oklahoma Water Quality Standards Implementation 

Plan.

[SOURCE: Amended in Rule Making 200100005, eff 7-1-01; Amended at 26 Ok Reg 

2498, eff 7-11-09 (RM 200900001)]

165:10-7-5. Prohibition of pollution

(a) General. Pollution is prohibited. All operators, contractors, drillers, 

service companies, pit operators, transporters, pipeline companies, or other 

persons shall at all times conduct their operations in a manner that will not 

cause pollution.

(b) Workable coal seams. Sections 305, 306, 307, and 308 of Title 52, Oklahoma 

Statutes Annotated, governing the drilling, operations, and plugging of oil and 

gas wells in workable coal beds are hereby adopted as rules of the Commission as 

fully as if set out verbatim herein.

(c) Reporting nonpermitted discharges (spills, etc.).

(1) All operators, contractors, drillers, service companies, pit operators, 

transporters, pipeline companies, or other persons conducting operations 

regulated by the Commission shall:

(A) Report verbally, with respect to their operations, to the Commission 

District Office or Field Inspector within 24 hours of discovery:

(i) Any non-permitted discharge of deleterious substances of ten bbls. 

or more (single event) to the surface.

(ii) Any discharge of a deleterious substance, regardless of quantity, 

to the waters of the State.

(B) File a written or oral report with the District Office within ten 

business days specifying the following:

(i) Name of party reporting, firm name, telephone number, and 

electronic mail address.

(ii) Legal location.

(iii) Lease or facility name.

(iv) Operator.

(v) Circumstances surrounding discharge of deleterious substance(s)

and whether discharge was to water or soil.

(vi) Date of occurrence.

(vii) Volumes of deleterious substance(s) discharged.

(viii) Type of materials discharged.

(ix) Method of cleanup (if any) undertaken and completed.

(x) Volumes of deleterious substance(s) recovered.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 91 -

(C) Maintain adequate records of each non-permitted discharge reflecting 

the information, time, and manner of reporting pursuant to this Section 

for a minimum of three (3) years.

Such documents shall be produced upon demand by an authorized 

representative of the Commission.

(D) Report hazardous substances that meet reportable quantities under 

Comprehensive Environmental Response Compensation and Liability Act 

(CERCLA) (40 C.F.R. Part 302) in the format as required under this 

subsection.

(2) Any operator, contractor, driller, service company, pit operator, 

transporter, or pipeline company who fails to comply with provisions of this 

rule may be fined $500.00 per incident.

[SOURCE: Amended at 9 Ok Reg 2295; Amended at 9 Ok Reg 2337, eff 6-25-92; 

Amended in Rule Making 97000002, eff 7-1-97; Amended at 29 Ok Reg 950, eff. 7-

1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-6. Protection of public water supplies

 The Commission, upon application of any municipality or other governmental 

subdivision, may enter an order establishing special field rules within a 

defined area to protect and preserve fresh water and fresh water supplies.

[SOURCE: Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-7. Informal complaints, citations, red tags, and shut down of 

operations

(a) This Section applies only to Field Operations Department of the Oil and 

Gas Conservation Division.

(b) For an alleged violation of an order or provision of this Chapter, a 

district manager or field inspector may attempt to contact the alleged 

violator or his agent, in person or by telephone. In addition, the district 

manager of field inspector may notify the alleged violator by mailing or 

delivering either Form 1036. The Form 1036 shall warn a person about an 

alleged violation, and it shall specify a time period for compliance. The 

Form 1036A shall be used for purposes of the monetary fines procedure in 

165:10-7-9. Mailing of either form may be to the last known address of the 

alleged violator according to Commission records.

(c) Where surface or subsurface pollution is apparent, a district manager or 

field inspector may direct an alleged violator to take steps necessary to stop 

and/or clean up pollution. Said steps may include a temporary shut down of 

the lease or facility. If an alleged violator cannot be located, the district 

manager or field inspector may take emergency action necessary to abate 

pollution.

(d) If a district manager or field inspector issues a Form 1036, an 

inspection of the lease or facility shall be made after the compliance period 

shown on the form. If the inspection shows that the alleged violator failed 

to comply as directed, the district manager or field inspector may:

(1) Issue a Form 1036A, where applicable,

(2) Refer the matter to the Office of General Counsel for prosecution, 

and/or 

(3) Temporarily shut down the lease or facility until further notice from 

the Commission.

(e) In shutting down a lease or facility, the district manager or field 

inspector shall affix at the site a red tag (directive to shut down). If the 

alleged violator removes or ignores a red tag, the district manager or field 

inspector shall refer the matter to the Office of General Counsel for 

prosecution, and the Commission may levy a fine up to $5,000.00.

[Source: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 12 Ok Reg 2017, 

eff 7-1-95; Amended at 28 Ok Reg 1949, eff 7-11-11 (RM 201000007)]
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 92 -

165:10-7-8. Inspection and enforcement [RESERVED]

165:10-7-9. Scheduled monetary fines

(a) Scope. This Section prescribes amounts and procedure for imposing 

monetary fines arising from the categories of rule violations shown on 

Schedules A and B, Appendix E and F, respectively to this Chapter.

(b) Issuance of complaint-citations.

(1) If the Conservation Division discovers an alleged violation in any 

category on Schedule A, it may issue a complaint-citation on Form 1036A. 

Said form shall describe the alleged rule violation, and it shall prescribe 

a monetary fine.

(2) If the Conservation Division discovers an alleged violation in any 

category on Schedule B, it may issue a complaint-citation on Form 1036A. 

Said form shall describe the alleged rule violation. It shall establish a 

time period for compliance without a monetary fine. It shall prescribe a 

Schedule B fine if the alleged violator fails to comply with Commission 

rules within the specified time period for compliance.

(c) Notice. Any complaint-citation (OCC Form 1036A) issued under this 

Section shall be mailed or delivered to the alleged violator at the last known 

address shown on Commission records.

(d) Hearing option.

(1) Any alleged violator shall have the option to pay the prescribed fine 

or contest it at an evidentiary hearing. Payment of the fine within the 

time provided on the complaint-citation shall be considered and accepted as 

a plea of no contest.

(2) To obtain an evidentiary hearing, the alleged violator must request it 

at the preliminary hearing described on the complaint-citation. Failure to 

timely request an evidentiary hearing may result in an order assessing the 

fine prescribed by the complaint-citation.

(3) Appeal from any report of the Administrative Law Judge shall be to the 

panel of Commissioners in accordance with the Rules of Practice, OAC 165:5.

(e) Payment of fines. A person may pay a fine with cash, a money order, or 

check; provided, that any cash payment must be made at a Commission cashier's 

window. All checks must be made payable to the Oklahoma Corporation 

Commission. A copy of the complaint-citation must accompany payment to ensure 

proper credit.

(f) Additional enforcement measures.

(1) The Conservation Division and the Secretary of the Corporation 

Commission may issue one or more complaint-citations to a person who fails 

to bring a lease and/or facility into compliance with the rules of this 

Chapter.

(2) Until payment in full or payment schedule has been determined, the 

Conservation Division may shut-down any lease and/or facility associated 

with an overdue fine assessed by Commission order after notice and hearing.

[SOURCE: Added at 9 Ok Reg 2295, eff 6-25-92]

165:10-7-10. Registration for land application of deleterious substances

(a) All persons who contract to land apply fluids pursuant to OAC 165:10-7-

17, OAC 165:10-7-19, OAC 165:10-7-26 or OAC 165:10-9-2 shall:

(1) Comply with OAC 165:30-3-11, OAC 165:30-3-13, all applicable laws and 

all applicable Commission rules regarding Deleterious Substance Transport 

Permits; and

(2) Submit to the Conservation Division a performance bond in the amount 

of $50,000.00, or other form of surety in an amount as approved by the 

Manager of the Pollution Abatement Department. The form of surety shall 

include an irrevocable commercial letter of credit, cash, a cashier's 

check, a certificate of deposit, a blanket surety bond, or other approved 

negotiable instrument. Financial statements are not an acceptable form of 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 93 -

surety. The surety may be released upon request made no sooner than thirty 

(30) days subsequent to the completion of operation(s) that have been 

permitted under such surety, if Conservation Division personnel determine, 

after inspection or review, that the release of surety is appropriate.

(b) Any person violating this Section may be fined in an amount up to 

$2,500.00. Any operation in violation of this Section may be shut down 

pending compliance with this Section.

[SOURCE: New at 30 Ok Reg 1041, eff 7-1-13 (RM 201300001)]

PART 2. ANODE GROUNDBEDS

165:10-7-14. Anode groundbeds

(a) Definitions. The following words or terms, when used in this Section, shall 

have the following meaning, unless the context clearly indicates otherwise:

(1) “Anode” means the electrode of an electrochemical cell at which oxidation 

occurs.

(2) “Cathodic protection” means a technique used to reduce the corrosion of a 

metal surface by making that surface the cathode of an electrochemical cell.

(3) “Deep anode groundbed” means one or more anodes installed vertically at a 

depth of fifty (50) feet or more below the earth's surface in a drilled hole 

for the purpose of providing cathodic protection.

(4) “Shallow anode groundbed” means one or more anodes installed either 

vertically or horizontally at a nominal depth of less than fifty (50) feet.

(5) “Annular space” means the space between the surface casing and the 

borewall or the space between two or more strings of casing placed in the 

borehole.

(6) “Operator” means the person who is duly authorized and in charge of the 

development of the operation of the pipeline or the development of a lease for 

the production of hydrocarbons.

(b) Permit to drill.

(1) The operator shall make application on Form 1000B and obtain a permit to 

drill a deep anode groundbed.

(2) A permit to drill shall be valid only for one or more deep anode 

groundbeds within a designated 10 acre tract.

(3) The Commission shall approve or deny the application within 30 days of 

date of receipt.

(4) Any contractor drilling a deep anode groundbed shall be licensed within 

the State of Oklahoma.

(5) Any operator who drills a deep anode groundbed without a permit may be 

fined up to one thousand dollars ($1,000.00).

(c) Expiration. A permit to drill shall expire six (6) months from the date of 

issuance, unless drilling operations are commenced.

(d) Posting of permit to drill at the site. During any activity subject to this 

Section the operator shall maintain at the site a legible copy of the permit to 

drill for inspection.

(e) Notice. The Commission’s District Manager or Field Inspector shall be given 

at least twenty-four (24) hours notice prior to commencing drilling operations.

(f) Notice of failure to comply with permit conditions. The operator shall 

notify the district office or the field inspector within twenty-four (24) hours 

of any failure to comply with the construction requirements approved on the 

permit.

(g) Deep anode groundbed abandonment.

(1) In the event the hole is lost during drilling, the hole will be plugged 

as soon as possible.

(2) Upon abandonment of a deep anode groundbed, the hole shall be plugged 

within thirty (30) days of abandonment.

(h) Construction standards.

(1) Shallow anode groundbeds.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 94 -

(A) Shallow anode groundbeds shall be constructed in order to prevent 

runoff water from entering the anode system or the commingling of water 

from separate groundwater bearing formations.

(B) Vertical shallow groundbeds shall be sealed by backfilling the hole 

with native cuttings or an approved sealing material. 

(2) Deep anode groundbeds.

(A) Deep anode groundbeds shall be constructed in order to prevent runoff 

water from entering the anode system or the commingling of groundwater 

formations with different water quality.

(B) Surface casing shall be set a minimum of twenty (20) feet below ground 

level, or at a depth previously approved by the Oil and Gas Division's 

Technical Department.

(C) If surface casing is not placed in the hole, the hole shall be filled 

with bentonite or cement from the top of the Coke Breeze Column to three 

(3) feet below surface. Native cuttings or soil shall be used to fill the 

remaining portion of the hole.

(D) The annular space between the casing and drilled hole shall be a 

minimum of two (2) inches to allow for a proper seal.

(E) The sealing material for the annular space for surface casing shall be 

bentonite, cement or a material previously approved by the Oil and Gas 

Division's Technical Department.

(F) Centralizers shall be used at a minimum of one (1) for every twentyfive (25) feet of surface casing run in the hole unless previously approved 

by the Oil and Gas Division's Technical Department on form 1000B.

(G)The groundbed shall be capped to prevent the entry of foreign material. 

Allowances for a vent pipe will be approved.

(i) Groundbed materials. Groundbed materials that do not contaminate 

groundwater shall be required at all times.

(j) Plugging requirements.

(1) All wires and vent pipe must be cut off at the top of the ten (10) foot 

surface plug, and the vent pipe must be securely capped and plugged.

(2) Cased holes shall be filled to at least ten (10) feet from the surface 

with native cuttings, anode materials, cement or with a material approved by 

the Pollution Abatement Department.

(3) Cement or bentonite shall be placed in the hole at a minimum of ten (10) 

feet below the surface to within three (3) feet of the surface. The remainder 

of the hole shall be filled with native cuttings, soil or a material approved 

by the Pollution Abatement Department.

(4) If the standard method is inadequate to stop artesian flow, alternate 

remedies must be employed to do so.

(5) All holes shall be properly completed or plugged to protect groundwater.

[SOURCE: Added in Rule Making 97000002, eff 7-1-97; Amended at 28 Ok Reg 1949, 

eff 7-11-11 (RM 201000007)]

PART 3. STORAGE AND DISPOSAL OF FLUIDS

165:10-7-15. Drilling or seismic activity near superfund sites or hazardous 

waste facilities

Any drilling or seismic activity related to oil or gas exploration or 

production shall be prohibited within 500 feet of the boundary of any 

superfund site pursuant to the Comprehensive Environmental Response 

Compensation and Liability Act (CERCLA), 42 U.S.C. Sections 9601, et. seq., or 

active hazardous waste treatment, storage, or disposal facility. A current 

listing of all superfund sites and active hazardous waste facilities is 

available from the Manager of Pollution Abatement. Seismic work, monitoring 

wells, or recovery wells necessary for identification, monitoring, or 

remediation of the superfund site or hazardous waste facility shall be exempt 

from this Section. Any request for exception to this Section shall comport 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 95 -

with the requirements generally for filing of applications under the 

Commission's Rules of Practice (see 165:5-7-1); in addition, notice shall be 

given to the Oklahoma State Department of Health, 1000 Northeast Tenth Street, 

Oklahoma City, Oklahoma 73152.

165:10-7-16. Use of noncommercial pits

(a) Scope. This Section shall cover the permitting, construction, operation, 

and closure requirements for any noncommercial pit. A noncommercial pit is an 

earthen pit which is located either on-site or off-site and is used for the 

handling, storage, or disposal of drilling fluids and/or other deleterious 

substances produced, obtained, or used in connection with the drilling and/or 

operation of a well or wells, and is operated by the generator of the waste. 

This does not cover disposal well pits. (See 165:10-7-20 and 165:10-9-3.)

(b) Liner requirements.

(1) Reserve/circulation and/or completion/fracture/workover pits.

(A) To assist in determining the construction requirements for a 

particular proposed reserve/circulation pit, either on-site or off-site, 

the operator of the pit shall indicate on Form 1000 the type of mud 

system(s) to be used, the maximum and average anticipated chloride 

concentration of the mud (based on drilling records in the area), 

whether or not pit fluids will be segregated, and shall furnish other 

information required by this Section or requested by the Commission's 

Technical Services Department.

(B) The Commission's Technical Services Department shall evaluate the 

site based upon Oklahoma Geological Survey maps and other pertinent 

information and shall assign one of the following categories to any 

proposed reserve/circulation pit, designating same on Form 1000 and 

indicating whether or not a liner is required:

(i) Category 1A – Geomembrane liner.

(I) Water based drilling fluid containment and/or water-based 

completion/fracture/workover fluid containment located over a 

alluvial deposit or in a near surface static water level 

environment. Any pit used to contain water-based drilling fluids, 

cuttings and/or completion/ fracture/ workover fluids located in 

alluvial deposit area or an area where the static water table is 

within 10 feet of the surface shall utilize a geomembrane liner 

for all drilling fluids and cuttings and/or completion/ fracture/ 

workover fluids.

(II) Water-based drilling fluid containment and/or water-based 

completion/fracture/workover fluid containment located within a 

wellhead protection area. Any pit used to contain water-based 

drilling fluids, cuttings and/or completion/fracture/workover 

fluids located within a wellhead protection area (WPA) as 

identified by the Wellhead Protection Program (42 U.S.C. Section 

300h-7, Safe Drinking Water Act), or within one mile of a public 

water well for which the WPA has not been delineated, shall be 

required to have a geomembrane liner.

(ii) Category 1B – Soil liner or geomembrane liner.

(I) Water-based drilling fluid containment and/or water-based 

completion/fracture/workover fluid containment located over a 

terrace deposit. Any pit used to contain water-based drilling 

fluids, cuttings and/or completion/ fracture/ workover fluids 

located over a terrace deposit shall be required to have either a 

soil liner or a geomembrane liner.

(II) Water-based drilling fluid containment and/or water-based 

completion/fracture/workover fluid containment located over a 

bedrock aquifer or Hydrologically Sensitive Area (HSA). Any pit 

used to contain water-based drilling fluids, cuttings and/or 

completion/ fracture/workover fluids located over any bedrock 

aquifer or HSA and is used to contain water-based drilling fluids 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 96 -

and/or cuttings and/or completion/fracture/workover fluids with 

chlorides in excess 5,000 mg/l shall be required to have a soil 

liner or a geomembrane liner. A separate unlined pit may be used 

to contain fluids and/or cuttings with a chloride content of less 

than of 5,000 mg/l.

(iii) Category 2 - Water-based/other situations. Any pit which is 

used to contain water-based drilling fluids, cuttings and/or 

completion/fracture/ workover fluids with a set of conditions 

different from Categories 1A and 1B shall not be required to be 

lined.

(iv) Category 3 - Oil-based. Any pit used to contain oil-based 

drilling fluids, cuttings and/or completion/fracture/workover fluids 

shall be required to have a geomembrane liner.

(v) Category 4 – Air-based. Any pit used to contain the cuttings 

from an air-based system shall not be required to be lined. The 

discharge of produced water into a category 4 pit is prohibited. 

(2) Other type pits.

(A) Any basic sediment pit shall be required to have a geomembrane 

liner.

(B) Any emergency pit shall not be required to be lined.

(C) Any flare pit shall not be required to be lined.

(D) Any recycling/reuse pit, spill containment pit, slit trench, or 

remediation pit shall conform to the same criteria for determining liner 

requirements for reserve/circulation and/or completion/fracture/workover 

pits, pursuant to (b)(1) of this Section.

(3) Converted pits. Any pit that is to be converted from one use to 

another, e.g., reserve pit to completion or fracture pit, shall have the 

more stringent liner requirements, pursuant to (c)(6) and (c)(7) of this 

Section.

(4) Offsite pits. Any offsite pit shall conform to the liner requirements 

in this Section and will require a permit. The operator of the proposed 

pit shall submit Form 1014 in duplicate to the appropriate Conservation 

Division District Office for review and approval. No offsite reserve pit 

may be permitted or constructed at a spacing closer than one pit per 

governmental quarter quarter section and a distance less than 600 feet from 

any other pit. Any offsite reserve pit may be reclassified or considered 

as a commercial pit, pursuant to 165:10-9-1, if it is constructed or used 

at a spacing closer than one reserve pit per governmental quarter quarter 

section. Closure of any offsite reserve pit shall not warrant the 

permitting of another offsite reserve pit within the same governmental 

quarter quarter section. For use of a pit without a permit, the pit 

operator may be fined up to $1,000.00.

(5) Variances. Any variance from the liner requirements of this Section 

may be granted by the Manager of the Technical Services Department after 

receipt of a written request and supporting documentation required by the 

Department.

(c) Construction requirements.

(1) Field or area rules. Any noncommercial pit which is to be constructed 

or used in an area covered by a field or area rule shall be subject to the 

more stringent requirements of either this Section or the field or area 

rule.

(2) Stockpiling of topsoil. Prior to constructing any noncommercial pit, 

except an emergency pit, all top soil within the top twelve inches shall be 

stripped and stockpiled for use as the final cover of fill at the time of 

closure. The top soil may be stockpiled in the berms, provided it is not 

mixed with other materials and can be readily distinguishable from other 

materials at the time of closure.

(3) Exclusion of runoff water. Any noncommercial pit shall be constructed 

and maintained so that runoff water from outside the location is not 

allowed to enter it.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 97 -

(4) Flood protection. Any noncommercial pit which is constructed in any 

area subject to frequent flooding according to the Soil Conservation 

Service County Soil Survey shall have berms substantial enough to prevent 

overtopping or washing out.

(5) Constructing on fill. Any noncommercial pit which requires a liner 

and is constructed on fill shall be constructed so that the maximum level 

of the solid contents will be maintained at least three feet below the 

natural ground level.

(6) Soil liners.

(A) Soil materials used or to be used in a soil liner shall undergo 

permeability testing either before or after construction, unless exempt 

pursuant to (B) of this paragraph.

(i) Pre-construction permeability testing shall consist of 

laboratory permeability tests on at least two specimens of 

representative soil liner materials compacted in the laboratory to 

approximately 90 percent of the material's Standard Proctor Density 

(ASTM D-698).

(ii) Post-construction permeability testing shall consist of at 

least two laboratory permeability tests on undisturbed samples of the 

completed soil liner or one field permeability test on the completed 

soil liner. Particular emphasis shall be placed on selecting the 

location(s) for permeability tests or test samples where 

nonuniformity in soil texture or color can be observed.

(iii) Laboratory permeability test procedures must conform to one of 

the methods described for fine-grained soils in the Corps of 

Engineers Manual EM-1110-2-1906 Appendix VII. In no case shall the 

pressure differential across the specimen exceed five feet of water 

per inch of specimen length. Field permeability tests shall be 

conducted only by the double ring infiltrometer method as described 

in ASTM D-3385. Permeability tests may be discontinued prior to flow 

stabilization upon satisfactory evidence that the permeability rate 

is less than 1.0 X 10-6 cm/sec.

(iv) If permeability testing shows that addition of bentonite or 

other approved material is needed to assist the native soils in 

meeting the permeability standard, it shall be applied at a minimum 

rate specified by the testing or engineering firm. Any bentonite 

used for liner material shall not have been previously used in 

drilling muds.

(B) Permeability testing requirements for soil materials may be exempt 

if laboratory testing of a minimum of two representative samples of the 

soil materials found throughout the entire depth of the proposed 

excavation indicates that the plasticity index is greater than 16 (ASTM 

D-4318) and that the amount passing the No. 200 U.S. standards sieve is 

greater than 60 percent (ASTM D-1140).

(C) Any soil liner shall be constructed by disturbing the soil to the 

depth of the bottom of the liner, applying fresh water as necessary to 

the soil materials to achieve a moisture content wet of optimum, then 

recompacting it with heavy construction equipment, such as a footed 

roller, until the required density is achieved, pursuant to (H) of this 

paragraph.

(D) Any soil liner shall cover the bottom and interior sides of the pit 

entirely.

(E) Any soil liner shall be installed on a slope no steeper than 3:1 

(horizontal to vertical).

(F) Any soil liner shall have a minimum thickness of six inches (after 

compaction), and shall have a maximum coefficient of permeability of 1.0 

x 10-6 cm/sec, unless it conforms to (G) of this paragraph.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 98 -

(G) A soil liner may have a coefficient of permeability greater than 

1.0 x 10-6 cm/sec if it is greater in thickness and constructed in 

accordance with the following:

(i) A minimum twelve inch compacted soil liner shall have a maximum 

coefficient of permeability of 2.0 x 10-6 cm/sec.

(ii) A minimum 18 inch compacted soil liner shall have a maximum 

coefficient of permeability of 3.0 x 10-6 cm/sec.

(iii) A compacted soil liner may not be constructed thicker than 18 

inches for the purpose of meeting a coefficient of permeability 

greater than 3.0 x 10-6 cm/sec.

(iv) Any soil liner with a minimum twelve inch or 18 inch thickness 

shall be constructed in maximum lifts of six inches (after 

compaction). Each lift shall be scarified before placement of the 

next lift and shall conform to (H) of this paragraph.

(H) Any soil liner shall be field tested for compaction, unless a postconstruction permeability test is performed, pursuant to (A)(ii) of this 

paragraph.

(i) The pit operator shall notify the appropriate Conservation 

Division District Office at least two (2) business days prior to 

field testing a soil liner for compaction to afford a Commission 

representative an opportunity to witness the field testing.

(ii) A minimum of six compaction tests shall be performed on any 

soil liner; a minimum of four widely spaced tests in the bottom of 

the pit and two tests on different slopes of the pit are required, 

unless otherwise directed by a Field Operations representative. 

Particular emphasis shall be placed on selecting locations for 

compaction tests where nonuniformity in soil texture or color can be 

observed.

(iii) Compaction tests shall be conducted in accordance with ASTM 

methods D-2922 or D-1556.

(iv) The soil materials of any liner shall be compacted to at least 

90 percent of the Standard Proctor Density (ASTM D-698).

(7) Geomembrane liners.

(A) Any geomembrane liner that is installed in a reserve/circulation 

pit, spill prevention pit, or remediation pit, completion/fracture/ 

workover pit, basic sediment pit, or recycling/reuse pit shall have a 

minimum thickness of 20-mil.

(B) Any geomembrane liner used in a noncommercial pit shall be 

chemically compatible with the type of substances to be contained and 

shall have ultraviolet light protection.

(C) Any geomembrane liner shall be placed over a specially prepared, 

smooth, compacted surface void of sharp changes in elevation, rocks, 

clods, organic debris, or other objects.

(D) Any geomembrane liner shall be continuous, although it may include 

seams, and shall cover the bottom and interior sides of the pit 

entirely. The edges shall be securely placed in a minimum twelve inch 

deep anchor trench around the perimeter of the pit or anchored in an 

equivalent manner approved by the appropriate Conservation Division 

District Office.

(8) Certification of liner. The operator of any noncommercial pit that is 

constructed with a soil or geomembrane liner shall secure an affidavit 

signed by the installer, certifying that the liner meets minimum 

requirements and was installed in accordance with Commission rules. It 

shall be the operator's responsibility to maintain the affidavit and all 

supporting documentation pertaining to the liner (e.g., permeability and 

compaction test results, bentonite receipts, and geomembrane liner 

specifications from the manufacturer), and shall make them available at all 

times for review by any representative of the Conservation Division.

(d) Operation and maintenance requirements.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 99 -

(1) Freeboard. The fluid level of any noncommercial pit shall be 

maintained at all times at least 24 inches below the lowest elevation on 

the top of the berm.

(2) Reserve/circulation pits. The operator of any reserve/ circulation 

pit shall limit its contents to the fluids and cuttings from a single well 

unless authorized by the District Manager.

(3) Off-site reserve pits. A waterproof sign shall be posted within 25 

feet of any off-site reserve pit and shall bear the name of the operator, 

legal description to the quarter quarter quarter section, permit number, 

and emergency telephone number.

(4) Recycling/reuse pits.

(A) Any pit permitted for drilling mud recycling or reuse may contain 

the fluids and cuttings from multiple wells, provided that those wells 

are operated by the pit operator.

(B) A waterproof sign shall be posted within 25 feet of any 

recycling/reuse pit and shall bear the name of the operator, legal 

description to the quarter quarter quarter section, permit number, and 

emergency telephone number.

(5) Prevention of pollution.

(A) All noncommercial pits shall be constructed, used, operated, and 

maintained at all times so as to prevent pollution. In the event of a 

nonpermitted discharge from a noncommercial pit, sufficient measures 

shall be taken by the operator to stop or control the loss of contents, 

and reporting procedures pursuant to 165:10-7-5(c) shall be followed. 

Any materials lost from a pit shall be cleaned up as directed by any 

Field Operations representative. For a willful non-permitted discharge 

from a noncommercial pit, the operator may be fined up to $2,000.00.

(B) The protection of migratory birds shall be the responsibility of 

the operator. Therefore, the Conservation Division recommends that to 

prevent the loss of birds, oil be removed or the surface area covered by 

the oil be protected from access to birds. [See Advisory Notice 165:10-

7-3(c)].

(e) Closure requirements.

(1) Designation of disposal method. The operator of any reserve/ 

circulation pit shall indicate the proposed method of disposal of drilling 

fluids and/or cuttings on Form 1000 as required by 165:10-3-1(f). Options 

shall be limited to the following, unless written approval is granted by a 

District Manager or Field Inspector Supervisor:

(A) Evaporation/dewatering and backfilling.

(B) Chemical solidification of pit contents.

(C) Annular injection (requires permit).

(D) Land application (requires permit).

(E) Disposal in permitted commercial pit.

(F) Disposal at permitted commercial soil farming facility.

(G) Disposal at permitted recycling/reuse facility.

(2) Trenching.

(A) Before trenching, stirring or otherwise disturbing the bottom of 

any noncommercial pit, the pit shall be completely dewatered.

(B) Trenching, stirring, or other similar practice shall be prohibited 

for any lined pit.

(3) Lined pits.

(A) When closing any noncommercial pit with a soil or geomembrane 

liner, extreme care shall be taken to preserve the integrity of the 

liner.

(B) For any lined reserve/circulation pit, completion/fracture/ 

workover pit, recycling/reuse pit, or basic sediment pit, all free 

liquids shall be removed or chemically solidified with nonhazardous 

material.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 100 -

(C) For any lined oil-based reserve/circulation pit, all cuttings or 

other materials remaining in the pit shall be chemically solidified with 

nonhazardous material.

(D) Soil cover, pursuant to (5) of this subsection, shall follow.

(4) Soil cover. Closure procedures for any noncommercial pit shall 

include a minimum of three feet of soil cover over any remaining pit 

contents, with all stockpiled topsoil being applied last. The materials 

shall be mounded or sloped to encourage runoff. A variance from this 

provision may be granted by the appropriate Conservation Division District 

Office for justifiable cause. A written request and supporting 

documentation is required. The appropriate Conservation Division District 

Office shall respond in writing within five business days either approving 

or disapproving the request.

(5) Erosion control. Any noncommercial pit shall be closed in such a 

manner that any future erosion will not cause the discharge of the pit 

contents. This may require vegetative cover and/or a diversion terrace(s).

(6) Notification to appropriate Conservation Division District Office. 

The operator of any noncommercial pit shall notify the appropriate Field 

Inspector or appropriate Conservation Division District Office at least 48 

hours prior to commencing closure, and for reserve/circulation pits shall 

advise if the disposal method is different from that indicated on Form 

1000. The operator shall also notify the Field Inspector or appropriate 

Conservation Division District Office within 48 hours after reclamation of 

the site has been completed.

(7) Time limits. Any noncommercial pit shall be closed within the time 

limits set forth in this paragraph. Any extension of time for pit closure 

must be requested by the operator, who shall file an application pursuant 

to OAC 165:5-7-33. A legal change of operator of any noncommercial pit 

shall not extend the time limit for closure. If a noncommercial pit is 

converted from one type of use to another, the last use shall determine the 

time limit for closure.

(A) Any Category 1A, 1B or 2 reserve/circulation pit, either on-site or 

off-site, shall be closed within twelve months after drilling operations 

cease.

(B) Any Category 3 reserve/circulation pit, either on-site or off-site, 

shall be closed within six months after drilling operations cease.

(C) Any Category 4 pit shall have closure procedures commenced within 

30 days and completed within 90 days after drilling operations cease.

(D) Completion/fracture/workover pits.

(i) Any reserve/circulation pit converted to a completion/fracture/ 

workover pit shall be closed within six (6) months after drilling 

operations cease. Upon request by the operator, a six (6) month 

extension shall be granted by the Conservation Division, after review 

by a field inspector to confirm the pit is in compliance with 165:10-

7-16 (c) and (d) requirements.

(ii) Any completion/fracture/workover pit not converted from a 

reserve/circulation pit shall be closed within 60 days after 

completion, fracture, or workover operations cease.

(E) Any emergency pit shall be emptied of its contents as soon as 

possible and closed within 60 days after the emergency situation ceases 

to exist.

(F) Any flare pit shall be closed within 30 days of abandonment of a 

lease.

(G) Any spill containment pit shall be closed within 30 days of 

abandonment of a lease.

(H) Any basic sediment pit shall be closed within 60 days after use of 

the pit ceases.

(I) Any recycling/reuse pit shall be closed within twelve months after 

operations cease.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 101 -

(J) Any remediation pit shall be closed immediately after receipt of 

all contaminated materials.

(8) For failure to comply with any closure requirement, the operator may 

be fined up to $1,000.00.

(9) Waiver of closure requirements. Exemption from closure and transfer 

of responsibility for any noncommercial pit to the surface owner or other 

party shall be requested by filing an application pursuant to OAC 165:5-7-

34. No approval shall be granted unless the analyses of the fluids show 

that the following ranges or concentrations are not exceeded:

(A) pH - 6.0-9.5 s.u.

(B) Chlorides - 3500 mg/l

(C) Total Dissolved Solids (TDS) or Total Soluble Salts (TSS)- 7000 mg 

mg/l

(D) Chromium (Total) - 10 mg/l

(E) Arsenic - 20 mg/l

(f) Flow back water pits with capacity in excess of 50,000 barrels.

(1) Scope: This subsection shall cover the permitting, construction, 

operation, and closure requirements for any noncommercial pit with a 

capacity in excess of 50,000 barrels used for the temporary storage of flow 

back water that is to be reused for hydraulic fracturing of wells. Such 

pits may be located either onsite or offsite of a well drilling location. 

Pits used to store only fresh water for fracturing of wells are addressed 

in OAC 165:10-7-16(b)(4). The permitting, construction, operation, and 

closure requirements for any noncommercial pit with a capacity of 50,000 

barrels or less used for temporary storage of flow back water that is to be 

reused for hydraulic fracturing of wells are addressed in OAC 165:10-7-

16(a)-(e).

(2) Application.

Prior to constructing any pit, the pit operator shall obtain a permit from 

the Manager of Field Operations or a Commission order authorizing the pit. 

For use of a pit without a permit or Commission order, the pit operator may 

be fined up to $5,000.00. Application for a pit permit shall be submitted 

to the Field Operations Department on Form 1014F.

(3) Application requirements. The pit operator shall attach to the Form 

1014F two complete sets of documents in support of the application, which 

documents shall include, but not be limited to, the following:

(A) Written permission from the surface owner allowing a pit to be 

constructed and used on the subject tract. 

(B) A lithologic log of test borings, identifying the subsurface 

materials encountered and the depth at which groundwater was encountered 

pursuant to (5)(A)(v) of this subsection.

(C) A topographic map of the pit site.

(D) The appropriate Soil Conservation Service (SCS) soil survey aerial 

photo and legend.

(E) A detailed drawing of the site, with complete construction plans 

drawn to scale by or under the supervision of a registered professional 

engineer.

(F) A plan for closure of the pit which shall provide for a minimum 

three feet of soil cover and shall specifically state how all aspects of 

closure shall be accomplished, including volume and fate of liquids, 

earthwork to close the pit (including placement of stockpiled topsoil), 

and revegetation of the site.

(G) An itemization of projected hauling, closure, reclamation, 

maintenance, and monitoring costs.

(H) A plan for post-closure maintenance and monitoring which shall 

address maintenance of the site as well as monitoring and plugging of 

wells. Exemption from the plugging of monitor wells may be obtained 

upon written request and approval of the Manager of Pollution Abatement.

(I) A plan for operation which shall address the method(s) by which 

excess water will be disposed.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 102 -

(4) Notice.

(A) Notice of application. Notice of the application for a permit for 

a pit with a capacity in excess of 100,000 barrels shall be published 

one time in a newspaper of general circulation in Oklahoma County, 

Oklahoma, and in a newspaper of general circulation published in each 

county in which the subject lands are located. The notice shall include 

the following information:

(i) The name, physical mailing address, telephone number, electronic 

mail address and facsimile number of the applicant or its 

representative, whom anyone may contact for additional information 

concerning the application.

(ii) The location of the proposed pit to the nearest 40 acre tract.

(iii) The capacity of the proposed pit.

(iv) The type of fluids to be stored in the proposed pit.

(v) The notice must also include the following language:

(I) Written protests to the relief sought must be submitted to 

the applicant or its representative and to the Manager of the 

Field Operations Department, Oklahoma Corporation Commission, P.O. 

Box 52000, Oklahoma City, OK, 73152-2000, within fifteen (15) days 

after publication of the notice. Written protests must specify 

the name of the applicant, location of the proposed pit, reasons 

for protest, and the name(s), physical mailing address(es), 

telephone number(s), electronic mail address(es) and facsimile 

number(s) of the protestant(s).

(II) If there are no written protests to the application and the 

Commission does not require a hearing, the application shall be 

presented to the Manager of the Field Operations Department for 

administrative review without a hearing, and if the application is 

protested, then any protestants shall receive notice of hearing.

(B) Proof of notice. The applicant shall submit affidavit(s) of 

publication to the Field Operations Department to show compliance with 

the requirements of subparagraph (4)(A) above.

(C) Procedure.

(i) If a written protest to the application is submitted to the 

Field Operations Department within fifteen (15) days after the date 

the notice of application is published, or if hearing is required by 

the Commission, the application shall be set for hearing and notice 

thereof given in the same manner required in the filing of an 

application on the Pollution Docket.

(ii) If no written protest is submitted to the Field Operations 

Department and the Commission does not require a hearing, the 

application shall be presented to the Manager of the Field Operations 

Department for administrative review.

(5) Construction requirements.

(A) Site limitations.

(i) Any pit that is to be constructed or operated in an area covered 

by a field or area rule shall be subject to the more stringent 

requirements of either this subsection or the field or area rule. 

(ii) No pit shall be constructed or used unless an investigation of 

the soils, topography, geology, and hydrology conclusively shows that 

storage of flow back water at the site will not be harmful to 

groundwater, surface water, soils, plants, or animals in the 

surrounding area. No pit shall be constructed or used on or in an 

abandoned mine, strip pit, quarry, canyon, or streambed.

(iii) No pit shall be constructed or used on any site that is 

located within a 100-year flood plain.

(iv) No pit shall be constructed or used within a wellhead 

protection area (WPA) as identified by the Wellhead Protection 

Program (42 USC Section 300h-7, Safe Drinking Water Act), or within 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 103 -

one mile of a public water well for which the WPA has not been 

delineated.

(v) No pit shall be constructed unless it can be shown that there 

will be a minimum of 25 feet between the bottom of the pit and the 

groundwater level. To ascertain this and to demonstrate the 

subsurface profile of the site, a minimum of three test borings (the 

exact number of locations to be determined by the Pollution Abatement 

Department) shall be drilled to a minimum depth of 25 feet below the 

proposed bottom of the pit and into the first free water encountered. 

Perched water tables are not considered for the purposes of this 

unit. Test borings need not extend deeper than 50 feet below the 

bottom of the pit if free water has not been encountered before that 

depth. All boreholes converted to monitor wells shall conform to 

(6)(A) of this subsection. All boreholes not converted to monitor 

wells shall be plugged from top to bottom with bentonite, cement, 

and/or other method approved by the Pollution Abatement Department 

within 30 days of drilling completion.

(B) Runoff water prohibited. No runoff water from surrounding land 

surfaces shall be allowed to enter a pit.

(C) Stockpiling of topsoil. Prior to constructing a pit, all topsoil 

within the top twelve inches of soil at the site shall be stockpiled for 

use as the final cover at the time of closure. The topsoil may be 

stockpiled in the outside slopes of the berms, provided it is not used 

for structural purposes and is readily distinguishable from other soil 

materials at the time of closure. 

(D) Maximum fluid depth. Any pit shall be constructed to contain a 

maximum fluid depth as authorized by the Manager of Field Operations on 

the Form 1014F, or in the Commission order authorizing the pit. A 

minimum freeboard of three feet shall be maintained.

(E) Maximum authorized volume. The maximum authorized volume allowed 

to be stored in a pit shall be calculated from three (3) feet below the 

point of the lowest elevation of the top of the berm wall.

(F) Width of the crown. The crown (top) of any berm shall be a minimum 

eight feet in width.

(G) Slopes. The inside slope of any exterior berm of the pit shall not 

be steeper than 3:1 (horizontal to vertical) and the outside slope of 

the pit shall not be steeper than 2.5:1. 

(H) Earthwork compaction. All earthwork shall be compacted to achieve 

a minimum 90% Standard Proctor Density and shall be applied in lifts 

where some method of bonding is achieved between lifts, with each lift 

not to exceed eight inches prior to compaction.

(I) Unique design requirements. For pits that may require special 

construction considerations, variances may be granted by the Manager of 

Field Operations or by Commission order if the proposed design meets or 

exceeds the requirements appearing in this subsection.

(J) Geomembrane liners.

(i) Pits permitted under this subsection must contain a geomembrane 

liner. The geomembrane liner must have a minimum thickness of 30 

mil.

(ii) The geomembrane liner shall be chemically compatible with the 

type of substances to be contained in the pit and shall have 

ultraviolet light protection sufficient to withstand the time the pit 

is to remain open.

(iii) The geomembrane liner shall be placed over a specially 

prepared, smooth, compacted surface void of sharp changes in 

elevation, rocks, clods, organic debris, or other objects. The pit 

operator shall notify the appropriate Conservation Division District 

Office at least two (2) business days prior to installation of the 

liner in the pit to afford a Commission representative an opportunity 

to inspect the site prior to the liner being installed. If a 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 104 -

Commission representative has not inspected the pit site within two 

(2) business days following notification, the pit operator may 

proceed to install the liner in the pit. 

(iv) The geomembrane liner shall be continuous, although it may 

include welded or extruded seams, and it must cover the bottom and 

interior sides of the pit entirely. Sewing of seams is prohibited. 

The edges shall be securely placed in a minimum twelve inch deep 

anchor trench around the perimeter of the pit. 

(K) Fluid level marker. A minimum of one stationary fluid level marker 

shall be erected in each pit. The marker shall be erected in a location 

within the pit where it can be easily observed. The marker shall be of 

such design that the maximum fluid level at any time may be clearly 

identified. Details of the proposed marker installation shall be 

approved by the Manager of Field Operations prior to installation. 

(L) Hydrologically sensitive areas. If the proposed pit is to be 

located over a hydrologically sensitive area, in addition to the 

foregoing construction requirements, the following additional 

requirements shall apply:

(i) A minimum 60-mil geomembrane liner or a minimum 30-mil 

geomembrane liner and a leachate collection system shall be required. 

(ii) The Manager of Pollution Abatement shall determine the minimum 

depth of all monitor wells.

(6) Monitor wells and leachate collection systems. 

(A) A minimum of three monitor wells-one (1) upgradient and two (2) 

downgradient from the pit-shall be installed. The exact number and 

location of the monitor wells shall be approved by the Manager of 

Pollution Abatement prior to installation. Additional monitor wells may 

be required for pits constructed in the general vicinity of public water 

supply wells, well head protection areas and hydrologically sensitive 

areas. No monitor well shall be installed more than 250 feet from the 

toe of the outside berm of the pit, nor shall any existing water well be 

used as a monitor well unless approved by the Manager of Pollution 

Abatement. All new monitor wells shall be drilled to a depth of at 

least ten feet below the top of the first free water encountered, and 

all monitor wells shall be drilled to a depth of at least ten feet below 

the base of the pit. All new monitor wells shall be drilled and 

completed by a licensed monitor well driller. If documentation is 

submitted to the Manager of Pollution Abatement prior to drilling the 

monitor wells to show that no free water will be encountered within 50 

feet below the bottom of the pit, the Manager of Pollution Abatement may 

give approval for the wells to be drilled to a lesser depth. All new 

monitor wells shall meet the requirements set out in rules established 

by the Oklahoma Water Resources Board, in addition to the following 

requirements:

(i) A removable and lockable cap shall be placed on top of the 

casing. The cap shall remain locked at all times, except when the 

well is being sampled.

(ii) Within 30 days of installation, specific completion information 

for all monitor wells shall be submitted to the Manager of Pollution 

Abatement.

(B) Leachate collection system: The pit operator may elect to install 

a leachate collection system in lieu of monitor wells, if such system 

will adequately detect any leak from the pit. The plan for the leachate 

collection system must accompany the Form 1014 and such plan must be 

approved by the Manager of Pollution Abatement prior to installation of 

the leachate collection system. 

(7) Monitor well and leachate collection system sampling. The pit 

operator shall sample the monitor wells or leachate collection system prior 

to placing any fluids other than fresh water in the pit. The following 

procedures shall be used:
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 105 -

(A) The appropriate Field Inspector shall be notified at least 24 hours

prior to sampling to allow a Commission representative an opportunity to 

witness the sampling.

(B) Samples shall be collected and handled by the pit operator 

according to EPA-approved standards. (RCRA Groundwater Monitoring 

Technical Enforcement Guidance Document, EPA, OSWER-9950.1, September 

1986, pp. 99-107.)

(C) If requested by a representative of the Conservation Division, a 

sufficient portion of each sample (approximately one (1) pint) shall be 

properly labeled and delivered or otherwise provided to the appropriate 

Conservation Division District Office or Field Inspector.

(D) All samples delivered to the laboratory shall be accompanied by a 

chain of custody form.

(E) All samples must be analyzed for pH and chlorides by a laboratory 

certified by the Oklahoma Department of Environmental Quality or 

operated by the State of Oklahoma. The Manager of Field Operations may 

require samples to be analyzed for additional constituents. 

(F) A copy of each analysis and a statement as to the depth to 

groundwater encountered in each well or leachate collection system, or 

an affidavit that no water was encountered, shall be forwarded to the 

appropriate Conservation Division District Office within 30 days of 

sampling.

(G) The pit operator is required to conduct sampling every six months 

after the date pit operations commence and for a minimum of one year 

after closure is completed. The Manager of Field Operations may require 

sampling on a more frequent basis.

(8) Liner certification. An affidavit signed by the person who was 

responsible for installing the pit liner, certifying that the liner meets 

minimum requirements and was installed in accordance with Commission rules, 

shall be submitted to the Manager of Field Operations before operation of 

the pit commences. Supporting documentation shall also be submitted, such 

as geomembrane liner specifications from the manufacturer, if requested by 

the District Manager.

(9) Pit approval. The pit operator shall notify the appropriate 

Conservation Division District Office at least two (2) business days prior 

to commencing pit operations to afford a Commission representative an 

opportunity to inspect the site. If a Commission representative has not 

inspected the pit site within two (2) business days following notification, 

the operator may commence pit operations, provided the affidavit and any 

supporting documentation referred to above has been submitted to the 

District Manager. 

(10) Operation and maintenance requirements.

(A) Vegetative cover. Vegetative cover shall be established on all 

areas of earthfill on the outside slope of the pit immediately after pit 

construction or during the first planting season following the 

construction of the pit if the pit construction is completed out of 

season. The cover shall be sufficient to protect those areas from soil 

erosion and shall be maintained. The Manager of Field Operations may 

approve alternative erosion control measures if the alternative method 

meets or exceeds the vegetative cover requirement.

(B) Fencing. The pit shall be completely enclosed by a fence at least 

four feet in height. No livestock shall be allowed inside the fence.

(C) Sign. A waterproof sign bearing the name of the pit operator, 

legal description, and emergency telephone number shall be posted within 

25 feet of the pit and shall be readily visible.

(D) Site security. All sites shall be secured by a locked gate. Fluids 

shall be placed in a pit only when representative(s) designated by the 

operator are present at the site if trucks are to be used in the 

operation. A key or combination to the lock shall be provided to the 

appropriate Field Inspector for the purpose of carrying out inspections. 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 106 -

(E) Acceptable materials. No operator of a flow back water pit shall 

place any substances in the pit other than flow back water or additional 

fresh water if required for hydraulic fracturing operations. The pit 

may receive flow back water from additional wells as long as the company 

authorized on the Form 1014F or in a Commission order operates or is a 

working interest owner in the additional wells. Another operator may 

use the pit on a temporary basis if the pit operator submits to and 

obtains the Commission's approval of an amended Form 1014F permitting 

such temporary use.

(F) Oil film.

(i) The flow back water pit shall not contain an oil film.

(ii) The protection of migratory birds shall be the responsibility 

of the pit operator. Therefore, the Conservation Division recommends 

that to prevent the loss of birds, oil films be removed as soon as 

possible from the pit or that the surface of the pit be protected 

from access to birds. [See Advisory Notice in OAC 165:10-7-3(c)].

(G) Aesthetics. All pit sites shall be maintained so that there is no 

junk iron or cable, oil or chemical drums, paint cans, domestic trash, 

or debris on the premises.

(H) Structural integrity. All pits shall be used, operated, and 

maintained at all times so as to prevent the escape of their contents. 

All erosion, cracking, sloughing, settling, animal burrows, or other 

condition that threatens the structural stability of any earthfill shall 

be repaired immediately upon discovery.

(I) Time period for operation. The period of time during which the 

pit is to remain in operation shall be specified on the approved Form 

1014F or Commission order.

(11) Prevention of pollution. All flow back water pits shall be used, 

operated, and maintained at all times so as to prevent pollution. In the 

event of a non-permitted discharge, sufficient measures shall be taken to 

stop or control the loss of materials, and reporting procedures in OAC 

165:10-7-5(c) shall be followed. Any materials lost due to such discharge 

shall be cleaned up as directed by a representative of the Conservation 

Division. For a willful non-permitted discharge, the pit operator may be 

fined up to $5,000.00.

(12) Closure requirements.

(A) Notification. The Manager of Field Operations shall be notified in 

writing whenever the pit becomes inactive, or operation of the pit 

ceases for any reason.

(B) Time limit. Closure shall be commenced within 60 days and 

completed within one year of when the pit becomes inactive or cessation 

of operations. In cases where extenuating circumstances exist, one 

extension of six (6) months may be administratively approved in writing 

by the Manager of Field Operations. The pit operator must file an 

application and notice of hearing pursuant to OAC 165:5-7-1 et seq. and 

obtain the issuance of a Commission order concerning any additional 

request for an extension of time for pit closure. 

(C) Trenching. Trenching, stirring or other similar practice shall be 

prohibited with respect to the pit.

(D) Preserving integrity of liner. Extreme care shall be taken to 

preserve the integrity of the liner when closing the pit. All fluids 

shall be removed from the pit when closing the pit. Once fluids have 

been removed from the pit, the liner may be folded and closed in place.

(E) Soil cover. A minimum of three feet of soil cover shall be placed 

over the pit, with all stockpiled topsoil being applied last. The soil 

cover shall be mounded or sloped to encourage runoff and so as to 

prevent erosion. The Manager of Field Operations may require the pit 

operator to establish a vegetative cover over the pit. The pit operator 

can request a variance to these requirements by submitting a written 

request and supporting documentation to the Manager of Field Operations. 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 107 -

The Manager of Field Operations shall respond in writing within five (5) 

business days after receipt of a request for a variance to the 

requirements in this subsection from the pit operator. 

(F) Notification to appropriate Conservation Division District Office. 

The pit operator shall notify the appropriate Field Inspector or 

appropriate Conservation Division District Office at least 48 hours 

prior to commencing closure. The pit operator shall also notify the 

Field Inspector or appropriate Conservation Division District Office 

within 48 hours after reclamation of the site has been completed.

(G) Penalty for failure to comply with closure requirements. A pit 

operator failing to comply with the closure requirements set out in this 

subsection may be fined up to $1,000.00.

(H) Post closure monitoring. The pit operator is required to sample the 

monitor wells or leachate collection system at the site for a minimum of 

one year after closure of the pit is completed, and the pit operator 

must comply with the sampling and reporting requirements appearing in 

OAC 165:10-7-16(f)(7), above. Variances to the post closure monitoring 

and reporting requirements may be granted in writing by the Manager of 

Field Operations if an approved leachate collection system has been 

employed at the site and if additional hydrogeologic data which 

demonstrates the pit has not leaked is submitted to and accepted by the 

Manager of Field Operations.

(13) Surety requirements.

(A) Agreement with Commission. The operator of a flow back water pit 

shall file with the Manager of Document Handling for the Conservation 

Division an agreement to properly close and reclaim the site in 

accordance with approved closure and reclamation procedures upon 

termination of operations. The agreement shall be on forms available 

from the Conservation Division and shall be accompanied by surety. The 

agreement shall provide that if the Commission finds that the operator 

has failed or refused to close the pit or take remedial action as 

required by law and the rules of the Commission, the surety shall pay to 

the Commission the full amount of the operator's obligation up to the 

limit of the surety.

(B) Surety amount and type. The Manager of Field Operations shall 

establish the amount of surety for the authority to construct and/or 

operate the pit. The amount of surety shall be based on factors such as 

dimensions of the pit and costs of hauling, closure, reclamation, and 

monitoring. The amount may be subject to change for good cause. Upon 

approved closure of a pit, the Manager of Field Operations may reduce 

the surety requirement to an amount which would cover the cost of 

monitoring the site and plugging the monitor wells. Surety shall be 

maintained for as long as monitoring is required. The type of surety 

shall be a corporate surety bond, certificate of deposit, or irrevocable 

letter of credit. Any type of surety that expires shall be renewed prior 

to 30 days before the expiration date.

(14) Application to existing pits. Operators of pits permitted prior to 

the effective date of this subsection must either comply with parts 

(f)(6)(monitor wells and leachate collection systems), (f)(7)(monitor well 

and leachate collection system sampling) and (f)(13)(surety requirements) 

or close such pits within one (1) year of the effective date of this 

subsection. Operators of pits permitted prior to the effective date of 

this subsection must also comply with parts (f)(5)(K) (fluid level marker), 

(f)(10)(operation and maintenance requirements), (f)(11) (prevention of 

pollution) and (f)(12)(closure requirements). All pits permitted but not 

yet constructed as of the effective date of this subsection shall also be 

subject to the construction requirements in part (f)(5). 

(15) Variances. Except as otherwise provided in this subsection, 

variances from provisions of this subsection may be granted for good cause 

by order after application, notice, and hearing.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 108 -

[Source: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 12 Ok Reg 2017, 

eff 7-1-95; Amended at 16 Ok Reg 2230, eff 7-1-99 (RM 980000035); Amended at 

23 Ok Reg 2229, eff 7-1-06 (RM 200600012); Amended at 24 Ok Reg 1796 (RM 

200700004), eff 7-1-2007; Amended at 25 OK Reg 2187, eff 7-11-08 (RM 

200800003); Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 

28 Ok Reg 1949, eff. 7-11-11 (RM 201000007); Amended at 29 Ok Reg 950, eff. 7-

1-12 (RM 201200005); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001); 

Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001]

165:10-7-17. Surface discharge of fluids

(a) Scope. This Section shall cover the surface discharge of hydrostatic 

test water, storm water from diked areas, and produced water from tanks or 

other containment vessels.

(b) Discharge of hydrostatic test water. 

(1) Hydrostatic test water used in the testing of new pipeline segments, 

new casing, new tubing, new tanks and new vessels, may be discharged as 

necessary without a permit, notification to the Commission, or adherence to

any other provisions of this Section, provided the following conditions are 

met:

(A) Low chlorides. Chloride concentration does not exceed 1000 mg/l.

(B) Sheen. There shall be no visible sheen or discoloration as a 

result of testing; however, certain dyes used to establish mechanical 

integrity may be approved.

(C) Notice to appropriate Conservation Division District Office. Any 

discharges exceeding 1,000 barrels shall require notification to the 

appropriate Conservation Division District Office.

(2) Hydrostatic test water used in the testing of existing tanks, vessel 

lines and transmission pipelines may be discharged upon notification to the 

Oklahoma Corporation Commission appropriate Conservation Division District 

Office on Form 1014HD provided that the following conditions are met:

(A) Oil and grease. The oil and grease content of the discharge water 

shall not exceed 15 mg/l.

(B) Sheen. There shall be no visible sheen or discoloration as a 

result of testing; however, certain dyes used to establish mechanical 

integrity may be approved.

(C) Total Suspended Solids. The Total Suspended Solids shall not 

exceed 45 mg/l.

(D) pH. The pH shall not be less than 6.5 nor exceed 9 s.u.

(E) Foreign material. The discharge must be free from foreign material 

such as welding scrap tank sediments or sand blasting waste material.

(F) Soil erosion. Standard soil erosion prevention procedures shall be 

required.

(3) Hydrostatic test water that meets the requirements listed in (b) (2) 

of this Section may be discharged in volumes less than 15 bbls without 

filing Form 1014HD.

(4) Hydrostatic test water that will be discharged to land and not 

directly into waters of the state and which may exceed the discharge 

parameters specified in (b)(2), shall be discharged only upon submission 

and approval by the Pollution Abatement Department of a plan for one-time 

discharge.

(5) Hydrostatic test water not covered under (b)(1) from transmission 

lines and tanks that contain waste products that are listed as hazardous 

waste under the Resource Conservation and Recovery Act and have not been 

cleaned or pigged must meet the following discharge requirements in 

addition to (b)(2) of this Section:

(A) The following parameters may not be exceeded: Benzene, .028 MG/L; 

toluene, .3 MG/L; phenol, .250 MG/L.

(B) EPA analytical method 8020 shall be used unless approved by the 

Manager of Pollution Abatement.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 109 -

(c) Discharge of storm water. Storm water accumulations in any diked area 

built for the containment of tank battery spills may be discharged as 

necessary without a permit, notification to the Commission, or adherence to 

any other provisions of this Section, provided the following conditions are 

met:

(1) No hydrocarbons. A visual inspection of the storm water is made and 

there is no sheen or other visible evidence of hydrocarbons being present.

(2) Low chlorides. Chloride concentration does not exceed 1000 mg/l.

(3) Conditions recorded. The operator records the conditions required by 

(1) and (2) in this subsection for each discharge, maintains those records 

for a period of three (3) years, and makes them available upon request to 

any representative of the Field Operations Department.

(d) Discharge of produced water.

(1) Site restrictions. Discharge of produced water shall only occur on 

land having an Exchangeable Sodium Percentage (ESP) no greater than 15, 

pursuant to (f)(3) of this Section, and all of the following 

characteristics as determined by the appropriate Soil Conservation District 

or by a qualified soils expert:

(A) A maximum slope of five percent.

(B) Depth to bedrock at least 20 inches.

(C) Slight salinity (defined as electrical conductivity less than 4,000 

micromhos/cm) in the topsoil or upper six inches of the soil.

(D) A water table deeper than six feet from the soil surface, except a 

perched water table.

(E) A minimum distance of 100 feet from any stream designated by 

Oklahoma Water Quality Standards (available for viewing at the 

Commission's Oklahoma City Office and appropriate Conservation Division 

District Offices) or any fresh water pond, lake, or wetland (designated 

by the National Wetlands Inventory Map Series, prepared by the U.S. Fish 

and Wildlife Service and available for viewing at the Commission's 

Oklahoma City Office).

(2) Water quality limitations. A surface discharge permit shall not be 

issued if the produced water to be discharged exceeds either of the 

following concentrations:

(A) Total Dissolved Solids (TDS) or Total Soluble Salts (TSS) - 5000 

mg/l.

(B) Oil and Grease - 1000 mg/l.

(e) Sampling requirements.

(1) Contact with appropriate Conservation Division District Office. The 

appropriate Conservation Division District Office shall be contacted at 

least two business days prior to sampling to allow a Commission 

representative an opportunity to witness the sampling of the receiving soil 

and produced water to be discharged. A variance from this provision may be 

granted by the appropriate Conservation Division District Office for 

justifiable cause. A written request and supporting documentation shall be 

required. The appropriate Conservation Division District Office shall 

respond in writing within five working days after receipt, either approving 

or disapproving the request.

(2) Produced water. Produced water to be discharged shall be sampled 

using the following procedure, unless exempt pursuant to (f)(4) of this 

Section.

(A) Prior to sampling, fresh water shall not be added to any tank or 

other containment vessel for dilution or any other purpose.

(B) A sample of the produced water to be discharged shall be taken from 

the bottom of the tank or other containment vessel. A minimum two quart 

sample shall be placed into a foil or teflon covered, glass container. 

The container shall be filled completely to exclude air and delivered to 

the laboratory within seven days. No samples shall be altered in any 

way.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 110 -

(C) Another sample of the produced water to be discharged 

(approximately one pint) shall be properly labeled and delivered or 

otherwise provided to the appropriate Conservation Division District 

Office or Field Inspector, unless exempt by the District Manager.

(3) Receiving soil. Soil samples shall be taken from the proposed 

discharge area and analyzed, unless exempt pursuant to (f)(4) of this 

Section. A minimum of 20 representative surface core samples (0-6 inches) 

must be taken from each sample area, combined and thoroughly mixed, then a 

minimum one pint composite sample taken and placed in a clean container for 

delivery to the lab. No sample area shall exceed 40 acres.

(f) Analysis requirements.

(1) Certified laboratory. The samples of soil and produced water shall be 

analyzed by a laboratory operated by the State of Oklahoma or certified by 

the Department of Environmental Quality or in the North American 

Proficiency Testing System, unless exempt pursuant to (4) of this 

subsection.

(2) Parameters for produced water. Parameters for analysis of the 

produced water shall include, but not be limited to, Total Dissolved Solids 

(TDS) or Total Soluble Salts (TSS) and Oil and Grease.

(3) Parameters for soil. Parameters for analysis of the receiving soil 

shall include, but not be limited to, Electrical Conductivity or Total 

Soluble Salts (TSS) and Exchangeable Sodium Percentage (ESP).

(4) Exemptions. The appropriate Conservation Division District Office may 

exempt the analysis of produced water if an analysis of the produced water 

from a well located within one mile and producing from the same formation 

has been previously submitted. Analysis of the receiving soil may be 

exempt if an analysis of the same soil type(s) within one mile of the 

proposed discharge site has been previously submitted.

(g) Application for permit.

(1) Permit required. No person shall discharge produced water from a tank 

or other containment vessel without applying for and obtaining a permit 

issued under this subsection. An operator discharging produced water 

without a permit may be fined up to $1,000.00.

(2) Who may apply. Only the operator of the well associated with the tank 

or other containment vessel, the contents of which are sought to be 

discharged, may apply for a surface discharge permit.

(3) Required form and attachments. Each application for surface discharge 

of produced water shall be submitted to the appropriate Conservation 

Division District Office on Form 1014D in quadruplicate. The forms shall 

be properly completed and signed. Attached to at least one of the forms 

shall be the following:

(A) A copy of written notice to the surface owner that the applicant 

intends to discharge produced water as per 165:10-7-17 to a specific 

portion of real property as designated by legal description.

(B) If the operator has an agent, a contractual agreement between the 

parties or an affidavit designating the contractor or agent (Form 

1014LA).

(C) A well prepared map or diagram, drawn to scale, showing the 

proposed and potential discharge areas.

(D) Site suitability report, pursuant to (d)(1) of this Section, 

provided by a qualified soils expert (include qualifications).

(E) Analysis of produced water, unless exempt pursuant to (f)(4) of 

this Section.

(F) Soil analysis, unless exempt pursuant to (f)(4) of this Section.

(G) Other information as required by this Section or requested by the 

appropriate Conservation Division District Office.

(4) Review period. The appropriate Conservation Division District Office 

shall review the application, either approve or disapprove it, and return a 

copy of Form 1014D within five business days of submission of all required 

or requested information. If approved, a permit number shall be assigned 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 111 -

to Form 1014D; if disapproved, the reason(s) shall be given. The applicant 

may make application for a hearing if it is not approved.

(h) Maximum application rate.

(1) Soil loading standards. The maximum application rate shall be 

calculated by the appropriate Conservation Division District Office using 

the following soil loading standards. (Soil loading standards are based 

upon standards set forth in "Diagnosis and Improvement of Saline and 

Alkaline Soils," U.S. Agriculture Handbook 60. Pub. U.S. Salinity 

Laboratory, Riverdale, California, 1954. "Critical Concentrations for 

Irrigation Water Supplies," Water Quality Criteria, 1972 Ecological 

Research Series, EPA R2-73033, March, 1973).

(A) Total Soluble Salts - 6,000 lbs/acre (less TSS in soil).

(B) Oil and Grease - 500 lbs/acre.

(2) Determination of most limiting parameter. The maximum application 

rate shall be restricted by the most limiting parameter. It may require 

more than one application to achieve the maximum application rate while 

avoiding runoff. The appropriate Conservation Division District Office 

shall indicate on the permit what the maximum application rate shall be 

after making the following calculations:

PROCEDURE FOR CALCULATING APPLICATION RATE OF TOTAL SOLUBLE SALTS (TSS)

 ppm TSS in soil1 X 2 = lbs/ac TSS in soil

6000 lbs/ac TSS - lbs/ac TSS in soil = Maximum TSS (lbs/ac) to be 

applied

Maximum TSS (lbs/ac)  ( ppm TSS in water1 X .000001) = 

Maximum lbs/ac of water to be applied 

Maximum lbs/ac  lbs/bbl2 = Maximum bbls/ac 

PROCEDURE FOR CALCULATING APPLICATION RATE OF OIL AND GREASE

500 lbs/ac  ( ppm in water X .000001) = Maximum lbs/ac of water 

to be applied 

Maximum lbs/ac  lbs/bbl2 = Maximum bbls/ac 

1Electrical Conductivity (EC expressed in micromhos/cm) may be used to estimate 

TSS: EC x 0.64 = ppm TSS.

2Based on documented weight of composite sample.

(i) Conditions of permit. Any discharge of produced water that is done under 

this Section shall be subject to the following conditions or stipulations of 

the permit.

(1) Presence of representative. A representative of the operator shall be 

on the discharge site at all times that water is being applied. A variance 

from this provision may be granted by the appropriate Conservation Division 

District Office for justifiable cause. A written request and supporting 

documentation shall be required. The appropriate Conservation Division 

District Office shall respond in writing within five business days after 

receipt, either approving or disapproving the request.

(2) Weather restrictions. Surface discharge shall not be done:

(A) During precipitation events or when precipitation is imminent.

(B) When the soil moisture content is at a level such that the soil 

would not readily take the addition of water.

(C) When the ground is frozen.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 112 -

(D) By spray irrigation when the wind velocity is such that even 

distribution of water cannot be accomplished or the buffer zones, 

pursuant to (3) of this subsection, cannot be maintained.

(3) Buffer zones. Surface discharge shall not be done within the 

following buffer zones:

(A) Fifty feet of a property line boundary.

(B) Fifty feet of any stream not designated by Oklahoma Water Quality 

Standards.

(C) Three hundred feet of any actively-producing water well used for 

domestic or irrigation purposes.

(D) Eight hundred feet of any public water well.

(4) Application rate. The maximum application rate of produced water 

stipulated by the permit shall not be exceeded. Application of produced 

water outside the approved plot shall be prohibited. Accurate records 

shall be kept as to the quantities discharged and the dates of each 

discharge.

(5) Discharge method. Discharge of produced water shall be uniform over 

the approved discharge plot and shall be made by spray irrigation or other 

method approved by the Commission prior to use. The flood irrigation 

method shall be limited to those fields that normally are irrigated in that 

manner.

(6) Runoff or ponding prohibited. No runoff or ponding of discharged 

water shall be allowed during application.

(7) Annual report. An annual report shall be submitted by April 1 of each 

year and shall be made on Form 1014P. Attached to the annual report shall 

be current (within three months) analyses of the produced water and soil 

from the discharge plot, pursuant to (8) of this subsection.

(8) Additional testing. The produced water shall be analyzed annually and 

the receiving soils shall be sampled and analyzed a minimum of every five 

(5) years, pursuant to (e)(1) through (e)(3) and (f)(1) through (f)(3) of 

this Section. When 75 percent of the maximum permitted application volume 

of TSS or Oil and Grease [(h) of this Section] has been applied or when the 

ESP exceeds 11, water and soil sampling shall be done quarterly or 

semiannually as determined by the appropriate Conservation Division 

District Office.

(9) Expiration of permit. The permit shall expire by its own terms when 

testing, pursuant to (8) of this subsection, indicates that the 

concentration of TSS or Oil and Grease in the water exceeds the limitations 

of (d)(2) of this Section, or more than 98 percent of the maximum 

application rate of TSS or Oil and Grease [(h) of this Section] has been 

applied or the ESP exceeds 15.

(10) Violations. If the applicant violates the conditions of the permit 

or this Section, the surface discharge shall be discontinued and the 

appropriate Conservation Division District Office shall be contacted 

immediately. The appropriate Conservation Division District Office may 

revoke the permit and/or require the operator to do remedial work. If the 

permit is not revoked, surface discharge may resume with Field Operations' 

approval. If the permit is revoked, the operator may make application for 

a hearing to reinstate it.

(j) Discharge from reserve pits. Water accumulation in any reserve pit used 

for the containment of air drilling cuttings or water-based drilling fluids 

may be discharged to land provided a permit is obtained from the Commission. 

Any operator discharging without a permit may be fined $5,000.00.

(1) Who may apply. Only the operator of the well or the operator’s 

designated agent may apply for the permit.

(2) Required form and attachments. Application for discharge of water to 

land shall be submitted to the appropriate Conservation Division District 

Office on Form 1014X. Attached to the application shall be the following:

(A) Written permission of the surface owner. For purposes of obtaining 

this permission, the applicant shall use Form 1014L.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 113 -

(B) A topographic map(s) with the location of the discharge area.

(C) Analysis of the water.

(D) Copies of all chain of custody forms.

(E) If there is an agent, a notarized affidavit designating the agent, 

signed by the operator (Form 1014LA).

(3) Conditions of permit.

(A) Notice to field inspector. The applicant shall notify the 

appropriate Conservation Division District Office at least 24 hours 

prior to discharge to allow a Commission representative an opportunity 

to be present.

(B) Presence of representative. A representative of the operator shall 

be on the discharge site at all times during discharge.

(C) Condition of water.

(i) Chloride content must not exceed 1,000 mg/l and TDS must not 

exceed 1,500 mg/l.

(ii) Sheen. There must be no visible sheen or discoloration as a 

result of drilling operations.

(iii) pH. The pH shall not be less than 6.5 nor exceed 9 standard 

units.

(D) Foreign material. The discharge shall be free of foreign material 

such as debris, sediments, and drilling mud solids.

(E) Maximum slope. A maximum slope of 5% if vehicles with a diffusion 

system are to be used; a maximum slope of 8% if a spray irrigation 

system is used.

(F) All discharge must be a minimum of 100 feet from any perennial 

stream, pond, lake or wetland and 50 feet from any intermittent stream. 

All land applications shall be a minimum of 50 feet from any property 

line.

(G) Land application method. The land application equipment must be 

approved by the Commission prior to use. The application method must 

not allow soil erosion to occur. If the irrigation method is to be 

used, the area must be terraced or appropriate erosion control methods 

shall be used. The integrity of the pit wall shall be maintained at all 

times to avoid the discharge of drilling mud solids.

(H) Runoff prohibited. No runoff shall be allowed. Ponding may be 

allowed as long as practices are in place that will not allow the water 

to run into creeks or drainage ways.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; amended at 13 Ok Reg 2381, eff 

7-1-96; Amended at 14 Ok Reg 2198, eff 7-1-97 (RM 97000002); Amended at 23 Ok 

Reg 2229, eff 7-1-06 (RM 200600012); Amended at 24 Ok Reg 1784, eff 7-1-07 (RM 

200700004); Amended at 25 OK Reg 2187, eff 7-11-08 (RM 200800003); Amended at 27 

Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 30 Ok Reg 1041, eff. 7-1-13 

(RM 201300001); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-18. Discharge to surface waters

 Discharge of deleterious substances to streams or other surface waters is 

prohibited except by order of the Commission; unless permitted by a valid 

National Pollutant Discharge Elimination System (NPDES) Permit issued by U.S. 

EPA.

165:10-7-19. Land application of water-based fluids from earthen pits, tanks and 

pipeline construction

(a) Authority for land application. No person shall land apply fluids except as 

provided by 165:10-9-2, 165:10-7-17, or this Section. Any operator failing to 

obtain a permit may be fined up to $2,000.

(b) Scope. This Section shall cover the land application of water-based 

drilling fluids and cuttings from earthen pits, tanks, or other containment 

structures; however, this Section shall not be exclusive of other authorities for 

land application listed in (a) of this Section. Any land application made under 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 114 -

this Section shall be done from a single well or pipeline construction location. 

Permits shall not be granted for lands that have been previously permitted and 

used for these practices or similar practices such as soil remediation within the 

last three (3) years.

(c) Site suitability restrictions. Land application shall only occur on land 

having all of the following characteristics below, as field verified by a soil 

scientist or other qualified person pre-approved by the Commission. Any variance 

from site suitability restrictions must be approved by the Oil and Gas 

Conservation Division (see (f)(2)(C) of this Section).

(1) Maximum slope. A maximum slope of eight percent for all application 

methods.

(2) Depth to bedrock. Depth to bedrock must be at least 20 inches.

(3) Soil texture. A soil profile (as defined by USDA soil surveys) 

containing at least twelve inches (may be cumulative) of one of the following 

soil textures between the surface and the water table, unless a documented 

impeding layer of shale is present: loam, silt loam, silt, sandy clay loam, 

silty clay loam, clay loam, sandy loam, fine sandy loam, sandy clay, silty 

clay, or clay.

(4) Salinity. Slight salinity [defined as Electrical Conductivity (EC) less 

than 4,000 micromhos/cm] in the topsoil, or upper six inches of the soil, and 

a calculated Exchangeable Sodium Percentage (ESP) less than 10.0.

(5) Depth to water table. No evidence of a seasonal water table within 

six (6) feet of the soil surface as verified by field observation and 

published data.

(6) Distance from water bodies. A minimum distance of 100 feet from the land 

application site boundary to any perennial stream and 50 feet to any 

intermittent stream shown on the appropriate United States Geological Survey 

(U.S.G.S.) topographic map (available for viewing at the Commission's Oklahoma 

City Office and appropriate Conservation Division District Offices) and a 

minimum of 100 feet to any freshwater pond, lake, or wetland. [Designated by 

the National Wetlands Inventory Map Series, prepared by the U.S. Fish and 

Wildlife Service, available for viewing at the Commission's Oklahoma City 

Office (also, see (h)(6) of this Section)].

(7) Site specific concerns. Void of slick spots within or adjacent to the 

land application area, where subsurface lateral movement of water is unlikely, 

or areas void of concentrated surface flow such as gullies or waterways.

(8) Stockpiling of cuttings. Stockpiling of cuttings may be used during the 

handling and transportation of the cuttings both at the well and pipeline 

construction location and the receiving site. At the well site or pad 

generating the waste or pipeline construction location the cuttings must be 

placed in a steel pit or the areas used for this practice must be lined and 

bermed if required by the appropriate Conservation Division District Office. 

A stockpile of cuttings at the receiving site must be located within the 

permitted area and the areas used for this practice must be lined and bermed 

if required by the appropriate Conservation Division District Office. The 

stockpile of cuttings, whether at the well or pipeline construction location 

or the receiving site, must be closed within 30 days of cessation of drilling 

operations.

(d) Sampling requirements.

(1) Notice to Field Inspector. The appropriate Field Inspector shall be 

contacted at least two business days prior to sampling of the receiving soil 

and sampling of the drilling fluids and/or cuttings to be land applied from an 

earthen pit. This is to allow a Commission representative an opportunity to 

be present.

(2) Receiving soil. Sampling of the receiving soil shall be performed by, or 

under the supervision of, a soil scientist or other qualified person preapproved by the Commission. Soil samples shall be taken from the proposed 

application area and analyzed. A minimum of four representative core samples 

from the surface (0-6 inches) must be taken from each ten acres, or part 

thereof. Each group of surface core samples representative of a ten-acre area 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 115 -

(or less) shall be combined and thoroughly mixed. A minimum one-pint composite 

sample shall be taken and placed in a clean container for delivery to the 

laboratory. Alternatively, soil samples may be composited by the laboratory. 

(3) Drilling fluids and/or cuttings.

(A) Earthen pits. Drilling fluids and/or cuttings to be land applied 

shall be sampled using the following procedure:

(i) Prior to sampling, fresh water (except natural precipitation) shall 

not be added to any pit for dilution or any other purpose.

(ii) A minimum of four samples, each from different quadrants of the 

pit and representative of the materials to be land applied, must be 

taken if the volume to be land applied is 25,000 bbls. or less. If more 

than 25,000 bbls. are to be land applied, a minimum of four quadrant 

samples plus one sample for each 5,000 bbls. over 25,000 bbls. will be 

required. The samples shall be combined and thoroughly mixed, then a 

minimum two quart composite sample placed into a foil or teflon covered 

glass container. The container shall be filled completely to exclude 

air and delivered to the laboratory within seven days. No samples shall 

be altered in any way.

(iii) After samples have been taken for analysis from a pit, the 

operator shall not allow the addition of fluids or other materials, 

except natural precipitation or fresh water to decrease the viscosity of 

the fluid.

(B) Tanks. Sampling of the drilling fluids and/or cuttings shall occur 

after the application has been approved. A minimum of one representative 

sample must be taken from each tank, the contents of which are to be land 

applied.

(e) Analysis requirements.

(1) Testing.

(A) The composite sample(s) of soil shall be tested by a laboratory 

operated by the State of Oklahoma or certified by the Oklahoma Department 

of Environmental Quality or in the North American Proficiency Testing 

System. Either a 1:1 extract or saturated paste extract shall be used for 

sample preparation.

(B) Methods of analysis.

(i) Earthen pits. The composite sample(s) of drilling fluids and/or 

cuttings shall be analyzed by a laboratory operated by the State of 

Oklahoma or certified by the Oklahoma Department of Environmental 

Quality or in the North American Proficiency Testing System.

(ii) Tanks. Samples of the drilling fluids and/or cuttings may be 

tested on-site. A filter press shall be used for preparation of 

samples. Tests must be performed by a person who is knowledgeable and 

experienced in the chemical testing of fluids. Acceptable on-site 

testing protocol may be obtained from the appropriate Conservation 

Division District Office.

(2) Parameters for receiving soil. Parameters for analysis of the receiving 

soil shall include at a minimum EC and ESP.

(3) Parameters for drilling fluids and/or cuttings.

(A) Earthen pits. Parameters for analysis of the drilling fluids and/or 

cuttings shall include at a minimum EC and Oil and Grease (O&G). Dry 

Weight shall also be determined if a significant amount of solids will be 

land applied.

(B) Tanks. EC shall be a required parameter for analysis of drilling 

fluids and/or cuttings. Dry weight shall also be determined if a 

significant amount of solids will be land applied.

(f) Application for permit.

(1) Who may apply. Only the operator of a well or pipeline or the operator’s

designated agent may apply for a land application permit under this Section, 

except that a commercial pit operator may also apply in case of emergency or 

for the purpose of facilitating repair or closure.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 116 -

(2) Required form and attachments. Each application for land application of 

drilling fluids and/or cuttings shall be submitted to the Pollution Abatement 

Department on Form 1014S. A legible original shall be required. The 

following shall be attached to the application:

(A) Written permission from the surface owner to allow the applicant to 

land apply drilling fluids and/or cuttings. For purposes of obtaining such 

consent, the applicant shall use Form 1014L.

(B) A topographic map and the most recent aerial photograph (minimum scale 

1:660) with the proposed and potential land application areas delineated as 

well as the location of cultural features such as buildings, water wells, 

etc. Both the topographic map and aerial photograph must show all areas 

within 1,320 feet of the boundary of the land application area.

(C) A site suitability report, pursuant to subsections (c) and (h)(6) of 

this Section, based on an on-site investigation and signed by a soil 

scientist or other qualified person. The report shall include detailed 

information concerning the site and shall discuss how all site 

characteristics were determined. Any requests for a variance to site 

suitability restrictions must be accompanied by a written justification 

that has been developed or approved by a soil scientist or other qualified 

person. The justification shall provide explanation as to safeguards which 

will assure that conditions of the permit will be met and there will be no 

adverse impacts from the land application.

(D) Analysis of drilling fluids and/or cuttings (for earthen pits only).

(E) Analyses of soil samples.

(F) Loading calculations.

(G) Copies of all chains-of-custody related to sampling.

(H) Manufacturer, model number, and specifications of testing equipment to 

be used (for tanks only).

(I) If there is an agent, a notarized affidavit designating same, signed 

by the operator within the last twelve months (Form 1014LA).

(J) Identification of any soil farming permit that has been issued in the 

same quarter section within the last three years. This information is 

available in the OCC Soil Farming Database on the web at www.occeweb.com.

(K) Other information as required by this Section or requested by the 

Pollution Abatement Department.

(3) Review period. The Pollution Abatement Department shall review the 

application, either approve or disapprove it, and return a copy of Form 1014S 

within five business days of submission of all required or requested 

information. If approved, a permit number shall be assigned to Form 1014S; if 

disapproved, the reason(s) shall be given. The applicant may make application 

for a hearing if it is not approved.

(g) Calculating maximum application rate.

(1) Earthen pits.

(A) The maximum application rate shall be calculated by the applicant or 

the applicant’s designated agent based on the analyses of the pit materials 

and the soil of the application area. The averaging of TDS or TSS values 

of soil sampling areas shall not be permitted. If the entire application 

area is larger than ten acres, requiring separate soil sampling areas, the 

applicant or the applicant’s designated agent shall use the highest soil 

TDS or TSS value of any sampling area in calculating the maximum 

application rate for the entire application area, and shall also calculate 

the maximum application rate of each ten acre (or less) application area 

using the respective TDS or TSS values of each soil sampling area. The 

applicant or the applicant’s designated agent shall decide which of the two 

loading rates to use and notify the appropriate Conservation Division 

District Office when notification of commencement of land application is 

given, pursuant to (h)(1) of this Section.

(B) Soil loading formulas contained in Appendix I shall be used.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 117 -

(C) The maximum application rate shall be restricted by the most limiting 

parameter. The Pollution Abatement Department shall indicate on the permit 

the maximum application rate and the minimum acreage that must be used.

(2) Tanks.

(A) The applicant shall calculate the maximum application rate based on 

the analysis of each tank or other containment vessel to be land applied 

and the soil of the application area. The averaging of TDS or TSS values 

of soil sampling areas shall not be permitted. If the entire application 

area is larger than ten acres, requiring separate soil sampling areas, the 

applicant shall have the option of using the highest soil TDS or TSS value 

of any sampling area in calculating the maximum application rate for the 

entire application area, or calculating the maximum application rate of 

each ten-acre (or less) application area using the respective TDS or TSS 

value of each soil sampling area.

(B) Soil loading formulas contained in Appendix I shall be used.

(C) Based on the maximum application rate, the applicant or its designated 

agent shall determine where the fluids will be applied and supervise the 

land application process. 

(h) Conditions of permit. Any land application which is performed under this 

Section shall be subject to the following conditions or stipulations of the 

permit:

(1) Notice to Field Inspector. The applicant shall notify the appropriate 

Field Inspector at least 24 hours prior to the commencement of land 

application to allow a Commission representative an opportunity to be present.

(2) Compliance agreement. Any person responsible for supervision of land 

application shall have signed a compliance agreement with the Commission (Form 

1014CA).

(3) Presence of representative. A representative of the applicant shall be 

on the land application site at all times during which fluids and/or cuttings 

are being applied. The representative shall be an employee of the applicant, 

designated agent, contractor, or other person pre-approved by the Commission.

(4) Materials to be land applied. Land application shall be limited to 

water-based drilling fluids and/or cuttings.

(5) Weather restrictions. Land application, including incorporation, shall 

not be done:

(A) During precipitation events.

(B) When the soil moisture content is at a level such that the soil cannot 

readily take the addition of drilling fluids.

(C) When the ground is frozen to a degree that the soil cannot readily 

take the addition of fluids.

(D) By spray irrigation when the wind velocity is such that even 

distribution of materials cannot be accomplished or the buffer zones, 

pursuant to (6) of this subsection, cannot be maintained.

(6) Buffer zones. Land application shall not be done within the following 

buffer zones, as identified in the site suitability report:

(A) Fifty feet of a property line boundary.

(B) Three hundred feet of any water well or water supply lake used for 

domestic or irrigation purposes.

(C) One-quarter (1/4) mile of any public water well or public water supply 

lake.

(7) Land application rate. The maximum calculated application rate of 

drilling fluids and/or cuttings shall not be exceeded. It may require more 

than one pass to achieve the maximum application rate while avoiding runoff or 

ponding, pursuant to (9) of this subsection. Application of drilling fluids 

and/or cuttings outside the approved plot shall be prohibited.

(8) Land application method.

(A) Application of drilling fluids and/or cuttings shall be uniform over 

the approved land application plot, shall not be applied at a rate to cause 

permanent vegetation damage, and shall be made by a method approved by the 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 118 -

Commission prior to use. The flood irrigation method shall be limited to 

those fields that normally are irrigated in that manner.

(B) For earthen pits, if more than 500 lbs/acre of Oil and Grease or 

50,000 lbs/acre of Dry Weight materials are applied, the materials shall be 

incorporated into the soil by use of the injection method, or by disking or 

some other method approved by the Commission.

(C) An application vehicle shall be either a single or double axle vehicle 

with a permanently attached tank that shall not exceed 100 barrels, and the 

vehicle shall be equipped so as to minimize pooling and ruts caused by tire 

tracks. It shall have a diffuser mechanism to spread the mud in a fan 

pattern. The mud will be forced from the tank with air pressure or a 

mechanical pump. Transport/tanker trucks (18 wheelers) shall not be used 

for land application. Use of an unauthorized vehicle may result in the 

revocation of the land application permit. A fine of up to $2,000.00 may 

be assessed for violation of this paragraph.

(D) Drill cuttings shall be spread with an industrial mechanical spreader

capable of broadcasting and fanning out the cuttings.

(9) Runoff or ponding prohibited. No runoff of land applied materials shall 

be allowed during application. Ponding is prohibited, except where the flood 

irrigation method is approved. In order to comply with this rule, some 

applications will require the use of more than the minimum calculated acreage 

and/or a drying period between applications.

(10) Vegetative cover. If the vegetative cover is destroyed or significantly 

damaged by disking, injection, or other practice associated with land 

application, a bona fide effort shall be made to restore or reestablish the 

vegetative cover within 180 days after the land application is completed. 

Additional efforts shall be made until the vegetative cover is fully restored 

or reestablished.

(11) Time period.

(A) Earthen pits. Land application shall be completed within 90 days from 

the date of the permit. At the end of the 90-day period, the permit shall 

expire by its own terms.

(B) Tanks. Land application shall be completed within 90 days after 

drilling ceases. At the end of the 90-day period, the permit shall expire 

by its own terms.

(12) Post-application report. A post-application report (Form 1014R) shall 

be submitted by the operator or the operator’s agent to the Manager of the 

Pollution Abatement Department within 90 days of the completion of land 

application. One extension may be granted for a period of up to 90 days by 

the Manager of the Pollution Abatement Department. If approval is obtained to 

amend the permit to authorize land application of contaminated soils and 

petroleum hydrocarbon based cuttings, any extension of time for submission of 

the post-application report granted by the Manager of the Pollution Abatement 

Department shall begin on the date the amended permit is approved. The report 

shall give specific details of the land application, including test results of 

materials applied and loading rate calculations (for tanks only), volumes of 

materials applied, and an aerial photograph (minimum scale 1:660) delineating 

the actual area where materials were applied. All applicable loading 

calculations from Appendix I of this Chapter shall be included in the Form 

1014R. The report shall contain a statement certifying that the land 

application was done in accordance with the approved permit. Failure to 

timely submit a Form 1014R may result in the assessment of a fine of up to 

$500.00.

(13) Violations. If the applicant violates the conditions of the permit or 

this Section, the land application shall be discontinued and the Pollution 

Abatement Department shall be contacted immediately. The Pollution Abatement 

Department may revoke the permit and/or require the operator to do remedial 

work. If the permit is not revoked, land application may resume with the 

Pollution Abatement Department's approval. If the permit is revoked,` the 

operator may make application for a hearing to reinstate it.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 119 -

(14) Requirements to close pit. Neither filing an application nor receiving 

a permit under this Section shall extend the time limit for closing a reserve 

pit pursuant to 165:10-7-16, or a commercial pit pursuant to 165:10-9-1.

(i) Variances. A variance from the time provisions of (d)(1), (h)(1), or 

(h)(10) of this Section may be granted by the appropriate Conservation Division 

District Office for justifiable cause. A written request and supporting 

documentation shall be required. The appropriate Conservation Division 

District Office shall respond in writing within five business days after 

receipt, either approving or disapproving the request.

[SOURCE: Amended at 14 Ok Reg 2198, eff 7-1-97 (RM 97000002); Amended at 23 Ok 

Reg 2229, eff 7-1-06 (RM 200600012); Amended at 25 OK Reg 2187, eff 7-11-08 (RM 

200800003); Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 

29 Ok Reg 950, eff. 7-1-12 (RM 201200005); Amended at 30 Ok Reg 1041, eff. 7-1-

13 (RM 201300001); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001]

165:10-7-20. Noncommercial disposal or enhanced recovery well pits used for 

temporary storage of saltwater

(a) Scope. This Section shall apply to any production operation where a pit 

is used for temporary storage of saltwater, except (c)(7) of this Section, 

which shall apply to any noncommercial well, regardless of whether or not a 

pit is used. Any pit sought to be approved pursuant to this Section will 

require a permit. The operator of the proposed pit shall submit Form 1014 in 

duplicate to the appropriate Conservation Division District Office for review 

and approval.

(b) Construction requirements.

(1) Splash pad/apron. A splash pad/apron shall be constructed at the 

unloading area of any noncommercial disposal well or enhanced recovery pit 

to the design and dimensions necessary to contain and direct all materials 

unloaded into the pit, unless the pit is of such design that discharge 

directly into it presents no spill potential.

(2) Pit specifications. Except as provided by (4)(A) of this subsection, 

any noncommercial disposal or enhanced recovery well pit shall be 

constructed of concrete or steel or be lined with a geomembrane liner 

according to the following:

(A) Concrete pits must be steel reinforced and have a minimum wall 

thickness of six inches.

(B) Steel pits must have a minimum wall thickness of three-sixteenths 

(3/16) inch. A previously used steel pit may be installed, provided it 

is free of corrosion or other damage.

(C) Geomembrane liners must:

(i) Have a minimum thickness of 30 mils, be chemically compatible 

with the type of wastes to be contained, and have ultraviolet light 

protection.

(ii) Be placed over a specially prepared, smooth, compacted surface 

void of sharp changes in elevation, rocks, clods, organic debris, or 

other objects.

(iii) Be continuous (may include seams) and cover the bottom and 

interior sides of the pit entirely. The edges must be securely 

placed in a minimum twelve inch deep anchor trench around the 

perimeter of the pit.

(3) Certification of liner. The operator of any saltwater storage pit 

that is constructed with a geomembrane liner shall secure an affidavit 

signed by the installer, certifying that the liner meets minimum 

requirements and was installed in accordance with Commission rules. It 

shall be the operator's responsibility to maintain the affidavit and all 

supporting documentation pertaining to the liner, such as geomembrane liner 

specifications from the manufacturer, etc., and shall make them available 

to a representative of the Conservation Division upon request.

(4) Monitoring of site.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 120 -

(A) If not constructed according to one of the three methods in (2) of 

this subsection, any noncommercial disposal or enhanced recovery well 

pit shall be required to have a leachate collection system or at least 

one monitor well, unless it can be shown that the pit is not located 

over a hydrologically sensitive area. The District Manager may require 

more than one monitor well if he has reason to believe one would not be 

sufficient to adequately monitor the site.

(B) Any monitor well shall be installed within 100 feet of the pit. An 

existing nearby water well may be used as a monitor well upon written 

approval by the District Manager or Manager of Field Operations.

(C) Any new monitor well shall be drilled to a depth of at least ten 

feet below the top of the first free water encountered and shall be 

drilled and completed by a licensed monitor well driller. If 

documentation is submitted to the District Manager prior to drilling the 

monitor well to show that no free water will be encountered within a 

depth of 50 feet from the surface, the District Manager may allow the 

monitor well(s) to be drilled to a lesser depth or eliminated.

(D) Any new monitor well shall meet the requirements as set out in 

rules established by the Oklahoma Water Resources Board, in addition to 

the following requirements:

(i) A removable and lockable cap placed on top of the casing. The 

cap must remain locked at all times, except when a well is being 

sampled.

(ii) Within 30 days of installation, construction details for any 

leachate collection system or specific completion information for any 

monitor well and a diagram of the location of any monitor well in 

relation to the pit shall be submitted to the Manager of Field 

Operations.

(c) Operation and maintenance requirements.

(1) Fencing. All noncommercial disposal or enhanced recovery well surface 

facilities that have a pit shall be completely enclosed by a fence at least 

four feet in height. Said fence shall be constructed in such a manner as 

to prevent livestock from entering the pit area.

(2) Site maintenance. The normal access surface of any well site that has 

a pit, including the access road(s), shall be maintained in a condition 

that will safely and easily allow access.

(3) Exclusion of runoff water. No pit shall be allowed to receive runoff 

water.

(4) Freeboard. The fluid level in any concrete or steel noncommercial 

disposal or enhanced recovery well pit shall be maintained at all times at 

least six inches below the top of the pit wall. Any geomembrane lined pit 

shall have a minimum of 18 inches of freeboard at all times.

(5) Temporary storage only. No pit shall be used as permanent storage for 

salt water.

(6) Sampling of monitor wells or leachate collection systems.

(A) Sampling of monitor wells and leachate collection systems shall 

occur once every six months, during the months of January and July.

(B) The appropriate District Manager shall be notified at least 24 

hours in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(C) Samples shall be collected, preserved, and handled by the operator 

according to EPA approved standards (RCRA Groundwater Monitoring 

Technical Enforcement Guidance Document, EPA, OSWER-9950.1, September, 

1986, pp. 99-107) and analyzed for pH, chlorides (Cl) and total 

dissolved solids (TDS) by a laboratory certified by the Oklahoma 

Department of Environmental Quality or operated by the State of 

Oklahoma. Analysis of additional parameters may be required as 

determined by the District Manager or Manager of Field Operations. A 

copy of each analysis and a statement as to the depth to groundwater 

encountered in each well, or an affidavit that no water was encountered, 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 121 -

shall be forwarded to the Manager of Field Operations, within 30 days of 

sampling.

(7) Prevention of pollution. All noncommercial disposal or enhanced 

recovery wells shall be maintained at all times so as to prevent pollution. 

In the event of a nonpermitted discharge from surface facilities, 

sufficient measures shall be taken immediately to stop, contain, and 

control the loss of materials. Reporting of said discharge shall be in 

compliance with 165:10-7-5(c). Any materials lost due to such discharge 

shall be cleaned up as directed by a representative of the Conservation 

Division of the Commission.

(8) Oil film. The operator of a saltwater pit shall be responsible for 

the protection of migratory birds. Therefore, the Conservation Division 

recommends that to prevent the loss of birds due to oil films, all open top 

tanks and pits containing fluid be kept free of oil films or sludge or be 

protected from access to birds. [See Advisory Notice 165:10-7-3(c)]

(d) Closure requirements.

(1) Time limit. Within 180 days of the cessation of operations, all 

associated pits shall be emptied of all contents, and either removed or 

filled with soil. All monitor wells shall be plugged with bentonite or 

cement, unless exempt in writing by the District Manager or Manager of 

Field Operations. The site shall be revegetated within one (1) year.

(2) Burial. If any concrete, steel, geomembrane, or other materials 

associated with the site are to be left on-site, they shall be buried under 

a minimum soil cover of three feet, pursuant to 165:10-3-17.

(e) Prospective application to existing facilities. All provisions of this 

Section, except those in (b)(2) and (b)(3), shall apply to all existing pits 

within the scope of this Section which are, or have been, in operation prior 

to the effective date of this Section. Operators shall have one (1) year from 

the effective date of this Section in which to bring their facilities into 

compliance with the applicable provisions of this Section. Failure to comply 

with any applicable provision may result in revocation of the authority to 

operate.

(f) Variances.

(1) A variance from the time requirements of (c)(6), (d)(1), or (e) of 

this Section may be granted by the District Manager or Manager of Field 

Operations for justifiable cause. A written request and justifiable 

explanation is required. The District Manager or Manager of Field 

Operations shall respond in writing within five business days, either 

approving or disapproving the request.

(2) Any variance from the liner requirements as required under (b)(2) of 

this Section may be granted by the Manager of Field Operations after 

receipt of a written request and supporting documentation required by the 

department.

[SOURCE: Amended in Rule Making 980000034, eff 7-1-99; Amended in Rule Making 

200600012, eff 7-1-2006; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 29 Ok Reg 950, eff. 7-1-12 (RM 201200005); Amended at 

32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-21. Refining and processing of oil and gas

(a) All deleterious substances obtained or used in the processing and 

refining of oil and gas shall be disposed of in a manner that will prevent the 

pollution of fresh water.

(b) Chemicals, gasolines, oil, and other deleterious substances shall be 

stored, where necessary, in tanks or containers of a material and of a 

construction and in a manner that will prevent the escaping, seepage, or 

draining of such liquids into any fresh water.

165:10-7-22. Permits for County Commissioners to apply waste oil, waste oil 

residue, or crude oil contaminated soil to roads
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 122 -

(a) Prohibition against application of waste oil, waste oil residue, or crude 

oil contaminated soil without permit. This Section prohibits any Board of 

County Commissioners from applying waste oil, waste oil residue, or crude oil 

contaminated soil to a street or road without a permit.

(b) Permit by appropriate Conservation Division District Office. A District 

Manager for the Conservation Division may issue to a Board of County 

Commissioners for a county within the district a permit to apply waste oil, 

waste oil residue, or crude oil contaminated soil to a street or road within 

the county.

(c) Permit requirements.

(1) Use of Form 1014W. The application and permit to apply waste oil, 

waste oil residue, or crude oil contaminated soil shall be made on Form 

1014W.

(2) Telephone permits. In case of emergency, a District Manager may issue 

a permit by telephone. If an applicant obtains a permit by telephone, then 

the applicant shall file Form 1014W and attachment within five business

days after receipt of the permit by telephone.

(3) Conditions for permit. 

(A) Waste oil, waste oil residue, and contaminated soils applied under 

this Section shall consist of crude oil and materials produced with 

crude oil only and shall not contain any refined oils such as motor 

oils, lubricants, compressor oils or hydraulic fluids.

(B) If required by the District Manager, a hydrocarbon analysis shall 

be submitted with Form 1014W. The analysis shall be performed by a 

laboratory certified by the Oklahoma Department of Environmental Quality 

or operated by the State of Oklahoma in accordance with OCC-approved 

methods.

(C) Waste oil, waste oil residue, and crude oil contaminated soil shall 

be applied in such a manner that pollution of surface or subsurface 

waters will not likely occur and public and private property adjoining 

the street or road will be protected.

(D) During operations for road oiling, all necessary signs, lights, and 

other safety and warning devices shall be used to alert road users to 

conditions. A sign shall be posted with the contractor or authority's 

name and phone number to contact in case of emergency.

(E) Following completion of the project there shall be a uniform 

soil/oil base (all liquid worked in), with no visible free-standing oil.

(F) Proper care shall be taken to avoid runoff of oil or water into 

borrow ditches or adjacent areas.

(G) No road oiling shall be conducted:

(i) When the temperature is less than 45 F.

(ii) In any area where water collects and stands.

(iii) Where soil moisture content or road conditions such as soil 

type, tight soil conditions, packed soil conditions, or grade limits 

prevent rapid absorption of the oil.

(d) Notice to appropriate Conservation Division District Office. The Board 

of County Commissioners receiving the permit shall notify the appropriate 

Conservation Division District Office at least two days prior to commencement 

of road oiling under a permit.

(e) Site inspection. At his discretion, a District Manager may request a 

Field Inspector of the Conservation Division or an Enforcement Officer of the 

Transportation Division to inspect the site at any time during the road oiling 

operation to ensure compliance with this Section.

(f) Duration of permit. The permit shall state the duration of the permit, 

and it shall also state that if the application fails to comply with either 

the terms of the permit or the terms of this Section, then the permit shall 

terminate automatically.

(g) Disapproval or cancellation of permits. 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 123 -

(1) If a District Manager receives a complaint about a road oiling permit, 

he shall cause an investigation of the complaint to be made as soon as 

practicable. During the investigation, the District Manager may direct the 

applicant to cease road oiling under a permit. If necessary, the District 

Manager may verbally revoke the permit.

(2) If a District Manager disapproves an application or cancels a permit, 

the applicant may apply to the Commission for an order under OAC 165:5-7-

41.

[Source: Amended at 12 Ok Reg 2017, eff 7-1-95; Amended in Rule Making 

200600012, eff 7-1-2006; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-23. Disposal of waste oil 

(a) All waste oil and waste oil residue shall be disposed of in one of the 

following ways:

(1) Transfer or sale to a reclaimer or transporter.

(2) Transfer or sale to County Commissioners.

(3) Administrative approval from the Conservation Division.

(b) All operators or owners of pits, tanks, commercial disposal operations, 

or reclaimers shall maintain books and records describing the disposition of 

all waste oil or waste oil residue. A copy of the run or load ticket will 

satisfy this requirement if the information required in (c) of this Section is 

contained therein.

(c) The following information shall be contained in said books and records 

and subject to audit and inspection by representatives of the Commission for a 

minimum period of three years:

(1) The amount of waste oil or waste oil residue removed.

(2) The location of the waste oil or waste oil residue prior to disposal.

(3) The destination of waste oil or waste oil residue as reported by 

transporter.

(4) The name of the transporter of waste oil or waste oil residue.

165:10-7-24. Waste management practices reference chart

(a) Scope. This Section provides reference guidelines for the disposal of 

wastes under the jurisdiction of the Commission which are generated by oil and 

gas operators and pipeline companies. Hazardous waste as defined at 40 CFR 

261.3 is regulated by the Oklahoma Department of Environmental Quality.

(b) Waste materials and disposal options. Consistent with EPA's policy on 

source reduction, recycling, treatment and proper disposal, operators shall 

use waste management practices as listed in (c) of this Section which 

describes the various management practices for the following waste materials. 

For any of the following waste materials where option (16) of subsection (c) 

is listed, option (16) shall be considered before any other option.

(1) Produced water: Options 1, 7 & 9

(2) Weighted water: Options 1 & 7 

(3) Used treatment fluids, frac sand, and other flowback wastes: Options 

1, 2, 5 & 7 and, for frac sand only, options 3 & 20

(4) Water based mud: Options 1, 2, 5, 6, 7, 8 & 19

(5) Water based mud cuttings: Options 1, 2, 3, 4, 5, 6, 7, 8, 12 & 19

(6) Oil based mud: Options 1, 2, 3, 4, 5, 7, 12 & 22

(7) Oil based mud cuttings: Options 1, 2, 3, 4, 5, 7, 8, 12 & 14

(8) Crude oil: Options 1, 4, 12, 13 & 14

(9) Used motor, gear, lube, compressor and hydraulic oils: Options 1, 15 

& 16

(10) Used solvents: Options 1, 15 & 16

(11) Oily debris: Options 1, 3, 13 & 20

(12) Filter media and backwash: Options 1, 3, 7, 15, 16 & 20

(13) Glycol, amine, and caustic wash: Options 1 & 7

(14) Iron sponge: Options 3 & 20
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 124 -

(15) Molecular sieve: Options 3 & 20

(16) Produced sand/sediment: Options 3, 7, 8, 17 & 20

(17) Tight emulsions: Options 1, 4, 8, 12, 14 & 17

(18) Unused treatment chemicals: Options 1, 15 & 16

(19) Tank bottoms from E&P: Options 1, 3, 4, 7, 8, 10, 12, 14 & 17

(20) Paraffin: Options 1, 3, 4, 12, 14, 15, 16 & 20

(21) Asbestos insulation: Options 3 & 15

(22) Non-asbestos insulation: Options 3, 15 & 20

(23) Used batteries: Options 1, 3, 15 & 16

(24) Oils containing PCBs: Option 11

(25) Oils not containing PCBs: Options 1, 15 & 16

(26) Empty oil and chemical drums: Options 1, 3 & 15

(27) Salt contaminated soils: Options 5, 6, 8 & 17

(28) Crude oil contaminated soils: Options 1, 3, 4, 8, 10, 12, 14, 17 & 

22

(29) Pit sludges from wellsites, disposal well pits and gathering systems: 

Options 1, 3, 4, 7, 8, 12, 17 & 20

(30) Gathering line pigging wastes: Options 1, 3, 7 & 20

(31) Gas plant sweetening wastes: Options 1, 3, 7 & 20

(32) Gas plant dehydration wastes: Options 1, 3 & 7

(33) Cooling tower blowdown from gas plants: Options 7 & 15

(34) Wastes from subsurface natural gas storage: Options 1, 3, 7 & 20

(35) Wastes other than refined product removed from produced water and 

other well fluids prior to injection or disposal: Options 1, 7, 8, 17 & 20

(36) Gases removed from the production stream: Options 1, 7, 13 & 18

(37) Waste crude oil and light hydrocarbons (gas condensate) in reserve 

pits, other impoundments or tankage at wellsites: Options 1, 7, 8, 13 & 17

(38) Contaminated ground water (except refined products): Options 1, 7, 

21 & 22

(39) Pipeline sludge and other deposits removed from pipe or equipment on 

E&P gathering systems: Options 1, 3, 7, 8, 10, 17 & 20

(40) Residues and truckwash from inside the tank of trucks used to 

transport saltwater, drilling mud or spent completion fluids: Options 1, 

3, 7 & 20

(41) Sewage and wastes from portable toilets: Option 15

(42) Crude pipeline pigging wastes, contaminated soil and residue from 

transmission and trunk lines: Options 1, 3, 4, 8, 12, 15, 16, 17 & 22

(43) Water or soil contaminated by refined product from E&P operations: 

Options 1, 16, 21 & 22

(44) Rigwash and supply water: Options 1, 5, 7 & 8

(45) Storm water and hydrostatic test water from E&P operations: Options 

1, 7, 9 & 22

(46) Spent filters: Options 1 & 3 

(47) Trash and debris: Options 15 & 20

(48) Refined petroleum product releases: Options 1, 3, 8, 13, 16, 17 & 22

(49) Refined petroleum product pigging wastes: Options 1, 3, 8, 15, 16, 

17 & 22

(50) Water or soil contaminated by refined products from pipelines: 

Options 1, 16, 21 & 22

(51) Hydrostatic test water from pipelines: Options 1, 9, 16 & 22

(52) Tank bottoms from crude pipeline facilities: Options 1, 3, 4, 8, 10, 

12, 14, 16, 17 & 22

(53) Tank bottoms from refined product pipeline facilities: Options 1, 3, 

14, 15, 16, 17 & 22

(54) Water based mud and cuttings associated with pipeline construction: 

Options 6 and 8 (165:10-7-19 only)

(c) Disposal options and rule reference guide. The following waste disposal 

options are referenced in (b) of this Section:

(1) Reclaim and/or recycle.

(2) Burial (in accordance with 165:10-7-16).
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 125 -

(3) Landfills regulated by the Oklahoma Department of Environmental 

Quality.

(4) Road applications by County Commissioners (in accordance with 165:10-

7-22 and 165:10-7-28).

(5) Noncommercial pits (in accordance with 165:10-7-16).

(6) Commercial mud disposal pits (in accordance with 165:10-9-1).

(7) Underground injection (in accordance with 165:10-5-1 through 165:10-5-

14).

(8) Land application (in accordance with 165:10-7-19 and 165:10-7-26).

(9) Discharge (in accordance with 165:10-7-17).

(10) Reclaim and/or recycle (in accordance with 165:10-7-23).

(11) In accordance with EPA; Code of Federal Regulations (CFR), Title 40, 

Part 761.60 through 761.79.

(12) Application to lease roads, well locations, and production sites (in 

accordance with 165:10-7-27 and 165:10-7-29).

(13) Open burning in accordance with Oklahoma Department of Environmental 

Quality regulations.

(14) Disposal of waste oil as specified in 165:10-7-23.

(15) Disposal in accordance with Oklahoma Department of Environmental 

Quality regulations.

(16) If the waste is determined to be a hazardous waste under the Federal 

Resource Conservation and Recovery Act (RCRA), disposal will be determined 

by the Oklahoma Department of Environmental Quality; if a non-hazardous 

waste, Option 17 may be used or other disposal option as approved by the 

Commission.

(17) On-site or in-situ bioremediation/remediation.

(18) Flaring or venting (in accordance with 165:10-3-15).

(19) Commercial soil farming (in accordance with 165:10-9-2).

(20) Burial as approved by the Commission.

(21) Surface discharge as approved by the Commission.

(22) Land application as approved by the Commission.

[Source: Amended at 12 Ok Reg 2039, eff 7-1-95; Amended at 14 Ok Reg 2198, eff 

7-1-97 (RM 97000002); Amended at 19 Ok Reg 1947, eff 7-1-02 (RM 200200017); 

Amended at 25 Ok Reg 2187, eff 7-11-08 (RM 200800003); Amended at 29 Ok Reg 

950, eff 7-1-12 (RM 201200005); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001)]

165:10-7-25. One-time land application of water-based fluids from tanks or 

other containment vessels [REVOKED]

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Revoked in Rule Making 97000002, 

eff 7-1-97]

165:10-7-26. Land application of contaminated soils and petroleum hydrocarbon 

based drill cuttings

(a) Authority for land application. No person shall land apply soils or drill 

cuttings contaminated by salt or petroleum hydrocarbons except as provided by 

this Section. Any operator failing to obtain a permit may be fined up to 

$2,000.00.

(b) Scope. This Section shall cover the land application of soils and drill 

cuttings contaminated by salt and/or petroleum hydrocarbons. Petroleum 

hydrocarbon-contaminated soils land applied under this Section shall meet the 

RCRA criteria for exempt or non-exempt/nonhazardous waste. [Reference 40 CFR

Subtitle C and EPA publication EPA530-K-95-003 "Crude Oil and Natural Gas 

Exploration and Production Wastes: Exemption from RCRA Subtitle C Regulation]. 

Hazardous waste as defined at 40 CFR 261.3 is regulated by the Oklahoma 

Department of Environmental Quality. Any land application made under this 

Section shall be done from a single well. Permits shall not be granted for 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 126 -

lands that have been previously permitted and used for this practice or similar 

practices such as soil remediation within the last three (3) years.

(c) Receiving site suitability restrictions. Land application shall only occur 

on land having all of the characteristics below, as field verified by a soil 

scientist or other qualified person pre-approved by the Commission. Any 

variance from site suitability restrictions must be approved by the Oil and Gas 

Conservation Division (see (g)(2)(C) of this Section).

(1) Maximum slope. A maximum slope of eight percent for all application 

methods.

(2) Depth to bedrock. Depth to bedrock will be at least 20 inches if crude 

oil contaminated soils or petroleum hydrocarbon-based drill cuttings are to 

be applied; 20 inches if salt contaminated soils are to be applied.

(3) Soil texture. A soil profile (as defined by USDA soil surveys) 

containing at least twelve inches (may be cumulative) of one of the following 

soil textures between the surface and the water table, unless a documented 

impeding layer of shale is present: loam, silt loam, silt, sandy clay loam, 

silty clay loam, clay loam, sandy loam, fine sandy loam, sandy clay, silty 

clay, or clay.

(4) Salinity. Slight salinity [defined as Electrical Conductivity (EC) less 

than 4,000 micromhos/cm] in the topsoil, or upper six inches of the soil, and 

a calculated Exchangeable Sodium Percentage (ESP) less than 10.0.

(5) Depth to water table. No evidence of a seasonal water table within six 

(6) feet of the soil surface as verified by field observation and published 

data.

(6) Distance from water bodies. A minimum distance of 100 feet from the 

land application site boundary to any perennial stream and 50 feet to any 

intermittent stream found on the appropriate United States Geological Survey 

(U.S.G.S.) topographic map (available for viewing at the Commission's 

Oklahoma City Office and appropriate Conservation Division District 

Offices); and a minimum of 100 feet to any freshwater pond, lake, or wetland 

designated by the National Wetlands Inventory Map Series, prepared by the 

U.S. Fish and Wildlife Service (available for viewing at the Commission's 

Oklahoma City Office). Also, see (h)(6) of this Section.

(7) Site specific concerns. Void of slick spots within or adjacent to the 

land application area, where subsurface lateral movement of water is 

unlikely, or areas void of concentrated surface flow such as gullies or 

waterways.

(8) Stockpiling of cuttings. Stockpiling of cuttings may be used during the 

handling and transportation of the cuttings both at the well location and the 

receiving site. At the well site or pad generating the waste, the cuttings

must be placed in a steel pit or the areas used for this practice must be 

lined and bermed if required by the appropriate Conservation Division 

District Office. A stockpile of cuttings at the receiving site must be 

located on the permitted area. The stockpile of cuttings, whether at the well 

location or the receiving site, must be closed within 30 days of cessation of 

drilling operations.

(d) Sampling requirements.

(1) Notice to Field Inspector. The appropriate Field Inspectors shall be 

contacted at least two business days prior to sampling of the receiving soil 

and materials to be land applied. This is to allow a Commission 

representative an opportunity to be present.

(2) Receiving soil. Sampling of the receiving soil shall be performed by, 

or under the supervision of, a soil scientist or other qualified person preapproved by the Commission. Soil samples shall be taken from the proposed 

application area and analyzed. A minimum of four representative surface core 

samples from the surface (0-6 inches) must be taken from each ten acres, or 

part thereof. Each group of surface core samples representative of a tenacre area (or less) shall be combined and thoroughly mixed. A minimum one 

pint composite sample shall be taken and placed in a clean container for 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 127 -

delivery to the laboratory. Alternatively, soil samples may be composited by 

the laboratory. 

(3) Materials to be land applied. Representative samples of the materials 

to be land applied shall be taken, composited into a minimum one-pint sample, 

and placed in a clean container for delivery to the laboratory. 

Alternatively, materials to be land applied may be composited by the 

laboratory.

(e) Analysis requirements. 

(1) Salt contaminated soils or drill cuttings. Analysis requirements will 

be dependent upon the loading method that is chosen. For most applications, 

loading based on Total Dissolved Solids (TDS) or Total Soluble Salts (TSS) 

will be most appropriate. However, applicants proposing to land apply on a 

site in western Oklahoma, where the soils commonly contain moderate to high 

levels of gypsum, may benefit from using the loading formula based on 

Chlorides (Cl).

(A) Samples of soil and materials to be land applied shall be tested by a 

laboratory proficient in testing soils. Either a 1:1 extract or saturated 

paste extract shall be used for sample preparation for TDS or TSS or Cl 

loading. A saturated paste moisture equivalent is necessary where the 

saturated paste sample preparation method is used.

(B) Parameters for analysis of the receiving soil shall include at a 

minimum EC, TDS or TSS, and ESP for TDS/TSS loading. For Chloride 

loading, parameters shall include Chlorides (dry weight basis) and ESP.

(C) Parameters for analysis of soils or drill cuttings contaminated by 

salt shall include at a minimum EC for TDS/TSS loading and both EC and Cl 

for Chloride loading.

(2) Soils and drill cuttings contaminated by petroleum hydrocarbons.

(A) Samples of soil and materials to be land applied shall be tested by a 

laboratory proficient in testing soils.

(B) Parameters for analysis of the receiving soil shall include at a 

minimum EC and ESP.

(C) Parameters for analysis of soils or drill cuttings contaminated by 

petroleum hydrocarbons shall include at a minimum a test of the 

appropriate carbon range(s), which is determined by the nature of the 

waste material. These include Gasoline Range Organics (GRO) - C6 to C10 

(EPA test method 8015/8020 M) and TPH (Oklahoma method 1005 extended C35).

(f) Application rates.

(1) Calculations. The maximum application rate for TDS or TSS, Cl, and GRO, 

or TPH shall be calculated by the applicant based upon the analyses of the 

materials to be land applied and the soil of the application area. For salt 

contaminated soils or drill cuttings, if the application area encompasses 

more than one soil sampling area, the rate shall be calculated in one of two 

ways, depending on how the application will be made. The applicant may 

either calculate the maximum application rate for the entire application area 

based upon the highest soil TDS or TSS or Cl value of any sampling area 

(averaging not allowed), or calculate it for each ten acre (or less) 

application area using the respective soil TDS or TSS or Cl values of each 

sampling area.

(2) Soil loading formulas. The maximum application rate for any application 

area shall be restricted by the most limiting parameter. To determine this, 

the soil loading formulas in Appendix I of this Chapter shall be used as 

applicable.

(3) Variances. In special situations, a request for a variance relating to 

soil loading of petroleum hydrocarbons may be administratively approved by 

the Manager of the Pollution Abatement Department. The applicant shall 

submit a written request explaining the circumstances or conditions which 

warrant a variance and shall also submit a management plan for reducing the 

petroleum hydrocarbon content in the soil to two percent or less.

(g) Application for permit.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 128 -

(1) Who may apply. Only the operator responsible for generating the waste 

to be land applied or the operator’s designated agent may apply for a land 

application permit, except that the Oklahoma Energy Resources Board or its 

designated contractor may make application to land apply materials for which 

there is no responsible party.

(2) Required form and attachments. Each application for land application of 

soils contaminated by salt and/or crude oil or petroleum hydrocarboncontaining deleterious substances shall be submitted to the Pollution 

Abatement Department on Form 1014S. A legible original shall be required. 

The following shall be attached to the application: 

(A) Written permission from the surface owner to allow the applicant to 

land apply, incorporate, and fertilize materials. For purposes of 

obtaining such consent, the applicant shall use Form 1014L.

(B) A topographic map and the most recent aerial photograph (minimum 

scale 1:660) with the proposed and potential land application areas 

delineated as well as the location of cultural features such as 

buildings, water wells, etc. Both the topographic map and aerial 

photograph must show all areas within 1320 feet of the boundary of the 

land application area.

(C) Receiving site suitability report, pursuant to subsections (c) and 

(h)(6) of this Section, based on an on-site investigation and signed by a 

soil scientist or other qualified person. The report shall include 

detailed information concerning the site and shall discuss how all site 

characteristics were determined. Any requests for a variance to site 

suitability restrictions must be accompanied by a written justification 

that has been developed or approved by a soil scientist or other qualified 

person. The justification shall provide explanation as to safeguards 

which will assure that conditions of the permit will be met and there will 

be no adverse impacts from the land application.

(D) Analyses of receiving soil samples.

(E) Analyses of contaminated soil or petroleum hydrocarbon-based drill 

cuttings.

(F) For contaminated soils, an investigation report and diagram, drawn to 

scale, detailing the aerial extent and depth of the contamination; and 

sampling procedures which were used to assure that representative samples 

were taken.

(G) Loading calculations.

(H) Copies of all chains-of-custody related to sampling.

(I) If there is an agent, a notarized affidavit designating same, signed 

by the operator within the last 12 months (Form 1014LA).

(J) Identification of any soil farming permit that has been issued in the 

same quarter section within the last three (3) years. This information is 

available in the OCC Soil Farming Database on the web at www.occeweb.com.

(K) Other information as required by this Section or requested by the 

Pollution Abatement Department.

(3) Review period. The Pollution Abatement Department shall review the 

application, either approve or disapprove it, and return a copy of Form 1014S 

within five business days of submission of all required or requested 

information. If approved, a permit number shall be assigned to Form 1014S; 

if disapproved, the reason(s) shall be given. The applicant may make 

application for a hearing if it is not approved.

(h) Conditions of permit. Any land application which is performed under this 

Section shall be subject to the following conditions or stipulations of the 

permit:

(1) Notice to Field Inspector. The applicant shall notify the appropriate 

Field Inspector at least 24 hours prior to the commencement of land 

application to allow a Commission representative an opportunity to be 

present.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 129 -

(2) Compliance agreement. Any person responsible for supervision of land 

application shall have signed a compliance agreement with the Commission

(Form 1014CA).

(3) Presence of representative. A representative of the applicant shall be 

on the land application site at all times during which materials are being 

applied. The representative shall be an employee of the applicant, 

designated agent, contractor, or other person pre-approved by the Commission.

(4) Materials to be land applied. Land application under this Section shall 

be limited to soils and drill cuttings contaminated by salt and/or petroleum 

hydrocarbons. Petroleum hydrocarbon-contaminated soils or drill cuttings 

land applied under this Section shall meet the RCRA criteria for exempt or 

non-exempt/nonhazardous waste. Hazardous waste as defined at 40 CFR 261.3 is 

regulated by the Oklahoma Department of Environmental Quality.

(5) Weather restrictions. Land application, including incorporation, shall 

not be done:

(A) During precipitation events.

(B) When the soil moisture content is at a level such that the soil 

cannot readily take the addition of materials.

(C) When the ground is frozen to a degree that the soil cannot readily 

take the addition of fluids.

(6) Buffer zones. Land application shall not be done within the following 

buffer zones, as identified in the site suitability report:

(A) Fifty feet of a property line boundary.

(B) Three hundred feet of any water well or water supply lake used for 

domestic or irrigation purposes.

(C) One-quarter (1/4) mile of any public water well or public water 

supply lake.

(7) Land application rate. The maximum calculated application rate of 

materials shall not be exceeded. Under no circumstances shall land applied 

materials exceed a two inch depth. Furthermore, no runoff or ponding of land 

applied materials shall be allowed. It may require more than one pass or 

lift to achieve the maximum application rate while avoiding runoff or 

ponding. For land applications involving petroleum hydrocarbons all free oil 

shall be removed.

(8) Land application method. 

(A) Application of materials shall be uniform over the approved land 

application area, and shall be made by a method approved by the Commission 

prior to use. Land applied materials shall be incorporated into the soil 

by disking or chiseling during or immediately after application to a 

minimum depth of two times the depth of applied materials; however, if any 

contaminated sandy soil is applied to any clayey soil, incorporation shall 

be to a minimum depth of four times the depth of the applied materials. 

Tillage of grassland may not be necessary. If materials are land applied 

on grassland a reduced application rate may be necessary.

(B) An application vehicle shall be either a single or double axle vehicle 

with a permanently attached tank that shall not exceed 100 barrels, and the 

vehicle shall be equipped so as to minimize pooling and ruts caused by tire 

tracks. It shall have a diffuser mechanism to spread the mud in a fan 

pattern. The mud will be forced from the tank with air pressure or a 

mechanical pump. Transport/tanker trucks (18 wheelers) shall not be used 

for land application. Use of an unauthorized vehicle may result in the 

revocation of the land application permit. A fine of up to $2,000.00 may 

be assessed for violation of this paragraph.

(C) Drill cuttings shall be spread with an industrial mechanical spreader

capable of broadcasting and fanning out the cuttings.

(9) Fertilizer. For any land application involving petroleum hydrocarboncontaminated soils and/or drill cuttings, if it is determined that 

revegetation is needed, fertilizer shall be applied at an appropriate rate as 

indicated by soil testing for available N-P-K to adjust the average carbonnitrogen ratio in order to enhance biodegradation of the petroleum 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 130 -

hydrocarbons and assist in reestablishing vegetation. Soil tests shall also 

include at a minimum EC, ESP, N-P-K, C:N ratio and TPH. Soil samples shall 

be collected from the affected area at a depth of six (6) inches. Background 

samples shall be collected from an adjacent unaffected area. In the absence 

of soil testing, Nitrogen, Phosphorus, and Potassium shall be applied at a 

rate of 160-40-40 lbs. per acre (actual N-P-K). Application of fertilizers 

shall be done in a manner that minimizes runoff potential (split 

applications) and so as to increase availability of nutrients to 

microorganisms for degradation of petroleum hydrocarbons.

(10) Vegetative cover. A bona fide effort shall be made to restore or 

reestablish the vegetative cover within 180 days after the land application 

is completed. Additional efforts shall be made until the vegetative cover is 

fully restored or reestablished.

(11) Time period. 

(A) Land application shall be completed within 90 days of the anticipated 

completion date shown on the approved application form.

(B) At the end of the 90-day period the permit shall expire by its own 

terms.

(12) Post-application report. A post-application report (Form 1014R) shall 

be submitted by the operator or the operator’s agent to the Manager of the 

Pollution Abatement Department within 90 days of the completion of land 

application. One extension may be granted for a period of up to 90 days by 

the Manager of the Pollution Abatement Department. If approval is obtained 

to amend a permit to land apply water-based fluids so as to authorize land 

application of contaminated soils and petroleum hydrocarbon based cuttings, 

any extension of time for submission of the post-application report granted 

by the Manager of the Pollution Abatement Department shall begin on the date 

the amended permit is approved. The report shall give specific details of 

the land application, including volumes of materials applied and an aerial 

photograph (minimum scale 1:660) delineating the actual area where materials 

were applied. All applicable loading calculations from Appendix I of this 

Chapter shall be included in the Form 1014R. The report shall contain a 

statement certifying that the land application was done in accordance with 

the approved permit. Failure to timely submit a Form 1014R may result in the 

assessment of a fine of up to $500.00.

(13) Violations. If the applicant violates the conditions of the permit or 

this Section, the land application shall be discontinued and the Pollution 

Abatement Department shall be contacted immediately. The Pollution Abatement 

Department may revoke the permit and/or require the operator to do remedial 

work. If the permit is not revoked, land application may resume with 

approval of the Pollution Abatement Department. If the permit is revoked, 

the operator may make application for a hearing to reinstate it.

(i) Variances. A variance from the time provisions of (d)(1), (h)(1), or 

(h)(10) of this Section may be granted by the appropriate Conservation Division 

District Office for justifiable cause. A written request and supporting 

documentation shall be required. The appropriate Conservation Division 

District Office shall respond in writing within five business days after 

receipt, either approving or disapproving the request.

[Source: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 12 Ok Reg 2039, eff 

7-1-95; Amended at 14 Ok Reg 2198, eff 7-1-97 (RM 97000002); Amended at 23 Ok 

Reg 2229, eff 7-1-06 (RM 200600012); Amended at 25 OK Reg 2187, eff 7-11-08 (RM 

200800003); Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001); Amended at 

27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 30 Ok Reg 1041, eff. 7-

1-13 (RM 201300001); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-27. Application of waste oil, waste oil residue, or crude oil 

contaminated soil by oil and gas operators and pipeline companies

(a) Scope. This Section shall cover the application of waste oil, waste oil 

residue, or crude oil contaminated soil by oil and gas operators and pipeline 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 131 -

companies to lease roads, pipeline service and tank farm roads, well locations, 

and production sites. Hazardous waste as defined at 40 CFR 261.3 is regulated by 

the Oklahoma Department of Environmental Quality.

(b) Permit by appropriate Conservation Division District Office. A District 

Manager for the Conservation Division may issue to an oil or gas operator or 

pipeline company within the District a permit for road application of waste oil, 

waste oil residue, or crude oil contaminated soil to lease roads, pipeline 

service and tank farm roads, well locations, and production sites within the 

District. This subsection prohibits any operator from applying waste oil, waste 

oil residue, or crude oil contaminated soil without a permit. Any operator or 

pipeline company violating this subsection may be fined up to $2,000.00.

(c) Permit requirements.

(1) Use of Form 1014X. The application to apply waste oil, waste oil 

residue, or crude oil contaminated soil shall be made on Form 1014X. The 

original and one copy are required.

(2) Landowner permission. Attached to the application shall be a copy of

written permission by the surface owner to allow the operator or pipeline 

company to apply waste oil, waste oil residue, or crude oil contaminated 

soil as per this Section to a specific portion of real property as 

designated by legal description. For purposes of obtaining such consent, 

the applicant shall use Form 1014L.

(3) Telephone permits. In case of an emergency, a District Manager may 

issue a permit by telephone. If an operator or pipeline company obtains a 

permit by telephone, the operator or pipeline company shall file Form 1014X 

and attachments within five business days after receipt of the permit by 

telephone.

(4) Conditions for permits.

(A) Waste oil, waste oil residue, and contaminated soils applied under 

this Section shall consist of crude oil and materials produced with 

crude oil only. Hazardous waste as defined at 40 CFR 261.3 is regulated 

by the Oklahoma Department of Environmental Quality.

(B) If required by the District Manager, a hydrocarbon analysis shall 

be submitted with Form 1014X. The analysis shall be performed by a 

laboratory that is operated by the State of Oklahoma or certified by the 

Oklahoma Department of Environmental Quality in accordance with OCCapproved methods.

(C) Waste oil, waste oil residue, and crude oil contaminated soil shall 

be applied in such a manner that pollution of surface or subsurface 

waters will not likely occur and public and private property adjoining 

the application area will be protected.

(D) During application, any necessary signs, lights and other safety 

and warning devices shall be used as traffic requires to alert users to 

conditions. A sign shall be posted with the contractor's or operator's 

name and phone number to contact in case of an emergency.

(E) No application shall be conducted:

(i) When the temperature is less than 45 F.

(ii) In any area where water collects and stands.

(iii) Where conditions such as grade, soil moisture content, soil 

type, tight soil conditions, or packed soil conditions cause runoff or 

prevent rapid absorption of the oil.

(F) Following completion of the project, there shall be a uniform soil/oil 

base (all liquids worked in), with no visible free-standing oil.

(G) Proper care shall be taken to avoid runoff of oil into borrow ditches 

or adjacent areas.

(d) Notice to Field Inspector. The operator or pipeline company receiving the 

permit shall notify the appropriate Field Inspector at least two days prior to 

commencement of application.

(e) Site inspection. At his discretion, a District Manager may request a Field 

Inspector of the Conservation Division or an Enforcement Officer of the 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 132 -

Transportation Division to inspect the site at any time during the application 

operation to ensure compliance with this Section.

(f) Duration of permit. The permit shall state the duration of the permit, not 

to exceed 60 days. If a complaint is received or the operator or pipeline 

company fails to comply with either the terms of the permit or this Section, the 

District Manager may direct the operator or pipeline company to cease application 

until the problem is resolved. If necessary, the District Manager may verbally 

revoke the permit and/or require the operator or pipeline company to perform 

remedial work. If a District Manager disapproves an application or cancels a 

permit, then the applicant may apply to the Commission for an order under 165:5-

7-41. 

[Source: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended at 12 Ok Reg 2017, 

eff 7-1-95; Amended in Rule Making 97000002, eff 7-1-97; Amended in Rule 

Making 200600012, eff 7-1-2006; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-28. Application of freshwater drill cuttings by County Commissioners

(a) Scope. This Section shall cover the one-time application of freshwater 

drill cuttings by a Board of County Commissioners to a street or road.

(b) Permits by District Office. A District Manager for the Conservation 

Division may issue to any Board of County Commissioners within the District a 

permit for road application of freshwater drill cuttings to a street or road 

within the county. This Section prohibits any Board of County Commissioners 

from applying freshwater drill cuttings without a permit.

(c) Site restrictions. Application of freshwater drill cuttings shall only 

occur on sites having an:

(1) Electrical Conductivity (EC) no greater than 6,000 micromhos/cm; and

(2) Exchangeable Sodium Percentage (ESP) less than 15.0.

(d) Sampling requirements.

(1) The appropriate Field Inspector shall be contacted at least two 

business days prior to sampling to allow a Commission representative an 

opportunity to witness the sampling of the receiving soil and freshwater 

drill cuttings to be applied.

(2) The receiving soil shall be sampled using the following procedure:

(A) A minimum of five samples shall be taken for each one-half (1/2) 

mile section of road (or borrow ditch) and composited into one sample 

for analysis.

(B) Sampling shall be to a minimum depth of six inches.

(3) The freshwater cuttings shall be sampled by taking a minimum of one 

representative sample for every five cubic yards of freshwater cuttings to 

be applied and composited into one quart sample for analysis.

(e) Analysis requirements.

(1) The composite samples of soil and drill cuttings shall be analyzed by 

a laboratory which tests soils.

(2) The parameters for the receiving soil shall include ESP and either EC 

or Total Dissolved Solids (TDS) or Total Soluble Salts (TSS).

(3) The parameters for the drill cuttings shall include TDS or Total 

Soluble Salts (TSS).

(f) Maximum application rate.

(1) The maximum application rate shall be calculated by the Board of 

County Commissioners using the following formula:

PROCEDURE FOR CALCULATING APPLICATION RATE OF TOTAL DISSOLVED SOLIDS (TDS) OR 

TOTAL SOLUBLE SALTS (TSS)

 ppm TDS or TSS in receiving soil x 2 = lbs/ac TDS or TSS in 

receiving soil.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 133 -

10,000 lbs/ac TDS or TSS - lbs/ac TDS or TSS in receiving soil = 

Maximum TDS or TSS (lbs/ac) to be applied .

Maximum TDS or TSS (lbs/ac) to be applied ÷ ( ppm TDS 

or TSS in cuttings x .000001) = Maximum lbs/ac of cuttings to be applied 

 .

Actual weight of drill cuttings lbs/cu ft x 27 = 

lbs/cu yd.

Maximum lbs/ac to be applied ÷ lbs/cu yd = cu 

yds/ac to be applied.

Total volume cu yds ÷ cu yds/ac = Minimum acres 

required .

(2) Calculations shall be submitted with the application.

(g) Permit requirements.

(1) Use of Form 1014W. The application to apply freshwater drill cuttings 

shall be made on Form 1014W. The original and one copy are required.

(2) Telephone permits. In case of an emergency, a District Manager may 

issue a permit by telephone. If any Board of County Commissioners obtains 

a permit by telephone, the applicant shall file Form 1014W within five 

business days after receipt of the permit by telephone.

(3) Conditions for permits.

(A) The method to be used for application of freshwater drill cuttings 

shall not pollute surface or subsurface waters and shall protect public 

and private property adjoining the application area.

(B) During application, any necessary signs, lights and other safety 

and warning devices shall be used to alert users to conditions. A sign 

shall be posted with the contractor's or authority's name to contact in 

case of an emergency.

(C) All free liquids shall be removed before cuttings are applied.

(D) Following completion of the project, there shall be a uniform 

soil/cuttings base.

(h) Notice to Field Inspector. The Board of County Commissioners receiving 

the permit shall notify the appropriate Field Inspector at least two days 

prior to commencement of the application.

(i) Site inspection. At his discretion, a District Manager may request a 

Field Inspector of the Conservation Division or an Enforcement Officer of the 

Transportation Division to inspect the site at any time during the application 

operation to ensure compliance with this Section.

(j) Duration of permit. The permit shall state the duration of the permit, 

not to exceed 60 days. If a complaint is received or the Board of County 

Commissioners fails to comply with either the terms of the permit or this 

Section, the District Manager may direct the Board of County Commissioners to 

cease application until the problem is resolved. If necessary, the District 

Manager may verbally revoke the permit and/or require the Board of County 

Commissioners to perform remedial work. If a District Manager disapproves an 

application or cancels a permit, then the applicant may apply to the 

Commission for an order under 165:5-7-41.

[SOURCE: Amended in Rule Making 200600012, eff 7-1-2006; Amended at 32 Ok Reg 

767, eff. 8-27-15 (RM 201500001)]

165:10-7-29. Application of freshwater drill cuttings by oil and gas 

operators

(a) Scope. This Section shall cover the one-time application of freshwater 

drill cuttings by oil and gas operators to private access areas, well 

locations, and production sites.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 134 -

(b) Permits by appropriate Conservation Division District Office. A District 

Manager for the Conservation Division may issue to an operator within the 

District a permit for application of freshwater drill cuttings to private 

access areas, well locations, and production sites within the District. This 

Section prohibits any operator from applying freshwater drill cuttings without 

a permit. Any operator violating this subsection may be fined up to 

$2,000.00.

(c) Site restrictions. Application of freshwater drill cuttings shall only 

occur on sites having an:

(1) Electrical Conductivity (EC) no greater than 6,000 micromhos/cm; and

(2) Exchangeable Sodium Percentage (ESP) less than 15.0.

(d) Sampling requirements.

(1) The appropriate Field Inspector shall be contacted at least two 

business days prior to sampling to allow a Commission representative an 

opportunity to witness the sampling of the receiving soil and freshwater 

drill cuttings to be applied.

(2) The receiving soil shall be sampled using the following procedure:

(A) A minimum of five samples shall be taken for each one-half (1/2) 

mile section of road (or borrow ditch), well location, or production 

facility and composited into one sample for analysis.

(B) Sampling shall be to a minimum depth of six inches.

(3) The freshwater cuttings shall be sampled by taking a minimum of one 

representative sample for every five cubic yards of freshwater cuttings to 

be applied and composited into one quart sample for analysis.

(e) Analysis requirements.

(1) The composite samples of soil and drill cuttings shall be analyzed by 

a laboratory which tests soils.

(2) The parameters for the receiving soil shall include ESP and either EC 

or Total Dissolved Solids (TDS) or Total Soluble Salts (TSS).

(3) The parameters for the drill cuttings shall include TDS or Total 

Soluble Salts (TSS).

(f) Maximum application rate.

(1) The maximum application rate shall be calculated by the operator using 

the following formula:

PROCEDURE FOR CALCULATING APPLICATION RATE OF TOTAL DISSOLVED SOLIDS (TDS) OR 

TOTAL SOLUBLE SALTS (TSS)

 ppm TDS or TSS in receiving soil x 2 = lbs/ac TDS or TSS 

in receiving soil.

10,000 lbs/ac TDS or TSS - lbs/ac TDS or TSS in receiving soil = 

Maximum TDS or TSS (lbs/ac) to be applied .

Maximum TDS or TSS (lbs/ac) to be applied ÷ ( ppm TDS or 

TSS in cuttings x .000001) = Maximum lbs/ac of cuttings to be applied 

 .

Actual weight of drill cuttings lbs/cu ft x 27 = lbs/cu 

yd.

Maximum lbs/ac to be applied ÷ lbs/cu yd = cu 

yds/ac to be applied.

Total volume cu yds ÷ cu yds/ac = Minimum acres 

required .

(2) Calculations shall be submitted with the application.

(g) Permit requirements.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 135 -

(1) Use of Form 1014X. The application to apply freshwater drill cuttings 

shall be made on Form 1014X. The original and one copy are required.

(2) Landowner permission. Attached to the application shall be a copy of 

written permission by the surface owner to allow the operator to apply 

freshwater drill cuttings as per this Section to a specific portion of real 

property as designated by legal description.

(3) Telephone permits. In case of an emergency, a District Manager may 

issue a permit by telephone. If an operator obtains a permit by telephone, 

the applicant shall file Form 1014X within five business days after receipt 

of the permit by telephone.

(4) Conditions for permits.

(A) The method to be used for application of freshwater drill cuttings 

shall not pollute surface or subsurface waters and shall protect public 

and private property adjoining the application area.

(B) During application, any necessary signs, lights, and other safety 

and warning devices shall be used as traffic requires to alert users to 

conditions. A sign shall be posted with the contractor's or operator's 

name to contact in case of an emergency.

(C) All free liquids shall be removed before cuttings are applied.

(D) Following completion of the project, there shall be a uniform 

soil/cuttings base.

(h) Notice to Field Inspector. The operator receiving the permit shall 

notify the appropriate Field Inspector at least two days prior to commencement 

of the application.

(i) Site inspection. At his discretion, a District Manager may request a 

Field Inspector of the Conservation Division or an Enforcement Officer of the 

Transportation Division to inspect the site at any time during the application 

operation to ensure compliance with this Section.

(j) Duration of permit. The permit shall state the duration of the permit, 

not to exceed 60 days. If a complaint is received or the operator fails to 

comply with either the terms of the permit or this Section, the District 

Manager may direct the operator to cease application until the problem is 

resolved. If necessary, the District Manager may verbally revoke the permit 

and/or require the operator to perform remedial work. If a District Manager 

disapproves an application or cancels a permit, then the applicant may apply 

to the Commission for an order under 165:5-7-41.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended in Rule Making 

200600012, eff 7-1-2006; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-30. Enhanced recovery project surface facilities [REVOKED]

[SOURCE: Added at 9 Ok Reg 2337, eff 6-25-92; Revoked in Rule Making 

980000034, eff 7-1-99]

165:10-7-31. Seismic and stratigraphic operations

(a) Scope. This Section shall cover the permitting, bonding, and plugging 

requirements for seismic exploration activities and stratigraphic test holes. 

Check-shots and vertical seismic profiles or other downhole wellbore seismic 

operations are excluded from this Section. Claims for damages sustained as a 

result of seismic operations, court proceeding costs and other matters 

concerning personal injury or property damage associated with seismic 

operations shall be brought in the district courts, pursuant to the Seismic 

Exploration Regulation Act (Okla. Stat. Tit. 52 §§ 318.21 through 318.23).

(b) Definitions. The following words and terms, when used in this Section, 

shall have the following meaning:

(1) "Seismic exploration" and "seismic operation" shall mean the drilling 

of seismic shot holes and use of surface energy sources such as weight drop 

equipment, thumpers, hydro pulses and vibrators and any of the activities 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 136 -

associated therewith. This definition does not include surveying of the 

seismic area or the activity of conducting private negotiations between 

parties.

(2) "Stratigraphic test holes" shall mean holes drilled for the sole 

purpose of obtaining subsurface geological information through direct 

analysis of cores or cuttings or through the use of geophysical 

measurements that do not require the use of artificial sources of seismic 

energy.

(3) "Operator" or "applicant" shall mean the person or entity who is 

either the owner of the right to conduct seismic exploration or who acts on 

behalf of the owner.

(4) "Surface estate" shall mean the fee simple or absolute fee ownership 

of a tract of real property as defined by Okla. Stat. Tit. 60 §§5 and 23, 

less and excluding the mineral estate.

(5) "Surface owner" shall mean the owner or owners of record of the 

surface estate of the property upon which the seismic exploration is to 

occur, based upon the records of the county clerk of the county within 

which the surface estate is actually located.

(6) "Technical information and data" shall be defined as pre-plats as 

referenced in (c)(2)(B) and post-plats as referenced in subsection (c)(5).

(c) Seismic permitting.

(1) Before commencing any seismic operations in the State of Oklahoma, the 

applicant shall:

(A) Be duly registered with the Commission, including provision of a 

permanent address.

(B) Post a financial surety guarantee with the Commission.

(C) Provide to the Commission the name and business or field address of 

the contractor responsible for the operations being conducted.

(D) Obtain a permit from the Conservation Division for each seismic 

operation.

(E) Attempt to notify all owners of the surface estate where seismic 

operations will occur at least fifteen (15) days prior to commencement 

of operations on such surface estate. It shall be sufficient notice 

pursuant to this Section when notice is given to the current surface 

owner(s) at the last address shown of record for the surface owner in 

the records of the county clerk in the county where the surface estate 

is located, or an address that is known by applicant to be more accurate 

than the foregoing address of record. If the applicant has the right to 

conduct seismic operations and has attempted to give actual notice of 

intent to conduct seismic operations to the surface owner any time 

before fifteen (15) days prior to conducting seismic operations, such 

action shall be considered sufficient notification for the purposes of 

this Section. For the purposes of this Section, an attempt to notify 

shall be considered sufficient when the notification is sent by U.S. 

mail, the notice is postmarked at least fifteen (15) days prior to 

commencement of any seismic operations, and has been given at the last 

address shown of record for the surface owner in the records of the 

county clerk in the county where the surface estate is located, or an 

address which is known by applicant to be more accurate than the 

foregoing address of record.

(F) File an affidavit, within ninety (90) days of the last mailing of 

the notice, with the Commission and the county clerk in the county where 

the property is located, setting out that mailing of the notice has 

occurred in compliance with this Section and the Seismic Exploration 

Regulation Act (Okla. Stat. Tit. 52 §§ 318.21 through 318.23).

(G) The notice shall include a copy of the oil or gas lease or seismic 

permit or other legal instrument of similar nature authorizing the use 

of the surface for seismic operations and shall contain the information

that is required for notices by Okla. Stat. Tit. 52 § 318.22.

(2) The applicant shall make application on the Commission’s Form 1000S.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 137 -

(A) The permit shall be valid for only one operation as approved on 

Form 1000S.

(B) A pre-plat of the operation area shall be attached to the 

application showing the location of the operation area delineated to the 

nearest section

(C) Post a performance bond in the amount of $50,000, or other form of 

surety in an amount as approved by the Conservation Division. The 

performance bond may be filed for each operation, or may be filed on an 

annual basis to cover all operations that may be undertaken during the 

year. If the performance bond is filed for a single operation, the 

amount may be approved by the Conservation Division for less than 

$50,000 or in another form of financial surety guarantee, depending on 

the nature of the seismic operation involved, the number of shot holes 

or surface energy source points, the cost of the operation and the size 

of the applicant’s business. The form of surety shall not include 

letters of credit or financial statements. Such bond(s) or other surety 

may be released upon request made no sooner than thirty (30) days 

subsequent to the completion of the applicant’s operation(s), which have 

been permitted under such bond(s) or other surety, upon satisfactory 

inspection or review by Conservation Division personnel.

(D) The permit shall expire twelve (12) months from the issue date, 

unless operations are commenced.

(E) The Conservation Division shall approve or deny the application 

within thirty (30) days of receipt of the application. The Conservation 

Division may act upon an application or amended application on an 

expedited basis.

(F) During any activity subject to this subsection, the applicant shall 

maintain at the site a copy of the approved permit, Form 1000S, for 

inspection.

(G) All technical information, excluding the Form 1000S, but including 

any plats, relative to the permitted operation shall remain confidential 

or the Conservation Division shall destroy the records. The plats and 

any other technical data submitted, shall be filed in the Technical 

Services Department of the Conservation Division. Upon request of the 

Manager of Field Operations, the technical data may be reviewed by Field 

Operations to ensure compliance with Commission rules.

(3) The operator shall file with the Conservation Division a written 

notice of commencement of seismic operations within 14 days after 

commencement of such operations.

(4) No seismic shot hole blasting shall be conducted within 200 feet of any 

habitable dwelling, building, or water well without written permission from 

the owner of the property or within 500 feet of any superfund site or 

hazardous waste facility.

(5) Plugging and post-plat. Within 30 days after completing a seismic 

operation, the applicant receiving the permit shall submit a copy of: the 

approved Form 1000S certifying the plugging of all seismic shot holes in 

compliance with this Section; and a post-plat or acceptable form of survey 

showing the actual location of all seismic shot holes.

Unless the applicant can demonstrate to the Conservation Division’s 

District Office that another method will provide sufficient protection to 

groundwater supplies and long term land stability, the following guidelines 

shall be observed:

(A) Standard plugging method. All holes shall be filled to within four 

feet from the surface with bentonite, native cuttings, or an appropriate 

substitute. The remainder of the shot hole shall be filled and tamped 

with native cuttings or soil.

(B) Special methods. In areas where the standard plugging method has 

been shown to be inadequate for the prevention of groundwater 

contamination, the Conservation Division may designate the area as a 

special problem area. In such event, the Conservation Division will 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 138 -

provide to the best of its ability, a clear geographical description of 

such area and the recommended, or required, hole plugging methods. 

Should the applicant encounter conditions such that the standard method 

appears inadequate for the prevention of groundwater contamination, the 

applicant shall inform the Conservation Division.

(i) Artesian flow. If the standard method is inadequate to stop 

artesian flow, alternate remedies must be employed to do so.

(ii) Water well conversion. Applicants are prohibited from allowing 

the conversion of seismic shot holes to water wells.

(iii) Groundwater protection. Alternative plugging procedures and 

materials may be utilized when the applicant has demonstrated to the 

Conservation Division’s satisfaction that the alternatives will 

protect usable quality water.

(iv) Timeliness. All seismic shot holes shall be plugged as soon as 

possible and shall not remain unplugged for a period of more than 30 

days after the drilling of the hole.

(d) Stratigraphic test permitting.

(1) Before commencing any stratigraphic test hole operations, those companies 

hereinafter referred to as the applicant shall:

(A) Be duly registered with the Commission, including provision of a 

permanent address.

(B) Post a financial surety guarantee with the Commission in compliance 

with 165:10-1-10.

(C) Obtain a permit from the Conservation Division for each stratigraphic 

test operation.

(2) The applicant shall make application on the Commission's Form 1000.

(A) The permit shall be valid for only one operation as approved on Form 

1000.

(B) The permit shall expire six (6) months from the issue date, unless 

operations are commenced.

(C) The Conservation Division shall approve or deny the application within 

30 days of receipt of the application.

(D) Notice to surface owners shall be given according to OAC 165:10-3-

1(g).

(E) During any activity subject to this subsection, the applicant shall 

maintain at the site a copy of the approved permit, Form 1000, for 

inspection.

(F) Any technical data submitted shall be filed in the Technical Services 

Department of the Conservation Division. Upon request of the Manager of 

Field Operations, the technical data may be reviewed by Field Operations to 

ensure compliance with Commission rules.

(G) The operator shall file with the Conservation Division a written 

notice of spudding of stratigraphic well within 14 days after spudding of 

the well.

(3) Unless the applicant can demonstrate to the Conservation Division's 

District Office that another method will provide sufficient protection to 

groundwater supplies and long term land stability, the following guidelines 

shall be observed:

(A) Surface casing requirements shall be met according to OAC 165:10-3-4.

(B) Storage and disposal of fluids associated with the drilling of 

stratigraphic test holes shall meet the requirements of OAC 165:10-7-16.

(C) Duty to plug and abandon shall be according to OAC 165:10-11-3.

(D) The Conservation Division shall be notified prior to commencement of 

plugging according to OAC 165:10-11-4.

(E) Plugging. Stratigraphic test holes shall be plugged according to OAC 

165:10-11-6 and certification submitted on Form 1003 in compliance with OAC 

165:10-11-7.

(e) Any person, firm, corporation or entity which conducts any seismic or 

stratigraphic test hole operations without a permit as provided in this Section, 

or in any other manner violates the rules of the Commission governing such 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 139 -

operation shall be subject to a penalty up to One Thousand Dollars ($1,000.00) 

per violation per day after completion of the informal complaints procedure 

provided in OAC 165:10-7-7 and notice and hearing pursuant to the Commission’s 

contempt proceedings.

(f) Complaints. A complaint alleging violations of this Section may be filed 

with the Commission against any person, firm or corporation conducting seismic 

and stratigraphic operation(s). The Commission may determine if and when a 

complaint has been adequately resolved, pursuant to the informal complaints 

process of OAC 165:10-7-7, and, if an environmental complaint, pursuant to the 

citizen complaint procedure of OAC 165:5-1-25.

[SOURCE: Added in Rule making 980000034, eff 7-1-99; Amended at 24 Ok Reg 1804 

(RM 200700004), eff 7-1-2007; Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001)]

165:10-7-32. Application to reclaim and/or recycle produced water for surface 

activities related to drilling, completion, workover, and production operations 

from oil and gas wells

(a) Authority to reclaim and/or recycle produced water. No person shall use 

produced water for any other purpose except as provided by this section. Any 

operator failing to obtain a permit may be fined up to $500.00.

(b) Scope. This Section shall cover the reclaiming and/or recycling of 

produced water from oil and gas wells for a single well location for the 

purpose of water supply for surface activities used for a specific permitted 

use. This does not include the use of produced water for down- hole operations 

referred to as weighted water under OAC 165:10-7-24(b)(2).

(c) Quality of produced water. For the purposes of this rule shall be limited 

to Total Dissolved Solids (TDS) or Total Soluble Salts (TSS) content not to 

exceed 5,000 mg/l and oil and grease content not to exceed 1,000 mg/l.

(d) Storage of produced water. If the produced water is stored in tanks, the 

tanks shall be legibly marked "recycle" water.

(e) Log of load tickets. The operator shall maintain copies of the load 

tickets from wells that the produced water was obtained. Such copies shall be 

made available to the OCC Inspector upon request.

(f) Notification to OCC District Office. The Operator shall orally notify the 

District Office when produced water is to be initially hauled to the permitted 

facility.

(g) Application for permit.

(1) The operator of the well must apply for the permit for the reclamation 

of produced water.

(2) Required Application. Each application for the reclaiming and/or 

recycling of produced water shall be submitted to the Field Operations 

District office on Form 1014D.

(3) A copy of written notice to the surface owner that the applicant 

intends to use produced water as per 165:10-7-32 to a specific portion of 

their real property as designated by legal description. For purposes of 

notice, a written waiver from the surface owner may also be submitted.

[SOURCE: Added in Rule making 200300001, eff 7-1-03; Amended in Rule Making 

200600012, eff 7-1-2006]

165:10-7-33. Use of truck wash pits

(a) Scope. This Section shall apply to truck wash pits. A truck wash pit is 

a pit used for the temporary storage of fluids generated from the washing or 

cleaning of a motor vehicle, trailer or container used to transport or store 

deleterious substances. Truck wash pit operators shall comply with all 

applicable Commission rules in OAC 165:30 Motor Carriers.

(b) Permit required. Any truck wash pit sought to be approved after the 

effective date of this Section will require a permit issued by the 

Conservation Division. For use of a truck wash pit without a permit, the 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 140 -

operator may be fined up to $2,000.00. The operator of the proposed pit shall 

submit Form 1014T to the Manager of Field Operations for the Conservation 

Division for review and approval. Documents required to be submitted with the 

Form 1014T include, but are not limited to, the following:

(1) A detailed drawing of the site, with complete construction plans drawn 

to scale for the proposed truck wash pit, any leachate collection system, 

and specific completion information for all monitor wells.

(2) A plat map with section, township, range and county showing the 

location of the proposed truck wash pit and the location of the monitor 

wells in relation to the pit they monitor.

(3) If the site on which the truck wash pit is to be located is not owned 

by the operator of the proposed pit, the operator must submit a copy of the 

written agreement between the operator and the surface owner authorizing 

use of the site for the pit. The agreement shall address the disposition 

of the pit (whether pit is to be buried on site, removed, etc.) at the 

termination or expiration of the agreement.

(c) Surety requirements.

(1) Any operator of a truck wash pit shall file with the Manager of Field 

Operations for the Conservation Division an agreement to properly close the 

pit upon termination of operations. The agreement shall be on forms 

available from the Conservation Division and shall be accompanied by 

surety. The agreement shall provide that if the Commission finds that the 

operator has failed or refused to comply with Commission rules or take 

remedial action as required by law and Commission rules, the surety shall 

pay to the Commission the full amount of the operator's obligation up to 

the limit of the surety.

(2) The Commission shall establish the amount of surety in the permit for 

the authority to operate a truck wash pit. The amount of surety shall be 

based on factors such as the dimensions of the pit, and costs of 

reclamation, monitoring, plugging of monitor wells, pit closure, trucking 

of any deleterious substances, remediation and earth work. The amount may 

be subject to change for good cause. The surety shall be maintained for as 

long as monitoring is required. The type of surety shall be a corporate 

surety bond, certificate of deposit, irrevocable commercial letter of 

credit, or other type of surety approved by the permit. Any type of surety 

that expires shall be renewed prior to 30 days before the expiration date.

(d) Site restriction. No truck wash pit shall be constructed in any area 

that floods according to the Soil Conservation Service County Soil Survey 

(available for viewing at the Commission's Oklahoma City Office or appropriate 

Conservation Division District Offices).

(e) Construction requirements.

(1) Splash pad/apron. A splash pad/apron shall be constructed at the 

unloading area of any truck wash pit to the design and dimensions necessary 

to contain and direct all materials unloaded into the pit.

(2) Pit specifications. Any truck wash pit shall be constructed of 

concrete or steel or shall be lined with a geomembrane liner. The 

following specifications shall be met:

(A) Any concrete pit shall be steel-reinforced and have a minimum wall 

thickness of six inches.

(B) Any steel pit shall have a minimum wall thickness of threesixteenths (3/16) inch. If a previously used steel pit is installed, it 

shall be free of corrosion or other damage.

(C) Any geomembrane liner shall meet these requirements:

(i) The geomembrane liner shall have a minimum thickness of 60-mils, 

shall be chemically compatible with the type of wastes to be 

contained, and shall have ultraviolet light protection.

(ii) The geomembrane liner shall be placed over a specially 

prepared, smooth, compacted surface void of sharp changes in 

elevation, rocks, clods, organic debris, or other objects.
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 141 -

(iii) The geomembrane liner shall be continuous (may include welded 

or extruded seams) and shall cover the bottom and interior sides of 

the pit entirely. Sewing of seams is prohibited. The edges shall be 

securely placed in a minimum twelve inch deep anchor trench around 

the perimeter of the pit.

(3) Certification of liner. The operator of any truck wash pit that is 

constructed with a geomembrane liner shall secure an affidavit signed by 

the installer, certifying that the liner meets minimum requirements and was 

installed in accordance with Commission rules. It shall be the operator's 

responsibility to maintain the affidavit and all supporting documentation 

pertaining to the liner, such as geomembrane liner specifications from the 

manufacturer, etc., and shall make them available to a representative of 

the Conservation Division upon request.

(4) Monitor wells or leachate collection system.

(A) Any truck wash pit shall be required to have a leachate collection 

system or a minimum of three monitor wells, one upgradient and two 

downgradient from the pit.

(B) No monitor well shall be installed more than 100 feet from a truck 

wash pit, nor shall any existing water well be used as a monitor well, 

unless written approval is given by the District Manager or Manager of 

Field Operations.

(C) All new monitor wells shall be drilled to a depth of at least ten 

feet below the top of the first free water encountered and shall be 

drilled and completed by a licensed monitor well driller. If 

documentation is submitted prior to drilling the monitor well to show 

that no free water will be encountered within a depth of 50 feet from 

the surface, the District Manager may require that monitor wells be 

drilled to a lesser depth.

(D) All new monitor wells shall meet the requirements as set out in 

rules established by the Oklahoma Water Resources Board, and a removable 

and lockable cap shall be placed on top of the casing. The cap shall 

remain locked at all times, except when a well is being sampled. A key 

to each well shall be made available to the appropriate District Manager 

or Field Inspector upon request.

(f) Operation and maintenance requirements.

(1) Exclusion of runoff water. No truck wash pit shall be allowed to 

receive runoff water.

(2) Freeboard. The fluid level in any concrete or steel truck wash pit 

shall be maintained at all times at least 6 inches below the top of the pit 

wall, unless otherwise specified on Form 1014T. Any geomembrane lined pit 

shall have a minimum of 24 inches freeboard at all times.

(3) Sampling of monitor wells or leachate collection systems.

(A) Sampling of monitor wells or leachate collection systems shall 

occur once every six months, during the months of January and July.

(B) The appropriate District Manager shall be notified at least 24 

hours in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(C) Samples shall be collected, preserved, and handled by the operator 

according to EPA-approved standards (RCRA Groundwater Monitoring 

Technical Enforcement Guidance Document, EPA, OSWER-9950.1, September, 

1986, pp. 99-107) and analyzed for pH, chlorides, Total Dissolved Solids 

(TDS) and Total Petroleum Hydrocarbons (TPH) by a laboratory certified 

by the Oklahoma Department of Environmental Quality or operated by the 

State of Oklahoma. Analysis of additional parameters may be required, 

as determined by the District Manager or Manager of Field Operations.

(D) If requested by the District Manager, each sample shall be split 

and an adequate portion (approximately one pint) properly labeled and 

delivered upon request or otherwise provided to the appropriate 

Conservation Division District Office or Field Inspector. A copy of 

each analysis and a statement as to the depth to groundwater encountered 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 142 -

in each well or leachate collection system, or an affidavit that no 

water was encountered, shall be forwarded to the Manager of Field 

Operations, within 30 days of sampling.

(4) Prevention of pollution. All truck wash pits shall be constructed, 

used, operated, and maintained at all times so as to prevent pollution. In 

the event of a nonpermitted discharge from a truck wash pit, sufficient 

measures shall be taken to stop or control the loss of materials and 

reporting procedures in 165:10-7-5(c) shall be followed. Any materials 

lost due to such discharge shall be cleaned up as directed by a 

representative of the Conservation Division.

(5) Oil film. The operator of a truck wash pit shall be responsible for 

the protection of migratory birds. Therefore, the Conservation Division 

recommends that to prevent the loss of birds due to oil films, all pits 

containing fluid be kept free of hydrocarbons, or be protected from access 

to birds. [See Advisory Notice in 165:10-7-3(c).]

(g) Closure requirements.

(1) Time limit. Within 90 days of the cessation of operation of any truck 

wash pit, such pit shall be emptied of all contents and filled with soil,

except as otherwise provided in the written agreement between the operator 

and surface owner regarding the disposition of the pit at the termination 

or expiration of the agreement. All monitor wells shall be plugged with 

bentonite or cement, unless exempt in writing by the District Manager or 

Manager of Field Operations. The site shall be revegetated within 180 

days.

(2) Burial. If any concrete, steel, geomembrane, or other materials 

associated with a truck wash pit are to be left on-site, they shall be 

buried under a minimum soil cover of three feet, pursuant to 165:10-3-17.

(3) Penalty for failure to meet closure requirements. An operator who 

fails to meet the closure requirements set out in this subsection may be 

fined up to $2,000.00.

(h) Additional requirements. The requirements set forth in this Section are 

minimum requirements. Additional requirements may be imposed if the site has 

certain limitations or other conditions of risk exist.

(i) Application to existing truck wash pits. Operators of truck wash pits 

permitted prior to the effective date of this Section must either comply with 

subsections and paragraphs (c), (e)(1), (e)(4), (f), (g) and (h) of this 

Section or close such pits within one (1) year of the effective date of this 

Section. All truck wash pits permitted, but yet to be constructed as of the 

effective date of this Section, shall also be subject to the construction 

requirements in paragraphs (e)(2) and (e)(3) of this Section.

(j) Variances. A variance from the time requirements of paragraph (g)(1) of 

this Section may be granted by the District Manager or Manager of Field 

Operations for justifiable cause. A written request and supporting 

documentation is required.

[SOURCE: New at 31 Ok Reg 977, eff. 9-12-14 (RM 201400002); Amended at 32 Ok 

Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-7-34. Use of reclaimed water in oil and gas operations

(a) Scope. This Section shall cover the permitting and use of reclaimed 

water from Department of Environmental Quality authorized facilities in oil 

and gas operations. Reclaimed water is wastewater from municipal wastewater 

treatment and/or public water supply treatment plants that has gone through 

various treatment processes to meet specific water quality criteria with the 

intent of being used in a beneficial manner. 

(b) Permit required. No person shall use reclaimed water in oil and gas 

operations without applying for and obtaining a permit issued under this 

Section. An operator using reclaimed water without a permit may be fined up 

to $2,000.00. 
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 143 -

(c) Who may apply. Only operators authorized to operate wells pursuant to 

OAC 165:10-1-10 may apply for this permit. 

(d) Required form and attachments. Each application to use reclaimed water 

in oil and gas operations shall be submitted to the Manager of Field 

Operations on Form 1014RW. The form shall be properly completed and signed. 

Attached to the form shall be the following:

(1) Analysis of reclaimed water proposed to be used in oil and gas 

operations. Samples of reclaimed water shall be analyzed by a laboratory 

operated by the State of Oklahoma or accredited by the Department of 

Environmental Quality or in the North American Proficiency Testing System. 

Parameters for analysis of the reclaimed water shall include, but not be 

limited to, Total Dissolved Solids or Total Soluble Salts.

(2) Copies of all chain of custody forms related to sampling.

(3) A topographic map and the most recent aerial photograph (minimum scale 

1:660) of the site where the reclaimed water is proposed to be used.

(4) Other information as required by this Section or requested by the 

Manager of Field Operations.

(e) Review period. The Manager of Field Operations shall review the 

application, either approve or disapprove it, and return a copy of Form 1014RW 

within five business days of submission of all required or requested 

information. If approved, a permit number shall be assigned to the Form 

1014RW; if disapproved, the reason(s) shall be given. The applicant can apply 

for a hearing if the permit is not approved.

(f) Violations. If the operator violates the conditions of the permit or 

this Section, the use of reclaimed water in oil and gas operations shall be 

discontinued and the Field Operations Department shall be contacted 

immediately. The Field Operations Department may revoke the permit and/or 

require the operator to do remedial work. If the permit is not revoked, use 

of reclaimed water in oil and gas operations may resume with the Field 

Operations Department’s approval. If the permit is revoked, the operator may 

file an application for a hearing to reinstate the permit.

[SOURCE: Added at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]
OAC 165:10-7 Corporation Commission

Eff. 8-27-15

- 144 -

[Blank Page]
OAC 165:10-8 Corporation Commission

Eff. 8-27-15

- 145 -

SUBCHAPTER 8. COMMERCIAL RECYCLING

PART 1. HYDROCARBON RECYCLING/RECLAIMING FACILITIES

Section

165:10-8-1. Scope

165:10-8-2. Definitions

165:10-8-3. Permit required

165:10-8-4. Application requirements

165:10-8-5. Surety requirements for reclaimers

165:10-8-6. Design and construction requirements

165:10-8-7. Operation and maintenance requirements

165:10-8-8. Reporting

165:10-8-9. Closure requirements

165:10-8-10. Additional requirements

165:10-8-11. Variances

PART 3. DRILLING WASTE RECYCLING/RECLAIMING FACILITIES [REVOKED]

165:10-8-25. Scope [REVOKED]

165:10-8-26. Definitions [REVOKED]

165:10-8-27. Pit requirements [REVOKED]

165:10-8-28. Application requirements [REVOKED]

165:10-8-29. Surety requirements for reclaimers [REVOKED]

165:10-8-30. Design and construction requirements [REVOKED]

165:10-8-31. Operation and maintenance requirements [REVOKED]

165:10-8-32. Reporting [REVOKED]

165:10-8-33. Closure requirements [REVOKED]

165:10-8-34. Additional requirements [REVOKED]

165:10-8-35. Variances [REVOKED]

[Authority: 52 O.S. Sections 139 and 141 (Supp. 1993)]

[Source: Codified 7-11-94]

PART 1. HYDROCARBON RECYCLING/RECLAIMING FACILITIES

165:10-8-1. Scope 

This Part shall cover the permitting, construction, operation, and closure 

requirements for any recycling/reclaiming facility.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94]

165:10-8-2. Definitions 

The following words and terms, when used in this Subchapter, shall have the 

following meaning, unless the context clearly indicates otherwise: 

"Tank bottom hydrocarbon recycling/reclaiming facility" means a 

recycling/reclaiming operation at a tank bottom reclaiming facility which is 

authorized by the Commission to recycle and/or reclaim marketable crude oil or 

condensate produced or used in the exploration or production of oil and gas. 

The facility shall comply with OAC 710:45-15-3.

"Hydrocarbon recycling/reclaiming facility at a saltwater disposal site"

means a recycling/reclaiming operation at a Class II saltwater disposal site 

which is authorized by the commission to recycle and/or reclaim marketable crude 

oil or condensate produced or used in the exploration or production of oil and 

gas. The facility shall comply with OAC 710:45-15-3.
OAC 165:10-8 Corporation Commission

Eff. 8-27-15

- 146 -

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200000002, eff 7-1-00]

165:10-8-3. Permit required

(a) Who may apply. The applicant for a recycling/reclaiming facility shall be 

the owner and/or lease holder of the site. 

(b) Compliance with Part. Before issuance of a permit, the applicant shall 

comply with this Part and if pits are to be used for storage, the applicant 

shall comply with 165:10-9-1, except at Class II saltwater disposals. 

(c) OCC Form 1020A. Application shall be filed on OCC Form 1020A.

(d) An Oklahoma Tax Commission Reclaimer License. The applicant shall have 

obtained a reclaimer license number under OAC 710:45-15-2. This number will be 

used by the Corporation Commission for its permit number.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200000002, eff 7-1-00]

165:10-8-4. Application requirements

(a) Permit required. No recycling/reclaiming facility shall be constructed, 

enlarged, or used without approval on Form 1020A.

(b) Site limitations. Recycling/reclaiming facilities shall not be restricted 

by site limitations unless pits are to be used.

(1) Tank bottom hydrocarbon recycling/reclaiming facilities with pits that 

are to be used for storage in the operation shall comply with OAC 165:10-9-

1.

(2) Hydrocarbon recycling/reclaiming facilities at a saltwater disposal site 

with pits that are used for unloading saltwater shall comply with OAC 

165:10-9-3.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200000002, eff 7-1-00]

165:10-8-5. Surety requirements for reclaimers

(a) Agreement to close. Any operator of a recycling/reclaiming facility shall 

file with the Manager of Document Handling an agreement to properly close and 

reclaim the site in accordance with approved closure and reclamation procedures 

upon termination of recycling/reclaiming operations. The agreement shall be on 

forms available from the Conservation Division and shall be accompanied by 

surety. The agreement shall provide that if the Commission finds that the 

operator has failed or refused to close the facility or take remedial action as 

required by law and the rules of the Commission, the surety shall pay to the 

Commission the full amount of the operator's obligation up to the limit of the 

surety.

(b) New facilities. Category A (165:10-1-11) or Category B (165:10-1-13) 

surety shall be required for coverage of the closure costs, including well 

pluggings and general site restoration. These costs shall be calculated upon 

the projected costs of closure for the facility, based on estimated costs of 

earth work, remediation, revegetation, plugging, etc. Such information shall be 

provided by the applicant and reviewed, adjusted and ordered by the Commission.

(c) Existing facilities. For facilities in operation prior to the effective 

date of this Part, the Commission can require, by order, the establishment of an 

escrow account to cover the costs of closure, by using a per barrel fee to be 

deposited into the account. Any interest the account earns until the total 

amount is collected shall be reinvested in the account. Any interest accrued 

after the account balance is full shall be returned to the operator.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended at 27 Ok Reg 2128, eff. 

7-11-10 (RM 201000003)]
OAC 165:10-8 Corporation Commission

Eff. 8-27-15

- 147 -

165:10-8-6. Design and construction requirements

(a) Spill prevention. Each facility shall be designed and constructed 

utilizing good engineering practices. Design and construction standards shall 

be determined on a case-by-case basis by the Commission. Each such facility 

shall be designed and constructed to prevent escape of deleterious substances.

(b) Unloading pits or sumps. All unloading areas at tank bottom hydrocarbon 

recycling/reclaiming facilities that use a pit to receive fluids and skimming 

pits shall be approved on OCC Form 1014.

(c) Required exhibits. Complete construction plans, drawings, and written 

specifications for the proposed facility shall be submitted to the Manager of 

Pollution Abatement for review and approval. Design and construction standards 

shall be determined on a case-by-case basis by the Commission. Applicants shall 

consult with the Commission prior to the construction of the proposed facility. 

The Commission may apply existing technological standards and/or establish new 

standards, as it deems appropriate to the proposed site and activities. All 

plans, drawings, and specifications shall be prepared by or under the 

supervision of a qualified expert.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200000002, eff 7-1-00]

165:10-8-7. Operation and maintenance requirements

(a) Fencing. All recycling/reclaiming facilities shall be completely enclosed 

by a fence at least four feet in height. No livestock shall be allowed inside 

the fence. Final construction is subject to approval by the Manager of 

Pollution Abatement.

(b) Sign. A waterproof sign bearing the name of the operator, legal 

description, permit number, and emergency phone number shall be posted within 25 

feet of the entrance gate to the facility and shall be readily visible.

(c) Site security. Receiving of any recycling/reclaiming material shall occur 

only when there is an attendant on duty. All sites shall be secured by a locked 

gate when an attendant is not on duty. A key or combination to the lock shall 

be provided to the appropriate Field Inspector for the purpose of carrying out 

inspections.

(d) Acceptable materials. Operators of a recycling/reclaiming facility shall 

only receive substances as defined in 165:10-1-2 "Deleterious substances."

(e) Oil film. OPERATORS TAKE NOTE: Federal statutes, such as the Bald Eagle 

Protection Act (16 U.S.C. Sections 668-668d), the Migratory Bird Treaty Act 

(16 U.S.C. Sections 703-711), the Endangered Species Act (16 U.S.C. Sections 

1531-1542), and the Lacey Act Amendments of 1981 (16 U.S.C. Sections 3371-

3378), dictate substantial fines and penalties for persons who allow birds of 

certain species to become fatally injured due to incidental contact with oil 

or oil by-products. These fines may be levied upon persons allowing such 

fatalities to occur, whether accidental or not. Misdemeanor and felony 

convictions may include imprisonment. Information on affected bird species, 

regulations under these Acts, and measures which can be taken to prevent such 

occurrences, such as the netting or covering of open-topped tanks and pits 

which contain oil or oil by-products, can be obtained from the U.S. Fish and 

Wildlife Service Office in Oklahoma City or the nearest Oklahoma Department of 

Wildlife Office.

(f) Aesthetics. 

(1) All surface trash, debris, junk and scrap or discarded material 

connected with the operations of the facility shall be removed from the 

premises. With written permission from the surface owner, the operator may, 

without applying for an exception to 165:10-3-17(b), bury all nonhazardous 

material at a minimum depth of three feet; cement bases are included.

(2) The appropriate Conservation Division District Office or field inspector 

may issue a Form 1085 for any alleged violation of this subsection. If the 

operator fails to conduct cleanup as directed, the Commission may fine the 

operator $500.00 for a first offense. For a subsequent offense, the fine may 
OAC 165:10-8 Corporation Commission

Eff. 8-27-15

- 148 -

be up to $1,000.00, and the facility shall be shut down until completion for 

cleanup operations.

(g) Structural integrity. All recycling/reclaiming facilities shall be used, 

operated, and maintained at all times so as to prevent the escape of their 

contents. Any condition that threatens the structural stability of any diked 

portion or the storage facility shall be repaired in a timely manner. 

(h) Prevention of pollution. All recycling/reclaiming facilities shall be 

used, operated, and maintained at all times so as to prevent pollution. In the 

event any non permitted discharge occurs, sufficient measures shall be taken to 

stop or control the loss of materials, and reporting procedures in accordance 

with 165:10-7-5(c) shall be followed. Any materials lost due to such discharge 

shall be cleaned up as directed by a representative of the Conservation 

Division. 

(i) Fines. For a willful non-permitted discharge from the facility, the 

operator may be fined up to $5,000.00.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200000002, eff 7-1-00; Amended at 27 Ok Reg 2128, eff. 7-11-10 (RM 201000003); 

Amended at 28 Ok Reg 1949, eff. 7-11-11 (RM 201000007)]

165:10-8-8. Reporting

(a) Annual report on Form 1014A. The operator of any recycling/reclaiming 

facility shall submit an annual report on Form 1014A to the Manager of Pollution 

Abatement, by February 1 of each year. In lieu of Commission Form 1014A, 

operators may submit Oklahoma Tax Commission Form 323A for the twelve calendar 

months of the previous year by February 1st.

(b) Daily log for tank bottom at a hydrocarbon recycling/reclaiming facility. 

The operator shall maintain a daily log and at a minimum shall include the date, 

volume, source (generator) and type of material. In addition, copies of any 

chemical analysis of materials or material safety data sheets shall be 

maintained.

(c) Daily load tickets for hydrocarbon recycling/reclaiming facilities at salt 

water disposal facilities. The operator shall keep the load tickets for 

saltwater and other deleterious substances received at the saltwater disposal 

facilities for a minimum of three years at the operator's office.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

200000002, eff 7-1-00]

165:10-8-9. Closure requirements

(a) Notification. The Manager of Pollution Abatement Department shall be 

notified in writing whenever a recycling/reclaiming facility shall be closed, or 

portions thereof, or becomes inactive unless it is shut down by the Commission.

(b) Closed facility. A recycling/reclaiming facility may be considered closed 

or inactive if the operator closes the facility, the operator is unable to 

furnish documentation to show that there has been receipt of deleterious 

substances during the last twelve months, the facility has been shut down by the 

Commission, or authority to operate has lapsed or is vacated by Commission 

order.

(c) Closure plan. An approved closure plan shall be submitted to the Pollution 

Abatement Department. Estimate of cost of closure shall be made part of the 

plan.

(d) Monitor wells. Monitor wells, if required, shall be plugged with bentonite 

or cement, upon approval in writing by the Manager of Pollution Abatement.

(e) Pits. When closing any pit with a geomembrane liner, extreme care shall be 

taken to preserve the integrity of the liner. All free liquids and sediments 

shall be removed.

(f) Burial. If any concrete, steel, geomembrane, or other materials associated 

with the site are to be left on-site, they shall be buried under a minimum soil 

cover of three (3) feet, pursuant to 165:10-3-7. 
OAC 165:10-8 Corporation Commission

Eff. 8-27-15

- 149 -

[Source: Added at 11 Ok Reg 3691, eff 7-11-94]

165:10-8-10. Additional requirements

The requirements set forth in this Part are minimum requirements. Additional 

requirements may be made upon a showing of good cause.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94]

165:10-8-11. Variances

Except as otherwise provided in this Subchapter, variances from provisions of 

this Part may be granted by the Manager of Pollution Abatement or by order after 

application, notice, and hearing.

[Source: Added at 11 Ok Reg 3691, eff 7-11-94]

PART 3. DRILLING WASTE RECYCLING/RECLAIMING FACILITIES [REVOKED]

165:10-8-25. Scope [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-26. Definitions [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-27. Pit requirements [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-28. Application requirements [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-29. Surety requirements for reclaimers [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-30. Design and construction requirements [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-31. Operation and maintenance requirements [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-32. Reporting [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]
OAC 165:10-8 Corporation Commission

Eff. 8-27-15

- 150 -

165:10-8-33. Closure requirements [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-34. Additional requirements [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]

165:10-8-35. Variances [REVOKED]

[Source: Added at 11 Ok Reg 3691, eff 7-11-94; Revoked at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 151 -

SUBCHAPTER 9. COMMERCIAL DISPOSAL FACILITIES

Section

165:10-9-1. Use of commercial pits 

165:10-9-2. Commercial soil farming 

165:10-9-3. Commercial disposal well surface facilities

165:10-9-4. Commercial recycling facilities

165:10-9-1. Use of commercial pits

(a) Scope. This Section shall cover the permitting, construction, operation, 

and closure requirements for any commercial pit. A commercial pit is a 

disposal facility which is authorized by Commission order and used for the 

disposal, storage, and handling of deleterious substances or soils 

contaminated by deleterious substances produced, obtained, or used in 

connection with drilling, production and/or pipeline construction operations. 

This does not cover disposal well pits. (See 165:10-9-3 and 165:10-7-20.)

(b) Application requirements.

(1) Who may apply. The applicant for a commercial pit shall be the owner 

of the land (or person having a written firm option to purchase the land at 

the time the application is filed) on which the proposed pit is to be 

located: if leased, both the owner and lessee shall be joint applicants.

(2) Compliance with rules. Before issuance of an order, the applicant 

shall comply with Commission Rules of Practice 165:5-7-1, 165:5-7-35, 

165:5-3-1, and this Section.

(3) Exhibits. Two complete sets of all exhibits which shall be relied 

upon by the applicant shall be submitted to the Pollution Abatement 

Department of the Commission, pursuant to 165:5-7-35. Those exhibits shall 

include, but are not limited, to the following:

(A) A lithologic log of test borings, identifying the subsurface 

materials encountered and the depth at which groundwater was encountered 

pursuant to (c)(2)(D) of this Section.

(B) Results of permeability tests of the proposed liner materials, 

pursuant to (e)(7) of this Section.

(C) A topographic map of the commercial pit site.

(D) The appropriate Soil Conservation Service (SCS) soil survey aerial 

photo and legend.

(E) A detailed drawing of the site, with complete construction plans 

drawn to scale by or under the supervision of a registered professional 

engineer.

(F) A plan for closure of the pit(s) which shall provide for a minimum 

three feet of soil cover and shall specifically state how all aspects of 

closure shall be accomplished, including volume and fate of liquids and 

solids, earthwork to close the pit(s) (including placement of stockpiled 

topsoil), and revegetation of the site.

(G) An itemization of projected hauling, closure, reclamation, 

maintenance, and monitoring costs.

(H) A plan for post-closure maintenance and monitoring which shall 

address maintenance of the site as well as monitoring and plugging of 

wells. Exemption from the plugging of monitor wells may be obtained 

upon written request and approval of the Manager of Pollution Abatement.

(I) A plan for operation which shall address the method(s) by which 

excess water will be disposed.

(c) Restrictions.

(1) Order required. No commercial earthen pit shall be constructed, 

enlarged, reconstructed, or used without a Commission order.

(2) Site limitations.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 152 -

(A) No commercial earthen pit shall be constructed or used unless an 

investigation of the soils, topography, geology, and hydrology 

conclusively shows that storage of water-based drilling fluids and/or 

cuttings at the site will not be harmful to groundwater, surface water, 

soils, plants, or animals in the surrounding area. No abandoned mine, 

strip pit, quarry, canyon, or streambed shall be used for disposal of 

oilfield wastes, nor shall a pit be constructed or used in such a 

setting.

(B) No commercial pit shall be constructed or used on any site that is 

located within a 100-year flood plain.

(C) No commercial pit shall be constructed or used within a wellhead 

protection area (WPA) as identified by the Wellhead Protection Program 

(42 USC Section 300h-7, Safe Drinking Water Act), or within one mile of 

a public water well for which the WPA has not been delineated.

(D) No commercial pit shall be constructed unless it can be shown that 

there will be a minimum of 25 feet between the bottom of the pit and the 

groundwater level. To ascertain this and to demonstrate the subsurface 

profile of the site, a minimum of three test borings (the exact number 

of locations to be determined by the Pollution Abatement Department) 

shall be drilled to a minimum depth of 25 feet below the proposed bottom 

of the pit and into the first free water encountered. Perched water 

tables are not considered for the purposes of this subparagraph. Test 

borings need not extend deeper than 50 feet below the bottom of the pit 

if free water has not been encountered before that depth. All boreholes 

converted to monitor wells shall conform to (e)(15) of this Section. 

All boreholes not converted to monitor wells shall be plugged from top 

to bottom with bentonite, cement, and/or other method approved by the 

Pollution Abatement Department within 30 days of drilling completion.

(E) No commercial pit shall be constructed or used within the following 

distances from the city limits of an incorporated municipality unless 

previously authorized by Commission order:

(i) Three miles if population is 20,000 or less.

(ii) Five miles if population is greater than 20,000.

(F) The construction, enlargement, reconstruction or operation of any 

commercial pit in any area listed in OAC 165:10-29-3 is prohibited.

(3) Means of water disposal. No commercial pit shall be constructed or 

used unless the operator can show that there will be an ongoing means of 

disposal of excess water pursuant to (b)(3)(I) of this Section.

(d) Surety requirements.

(1) Agreement with Commission. Any operator of a commercial pit shall 

file with the Manager of Document Handling for the Conservation Division an 

agreement to properly close and reclaim the site in accordance with 

approved closure and reclamation procedures upon termination of disposal 

operations due to abandonment, shutdown, full pits, or other reason. The 

agreement shall be on forms available from the Conservation Division and 

shall be accompanied by surety. The agreement shall provide that if the 

Commission finds that the operator has failed or refused to close the pits 

or take remedial action as required by law and the rules of the Commission, 

the surety shall pay to the Commission the full amount of the operator's 

obligation up to the limit of the surety.

(2) Surety amount and type. The Commission shall establish the amount of 

surety in the order for the authority to construct, enlarge, or operate a 

commercial pit. The amount of surety shall be based on factors such as 

dimensions of the pit and costs of hauling, closure, reclamation, and 

monitoring. The amount may be subject to change for good cause. Upon 

approved closure of a pit, the Manager of Pollution Abatement may 

administratively reduce the surety requirement to an amount which would 

cover the cost of monitoring the site and plugging the monitor wells. 

Surety shall be maintained for as long as monitoring is required. The type 

of surety shall be a corporate surety bond, certificate of deposit, 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 153 -

irrevocable letter of credit, or other type of surety approved for the pit 

by order of the Commission. Any type of surety that expires shall be 

renewed prior to 30 days before the expiration date.

(3) Posting surety before permit is issued. An operator shall post surety 

with the Commission before a construction permit is issued, pursuant to 

(e)(1) of this Section.

(e) Construction requirements.

(1) Permit required. Prior to constructing any pit, a commercial pit 

operator shall obtain a permit from the Manager of Pollution Abatement. 

Application shall be made on Form 1014N. For use of a commercial pit 

without a permit, the pit operator may be fined up to $5,000.00.

(2) Runoff water prohibited. No runoff water from surrounding land 

surfaces shall be allowed to enter a pit.

(3) Stockpiling of topsoil. Prior to constructing a pit, all topsoil 

within the top twelve inches of soil on the site shall be stockpiled for 

use as the final cover at the time of closure. The topsoil may be 

stockpiled in the outside slopes of the berms, provided it is not used for 

structural purposes and can be readily distinguishable from other soil 

materials at the time of closure. In cases where topsoil is stockpiled in 

the berms, it shall be shown in the as-built drawings pursuant to (e)(16) 

of this Section.

(4) Monitoring by engineer. A registered professional engineer or an 

engineer-in-training working under the supervision of a registered 

professional engineer (RPE) shall monitor the construction of any 

commercial pit to assure that approved design specifications and Commission 

rules are adhered to. A minimum of three on-site visits to the site shall 

be made; one pre-construction, one during construction, and one postconstruction. At least the post-construction on-site visit shall be made 

by the RPE.

(5) Maximum fluid depth. Any pit shall be constructed to contain a 

maximum fluid or sediment depth of seven feet, with a minimum freeboard of 

three feet.

(6) Maximum dimensions. Any pit shall not be constructed to dimensions 

greater than that approved in the order. Furthermore, the maximum width of 

a pit or pit cell shall not exceed 175 feet if closure must be accomplished 

from one side or two adjacent sides; 350 feet if closure can be 

accomplished from at least two opposite sides or three adjacent sides. Pit 

dimensions shall be measured at the maximum allowable fluid level.

(7) Soil liners.

(A) Soil materials to be used in a soil liner shall undergo 

permeability testing before construction. Pre-construction permeability 

testing shall consist of laboratory permeability tests on at least two 

specimens of representative soil liner materials compacted in the 

laboratory to approximately 95 percent of the material's Standard 

Proctor Density (ASTM D-698).

(B) Laboratory permeability test procedures must conform to one of the 

methods described for fine-grained soils in the Corps of Engineers 

Manual EM-1110-2-1906 Appendix VII. In no case shall the pressure 

differential across the specimen exceed five feet of water per inch of 

specimen length.

(C) If permeability testing shows that addition of bentonite or other 

approved material is needed to assist the native soils in meeting the 

permeability standard, it shall be applied at a minimum rate specified 

by the testing or engineering firm. Any bentonite used for liner

material shall not have been previously used in drilling muds.

(D) Any soil liner shall be constructed by disturbing the soil to the 

depth of the bottom of the liner, applying fresh water as necessary to 

the soil materials to achieve a moisture content wet of optimum, then 

recompacting it with heavy construction equipment, such as a footed 

roller, until the required density is achieved, pursuant to (H) of this 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 154 -

paragraph. The liner shall be constructed in maximum six inch lifts 

(after compaction), with each lift being scarified before placement of 

the next lift.

(E) Any soil liner shall cover the bottom and interior sides of the pit 

entirely.

(F) Any soil liner shall be installed on a slope no steeper than 3:1 

(horizontal to vertical).

(G) Any soil liner shall have a minimum thickness of 18 inches (after 

compaction) and shall have a maximum coefficient of permeability of 1.0 

x 10-7 cm/sec.

(H) Any soil liner shall be field tested for compaction, unless a postconstruction permeability test is performed pursuant to (I) of this 

paragraph.

(i) A minimum of six compaction tests shall be performed on any soil 

liner; a minimum of four widely spaced tests in the bottom of the pit 

and two tests on different slopes of the pit are required, unless 

otherwise directed by a Conservation Division representative. 

Particular emphasis shall be placed on selecting locations for 

compaction tests where nonuniformity in soil texture or color can be 

observed.

(ii) Compaction tests shall be conducted in accordance with ASTM 

methods D-2922 or D-1556.

(iii) The soil materials of any liner shall be compacted to at least 

95 percent of the Standard Proctor Density.

(I) Post-construction permeability testing shall consist of at least 

two laboratory permeability tests on undisturbed samples of the 

completed soil liner.

(i) Particular emphasis shall be placed on selecting the location(s) 

for permeability tests or test samples where nonuniformity in soil 

texture or color can be observed.

(ii) Field permeability tests shall be conducted only by the double 

ring infiltrometer method as described in ASTM D-3385. Permeability 

tests may be discontinued prior to flow stabilization upon 

satisfactory evidence that the permeability rate is less than 1.0 x 

10-7 cm/sec.

(8) Geomembrane liners.

(A) Any geomembrane liner that is installed in a commercial pit shall 

have a minimum thickness of 30 mil.

(B) Any geomembrane liner used in a commercial pit shall be chemically 

compatible with the type of substances to be contained and shall have

ultraviolet light protection.

(C) Any geomembrane liner shall be placed over a specially prepared, 

smooth, compacted surface void of sharp changes in elevation, rocks, 

clods, organic debris, or other objects.

(D) Any geomembrane liner shall be continuous, although it may include 

welded or extruded seams, and shall cover the bottom and interior sides 

of the pit entirely. Sewing of seams is prohibited. The edges shall be 

securely placed in a minimum twelve inch deep anchor trench around the 

perimeter of the pit.

(9) Width of the crown. The crown (top) of any berm shall be a minimum of 

eight feet in width.

(10) Slopes. The inside slope of any exterior berm (having fluid on one 

side) shall not be steeper than 3:1 (horizontal to vertical) and the 

outside slope 2.5:1. The slopes of any interior berm (having fluid on both 

sides) shall not be steeper than 3:1.

(11) Earthwork compaction. All earthwork, except as noted in (7)(H)(iii) 

of this subsection, shall be compacted to achieve a minimum 90% Standard 

Proctor Density and shall be applied in lifts where some method of bonding 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 155 -

is achieved between lifts, with each lift not to exceed eight inches prior 

to compaction.

(12) Pipe installation. Any pipe, tinhorn, culvert, or conduit in the 

berm between two adjoining pits shall be placed so that there is a minimum 

of 36 inches between the top of the pipe, tinhorn, culvert, or conduit and 

the lowest point in the top of the berm separating the pits.

(13) Splash pad. All pits which receive fluids directly from a vacuum 

truck shall have a splash pad at the point where fluids are received unless 

a waiver is obtained from the Manager of Pollution Abatement by showing 

that erosion of the liner will not occur. The pad must be constructed of 

materials and to the dimensions necessary to effectively prevent the liner 

from eroding.

(14) Fluid level marker. A minimum of one stationary fluid level marker 

shall be erected in each pit or cell. The marker shall be erected in a 

location within the pit or cell where it can be easily observed. The 

marker shall be of such design that the maximum fluid level at any time may 

be clearly identified. Details of the proposed marker installation shall 

be approved by the Manager of Pollution Abatement prior to installation. 

Markers shall be installed under the supervision of a registered 

professional engineer, licensed land surveyor, or other person approved by 

the Manager of Pollution Abatement prior to installation.

(15) Monitor wells. All commercial pits shall have a minimum of three 

monitor wells installed- one upgradient and two downgradient from the pit. 

The exact number and location of wells shall be approved by the Pollution 

Abatement Department prior to installation. No monitor well shall be 

installed more than 250 feet from the toe of the outside berm of a 

commercial pit, nor shall any existing water well be used as a monitor well 

unless approved by the Manager of Pollution Abatement. Monitor wells 

installed prior to the effective date of this Section may be accepted by 

the Manager of Pollution Abatement if it can be shown that they adequately 

monitor a site. All new monitor wells shall be drilled to a depth of at 

least ten feet below the top of the first free water encountered, and all 

monitor wells shall be drilled to a depth of at least ten feet below the 

base of the pit. All new monitor wells shall be drilled and completed by a 

licensed monitor well driller. If documentation is submitted to the 

Manager of Pollution Abatement prior to drilling the monitor wells to show

that no free water will be encountered within 50 feet below the bottom of 

the pit, the Manager of Pollution Abatement may require that monitor wells 

be drilled to a lesser depth. All new monitor wells shall meet the 

requirements as set out in rules established by the Oklahoma Water 

Resources Board, in addition to the following requirements:

(A) A removable and lockable cap shall be placed on top of the casing. 

The cap shall remain locked at all times, except when the well is being 

sampled.

(B) Within 30 days of installation, specific completion information for 

all monitor wells shall be submitted to the Manager of Pollution 

Abatement.

(16) As-built drawing. A detailed, as-built drawing of the pit(s) and 

monitor wells by or under the supervision of a registered professional 

engineer shall be submitted to the Manager of Pollution Abatement before 

operation of the pit(s) commences.

(17) Liner certification. An affidavit signed by the person who was 

responsible for installing the pit liner, certifying that the liner meets 

minimum requirements and was installed in accordance with Commission rules, 

shall be submitted to the Manager of Pollution Abatement before operation 

of the pit commences. Supporting documentation shall also be submitted, 

such as post-construction permeability or compaction test results, 

bentonite receipts, and geomembrane liner specifications from the 

manufacturer.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 156 -

(18) Pit approval. Acceptance of fluids into a pit shall not commence 

until a representative of the Conservation Division has inspected and 

approved the pit.

(19) Hydrologically sensitive areas. If the proposed site is known to be 

located over a hydrologically sensitive area, in addition to the foregoing 

construction requirements, the additional requirements shall apply:

(A) The total depth of a pit shall not exceed eight feet, and the total 

designed fluid or sediment depth shall not exceed five feet.

(B) A soil liner having a minimum thickness of three feet and a 

coefficient of permeability no greater than 1.0 x 10-8 cm/sec or a 

minimum 60-mil geomembrane liner shall be required.

(C) The Manager of Pollution Abatement shall determine the minimum 

depth of all monitor wells.

(f) Operation and maintenance requirements.

(1) Vegetative cover. Vegetative cover shall be established on all areas 

of earthfill immediately after pit construction or during the first 

planting season if pit construction is completed out of season. The cover 

shall be sufficient to protect those areas from soil erosion and shall be 

maintained.

(2) Fencing. All commercial facilities shall be completely enclosed by a 

fence at least four feet in height. No livestock shall be allowed inside 

the fence.

(3) Sign. A waterproof sign bearing the name of the operator, legal 

description, most current order number, and emergency phone number shall be 

posted within 25 feet of the entrance gate to any commercial pit and shall 

be readily visible.

(4) Site security. Dumping into a commercial pit shall occur only when 

there is an attendant on duty. All sites shall be secured by a locked gate 

when an attendant is not on duty. A key or combination to the lock shall 

be provided to the appropriate Field Inspector for the purpose of carrying 

out inspections.

(5) Fluid level. Drilling fluids and/or cuttings shall not be accepted 

into a commercial pit unless the fluid level can be maintained at an 

elevation no higher than the maximum level of the fluid level marker.

(6) Acceptable materials.

(A) No operator of a commercial pit shall receive any substances other 

than water-based drilling fluids and/or cuttings or salt contaminated 

soils.

(B) No operator of a pit permitted prior to July 9, 1987, shall receive 

fluids and/or cuttings with a chloride content greater than 3500 mg/l. 

No operator of a pit permitted after July 9, 1987, shall receive fluids 

and/or cuttings with a chloride content greater than 5000 mg/l.

(C) A sample from each incoming load shall be collected, filtered using 

a standard API filter press, and tested for chlorides.

(D) The date, volume, source, and chloride level of each load received 

shall be entered into a log book. The log book shall be available for 

inspection by a representative of the Conservation Division of the 

Commission at all times. Log books shall be kept for a minimum of five 

years after closure is completed.

(7) Pit contents. No pit permitted prior to July 9, 1987, shall contain 

fluids and/or cuttings with a chloride content greater than 5,000 mg/l. No 

pit permitted after July 9, 1987, shall contain fluids and/or cuttings with 

a chloride content greater than 10,000 mg/l. The contents of each pit or 

pit cell shall be sampled and analyzed by the operator at least once every 

six months (during January and July) after operations commence. More 

frequent sampling may be required by the Manager of Pollution Abatement. 

The following procedures shall be used:
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 157 -

(A) The appropriate Field Inspector shall be notified at least 24 hours 

in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(B) Samples shall be collected and handled by the operator according to 

EPA-approved standards. (RCRA Groundwater Monitoring Technical 

Enforcement Guidance Document, EPA, OSWER-9950.1, September 1986, pp. 

99-107.)

(C) A minimum of five samples per 50,000 bbls., or part thereof, is 

required for each pit or pit cell. Samples must be taken from different 

horizontally and vertically distributed locations in each pit or pit 

cell.

(D) The samples shall be combined and thoroughly mixed, then a minimum 

two pint composite sample taken for analysis.

(E) If requested by a representative of the Conservation Division, each 

composite sample shall be split and an adequate portion (approximately 

one pint) shall be properly labeled and delivered or otherwise provided 

to the appropriate Conservation Division District Office or Field 

Inspector.

(F) All samples delivered to the laboratory shall be accompanied by a 

chain of custody form.

(G) All composite samples must be analyzed for chlorides by a 

laboratory certified by the Oklahoma Department of Environmental Quality 

or operated by the State of Oklahoma. Analysis of additional parameters 

may be required, as determined by the Manager of Pollution Abatement.

(H) A copy of each analysis shall be forwarded to the Pollution 

Abatement Department within 30 days of sampling.

(8) Oil film.

(A) No commercial pit shall contain an oil film covering more than one 

percent of the surface area of the pit.

(B) The protection of migratory birds shall be the responsibility of 

the operator. Therefore, the Conservation Division recommends that to 

prevent the loss of birds, oil films be removed, or the surface area 

covered by the film be protected from access to birds. (See Advisory 

Notice in 165:10-7-3(c).)

(9) Aesthetics. All commercial pit sites shall be maintained so that 

there is no junk iron or cable, oil or chemical drums, paint cans, domestic 

trash, or debris on the premises.

(10) Structural integrity. All commercial pits shall be used, operated, 

and maintained at all times so as to prevent the escape of their contents. 

All erosion, cracking, sloughing, settling, animal burrows, or other 

condition that threatens the structural stability of any earthfill shall be 

repaired immediately upon discovery.

(11 Monitor wells. Sampling of monitor wells shall begin prior to 

accepting any drilling fluids and/or cuttings into a new facility and 

within 30 days of drilling completion on existing facilities, and shall be 

done at least once every six months (during January and July) after 

operations commence until three years after closure is completed. Sampling 

of greater frequency of duration may be required by the Manager of 

Pollution Abatement. The following procedures shall be used:

(A) The appropriate Field Inspector shall be notified at least 24 hours 

in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(B) Samples shall be collected and handled by the operator according to 

EPA-approved standards. (RCRA Groundwater Monitoring Technical 

Enforcement Guidance Document, EPA, OSWER-9950.1, September 1986, pp. 

99-107.)

(C) If requested by a representative of the Conservation Division, an 

adequate portion of each sample (approximately one pint) shall be 

properly labeled and delivered or otherwise provided to the appropriate 

Conservation Division District Office or Field Inspector.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 158 -

(D) All samples delivered to the laboratory shall be accompanied by a 

chain of custody form.

(E) All samples must be analyzed for pH and chlorides by a laboratory 

certified by the Oklahoma Department of Environmental Quality or 

operated by the State of Oklahoma. Analysis of additional parameters 

may be required based on the operation of the facility as determined by 

the Manager of Pollution Abatement.

(F) A copy of each analysis and a statement as to the depth to 

groundwater encountered in each well, or an affidavit that no water was 

encountered, shall be forwarded to the Pollution Abatement Department 

within 30 days of sampling.

(12) Prevention of pollution. All commercial pits shall be used, 

operated, and maintained at all times so as to prevent pollution. In the 

event of a nonpermitted discharge from a commercial pit, sufficient 

measures shall be taken to stop or control the loss of materials, and 

reporting procedures in 165:10-7-5(c) shall be followed. Any materials 

lost due to such discharge shall be cleaned up as directed by a 

representative of the Conservation Division. For a willful non-permitted 

discharge, the pit operator may be fined up to $5,000.00.

(g) Semiannual report. The operator of any commercial pit shall submit a 

semiannual report on Form 1014A to the Manager of Pollution Abatement by 

February 1 and August 1 of each year.

(h) Closure requirements.

(1) Notification. The Manager of Pollution Abatement shall be notified in 

writing whenever a commercial pit becomes inactive, is abandoned, full of 

sediment, or operation of the pit ceases for any reason. A commercial pit 

may be considered to be inactive by the Commission if:

(A) The pit has been shut down by the Commission because of a violation 

which results in the filing of an application for an order to vacate the 

operator's authority.

(B) The authority to operate has been terminated by failure to comply 

with (j) of this Section.

(C) The operator is unable to furnish documentation to show that there 

has been receipt of drilling fluids and/or cuttings into the pit during 

the previous twelve months.

(2) Time limit. Closure of all commercial pits shall be commenced within 

60 days and completed within one year of cessation of pit operations, 

pursuant to (1) of this subsection. In cases where extenuating 

circumstances arise, one extension of six months may be administratively 

approved in writing by the Manager of Pollution Abatement. Closure shall 

be in accordance with an approved closure plan. A progress report shall be 

submitted to the Manager of Pollution Abatement, every three months (during 

January, April, July, and October) after cessation of pit operations until 

closure is completed.

(3) Restrictive covenant. A restrictive covenant shall be filed with the 

County Clerk of the county in which a commercial pit is located. The 

document shall accurately describe the pit location and shall specifically 

restrict the current or future landowners of the pit site from puncturing 

the final cover of the pit or otherwise disturbing the site to the extent 

that pollution could occur.

(4) Penalty for failure to meet closure requirements. An operator failing 

to meet the closure requirements set out in this subsection may be fined up 

to $1,000.00.

(i) Additional requirements. The requirements set forth in this Section are 

minimum requirements. Additional requirements may be made upon a showing of 

good cause that an operator has a history of complaints for failure to comply 

with Commission rules and regulations, the site has certain limitations, or 

other conditions of risk exist.

(j) Application to existing pits. Subsections (a), (c)(1), (d), (e), (f), 

(g), (h), and (i) of this Section shall apply to all commercial pits permitted 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 159 -

or ordered prior to the adoption of this Section. All pits permitted, but yet 

to be constructed as of the effective date of this Section, shall be subject 

to all of the construction requirements under (e) of this Section.

(k) Variances. Except as otherwise provided in this Section, variances from 

provisions of this Section may be granted for good cause by order after 

application, notice, and hearing.

(l) Compliance history. In the event the Commission has evidence that an 

applicant for a commercial disposal pit may not possess a satisfactory 

compliance history with Commission rules, the Director of the Conservation 

Division may seek an order of the Commission, issued after application, notice, 

and hearing, determining whether the applicant should be authorized to operate 

such a facility.

[SOURCE: Amended at 9 Ok Reg 2295; Amended at 9 Ok Reg 2337, eff 6-25-92; 

Amended at 25 OK Reg 2187, eff 7-11-08 (RM 200800003); Amended at 27 OK Reg 

2128, eff. 7-11-10 (RM 201000003); Amended at 28 OK Reg 1949, eff. 7-11-11 

(RM 201000007); Amended at 29 OK Reg 950, eff. 7-1-12 (RM 201200005); Amended 

at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001); Amended at 32 Ok Reg 767, eff. 

8-27-15 (RM 201500001)]

165:10-9-2. Commercial soil farming 

(a) Order required. No person shall conduct commercial soil farming without 

an order of the Commission.

(b) Site suitability restrictions. Commercial soil farming shall only occur 

on a tract of land having all of the following characteristics [paragraphs 

(1) through (5) shall be determined by the appropriate Soil Conservation 

District or a qualified soils expert]:

(1) A maximum slope of five percent.

(2) Depth to bedrock no less than 20 inches.

(3) A soil profile containing at least twelve inches of one of the 

following U.S.D.A. soil textures:

(A) loam

(B) silt loam

(C) silt

(D) sandy clay loam

(E) clay loam

(F) silty clay loam

(G) sandy clay

(H) silty clay or clay

(4) No commercial soil farming operations shall be conducted on any site 

that is located within a 100-year flood plain.

(5) Slight salinity (defined as electrical conductivity less than 4,000 

micromhos/cm) in the topsoil or upper six inches of the soil.

(6) An Exchangeable Sodium Percentage (ESP) less than 15.

(7) A water table deeper than 25 feet from the soil surface, excluding 

perched water tables (submit basis for this determination).

(8) A minimum distance of 100 feet from any stream designated by Oklahoma 

Water Quality Standards or any fresh water pond, lake, or wetland 

(available for viewing at the Commission's Oklahoma City or appropriate 

Conservation Division District Offices).

(9) The site shall not be located within three (3) miles upstream within 

the watershed for any lake used for public water supply.

(10) No commercial soil farming operations shall be conducted within a 

wellhead protection area (WPA) as identified by the Wellhead Protection 

Program (42 USC Section 300h-7, Safe Drinking Water Act), or within one 

mile of a pubic water well for which the WPA has not been delineated.

(11) No commercial soil farming operations shall be conducted within the 

following distances from the city limits of an incorporated municipality 

unless previously authorized by Commission order:

(A) Three miles if population is 20,000 or less.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 160 -

(B) Five miles if population is greater than 20,000.

(c) Application requirements.

(1) Who may apply. The applicant or joint applicant for commercial soil 

farming shall be the owner of the land (or person having a firm option, in 

writing, to purchase the land) which is to be used for soil farming.

(2) Order required. The Commission may issue an order upon compliance 

with Commission Rules of Practice 165:5-7-1, 165:5-7-35, 165:5-3-1, and 

this Section.

(3) Required exhibits. All exhibits intended to support an application 

shall be filed pursuant to 165:5-7-35. The exhibits shall include the 

following:

(A) A site suitability report, pursuant to (b) of this Section, 

provided by the appropriate Soil Conservation District or a qualified 

soils expert (include qualifications). The report must contain a 

U.S.D.A. Soil Survey map, or when Soil Survey map does not have adequate 

detail, a map prepared by a qualified soils expert. A legend and soil 

type description shall be attached.

(B) Plan of conservation management practices covering needs of storm 

water disposal and erosion control.

(C) A well-prepared map or diagram, drawn to scale, showing the size 

and configuration of the individual soil farming plots. Latitude and 

longitude coordinates designating the corners of the individual soil 

farming plots must be supplied. The map or diagram must also include 

filter strips, receiving pit(s), and staging area(s).

(D) A topographic map of the subject area.

(E) Initial soil analysis with a map indicating the location of soil 

samples.

(F) A detailed discussion of the method of application and use of 

filter strips and provisions for preventing runoff from the application 

area.

(G) A detailed description of how the receiving pit(s) and staging 

area(s) are to be constructed, including, but not limited to, 

designation of the materials to be used for construction of the 

receiving pit(s) and staging area(s).

(d) Sampling requirements.

(1) Contact with appropriate Conservation Division District Office. The 

appropriate Conservation Division District Office shall be contacted at 

least two business days prior to sampling to allow a Commission 

representative an opportunity to witness the sampling of the receiving 

soil.

(2) Receiving soil. Subsequent to the preparation of a conservation plan 

or site suitability report, soil samples shall be taken from the proposed 

soil farming plot and analyzed. Analysis shall be submitted pursuant to 

(c)(3)(E) of this Section. Soil sampling shall follow this procedure:

(A) If the site contains soil types from different parent material, 

separate areas shall be established for soil sampling and loading 

calculations.

(B) A sample area shall not exceed 40 acres.

(C) A minimum of 20 representative surface core samples (0-6 inches) 

and 20 representative subsurface core samples (18-30 inches) must be 

taken from each sample area. The samples shall be composited for 

analysis of a single surface core sample and a single subsurface core 

sample.

(3) Sampling incoming loads of mud and/or cuttings. A sample from each 

incoming load of mud and/or cuttings shall be collected, filtered using a 

standard API filter press, and tested for Total Dissolved Solids (TDS). 

The date, volume, source, and TDS level of each incoming load of mud and/or 

cuttings received shall be entered into a log book. The log book shall be 

available for inspection by a representative of the Conservation Division. 

Log books shall be kept for a minimum of five years.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 161 -

(4) Sampling of mud and/or cuttings to be soil farmed. The mud and/or 

cuttings to be soil farmed shall be sampled using the following procedures:

(A) A minimum of five samples per 50,000 bbls., or part thereof, each 

representative of the materials to be soil farmed, is required for each 

pit or pit cell. Samples must be taken from different horizontally and 

vertically distributed locations in each pit or pit cell.

(B) The samples shall be combined and thoroughly mixed, then a minimum 

two pint composite sample shall be taken for TDS and percent of solids

analysis, a minimum three pint composite sample taken for oil and grease 

analysis, and a minimum two pint composite sample taken for arsenic and 

chrome analysis.

(C) If requested by a representative of the Conservation Division, each 

composite sample for TDS and percent of solids analysis shall be split 

and an adequate portion (approximately one pint) properly labeled and 

delivered or otherwise provided to the appropriate Conservation Division 

District Office or Field Inspector.

(D) After samples have been taken for analysis from a pit or pit cell, 

the operator shall not allow the addition of fluids or other materials, 

except natural precipitation or fresh water, to decrease the viscosity 

of the fluid.

(e) Analysis requirements.

(1) Approved laboratory. Soil and mud and/or cuttings samples shall be 

analyzed by a laboratory operated by the State of Oklahoma or certified by 

the Oklahoma Department of Environmental Quality.

(2) Soil. Parameters for analysis of soil shall include, but are not 

limited to pH, Total Soluble Salts (TSS) or Electrical Conductivity, and 

Exchangeable Sodium Percentage (ESP).

(3) Mud and/or cuttings contents. Parameters for analysis of mud and/or 

cuttings contents shall include, but are not limited to, the following: 

pH, TDS, Electrical Conductivity, Arsenic, Chromium and Oil and Grease. 

Arsenic and Chromium may be analyzed by either Nitric Acid Extraction or 

Acetic Acid Extraction ("Test Methods for Evaluating Solid Waste," SW846, 

second edition, U.S. EPA). The analysis shall specify which method of 

extraction was used.

(f) Maximum application rate.

(1) Loading limits.

(A) The maximum application rate (loading limit) shall be calculated by 

the operator using the calculations in (g) of this Section and the 

following soil loading standards:

(i) Total Soluble Salts: 6,000 lbs/acre (less TSS in soil).

(ii) Arsenic: 80 lbs/acre.

(iii) Chromium: 80 lbs/acre.

(iv) Oil and Grease: 40,000 lbs/acre.

(v) Total Dry Weight: 200,000 lbs/acre.

(B) Limitations in (A) of this paragraph are based upon standards set 

forth in the following publications:

(i) "Diagnosis and Improvement of Saline and Alkaline Soils," U.S. 

Agriculture Handbook, No. 60, U.S. Salinity Laboratory, Riverdale, 

California, 1954

(ii) "Critical Concentrations for Irrigation Water Supplies," Water 

Quality Criteria, 1972 Ecological Research Series, EPA-R2-73-033, 

March, 1973

(iii) H.R. Moseley, "Summary and Analysis of API Onshore Drilling 

Mud and Produced Water Environmental Studies," American Petroleum 

Institute Bulletin, No. D-19, 1983

(2) Determination of most limiting parameter. The maximum application 

rate shall be restricted by the most limiting parameter. It may require 

more than one application to achieve the maximum application rate while 

avoiding runoff. Determination of the most limiting parameter is based 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 162 -

upon concentrations found in the 0"-6" soil profile at the soil farming 

site.

(3) Records required. Accurate records shall be kept as to when, where 

(which application area), and how much is applied. The operator shall make 

such records available at all times for inspection by a representative of 

the Conservation Division. Additionally, a semiannual report shall be 

submitted to the Manager of Pollution Abatement, pursuant to (k) of this 

Section.

(4) Additional soil sampling required when sixty percent of the maximum 

application rate is obtained. Additional soil sampling and analysis of a 

plot shall be done prior to each soil farming application when records show 

that 60 percent of the maximum application rate in (1) of this subsection 

of any parameter except total weight is reached. Requirements of (d) and 

(e) of this Section shall be met. Soil farming shall not be permitted on a 

plot if the analysis indicates that more than 95 percent of the maximum 

application rate of any parameter has been reached or if the ESP is greater 

than 15.

(g) Calculations. The procedures described in Appendix H of this Chapter 

shall be used in calculating the maximum application rate.

(h) Operation requirements.

(1) Surety required.

(A) Any operator of a commercial soil farming site shall file with the 

Manager of Document Handling for the Conservation Division an agreement 

to clean up pollution, restore the site, and/or plug monitor wells upon 

termination of operations. The agreement shall be on forms available 

from the Conservation Division and shall be accompanied by surety. The 

agreement shall provide that if the Commission finds that the operator 

has failed or refused to comply with the rules or take remedial action 

as required by law and this Section, the surety shall pay to the 

Commission the full amount of the operator's obligation up to the limit 

of the surety.

(B) The Commission shall establish the amount of surety in the order 

for the authority to operate a commercial soil farming site. The amount 

may be subject to change for good cause. The surety shall be maintained 

for as long as monitoring is required. The type of surety shall be a 

corporate surety bond, certificate of deposit, irrevocable letter of 

credit, or other type of surety approved by order of the Commission. 

Any type of surety that expires shall be renewed prior to 30 days before 

the expiration date.

(2) Sign required. A waterproof sign bearing the name of the operator, 

legal description, order number, and emergency phone number shall be posted 

within 25 feet of the entrance to any commercial soil farming site and 

shall be readily visible.

(3) Monitor wells.

(A) Any commercial soil farming operation shall be required to have a 

minimum of three (3) monitor wells installed- one upgradient and two (2) 

downgradient. The exact number and location of wells shall be 

established by the Pollution Abatement Department.

(B) No monitor well shall be installed more than 250 feet from a 

commercial soil farming operation, nor shall any existing water well be 

used as a monitor well, unless approved by the Manager of Pollution 

Abatement. Monitor wells installed prior to the effective date of this 

Section may be accepted by the Manager of Pollution Abatement if it can 

be shown that they adequately monitor a site.

(C) All new monitor wells shall be drilled to a depth of at least ten 

feet below the top of the first free water encountered, and shall be 

drilled and completed by a licensed monitor well driller. If 

documentation is submitted to the Manager of Pollution Abatement prior 

to drilling the monitor wells to show that no free water will be 

encountered within a depth of 50 feet from the surface, then the Manager 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 163 -

of Pollution Abatement may require that monitor wells be drilled to a 

lesser depth.

(D) All new monitor wells shall meet the requirements as set out in 

rules established by the Oklahoma Water Resources Board, in addition to 

the following requirements:

(i) A removable and lockable cap shall be placed on top of the 

casing. The cap shall remain locked at all times, except when the 

well is being sampled.

(ii) Within 30 days after installation, specific completion 

information for all monitor wells and a diagram of their locations in 

relation to the soil farming site shall be submitted to the Manager 

of Pollution Abatement.

(4) Sampling of monitor wells. Sampling of monitor wells shall begin 

prior to the first soil farming application and shall be done once every 

six months (during January and July) after operations commence until one 

year after the last application is made, then once every year for three 

years according to the following:

(A) The appropriate District Manager shall be notified at least 24 

hours in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(B) Samples shall be collected and handled by the operator according to 

EPA-approved standards ("RCRA Groundwater Monitoring Technical 

Enforcement Guidance Document," EPA, OSWER-9950.1, September, 1986, 

pp.99-107.)

(C) If requested by a representative of the Conservation Division, an 

adequate portion of each sample (approximately one pint) shall be 

properly labeled and delivered or otherwise provided to the appropriate 

Conservation Division District Office or Field Inspector.

(D) All samples must be analyzed for pH and chlorides by a laboratory 

certified by the Oklahoma Department of Environmental Quality or 

operated by the State of Oklahoma. Analysis of additional parameters 

may be required based on the operations as determined by the Manager of 

Pollution Abatement.

(E) A copy of each analysis and a statement as to the depth to 

groundwater encountered in each well, or an affidavit that no water was 

encountered, shall be forwarded to the Pollution Abatement Department 

within 30 days of sampling.

(5) Representative soil analysis. A representative soil analysis of the 

active soil farming plot (or plots) shall be submitted to the Manager of 

Pollution Abatement with the semiannual report on Form 1014A. The analysis 

shall include TSS, oil and grease, ESP, arsenic and chrome.

(6) Site Security. Soil farming shall only occur when there is an 

attendant on duty. All sites shall be secured by a locked gate when an 

attendant is not on duty. A key or combination to the lock shall be 

provided to the appropriate Field Inspector for the purpose of carrying out 

inspections.

(i) Conditions of operation.

(1) Required form. A completed Form 1014CS shall be submitted to the 

Manager of Pollution Abatement for approval prior to commencement of soil 

farming.

(2) Notice to Commission. The applicant, by agreement with the 

Conservation Division, shall schedule the commencement of soil farming no 

less than 24 hours prior thereto, to allow a Commission representative to 

be present to witness the work.

(3) Presence of representative. A representative of the applicant shall 

be on the soil farming site at all times during application of the pit 

materials to the land.

(4) Type muds to be soil farmed. Commercial soil farming is limited to 

water-based type muds and/or cuttings. At the time of land application, 

soil farming of water-based type muds and/or cuttings with a chloride 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 164 -

content greater than 5,000 mg/l shall be prohibited. Soil farming of mud 

containing asphalt based oil, or oil-based muds and/or cuttings shall be 

prohibited.

(5) Weather restrictions. Commercial soil farming shall not be done:

(A) During precipitation events.

(B) When the soil moisture content is at a level such that the soil 

would not readily take the addition of drilling fluids.

(C) When the ground is frozen.

(D) By spray irrigation when the wind velocity is such that even 

distribution of materials cannot be accomplished or the buffer zones, 

pursuant to (6) of this subsection, or filter strips, pursuant to (7) of 

this subsection, cannot be maintained.

(6) Buffer zones: No commercial soil farming shall be done within the 

following buffer zones: 

(A) One hundred feet of a property line boundary.

(B) Fifty feet of any stream not designated by Oklahoma Water Quality 

Standards.

(C) Three hundred feet of any actively-producing water well used for 

domestic, irrigation or industrial purposes.

(D) One thousand three hundred feet of any public water well.

(7) Filter strips. No commercial soil farming shall be done on filter 

strips. Filter strips must have a minimum width of 100 feet, and 

vegetation must be maintained on filter strips.

(8) Application rate. The maximum application rate of drilling fluids 

and/or cuttings stipulated by the permit shall not be exceeded. 

Furthermore, the minimum required acreage within the approved soil farming 

plot, as designated by the permit, shall be fully utilized. Application of 

drilling fluids and/or cuttings outside the approved plot shall be 

prohibited.

(9) Soil farming method.

(A) Application of mud and/or cuttings shall be uniform over the soil 

farming plot and shall be made by injection, spray irrigation, or other 

method approved by the Commission prior to use. The flood irrigation 

method shall be limited to those fields that normally are irrigated in 

that manner.

(B) An application of more than 50,000 lbs/acre of dry weight materials 

or more than 500 lbs/acre of oil and grease shall be incorporated into 

the soil by injection, disking, or other method approved by the 

Commission. If the injection method is not used, incorporation must be 

made within a reasonable time period after completion of application, 

not to exceed 14 days unless extended by the Pollution Abatement 

Department pursuant to a written request.

(C) When the spray irrigation method is used and solids eventually 

accumulate on the soil surface to a one-eighth (1/8) inch depth, then 

the materials shall be incorporated prior to subsequent soil farming.

(D) The type of vehicle to be used to soil farm the mud and/or cuttings 

must be approved by the Manager of Pollution Abatement prior to 

commencement of operations.

(10) Runoff or ponding prohibited. No runoff or ponding of soil farmed 

materials shall be allowed during application.

(11) Suspension of soil farming authority. If the applicant violates the 

order authorizing soil farming, or this Section, soil farming shall be 

discontinued and the Pollution Abatement Department shall be contacted 

immediately. The Pollution Abatement Department may shut down the facility 

until the operator completes any remedial work. Soil farming may resume 

with the approval of the Pollution Abatement Department.

(12) Prevention of pollution. All commercial soil farming facilities 

shall be operated and maintained at all times so as to prevent pollution. 

In the event of a nonpermitted discharge from a commercial soil farming 

facility, sufficient measures shall be taken to stop or control the loss of 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 165 -

materials and reporting procedures in 165:10-7-5 (c) shall be followed. 

Any materials lost due to such discharge shall be cleaned up as directed by 

a representative of the Conservation Division.

(13) Vegetative cover. If the vegetative cover of the area which has been 

soil farmed is destroyed or significantly damaged by disking, injection, or 

other practice associated with soil farming, the vegetative cover shall be 

reestablished within one year after the last soil farming application.

(14) Fencing. All commercial soil farming sites shall be completely 

enclosed by a fence at least four feet in height. No livestock shall be 

allowed inside the fence.

(j) Additional requirements. The requirements set forth in this Section are 

minimum requirements. Additional requirements may be made upon a showing of 

good cause that an operator has a history of complaints for failure to comply 

with Commission rules, or the site has certain limitations, or other 

conditions of risk exist.

(k) Semiannual report. The operator of any commercial soil farming facility 

shall submit a semiannual report on Form 1014A to the Manager of Pollution 

Abatement by February 1 and August 1 of each year.

(l) Prospective application to existing operations. Subsections (d), (e), 

(f), (g), (h), (i), (j), (k) and (m) of this Section shall apply to all 

commercial soil farming operations for which an order or permit was obtained 

prior to the adoption of this Section. All affected operators shall have 

their facility in compliance with all of the noted subsections by December 31, 

1988. Failure to be in compliance by that date shall result in termination of 

the authority to operate.

(m) Variances. Except as provided in this Section, variances from provisions 

of this Section may be granted for good cause by order after application, 

notice, and hearing.

(n) Compliance history. In the event the Commission has evidence that an 

applicant for a commercial soil farming operation may not possess a satisfactory 

compliance history with Commission rules, the Director of the Conservation 

Division may seek an order of the Commission, issued after application, notice, 

and hearing, determining whether the applicant should be authorized to conduct 

such commercial soil farming operation.

[Source: Amended at 12 Ok Reg 2017, eff 7-1-95; Amended at 25 OK Reg 2187, 

eff 7-11-08 (RM 200800003); Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 29 OK Reg 950, eff. 7-1-12 (RM 201200005); Amended at 

32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-9-3. Commercial disposal well surface facilities

(a) Scope. This Section shall apply to the surface facilities of any 

commercial disposal well. Any pit sought to be approved pursuant to this 

Section will require a permit. The operator of the proposed pit shall submit 

Form 1014 in duplicate to the appropriate Conservation Division District 

Office for review and approval. 

(b) Site restriction. No commercial disposal well pit shall be constructed 

in any area that floods according to the Soil Conservation Service County Soil 

Survey (available for viewing at the Commission's Oklahoma City Office or 

appropriate Conservation Division District Offices).

(c) Construction requirements.

(1) Dikes. A dike shall be constructed and maintained around any storage 

tank or group of tanks. The diked area shall be capable of totally 

containing at least one and one-half (1 1/2) times the volume held by the 

largest storage tank.

(2) Leak containment. A means for containing leaks shall be provided at 

all pumps and connections.

(3) Splash pad/apron. A splash pad/apron shall be constructed at the 

unloading area of any pit to the design and dimensions necessary to contain 

and direct all materials unloaded into the pit. If a pit is not used, an 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 166 -

apron shall be constructed at the unloading area to the design and 

dimensions necessary to direct any spills into containment.

(4) Pit specifications. Any commercial disposal well pit shall be 

constructed of concrete or steel or shall be lined with a geomembrane 

liner. The following specifications shall be met:

(A) Any concrete pit shall be steel-reinforced and have a minimum wall 

thickness of six inches.

(B) Any steel pit shall have a minimum wall thickness of threesixteenths (3/16) inch. If a previously used steel pit is installed, it 

shall be free of corrosion or other damage.

(C) Any geomembrane liner shall meet these requirements:

(i) The geomembrane liner shall have a minimum thickness of 30-mils, 

shall be chemically compatible with the type of wastes to be 

contained, and shall have ultraviolet light protection.

(ii) The geomembrane liner shall be placed over a specially 

prepared, smooth, compacted surface void of sharp changes in 

elevation, rocks, clods, organic debris, or other objects.

(iii) The geomembrane liner shall be continuous (may include seams) 

and shall cover the bottom and interior sides of the pit entirely. 

The edges shall be securely placed in a minimum twelve inch deep 

anchor trench around the perimeter of the pit.

(5) Certification of liner. The operator of any commercial disposal well 

pit that is constructed with a geomembrane liner shall secure an affidavit 

signed by the installer, certifying that the liner meets minimum 

requirements and was installed in accordance with Commission rules. It 

shall be the operator's responsibility to maintain the affidavit and all 

supporting documentation pertaining to the liner, such as geomembrane liner 

specifications from the manufacturer, etc., and shall make them available 

to a representative of the Conservation Division upon request.

(6) Monitor wells or leachate collection system.

(A) Any commercial disposal well pit shall be required to have a 

leachate collection system or a minimum of three monitor wells, one 

upgradient and two downgradient from the pit.

(B) No monitor well shall be installed more than 100 feet from a 

commercial disposal well pit, nor shall any existing water well be used 

as a monitor well, unless written approval is given by the District 

Manager or Manager of Field Operations.

(C) All new monitor wells shall be drilled to a depth of at least ten 

feet below the top of the first free water encountered and shall be 

drilled and completed by a licensed monitor well driller. If 

documentation is submitted prior to drilling the monitor well to show 

that no free water will be encountered within a depth of 50 feet from 

the surface, the District Manager may require that monitor wells be 

drilled to a lesser depth.

(D) All new monitor wells shall meet the requirements as set out in 

rules established by the Oklahoma Water Resources Board, in addition to 

the following requirements:

(i) A removable and lockable cap shall be placed on top of the 

casing. The cap shall remain locked at all times, except when a well 

is being sampled. A key to each well shall be made available to the 

appropriate District Manager or Field Inspector upon request.

(ii) Within 30 days of installation, construction details for any 

leachate collection system or specific completion information for all 

monitor wells and a diagram of their locations in relation to the pit 

they monitor shall be submitted to the Manager of Field Operations.

(d) Operation and maintenance requirements.

(1) Sign. A waterproof sign shall be erected and maintained within 25 

feet of the entrance road to any commercial disposal well, shall be readily 

visible, and shall contain the name of the operator, order or permit 

number, legal description, and emergency phone number.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 167 -

(2) Fencing. All commercial disposal well surface facilities that have a 

pit shall be completely enclosed by a fence at least four feet in height. 

No livestock shall be allowed inside the fence.

(3) Site maintenance. The normal access surface of any commercial 

disposal well site, including the access road(s), shall be maintained in a 

condition that will safely and easily accommodate a passenger car during 

all weather conditions.

(4) Exclusion of runoff water. No commercial disposal well pit shall be 

allowed to receive runoff water.

(5) Freeboard. The fluid level in any concrete or steel commercial 

disposal well pit shall be maintained at all times at least 6 inches below 

the top of the pit wall, unless otherwise specified on Form 1014. Any 

geomembrane lined pit shall have a minimum of 24 inches freeboard at all 

times.

(6) Temporary storage only. No pit shall be used as permanent storage for 

salt water.

(7) Sampling of monitor wells or leachate collection systems.

(A) Sampling of monitor wells or leachate collection systems shall 

occur once every six months, during the months of January and July.

(B) The appropriate District Manager shall be notified at least 24 

hours in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(C) Samples shall be collected, preserved, and handled by the operator 

according to EPA-approved standards (RCRA Groundwater Monitoring 

Technical Enforcement Guidance Document, EPA, OSWER-9950.1, September, 

1986, pp. 99-107) and analyzed for pH, chlorides and Total Dissolved 

Solids (TDS) by a laboratory certified by the Oklahoma Department of 

Environmental Quality or operated by the State of Oklahoma. Analysis of 

additional parameters may be required, as determined by the District 

Manager or Manager of Field Operations.

(D) If requested by the District Manager, each sample shall be split 

and an adequate portion (approximately one pint) properly labeled and 

delivered upon request or otherwise provided to the appropriate 

Conservation Division District Office or Field Inspector. A copy of 

each analysis and a statement as to the depth to groundwater encountered 

in each well or leachate collection system, or an affidavit that no 

water was encountered, shall be forwarded to the Manager of Field 

Operations, within 30 days of sampling.

(8) Prevention of pollution. All commercial disposal well pits shall be 

used, operated, and maintained at all times so as to prevent pollution. In 

the event of a nonpermitted discharge from surface facilities of a 

commercial disposal well, sufficient measures shall be taken to stop or 

control the loss of materials and reporting procedures in 165:10-7-5(c) 

shall be followed. Any materials lost due to such discharge shall be 

cleaned up as directed by a representative of the Conservation Division.

(9) Oil film. The operator of a saltwater disposal system shall be 

responsible for the protection of migratory birds. Therefore, the 

Conservation Division recommends that to prevent the loss of birds due to 

oil films, all open top tanks and pits containing fluid be kept free of 

hydrocarbons, or be protected from access to birds. [See Advisory Notice 

165:10-7-3(c).]

(10) Site security. Commercial disposal well facilities must be secured 

at all times so as to prevent unauthorized access. If an electronic system 

is used to secure the facility or if fluids to be disposed in the well are 

transported to the facility by pipe, an automatic shut-off or alarm system 

must be installed to ensure that disposal operations cease if a well 

mechanical failure or downhole problem occurs. If an electronic system is 

not used to secure the facility, fluids shall be received for placement in 

a commercial disposal well only when there is an attendant on duty if 

fluids are hauled in by truck. All sites not protected by an electronic 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 168 -

system shall be secured by a locked gate when an attendant is not on duty. 

A key or combination to the lock or electronic security system access code

shall be provided to the appropriate Field Inspector for the purpose of 

carrying out inspections.

(e) Closure requirements.

(1) Time limit. Within 90 days of the cessation of operation of any 

commercial disposal well, all associated pits shall be emptied of all 

contents and filled with soil. All monitor wells shall be plugged with 

bentonite or cement, unless exempt in writing by the District Manager or 

Manager of Field Operations. The site shall be revegetated within 180 

days.

(2) Geomembrane-lined pits. When closing any commercial disposal well pit 

with a geomembrane liner, extreme care shall be taken to preserve the 

integrity of the liner. All free liquids shall be removed or chemically 

solidified. A geomembrane cap shall be placed over the top of any 

remaining contents to completely encapsulate them. Any geomembrane cap 

shall have a minimum thickness of twelve mils and shall be chemically 

compatible with the type of substances to be encapsulated. Burial, 

pursuant to (3) of this subsection, shall follow.

(3) Burial. If any concrete, steel, geomembrane, or other materials 

associated with a commercial disposal well site are to be left on-site, 

they shall be buried under a minimum soil cover of three feet, pursuant to 

165:10-3-17.

(f) Prospective application to existing facilities. All provisions of this 

Section except (4) and (5) of subsection (c) shall apply to all existing 

commercial disposal well pits which are, or have been, in operation prior to 

the effective date of this Section. Operators shall have 180 days from the 

effective date of this Section in which to bring their facilities into 

compliance with the applicable provisions of this Section. Failure to comply 

with any applicable provision may result in revocation of the authority to 

operate.

(g) Variances. A variance from the time requirements of (d)(7) or (e)(1) of 

this Section may be granted by the District Manager or Manager of Field 

Operations for justifiable cause. A written request and supporting 

documentation is required. The District Manager or Manager of Field 

Operations shall respond in writing within five business days, either 

approving or disapproving the request.

[Source: Amended at 11 Ok Reg 3691, eff 7-11-94; Amended at 27 OK Reg 2128, 

eff. 7-11-10 (RM 201000003); Amended at 28 OK Reg 1949, eff. 7-11-11 

(RM 201000007); Amended at 29 OK Reg 950, eff. 7-1-12 (RM 201200005); Amended 

at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001); Amended at 32 Ok Reg 767, eff. 

8-27-15 (RM 201500001)]

165:10-9-4. Commercial recycling facilities

(a) Scope. This Section shall cover the permitting, construction, operation, 

and closure requirements for commercial recycling facilities. A commercial 

recycling facility is a facility which is authorized by Commission order to 

recycle materials defined as “deleterious substances” in OAC 165:10-1-2. Such 

substances must undergo at least one treatment process and must be recycled 

into a marketable product for resale and/or have some beneficial use. This 

definition does not include the reuse of drilling mud (plug mud) which was 

previously utilized in drilling or plugging operations. This Section does not 

cover hydrocarbon recycling/reclaiming facilities (see OAC 165:10-8-1 through 

165:10-8-11). 

(b) Application requirements for facilities to recycle flowback water.

(1) Who may apply. The applicant for a commercial recycling facility 

shall be the owner of the land (or person having a written firm option to 

purchase the land at the time the application is filed) on which the 

proposed facility is to be located. If the land on which the proposed 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 169 -

facility is to be located is leased, both the owner and lessee of the land 

shall be joint applicants.

(2) Compliance with rules. Before issuance of an order authorizing the 

commercial recycling facility, the applicant shall comply with Commission 

Rules of Practice OAC 165:5-7-1, 165:5-7-35, 165:5-3-1, and this Section.

(3) Exhibits. Two complete sets of all exhibits which shall be relied 

upon by the applicant shall be submitted to the Pollution Abatement 

Department of the Commission, pursuant to OAC 165:5-7-35. Those exhibits 

shall include, but are not limited, to the following:

(A) A lithologic log of test borings, identifying the subsurface 

materials encountered and the depth at which groundwater was encountered 

pursuant to (d)(2)(D) of this Section.

(B) A topographic map of the commercial recycling facility site.

(C) The appropriate Soil Conservation Service (SCS) soil survey aerial 

photo and legend.

(D) A detailed drawing of the site, with complete construction plans 

drawn to scale by or under the supervision of a registered professional 

engineer.

(E) A plan for closure of the facility, which shall specifically state 

how all aspects of closure shall be accomplished, including volume and 

fate of liquids and solids, earthwork to close any pit(s) (including 

placement of stockpiled topsoil), and revegetation of the site.

(F) An itemization of projected hauling, closure, reclamation, 

maintenance, and monitoring costs.

(G) A plan for post-closure maintenance and monitoring which shall 

address maintenance of the site as well as monitoring and plugging of 

wells. Exemption from the plugging of monitor wells may be obtained 

upon written request and approval of the Manager of Pollution Abatement.

(H) A plan for operation which shall address the method(s) by which 

excess water will be disposed.

(c) Application requirements for recycling facilities designed for 

deleterious substances other than flowback water.

(1) Who may apply. The applicant for a commercial recycling facility 

shall be the owner of the land (or person having a written firm option to 

purchase the land at the time the application is filed) on which the 

proposed facility is to be located. If the land on which the proposed 

facility is to be located is leased, both the owner and lessee of the land 

shall be joint applicants.

(2) Compliance with rules. Before issuance of an order authorizing the 

commercial recycling facility, the applicant shall comply with Commission 

Rules of Practice OAC 165:5-7-1, 165:5-7-35, 165:5-3-1, and this Section.

(3) Exhibits. Two complete sets of all exhibits which shall be relied 

upon by the applicant shall be submitted to the Pollution Abatement 

Department of the Commission pursuant to OAC 165:5-7-35. Those exhibits 

shall include, but are not limited, to the following:

(A) A topographic map of the commercial recycling facility site.

(B) The appropriate Soil Conservation Service (SCS) soil survey aerial 

photo and legend.

(C) A detailed drawing of the site, with complete construction plans, 

which shall include, but not be limited to, the location of any pits, 

staging areas and storm water retention structures. 

(D) A detailed description of the recycling process and the types of 

deleterious substances that will be recycled. 

(E) A plan for closure of the facility, which shall specifically state 

how all aspects of closure shall be accomplished, including volume and 

disposition of liquids and solids, earthwork to close any pit(s) 

(including placement of any stockpiled topsoil), removal of all 

materials in staging areas, and revegetation of the site.

(F) An itemization of projected hauling, closure, reclamation, 

maintenance, and monitoring costs.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 170 -

(G) A plan for post-closure maintenance and monitoring which shall 

address maintenance of the site as well as monitoring and plugging of 

wells. Exemption from the plugging of monitor wells may be obtained 

upon written request and approval of the Manager of Pollution Abatement.

(d) Restrictions.

(1) Order required. No commercial recycling facility shall be 

constructed, enlarged, reconstructed, or used without a Commission order.

(2) Site limitations.

(A) No commercial recycling facility shall be constructed or used 

unless an investigation of the soils, topography, geology, and hydrology 

conclusively shows that storage of deleterious substances and the 

recycling of such substances at the site will not be harmful to 

groundwater, surface water, soils, plants, or animals in the surrounding 

area. No commercial recycling facility shall be constructed or used on 

or in an abandoned mine, strip pit, quarry, canyon, or streambed.

(B) No commercial recycling facility shall be constructed or used on 

any site that is located within a 100-year flood plain.

(C) No commercial recycling facility shall be constructed or used 

within a wellhead protection area (WPA) as identified by the Wellhead 

Protection Program (42 USC Section 300h-7, Safe Drinking Water Act), or 

within one mile of a public water well for which the WPA has not been 

delineated.

(D) Pits shall not be constructed or used at flowback water recycling 

facilities unless it can be shown that there will be a minimum of 25 

feet between the bottom of the pit(s) and the groundwater level. To 

ascertain this and to demonstrate the subsurface profile of the site, a 

minimum of three test borings (the exact number of locations to be 

determined by the Pollution Abatement Department) shall be drilled to a 

minimum depth of 25 feet below the proposed bottom(s) of the pit(s) and 

into the first free water encountered. Perched water tables are not 

considered for the purposes of this subparagraph. Test borings need 

not extend deeper than 50 feet below the bottom(s) of the pit(s) if free 

water has not been encountered before that depth. All boreholes 

converted to monitor wells shall conform to (f)(14) of this Section. 

All boreholes not converted to monitor wells shall be plugged from top 

to bottom with bentonite, cement, and/or other method approved by the 

Pollution Abatement Department within 30 days of drilling completion.

(E) If pits are not used in the operation of a commercial recycling 

facility, the Manager of Pollution Abatement may require test borings to 

be drilled at the site if data from monitor well boring(s) is 

insufficient to properly evaluate the site.

(F) No commercial recycling facility that is to use pits with a 

capacity in excess of 50,000 barrels shall be constructed or used within 

the following distances from the city limits of an incorporated 

municipality unless previously authorized by Commission order:

(i) Three miles if population is 20,000 or less.

(ii) Five miles if population is greater than 20,000.

(3) Means of water disposal. No commercial recycling facility shall be 

constructed or used unless the operator can show that there will be an 

ongoing means of disposal of excess water pursuant to (b)(3)(H) of this 

Section.

(e) Surety requirements.

(1) Agreement with Commission. Any operator of a commercial recycling 

facility shall file with the Manager of Document Handling for the 

Conservation Division an agreement to properly close and reclaim the site 

in accordance with approved closure and reclamation procedures upon 

termination of recycling operations due to abandonment, shutdown, full 

pits, or other reason. The agreement shall be on forms available from the 

Conservation Division and shall be accompanied by surety. The agreement 

shall provide that if the Commission finds that the operator has failed or 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 171 -

refused to close the facility or take remedial action as required by law 

and the rules of the Commission, the surety shall pay to the Commission the 

full amount of the operator's obligation up to the limit of the surety.

(2) Surety amount and type. The Commission shall establish the amount of 

surety in the order for the authority to construct, enlarge, or operate a 

commercial recycling facility. The amount of surety shall be based on 

factors such as dimensions of the facility and costs of closure, 

reclamation, monitoring, plugging of monitor wells, any pit closure, 

trucking of any deleterious substances, remediation, earth work, 

revegetation, etc. The amount may be subject to change for good cause. 

Upon approved closure of a facility, the Manager of Pollution Abatement may 

administratively reduce the surety requirement to an amount which would 

cover the cost of monitoring the site and plugging the monitor wells. 

Surety shall be maintained for as long as monitoring is required. The type 

of surety shall be a corporate surety bond, certificate of deposit, 

irrevocable letter of credit, or other type of surety approved for the 

facility by order of the Commission. Any type of surety that expires shall 

be renewed prior to 30 days before the expiration date. 

(3) Posting surety before permit is issued. An operator shall post surety 

with the Commission on forms provided by the Manager of Document Handling 

before a construction permit is issued, pursuant to (f)(1) of this Section.

(f) Construction requirements.

(1) Permit required. Prior to constructing any commercial recycling 

facility, the facility operator shall obtain a permit from the Manager of 

Pollution Abatement. Application shall be made on Form 1014CR. For use of 

a commercial recycling facility without a permit, the facility operator may 

be fined up to $5,000.00.

(2) Runoff water prohibited. No runoff water from surrounding land 

surfaces shall be allowed to enter a commercial recycling facility.

(3) Stockpiling of topsoil. Prior to constructing any pit with a capacity 

in excess of 50,000 barrels utilized in a commercial recycling facility, 

all topsoil within the top twelve inches of soil on the site shall be 

stockpiled for use as the final cover at the time of closure. The topsoil 

may be stockpiled in the outside slopes of the berms, provided it is not 

used for structural purposes and can be readily distinguishable from other 

soil materials at the time of closure. In cases where topsoil is 

stockpiled in the berms, it shall be shown in the as-built drawings 

pursuant to (f)(16) of this Section.

(4) Monitoring by engineer. Construction of any pit(s) with a capacity in 

excess of 50,000 barrels shall be monitored by a registered professional 

engineer or an engineer-in-training working under the supervision of a 

registered professional engineer (RPE) to assure that approved design 

specifications and Commission rules are adhered to. A minimum of three onsite visits to the site shall be made: one pre-construction, one during the 

installation of the geomembrane liner, and one post-construction. At least 

the post-construction on-site visit shall be made by the RPE.

(5) Maximum fluid depth. Any pit utilized in a commercial recycling 

facility shall be constructed in accordance with the maximum fluid or 

sediment depth specified in the order authorizing the facility. Any pit 

shall have a minimum freeboard of three feet.

(6) Maximum dimensions. Any pit utilized in a commercial recycling 

facility shall not be constructed to dimensions greater than that approved 

in the order. Pit dimensions shall be measured at the maximum allowable 

fluid level.

(7) Geomembrane liners.

(A) Any pit utilized in a commercial recycling facility must contain a 

geomembrane liner. The geomembrane liner shall have a minimum thickness 

of 30 mil.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 172 -

(B) Any geomembrane liner used in such pits shall be chemically 

compatible with the type of substances to be contained in the pit and 

shall have ultraviolet light protection.

(C) Any geomembrane liner shall be placed over a specially prepared, 

smooth, compacted surface void of sharp changes in elevation, rocks, 

clods, organic debris, or other objects.

(D) Any geomembrane liner shall be continuous, although it may include 

welded or extruded seams, and the liner must cover the bottom and 

interior sides of the pit entirely. Sewing of seams is prohibited. The 

edges shall be securely placed in a minimum twelve inch deep anchor 

trench around the perimeter of the pit. 

(8) Width of the crown. The crown (top) of any berm of a pit with a 

capacity in excess of 50,000 barrels utilized in a commercial recycling 

facility shall be a minimum of eight feet in width.

(9) Slopes. The inside slope of any exterior berm (having fluid on one 

side) shall not be steeper than 3:1 (horizontal to vertical) and the 

outside slope 2.5:1. The slopes of any interior berm (having fluid on both 

sides) shall not be steeper than 3:1.

(10) Earthwork compaction. All earthwork for pits with a capacity in 

excess of 50,000 barrels shall be compacted to achieve a minimum 90% 

Standard Proctor Density and shall be applied in lifts where some method of 

bonding is achieved between lifts, with each lift not to exceed eight 

inches prior to compaction.

(11) Pipe installation. Any pipe, tinhorn, culvert, or conduit in the 

berm between two adjoining pits shall be placed so that there is a minimum 

of 36 inches between the top of the pipe, tinhorn, culvert, or conduit and 

the lowest point in the top of the berm separating the pits.

(12) Splash pad. All pits utilized in commercial recyling facilities 

which receive fluids directly from a truck shall have a splash pad at the 

point where fluids are received unless a waiver is obtained from the 

Manager of Pollution Abatement by showing that damage of the liner will not 

occur. The pad must be constructed of materials and to the dimensions 

necessary to effectively prevent the liner from eroding.

(13) Fluid level marker. A minimum of one stationary fluid level marker 

shall be erected in each pit or cell as required by the Manager of 

Pollution Abatement. The marker shall be erected in a location within the 

pit or cell where it can be easily observed. The marker shall be of such 

design that the maximum fluid level at any time may be clearly identified. 

Details of the proposed marker installation shall be approved by the 

Manager of Pollution Abatement prior to installation. Markers shall be 

installed under the supervision of a registered professional engineer, 

licensed land surveyor, or other person approved by the Manager of 

Pollution Abatement prior to installation.

(14) Monitor wells. Monitor wells must be installed in conjunction with 

every commercial recycling facility as required by the Manager of Pollution 

Abatement. All pits utilized in commercial recycling facilities shall have 

a minimum of three monitor wells installed-one upgradient and two 

downgradient from the pit. The exact number and location of monitor wells 

shall be approved by the Pollution Abatement Department prior to 

installation. No monitor well shall be installed more than 250 feet from 

the toe of the outside berm of a pit, nor shall any existing water well be 

used as a monitor well unless approved by the Manager of Pollution 

Abatement. Monitor wells installed prior to the effective date of this 

Section may be accepted by the Manager of Pollution Abatement if it can be 

shown that they adequately monitor a site. All new monitor wells shall be 

drilled to a depth of at least ten feet below the top of the first free 

water encountered, and all monitor wells shall be drilled to a depth of at 

least ten feet below the base of any pit. All new monitor wells shall be 

drilled and completed by a licensed monitor well driller. If documentation 

is submitted to the Manager of Pollution Abatement prior to drilling the 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 173 -

monitor wells to show that no free water will be encountered within 50 feet 

below the bottom of any pit, the Manager of Pollution Abatement may require 

that monitor wells be drilled to a lesser depth. All new monitor wells 

shall meet the requirements as set out in rules established by the Oklahoma 

Water Resources Board, in addition to the following requirements:

(A) A removable and lockable cap shall be placed on top of the casing. 

The cap shall remain locked at all times, except when the well is being 

sampled.

(B) Within 30 days of installation, specific completion information for 

all monitor wells shall be submitted to the Manager of Pollution 

Abatement.

(15) Leachate collection system. The commercial recycling facility 

operator may elect to install a leachate collection system in lieu of 

monitor wells if such system will adequately detect any leak from the 

facility. The plan for the leachate collection system must be approved by 

the Manager of Pollution Abatement prior to installation of the leachate 

collection system. 

(16) As-built drawing. A detailed, as-built drawing of the facility and 

monitor wells or leachate collection system by or under the supervision of 

a registered professional engineer shall be submitted to the Manager of 

Pollution Abatement before operation of a facility utilizing pits with a 

capacity in excess of 50,000 barrels commences. Operators of facilities 

which do not utilize pits and facilities utilizing pit(s) with a capacity 

of 50,000 barrels or less shall submit to the Manager of Pollution 

Abatement as-built drawings prepared by a qualified expert before operation 

of such facilities commence.

(17) Liner certification. An affidavit signed by the person who was 

responsible for installing any pit liner, certifying that the liner meets 

minimum requirements and was installed in accordance with Commission rules, 

shall be submitted to the Manager of Pollution Abatement before operation 

of the facility commences. Supporting documentation shall also be 

submitted, such as geomembrane liner specifications from the manufacturer.

(18) Facility approval. Acceptance of materials by a commercial recycling 

facility shall not commence until a representative of the Conservation 

Division has inspected and approved the facility.

(19) Hydrologically sensitive areas. If the proposed site is known to be 

located over a hydrologically sensitive area, in addition to the foregoing 

construction requirements, the additional requirements shall apply:

(A) The total depth of any pit shall not exceed eight feet, and the 

total designed fluid or sediment depth shall not exceed five feet.

(B) A minimum 60-mil geomembrane liner shall be required.

(C) The Manager of Pollution Abatement shall determine the minimum 

depth of all monitor wells.

(g) Operation and maintenance requirements.

(1) Vegetative cover. Vegetative cover shall be established on all areas 

of earthfill immediately after any pit construction or during the first 

planting season if pit construction is completed out of season. The cover 

shall be sufficient to protect those areas from soil erosion and shall be 

maintained.

(2) Fencing. All commercial recycling facilities shall be completely 

enclosed by a fence at least four feet in height. No livestock shall be 

allowed inside the fence.

(3) Sign. A waterproof sign bearing the name of the commercial recycling 

facility operator, legal description, most current order number, and 

emergency phone number shall be posted within 25 feet of the entrance gate 

to any commercial recycling facility and shall be readily visible.

(4) Site security. Acceptable materials can be received by a commercial 

recycling facility only when there is an attendant on duty. All sites 

shall be secured by a locked gate when an attendant is not on duty. A key 
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 174 -

or combination to the lock shall be provided to the appropriate Field 

Inspector for the purpose of carrying out inspections.

(5) Fluid level. Deleterious substances shall not be accepted into any 

pit unless the fluid level can be maintained at an elevation no higher than 

the maximum level of the fluid level marker.

(6) Acceptable materials.

(A) An operator of a commercial recycling facility shall accept for 

recycling only those materials defined as "deleterious substances" in 

OAC 165:10-1-2 and as authorized in the order for the facility. Such 

substances must undergo at least one treatment process and must be 

recycled into a marketable product for resale and/or have some 

beneficial use. 

(B) A sample from each incoming load shall be collected, filtered (if 

necessary) and tested as required by Commission order. 

(C) The date, volume, source (generator), type of material and test 

results of each load received shall be entered into a log book.

Supporting documentation such as any chemical analyses or D.O.T. 

material safety data sheets concerning such loads shall also be 

maintained by the operator. The log book and supporting documentation 

shall be available for inspection by a representative of the 

Conservation Division of the Commission at all times. Log books and 

supporting documentation shall be kept for a minimum of five years after 

closure is completed.

(7) Storage of deleterious substances. A commercial recycling facility 

shall not store anything other than deleterious substances as defined in 

OAC 165:10-1-2 and as authorized in the order for the facility. The 

contents of each pit or cell at a facility shall be sampled and analyzed by 

the operator at least once every six months (during January and July) after 

operations commence. More frequent sampling may be required by the Manager 

of Pollution Abatement. The following procedures shall be used:

(A) The appropriate Pollution Abatement Department representative shall 

be notified at least 24 hours in advance of sampling to allow the

representative an opportunity to witness the sampling.

(B) Samples shall be collected and handled by the operator according to 

procedures established by the Manager of Pollution Abatement. 

(C) If requested by a representative of the Conservation Division, each 

composite sample shall be split and a sufficient portion (approximately 

one pint) shall be properly labeled and delivered or otherwise provided 

to the appropriate Conservation Division District Office or Field 

Inspector.

(D) All samples delivered to the laboratory shall be accompanied by a 

chain of custody form.

(E) All composite samples must be analyzed for constituents as required 

by Commission order by a laboratory certified by the Oklahoma Department 

of Environmental Quality or operated by the State of Oklahoma. Analysis 

of additional parameters may be required, as determined by the Manager 

of Pollution Abatement.

(F) A copy of each analysis shall be forwarded to the Pollution 

Abatement Department within 30 days of sampling.

(8) Oil film.

(A) No pit utilized in a commercial recycling facility shall contain an 

oil film covering more than one percent of the surface area of the pit.

(B) The protection of migratory birds shall be the responsibility of 

the operator. Therefore, the Conservation Division recommends that to 

prevent the loss of birds, oil films be removed, or the surface area of 

any pit be protected from access to birds. [See Advisory Notice in OAC 

165:10-7-3(c)].

(9) Aesthetics. All commercial recycling facilities shall be maintained 

so that there is no junk iron or cable, oil or chemical drums, paint cans, 

domestic trash, or debris on the premises.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 175 -

(10) Structural integrity. All pits utilized in commercial recycling 

facilities shall be used, operated, and maintained at all times so as to 

prevent the escape of their contents. All erosion, cracking, sloughing, 

settling, animal burrows, or other condition that threatens the structural 

stability of any earthfill shall be repaired immediately upon discovery.

(11) Monitor well and leachate collection system sampling. Sampling of 

monitor wells or leachate collection systems shall begin prior to accepting 

any deleterious substances into a new facility and within 30 days of 

completing the drilling of monitor wells or installation of leachate 

collection systems on existing facilities, and sampling shall be done at 

least once every six months (during January and July) after operations

commence until three years after closure is completed. Sampling of greater 

frequency or duration may be required by the Manager of Pollution 

Abatement. The following procedures shall be used:

(A) The appropriate Field Inspector shall be notified at least 24 hours 

in advance of sampling to allow a Commission representative an 

opportunity to witness the sampling.

(B) Samples shall be collected and handled by the operator according to 

EPA-approved standards. (RCRA Groundwater Monitoring Technical 

Enforcement Guidance Document, EPA, OSWER-9950.1, September 1986, pp. 

99-107.)

(C) If requested by a representative of the Conservation Division, a 

sufficient portion of each sample (approximately one pint) shall be 

properly labeled and delivered or otherwise provided to the appropriate 

Conservation Division District Office or Field Inspector.

(D) All samples delivered to the laboratory shall be accompanied by a 

chain of custody form.

(E) All samples must be analyzed for pH and chlorides by a laboratory 

certified by the Oklahoma Department of Environmental Quality or 

operated by the State of Oklahoma. Analysis of additional parameters 

may be required based on the operation of the facility as determined by 

the Manager of Pollution Abatement.

(F) A copy of each analysis and a statement as to the depth to 

groundwater encountered in each well or leachate collection system, or 

an affidavit that no water was encountered, shall be forwarded to the 

Pollution Abatement Department within 30 days of sampling.

(G) Monitor wells shall be plugged in accordance with Oklahoma Water 

Resources Board rules. 

(12) Prevention of pollution. All commercial recycling facilities shall 

be used, operated, and maintained at all times so as to prevent pollution. 

In the event of a nonpermitted discharge at or from a commercial recycling 

facility, sufficient measures shall be taken to stop or control the loss of 

materials, and reporting procedures in 165:10-7-5(c) shall be followed. 

Any materials lost due to such discharge shall be cleaned up as directed by 

a representative of the Conservation Division. For a willful non-permitted 

discharge, the commercial recycling facility operator may be fined up to 

$5,000.00.

(h) Semiannual report. The operator of any commercial recycling facility

shall submit a report on Form 1014A to the Manager of Pollution Abatement by 

February 1 and August 1 of each year.

(i) Closure requirements.

(1) Notification. The Manager of Pollution Abatement shall be notified in 

writing whenever a commercial recycling facility becomes inactive, is 

abandoned, or operation of the facility ceases for any reason. A 

commercial recycling facility may be considered to be inactive by the 

Commission if:

(A) The facility has been shut down by the Commission because of a 

violation which results in the filing of an application for an order to 

vacate the operator's authority.
OAC 165:10-9 Corporation Commission

Eff. 8-27-15

- 176 -

(B) The operator is unable to furnish documentation to show that there 

has been receipt of deleterious substances to be recycled at the 

facility during the previous twelve months.

(C) The authority to operate the facility has been terminated by failure 

to comply with (k) of this Section. 

(2) Time limit. Closure of all commercial recycling facilities shall be 

commenced within 60 days and completed within one year of cessation of 

operations, pursuant to (1) of this subsection. In cases where extenuating 

circumstances arise, one extension of six months may be administratively 

approved in writing by the Manager of Pollution Abatement. Closure shall 

be in accordance with an approved closure plan. A progress report shall be 

submitted to the Manager of Pollution Abatement, every three months (during 

January, April, July, and October) after cessation of operations until 

closure is completed.

(3) Restrictive covenant. The Manager of Pollution Abatement may require

a restrictive covenant to be filed with the County Clerk of the county in 

which a commercial recycling facility is located. The document shall 

accurately describe the facility location and shall specifically restrict 

the current or future landowners of the site from puncturing the final 

cover of any pit utilized in a commercial recycling facility or otherwise 

disturbing the site to the extent that pollution could occur.

(4) Penalty for failure to meet closure requirements. An operator failing 

to meet the closure requirements set out in this subsection may be fined up 

to $1,000.00.

(j) Additional requirements. The requirements set forth in this Section are 

minimum requirements. Additional requirements may be made upon a showing of 

good cause that an operator has a history of complaints for failure to comply 

with Commission rules and regulations, the site has certain limitations, or 

other conditions of risk exist.

(k) Application to existing facilities. Operators of facilities permitted or 

ordered prior to the effective date of this Section must either comply with 

subsections (a), (d)(1), (e), (f)(2), (f)(11), (f)(12), (f)(13), (f)(14), 

(f)(15), (g), (h), (i), (j) and (m) of this Section or close such facilities 

within one (1) year of the effective date of this Section. All commercial 

recycling facilities permitted, but yet to be constructed as of the effective 

date of this Section, shall also be subject to all of the construction 

requirements in subsection (f) of this Section.

(l) Variances. Except as otherwise provided in this Section, variances from 

provisions of this Section may be granted for good cause by order after 

application, notice, and hearing.

(m) Compliance history. In the event the Commission has evidence that an 

applicant for a commercial recycling facility may not possess a satisfactory 

compliance history with Commission rules, the Director of the Conservation 

Division may seek an order of the Commission, issued after application, notice, 

and hearing, determining whether the applicant should be authorized to operate 

such a facility.

[Source: Added at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 29

OK Reg 950, eff. 7-1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff. 8-27-15 

(RM 201500001)]
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 177 -

SUBCHAPTER 10. BROWNFIELDS PROGRAM 

PART 1. GENERAL PROVISIONS 

Section

165:10-10-1. Purpose 

165:10-10-2. Brownfields defined 

165:10-10-3. Administration and enforcement of rules 

165:10-10-4. Determination of Brownfields eligibility 

165:10-10-5. The Commission's application process for Brownfields sites 

165:10-10-6. Eligibility of site 

165:10-10-7. The Commission's Brownfields site list 

165:10-10-8. Processing of Brownfields application 

165:10-10-9. Assessment and remediation of site 

165:10-10-10. Notice 

165:10-10-11. Public meetings and public comments 

165:10-10-12. Closures of Brownfields 

165:10-10-13. Commission Brownfields certificates issued 

165:10-10-14. Responsible party and other sites that can receive a Commission 

"No Further Action Certificate" or "Certificate of Completion" 

(for remedial actions)

165:10-10-1. Purpose

 The purpose of this Subchapter is to provide the Oklahoma Corporation 

Commission (Commission) rules to govern the Brownfields Program (Brownfields) 

under Okla. Stat. Tit. 27A §§1-3-101(E)(1)(j), 1-3-101 (E)(2) and 1-3-101 

(E)(5); Okla. Stat. Tit. 17 §§52(A)(1)(j), 52(A)(2) and 52(A)(5) and Okla. 

Stat. Tit. 52 §§139(B)(1)(j), 139(B)(2) and 139(B)(5) as authorized and funded 

by the federal Environmental Protection Agency (EPA).

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-2. Brownfields defined

(a) A “Brownfields” is a real property (site) where expansion, redevelopment, 

normal use or reuse may be complicated by the presence or potential presence of 

a deleterious substance, pollutant, or contaminant. This includes land that is 

contaminated by petroleum, petroleum products, and related wastes, including 

crude, condensate, gasoline and diesel fuel, produced water/brine, glycol 

and/or drilling mud. A proposed Brownfields site is a defined area; it does 

not need to be the entire property or lease.

(b) Sites excluded from participation are:

(1) Sites controlled by responsible parties (RPs);

(2) Sites listed on the National Priorities List (NPL) maintained by EPA;

(3) Sites subject to order or consent decree under the Comprehensive 

Environmental Response, Compensation, and Liability Act (CERCLA), commonly 

known as Superfund;

(4) Sites permitted under certain federal programs including the Resource 

Conservation and Recovery Act (RCRA), CERCLA, the Toxic Substances Control 

Act (TSCA), or the Safe Drinking Water Act (SDWA);

(5) Lands where closure of the remediation process has been approved by or 

where a closure plan concerning remediation has already been submitted to 

the Commission;

(6) Sites owned or under the control of the federal government; 

(7) Portions of sites with PCB (polychlorinated biphenyls) pollution 

subject to remediation under TSCA;

(8) Portions of facilities with an approved or ongoing federal Leaking 

Underground Storage Tank (LUST) Fund remediation; however the Oklahoma LUST 

fund and the Oklahoma Petroleum Storage Tank (PST) Indemnity fund are 
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 178 -

potentially available for assessing and cleaning up newly listed PST 

Brownfields sites in Oklahoma.

(c) All Brownfields assessment and remediation projects will be overseen by a 

qualified environmental professional, defined by EPA as someone who possesses 

sufficient specific education, training, and experience necessary to exercise 

professional judgment to develop opinions and conclusions regarding conditions 

indicative of releases or threatened releases of deleterious substances on, at, 

in, or to a property, sufficient to meet the objectives and performance factors 

of the EPA’s All Appropriate Inquiries rule (40 CFR Part 312) and ASTM E1527-

05. Qualified environmental professionals must have one of the following:

(1) A state or tribal issued certification or license (including 

Professional Engineer, Professional Geologist, and PST Division of the 

Corporation Commission licensed Remediation Consultant) and three years of 

relevant full-time work experience; or

(2) A Baccalaureate or higher degree in science or engineering, including 

geologists as defined in 25 O.S. § 35 and engineers as defined in 59 O.S. § 

475.1 et seq., and five years of relevant full-time work experience; or

(3) Ten years of relevant full-time work experience.

(4) Individuals who do not meet the above requirements must work under the 

supervision or responsible charge of an individual who meets the 

requirements for an environmental professional.

(d) Responsible party (RP) and other ineligible parties defined. A person, 

corporation, company, non-profit organization, or any other entity that:

(1) Caused the pollution at the proposed Brownfields site or knew about the 

pollution and allowed it to occur; or

(2) Contributed to already existing pollution at the site; or

(3) Hindered or otherwise knowingly attempted to obstruct efforts to 

perform environmental assessments of or to remediate pollution caused by an 

RP at the site; or

(4) Is not in compliance with a final agency order or any final order or 

judgment of a court of record secured by any state or federal agency for any 

of the responsible party’s actions at the site which could have led to a 

leak, spill, and/or other cause of the pollution in violation of agency 

rules, or

(5) Has demonstrated a pattern of uncorrected noncompliance with state or 

federal environmental laws or rules; or 

(6) Has past operations at the site and/or at other sites that indicate a 

reckless disregard for the protection of human health and safety or the 

environment. 

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-3. Administration and enforcement of rules

(a) The Manager of Pollution Abatement and the Brownfields program staff shall 

supervise and coordinate the administration and enforcement of the rules of 

this Subchapter under the direction of the Director of Oil and Gas Conservation 

and the Commission.

(b) The primary goal of the implementation of Brownfields site assessments and 

remediation projects shall be the protection and/or restoration of the 

beneficial use of the land, the soil and any surface or subsurface waters of 

the State adversely impacted or impaired by pollution from a Commission 

regulated Brownfields site.

(c) Site assessments and remediation projects conducted under the supervision 

and coordination of the Manager of Pollution Abatement and/or Pollution 

Abatement/UIC/Brownfields staff shall adhere to the general practices appearing 

in the Oil and Gas Conservation Division’s Guardian Guidance document for 

petroleum and produced water site assessment and remediation oversight, 

enforcement, approval and verification including the Guidelines and Numerical 

Criteria for New or Historic Produced Water/Brine Spills. 

(d) Applicant may request in writing, and the Manager of Pollution Abatement 
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 179 -

and/or the Brownfields Program manager may grant, an administrative exception 

to a Commission Brownfields rule if applicant can demonstrate that: 

(1) Requirements in pertinent state laws and federal Brownfields rules and 

laws are still met, and 

(2) The exception will cause human health, safety and the environment and 

the beneficial use of the land to be protected at least as well as strict 

adherence to the Commission Brownfields rule would have.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-4. Determination of Brownfields eligibility 

(a) The Commission’s Brownfields staff will determine the initial eligibility 

for any allegedly contaminated portion of a Brownfields project. Brownfields 

staff will determine to the extent possible:

(b) If the site is a relatively low risk site, compared to all types of 

pollution sites;

(c) If any funds have already been spent on the site, and the source of any 

such funds;

(d) If there are any viable responsible parties. Commission records will be 

checked by Commission staff for all Brownfields sites; and

(e) Whether the current or immediate past owner and/or operator of the site 

caused or made the pollution worse and whether such parties took reasonable 

corrective steps with regard to any pollution. 

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-5. The Commission’s application process for Brownfields sites

(a) Pre-application. The applicant may want to consider a pre-application 

conference by telephone, e-mail, mail, or in person with Brownfields staff. 

During the pre-application conference the applicant will be advised about what 

information is necessary in order for Brownfields staff to determine whether 

the applicant and the applicant’s site are eligible for the Brownfields 

program.

(b) Applicant eligibility. An applicant may be any non-responsible party 

(non-RP) including:

(1) The legal owner in fee simple, the tenant or lessee of the property, or 

a person who has a written firm option to purchase or operate the property 

at the time the application is filed and who has the ability to implement a 

redevelopment proposal, if needed, once site assessment and/or remediation 

is complete;

(2) Any person who acquired the ownership, operation, management, or 

control of the site through foreclosure or under the terms of a bona fide 

security interest in a mortgage or lien on, or an extension of credit for 

the property, or foreclosed on the property, or received an assignment or 

deed instead of foreclosure or some other indicia of ownership and thereby 

becomes the owner of the property;

(3) An agency, non-profit organization or other entity who chooses to clean 

up or otherwise rehabilitate a property for the owner or tenant in order for 

it to be returned to productive use or become green space; 

(4) The Oklahoma Energy Resources Board (OERB), regarding sites in its 

surface restoration program which meet the definition of a Brownfields 

property appearing in OAC 165:10-10-2. There is no requirement that OERB 

sites be designated as Brownfields sites, or 

(5) A non-RP who wishes to restore property for a potential or known RP. If 

an entity that is not the RP wants to apply to the Brownfields program and 

is accepted and completes the process, such a site would be granted limited 

liability protection;

(c) When a non-RP wants to apply to remediate a property under the Brownfields 

program, the applicant must certify by affidavit that it owns the property or 

has a current lease or easement which is given to accomplish the remediation, 
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 180 -

or if it does not, has provided legal notice to the property owner of 

applicant’s desire to remediate the site.

(d) If an application is denied by Brownfields staff, staff will promptly 

provide applicant with a written statement of the reasons for such denial. 

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-6. Eligibility of site

(a) Any facility or real property where normal use, reuse, expansion or 

redevelopment is hindered by pollution or suspected pollution of a substance or 

substances caused by releases from activities regulated by the Commission may 

qualify as a Brownfields site. 

(b) The applicant will need to provide an Applicant Eligibility form with the 

following information included on the form:

(1) A physical address for the land or property;

(2) A legal description of the land or property; 

(3) Driving directions from nearest major intersection.

(c) A site survey by a surveyor, or a site plan containing global positioning 

system (GPS) coordinates made under the supervision of a qualified 

environmental professional defining the area to be addressed must be submitted

for each Brownfields site once it is accepted into the program.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-7. The Commission’s Brownfields site list

(a) The Commission is required by federal statutes to maintain a current list 

of every site which has qualified as a Brownfields site, including those sites 

on which work has been completed. The list shall be made available to the 

public on the Commission’s website. 

(b) Each site on the Brownfields sites list will include:

(1) Site name;

(2) Address or legal description of the site;

(3) Town, city, and county of the site;

(4) Site level of progress;

(5) Allowable use of revitalized land; and 

(6) County name, address and telephone number of the county clerk’s office 

where the certificate(s) referred to in OAC 165:10-10-13 is or will be 

filed.

(c) Brownfields staff will be responsible for maintaining and updating the 

public record of sites that have qualified for the Commission’s Brownfields 

Program.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-8. Processing of Brownfields application

(a) All applicants and properties must meet federal and state Brownfields 

eligibility requirements. Commission standards and practices in effect at the 

time the application is filed will also be considered in determining whether 

eligibility requirements have been satisfied. 

(b) General process for applying. Applicants for the Brownfields program, 

except for sites submitted by Commission field inspectors, will be required to 

submit an Application for Brownfields Program Eligibility form and an 

Application for Brownfields Site Assessment (see OAC 165:10-10-15 Brownfields 

Forms) and any required documentation to show they are eligible.

(c) The OERB Voluntary Environmental Program has sole discretion in 

determining whether it is to apply to the Commission's Brownfields program 

regarding abandoned exploration and production (E & P) sites which have been 

submitted to the OERB for consideration under its program which is limited to 

surface restoration. The site must meet the definition of a Brownfields 

property as defined in OAC 165:10-10-2.
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 181 -

(d) Applicant must notify the Brownfields staff in writing of any litigation 

the Applicant has knowledge of concerning the site which has concluded or is 

pending, and any information concerning outstanding judgments, liens, tax 

levies, etc. filed of record at the time the application is filed or which is 

filed after applicant submits its application to the Commission and prior to 

final Commission action regarding the site. 

(e) Completed applications must be sent to the following address: Oklahoma 

Corporation Commission, Oil and Gas Conservation Division, Brownfields Program, 

P.O. Box 52000, Oklahoma City, OK 73152-2000.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-9. Assessment and remediation of site 

(a) Assessments

(1) The appropriate Commission staff may conduct initial site inspections 

to evaluate and recommend those sites that qualify for the Brownfields 

program; Brownfields staff will approve inspections and assessments and list 

each approved site in the database. 

(2) Qualified environmental professionals will perform an assessment (Phase 

I and/or Phase II) of each property. 

(3) Governmental entities, quasi-governmental entities, and non-profit 

organizations may be eligible for a Targeted Brownfields Assessment (TBA) 

conducted by either the Commission or EPA. 

(4) OERB’s qualified staff or contractor may perform assessments on 

abandoned exploration and production (E&P) sites. 

(5) Assessments of former retail petroleum storage tank sites will be 

overseen by and coordinated with the Commission’s PST Division staff. 

(6) EPA’s All Appropriate Inquiry (AAI) Rule appearing in 40 CFR Part 312 

shall be complied with as per the Commission’s guidance.

(7) If during an initial investigation or Phase I or Phase II assessment 

pollution is discovered and immediately removed from the site, as confirmed 

with sample analytical results, the site may qualify for No Further Action 

(NFA) status. 

(b) Phase I. Basic site and assessment information is necessary for 

exploration, production, and/or pipeline sites known or suspected to be 

contaminated by substances defined in OAC 165:10-10-2(a), and for PST sites. 

Initial site assessment information includes, but is not limited to:

(1) Analyses from one or more soil and water background samples;

(2) A certified survey or the results of a GPS survey defining the area of 

pollution,

(3) The present and proposed uses of the site; 

(4) The operational history of the site and current use of areas contiguous 

to the site; and 

(5) Detailed historical and records reviews as per AAI, which may be waived 

by Brownfields staff until after the basic physical environmental/pollution 

assessment is completed and Commission staff concludes its review of sample 

data pertaining to the site.

(6) A Category Index Table must be submitted for all oil and gas and 

pipeline sites likely or definitely polluted above action levels. The 

Category Index Table appears in the Commission’s Guardian Guidance document, 

which is available on the Commission’s website or by request.

(7) Sites that are determined by the Brownfields staff to need no 

remediation following an acceptable Phase I assessment can be issued NFA 

certification once the Brownfields staff receives appropriate documentation.

(c) Phase II. Phase II sites are those sites where the Phase I assessment 

demonstrates the need for additional assessment, action level determination, 

and (often) remediation guidance.

(1) Phase II oil and gas sites and pipeline (crude and refined product and 

produced water) sites will be overseen by the Oil and Gas Conservation 

Division’s Brownfields staff;
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 182 -

(2) Phase II retail petroleum storage tank sites will be referred to the 

Commission’s PST Division and will adhere to the Oklahoma Risk-Based 

Corrective Action guidelines for assessment and remediation;

(3) Necessary information generally includes but is not limited to 

concentrations of pollutants in the soils, surface water or groundwater at 

the site; the vertical and horizontal extent of pollution in the soils, 

surface water or groundwater at the site; a determination that risk based 

criteria to protect human health and the environment at and around the site 

are or are not being met; and recommendations on how to meet risk based 

criteria, including remediation as needed;

(4) Sites that are determined by the Brownfields staff to need no 

remediation following appropriate environmental and risk assessment can be 

issued NFA certificates once the Brownfields staff receives appropriate 

documentation. 

(d) Status of site when NFA is required.

(1) A no further action determination is appropriate for a site if at the 

conclusion of the initial inspection, TBA, Phase I or Phase II 

investigation, or subsequent to the immediate removal of pollution from a 

site, the Brownfields staff or other appropriate Commission staff finds or 

concurs that the site poses no significant risk to human health or safety or 

the environment according to the proposed use of the site. 

(2) Brownfields staff will issue a NFA certificate when the site is 

restored for beneficial use and other required program elements, if any, are 

completed.

(e) When pollution is likely present or is present above action levels. If 

pollution is likely present or is present above action levels at a site, 

further assessment and remediation will adhere to one of the following 

regimens:

(1) The Oil and Gas Conservation Division’s Guardian Guidance document and 

rules for petroleum and produced water site assessment and remediation 

oversight, enforcement, approval and verification; or

(2) The PST Division’s guidance document and rules for site assessment and 

cleanup oversight, enforcement, approvals and verification; or

(3) For E&P sites where there is no RP, the OERB Voluntary Environmental 

Program may, in its sole discretion, submit to the Commission's Brownfields 

program those abandoned E & P sites which have qualified for the OERB's 

program, which is limited to surface restoration in order that such sites 

may be assessed and remediated by OERB in accordance with the Commission's 

Brownfields rules; and

(4) The Commission’s Brownfields staff will act as the regulator for the 

Brownfields program and ensure that applicable Brownfields laws and rules 

are followed.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-10. Notice

(a) Public notice. Public notice is necessary for remediation sites (Phase II 

sites requiring remediation or cleanup). The applicant must provide public 

notice that its proposal regarding the site is ready for public review. The 

notice must be published one time in newspapers of general circulation 

published in Oklahoma and Tulsa counties, Oklahoma, and in a newspaper of 

general circulation published in each county where the lands that are the 

subject of the application are located. The applicant shall also submit the 

notice to the Brownfields staff for posting on the Commission’s website. The 

notice must contain the:

(1) Name and address of the location where the application and related 

documentation, including any proposed remediation plan, may be reviewed, in 

addition to the days of the week and hours during which such information may 

be reviewed;

(2) Applicant’s name, mailing address, telephone number, email address and 
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 183 -

contact person, as well as the Commission’s mailing address and a telephone 

number and email address of a contact person at the Commission;

(3) Name, address and legal description of the Brownfields site, and a copy 

of the survey or site plan;

(4) Purpose of the notice;

(5) Description of the proposed cleanup, monitored natural attenuation, 

institutional control, and/or other remedial action being sought; 

(6) Other pertinent information required by Brownfield’s staff and rules;

(7) Other information the applicant may deem relevant; and

(8) Time period of at least thirty (30) days after the notice is published 

for the submission of written public comments and written requests for a 

public meeting regarding the site, in addition to the mailing address and email address to which public comments and requests for public meetings can 

be sent, the name of a contact person and any facsimile numbers, if 

available. The notice must also provide that any written public comments 

and requests for a public meeting are to be sent to the Oklahoma Corporation 

Commission, Oil and Gas Conservation Division, Brownfields Program, P.O. Box 

52000, Oklahoma City, Oklahoma, 73152-2000. 

(b) Public meeting.

(1) If the Commission receives a timely written request for a public 

meeting, if the Commission determines there is a significant degree of 

public interest in the site remediation proposal and the action being 

sought, or if the applicant chooses to have a public meeting, then the 

applicant must publish notice of the date, time and address of a public 

meeting at least thirty (30) days prior to the meeting in the manner 

described in paragraph (a), above, and include in the notice the information 

appearing in paragraphs (a)(1) through (a) (8), above. 

(2) The notice must provide for a time period of at least thirty (30) days

after the notice is published for the submission of written public comments, 

and that verbal comments may be made at the meeting. The mailing address 

and e-mail address to which public comments can be sent, the name of a 

contact person and any facsimile numbers, if available, must also be 

included in the notice. The notice must also provide that any written 

public comments are to be sent to the Oklahoma Corporation Commission, Oil 

and Gas Conservation Division, Brownfields Program, P.O. Box 52000, Oklahoma 

City, Oklahoma, 73152-2000.

(3) The public meeting will be held in a convenient location near the 

proposed Brownfields site;

(c) Publisher’s affidavits. The applicant is required to provide to the 

Brownfields staff the publisher’s affidavits regarding the public notice for 

comments and/or a public meeting within twenty (20) days after the date(s) of 

publication;

(d) When public notice is not required. Applicant is not required to publish 

a notice regarding those sites Brownfields staff or other appropriate 

Commission staff find or concurs need no action after staff’s review of 

applicant’s site assessment information. 

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-11. Public meetings and public comments 

(a) The format for each public meeting will be established by the Commission’s 

Brownfields staff or its Public Information Staff, and the Commission’s 

Brownfields staff or its Public Information Staff will moderate each public 

meeting;

(b) The moderator may set reasonable time limits for speakers, and the 

moderator may extend the time for public comment at the conclusion of the 

public meeting; 

(c) Anyone may provide public comments or submit a written statement and data 

regarding the remediation proposal at any public meeting; 

(d) The applicant or its representative must be available at each public 
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 184 -

meeting in order to answer questions;

(e) If the Commission receives no request for a public meeting, and the 

Commission deems no public meeting necessary, and no public comments are 

received, then the Commission will proceed with the applicable determination; 

(f) If the Commission receives public comments, the appropriate Brownfields 

staff will prepare a written response to such comments within ninety (90) days 

after the close of the comment period.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-12. Closures of Brownfields

(a) Final surface remediation confirmation.

(1) A qualified environmental professional for the applicant and/or the 

Brownfields, other Oil & Gas, or PST staff of the Commission, or the OERB, 

if such entity is involved with the site, will perform a closure survey, 

which may include but is not limited to visual observations and sampling the 

soil, surface water and/or groundwater at the site to confirm the project is 

completed and the property is ready for its proposed use; 

(2) The results of the closure survey, including any soil, surface water 

and/or groundwater sample results, must be submitted to appropriate 

Commission and Brownfields staff, and the appropriate regulatory program 

will confirm if cleanup standards have been met.

(b) Final documentation.

(1) The applicant is required to submit all necessary documentation 

regarding the site to Brownfields staff.

(2) The Brownfields staff will review, as required by applicable laws and 

rules, the work performed on the site as reflected in the documentation 

filed by Applicant.

(3) The applicant shall submit to Brownfields staff recorded copies of 

documents confirming that any deed restrictions or other institutional 

controls have been filed with the appropriate authorities.

(c) Request for closure. The applicant shall request closure of the site 

after all reviews have been completed by applicable Commission staff members 

and the site is found by Commission staff to be in compliance with all the 

Brownfields and regulatory laws and rules.

(d) Records of sites. The Brownfields staff will maintain a public record of 

each site that has qualified for the Brownfields program for a period of 

three (3) years. After the three (3) year period has expired the records will 

be archived.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-13. Commission Brownfields certificates issued

(a) A “No Action Necessary” or a “No Further Action” Certificate shall be 

issued to applicant by the Commission when the Commission has made such 

determination.

(b) A “Certificate of Completion” will be issued by the Commission for 

remediated sites after the closure survey of the site and review of the project 

has been approved by the Commission.

(c) The Certificates will state whether or not any continuing care of 

structural institutional controls, or any long term monitoring of the site, is 

to occur after issuance of any Certificate.

(d) All Brownfields Certificates issued by the Commission must be filed by the 

applicant in the office of the county clerk in the county where the Brownfields 

site is located. The Applicant is required to provide a copy of the 

certificate reflecting that it has been recorded with the county clerk’s office 

both to the landowner of the subject site and to the Brownfields staff within 

thirty (30) days after the certificate has been filed.

(e) Applicant’s submission of any false or materially misleading information 

to the Commission in conjunction with its application shall render voidable any 
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 185 -

of the Certificates discussed above. 

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-10-14. Responsible party and other sites that can receive a Commission 

“No Further Action Certificate” or “Certificate of Completion” (for remedial 

actions)

 An RP that is legally responsible for the remediation of the pollution at a 

site and is therefore not eligible for the Commission’s Brownfields Program, 

can:

(1) Request that a standard case closed letter be sent to the RP by the 

Commission’s Field Operations or Pollution Abatement (PA) Departments 

reflecting that the necessary work at the site has been completed and that 

the case has been closed by such Department, or

(2) Request that the Commission PA Department issue a Brownfields 

equivalent of a “No Further Action” Certificate” or a “Certificate of 

Completion” at the conclusion of an equivalent state funded program 

involving the site.

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]
OAC 165:10-10 Corporation Commission

Eff. 8-27-15

- 186 -

[BLANK PAGE]
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 187 -

SUBCHAPTER 11. PLUGGING AND ABANDONMENT

Section

165:10-11-1. License for pulling pipe and plugging wells

165:10-11-2. Operating requirements for licensees

165:10-11-3. Duty to plug and abandon

165:10-11-4. Notification and witnessing of plugging 

165:10-11-5. Supervision and witnessing [REVOKED]

165:10-11-6. Plugging and plugging back procedures 

165:10-11-7. Plugging record 

165:10-11-8. Procedures for identification and control of wellbores in which

 radioactive sources have been abandoned 

165:10-11-9. Temporary exemption from plugging requirements

165:10-11-1. License for pulling pipe and plugging wells

(a) No person shall contract to pull casing or plug oil, gas, injection, 

disposal, or other service wells, or contract to salvage casing therefrom, or 

purchase wells for the purpose of salvaging casing therefrom until a license has 

been secured from the Commission.

(1) The application for such license shall state:

(A) The name of the applicant.

(B) The names and addresses of all partners, chief officers, and 

directors.

(C) The experience of applicant.

(D) Evidence of financial responsibility of the applicant.

(E) The counties in which the applicant will operate.

(2) Notice that an application has been filed shall be published by the 

applicant in a newspaper of general circulation in Oklahoma County and in the 

county where the applicant's principal place of business is located. The 

applicant shall file proof of publication prior to the hearing or 

administrative approval. The notice shall include:

(A) The name of the applicant.

(B) Generally what operations the applicant intends to conduct for which 

applicant is financially responsible.

(C) The counties in which applicant will operate.

(3) If a written objection to the application is filed within 15 days after 

the application is published or if a hearing is required by the Commission, 

the application shall be set for hearing and notice thereof shall be given as 

the Commission shall direct. If no objection is filed and the Commission 

does not require a hearing, the matter shall be presented administratively to 

the Manager of Field Operations who shall file a report and make 

recommendations to the Commission.

(b) The license shall not be transferable and may at any time be revoked by the 

Commission upon complaint, notice, and hearing. 

(c) Any person violating this Section may be fined up to $2,500.00. Any 

operation in violation of this Section shall be shut down pending compliance 

with this Section.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended in Rule Making 

97000002, eff 7-1-97]

165:10-11-2. Operating requirements for licensees

(a) This Section shall apply to each licensee under 165:10-11-1.

(b) If a licensee prepares the Notice of Intent to Plug (Form 1001 and/or the 

Plugging Report (Form 1003), then the licensee shall:

(1) Include the following on any submitted form:
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 188 -

(A) The name and address of the well operator if the licensee is serving 

as a contractor for the operator of the well.

(B) The name and address of the person or entity hiring the licensee if 

the licensee is serving as the contractor for any person who is not an 

operator of the well.

(C) That he is acting independently if the licensee either purchased the 

well for salvage or contracted with the landowner to plug the well in 

exchange for casing and/or other well equipment.

(2) Mail a copy of Form 1001 to the last known operator of the well to be 

plugged, as shown by the records of the Conservation Division.

(c) For purposes of this subsection, the term "plugged well" shall refer to a 

well for which the Conservation Division has a plugging record. A licensee 

shall comply with the requirements of 165:10-1-10 and 165:10-3-1 before entering 

a plugged well if:

(1) The licensee is not hired by the operator of the well to conduct the reentry operation.

(2) The owner of the well is either the licensee or the surface owner of the 

tract on which the well was drilled.

(3) The Commission has not contracted with the licensee to replug the well.

(d) A licensee shall be responsible for the plugging of a well if:

(1) The licensee is the owner of the well or the licensee is the operator of 

the well.

(2) The licensee enters a well without having contracted with the operator 

or with a party other than the operator who has authority to authorize the 

licensee to enter the well on behalf of such party.

(e) Any violation of this Section will subject licensee to a fine, to 

suspension or revocation of licensee's license issued pursuant to 165:10-11-1, 

and to proceedings as authorized by statute in the district court.

[SOURCE: Amended in Rule Making 97000002, eff 7-1-97]

165:10-11-3. Duty to plug and abandon

(a) Scope. This Section applies to:

(1) Liability of the well owners and operator or other responsible person(s) 

to plug a well.

(2) Time periods for plugging wells:

(A) Without casing.

(B) With only surface casing and cement.

(C) With production casing.

(3) Wells exempted from plugging.

(4) Notice of Temporary Exemption from Plugging granting permission to 

postpone plugging of a well.

(b) Liability of owners and operators or other responsible persons(s). Any 

working interest owner and operator of any oil, gas, disposal, injection, or 

other service well or any seismic, core, or other exploratory hole, whether 

cased or uncased, shall be jointly and severally liable and responsible for the 

plugging thereof in accordance with this Subchapter unless other responsible 

person(s) become liable for such plugging. "Other responsible person(s)" means 

person(s) exercising dominion and control over any oil, gas, disposal, 

injection, or other service well or any seismic, core, or other exploratory 

hole, whether cased or uncased, without the authority or permission of the 

working interest owners or operator thereof. In such instances the other 

responsible person(s) shall be jointly and severally liable with the owners and 

operator for the plugging of the well. The owner of the surface estate shall 

not be considered an "other responsible person" solely as a result of:

(1) the reversion of the ownership of an abandoned wellbore and associated 

equipment to the surface owner, as a matter of law, unless the surface owner

engages in activities that potentially compromise the integrity of the 

wellbore; or
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 189 -

(2) the removal of abandoned surface equipment, trash and debris from the 

surface estate, or remediation activities regarding the surface estate.

(c) Time period for plugging well without casing. Each well in which neither 

production casing nor surface casing has been run shall be properly plugged 

within 72 hours after drilling or testing is completed. However, should the 

lack of production and surface casing create a fire hazard or a risk of 

contaminating the environment or formations containing oil, gas, or known 

treatable water, said well shall be properly plugged within 24 hours after 

drilling and testing is completed. The well marker requirement described in 

165:10-3-4 (e) shall be followed.

(d) Time period for plugging well with only surface casing and cement. Each 

well in which only surface casing has been run and cemented in conformance with 

165:10-3-4 shall be properly plugged within 90 days after drilling or testing is 

completed unless the lack of production or intermediate casing creates a fire 

hazard or risk of contaminating the environment or formations containing oil, 

gas, or known treatable water, in which case or cases the well shall be plugged 

within 24 hours.

(e) Time period for plugging well with production casing. Unless exempted 

under provisions contained elsewhere in this Section, any well which has 

production casing in place shall be plugged within one year after the latter of:

(1) Cessation of drilling if the well was not completed or tested; or

(2) Cessation of the latter of completion or testing if the well has not 

produced; or

(3) Cessation of production.

(4) From April 1, 1998, to March 31, 1999, the time period for plugging of 

any producing well with production casing in place that has ceased production 

shall be two years. The Commission shall review the need for the continued 

effectiveness of this provision during the time period set forth above on a 

quarterly basis. This provision shall not apply to any well that poses a 

public health, safety or pollution threat to the environment and surface or 

subsurface waters of the state.

(f) Operators failing to commence timely plugging operations. An operator who 

fails to commence plugging operations as required in (c), (d), and (e) of this 

Section after due notice from the District Office or the appropriate field 

inspector may be fined up to $1,000.00.

(g) Wells exempted from plugging. The following wells which have production 

casing in place shall be exempt from (e) of this Section:

(1) Shut-in gas wells, for the purpose of this Section, shall be considered 

producing wells in operation.

(2) Any well for which a written order of the Commission granting a specific 

exception to plugging is in full force and effect.

(3) Supply wells or wells authorized by order of the Commission for 

injection or disposal purposes and are in compliance with the rules of the 

Commission.

(4) Any well for which a temporary exemption from the plugging rules has

been approved.

[SOURCE: Amended at 9 Ok Reg 2295; Amended at 9 Ok Reg 2337, eff 6-25-92; 

Amended in Rule Making 97000002, eff 7-1-97; Amended in Rule Making 980000035, 

eff 7-1-99; Amended at 29 OK Reg 950, eff 7-1-12 (RM 201200005)]

165:10-11-4. Notification and witnessing of plugging

(a) Wells without production casing. The appropriate Conservation Division 

District Office shall be notified at least 12 hours prior to commencement of 

plugging operations and a plugging procedure agreed upon for any well without 

production casing. Each plugging operation may be witnessed by an authorized 

representative of the Conservation Division.

(b) Wells with production casing. A separate Notification of Intention to Plug 

(Form 1001) for each well with production casing shall be filed, in duplicate, 

with the appropriate Conservation Division District Office at least five days 
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 190 -

prior to the commencement of plugging operations. The five day notice 

requirement may be reduced or waived:

(1) If a qualified representative of the Conservation Division is available 

to witness the plugging operation.

(2) At the discretion of the District Manager of the District in which the 

well is located or his supervisor.

(c) Expiration.

(1) Ninety-day period. The Notification of Intention to Plug (Form 1001) 

shall expire ninety days after it is filed with the appropriate Conservation 

Division District Office, unless plugging operations are commenced and 

thereafter continued with due diligence to completion.

(2) Thirty-day extension. A thirty day extension of the Notification of 

Intention to Plug may be granted providing the Conservation Division staff 

determines that no material change of condition has occurred, if written 

request for the extension is received prior to the expiration date of the 

original Notification of Intention to Plug. Only one extension may be 

granted.

(d) Penalty. An operator or licensed plugger plugging a well without notifying 

and agreeing on a plugging procedure with the District Office may be fined up to 

$1,000.00 and may be required by the appropriate District Manager to reenter and 

replug the well.

[Source: Amended at 11 Ok Reg 3691, eff 7-11-94; Amended in Rule Making 

97000002, eff 7-1-97; Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 201300001)]

165:10-11-5. Supervision and witnessing [REVOKED]

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Revoked in Rule Making 

97000002, eff 7-1-97]

165:10-11-6. Plugging and plugging back procedures 

(a) Scope. This Section establishes minimum standards for plugging and 

plugging back wells. The standards apply to:

(1) Wells drilled for the production of oil or gas.

(2) Wells drilled or used for disposal or enhanced recovery injection.

(3) Wells used in subsurface gas storage units.

(4) Monitoring wells in enhanced recovery projects or subsurface gas storage 

units.

(5) Wells plugged back for:

(A) Oil or gas production.

(B) Disposal or injection.

(C) Conversion to a water well.

(6) "Rat hole" or "mouse holes" used in rotary drilling of wells.

(7) Wells used for geophysical or geological exploration. 

(8) Wells used for other service operations.

(b) Alternate plugging materials and procedures

(1) The Manager of Field Operations, or other designated Conservation 

Division staff member, may approve the use of an alternate material other 

than cement or in combination with cement for wells listed in subsection (a), 

provided alternate plugging materials shall not be used to plug or plug back 

wells listed in subsection (a)(2), wells drilled or used for disposal or 

enhanced recovery injection, subsection (a)(3), wells used in subsurface gas 

storage units, subsection (a)(5)(B), wells plugged back for disposal or 

injection, and underground injection wells authorized under the Oklahoma 

Brine Development Act, 17 O.S. Section 500 et seq.

(2) The Director of Oil and Gas Conservation, in consultation with the 

Conservation Division’s Field Operations staff and the public, shall develop 

specific plugging criteria for any type of alternate plugging material 

authorized for use instead of cement or in combination with cement. The 

plugging criteria for approved alternate material shall be available to the 
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 191 -

public for review and copying at the Conservation Division’s offices and on 

the Commission’s Internet website.

(3) A District Manager may approve alternate plugging procedures for the use 

of alternate plugging materials.

(4) A detailed description of the alternate plugging operation shall be 

included with the Plugging Report (Form 1003).

(5) The District Manager shall note his approval of the alternate plugging 

procedure on the well’s Plugging Report (Form 1003).

(6) Any alternate plugging material or procedure shall conform to the 

minimum plugging standards relating to formations or depths set forth in the 

Sections below. Provided, based upon the type of alternate plugging material 

being utilized, the District Manager approving the alternate procedure may 

authorize variances to the plugging standards delineated in this Section 

otherwise applicable to the use of cement, where such variances are necessary 

to ensure an effective well plugging. 

(c) Application and cross references:

(1) Subsection (n) of this Section provides for administrative approval of 

alternative plugging procedures if downhole problems in a wellbore prevent an 

operator from complying with the minimum standards established by this 

Section.

(2) Subsection (o) of this Section applies to plugging of "rat holes" and 

"mouse holes" used at the surface during rotary drilling.

(3) OAC 165:10-11-8 establishes additional procedures for identification and 

control of wellbores in which certain logging tools have been abandoned.

(4) OAC 165:10-7-31 establishes the minimum standards for plugging wellbores 

used in seismic exploration.

(5) Subsections (d) through (p) of this Section establish plugging and plug 

back standards for all other wellbores subject to this Section.

(d) Formations to be plugged. 

(1) Except as provided in (2) of this subsection, for cased formations, if 

the operator plugs or plugs back a well, the operator shall plug any 

formation or formations in communication with a formation that:

(A) Bears H2S;

(B) Bears oil or gas;

(C) Bears treatable water;

(D) Was used in the wellbore for injection as part of a saltwater 

disposal well or enhanced recovery injection well; or

(E) Is open in the wellbore below either the shoe of the casing or the 

base of the liner to be left in the well after plugging.

(2) Paragraph (1) of this subsection shall not apply to any formation behind 

the pipe left in the hole, unless a formation endangers a treatable water 

formation or any oil and gas bearing formation.

(e) Mud requirements. Before or after running a plug, the operator shall 

remove or displace all oil and saltwater in the wellbore, and the operator shall 

fill the wellbore and/or casing with drilling (plug) mud. The minimum mud 

weight shall be nine pounds per gallon. The minimum viscosity for the drilling 

mud shall be 36 (API Full Funnel Method). If the operator removes casing from 

the wellbore, the operator shall keep the wellbore filled with drilling mud 

meeting or exceeding the weight and viscosity requirements of this subsection.

(f) Approved cementing methods.

(1) Cement plugs.

(A) To plug or plug back a well, either the tubing and pump method or the 

pump and plug method shall be used and a continuous flow of cement shall 

be pumped for each stage.

(B) Surface pumping and shut in pressures shall be of sufficient pressure 

to:

(i) Squeeze off perforations in the casing.

(ii) Prevent the plug from floating upward in the wellbore.
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 192 -

(2) Bridge plugs. The operator may run by the bailer method cement required 

in the casing above a bridge plug as provided by (g) of this Section. 

(g) Use of bridge plugs.

(1) Permitted use. Except as provided in (2) of this subsection for top 

plugs, a bridge plug may be used to permanently plug off a formation if:

(A) The only openings from the formation into the wellbore are 

perforations in the casing.

(B) The annulus between the casing and the formation is filled with 

cement from a depth 50 feet below the base of the formation to a depth 50 

feet above the top of the formation.

(C) The bridge plug is set above the top of the perforations in the 

cemented interval described in (B) of this paragraph.

(D) Sufficient cement is placed on top of the bridge plug to fill the 

casing from the top of the bridge plug to a depth ten feet above the top 

of the bridge plug.

(2) Prohibited use for top plug. A bridge plug may not be used for a top 

plug described in (j) of this Section.

(h) Cement plug for uncased hole below the casing or liner. If any production 

casing or liner is to be left in the wellbore, then any uncased hole below the 

casing or liner shall:

(1) Be filled with cement:

(A) From a depth which is the lesser of total depth of the well or 50 

feet below the lower of shoe of the casing or base of the liner.

(B) To a depth of 50 feet above the lower of the casing shoe or the base 

of the liner; or

(2) Have a cast iron bridge plug set above the top of the liner with cement.

(i) Intermediate cement plugs. If a bridge plug and cement are not used, a 

cement plug shall be run over any other formation required to be plugged off by 

this Section. To plug off a formation, the wellbore shall be filled with cement 

from a depth at least 50 feet below the base of the formation to a depth at 

least 50 feet above the top of the formation.

(j) Cement top plug.

(1) No treatable water exists. If no treatable water exists, the wellbore 

shall be filled with cement from a depth of at least 30 feet to a depth of 

three feet from the surface.

(2) Treatable water exists. Except as provided in (p) of this Section for 

converting a well to a water well, the wellbore shall be filled with cement 

as follows:

(A) If there is no surface casing or the base of the surface casing is 25 

feet or further above the base of the treatable water, the wellbore shall 

be filled with cement from a depth of at least 50 feet below the base of 

the treatable water to a depth the lesser of:

(i) Fifty feet above the base of treatable water; or

(ii) Three feet below surface.

(B) If the surface casing is set at or below the base of the treatable 

water, the wellbore shall be filled with cement from a depth of at least 

50 feet below the base of the surface casing to a depth the lesser of:

(i) Fifty feet above the base of the surface casing; or

(ii) Three feet below surface.

(C) If the cement plug prescribed by (2) of this subsection is not 

sufficient to bring the level of cement to within three feet from the 

surface, then the wellbore shall be filled with cement from a depth of at 

least 30 feet to a depth of three feet from the surface.

(k) Cutting off surface pipe and identification of the abandoned wellbore.

(1) This subsection applies to a wellbore plugged for abandonment. It does 

not apply to a wellbore plugged back for conversion to a water well under (p) 

of this Section.

(2) After setting the top plugs in a well, the operator shall cut off the 

casing left in the wellbore three feet below surface, and the operator shall 

cap the casing in the wellbore with a steel plate.
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 193 -

(3) The operator shall inscribe or embed the well number and date of 

plugging on the steel plate.

(l) Tagging the top of the plug. The Field Inspector for the Conservation 

Division may require the operator to determine the depth of the top of a plug by 

running a wireline or tubing string.

(m) Fall back of cement. If the cement for a plug falls back during setting 

below the top depth required by this Section, the operator shall run additional 

cement until the plug meets the minimum requirements of this Section.

(n) Alternative plugging procedure for down-hole problems.

(1) In plugging a well, if the operator encounters a downhole problem which 

prevents the operator from complying with the standards of this Section, the 

District Manager may prescribe an alternative plugging procedure provided 

that the alternative plugging procedure prevents the vertical migration in 

the wellbore of oil, gas, saltwater, H2S, and other deleterious substances 

into a formation bearing oil, gas, or treatable water.

(2) The District Manager shall note his approval of the alternative plugging 

procedure on the well's Plugging Report (Form 1003).

(o) Plugging of rat holes and mouse holes. If a rat hole or mouse hole was 

used at the surface for drilling the well, it shall be plugged within 90 days 

after drilling operations are complete as follows:

(1) The hole shall be filled with drilling mud from bottom to a depth eight 

feet below the surface.

(2) The operator shall fill the hole with cement from a depth of eight feet 

to a depth of three feet below the surface.

(3) The operator shall fill the hole with dirt from a depth of three feet to 

surface.

(p) Plug back for conversion to a water well. The District Manager may permit 

a well operator to plug back a well for permanent use as a water well by: 

(1) Setting any bottom hole and intermediate plugs required by this Section.

(2) Setting a top cement plug from the base of treatable water to 50 feet 

below the base of treatable water.

(3) Obtaining written permission from the owner of the ground water rights 

for conversion of the well to a water well.

(4) Submitting under 165:10-11-7, a Plugging Report (Form 1003) noting the 

conversion of the well with a copy of the written permission from the owner

of the ground water rights for conversion of the well to a water well.

[SOURCE: Amended at 13 Ok Reg 2395, eff 7-1-96; Amended in Rule Making 

97000002, eff 7-1-97; Amended in Rule Making 980000013, eff 7-15-98; Amended in 

Rule making 980000034, eff 7-1-99; Amended in Rule Making 200200017, eff 7-1-02; 

Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28 OK Reg 

1949, eff. 7-11-11 (RM 201000007)]

165:10-11-7. Plugging record

(a) Within 30 days after plugging a well, the owner or operator of the well 

shall submit for the well in duplicate to the appropriate Conservation Division

District Office:

(1) Plugging Record (Form 1003).

(2) Form 1003 shall be completed and signed by employees of both the 

operator and the cementer.

(3) If a Completion Report (Form 1002A) has not been submitted for the well, 

Form 1002A shall be attached to the Form 1003.

(b) Any operator failing to comply with this Section may be fined up to 

$500.00.

[SOURCE: Amended at 9 Ok Reg 2295, eff 6-25-92; Amended in Rule Making 

97000002, eff 7-1-97; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003)]
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 194 -

165:10-11-8. Procedures for identification and control of wellbores in which 

radioactive sources have been abandoned

(a) Notice and permission to abandon.

(1) When a radioactive source has been lost and abandoned in a well bore, 

the operator shall immediately notify the appropriate District Office and 

request permission to plug or plug-back and/or bypass to conform to the 

conditions set out in this Section. The District Manager or his designee may 

exercise the option of witnessing the procedure.

(2) A radioactive source shall not be considered abandoned until all 

reasonable efforts have been expended to retrieve the source.

(b) Method of plugging.

(1) Wells in which radioactive sources have been abandoned shall be 

mechanically equipped and plugged in such a manner so as to prevent either 

accidental or intentional mechanical disintegration of the radioactive 

source.

(2) When a radioactive source has been lost in a well bore and cannot be 

recovered, the tool shall be covered with a 100 foot plug consisting of 

standard oil field cement with an approved deflection tool cemented in place 

at the top of the plug. An additional 100 foot plug colored by red iron 

oxide shall be run on top of the deflection tool.

(c) Approval for alternate plugging method. When an operator, after expending 

all reasonable efforts, finds that it is not possible to abandon the source as 

prescribed in (d) of this Section, an alternate plugging procedure must be 

approved by the Commission prior to use.

(d) Markers for wells in which a radioactive source has been abandoned. Upon 

abandonment of a well in which a radioactive source has been abandoned, and the 

abandonment procedure has been approved by the Commission, the operator shall 

cause a permanent plaque to be attached to casing remaining in the well within 

thirty (30) days of such abandonment. The plaque shall be attached in such a 

manner that reentry could not be accomplished without disturbing it. The plaque 

shall be constructed of a long lasting material and shall contain the following 

information:

(1) Well name and well number.

(2) Name of operator.

(3) The source material abandoned.

(4) Total depth of the well.

(5) The latitude and longitude and the true vertical depth of the location 

of the abandoned radioactive source in the well bore. For purposes of this

Section, true vertical depth is measured at the surface location of the well 

bore in which the radioactive source has been abandoned.

(6) The date of abandonment.

(7) The activity of the source.

(8) Trefoil radiation symbol with a radioactive warning.

(e) Completion reports and plugging records of wells with lost radioactive 

sources. When a radioactive source has been lost and abandoned in a well bore, 

both the Form 1002A Completion Report and Form 1003 Plugging Record submitted by 

the well operator to the Commission pursuant to OAC 165:10-3-25 and OAC 165:10-

11-7, respectively, shall contain all of the information required in (d) of this 

Section. The well operator shall also forward copies of the Form 1002A 

Completion Report and Form 1003 Plugging Record to the Radiation Management 

Section of the Oklahoma Department of Environmental Quality.

(f) Record of abandoned radioactive sources. The Commission will maintain a 

current listing of all wells in which radioactive sources have been abandoned.

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92; Amended in Rule Making 

97000002, eff 7-1-97; Amended at 28 Ok Reg 1949, eff 7-11-11 (RM 201000007)]

165:10-11-9. Temporary exemption from plugging requirements
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 195 -

(a) Scope. The Commission may permit any well which is required to be properly 

abandoned pursuant to OAC 165:10-11-3 and OAC 165:10-11-5, at the request of an 

operator, to be temporarily abandoned.

(b) Application. An application for a permit to temporarily exempt a well from 

the plugging requirement shall be made on Form 1003A completed in its entirety, 

and submitted to the appropriate Conservation Division’s District Office.

(c) Permit.

(1) Any operator seeking approval for temporary abandonment shall submit a 

notice of intent to temporarily abandon the well, Form 1003A, to the 

appropriate District Office describing the temporary abandonment procedure 

used.

(2) The permit will be valid for a period of five (5) years. At least 30 

days prior to the expiration of any approved temporary abandonment permit, 

the operator shall return the well to beneficial use in accordance with 

Commission rules, permanently plug and abandon said well, or apply for a new 

permit to temporarily abandon the well.

(3) No temporary abandonment will be approved that does not prevent the 

contamination of treatable water and/or other natural resources and the 

leakage of any substance at the surface.

(4) If the well fails the tests required herein the problem shall be found, 

corrected and a new test successfully conducted within 30 days or the well 

shall be plugged and abandoned in accordance with Commission rules.

(5) Upon successful completion of the work on the temporarily abandoned 

well, the operator will submit a new request for temporary abandonment to the 

appropriate District Office.

(d) Protection of treatable water. The treatable water shall be protected by 

one or more of the following:

(1) A drillable, retrievable or temporary bridging plug set above the 

producing interval and below the top of the cement. The surface shall be 

capped with a valve in operational condition. A pressure test may be 

required by the appropriate District Office.

(2) A packer run on tubing and set above the producing interval and below 

the top of the cement. The well shall be equipped with suitable wellhead 

packoff equipment and be closed to the atmosphere.

(3) A fluid level test determined by use of equipment approved by the 

Conservation Division’s Field Operations Department. The fluid level must be 

no higher than 150 feet below the base of the treatable water. The Field 

Inspector shall be notified at least 48 hours beforehand to be afforded the 

opportunity of witnessing the procedure. Fluid level tests must be conducted 

annually each of the five (5) years during the anniversary month of the 

permit. Additional tests may be required at any time at the request of the 

Conservation Division’s Field Operations Department. The wellhead shall be 

closed to the atmosphere.

(4) A casing inspection log confirming the mechanical integrity of the 

production casing submitted to the appropriate Conservation Division’s 

District Office.

(5) Alternate methods of testing may be approved by the Conservation 

Division’s Field Operations Department by written application and upon 

showing that such a test will provide information sufficient to determine 

that the well does not pose a threat to natural resources.

(e) Surface facilities. The well site of a well with temporary exemption from 

the plugging requirements shall be kept in a neat and orderly manner, including 

lease roads, with a legible sign showing the name of the operator, operator 

telephone number, well name, number, and the legal location.

(f) Termination of permit. The permit for a temporary exemption from plugging 

shall terminate and plugging operations shall commence within 30 days after:

(1) The time interval set has lapsed and a renewal has not been granted.

(2) The lease or unit on which the exempted well was located has become 

nonproductive.
OAC 165:10-11 Corporation Commission

Eff. 8-27-15

- 196 -

(3) The fluid level has risen to a point less than 150 feet below the base 

of the treatable water.

(4) The Conservation Division’s Field Operations Department has determined 

that the surface area or wellhead equipment requirement does not meet the 

standards required by the Commission.

(g) Exception to termination of permit. An exception to the termination of an 

exemption from the plugging requirements shall be allowed if:

(1) An application to convert the well to a disposal, injection, or supply 

well has been filed with the Commission, and proper notice, according to OAC 

165:5, has been met.

(2) An application requesting an exception to the plugging rules has been 

filed with the Commission and an exception has been granted by an order of 

the Commission.

[SOURCE: Added at 9 Ok Reg 2337, eff 6-25-92; Amended in Rule Making 97000002, 

eff 7-1-97; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]
OAC 165:10-12 Corporation Commission

Eff. 8-27-15

- 197 -

SUBCHAPTER 12. PROCEDURES FOR THE SEEPING NATURAL GAS PROGRAM

Section

165:10-12-1. Purpose

165:10-12-2. Coordination of Seeping Natural Gas Program

165:10-12-3. Jurisdiction and scope

165:10-12-4. Administration of the fund

165:10-12-5. Definitions

165:10-12-6. Notice requirements for seeping natural gas occurrences

165:10-12-7. Commission Rapid Action Assessment Team

165:10-12-8. Standard procedure for the Rapid Action Assessment Team

165:10-12-9. Assistance to owners of property

165:10-12-10. Reimbursement of expenditures

165:10-12-1. Purpose 

The purpose of this Subchapter is to provide the Oklahoma Corporation 

Commission ("Commission") rules to govern responses to occurrences concerning 

the Seeping Natural Gas Program. All procedural rules necessary to initiate, 

regulate and administer the Seeping Natural Gas Program are contained in this 

Subchapter.

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]

165:10-12-2. Coordination of Seeping Natural Gas Program

The Commission shall coordinate response efforts when notified of an 

occurrence of seeping natural gas. The Commission shall enlist private 

industry, state, county, municipal, and local government official entities as 

needed. These entities will aid the Commission with investigating, identifying 

and abating the hazard. If the Commission has determined that the applicable 

utility may be responsible for the problem, even though the utility initially 

advised the Commission it was not, the Commission can require the utility to 

run further tests to re-evaluate the occurrence as to the utility's lines and 

equipment. These rules do not supersede OAC 165:45-11-11 (a)(9).

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]

165:10-12-3. Jurisdiction and scope

Pursuant to 17 O.S. 2006, Section 180.10 (C) the Commission is directed to 

promulgate and enforce rules, and issue and enforce orders relating to seeping 

natural gas. The rules of this Subchapter shall be known as the Commission 

Procedures for the Seeping Natural Gas Program, and shall be cited as OAC 

165:10-12-1 et seq.

(1) The rules of this Subchapter shall govern all proceedings concerning 

the Seeping Natural Gas Program. 

(2) The Commission retains the authority to grant an exception, for good 

cause shown, to any rule contained herein unless otherwise precluded by law. 

(3) The rules of this Subchapter establish procedures for the investigation 

of seeping natural gas and the administration of the Seeping Natural Gas 

Fund for the purpose of providing funding to eligible property owners for 

the mitigation of seeping natural gas on their property, in those cases in 

which the Commission is unable to abate the hazard of a seeping natural gas 

occurrence by issuing an order to a responsible person or by plugging a 

well.

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]
OAC 165:10-12 Corporation Commission

Eff. 8-27-15

- 198 -

165:10-12-4. Administration of the fund

(a) The Commission will appoint the Director of Administration of the 

Commission as the Seeping Natural Gas Fund Administrator. 

(b) The Administrator is expressly authorized to bring actions before the 

Commission to enforce provisions of this Subchapter. 

(c) The Administrator shall act under the supervision of the Commission, to 

administer the Seeping Natural Gas Fund in accordance with the rules and 

procedures approved by the Commission and consistent with this Subchapter. The 

Administrator is authorized to enforce, implement, and administer applicable 

rules and orders of the Commission. 

(d) The Administrator’s general duties shall include but not be limited to:

(1) Providing disbursements from the Fund; 

(2) Managing the daily operations and affairs of the Fund; 

(3) Engaging annual audits of the expenditures of the Fund and of the 

distribution from the Fund to property owners who receive payment from the 

Fund;

(4) Resolving disputes related to issues addressed in this Subchapter; 

(5) Reviewing all applications for assistance from property owners;

(6) Performing any other duties as directed by the Commission.

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]

165:10-12-5. Definitions

The following words or terms, when used in this Chapter, shall have the 

following meaning unless the context clearly indicates otherwise:

"Hazardous gas concentration" means a concentration that presents or causes

a risk of accident or fire. 

"Natural gas" means a highly compressible, highly expansible mixture of 

hydrocarbons having a low specific gravity and occurring naturally in gaseous 

form. Besides hydrocarbon gases, natural gas may contain appreciable quantities 

of nitrogen, helium, carbon dioxide, hydrogen sulfide, and water vapor. 

"Person" means any individual, business association or corporation, 

partnership, governmental or political subdivision, public corporation, body 

politic and corporate public authority, trust or any other legal entity.

"Responsible party" means any person or persons responsible for a facility 

which is found to be causing a seeping natural gas occurrence. 

"Seeping natural gas" means natural gas which has migrated into, under or 

around a structure at hazardous concentrations.

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]

165:10-12-6. Notice requirements for seeping natural gas occurrences

(a) Upon identification of a possible occurrence of seeping natural gas, a

utility shall notify the Pipeline Safety Department of the Commission. If the 

Pipeline Safety Department determines that the seeping gas occurrence is not 

caused by a pipeline under its jurisdiction, Pipeline Safety will contact the 

Consumer Services Division and the Oil and Gas Conservation Division. 

(b) Upon a utility's initial determination that hazardous gas seepage is not 

from its system, the utility shall provide the property owner with a brochure 

explaining the situation and providing the impacted property owner with 

information about available assistance, including pertinent Commission 

telephone numbers. For assistance, the property owner or an authorized 

representative of the property owner shall contact the Commission.

(c) The District office of the Oil and Gas Conservation Division will contact 

the local Fire Marshall/Fire Chief and the utility to inform them that the 

Rapid Action Assessment Team has been activated. 

(d) The Field Operations Department of the Oil and Gas Conservation Division 

will assess and evaluate the situation and act accordingly. 

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]
OAC 165:10-12 Corporation Commission

Eff. 8-27-15

- 199 -

165:10-12-7. Commission Rapid Action Assessment Team

(a) The Oil and Gas Conservation Division shall form a Rapid Action Assessment 

Team to handle any seeping natural gas occurrence that occurs within the State 

after determining that it is not caused by a pipeline regulated by the Pipeline 

Safety Act or a utility. 

(b) The Rapid Action Assessment Team will be equipped with qualified personnel 

and the proper and necessary equipment to handle investigations of seeping 

natural gas occurrences.

(c) Each Commission District Office will have access to designated trained 

personnel and equipment prepared for investigating a seeping natural gas 

occurrence. 

(d) No person entering upon the land to investigate or abate the hazards 

pursuant to the authority of the Commission will be held responsible for future 

abatement work on the land or be liable for damages or otherwise for conditions 

subsequently arising or in connection with the land. 

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]

165:10-12-8. Standard procedure for the Rapid Action Assessment Team

As soon as the Oil and Gas Conservation Division is notified of an unknown 

gas surface seep in or around a structure that the utility has determined is 

not leaking from its lines, except in situations where the Oklahoma Emergency 

Management Plan is activated, Commission personnel will respond as follows:

(1) The Field Inspector from the Oil and Gas Conservation Division will 

respond with gas detection equipment and notify the Field Supervisor and 

District Manager.

(2) The District Manager will activate the local Rapid Action Assessment 

Team and notify local officials and the following Commission offices in 

Oklahoma City: Consumer Services, Field Operations and Public Information.

(3) The District Office will research well data, aerial photos and maps on 

file with the Oil and Gas Conservation Division.

(4) The Oil and Gas Field Supervisor and Field Inspector will coordinate 

with any responsible party in the locality and will research any available 

maps and records. 

(5) If no known oil or gas wells are present, the Rapid Action Assessment 

Team will number and set soil gas monitoring probes at strategic locations 

in the area and initiate a gas monitoring program to measure the 

concentration and sample the composition of gas and log results at monitored 

locations.

(6) If the source of gas can be identified and there is a responsible 

party, the Rapid Action Assessment Team will request a Commission order 

directing the responsible party to abate the hazard.

(7) If no known responsible party is located, the Rapid Action Assessment 

Team will position the monitoring system to allow for measurement of 

concentration and dissipation of the gas.

(8) Upon the completion of the mitigation process, the Commission shall 

notify the utilities in writing.

(9) Upon notification by the Commission that the mitigation process has 

been completed, the utility shall verify that the hazard has been abated 

prior to establishing or resuming gas service.

(10) If the utility believes it should not establish or resume service, it 

shall file an emergency application with the Commission to show cause why 

service should not be established or resumed. The Commission shall hear 

such application with or without notice. At the time of the hearing, the 

Commission shall receive exhibits and recommendations as required by OAC 

165:5-7-39(c). The Commission shall rule on the request as it deems 

appropriate.

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]
OAC 165:10-12 Corporation Commission

Eff. 8-27-15

- 200 -

165:10-12-9. Assistance to owners of property

(a) An owner of property who has a seeping natural gas occurrence as defined 

by 165:10-12-5 may file an application with the Commission to receive 

assistance with installing a system to divert natural gas away from the 

structure or to abate the hazard.

(b) After the Oil and Gas Conservation Division and the Consumer Services 

Division have completed their review of the property owner’s application, they 

will forward it to the Director of Administration of the Commission, and the 

Director of Administration will recommend the application for Commission 

action. 

(c) The Commission shall determine the eligibility of the owner of a structure 

for assistance based on the nature and extent of the hazard, whether the owner 

is unable to inhabit the structure, the financial need of the owner of the 

structure and other relevant factors dependent upon the Oklahoma Legislature's 

current and future approval of and appropriation for the Natural Gas Seep 

Program. 

(d) If the property owner's application is approved, the Commission may 

expend, pursuant to the Oklahoma Central Purchasing Act, Title 74 O.S. 85.1 et. 

seq., up to $20,000 from the Seeping Natural Gas Fund to engage the services of 

a contractor to install a system to divert natural gas away from a structure or 

to otherwise abate the hazard, 

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]

165:10-12-10. Reimbursement of expenditures

(a) The Commission may seek reimbursement of expenditures made by the 

Commission from a responsible party. Any monies received as reimbursement 

shall be deposited to the credit of the Commission Gas Seep Fund. 

(b) The Rule shall not relieve any person or persons otherwise legally 

responsible from any obligation to properly abate hazards associated with 

seeping natural gas.

[SOURCE: Added at 24 Ok Reg 1806 (RM 200700004), eff 7-1-2007]
OAC 165:10-13 Corporation Commission

Eff. 8-27-15

- 201 -

SUBCHAPTER 13. DETERMINATION OF ALLOWABLES - OIL AND GAS WELLS

Section

165:10-13-1. Oil and gas production [RESERVED]

165:10-13-2. Classification of wells for allowable purposes 

165:10-13-3. Production tests on new, re-entered, and recompleted wells 

165:10-13-4. Reservoir performance tests 

165:10-13-5. Most efficient rate 

165:10-13-6. Load oil 

165:10-13-7. Production from different pools 

165:10-13-8. Transfer of allowables 

165:10-13-9. Allowable for increased density well 

165:10-13-10. Applications for reinstatement of cancelled underage for oil 

wells and for unallocated gas wells 

165:10-13-1. Oil and gas production [RESERVED] 

165:10-13-2. Classification of wells for allowable purposes

(a) For purposes of this Subchapter the terms gas, oil, and gas-oil ratio are 

defined in 165:10-1-2.

(b) Any well having a gas-oil ratio of 15,000 to one or more shall be 

classified as a gas well for allowable purposes.

(c) Any well having a gas-oil ratio of less than 15,000 to one shall be 

classified as an oil well for allowable purposes.

(d) If a well is a multiply completed well under 165:10-3-35, then each zone of 

the completion shall be classified separately for allowable purposes.

(e) If a well is commingled under 165:10-3-39, the classification of the well 

for allowable purposes shall be determined by the gas-oil ratio of the 

commingled production.

165:10-13-3. Production tests on new, re-entered, and recompleted wells

(a) On all new wells, re-entered wells, and recompleted wells classified as oil 

wells for allowable purposes, in any regular spacing unit(s) and reservoir 

dewatering oil spacing unit(s), initial production tests shall be performed and 

reported to the Commission on Form 1029A for discovery oil wells, Form 1002A for 

other oil wells, unless otherwise specified by order of the Commission. The 

test shall not commence until after recovery of a volume of oil equivalent to or 

greater than the amount of load oil or other liquids introduced into the well.

(b) On all new wells, re-entered wells, and recompleted wells classified as gas 

wells for allowable purposes, initial production tests shall be performed and 

reported to the Commission on Form 1016 unless otherwise specified by order of 

the Commission or by OAC 165:10-17-7(b)(1).

(c) If special pool rules prescribe, by order of the Commission, the manner in 

which production tests are to be performed in any separate common source of 

supply, the production or gas-oil ratio test shall be performed and reported to 

the Commission in accordance with such special pool rules.

[SOURCE: Amended at 19 Ok Reg 639, eff 1-14-02 (emergency); Amended at 19 Ok 

Reg 966, eff 7-1-02 (RM 200100009); Amended at 25 OK Reg 2187, eff 7-11-08 (RM 

200800003) ; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-13-4. Reservoir performance tests

 The Commission may require, from time to time, the presentation of such data 

and facts as may be necessary to indicate reservoir performance and conditions 

in any oil or gas pool. The Commission may witness or supervise the taking of 

such reservoir performance tests and keep such records as it deems necessary to 

properly regulate the operation of any oil or gas pool. Any test requested by 
OAC 165:10-13 Corporation Commission

Eff. 8-27-15

- 202 -

the Commission may be witnessed by any operator in the pool. When special pool 

rules require bottom hole pressure tests, the tests shall be reported to the 

Conservation Division on Form 1027.

165:10-13-5. Most efficient rate

 Subject to the procedural requirements of 165:5-7-12, the Commission may 

issue an order increasing or decreasing the rate of oil and gas production in an 

oil pool to correspond to the most efficient rate of production which is 

consistent with sound engineering and conservation practices as may be justified 

by the circumstances and evidence submitted.

165:10-13-6. Load oil

Load oil used in well completions which is not produced from the same lease 

or spacing unit shall not be charged against the well, lease, or unit. The 

well shall be allowed to produce such load oil in addition to the current 

monthly allowable. Operators claiming credit for load oil for allowable 

purposes may file Oklahoma Tax Commission Form 317 not more than 6 months after 

treating the well.

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]

165:10-13-7. Production from different pools

(a) In the event there are two or more common sources of supply produced 

through a well or wells on the same lease or drilling and spacing unit and which 

are not commingled under 165:10-3-39, the production from each common source of 

supply shall be separately produced, measured, and/or accounted for to the 

Commission.

(b) If one or more of the zones produced are classified as oil for allowable 

purposes, the operator of the well shall submit to the Conservation Division a 

multi-zone report on Form 1011 showing the production from each oil-bearing 

common source of supply on or before the last day of the succeeding proration 

period.

165:10-13-8. Transfer of allowables

 Subject to the procedural requirement of 165:5-7-12, the Commission may issue 

an order transferring, after proper adjustment, all or part of an allowable from 

a well with a high gas-oil ratio or high water-oil ratio to a well having a 

lower gas-oil ratio or water-oil ratio, if:

(1) The wells produce from the same common source of supply.

(2) The wells are located on the same lease or in the same drilling and 

spacing unit.

165:10-13-9. Allowable for increased density well

(a) Allowable production. Except as otherwise provided by rule or order of the 

Commission, the allowable production for permitted wells within a drilling and 

spacing unit producing from the same common source(s) of supply shall be 

determined as follows:

(1) Each individual well shall be classified for allowable purposes by gasoil ratio under 165:10-13-2.

(2) Permitted wells of the same classification for allowable purposes shall 

share a single well allowable.

(3) Permitted wells of different classifications for allowable purposes 

shall receive allowables as provided by the order of the Commission 

authorizing the additional well(s).

(b) Shared single allowable. If two or more wells in a single drilling and 

spacing unit are classified as gas wells for allowable purposes, the shared 

single allowable for the unit shall be determined by the greater of:

(1) A minimum allowable; or
OAC 165:10-13 Corporation Commission

Eff. 8-27-15

- 203 -

(2) A normal allowable based on the wellhead absolute open flow potential of 

the best well in the drilling and spacing unit producing from the same common 

source of supply.

(c) Additional well. If an additional well is not of the same classification 

as any prior permitted well, it shall receive an allowable as provided by the 

order permitting the well.

(d) Effect of penalties. If the allowable for a well in a drilling and spacing 

unit is subject to a percentage penalty or lid on production, the penalty or lid 

on production shall apply to the ratable share of production of the shared 

single allowable for the penalized well as opposed to the entire shared single 

allowable for the unit.

(1) The ratable share of production of the shared single allowable for an 

unallocated gas well is that volume of gas which bears the same ratio to the 

shared single allowable as the wellhead absolute open flow potential for the 

well bears to the sum of the wellhead absolute open flow potentials for all 

wells in the drilling and spacing unit of the same classification for 

allowable purposes.

(2) The ratable share of production of the shared single allowable for a 

special allocated gas well is that volume of gas which bears the same ratio 

to the shared single allowable as the unpenalized monthly allowable the well 

would receive if it were the only well in the unit bears to the sum of such 

allowables for all the wells in the drilling and spacing unit of the same 

classification for allowable purposes.

(3) No special allocated well shall receive an allowable less than the 

defined minimum unit allowable divided by the number of wells in the drilling 

and spacing unit of the same classification for allowable purposes.

(4) The ratable share of production of the shared single allowable for an 

oil well is that volume of oil which bears the same ratio to the shared 

single allowable as the potential for the well bears to the sum of the 

potentials for all wells in the drilling and spacing unit of the same 

classification for allowable purposes. If the oil well was assigned a 

separate allowable under (c) of this Section, the penalty shall apply to the 

allowable assigned to the well.

(5) The portion of the shared single allowable representing the reduction in 

the allowable for the penalized well is not allocable to other wells in the 

drilling and spacing unit.

(e) Which operator shall file required tests. If the operators of the wells in 

a drilling and spacing unit cannot agree as to which operator shall file the 

required tests and production reports for the unit or as to what proportion of a 

shared single allowable shall be attributable to each well of the same 

classification for allowable purposes, the Commission may, after application, 

notice, and hearing, issue an order determining which operator shall file the 

tests and reports or what the proportional share of the shared single allowable 

is attributable to each well or the maximum rate of allowable production for 

each well.

(f) Wellhead absolute open flow potential. For the purpose of this Section, 

the wellhead absolute open flow potential for a test exempt gas well shall be 

presumed to equal:

(1) The average daily production for the previous calendar year (or that 

portion of the previous calendar year if the first sales date was after 

January 1 of that year), or the minimum allowable that would otherwise be 

assigned to an unallocated gas well under applicable rules of the Commission 

as if such well were the only well in the unit, whichever is less, for an 

unallocated well; or

(2) The product of two multiplied by the monthly allowable for the well 

under 165:10-17-9 for a special allocated well.

(g) Testing or reporting requirements. This Section shall not exempt any well 

from any testing or reporting requirement imposed by rule or order of the 

Commission.
OAC 165:10-13 Corporation Commission

Eff. 8-27-15

- 204 -

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92; Amended in Rule Making 

980000033, eff 7-1-99]

165:10-13-10. Applications for reinstatement of cancelled underage for oil 

wells and for unallocated gas wells

(a) Oil well. 

(1) With respect to an oil well, all underage for the proration period in 

excess of 15 percent of the allowable shall be automatically cancelled at the 

end of the proration period, except underage accrued under (4) of this 

subsection because of the failure to split a tank.

(2) A producer may apply to reinstate cancelled underage if the well is 

capable of producing in excess of its allowable. The procedure for applying 

for reinstatement of cancelled underage is described in (c) of this Section.

(3) Except in situations where the operator has failed to comply with 

applicable well testing and reporting requirements of the Commission, failure

or refusal of the purchaser to take the allowable shall be grounds for 

reinstatement of any underage accumulated because of such failure or refusal. 

Underage of this nature may be accumulated until balanced by future runs.

(4) The operator shall not be required to sell less than a full stock tank 

of oil by the end of the proration period to avoid cancellation of underage. 

Instead, such underage may be accrued until the operator accumulates and 

sells a volume of oil from the tank amounting to a full tank, and the sale of 

oil representing such underage shall not be considered as overage.

(b) Unallocated gas well.

(1) With respect to any unallocated gas well, of the total underage for the 

well or unit existing at the end of the proration period, 75% shall be 

automatically cancelled and 25% shall be automatically carried forward to the 

next prorationing period.

(2) Said underage carried forward to the next balancing period must be 

utilized in said balancing period, with that amount of underage carried 

forward but not used, to be cancelled at the end of the prorationing period.

(c) Procedure for reinstatement of cancelled underage.

(1) The operator of an oil well may apply for reinstatement of cancelled 

underage by application for administrative approval on Form 1010 within 90 

days after cancellation of the underage.

(2) If the Conservation Division declines to approve the Form 1010 

application, the applicant shall be notified in writing that application, 

notice, and hearing under 165:5-7-1 are necessary to obtain reinstatement of 

cancelled underage.

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 205 -

SUBCHAPTER 15. OIL WELL PRODUCTION AND ALLOWABLES 

Section

165:10-15-1. Classification of oil pools and projects 

165:10-15-2. Overage adjustments for oil wells 

165:10-15-3. Effect of percentage penalty on oil wells 

165:10-15-4. Discovery oil pools [RESERVED]

165:10-15-5. Discovery oil allowables 

165:10-15-6. Production tests and reports for discovery oil pools 

165:10-15-7. Procedure for obtaining discovery allowable 

165:10-15-8. Allocated oil pools [RESERVED] 

165:10-15-9. Allocated oil allowables 

165:10-15-10. Production tests and reports for allocated oil wells 

165:10-15-11. Unallocated oil pools [RESERVED] 

165:10-15-12. Unallocated oil allowables 

165:10-15-13. Production tests and reports for unallocated oil wells

165:10-15-14. Enhanced oil recovery project allowables 

165:10-15-15. Production tests and reports for enhanced oil recovery projects

165:10-15-16. Excessive water exempt oil project allowables 

165:10-15-17. Production tests and reports for excessive water exempt oil 

projects 

165:10-15-18. Production tests and reports for reservoir dewatering oil spacing 

units

165:10-15-1. Classification of oil pools and projects

(a) Types of oil pools. Each producing oil pool shall be classified by the 

Commission into one of the following categories:

(1) Discovery oil pool (165:10-15-5).

(2) Allocated oil pool (165:10-15-9).

(3) Unallocated oil pool (165:10-15-12).

(4) Enhanced oil recovery project (165:10-15-14).

(5) Excessive water exempt oil project (165:10-15-16).

(6) Reservoir dewatering oil spacing unit (165:10-15-18).

(b) Treatment of an oil well located in a gas pool. An oil well located in a 

gas pool shall be treated as an unallocated oil well, unless the oil well is 

subject to one of the following:

(1) Pool rules controlled by volumetric withdrawal.

(2) Discovery oil pool rules.

(3) Allocated oil pool rules.

(4) Some other order of the Commission.

(c) Discovery oil pools.

(1) A new oil pool which has complied with the provision of 165:10-15-5 may 

be granted discovery allowable production rates, administratively, subject to 

either:

(A) Spacing requirements.

(B) Order of the Commission.

(2) Each permitted discovery oil well shall be subject to discovery oil pool 

rules until either:

(A) Expiration of the discovery allowable period.

(B) Reclassification of the well or pool.

(d) Allocated oil pool.

(1) The Commission shall classify an oil pool as an allocated oil pool when:

(A) At any market demand hearing the total production from an oil pool or 

from any well within the pool needs to be regulated; or

(B) For good cause shown, upon application, notice, and hearing.

(2) A gas well located in an allocated oil pool that is reclassified as an 

oil well for allowable purposes shall be subject to allocated oil pool rules.
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 206 -

(3) Each allocated oil well shall be subject to the allocated oil pool rules 

until the Commission reclassifies the well or pool.

(e) Unallocated oil pools.

(1) Classification of unallocated oil pool:

(A) Any pool or area which does not require specific regulation and

control by the Commission to restrict production to the market demand, aid 

in the prevention of waste, assure the maximum ultimate recovery of oil 

and gas from the pool, or protect correlative rights shall be classified 

as an unallocated pool.

(B) The Commission shall determine which discovery and allocated pools 

will be placed in the unallocated classification at each market demand 

hearing.

(2) Each unallocated oil well shall be subject to unallocated oil pool rules 

until the Commission reclassifies the well or pool.

(f) Enhanced oil recovery projects.

(1) Authorized pressure maintenance. The Commission may, upon application, 

notice, and hearing, authorize the pressure maintenance of a pool or the 

production of oil by the injection of fluid, fluids, gas, gases, or other 

material into a common source of supply or a portion thereof, whether

unitized or not, where substantial quantities of additional oil may be 

recovered which could not be recovered under ordinary primary depletion 

methods. When so authorized, the project will be classified as an Enhanced 

Oil Recovery Project with one of the following classifications:

(A) Pressure Maintenance Project

(B) Gas Repressuring Project

(C) Waterflood Project

(D) Other Enhanced Recovery Projects

(2) Status of a gas well reclassified as an oil well. If a well classified 

as a gas well in an enhanced oil recovery project is reclassified as an oil 

well for allowable purposes, the well shall be subject to the appropriate 

enhanced oil recovery project rules.

(3) Termination of enhanced oil recovery status. Each enhanced oil recovery 

well shall be subject to enhanced oil recovery project rules until one of the 

following occurs:

(A) Termination of the enhanced oil recovery project.

(B) The well is reclassified as a gas well for allowable purposes.

(C) The Commission issues an order reclassifying the well or project.

(D) The well is abandoned.

(g) Excessive water exempt oil projects. 

(1) Oil production rates. The Director of Conservation may administratively 

authorize the production of oil at rates greater than the normal allowable 

provided the water-oil ratio of the well and/or pool is greater than or equal 

to 3:1. All applications shall comply with 165:5-7-12.

(2) Status of a gas well reclassified as an oil well. If a well classified 

as a gas well in an excessive water exempt oil project is reclassified as an 

oil well for allowable purposes, the well shall be subject to excessive water 

exempt oil project rules.

(3) Termination of excessive water exempt status. Each excessive water 

exempt well shall be subject to excessive water exempt oil project rules 

until at least one of the following occurs:

(A) The water-oil ratio declines below 3:1.

(B) Termination of the excessive water exempt oil project.

(C) The well is reclassified as a gas well.

(D) The Commission issues an order reclassifying the well or project.

(h) Allowable for reservoir dewatering oil spacing unit. 

(1) Oil production rates. To set an allowable for a well in a reservoir 

dewatering oil spacing unit, the operator shall refer to Appendix J and 

submit the appropriate forms and/or application as provided in OAC 165:10-15-

18.
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 207 -

(2) Reclassification of oil well as gas well. If a well in a reservoir 

dewatering oil spacing unit is later subject to reclassification as a gas 

well for allowable purposes, such reclassification will be determined 

according to general classification procedures based on the its gas/oil ratio 

pursuant to OAC 165:10-1-6(d) and (e) and 165:10-13-2. If the subject well 

is designated an excessive water exempt oil project pursuant to OAC 165:10-

15-1(g) and 165:10-15-16, reclassification shall be determined by OAC 165:10-

15-1(g)(2). If the subject well is assigned an allowable based upon its most 

efficient rate pursuant to OAC 165:10-13-5, such allowable shall remain in 

effect under the order establishing the production rate, so that the well 

will not be reclassified, until its status is modified or terminated by the 

terms of the instant or a subsequent Commission order. 

(3) Termination of reservoir dewatering oil spacing unit allowable. The oil 

allowable assigned a reservoir dewatering oil spacing unit shall remain in 

effect until one of the following occurs:

(A) The subject well is reclassified as a gas well pursuant to OAC 

165:10-1-6 and 165:10-13-2. 

(B) The subject well’s status as an excessive water exempt oil project 

is terminated pursuant to OAC 165:10-15-1(g)(3).

(C) The subject well’s status under a most efficient rate order is 

modified or terminated by the terms of the instant or a subsequent 

Commission order.

[SOURCE: Amended in Rule Making 200100009, eff 7-1-02]

165:10-15-2. Overage adjustments for oil wells

 No well, lease, unit, or project shall be overproduced in excess of 15 

percent of the allowable for the proration period. All overage accrued at the 

end of the proration period shall be deducted from the allowable for the second 

succeeding proration period.

165:10-15-3. Effect of percentage penalty on oil wells

 If a percentage penalty has been assigned to an oil well, the penalty shall, 

depending on the status of the well, be subtracted from:

(1) Discovery status. The applicable allowable from the Discovery Allowable 

Table (Appendix B to this Chapter) or the capacity of the well to produce as 

reported, whichever is less.

(2) If allocated or unallocated per-well status. The applicable allowable 

from the Allocated Well Allowable Table (Appendix A to this Chapter) 

multiplied by the current market demand factor or the capacity of the well to 

produce as reported, whichever is less.

(3) If unallocated per-lease status. The shallowest ten acre or less 

allowable from the Allocated Well Allowable Table (Appendix A to this 

Chapter) multiplied by the current market demand factor for the penalized 

well only. The penalty shall be subtracted from the lease allowable.

[SOURCE: Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-15-4. Discovery oil pools [RESERVED]

165:10-15-5. Discovery oil allowables

(a) Number of barrels of oil per day and duration of the discovery allowable 

period. The maximum number of barrels of oil per day and the duration of the 

discovery allowable period shall be determined from the Discovery Allowable 

Table (Appendix B to this Chapter) or the Allocated Well Allowable (Appendix A 

to this Chapter), whichever is greater, provided that the well is in compliance 

with the other provisions of this Section and other rules pertaining to 

allowables. If the well is not capable of producing at the discovery rate 

without causing preventable waste, the temporary discovery allowable shall be 
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 208 -

the capacity of the well to produce as reported, unless otherwise limited by the 

Commission.

(b) Effective date of discovery allowable.

(1) The discovery allowable period for the pool shall begin with the date of 

first completion of the discovery well of the pool and extend as provided in 

the Discovery Well Allowable Table (Appendix B to this Chapter).

(2) The discovery allowable period for each well in the pool shall run from 

the date specified under 165:10-15-7 for each well to the date of termination 

of the pool, if granted administratively.

(3) If application, notice, and hearing are required, the effective date of 

the discovery allowable period shall be specified by an order of the 

Commission, provided that such date shall not precede the date of filing of 

the application. The date of expiration of the discovery allowable shall 

still be determined as set forth in (1) of this subsection.

(c) Gross allowable production. The gross allowable production for any 

proration period from a well in a discovery pool may, at the option of the 

operator, be produced at any time during the proration period; however, in no 

event shall the production exceed the maximum efficient rate of flow.

[SOURCE: Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-15-6. Production tests and reports for discovery oil pools

(a) Initial test requirements. The operator of each well in each discovery 

pool shall perform an initial potential test and furnish the Conservation 

Division the results of such test not later than 30 days after completion of 

each well. Each individual well shall be tested for not less than six hours and 

not more than 24 hours with the production calculated and reported at a daily 

rate (24 hours).

(b) Witnessing of tests.

(1) With respect to initial test, the operator shall give twenty-four (24) 

hour notice of the opportunity to witness said test to the Conservation 

Division and the offset operator(s) producing from the same pool, but no 

waiver or signature of Conservation Division personnel is required.

(2) Any operator in the pool may witness any official test for any well in 

the pool. However, any person other than a Commission employee witnesses a 

test at their sole risk and expense.

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92; Amended in Rule Making 

980000033, eff 7-1-99; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-15-7. Procedure for obtaining discovery allowable

(a) Any operator desiring a discovery allowable shall file Form 1028 with the 

material and information specified below:

(1) A resistivity and a porosity type wireline survey of the well in 

question, if run.

(2) A Completion Report (Form 1002A) and Cementing Report (Form 1002C), 

completed in detail.

(3) A Potential Test (Form 1029A), completed in detail.

(4) A plat of the area showing all of the following information for each 

well within one and one-half (1 1/2) miles of the subject well:

(A) Operator.

(B) Well name and number.

(C) Total depth.

(D) Current status of the well (dry, oil, gas, injection, disposal, 

temporarily abandoned).

(E) Name of interval open, if any.

(F) Perforations, top and bottom, if any.

(G) Average daily production.

(5) An isopach contour map of the productive interval and/or a structural 

contour map of a nearby marker bed or formation, not separated from the 
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 209 -

producing interval by an unconformity, which is commonly used in the area. 

The Conservation Division may require either or both types of maps to 

determine the discovery status. The Commission may also require additional 

geological and/or engineering data, such as: stratigraphic cross-sections, 

structural cross-sections, production, and pressure information.

(b) The Conservation Division may administratively designate a discovery 

allowable for a well when the operator furnishes the Technical Department with 

the information specified in (a) of this Section. If the information is 

provided within 30 days of the date of first production and the application is 

approved, the effective date of the discovery allowable shall be the date of 

first production. If the information is provided more than 30 days after the 

date of first production and the application is approved, the discovery 

allowable shall be effective the date of filing.

(c) If a gas well in a discovery oil pool is reclassified as an oil well for 

allowable purposes, the operator must file the appropriate form, information and 

material specified in (a) of this Section within 30 days of reclassifying the 

well to obtain a discovery allowable. The allowable shall be effective the date 

the well was reclassified as an oil well as indicated on Form 1002A. If the 

application is not received within the specified time period, the application 

will be processed in accordance with (b) of this Section.

165:10-15-8. Allocated oil pools [RESERVED]

165:10-15-9. Allocated oil allowables

(a) Effective date of allowables. The allowable for an allocated well 

completed or recompleted on or after the first day of the proration period shall 

become effective the date of completion of the well, provided the operator has 

complied with the provisions of this Section and other rules governing 

allowables. In situations where the operator fails to comply, the allowable 

shall become effective the date the operator complies with this Section and 

other rules governing allowables.

(b) Allowables in allocated pools. Allowables in allocated pools shall be 

granted on an individual well basis, subject to appropriate spacing 

requirements, unless otherwise specified by order of the Commission. The 

allowable for each allocated well shall be determined as if the well was an 

unallocated well operating under 165:10-15-12(b) or 165:10-15-12(c)(1), 

whichever is appropriate, unless adjusted by order of the Commission. The 

operator shall produce the allowable on each well from that well and no part 

thereof from any other well.

(c) Application. Upon application by the Director of Conservation or any 

interested party, and after notice and hearing, the Commission may order the 

wells in a common source of supply to be produced under allowables established 

by special pool rules in lieu of the provisions of this Section. All 

requirements as to production tests and allowables shall be set forth by the 

order of the Commission establishing such special pool rules.

165:10-15-10. Production tests and reports for allocated oil wells

 All production tests and reports shall be filed as if the allocated well were 

an unallocated well operating on a per-well basis allowable under 165:10-15-

13(a).

165:10-15-11. Unallocated oil pools [RESERVED]

165:10-15-12. Unallocated oil allowables

(a) Effective date of allowable. The allowable for a well completed or 

recompleted on or after the first day of a proration period shall become 

effective the date of completion of the well, provided the operator has complied 

with the provisions of this Section and other rules governing allowables. In 

situations where the operator fails to comply, the allowable shall become 
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 210 -

effective the date the operator complies with this Section and other rules 

governing allowables.

(b) Well in an unallocated pool. Each well in an unallocated pool in which 

drilling and spacing units have been established shall be assigned the 

applicable allowable on a per-well basis from the Allocated Well Allowable Table 

(Appendix A to this Chapter) multiplied by the current market demand factor 

unless adjusted by order of the Commission. The production from each well shall 

be separately accounted for to the Commission.

(c) Lease in an unallocated pool. Each individual lease in an unallocated pool 

in which drilling and spacing units have not been established shall be assigned 

allowables, at the option of the operator, on either of the following basis:

(1) A per-well basis. If the operator elects to accept the per-well basis 

allowable, each well on the lease shall be assigned an allowable applicable 

to a ten-acre or less allowable at the appropriate depth from the Allocated 

Well Allowable Table (Appendix A to this Chapter) multiplied by the current 

market demand factor unless adjusted by order of the Commission. The 

production from each well shall be separately accounted for to the 

Commission.

(2) A per-lease basis. If the operator elects to accept the per-lease basis 

allowable, the allowable for the lease shall be the shallowest ten-acre or 

less allowable from the Allocated Well Allowable Table (Appendix A to this 

Chapter) multiplied by the current market demand factor multiplied by the 

number of wells on the lease unless adjusted by order of the Commission. The 

production from each lease shall be separately measured and accounted for to 

the Commission.

165:10-15-13. Production tests and reports for unallocated oil wells

(a) Per-well basis allowable.

(1) If the well is an allocated well, or an unallocated well located on 

lands in which drilling and spacing units have not been established and the 

operator elected to accept allowables on a per-well basis, or an unallocated 

well located on lands in which drilling and spacing units have been 

established, the operator shall file a production test no later than 30 days 

after the earlier of:

(A) Making the election,

(B) Completion of the well, or

(C) Recompletion of the well.

Each individual well shall be tested for not less than six hours and not 

more than 24 hours with the production calculated and reported at a daily 

rate (24 hours).

(2) Each new well shall be given an allowable equal to the allowable for an 

unallocated per-well basis well until the production test has been performed 

with the results reported to the Conservation Division. The allowable shall 

be effective for a period not longer than 30 days from completion of the 

well. A Form 1002A Completion Report may be used in lieu of a Form 1029A to 

establish an oil allowable if oil and gas production rates reported on Form 

1002A establish the well’s classification as an oil well. No further 

allowable shall be assigned to the well until compliance with this 

subsection.

(3 Until an operator submits the required test results for any well, as 

provided in subsection (a)(1), no allowable shall be assigned to the well. 

If said test results are filed late, then the allowable shall be effective 

the first day of the following month after the Conservation Division accepts 

the test.

(4) All initial tests shall be conducted in the manner set forth in (1) of 

this subsection.

(5) Annual testing shall not be required.

(b) Per-lease basis allowables.

(1) If the well is an unallocated well located on lands in which drilling 

and spacing units have not been established and the operator elects to accept 
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 211 -

allowables on a per-lease basis, the operator shall file a production test 

with the Conservation Division not later than 30 days after:

(A) Making the election,

(B) Completion of the initial well on the lease,

(C) Completion of a subsequent well on the lease,

(D) Recompletion of any well on the lease, or

(E) Retesting of any well on the lease.

Each well on the lease shall be tested for not less than six hours and not 

more than 24 hours with the production calculated and reported at a daily 

rate (24 hours).

(2) Each lease shall be given an additional allowable equivalent to the 

shallowest ten-acre or less allowable from the Allocated Well Allowable Table 

(Appendix A to this Chapter) multiplied by the current market demand factor 

for each new producing well added to the lease until the production test has 

been performed with the results reported to the Conservation Division. The 

additional allowable shall be effective for a period not longer than 30 days 

from completion of the well. No further additional allowable shall be 

assigned to the lease until compliance with this subsection.

(3) If an operator fails to submit the required test results for any lease 

with allowables calculated on a per-lease basis, no allowable shall be 

assigned to the lease. The operator may submit the results of the test to 

the Conservation Division to reinstate the allowable. A Form 1002A 

Completion Report may be used in lieu of a Form 1029A to establish an oil 

allowable if oil and gas production rates reported on Form 1002A establish 

the well’s classification as an oil well. The allowable shall be effective 

the first day of the following month after the Conservation Division accepts 

the test.

(4) No lease shall be granted underage resulting from failure to perform a 

required test in compliance with this Section.

(5) All initial tests, annual tests and retests shall be conducted in the 

manner set forth in (1) of this subsection.

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92; Amended in Rule Making 

980000033, eff 7-1-99; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 200900001)]

165:10-15-14. Enhanced oil recovery project allowables

(a) Effective date of allowable. The allowable for an enhanced oil recovery 

project shall be effective on the date operations commenced or the date 

specified by order of the Commission authorizing the project, whichever is 

later, provided the operator has complied with the provisions of this Section 

and other rules governing allowables. In situations where the operator fails to 

comply, the allowable shall become effective the date the operator complies with 

this Section and other rules governing allowables.

(b) Qualification for enhanced oil recovery allowable. For any project to 

qualify for an enhanced oil recovery allowable, an order of the Commission 

authorizing the project must be obtained.

(c) Allowable for enhanced oil recovery project. The allowable for an enhanced 

oil recovery project shall be on a project basis and shall be the capacity of 

the project to produce.

(d) Wells on a project producing from another reservoir. Oil wells within the 

boundaries of a project which do not produce from the project shall not be 

permitted to produce any portion of the allowable of such enhanced oil recovery 

project. The oil produced by non-project wells shall be separately produced, 

measured, and reported.

165:10-15-15. Production tests and reports for enhanced oil recovery projects

(a) Within 30 days of commencement of any enhanced oil recovery project, the 

operator shall file with the Conservation Division an inventory of all the wells 

located within the boundaries of the project completed in the approved common 
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 212 -

source of supply showing the name of the project and the new OTC Production Unit 

Number (including merge number) and the following for each well:

(1) Previous OTC Production Unit Number.

(2) API Number.

(3) Well Name and Number.

(4) Legal location, including quarter quarter quarter quarter section.

(5) Current status (producer, injector, observation, or temporarily 

abandoned).

The inventory shall also include the current daily (24 hour) production and 

injection rates for the project.

(b) The operator shall notify the Conservation Division in writing within 30 

days of the completion of any new well or the change in status of any existing 

well in the project.

(c) Until the operator submits the required test results for any enhanced oil 

recovery project as provided in subsection (a), no allowable shall be assigned 

to the project. If said test results are filed late, then the allowable shall 

be effective the first day of the following month after the Conservation 

Division accepts the tests.

(d) All initial tests shall be conducted as set forth in subsection (a).

(e) Annual testing shall not be required except as provided in OAC 165:10-1-6.

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]

165:10-15-16. Excessive water exempt oil project allowables

(a) Effective date of allowables. The allowable for an excessive water exempt 

oil project shall be on a well or a project basis and shall be effective when 

the Conservation Division receives and accepts the production test of, Form 

1013, unless otherwise specified by order of the Commission.

(b) Qualification for excessive water exempt oil project. For any project or 

well to qualify for excessive water exempt allowable, an order of the Commission 

authorizing the well or project must be obtained.

(c) Allowable for excessive water exempt oil project. The allowable for a well 

or project which has received a special excessive water exempt allowable shall 

be the capacity of the well or project to produce without causing preventable 

waste unless otherwise adjusted by the Director of Conservation. The production 

from a well which has received a special excessive water exempt allowable under 

this Section shall be separately produced, measured, and accounted for to the 

Commission from the oil produced from the remainder of the lease.

165:10-15-17. Production tests and reports for excessive water exempt oil 

projects

(a) The operator of each individual well with an excessive water exempt 

allowable shall file an initial production test, in duplicate, on Form 1013 with 

the Conservation Division. Each individual well shall be tested for seven 

consecutive days, and the amount of oil and the amount of water produced each 

day shall be reported on Form 1013. With respect to the initial test, the 

operator shall give twenty-four (24) hour notice of the opportunity to witness 

said test to the Conservation Division and the offset operator(s) producing from 

the same formation, but no waiver or signature of Conservation Division 

personnel is required on Form 1013.

(b) Each individual well shall be given an initial allowable equal to the 

unallocated per-well basis allowable until the production test has been 

performed with the results reported to the Conservation Division on Form 1013. 

The allowable shall be effective for a period not longer than 30 days from 

completion of the well. No further allowable shall be assigned to the well 

until compliance with this subsection.

(c) Until the operator submits the required test results for any excessive 

water exempt well or project, as provided in subsection (a), no allowable shall 

be assigned to the well or project. If said test results are filed late, the 
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 213 -

allowable shall be effective the first day of the following month after the 

Conservation Division accepts the test.

(d) All initial tests shall be conducted as set forth in (a) of this 

Subsection.

(e) Annual testing shall not be required except as provided in OAC 165:10-1-6.

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]

165:10-15-18. Production tests and reports for reservoir dewatering oil spacing 

units

(a) Effective date for oil allowable. To establish the commencement date of 

an allowable for an oil well in a reservoir dewatering oil spacing unit, the 

operator shall file Forms 1002A and 1013, in lieu of the Form 1029A, with the 

Commission according to OAC 165:10-13-3 within thirty (30) days after the 

completion date of the well. The allowable will commence on the date of first 

production.

(b) Qualification for reservoir dewatering unit. Proof of fifty percent (50%) 

water saturation presented at the time of a hearing to establish dewatering oil 

spacing may entail calculations from logs or core data from wells within the 

common source of supply covered by the application or an analogous common 

source of supply, or an actual production test from a well in the common source 

of supply covered by the application. To qualify for the reservoir dewatering 

spacing unit allowable provided on Appendix J, the Form 1013 must provide data 

that verifies that the water-oil ratio is greater than 1:1. If the water-oil 

ratio is less than 1:1, then the oil allowable shall be the appropriate 

allowable for the depth of the top of the formation and the maximum acreage 

provided in Appendix A. 

(c) Allowable rate not provided for in Appendix J. To establish an allowable 

other than that specified in Appendix J, the operator shall file a Form 1030 

with the Commission to adjust the allowable.

(d) Record of annual production rates. The operator shall maintain production 

records on an annual basis. Operators shall make these records available to 

the Conservation Division staff upon the request of the Manager of the 

Technical Department. Annual testing shall not be required except as provided 

in OAC 165:10-1-6.

[SOURCE: Amended in Rule Making 200100009, eff 7-1-02]
OAC 165:10-15 Corporation Commission

Eff. 8-27-15

- 214 -

[BLANK PAGE]
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 215 -

SUBCHAPTER 17. GAS WELL OPERATIONS AND PERMITTED PRODUCTION

Section

165:10-17-1. Gas production from gas pools [RESERVED]

165:10-17-2. Classification of gas pools 

165:10-17-3. Effective date of allowables 

165:10-17-4. Standard gas measurement law 

165:10-17-5. Meters and recorders 

165:10-17-6. General well testing requirements 

165:10-17-7. Well tests 

165:10-17-8. Allocated pools 

165:10-17-9. Special allocated gas pools 

165:10-17-10. Unallocated pools [RESERVED]

165:10-17-11. Maximum permitted rates of production for unallocated gas wells

165:10-17-12. New proposed well classification for the priority schedule

165:10-17-13. Use of gas for carbon black 

165:10-17-14. Waste of tail gas at gasoline plants 

165:10-17-15. Gas removed from storage 

165:10-17-16. Reports 

165:10-17-1. Gas production from gas pools [RESERVED]

165:10-17-2. Classification of gas pools

(a) Types of gas pools. Each gas pool shall be classified by the Commission 

into one of the following categories:

(1) Allocated Gas Pool.

(2) Special Allocated Gas Pool.

(3) Unallocated Gas Pool.

(b) Treatment of gas well in an oil pool. If a well in an oil pool is 

classified as a gas well for allowable purposes, the well shall be treated as 

if it were in an unallocated gas pool, unless the well is subject to pool 

rules which establish allowables by volumetric withdrawal.

(c) Allocated gas wells. 

(1) Classification of pool by order. Upon application, notice, and 

hearing, the Commission may issue an order establishing allowables for gas 

wells in a pool by the allocated gas pool rules in 165:10-17-8.

(2) Status of an oil well reclassified as a gas well. If a well 

classified as an oil well in an allocated gas pool is reclassified as a gas 

well for allowable purposes, the well shall be subject to allocated gas 

pool rules.

(3) Termination of allocated status. Each allocated gas well shall be 

subject to allocated gas pool rules until:

(A) The Commission establishes special allocated gas pool rules for the 

common source of supply.

(B) The well is reclassified as an oil well for allowable purposes.

(C) The Commission issues an order reclassifying the well as an 

unallocated gas well.

(D) The well becomes the only gas well in the pool.

(E) The well is abandoned.

(d) Special allocated gas pools. Each gas pool for which special pool 

allocation rules (field rules) are or have been established by the Commission 

shall be classified as a special allocated gas pool. Each gas well in a 

special allocated gas pool shall be referred to as a special allocated gas 

well for allowable purposes.

(e) Unallocated gas pools. Each gas pool not classified as an allocated gas 

pool or as a special allocated gas pool shall be classified as an unallocated 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 216 -

gas pool. Each gas well in an unallocated gas pool shall be referred to as an 

unallocated gas well for allowable purposes.

165:10-17-3. Effective date of allowables

A gas well shall be assigned an allowable as of the date it is connected 

into a pipeline and the first delivery is made if the Notice of Intention to 

Drill (Form 1000) is valid, the Completion Report (Form 1002A) is filed with

attachments, if required, and all required tests are run within 30 days from 

the date of first sales and are filed within 45 days of the date of first 

sales, and special reports have been filed with the Conservation Division.

[SOURCE: Amended in Rule Making 980000033, eff 7-1-99]

165:10-17-4. Standard gas measurement law

 Sections 471 through 477, inclusive, of Title 52, Oklahoma Statutes 

Annotated, cited as the "Standard Gas Measurement Law", are hereby adopted as 

rules of the Commission as fully as if set out verbatim herein.

165:10-17-5. Meters and recorders

(a) Requirement of a gas meter and recorder.

(1) For allowable, allocation or custody transfer purposes, each well 

producing natural gas other than a shut-in gas well shall have a gas meter 

and recorder for the gathering line; provided, if two or more wells share a 

single allowable, a single meter and recorder may be used to measure gas 

production, unless a special order of the Commission or either 165:10-13-9 

or 165:10-3-39 require allocation of gas production on a per well basis.

(2) For purposes of (1) of this subsection, the term "recorder" refers to 

a circular gas chart recorder or other type of recording device which has 

been mutually agreed upon by the gas seller and the gas purchaser.

(3) For purposes of (1) of this subsection, an offsite recorder shall be 

permitted provided:

(A) There is compliance with the requirements of (2) of this 

subsection.

(B) The recording device is made available for inspection by the

Conservation Division to determine that the recorder is functioning 

properly.

(4) Offsite recordation under (1) and (3) of this subsection shall be 

treated as wellsite metering for purposes of the reporting requirements of 

165:10-1-47.

(5) Use of electronic gas measurement and recording devices that meet 

industry standards of (b)(2) of this Section are permitted for allowable, 

allocation, custody transfer, and well testing.

(b) Standards for meters and recorders.

(1) Each meter and recorder shall be properly constructed, maintained, 

repaired, and operated to continually and accurately register the quantity 

of gas produced from the well into a gathering line.

(2) The meter and recorder shall be installed, used, and operated 

according to the natural gas industry standards and guidelines promulgated 

by the American Gas Association, the American Petroleum Institute, and the 

Gas Processors Association, in effect at the time of installation of the 

meter and recorder. If there are conflicting standards, then the most 

current American Petroleum Institute standard shall apply.

(c) Prohibited meter bypasses. For each meter measuring production at the 

wellsite, use of piping to bypass the meter is prohibited. Gas meters with 

internal bypasses are permitted.

(d) Reporting of estimated volume if the meter or recorder fails.

(1) Seventy-two hours to repair equipment. If a meter or recorder at the 

wellsite malfunctions, then the malfunctioning equipment shall be repaired 

within 72 hours after discovery of the malfunction.
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 217 -

(2) Reporting of estimated volumes while the meter or recorder is down. 

If the well continues to produce gas while the meter or recorder is 

malfunctioning or being repaired, estimated gas volumes shall be reported 

to the Conservation Division for purposes of 165:10-1-47.

[Source: Amended at 12 Ok Reg 2017, 7-1-95]

165:10-17-6. General well testing requirements

(a) All single-point and multi-point potential tests shall be calculated for 

all non-exempt gas wells in a uniform manner with respect to the following:

(1) The potential shall be the calculated wellhead absolute open flow 

potential of the well determined by obtaining a static column wellhead 

flowing pressure and shall indicate the capacity of the well to produce 

against zero psia at the wellhead.

(2) All pressures used in test calculations shall be corrected to pounds 

per square inch absolute, using 14.4 psia as the average barometric 

pressure.

(3) The static column wellhead pressure, either measured or calculated as 

reported in the potential test, shall be no more than 90 percent of the 

wellhead shut-in pressure. If data cannot be obtained in accordance with 

the foregoing provisions, an assumed static column wellhead pressure of 90 

percent of the wellhead shut-in pressure shall be used to calculate the 

results of the test. This paragraph supersedes any contrary provision in 

special pool rules.

(b) The operator of a well shall be responsible for testing the well and 

submitting the test results to the Conservation Division. The results of a 

potential test shall be filed with the Conservation Division on Form 1016. If 

the operator wishes to obtain a copy of the approved Form 1016, he shall 

enclose with the original form a self-addressed stamped envelope and one 

additional copy of the test and/or form. The Conservation Division shall 

acknowledge such requests within 15 days, stating either the date of 

acceptance of the test results or rerunning the original test if it has been 

rejected. If any order or rule of the Conservation Division requires 

witnessing of a test, the operator of the well shall be responsible for 

securing the presence of an authorized Conservation Division representative to 

witness the test and sign the Form 1016 for the test.

(c) Unless otherwise prescribed by special pool rules, field testing 

procedure shall be performed in accordance with the procedures set out in 

Oklahoma Corporation Commission Manual of Back-Pressure Testing of Gas Wells, 

Parts I and II, utilizing the specified tables in the Interstate Oil and Gas 

Compact Commission Manual of Back-Pressure Testing. A gas turbine meter may 

be used in lieu of an orifice meter for flow measurements in gas well testing.

(d) The initial test for all gas wells shall be run into the pipeline within 

30 days and test results filed within 45 days after the date of first sales of 

gas. Any test filed after the 45 day limit will not be made effective until 

the first of the month following the date of acceptance of the test. With 

regard to initial tests for special allocated gas wells, the operator of the 

well shall provide twenty-four (24) hours notice to the Conservation Division 

of its intent to run an initial test in order to give the Conservation 

Division the opportunity to witness said test, but in no case shall the 

operator be precluded from performing said test and filing the results as 

provided for in subsection (b). Initial tests for special allocated gas 

wells need not be witnessed, nor signatures obtained, if witnessed, in order 

for the Conservation Division to assign an allowable to said well. Initial 

tests for unallocated gas wells with calculated open flow of less than two 

million cubic feet per day are exempt from witnessing by Conservation Division 

personnel under 165:10-17-7(b)(1).

(e) The annual test for all non-exempt gas wells shall be run into a pipeline 

in accordance with this Section or applicable pool rules. Any annual test for 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 218 -

a well in a special allocated pool, filed late shall not be made effective 

until the first of the month following the date of acceptance of the test.

(g) Wells in allocated pools shall be tested in accordance with the 

requirements for wells in unallocated pools, unless superseded by specific 

field rules. Form 1016 shall be used to report shut-in pressure tests on 

wells in allocated and special allocated pools, except for the Guymon-Hugoton 

Pool #182 which shall use a form 1017 Deliverability Gas Test.

[SOURCE: Amended at 16 Ok Reg 2206, eff 7-1-99 (RM 980000033); Amended at 25 

OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-17-7. Well tests

(a) Wells in special allocated pools.

(1) An initial test shall be filed for each newly completed gas well in 

each special allocated pool. The well shall be tested into a pipeline no 

later than 30 days after the date of the first sale of gas. Test procedures 

shall be those specified in the applicable pool rules subject to the uniform 

requirements of 165:10-17-6.

(2) An annual test shall be filed in accordance with the requirements of 

the applicable pool rules, subject to the following provisions specific to 

the Guymon-Hugoton special allocated pool.

(3) Wells in the Guymon-Hugoton special allocated pool.

(A) The Conservation Division staff will not be required to witness any 

well test on any well in the Guymon-Hugoton special allocated gas pool 

unless requested to do so by an offset operator. Operators have a right 

to witness any well test on any well offsetting said operator’s well in 

the pool. Operators of offsetting wells will be given sufficient prior 

notice of testing to allow for a representative to be present to witness 

testing, and will be provided access to the designated witness throughout 

testing.

(B) Wells in the Guymon-Hugoton special allocated gas pool which are not 

capable of producing 450 Mcf/day will be exempt from biannual 

deliverability tests. Operators shall have the right to elect to receive 

the minimum allowable by deciding not to conduct well deliverability 

tests on any such wells in the pool. No well shall be exempt from the 

annual wellhead shut-in pressure test requirements. For the purpose of 

the annual wellhead shut-in pressure test, the shut-in pressure shall be 

measured after the well has been shut-in for approximately 48 hours. In 

no case shall the well have been shut-in for less than 44 hours at the 

time the shut-in pressure is taken.

(b) Wells in unallocated pools.

(1) Testing of newly completed or newly recompleted wells.

(A) An initial test shall be submitted to the Conservation Division for 

each newly completed gas well or recompleted gas well involving a new 

formation in an unallocated gas pool under 165:10-17-2. The well shall 

be tested into a pipeline no later than 30 days after the date of first 

sale of gas into a pipeline. The flow period for the initial test shall 

be 24 hours.

(B) It shall not be necessary for the operator to submit the initial 

flow potential test for an unallocated well with a maximum flow rate of 

less than the minimum allowable. Only a current 24-hour wellhead shut-in 

pressure is required, unless otherwise requested by the Commission. A 

copy of the Form 1002A Completion Report may be submitted in lieu of Form 

1016 to establish the minimum allowable, provided the section on the Form 

1002A Completion Report requesting a minimum gas allowable is explicitly 

marked, and the following items are reported:

(i) current 24 hour shut-in pressure;

(ii) date of first sales and date of recompletion, if applicable;

(iii) Oklahoma Tax Commission production unit number; and
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 219 -

(iv) name of reporting entity of monthly gas volumes for the well 

(either the purchaser/measurer, or self-reporting operator). If the 

required information is not provided on the Form 1002A Completion 

Report submitted to the Commission, an initial test on Form 1016 

containing the information must be filed with the Commission to 

establish an initial allowable for the well.

(C) An initial potential test is required to receive an allowable 

greater than a minimum allowable. If said initial test is taken between 

January 1 and April 30 of the calendar year, the test shall be used for 

allowable purposes for the remainder of that calendar year. If the 

initial test is taken between May 1 and December 31, the test shall be 

effective for the remainder of the current calendar year, and for the 

entire succeeding calendar year. A request to extend the time to test 

may be granted by the Conservation Division in order to recover fluids 

introduced into the well. The request shall be submitted in writing to 

the Conservation Division with the expected test date.

(2) Annual testing or retesting of established gas wells. A potential test 

to assign a new allowable for an initially tested well may be submitted on 

Form 1016 at any time after three months from the date of the initial test. 

A test run between January 1 and April 30 shall be effective for the 

remainder of that calendar year. A test run between May 1 and December 31 

shall be effective for the remainder of the current calendar year, and for 

the entire succeeding calendar year. The Director of the Conservation 

Division may require additional tests at any time. Tests become effective 

the first day of the month following acceptance of the test by the 

Conservation Division.

(A) Unless specifically requested by the Director of the Conservation 

Division, it shall not be necessary to run an annual potential test or 

retest for an established well having a flow rate of less than the 

minimum allowable.

(B) Upon expiration of a potential test, the well will revert to a 

minimum allowable status, unless superseded by a later potential test.

(C) If two or more potential tests are submitted for a well, and the 

effective periods of the tests overlap or conflict, the test having the 

greatest calculated open flow potential shall be utilized to determine 

the well's allowable for the overlapping period.

(3) One-point tests. The potential test required for each gas well in each 

unallocated pool shall use the one-point back pressure method and an assumed 

flow characteristic of 0.85 shall be used in establishing the wellhead 

absolute open flow. The test shall be governed by the requirements of OAC 

165:10-17-6.

(4) Durability of minimum allowable. Once an initial allowable is 

established for a well, that well shall be assigned at least a minimum 

allowable until such time the well is plugged, reclassified, recompleted or 

commingled into an additional formation, or is found to be in violation of a 

rule or order of the Commission. If a potential test is submitted for the 

well, that test will supersede the minimum allowable for the effective 

period of the test set out herein.

(5) Test exemptions for certain minimum wells.

(A) The following types of gas wells shall be exempt from initial and 

annual potential and shut-in tests:

(i) Minimum gas wells producing exclusively from coal bed methane 

formations.

(ii) Minimum gas wells producing from shale formations or including 

shale formations, if commingled.

(iii) Minimum gas wells using down hole pumps for artificial lift 

of produced liquids.

(B) For these exempt wells operators shall report the initial stabilized 

rate of production on Form 1002A “Completion Report” in lieu of reporting 

an initial test on Form 1016 “Backpressure test for Natural Gas Wells”. 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 220 -

(6) Minimum compliance. Each operator shall be responsible for 

conducting and submitting the required potential tests on the applicable 

form. All submitted tests must contain complete and accurate information. 

Permitted production rates will be granted only to those wells which meet 

this requirement and all other rules or orders of the Commission.

[SOURCE: Amended at 14 Ok Reg 2198, eff 7-1-97 (RM 97000002); Amended at Ok 

Reg 2165, eff 7-1-98 (RM 97000011); Amended at Ok Reg 2206, eff 7-1-99 (RM 

980000033); Added at 24 Ok Reg 183, eff 10-4-06 (emergency RM 200600013); 

Amended at 24 Ok Reg 1784, eff 7-1-2007 (RM 200700004); Amended at 25 OK Reg 

2187, eff 7-11-08 (RM 200800003); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001)]

165:10-17-8. Allocated pools

(a) The current monthly allowable for each allocated pool shall be equal to 

the total production from the pool during the current month.

(b) The current allowable for each capable drilling and spacing unit within 

the pool shall be that proportion of the pool allowable that the acreage of 

the drilling and spacing unit bears to the total developed acreage in the 

pool, adjusted in accordance with any order of the Commission imposing an 

allowable adjustment. The current allowable for each limited drilling and 

spacing unit shall be equal to the current production from the unit. A unit 

shall be deemed limited when its underage is cancelled under this Section 

until it thereafter produces a current allowable for any one month.

(c) Accrued underage shall be carried forward as a cumulative credit by 

adding it to the unit's current allowable until the underage has been 

produced. If the unit's cumulative underage exceeds six times the allowable 

assigned to it for the preceding January, all of the underage will be 

cancelled, the unit shall be classified as "limited", and the unit shall not 

thereafter accumulate underage until such time as the unit produces a current 

allowable for any one month. All cancelled underage shall be distributed to 

the capable drilling and spacing units within the pool in the proportion that 

the acreage of each unit bears to the total capable acreage in the pool, 

adjusted in accordance with any order of the Commission imposing an allowable 

adjustment. A capable unit shall be any nonlimited unit. Cancelled underage 

may be reinstated administratively by the Director of Conservation to any 

capable unit in an overproduced status within six months after cancellation by 

application on Form 1010. 

(d) Accrued overage shall be carried forward as a cumulative charge against 

the unit by subtracting it from the unit's current allowable until the overage 

has been made up. If the cumulative overage exceeds six times the current 

allowable assigned for the preceding January, the Director of Conservation 

shall notify the operator in writing, and the unit shall thereafter be 

permitted to produce not more than 25 percent of its current allowable until 

all of the overage in excess of six times the well's current allowable for the 

preceding January has been made up. In the event the operator fails to limit 

production as herein provided, the well shall be ordered shut-in by the 

Commission upon application of the Director of Conservation and after notice 

and hearing. 

(e) If a unit did not have a current allowable assigned to it on a full 

month's basis for the preceding January, the first current allowable assigned 

to the unit on a full month's basis shall be used as reference for the purpose 

of limiting underage and overage.

165:10-17-9. Special allocated gas pools

(a) Scope. This Section applies to special allocated gas pools except any 

special allocated gas pool with allowables based upon volumetric withdrawals.

(b) Minimum unit allowable of 150 mcf/d. For all special allocated gas pools 

except the West Cheyenne Upper Morrow, Purvis Chert, Guymon-Hugoton, Custer 

City N. Hunton, Sharon W. Morrow, Red Oak Fanshawe, Red Oak Red Oak, and Red 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 221 -

Oak Spiro, the minimum allowable for a drilling and spacing unit in the pool 

shall be 150 MCF/D regardless of the amount of any location exception penalty 

charged against a unit well. For purposes of this Section, the net minimum 

allowable shall be the gross minimum allowable adjusted for overage or underage 

according to this Section.

(c) Minimum unit allowable of 450 mcf/d for the Guymon-Hugoton pool.

(1) For the Guymon-Hugoton Special Allocated Gas Pool, minimum allowables 

shall be determined as follows: The minimum allowable shall be the lesser 

of 450 mcf/d or the drilling and spacing unit's capability. Capability 

shall be defined as the average of the highest three (3) of the last twelve 

(12) months of production. A drilling and spacing unit receiving a minimum 

allowable shall not accrue underage. The minimum allowables under this 

Section shall not affect the calculation of capable well allowables. The 

field monthly allowable shall be equal to total nominations and not adjusted 

for underage or overage.

(2) The deliverability standard pressure (DSP) to be used in the 

application of special allocated rules (field rules) shall be defined as 25 

pounds less than the average shut-in wellhead pressure of the pool.

(3) The Corporation Commission shall calculate and publish reports of 

allowable and production quarterly.

(d) Minimum unit allowable of 2,000 mcf/d for the Red Oak Fanshawe, Red Oak 

Red Oak, and Red Oak Spiro Pools. For the Red Oak Fanshawe, Red Oak Red Oak, 

and Red Oak Spiro Pools (Pool Nos. 456, 457 and 458) located in Latimer and 

LeFlore Counties, Oklahoma, the minimum allowable for a drilling and spacing 

unit in each pool shall be 2,000 mcf/d. For purposes of this Section, the net 

minimum allowable shall be the gross minimum allowable adjusted for overage or 

underage according to this Section.

(e) Double minimum allowable of 300 mcf/d.

(1) Compressor and application required. For all special allocated gas 

pools except the West Cheyenne Upper Morrow, Purvis Chert, Guymon-Hugoton, 

Custer City N. Hunton, Sharon W. Morrow, Red Oak Fanshawe, Red Oak Red Oak, 

and Red Oak Spiro, if a drilling and spacing unit has a minimum allowable

under (b) of this Section, the operator of a well in the drilling and 

spacing unit may obtain for the unit a double minimum allowable regardless 

of any location penalty against a well by installing a compressor on a unit 

well and applying for a double minimum allowable under (2) of this 

subsection.

(2) Request for administrative approval. To apply for a double minimum 

allowable, the operator shall submit to the Manager of Production Allowables 

for the Conservation Division a letter requesting a double minimum allowable 

and stating the factual basis for the request and the legal description of 

the well with the compressor.

(f) Basic allowable.

(1) Use of basic allowable for determining overage and underage. For 

purposes of determining the amount of overage or underage accrued by a well 

or drilling and spacing unit, the Conservation Division shall establish on a 

yearly basis a status factor known as the basic allowable.

(2) Apportionment of basic allowable.

(A) Increased density unit without apportionment of the allowable. If 

neither OAC 165:10-13-9 nor an order of the Commission require specific 

allocation of the unit allowable to each unit well, overage and underage 

shall be carried on a unit basis.

(B) Increased density unit with ratable allowables. If either OAC 

165:10-13-9 or an order of the Commission require specific allocation of 

the unit allowable to each unit well, overage and underage shall be 

carried on a per well basis. For purposes of computing overage and 

underage, the basic allowable shall be apportioned to each unit well 

using the formula for determining each well's ratable allowables for the 

applicable month under (3) of this subsection. The term “ratable 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 222 -

allowables” refers to a well's share of the unit allowable under the

formula apportioning the allowable amongst the unit wells.

(3) Computation of the basic allowable. Except as provided in (C) of this 

paragraph for basic allowable changes, the basic allowable for the calendar 

year shall be computed as follows:

(A) For all pools except the Red Oak Pools. For all pools except the 

Red Oak Fanshawe, Red Oak Red Oak, and Red Oak Spiro, the basic allowable 

shall equal the drilling and spacing unit's January allowable for the 

calendar year.

(B) For the Red Oak Pools. For the Red Oak Fanshawe, Red Oak Red Oak, 

and Red Oak Spiro, the basic allowable shall equal the drilling and 

spacing unit's March allowable for the calendar year.

(C) Changes in the basic allowable.

(i) Test exempt minimum allowable. If a drilling and spacing unit 

receives test exempt minimum allowable status as provided in this 

Section, then the basic allowable shall be a minimum allowable.

(ii) Test exempt double minimum allowable. If a drilling and spacing 

unit receives a test exempt double minimum allowable as provided in 

this Section, then the basic allowable for the unit shall be a double 

minimum allowable.

(iii) Retests. If the well operator submits to the Conservation 

Division a retest which is approved by the Conservation Division, then 

the Conservation Division shall recompute the basic allowable using 

the retest. Retests are permitted at any time and become effective 

the first day of the month after acceptance by the Conservation 

Division.

(g) Determination of overage and underage.

(1) Overage.

(A) Drilling and spacing unit without ratable allowables. If no well in 

a drilling and spacing unit is subject to a ratable allowable, the 

current monthly allowable shall be compared with the second prior month's 

unit production. Production in excess of the current monthly allowable 

is overage. Aside from any adjustment to the pool allowable required by 

pool rules, overage shall not reduce any subsequent monthly allowable 

until accumulated overage exceeds the applicable overage limit under (h) 

of this Section.

(B) Drilling and spacing unit subject to ratable allowables. If any 

well in a drilling and spacing unit is subject to a ratable allowable, 

the current monthly ratable allowable for the well shall be compared with 

the second prior month's production from the well. Production in excess 

of the ratable allowable is overage. Aside from any adjustment to the 

pool allowable required by pool rules, the well's overage shall not 

reduce any subsequent monthly ratable allowable until accumulated overage 

exceeds the well's overage limit under (h) of this Section.

(2) Underage.

(A) Drilling and spacing unit without ratable allowable. If no well in 

a drilling and spacing unit is subject to a ratable allowable under OAC 

165:10-13-9, the current monthly allowable for the unit shall be compared 

with the second prior month's unit production. If production is less 

than the allowable, the difference between the production and the unit 

allowable is underage. Aside from any adjustment to the pool allowable

required by pool rules, only reinstated cancelled underage under (k) of 

this Section shall increase any subsequent monthly allowable.

(B) Drilling and spacing unit with ratable allowables. In a drilling 

and spacing unit with ratable allowables, the current monthly ratable 

allowable for a well shall be compared with the second prior month's 

production from the well. If production was less than the current 

monthly ratable allowable, the difference between the production and the 

ratable allowable is underage. Aside from any adjustment to the pool 

allowable required by pool rules, only reinstated cancelled underage 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 223 -

under (k) of this Section shall increase any subsequent monthly ratable 

allowable for the well.

(h) Overage limits.

(1) For all pools Except the Red Oak Fanshawe, Red Oak Red Oak, and Red Oak 

Spiro. For all pools except the Red Oak Fanshawe, Red Oak Red Oak, and the 

Red Oak Spiro, the overage limit is six times:

(A) The basic allowable for the drilling and spacing unit, if the 

overage carried on a unit basis; or

(B) The well's share of the basic allowable for the drilling and spacing 

unit, if the well receives a ratable allowable.

(2) For the Red Oak Fanshawe, Red Oak Red Oak, and Red Oak Spiro Pools. 

For the Red Oak Fanshawe, Red Oak Red Oak, and Red Oak Spiro Pools, the 

overage limit is 168 times:

(A) The basic allowable for the drilling and spacing unit, if the 

overage is carried on a unit basis; or

(B) The well's share of the basic allowable for the drilling and spacing 

unit, if the well receives a ratable allowable.

(3) Mandatory curtailment for excessive overage.

(A) Single well drilling and spacing unit. If accumulated overage from 

a single well drilling and spacing unit exceeds the applicable overage 

limit, production from the unit shall be curtailed to 25 percent of the 

monthly allowable until accumulated overage is reduced below the overage 

limit.

(B) Multiple well unit without ratable allowables. In a multiple well 

drilling and spacing unit without ratable allowables, if accumulated 

overage for the unit exceeds the applicable overage limit, the unit 

production shall be curtailed to 25 percent of its monthly allowable 

until the accumulated overage is reduced below the overage limit.

(C) Multiple well unit with a ratable allowable. In a multiple well 

drilling and spacing unit with one or more wells subject to a ratable 

allowable, if the accumulated overage for a well exceeds its overage 

limit, production from the well shall be curtailed to 25 percent of its 

monthly ratable allowable until the well's accumulated overage is reduced 

below its overage limit.

(i) Underage limits.

(1) For the Red Oak Fanshawe, Red Oak Red Oak, and Red Oak Spiro Pools. 

For the Red Oak Fanshawe, Red Oak Red Oak, and Red Oak Spiro Pools (Pool 

Nos. 456, 457 and 458) located in Latimer and LeFlore Counties, Oklahoma, 

the underage limit is three times the status factor for:

(A) The drilling and spacing unit,

(i) If the unit has only one well, or

(ii) If the unit has multiple wells but no unit well has a ratable 

allowable; or

(B) The well, if a well has a ratable allowable.

(2) For all other special allocated gas pools subject to this Section. For 

all other special allocated gas pools subject to the Section, the underage 

limit is six times the status factor for:

(A) The drilling and spacing unit, if the status factor is determined on 

a unit basis; or

(B) The well, if the well is subject to a ratable allowable.

(j) Cancellation of underage.

(1) Underage in excess of the underage limit. If accumulated underage 

exceeds the applicable underage limit, the accumulated underage shall be 

cancelled.

(2) Subsequent underage. After cancellation, underage shall not accrue 

until after:

(A) The drilling and spacing unit produces a current monthly allowable, 

if the unit wells share a unit allowable; or

(B) A well with a ratable allowable produces a current monthly ratable 

allowable.
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 224 -

(k) Reinstatement of cancelled underage.

(1) The operator may apply for reinstatement of cancelled underage by:

(A) An application for administrative approval on Form 1010, if filed 

within six months after cancellation of underage; or

(B) Application, notice, and hearing under OAC 165:5-7-1.

(2) Reinstated cancelled underage shall be available to increase the 

monthly allowable or ratable allowable for up to one year without 

cancellation. If reinstated underage is cancelled, the operator may reapply 

under (1) of this subsection.

(3) For the Guymon-Hugoton special allocated gas pool, the operator of any 

drilling and spacing unit in such pool which unit has accumulated cancelled 

underage credited thereto on the records of the Commission prior to July 1, 

1998 shall have until January 1, 2000 to file an application with the 

Commission pursuant to OAC 165:5-7-1 for the reinstatement of such 

accumulated cancelled underage as credited to such unit prior to July 1, 

1998. Upon the filing of such an application, the cause seeking 

reinstatement of such accumulated cancelled underage shall be diligently 

prosecuted. In such proceeding for the reinstatement of such accumulated 

cancelled underage credited to such drilling and spacing unit prior to July 

1, 1998, the Commission shall determine the portion of such accumulated 

cancelled underage which is proper and valid under the special pool 

allocation rules (field rules) applicable to the Guymon-Hugoton special 

allocated gas pool and shall reinstate only such portion that is determined 

to be proper and valid under such special pool allocation rules (field 

rules). If an application for reinstatement of any such accumulated 

cancelled underage credited to a drilling and spacing unit on the records of 

the Commission prior to July 1, 1998 is not filed with the Commission on or 

before January 1, 2000, such accumulated cancelled underage shall be 

permanently deleted from the records of the Commission and shall not 

thereafter be able to be reinstated or used for any other purpose under the 

special pool allocation rules (field rules) applicable to the Guymon-Hugoton 

special allocated gas pool. 

(l) Effect of reinstatement of underage on pool allowables. If cancelled 

underage has been distributed among the capable wells in the pool, reinstated 

underage shall not be deducted for the allowables of the capable wells which 

received distributed cancelled underage.

(m) Test exempt status.

(1) No allowable without test. For all pools except West Cheyenne Upper 

Morrow and Purvis Chert, no allowable shall be assigned unless:

(A) Single well drilling and spacing unit. The operator submits the 

required test or the unit has test exempt status under this Section.

(B) Multiple well drilling and spacing unit. In a multiple well 

drilling and spacing unit, the operator of at least one well in the unit 

submits the required test in accordance with applicable pool rules or the 

unit is granted test exempt status under this Section.

(2) Automatic test exempt status.

(A) For the West Cheyenne Upper Morrow and Purvis Chert Pool. For the 

West Cheyenne Upper Morrow and Purvis Chert, a drilling and spacing unit 

shall have test exempt status as follows:

(i) Single well drilling and spacing unit. In a single well drilling 

and spacing, the well operator does not submit either an initial or an 

annual test.

(ii) Multiple well drilling and spacing unit. In a multiple well 

drilling and spacing unit, none of the well operators in the unit 

submit either an initial or annual test. A test exempt drilling and 

spacing unit on the West Cheyenne Upper Morrow and Purvis Chert Pools 

shall have a minimum allowable under the applicable orders 

establishing and modifying pool rules as opposed to (b) of this 

Section.
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 225 -

(3) Test exempt status upon requests for all other pools. For all other 

pools except Guymon-Hugoton a drilling and spacing unit shall be test exempt 

upon written request to the Conservation Division if the potential for the 

unit does not exceed:

(A) The applicable minimum allowable under this Section.

(B) A double minimum allowable, if the Conservation Division has granted 

a double minimum to the unit.

(4) Termination of requested test exempt status.

(A) Automatic termination. Requested test exempt status shall terminate 

upon:

(i) Submission of a retest. Submission of a retest showing that the 

well has a potential in excess of a test exempt allowable, or;

(ii) Overproduction.

(I) Single well drilling and spacing unit. If gas production from 

a single well drilling and spacing unit exceeds a test exempt

allowable during any month while the well has test exempt status, 

the unit shall lose test exempt status beginning with next month 

following the month with overproduction.

(II) Multiple well drilling and spacing unit. If total gas 

production from a multiple well drilling and spacing unit exceeds 

the minimum allowable during any month while the unit has test 

exempt status, the unit shall lose test exempt status beginning 

with the next month following the month with overproduction.

(B) Reinstatement of test exempt status after automatic termination. 

After termination of test exempt status for overproduction, the 

Conservation Division shall not reinstate test exempt status until:

(i) The operator requests test exempt status; and

(ii) The allowable year during which overproduction occurred expires.

(n) Suspension of well allowable calculations under field rules when market 

demand exceeds supply for Red Oak Fanshawe, Red Oak Red Oak, and Red Oak Spiro 

pools. The Commission, upon finding in the market demand hearing that the 

supply of natural gas from the various separate common sources of supply 

included in and covered by the Red Oak Fanshawe Pool 456, the Red Oak Red Oak 

Pool 457, and the Red Oak Spiro Pool 458 is less than such market demand, shall 

suspend the special field rules calculations for determining allowables for 

wells in such pools and such suspension shall be effective until such time that 

the supply of natural gas from these pools exceeds the market demand for such 

natural gas, and during such suspension the gas allowables for wells in such 

pools shall be determined under this rule. See Order No. 571714 which issued 

in Cause CD No. 200902831.

(1) For existing wells, granting separate allowables and establishing 

overage status as of the effective date of this rule. Each well in 

existence as of the effective date of this rule which is then completed in 

one or more of the Red Oak Fanshawe Pool 456, Red Oak Red Oak Pool 457, and 

the Red Oak Spiro Pool 458 shall be deemed an Existing Well for purposes of 

this rule. Each Existing Well shall receive a full separate allowable. Any 

total net overage including cancelled underage, accumulated by and assigned 

to any such drilling and spacing unit, shall be distributed and assigned in 

equal proportions to the Existing Wells in such drilling and spacing unit. 

Any such net overage so assigned to an Existing Well shall hereinafter be 

made up from the separate allowable for such well under the provisions of 

the Commission’s rules applicable to a well in an unallocated gas pool.

(2) Test requirements and determination of unit allowables for new and 

existing wells. Any new well drilled and completed or any Existing Well recompleted into one or more of the Red Oak Fanshawe Pool 456, Red Oak Red 

Oak Pool 457, and Red Oak Spiro Pool 458 after the effective date of this 

rule, shall be deemed a New Well for purposes of this rule. The allowable 

for any New Well or Existing Well as to the applicable pool covered hereby 

shall be determined using the same allowable formula used by the Commission 

for the determination of a gas allowable for a capable well or a minimum 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 226 -

well in an unallocated gas pool. EXCEPTION: Any Existing Well which is a 

minimum well shall be exempt from the annual test requirement. If any 

drilling and spacing unit formed for any common source of supply in any pool 

covered by this rule contains more than one New Well completed in such 

common source of supply and such New Wells are classified as gas wells, such 

New Wells shall share a single unit gas allowable in the same manner as any 

other gas wells in the same drilling and spacing unit in an unallocated gas 

pool, unless the Commission grants a separate gas allowable as to production 

from such pool after proper notice and hearing. 

(o) Suspension of well allowable calculations using field rules when market 

demand exceeds supply for the Guymon-Hugoton Pool 182. The Commission, upon 

finding that the supply of natural gas from Guymon-Hugoton Pool 182 common 

source of supply is less than the market demand and that the expectations for 

supply to continue to be less than the market demand as determined in the 

market demand hearing, will suspend special field rule calculations for 

determining allowables until such time that the supply of natural gas from this 

pool exceeds the market demand. See Order No. 571714 which issued in Cause 

CD No. 200902831.

(1) For allowable purposes, wells which produce less than 450 mcfg per day 

must conduct a 48 hour shut-in pressure test according to pool rules. For 

reporting purposes, an operator may submit these data for several wells as 

an attachment to Form 1017 providing operator name, date of test, well name, 

location and api number for each well. 

(2) For allowable purposes, wells which produce more than 450 mcfg per day 

must conduct a deliverability test according to pool rules and submitted on 

Form 1017.

(3) Upon submission of the proper test, the allowable shall be the well’s 

capability to produce.

(p) Suspension of well allowable calculations using field rules when all wells 

in the West Cheyenne Upper Morrow gas pool produce less than the pool minimum 

allowable and the market demand exceeds supply. The Commission, upon finding 

that the supply of natural gas from West Cheyenne Upper Morrow Pool 136 common 

source of supply is less than the market demand and that the expectations for 

supply to continue to be less than the market demand as determined in the 

market demand hearing, will suspend special field rule calculations for 

determining allowables and well allowables will be the wells’ capacity to 

produce up to 2000 mcf per day. See Order No. 571714 which issued in Cause CD 

No. 200902831. Each well will be exempt from the annual test requirement.

[SOURCE: Amended in Rule Making 970000011, eff 7-1-98; Amended in Rule Making 

980000033, eff 7-1-99; Amended in Rule Making 200100006, eff 7-1-01; Amended in 

Rule making 200400006, eff 7-1-04; Amended at 26 Ok Reg 2498, eff 7-11-09 (RM 

200900001); Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003)]

165:10-17-10. Unallocated pools [RESERVED]

165:10-17-11. Maximum permitted rates of production for unallocated gas wells

(a) Scope.

(1) This Section shall apply to each gas well in unallocated status except 

as otherwise provided by Commission order. The Commission may establish 

different production rates by:

(A) Location exception order.

(B) Establishment of pool rules for the common source of supply.

(C) Other order adjusting gas production from the well.

(2) For purposes of this Section, the term "well" shall include any 

drilling and spacing unit with multiple unallocated gas wells, which do not 

receive separate maximum permitted rates of production by Commission order.

(3) For the purposes of this Section, the term "allowable formula" shall 

mean the formula used by the Commission for the determination of the daily 

rates for capable and minimum wells.
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 227 -

(4) For purposes of this Section, the term "capable well" shall refer to 

those unallocated gas wells having a wellhead absolute flow potential of 

2000 mcf/d or greater. All other wells are minimum wells.

(5) For purposes of this Section, the term "daily natural flow" means the 

wellhead absolute open flow potential determined in the manner described in 

OAC 165:10-17-6 and OAC 165:10-17-7.

(b) Commission authority and responsibility. Production shall be governed by 

the provisions of 52 O.S. Section 29. Pursuant to said statute, the 

Commission has the power and authority to adjust allowables to meet reasonable 

market demand. The Commission, upon its own application, after notice and 

hearing, shall establish allowables which may be greater or lesser than those 

set forth in 52 O.S. Section 29.

(c) Procedure.

(1) Allowables for wells other than those provided in subsections (a), 

(e), (f), and (g) of this Section shall be determined pursuant to a 

proration hearing held at least annually. The Commission may hold 

additional proration hearings at shorter intervals if necessary. At least 

15 days prior to scheduled annual hearings, the Commission shall publish in 

a newspaper of general circulation in Oklahoma County, the proposed 

allowable formula for the next proration period. The annual proration 

hearings shall be held at least 30 days prior to the proration period for 

which the allowable is being determined. Such hearing shall be for the 

purpose of gathering comments and hearing testimony from all interested 

parties concerning the determination of reasonable market demand for the 

next proration period. As a guideline, but not to the exclusion of any 

other information that the Commission deems pertinent, the following may be 

considered by the Commission in determining reasonable market demand and 

corresponding allowables:

(A) Production from prior years.

(B) Production from the most recent proration period.

(C) Wellhead open flow potentials.

(D) New wells, recompletions, temporarily abandoned wells and plugged 

wells.

(E) Gas which is available but is not being produced at the present 

time.

(F) Changes in existing gas markets, forecasts, and new markets for 

Oklahoma gas.

(G) State-wide gas production and the portion thereof attributable to 

unallocated gas wells.

(H) Overproduction and underproduction from the preceding proration 

period.

(2) After a proration hearing, the Commission shall publish in a newspaper 

of general circulation in Oklahoma County, the allowable formula, no later 

than 15 days prior to the proration period for which the allowable formula 

is determined.

(d) Emergency allowables.

(1) When the Commission determines that an emergency gas supply situation 

exists, the Commission may establish an emergency allowable. The emergency 

allowable shall provide for the protection of correlative rights including 

those relating to minimum wells and penalized wells.

(2) The Commission may extend or change the emergency allowable for as 

long as an emergency exists. However, any authorized extension of the 

emergency allowable shall be by order after notice and hearing.

(e) Exceptions. Upon application, notice, and hearing, the Commission may 

establish a different allowable for good cause shown.

(f) Exclusion for hardship and distressed wells. The allowable established 

under this Section shall not limit rates established by special order for 

those wells classified as hardship or distressed wells.
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 228 -

(g) Discovery gas well.

(1) For thirty (30) months from the date of first production, a discovery 

gas well, as defined in this subsection, subject to the provisions of this 

Section, shall have a production allowable which shall be the greater of one 

thousand three hundred (1,300) mcf/d or sixty-five percent (65%) of the 

absolute open flow (AOF) as specified by the Corporation Commission. Such 

discovery well allowable shall not be available for any discovery gas well 

wherein two (2) or more separate common sources of supply are commingled and 

one (1) common source of supply would not qualify a new gas well as a 

discovery gas well, as defined in this Section.

(2) Drilling and spacing units which are downspaced after June 1, 1997, 

shall not qualify for the discovery gas well allowable.

(3) For purposes of this subsection, “discovery gas well” shall mean a new 

gas well, which is not an off-pattern well, is the first well completed in a 

common source of supply within a drilling and spacing unit and is at least 

one (1) mile from all existing gas wells which are completed in the same 

common source of supply. In the absence of spacing, a discovery well shall 

be the first well in the governmental section completed in a common source 

of supply, provided that the discovery gas well shall not be drilled closer 

than one thousand three hundred twenty (1,320) feet from the boundaries of 

the governmental section and is at least one (1) mile from all existing gas 

wells which are completed in the same common source of supply.

(h) Exclusion for reservoir dewatering. Allowables shall not apply, 

regardless of unit size, in the instance of production of gas by reservoir 

dewatering to extract said gas from reservoirs having initial water 

saturations at or above fifty (50%) percent.

(i) Minimum compliance. 

(1) The Conservation Division shall monitor well production at least 

annually. The allowable for a well shall be based on the product of the 

number of days in the proration period, multiplied by the applicable 

allowable formula, provided that said product shall be reduced for 

overproduction as provided by this Section or by any penalty or limitation 

on production imposed by applicable Commission order.

(2) Any overproduction existing at the end of the calendar year shall be 

applied against the allowable for the next calendar year. Furthermore, the 

overproduced well shall be required to make up overproduction within the 

first six months of the next calendar year. If the overproduction is not 

made up within that time period, the flow rate shall not exceed ten percent 

of the then current allowable until the overproduction is made up.

[Source: Amended at 9 Ok Reg 3969, eff 8-28-92 (emergency); Amended at 10 Ok 

Reg 1275, eff 9-25-92 (emergency); Amended at 10 Ok Reg 1579, eff 5-13-93; 

Amended in Rule Making 97000002, eff 7-1-97; Amended in Rule Making 980000011, 

eff 7-1-98; Amended in Rule Making 200200017, eff 7-1-02; Amended at 25 OK Reg 

2187, eff 7-11-08 (RM 200800003); Amended at 30 Ok Reg 1041, eff. 7-1-13 (RM 

201300001)]

165:10-17-12. New proposed well classification for the priority schedule

(a) Any common purchaser as defined in 52 O.S. 1981, Section 240 shall 

purchase all the gas which may be offered for sale and which may reasonably be 

reached by its trunk lines or gathering lines, without discrimination in favor 

of one producer as against another or in favor of any one source of supply as 

against another, except as authorized by the Commission under (b) of this 

Section.

(b) In the interest of the prevention of waste and protection of correlative 

rights, the following priority schedule shall be implemented by any first 

purchaser of gas whenever the permitted production from all wells in any 

common source of supply in its system in this State, including gas which is 

processed, is in excess of that purchaser's reasonable market demand; 

provided, however, if the first purchaser does not contractually control 
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 229 -

wellhead production, the first taker of gas shall be responsible for 

implementation of the following priority schedule.

(1) Priority One - Hardship and distressed wells.

(2) Priority Two - Enhanced recovery wells.

(3) Priority Three - Wells producing casinghead gas and associated gas.

(c) With respect to all gas not identified in (b) of this Section, the 

collective market demand of multiple common purchasers on each pipeline system 

for natural gas production from each well and each common source of supply in 

this state shall be deemed adequate to meet statutory purchasing requirements 

unless the Commission, upon its own motion or upon verified application by any 

interested party and after notice and hearing, as hereinafter provided, shall 

determine that differing obligations shall be imposed upon any common 

purchaser in order to protect correlative rights, the interest of the public 

or otherwise meet the requirements of applicable law.

(d) When permitted production of gas from all Priority 1, 2, and 3 wells from 

which a purchaser or taker is required to take exceeds the market demand of 

said purchaser or taker, all reductions in gas purchases or takes from wells 

in each priority shall be ratable. All production from the lower priority 

wells shall be shut-in before production from any well in the next higher 

priority is curtailed.

(e) Any well which meets the definition of more than one priority shall be 

assigned the higher priority.

(f) When there is more than one purchaser or taker involved in the taking of 

gas from a well into any purchaser's system, all purchasers and takers within 

that system shall be responsible for compliance with this Section.

(g) Upon a verified application of the Director of the Conservation Division 

or any other person, the Commission, after notice and hearing, may determine 

if gas has been ratably purchased or taken from a common source of supply on a 

system-wide basis in accordance with this Section without avoidable waste and 

with equitable participation in production and markets by all operators and 

other interested parties.

(h) First purchasers or takers of gas produced from Priority 1, 2, or 3 

wells, who anticipate curtailing production from such wells, shall file by the 

twentieth day of each month nominations of requirements for gas to be 

purchased and/or used by them during the following month (Form 1004B). 

Nominations shall be made according to priorities established in (b) of this 

Section. Curtailments of production and acceptance of deliveries of gas shall 

be performed in accordance with (a) and (b) of this Section.

(i) Any interested party may file an application requesting that the 

Commission, for good cause shown, authorize limited deviation from the general 

priority schedule provided under (b) of this Section. The Commission, on its 

own motion, may initiate a review of the continued need for such a limited 

deviation. After notice and hearing, the Commission may authorize limited 

deviation upon finding that the same is necessary in order to prevent waste, 

protect correlative rights, and is otherwise required by the public interest 

or authorized by law.

[Source: Amended at 12 Ok Reg 2045, eff 7-1-95]

165:10-17-13. Use of gas for carbon black

 Gas may not be used for the manufacture of carbon black or similar products 

predominately carbon, except as specifically authorized by the Commission 

after notice and hearing.

165:10-17-14. Waste of tail gas at gasoline plants

 The duty, obligation, and jurisdiction of the Commission to prevent waste 

of tail gas where an additional market is available shall not be circumvented 

by any exclusive provisions in private contracts between the owners and the 

purchasers of tail gas.
OAC 165:10-17 Corporation Commission

Eff. 8-27-15

- 230 -

165:10-17-15. Gas removed from storage

 The rules relating to gas production from pools shall not apply to gas 

being removed from storage except and unless waste is involved.

165:10-17-16. Reports

 A calendar year shall constitute the accounting period for each unallocated 

gas well. At the end of each calendar year, the Conservation Division will 

mail an original and one copy of Machine Accounting Form 1007A (Unallocated 

Gas Well Survey) to the operator, and the operator shall complete and file the 

original form with the Conservation Division on or before the following 

February 15th and retain the copy for his own use.

[Source: Amended in Rule Making 200200017, eff 7-1-02]
OAC 165:10-19 Corporation Commission

Eff. 8-27-15

- 231 -

SUBCHAPTER 19. NATURAL GAS POLICY ACT DETERMINATION

[REVOKED]

165:10-19-1. Definitions [REVOKED]

165:10-19-2. Applications for NGPA determination [REVOKED]

165:10-19-3. Application for additional well in existing proration unit 

[REVOKED]

165:10-19-4. Notice of application; service of notice [REVOKED]

165:10-19-5. Procedures for protest, administrative consideration, and hearing 

[REVOKED]

165:10-19-6. Stripper well determination [REVOKED]

165:10-19-1. Definitions [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]

165:10-19-2. Applications for NGPA determination [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]

165:10-19-3. Application for additional well in existing proration unit 

[REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]

165:10-19-4. Notice of application; service of notice [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]

165:10-19-5. Procedures for protest, administrative consideration, and hearing 

[REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]

165:10-19-6. Stripper well determination [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]
OAC 165:10-19 Corporation Commission

Eff. 8-27-15

- 232 -

[BLANK PAGE]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 233 -

SUBCHAPTER 21. APPLICATIONS FOR TAX EXEMPTIONS

PART 1. TERTIARY RECOVERY PROJECT [REVOKED]

Section

165:10-21-1. Tertiary recovery project certification [REVOKED]

PART 2. ENHANCED RECOVERY PROJECT [REVOKED]

165:10-21-2. Gross production tax exemption for enhanced recovery project 

[REVOKED]

PART 3. HORIZONTALLY DRILLED PRODUCTION WELLS [REVOKED]

165:10-21-3. Qualification and application for exemption from the levy of gross 

production tax on horizontally drilled production wells [REVOKED]

PART 4. DELETERIOUS SUBSTANCES [REVOKED]

165:10-21-4. Recycling, reuse, and ultimate destruction of deleterious 

substances [REVOKED]

PART 6. PRODUCTION ENHANCEMENT PROJECTS 

165:10-21-21. General

165:10-21-22. Definitions

165:10-21-23. Qualification procedure

165:10-21-24. Rebates - Refund procedure

PART 7. RE-ESTABLISHMENT OF PRODUCTION FROM AN INACTIVE WELL 

165:10-21-35. General

165:10-21-36. Definitions

165:10-21-37. Qualification procedure

165:10-21-38. Rebates - Refund procedure

PART 8. DEEP WELLS 

165:10-21-45. General

165:10-21-46. Definitions [REVOKED]

165:10-21-47. Qualification procedure

165:10-21-47.1.Rebates - Refund procedure

165:10-21-48. Audit requirements [REVOKED]

165:10-21-49. Certificate of investment to be filed by the operator [REVOKED]

PART 9. NEW DISCOVERY WELLS

165:10-21-55. General

165:10-21-56. Definitions

165:10-21-57. Qualification procedure

165:10-21-58. Rebates - Refund procedure

165:10-21-59. Audit requirements [REVOKED]

PART 11. HORIZONTALLY DRILLED PRODUCING WELLS

165:10-21-65. General

165:10-21-66. Definitions

165:10-21-67. Qualification procedure

165:10-21-68. Rebates - Refund procedure

165:10-21-69. Time periods for exemption from gross production tax levied on 

horizontally drilled producing wells

PART 13. INCREMENTAL PRODUCTION FROM ENHANCED RECOVERY PROJECTS

165:10-21-75. General

165:10-21-76. Definitions

165:10-21-77. Qualification procedure

165:10-21-78. Recovery of costs allowed as payback factors

165:10-21-79. Responsibility for filing and payment of taxes
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 234 -

165:10-21-80. Expiration of exemption for incremental production

PART 14. PRODUCTION OF OIL, GAS OR OIL AND GAS FROM ANY WELL LOCATED WITHIN

 BOUNDARIES OF A THREE-DIMENSIONAL SEISMIC SHOOT

165:10-21-82. General

165:10-21-82.1.Definitions

165:10-21-82.2.Qualification procedure

165:10-21-82.3.Rebates - Refund procedure

165:10-21-82.4.Time periods for exemption from gross production tax levied on 

oil, gas or oil and gas production from a well located within 

boundaries of three-dimensional seismic shoot

PART 15. GENERAL PROVISIONS

165:10-21-85. Election of exemption

PART 17. SALES TAX EXEMPTION FOR ELECTRICITY AND ASSOCIATED DELIVERY 

ANDTRANSMISSION SERVICES SOLD FOR OPERATION OF RESERVOIR 

DEWATERING PROJECT AND/OR UNIT

165:10-21-90. General

165:10-21-91. Definitions

165:10-21-92. Qualification procedure

PART 19. STATE SALES TAX EXEMPTION FOR ELECTRICITY SOLD FOR OPERATION OF

ENHANCED RECOVERY METHODS ON A SPACING UNIT OR LEASE

165:10-21-95. General

165:10-21-96. Definitions

165:10-21-97. Qualification procedure

SUBCHAPTER 21. APPLICATIONS FOR TAX EXEMPTIONS

PART 1. TERTIARY RECOVERY PROJECT [REVOKED]

165:10-21-1. Tertiary recovery project certification [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2933, eff 7-11-96]

PART 2. ENHANCED RECOVERY PROJECT [REVOKED]

165:10-21-2. Gross production tax exemption for enhanced recovery project 

[REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2933, eff 7-11-96]

PART 3. HORIZONTALLY DRILLED PRODUCTION WELLS [REVOKED]

165:10-21-3. Qualification and application for exemption from the levy of gross 

 production tax on horizontally drilled production wells [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2933, eff 7-11-96]

PART 4. DELETERIOUS SUBSTANCES

165:10-21-4. Recycling, reuse, and ultimate destruction of deleterious

 substances [REVOKED]

[SOURCE: Revoked in rule making 200000009, eff 5-11-01]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 235 -

PART 6. PRODUCTION ENHANCEMENT PROJECTS

165:10-21-21. General

Exemption from the levy of gross production tax pursuant to 68 O.S. Section 

1001(G) on the incremental production which results from a production enhancement 

project with a project beginning date on or after July 1, 1994, and prior to 

July 1, 2020, shall be determined according to the provisions of this Part, which 

have been jointly adopted by the Oklahoma Corporation Commission and Oklahoma Tax 

Commission pursuant to 68 O.S. Section 1001(N)(1).

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 200000009, eff 5-11-01; Amended in Rule Making 200400006, eff 7-1-04; 

Amended at 24 Ok Reg 1809 (RM 200700004), eff 7-1-2007; Amended at 27 OK Reg 

2128, eff. 7-11-10 (RM 201000003); Amended at 29 OK Reg 950, eff. 7-1-12 (RM 

201200005); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-21-22. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

"Base production" means the average monthly amount of production for the 

twelve-month (12) period immediately prior to the commencement of the project or 

the average monthly amount of production for the twelve-month period immediately 

prior to the commencement of the project less the monthly rate of production 

decline for the project for each month beginning one hundred eighty (180) days 

prior to the commencement of the project. The monthly rate of production decline 

shall be equal to the average extrapolated monthly decline rate for the twelvemonth period immediately prior to the commencement of the project based on the 

production history of the well. If the well or wells covered by the application 

had production for less than the full twelve-month period prior to the filing of 

the application for the production enhancement project, the base production shall 

be the average monthly production for the months during that period that the well 

or wells produced.

"Effective date" means the project beginning date for the production 

enhancement project.

"Exemption period" means a period of twenty-eight (28) months from the date of 

first sale after completion of the production enhancement project.

"Incremental production" means the amount of crude oil, natural gas or other 

hydrocarbons which are produced as a result of the production enhancement project 

in excess of the base production.

"Production enhancement project" means: for production enhancement projects 

having a project beginning date on or after July 1, 1997, and prior to July 1, 

2020, "production enhancement project" means any workover as defined in this 

Section, recompletion as defined in this Section, reentry of plugged and 

abandoned wellbores, or addition of well or field compression.

"Recompletion" means: for production enhancement projects having a project 

beginning date on or after July 1, 1997, and prior to July 1, 2020, 

"recompletion" means any downhole operation in an existing oil or gas well that 

is conducted to establish production of oil or gas from any geologic interval not 

currently completed or producing in such existing oil or gas well within the same 

or a different geologic formation.

"Workover" means any downhole operation in an existing oil or gas well that is 

designed to sustain, restore or increase the production rate or ultimate recovery 

in a geologic interval currently completed or producing in said existing oil or 

gas well. For production enhancement projects having a project beginning date on 

or after July 1, 1997, and prior to July 1, 2020, "workover" includes, but is not 

limited to, the following: acidizing; reperforating; fracture treating; 

sand/paraffin/scale removal or other wellbore cleanouts; casing repair; squeeze 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 236 -

cementing; installation of compression on a well or group of wells or initial 

installation of artificial lifts on oil and/or gas wells, including plunger 

lifts, rod pumps, submersible pumps and coiled tubing velocity strings; 

downsizing existing tubing to reduce well loading; downhole commingling; bacteria 

treatments; upgrading the size of pumping unit equipment; setting bridge plugs to 

isolate water production zones; or any combination thereof. “Workover” shall 

not mean the routine maintenance, routine repair, or like-for-like replacement of 

downhole equipment such as rods, pumps, tubing, packers, or other mechanical 

devices.

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 97000025, eff 7-1-98; Amended in Rule Making 200000009, eff 5-11-01; 

Amended in Rule Making 200400006, eff 7-1-04; Amended at 24 Ok Reg (RM 

200700004), eff 7-1-2007; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 29 OK Reg 950, eff. 7-1-12 (RM 201200005); Amended at 32 

Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-21-23. Qualification procedure

The well operator or one of the working interest owners in the well, on behalf 

of the well operator and the other owners of the well, shall apply for 

qualification of the production enhancement project and incremental production, 

at the Oklahoma Corporation Commission on OCC Form 1534.

(1) OCC Form 1534 shall be completed in its entirety, and together with 

supporting documentation, shall be submitted to the Technical Services 

Department of the Conservation Division of the Oklahoma Corporation Commission 

for review. 

(2) If the Department approves the application, a copy of the approved 

application shall be available to the operator.

(3) If the application is denied or refused, or approval is delayed beyond 

sixty (60) days, the applicant may seek review by application, notice and 

hearing.

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 200600012, eff 7-1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003)]

165:10-21-24. Rebates - Refund procedure

(a) Request to Oklahoma Tax Commission for a tax refund. If the Oklahoma 

Corporation Commission approves the application, the operator or one of the 

working interest owners in the well, on behalf of the well operator and the other 

owners of the well, shall make its request for refund by letter to the Audit 

Division, Oklahoma Tax Commission. Such letter request shall state the reason 

for refund and the amount claimed and must be accompanied by the following:

(1) A copy of the application approved by the Corporation Commission 

certifying the well as a production enhancement project.

(2) A properly completed OTC Form 328 Gross Production 841/495 Refund 

Report.

(3) If the refund request is filed by any person other than the party named 

in the Oklahoma Corporation Commission application, a notarized affidavit, 

signed by the party named in the application must be filed, authorizing the 

applicant to apply for the refund.

(b) No rebate for production occurring prior to July 1, 2003; claim limitation. 

Effective July 1, 2014, no refund of gross production taxes shall be claimed for 

oil and gas production exempt from gross production taxes pursuant to 68 O.S. 

Section 1001(G) for production occurring prior to July 1, 2003. Claims for 

rebate filed with the Oklahoma Tax Commission shall be subject to limitations

pursuant to Title 68 O.S., Section 1001(L).
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 237 -

(c) Method of appeal. If the refund is denied, the applicant may file an appeal 

under the provisions of Title 68, Sections 227 and 228 of the Oklahoma Statutes.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended 

in Rule Making 200400006, eff 7-1-04; Amended in Rule Making 200600012, eff 7-

1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 32 

Ok Reg 767, eff. 8-27-15 (RM 201500001)]

PART 7. RE-ESTABLISHMENT OF PRODUCTION FROM AN INACTIVE WELL

165:10-21-35. General

Exemption from the levy of gross production tax pursuant to 68 O.S. Section 

1001(F) on the reestablishment of production from an inactive well shall be 

determined according to the provisions of this Part, which have been jointly 

adopted by the Oklahoma Corporation Commission and Oklahoma Tax Commission 

pursuant to 68 O.S. Section 1001(N)(1).

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 200000009, eff 5-11-01; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-21-36. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

"Effective date" means the date on which the reestablishment of production 

has occurred.

"Exemption period" means a period of twenty-eight (28) months from the date 

upon which production from an inactive well is reestablished.

"Inactive well" means a well which may be defined under one (1) of the 

following three (3) categories:

(A) A well which after July 1, 1994, experiences mechanical failure or loss 

of mechanical integrity, as defined by the Corporation Commission, including 

but not limited to, casing leaks, collapse of casing or loss of equipment in 

a wellbore, or any similar event which causes cessation of production, shall 

be considered an inactive well. For use within this sub-paragraph 

"mechanical failure" means a well which experiences mechanical failure or 

loss of mechanical integrity because of, but not limited to, casing leaks, 

collapse of casing or loss of equipment in a wellbore, or any similar event 

which results in a workover of the well and cessation of production as 

evidenced by the use of a workover rig or other mechanical device being 

placed over the well to repair the well or equipment. This applies to wells 

for which work to reestablish production began on or after July 1, 1994, and 

for which production is reestablished prior to July 1, 2020.

(B) A well on which work to reestablish production commenced on or after 

July 1, 1994, and for which production is reestablished on or after July 1, 

1997, and prior to July 1, 2020, that has not produced oil, gas or oil and 

gas for a period of not less than one (1) year as evidenced by the 

appropriate forms on file with the Oklahoma Corporation Commission 

reflecting the well’s status.

(C) A well on which work to reestablish production commenced on or after 

July 1, 1994, and for which production is reestablished prior to July 1, 

1997, that has not produced oil, gas or oil and gas for a period of not less 

than two (2) years as evidenced by the appropriate forms on file with the 

Oklahoma Corporation Commission reflecting the well's status.

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended in Rule Making 97000025, eff 7-1-98; Amended in Rule 

Making 200000009, eff 5-11-01; Amended in Rule making 200400006, eff 7-1-04; 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 238 -

Amended at 24 Ok Reg 1810 (RM 200700004), eff 7-1-2007; Amended at 27 OK Reg 

2128, eff 7-11-10 (RM 201000003); Amended at 29 OK Reg 950, eff 7-1-12 (RM 

201200005); Amended at 32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

165:10-21-37. Qualification procedure

The well operator or one of the working interest owners, on behalf of the well 

operator and the other owners of the well, shall apply for qualification of the 

well and production at the Oklahoma Corporation Commission on OCC Form 1534.

(1) OCC Form 1534 shall be completed in its entirety, and together with 

supporting documentation, shall be submitted to the Technical Services 

Department of the Conservation Division of the Oklahoma Corporation Commission 

for review. 

(2) If the Department approves the application, a copy of the approved 

application shall be available to the operator.

(3) If the application is denied or refused, or approval is delayed beyond 

sixty (60) days, the applicant may seek review by application, notice and 

hearing.

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 200600012, eff 7-1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003)]

165:10-21-38. Rebates - Refund procedure

(a) Request to Oklahoma Tax Commission for a tax refund. If the Oklahoma 

Corporation Commission grants the application, the operator or one of the working 

interest owners in the well, on behalf of the well operator and the other owners 

of the well, shall make its request for refund by letter to the Audit Division, 

Oklahoma Tax Commission. Such letter request shall state the reason for refund 

and the amount claimed and must be accompanied by the following:

(1) A copy of the application approved by the Corporation Commission 

certifying the well as an inactive well for which production has been 

reestablished.

(2) A copy of an approved OTC Form 320C that shows the date of the reestablishment of production of oil and/or gas.

(3) A properly completed OTC Form 328 Gross Production 841/495 Refund 

Report.

(4) If the refund request is filed by any person other than the party named 

in the Oklahoma Corporation Commission application, a notarized affidavit, 

signed by the party named in the application must be filed, authorizing the 

applicant to apply for the refund.

(b) No rebate for production occurring prior to July 1, 2003; claim limitation. 

Effective July 1, 2014, no refund of gross production taxes shall be claimed for 

oil and gas production exempt from gross production taxes pursuant to 68 O.S. 

Section 1001(F) for production occurring prior to July 1, 2003. Claims for 

rebate filed with the Oklahoma Tax Commission shall be subject to limitations

pursuant to Title 68 O.S., Section 1001(L).

(c) Method of appeal. If the refund is denied, the applicant may file an appeal 

under the provisions of Title 68, Sections 227 and 228 of the Oklahoma Statutes.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended 

in Rule Making 200400006, eff 7-1-04; Amended in Rule Making 200600012, eff 7-

1-2006; Amended at 32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

PART 8. DEEP WELLS

165:10-21-45. General

(a) General provisions. Exemption from the levy of gross production tax on the 

production of gas, oil, or gas and oil from wells certified as being "Deep Wells" 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 239 -

set out in 68 O.S. § 1001(H) shall be determined according to the provisions of 

this Part, which have been jointly adopted by the Oklahoma Corporation Commission 

and the Oklahoma Tax Commission pursuant to 68 O.S. § 1001(N)(1).

(b) Definitions. For purposes of qualifying for the exemption, "depth" means 

the length of the maximum continuous string of drill pipe utilized between the 

drill bit face and the drilling rig's kelly bushing.

(c) Exemption for wells spudded between July 1, 2002, and July 1, 2005, drilled 

to a depth of fifteen thousand (15,000) feet or greater. Deep wells spudded 

between July 1, 2002, and July 1, 2005, and drilled to a depth of fifteen 

thousand (15,000) feet or greater shall be exempt from the gross production tax, 

beginning from the date of first sale, for a period of forty-eight (48) months, 

on production which occurs prior to July 1, 2011. Production on or after July 1, 

2011, and before July 1, 2015, from wells qualifying for this exemption shall be 

taxed at a rate of four percent (4%) until the expiration of forty-eight (48) 

months from the date of first sale.

(d) Exemption for wells spudded between July 1, 1997, and July 1, 2005, drilled 

to a depth of twelve thousand five hundred (12,500) feet or greater. Deep wells 

spudded between July 1, 1997, and July 1, 2005, and drilled to a depth of twelve 

thousand five hundred (12,500) feet or greater shall be exempt from the gross 

production tax, beginning from the date of first sale, for a period of twentyeight (28) months.

(e) Additional exemptions for deep wells. Production from deep wells spudded 

and drilled as noted below shall be eligible for an exemption from the gross 

production tax which shall begin from the date of first sale, and vary as to 

duration in relation to the depth of the well.

(1) 12,500 to 14,999 feet and spudded between July 1, 2005 and July 1, 2015. 

The duration of the exemption for wells drilled to this depth is twenty-eight 

(28) months.

(2) 15,000 to 17,499 feet and spudded between July 1, 2005 and July 1, 2011. 

The duration of the exemption for wells drilled to this depth is forty-eight 

(48) months on production which occurs prior to July 1, 2011. Production on 

or after July 1, 2011, and before July 1, 2015, from wells qualifying for this 

exemption shall be taxed at a rate of four percent (4%) until the expiration 

of forty-eight (48) months from the date of first sale.

(3) 15,000 to 17,499 feet and spudded between July 1, 2011, and July 1, 

2015. The tax levied on the production from wells drilled to this depth 

shall be reduced to a rate of four percent (4%) for a period of forty-eight 

(48) months from the date of first sale.

(4) 17,500 feet or greater and spudded between July 1, 2002 and July 1, 2011. 

The duration of the exemption for wells drilled to this depth is sixty (60) 

months on production which occurs prior to July 1, 2011. Production on or 

after July 1, 2011, and before July 1, 2015, from wells qualifying for this 

exemption shall be taxed at a rate of four percent (4%) until the expiration 

of sixty (60) months from the date of first sale.

(5) 17,500 feet or greater and spudded between July 1, 2011, and July 1, 

2015. The tax levied on the production from wells drilled to this depth shall 

be reduced to a rate of four percent (4%) for a period of sixty (60) months 

from the date of first sale.

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 970000025, eff 7-1-98; Amended in Rule Making 200000009, eff 5-11-01; 

Amended in Rule Making 200300001, eff 7-1-03; Amended in Rule Making 200400006, 

eff 7-1-04; Amended in Rule Making 200600012, eff 7-1-2006; Amended at 24 Ok 

Reg 1811 (RM 200700004), eff 7-1-2007; Amended at 26 Ok Reg 2498, eff 7-11-09 

(RM 200900001); Amended at 27 OK Reg 2128, eff 7-11-10 (RM 201000003); Amended 

at 28 OK Reg 1949, eff 7-11-11 (RM 201000007); Amended at 29 OK Reg 950, eff 7-

1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

165:10-21-46. Definitions [REVOKED]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 240 -

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Revoked in Rule 

Making 97000025, eff 7-1-98]

165:10-21-47. Qualification procedure

An OCC Form 1002A Completion Report accepted by the Oklahoma Corporation 

Commission reflecting that a well was spudded during the applicable time period 

and drilled to the prescribed depth appearing in OAC 165:10-21-45 constitutes 

approval by the Commission of an application for qualification for the exemption.

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Amended at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule 

Making 200600012, eff 7-1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007); Amended at 

32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

165:10-21-47.1. Rebates - Refund procedure

(a) Request to Oklahoma Tax Commission for a tax refund. If the Oklahoma 

Corporation Commission accepts an OCC Form 1002A Completion Report consistent 

with the provisions of OAC 165:10-21-47, the operator or one of the working 

interest owners in the well, on behalf of the well operator and the other owners 

of the well, shall make its request for refund by letter to the Audit Division, 

Oklahoma Tax Commission. Such letter request shall state the reason for refund 

and the amount claimed and must be accompanied by the following:

(1) An OCC Form 1002A Completion Report accepted by the Corporation 

Commission.

(2) A copy of an approved OTC Form 320A that shows date of first sale of 

production.

(3) A properly completed OTC Form 328 Gross Production 841/495 Refund Report.

(4) If the refund request is filed by any person other than the party named 

in the application, a notarized affidavit, signed by the party named in the 

application must be filed, authorizing the applicant to apply for the refund.

(b) No rebate for production occurring prior to July 1, 2003; claim limitation. 

Effective July 1, 2014, no refund of gross production taxes shall be claimed for 

oil and gas production exempt from gross production taxes pursuant to 68 O.S. 

Section 1001(H) for production occurring prior to July 1, 2003. Claims for rebate 

filed with the Oklahoma Tax Commission shall be subject to limitations pursuant 

to Title 68 O.S., §1001(L).

(c) Claims for refunds for certain deep wells filed for production periods from 

July 1, 2009, to June 30, 2011. For deep wells addressed in OAC 165:10-21-45(c), 

OAC 165:10-21-45(e)(2) and OAC 165:10-21-45(e)(4), claims for refunds for 

production periods beginning on or after July 1, 2009, and ending on or before 

June 30, 2011, shall be paid in equal payments for a period of thirty-six (36) 

months. The first payment shall be made after July 1, 2012, but prior to 

August 1, 2012. [See: 68 O.S. § 1001(M)]

(d) Method of appeal. If the refund is denied, the applicant may file an appeal 

under the provisions of Title 68, Sections 227 and 228 of the Oklahoma Statutes.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended 

in Rule Making 200400006, eff 7-1-04; Amended in Rule Making 200600012, eff 7-

1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28

OK Reg 1949, eff. 7-11-11 (RM 201000007); Amended at 32 Ok Reg 767, eff. 8-27-

15 (RM 201500001)]

165:10-21-48. Audit requirements [REVOKED]

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Revoked in Rule Making 200300001, eff 7-1-03]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 241 -

165:10-21-49. Certificate of investment to be filed by the operator [REVOKED]

[SOURCE: Added at 12 Ok Reg 491, eff 1-1-95 (emergency); Added at 12 Ok Reg 

1605, eff 7-1-95; Revoked at 13 Ok Reg 2933, eff 7-11-96]

PART 9. NEW DISCOVERY WELLS

165:10-21-55. General

(a) Exemption from the levy of gross production tax on the production of gas, 

oil, or gas and oil from wells spudded or reentered between July 1, 1995 and 

July 1, 2015, which qualify as a new discovery well pursuant to Title 68, Section 

1001(I), shall be determined according to the provisions of this Part, which have 

been jointly adopted by the Oklahoma Corporation Commission and the Oklahoma Tax 

Commission pursuant to Title 68, Section 1001(N)(1). Such exemption from the 

gross production tax shall be from the date of first sales for a period of 

twenty-eight (28) months. 

(b) "New discovery" means production of oil, gas or oil and gas from:

(1) A well, spudded or reentered on or after July 1, 1997, and prior to 

July 1, 2015, which discovers crude oil in paying quantities and is located 

more than one mile from the nearest oil well producing from the same 

producing interval of the same formation.

(2) A well, spudded or reentered on or after July 1, 1997, and prior to 

July 1, 2015, which discovers crude oil in paying quantities beneath current 

production in a deeper producing interval located more than one mile from 

the nearest oil well producing from the same deeper producing interval.

(3) A well, spudded or reentered, on or after July 1, 1997, and prior to 

July 1, 2015, which discovers natural gas in paying quantities and is 

located more than two miles from the nearest gas well producing from the 

same producing interval.

(4) A well, spudded or reentered, on and after July 1, 1997, and prior to 

July 1, 2015, which discovers natural gas in paying quantities beneath 

current production in a deeper producing interval that is more than two 

miles from the nearest gas well producing from the same deeper producing 

interval.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

97000025, eff 7-1-98; Amended in Rule Making 200000009, eff 5-11-01; Amended in 

Rule Making 200400006, eff 7-1-04; Amended at 24 Ok Reg 1811, eff 7-1-2007 (RM 

200700004); Amended at 27 OK Reg 2128, eff 7-11-10 (RM 201000003); Amended at 

29 OK Reg 950, eff 7-1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff 8-27-15 

(RM 201500001)]

165:10-21-56. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

“Effective date" means the date the well was spudded or the beginning date for 

a re-entered well.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

97000025, eff 7-1-98]

165:10-21-57. Qualification procedure

The well operator or one of the working interest owners, on behalf of the well 

operator and the other owners of the well, shall apply for qualification of the 

well at the Oklahoma Corporation Commission on OCC Form 1534.

(1) OCC Form 1534 shall be completed in its entirety, and together with 

supporting documentation, shall be submitted to the Technical Services 

Department of the Oklahoma Corporation Commission for review.
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 242 -

(2) If the Department approves the application, an approved copy shall be 

available to the operator.

(3) If the application is denied or refused, or approval is delayed beyond 

sixty (60) days, the applicant may seek review by application, notice and 

hearing.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200600012, eff 7-1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003)]

165:10-21-58. Rebates - Refund procedure

(a) Request to Oklahoma Tax Commission for a tax refund. If the Oklahoma 

Corporation Commission approves the application, the operator or one of the 

working interest owners in the well, on behalf of the well operator and the other 

owners of the well, shall make its request for refund by letter to the Audit 

Division, Oklahoma Tax Commission. Such letter request shall state the reason 

for refund and the amount claimed and must be accompanied by the following:

(1) A copy of the application approved by the Corporation Commission 

certifying the well as a new discovery well spudded or re-entered between July 

1, 1995 and July 1, 2015.

(2) A copy of an approved OTC Form 320A that shows date of first sale of 

production.

(3) A properly completed OTC Form 328 Gross Production 841/495 Refund Report.

(4) If the refund request is filed by any person other than the party named 

in the application, a notarized affidavit, signed by the party named in the 

application must be filed, authorizing the applicant to apply for the refund.

(b) No rebate for production occurring prior to July 1, 2003; claim limitation. 

Effective July 1, 2014, no refund of gross production taxes shall be claimed for 

oil and gas production exempt from gross production taxes pursuant to 68 O.S. 

Section 1001(I) for production occurring prior to July 1, 2003. Claims for 

rebate filed with the Oklahoma Tax Commission shall be subject to limitations

pursuant to Title 68 O.S., Section 1001(L).

(c) Method of appeal. If the refund is denied, the applicant may file an appeal 

under the provisions of Title 68, Sections 227 and 228 of the Oklahoma Statutes.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended 

in Rule Making 200400006, eff 7-1-04; Amended in Rule Making 200600012, eff 7-

1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 29

OK Reg 950, eff 7-1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff 8-27-15 

(RM 201500001)]

165:10-21-59. Audit requirements [REVOKED]

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Revoked in Rule Making 

200300001, eff 7-1-03]

PART 11. HORIZONTALLY DRILLED PRODUCING WELLS

165:10-21-65. General

Exemption from the levy of Gross Production Tax on horizontally drilled 

producing wells set out in 68 O.S. § 1001(E) shall be determined according to the 

provisions of this Part, which have been jointly adopted by the Oklahoma 

Corporation Commission and the Oklahoma Tax Commission pursuant to law. [See: 

68 O.S. §1001(N)(1)]

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended

at 28 Ok Reg 1949, eff 7-11-11 (RM 201000007)]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 243 -

165:10-21-66. Definitions

In addition to terms defined in 165:10-1-2, the following words and terms, 

when used in this Part, shall have the following meaning, unless the context 

clearly indicates otherwise:

"Angle of deviation" means that angle in which a wellbore may deviate from the 

vertical.

"Date of completion of a gas well" means the date that gas is capable of being 

delivered to a pipeline purchaser.

"Date of completion of an oil well" means the date that the well first 

produces into the lease tanks through permanent well head equipment.

"Effective date" means that the first production must have commenced after 

July 1, 2002 and before July 1, 2011, or that the first production must have 

commenced on or after July 1, 2011, and before July 1, 2015.

"Horizontal displacement" means that distance drilled into the pay zone of a 

formation at an angle exceeding seventy (70) degrees.

"Horizontally drilled payout" means the point at which gross working interest 

revenue from the horizontally drilled well equals the cost of drilling and 

completing such well.

"Horizontally drilled well" means an oil, gas, or oil and gas well drilled or 

completed in a manner which encounters and subsequently produces from a 

geological formation at an angle in excess of seventy (70) degrees from the 

vertical and which laterally penetrates a minimum of one hundred and fifty (150) 

feet into the pay zone of the formation.

"Project payback" shall be determined as of the date of the completion of the 

well and shall not include any expenses beyond the completion date of the well, 

and is subject to the approval of the Oklahoma Tax Commission. 

"True vertical depth" means that depth measured from the surface perpendicular 

to the surface.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

97000025, eff 7-1-98; Amended in Rule Making 200000009, eff 5-11-01; Amended in 

Rule Making 200400006, eff 7-1-04; Amended at 24 Ok Reg 1811 (RM 200700004), 

eff 7-1-2007; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended 

at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]

165:10-21-67. Qualification procedure 

The well operator or one of the working interest owners in the well, on behalf 

of the well operator and the other owners of the well, may apply for 

qualification of the production from horizontally drilled wells at the Oklahoma 

Corporation Commission on OCC Form 1534. In lieu of the OCC Form 1534, an OCC 

Form 1002A Completion Report accepted by the Commission reflecting that the well 

is a horizontally drilled producing well as addressed in this Part constitutes 

approval by the Commission of an application for qualification for the exemption.

(1) If an OCC Form 1534 is submitted to the Commission, such form shall be 

completed in its entirety, and together with supporting documentation, shall be 

submitted to the Technical Services Department of the Conservation Division of 

the Oklahoma Corporation Commission for review.

(2) If the Department approves the application, a copy shall be available to 

the operator.

(3) If the application is denied or refused, or approval is delayed beyond 

sixty (60) days, the applicant may seek review by application, notice and 

hearing.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200600012, eff 7-1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 244 -

165:10-21-68. Rebates - Refund procedure

(a) Request to Oklahoma Tax Commission for a tax refund. If the Commission 

approves the application or accepts an OCC Form 1002A Completion Report 

consistent with the provisions of OAC 165:10-21-67, the well operator or one of 

the working interest owners in the well, on behalf of the well operator and the 

other owners of the well, shall make its request for refund by letter to the 

Audit Division, Oklahoma Tax Commission. Such letter request shall state the 

reason for refund and the amount claimed and must be accompanied by the 

following:

(1) A copy of the approved application or OCC Form 1002A Completion Report 

accepted by the Corporation Commission.

(2) A copy of an approved OTC Form 320A that shows the date of initial 

production.

(3) A properly completed OTC Form 328 Gross Production 841/495 Refund Report.

(4) If the refund request is filed by any person other than the party named 

in the application, a notarized affidavit, signed by the party named in the 

application must be filed, authorizing the applicant to apply for the refund.

(b) No rebate for production occurring prior to July 1, 2003; claim 

limitation. Effective July 1, 2014, no refund of gross production taxes shall 

be claimed for oil and gas production exempt from gross production taxes pursuant 

to 68 O.S. Section 1001(E) for production occurring prior to July 1, 2003. 

Claims for rebate filed with the Oklahoma Tax Commission shall be subject to 

limitations pursuant to Title 68 O.S., Sections (1001)(E)(2), (1001)(L), and 

(1001)(M).

(1) Claims for refunds within fiscal years ending June 30, 2010, and June 30, 

2011. Claims for refunds for the production periods within the fiscal years

ending June 30, 2010, and June 30, 2011, shall be filed with and received by 

the Oklahoma Tax Commission no later than December 31, 2011.

(2) Claims for refunds filed for production periods from July 1, 2009, to 

June 30, 2011. For a horizontally drilled well producing oil, gas, or oil and 

gas prior to July 1, 2011, which production commenced after July 1, 2002, 

claims for refunds for production periods beginning on or after July 1, 2009, 

and ending on or before June 30, 2011, shall be paid in equal payments for a 

period of thirty-six (36) months. The first payment shall be made after July 

1, 2012, but prior to August 1, 2012. [See: 68 O.S § 1001(M)].

(c) Method of appeal. If the refund is denied, the applicant may file an appeal 

under the provisions of Title 68, Sections 227 and 228 of the Oklahoma Statutes.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended 

in Rule Making 200400006, eff 7-1-04; Amended in Rule Making 200600012, eff 7-

1-2006; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28

OK Reg 1949, eff. 7-11-11 (RM 201000007); Amended at 32 Ok Reg 767, eff. 8-27-

15 (RM 201500001)]

165:10-21-69. Time periods for exemption from gross production tax levied on 

horizontally drilled producing wells

(a) General provisions. The exemption for horizontally drilled wells qualified 

pursuant to this Part shall be determined as set out below in this Section.

(b) Forty-eight (48) month exemption-production prior to July 1, 2011, which 

commenced after July 1, 2002. For a horizontally drilled well producing oil, 

gas, or oil and gas prior to July 1, 2011, which production commenced after 

July 1, 2002, the duration of the exemption from the project beginning date 

until project payback is achieved may not exceed a period of forty-eight (48) 

months commencing with the date of initial production from the horizontally 

drilled well. [See: 68 O.S. Section 1001(E)(1)]

(c) Forty-eight (48) month exemption – production commenced on or after July 1, 

2011, and before July 1, 2015. The tax levied on oil, gas, or oil and gas 

production from a horizontally drilled well, which production commenced on or 

after July 1, 2011, and before July 1, 2015, shall be reduced to a rate of one 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 245 -

percent (1%) for a period of forty-eight (48) months commencing with the date of 

initial production from the horizontally drilled well. [See: 68 O.S. Section 

1001(E)(3)]

[SOURCE: Added in Rule Making 200300001, eff 7-1-03; Amended in Rule Making 

200400006, eff 7-1-04; Amended at 24 Ok Reg 1812 (RM 200700004), eff 7-1-2007; 

Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 28 OK Reg 

1949, eff. 7-11-11 (RM 201000007)]

PART 13. INCREMENTAL PRODUCTION FROM ENHANCED RECOVERY PROJECTS

165:10-21-75. General

Exemption from the levy of gross production tax on the incremental production 

of oil or other liquid hydrocarbons attributable to the working interest owners 

of an enhanced recovery project shall be determined according to the provisions 

of this Part, 68 O.S. §1001(D) and other applicable sections of such statute. 

The provisions of 68 O.S. §1001(D) do not apply to any enhanced recovery project 

using fresh water as the primary injectant, except when using steam. The 

exemption granted pursuant to 68 O.S. §1001(D) shall not apply to any production 

upon which a tax is paid at a rate of two percent. [See: 68 O.S. §1001(O)(2)].

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); 

Amended at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-21-76. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

"Base production amount” means the average monthly amount of production for 

the twelve (12) month period immediately prior to the project beginning date 

minus the monthly rate of production decline for the project or property for each 

month beginning one hundred eighty (180) days prior to the project beginning 

date.

"Completion date" means the date a well is first capable of being used for the 

injection of liquids, gases or other matter, or is capable of producing crude oil 

or other liquid hydrocarbons through permanent wellhead equipment.

"Enhanced recovery project costs" means the incremental project costs that are 

allowed as payback factors in determining the exemptions from the levy of gross 

production tax of project incremental production.

"Incremental production" means the amount of crude oil or other liquid 

hydrocarbons which are produced during an approved enhanced recovery project and 

which are in excess of the base production amount of crude oil or other liquid 

hydrocarbons.

"Incremental working interest revenue" means the gross value of the 

incremental production, less the royalty interest therein.

"Monthly rate of production decline" means a rate equal to the average 

extrapolated monthly decline rate for the twelve (12) month period immediately 

prior to the project beginning date as determined by the Commission, based on the 

production history of the field, its current status, and sound reservoir 

engineering principles.

"Project beginning date" means the date on which the injection of liquids, 

gases or other matter begins on an enhanced recovery project.

"Project payback or payout" means that point at which the incremental working 

interest revenue from the enhanced recovery project equals the enhanced project 

costs. Project payback shall be determined as of the date of the completion of 

the well and shall not include any expenses beyond the completion date of the 

well, and is subject to the approval of the Tax Commission. 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 246 -

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200300001, eff 7-1-03; Amended 

in Rule Making 200400006, eff 7-1-04; Amended at 24 Ok Reg 1812 (RM 200700004), 

eff 7-1-2007; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended 

at 32 Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-21-77. Qualification procedure

The provisions of this Section establish criteria for determining if an 

operator of an enhanced recovery project has met the required conditions to 

qualify the incremental production from such project for the exemption from the 

Gross Production Tax. [See: 68 O.S. §1001(D)]

(1) Administrative approval and determination. An operator seeking an 

exemption of incremental production from the gross production tax shall make 

application to the Oklahoma Corporation Commission on OCC Form 1139 for a 

determination that such project qualifies, a determination of the starting 

date, and of the base production amount. 

(A) OCC Form 1139 shall be completed in its entirety, and together with 

supporting documentation, shall be submitted to the Technical Services 

Department of the Conservation Division of the Oklahoma Corporation 

Commission. If the application is approved, a copy shall be available to 

the operator. If the application is denied or refused, or approval is 

delayed beyond sixty (60) days, the operator may seek review by 

application, notice and hearing.

(B) To obtain the tax exemption, the operator shall forward a copy of the 

approved application to the Oklahoma Tax Commission, together with any 

other data required by that agency.

(2) Tax Commission approval of exemption. An operator desiring an exemption 

from the gross production tax shall make application by letter to the Audit 

Division, Oklahoma Tax Commission. Such application shall be accompanied by:

(A) A copy of the application approved by the Corporation Commission 

containing a determination of the project beginning date, base production 

amount and project payback.

(B) The ratio of working interest/royalty interest in the well. Only the 

incremental production attributable to the working interest owners shall be 

exempted from the gross production tax. For purposes of this exemption, 

overriding royalty shall be included in working interest.

(C) A schedule of production, by month, of the gross amounts of crude oil 

or other liquid hydrocarbons produced, and the gross values thereof, from 

the project beginning date until the date application is made to the Tax 

Commission.

(D) OTC Forms 320A, 320C, and 320U, as are necessary, to set up the OTC 

Production Units, to request merge numbers, and to show the entity who will 

remit taxes.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200600012, eff 7-1-2006; Amended 

at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003)]

165:10-21-78. Recovery of costs allowed as payback factors

(a) Secondary recovery project, project beginning date on or after July 1, 2000, 

and before July 1, 2020. For any secondary recovery project approved or having 

an initial project beginning date on or after July 1, 2000, and before July 1, 

2020, any incremental production attributable to the working interest owners 

which results from such secondary recovery project shall be exempt from the gross 

production tax levied pursuant to 68 O.S. §1001 for a period not to exceed five 

(5) years from the initial project beginning date or for a period ending upon the 

termination of the secondary recovery process, whichever occurs first. [Applicant 

may omit payback report for such secondary recovery projects.] 

(b) Tertiary enhanced recovery project, project beginning date on or after 

July 1, 1993 and before July 1, 2020. For any tertiary enhanced recovery project 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 247 -

with a project beginning date on or after July 1, 1993, and before July 1, 2020, 

allowable enhanced recovery project costs shall include only incremental capital 

costs and incremental operating expenses, excluding administrative expenses. The 

capital expenses of pipelines constructed to transport carbon dioxide to a 

tertiary recovery project shall not be included in determining project payback. 

The period for project payback shall not exceed ten (10) years from the project 

beginning date.

(c) Excluded costs. The cost of tank batteries, meters, pipelines or other 

external equipment shall not be included in allowable enhanced recovery project 

costs. Allowable costs shall be determined using generally accepted accounting 

principles such as outlined in the "Council of Petroleum Accountants Society 

(COPAS) - Accounting Procedure Form for Joint Operations" and "COPAS Bulletin No. 

16", or subsequent revisions thereto.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

97000025, eff 7-1-98; Amended in Rule Making 200000009, eff 5-11-01; Amended in 

Rule Making 200300001, eff 7-1-03; Amended in Rule Making 200400006, eff 7-1-

04; Amended at 24 Ok Reg 1813 (RM 200700004), eff 7-1-2007; Amended at 27 OK 

Reg 2128, eff 7-11-10 (RM 201000003); Amended at 29 OK Reg 950, eff 7-1-12 (RM 

201200005); Amended at 32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

165:10-21-79. Responsibility for filing and payment of taxes

(a) Responsibility for reporting; reporting; forms required. The operator of a 

qualifying project will have primary responsibility for filing OTC Form 300-R-7-

81, Gross Production Tax Monthly Tax Report, and for remitting gross production 

and petroleum excise taxes on project production controlled by the operator. 

Working interest owners who take-in-kind will be responsible for filing Gross 

production Monthly Tax Reports, unless the take-in-kind owner has made an 

agreement with his purchaser or the operator to report and remit on his behalf. 

A take-in-kind interest owner must submit, through the project operator, a Form 

320, showing the disposition of his share of production. Purchasers may report 

taxes on project production with the approval of the Tax Commission, provided 

whenever there are multiple purchasers from a project, each reporting purchaser 

must report his allocated share of production, incremental production, and any 

exempt interest. All persons remitting taxes must comply with Tax Commission 

security requirements.

(b) Valuation of incremental production. When an operator or a single purchaser 

files the gross production tax reports and remits taxes, the incremental 

production will be valued at the volume-weighted average price per barrel of all 

crude oil or other liquid hydrocarbons produced from the project during the 

month. When multiple purchasers file the gross production tax reports and remit 

taxes, the incremental production will be valued at the volume-weighted average 

price per barrel purchased for the month, by each purchaser individually.

(c) Method of computing production, base production amount and incremental 

production.

(1) Frac oil recovered must be excluded as a Code 07 exemption. Frac oil 

will not be counted as part of the project base production amount, nor as 

incremental production.

(2) Incremental production will be deducted next as a Code 11 exemption.

(3) Exempt interests will be deducted next, in order of exemption code, as a 

decimal equivalent of the amount and value of production remaining after 

subtraction of the frac oil and incremental production.

(d) Well operators are advised to contact the Oklahoma Tax Commission concerning 

required annual reporting.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96]

165:10-21-80. Expiration of exemption for incremental production

For secondary recovery projects approved prior to July 1, 2020, and tertiary 

recovery projects approved prior to July 1, 2020, once the gross working revenue 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 248 -

equals the enhanced recovery project cost, the exemption of incremental 

production shall end and the Oklahoma Tax Commission shall resume collection of 

the Gross Production Tax thereon.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-01; Amended in Rule Making 200400006, eff 7-1-04; Amended 

at 24 Ok Reg 1813, eff 7-1-2007 (RM 200700004); Amended at 27 OK Reg 2128, eff 

7-11-10 (RM 201000003); Amended at 29 OK Reg 950, eff 7-1-12 (RM 201200005); 

Amended at 32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

PART 14. PRODUCTION OF OIL, GAS OR OIL AND GAS FROM ANY WELL LOCATED WITHIN

 BOUNDARIES OF A THREE-DIMENSIONAL SEISMIC SHOOT

165:10-21-82. General

Exemption from the levy of gross production tax on the production of oil, gas 

or oil and gas from a well, drilling of which is commenced on or after July 1, 

2000, and prior to July 1, 2015, located within the boundaries of a threedimensional seismic shoot and drilled based on three-dimensional seismic 

technology, shall be determined according to the provisions of this Part.

[SOURCE: Added in Rule Making 200000009, eff 5-11-01; Amended in Rule Making 

200400006, eff 7-1-04; Amended at 24 Ok Reg 1813 (RM 200700004), eff 7-1-2007; 

Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 29 OK Reg 

950, eff 7-1-12 (RM 201200005); Amended at 32 Ok Reg 767, eff 8-27-15 (RM 

201500001)]

165:10-21-82.1. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

“Three-dimensional seismic shoot” means any three-dimensional geophysical or 

seismic exploration activity conducted in the field for the purpose of drilling 

for and producing oil, gas or oil and gas from geological formations, intervals 

and/or common sources of supply.

“Three-dimensional seismic technology” means any three-dimensional geophysical 

or seismic equipment or instruments, data processing equipment, and/or data 

utilized to evaluate geological formations, intervals and/or common sources of 

supply in connection with a three-dimensional seismic shoot.

[SOURCE: Added in Rule Making 200000009, eff 5-11-01]

165:10-21-82.2. Qualification procedure

(a) Applicable wells. The provisions of this Section establish criteria for 

determining if an operator producing oil, gas or oil and gas from a well, 

drilling of which is commenced on or after July 1, 2000, and prior to July 1, 

2015, located within the boundaries of a three-dimensional seismic shoot and 

drilled based on three-dimensional seismic technology, has met the required 

conditions to qualify the production from such a well for the exemption from the 

Gross Production Tax. [See: 68 O.S. §1001(J)]

(b) Administrative approval and determination. An operator seeking an exemption 

of the gross production tax on production from a well located within the 

boundaries of a three-dimensional seismic shoot and drilled based on such 

technology, shall make application to the Oklahoma Corporation Commission on a 

Form 1534 for a determination that the well qualifies for such exemption, as 

provided in 68 O.S. 2000 Supp. §1001(J).

(1)OCC Form 1534 shall be completed in its entirety, and together with 

supporting documentation, shall be submitted to the Technical Services 

Department of the Conservation Division of the Oklahoma Corporation 

Commission. If the application is administratively approved, a copy shall be 

available to the operator. If the application is denied or refused, or 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 249 -

approval is delayed beyond sixty (60) days, the operator may seek review by 

application, notice and hearing.

(2) To obtain the tax exemption, the operator shall forward a copy of the 

approved application to the Oklahoma Tax Commission, together with any other 

data required by that agency pursuant to OAC 165:10-21-82.3.

(3) Any data, maps and other information submitted with the Form 1534 for 

determination that a well qualifies for the exemption provided in this 

paragraph shall be held as confidential information by the Conservation 

Division and/or Commission, and shall be returned to the applicant or 

destroyed upon approval of the application.

[SOURCE: Added in Rule Making 200000009, eff 5-11-2001; Amended in Rule Making 

200300001, eff 7-1-2003; Amended in Rule Making 200400006, eff 7-1-2004; 

Amended in Rule Making 200600012, eff 7-1-2006; Amended at 24 Ok Reg 1813 (RM 

200700004), eff 7-1-2007; Amended at 27 OK Reg 2128, eff. 7-11-10 (RM 

201000003); Amended at 29 OK Reg 950, eff. 7-1-12 (RM 201200005); Amended at 32 

Ok Reg 767, eff 8-27-15 (RM 201500001)]

165:10-21-82.3. Rebates - Refund procedure

(a) Request to Oklahoma Tax Commission for a tax refund. If the Commission 

approves the application, the well operator or one of the working interest owners 

in the well, on behalf of the well operator and the other owners of the well, 

shall make its request for refund by letter to the Audit Division, Oklahoma Tax 

Commission. Such letter request shall state the reason for refund and the amount 

claimed and must be accompanied by the following:

(1) A copy of the application approved by the Corporation Commission 

certifying that the well meets the criteria of the statute insofar that its 

drilling was commenced on or after July 1, 2000, and prior to July 1, 2015, 

that it is located within the boundaries of a three-dimensional seismic shoot 

and was drilled based on such technology, and indicating whether the seismic 

shoot was shot either prior to or on or after July 1, 2000.

(2) A schedule of production, by month, of the gross amounts of oil, gas or 

oil and gas produced, and the gross values thereof, from the date of first 

sale until the date application is made to the Tax Commission.

(3) OTC Form 320A, 320C, and 320U, as are necessary, to set up the OTC 

Production Units, to request merge numbers, and to show the entity who will 

remit taxes.

(4) If the refund request is filed by any person other than the party named 

in the application, a notarized affidavit, signed by the party named in the 

application must be filed, authorizing the applicant to apply for the refund.

(b) No rebate for production occurring prior to July 1, 2003; claim limitation. 

Effective July 1, 2014, no refund of gross production taxes shall be claimed for 

oil and gas production exempt from gross production taxes pursuant to 68 O.S. 

Section 1001(J) for production occurring prior to July 1, 2003. Claims for 

rebate filed with the Oklahoma Tax Commission shall be subject to limitations

pursuant to Title 68 O.S., Section 1001(L).

(c) Method of appeal. If the refund is denied, the applicant may file an appeal 

under the provisions of Title 68, Sections 227 and 228 of the Oklahoma Statutes.

[SOURCE: Added in Rule Making 200000009, eff 5-11-2001; Amended in Rule Making 

200300001, eff 7-1-2003; Amended in Rule Making 200400006, eff 7-1-2004; 

Amended in Rule Making 200600012, eff 7-1-2006; Amended at 24 Ok Reg 1813 (RM 

200700004), eff 7-1-2007; Amended at 27 OK Reg 2128, eff 7-11-10 (RM 

201000003); Amended at 29 OK Reg 950, eff 7-1-12 (RM 201200005); Amended at 32 

Ok Reg 767, eff 8-27-15 (RM 201500001)]
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 250 -

165:10-21-82.4. Time periods for exemption from gross production tax levied on 

oil, gas or oil and gas production from a well located within boundaries of 

three-dimensional seismic shoot 

The exemption from gross production tax levied on oil, gas or oil and gas 

production from a well qualified pursuant to this Section shall be applied as 

follows:

(1) Eighteen (18) month exemption. For a well where the seismic shoot was 

shot prior to July 1, 2000, the well shall be exempt from the gross 

production tax levied from the date of first sales for a period of eighteen 

(18) months. 

(2) Twenty-eight (28) month exemption. For a well where the seismic shoot 

was shot on or after July 1, 2000, the well shall be exempt from the gross 

production tax levied from the date of first sales for a period of twentyeight (28) months.

[SOURCE: Added in Rule Making 200000009, eff 5-11-01; Amended in Rule Making 

200300001, eff 7-1-03]

PART 15. GENERAL PROVISIONS

165:10-21-85. Election of exemption

(a) Election of exemptions generally. Persons entitled to exemption based upon 

production from qualifying oil, gas, or oil and gas wells shall be entitled only 

to the exemption granted pursuant to:

(1) Incremental production from enhanced recovery projects, as authorized by 

68 O.S. §1001(D) and Part 13 of this Subchapter; or,

(2) Horizontally drilled production wells, as authorized by 68 O.S. §1001(E) 

and Part 11 of this Subchapter; or,

(3) Reestablished production from inactive wells, as authorized by 68 O.S. 

§1001(F) and Part 7 of this Subchapter; or,

(4) Production enhancement projects, as authorized by 68 O.S. §1001(G) and 

Part 6 of this Subchapter; or,

(5) Production from deep wells, as authorized by 68 O.S. §1001(H) and Part 8 

of this Subchapter; or,

(6) Production from new discovery wells, as authorized by 68 O.S. §1001(I) 

and Part 9 of this Subchapter; or,

(7) Production from wells located within the boundaries of three-dimensional 

seismic shoot, as authorized by 68 O.S. §1001(J) and Part 14 of this 

Subchapter.

(b) Special provision. Prior to July 1, 2015, expiration of an exemption 

available for production from a qualifying well pursuant to one of Subsections 

(a)(2) through (a)(7) of this Section does not prohibit any person from 

qualifying for the exemption provided for in Subsection (a)(1). On or after 

July 1, 2015, expiration of an exemption available for production from a 

qualifying well pursuant to Subsections (a)(3) or (a)(4) of this Section does not 

prohibit any person from qualifying for the exemption provided for in Subsection 

(a)(1). An exemption granted pursuant to Subsection (a)(1) of this Section shall 

not apply to any production upon which a tax is paid at a rate of two percent. 

[See: 68 O.S.§1001(O)].

(c) Refund limited to interest owners of record and operators at time of 

qualifying act. Only the operator and interest owners of record at the time of 

the qualifying act are eligible for the rebate of gross production tax 

attributable to their interest in the project.

(1) In the case of a change in the operator of a qualified project, it is 

permissible for the new operator to file the claim for refund on behalf of all 

participating interest owners for the prior and the current periods, although 

the new operator would not be eligible for any share in the refund.
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 251 -

(2) A former operator or interest owner may also file the claim for the 

periods in which the owner or operator actively participated in the project 

and distribute the appropriate refund amounts to the eligible interest owners.

[SOURCE: Added at 13 Ok Reg 2933, eff 7-11-96; Amended in Rule Making 

200000009, eff 5-11-2001; Amended in Rule Making 200600012, eff 7-1-2006; 

Amended at 32 Ok Reg 767, eff 8-27-15 (RM 201500001)]

PART 17. SALES TAX EXEMPTION FOR ELECTRICITY AND ASSOCIATED DELIVERY AND 

TRANSMISSION SERVICES SOLD FOR OPERATION OF RESERVOIR DEWATERING PROJECT AND/OR 

UNIT

165:10-21-90. General

(a) Scope. This Part deals with the classification by the Oklahoma Corporation 

Commission (Corporation Commission or Commission) of a reservoir dewatering 

project and/or unit for the purpose of an exemption, beginning January 1, 2004, 

from sales taxes levied on electricity and associated delivery and transmission 

services sold to an oil and gas operator for reservoir dewatering projects and 

associated operations commencing on or after July 1, 2003, as provided in 68 

O.S. 2002 Supp., §1357(28).

(b) Distinction from designation as reservoir dewatering oil spacing unit or 

other spacing application. The classification of an area and reservoir(s) as a 

"reservoir dewatering project" and/or a "reservoir dewatering unit" pursuant to 

this Part shall be separate and distinct from the designation of a reservoir 

dewatering oil spacing unit for oil allowable purposes pursuant to OAC 165:10-

15-18. Corporation Commission approval of an area and reservoir(s) for the 

instant sales tax exemption shall be made by application under this Part and 

not as a result of a spacing application filed for oil allowable purposes under

OAC 165:10-15-1 and OAC 165:10-15-18, a spacing application filed for gas 

allowable purposes under OAC 165:10-17-2 through 10-17-16, a spacing 

application filed for horizontal drilling purposes under OAC 165:10-3-28, or 

any spacing application filed under OAC 165:10-1-22. 

(c) Reservoir Dewatering Projects for Oil Production. Any reservoir that is 

the subject of an application pursuant to this Part, which produces 

predominantly oil, shall be evaluated to determine the initial water-to-oil 

ratio is equal to or greater than five-to-one (5-to-1).

(d) Reservoir Dewatering Projects for Gas Production. Any reservoir that is 

the subject of an application pursuant to this Part, which produces 

predominantly gas, shall be evaluated to determine the initial five-to-one (5-

to-1) water-to-oil ratio using a gas conversion factor of one (1) barrel of oil 

converted to an MCF of natural gas based on an initial natural gas formation 

volume factor, BTU or price calculation or conversion accepted by the 

Conservation Division.

[SOURCE: Added in Rule Making 200300001, eff 7-1-03]

165:10-21-91. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

“Reservoir dewatering project” means an oil or gas production project 

covering a specified area and reservoir(s), which utilizes water recovery and 

disposal technology to increase water production in the initial phase of 

reservoir development, with the primary purpose of increasing oil or gas 

production from the reservoir(s) as a result of the dewatering process. For 

the purpose of qualification for the sales tax exemption pursuant to this Part, 

the definition of reservoir dewatering project shall require the proof that the 

reservoir’s initial water-to-oil ratio is greater than or equal to five-to-one 

(5-to-1), or is greater than or equal to the appropriate gas-to-water ratio 

calculated using the gas conversion factor outlined in OAC 165:10-21-90(d). This 

definition shall not include enhanced recovery projects or secondary recovery 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 252 -

properties, which are subject to gross production tax exemptions pursuant to 68 

O.S. Section 1001 and Part 13 of this Subchapter, OAC 165:10-21-75 through 10-

21-80.

“Reservoir dewatering unit” means an area and reservoir(s) designated a 

reservoir dewatering project where a reservoir dewatering process is conducted 

as defined in this Part. 

[SOURCE: Added in Rule Making 200300001, eff 7-1-03]

165:10-21-92. Qualification procedure

(a) Applicable operations. The provisions of this Section establish criteria 

for determining if an area and reservoir(s) can be classified a reservoir 

dewatering project and/or a reservoir dewatering unit, beginning January 1, 2004, 

for the purpose of an exemption from sales taxes levied on electricity and 

associated delivery and transmission services sold to an oil and gas operator 

for a reservoir dewatering project and associated operations commencing on or 

after July 1, 2003.

(b) Application to the Oklahoma Corporation Commission. An oil and gas operator 

seeking the classification of an area and reservoir(s) as a reservoir dewatering 

project and/or reservoir dewatering unit pursuant to this Part shall file an 

application with the Corporation Commission on a Form 1535 for a determination 

that the project and/or unit qualifies for the exemption, as provided in 68 O.S. 

2002 Supp., §1357(28). The operator shall attach to the Form 1535 a copy of the 

following information:

(1) A production test or other appropriate data showing the initial water-tooil ratio is greater than or equal to five-to-one (5-to-1) or is greater than 

or equal to the appropriate gas-to-water ratio calculated using the gas 

conversion factor outlined in OAC 165:10-21-90(d). For this purpose, a 

Corporation Commission Form 1013 may be filed with the sales tax exemption 

application to demonstrate the initial 5-to-1 water-to-oil ratio for the 

reservoir.

(2) Geological structure and isopach maps for the applicable reservoir 

showing its geological characteristics; and any additional engineering and 

geological data or information deemed necessary by the Conservation Division 

to evaluate the application.

(3) A schematic diagram of the electrical grid and dewatering and water 

disposal equipment associated with the reservoir dewatering project covered by 

the application.

(c) Administrative approval and determination. 

(1) If the application is administratively approved, copy shall be 

forwarded to the operator.

(2) To obtain the tax exemption, the operator should contact the Director’s 

Office, Taxpayer Assistance Division, Oklahoma Tax Commission, 2501 N. 

Lincoln Blvd., Oklahoma City, Ok. 73194.

(3) Any data, maps and other information submitted with the Form 1535 for 

determination that an area and reservoir qualify for the exemption provided 

in this Part shall be held as confidential information by the Conservation 

Division and/or Corporation Commission, and shall be returned to the 

applicant or destroyed upon approval of the application.

[SOURCE: Added in Rule Making 200300001, eff 7-1-03; Amended in Rule Making 

200600012, eff 7-1-2006]

PART 19. STATE SALES TAX EXEMPTION FOR ELECTRICITY SOLD FOR OPERATION OF 

ENHANCED RECOVERY METHODS ON A SPACING UNIT OR LEASE

165:10-21-95. General

(a) Scope. This Part deals with the designation by the Oklahoma Corporation 

Commission (Corporation Commission or Commission) of enhanced recovery methods 

on a spacing unit or lease for the purpose of an exemption, beginning July 1, 
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 253 -

2006, from sales taxes levied on electricity sold to an oil and gas operator 

for such operations, as provided in 68 O.S. §1357(32).

(b) Distinction from designation as enhanced recovery project pursuant to 

application for underground injection, spacing or unitization. The designation 

of enhanced recovery methods on a spacing unit or lease pursuant to this Part 

shall be separate and distinct from the designation of an enhanced recovery 

project otherwise provided by Commission rules. The Commission’s designation 

pertaining to the instant sales tax exemption shall be made by application 

under this Part and not as a result of an application for: (1) enhanced 

recovery project designation under OAC 165:10-5-4; (2) drilling and spacing 

units under OAC 165:10-15-1 and OAC 165:10-15-18 (oil allowables), OAC 165:10-

17-2 through 10-17-16 (gas allowables), OAC 165:10-3-28 (horizontal drilling), 

or any spacing application under OAC 165:10-1-22; or (3) unitization under 

Title 52 O.S., § 287.1 et seq. and OAC 165:5-7-20.

[SOURCE: Added in Rule Making 200600012, eff 7-1-2006]

165:10-21-96. Definitions

The following words and terms, when used in this Part, shall have the 

following meaning, unless the context clearly indicates otherwise:

"Enhanced recovery methods" means production methods by which oil is 

produced, or is attempted to be produced, including but not limited to, 

increased pressure in a producing formation through use of water or saltwater 

if the electrical usage is associated with and necessary to the operation of 

equipment required to inject or circulate fluids in the producing formation for 

the purpose of forcing oil or petroleum into a wellbore for eventual recovery 

and production from the wellhead. 

[SOURCE: Added in Rule Making 200600012, eff 7-1-2006]

165:10-21-97. Qualification procedure

(a) Applicable operations. The provisions of this Section establish criteria 

for designating enhanced recovery methods on a spacing unit or lease, beginning 

July 1, 2006, for the purpose of an exemption from sales taxes levied on 

electricity sold to an oil and gas operator for such operations. 

(b) Application to the Oklahoma Corporation Commission. An operator seeking 

the designation of enhanced recovery methods on a spacing unit or lease 

pursuant to this Part shall file an application with the Corporation Commission 

on a Form 1535 for a determination that the operations qualify for the 

exemption, as provided in 68 O.S. §1357(32). The operator shall attach to the 

Form 1535 a copy of the following information:

(1) Production test or other appropriate data showing the total content 

of oil recovered after the use of enhanced recovery methods does not 

exceed one percent (1%) by volume. For this purpose, a Corporation 

Commission Form 1535 may be filed with the sales tax exemption application 

to demonstrate the daily rate and total content of oil recovery by volume 

from the spacing unit or lease prior to use of enhance recovery methods.

(2) Geological structure and isopach maps for the producing formation and 

any additional engineering and geological data or information deemed 

necessary by the Conservation Division to evaluate the application.

(3) A map and schematic diagram of the producing wells, underground 

injection or disposal wells, and other water injection or circulating 

equipment associated with the enhanced recovery methods on a spacing unit 

or leased covered by the application.

(c) Administrative approval and determination.

(1) If the application is administratively approved, a copy shall be 

forwarded to the operator.
OAC 165:10-21 Corporation Commission

Eff. 8-27-15

- 254 -

(2) To obtain the tax exemption, the operator should contact the 

Director’s Office, Taxpayer Assistance Division, Oklahoma Tax Commission, 

2501 N. Lincoln Blvd., Oklahoma City, OK. 73194.

(3) Any data, maps and other information submitted with the Form 1535 for 

designation that enhanced recovery methods on a spacing unit or lease 

qualify for the exemption provided in this Part shall be held as 

confidential information by the Conservation Division and Corporation 

Commission, and upon approval of the application, shall be returned to the 

applicant or destroyed.

[SOURCE: Added at 23 Ok Reg, eff 7-1-06 (RM 200600012); Amended at 25 OK Reg 

2187, eff 7-11-08 (RM 200800003)]
OAC 165:10-23 Corporation Commission

Eff. 8-27-15

- 255 -

SUBCHAPTER 23. RATABLE SHARING OF REVENUE

[REVOKED]

Section

165:10-23-1. Definitions [REVOKED]

165:10-23-2. General provisions for all interest owners in a well producing 

natural gas or casinghead gas [REVOKED]

165:10-23-3. Revenue sharing in contract entered into on or after January 1, 

1984; market by operator [REVOKED]

165:10-23-4. Revenue sharing in contract entered into prior to May 3, 1983 

[REVOKED]

165:10-23-5. Revenue sharing in contract entered into on or after May 3, 1983, 

but prior to January 1, 1984 [REVOKED] 

165:10-23-6. Gas statements of production [REVOKED] 

165:10-23-7. Expiration of a gas contract [REVOKED] 

165:10-23-8. Special circumstances; parties selling under a joint operating 

agreement [REVOKED]

165:10-23-9. Payments on production [REVOKED] 

165:10-23-10. Administrative expense [REVOKED] 

165:10-23-11. Commencement of an action [REVOKED] 

165:10-23-12. Other rights and remedies [REVOKED] 

165:10-23-13. Crude oil [REVOKED] 

165:10-23-14. Liability [REVOKED] 

165:10-23-15. Severability [REVOKED] 

165:10-23-1. Definitions (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-2. General provisions for all interest owners in a well producing 

natural gas or casinghead gas (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-3. Revenue sharing in contract entered into on or after January 1, 

1984; market by operator (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-4. Revenue sharing in contract entered into prior to May 3, 1983

(Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-5. Revenue sharing in contract entered into on or after May 3, 1983, 

but prior to January 1, 1984 (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-6. Gas statements of production (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]
OAC 165:10-23 Corporation Commission

Eff. 8-27-15

- 256 -

165:10-23-7. Expiration of a gas contract (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-8. Special circumstances; parties selling under a joint operating 

agreement (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-9. Payments on production (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-10. Administrative expense (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-11. Commencement of an action (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-12. Other rights and remedies (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165-10-23-13. Crude oil (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-14. Liability (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]

165:10-23-15. Severability (Revoked)

[Source: Revoked at 10 Ok Reg 2601, eff 6-25-93]
OAC 165:10-24 Corporation Commission

Eff. 8-27-15

- 257 -

SUBCHAPTER 24. MARKET SHARING

Section

165:10-24-1. Scope

165:10-24-2. Definitions

165:10-24-3. Election to market share

165:10-24-4. Duties and accounting

165:10-24-5. Replacement of the designated marketer

165:10-24-6. Fees

[Authority: 52 O.S. 1992, Section 581.1 et seq.]

[Source: Codified 6-25-93]

165:10-24-1. Scope

(a) This Subchapter implements the Natural Gas Market Sharing Act of 1992, 

codified at 52 O.S. Section 581, et seq.

(b) This Subchapter establishes a procedure whereby an owner in a well may 

compel the well operator or other designated marketer to either sell gas on the 

owner's behalf or find a market for that owner's gas.

(c) This Subchapter shall apply to the sale of natural gas from a well except 

for:

(1) any sale under a gas contract for more than one year, entered into 

before January 1, 1985 (including any successor, replacement or roll-over 

contract entered into before January 1, 1990) provided that any participating 

mineral owners who were sharing in a contract on January 1, 1992, and 

continue to share in such a contract on September 1, 1992, are subject to 

this Subchapter;

(2) any sale under a contract which provides for:

(A) an initial term of more than three years; and

(B) a guarantee or warranty of delivery of fixed volumes without 

limitation on specified wells or reserves; and

(C) delivery of such volumes;

(3) any sale of natural gas liquids extracted by mechanical processing of 

the natural gas stream for removal of liquid components other than methane.

(d) Nothing in this Subchapter shall change the obligation of a first purchaser 

of production under an existing gas contract unless otherwise agreed to by the 

parties.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93; Amended at 11 Ok Reg 3699, eff 

7-11-94]

165:10-24-2. Definitions

The following words or terms, when used in this Subchapter, shall have the 

following meaning, unless the context clearly indicates otherwise:

"Designated marketer" means the operator of the well or a producing owner 

substituted for the operator as provided in 165:10-24-5.

"Electing owner" means any owner who elects to produce and market its share 

of production pursuant to the provisions of this Subchapter.

"Nonexempt sales" means those gas sales which are subject to the provisions 

of this Subchapter and do not qualify for exemptions as set forth in 165:10-24-

1(c) and 165:10-24-3(b).

"Overproduced owner" means an owner who has produced and sold a volume of gas 

in excess of his working interest percentage of cumulative sales from a well.

"Owner" means a person or persons who own a working interest in a well.

"Producing owner" means an owner who produces and sells gas from a well for 

its own account.
OAC 165:10-24 Corporation Commission

Eff. 8-27-15

- 258 -

"Working interest" means the interest in a well, calculated prior to 

deduction for royalty, overriding royalty and other non-cost bearing interests 

burdening production, entitling the owner thereof to drill for and produce oil 

and gas, including the interest of a participating mineral owner to the extent 

set forth in Section 87.1 of Title 52 of the Oklahoma Statutes.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-24-3. Election to market share

(a) An owner eligible to market share as to a particular well, may elect to 

market share as to such well by sending written notice to the designated 

marketer for the well.

(b) An owner may not elect to market share as to a particular well if as to 

such well:

(1) said owner is subject to a balancing agreement (or other written 

agreement expressly providing for gas balancing or the taking, sharing, 

marketing of gas); or 

(2) the term has yet to expire for a gas contract, where the owner 

terminated the contract for value received; or 

(3) said owner terminated market sharing within the previous 12 months; or 

(4) said owner is currently over-produced; or 

(5) the designated marketer is relieved from the duty to market share 

pursuant to 165:10-24-4(g) or 165:10-24-4(i) and (j).

(c) An election to market share shall be effective on the first day of the 

month following 60 days from receipt of the election by the designated marketer.

(d) The well operator shall serve as the designated marketer until 

appointment of a substitute.

(e) An owner may terminate his election by sending writing notice to the 

designated marketer. Notice of termination is effective on the first day of the 

month following 60 days after receipt of the notice.

(f) Copies of all market sharing elections and notices shall be sent to the 

well operator, if said operator is not the designated marketer.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-24-4. Duties and accounting

(a) The designated marketer shall find an independent, non-affiliated 

purchaser for the electing owner's gas, or the designated marketer shall produce 

and sell said gas for the account of the electing owner.

(b) During market sharing, the designated marketer shall have the right to 

produce and sell and electing owner's gas, without further notice and consent 

except in those cases where the designated marketer has secured an independent 

non-affiliated purchaser for the gas production of such electing owner.

(c) If the designated marketer produces and sells the electing owner's gas for 

the account of the electing owner, the designated marketer shall account to the 

electing owner at the average price, weighted by volume, received by the 

marketer for all of the designated marketer's non-exempt sales from the well for 

that month, less post production cost and expenses required to render the gas 

marketable and to sell and deliver the gas to market, and net of all reasonable 

marketing costs, expenses and administrative fees. Volumetric allocation 

between the designated marketer and the electing owner shall be in proportion to 

their working interests in the well, with one exception. If the owner's 

proportionate production interest is different from his working interest, the 

proportionate production interest shall be used.

(d) Disbursement of gas sales proceeds shall be subject to the Production 

Revenue Standards Act of 1992 (52 O.S. Section 570.1, et seq.).

(e) The designated marketer shall not be considered as a fiduciary to any 

electing owner or to any owner with an interest burdening the electing owner's 

interest. The designated marketer shall not be liable for losses absent bad 

faith, gross negligence or willful misconduct.
OAC 165:10-24 Corporation Commission

Eff. 8-27-15

- 259 -

(f) Market sharing according to this Subchapter shall not confer any contract 

rights to an electing owner or his assigns, either directly or as third party 

beneficiaries.

(g) For a gas contract with a term in excess of one year, the designated 

marketer may require an electing owner to either agree in writing to be bound by 

the contract terms or forego market sharing under that contract. Absent a 

confidentiality provision in said gas contract, the designated marketer shall 

send a copy of the gas contract to each electing owner.

(1) After receipt of the contract, the electing owner shall have 30 days in 

which to:

(A) send written consent to the contract terms, or 

(B) provide a written termination of market sharing or 

(C) elect a new designated marketer.

(2) If the electing owner fails to so respond, his election to market share 

shall be deemed terminated.

(h) If the designated marketer ceases to sell gas from the well and therefore 

has no sales, the designated marketer:

(1) may:

(A) notify the electing owners in writing that it has no sales and that 

the electing owners must elect a new designated marketer, or

(B) locate a non-affiliated purchaser for the electing owners.

(2) shall not be responsible for sharing sales with electing owners as it 

has no sales. If such a designated marketer again begins to produce and 

market gas from the well, then the electing owners may re-elect it as 

designated marketer.

(i) If the designated marketer provides the electing owner with a sales 

contract with a gas purchaser, the designated marketer shall be relieved of the 

duty to market share with the electing owner to the extent that the terms of 

said contract provide for the purchase of the electing owner's share of each 

withdrawal from the well during the contract period, provided:

(1) The designated marketer is not an affiliate of the gas purchaser: said 

term "affiliate" being defined at 18 O.S. Section 1148A(2); and 

(2) The contract is of a type and with terms generally offered at the time 

to other producers for gas production from wells in the common source of 

supply; and 

(3) If the designated marketer operates and controls a gathering line to the 

well, it does not prohibit access to downstream transportation or impose 

unjust or discriminatory gathering fees or tariffs upon the electing owner; 

and 

(4) Before discontinuing market sharing if it had begun, the designated 

marketer provides the electing owner with at least thirty days in which to 

accept or reject the offer for said contract.

(j) In so far as the exemption established by subsection (i) of this Section, 

if the designated marketer fulfills each of the foregoing conditions, it shall 

be relieved from the duty to market share with the electing owner for a time 

period hereafter described as the "exemption period", calculated as follows:

(1) If the electing owner enters into said contract with said purchaser, 

then the exemption period shall be the duration of the contract as originally 

offered to the electing owner or the duration of the contract as entered into 

by the electing owner, whichever is greater;

(2) If the electing owner fails to enter into said contract for any reason, 

then the exemption period shall be the duration of the contract period as 

initially offered to the electing owner or twelve months, whichever is less.

(k) During the exemption period as determined in subsection (j) of this 

Section, failure to enter into said contract shall not be grounds for election 

or appointment of an additional designated marketer to market share with the 

electing owner with respect to volumes of gas which would have been purchased if 

the electing owner had entered into the said contract as initially offered to 

the electing owner.
OAC 165:10-24 Corporation Commission

Eff. 8-27-15

- 260 -

(l) Upon request, the designated marketer or electing owner shall provide the 

first purchaser of production with information concerning the election to market 

share and the electing owner's share of monthly production.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-24-5. Replacement of the designated marketer

A new designated marketer may be appointed by a majority vote of the 

remaining market sharing owners. If an electing owner does not agree to the 

terms of a gas contract with a term greater than one year, the electing owner 

may elect a new designated marketer unless said election is prohibited by 

165:10-24-4(i) and (j). Otherwise, substitution of the designated marketer 

shall occur not more than once every twelve months.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-24-6. Fees

(a) The designated marketer may charge each electing owner with an 

administrative fee for marketing the electing owner's share of production. Said 

fee shall be assessed monthly on a per-well basis. It shall be based on a 

formula described in this Section subject to annual adjustments as provided 

below. Said formula consists of 2.5% of the electing owner's monthly share of 

proceeds, but not less than twenty dollars nor more than seventy-five dollars, 

unless application of the annual adjustment factor provides a different maximum 

amount. The maximum amount of the fee permitted by this Section shall be 

adjusted as of the first day of May each year following May 1, 1993. The annual 

adjustment shall be computed by multiplying the rate currently in use by the 

percentage of increase or decrease in the annual overhead adjustment factor 

established by the Council of Petroleum Accountants Societies at its annual 

spring meeting for purposes of adjusting the combined fixed-rate overhead 

charges against joint operations in a well.

(b) If the designated marketer produces and sells gas for the account of the 

electing owner, the designated marketer may charge the electing owner or deduct 

said fee from the electing owner's share of the undistributed proceeds of 

production.

(c) Administrative fees under this Section shall be in addition to and separate 

from any and all post-production costs and expenses, including but not limited 

to reasonable marketing costs and expenses which may also be deducted from the 

proceeds payable to eligible electing owners.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]
OAC 165:10-25 Corporation Commission

Eff. 8-27-15

- 261 -

SUBCHAPTER 25. ESCROWED ACCOUNTS FOR POOLED MONIES

Section

165:10-25-1. Definitions 

165:10-25-2. Escrow account required 

165:10-25-3. Escrow account requirements 

165:10-25-4. Payment to owner 

165:10-25-5. Reports to the Commission 

165:10-25-6. Payment to the Commission 

165:10-25-7. Affidavit of compliance 

165:10-25-8. Forms 

165:10-25-9. Release from liability 

165:10-25-10. Construction 

165:10-25-1. Definitions

 The following words or terms, when used in this Subchapter, shall have the 

following meaning, unless the context clearly indicates otherwise:

 "Escrow account" means an account established in a financial institution and 

held in the name of the holder and an escrow agent wherein each owner is 

federally insured to One Hundred Thousand Dollars ($100,000.00).

 "Financial institution" means a federally or state chartered bank, savings 

and loan, or credit union.

 "Holder" means any person in possession of royalties, bonus payments, or 

other monies directed to be paid under a Commission pooling order and which 

cannot be paid because the persons entitled thereto are unknown or cannot be 

located.

 "Owner" means the last known record titleholder of a mineral interest which 

is subject to a Commission pooling order.

 "Person" means any individual, partnership, joint stock associations, trust, 

cooperative, unincorporated association, or corporation.

165:10-25-2. Escrow account required

(a) Each pooling order which pools interest of unknown or unlocated owners 

shall contain language substantially similar to the following: "If any payment 

of bonus, royalty payments, or other payments due and owing under this order 

cannot be made because the person entitled thereto cannot be located or is 

unknown, then said bonus, royalty payments or other payments shall be paid into 

an escrow account in a financial institution within ninety (90) days after this 

order and shall not be commingled with any funds of the applicant or operator. 

Provided however, that the Commission shall retain jurisdiction to grant to 

financially solid and stable holders an exception to the requirement that such 

funds be paid into an escrow account with a financial institution and permit 

such holder to escrow such funds within such holder's organization. 

Responsibility for filing reports with the Commission as required by law and 

Commission rule as to bonus, royalty or other payments escrowed hereunder shall 

be with the applicable holder. Such escrowed funds shall be held for the 

exclusive use of, and the sole benefit of, the person entitled thereto. It 

shall be the responsibility of the operator to notify all other holders of this 

provision and of the Commission rules regarding unclaimed monies under pooling 

orders".

(b) Each pooling order issuing upon an application filed on or after July 1, 

1984, shall contain, in addition to the foregoing language, an attached exhibit 

listing all parties or interests which are unknown or cannot be located, 

together with each party's last known address, if available.

165:10-25-3. Escrow account requirements

(a) Monies which are directed to be paid under a Commission pooling order and 

which cannot be paid because the persons entitled thereto are unknown or cannot 
OAC 165:10-25 Corporation Commission

Eff. 8-27-15

- 262 -

be located shall be placed into escrow accounts in a financial institution. The 

holder shall choose the institution. The holder and the financial institution 

may make such arrangements as are necessary and appropriate for the 

establishment of the account. Service charges, fees, and costs may be deducted 

from any interest generated by the monies but in no event shall such charges, 

fees, and costs be deducted from the principal. Any financially solid and 

stable holder may apply to the Commission for an exception to the requirement to 

place monies into escrow accounts in a financial institution. The granting of 

an exception shall be within the sole discretion of the Commission and may only 

be granted upon the filing of a proper application therefor pursuant to notice 

given to the Manager of the Mineral Owners Escrow Account by mail at least ten 

days prior to the hearing and by publication one time at least 15 days prior to 

the hearing in a newspaper of general circulation in Oklahoma County and in a 

newspaper of general circulation in the county where the holder's principal 

office in the state is located. The granting of an exception shall not exempt 

the holder from any other requirements set forth in this Subchapter.

(b) Only one account need be established by each holder. If only one account 

is established, a record shall be make of deposits and withdrawals for each 

person for whom monies are being held. Either the holder or the financial 

institution may keep the deposit/withdrawal record.

(c) An application for an exception under (a) of this Section shall state that 

the holder has proof by the holder's annual financial statement that it is a 

solid and stable holder. The holder must introduce its annual financial 

statement into evidence in the cause and the order, if one is issued, shall show 

that the annual financial statement was in fact introduced into evidence and 

considered by the Administrative Law Judge in making the determination to grant 

holder's request for an exemption under (a) of this Section, and holder shall 

submit a current financial statement on an annual basis thereafter.

(d) Withdrawals from such escrow account by the holder may only be made for the 

following purposes:

(1) To pay the rightful recipient of the monies upon presentation of a 

proper claim.

(2) To submit and pay to the Commission the principal of all monies placed 

in escrow pursuant to 165:10-25-6.

(3) To correct an overpayment or other mistake made in the distribution of 

monies by the holder.

[SOURCE: Amended at 9 Ok Reg 2337, eff 6-25-92]

165:10-25-4. Payment to owner

 The holder shall have a designated officer or employee to whom claims upon 

the escrow account may be made. The holder shall promptly pay the appropriate 

sum to any person showing the holder sufficient proof of ownership and proof of 

identity as may be determined in good faith by the holder. The holder shall 

report any payments made on his annual report to the Commission.

165:10-25-5. Reports to the Commission

 Each holder shall submit a report for persons who cannot be located or are 

unknown and for whom monies are being held in escrow no later than 30 days after 

such holder's annual reporting date. Each holder's initial report shall be 

filed no later than one year and 30 days after the date of the issuance of the 

first pooling order subject to this Subchapter. Such reports shall be filed 

each year that any monies are held in escrow, until the well is plugged.

165:10-25-6. Payment to the Commission

(a) No later than 30 days after the annual reporting date of each year, the 

holder shall submit to the Commission the principal of all monies placed in 

escrow accruing under the orders issued during the first year, and all 

subsequent years where the sum exceeds $100.00 for any one person.
OAC 165:10-25 Corporation Commission

Eff. 8-27-15

- 263 -

(b) If the holder has placed in escrow less than $100.00 for any one person, 

the holder may follow the procedures for deposit, or maintain the funds in 

escrow. If the amount accumulates to over $100.00 for any one person after any 

annual reporting date, it shall be submitted to the Commission on the next 

annual reporting date.

(c) Payments shall be tendered to the Finance Office of the Commission. 

Payments shall be made by cashier's check, certified check, or money order made 

payable to the "Oklahoma Corporation Commission".

165:10-25-7. Affidavit of compliance

 In addition to the Plugging Record (Form 1003) and Completion Report (Form 

1002A) required under 165:10-11-7, the operator shall file a compliance 

affidavit. No plugging bond shall be released until after the compliance 

affidavit is filed.

165:10-25-8. Forms

 The Commission may issue appropriate forms to implement the provisions of 

this Subchapter.

165:10-25-9. Release from liability

 Any holder who pays or delivers monies to the Commission required to be paid 

under this Subchapter shall be relieved of all liability for the monies so paid 

or delivered for any claim which then exists or thereafter may arise or be made 

in respect to such monies.

165:10-25-10. Construction

 This Subchapter shall not be construed as limiting the Commission's authority 

to grant an exception to any rule in this Subchapter, unless precluded by law.
OAC 165:10-25 Corporation Commission

Eff. 8-27-15

- 264 -

[BLANK PAGE]
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 265 -

SUBCHAPTER 27. PRODUCTION REVENUE STANDARDS

Section

165:10-27-1. Scope

165:10-27-2. Effective date [REVOKED]

165:10-27-3. Definitions

165:10-27-4. Well operator records

165:10-27-5. Pre-sale nominations

165:10-27-6. Entitlement

165:10-27-7. Post-sale reports

165:10-27-8. Operator's option to confirm zero volume of gas sales because

 of noncompliance

165:10-27-9. Designated payor for royalty distributions

165:10-27-10. Administrative fees

165:10-27-11. Balancing of royalty accounts

165:10-27-12. Record keeping

165:10-27-13. Check stub information

[Authority: 52 O.S. 1992, Section 570.13 et seq.]

[Source: Codified 6-25-93]

165:10-27-1. Scope

This Subchapter implements the Production Revenue Standards Act of 1992, 

codified at 52 O.S. Section 570.1, et seq. It shall apply to all producing 

wells as set forth in the Production Revenue Standards Act of 1992. However, 

Sections 165:10-27-4 through 165:10-27-10 shall not apply to any well which is a 

part of a compulsory enhanced recovery project, or where royalty remittance is 

otherwise regulated by written agreement among all owners in the well. This 

Subchapter is intended to supplement and clarify as needed the language in the 

statutes.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-27-2. Effective date [Revoked]

[Source: Added at 10 OK Reg 2601, eff 6-25-93; Revoked at 11 Ok Reg 3699, eff 

7-11-94]

165:10-27-3. Definitions

The following words or terms, when used in this Subchapter, shall have the 

following meaning, unless the context clearly indicates otherwise.

"Owner" means a person or governmental entity with a legal interest in the 

mineral acreage under a well which entitles that person or entity to oil or gas 

production or the proceeds or revenues therefrom.

"Produce", "producing" and "production" mean the physical act of severance of 

oil and gas from a well by an owner and includes but is not limited to the sale 

or other disposition thereof.

"Producing owner" means an owner entitled to produce who during a given month 

produces oil or gas for its own account or the account of subsequently created 

interests as they burden its interest.

"Proportionate production interest" means that interest in production which a 

working interest owner is entitled to produce in order to adjust for shifting of 

royalty burdens among working interest owners under the royalty provisions of 52 

O.S. Sections 570.1, et seq., and is equal to the quotient of:
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 266 -

(A) the sum of a working interest owner's net revenue interest plus the 

net revenue interests of any subsequently created interests as they burden 

such owner's working interest,

(B) divided by the remainder of one (1) less the royalty share.

"Proportionate royalty share" means the percentage of the royalty share owned 

by a royalty interest owner calculated by dividing such owner's royalty interest 

in a well by the royalty share.

"Royalty interest" means the entirety of the percentage interest in 

production or proceeds therefrom:

(A) reserved or granted by a mineral interest owner exclusive of any 

interest defined as a working interest or a subsequently created interest, 

or 

(B) otherwise provided or ascribed to a mineral interest owner by 

statute, rule, order or operation of law.

"Royalty interest in a well" means an owner's royalty interest multiplied by 

the quotient of:

(A) the gross mineral acres under the well attributable to such interest, 

divided by

(B) the total mineral acres under the well.

"Royalty proceeds" means the share of proceeds or other revenue derived from 

or attributable to any production of oil and gas attributable to the royalty 

share, but shall not include payments of bonus, delay rentals, shut-in royalties 

or any additional royalty payable to the Commissioners of the Land Office or 

other governmental entity, pursuant to and valued according to the terms of its 

oil and gas lease, which is calculated separately from the royalty portion of 

actual proceeds from the sale of oil or gas.

"Royalty share" means the percentage of the well equal to the sum of all 

royalty interests in the well.

"Share of production" means the monthly entitlement to produce belonging to a 

producing owner.

"Shipper" means any entity who contracts with a transporter to move gas 

through the transporter's system.

"Subsequently created interest" means any interest carved from a working 

interest other than a royalty interest. In addition to the royalty interest 

contained in a lease, a non-participatory interest created by a working interest 

owner for the benefit of a mineral interest owner in excess of a one-eighth 

(1/8) royalty interest may, by separate agreement other than the oil and gas 

lease, be a subsequently created interest and thereby not be communitized under 

the terms of the Production Revenue Standards Act only if there is clear and 

unambiguous language expressing that intent in the creating document. The 

additional royalty payable to the Commissioners of the Land Office or other 

governmental entity pursuant to and valued according to the terms of its oil and 

gas lease, which is calculated separately from the sale of oil or gas, shall 

also be a subsequently created interest and thereby shall not be communitized 

under 52 O.S. Section 570.1, et seq.

"Well" means an oil or gas well, and shall include:

(A) a well having uniform ownership as to all producing zones, or 

(B) a drilling and spacing unit having uniform ownership wherein multiple 

wells producing gas are commonly metered, and 

(C) each separately metered producing zone within a single wellbore 

wherein ownership varies by zone.

"Working interest" means the interest in a well entitling the owner thereof 

to drill for an produce oil and gas, including but not limited to the interest 

of a participating mineral owner to the extent set forth in Section 87.1 of 

Title 52 of the Oklahoma Statutes.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93; Amended at 11 Ok Reg 3699, eff 

7-11-94]
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 267 -

165:10-27-4. Well operator records

Each well operator shall establish or cause to be established records showing 

the production allocations and payments to each interest owner in the well. For 

purposes of such records, the working interest owners shall provide the well 

operator with accounting and remittance information as required by statute. At 

a minimum, the required information shall consist of the name, address, interest 

amount and tax identification number of each royalty owner along with payment 

status. Each working interest owner shall provide said information in writing 

within 60 days of receipt of a written information request from the well 

operator. Updated information shall be provided by a working interest owner 

within 60 days after receipt of notice of a change.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93; Amended at 11 Ok Reg 3699, eff 

7-11-94]

165:10-27-5. Pre-sale nominations

(a) Any producing owner marketing production separately from the well 

operator shall send pre-production nominations to the well operator for his 

withdrawals. A nomination shall be due five business days prior to the month in 

which the nomination is to be effective, but earlier if required by the first 

purchaser or transporter. The nomination shall consist of the name of the first 

purchaser or shipper, shipper contract number and the volumes of gas nominated 

for production for such producing owner's account.

(b) Nothing in this Section shall supersede or limit the operator's right to 

control gas nominations and allocations under a joint operating agreement, 

separate balancing agreement or Commission order.

(c) The owner of the gas meter shall confirm all nominations with the operator 

of the well no later than the last business day prior to the month in which 

production occurs.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93; Amended at 11 Ok Reg 3699, eff 

7-11-94]

165:10-27-6. Entitlement

Each producing owner in a well shall be entitled to produce each month his 

proportionate production interest subject to balancing restrictions created by 

statute, rule, agreement or operation of law.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-27-7. Post-sale reports

(a) Within sixty days after the end of the month of production, each producing 

owner shall report and account to the operator of the well, the identity of the 

first purchaser or shipper of the gas and information specified in 165:10-27-13.

(b) Within fifteen days after the end of the month of production, each owner of 

a gas meter taking gas solely from a gathering system shall provide upon first 

request by the owner of such gathering system and thereafter, the gross volume 

of gas measured by such meter both in MCF and British Thermal Unit equivalent.

(c) Within twenty days after the end of the month of production, each owner of 

a gas meter shall provide or cause to be provided in writing to the operator of 

the well, the gross volume of gas measured by such meter, both in MCF and 

British Thermal Unit equivalent, and the volume of gas allocated at the meter to 

each first purchaser or shipper and each contracted producing owner that sold 

gas to the owner of the gas meter. Each meter owner shall, within the same time 

period, furnish each first purchaser or shipper the volume of gas allocated at 

the meter to that first purchaser or shipper. However, if the gas processing 

plant operator is performing the allocations, then within ten days after the end 

of the month of production, the owner of the pipeline residue gas meter shall 

provide, upon first request by the processing plant operator and thereafter, the 

volume in MCF and British Thermal Unit equivalent measured through its meter as 
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 268 -

required by the gas processing plant operator for its allocations under this 

subsection.

(d) As an alternative to supplying the operator with information in the manner 

prescribed by subsections (b) and (c) of this Section, the owner of a gas meter 

who has a contract with one or more producing owners, covering all of the gas 

flowing through its meter, may furnish monthly volume statements to the operator 

of the well, provided said owner of the gas meter has previously furnished the 

operator with names of the producing owners and the decimal interest owned by 

each such producing owner or owners or any method other than by decimal interest 

then in effect for allocating gas among the producing owners. After adopting 

alternative reporting under this subsection, the owner of the gas meter shall be 

required to supply the operator of the well with any change to the name of a 

producing owner, the decimal interest by a producing owner or the method, other 

than by decimal interest, for allocating gas among the producing owners: such 

change to reported by the owner of the gas meter to the operator of the well 

within thirty days after the owner of the gas meter receives notice of such 

change.

(e) Within thirty-five days after the end of the month of production, each 

first purchaser or shipper of gas from a gas meter shall furnish or cause to be 

furnished to the operator of the well, a volume allocation statement showing the 

volume of gas purchased from or shipper for each contracted producing owner. 

Within thirty days after making any retroactive gas volume adjustment for such 

well, the first purchaser or shipper shall furnish notice of such retroactive 

gas volume adjustment to the operator of the well.

(f) Any person subject to multiple reporting requirements under this Section 

shall not be required to re-report the same information to the operator if such 

information has been previously provided by such person in a different report. 

Such person may consolidate the required information into a single report to the 

operator; provided, however, that all such reporting must comply with the 

applicable statutory time periods for the type of information being communicated 

to the operator.

(g) Any first purchaser, shipper or owner of a gas meter that does not provide 

the information required of it by this Section shall be subject to having its 

takes from the well suspended by the operator of the well pursuant to 165:10-27-

8.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93; Amended at 11 Ok Reg 3699, 7-11-

94]

165:10-27-8. Operator's option to confirm zero volume of gas sales because of 

noncompliance

(a) If a producing owner fails to timely provide the operator of the well with 

any of the information required by 165:10-27-4 and 165:10-27-7, or if the owner 

of a gas meter, first purchaser or shipper of gas fails to timely provide the 

operator of the well with any of the information required of it by 165:10-27-7 

for the transfer, transportation, delivery or sale of gas by a producing owner, 

the operator of the well shall have the right, but not the obligation, to 

confirm zero volume of gas sales for such producing owner, and to make available 

for nomination and sale to other producing owners in the well, then in 

compliance with said Sections, all of such producing owner's share of production 

for the next subsequent calendar month and for each and every month thereafter 

of noncompliance. If the operator elects to make such producing owner's share 

of production available for nomination and sale, the operator shall immediately 

notify such producing owner by certified mail and inform such producing owner 

that such producing owner shall no longer have the right to nominate any volume 

of gas, until the next production month following the date of compliance, unless 

the operator of the well agrees to an earlier date. Such notice shall contain 

the lease or well identification, legal description, production months of 

noncompliance, a brief description of the noncompliance, and a provision stating 

that the operator is confirming zero volume of gas sales for such producing 
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 269 -

owner. The operator shall than immediately notify each producing owner then in 

compliance with the aforesaid Sections and inform said producing owner about 

additional gas volumes available for nomination and sale. In regard to the 

producing owner for which the operator has confirmed zero gas sales, the 

operator shall also immediately notify in writing such producing owner's first 

purchaser or shipper, and the owner of the gas meter, and such notice shall 

report that such producing owner does not have the right to nominate and sell or 

transport any volume of gas, until the next production month following 

compliance, unless the operator of the well agrees to an earlier date. Such 

notice shall also contain the lease or well identification, legal description, a 

brief description of the noncompliance, and the production months of 

noncompliance.

(b) As soon as a noncomplying party is in compliance, but no sooner than the 

next production month unless otherwise agreed to, the operator of the well shall 

give the affected producing owner the opportunity to nominate and sell gas 

subject to existing agreements or by common practice within the oil and gas 

industry.

(c) The first purchaser or shipper and the owner of the gas meter shall be 

entitled to rely on and shall incorporate on a prospective basis any nomination 

or allocation changes pursuant to such notification from the operator under this 

Section. Changes pursuant to such notification may be made on a retroactive 

basis if so agreed to by the operator, owner of the meter, the first purchaser 

or shipper.

(d) The remedies provided for in this Section shall not preclude any party from 

pursuing the remedies available to it through the district courts, as provided 

by existing law, including the right of offset.

(e) All elections and notices given pursuant to the provisions of this 

Subchapter shall become effective as of the first day of the month following the 

end of any time period specified in the Production Revenue Standards Act as last 

amended, 52 O.S. Section 570.1, et seq.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93; Amended at 11 Ok Reg 3699, eff 

7-11-94]

165:10-27-9. Designated payor for royalty distributions

(a) For royalty distributions, the well operator shall serve as payor for all 

proceeds of production, absent appointment of a substitute payor and/or election 

of a working interest owner to distribute royalties attributable to that working 

interest owner's sales.

(b) A substitute payor may be appointed by Commission order or by the owners 

owning a majority in interest of the working interest in the well. A substitute 

payor so appointed shall assume the rights and duties of the well operator 

concerning assessment of fees, royalty record maintenance and disbursement of 

royalties. A surety bond of $50,000 shall be required if the substitute payor 

is not a working interest owner, a first purchaser of production from the well, 

a bank or a trust company. Such bond shall be posted with the Surety Department 

of the Conservation Division before receipt of sales proceeds by the substitute 

payor. Any such bond shall be drafted so as to compensate royalty owners if the 

substitute payor defaults on his disbursement obligation.

(c) A producing owner may elect to distribute royalties from his sales subject 

to the following conditions:

(1) the producing owner shall provide 60 days written notice to the 

operator before starting or stopping the alternative procedure;

(2) the producing owner shall assume liability for its errors;

(3) the producing owner shall report payment information to the well 

operator within 30 days after each disbursement;

(4) the producing owner cannot re-start the alternative procedure within 

12 months after terminating it.
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 270 -

(d) For good cause shown, the Commission may cancel a producing owner's 

election to separately distribute royalty. Cancellation shall occur only by 

order after application, notice and hearing.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-27-10. Administrative fees

(a) This Section prescribes fees which may be charged by the operator of a gas 

producing well or substitute payor, for administrative expenses generated by the 

Production Revenue Standards Act.

(b) Fees shall be assessed on a per-well basis against the cost-bearing working 

interests in a well according to respective gross working interest. They shall 

not be assessed against either royalty interests or non-cost bearing working 

interests in the well.

(c) A one-time implementation fee shall cover any cost associated with 

establishing or modifying the well operator's record keeping for the well, and 

it shall apply to any existing gas producing well with a date of first 

production occurring before September 1, 1992. If operations are transferred to 

a different operator after assessment of the one-time implementation fee, the 

successor operator may not assess another implementation fee against the working 

interests in the well.

(d) Should any working interest owner in a well producing gas fail to fully and 

timely comply with the requirements of 165:10-27-4, the well operator or 

substitute payor shall have the right to charge against said non-complying 

working interest owner a late fee of two hundred-fifty dollars per affected 

well.

(e) An annual maintenance fee shall cover any cost associated with record 

keeping, issuance of gas balancing statements and any election of a producing 

owner regarding separate distribution of royalty proceeds. Maintenance fees 

shall be calculated on an annual basis using the first day of May as the 

anniversary date. Such fees may be prorated and billed on a monthly basis at 

the well operator's discretion. If a well has a date of first production after 

the first day of May of the calendar year, the annual maintenance fee shall be 

prorated based on the remaining number of months before the next anniversary 

date on the first day of May.

(f) No working interest owner other than the well operator shall be entitled to 

assess either an implementation fee or a maintenance fee.

(g) The rates for implementation fees and annual maintenance fees shall be 

based on the appropriate table values found in Appendix G to this Chapter, 

subject to annual adjustments as provided below. The appropriate table value 

shall be determined from a matrix using the number of working interest owners or 

royalty owners in a well. The table value shall be adjusted as of the first day 

of May each year following May 1, 1993. The annual adjustment shall be computed 

by multiplying the rate currently in use by the percentage of increase or 

decrease in the annual overhead adjustment factor established by the Council of 

Petroleum Accountants Societies at its annual spring meeting for purposes of 

adjusting the combined fixed-rate overhead charges against joint operations in a 

well.

(h) Any fee assessed under this Section may be billed or deducted from the 

working interest owner's share of undistributed proceeds of production.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-27-11. Balancing of royalty accounts

(a) In the event of a production imbalance among royalty owners in a well, the 

affected working interest owners may adopt a royalty payment method to balance 

the royalty accounts, provided it is used only to extent necessary to balance 

the cumulative accounts of the royalty owners, and prior notice of the plan is 

sent to the affected royalty owners and to the well operator along with any 

ongoing information necessary for said operator to discharge its duties.
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 271 -

(b) Nothing in this Section shall impair any balancing rights arising by 

contract or law.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-27-12. Record keeping

Any record required by this Subchapter shall be maintained for a period of at 

least five years. Upon reasonable request, the well operator or substitute 

payor shall make available to a royalty owner for confidential inspection a 

record of receipts and payment of proceeds to said royalty owner, as well as 

copies of information furnished to the well operator pursuant to the Production 

Revenue Standards Act.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]

165:10-27-13. Check stub information

(a) With each royalty payment, the following information shall be provided:

(1) lease or well identification;

(2) month and year of sales included in the payment;

(3) total barrels or MCF attributed to such payment;

(4) price per barrel or MCF, including British Thermal Unit adjustment of 

gas sold;

(5) gross production and severance taxes attributable to said interest;

(6) net value of total sales attributed to such payment after deduction 

of gross production and severance taxes;

(7) owner's interest in the well expressed as a decimal;

(8) owner's share of the total value of sales attributed to such payment 

before any deductions;

(9) owner's share of the sales value attributed to such payment less 

owner's share of the production and severance taxes.

(b) Upon payee's request, the payor shall provide a list of any other deduction 

from such payment.

(c) All revenue decimals shall be calculated to at least six decimal places.

(d) Gas volumes shall be measured according to 52 O.S. Section 474.

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]
OAC 165:10-27 Corporation Commission

Eff. 8-27-15

- 272 -

[BLANK PAGE]
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 273 -

SUBCHAPTER 29. SPECIAL AREA RULES

Section

165:10-29-1. Lake Atoka and McGee Creek Reservoir

165:10-29-2. Alternative location requirements for horizontal well units

165:10-29-3. Rush Springs Sandstone Groundwater Basin

165:10-29-1. Lake Atoka and McGee Creek Reservoir

(a) Scope. The requirements of this section will apply to wells located in 

the areas listed below, and will supersede all field orders related to these 

areas. These requirements are in addition to the Commission’s existing 

statewide requirements. The areas controlled by this section include:

(1) IN ATOKA COUNTY

(A) Sections 1-35 of Township 1 North, Range 12 East;

(B) Sections 1-18, 21-28 and 35-36 of Township 1 North, Range 13 East;

(C) Sections 1-36 of Township 1 North, Range 14 East;

(D) Section 6 of Township 1 North, Range 15 East;

(E) Sections 1-5, 8-16, 20-29 and 32-36 of Township 2 North, Range 12 

East;

(F) Sections 1-36 of Township 2 North, Range 13 East;

(G) Sections 4-9 of Township 2 North, Range 14 East;

(H) Sections 1-2, 11-14, 23-26 and 36 of Township 1 South, Range 11 

East;

(I) Sections 2-10, 16-20, 24-25 and 30-31 of Township 1 South, Range 

12 East;

(J) Sections 1-3, 9-16, 19-30 and 32-36 of Township 1 South, range 13 

East;

(K) Sections 1-11 and 13-36 of Township 1 South, Range 14 East;

(L) Sections 1-5, 8-17, 22-27 and 34-36 of Township 2 South, Range 13 

East;

(M) Sections 1-24 and 26-35 of Township 2 South, Range 14 East;

(N) Sections 1-2 and 12 of Township 3 South, Range 13 East;

(O) Sections 2-9 of Township 3 South, Range 14 East.

(2) IN PITTSBURG COUNTY

(A) Sections 7, 18-22 and 25-36 of Township 2 North, Range 14 East;

(B) Section 31 of Township 2 North, Range 15 East;

(C) Sections 1-3, 9-16, 20-29 and 32-36 of Township 3 North, Range 12 

East;

(D) Sections 1-36 of Township 3 North, Range 13 East;

(E) Sections 6 and 28-33 of Township 3 North, Range 14 East;

(F) Sections 26-28 and 32-36 of Township 4 North, Range 13 East.

(3) IN COAL COUNTY Sections 12-14, 22-27 and 34-36 of Township 1 North, 

Range 11 East.

(b) General. The design criteria for all wells shall consider all pertinent 

factors for well control including formation pressures and casing setting 

depths such that the wellbore can be maintained under control at all times and 

that all surface and subsurface fresh water supplies or formations are 

protected.

(c) Well site limitations. No oil and/or gas well shall be located within 

1,320 feet of the maximum water surface level contour line of either reservoir. 

The maximum water surface level is 609.8 feet above sea level for McGee Creek 

and 590 feet above sea level for Lake Atoka Reservoir.

(d) Drill site containment. During the drilling and completion of an oil and 

gas well the operator shall:

(1) Maintain an earthen retaining wall downslope of the well, no closer 

than 50 feet from the wellbore, if the well is located within six (6) miles 
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 274 -

of the maximum water surface level contour line of either reservoir. The 

maximum water surface level is 609.8 feet above sea level for McGee Creek 

Reservoir and 590 feet above sea level for Lake Atoka. The retaining wall 

shall be constructed prior to the commencement of drilling and shall be of 

adequate size for the terrain involved with a minimum length of 330 feet and 

a minimum compacted height of two (2) feet;

(2) Maintain a diversion ditch upslope of the well. The diversion ditch 

shall be constructed prior to the commencement of drilling and shall be 

adequate to divert surface drainage water from the well location;

(3) Pump any fluid, other than storm water, trapped within the well site into 

steel tanks for storage and removal. Storm water may be discharged as 

necessary as long as there is no sheen or other visible evidence of 

hydrocarbons being present, the chloride concentration does not exceed 500 

mg/l, and the operator maintains records of each discharge for a period of 

three (3) years. These records must be supplied to the Commission upon 

request.

(e) Production site containment. 

(1) During production operations, all fluid separation and storage vessels 

shall be enclosed within earthen or equivalent retaining walls so that the 

enclosed area has a storage capacity of at least one and one-half (1.5) 

times the liquid capacity of the largest vessel in the storage area.

(2) Any fluid other than storm water and any storm water that cannot be 

discharged will be pumped into steel tanks for storage and removal. Storm 

water may be discharged as necessary as long as there is no sheen or other 

visible evidence of hydrocarbons being present, the chloride concentration 

does not exceed 500 mg/l, and the operator maintains records of each 

discharge for a period of three (3) years. These records must be supplied 

to the Commission upon request.

(f) Erosion control. During the drilling phase of operations, silt fencing or 

other suitable materials or practices shall be used on the downslope side of 

the drill site to control runoff from the location. The silt fencing or other 

suitable materials or practices used to control runoff at the location shall be 

maintained in a manner so as to consistently work to control run-off.

(g) Circulating and reserve pits. 

(1) Steel tanks shall be used for circulating and reserve pits for all 

drilling operations located within one (1) mile of the maximum water surface 

level contour line of either reservoir. The maximum water surface level is 

609.8 feet above sea level for McGee Creek Reservoir and 590 feet above sea 

level for Lake Atoka.

(2) Outside of the areas designated by OAC 165:10-29-1(g)(1), any pit shall 

be lined with a geomembrane liner that meets or exceeds each of the 

following specifications:

(A) be made of linear low density polyethylene;

(B) have a thickness of 20 millimeters; and

(C) conform to the test requirements prescribed in the Geosynthetic 

Research Institute (GRI) Test Method GM17; and

(D) The liner shall also comply with the requirements for geomembrane 

liners found in OAC 165:10-7-16(c)(7).

(3) No pit shall be constructed or maintained so as to receive outside 

runoff water and the fluid level of earthen pits shall be maintained at all 

times as least 24 vertical inches below the lowest point of embankment. 

(4) If there is flowback during the fracing of a well, the flowback must be 

to steel tanks prior to being placed into a lined pit if the temperature of 

the flowback exceeds 150 degrees Fahrenheit. 

(5) The Oklahoma Corporation Commission shall inspect all pits within the 

purview of these rules prior to the liner being installed. The operator 

shall notify the District Office at least one (1) business day prior to 

installation of the liner. If the Commission has not inspected the pit 

within one (1) business day following the notification, the operator may 

proceed to install the liner.
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 275 -

(6) Any reserve/circulation pit shall be closed within six (6) months after 

drilling operations cease. Upon request by the operator, a six (6) month 

extension shall be granted by the District Office, after review by a field 

inspector to confirm the pit is in compliance with Commission requirements.

(h) Air drilling. When drilling with air for circulation, an unlined earthen 

pit to contain the wellbore cuttings is allowed, provided the chloride 

concentration of any fluids discharged into the pit does not exceed 1000 mg/l. 

Discharge of air and cuttings from the "blooey line" shall be subjected to 

fresh water injection or spray to eliminate, to the greatest extent possible, 

the drift of dust and particulates from the well site. Water and additives for 

liquid drilling fluid shall be maintained at the well site at all times in 

sufficient volumes to circulate the wellbore if needed. All water in the 

unlined earthen pit shall be removed and properly disposed of as soon as air 

drilling ceases.

(i) Casing. All casing shall be new or reconditioned and tested to conform to 

API specifications.

(1) Surface casing. Surface casing shall be set to a minimum depth of 700 

feet, or 50 feet below the deepest treatable water, whichever depth is 

greater. In setting the surface casing, a minimum of six (6) centralizers 

shall be used in the bottom portion of the casing string.

(2) Production casing. Production casing of four and one-half (4.5) inches 

or greater OD, and all related equipment items, such as the wellhead valves, 

shall have a pressure rating sufficiently in excess of the highest formation

pressure encountered in the well. In setting the production casing, the 

annular space between the wellbore and the production casing shall be filled 

with cement calculated to fill at least 500 feet above the shallowest 

planned zone to be tested. Centralizers shall be used across the planned 

zone(s) to be tested. The production casing shall be pressure tested to 

conform to OAC 165:10-3-4(g). In the event the total depth of the well is 

less than 500 feet, the annular space between the wellbore and the 

production casing shall be filled with cement calculated to fill at least 

that portion of the wellbore to the base of the surface casing. 

Centralizers shall be used across the planned zone to be tested. The 

production casing shall be pressure tested to comply with OAC 165:10-3-4(g).

(j) Blowout prevention equipment. Before drilling below the surface casing 

and until drilling operations are completed, a blowout preventer (BOP) with a 

minimum of two (2) hydraulically operated rams, one (1) blind type and one (1) 

pipe type to fit the drill pipe, and related well control equipment, including 

a manifold and a floor valve, with a working pressure that exceeds the maximum 

anticipated surface pressure, shall be installed, used and tested in a manner 

to prevent blowouts. The BOP stack shall include a drilling spool with side 

outlets if side outlets are not provided on the BOP body. BOPs shall be tested 

to the rated pressure of the blowout stack assembly. All blowout prevention 

equipment is to be tested prior to drilling out from the surface casing. While 

drilling operations are in progress, the BOP shall be actuated once each trip. 

When removing drill pipe from any hole that utilized drilling fluids, the 

annulus shall be filled with mud before the mud level drops 100 feet from 

surface. A Kelley-cock shall be installed below the swivel. Wells being 

drilled to a depth less than 4,000 feet may use annular type blowout 

preventers. 

(k) Drill stem testing. Drill stem testing shall only be allowed during 

daylight hours. Fluid removed from the well during testing must be flowed or 

pumped into steel pits or tanks and promptly removed from the location at the 

conclusion of testing. The formation fluids in the hole shall be reversed-out 

prior to the removing of the drill stem test tool from the hole. 

(l) Prevention of leakage and pollution. Equipment, pipe, pumps, tanks, and 

other appurtenances used in conducting operations shall be maintained at all 

times to prevent leakage and the escape of saltwater, oil and other deleterious 

substances. All oil, water and deleterious substances from wet strings of 
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 276 -

tubing shall be drained into steel tanks. All cellars with oil and oil sumps 

shall be promptly pumped out.

(m) Exceptions to this section. When good cause is shown, and when it is not 

reasonably likely to result in any pollution to either reservoir, an 

administrative exception to a requirement of this section may be granted by the 

Oklahoma Corporation Commission. Notice of an application for an exception to 

this section shall be sent at least 15 days in advance to: (1) the manager of 

the District 4 Office of the Oil and Gas Conservation Division of the Oklahoma 

Corporation Commission; (2) the General Manager of the Oklahoma City Water 

Utilities Trust, 420 W. Main, Suite 500, Oklahoma City, Oklahoma 73102; and (3) 

the General Manager of the McGee Creek Authority, 420 W. Main, Suite 500, 

Oklahoma City, Oklahoma 73102. A 15-day period from the date of the written 

notice should be established for any party to file an objection to such an 

administrative application. If an objection is filed, a full hearing shall be 

held on the merits.

(n) Other. In reviewing an application for a permit-to-drill (form 1000), the 

Technical Services Department of the Oklahoma Corporation Commission will 

determine whether or not the well lies within any of the areas designated in 

OAC 165:10-29-1(c), OAC 165:10-29-1(d)(1) and OAC 165:10-29-1(g)(1).

[SOURCE: Added at 25 OK Reg 2187, eff 7-11-08 (RM 200800003)]

165:10-29-2. Alternative location requirements for horizontal well units

(a) Scope and effect. The well location requirements of this Section apply to 

horizontal wells completed in horizontal well units in designated common 

sources of supply as specified in this Section. Horizontal wells covered by 

this Section are subject to OAC 165:10-3-28 and other applicable Commission 

rules except as provided in this Section.

(b) Woodford shale.

(1) This subsection applies to horizontal wells completed in the Woodford 

shale common source of supply.

(2) The completion interval of a horizontal well subject to this subsection 

shall be located not less than the minimum distance from the boundary of a 

standard or non-standard horizontal well unit as follows:

(A) Not less than 330 feet from an east or west unit boundary.

(B) Not less than 165 feet from a north or south unit boundary.

[Source: Added at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Amended at 32 

Ok Reg 767, eff. 8-27-15 (RM 201500001)]

165:10-29-3. Rush Springs Sandstone Groundwater Basin

(a) Scope. The requirements of this section will apply to the areas listed 

below, and will supersede Commission field order number 251978 related to these 

areas. These requirements are in addition to the Commission’s existing 

statewide requirements. The areas controlled by this section include:

(1) IN BECKHAM COUNTY

(A) Sections 1-18, 21-25 and 36 of Township 8 North, Range 21 West;

(B) Sections 1-5, and 8-12 of Township 8 North, Range 22 West;

(C) Sections 19 and 26-36 of Township 9 North, Range 21 West;

(D) Sections 21-28 and 33-36 of Township 9 North, Range 22 West.

(2) IN BLAINE COUNTY

(A) Sections 2-11, 15-22 and 26-35 of Township 13 North, Range 12 

West;

(B) All sections of Township 13 North, Range 13 West;

(C) Sections 2-35 of Township 14 North, Range 12 West;

(D) All sections of Township 14 North, Range 13 West;

(E) Sections 6-8, 16-21 and 27-35 of Township 15 North, Range 12 West;

(F) All sections of Township 15 North, Range 13 West;

(G) Sections 30 and 31 of Township 16 North, Range 12 West;

(H) Sections 3-11 and 13-36 of Township 16 North, Range 13 West;
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 277 -

(I) Sections 5-8, 16-21 and 28-34 of Township 17 North, Range 13 West;

(J) Sections 31 and 32 of Township 18 North, Range 13 West.

(3) IN CADDO COUNTY

(A) All sections of Township 5 North, Range 9 West;

(B) All sections of Township 5 North, Range 10 West;

(C) Sections 1-17, 20-29 and 33-36 of Township 5 North, Range 11 West;

(D) Sections 1, 2 and 12 of Township 5 North, Range 12 West;

(E) Sections 2-36 of Township 6 North, Range 9 West;

(F) All sections of Township 6 North, Range 10 West;

(G) All sections of Township 6 North, Range 11 West;

(H) Sections 1-5, 7-18, 21-27, 35 and 36 of Township 6 North, Range 12 

West;

(I) Sections 12 and 13 of Township 6 North, Range 13 West;

(J) Sections 31-35 of Township 7 North, Range 9 West;

(K) Sections 4-10, 15-23 and 25-36 of Township 7 North, Range 10 West;

(L) All sections of Township 7 North, Range 11 West;

(M) Sections 1-30 and 32-36 of Township 7 North, Range 12 West;

(N) Sections 1-18 and 21-24 of Township 7 North, Range 13 West;

(O) Sections 6, 7, 17-20 and 28-33 of Township 8 North, Range 10 West;

(P) All sections of Township 8 North, Range 11 West;

(Q) All sections of Township 8 North, Range 12 West;

(R) All sections of Township 8 North, Range 13 West;

(S) Sections 3-11, 14-23 and 26-36 of Township 9 North, Range 11 West;

(T) All sections of Township 9 North, Range 12 West;

(U) All sections of Township 9 North, Range 13 West;

(V) Sections 6-9, 14-23, 26-30 and 32-34 of Township 10 North, Range 9 

West;

(W) Sections 1-27 of Township 10 North, Range 10 West;

(X) Sections 1-8, 10-13, 17-20 and 28-33 of Township 10 North, Range 

11 West;

(Y) All sections of Township 10 North, Range 12 West;

(Z) All sections of Township 10 North, Range 13 West;

(AA) All sections of Township 11 North, Range 11 West;

(BB) All sections of Township 11 North, Range 12 West;

(CC) All sections of Township 11 North, Range 13 West;

(DD) Sections 4, 5, 7-9 and 14-36 of Township 12 North, Range 11 West;

(EE) Sections 2-36 of Township 12 North, Range 12 West;

(FF) All sections of Township 12 North, Range 13 West.

(4) IN CANADIAN COUNTY

(A) Sections 16-21 and 28-30 of Township 11 North, Range 9 West;

(B) Sections 5-11 and 13-35 of Township 11 North, Range 10 West;

(C) Section 31 of Township 12 North, Range 10 West.

(5) IN COMANCHE COUNTY

(A) Sections 1-17, 21-27, 35 and 36 of Township 3 North, Range 9 West;

(B) Sections 1, 2 and 12 of Township 3 North, Range 10 West;

(C) All sections of Township 4 North, Range 9 West;

(D) Sections 1-29 and 33-36 of Township 4 North, Range 10 West;

(E) Sections 1-4 and 11-13 of Township 4 North, Range 11 West.

(6) IN CUSTER COUNTY

(A) All sections of Township 12 North, Range 14 West;

(B) All sections of Township 12 North, Range 15 West;

(C) All sections of Township 12 North, Range 16 West;

(D) Sections 1-28 and 34-36 of Township 12 North, Range 17 West;

(E) Sections 1-4 and 11-13 of Township 12 North, Range 18 West;

(F) All sections of Township 13 North, Range 14 West;

(G) All sections of Township 13 North, Range 15 West;

(H) All sections of Township 13 North, Range 16 West;

(I) All sections of Township 13 North, Range 17 West;

(J) Sections 1-30 and 32-36 of Township 13 North, Range 18 West;

(K) Sections 1-5, 9-15 and 24 of Township 13 North, Range 19 West;
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 278 -

(L) All sections of Township 14 North, Range 14 West;

(M) All sections of Township 14 North, Range 15 West;

(N) All sections of Township 14 North, Range 16 West;

(O) All sections of Township 14 North, Range 17 West;

(P) All sections of Township 14 North, Range 18 West;

(Q) All sections of Township 14 North, Range 19 West;

(R) Sections 1-3, 10-14 and 23-25 of Township 14 North, Range 20 West;

(S) All sections of Township 15 North, Range 14 West;

(T) All sections of Township 15 North, Range 15 West;

(U) All sections of Township 15 North, Range 16 West;

(V) All sections of Township 15 North, Range 17 West;

(W) All sections of Township 15 North, Range 18 West;

(X) All sections of Township 15 North, Range 19 West;

(Y) Sections 1-3, 10-15, 22-27 and 34-36 of Township 15 North, Range 

20 West.

(7) IN DEWEY COUNTY

(A) All sections of Township 16 North, Range 14 West;

(B) All sections of Township 16 North, Range 15 West;

(C) All sections of Township 16 North, Range 16 West;

(D) All sections of Township 16 North, Range 17 West;

(E) All sections of Township 16 North, Range 18 West;

(F) All sections of Township 16 North, Range 19 West;

(G) Sections 1-3, 10-15, 22-27 and 34-36 of Township 16 North, Range 

20 West;

(H) All sections of Township 17 North, Range 14 West;

(I) All sections of Township 17 North, Range 15 West;

(J) All sections of Township 17 North, Range 16 West;

(K) All sections of Township 17 North, Range 17 West;

(L) All sections of Township 17 North, Range 18 West;

(M) All sections of Township 17 North, Range 19 West;

(N) Sections 12-14, 23-26, 35 and 36 of Township 17 North, Range 20 

West;

(O) Sections 31-36 of Township 18 North, Range 14 West;

(P) Sections 31-36 of Township 18 North, Range 15 West;

(Q) Sections 31-36 of Township 18 North, Range 16 West;

(R) Sections 31-36 of Township 18 North, Range 17 West;

(S) Sections 31-36 of Township 18 North, Range 18 West;

(T) Sections 31-36 of Township 18 North, Range 19 West.

(8) IN GRADY COUNTY

(A) Sections 19, 20 and 29-32 of Township 3 North, Range 6 West;

(B) All sections of Township 3 North, Range 7 West;

(C) All sections of Township 3 North, Range 8 West;

(D) Sections 4-36 of Township 4 North, Range 7 West;

(E) All sections of Township 4 North, Range 8 West;

(F) Sections 27-29 and 31-34 of Township 5 North, Range 7 West;

(G) Sections 2-11, 14-23 and 26-36 of Township 5 North, Range 8 West;

(H) Sections 7-11, 14-23 and 25-26 of Township 6 North, Range 8 West.

(9) IN KIOWA COUNTY

(A) Sections 1-6 and 9-14 of Township 7 North, Range 14 West;

(B) Sections 1-3 of Township 7 North, Range 15 West;

(C) All sections of Township 8 North, Range 14 West.

(10) IN STEPHENS COUNTY

(A) Sections 5 and 6 of Township 2 North, Range 6 West;

(B) Sections 1-12 of Township 2 North, Range 7 West;

(C) Sections 1-6 and 10-12 of Township 2 North, Range 8 West;

(D) Section 1 of Township 2 North, Range 9 West.

(11) IN WASHITA COUNTY

(A) Sections 1-6 of Township 7 North, Range 14 West;

(B) All sections of Township 8 North, Range 14 West;

(C) All sections of Township 8 North, Range 15 West;
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 279 -

(D) Sections 1-30, 35 and 36 of Township 8 North, Range 16 West;

(E) Sections 1-30 of Township 8 North, Range 17 West;

(F) Sections 1-26 of Township 8 North, Range 18 West;

(G) Sections 1-24, 30 and 31 of Township 8 North, Range 19 West;

(H) All sections of Township 8 North, Range 20 West;

(I) All sections of Township 9 North, Range 14 West;

(J) All sections of Township 9 North, Range 15 West;

(K) Sections 1-5, 8-17 and 20-36 of Township 9 North, Range 16 West;

(L) Sections 31-36 of Township 9 North, Range 17 West;

(M) Sections 31-36 of Township 9 North, Range 18 West;

(N) Sections 31-36 of Township 9 North, Range 19 West;

(O) Sections 31-36 of Township 9 North, Range 20 West;

(P) All sections of Township 10 North, Range 14 West;

(Q) All sections of Township 10 North, Range 15 West;

(R) Sections 1-5, 8-17, 20-29 and 32-36 of Township 10 North, Range 16 

West;

(S) All sections of Township 11 North, Range 14 West;

(T) All sections of Township 11 North, Range 15 West;

(U) Sections 1-30 and 32-36 of Township 11 North, Range 16 West;

(V) Sections 1, 2 and 11-13 of Township 11 North, Range 17 West.

(b) Commercial pits prohibited. The construction, enlargement, reconstruction 

or operation of any commercial pit (as defined in OAC 165:10-9-1) in any area 

listed in subsection (a) above, is prohibited.

[SOURCE: Added at 29 OK Reg 950, eff 7-1-12 (RM 201200005)]
OAC 165:10-29 Corporation Commission

Eff. 8-27-15

- 280 -

[BLANK PAGE]
OAC 165:10 Appendix A Corporation Commission

Eff. 8-27-15

- 281 -

APPENDIX A. ALLOCATED WELL ALLOWABLE TABLE* [REVOKED]

[SOURCE: Revoked at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]

APPENDIX A. ALLOCATED WELL ALLOWABLE TABLE* [NEW]

 A C R E A G E 

DEPTH OF COMPLETION 10

INTERVAL** or less 20 40 80 160

 To-3000 30 45 57

3001-3200 31 45 57

3201-3400 32 46 58

3401-3600 33 47 59

3601-3800 34 48 60

3801-4000 35 49 61

4001-4200 36 49 61 71

4201-4400 37 50 62 73

4401-4600 38 51 63 75

4601-4800 39 52 64 77

4801-5000 40 53 65 79

5001-5200 41 54 67 82

5201-5400 42 55 69 85

5401-5600 43 56 71 88

5601-5800 45 58 73 91

5801-6000 47 60 75 94

6001-6200 49 62 77 97

6201-6400 51 64 79 100

6401-6600 53 66 82 103

6601-6800 55 68 85 107

6801-7000 57 70 88 110

7001-7200 59 72 90 113

7201-7400 61 74 92 116

7401-7600 63 76 95 119

7601-7800 65 78 98 122

7801-8000 67 80 101 126

8001-8200 69 83 104 130

8201-8400 71 86 107 134

8401-8600 73 89 111 139
OAC 165:10 Appendix A Corporation Commission

Eff. 8-27-15

- 282 -

Appendix A, p2

 A C R E A G E 

DEPTH OF COMPLETION 10

INTERVAL** or less 20 40 80 160

8601-8800 75 92 115 144

8801-9000 77 95 119 149

9001-9200 79 98 123 154

9201-9400 81 101 127 159

9401-9600 84 105 131 164

9601-9800 87 109 136 170

9801-10000 90 113 141 176

10001-10200 95 119 148 185 333

10201-10400 100 125 156 195 351

10401-10600 105 131 164 205 369

10601-10800 110 137 172 215 387

10801-11000 115 144 180 225 405

11001-11200 122 153 190 239 431

11201-11400 129 162 202 254 458

11401-11600 137 171 214 269 485

11601-11800 145 181 226 284 512

11801-12000 153 191 239 299 539

12001-12200 163 203 254 318 573

12201-12400 173 215 269 338 609

12401-12600 183 228 285 358 645

12601-12800 193 241 301 378 681

12801-13000 203 254 317 398 717

13001-13200 213 266 333 416 749

13201-13400 223 278 349 436 785

13401-13600 233 290 365 455 819

13601-13800 243 303 380 475 855

13801-14000 253 316 395 494 890

14001-14200 263 328 410 514 926

14201-14400 273 340 426 534 962

14401-14600 283 353 441 554 998
OAC 165:10 Appendix A Corporation Commission

Eff. 8-27-15

- 283 -

Appendix A, p3

 A C R E A G E 

DEPTH OF COMPLETION 10

INTERVAL** or less 20 40 80 160

14601-14800 293 366 457 573 1032

14801-15000 303 379 473 593 1068

 * Allowables currently are established at 200 percent of market demand. To 

determine the allowable for any well, the number in the appropriate column 

of the chart in the appendix must be doubled (multiplied by 2). The minimum 

allocated well is therefore 60 BOPD (from the 10 acre column, depth to 3,000 

feet, 30 BOPD times 2) (Market Demand). 

** Depth in feet from the surface of the ground to the top of the completion 

interval.

[SOURCE: New at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]
OAC 165:10 Appendix A Corporation Commission

Eff. 8-27-15

- 284 -

[BLANK PAGE]
OAC 165:10 Appendix B Corporation Commission

Eff. 8-27-15

- 285 -

APPENDIX B. DISCOVERY WELL ALLOWABLE TABLE [REVOKED]

[SOURCE: Revoked at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]

APPENDIX B. DISCOVERY WELL ALLOWABLE TABLE [NEW]

 (100 percent of market demand)

DEPTH OF BARRELS DAYS AFTER

COMPLETION INTERVAL* PER DAY DISCOVERY

0-1000 100 365

1001-1200 105 391

1201-1400 110 416

1401-1600 115 442

1601-1800 120 467

1801-2000 125 493

2001-2200 130 518

2201-2400 135 545

2401-2600 140 569

2601-2800 145 596

2801-3000 150 621

3001-3200 155 647

3201-3400 160 672

3401-3600 165 698

3601-3800 170 723

3801-4000 175 749

4001-4200 180 774

4201-4400 185 800

4401-4600 190 825

4601-4800 195 851

4801-5000 200 876

5001-5200 205 910

5201-5400 210 942

5401-5600 215 975

5601-5800 225 1007

5801-6000 235 1041

6001-6200 245 1073

6201-6400 255 1107

6401-6600 265 1139

6601-6800 275 1172

6801-7000 285 1205

7001-7200 295 1245

7201-7400 305 1285

7401-7600 315 1326

7601-7800 325 1365
OAC 165:10 Appendix B Corporation Commission

Eff. 8-27-15

- 286 -

Appendix B, p2

DEPTH OF BARRELS DAYS AFTER

COMPLETION INTERVAL* PER DAY DISCOVERY

7801-8000 335 1406

8001-8200 345 1445

8201-8400 355 1486

8401-8600 365 1526

8601-8800 375 1567

8801-9000 385 1606

9001-9200 395 1650

9201-9400 405 1694

9401-9600 420 1737

9601-9800 435 1781

9801-10000 450 1825

10001-10200 475 1837

10201-10400 500 1847

10401-10600 525 1859

10601-10800 550 1869

10801-11000 575 1880

11001-11200 610 1888

11201-11400 645 1895

11401-11600 685 1902

11601-11800 725 1910

11801-12000 765 1917

12001-12200 815 1917

12201-12400 865 1917

12401-12600 915 1917

12601-12800 965 1917

12801-13000 1015 1917

13001-13200 1065 1917

13201-13400 1115 1917

13401-13600 1165 1917

13601-13800 1215 1917
OAC 165:10 Appendix B Corporation Commission

Eff. 8-27-15

- 287 -

Appendix B, p3

DEPTH OF BARRELS DAYS AFTER

COMPLETION INTERVAL* PER DAY DISCOVERY

13801-14000 1265 1917

14001-14200 1315 1917

14201-14400 1365 1917

14401-14600 1415 1917

14601-14800 1465 1917

14801-15000 1515 1917

 * Depth in feet from the surface of the ground to the top of the completion 

interval.

[SOURCE: New at 28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]
OAC 165:10 Appendix B Corporation Commission

Eff. 8-27-15

- 288 -

[BLANK PAGE]
OAC 165:10 Appendix C Corporation Commission

Eff. 8-27-15

- 289 -

APPENDIX C: TABLE HD [REVOKED]

[Source: Revoked at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); Revoked at 

28 OK Reg 1949, eff. 7-11-11 (RM 201000007)]

APPENDIX C: TABLE HD [NEW]

RECOMMENDED ADDITIONAL ALLOWABLE FOR HORIZONTAL OIL WELLS

BASED ON TRUE VERTICAL DEPTH AND COMPLETION INTERVAL

AVERAGE TRUE VERTICAL DEPTH OF 

COMPLETION INTERVAL IN FEET

ADDITIONAL ALLOWABLE IN BARRELS PER 

FOOT OF COMPLETION INTERVAL

TO 4,000 .2

4,001 TO 8,000 .3

8,001 TO 12,000 .4

GREATER THAN 12,000 .5

All oil produced and marketed during the drilling and completion operations 

shall be charged against the allowable assigned to the well upon completion. 

Effective date of the allowable shall be the date of first production.

[Source: New at 27 OK Reg 2128, eff. 7-11-10 (RM 201000003); New at 28 OK 

Reg 1949, eff. 7-11-11 (RM 201000007)]
OAC 165:10 Appendix C Corporation Commission

Eff. 8-27-15

- 290 -

[BLANK PAGE]
OAC 165:10 Appendix D Corporation Commission

Eff. 8-27-15

- 291 - 

APPENDIX D. LIST OF NGPA FORMS [REVOKED]

[SOURCE: Revoked at 13 Ok Reg 2401, eff 7-1-96]
OAC 165:10 Appendix D Corporation Commission

Eff. 8-27-15

- 292 -

[BLANK PAGE]
OAC 165:10 Appendix E Corporation Commission

Eff. 8-27-15

- 293 -

APPENDIX E. SCHEDULE A FINES [REVOKED]

[Source: Revoked in Rule Making 200200017, eff 7-1-02]

APPENDIX E. SCHEDULE A FINES [NEW]

RULE VIOLATION FINE

165:10-3-1 Failure to obtain permit (Form 1000) to drill,

re-enter, deepen or recomplete. $1,000

165:10-3-3 Failure to report surface casing failure. $1,000

165:10-3-4 Failure to set sufficient surface casing or 

circulate cement. $5,000

165:10-3-4 Failure to run and cement surface well marker. $1,000

165:10-5-2 Failure to obtain permit for injection or 

disposal well. $5,000

165:10-5-13 Failure to obtain permit for annular injection

of drilling fluids. $2,500

165:10-7-14 Failure to obtain approval to drill deep anode 

groundbed. $1,000

165:10-7-16 Failure to obtain permit for construction of 

off-site pit. $1,000

165:10-7-16 Illegal discharge from noncommercial pit. $2,000

165:10-7-17 Failure to obtain permit to discharge produced 

water to surface. $1,000

165:10-7-19 Failure to obtain permit for one-time land 

application of water-based fluids from tanks/

earthen pits. $2,000

165:10-7-26 Failure to obtain permit for a one-time land 

application of contaminated soils or petroleum 

hydrocarbon-based drill cuttings. $2,000

165:10-7-27 Failure to obtain permit to apply waste oil, 

waste oil residue, or crude oil contaminated 

soil to lease roads, pipeline service roads, 

tank farm roads, well locations and production 

sites. $2,000

165:10-7-29 Failure to obtain permit for a one-time 

application of freshwater-based drill cuttings 

to private access areas, well locations and 

production sites. $2,000

165:10-9-1 Failure to obtain permit for construction and 

use of commercial pit. $5,000

165:10-9-1 Illegal discharge from a commercial pit. $5,000
OAC 165:10 Appendix E Corporation Commission

Eff. 8-27-15

- 294 -

Appendix E, p2

165:10-11-1 Failure to acquire license to pull pipe and 

plug wells. $2,500

165:10-11-4 Failure to obtain plugging instructions and 

notify district office of time well is to be 

plugged. $1,000

[Source: New in Rule Making 200200017, eff 7-1-02]
OAC 165:10 Appendix F Corporation Commission

Eff. 8-27-15

- 295 -

APPENDIX F. SCHEDULE B FINES [REVOKED]

[Source: Revoked in RM 200200017, eff. 7-1-02, and revoked at 27 OK Reg 

2128, eff. 7-11-10 (RM 201000003)]

APPENDIX F. SCHEDULE B FINES [NEW]

RULE VIOLATION FINE

165:10-1-10 Failure to maintain current surety. $500

165:10-3-4 Failure to protect treatable water or file for 

alternate casing procedure. $2,500

165:10-3-17 Failure to remove trash, debris and junk from well 

site. Up to $1,000

165:10-3-17 Failure to post lease sign or OTC number.

 $50 per well/$500 per lease

165:10-3-25 Failure to file completion report, Form 1002A. $250

165:10-3-26 Failure to submit required electric logs. $250

165:10-3-35 Failure to obtain order for multiple completion. $500

165:10-3-39 Failure to obtain order for commingling. $500

165:10-5-6 Failure to conduct/perform mandatory initial 

mechanical integrity test within rule timeframe. $500

165:10-5-6 Failure to perform subsequent mechanical 

integrity test. $500

165:10-5-7 Failure to file fluid injection report, Form 1012. $500

165:10-5-7 Failure to report loss of mechanical integrity 

on well. $1,500

165:10-7-5 Failure to report non-permitted discharge. $500

165:10-7-16 Failure to comply with any closure requirement

for noncommercial pit. $1,000

165:10-9-1 Failure to close commercial pit as required by 

rule. $1,000

165:10-11-3 Failure to plug well in rule timeframe. $1,000

165:10-11-7 Failure to file plugging report as required

by rule. $500

[Source: New in RM 200200017, eff. 7-1-02, and new at 27 OK Reg 2128, eff. 

7-11-10 (RM 201000003)]
OAC 165:10 Appendix F Corporation Commission

Eff. 8-27-15

- 296 -

[BLANK PAGE]
OAC 165:10 Appendix G Corporation Commission

Eff. 8-27-15

- 297 -

APPENDIX G.

IMPLEMENTATION FEES (ONE - TIME)

No. of Working Interest Owners

No. of RIOs* 2-10 11-20 21+

2-30 $350 $500 $650

31-100 $500 $500 $650

100+ $650 $650 $650

MAINTENANCE FEES (ANNUAL)

No. of Working Interest Owners

No. of RIOs* 2-10 11-20 21+

2-30 $200 $325 $450

31-100 $325 $325 $450

100+ $450 $450 $450

* RIO = Royalty Interest Owners

[Source: Added at 10 Ok Reg 2601, eff 6-25-93]
OAC 165:10 Appendix G Corporation Commission

Eff. 8-27-15

- 298 -

[BLANK PAGE]
OAC 165:10 Appendix H Corporation Commission

Eff. 8-27-15

- 299 -

APPENDIX H. CALCULATIONS

PROCEDURE FOR CALCULATING LOADING RATE OF TOTAL SOLUBLE SALTS (TSS)

 ppm TSS in soil1 X 2 = lbs/ac TSS in soil

6,000 lbs/ac TSS - lbs/ac TSS in soil = Maximum TSS 

(lbs/ac) to be applied 

Maximum TSS (lbs/ac) ÷ ( ppm TSS in pit materials1 X 

.000001) = Maximum lbs/ac of pit materials to be applied 

Maximum lbs/ac ÷ lbs/bbl = Maximum bbls/ac 

PROCEDURE FOR CALCULATING LOADING RATE OF HEAVY METALS AND OIL AND GREASE

OCC Standard for the parameter lbs/ac ÷ ( ppm in pit 

materials X .000001) = Maximum lbs/ac of pit materials to be 

applied 

Maximum lbs/ac ÷ lbs/bbl = Maximum bbls/ac 

PROCEDURE FOR CALCULATING MAXIMUM DRY WEIGHT

Weight of drilling mud2 lbs/gal x 42 = lbs/bbl

200,000 lbs ÷ lbs/bbl = Maximum bbls/acre 

PROCEDURE FOR CALCULATING VOLUME OF PIT CONTENTS

V = (

Wt X Lt) + (Wb X Lb) X D X .1781

 2

Where, V = volume

Wt= width of pit in feet at top of pit contents.

Lt= length of pit in feet at top of pit contents.

Wb= width of pit in feet at bottom of pit.

Lb= length of pit in feet at bottom of pit.

D = depth in feet of pit contents to be soil farmed.

1Electrical Conductivity (EC expressed in micromhos/cm) may be used to

estimate TSS: EC x 0.64 = ppm TSS.

2Based on laboratory analysis of Dry Weight.

[Source: Added at 12 Ok Reg 2017, 7-1-95]
OAC 165:10 Appendix H Corporation Commission

Eff. 8-27-15

- 300 -

[BLANK PAGE]
OAC 165:10 Appendix I Corporation Commission

Eff. 8-27-15

- 301 -

APPENDIX I. SOIL LOADING FORMULAS

TOTAL DISSOLVED SOLIDS

EC of receiving soil ______ micromhos/cm x 0.64 = ______ ppm TDS. TDS 

in receiving soil ________ ppm x 2 = _______ lbs/ac TDS in receiving 

soil.

6,000 lbs/ac TDS* - _______ lbs/ac TDS in receiving soil = Maximum TDS 

(lbs/ac) to be applied _______.

EC of materials to be applied ________ micromhos/cm x 0.64 = _______ 

ppm TDS.

Maximum TDS (lbs/ac) to be applied _______  (TDS of materials to be 

applied ________ ppm x .000001) = Maximum weight of materials to be 

applied _______ lbs/ac.

FOR LIQUID MATERIALS:

Maximum weight of materials to be applied _______ lbs/ac  (sample 

weight _______ lbs/gal** x 42) = Maximum loading _______ bbls/ac.

Total volume of materials to be applied _______ bbls  Maximum loading 

________ bbls/ac = Minimum acres required ________.

FOR SOLID MATERIALS:

Maximum weight of materials to be applied ________ lbs/ac  (sample 

weight _______ lbs/gal** x 202) = Maximum loading ________ cu yds/ac. 

Total volume of materials to be applied _________ cu yds  Maximum 

loading ______ cu yds/ac = Minimum acres required _______.
OAC 165:10 Appendix I Corporation Commission

Eff. 8-27-15

- 302 -

Appendix I, p2

CHLORIDES

Cl in receiving soil ________ ppm x 2 = ________ lbs/ac Cl in receiving 

soil.

3500 lbs/ac Cl - _______ lbs/ac Cl in receiving soil = Maximum Cl 

(lbs/ac) to be applied ________.

Maximum Cl (lbs/ac) to be applied ________  (Cl of materials to be 

applied ________ ppm x .00000l) = Maximum weight of materials to be 

applied ________ lbs/ac.

Maximum weight of materials to be applied ________ lbs/ac  (sample 

weight ________ lbs/gal** x 202) = Maximum loading ________ cu yds/ac.

Total volume of materials to be applied ________ cu yds  Maximum loading 

________ cu yds/ac = Minimum acres required ________.

OIL AND GREASE1 

40,000 lbs/ac O&G*  (O&G of materials to be applied ________ ppm x 

.000001) = Maximum weight of materials to be applied _______ lbs/ac.

FOR LIQUID MATERIALS:

Maximum weight of materials to be applied _______ lbs/ac  (sample 

weight _________ lbs/gal** x 42) = Maximum loading _______ bbls/ac.

Total volume of materials to be applied _______ bbls  Maximum loading 

________ bbls/ac = Minimum acres required ________.

Maximum bbls/ac  4.809 = Maximum cu yds/ac ________.
OAC 165:10 Appendix I Corporation Commission

Eff. 8-27-15

- 303 -

Appendix I, p3

FOR SOLID MATERIALS:

Maximum weight of materials to be applied ________ lbs/ac  (sample 

weight ________ lbs/gal** x 202) = Maximum loading ________ cu yds/ac.

Total volume of materials to be applied _______ cu yds  Maximum 

loading _______ cu yds/ac = Minimum acres required _______.

DRY WEIGHT

Wet weight of drilling mud**________ lbs/gal x ________ % Dry weight = 

________ lbs/gal Dry weight.

________lbs/gal Dry weight x 202 = ________ lbs/cu yd.

200,000 lbs/ac Dry weight  ________ lbs/cu yd = Maximum cu yds/ac 

________.

Total volume of materials to be applied ________ cu yds  Maximum cu 

yds/ac ________ = Minimum acres required ________.

*Soil loading standards are based upon standards set forth in "Diagnosis 

and Improvement of Saline and Alkaline Soils," U.S. Agriculture Handbook 

60. Pub. U.S. Salinity Laboratory, Riverdale, California, 1954; Moseley, 

H.R., "Summary and Analysis of API Onshore Drilling Mud and Produced 

Water Environmental Studies," 1983, American Petroleum Institute Bulletin 

D-19.

**Based on actual weight of composite sample of materials.

1 GRO or DRO may be substituted for oil and grease

[SOURCE: Added at 12 Ok Reg 2039, 7-1-95; Amended in Rule Making 97000002, eff 

7-1-97
OAC 165:10 Appendix I Corporation Commission

Eff. 8-27-15

- 304 -

[BLANK PAGE]
OAC 165:10 Appendix J Corporation Commission

Eff. 8-27-15

- 305 -

APPENDIX J. DEWATERING OIL ALLOWABLE TABLE

(100 percent of market demand)

 Depth* Barrels

Per Day

 To-3000 200

 3001-4000 400

 4001-5000 600

 5001-6000 800

 6001-7000 1000

 7001-8000 1100

 8001-9000 1200

 9001-10000 1300

 10001- 1400

* The depth in feet from the surface of the ground to the top of the producing 

formation in the oil well.

[SOURCE: Added in Rule Making 200100009, eff 7-1-02]
OAC 165:10 Appendix J Corporation Commission

Eff. 8-27-15

- 306 -

[BLANK PAGE]