ARKANSAS

OIL AND GAS COMMISSION

GENERAL 

RULES AND REGULATIONS

As of October 1, 2015
FOREWORD

This publication contains the Commission Rules and Regulation of statewide application. 

Special rules pertaining to individual oil, gas, or salt water fields and pools are not included but 

should be consulted.

In using this publication one should be aware that there is a considerable body of 

statutory law in Arkansas that must be consulted in evaluating an oil and gas matter.

This statutory law is not set out in full herein. The reader should refer to Arkansas Code, 

Annotated, Title 15, Chapter 72, for the statutory law.
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Table of Contents

GENERAL RULE A – ADMINISTRATIVE............................................................................................................................... 1

RULE A-1: APPLICATION OF RULES, REGULATIONS, AND ORDERS .................................................................................... 1

RULE A-2: GENERAL HEARING PROCEDURES .......................................................................................................................... 2

RULE A-3: ADDITIONAL REQUIREMENTS FOR SPECIFIC TYPES OF HEARINGS................................................................ 8

RULE A-4: DEFINITIONS................................................................................................................................................................ 12

RULE A-5: ENFORCEMENT PROCEDURES ................................................................................................................................ 20

RULE A-6: RESERVED.................................................................................................................................................................... 27

RULE A-7: DETERMINATION OF NATURAL GAS WELL CATEGORIES FOR SEVERANCE TAX PURPOSES................. 27

RULE A-8: REPORTING REQUIREMENTS FOR MINERAL PROCEEDS ESCROW ACCOUNTS .......................................... 32

GENERAL RULE B - DRILLING AND PRODUCTION ..................................................................................................... 33

RULE B-1: APPLICATION TO DRILL A PRODUCTION WELL ................................................................................................. 33

RULE B-2: PROOF OF FINANCIAL RESPONSIBILITY REQUIRED TO BE FURNISHED ...................................................... 38

RULE B-3: SPACING OF WELLS ................................................................................................................................................... 43

RULE B-4: REPEALED .................................................................................................................................................................... 45

RULE B-5: SUBMISSION OF WELL RECORDS AND ISSUANCE OF CERTIFICATE OF COMPLIANCE ............................ 45

RULE B-6: OIL, GAS AND WATER TO BE PROTECTED ........................................................................................................... 48

RULE B-7: WHEN WELLS SHALL BE PLUGGED AND ABANDONED AND NOTICE OF INTENTION TO PLUG AND 

ABANDON WELLS ...................................................................................................................................................... 49

RULE B-8: PLUGGING METHODS AND PROCEDURES............................................................................................................ 52

RULE B-9: DRY GAS WELL PLUGGING METHODS AND PROCEDURES.............................................................................. 53

RULE B-10: SEISMIC CORE AND OTHER EXPLORATORY HOLES TO BE PLUGGED; METHODS, RECORDS................. 58

RULE B-11: DOMESTIC NATURAL GAS WELLS AND CONVERSION OF PERMITTED OIL AND NATURAL GAS 

WELLS FOR USE AS DOMESTIC NATURAL GAS OR FRESH WATER SUPPLY WELLS ................................ 59

RULE B-12: CASING PULLER’S PERMITS AND BONDS............................................................................................................. 61

RULE B-13: ORGANIZATION REPORTS........................................................................................................................................ 61

RULE B-14: SURFACE EQUIPMENT............................................................................................................................................... 62

RULE B-15: CASING REQUIREMENTS .......................................................................................................................................... 63

RULE B-16: BLOW-OUT PREVENTION ......................................................................................................................................... 65

RULE B-17: WELL DRILLING PITS AND COMPLETION PITS REQUIREMENTS .................................................................... 66

RULE B-18: WELLHEAD FITTINGS................................................................................................................................................ 76

RULE B-19: REQUIREMENTS FOR WELL COMPLETION UTILIZING FRACTURE STIMULATION .................................... 76

RULE B-20: REPEALED .................................................................................................................................................................... 81

RULE B-21: REPEALED .................................................................................................................................................................... 81

RULE B-22: REPEALED .................................................................................................................................................................... 81

RULE B-23: TUBING ......................................................................................................................................................................... 82

RULE B-24: CHOKES ........................................................................................................................................................................ 82

RULE B-25: REPEALED .................................................................................................................................................................... 82

RULE B-26: GENERAL LEASE OPERATING REQUIREMENTS.................................................................................................. 83

RULE B-27: SALT WATER ............................................................................................................................................................... 91

RULE B-28: REPEALED .................................................................................................................................................................... 91

RULE B-29: REPEALED .................................................................................................................................................................... 91

RULE B-30: DEVIATION TESTS...................................................................................................................................................... 92

RULE B-31: REPEALED .................................................................................................................................................................... 93

RULE B-32: VACUUM PUMPS PROHIBITED.................................................................................................................................. 93

RULE B-33: PRODUCTION PRACTICE........................................................................................................................................... 95

RULE B-34: NOTICE OF FIRE, BREAKS, OR BLOW-OUTS AND REMEDIATION OF ASSOCIATED SPILLS OF 

CRUDE OIL AND PRODUCED WATER .................................................................................................................... 96

RULE B-35: DETERMINING AND NAMING COMMON SOURCES OF SUPPLY .................................................................... 100
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RULE B-36: TAKINGS TO BE RATABLE ..................................................................................................................................... 101

RULE B-37: DUAL COMPLETION OF WELLS............................................................................................................................. 102

RULE B-38: ESTABLISHMENT OF FIELD RULES ...................................................................................................................... 103

RULE B-39: PRE-HEARING CONFERENCE REQUIRED FOR PROPOSED FIELD-WIDE UNITIZATIONS.......................... 104

RULE B-40: AUTHORIZATION FOR DIRECTOR OF PRODUCTION AND CONSERVATION TO 

ADMINISTRATIVELY APPROVE APPLICATIONS FOR EXCEPTIONAL WELL LOCATIONS....................... 105

RULE B-41: RULE FOR OPERATION IN HYDROGEN SULFIDE (H2S) AREAS...................................................................... 109

RULE B-42: SEISMIC RULES AND REGULATIONS ................................................................................................................... 114

RULE B-43: ESTABLISHMENT OF DRILLING UNITS FOR GAS PRODUCTION FROM CONVENTIONAL AND 

UNCONVENTIONAL SOURCES OF SUPPLY OCCURRING IN CERTAIN PROSPECTIVE AREAS NOT 

COVERED BY FIELD RULES ................................................................................................................................... 118

RULE B-44: ESTABLISHMENT OF DRILLING UNITS FOR GAS PRODUCTION FROM ALL SOURCES OF SUPPLY 

OCCURING IN CERTAIN PRODUCING AREAS IN FRANKLIN, LOGAN, SCOTT, SEBASTIAN AND 

YELL COUNTIES........................................................................................................................................................ 127

RULE B-45: ESTABLISHMENT OF WELL SET-BACK REQUIREMENTS FOR DRY GAS PRODUCTION WELLS 

OCCURING IN ESTABLISHED FIELDS IN CRAWFORD, FRANKLIN, JOHNSON, LOGAN, MADISON, 

POPE, SCOTT, YELL, SEBASTIAN AND WASHINGTON COUNTIES................................................................. 135

GENERAL RULE C - OIL............................................................................................................................................ 138

RULE C-1: FIELDS OR POOLS IN WHICH PRODUCTION WILL BE CONTROLLED........................................................... 138

RULE C-2: REPORTS BY PRODUCERS ...................................................................................................................................... 139

RULE C-3: RESERVOIR SURVEYS ............................................................................................................................................. 141

RULE C-4: OPERATORS TO ASSIST IN RESERVOIR SURVEYS............................................................................................ 142

RULE C-5: OIL ASSESSMENT ..................................................................................................................................................... 143

RULE C-6: MONTHLY REPORTS-COSTS................................................................................................................................... 144

RULE C-8: FLUID REPRESSURING AND WATER FLOODING OF OIL AND GAS PROPERTIES ...................................... 145

RULE C-9: PRESSURE MAINTENANCE OR REPRESSURING WITH GAS OF OIL AND GAS PROPERTIES.................... 148

RULE C-10: ESTABLISHMENT OF WELL SET-BACK REQUIREMENTS FOR OIL PRODUCTION WELLS ....................... 151

GENERAL RULE D - GAS.......................................................................................................................................................... 152

RULE D-1: REPEALED .................................................................................................................................................................. 152

RULE D-2: REPEALED .................................................................................................................................................................. 152

RULE D-3: REPEALED .................................................................................................................................................................. 152

RULE D-4: REPEALED .................................................................................................................................................................. 152

RULE D-5: REPEALED .................................................................................................................................................................. 152

RULE D-6: REPEALED .................................................................................................................................................................. 152

RULE D-7: NATURAL GAS TO BE METRED............................................................................................................................. 153

RULE D-8: MONTHLY NATURAL GAS PRODUCTION REPORTS......................................................................................... 154

RULE D-9: GAS-OIL RATIO ......................................................................................................................................................... 155

RULE D-10: GAS-OIL RATIO SURVEYS AND REPORTS........................................................................................................... 156

RULE D-11: PIPELINE MAPS ......................................................................................................................................................... 157

RULE D-12: GAS UTILIZATION .................................................................................................................................................... 158

RULE D-13: USE OF GAS FOR OTHER THAN LIGHT OR FUEL............................................................................................... 159

RULE D-14: GAS ASSESSMENT.................................................................................................................................................... 160

RULE D-15: MEASURING GAS AT CUSTODY TRANSFER POINTS........................................................................................ 161

RULE D-16: BACK PRESSURE TESTS FOR NATURAL GAS PRODUCTION ALLOWABLE DETERMINATION ............... 162

RULE D-17: GENERAL RULE FOR THE REGULATION OF NATURAL GAS PIPELINES..................................................... 164

RULE D-18: AUTHORITY TO COMMINGLE................................................................................................................................ 169

RULE D-19: ADDITIONAL COMPLETIONS WITHIN COMMON SOURCESOF SUPPLY WITHIN A DRILLING UNIT...... 171

RULE D-20: NOISE LEVEL REQUIREMENTS FOR NON-WELLHEAD COMPRESSOR FACILITIES ................................... 173

RULE D-21: PROCEDURES FOR DETERMINING THE PRODUCTION ALLOWABLE FOR DRY NATURAL GAS 

PRODUCTION WELLS............................................................................................................................................... 175

RULE D-22: REQUIREMENTS FOR LEASE GAS RIGHTS SUPPLY LINES.............................................................................. 177
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GENERAL RULE E - TRANSPORTATION.......................................................................................................................... 180

RULE E-1: PIPE LINES, PURCHASERS AND TRANSPORTERS.............................................................................................. 180

RULE E-2: REPORTS FROM OIL PIPE LINES, TRANSPORTERS AND STORERS................................................................ 181

RULE E-3: EXPLORATION AND PRODUCTION FLUID GATHERING, HANDLING AND TRANSPORTATION ............. 182

GENERAL RULE F - PROCESSING....................................................................................................................................... 185

RULE F-1: GENERAL ORDER ..................................................................................................................................................... 185

RULE F-2: REFINERY REPORTS................................................................................................................................................. 185

RULE F-3: GASOLINE PLANT REPORTS................................................................................................................................... 185

GENERAL RULE G - ABANDONED AND ORPHAN WELL PLUGGING PROGRAM ..................................186

RULE G-1: ABANDONED OR LEAKING WELL AND WELL SITE REMEDIATION ............................................................. 186

RULE G-2: PLUGGING OF ORPHAN WELLS............................................................................................................................. 189

RULE G-3: TRANSFER OF WELLS IN THE ABANDONED AND ORPHANED WELL PLUGGING PROGRAM ................ 190

GENERAL RULE H - CLASS II UIC WELLS ...................................................................................................................... 191

RULE H-1: CLASS II DISPOSAL AND CLASS II COMMERCIAL DISPOSAL WELL PERMIT APPLICATION 

PROCEDURES............................................................................................................................................................. 191

RULE H-2: WELL CONSTRUCTION, OPERATING AND REPORTING REQUIREMENTS FOR CLASS II DISPOSAL 

WELLS ......................................................................................................................................................................... 206

RULE H-3: WELL CONSTRUCTION, OPERATING AND REPORTING REQUIREMENTS FOR CLASS II 

COMMERCIAL DISPOSAL WELLS.......................................................................................................................... 210

ELECTRONIC COPIES OF REQUIRED FORMS 

www.aogc.state.ar.us
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GENERAL RULE A – ADMINISTRATIVE 

RULE A-1: APPLICATION OF RULES, REGULATIONS, AND ORDERS

a) The following General Rules have been adopted by the Oil and Gas Commission in accordance 

with applicable state law requirements and are General Rules of state-wide application, applying 

to the conservation and prevention of waste of crude oil and natural gas in the State of Arkansas 

and protection of the vested, co-equal or correlative rights of owners of crude oil and natural gas. 

b) Any specific provision of an existing rule, regulation or order shall prevail as against a General 

Rule if in conflict therewith.

c) After the effective date of this General Rule, no further order, special rule or regulation of the 

Commission shall be issued to modify, waive, amend, or otherwise alter the provisions of a 

General Rule unless the General Rule provides a specific provision to do so. 

(Source: 1991 rule book; amended May 11, 2008)
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RULE A-2: GENERAL HEARING PROCEDURES

a) Execution and Filing

1) All applications, except for applications filed by the Director, shall be in writing and state 

the interests of the application and the general nature of the order requested. Fourteen 

copies of the application, including exhibits, shall be filed with the Commission 

Director’s office located in Little Rock, Arkansas (“Director’s Office”). The application 

shall be deemed filed when it is received by the Director’s Office. 

2) All fourteen (14) copies of the applications, including exhibits, except for those filed by 

the Director, must be received in the Directors Office at least twenty (20) days prior to 

the first day of regularly scheduled hearing. If the applicant or his/her representative files 

an electronic version (a .pdf file labeled by the assigned docket number) of the 

application, including exhibits, on an electronic storage device approved by the Director a 

minimum of twenty (20) days prior to the first day of the regularly scheduled hearing, the 

fourteen (14) copies of the applications, including exhibits must be received in the 

Director’s office eighteen (18) days prior to the first day of the regularly scheduled 

hearing. 

3) Every application shall be signed by the applicant or his/her representative and his/her 

address shall be stated thereon. The signature of the applicant or his/her representative 

constitutes a certificate by him/her that he/she has read the petition and that to the best of 

his/her knowledge, information and belief there is good ground to support the same.

4) Unless otherwise provided by General Rule of the Commission, each application, except 

for applications filed by the Director, shall be accompanied by a five hundred dollar 

($500.00) filing fee made payable to the Arkansas Oil and Gas Commission.

5) The applicant shall also submit a check payable to the Arkansas Oil and Gas Commission 

in an amount approved by the Commission, not to exceed two dollars ($2.00) per name of 

persons named in the application, whose address are known as well as addresses for other 

persons that the applicant seeks to provide a copy of the order. The applicant shall also 

provide mailing labels for each person named in the application whose address is known, 

as well as any other person that the applicant seeks to provide a copy of the order. If the 

address of the person is unknown, the Applicant shall provide a statement to that affect. 

All mailing labels shall be provided within three (3) days after the date of the hearing.

6) If after the application is filed, and prior to the hearing date, the Director finds the 

application deficient relative to the requirements of subsections a) 1) through 4) above, 

the Director shall return the application to the applicant with a statement as to the 

deficiencies. 

7) If after the application is filed, and prior to the hearing date, the Director determines that 

additional facts, data, records, or other information are necessary to fully evaluate the 

application, the Director may require the applicant to submit such necessary facts, data, 

records or other information.

8) Amendments may be filed at the time of the hearing. However, any amendments filed 

prior to the hearing date shall be submitted at least ten (10) days prior to the hearing date, 

and contain a written statement or a clear indication as to what the amendment is being 

amended. Any application that is substantially amended, as determined by the 
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Commission, regardless of the time of the amendment, may be continued until the next 

hearing of the Commission. 

b) Notice of Hearing

1) The Applicant shall prepare a notice of hearing which shall be issued in the name of the 

Arkansas Oil and Gas Commission. Such notice shall include a statement pertaining to 

the legal authority for the hearing; the name of the applicant; the legal description of the 

property or unit; a statement of the requested action; a listing of interested parties; the 

time, date and location of the hearing; the Commission assigned docket number; and the 

contact information of the Commission offices. The notice shall also state that any 

interested person may file an entry of appearance in the hearing by submitting such entry 

of appearance in writing to the Hearing Officer or Director, and that thereafter such 

person shall be deemed a party of record in the proceeding.

2) Unless otherwise provided by the Brine Act found in Ark. Code Ann. § 15-76-201 et. 

seq. or General Rule of the Commission, the Applicant shall serve such notice in the 

following manner: 

A) By mailing such notice by U.S. Postal service, first-class mail, directed to all 

interested parties at their last known addresses at least ten (10) days prior to the 

date of the hearing, but not more than thirty (30) days prior to the date of the 

hearing; and

B) By publication of such notice for at least one (1) day, with the notice appearing at 

least ten (10) days prior to the date of the hearing, but not more than thirty (30) 

days prior to the date of the hearing, in the newspaper of general circulation 

published in each county containing some portion of the land identified in the 

application. 

c) Emergency Hearings

In the event an emergency is found to exist by the Commission which in its judgment requires the 

making, changing, renewal or extension of an order, special rule, or regulation, without first 

having a hearing, such emergency order shall have the same validity as if a hearing with respect 

to the same had been held after due notice. The emergency order permitted by this section shall 

remain in force until the date of the next regular Commission hearing set to be held after the 

emergency rule, regulation or order was issued, or sixty days from its effective date in accordance 

with the Brine Act found in Ark. Code Ann. § 15-76-307, and, in any event, it shall expire when 

any order made after due notice and hearing with respect to the subject matter of such emergency 

order becomes effective.

d) Pre-Hearing Conferences

1) Upon his/her own motion, or the motion of a party of record, the Hearing Officer, as 

designated by the Commission, may convene a meeting of the parties or their counsel in 

order to:

A) Simplify the factual and legal issues presented by the hearing request;

B) Receive stipulations, admissions of fact and the contents and authenticity of 

documents;
GENERAL RULES AND REGULATIONS

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C) Exchange lists of witnesses the parties intend to have testify and copies of all 

documents the parties intend to introduce into evidence at the hearing; and

D) Discuss and resolve such other matters as may tend to expedite the disposition of 

the hearing request and to assure a just conclusion thereof.

2) Pre-hearing conferences may be held by telephone conference if such procedure is 

acceptable to all parties.

e) Hearings

1) Every hearing shall be held on a date and at a location established by the Commission, 

and conducted by a Hearing Officer designated by the Commission. The Hearing Officer 

shall take all necessary actions to avoid delay, to maintain order and to develop a clear 

and complete record, and shall have all powers necessary and appropriate to conduct a 

fair hearing and to render a decision on the petition, including but not limited to the 

following:

A) To administer oaths and affirmations;

B) To receive relevant evidence;

C) To regulate the course of the hearing and the conduct of the parties and their 

counsel therein;

D) To consider and rule upon procedural requests;

E) To examine witnesses and direct witnesses to testify, limit the number of times 

any witness may testify, limit repetitive or cumulative testimony and set 

reasonable limits on the amount of time each witness may testify; and

(F) To require the production of documents or subpoena the appearance of witnesses, 

either on the Hearing Officer's own motion or for good cause shown on motion 

of any party of record. The Hearing Officer may require that relevant documents 

be produced to any party of record on his/her own motion or for good cause 

shown on motion of any party of record.

2) Every person appearing shall enter his/her appearance by stating his/her name and 

address. Thereafter, such person shall be deemed a party of record.

3) All participants in the hearing shall have the right to be represented by an attorney 

licensed to practice law in the State of Arkansas. An attorney appearing in a 

representative capacity in any proceeding hereunder shall file a written notice of 

appearance identifying his or her name, address and telephone number, and identifying 

the party represented.

4) The Hearing Officer shall allow all parties to present statements, testimony, evidence and 

argument as may be relevant to the proceeding.

5) The Director, or his/her designee, may appear at any public hearing and shall have the 

opportunity to question parties or otherwise elicit such information as is necessary to 

reach a decision on the application.
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6) Preliminary Matters: Where applicable, the following shall be addressed prior to 

receiving evidence:

A) The applicant may offer preliminary exhibits, including documents necessary to 

present the issues to be heard, notices, proof of publication and orders previously 

entered in the cause.

B) Rulings may be made by the Hearing Officer on any pending motions.

C) Any other preliminary matters appropriate for disposition prior to presentation of 

evidence.

7) Every hearing shall be conducted in accordance with the Commission’s rules and 

applicable laws of this State. 

f) Evidence

1) Admissibility: A party shall be entitled to present his/her case by oral or documentary 

evidence, to submit rebuttal evidence, and to conduct such cross-examination as may be 

required for a full and true disclosure of the facts. Any oral or documentary evidence may 

be received, but the presiding Hearing Officer may exclude evidence which is irrelevant, 

immaterial or unduly prejudicial or repetitious. However, the erroneous ruling on the 

admissibility of evidence shall not of itself invalidate any rule, regulation or order. 

2) Official Notice: Official notice may be taken of any material fact not appearing in 

evidence in the record if the circuit courts of this State could take judicial notice of such 

fact. In addition, notice may be taken of generally recognized technical or scientific facts 

within the Commission’s specialized knowledge.

3) Order of Proof: The applicant shall open the proof. Other parties of record shall be heard 

immediately following the petitioner. The Hearing Officer or Director or his/her 

designee, as well as any Commissioner may examine any witnesses. In all cases, the 

Hearing Officer shall designate the order of proof and may limit the scope of examination 

or cross-examination.

4) Briefs: The Hearing Officer may require or allow parties to submit written briefs to the 

Hearing Officer within 10 days after the close of the hearing or within such other time as 

the Hearing Officer shall determine as being consistent with the Commission’s 

responsibility for an expeditious decision.

g) Recording of Proceedings; Testimony

The Commission shall provide a certified court reporter to take down the testimony and preserve 

a record of all proceedings at the hearing. Any person testifying shall be required to do so under 

oath. However, relevant unsworn statements, comments and observations by any interested 

person may be heard and considered by the Commission as such and included in the record. 

h) Postponement or Continuance of Hearing

Any hearing may be postponed or continued for due cause by the Hearing Officer upon his/her 

own motion or upon the motion of a party to the hearing. A motion filed by a party to the hearing 

shall set forth facts attesting that the request for continuance is not solely for the purpose of delay. 

All parties involved in a hearing shall avoid undue delay caused by repetitive postponements or 
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continuances so that the subject matter of the hearing may be resolved expeditiously. The 

Applicant may postpone or continue the hearing of an application for three consecutive regularly 

scheduled Commission meetings without prior approval of the Hearing Officer. After the third 

consecutive postponement, the application shall be dismissed, unless the Hearing Officer allows 

an exception for due cause, and the applicant shall be required to re-file in accordance with 

applicable General Rules in order for an application to be scheduled for a hearing.

i) Default

If a party, after proper service of notice, fails to appear at the pre-hearing conference or at a 

hearing, and if no continuance is granted, the Commission may then proceed to make its decision 

in the absence of such party. If the failure to appear at such pre-hearing conference or hearing is 

due to an emergency situation beyond the parties' control, and the Commission is notified of such 

situation on or before the scheduled pre-hearing conference or hearing, the Hearing Officer may 

continue or post-pone the pre-hearing conference or hearing. Emergency situations include 

sudden unavailability of counsel, sudden illness of a party or his representative, or similar 

situations beyond the parties' control.

j) Voting

1) In order for the Commission to adopt a motion approving an application as applied for, or 

as amended by either the applicant of a Commissioner, there must be:

A) A quorum present;

B) A majority of the votes cast must be in favor of the motion outlining the 

proposed order; and 

C) At least five (5) votes cast must be in favor of the motion outlining the proposed 

order. 

2) If a motion approving the application as applied for, or as modified by either 

the applicant or a Commissioner does not receive the votes required in subparagraphs i) 

A) through C) above, and no subsequent or substitute motion receives the votes required 

in subparagraphs i) A) through C) above, then the application shall be deemed to be 

denied by the Commission. 

3) If an application is deemed to be denied by the Commission in accordance with 

subparagraph i) 2) above, the Commission shall enter an order of denial, which may be 

appealed as a final decision under the Arkansas Administrative Procedures Act found in 

Ark. Code Ann. § 25-15-201 et. seq.

4) Nothing in this subparagraph shall limit the Commission’s authority to continue any 

application for due cause. 

k) Commission’s Order--Final Administrative Decision

Within 30 days of the close of the hearing record, the Commission shall issue findings of fact, 

conclusions of law and final administrative decision of the Commission signed by the Director. 

The Commission shall have continuing jurisdiction for the purposes of enforcement, and/or 

modifications or amendments to the provisions of all orders. Any appeals shall be governed by 

the Administrative Procedures Act found in Ark. Code Ann. § 25-15-201 et. seq.
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l) Notice of Order--Recordation

Within 30 days after an order has been issued, a copy of such order shall be mailed by the 

Commission to each interested party at his/her last known address or his/her attorney of record, 

and filed in accordance with the Administrative Procedures Act found in Ark. Code Ann. § 25-

15-201 et. seq.

m) Official Record 

 In every case of adjudication, the official record shall be complied in accordance with the 

Administrative Procedures Act found in Ark. Code Ann. § 25-15-201 et. seq.

(Source: 1991 rule book; amended April 13, 2008; amended June 5, 2009; amended October 24, 2009)
GENERAL RULES AND REGULATIONS

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RULE A-3: ADDITIONAL REQUIREMENTS FOR SPECIFIC TYPES OF HEARINGS

a) Abandoned Well and Emergency Response Hearings 

1) Unless otherwise specified below, General Rule A-2 shall apply to all abandoned well 

and emergency response hearing proceedings pursuant to Ark. Code Ann. § 15-72-217.

2) The Director shall only provide notice to the permit holder named in the application, in 

accordance with General Rule A-2 (b) (2). 

3) The Director shall have the burden of proof at the hearing. A decision shall be supported 

by a substantial evidence standard.

b) Integration Hearings 

1) Unless otherwise specified below, General Rule A-2 shall apply to all drilling unit 

integration proceedings.

2) Commencement of Action

Where the oil or gas rights within a drilling unit are separately owned and the owners of 

those rights have not voluntarily agreed to integrate or pool those rights to develop the oil 

or gas, an owner may petition the Commission for an order integrating those rights, 

pursuant to Ark. Code Ann. § 15-72-302 and §15-72-303. The application for an order 

integrating interests shall contain the following:

A) The name and address of the applicant;

B) The applicant’s reasons for desiring to integrate the separately owned interests;

C) A legal land description of the drilling unit sought to be established;

D) A geologic report of the area where the proposed drilling unit is to be located 

indicating the potential presence of reservoirs;

E) If the application is for the integration of an exploratory drilling unit, as 

contemplated by Ark. Code Ann. § 15-72-302:

i) the names of all owners named in the application who have not agreed to 

integrate their interests in the right to drill and produce oil or gas, or 

both, in the proposed drilling unit as of the date of filing the petition, as 

disclosed by the records in the office of the clerk for the county or 

counties in which the drilling unit is situated, and;

ii) a statement that the persons who own at least an undivided fifty percent 

(50%) interest in the right to drill and produce oil or gas or both, from the 

total proposed unit agree thereto at the time of the filing of the 

application;

F) If the application is for the integration of an established drilling unit, as 

contemplated by Ark. Code Ann. § 15-72-303, and created in accordance with 

applicable Commission Orders or General Rules; the names of all owners named 

in the application who have not agreed to integrate their interests in the right to 
GENERAL RULES AND REGULATIONS

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drill and produce oil or gas, or both, in the proposed drilling unit as of the date of 

filing the petition, as disclosed by the records in the office of the clerk for the 

county or counties in which the drilling unit is situated;

G) Unleased mineral owners.

i) A resume of efforts showing that the applicant has exercised due 

diligence, to locate each unleased mineral owner, and that a bona fide 

effort was made to reach an agreement with each owner as to how the 

unit would be developed, as follows:

aa) Due diligence, regarding non-industry owners (persons who are 

not actively involved in the oil and gas business) means, except 

for good cause shown, to be determined at the discretion of the 

Commission, that the Applicant attempted to contact said owners 

and that bona fide efforts to reach an agreement commenced at 

least sixty (60) days prior to the date of the hearing; and that 

there are sufficient contacts to show that the Applicant has 

exhausted all reasonable efforts to reach an agreement. However, 

the Applicant shall not be required to contact an owner that the 

Applicant is precluded by law from contacting, or an owner who 

has expressly stated that the Applicant is not to contact said 

owner.

bb) Due diligence, regarding industry owners (person who as an 

active business practice are involved in the oil and gas business) 

means that the Applicant has provided industry owners notice, 

including an Authorization for Expenditure (“AFE”) and Well 

Proposal, prior to filing the integration application. 

ii) An affidavit indicating what the highest and/or best cash bonus and 

royalty terms that the Applicant has knowledge of that have been offered 

and accepted, or contracted for, for any acreage within the unit(s) where 

the well is located (as defined in Section (a)(2) of General Rule B-3), 

including any acreage within the unit(s) subject to leases or other 

agreements with a fee mineral owner covering lands located in more than 

one unit. If this information changes prior to the hearing, the Applicant 

shall inform the Commission of any changes. If no affidavit is provided 

prior to or at the time of the hearing, the Applicant shall provide sworn 

testimony as to the highest and/or best cash bonus and royalty terms that 

the Applicant has knowledge of that have been offered and accepted, or 

contracted for, for any acreage within the unit(s) where the well is 

located (as defined in Section (a)(2) of General Rule B-3), including any 

acreage within the unit(s) subject to leases or other agreements with a fee 

mineral owner covering lands located in more than one unit. 

H) Uncommitted Leasehold Working Interest Owners. 

A resume of efforts showing that the applicant has exercised due diligence, to 

locate each uncommitted leasehold working interest owner and that a bona fide 

effort, was made to reach an agreement with each owner as to how the unit would 

be developed, by providing the uncommitted leasehold working interest owners 
GENERAL RULES AND REGULATIONS

10

notice, including an AFE and Well Proposal, prior to filing the integration 

application.

I) Any other information relevant to protect correlative rights of the parties sought 

to be affected by the order.

c) Appeal of Director’s Decision.

1) Any interested party may appeal a permit denial, any enforcement action, or rule 

interpretation decision made by the Director to the Commission.

2) Unless otherwise specified below, General Rule A-2 shall apply to all hearings requested 

to appeal a decision of the Director.

3) The application to appeal a Director’s decision shall be accompanied by a two hundred 

and fifty dollar ($250.00) filing fee. 

d) Exceptional Well Location

1) Unless otherwise specified below, General Rule A-2 shall apply to all hearings for an 

application which has been referred to the Commission in accordance with General Rule 

B-40, or for which General Rule B-40 is not applicable. 

2) The application shall include proof of notice to each owner within the unit in which the 

well is located and within the units offsetting the boundary line or lines, or in the case of 

wells in uncontrolled fields within the boundaries of mineral lease lines and the offsetting 

lease(s), which shall be encroached upon by the exceptional well location. 

3) If the application has been referred to the Commission in accordance with General Rule 

B-40, no application fee is required to be submitted with the application.

e) Authority to Commingle and Additional Completions

1) Unless otherwise specified below, General Rule A-2 shall apply to all hearings for which 

the applicant has requested a hearing for an application which has been denied in 

accordance with General Rule D-18 or General Rule D-19, or for which General Rules 

D-18 or D-19 are not applicable. 

2) If the applicant requests the hearing in accordance with General Rule D-18, the 

application shall include proof of notice to all offset operators in all adjacent units.

3) If the applicant requests the hearing in accordance with General Rule D-19, the 

application shall include proof of notice to all working interest owners in the subject unit 

and all offset operators in all adjacent established units including all working interest 

owners in the offset unit where the operator is the same as the applicant.

f) Establishment of Field Rules

1) Unless otherwise specified below, General Rule A-2 shall apply to all hearings for the 

creation of field rules, as provided by General Rule B-38.
GENERAL RULES AND REGULATIONS

11

2) The application shall include proof of notice to each owner, as defined in Ark. Code Ann. 

§ 15-72-102 (9), within the proposed unit(s) in which the well(s) is/are located and within 

all units offsetting the boundary line or lines of the proposed unit(s).

3) The application shall include a geologic report of the proposed field, specifying the 

geologic setting of the proposed field and including at a minimum a completion report of 

the discovery and other wells located within the proposed field, a type geophysical log 

from a well(s) in the proposed field and a structure and isopach map of the productive 

zone(s) within the proposed field.

(Source: 1991 rule book; amended April 13, 2008; amended December 14, 2008; amended July 17, 2009)
GENERAL RULES AND REGULATIONS

12

RULE A-4: DEFINITIONS

Unless the context otherwise requires, the words defined shall have the following meaning when found in 

these rules, to-wit:

ATMOSPHERIC PRESSURE -- shall mean the pressure of air at the sea level, equivalent to about 14.7 

pounds to the square inch.

BALANCE -- (Gas) shall mean an instrument used for determining the specific gravity of gases by 

weighing methods.

BAROMETRIC PRESSURE -- shall mean the pressure or weight of air determined by the use of a 

barometer at a given point.

“BARREL” or “BARREL OF OIL” -- shall mean 42 United States gallons of oil at a test of 60 degrees 

Fahrenheit, with deductions for the full percent of basic sediment, water and other impurities 

present, ascertained by centrifugal or other recognized and customary test.

BLOW-OUT -- shall mean a sudden or violent escape of crude oil or natural gas, as from a drilling well, 

when high formation pressure is encountered.

BLOW-OUT PREVENTER -- shall mean a heavy casing head control filled with special gates or discs 

which may be closed around the drill pipe, or which completely closes the top of the casing if 

the pipe is withdrawn.

BOTTOM HOLE PRESSURE -- shall mean the pressure in pounds per square inch at or near the 

bottom of an oil or gas well determined at the face of the producing horizon by means of a 

pressure recovery instrument, adopted and recognized by the oil and gas industry, which can be 

lowered into the bore of the well. In the case of gas wells or wells having no fluid in the well 

bore, it shall mean the pressure as calculated by adding the pressure at the surface of the ground 

to the calculated weight of the column of gas from the surface to the bottom of the hole.

CASING PRESSURE -- shall mean the pressure built up between the casing and tubing when the casing 

and tubing are packed off at the top of the well.

CASINGHEAD GAS -- shall mean any gas or vapor, or both gas, and vapor, indigenous to an oil stratum 

and produced from such stratum with oil.

CHRISTMAS TREE -- shall mean an assembly of valves and fittings at the head of the casing of a well 

to control the flow. Also spoken of as “well head connections.”

CIRCULATION -- shall mean the passing of an approved fluid down through the drill stem and up to 

the surface in the process of rotary drilling in setting casing. 

COMBINATION WELL -- shall mean a well productive of both oil and gas in commercial quantities 

from the same common source of supply and which has sufficient natural gas pressure to cause 

the gas to enter a pipe line carrying more than atmospheric pressure.

COMMISSION -- shall mean the Arkansas Oil and Gas Commission.

COMMON SOURCE OF SUPPLY -- shall mean the geographical area or horizon definitely separated 

from any other such area or horizon and which contains, or from competent evidence appears to 

contain, a common accumulation of oil or gas or both. Any oil or gas field or part thereof which 
GENERAL RULES AND REGULATIONS

13

comprises and includes any area which is underlaid, or which from geological or other scientific 

data or experiments or from drilling operations or other evidence appears to be underlaid by a 

common pool or accumulation of oil or gas or both oil and gas.

CONDENSATE -- shall mean the liquid produced by the condensation of a vapor or gas either after it 

leaves the reservoir or while still in the reservoir. Condensate is often called Distillate, Drips, 

White Oil, Etc.

CONNATE WATER -- shall mean water which was deposited with the deposition of solid sediments in 

an oil or gas reservoir and which has not, since its deposition, existed as surface water at 

atmospheric pressure.

CONSERVATION -- shall mean the conserving, preserving, guarding or protecting the oil and gas 

resources of the state by obtaining the maximum efficiency with minimum waste in the 

production, transportation, processing, refining, treating and marketing of the unrenewable oil 

and gas resources of the state.

CONTROLLED OIL FIELD -- shall mean any common source of supply of crude oil discovered after 

January 1, 1937, or any field discovered prior to January 1, 1937, provided any pool therein has 

been discovered after January 1, 1937.

CONTROLLED GAS FIELD -- shall mean any common source of supply of natural gas discovered 

after January 1, 1937, or any field discovered prior to January 1, 1937, provided any pool therein 

has been discovered after January 1, 1937.

CONTROLLED PRODUCTION -- shall mean the production of oil or gas or both oil and gas from a 

controlled oil or gas field.

CORE HOLE -- shall mean a hole drilled below the fresh water level for obtaining geological and 

structural information without penetrating a known producing formation in the area.

CRUDE OIL -- shall mean petroleum oil, and other hydrocarbons, regardless of gravity, which are 

produced at the well in liquid form by ordinary production methods, and which are not the result 

of condensation of gas before or after it leaves the reservoir.

CUBIC FOOT OF GAS -- shall mean the volume of gas contained in one cubic foot of space at the 

standard pressure base and the standard temperature base. The standard pressure base shall be 

14.65 pounds per square inch absolute and the standard temperature base shall be 60o Fahrenheit.

DAY -- shall mean a period of twenty-four (24) consecutive hours from 7:00 a.m. one day to 7:00 a.m. 

the following day.

DEVELOPMENT -- shall mean any work which actively looks toward bringing in production, such as 

erecting rigs, building tankage, drilling wells, etc.

DIFFERENTIAL PRESSURE -- shall mean the difference between the tubing pressure and the flowline pressure; the drop flow-line pressure; the drop in pressure of the fluid in passing through the 

flow-nipple or choke; in the case of an orifice meter, the difference of the pressures on the upstream and the down-stream sides of the orifice; a pressure measured with a differential gauge or 

with a manometer (U-tube); any difference in pressure.
GENERAL RULES AND REGULATIONS

14

DISTILLATE -- shall mean a product of distillation of the fluid condensed from the vapor driven off in 

the still, such as gasoline, naphtha, kerosene, and light lubrication oils, the result of distillation 

of crude oil. Condensate is commonly referred to as distillate.

DIVISION ORDER -- shall mean a written statement, dated, duly signed by the owners and delivered to 

the purchaser, certifying and guaranteeing the interests of ownership of the production and 

directing payments according to those interests.

DRY GAS -- shall mean natural gas obtained from sands that produce gas only; or natural gas obtained 

which does not contain the heavier fractions which may easily condense under normal 

atmospheric conditions; not casinghead gas.

EDGE WATER -- shall mean water that holds the oil or gas, or both oil and gas, in higher structural 

position, usually encroaching on a pool as the oil or gas is removed.

FIELD -- shall mean the general area which is underlaid or appears to be underlaid by at least one pool; 

and “field” shall include the underground reservoir or reservoirs containing crude petroleum oil 

or natural gas, or both. The words “field” and “pool” mean the same thing when only one 

underground reservoir is involved; however, “field” unlike “pool,” may relate to two or more 

pools.

FLOWING WELL -- shall mean a well from which oil or gas flows naturally without pumping or other 

means of artificial lift.

GAS -- shall mean the natural gas obtained from gas or combination wells regardless of its chemical 

analysis.

GAS ALLOWABLE -- shall mean the amount of natural gas authorized to be produced by order of the 

Commission.

GAS ASSESSMENT -- shall mean the assessment on each thousand cubic feet of gas produced from a 

gas well to pay the costs incident to the administration of the rules of the Commission.

GAS REPRESSURING -- shall mean the introduction of gas or air into a common source of supply by 

artificial means in order to replenish, replace, or increase the gas energy causing the oil to flow 

out of the reservoir.

GAS-SOUR -- shall mean gas which contains hydrogen sulfide in sufficient quantities to render it unfit 

for domestic or commercial use.

GAS-WELL -- shall mean (1) a well which produces natural gas only; (2) any well capable of producing 

gas in commercial quantities and also producing oil from the same common source of supply but 

not in commercial quantities; or (3) any well classed as a gas well by the Commission for any 

reason; (4) a well that contains no liquid hydrocarbons in the reservoir.

GAS-LIFT -- shall mean a method of injecting gas for lifting a liquid from the well to the surface.

GAS-OIL RATIO -- shall mean the number of cubic feet of gas at atmospheric pressure, as produced 

from an oil well or combination well, divided by the number of barrels (42 gallons) of oil, the 

unit of time being a day of 24 hours. 

ILLEGAL OIL -- shall mean oil which has been produced within the State of Arkansas from any well 

during any time that well has produced in excess of the amount allowed by any rule, regulation 
GENERAL RULES AND REGULATIONS

15

or order of the Commission, as distinguished from oil produced within the State of Arkansas 

from a well not producing in excess of the amount so allowed, which is “legal oil.”

ILLEGAL GAS -- shall mean gas which has been produced within the State of Arkansas from any well 

during any time that well has produced in excess of the amount allowed by any rule, regulation 

or order of the Commission, as distinguished from gas produced within the State of Arkansas 

from a well not producing in excess of the amount so allowed, which is “legal gas.”

ILLEGAL PRODUCT -- shall mean any product of oil or gas, any part of which was processed or 

derived, in whole or in part, from illegal oil or illegal gas or from any product thereof as 

distinguished from “legal product,” which is a product possessed or derived to no extent from 

illegal oil or illegal gas.

INDICES OF PRODUCTIVE VALUE -- shall mean the factors to be considered in ascertaining the 

productivity of all property in a common source of supply for the purpose of fixing the allowable 

production. These indices can mean, at the discretion of the Commission, acreage, gas oil ratios, 

static reservoir pressures, flowing pressures, fluid level drawdowns, the well or wells, or any 

other pertinent factors.

LEASE TANK -- shall mean the tank or other receptacle into which oil is produced either directly from a 

well or from a well through gas separator, gun barrel or similar equipment.

METER -- shall mean an instrument for measuring and recording the volume of gases or liquids.

MONTH and CALENDAR MONTH -- shall mean the period or interval of time from 7 a.m. on the 

first day of any month of the calendar to 7 a.m., of the first day of the next succeeding month of

the calendar.

MUD-LADEN FLUID -- shall mean any approved mixture of water and clay or other material as the 

term is commonly used in the industry.

NATURAL GASOLINE -- shall mean gasoline manufactured from casinghead gas or from any natural 

gas.

OIL -- shall mean crude oil or petroleum.

OIL ALLOWABLE -- shall mean the amount of oil authorized to be produced by the order of the 

Commission.

OIL ASSESSMENT -- shall mean the assessment on each barrel of oil produced, from any field or 

reservoir, to pay the costs incident to the administration of the rules of the Commission.

OIL-PIPELINE -- shall mean oil free from water and basic sediment to the degree that it is acceptable 

for pipe line transportation and refinery use.

OIL-WELL -- shall mean any well capable of producing oil in paying quantities not a gas well.

OPERATOR -- shall mean any person who, duly authorized, is in charge of the development of a lease 

or the operation of a producing well.

OVERAGE, OVER-PRODUCTION -- shall mean the oil or gas produced in excess of the allowable as 

set by the Commission.
GENERAL RULES AND REGULATIONS

16

OWNER -- shall mean the person who was the right to drill into and produce from any field or reservoir, 

and to appropriate the production either for himself or for himself and another.

PERIOD, ALLOWABLE -- shall mean the month or day, as designated, in which allowable may be 

produced.

PERMEABILITY -- shall mean a measure, determined by scientific means, of the ability of fluid or gas 

to traverse the producing horizon in an oil or gas reservoir.

PERSON -- shall mean any natural person, corporation, association, partnership, receiver, trustee, 

guardian, executor, administrator, Federal agency, or representative of any kind.

PETROLEUM -- shall mean the natural untreated oil obtained from an oil well.

PIPE LINE -- shall mean any pipes above or below the ground used or to be used for the transportation 

of oil or gas.

PIPE LINE OIL -- see, Oil, Pipeline.

PLUG -- shall mean the abandoning of a producing or non-productive well; the stopping of the flow of 

water, gas or oil in a well.

POOL -- shall mean an underground reservoir containing a common accumulation of crude petroleum oil 

or natural gas or both. Each zone of a general structure which is completely separated from any 

other zone in the structure is covered by the term “Pool” as used herein.

POROSITY -- shall mean the state or quality of being porous; the volume of pore space expressed as a 

percentage of the total volume of the rock mass; the percentage or pores of interspaces forming 

the total bulk of the material.

POTENTIAL -- shall mean the actual or properly computed daily ability of a well to produce oil or gas, 

either or both, as determined by the rules and regulations of the Commission.

PRESSURE BASE -- shall mean an absolute pressure agreed upon or set as a base for converting the 

volume of gas metered to correct volume. The standard pressure base shall be 14.65 pounds per 

square inch absolute.

PRESSURE MAINTENANCE -- (1) shall mean the reintroduction (in the early stages of field 

development) of gas or fluid produced from an oil, gas or combination well to maintain the 

pressure of the reservoir. (2) The introduction of gas or fluid for the same purpose but obtained 

from an outside source.

PRODUCER -- shall mean any person who owns, in whole or in part, a well capable of producing oil or 

gas or both in paying quantities.

PRODUCT -- means any commodity made from oil or gas, and shall include refined crude oil, crude 

tops, topped crude, processed crude petroleum, residue from crude petroleum, cracking stock, 

uncracked fuel oil, fuel oil, treated crude oil, residuum, gas oil, casinghead gasoline, natural gas, 

gasoline, naphtha, distillate, gasoline, kerosene, benzine, wash oil, waste oil, blended gasoline, 

lubricating oil, blends or mixture of oil with one or more liquid products or by-products derived 

from oil or gas, whether herein above enumerated or not.

PRODUCTION, ILLEGAL, -- see Illegal Gas, Illegal Oil.
GENERAL RULES AND REGULATIONS

17

PRODUCTION INTERESTS -- shall mean the right to a specified part of production.

PROVEN OIL OR GAS LAND -- shall mean that area which has been shown by development and 

geological information to be such that additional wells drilled thereon are reasonably certain to 

be commercially productive of oil or gas or both.

PURCHASER -- shall mean any person who directly or indirectly purchases, transports, takes or 

otherwise removes production to his account from a well or lease. Purchaser is usually 

considered to be the person holding the Division Order.

RATABLE TAKE -- see Controlled Production.

RECOMPLETION -- shall mean completion operations performed in a source of supply that is separate 

and distinct from the source of supply in which the well was successfully completed prior to the 

commencement of the current completion operations.

REFINER -- shall mean every person who has any part in the control or management of any operation by 

which the physical or chemical characteristics of oil or products are changed, but exclusive of 

the operations of passing oil through separators to remove gas, placing oil in settling tanks to 

remove basic sediment and water, dehydrating oil, and generally cleaning and purifying oil.

REPRESSURE -- shall mean to increase the reservoir pressure by the introduction of gas or fluid into the 

reservoir.

RESERVOIR PRESSURE -- see Bottom Hole Pressure.

ROCK PRESSURE -- shall mean the well head pressure on a gas well that has been closed long enough 

to attain a maximum.

ROTARY DRILLING -- shall mean the hydraulic process of drilling, consisting of rotating a column of 

drill pipe to the bottom of which is attached a rotary drilling bit.

RUN -- shall mean oil or gas removed from the lease.

SEPARATOR -- shall mean an apparatus for separating gas from oil with relative efficiency, as it is 

produced.

SHUT-IN PRESSURE -- shall mean the pressure noted at the wellhead when the well is completely shut 

in. Not to be confused with Bottom Hole Pressure

SPUDDING -- shall mean the initial step in drilling.

STORER -- shall mean every person as herein defined who stores, terminals, retains in custody under 

warehouse or storage agreements or contracts, oil which comes to rest in his tank or other 

receptacle under control of said storer, but excluding the ordinary lease stock of producers.

TAKER -- see Purchaser.

TENDER -- shall mean a permit or certificate of clearance for the transportation of oil, gas, or products, 

approved and issued or registered under the authority of the Commission.

TENDERSHIP -- shall mean the production delivered from one person to another.
GENERAL RULES AND REGULATIONS

18

TOPPING PLANT -- shall mean a refinery designed to remove only the gasoline and kerosene fractions 

from oil.

TRAP PRESSURE -- shall mean pressure held at the oil and gas separator.

TRANSPORTER-- shall mean and include any common carrier by pipe line, barge, boat or other water 

conveyance, or truck or other conveyance except railroads, and any person transporting oil by 

pipeline, barge, boat or other water conveyance, or truck and other conveyance.

TUBING -- shall mean the conduit through which oil or gas is removed from a well.

VACUUM -- shall mean pressure which is reduced below the pressure of the atmosphere.

VOLATILE -- shall mean easily wasting away by evaporation.

WASTE -- in addition to its ordinary meaning, shall mean “physical waste” as that term is generally 

understood in the oil and gas industry. It shall include:

(1) The inefficient, excessive or improper use or dissipation of reservoir energy; and the 

locating, spacing, drilling, equipping, operating or producing of any oil or gas well or wells 

in a manner which results, or tends to result, in reducing the quantity of oil or gas ultimately 

to be recovered from any pool in this state.

(2) The inefficient storing of oil; and the locating, spacing, drilling, equipping, operating or 

producing of any oil or gas well or wells in a manner causing, or tending to cause, 

unnecessary or excessive surface loss or destruction of oil or gas.

(3) Abuse of the correlative rights and opportunities of each owner of oil and gas in a common 

reservoir due to non-uniform, disproportionate, and unratable withdrawals causing undue 

drainage between tracts of land.

(4) Producing oil or gas in such manner as to cause unnecessary water channeling or coning.

(5) The operation of any oil well or wells with an inefficient gas-oil ratio.

(6) The drowning with water of any stratum or part thereof capable of producing oil or gas.

(7) Underground waste however caused and whether or not defined.

(8) The creation of unnecessary fire hazards.

(9) The escape into the open air from a well producing both oil and gas, of gas in excess of the 

amount which is necessary in the efficient drilling or operation of the well.

(10) The use of gas for the manufacture of carbon black.

(11) Permitting gas produced from a gas well to escape into the air.

WATER CONE -- shall mean the creation of irregularly intruding water by allowing a well to produce 

too rapidly.

WELL LOG -- shall mean an electrical, or any other type of survey, made for the purpose of ascertaining 

the strata through which a well bore has penetrated.
GENERAL RULES AND REGULATIONS

19

WILDCAT WELL -- shall mean a well drilled outside the geological confines of proven production.

WORKOVER -- shall mean work of a remedial nature performed within the vertical confines of the 

same source of supply.

(Source: 1991 rule book)
GENERAL RULES AND REGULATIONS

20

RULE A-5: ENFORCEMENT PROCEDURES

a) Definitions:

1) “Commission” shall mean the Arkansas Oil and Gas Commission, on which the Director 

serves as secretary, but is a non-voting member.

2) “Director” shall mean the Commission Director of Production and Conservation.

3) “Regulated Entity” shall mean all operators, owners, producers or persons subject to 

Commission regulatory authority. 

4) “UIC” shall mean the Underground Injection Control program of the Federal Safe 

Drinking Water Act.

b) Any regulated entity engaged in the drilling, operation or plugging of any production, injection, 

or other well or drill hole regulated by the Commission; or the operation of any crude oil or gas 

production or injection facility; or the operation of any natural gas line or crude oil flowline 

regulated by the Commission; or transporter by tank truck of any oilfield production or 

completion fluid; or seismic activity; or any other activity regulated by the Commission, is 

subject to this rule for violation of any oil, gas and/or brine statutes, or any rule, regulation, or 

permit condition of the Commission. 

c) In accordance with Ark. Code Ann. § 15-72-103(c) or § 15-76-303(c), any person knowingly and 

willfully aiding or abetting any other person in the violation of any statute relating to the 

conservation of oil, gas and/or brine, or the violation of any provision of the state oil, gas and/or 

brine statutes, or any rule, regulation, order, or permit condition, shall be subject to the same 

penalties as are prescribed herein for the regulated entity.

d) Notice of Non-Compliance 

1) A Notice of Non-Compliance may be issued when any regulated entity is in noncompliance with any requirement of the Arkansas oil, gas and/or brine statutes, or rules, 

regulations, orders, or any permit condition, and:

A) That the non-compliance was not caused by the regulated entity’s deliberate 

action;

B) That any action necessary to abate the non-compliance was commenced 

immediately and was or will be completed within a specified date certain, as 

established by the Director, or his or her designee, not to exceed thirty (30) days 

from the date of the determination that the regulated entity was determined to be 

in non-compliance; and

C) That the non-compliance has not caused and cannot reasonably be expected to 

cause significant environmental harm or damage to property. 

2) The notice of non-compliance shall be documented in writing and, delivered via first 

class mail to the regulated entity or to the regulated entity’s representative as reported on 

the AOGC Form 1 Organization Report. The written notification shall indicate the nature 

and circumstances of the non-compliance, and the time within which and the means by 

which the non-compliance is to be abated. 
GENERAL RULES AND REGULATIONS

21

3) If abatement was not completed as specified in the written notification, the Director, or 

his or her designee, may issue a formal Notice of Violation in accordance with 

subparagraph (e) below. 

4) The provisions of this subparagraph (d), shall not apply to the following types of 

incidents, which may require a Notice of Violation to be issued in accordance with 

subparagraph (e) below:

A) Conducting any regulated activity specified in paragraph (b) above prior to 

issuance or re-issuance of the appropriate Commission permit or authority;

B) Operating an annular or casing injection/disposal well or a well with pressure on 

the annulus;

C) Failure to maintain required performance bond or pay annual well fees;

D) Failure to establish mechanical integrity on any UIC well prior to operation, or 

failure to repair any UIC well following failure of mechanical integrity;

E) Commencing any work or activity on a well or its related production facility or 

well site that has been placed in the Abandoned and Orphan Well Plugging 

Program;

F) Failure to provide emergency response for a crude oil or saltwater spill;

G) Improper discharge or disposal of produced fluids; or

H) Operating a well in violation of spacing requirements or permit conditions.

e) Notice of Violation(s)

1) A Notice of Violation may be issued, by the Director or his or her designee, when any 

regulated entity is in violation of any requirements of the Arkansas oil, gas, and/or brine 

statutes, or rules, regulations, orders, or any permit conditions of the Commission. 

Unless otherwise determined by the Commission after notice and a hearing, a regulated 

entity shall not be held responsible by the Commission for violations of oil, gas and/or 

brine statutes, or rules, regulations, or permit conditions of the Commission in the 

absence of the issuance of an underlying Notice of Violation.

2) The Notice of Violation shall be in writing and contain:

A) A statement regarding the nature of the violation, including a citation to the 

specific section of the oil, gas and/or brine statutes, or any rule, regulation, order 

or permit condition of the Commission alleged to have been violated; 

B) The suggested action needed to abate the violation including any appropriate 

remedial measures to prevent future violations; 

C) The time within which the violation should be abated; and

D) A notice of any civil penalties, as specified in subparagraph g) below, the 

Director will request to be issued by the Commission. 
GENERAL RULES AND REGULATIONS

22

E) A notice of any civil penalties for violations of natural gas line regulations under 

United States Department of Transportation, Office of Pipeline Safety 

jurisdiction in accordance with appropriate federal regulation specified in 49 

CFR 190.223, the Director will request to be issued by the Commission. 

3) The Notice of Violation may include a well, lease, or unit cessation requirement for the 

following types of violations:

A) Violation of production allowable;

B) Failure to maintain required well specific performance bond;

C) Drilling or operating, without a Commission permit or permit transfer, a well 

required to be permitted or transferred;

D) Operating a well that has been determined to be abandoned by the Commission;

E) Failure to plug a leaking well or a well ordered to be plugged by the 

Commission;

F) Operating an annular or casing injection/disposal well;

G) Operating a UIC Class II or V well with a failed mechanical integrity test;

H) Operating a UIC Class II or V well with pressure on the annulus indicating 

tubing and/or casing failure; 

I) Failure to provide emergency response or remediate a crude oil or produced 

water spill; 

J) Improper disposal or discharge of produced fluids; or

K) Any other violation for which a cessation requirement is authorized by an oil, gas

and/or brine statute, or rule, regulation, order or permit condition.

4) The Notice of Violation may also include a state-wide cessation requirement for the 

following types of violations:

A) Failure to maintain required blanket financial assurance as specified in General 

Rule B-2;

B) Failure to pay annual well fees as specified in General Rule B-2; 

C) Failure to pay any monies due the Abandoned and Orphaned Well Plugging Fund 

as specified in General Rule G-1; or

D) Failure to comply with the provisions of General Rule B-42, or General Rule E3.

E) Any other violation for which a state-wide cessation requirement is authorized by 

an oil, gas and/or brine statute, or rule, regulation, order or permit condition.
GENERAL RULES AND REGULATIONS

23

5) The Director, or his or her designee, shall send via certified mail the Notice of Violation 

to the regulated entity, or the regulated entity’s representative as reported on the AOGC 

Form 1 Organization Report, charged with the violation(s), or provide personal delivery 

of a copy of the notice to the regulated entity, or the regulated entity’s representative. 

6) The regulated entity charged with the violation(s) may request a Director’s Review of the 

Notice of Violation and provide the Director, in writing, any information in mitigation of 

the violation(s) on or before thirty (30) calendar days of the mailing or personal delivery 

of the original Notice of Violation, unless a shorter time period is specified in the Notice 

of Violation for instances where there is a condition that creates an imminent danger to 

the health or safety of the public or threatens significant environmental harm or damage 

to the property. Such written information may include a proposed alternative to the 

required action needed to abate the violation(s). Upon receipt of such information from 

the regulated entity, the Director, shall conduct a review.

7) During the review, the Director may consider any of the following criteria in reaching a 

Final Director’s Decision regarding the violation(s): 

A) The regulated entity’s history of previous violations, including violations at other 

locations and under other permits;

B) The seriousness of the violation, including any irreparable harm to the 

environment or damage to property;

C) The degree of culpability of the regulated entity; and

D) The existence of any additional conditions or factors in aggravation or mitigation 

of the violation, including information provided by the regulated entity.

8) Upon completion of the review, the Director shall issue a Final Director’s Decision to:

A) affirm the violation; or

B) vacate the violation; or

C) amend or modify the type of violation and abatement requirements specified in 

the violation; or

D) establish probationary or permanent modification or conditions to any underlying 

permit related to the violation, which may include special monitoring or reporting 

requirements; or

E) enter into a settlement agreement to extend the amount of time provided to 

complete remedial actions necessary to abate the violations or reduce the amount 

of the requested assessed civil penalty. 

9) The Final Director’s Decision shall be delivered to the regulated entity, or the regulated 

entity’s representative, as reported on the AOGC Form 1 Organization Report, via first 

class mail. The Final Director’s Decision may be appealed to the Commission by filing 

an application in accordance with General Rule A-2, A-3, and other applicable hearing 

procedures. The application to appeal the Final Director’s Decision is required to be 

received by the Director within thirty (30) days of the mailing of the Final Director’s 

Decision. The application shall state the reason for the appeal and shall be scheduled to 
GENERAL RULES AND REGULATIONS

24

be heard by the Commission in accordance with General Rule A-2, A-3, and other 

applicable hearing procedures. 

10) A Notice of Violation for which a Director’s Review has not been requested, shall 

become a final administrative decision of the Commission thirty (30) days following the 

mailing of the Notice of Violation.

11) A Final Director’s Decision not appealed to the Commission within thirty (30) days of 

mailing of the Final Director’s Decision shall become a final administrative decision of 

the Commission. 

12) All violations specified in a Notice of Violation(s) which have become a final 

administrative decision in accordance with subparagraph e) 10), a Final Director’s 

Decision which has become a final administrative decision of the Commission in 

accordance with subparagraph e) 11), or by Order of the Commission, shall be fully 

abated within the time frame specified in the original Notice of Violation, Final 

Director’s Decision, or Order of the Commission. No further permits or authorities shall 

be issued to the regulated entity until all outstanding violations specified in a Notice of 

Violation which has become a final administrative decision in accordance with 

subparagraph e) 10), a Final Director’s Decision which has become a final administrative 

decision of the Commission in accordance with subparagraph e) 11), or by Order of the 

Commission have been fully abated.

f) In addition to the issuance of a Notice of Violation(s), the Director may initiate further 

enforcement proceedings, as provided for in statute, as follows:

1) Assessment of a civil penalty as provided in Ark. Code Ann. § 15-71-114, § 15-72-103, § 

15-72-202, or § 15-76-303;

2) The revocation of a certificate of clearance on a state-wide basis, as provided for in Ark. 

Code Ann. § 15-71-110 (11);

3) The filing of a civil complaint in a court of competent jurisdiction in the County where 

the violation occurred, as provided for in Ark. Code Ann. § 15-72-108 or § 15-76-304;

4) The filing of a criminal complaint in any court of competent jurisdiction, as provided for 

in Ark. Code Ann. § 15-71-114, § 15-72-104 or § 15-76-303. 

g) Civil Penalties 

1) The Director shall determine whether to request the assessment of civil penalties based 

on failure to comply with the applicable abatement requirements for violations issued 

under subparagraphs (g) (2) and (3) below. The Director shall determine whether to 

request the assessment of civil penalties for violations issued under subparagraphs (g) (4) 

and (5) below. If a civil penalty is requested by the Director, the Regulated Entity may 

voluntarily agree to the assessment and pay the civil penalty as requested or modified by 

the Director, or the Director or his designee may file an application, in accordance with 

General Rule A-2, A-3, and other applicable hearing procedures, to request the issuance 

of the requested civil penalty by the Commission. The maximum amount of the

Director’s requested civil penalty shall be computed as provided in subparagraphs (g) (2) 

through (5) below. However, the Commission is not bound by the Director’s request, or 

the amounts provided below, and may impose civil penalties of up to the maximum 

amounts permitted by law.
GENERAL RULES AND REGULATIONS

25

2) Administrative violations, defined as failure to file required reports and forms and to 

provide required notices (excluding spill notice), including, but not limited to regulated 

activities such as, the failure to file production and well reports or other reports required 

by Commission rules, regulations, orders or permit conditions; failure to notify the 

Commission before the setting of surface casing, or the plugging of a well; failure to 

maintain required performance bond in force for the wells under permit; or pay annual 

well fees within the specified time. The Director may request the assessment of up to 

$1000 per administrative violation and up to $1000 per day for each day the violation 

remains unabated after the specified compliance date. The per administrative violation 

civil penalty request shall be calculated as follows:

A) No previous violation of the same rule: $250. One previous violations of the 

same rule: $500. Two or more previous violations of the same rule: $1000. The 

fourth and each subsequent violation of the same rule shall be considered a 

significant violation in accordance with subparagraph g) 4) below.

B) The time frame used for determining previous violations shall be limited to the 

regulated entity’s violation record for the preceding three full calendar years 

before the issuance of the violation.

3) Operating violations, defined as failure to maintain compliance with Commission rules 

on well drilling and operation, and production facility, pipeline and seismic operations 

and/or commencing operations requiring a permit prior to issuance or re-issuance of the 

required permit or authority. These operations include, but are not limited to regulated

activities such as, operating a well or natural gas pipeline system without the proper 

permit or transfer of ownership, failure to maintain a well or crude oil flow line in a leakfree condition, failure to comply with non-jurisdictional natural gas pipeline 

requirements, failure to notify of a spill occurrence, failure to maintain containment 

dikes, or operating an Exploration and Production Fluid Transportation System without a 

proper permit. Multiple incidents of the same violation against a regulated entity on the 

same occasion shall not be considered separate violations. The Director may request the 

assessment of up to $2500 per operating violation and up to $2500 per day for each day 

the violation remains unabated after the specified compliance date, with the exception 

that operating violations as specified in Ark. Code Ann. § 15-76-303 are limited to a 

maximum of $1,000 per operating violation. The per operating violation civil penalty 

shall be calculated as follows:

A) No previous violation of the same rule $500. One previous violation of the same 

rule, $750; two or more previous violations of the same rule, $1000. The fourth 

and each subsequent violation of the same rule shall be considered a significant 

violation in accordance with subparagraph g) 4) below.

B) The time frame used for determining previous violations shall be limited to the 

regulated entity’s violation record for the preceding three full calendar years 

before the issuance of the violation; plus

C) If the violation had a low degree of probability to cause environmental impact to 

soil and/or land surface, vegetation or crops, surface water, groundwater, 

livestock or wildlife, add $250; or, if the violation had a high degree of 

probability to cause environmental impact to soil and/or land surface, vegetation 

or crops, surface water, groundwater, livestock or wildlife, add $500; or, if the 
GENERAL RULES AND REGULATIONS

26

violation caused environmental impact to soil and/or land surface, vegetation or 

crops, surface water, groundwater, livestock or wildlife, add $1000, or

D) f the violation created a hazard to the safety of any person, such as the 

contamination of a potable water well or emission of hydrogen sulfide gas, add 

$2000.

4) Except as limited in Ark. Code Ann. § 15-76-303, or as otherwise provided in 

subparagraphs g) 5) or 6) below, significant violations may result in a request by the 

Director or his or her designee, of a civil penalty of up to $2500 per violation and up to 

$2500 per day for each day of the violation for the following types of violations: failure 

to comply with the provisions of General Rule A-7, failure to comply with well spacing 

provisions, operating a UIC well without a proper permit, operating an annular or casing 

injection/disposal well, operating a UIC well prior to establishing mechanical integrity, 

operating a UIC well with a failed mechanical integrity test, operating a UIC well with 

pressure on the annulus, failure to provide emergency response or remediate a crude oil 

or produced water spill, or the improper disposal or discharge of produced fluids. The 

per violation civil penalty shall be computed as follows:

A) An initial amount of $1000; plus

B) One or more previous violations of the same type: add $500 per violation; plus

C) If the violation caused environmental impact to surface water, ground water or 

wildlife: add $1000, or if the violation created a hazard to the safety of any 

person, such as the contamination of a potable water well or emission of 

hydrogen sulfide gas: add $1500.

D) The time frame used for determining previous violations shall be limited to the 

regulated entity’s violation record for the preceding three full calendar years 

before the issuance of the violation.

5) In accordance with Ark. Code Ann. §15-72-103, the Director, or his or her designee, may 

request a civil penalty of up to $100,000 for any person who transports a liquid or other 

substance and violates a rule, regulation, or order of the commission by dumping or 

disposing of the liquid or other substance improperly or without authorization at a well or 

well site.

6) The Director, or his or her designee, may request any amount in civil penalties authorized 

by applicable federal law for violations of the United States Department of 

Transportation, Office of Pipeline Safety jurisdictional natural gas line requirements.

h) All civil penalties assessed and paid to the Commission shall be deposited in the Commission 

operating fund. Additionally, all civil penalties assessed and paid, for violations specified in Ark. 

Code Ann. § 15-72-202 shall be turned into the general fund of the county where the violation 

occurred to be used on roads, bridges, and highways at the discretion of the county court.

(Source: new rule September 14, 2008; amended July 17, 2009; amended October 24, 2009; amended 

July 29, 2011; amended February 17, 2012; amended January 20, 2014)
GENERAL RULES AND REGULATIONS

27

RULE A-6: RESERVED

Reserved for Future Use

RULE A-7: DETERMINATION OF NATURAL GAS WELL CATEGORIES FOR 

SEVERANCE TAX PURPOSES

a) Applicability

In accordance with Ark. Code Ann. § 26-58-128, the Director of the Oil and Gas Commission 

shall determine the well categories for all gas production wells, which will be used by the 

Arkansas Department of Finance and Administration to determine the appropriate severance tax 

rate for each well. All gas production wells under the jurisdiction of the Oil and Gas Commission 

are subject to the provisions of this rule.

b) Definitions:

1) “Commission” shall mean the Arkansas Oil and Gas Commission, on which the Director 

serves as secretary, but is a non-voting member.

2) “Conventional Gas Well” means a gas well that is not classified as a high cost gas well.

3) “Director” means the Oil and Gas Commission Director of Production and Conservation.

4) “High Cost Gas Well” means a gas well that:

A) Produces gas from any shale formation, including but not limited to the 

Fayetteville Shale, Woodford Shale, Moorefield Shale and the Chattanooga 

Shale, or their stratigraphic equivalents as described in published stratigraphic 

nomenclature recognized by the Arkansas Geologic Survey; or 

B) Produces gas from any completion that is located at a depth of more than 12,500 

feet below the surface of the earth, where the term “depth” means the length of 

the maximum continuous drilling string of drill pipe used between the drill bit 

face and the drilling rig’s Kelly bushing; or

C) Produces gas from a tight gas formation which is defined as a formation which: 

i) Has previously been determined to be a low permeability formation by 

Commission Orders or field rules for Booneville and Chismville (84-

2003-07), Gragg (89-2004-07), Waveland (86-2004-07), Rich Mountain 

(304-2006-09), Mansfield (28-2003-03), Witcherville and Excelsior 

(103-2005-07); and General Rule B-44; or

ii) Is determined by the Director to have an estimated in situ permeability of 

one-tenth millidarcy (0.1 mD) or less; or

iii) Is determined to be a tight gas formation by field rule, general rule or 

orders approved by the Commission and issued by the Director.

D) Produces gas from a geopressured brine; or

E) Produces occluded gas from a coal seam. 
GENERAL RULES AND REGULATIONS

28

5) “Marginal Conventional Gas Well” shall mean a conventional gas well which is 

incapable of producing more than 250 Mcf per day, from all zones producing in such 

well, as determined by the sum of the individual deliverability rates for each zone, using 

one of the current wellhead deliverability rate methodologies described in subparagraph 

h) below.

6) “Marginal High Cost Gas Well” shall mean a high cost gas well which is incapable of 

producing more than 100 Mcf per day, from all zones producing in such well, as 

determined by the sum of the individual deliverability rates for each zone, using one of 

the current wellhead deliverability rate methodologies described in subparagraph h) 

below.

7) “New Discovery Gas Well” shall mean any conventional gas well for the period 

commencing on the date of first production and ending on the date that is 24 consecutive 

calendar months following the date of first production.

c) On or before January 1, 2009, the Director shall determine the initial well category for each 

existing gas producing well in the State. If a well contains two or more separately metered 

producing zones (sources of supply), and one or more of the producing zones are different 

categories, the well category shall be based on which zone in the well produces the larger 

percentage of the total well production, based on the most recent back pressure test methodology 

specified in General Rule D-16. On or before January 1, 2009 the Director shall notify each 

permit holder of each existing wells determination as a:

1) High Cost Gas Well, including whether it is a high cost gas well producing gas from the 

date of first production and for a minimum period of 36 consecutive calendar months 

following the date of first production, unless a longer time period is granted by the 

Department of Finance and Administration in accordance with Ark Code Ann. § 26-58-

127; or

2) Marginal Conventional Gas Well; or 

3) Marginal High Cost Gas Well; or

4) New Discovery Gas Well; or

5) A Conventional Gas Well.

d) After January 1, 2009 the Director shall determine, at the time of permitting each new well, the 

appropriate well category as specified in subparagraph c) above, which shall be effective the date 

of first production from the well. This well category determination, made at the time of the initial 

new well permit issuance or as amended in accordance with this subparagraph or subparagraph g) 

below, shall determine the well category throughout the life of that well. Once a permit is issued, 

if a well is completed in two or more separately metered producing zones (sources of supply), and 

one or more of the producing zones are different categories, with respect to a Conventional Gas 

Well or a High Cost Gas Well, the well category shall be based on which zone in the well 

produces the larger percentage of the total well production, based on the initial back pressure tests 

required by General Rule D-16. The well category determination, shall determine the category for 

that well throughout the life of that well, regardless if other zones are produced within the well at 

a later date, until such time as the well qualifies as a Marginal Conventional Gas Well or a 

Marginal High Cost Gas Well. 
GENERAL RULES AND REGULATIONS

29

e) Following the well category determination for all existing wells on January 1, 2009, and the 

ongoing categorization for all new wells after January 1, 2009, the permit holder may request at 

any time, on a form prescribed by the Director, another well category determination with respect 

to the well category definitions specified in subparagraph b) above, in accordance with the 

application procedures specified in subparagraph i) below.

f) Upon submission of the application and supporting documentation or other required information, 

the Director shall make a determination within fifteen (15) calendar days from the receipt of such 

application.

1) The effective date of the well category determination request shall automatically be the 

first day of the next month following the postmark date the application was mailed to the 

Director or date of the Director’s Office date stamp, if delivered in person to the Director.

2) If approved by the Director, the application shall be sent via first class mail to the permit 

holder and a copy forwarded to the Department of Finance and Administration (“DFA”). 

3) If the application is denied by the Director, the permit holder may appeal the Director’s 

determination to the Commission by filing an application in accordance with General 

Rule A-2, A-3, and other applicable hearing procedures. If the permit holder does not 

appeal the denial, and the date of the Director’s denial occurs after the effective date of 

the well determination request as defined in subparagraph f) 1) above, the permit holder 

may be subject to additional payment provisions in accordance with DFA procedures. If 

the permit holder appeals the denial, the effective date of the well categorization request 

shall remain in effect pending the outcome of the appeal. 

g) If following a review of completion reports, monthly production reports, the applicable wellhead 

deliverability rate, utilizing one of the current methodologies specified in subparagraph h) below, 

or other information, the Director determines a well is not correctly categorized, the Director shall 

determine the correct well category and notify the permit holder. The corrected well category 

determination shall become effective on the first day of the month following the month in which 

the Director notifies the permit holder of the corrected well category determination, unless the 

permit holder files an appeal of the Director’s decision in accordance with General Rule A-2, A3, and other applicable hearing procedures.

h) All existing well category determinations under subparagraph c) and all new well category 

determinations under subparagraph d) shall be made on the basis of one of the following current 

wellhead deliverability rate methodologies:

1) Establishing cumulative deliverability of the well utilizing test methodologies specified in 

General Rule D-16; or

2) Calculating the cumulative deliverability of the well utilizing the most recent six month 

average daily rate of production for the well under actual operating conditions by 

dividing the total gas reported for the well by the number of days the well produced 

during the applicable six month period. However, this well category determination 

method is not applicable for wells subject to an exceptional location penalty.

i) Well Category Determination and Application Procedures

1) High Cost Gas Well.
GENERAL RULES AND REGULATIONS

30

A) The High Cost Gas Well category shall be assigned to all existing wells on 

January 1, 2009, which satisfy the definition of a High Cost Gas Well in 

accordance with subparagraph b) 4) above. If on that date the High Cost Gas 

Well has a reported date of first production on or after January 1, 2006, the well 

shall automatically qualify for a cost recovery period for a period of 36 

consecutive calendar months following the date of first production, unless a 

longer time period is granted by the Department of Finance and Administration 

in accordance with Ark Code Ann. § 26-58-127. 

B) On or after January 1, 2009, the High Cost Gas Well category shall be assigned 

to all newly permitted wells that satisfy the definition of a High Cost Gas Well in 

accordance with subparagraph b) 4) above at the time of well categorization in 

accordance with subparagraphs d) and g) above. The well shall automatically 

qualify for a cost recovery period for a period of 36 consecutive calendar months 

following the date of first production, unless a longer time period is granted by 

the Department of Finance and Administration in accordance with Ark Code 

Ann. § 26-58-127.

C) At the conclusion of the cost recovery period, specified in subparagraph i) 1) A) 

and B) above, the well shall automatically be re-classified as a High Cost Gas 

Well no longer subject to the tax rate for the cost recovery period, and shall be 

subject to the applicable severance tax rate specified in Ark Code Ann. § 26-58-

111(5)(D) unless an application is made for classification as a Marginal High 

Cost Gas Well in accordance with subparagraph i) 3) B) below. The effective 

date of the automatic re-classification shall be the first day of the month 

following the month in which the specified recovery period expired.

2) New Discovery Gas Well 

A) The New Discovery Gas Well category shall be assigned to all existing 

conventional wells on January 1, 2009, which as of that date, have a reported 

date of first production on or after January 1, 2007.

B) The New Discovery Gas Well category shall be automatically assigned to all 

newly permitted conventional wells on or after January 1, 2009 at the time of 

well categorization in accordance with subparagraphs d) and g) above. The well 

category determination shall remain in effect for 24 consecutive calendar months 

following the date of first production.

C) At the conclusion of the 24 consecutive calendar months following the date of 

first production, the New Discovery Gas Well determination shall automatically 

terminate. The effective date of the automatic termination shall be the first day of 

the month following the month in which the actual date of termination occurred. 

The well shall be automatically re-classified as a Conventional Gas Well subject 

to the applicable severance tax rate specified in Ark Code Ann. § 26-58-

111(5)(D), unless application is made for classification as a Marginal 

Conventional Gas Well in accordance with subparagraph i) 3) B) below.

3) Marginal Conventional Gas Well and Marginal High Cost Gas Well

A) The applicable Marginal Gas well category shall be assigned to all existing 

Conventional Gas Wells and High Cost Gas Wells on January 1, 2009, that 

qualify as either a Marginal Conventional Gas Well or a Marginal High Cost Gas 
GENERAL RULES AND REGULATIONS

31

Well and, which as of that date do not qualify as either a New Discovery Gas 

Well during the cost recovery period set forth in subparagraphs i) 2) A), and B) 

above, or a High Cost Gas Well during the cost recovery period set forth in 

subparagraphs i) 1) A) and B) above.

B) When a Conventional Gas Well qualifies as a Marginal Conventional Gas Well, 

or a High Cost Gas Well qualifies as a Marginal High Cost Gas Well, a permit 

holder may apply to the Director, for a Marginal Conventional Gas Well or 

Marginal High Cost Gas Well category determination. The request shall be on a 

form prescribed by the Director and shall include a copy of the most recent well 

head deliverability rate determination for all producing zones based on one of the 

current wellhead deliverability rate methodologies specified in subparagraph h) 

above.

C) The effective date of the applicable Marginal Gas well determination shall be the 

first day of the month following the month in which the permit holder’s 

application was received in accordance with subparagraph f) above.

D) A permit holder shall immediately notify the Director in writing when a well, 

which has been previously determined to be a Marginal Conventional Gas Well 

no longer qualifies as a Marginal Conventional Gas Well, or a Marginal High 

Cost Gas Well no longer qualifies as a Marginal High Cost Gas Well. When a 

previously determined Marginal Conventional Gas Well becomes capable of 

producing more than 250 Mcf per day over a 30 day period or a well previously 

determined to be a Marginal High Cost Gas Well becomes capable of producing 

more than 100 Mcf per day over a 30 day period, the permit holder shall submit a 

copy of the most recent well head deliverability rates for each producing zone in 

the well, based on one of the current wellhead deliverability rate methodologies 

specified in subparagraph h) above, along with the required written notice to the 

Director. 

4) Wells not classified as a High Cost Gas Well, New Discovery Gas Well, Marginal 

Conventional Gas Well or Marginal High Cost Gas Well, as described above, shall be 

automatically classified as a Conventional Gas Well subject to the severance tax rate 

specified in Ark Code Ann. § 26-58-111(5)(D).

j) Failure to comply with any provision of this rule may result in the initiation of enforcement 

actions in accordance with General Rule A-5, including the assessment of a civil penalty not to 

exceed two thousand five hundred dollars ($2500) per day for each day of the violation. 

(Source: new rule November 16, 2008; amended June 5, 2009)
GENERAL RULES AND REGULATIONS

32

RULE A-8: REPORTING REQUIREMENTS FOR MINERAL PROCEEDS ESCROW 

ACCOUNTS

a) In accordance with Ark. Code Ann. § 18-28-402 every holder of mineral proceeds shall establish 

an escrow account for mineral proceeds if the person entitled to the receipt of the mineral 

proceeds is unknown or has not been located within one (1) year after the funds become payable 

or distributable. 

b) Any holder required to establish more than one (1) escrow account by this rule may commingle 

all such accounts in a single account, provided that the holder shall maintain separate records of 

each deposit and withdrawal for every escrow account. 

c) Every holder shall file an annual report for each escrow account until such time as the mineral 

proceeds are presumed abandoned and deposited by the Auditor of the State in the Abandoned 

Mineral Proceeds Trust Fund as specified in Ark. Code Ann. § 18-28-403. 

d) The annual report shall contain the following information for each escrow account:

1) the name and last known address of the property owner;

2) the legal description of the property interest;

3) the location and account number of the escrow account;

4) the name of the person authorized to order withdrawals from the escrow account; and

5) any other information the Commission may require.

e) The annual reports are required to be filed on January 15th of each year and shall be deemed 

delinquent on February 1st of each year. Failure to submit the required reports by February 1st of 

each year may result in the issuance of a fine not to exceed one thousand dollar ($1,000) for each 

violation.

f) Any holder who violates any other provision of this Rule may be subject to a fine not to exceed 

one thousand dollar ($1,000) for each violation, and the Commission may conduct random audits 

of the escrow accounts required by this Rule.

(Source: new rule November 16, 2008)
GENERAL RULES AND REGULATIONS

33

GENERAL RULE B - DRILLING AND PRODUCTION

RULE B-1: APPLICATION TO DRILL A PRODUCTION WELL

a) Definitions:

1) “Production Well” means a well drilled, deepened, or re-entered after plugging, for the 

exploration or production of oil and/or gas or brine; or a well drilled, deepened or reentered after plugging for a water supply for use in connection with an enhanced oil 

recovery project.

2) “Deepen” for a cased well means an operation whereby a well is drilled to a measured 

depth below the cement casing shoe. For an open hole completion, “Deepen” means an 

operation whereby a well is drilled below the original measured depth of the well. 

3) “Drill” means the commencement of an operation to either set conductor pipe or the 

moving in a drilling rig capable of drilling to a depth to set the requisite amount of 

surface casing and spudding the well, if conductor pipe is not used. 

4) “Permit Holder” means the person to whom the permit is issued and is responsible for all 

regulatory requirements relative to the production well.

5) “Re-enter” means an operation whereby access to a previously plugged wellbore is reestablished for any purpose including replugging.

6) “Shale Operations” means drilling activities relating to the production of gas and other 

petroleum hydrocarbons directed at an unconventional shale gas formation in a county 

listed in Arkansas General Rule B-43(c) or (d). “Shale Operations” does not include: (i) 

the periodic inspection, maintenance, or repair of completion activities; (ii) preparatory 

activities such as inspection, surveying, or staking; or (iii) drilling additional wells, 

redrilling, or recompletion operations on an existing drilling pad if the operator does not 

expand the existing pad. For purposes of this rule, “Shale Operations” does include well 

site construction operations. 

7) “Spud” means the commencement of drilling a wellbore to a depth to set the requisite 

amount of surface casing.

b) Permit Application Procedures for a Permit to Drill, Deepen or Re-enter a Production Well

1) No person shall drill, deepen, or re-enter a plugged production well, without a permit. A 

copy of the permit shall be posted on site prior to a well being spud or the 

commencement of deepening or re-entering operations. 

2) The Permit Holder is required to provide notice to the surface owner in accordance with 

Ark Code Ann. § 15-72-203.

A) If notice is required in accordance with Ark Code Ann § 15-72-203 (c) and entry 

upon the surface owner’s surface estate is required on or after the effective date 

of this rule, the notice shall contain: 

A) the proposed date Shale Operations will commence; and
GENERAL RULES AND REGULATIONS

34

B) the location of the proposed well and the pad location, including 

the section, township, range, and plat of the pad location, if 

available; and

C) a statement that the Permit Holder has a pending or approved 

drilling permit for the proposed Shale Operations on the surface 

owner's property and that the permit shall be available for 

inspection by the surface owner on request by the surface 

owner; and 

D) the name, address, telephone number, fax number, and 

electronic mailing address of the Permit Holder or the Permit 

Holder's agent.

B) The Notice shall be sent by certified United States mail or delivered personally, 

to the surface owner at the address of the surface owner stated in the public 

records of the county collector of the county in which the surface owner’s 

property is located, at least fourteen (14) days before the Permit Holder proposes 

to begin Shale Operations on the surface owner’s property.

C) After written notice of the Permit Holder's intent to begin Shale Operations is 

given under this subsection, a Permit Holder is not required to give any other 

notice to begin, conduct, or complete Shale Operations on the surface owner’s 

property. 

D) Written notice under this subsection is: 

i) presumed delivered three (3) days after mailing by certified mail; 

ii) effective immediately upon hand delivery; 

E) Written notice is not required:

i) for emergency situations in which the Shale Operations are required to 

protect the public health and safety or the environment; or

ii) if a surface owner has a contractual relationship with a Permit Holder or 

the Permit Holder’s agent that specifies when or how the Permit Holder 

shall give notice regarding the beginning of Shale Operations. 

F) After receipt of a written notice of the Permit Holder's intent to begin Shale 

Operations under this subsection, the surface owner shall not make alterations to 

a proposed drilling location to interfere with the Shale Operations for which the 

surface owner received the notice. 

G) The provisions of subparagraphs b) 2) A) through F) above do not supersede, 

modify, or supplant the notice provisions of General Rule B-42.

3) The Permit Holder shall notify the appropriate Commission Regional Office by 

telephone, or other approved method, a minimum of twenty-four (24) hours prior to a 

well being spud or the commencement of deepening or re-entering operations. 

Commission staff may conduct site inspections as deemed necessary.
GENERAL RULES AND REGULATIONS

35

4) No production well may be drilled at a surface location other than that specified on the 

permit, except that if a Permit Holder has commenced drilling operations and the 

production well is lost due to adverse drilling conditions prior to surface casing being set, 

the Permit Holder may request an amendment of the permit without a fee for the new 

location, provided the production well remains on the same surface owners’ property 

where the production well was originally permitted. The Director may approve the 

commencement of drilling operations prior to the filing of an amended permit. 

Movement of the production well location off the original surface owners’ property, or 

after surface casing has been set, requires the filing of a new permit application, along 

with a new permit fee and plat. Drilling may not commence prior to the issuance of a new 

permit. 

5) Application for a permit to drill, deepen or re-enter a plugged production well shall be 

made on forms prescribed by the Director. The application shall be executed under 

penalties of perjury, accompanied by a non-refundable permit fee of $300.00; and the 

permit shall not be issued until any required financial assurance in accordance with 

General Rule B-2 is submitted and approved.

6) If the application does not contain all of the required information or required documents, 

the Director, or his designee, shall notify the applicant in writing. The notification shall 

specify the additional information or documents necessary for an evaluation of the 

application, and shall advise the applicant that the application will be deemed denied 

unless the information or documents are received within sixty (60) days following the 

date of mailing or personal delivery of the notification.

7) Permits shall automatically expire six (6) months from the date of issuance, unless 

commencement of the drilling, deepening or re-entry of plugged production well 

operations authorized by the permit has occurred, which are to be continued with due 

diligence, but not to exceed 1 year from the date of commencement of the drilling, 

deepening or re-entry of plugged production well operations authorized by the permit, at 

which time the production well shall be plugged or a new permit application, along with a 

new permit fee and plat, must be filed.

8) Permits for the drilling, deepening or re-entry of plugged production well are not 

transferable prior to the completion of drilling operations and the setting of surface 

casing. A new permit application, along with a new permit fee and plat must be filed.

9) The permit application to drill, deepen or re-enter a plugged production well shall include 

at a minimum:

A) The proposed name of the production well.

B) The surveyed location and ground elevation of the production well. A survey is 

not required for a deepened production well, or a re-entered plugged production 

well, if the original production well location was surveyed and shown on the 

original production well permit application. If the application is for a horizontal 

production well, the surface location and proposed bottom hole location of the 

lateral portion of the horizontal production well shall be shown. If applicable, a 

Form 25 must be submitted for horizontal production wells where the costs and 

production are to be shared between drilling units in accordance with General 

Rule B-43 or B-44, or a Form 5 must be submitted for a location exception in 

accordance with General Rule B-40.
GENERAL RULES AND REGULATIONS

36

C) A plat showing:

i) The exact location of the production well proposed to be drilled, 

deepened or re-entered; an outline of the proposed drilling unit and/or 

leasehold, whichever is applicable, unless the production well is a 

wildcat well; and the distance from the production well to the nearest 

section lines, drilling unit lines and or lease lines, whichever is 

applicable; and

ii) If the production well is located within a controlled oil or gas field, the 

plat shall also include the location of all producing wells completed or 

producing within the same common source of supply in the drilling unit 

and/or leasehold.

D) The name of the proposed drilling contractor.

E) The proposed depth of the production well, and the name of the deepest geologic 

formation to be tested.

10) The application for a permit to drill, deepen or re-enter a plugged production well shall be 

signed by a person authorized to sign for such owner as specified on the Organizational 

Report filed in accordance with General Rule B-13. 

11) The applicant must be authorized to do business in the State or Arkansas, and by filing an 

application, the applicant irrevocably waives, to the fullest extent permitted by law, any 

objection to a hearing before the Commission.

12) If the applicant satisfies the requirements of all applicable statutes and this Rule, a permit 

shall be issued, and in no circumstances be unduly withheld, unless:

A) The applicant has falsified or otherwise misstated any material information on or 

relative to the permit application;

B) No further permits or authorities may be issued in accordance with General Rule 

A-5.

c) Production Well Drilling Permit Revocation Procedures

1) The Director may revoke a production well drilling permit if the Permit Holder fails to 

meet permit conditions as specified in the production well drilling permit, the production 

well permit was issued in error, or the Permit Holder falsified or otherwise misstated any 

material information in the application form.

2) The Director shall notify the Permit Holder of the production well drilling permit in 

writing. Following the revocation notice the Permit Holder is required to plug the 

production well. The Permit holder shall have thirty (30) days from the date of the 

production well drilling permit to appeal the Director’s Decision to revoke the production 

well drilling permit in accordance with General Rule A-2, A-3, and other applicable 

hearing procedures. Drilling or production may not commence or continue during the 

appeal process. A revocation of a production well drilling permit for which an appeal has 

not been filed, shall become a final administrative decision of the Commission thirty (30) 

days following the date of the revocation. 
GENERAL RULES AND REGULATIONS

37

(Source: 1991 rule book; amended July 29, 2011; amended January 20, 2014)
GENERAL RULES AND REGULATIONS

38

RULE B-2: PROOF OF FINANCIAL RESPONSIBILITY REQUIRED TO BE 

FURNISHED

a. For purposes of this rule, the person, operator, producer, or owner designated by the Director of 

Production and Conservation or his designee as the party responsible for compliance, and whom 

is the entity required to hold the permit to drill, produce, dispose or inject will be referred to as 

the permit holder.

b. Financial Assurance is required to be submitted with the following applications:

1. An application to drill an oil and/or gas well, Class II disposal well, injection well, brine 

production well, Class V brine disposal well, water supply well or other type of 

exploratory hole(s) or well(s); or

2. An application to transfer ownership or operations of any existing oil and/or gas well, 

Class II disposal well, injection well, brine production well, Class V brine disposal well, 

water supply well or other type of exploratory hole(s) or well(s) to another permit holder.

c. Financial Assurance is required to remain in full force and effect by the designated permit holder: 

1. for one year after the issuance of the permit to drill in accordance with A.C.A. 15-72-214; 

or

2. until the well(s) have been plugged and associated production site(s) restored in 

accordance with Commission rules; or

3. the well(s) have been transferred to a new permit holder in accordance with Commission 

rules; or

4. all outstanding notices of violation or orders of compliance issued against the permit 

holder have been satisfied; or

5. the permit holder has paid annual fee assessments to the Commission in accordance with 

section h. of this rule for two consecutive years, and such permit holder is not in violation 

of the Commission’s regulations or statutes; or 

6. all permit holders of record with the Commission on January 1, 2006 who were assessed 

annual fees in accordance with section (h) of this rule and paid such fees, and who were 

not in violation of any Commission order or rule at the time the fees were paid.

d. Financial Assurance shall be submitted and payable to the Commission in the form of: 

1. A surety bond issued by a surety company authorized to transact business in Arkansas; or

2. An irrevocable letter of credit subject to the following conditions:

A. The letter of credit shall be issued by a bank whose deposits are insured by the 

Federal Deposit Insurance Corporation.

B. The letter of credit shall provide on its face that the Commission, its lawful 

assigns, or the attorneys for the Commission or its assigns, may sue, waive notice 

and process, appear on behalf of, and confess judgment against the issuing bank 

(and any confirming bank) in the event that the letter of credit is dishonored. The 
GENERAL RULES AND REGULATIONS

39

letter of credit shall be deemed to be made in Union County, Arkansas for the 

purpose of enforcement and any actions thereon shall be enforceable in the 

Courts of Arkansas, and shall be construed under Arkansas law.

3. A Certificate of Deposit subject to the following conditions: 

A. The Director of Production and Conservation or his designee shall require that 

certificate of deposit be made payable to or assigned to the Commission both in 

writing and upon the records of the bank issuing the certificate. If assigned, the 

Director of Production and Conservation or his designee shall require the banks 

issuing these certificates to waive the rights of setoff or liens against those 

certificates.

B. The Director of Production and Conservation or his designee shall not accept an 

individual certificate of deposit in an amount in excess of the maximum insurable 

amount as determined by the Federal Deposit Insurance Corporation or the 

Federal Savings and Loan Insurance Corporation.

C. Any interest accruing on a certificate of deposit shall be for the benefit of the 

permit holder except that accrued interest shall first be applied to any prepayment 

penalty when a certificate of deposit is forfeited by the Commission.

D. The Certificate of deposit, if a negotiable instrument, shall be placed in the 

Commission’s possession. If the certificate of deposit is not a negotiable 

instrument, a withdrawal receipt, endorsed by the permit holder, shall be placed 

in the Commission’s possession.

4. Cash submitted in the form of personal or corporate check, money order, or cashiers 

check to be deposited in the Commission’s authorized bank account.

e. Financial Assurance shall be required for:

1. all holders of permits to drill and/or operate gas well(s), and all Class II disposal wells 

injecting fluids associated with dry gas production wells; and

2. all permit holders of commercial Class II disposal wells; and

3. all permit holders of brine production and Class V brine disposal well(s), and

4. all permit holders of other types of wells or exploratory holes or wells, and 

5. all permit holders of liquid hydrocarbons production wells and Class II disposal and 

enhanced oil recovery injection wells operated in conjunction with liquid hydrocarbon 

wells, whom have not been a permit holder of record with the Commission for a 

minimum of two calendar years preceding the date of the application specified in section 

(b) above.

f. When a permit holder is required to submit Financial Assurance, the minimum amount of the 

Financial Assurance shall be:

1. $3,000 per well for an oil and /or gas production well, Class II Enhanced Recovery well; 

brine production well, water supply well, or other type of exploratory hole or well; or
GENERAL RULES AND REGULATIONS

40

2. $25,000 for a Class II Disposal or Class V Brine Disposal wells; or

3. $50,000 for a Class II Commercial Disposal well; or

4. A blanket financial assurance as follows:

A. $25,000 for 1-25 wells; or

B. $50,000 for 26-100 wells; or

C. $100,000 for 101 or more wells.

g. The Director of Production and Conservation or his designee is authorized to approve 

administratively each financial assurance instrument required to be filed with the Commission. 

The Director is further authorized to require additional financial assurance based on but not 

limited to how long a permit holder has operated in the State, environmental consideration of the 

well location, and other factors impacting the cost of plugging the well and restoring the 

associated well site, and the compliance history of the permit holder.

h. Effective January 1, 2006, financial assurance in the form of annual fees shall be paid, by all 

permit holders of liquid hydrocarbon wells and any Class II Disposal or Class II Enhanced 

Recovery wells associated with liquid hydrocarbon wells, as follows:

1. Fees shall be assessed annually for all issued permits and wells of record as of January 1 

of each year.

2. All assessed fees shall be paid in full by March 1 of each year, after which time the 

permit holder’s Authority to Produce and Transport and Authority to Dispose and/or 

Inject will be terminated until all delinquent fees are paid.

3. The permit holder shall remain liable for the payment of such fees until the well or wells 

under permit to the permit holder are plugged and restored; or the well or wells have been 

transferred to a new permit holder pursuant to Commission rules. Liability for payment 

of annual well fees ceases on the date when the well has been plugged and restored, or on 

the effective date stated on the Commission’s Notification of Transfer form.

4. If a permit holder’s fee check is returned due to insufficient funds or because payment 

was stopped, the permit holder is required to repay fees for that year by cashiers check or 

money order.

i. A permit holder may administratively contest the amount of the fee assessment as follows:

1. By submitting a written objection to the assessment amount on or before March 1 of each 

year. The objection must be accompanied by the full assessed amount.

2. The objection must be in writing, signed by the permit holder, or by an individual 

authorized to sign for the permit holder, and must identify the nature of the objection. 

The written objection must include a statement of the facts supporting the objection and 

copies of any relevant documents to support the objection.

3. The Director of Production and Conservation or his designee shall review the application, 

and has the authority to amend the fee assessment and refund any monies due the permit 

holder.
GENERAL RULES AND REGULATIONS

41

j. The amount of annual fees assessed each January 1 to all permit holders of liquid hydrocarbon 

and associated Class II wells shall be as follows:

1. 1–5 Permits or Wells $100/Well

2. 6–15 Permits or Wells $750/Operator

3. 16-50 Permits or Wells $1,250/Operator

4. 51-150 Permits or Wells $2,000/Operator

5. 151-300 Permits or Wells $3,000/Operator

6. 301 or more Permits or Wells $4,000/Operator

k. Permit holder’s failure to comply with the Commission’s order to plug, replug or repair a well, or 

to restore a well site, within thirty (30) days of the issuance of such order constitutes grounds for 

forfeiture of the financial assurance held by the Commission, as follows:

1. The Director shall send written notification by certified mail, return receipt requested, to 

the Permit Holder and the issuer of the financial assurance, if any, informing them of the 

Director’s determination to forfeit the financial assurance for failure to comply with the 

above Commission Order.

2. The Director may allow the financial assurance issuer to undertake necessary plugging, 

replugging, repair or site restoration work if the financial assurance issuer can 

demonstrate an ability to complete such work in accordance with Commission rules. No 

financial assurance liability shall be released until the successful completion of all 

plugging, replugging, repair or site restoration ordered by the Commission.

3. In the event forfeiture of the financial assurance is warranted under the provisions of this 

rule, the Director shall afford the permit holder the right to a hearing, if such hearing is 

requested in writing by the Permit Holder within fifteen (15) days after the forfeiture 

notification is mailed in accordance with subsection (1). If the permit holder does not 

request a hearing within the fifteen (15) day period, the Director shall issue a final 

decision ordering forfeiture and collection of funds. If a hearing is requested by the 

permit holder, the hearing shall be docketed for the next regularly scheduled Commission 

hearing.

4. At the forfeiture hearing, the Director shall present evidence in support of the 

determination for financial assurance forfeiture. The Permit Holder shall present 

evidence contesting the Director’s determination. The Commission may administer oaths 

and affirmations, subpoena witnesses and written or printed materials, compel attendance 

of witnesses or production of those materials, compel discovery, and take evidence, 

necessary to render a decision.

5. Within thirty (30) days after the close of the record for the forfeiture hearing, the 

Commission shall issue findings of fact, conclusions of law and the disposition of the 

case.
GENERAL RULES AND REGULATIONS

42

(Source: 1991 Rule Book; amended (Order 27-95) June 20, 1995; amended (Order 4-99) March 23, 1999; 

amended January 15, 2006; amended October 15, 2006; amended November 16, 2008; amended June 5, 

2009)
GENERAL RULES AND REGULATIONS

43

RULE B-3: SPACING OF WELLS

a. For purposes of this rule and with respect to all established field rules, exploratory drilling units, 

wildcat wells, and in uncontrolled areas, the term well location shall be defined as follows:

(1) For the purpose of well drilling permit issuance, well location is defined as the proposed 

bottom hole location in a vertical or directionally drilled well or the estimated productive 

portion of a lateral in a horizontal well, projected to the surface. For purposes of 

assigning an API number the well site location shall be considered the actual surface 

location of the well.

(2) For the purpose of well setback provisions, except in uncontrolled areas, well location is 

defined as the actual physical location of the completed interval in the well, projected to 

the surface, as follows: 

A. In a vertically drilled well without a directional survey, the well location is the 

surface location. In a vertically drilled well, the well location is the location of 

the perforated interval of the well bore, projected vertically to the surface;

B. In a directionally drilled well, the well location is the location of the midpoint of 

the perforated interval of the producing formation, as calculated from the 

directional survey, projected vertically to the surface;

C. In a horizontally drilled well, the well location is the entire perforated length of 

the lateral section of the well bore, as shown on a directional survey, projected 

vertically to the surface.

b. The spacing of wells in oil and gas fields established by Commission Order, shall be governed by 

field rules for that particular field, adopted after notice and hearing.

c. The spacing of wells in other areas designated as prospective of oil and gas production shall be 

governed by General Rule adopted after notice and hearing.

d. The well location for a well drilled for oil or gas production in an exploratory drilling unit 

established by Commission Order shall not be located closer than 280 feet from the drilling unit 

boundary, except that wells drilled in exploratory drilling units established by General Rule B-43, 

shall be governed by the well setback provisions of General Rule B-43.

e. The following applies to all wildcat well locations not drilled in exploratory drilling units: 

(1) The well location for a wildcat well drilled for oil or gas production purposes, within an 

area not covered by Field Rules or General Rule B-43, shall not be located closer than 

280 feet from a quarter, quarter division line within a governmental section. 

(2) The well location for a wildcat well, drilled for the purposes of oil or gas production, 

within an area subject to Field Rules, but proposed to be drilled to a geologic formation 

for which Field Rules have not been established shall be subject to the set back 

provisions specified in e (1) above.

f. The well location for a well drilled for oil or gas production purposes, and completed in pools in 

field(s) where Field Rules do not exist for these uncontrolled pools, shall not be located closer 

than 280 feet from the nearest mineral lease line.
GENERAL RULES AND REGULATIONS

44

g. The well location for an injection well drilled or completed for enhanced recovery purposes shall 

not be located closer than 280 feet from a unitized boundary line. The well location for a disposal 

well drilled or completed pursuant to General Rule C-7 shall be located no closer that 280 feet 

from the drilling unit boundary, or no closer than 280 feet from the mineral lease line if such well 

is located outside a drilling unit. 

h. The well location for wells drilled for the purposes of water supply for purposes of enhanced oil 

recovery are subject to all the provisions of this rule with the exception of the set back provisions 

for well location. No production of hydrocarbons will be allowed from a water supply well.

i. The Commission may, after notice and hearing, grant exceptions to the rule, provided such 

exceptions will create neither waste nor hazards conducive to waste. No well drilled in violation 

of this rule without special permit obtained in the manner prescribed in said rule and no well 

drilled under such a special permit, which does not conform to the terms of such special permit in 

all respects, shall be permitted to produce either oil or gas and any such well so drilled in 

violation of said rule or in violation of a permit granted under an exception to such rule shall be 

plugged.

(Source: 1991 rule book; amended November 13, 2005; amended September 16, 2006)
GENERAL RULES AND REGULATIONS

45

RULE B-4: REPEALED

Rule Repealed Effective November 11, 2007

RULE B-5: SUBMISSION OF WELL RECORDS AND ISSUANCE OF CERTIFICATE 

OF COMPLIANCE

a. During the drilling, original completion, recompletion, or workover of every well, the owner, 

operator, contractor, driller or other person responsible for the conduct of drilling, original 

completion, recompletion or workover operations, shall keep adequate records of the well being 

drilled, all of which shall be accessible to the Commission and its agents at all reasonable times.

b. For purposes of this rule, original completion shall be defined as initial zone perforation, and 

configuration of wellhead for production, excluding pipeline connections. Any further completion 

work, after the initial configuration of the wellhead, shall be considered a recompletion or 

workover, and subject to the filing requirements of Section (d) or (f) below.

c. For purposes of this rule, recompletion is as defined in General Rule A-4.

d. For purposes of this rule, workover is as defined in General Rule A-4. Upon completion of 

workover operations, only well records specified in Section (f)(1)(3) are required to be submitted.

e. Wells drilled as dry holes, where production casing has not been set, shall be subject to the well 

record submission requirements specified in Section (f) (1), (2) and (3) within 30 days after the 

completion of drilling activities.

f. Upon original completion or recompletion of the well, the operator, contractor, driller, or other 

person responsible for the conduct of the drilling operation shall file with the Commission:

1. Properly filled out Well Completion Report.

2. All electric logs or other geophysical logs of the open well bore, which measure 

resistivity, porosity, temperature, and gamma ray emission and for planned directional 

and horizontal wells, borehole deviation and direction logs including a true vertical depth 

logs, to be submitted in a 1 inch, 2 inch and 5 inch to 100 foot scale format or other scale 

format acceptable to the Commission. All logs shall be submitted, at a minimum, as 

paper copies in standard continuous logging paper format. If electronic copies of the logs 

can be provided from the logging service company, the operator is also required to 

submit copies of the electronic logs in either LAS (ASCII Format) or raster format image 

(200 DPI Black & White in TIF, JPG, BMP) to the Commission on an approved

electronic storage device. If electronic copies of the logs cannot be provided by the 

logging service company, the operator shall file an affidavit with the Commission stating 

electronic logs could not be provided by the logging service company.

3. All logging and well service company tickets applicable to the completion or 

recompletion operation which indicate all logging and completion activities occurring in 

the well.

4. Properly filled out Request for Certificate of Compliance.

5. Application to Abandon other than for a dry hole
GENERAL RULES AND REGULATIONS

46

g. For directional or horizontal wells, or deviated wells not in compliance with General Rule B-30, 

the following shall also be submitted:

(1) A post drilling plat shall be filed with any Completion and Recompletion Report to 

demonstrate the actual location of all vertical, directional and horizontally drilled 

boreholes in the drilling unit. The plat should provide and present the following:

A. The locations of all wells which have been drilled within the drilling unit (except 

for those wells that have been plugged and abandoned), by providing their 

surface and bottom hole location, and either midpoint perforations for deviated or 

directionally drilled wells or the closest point along any lateral section of the 

horizontal portion of the well bore (whichever is applicable) measured to the 

nearest mineral lease, drilling unit or division line within a governmental section, 

whichever applies to the established drilling unit in that field; and 

B. The distance between common sources of supply for which an allowable 

determination is required; and

C. The actual location of the entire perforated length of the lateral section in a 

horizontal well showing the set back distances to offset wells.

(2) A directional survey in table form, accompanied by the following:

A. A two dimensional cross section diagram, viewed perpendicular to the axis of 

maximum lateral borehole displacement, which depicts the measured and true 

vertical depth and the displacement from vertical of the wellbore; and

B. An azimuth plot viewed in plan view providing displacement of the well path 

from the surface location.

h. The above reports shall be filed within 30 days of the original completion, recompletion or 

workover of the well and prior to commencement of production. Upon receipt of the required 

information specified in Section (f) (1), (2) and (4), and Section (o) (8) of General Rule B-43 if 

applicable, a Certificate of Compliance shall be issued granting authority to produce and 

transport oil and/or gas for a period of 30 days at which time the required information specified 

in Section (f) (3) must be on file in order for a final Permit to Produce and Transport to be issued. 

However, if completion activities are not completed within 90 days of the setting of the 

production casing or other production related casing, the required information specified in (f) (1), 

(2) and (3) are required to be submitted, pending submission of final reports at the conclusion of 

completion activities and a request for a Certificate of Compliance.

i. Failure to comply with the provisions of this rule shall be sufficient reason to cause the 

suspension of the issuance of any further drilling permits on a statewide basis to that operator 

until the required information is submitted to the Commission, within 10 days following written 

notice provided to the operator of the failure to provide the required information. 

j. If an operator makes a request, in writing, that the log described in Section (f) (2) be kept 

confidential, the request will be honored for a period not to exceed 90 days after the logging for 

completion or abandonment of the well, provided that the report or the data thereon, when 

pertinent, may be introduced in evidence in any public hearing before the Commission or any 

court, regardless of the request that such record be kept confidential.
GENERAL RULES AND REGULATIONS

47

(Source: 1991 rule book; amended September 16, 2006; amended January 14, 2008; amended May 11, 

2008)
GENERAL RULES AND REGULATIONS

48

RULE B-6: OIL, GAS AND WATER TO BE PROTECTED

Before any well or any producing horizon encountered therein shall be abandoned, the owner or operator 

shall use such means, methods and procedures as may be necessary to prevent water from entering any oil 

or gas-bearing formations, and to protect any underground or surface water that is suitable for domestic or 

irrigation purposes from waste, downward drainage, harmful infiltration and addition of deleterious 

substances.

(Source: 1991 rule book)
GENERAL RULES AND REGULATIONS

49

RULE B-7: WHEN WELLS SHALL BE PLUGGED AND ABANDONED AND 

NOTICE OF INTENTION TO PLUG AND ABANDON WELLS

a) The current permit holder is responsible for plugging wells as defined in this rule. In the case of 

leaking wells, plugging responsibility is in accordance with General Rule B-26 (k) and (l).

b) All new wells drilled for oil, gas, or brine exploration, oil, gas or brine production, water supply 

or injection purposes, except such holes as are described in Rule B-10, regardless of depth are 

required to be either properly cased with production casing or the uncased well or dry hole shall 

be plugged and abandoned in accordance with applicable commission rules, unless an extension 

of time to plug is granted in accordance with subparagraph (c) below.

c) Uncased wells and dry holes

1) Any well in which production casing is not set and cemented shall be plugged in 

accordance with applicable commission rules, prior to the time that the equipment used to 

drill said well is released from the drilling operation. In the case of “staged” drilling 

operations, where multiple drilling rigs are used to drill the well over a period of time, 

production casing shall be set and cemented within 180 days after setting of the surface 

casing or the well shall be plugged, unless an extension of time to plug is granted in 

accordance with subparagraph 2) below.

2) The Director however, may grant an extension of time to plug an uncased well. In 

determining whether to grant an extension and in determining the length of an extension, 

the Director may consider:

A) The permit holders specific plans for further wellbore utilization,

B) The total depth of the well,

C) The depth of surface and any intermediate casing,

D) A description of the current condition of the hole including a description of the 

type of drilling fluids currently in the well,

E) The location of the well.

3) If the Director determines that the uncased well presents a risk of contamination to the 

environment or a risk to public safety the Permit Holder shall be required to repair, case, 

plug or perform other remediation measures to the well, as determined by the Director, 

within twenty four (24) hours after notification by the Director.

d) All cased wells utilized for oil, gas or brine production, water supply or injection purposes, except 

such holes as are described in Rule B-10, shall be plugged and abandoned in accordance with 

applicable commission rules after the well has been idle for more than 24 months, or sooner 

should the Director determine that the cased well presents a risk of contamination to the 

environment or a risk to public safety, unless an application is filed to request temporary 

abandonment status for the well in accordance with subparagraph h) below. Upon such 

determination by the Director or if temporary abandonment status is denied, the Permit Holder 

shall commence plugging the well within 30 days after notification by the Director. Failure to 

commence plugging the well within 30 days after notification by the Director may result in the 

initiation of well abandonment proceedings in accordance with General Rule G-1.
GENERAL RULES AND REGULATIONS

50

e) Prior to the commencement of any work in plugging and abandonment operations, the permit 

holder or other person responsible for the conduct of the drilling operations shall give notice of 

the intent to plug and abandon such well in a form prescribed by the Director as follows:

1) For uncased wells and dry holes, notice shall be provided via verbal or facsimile 

communication to the Commission Regional Office where the well is located, as soon as 

possible, but no less than 8 hours, prior to commencement of plugging operations.

2) For cased wells, written notice on a form prescribed by the Director shall be provided to 

the Commission Regional Office where the well is located, at least 72 hours prior to the 

commencement of plugging operations.

f) Upon receipt and review of such verbal or written notice, the Commission Regional Office shall 

authorize the commencement of plugging operations and may send a duly authorized 

Commission representative to the well location to witness the plugging of such well.

g) Authorization to plug and abandon is not granted unless the appropriate notice, as specified in 

subparagraph (e) above, has been provided to the Oil and Gas Commission by the permit holder 

or person responsible for the plugging of the well. Plugging of the well without providing proper 

notice as required can result in the Permit Holder being required to drill out the well plugs and the 

well replugged under Commission observation.

h) Temporary Abandonment Status

1) An application for temporary abandonment status shall be made on form prescribed by 

the Director and, if approved, shall be valid for a period not to exceed three (3) years 

from the date of the Director’s approval. At the expiration of the three (3) year period the 

Permit Holder shall commence plugging operations within thirty (30) days, or file an 

application to request a hearing before the Commission in accordance with General Rules 

A-2, A-3 and other applicable hearing procedures to request an extension of the three (3) 

year period of the temporary abandonment status. Wells in an approved 

waterflood/enhanced oil recovery unit are exempt from the three (3) year time limit as 

long as the unit remains active.

2) Wells which have not produced for more ten (10) years are not eligible for approval by 

the Director of temporary abandonment status. Temporary abandonment status for these 

wells may only be granted by the Commission after notice and a hearing in accordance 

with General Rule A-2, A-3 and other applicable hearing procedures. 

3) Temporary abandonment status shall be approved by the Director provided:

A) The well is secured with a suitable wellhead with no leakage of any substance at 

the surface, and

B) The well site is maintained in accordance with General Rule B-26 i), and 

C) Proper well identification is maintained in accordance with General Rule B-26 

b), and

D) Useable groundwaters are protected utilizing one of the following methods:

i) Set a drillable, retrievable or other type of mechanical bridge plug 

above the producing interval, in the cemented portion of the 
GENERAL RULES AND REGULATIONS

51

production casing, but at least 150 feet below the base of the lowest 

usable groundwater in the area, and secured at the surface with a 

wellhead and valve in operable condition; or

ii) Set a packer run on tubing above the producing interval, in the 

cemented portion of the production casing, but at least 150 feet 

below the base of the lowest usable groundwater in the area, and 

secured at the surface with suitable wellhead packoff equipment and 

closed to the atmosphere or with a wellhead and valve in operable 

condition;

iii) Run a casing inspection log confirming the mechanical integrity of 

the production casing and secured at the surface with a wellhead and 

valve in operable condition; or

iv) Conduct a fluid level test by wireline or other approved electronic or 

mechanical means, which determines that the static fluid level is at 

lease 150 feet below the base of the lowest usable groundwater in the 

area, and which must be witnessed by commission staff upon no less 

than 48 hours notice prior to conducting the fluid level test. The fluid 

level test shall be conducted annually, on the anniversary date of the 

temporary abandonment during each year of the three (3) year 

temporary abandonment period.

4) Failure to maintain any of the above conditions will result in revocation of the temporary 

abandonment status and require the well to be plugged in thirty (30) days, unless an 

extension of time to plug is granted after notice and hearing.

5) Wells returning to active status from temporary abandonment status shall file for 

authorization to commence production operations on a form prescribed by the Director.

(Source: 1991 rule book; amended December 16, 2007; amended February 19, 2009)
GENERAL RULES AND REGULATIONS

52

RULE B-8: PLUGGING METHODS AND PROCEDURES

The methods and procedures for plugging a well shall be as follows:

A. The bottom of the hole shall be filled to the top of each producing stratum and a cement plug of 

not less than one hundred (100) feet in length shall be placed inside the casing immediately above 

each producing stratum; or a bridge plug, regular or wireline type, may be placed at the top of 

each producing stratum. In the event bridge plugging is to be used for permanent abandonment, 

the bridge plug must be covered with a minimum of ten (10) feet of cement; the casing must be 

free from openings, except perforations for the injection or producing formation and the casing 

well bore annulus must be filled with cement to fifty (50) feet above the top of the formation.

B. A cement plug not less than one hundred (100) feet in length shall be placed at approximately 

fifty (50) feet below all fresh water-bearing stratum when the surface casing is not cemented 

below the base of the fresh water-bearing stratum. In the event the surface casing has been 

cemented below the base of the fresh water-bearing stratum, a one hundred (100) foot cement 

plug shall be placed inside the base of the surface casing.

C. A plug shall be placed at the surface of the ground in each hole plugged in such manner as not to 

interfere with soil cultivation.

D. The interval between plugs shall be filled with an approved heavy mud-laden fluid.

E. An uncased rotary drilling hole shall have a cement plug of not less that one hundred (100) feet 

placed immediately above (1) the Smackover limestone zone and (2) any known productive zone 

in the area, and the hole shall be filled with approved heavy mud up to the base of the surface 

casing and a plug of not less than one hundred (100) feet of cement placed inside the base of the 

surface casing, provided the casing is cemented through the base of the fresh water-bearing 

stratum. A cement plug of not less than one hundred (100) feet in length shall be placed at a 

point fifty (50) feet below the base of the fresh water-bearing stratum in the event the surface 

casing is not cemented through the base of the fresh water-bearing stratum. The hole shall be 

capped similar to other abandoned holes.

F. Any other method approved by the Commission may be used.

(Source: 1991 rule book)
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53

RULE B-9: DRY GAS WELL PLUGGING METHODS AND PROCEDURES

a) Definitions:

1) "Cased Well" means a well in which production casing has been set and cemented.

2) "Cement" means a class A or H neat cement with a minimum weight of 14.5 pounds per 

gallon, unless the cement contains additives which improve the ability of the cement to 

provide necessary protection and which maintains a minimum compressive strength of 

500 PSI after 72 hours.

3) "Circulation Method" means placement of cement used in plugging a well by circulating 

cement by positive pressure displacement through tubing set at a specified depth in the 

well.

4) "Dump Bailer Method" means placement of cement used in plugging a well by using a 

dump bailer on a wire line.

5) "General Oilfield Waste" means oily rags, chemical containers including any unused 

chemicals, oil filters and gaskets, used motor oil, lubricating oils, hydraulic fluids, diesel 

fuels, paint and solvent wastes and other similar wastes generated during drilling, 

completion, production, workover and plugging activities and which are not exempt from 

the provisions of Subtitle C of the Federal Resource Conservation Recovery Act of 1976.

6) "Mud" means only a fresh-water based drilling mud with a minimum weight of 9 pounds 

per gallon with a minimum viscosity of 45 seconds using API Full Funnel Method. Mud 

may contain water (fresh or brine), Bentonite, Attapulgite or other additives if they do not 

reduce the weight or viscosity below the required minimum.

7) "Plugging Fluid Waste" means plugging fluids, including cement, that are generated from 

the well during plugging activities.

8) "Uncased Well" means a well in which production casing has not been set or is set, but 

not cemented.

b) Uncased Wells

1) Uncased wells shall be plugged when required by General Rule B-7. 

2) Notice of the plugging of uncased wells shall be given to the Commission Regional 

Office where the well is located, in accordance with General Rule B-7. Following initial 

notice to the Commission Regional Office, additional requirements concerning the well 

plugging operation, may be given to the Permit Holder or the Permit Holder’s authorized 

representative. 

3) Uncased wells where intermediate casing has been set, shall be subject to all the required 

plugging time frames for uncased wells and the applicable plugging requirements for 

cased wells in (c) below with respect to the protection of freshwater and oil and gas 

zones.

4) Plugging Requirements
GENERAL RULES AND REGULATIONS

54

A) The uncased well bore shall be filled with mud from the total depth of the well to 

the base of the surface casing prior to commencing plugging operations.

B) Any zones which have been productive of oil and or gas occurring in wells 

within 1⁄2 mile of the uncased well, shall have a one hundred (100) foot cement 

plug placed above each such correlated interval in the uncased well.

C) A zone which contains any amount of hydrogen sulfide gas, or any other zone 

within the well which does not contain hydrogen sulfide gas, but hydrogen 

sulfide gas is present within the same zone within any well within one-half 

(1/2) mile, shall be covered, at a minimum, with a cement plug from one hundred 

(100) feet below to one hundred (100) feet above the zone or with a greater 

amount of cement sufficient to shut-off and control the flow of hydrogen sulfide 

gas.

D) If surface casing has been set to a depth of at least five hundred (500) feet in the 

well, a one hundred (100) foot cement plug shall be placed, utilizing the 

circulation method, from a depth of fifty (50) feet below the base of the surface 

casing, or from the depth of any deeper freshwater well within 1⁄2 mile of the dry 

hole, and extending fifty (50) feet into the cemented surface casing.

E) If surface casing has not been set to a minimum depth of five hundred (500) feet 

in the well, a cement plug shall be placed, from a depth of at least five hundred

(500) feet or from the depth of any deeper freshwater well within one-half (1⁄2)

mile of the dry hole, extending to fifty (50) feet into the cemented surface casing. 

F) Any zones not covered by the surface casing plug specified above, which 

produced water during the drilling or subsequent plugging operations, shall be 

covered at a minimum, with a cement plug from fifty (50) feet below to fifty (50)

feet above the zone or a greater amount of cement sufficient to shut-off the flow 

of water.

G) A cement plug shall be placed from a minimum depth of fifty (50) feet to a depth 

of three (3) feet below the surface of the ground and the casing cut off three (3) 

feet below the ground surface, or deeper if surface use conditions indicate, and a 

plate welded onto the top of the casing and the remaining wellbore filled with 

soil and leveled in such manner as not to interfere with soil cultivation or surface 

use.

5) In the case of lost tools or stuck drill pipe, every reasonable attempt should be made to 

recover the tools or drill pipe, at least to a depth of the required surface casing plug, and 

the required surface casing plugs placed as required above. In the event the lost tools or 

stuck drill pipe cannot be recovered from a depth below the required depth of the surface 

casing plug, the Director may vary the plugging requirements of this subparagraph and 

specify alternative plugging requirements. In determining whether to approve and in 

selecting an alternative plugging requirement, the Director shall consider the potential for 

damage to fresh water, the depth of the lost tools or equipment in relation to the depth of 

fresh water zones, well construction characteristics, and the potential for upward 

migration of wellbore fluids into the fresh groundwater.

c) Cased Wells

1) Cased wells shall be plugged when required by General Rule B-7.
GENERAL RULES AND REGULATIONS

55

2) Notice of the plugging of cased wells shall be given to the Commission Regional Office 

where the well is located, in accordance with General Rule B-7.

3) Plugging Requirements 

A) The wellbore shall be filled with mud from total depth of the well to the base of 

the surface casing prior to commencing plugging operations.

B) Cast iron bridge plugs may be set above the lowermost perforated interval or 

between perforated intervals prior to filling the wellbore with mud, in which case 

the wellbore need only be filled with mud from the top of the uppermost cast iron 

bridge plug to the base of the surface casing prior to commencing plugging 

operations.

C) If using the circulation method, a cement plug of not less than one hundred (100) 

feet in length, shall be placed from fifty (50) feet below, or total depth if well 

bore did not extend to a point fifty (50) feet below, and extend across the 

perforated interval, to a point fifty (50) feet above each perforated interval. 

D) If using the dump bailer method, a cast iron bridge plug, shall be placed inside 

the cemented portion of the production casing, immediately above each 

perforated interval, with each bridge plug covered with a minimum of ten (10) 

feet of cement. In the alternative a cast iron bridge plug may be placed over the 

lower most perforated interval and the wellbore casing filled with cement to a 

point fifty (50) feet above the top of the uppermost perforated interval, provided 

the production casing/wellbore annulus is filled with cement to a point fifty (50)

feet above the uppermost perforated interval.

E) If cement is not present on the outside of the production casing at the location of 

each required cement plug, specified in F), G) and H) below, cement shall be 

placed on the outside of the production casing in the production casing/wellbore 

annulus from a point fifty (50) feet below, or total depth if the well bore did not 

extend to a point fifty (50) feet below, and extending across the required interval 

to be plugged, to a point fifty (50) feet above each required interval to be 

plugged. However, the Director may approve alternative, but equally protective, 

placement of cement plugs, openhole devices or plugging materials when 

necessary due to well construction limitations. 

F) Any zones not covered by the surface casing, which produce water during the 

plugging operation or are known to be significant water producing formations or 

which are known to be over-pressured, shall be covered at a minimum, with a 

cement plug from fifty (50) feet below to fifty (50) feet above the zone or a 

greater amount of cement sufficient to shut-off the flow of water. The Director 

may approve alternative, but equally protective, plugging materials or other 

open-hole devices sufficient to shut-off the flow of water. 

G) If surface casing has been set to a minimum depth of five hundred (500) feet in 

the well, a one hundred (100) foot surface casing cement plug shall be placed, on 

the outside and inside of the production casing if production casing is not 

removed, from a depth of fifty (50) feet below the base of the surface casing, or 

from the depth of any deeper freshwater well within 1⁄2 mile of the wellbore, and 

extend fifty (50) feet into the cemented surface casing. 
GENERAL RULES AND REGULATIONS

56

H) If surface casing has not been set to a minimum depth of five hundred (500) feet 

in the well, a cement plug shall be placed, on the outside and inside of the 

production casing, if production casing is not removed, from a depth of at least 

five hundred (500) feet or from the depth of any deeper freshwater well within 1⁄2 

mile of the well bore and extend fifty (50) feet into the cemented surface casing 

present in the wellbore. However, if it can be demonstrated that no freshwater 

bearing zones are present below the existing surface casing set in the well, the 

Director may approve an alternative surface casing plug extending from fifty (50) 

feet below the existing surface casing and extending fifty (50) feet into the 

cemented surface casing present in the wellbore.

I) The casing shall be cut off three (3) feet below the ground surface, or deeper if 

surface use conditions indicate, and a plate welded onto the top of the casing and 

the remaining wellbore filled with soil and leveled in such manner as not to 

interfere with soil cultivation or surface use. A cement plug, not less than three

(3) feet, shall be also be placed below the plate that is welded onto the top of the 

casing.

4) Foreign Material Prohibited

A) Except for an unavoidable loss of drilling and logging tools, production 

equipment or the presence of damaged casing obstructing the wellbore, placing 

or lodging any material or substance, in an unplugged well to either fill or bridge 

the hole for the purpose of avoiding proper plugging procedures is prohibited.

B) Foreign materials which have been placed in the hole shall be removed before 

plugging operations are commenced.

5) Plugging A Bridged Well

A) When a well becomes obstructed because of the loss of drilling or logging tools 

or producing equipment, which would be impractical to remove, the Director 

may vary the plugging requirements of this subparagraph and specify alternative 

plugging requirements. 

B) In determining whether to approve and in selecting alternative plugging 

requirements, the Director shall consider the time and cost of removing lost tools 

or equipment, the potential for damage to fresh water, the depth of the lost tools 

or equipment in relation to the depth of fresh water zones, well construction 

characteristics, and the potential for upward migration of wellbore fluids into the 

fresh groundwater.

d) Horizontal Well Plugging Procedures

1) For an uncased well, the plugging procedures shall be in accordance with sub-paragraph 

(b) above with the exception that (i) the production interval plug shall be placed at the 

beginning of the well curve “kick-off point” and the required cement placed or extend 

above that point, and (ii) oil-based drilling mud may be used to fill the horizontal lateral 

of the wellbore up to the “kick-off point” provided the “kick-off point” is below any 

known fresh groundwater.
GENERAL RULES AND REGULATIONS

57

2) For an cased well, the plugging procedures shall be in accordance with sub-paragraph (c) 

above with the exception that (i) the production interval plug shall be placed at the 

beginning of the well curve “kick-off point” and the required cement placed or extend 

above that point, and (ii) oil-based drilling mud may be used to fill the horizontal lateral 

of the wellbore up to the “kick-off point” provided the “kick-off point” is below any 

known fresh groundwater.

3) If a vertical “pilot hole” is drilled below the well curve “kick-off point”, and the pilot 

hole encountered another producing interval in the vertical pilot hole below the “kick–off 

point”, a one hundred (100) foot cement plug shall be placed above each such correlated 

interval encountered in the vertical pilot hole, prior to drilling the horizontal portion of 

the well, unless approval has been granted to produce the other interval encountered in 

the pilot hole in accordance with applicable general rules or order of the Commission. 

Additionally, the Director may approve alternative forms of zonal isolation based on the 

productive potential of the isolated zone. 

4) Well-site clean-up shall be in accordance with sub-paragraph (e) below.

e) Well Site Clean-Up

1) When plugging a well, the permit holder shall provide at least one (1) pit as described in 

subparagraph e) 2) below, or leak free, above ground, portable container into which 

plugging fluid wastes shall be deposited.

2) Plugging pits, shall be constructed with sufficient capacity to contain all plugging fluid 

wastes within the pits, and maintained in a manner that reasonably prevents overflow 

during plugging operations. Plugging pits shall be used only for the temporary storage of 

plugging fluid wastes, and shall not be used for the disposal of general oilfield wastes.

3) All general oilfield wastes generated during plugging activities shall be temporarily 

stored in on-site containers, and shall be removed from the site at the conclusion of 

plugging activity. General oilfield wastes shall not be disposed of through on-site burial 

or in plugging pits.

4) All plugging pits shall be filled and graded within thirty (30) days after conclusion of 

plugging activities, unless an extension has been granted by the Director. All plugging 

pits shall be closed allowing no subsidence or leakage of fluids, and where applicable, 

with sufficient compaction to support agriculture or forestry machinery.

5) All production equipment, concrete bases, machinery, and equipment debris shall be 

removed from the site.

6) Any drilling rat holes shall be filled with mud to a depth of ten (10) feet below the 

surface, at which point a cement plug shall be placed from ten (10) feet to three (3) feet 

below ground level and leveled to the surface with soil.

(7) Any other excavations shall be filled and the overall well site graded or contoured to 

prevent erosion.

f) Alternative plugging methods maybe authorized by the Director, provided the same or equal level 

of protection for the freshwater and oil and gas zones can be maintained.

(Original rule Repealed Effective October 15, 2006; new rule March 25, 2010; amended October 1, 2015)
GENERAL RULES AND REGULATIONS

58

RULE B-10: SEISMIC CORE AND OTHER EXPLORATORY HOLES TO BE 

PLUGGED; METHODS, RECORDS

Before any hole is abandoned which is drilled for seismic, core or other exploratory purposes below the 

fresh water formation, it shall be the duty of the owner or driller of any such hole to plug the same in such 

manner as to properly protect all water-bearing formations.

A. Core Holes:

1. Core holes shall comply with the Minimum Surface Casing and Plugging Requirements.

2. No core hole shall be completed as a producing well.

3. A Plugging Record shall be filed no later than thirty (30) days from the date drilling 

operations commence.

4. A copy of all electric logs shall be filed with the Commission no later than one (1) year 

from the date drilling operations commence. In the event an electric log was not run, the 

operator shall file a copy of a driller’s log.

5. All information required to be filed shall be kept confidential for a period of one (1) year 

from the date drilling operations commence.

(Source: 1991 rule book)
GENERAL RULES AND REGULATIONS

59

RULE B-11: DOMESTIC NATURAL GAS WELLS AND CONVERSION OF

PERMITTED OIL AND NATURAL GAS WELLS FOR USE AS DOMESTIC NATURAL 

GAS OR FRESH WATER SUPPLY WELLS

a) Domestic Natural Gas Wells 

1) Any well drilled by persons for use as a domestic, livestock or agriculture natural gas 

source, is not under the jurisdiction of the Commission and is not subject to permitting or 

regulation by the Commission, provided such natural gas is not sold or gathered for sale 

to others. Such wells may be subject to other applicable State laws. 

2) If the gas produced from a well operating as a domestic use well is gathered for resale to 

others, that well is under the jurisdiction of the Commission and shall be subject to all 

applicable regulatory requirements of the Commission and any other applicable state 

laws regarding the production, gathering and distribution of natural gas for use by 

consumers. 

b) Domestic Use Transfer(s) after November 16, 2008. 

1) A controlled natural gas production well, required to be permitted by the Commission, 

may be transferred to a surface owner for use as a domestic natural gas supply well if the 

well has not produced commercial quantities of natural gas during the previous twenty 

four (24) calendar months provided: 

A) The operator files, on a form prescribed by the Director, a request to transfer the 

well to the surface owner, which shall include written documentation from the 

surface owner accepting transfer of the well for use as a domestic natural gas 

supply well; and 

B) A statement by the surface owner and the operator that the natural gas from the 

well will be used on the property where the well is located and that any natural 

gas production from the well will not be sold; and 

C) Written documentation from all owner(s), as defined in Ark. Code Ann. § 15-72-

102 (9), and all mineral owners in the drilling unit upon which the well is 

located, stating that they do not object to the transfer of the well to the surface 

owner. 

2) An oil or natural gas production well may be transferred to a surface owner for use as a 

domestic or livestock freshwater supply well provided: 

A) The operator files, on a form prescribed by the Director, a request to transfer the 

well to a surface owner prior to commencing plugging operations, which shall 

include written documentation from the surface owner accepting transfer of the 

well for use as a freshwater supply well; and 

B) The well is plugged in accordance with current Commission plugging 

requirements with respect to all oil and natural gas producing zones and a cement 

plug is placed, on the inside and outside of the production casing if left in the 

well, from 100 feet below the base of the fresh water extending up to the base of 

the fresh water in the well; and 

C) All related surface production equipment is removed from the well site. 
GENERAL RULES AND REGULATIONS

60

3) Following completion of the above domestic use well transfer requirements, all 

regulatory oversight of the well by the Commission shall terminate and the well shall 

become the sole responsibility of the surface owner. The well shall be subject to any 

applicable state laws regarding private fresh water wells or domestic natural gas supply 

wells administered by state and or federal agencies other than the Arkansas Oil and Gas 

Commission. 

c) Uncontrolled natural gas production wells may not be transferred for domestic use, unless 

otherwise approved the Commission after notice and a hearing. Notice shall be given to all 

owner(s), as defined in Ark. Code Ann. § 15-72-102 (9), and all mineral owners in the leasehold 

upon which the well is located. Any person requesting a transfer of an uncontrolled natural gas 

production well shall file an application in accordance with General Rules A-2, A-3, and other 

applicable hearing procedures.

d) Domestic Use Transfer(s) prior to November 16, 2008. 

Any natural gas production well transferred to a surface owner for use as a domestic natural gas 

supply well prior to November 16, 2008, shall no longer be subject to the regulatory oversight by 

the Commission as long the natural gas from the well is used only on the property where the well 

is located and that any natural gas production from the well is not sold. 

(Source: 1991 rule book; amended November 16, 2008; amended May 18, 2012)
GENERAL RULES AND REGULATIONS

61

RULE B-12: CASING PULLER’S PERMITS AND BONDS

Rule Repealed Effective November 11, 2007

RULE B-13: ORGANIZATION REPORTS

a) Every person or entity engaged in any operation or activity regulated by the Commission, shall 

file with the Commission an organization report on a form prescribed by the Director, prior to 

engaging in the operation or activity. At a minimum, the form shall include: 

1) Name of person or entity and type of operation(s) being conducted; 

2) An official mailing address to which all correspondence from the Commission is to be 

sent. If the official mailing address is to be sent to a registered agent for the person or 

entity, then the name of the registered agent must also be included;

3) A list of official telephone number(s), facsimile number(s), and e-mail address(es) for 

which contact by the Commission may be made;

4) The type of entity, and a list of all persons authorized to submit required forms, reports, 

and other documents for the entity;

5) A statement that the person or entity is authorized to conduct business within the State; 

and

6) Any other information deemed necessary by the Director.

b) Every person or entity shall file an updated organization report with the Commission on or before 

July 1st of every calendar year.

c) After any change occurs as to facts stated in the report filed, a supplementary report shall be filed 

with the Commission within thirty (30) days of any change.

(Source: 1991 rule book; amended January 22, 2009)
GENERAL RULES AND REGULATIONS

62

RULE B-14: SURFACE EQUIPMENT

Meter settings of adequate size to measure the gas efficiently for the purpose of obtaining gas-oil ratios 

shall be installed on the gas vent line of every separator, or a connection placed on end of flare line to 

permit measuring gas by means of orifice well tester. Wellhead equipment shall be installed and 

maintained in first-class condition so that static bottom hole pressures may be obtained at any time by 

duly authorized agents of the Commission. Valves shall be installed so that pressures can be readily 

obtained on both casing and tubing.

(Source: 1991 rule book)
GENERAL RULES AND REGULATIONS

63

RULE B-15: CASING REQUIREMENTS

a. In all established fields, casing requirements shall be governed by the specific field rules for that 

field, and are not superceeded by this rule.

b. All fresh water sands shall be fully protected by the setting and cementing of surface casing to 

prevent the fresh water sands from becoming contaminated with oil, gas, or salt water. Surface 

casing shall be set and cement circulated to surface utilizing the pump and plug method. Cement 

shall be allowed to set a minimum of twelve (12) hours.

1) The minimum surface casing requirements for wildcat wells or wells not covered by field 

rules, in the counties of Ashley, Bradley, Calhoun, Columbia, Hempstead, Lafayette, 

Miller, Nevada, Ouachita, and Union, are as follows:

 TVD of well Amount of Surface Casing

0′ - 3,000′ 100′

3,001′- 4,000′ 160′

4,001′- 5,000′ 300′

5,001′- 6,500′ 500′

6,501′- 7,500′ 750′

7,501′- 8,500′ 1,000′

8,501′-10,500′ 1,250′

10,501′ & below 1,500′

2) The minimum surface casing requirements for wildcat wells or wells not covered by field 

rules, in the counties of Crawford, Franklin, Johnson, Logan, Madison, Pope, Scott, 

Sebastian, Washington, and Yell, are as follows:

 TVD of Well Amount of Surface Casing

0′- 1,500′ 100′

1,501′- 3,000′ 200′

3,001′- 6,500′ 500′

6,501′-10,000′ 800′

10,001′ & below 1,000′

3. The minimum surface casing requirements for wildcat wells or wells not covered by field 

rules, in the counties of Cleburne, Conway, Faulkner, Independence, Jackson, Searcy, 

Stone, Van Buren, and White, shall be to a depth of 500 feet or the top of the Paleozoic 

age rock sequence, whichever is greater. 

4. The minimum surface casing requirements for wildcat wells or wells not covered by field 

rules, in the counties of Arkansas, Lonoke, Monroe, Prairie, and Woodruff, shall be to a 

depth of 1,250 feet.

5. The minimum surface casing requirements for wildcat wells or wells not covered by field 

rules, in the counties of Crittenden, Cross, Lee, Phillips and St. Francis, shall be to a 

depth of 2,000 feet.

c. A producing string of casing shall be set at least to the top of the producing formation and shall 

be cemented so that the calculated fill, after allowing for twenty-five percent excess, will be at 

least two hundred fifty feet above the top of any productive interval. Cementing shall be done by 
GENERAL RULES AND REGULATIONS

64

the pump and plug method. Cement shall be allowed to set a minimum of twenty-four (24) hours 

before drilling the plug. 

d. The Director may grant exceptions to the above requirements if conditions exist that require more 

than these requirements for the purpose of safety or for the protection of fresh water sands and oil 

or gas bearing sands or may establish minimum surface casing requirements in future producing 

areas not covered by this rule.* 

*Director’s Notice to Fayetteville Shale Operators – June 1, 2015 (Supersedes previous

version of June 1, 2011). Unless an exception is granted, all operators of all wells spud

after May 22, 2015, or permitted on or after June 1, 2015 in Cleburne, Conway, Faulkner, 

Independence, Jackson, Searcy, Stone, Van Buren, and White Counties, and Fayetteville 

Shale wells only in Pope County, shall comply with casing and cementing requirements 

based on the zone in which the well is located (please contact the El Dorado Regional 

office for the zone map). The well casing and cementing requirements are as follows: 

1. Surface casing shall be set to a depth equal to 500 feet below the lowest ground 

surface elevation occurring within 1 mile of the proposed well, with a minimum of 

1000 feet of surface casing required to be set and cemented to surface.

2. Production casing shall be set to at least the top of the producing formation, and 

cemented, such that the calculated top of cement (TOC), plus a twenty-five percent 

excess, shall be at a minimum of:

a. 100 feet above the surface casing shoe in Zone 1;

b. 500 feet below the surface casing shoe in Zone 2; and

c. 1500 feet below the surface casing shoe in Zone 3.

3. If a gas bearing zone is encountered above the Fayetteville Shale in the subject well 

or in another well within a one (1) mile radius of the subject well, and the above 

cementing requirements do not result in at least 250 feet of cement placed above the 

shallow gas bearing zone, the TOC shall be increased to provide a minimum of 250 

feet of cement above the shallower gas bearing zone. However, the additional 

cementing requirements in the subject well shall not result in the production casing 

TOC to extend more than 100 feet above the surface casing shoe inside the surface 

casing. 

(Source: 1991 rule book; amended September 16, 2006)
GENERAL RULES AND REGULATIONS

65

RULE B-16: BLOW-OUT PREVENTION

All proper and necessary precautions shall be taken for keeping the well under control during drilling 

operations, including but not limited to the use of blow-out preventers and high pressure fittings attached 

to properly anchored and cemented casing strings or maintain mud-laden fluid of sufficient weight to 

provide proper well control. Blow-out preventers shall be tested at regular intervals to insure proper 

operation. 

(Source: 1991 rule book; amended October 15, 2006)
GENERAL RULES AND REGULATIONS

66

RULE B-17: WELL DRILLING PITS AND COMPLETION PITS REQUIREMENTS

a) Applicability

This rule applies to all pits constructed during the drilling, completion and testing of a brine, oil, 

gas, or oil and gas production well, brine injection or disposal well, Class II Disposal Well, and 

Class II Commercial Disposal Well. Pits as used in context of this rule refer to the type pits as 

defined in subparagraph c) below. 

b) Joint Enforcement

After the effective date of this rule, any Operator who constructs or operates a pit covered by this 

Rule, shall be subject to the specific enforcement provisions under the respective authorities of 

the Arkansas Oil and Gas Commission (AOGC) or the Arkansas Department of Environmental 

Quality (ADEQ). The regulation of the activities covered under this rule by AOGC and ADEQ 

shall be in accordance with a Memorandum of Agreement (MOA) between AOGC and ADEQ.

c) Definitions: 

1) AOGC: Arkansas Oil and Gas Commission.

2) ADEQ: Arkansas Department of Environmental Quality.

3) APC&EC: Arkansas Pollution Control and Ecology Commission.

4) Closed Loop System: A system that uses a combination of solids control equipment 

incorporated in a series of steel tanks that eliminates the use of a Pit.

5) Completion Flow-Back Fluid: Any of a number of liquid and gaseous fluids or mixtures 

of fluids, chemicals and or solids that flow from a well and consisting of Drilling Fluid, 

silt, debris, water, brine, oil scum, paraffin, or other materials which have been removed 

from the well bore during the initial completion of a well, but does not include Frac 

Flow-Back Fluid.

6) Cuttings: Fragments of rock which are a result of the cutting action of the drill bit on 

rock formations encountered in the well, which are transported to the surface by the 

Drilling Fluid.

7) Discharge: The release, overflow, leakage or seepage of any fluids covered by this Rule.

8) Drilling Fluid: Any of a number of liquid and gaseous fluids and mixtures of fluids and 

solids (as solid suspensions, mixtures and emulsions of liquids, gases, Cuttings and other 

solids) utilized during brine, oil, or gas drilling operations. Drilling Fluid is generally 

synonymous with drilling mud, which typically contains bentonitic clays, chemical 

additives, foaming agents, lubricants, emulsifiers and weighting materials, and which 

encompasses most muds used in drilling operations, especially muds that contain 

significant amounts of suspended solids, emulsified water or oil. Mud includes all types 

of Water-Based, Oil-Based and synthetic-based Drilling Fluids.

9) Director of the ADEQ: The Director of the Arkansas Department of Environmental 

Quality or his or her designated representative.
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67

10) Director of AOGC: The Director of the Arkansas Oil and Gas Commission or his or her 

designated representative.

11) Ecologically Sensitive Waterbody (ESW): Waters that have been given the designated 

use of Ecologically Sensitive Waterbody by the Arkansas Pollution Control and Ecology 

Commission. This beneficial use identifies segments known to provide habitat within the 

existing range of threatened, endangered or endemic species of aquatic or semi-aquatic 

life forms.

12) Encountered Water: Water encountered during brine, oil, or gas drilling operations, 

which is of sufficient quantity to require disposal, and which is not Produced Water. 

13) Exploration and Production Waste (E&P Waste): Wastes associated with the exploration, 

development and production of brine, oil, or gas and which are not regulated by the 

provisions of, and, therefore, exempt from the Federal Resource Conservation and 

Recovery Act, and may include, but are not limited to the following: salt water (produced 

brine or produced water); Oil-Based Drilling Fluids; Water-Based Drilling Fluids, 

Completion Flow-Back Fluid, Frac Flow-Back Fluid, Workover Flow-Back Fluid, 

Produced Water; rainwater from firewalls and Pits at drilling and production facilities; 

and other wastes not described above.

14) Extraordinary Resource Waters (ERW): Waters that have been given the designated use 

of Extraordinary Resource Waterbody by the Arkansas Pollution Control and Ecology 

Commission. This beneficial use is a combination of the chemical, physical and 

biological characteristics of a water body and its watershed which is characterized by 

scenic beauty, aesthetics, scientific values, broad scope recreation potential and 

intangible social values.

15) Frac Flow-Back Fluid: Fluids that consist of fresh water and solids such as sand or other 

proppant (resin or ceramic grains) or other additives that flow from a well following 

hydraulic fracturing of a well. 

16) Natural and Scenic Waterways (NSW): Waters that have been given the designated use 

of Natural and Scenic Waterways by the Arkansas Pollution Control and Ecology 

Commission. This beneficial use identifies segments which have been legislatively 

adopted into a state or federal system.

17) Nonhazardous Oilfield Wastes (NOW): Fluids to be used or reused in connection with 

activities associated with the exploration, development, and production of brine, oil, or 

gas and includes, but is not limited to, Drilling Fluids, completion fluids, surfactants, and 

chemicals used to detoxify brine, oil, or gas wastes. 

18) Oil-Based Drilling Fluid: Drilling Fluid containing diesel or crude oil rather than fresh 

water as the main liquid phase of the drilling mud.

19) Operator: Any person who has the primary management and ultimate decision-making 

responsibility over the operation of a facility or activity. The Operator is responsible for 

ensuring compliance with all applicable regulations and conditions. 

20) Person: Natural person, corporation, organization, municipality, government or 

governmental subdivision or agency, public or private corporation, business trust, estate, 

trust, individual, partnership, association, or any other legal entity. 
GENERAL RULES AND REGULATIONS

68

21) Pit: shall include:

A) Circulation Pit: A pit used during drilling where Drilling Fluids are circulated 

during drilling operations. The Circulation Pit may be part of the Mud Pit. 

Circulation Pits may also refer to a series of open, above-ground tanks, usually 

made of steel.

B) Completion Pit: A pit used for storage of Completion Flow-Back Fluid and 

Drilling Fluids or other materials which have been cleaned out of the well bore 

during the initial completion of a well. Circulation or Mud Pits may be used as a 

Completion Pits when drilling operations conclude.

C) Emergency Pit: A pit used for containing fluids at an operating well during an 

actual emergency and for a temporary period of time. Use of the Emergency Pit 

is necessitated due to unplanned operational issues, which may include but is not 

limited to, a temporary shutdown of a disposal well or fluid injection well or 

associated equipment, temporary overflow of saltwater storage tanks on a 

producing lease, gas flaring, cement circulation, or a producing well loading up 

with formation fluids. 

D) Mud Pit: A pit or series of pits used during drilling where fluids are mixed and

circulated during drilling operations. Mud Pits may also refer to a series of open, 

above-ground tanks, usually made of steel.

E) Reserve Pit: A pit not part of the active circulation system, used to store Drilling 

Fluids or to contain fluids generated during drilling operations. Such fluids 

would include, but not be limited to, Cuttings, Drilling Fluids, and Encountered 

Water.

F) Test Pit: A pit constructed for use during a well test.

G) Workover Pit: A pit used for storage of Completion Flow-Back Fluid, Workover 

Flow-Back Fluid and other materials which have been cleaned out of the well 

bore during any subsequent completion or re-completion. 

22) Pollution: Such contamination or other alteration of the physical, chemical, or biological 

properties of any waters of the state, or such discharge of any liquid, gaseous, or solid 

substance in any waters of the state as will, or is likely to, render the waters harmful, 

detrimental, or injurious to public health, safety, or welfare; to domestic, commercial, 

industrial, agricultural, recreational, or other legitimate beneficial uses; or to livestock, 

wild animals, birds, fish, or other aquatic life.

23) Produced Water: Water produced from any productive or potentially productive brine, 

oil, or gas producing interval in the well, which is not Completion Flow-Back Fluid, Frac 

Flow-Back Fluid, Workover Flow-Back Fluid, or Encountered Water.

24) Stormwater: Rainwater runoff, snow melt runoff, and surface runoff and drainage.

25) Water-Based Drilling Fluid: Drilling Fluid containing fresh waters rather than diesel or 

crude oil as the liquid component of the drilling mud.

26) Waters of the State: All streams, lakes, marshes, ponds, watercourses, waterways, wells, 

springs, irrigation systems, drainage systems, and all other bodies or accumulations of 
GENERAL RULES AND REGULATIONS

69

water, surface and underground, natural or artificial, public or private, which are 

contained within, flow through, or border upon this state or any portion of the state.

27) Water Table: The surface between the zone of saturation and the zone of aeration and the 

surface of a body of unconfined ground water at which the pressure is equal to that of the 

atmosphere.

28) Workover Flow-Back Fluid: Any of a number of liquid and gaseous fluids and mixtures 

of fluids, chemicals and or solids consisting of Drilling Fluid, silt, debris, water, brine, oil 

scum, paraffin, or other materials which are removed from the well bore during the 

subsequent or recompletion of a well.

d) Commencement of Construction Operations

The Operator shall notify the appropriate AOGC Regional Office, via mail, e-mail or fax, at least 

forty-eight (48) hours prior to the commencement of Pit construction operations. The Notice of 

Commencement (NOC) shall be on a form agreed upon by AOGC and ADEQ and shall include at 

a minimum (i) the Operator information (name, address, and emergency contact phone number), 

(ii) the location of the drill pad site (latitude and longitude in degrees, minutes, seconds, and 

County, Section, Range, and Township, including the 1/4 of the 1/4 position within the Section), 

(iii) the approximate size of the drill pad, (iv) the approximate distance to the nearest Waters of 

the State, (v) the type of fluid system and type of Drilling Fluids to be used, (vi) well name, (vii) 

nearest city/town, and (viii) the approximate date Pit construction operations shall commence. 

Upon receiving the Notice of Commencement, AOGC shall forward a copy to ADEQ, Arkansas 

Department of Health, and the County Judge of the county in which the pit is located. AOGC and 

ADEQ staff may conduct site inspections as deemed necessary.

e) Discharges Prohibited

The Discharge from a Pit or any activity associated with the drilling or completion of a well to 

any surface or ground waters or in a location where it is likely to cause pollution to any surface or 

groundwaters is prohibited. Such discharge may subject the Operator to ADEQ enforcement 

actions under the provisions of the Water and Air Pollution Control Act (Act 472 of 1949, as 

amended, A. C. A. § 8-4-101, et seq.) and enforcement actions of AOGC under Act 105 of 1939, 

as amended. Any Discharge must be reported within twenty-four (24) hours to the AOGC and 

ADEQ. Leakage from any Pit is considered an unauthorized Discharge. 

f) Mud, Circulation and Reserve Pit Construction Requirements:

1) General Requirements:

A) Mud, Circulation and Reserve Pits constructed within the 100 year flood plain 

must be in accordance with any county or other local ordinance or requirement 

pertaining to the 100 year flood plain.

B) The location of all Mud, Circulation or Reserve Pits shall be chosen with 

reasonable consideration to maximizing the distance from surface waters. Mud, 

Circulation or Reserve Pit construction in streams, creeks, lakes, or any other 

water bodies is strictly prohibited. 

C) Any Mud, Circulation or Reserve Pit construction in wetlands must receive 

appropriate prior authorization from the U.S. Army Corps of Engineers.
GENERAL RULES AND REGULATIONS

70

D) In areas other than jurisdictional wetlands referenced in subparagraph f) 1) C) 

above, where the water table is ten (10) feet or less below the ground surface, all 

Mud, Circulation or Reserve Pits shall be constructed above ground, or the 

Operator shall use a closed loop system.

2) Reserve Pit Requirements:

A) All Reserve Pits shall be constructed with a minimum of two (2) feet of 

freeboard, and shall be maintained to handle a storm event up to a 10-year, 24-

hour storm event during the operation of the Reserve Pit. Reserve Pits 

constructed above ground utilizing bermed side walls, shall be constructed with 

a minimum of 2:1 (two feet horizontal to one foot vertical) side slope on both the 

interior and exterior walls. The top of the bermed pit walls must be a minimum 

of 2 feet wide. 

B) All Reserve Pits shall be constructed with a liner using one of the following 

methods:

i) A synthetic liner of at least twenty (20) mils thickness, with a four (4) 

inch welded seam overlap, completely covering the Reserve Pit bottom 

and inside walls. Sand or sandy material must be placed below the liner 

if a rocky or uneven surface is encountered. The synthetic liner must be 

protected from deterioration, punctures and/or any activity which may 

damage the integrity of the synthetic liner.

ii) A compacted clay liner may be applied to the bottom and sides of the 

Reserve Pit to create an impervious/impermeable barrier. Construction 

of the Reserve Pit and compacted clay liner shall be in accordance with 

sound construction and engineering principles designed and constructed 

to prevent any leakage or seepage to Waters of the State, with due 

consideration given to the topography, Pit material composition, and 

availability of liner material(s). The clay used to construct the liner may 

be in situ or mixed with additional off-site materials, if the on-site clay is 

inadequate.

iii) Other materials or methods used for liner construction must be approved 

by both the Director of the ADEQ and the Director of the AOGC prior to 

use.

3) Mud and Circulation Pits:

A) Closed Loop Systems may be used for Mud and Circulation Pits, and must be 

maintained in a leak-free condition.

B) Earthen Mud and Circulation Pits shall be constructed with a minimum of two 

(2) feet of freeboard, and shall be maintained to handle a storm event up to a 10-

year, 24-hour storm event during the operation of the Mud or Circulation Pit. 

C) Earthen Mud and Circulation Pit liners shall be constructed using one of the 

following methods:

i) A synthetic liner of at least twenty (20) mils thickness, with a four (4) 

inch welded seam overlap, completely covering the Reserve Pit bottom 
GENERAL RULES AND REGULATIONS

71

and inside walls. Sand or sandy material must be placed below the liner 

if a rocky or uneven surface is encountered. The synthetic liner must be 

protected from deterioration, punctures and/or any activity which may 

damage the integrity of the synthetic liner.

ii) Bentonite drilling mud from fresh Water-Based Drilling Fluids may be 

used on the bottom and sides of the earthen Mud or Circulation Pit to 

create an impervious/impermeable barrier. Application of the Mud or 

Circulation Pit bentonite drilling mud liner shall be in accordance with 

sound construction and standard industry practices designed and 

constructed to prevent any Discharge. 

iii) A concrete liner may be applied to the bottom and sides of the earthen 

Mud or Circulation Pit to create an impervious/impermeable barrier. 

Construction of the Mud or Circulation Pit concrete liner shall be in 

accordance with sound construction and standard industry practices 

designed and constructed to prevent any Discharge.

D) Oil-Based Drilling Fluids shall not be placed in an earthen Mud or Circulation Pit 

unless the Pit is lined with a synthetic or concrete liner as prescribed in 

subparagraph f) 3) C) i) or iii) above.

E) If Oil-Based Drilling Fluids are to be used, and the location of the Mud or 

Circulation Pit is within 100 feet of a pond, lake, stream, ERW, ESW or NSW, 

the Operator is required to use a Closed Loop System.

g) Operating Requirements For Mud, Circulation or Reserve Pits:

1) No waste oil, hydraulic fluids, transmission fluids, trash or any other miscellaneous rig 

waste may be disposed into a Mud, Circulation, or Reserve Pit. 

2) Post-drilling Produced Water, and Frac Flow-Back Fluid may not be placed, stored or 

disposed in a Mud, Circulation, or Reserve Pit, except that as part of a Frac Flow-Back 

Fluid recycling program, Frac Flow-Back Fluids may be temporarily placed or stored in a 

Reserve Pit, for a period not to exceed ninety (90) days per pit use for this purpose if:

A) The Reserve Pit is constructed with a clay liner as specified in subparagraph f) 2) 

B) ii) above and a synthetic liner of at least forty (40) mils thickness, in addition 

to all other applicable Reserve Pit construction requirements as specified in 

subparagraph f) 2) above; and

B) The Operator requests approval from ADEQ in writing prior to the placement or 

storage of the Frac Flow-Back Fluid in a Reserve Pit. Such request shall include 

the AOGC Well Permit Number, well names(s), description of the water to be 

stored, anticipated dates of use, volume of water to be stored or placed, detailed 

information on any proposed pipelines for the transfer Frac Flow-Back Fluids 

including a map showing proposed pipeline location for; and

C) No Frac Flow-Back Fluids or other fluids mixed with Frac Flow-Back Fluids 

temporally stored or placed in a Reserve Pit may be sent to any commercial land 

applications disposal facility or land applied onsite.
GENERAL RULES AND REGULATIONS

72

3) Water-Based Drilling Fluid or Encountered Water may be placed or stored in an earthen 

Mud, Circulation or Reserve Pit. 

4) Mud, Circulation and Reserve Pits must be maintained in such a manner as to prohibit 

any Discharges. The Operator is required to maintain adequate storage capacity at all 

times. 

5) Mud, Circulation and Reserve Pit levees or walls shall be protected and maintained at all 

times to prevent deterioration or discharge. In addition, Pit liners shall also be 

maintained and protected from deterioration or puncture causing discharge of fluids until 

such time that the Pit is emptied and closed.

6) Mud, Circulation and Reserve Pits shall contain only Drilling Fluids generated during the 

drilling of the well or wells at the drilling pad where the Pit is constructed, except that 

transfer of Frac Flow-Back Fluids to another drill pad is permitted in accordance with 

subparagraph g) 2) above. The transfer of Frac Flow-Back Fluids via tank truck shall be 

in accordance with General Rule E-3. If the transfer of Frac Flow-Back Fluids is via 

pipeline, such pipeline shall be constructed and maintained in a leak-free condition and 

protected from deterioration, punctures and/or any activity which may damage the 

integrity of the pipeline. If the proposed pipeline will result in a stream crossing, a short 

term activity authorization shall be received from the ADEQ prior to construction. Any 

discharge from the pipeline shall be reported immediately to ADEQ.

7) In the event of an emergency and with prior approval from either the Director of ADEQ 

or the AOGC, the Reserve Pit may be used for temporary additional storage of WaterBased Drilling Fluids from another drilling pad location. In the event of an emergency, 

any request for approval must be submitted to both ADEQ and AOGC for review. 

ADEQ or AOGC will provide notice to each other at the time of the approval of any 

request made pursuant to this paragraph.

8) Except as specified in subparagraph i) 1), or in an emergency and with prior approval 

from the Director of the ADEQ hauling or transporting Drilling Fluids from a Pit to an 

off-site location, not located on a drilling pad, for additional storage is prohibited. 

9) Oil-Based Drilling Fluids shall be segregated from Water-Based Drilling Fluids and other 

Drilling Fluids.

h) Fluid Disposal and Earthen Pit Closure Requirements for Water-Based Drilling Fluid and 

Encountered Water.

1) Water-Based Drilling Fluid or Encountered Water stored in the Pits shall be removed to 

the maximum extent practical using pumps or similar equipment at the time of Pit 

closure, and shall be disposed of in one of the following manners:

A) Land applied in accordance with an active ADEQ land application permit. 

B) Disposed of fluid into approved NPDES or state permitted facility.

C) Injected via Class II wells permitted by AOGC.

D) Pumping the Water-Based Drilling Fluids back down the well bore of the well in 

accordance with AOGC requirements.
GENERAL RULES AND REGULATIONS

73

E) Water-Based Drilling Fluids exhibiting high viscosity to high solids 

concentration may be solidified or stabilized by combining with available native 

soils and buried in situ. The Operator is responsible for ensuring the native soils 

are properly mixed to prevent any discharge. 

F) By any other method as approved by ADEQ and AOGC.

2) The Operator shall take all reasonable measures to ensure that Drilling Fluid and 

Encountered Water that is removed from the well-site, are properly transported to and 

disposed of or recycled or reclaimed at an AOGC or ADEQ permitted site or facility, or a 

permitted site or facility outside of Arkansas.

3) Any synthetic liner used shall be removed to the fullest extent practicable and properly 

disposed or recycled.

4) The closed Pit shall be filled with native materials and covered with topsoil at depths 

consistent with adjoining onsite areas, with the contour mounded or sloped to discourage 

erosion and restored as close to the original contours as is practicable. Topsoil and native 

materials removed during Pit construction may be preserved and used during closure. 

5) The oil & grease content of the material to be buried in situ shall be less than 3% by dry 

weight.

6) The pit and applicable portion of the drill pad not utilized for production purposes, shall 

be returned to grade, reclaimed and seeded within a reasonable amount of time not to 

exceed one hundred eighty days (180) days after the drilling or workover rig is removed 

from the site, or in the case of a multiple well drill pad, within 180 days after the drilling 

or workover rig utilized for the last well to be drilled from the drill pad is removed, 

during which period the reserve pit shall be maintained in accordance with the provisions 

of this rule. An extension of the time to close the pit may be granted upon approval of 

both AOGC and ADEQ. Vegetative coverage of 75%, or equivalent to the surrounding 

landscape, whichever is less, shall be obtained within six (6) months of Pit closure. Until 

vegetation is established, the Operator is responsible for maintaining a stormwater 

erosion and sediment control plan. 

7) The Operator shall submit the Notice of Pit closure to AOGC signed by the Operator 

within 30 days after Pit closure has been completed. AOGC shall forward a copy to 

ADEQ. 

i) Fluid Disposal and Earthen Pit Closure Requirements for Oil-Based Drilling Fluids.

1) Oil-Based Drilling Fluids shall be removed from the Pit and hauled to a permitted Class 1 

(as defined by APC&EC Regulation No. 22) landfill for disposal or be transferred to 

above ground tanks for re-use at another well location, or other disposal methods or uses 

of Oil-Based Drilling Fluids as approved by the ADEQ. The Operator shall inform the 

AOGC of the location of the disposal or transfer of the Oil-Based Drilling Fluid. AOGC 

shall forward a copy to ADEQ.

2) If an Oil-Based Drilling Fluid other than diesel is used as the base, additional analytical 

or disposal requirements may be required, which shall require prior notification and 

approval by ADEQ.
GENERAL RULES AND REGULATIONS

74

3) Any synthetic liner used shall be removed to the fullest extent practicable and properly 

disposed or recycled.

4) The closed Pit shall be filled with native materials and covered with topsoil at depths 

consistent with adjoining onsite areas, with the contour mounded or sloped to discourage 

erosion and restored as close to the original contours as is practicable. Topsoil and native 

materials removed during Pit construction may be preserved and used during closure. 

5) The area shall be returned to grade, reclaimed and seeded within a reasonable amount of 

time not to exceed one hundred eighty days (180) days after the drilling rig is removed 

from the site. Vegetative coverage of 75%, or equivalent to the surrounding landscape, 

whichever is less, shall be obtained within six (6) months of closure. Until vegetation is 

established, the Operator is responsible for maintaining a stormwater erosion and 

sediment control plan.

6) The Operator shall submit the Notice of Pit closure to AOGC signed by the Operator 

within 30 days after Pit closure has been completed. AOGC shall forward a copy to 

ADEQ. 

j) Requirements for Workover Pits, Emergency Pits and Test Pits

1) No Produced Water, Workover Flow-Back Water, waste oil, or any other Nonhazardous 

Oilfield Wastes (NOW) shall be placed in a Workover, Emergency, or Test Pit, unless the 

Pit is lined in accordance with subparagraph f) 2) B) above.

2) All Workover, Emergency, or Test Pits shall be closed within thirty (30) days after the 

associated workover, emergency, or test ceases. Any Workover, Emergency, or Test Pit 

shall be closed in accordance with the requirements of subparagraph h) above.

k) Other drilling mud systems not specifically authorized by this Rule shall require prior notification 

and approval by the Director of the AOGC and the Director of ADEQ.

l) Stormwater Erosion and Sediment Controls

1) The Operator shall prepare a stormwater erosion and sediment control plan for the well 

site covered by this rule. The plan shall be prepared in accordance with proven and 

accepted engineering practices. The plan shall describe and ensure the implementation of 

both erosion and sediment control practices which are to be used to reduce pollutants in 

stormwater discharges associated with the well pad and access roads to minimize erosion 

and reduce the sediments which may enter waters of the state and assure compliance with 

any applicable Water Quality Standards (WQS). Facilities shall implement the 

provisions of the plan required under this rule. The Operator shall provide upon request 

by the ADEQ or AOGC a copy of the stormwater erosion and sediment control plan.

2) In lieu of a stormwater erosion and sediment control plan as required above, the Operator 

may use a guidance document that provides Operators the appropriate erosion and 

sediment controls based upon geographic region, terrain, and distance to adjacent water 

bodies previously submitted and approved by ADEQ. 

3) Any facility that potentially discharges stormwater runoff to a water body listed for 

siltation pursuant to Section 303(d) of the Clean Water Act, or an ERW, ESW or a NSW 

shall have a site specific stormwater erosion and sediment control plan prepared and 

certified by a registered professional engineer, and such plan shall incorporate best 
GENERAL RULES AND REGULATIONS

75

management practices to provide reductions of the listed pollutants to the extent 

reasonably feasible. The 303(d) list, and the location of ERW, ESW, and NSW waters 

are available from ADEQ’s website at the following 

address: http://www.adeq.state.ar.us/water/.

(Source: Original Rule Repealed October 15, 2006; New Rule Effective October 28, 2010 –

Implementation October 1, 2011; amended April 1, 2012)
GENERAL RULES AND REGULATIONS

76

RULE B-18: WELLHEAD FITTINGS

Christmas tree fittings or wellhead connections shall have a working pressure or a test pressure in keeping 

with the expected depth of the well.

(Source: 1991 rule book)

RULE B-19: REQUIREMENTS FOR WELL COMPLETION UTILIZING FRACTURE 

STIMULATION

a) Definitions

1) “ADEQ” means the Arkansas Department of Environmental Quality.

2) “Additive” means any substance or combination of substances, including proppant, 

having a specified purpose that is combined with a Hydraulic Fracturing Fluid. 

3) “AOGC” means the Arkansas Oil and Gas Commission.

4) “Chemical Abstract Service” or “CAS” means the chemical registry that is the 

authoritative collection of disclosed chemical substance information.

5) “Chemical Constituent” means a discrete chemical with its own specific name or identity 

(such as, but not necessarily, a CAS number) that is contained in an additive.

6) “Chemical Family” means a group of elements in the Periodic Table or, more commonly,

compounds that share certain physical and chemical characteristics and have a common 

name.

7) “Hydraulic Fracturing Fluid” means the base fluid type utilized in a particular Hydraulic 

Fracturing Treatment.

8) “Hydraulic Fracturing Treatment” means stimulating a well by the application of 

Hydraulic Fracturing Fluids and Additives with force in order to create artificial fractures 

in the formation for the purpose of improving the capacity to produce hydrocarbons.

9) “RCRA” means Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et. seq.

b) The provisions of this Rule shall apply to all new wells for which an initial drilling permit is 

issued on or after the effective date of this Rule. 

c) Persons applying for a permit to drill shall indicate on the initial drilling application the intent to 

perform Hydraulic Fracturing Treatment operations and provide the information required in 

accordance with subparagraph d) below. If the intent to fracture stimulate a well was not provided 

at the time of the initial drilling application, a Permit Holder desiring to perform Hydraulic 

Fracturing Treatment operations shall send the information required in accordance with 

subparagraph d) below via e-mail, fax or mail to the AOGC office where the initial drilling 

permit was issued, prior to commencement of Hydraulic Fracturing Treatment operations. 

d) The application described in subparagraph c) above shall include:
GENERAL RULES AND REGULATIONS

77

1) The following information on the proposed casing program, demonstrating that the well 

will have steel alloy casing designed to withstand the anticipated maximum pressures to 

which the casing will be subjected in the well:

A) Whether the well will be a vertical well, a directional well, or a horizontal well; 

and

B) The estimated true vertical and measured production casing setting depths; and

C) The casing grade and minimum internal yield pressure for the production casing 

proposed to be used in the well.

2) The following information demonstrating that the well will have sufficient cement 

volume and integrity to prohibit movement of fracture fluids up-hole into the various 

casing or well bore annuli:

A) The proposed cement formulation(s)’ minimum compressive strength; and

B) The estimated top of cement for the production casing string. 

3) The anticipated surface treating pressure range for the proposed Hydraulic Fracturing 

Treatment program. The production casing described in subparagraph d) 1) above shall 

be sufficient to contain the maximum anticipated treating pressure of the Hydraulic 

Fracturing Treatment, which shall not exceed 80% of the minimum internal yield 

pressure for such production casing. 

e) Surface casing in the well in which the proposed Hydraulic Fracturing Treatment will occur shall 

be set, and cemented to the surface, to a depth in accordance with General Rule B-15, and have 

sufficient internal yield pressure to withstand the anticipated maximum pressures to which the 

casing will be subjected in the well. If during the drilling of the surface portion of the well, and 

prior to setting surface casing, a freshwater flow is encountered, or the Permit Holder gains 

knowledge that freshwater will be encountered, from a deeper zone than was specified on the 

permit to drill, surface casing shall be set and cemented at least one hundred (100) feet below the 

deepest encountered freshwater zone.

f) If during the setting and cementing of production and/or any intermediate casings the cement 

program does not occur as submitted in accordance with this Rule, and would cause a reasonably 

prudent Permit Holder to question the integrity of the cementing program with respect to isolating 

the zone of Hydraulic Fracturing Treatment from movement of fracture fluids up-hole into the 

various casing or well bore annuli, the Permit Holder shall immediately notify the Director, or his 

designee, in writing as soon as practicable, but not more than twenty-four (24) hours after the 

event. In reviewing the report, the Director, or his designee, may require a bond log or other 

cement evaluation tool to document cement integrity and require additional cementing operations 

or other appropriate well workover efforts necessary to correct any cement deficiencies prior to 

initiating any Hydraulic Fracturing Treatments in the well. 

g) The Permit Holder shall notify the Director or his designee via e-mail, fax or other approved 

method, a minimum of forty-eight (48) hours prior to commencement of a Hydraulic Fracturing 

Treatment on a well. If the Permit Holder cannot provide notice a minimum of forty-eight (48) 

hours prior to commencement, the Permit Holder shall provide a written explanation as to why 

the notice could not be provided, and the Permit Holder shall provide notice in the manner 

described above as soon as the Permit Holder is aware that a Hydraulic Fracturing Treatment has 

been scheduled.
GENERAL RULES AND REGULATIONS

78

h) The Permit Holder shall monitor all casing annuli that would be diagnostic as to a potential loss 

of well bore integrity during the Hydraulic Fracturing Treatment. The Permit Holder shall 

establish methods to timely relieve any excessive pressures to avoid the loss of surface casing 

integrity.

i) The Permit Holder must provide written notice to the Director, or his designee, of (i) any change 

in surface casing annulus pressure that would indicate movement of fluids into the annulus, or (ii) 

a pressure that exceeds the rated minimum internal yield pressure on any casing string in 

communication with the Hydraulic Fracturing Treatment. This written notice shall be delivered 

as soon as possible after the event, but not more than twenty-four (24) hours after the event. 

Following notification and any request for additional information, the Director, or his designee, 

may request additional documentation or well tests to determine if the Hydraulic Fracturing 

Treatment potentially endangered any freshwater zones. The Director, or his designee, may 

require appropriate additional cementing operations, or other well workover efforts to correct any 

well failure. Pending completion of required operations or efforts, the Director, or his designee, 

may order the cessation of further Hydraulic Fracturing Treatment and/or other well operations. 

The Director shall report any such incident to the Commission at its next regularly scheduled 

hearing, and the Commission may take such further action as it deems necessary and appropriate 

under the circumstances.

j) All non-exempt RCRA materials and fluids used on-site in the Hydraulic Fracturing Treatment 

shall be handled and stored in accordance with ADEQ requirements and any spills of these 

materials and fluids on-site or off-site shall be reported to ADEQ in accordance with applicable 

ADEQ requirements. All RCRA exempt materials and fluids used on-site in the Hydraulic 

Fracturing Treatment shall be contained in leak free tanks or other containment vessels. Any onsite spill of these materials or fluids shall be immediately contained, remediation efforts shall be 

commenced as soon as practical, and the incident shall be reported to the Director, or his 

designee, within twenty-four (24) hours. 

k) All Hydraulic Fracturing Treatment flow back fluids shall be handled, transported, stored, 

disposed, or recycled for re-use in accordance with the applicable provisions of General Rule B17, General Rule E-3 and General Rule H-1, H-2 and H-3.

l) Following completion of the Hydraulic Fracturing Treatment, the Permit Holder shall, for 

purposes of disclosure, report detailed information to the Director, or his designee, of the 

Hydraulic Fracturing Treatment in the manner customarily reported or presented to the Permit 

Holder, within the time period specified in General Rule B-5, as follows:

1) The maximum pump pressure measured at the surface during each stage of the Hydraulic 

Fracturing Treatment; and

2) The types and volumes of the Hydraulic Fracturing Fluid and proppant used for each 

stage of the Hydraulic Fracturing Treatment; and

3) The calculated fracture height as designed to be achieved during the Hydraulic Fracturing 

Treatment and the estimated TVD to the top of the fracture; and

4) A list of all Additives used during the Hydraulic Fracturing Treatment specified by 

general type, such as acid, biocide, breaker, corrosion inhibitor, crosslinker, demulsifier, 

friction reducer, gel, iron control, oxygen scavenger, pH adjusting agent, scale inhibitor, 

proppant and surfactant; and
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79

5) The names of all specific Additives for each Additive type, specified in subparagraph l) 

4) above, utilized during the Hydraulic Fracturing Treatment and the actual rate or 

concentration for each such Additive expressed as pounds per thousand gallons or gallons 

per thousand gallons additionally, the Additives are to be expressed as a percent by 

volume of the total Hydraulic Fracturing Fluids and Additives; and 

6) The Permit Holder shall supply field service company tickets (excluding pricing) and 

reports regarding the Hydraulic Fracturing Treatment, as used in the normal course of 

business to satisfy some or all of the foregoing information requirements; and

7) The Permit Holder shall supply all information received from the person performing the 

Hydraulic Fracturing Treatment specified in subparagraph m) 4) below.

8) If the Permit Holder causes any Additives to be utilized during the Hydraulic Fracturing 

Treatment not otherwise disclosed by the person performing the Hydraulic Fracturing 

Treatment, the Permit Holder shall disclose a list of all Chemical Constituents and 

associated CAS numbers contained in all such Additives; provided, however, in those 

limited situations where the specific identity of any such Chemical Constituent and 

associated CAS number is entitled to be withheld as a trade secret under the criteria set 

forth in subsection (a)(2) of 42 U.S.C. § 11042, the Permit Holder shall (i) submit to the 

Director a claim of entitlement to have the identity of such Chemical Constituent 

withheld as a trade secret, and (ii) provide the Director with the Chemical Family 

associated with such Chemical Constituent. The identity of any Chemical Constituent 

that qualifies as a trade secret under the criteria set forth in subsection (a)(2) of 42 U.S.C. 

§ 11042 shall be held confidential by the Director.

9) Nothing in subparagraph l) 8) above shall authorize any person to withhold information 

which is required by state or federal law to be provided to a health care professional, a 

doctor, or a nurse. All information required by a health care professional, a doctor, or a 

nurse shall be supplied, immediately upon request, by the person performing the 

Hydraulic Fracturing Treatment, directly to the requesting health care professional, 

doctor, or nurse, including the percent by volume of the Chemical Constituents (and 

associated CAS numbers) of the total Hydraulic Fracturing Fluids and Additives.

m) Any person performing Hydraulic Fracturing Treatments within the State of Arkansas shall:

1) Be authorized to do business in the State of Arkansas; and

2) Be required to file Organization Reports in accordance with General Rule B-13, and 

include the length of time the entity has been in the business of performing Hydraulic 

Fracturing Treatments; and

3) Disclose to the Director, or his designee, and maintain separate master lists of:

A) All Hydraulic Fracturing Fluids to be utilized during any Hydraulic Fracturing 

Treatment within the State of Arkansas; and

B) All Additives to be utilized during any Hydraulic Fracturing Treatment within 

the State of Arkansas; and 

C) All Chemical Constituents and associated CAS numbers to be utilized in any 

Hydraulic Fracturing Treatment within the State of Arkansas; provided, however, 

in those limited situations where the specific identity of any such Chemical 
GENERAL RULES AND REGULATIONS

80

Constituent and associated CAS number is entitled to be withheld as a trade 

secret under the criteria set forth in subsection (a)(2) of 42 U.S.C. § 11042, the 

person performing the Hydraulic Fracturing Treatment shall (i) submit to the 

Director a claim of entitlement to have the identity of such Chemical Constituent 

withheld as a trade secret, and (ii) provide the Director with the Chemical Family 

associated with such Chemical Constituent. The identity of any Chemical 

Constituent that qualifies as a trade secret under the criteria set forth in 

subsection (a)(2) of 42 U.S.C. § 11042 shall be held confidential by the Director; 

and

4) Provide to the Permit Holder for each well that such person performs a Hydraulic 

Fracturing Treatment, lists of: 

A) The Hydraulic Fracturing Fluids utilized during the Hydraulic Fracturing 

Treatment; and

B) The Additives utilized during the Hydraulic Fracturing Treatment, and the actual 

rate or concentration for each such Additive utilized, expressed as pounds per 

thousand gallons or gallons per thousand gallons; additionally, the Additives are 

to be expressed as percent by volume of the total Hydraulic Fracturing Fluids and 

Additives, so that the Permit Holder may comply with its obligations under 

subparagraph l) above; and 

C) All Chemical Constituents and associated CAS numbers utilized during the 

Hydraulic Fracturing Treatment; unless the specific identity of any such 

Chemical Constituent and associated CAS number is entitled to be withheld as a 

trade secret in accordance with subparagraph m) 3) c) above. 

5) Nothing in subparagraphs m) 3) c) or l) 4) c) above shall authorize any person to 

withhold information which is required by state or federal law to be provided to a health 

care professional, a doctor, or a nurse. All information required by a health care 

professional, a doctor, or a nurse shall be supplied, immediately upon request, by the 

person performing the Hydraulic Fracturing Treatment, directly to the requesting health 

care professional, doctor, or nurse, including the percent by volume of the Chemical 

Constituents (and associated CAS numbers) of the total Hydraulic Fracturing Fluids and 

Additives.

n) No Permit Holder shall utilize the services of another person to perform a Hydraulic Fracturing 

Treatment unless the person performing a Hydraulic Fracturing Treatment is in compliance with 

subparagraph m) above.

(Source: Original Rule Repealed October 15, 2006; New Rule Effective January 15, 2011; Amended 

February 08, 2013)
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81

RULE B-20: REPEALED

Rule Repealed Effective October 15, 2006

RULE B-21: REPEALED

Rule Repealed Effective October 15, 2006

RULE B-22: REPEALED

Rule Repealed Effective November 11, 2007
GENERAL RULES AND REGULATIONS

82

RULE B-23: TUBING

a) All oil wells shall be equipped with, and produced through tubing. Bottom of tubing on flowing 

wells shall not be higher than top of producing interval. If tubing is perforated, the perforations 

shall not extend above the top of the producing interval. 

b) All dry gas wells are not required to produce through tubing, provided surface casing has been 

set in the well in accordance with applicable rules. If multiple gas zones are produced in the well, 

authority to commingle in accordance with General Rule D-18 shall be required.

(Source: 1991 rule book; amended October 15, 2006)

RULE B-24: CHOKES

All wells shall be equipped with adequate chokes, to properly control the flow thereof.

(Source: 1991 rule book)

RULE B-25: REPEALED

Rule Repealed Effective November 11, 2007
GENERAL RULES AND REGULATIONS

83

RULE B-26: GENERAL LEASE OPERATING REQUIREMENTS

a) Definitions for purposes of this rule

1) “ADEQ” means the Arkansas Department of Environmental Quality.

2) “Crude Oil Tank Battery” means a combination of saltwater and crude oil storage tanks 

and other vessels commonly used in the production and temporary storage of crude oil.

3) “Director” means the Arkansas Oil and Gas Commission Director of Production and 

Conservation.

4) “EPA” means the United States Environmental Protection Agency

5) “Gas Well Produced Fluids Storage Tanks” means tanks or other vessels commonly used 

for the temporary storage of fluids, produced with natural gas, prior to disposal.

6) “Lease” means a tract of land under agreement by an owner or person, for the purpose of 

producing oil and or gas and allocating that production for himself or the owners of the 

oil and gas rights under that tract of land.

7) “Permit Holder” shall mean the operator or person, who is duly authorized to develop a 

lease or unit as owner or through agreement and has the right to drill and produce from 

any field or reservoir and to appropriate the production for himself or others.

8) “Produced Fluids” shall mean those fluids produced or generated during the crude oil 

production and separation process and shall include crude oil, crude oil bottom sediment 

and shall include all waters regardless of chloride content associated with production of 

oil and or gas. 

9) “RCRA” means Subtitle C of the Federal Resource Conservation Recovery Act of 1976.

10) “USDW” means Underground Source of Drinking Water which is defined as an aquifer 

or its portion which:

A) supplies any public water system; or

B) contains a sufficient quantity of groundwater to supply a public water system and 

currently supplies drinking water for human consumption or contains fewer than 

10,000 mg/l total dissolved solids; and

C) Which is not an exempted aquifer (see 40 CFR). 

b) Well Identification

1) Each oil and or gas well shall have a legible sign placed at the well showing the Permit 

Holder and the well name and number as shown on the permit as listed in the 

Commission records. If the lease is a single well lease, the well sign may be placed at the

associated tank battery or lease entrance. 

2) Every entrance from a public road to north Arkansas gas well sites shall have a legible 

sign placed at that entrance. The sign shall show the name of the Permit Holder, a list of 

all wells accessed by that entrance, the section, township and range, and a telephone 
GENERAL RULES AND REGULATIONS

84

number at which the Permit Holder or his authorized agent can be reached during an 

emergency. 

3) For any newly drilled well, the required sign shall be posted within 45 days after 

cessation of drilling operations.

4) Any changes or corrections in the well information, required to be posted in accordance 

with this rule, shall be made to the well signs within sixty (60) days after the change 

occurs, or in the case of a transfer of well ownership, within sixty (60) days after the 

effective date of the transfer in the Commission records. All prior signs, if not correct, 

shall be removed.

c) Crude Oil Tank Batteries

 

1) All existing and newly constructed tank batteries shall be registered with the Commission 

and assigned a Commission registration number. Registration shall be reported to the 

Commission utilizing information as reported on the existing AOGC Form 6 Monthly 

Producers Report.

2) All tank battery registrations, shall be transferred, at the time of associated well transfers, 

utilizing the approved notice of well transfer forms filed with the Commission.

3) Each tank battery shall have a legible sign in a conspicuous place on or near the near the 

crude oil storage tank(s). The sign shall show the name of the Permit Holder who holds 

the Commission permit to operate the lease or unit, the lease name, the section, township 

and range, and a telephone number at which the Permit Holder or his authorized agent 

can be reached during an emergency.

4) All tank batteries consisting of tanks containing produced fluids or crude oil storage tanks 

or containing tanks equipped to receive produced fluids, shall be surrounded by 

containment dikes or other containment structures as may be appropriate under the 

circumstances, as approved by the Director. All containment dikes or other approved 

structures shall be constructed or installed in accordance with sub-paragraph (e) below.

5) Tank batteries constructed after the effective date of this rule, shall not be located:

A) within 200 feet of an existing occupied habitable dwelling, unless the current 

owner of the structure has provided a written waiver consenting to the 

construction closer than 200 feet, in which case the tank battery shall be 

completely fenced to prevent unauthorized access; however, in no event may a 

tank battery may be constructed closer that 100 feet to an existing habitable 

dwelling; or

B) within 300 feet of a school, hospital or other type of public use building as 

defined in Arkansas Fire Prevention Code Section 3406.3.1.3.1; or

C) within 300 feet of a stream or river designated as an Extraordinary Resource 

Water (ERW), Natural and Scenic Waterways or Ecological Sensitive 

Waterbodies as defined by APC&E Regulation 2, or within 200 feet of other 

streams, waterways, rivers, ponds, lakes, wetlands (unless approved by other 

appropriate governmental agencies), or other bodies of water (as indicated by a 

blueline designation on a 7.5 minute USGS Topographic Map), unless the Permit 
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85

Holder utilizes additional containment measures other than the required 

containment specified in sub-paragraph (e) below, as approved by the Director.

6) Tanks or any part of such tanks shall not be buried below the ground surface.

7) All tanks shall be maintained in a leak-free condition.

8) All open top tanks shall be covered with bird netting, or other system designed to keep 

birds and flying mammals from landing in the tank.

d) Gas Well Produced Fluids Storage Tanks 

1) Tanks or any part of such tanks shall not be buried below the ground surface.

2) All tanks shall be maintained in a leak-free condition.

3) All open top tanks shall be covered with bird netting, or other system designed to keep 

birds and flying mammals from landing in the tank.

4) Tanks constructed after the effective date of this rule, shall not be located:

A) within 200 feet of an existing occupied habitable dwelling, unless the current 

owner of the structure has provided a written waiver consenting to the 

construction closer than 200 feet, in which case the tank battery shall be 

completely fenced to prevent unauthorized access; however, in no event may a 

tank battery may be constructed closer that 100 feet to an existing habitable 

dwelling; or

B) within 300 feet of a school, hospital or other type of public use building as 

defined in Arkansas Fire Prevention Code Section 3406.3.1.3.1; or

C) within 300 feet of a stream or river designated as an Extraordinary Resource 

Water (ERW), Natural and Scenic Waterways or Ecological Sensitive 

Waterbodies as defined by APC&E Regulation 2, or within 200 feet of other 

streams, waterways, rivers, ponds, lakes, wetlands (unless approved by other 

appropriate governmental agencies), or other bodies of water (as indicated by a 

blueline designation on a 7.5 minute USGS Topographic Map), unless the Permit 

Holder utilizes additional containment measures other than the required 

containment specified in sub-paragraph (e) below, as approved by the Director.

5) All tanks containing produced fluids or equipped to receive produced fluids shall be 

surrounded by containment dikes or other containment structures as may be appropriate 

under the circumstances, as approved by the Director. All containment dikes or other 

approved structures shall be constructed or installed in accordance with sub-paragraph (e) 

below.

e) Containment Dikes or Other Containment Structures

1) All Crude Oil Tank Batteries and Gas Well Produced Fluids Storage Tanks shall be 

surrounded by containment dikes or such other structure as may be appropriate under the 

circumstances, as approved by the Director to prevent waste, protect life, health or 

property, unless an exception is granted by the Commission following notice and hearing. 
GENERAL RULES AND REGULATIONS

86

2) Required containment dikes or other approved structures shall be designed to have a 

capacity of at least 11⁄2 times the largest tank the containment dike or approved structure 

surrounds. 

3) The natural or man-made material utilized for the construction of the required 

containment dikes or other approved structures and the natural or man-made material 

used to line the bottom of the containment area shall be sufficiently impervious so as to 

contain fluids and resist erosion.

4) Vegetation on the top and outside surface of containment structures shall be properly

maintained so as to not pose a fire hazard.

5) The area within the containment dike or other approved containment structure shall be 

kept free of excessive vegetation, stormwater, produced fluids, other oil and gas field 

related debris, general trash, or any flammable material. Drain lines installed through the 

firewall, for the purpose of draining stormwater, shall have a valve installed which shall 

remain closed and capped when not in use. Any fluids collected, spilled or discharged 

within such containment structures shall be removed as soon as practical, using the 

following proper disposal methods: 

A) Stormwater, which has not been mixed with non-exempt RCRA waste as defined 

by the EPA, may be drained from the containment structure provided the 

following conditions are met:

i) the chloride content shall not exceed applicable state water quality 

standards. 

ii) there must be no visible evidence of hydrocarbons or hydrocarbon sheen 

present; 

iii) the discharge shall only take place during daylight hours; 

iv) a representative of the Permit Holder must be present during discharge; 

and 

v) the Permit Holder shall maintain a record of each stormwater discharge, 

occurring in the previous 6 month period, and which shall be available 

for review upon request by Commission staff. The record shall indicate 

the location, quantity, chloride content, presence of any hydrocarbons 

(sheen), and date of discharge.

B) Produced fluids which have not been mixed with non-exempt RCRA waste as 

defined by the USEPA, may be recycled through the production equipment or 

removed from the containment structure and disposed in a properly permitted 

Class II UIC Well.

C) All stormwater and produced fluids which have been mixed with non-exempt 

RCRA waste as defined by the USEPA shall be removed and disposed in 

accordance with applicable Pollution Control and Ecology Commission 

regulations, as administered by ADEQ.

D) Crude oil bottom sediments (BS&W) may be:
GENERAL RULES AND REGULATIONS

87

i) applied on oil field lease roads under the following conditions:

a) application shall be in such a manner as to avoid runoff onto 

immediately adjacent lands or into Waters of the State; and

b) immediately following completion of the application, all liquid 

fractions shall be immediately incorporated into the road bed 

with no visible free-standing oil; and

c) no lease road shall be oiled more than twice a year; and

d) no lease road shall be oiled during precipitation events; and

e) the applied BS&W shall not have a produced water content 

greater than ten percent (10%) free water by volume; or

ii) injected into an inactive oil and gas production well:

a) which has been equipped with tubing and packer, for the purpose 

of said injection, the packer to be set within the production 

casing, at least fifty (50) feet below the top of the production 

casing cement, but no less than five hundred (500) feet below the 

base of the deepest USDW, and

b) injection of the BS&W shall not exceed 45 days, after which 

time the well shall be immediately plugged in accordance with 

General Rule B-8,and

c) if the Director determines through field observations that the 

injection activities are endangering the USDW, the injection 

activities shall cease until the condition is corrected. 

6) Any residual produced fluids remaining within the containment dike, after removal, as 

required in subsection (e) (5) above, shall be remediated in place in accordance with 

General Rule B-34.

7) Any spill, leak or discharge of produced fluids escaping from a containment dike shall be 

reported and remediated in accordance with General Rule B-34.

8) When a Crude Oil Tank Battery, Gas Well Produced Fluids Storage Tank or a gas well 

separator is removed, the Permit Holder shall remove all above ground piping and 

flowlines coming into said tanks or separator and cap all below ground piping and 

flowlines, level and grade soil portion of the containment dikes, remove from site all nonsoil containment structure construction material, and remediate all hydrocarbon 

contaminated soil at tank or separator site in accordance with General Rule B-34.

f) Liquid Hydrocarbon Flowlines

1) All flowlines used in the production of liquid hydrocarbons, constructed after the

effective date of this rule, shall be buried at least twenty-four (24) inches below the 

ground surface. Flowlines may be exempt from these burial requirements upon approval 

of the Director, in the following circumstances:
GENERAL RULES AND REGULATIONS

88

A) the topographical features, land uses or ground conditions prevent the 

efficient burial of flowlines; or

B) the suspected presence of numerous old abandoned flowlines, in old producing 

fields, render the burial of new lines impractical or which will significantly 

increase the likelihood of causing the discharge of crude oil from the old lines; or 

C) the terms of the oil and gas lease or surface owner agreement, prohibit the burial 

of flowlines; or

D) the flowlines are installed or placed within the lease road right of way; or

E) the flowlines from the well to the tank battery are entirely within the confines of 

the original drilling location.

2) All flowlines which cross and are not buried under natural drainage features such as 

creeks, streams, rivers or intermittent streams or ravines shall be constructed in such 

fashion as to bridge the drainage feature to protect the flowlines from damage due to lack 

of adequate support, resulting in potential discharge and violation of the state water 

quality standards. 

3) The Director shall have the authority to require active flowlines existing on the effective 

date of this rule to be replaced, buried or constructed in accordance with subsection (2) 

above or to require the visible aboveground inactive or abandoned portions of those 

abandoned flowlines to be removed and the open ends sealed, if the Director finds, based 

on field observation, that the flowlines constitute a hazard to public safety or can 

reasonably be expected to cause damage to the environment through leaks, spills or 

discharges.

4) No flowlines transporting produced water shall have an outlet valve installed for the 

purpose of discharging produced water between the place or well of origin and the 

authorized storage or disposal point. A specialized valve, installed for the purpose of 

venting trapped air, following flowline maintenance is permissible.

5) Any spill, leak or discharge from a flowline shall be reported and remediated in 

accordance with General Rule B-34.

g) Natural gas production lines and gathering lines shall be installed and operated in accordance 

with General Rule D-17 – General Rule Relative to Establishing An Effective And Efficient 

Procedure For The Regulation Of Production Field Lines For Natural Gas As Well As Safety 

Standards or other applicable Commission rules.

h) Power Lines

1) All power lines installed after the effective date of this rule, shall be installed in such a 

manner as to prevent contact by vehicle or pedestrian travel.

2) The Director shall have the authority to require power lines existing on the effective date 

of this rule, to be in compliance with sub-paragraph (h) (1) above, if the Director finds, 

based on field observation, that the power lines constitute a hazard to public safety.

i) Equipment Use and Storage
GENERAL RULES AND REGULATIONS

89

1) All well head areas shall be kept free of excessive vegetation.

2) All production equipment, including but not limited to separators, heater treaters, 

piping, compressors, injection pumps, and chemical containers, shall be kept free of 

vegetation and maintained at all times in a safe and good working condition.

3) Used refined oil from any production equipment such as pumpjacks, injection pumps and 

compressors shall not be improperly disposed or placed in storage tanks containing 

produced water. All used refined oil shall be disposed in accordance with Arkansas 

Pollution Control and Ecology Commission Regulation 23, Section 279.

4) Excess usable or operable production equipment, not integrally related to production 

activities on the lease, established drilling unit, or other unitized production area shall not 

be stored on any surface property unless written consent from the current surface owner 

where the production equipment is located, has been granted to the Permit Holder to store 

such equipment, unless the equipment has been designated by the Permit Holder to be 

used in the future on that lease, established drilling unit, or other unitized production area 

and the equipment and storage area, which shall be limited to an area in close proximity 

to existing well site(s) or production area(s), and are maintained and kept free of 

excessive vegetation. 

5) Other trash and debris, including but not limited to, abandoned, unusable or unrepairable, 

junk tanks, treaters, tubulars, injection pumps, pump jacks, concrete, above ground piping 

and flowlines, and any other general junk equipment or machinery shall not be stored on 

any surface property except that owned by the Permit Holder. Removed trash and debris 

shall be disposed in accordance with applicable ADEQ or other state agency regulations.

j) Production Pits

1) "Production Pit", as used in this Section, is an earthen surface impoundment, whether a 

man-made excavation or a diked area which was or currently is used for temporary 

storage of produced fluids prior to disposal.

2) Construction of production pits, other than those pits previously authorized by 

Commission Orders are prohibited.

3) All other production pits in existence as of the effective date of this rule shall cease to be 

used on the effective date of this rule and closed within 90 days after the effective date of 

this rule in a manner prescribed by the Commission and in accordance with all applicable 

state laws an regulations, unless exempted in accordance with subsection (4) below.

4) Any production pit in existence as of the effective date of this rule, may not be subject to 

closure in accordance with subsection (j) (3) above if:

A) the pit is no longer used for temporary storage of produced fluids; and

B) the water quality in the pit is less than 1500 TDS with no visible sheen of oil; and

C) a written, notarized authorization from the current surface owner has been 

received by the Director requesting the pit not be closed and demonstrating an 

acceptable alternative use for the pit; and

D) in determining not to require the pit be closed, the Director shall:
GENERAL RULES AND REGULATIONS

90

i) review the current location of the pit relative to any ongoing 

production operations in the area; and

ii) review the proposed alternative use relative to public health and 

safety considerations and potential use for agricultural, recreational or 

wildlife habitat purposes.

E) If the Director determines, based on a review of the information submitted by the 

operator and surface owner, the pit is not exempted, the pit shall be closed, 

within six (6) months, by the operator, in accordance with subsection (3) above.

k) Leaking Permitted Well 

Where any oil and gas reservoir fluids or salt waters or other produced fluids are potentially 

leaking into the USDW as determined by geologic and field investigation or are leaking onto the 

surface, through a permitted well transferred to the Permit Holder, the permitted well shall be 

plugged by the Permit Holder. Pending plugging of the well, all injection wells within a 1/4 mile 

radius of the leaking drill hole shall be shut-in until the well is plugged. 

l) Leaking Previously Plugged Well

Where any oil and gas reservoir fluids or salt waters are potentially leaking into the USDW or to 

the surface as determined by geologic and field investigation, through a well plugged under 

applicable Commission rules, the well shall be replugged by the original Permit Holder 

responsible for plugging the leaking well. If the original Permit Holder is no longer in existence 

or cannot be located, the well shall be eligible for plugging through the Arkansas Orphan and 

Abandoned Well Plugging Fund. Pending plugging of the well all injection wells within a 1/4 

mile radius of the leaking well shall be shut-in until the leaking well is plugged.

(Source: 1991; amended July 13, 2003; amended October, 14, 2007; amended August 17, 2008)
GENERAL RULES AND REGULATIONS

91

RULE B-27: SALT WATER

All wells producing two percent (2%) or more salt water in the controlled fields must be reported monthly 

by their owner or operator to the Commission “Well Status Report and Gas Oil Ratio.”

(Source: 1991 rule book)

RULE B-28: REPEALED

Rule Repealed Effective November 11, 2007

RULE B-29: REPEALED

Rule Repealed Effective October 15, 2006
GENERAL RULES AND REGULATIONS

92

RULE B-30: DEVIATION TESTS

The maximum point at which a well penetrates the producing formation shall not unreasonably vary from 

the vertical drawn from the center of the hole at the surface. Deviations in excess of the following shall 

be deemed to be unreasonable: More than 3 degrees from the vertical drawn from the center of the hole at 

the surface.

The Commission shall have the right to make, or to require the operator to make a directional survey of 

the hole, under the following circumstances: (a) in all cases where the operator has proposed to 

deliberately drill a directional well from an exceptional surface location and/or to an exceptional bottom 

hole location; (b) prior to a permit being issued, if an off-set operator requests a directional survey and 

agrees in writing to pay all costs and expenses of such survey and to assume liability for all risks 

associated with the survey and further posts a bond in sufficient sum as determined by the Commission as 

security against all costs and risks associated with the survey or, (c) at any time, by order of the 

Commission, if the Commission is first presented with substantial evidence that it is likely that the well 

was drilled other than at the location permitted or that the well has deviated in the direction of a unit 

boundary to a bottom location which would necessitate an increased penalty upon the well's production 

allowable. The Commission shall have the continuing jurisdiction to assess the expense and risk of such 

survey between the operator and any opposing party.

(Source: 1991 rule book; amended July 13, 2003)
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93

RULE B-31: REPEALED

Rule Repealed Effective October 15, 2006

RULE B-32: VACUUM PUMPS PROHIBITED

a) The use of vacuum pumps or other devices for the purpose of putting a vacuum on any gas or oilbearing stratum is prohibited except in fields using vacuum pumps on January 1, 1939, unless 

otherwise approved by the Commission or in accordance with subparagraph b) below.

b) Administrative Approval. The Director or his designee is authorized to approve an application 

for administrative approval of the use of vacuum pumps or other devices for the purpose of 

putting a vacuum on any gas or oil bearing stratum if the following conditions are met:

1) The application provides proof that the field is practically depleted or the use of vacuum 

pumps or other devices for the purpose of putting a vacuum on any gas or oil-bearing 

stratum is otherwise necessary for the prevention of waste. 

2) The application includes detailed plat maps indicating current well locations in all 

included drilling units or leases in uncontrolled pools or fields. 

3) Notice has been given to all owners, as defined by Ark. Code Ann. (1987) § 15-72-102(9) 

and no objections were received by the Director in accordance with subparagraph b) 6) 

below. 

4) Each such application is submitted on a form prescribed by the Director, and includes the 

name and address of each owner, as defined in Ark. Code Ann. (1987) § 15-72-102(9), 

within each drilling unit in which applicant seeks approval to use the vacuum pump or 

other devices for the purpose of putting a vacuum on any gas or oil-bearing stratum.

5) Concurrently with the filing of such application, the applicant shall send to each owner 

specified in subparagraph b) 4) above a notice of the application filing and verify such 

mailing by affidavit, setting out the names and addresses of all owners, as defined by 

Ark. Code Ann. (1987) § 15-72-102(9), and the date(s) of mailing.

6) Any owner, as defined by Ark. Code Ann. (1987) § 15-72-102(9), noticed in accordance 

with subparagraph b) 5) above shall have the right to object to the granting of such 

application within fifteen (15) days after the receipt of the application by the 

Commission. Each objection must be made in writing and filed with the Director or his 

designee. If a timely written objection is filed as herein provided, then the applicant shall 

be promptly furnished a copy and such application shall be denied. If the application is 

denied under this subparagraph, the applicant may file an application for hearing in 

accordance with General Rules A-2 and A-3, and other applicable hearing procedures.

7) An application may be referred to the Commission for determination when the Director 

or his designee deems it necessary that the Commission make such determination for the 

purpose of protecting the correlative rights of all parties, in order to prevent waste, or for 

any other reason. Promptly upon such determination, and not later than fifteen (15) days 

after receipt of the application, the Director or his designee shall give the applicant 

written notice, citing the reason(s) for referral to the full Commission for determination, 

and the application shall be denied. If the application is denied under this subparagraph,

the applicant may file an application for hearing in accordance with General Rules A-2 

and A-3, and other applicable hearing procedures.
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8) If the Director has not notified the applicant of the determination to refer the application 

to the Commission within the fifteen (15) day period in accordance with the foregoing 

provisions, and if no objection is received at the office of the Commission within the 

fifteen (15) days as provided for in subparagraph b) 6), the application shall be approved. 

(Source: 1991 rule book; amended July 29, 2011)
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RULE B-33: PRODUCTION PRACTICE

Naturally flowing wells shall be produced at a continuous, uniform rate as far as is practicable, in keeping 

with the current allowable, unless the Commission specially permits stop-cocking to reduce the gas-oil 

ratio or overcome logging up.

(Source: 1991 rule book)
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96

RULE B-34: NOTICE OF FIRE, BREAKS, OR BLOW-OUTS AND REMEDIATION OF 

ASSOCIATED SPILLS OF CRUDE OIL AND PRODUCED WATER

a) Definitions for purposes of this rule

1) “Permit Holder” shall mean the operator or person, who is duly authorized to develop a 

lease or unit as owner or through agreement and has the right to drill and produce from 

any field or reservoir and to appropriate the production for himself or others.

b) Notification

1) Any Permit Holder of an oil, gas and brine production, UIC Class II, and Class V (brine 

disposal) well or an owner or operator of tanks, storage tanks, or other receiving and 

storage receptacles into which crude oil is produced, received, or stored, or through 

which oil is transported in flowlines, shall immediately, but not more than twenty-four 

(24) hours, notify the Commission Regional Office, where the event has occurred, by 

telephone or facsimile concerning all fires, blow-outs, spills, leaks or discharges in excess 

of one (1) barrel of crude oil or five (5) barrels of produced water, which occur at these 

facilities.

2) All notices of fires, blowouts, spills, leaks, or discharges provided to the Commission 

Regional Office, shall include the name of the operator responsible and the location of 

the fire, blow-out, spill leak, or discharge by providing the Section, Township, Range and 

property, lease, or unit, name. Such report shall also specify what emergency steps have 

been taken or are in progress to remedy the situation reported. 

3) If the reported fire, blow-out, spill, leak, or discharge results in a spill or discharge in 

excess of one (1) barrel of crude oil and or five (5) barrels of produced water outside the 

containment, the Permit Holder shall also provide the following in the required written 

incident report, on a form prescribed by the Director:

A) the amount of crude oil and produced water spilled or discharged,

B) the areal extent of the spill or discharge,

C) the cause of the spill or discharge, and

D) the proposed remediation efforts.

4) Spills or discharges from interstate and intrastate pipeline (downstream from custody 

transfer), or from refined product pipelines are not covered by this rule and are under the 

jurisdiction of the Arkansas Department of Environmental Quality (ADEQ).

5) All crude oil and produced water spills or discharges, regardless of amount, which enter 

Waters of the State as defined in Ark. Code Ann. § 8-4-102 shall be reported immediately 

to the ADEQ. That portion of the spill which entered Waters of the State shall be under 

the jurisdiction of the ADEQ for remediation and enforcement purposes.

c) Crude Oil Spill Remediation Requirements

1) All crude oil spills that occur after the effective date of this rule, regardless of amount, 

from wells, flowlines, tanks, pits or containment dikes are subject to this rule.
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97

2) The Permit Holder is required to initiate the following emergency response procedures 

for all crude oil spills immediately after a spill has occurred, but not more than 24 hours 

after the spill: 

A) Contain spilled crude oil using earthen dikes, booms and other containment 

measures to minimize the amount of area affected by the spill.

B) If a spill enters surface waters, the spill shall be contained with booms and/or 

underflow dams and removed as expeditiously as possible. Further remediation 

requirements shall be determined by ADEQ in accordance with sub-paragraph (a) 

(5) above.

C) The cause of spill shall be repaired immediately.

D) Impounded free oil shall be picked up and put in lease storage tanks or removed 

from the site and recycled.

3) Remaining oil on the land surface shall be removed using absorbent material, which shall 

be handled as follows:

A) All non-organic/non-biodegradable absorbent materials shall be removed from 

the site and disposed of at an ADEQ permitted waste treatment or disposal

facility or other disposal options as allowed by applicable state law or regulation.

B) On-site disposal of organic/biodegradable absorbent materials, such as straw and 

peat moss, may be disposed through land spreading over the area affected by the 

initial spill and remediated in accordance with sub-paragraphs (4) (A) thru (D) 

below.

4) Contaminated soil area affected by a spill may be remediated in place and shall, within 10 

days, at a minimum be:

A) fertilized with 13-13-13 fertilizer or an amount of other acceptable fertilizer 

sufficient to treat the soil with 0.5 lbs per square yard; and

B) limed with sufficient agricultural grade lime over the affected area in order to 

maintain a pH of between 6-8; if the pH of the soil/oil mixture is less than 6, 

additional lime shall be incorporated to increase pH above 6; and

C) tilled to a depth of at least 4 inches but no greater than 12 inches to create a soil 

and crude oil mixture that contains less than 5% total petroleum hydrocarbon 

(TPH) following the completion of the initial tilling; and

D) watered to maintain soil moisture sufficient to promote plant growth (if 

extremely dry soil conditions exist); and

E) stabilized to minimize erosion and run-off of stormwater to prevent violation of 

applicable water quality standards.

F) If the soil in the affected area is frozen or previously saturated due to rain or 

snow melt, prohibiting compliance with sub-paragraphs (A) thru (E) above, the 

Permit Holder shall stabilize the area to prevent any surface run-off of crude oil 
GENERAL RULES AND REGULATIONS

98

from leaving the affected area until conditions permit compliance with subparagraphs (A) thru (E) above.

G) The soil affected by the spill must contain less than 1% TPH within 12 months 

after the date of the spill.

H) The Director may require additional remediation action to be taken by the 

operator, which may include flushing of the area with freshwater (which shall be 

collected and disposed in a UIC Class II well), the addition of organic material 

(e.g., peat moss, straw), chemical treatment, additional disking of the soil or soil 

and absorbent material removal if the soil and/or absorbent material within the 

spill area cannot meet the TPH standard specified in sub-paragraph (c)(4)(C) 

above.

I) Contaminated soils removed from the site for off-site disposal shall be disposed 

of at an Arkansas Department of Environmental Quality permitted landfill 

permitted to receive such waste other ADEQ permitted surface waste treatment 

or disposal facility or as required by applicable state law or regulation.

5) If a spill enters a public road ditch, visible crude oil-contaminated soil shall be removed 

from the roadside ditch and: 

A) removed from the site in accordance with sub-paragraph (c)(4)(I) above; or

B) incorporated into the non-road ditch area of the spill and remediated in 

accordance with sub-paragraph (c)(4)(A) thru (E) above.

6) The Permit Holder shall be required to submit on request, or within 15 days after the spill 

occurred, on a form prescribed by the Director, the following information:

A) a topographic map showing the areal extent of the spill and the proximity of 

surface waters;

B) the type of soil and current land use;

C) the TPH content in the spill area;

D) explanation of the cause of the spill, and planned efforts to prevent and minimize 

the effects of future spills at the site.

E) Additional reports are required each 90 days until the spill remediation is 

completed and approved by the Director.

7) The Commission after notice and hearing shall have the authority to amend the above 

remediation methodology, or approve alternative remediation methodologies if those 

methods achieve the same or higher standard of spill remediation. 

d) Produced Water Spill Remediation Requirements

1) All spills of produced water, which occur after the effective date of this rule, from wells, 

flowlines, pits, tanks or containment dikes, shall immediately, but not more than 24 hours 

be contained using earthen dikes and other containment measures to minimize the amount 

of area affected by the spill.
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99

2) All impounded produced water shall be picked up and removed from the site for disposal 

into an approved Class II UIC well, or recycled through the Permit Holder’s production 

process.

3) The affected area shall be limed with at least 50 lbs. of agricultural grade lime per 100 

square feet of affected area and tilled to a depth of at least 4 inches.

4) Based on the quantity and areal extent of the produced water spill, the proximity of the 

spill area to surface water features, the nature of the soil and land use of the area and any 

impact to public safety, the Director may require additional remediation action to be 

taken by the Permit Holder. These additional actions may include flushing of the area 

with freshwater (which shall be collected and disposed in a permitted Class II well), the 

addition of organic material (e.g., peat moss, hay, straw), additional chemical treatment, 

additional disking the soil, or soil removal. The operator shall be required to continue 

these corrective actions until the spill remediation efforts are deemed complete by the 

Director based on site specific conditions.

(Source: 1991 rule book; amended September 17, 2007)
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RULE B-35: DETERMINING AND NAMING COMMON SOURCES OF SUPPLY

Wells shall be classified as to the common sources of supply from which they produce and common 

sources of supply shall be determined and named by the Commission, provided, that in the event any 

person is dissatisfied with any such classification or determination, an application may be made to the 

Commission for such classification or determination, deemed proper and the Commission will hear and 

determine the same.

In naming the common sources of supply, preference shall be given to common usage and geographical 

names. Separate common sources of supply within the same area shall preferably be named according to 

the producing formation.

(Source: 1991 rule book)
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101

RULE B-36: TAKINGS TO BE RATABLE

Every person, now or hereafter engaged in the business of purchasing and selling crude oil or natural gas 

in this State, shall purchase, without discrimination in favor of one producer against another, or in favor 

of any one source of supply as against another. For purposes hereof, a distinction shall exist between 

“crude oil” and “natural gas” purchased from “oil wells” and “gas wells” as those wells are respectively 

defined within Rule A-4 and takings shall be deemed to be ratable when purchases are made without 

discrimination between wells within each such separate classification.

(Source: 1991 rule book)
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RULE B-37: DUAL COMPLETION OF WELLS

a) A Permit Holder may elect to complete a well in such a manner as to permit the production of 

oil or gas from one formation through the tubing and oil or gas from a separate formation through 

the annular space between the tubing and casing, subject to the following conditions:

1) That each well dually completed shall be regarded as a separate and distinct Well; and

2) That the production shall be taken and measured separately; and

3) That all rules, regulations and orders governing individual oil or gas wells shall be strictly 

adhered to.

b) A Permit Holder may file an application with the Director to complete a gas well for production 

of dry gas from a formation through the annular space between the production casing and the 

surface casing, provided the following conditions are met:

1) Each application shall be made on a form prescribed by the Director and shall include 

proof of written notice to all offset operators or owners, as defined in Ark. Code Ann. § 

15-72-109, in governmental sections that are contiguous to the lease upon which 

uncontrolled gas is to be produced; or if controlled, then proof to all offset operators or 

owners, as defined in Ark. Code Ann. § 15-72-109, having the right to produce from the 

same shallow formation in the adjacent governmental sections. 

2) Surface casing in the subject well has been set and cemented to a depth of as required by 

General Rule B-15; and

3) The proposed zone to be produced would otherwise not be economic due to limited 

production potential.

4) Any offset operator or owner noticed in accordance with subparagraph (b)(1) above shall 

have the right to object to the granting of such application within fifteen (15) days after 

receipt of the application by the Commission.

5) If an objection is received within fifteen (15) days after receipt of the application by the 

Commission, or if the Permit Holder does not satisfy all requirements of this paragraph 

(b), the application shall be denied. If an application is denied the Permit Holder may 

request to have the matter placed, in accordance with established procedures, on the 

docket of a regularly scheduled Commission hearing.

6) If no objection is received by the Commission within fifteen (15) days after receipt of the 

application by the Commission, and the Permit Holder is in compliance with all

requirements of this paragraph (b), the application shall be approved.

(Source: 1991 rule book; amended December 16, 2007)
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RULE B-38: ESTABLISHMENT OF FIELD RULES

a) An application for the purpose of establishing field rules, regulations, and well spacing and 

drilling units for a new reservoir or pool, except within the covered lands specified in General 

Rule B-43 or General Rule B-44, shall be submitted, in accordance with General Rules A-2, A-3, 

and applicable hearing procedures, to the Commission within six months after the initial 

completion of the discovery well in a pool or reservoir or after the drilling of three wells, 

whichever occurs first. Prior to receipt of an application, no further permits to drill more than 

three wells in the same source of supply in the exploratory area as defined by the Director shall be 

issued.

b) Upon receipt by the Commission of an application for public hearing to establish field rules, 

regulations, well spacing, and drilling units for a reservoir, additional permits beyond the initial 

three wells may be issued to that reservoir or pool, provided the well permit applications comply 

with the drilling unit size and well location provision as contained in the application. Permits 

may continue to be issued until a hearing is held and a decision rendered.

c) The Commission may, after notice and hearing in accordance with General Rule A-2, A-3 and 

other applicable hearing procedures, grant exceptions to this rule, provided such exceptions will 

create neither waste nor hazards conducive to waste.

(Source: 1991 rule book; amended September 16, 2006; amended August 17, 2008)
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RULE B-39: PRE-HEARING CONFERENCE REQUIRED FOR PROPOSED FIELDWIDE UNITIZATIONS

Prior to the filing of a Petition for a public hearing to consider the need for the operation as a unit of an 

entire pool, or any portion thereof, pursuant to the provisions of Acts 1951, No. 134, the petitioner shall 

have a pre-hearing conference with the Commission (or its delegated representatives) for purposes of 

reviewing the proposed plan of unitization including the information required by Subsection C-1 Ark. 

Stats. 53-115 together with those additional proposed provisions and geological and engineering data 

which the Commission determines to be appropriate for preliminary review before the execution of the 

Unit Agreement in order to prevent waste and protect the correlative rights of all interested parties.

(Source: 1991 rule book)
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105

RULE B-40: AUTHORIZATION FOR DIRECTOR OF PRODUCTION AND 

CONSERVATION TO ADMINISTRATIVELY APPROVE APPLICATIONS FOR 

EXCEPTIONAL WELL LOCATIONS

a) The Director of Production and Conservation or his designee is authorized to issue a Drilling 

Permit for a well proposed to be drilled, is being drilled, or has been drilled, but prior to

commencement of production, at a location within an established drilling unit, which fails to 

conform to the drilling unit setback distance requirements as measured from the approximate 

center of the wellbore to unit boundary lines under applicable field rules or Commission general 

rules. This rule is only applicable: 

(1) To dry gas wells drilled vertically or directionally and does not apply to any type of dry 

gas well drilled as a wildcat well, as defined in General Rule B-3, or for dry gas wells 

drilled in Exploratory Units established by Commission order; or

(2) To oil or gas condensate wells drilled in standard drilling units from which the well 

setbacks are defined by distance from a drilling unit boundary defined by a legal land 

description and does not apply to drilling units where well setbacks are established by 

other methods, or for wildcat wells or for wells in Exploratory Units established by the 

Commission; or

(3) To oil wells located in uncontrolled fields where the standard well setback as specified in 

General Rule B-3, apply to lease lines rather than drilling unit lines.

b) In each such instance in which a permit is issued, except in uncontrolled fields which are not 

subject to an allowable, a reduction (penalty) in the allowable to which such well would 

otherwise be entitled, under the provisions of the applicable field rules or other general well 

spacing rules, shall be assessed by multiplying a fraction, the numerator of which shall be the 

distance expressed in feet between the location of such proposed well and the boundary of the 

drilling unit in which the well is to be drilled and the denominator of which shall be the distance 

expressed in feet at which wells within such field and/or drilling unit are otherwise required to be 

located. If the proposed location encroaches upon more than one boundary of said unit, then the 

penalty to be imposed upon the production allowable shall be cumulative of the penalties from 

both boundaries as described in sub section 1) below.

1) If the proposed location encroaches upon more than one boundary as specified in section 

(b) above, the reduction in the allowable shall be calculated as follows:

First boundary encroachment expressed as:

setback footage specified by rule (minus)(-) actual footage of proposed well from unit boundary (divided by)(÷)

setback footage specified by rule, plus (+)

Second boundary encroachment expressed as:

setback footage specified by rule (minus)(–) actual footage of proposed well from unit boundary (divided by)(÷)

setback footage specified by rule = penalty factor

Then:

penalty factor (x) full calculated allowable (MCF or bbl) = amount allowable reduced (MCF or bbl)

Then:
GENERAL RULES AND REGULATIONS

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full calculated allowable (MCF or bbl) (minus)(–) amount allowable reduced (MCF or bbl) = production 

allowable (MCF or bbl)

2) Each such application for an exceptional location shall be submitted on a form prescribed 

by the Director of Production and Conservation, accompanied by an application fee of 

$500.00 and include the name and address of each owner, as defined in A.C.A. § 15-72-

102(9), within the drilling unit in which the proposed well is to be drilled and within the 

drilling units offsetting the boundary line or lines, or in the case of wells in uncontrolled 

fields within the boundaries of mineral lease lines and the offsetting lease(s), which shall 

be encroached upon by the proposed exceptional well location. 

3) Concurrently with the filing of an application in accordance with this rule, the applicant 

shall send to each owner specified in sub-section 2) above a notice of the application 

filing and verify such mailing by affidavit, setting out the names and addresses of all 

owners and the date(s) of mailing.

4) Any owner noticed in accordance with sub-section 2) shall have the right to object to the 

granting of such application within fifteen (15) days after the receipt of the application by 

the Commission. Each objection must be made in writing and filed with the Director. If 

a timely written objection is filed as herein provided, then the applicant shall be promptly 

furnished a copy of such objection and the application shall be denied. If the application 

is denied under this subsection, the applicant may request to have the application placed, 

in accordance with General Rule A-2, A-3, and other applicable hearing procedures, on 

the docket of a regularly scheduled Commission hearing for a Commission 

determination, except that no additional application fee is required.

5) An application may be referred to the Commission for determination when the Director: 

(1) deems the penalty to be imposed upon the allowable for such well, calculated as 

herein provided, to be inadequate to offset any advantage which the applicant may have 

over any other producer, as defined in A.C.A. § 15-72-102(8), by reason of the drilling of 

the well at such exceptional location, or (2) deems it necessary that the Commission 

make such determination for the purpose of protecting correlative rights of all parties. 

Promptly upon such determination, and not later than fifteen (15) days after receipt of the 

application, the Director shall give the applicant written notice, citing the reason(s) for 

denial of the application under this rule and the referral to the full Commission for 

determination. 

6) Applications for exceptional locations resulting from directional drilling shall be 

considered for administrative approval in accordance with this rule, provided, that no 

allowable shall be authorized until the Commission has been furnished a bottom hole 

directional survey for each common source of supply for which an allowable is requested. 

In all such cases where directional surveys are made available, the distance, of the midpoint perforations, for each common source of supply in a directional well, from the 

drilling unit boundary shall be used in calculating the allowable. 

7) If the Director has not notified the applicant of the determination to refer the application 

to the Commission within the fifteen (15) day period in accordance with the foregoing 

provisions, and if no objection is received at the office of the Commission within the 

fifteen (15) days as provided for in sub-section 4), the application shall be approved and a 

Drilling Permit issued.

c) For dry gas wells, as specified in sub-section a) 1) above, an alternative to a reduction in the 

allowable (penalty) method, as outlines in Section b) above, may be requested if each affected 
GENERAL RULES AND REGULATIONS

107

drilling unit has been previously integrated, by Commission Order or is 100% leased, and is 

currently held by production, and if all the working interest owners in each affected drilling unit 

agree, in writing, to share the proceeds from a well which encroaches upon the drilling unit 

boundary. The below methodology for determining percentages for the sharing of costs, 

production and royalty among the affected drilling units, may be administratively authorized by 

the Director or his designee. The method for determining the percentages for sharing the costs of 

and the proceeds of production from one or more separately metered wells shall be as follows: 

1) For vertical or directionally drilled wells, the acreage within an agreed upon area

extending out from the perforated internal, as defined in General Rule B-3, shall be 

calculated for each such separately metered well (the “calculated area”). The calculated 

area shall be based upon the estimated drainage area of the perforated interval. 

2) Each calculated area shall be allocated and assigned to each drilling unit according to that 

portion of the calculated area occurring within each drilling unit.

3) Each such application for utilizing the above methodology shall be submitted on a form 

prescribed by the Director of Production and Conservation, accompanied by an 

application fee of $500.00 and include the name and address of each owner, as defined in 

A.C.A. § 15-72-102(9), within each of the drilling units in which the proposed well is to 

be drilled and/or completed and which contains a portion of the calculated area as defined 

in sub-section c) 1) above.

4) Concurrently with the filing of an application utilizing the above methodology, the 

applicant shall send in written authorization from each owner specified in sub-section c) 

3) above. 

5) An application may be referred to the Commission for determination when the Director 

deems it necessary that the Commission make such determination for the purpose of 

protecting correlative rights of all parties. Promptly upon such determination, and not 

later than fifteen (15) days after receipt of the application, the Director shall give the 

applicant written notice, citing the reason(s) for denial of the application under this rule 

and the referral to the full Commission for determination. 

6) If the Director has not notified the applicant of the determination to refer the application 

to the Commission within the fifteen (15) day period in accordance with the foregoing 

provisions, and if no objection is received at the office of the Commission within the 

fifteen (15) days as provided for in subsection (c)(5), the application shall be approved 

and a drilling permit issued.

7) Upon receipt of the drilling permit, the applicant shall give the other working interest 

parties written notice that the drilling permit has been issued. The working interest 

parties, who have not previously made an election, shall have fifteen (15) days after 

receipt of said notice within which to make an election to participate in the well or be 

deemed as electing non-consent and subject to the non-consent penalty set out in the 

existing Joint Operating Agreement(s) covering their respective drilling unit.

8) Following completion of the well and prior to the issuance by the Commission of the 

Certificate of Compliance to commence production, the final location of the perforated 

interval shall be submitted to the Commission to verify the proposed portion of the 

calculated area occurring within each drilling unit as specified in sub-section c) 1) above.
GENERAL RULES AND REGULATIONS

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(Source: 1991 rule book; amended (Order 1-94(4)) January 25, 1994; amended July 17, 2006; amended 

December 16, 2007; amended August 17, 2008)
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RULE B-41: RULE FOR OPERATION IN HYDROGEN SULFIDE (H2S) AREAS

Each operator who conducts operations in known areas of Hydrogen Sulfide (H2S) with minimum 

concentrations of fifteen (15) ppm under atmospheric conditions or one hundred (100) ppm or more in the 

gas stream shall provide safeguards to protect the general public from the harmful effects of Hydrogen 

Sulfide (H2S). The Director of the Arkansas Oil and Gas Commission shall determine the areas covered 

by this rule.

Operations shall include drilling, completion, workover, producing, gathering, and storage of hydrocarbon 

fluids, natural gas and fluids produced in association with Bromine extraction. These operations fall 

under these guidelines only if they contain gas in the system which has Hydrogen Sulfide (H2S) as a 

constituent of the gas.

DEFINITIONS

Radius of Exposure shall mean that radius constructed with the point of escape as its starting point and 

its length calculated as provided for in General Provisions D.

Area of Exposure shall mean the area within a circle constructed with the point of escape as its center 

and the radius of exposure as its radius.

Public Area shall mean a dwelling, place of business, church, school, hospital, school bus stop, 

governmental building, a public road, all or any portion of a park, town, city, village, or other similar area 

that can be populated at any given time.

Public Road shall mean any federal, state, county, or municipal street or road owned or maintained for 

public access or use.

Contingency Plan shall mean a written document that shall provide 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 hydrogen sulfide.

I. GENERAL PROVISIONS

A. Each operator shall determine the Hydrogen Sulfide (H2S) concentration in the gaseous mixture 

in an operation or system. Test of vapor accumulation in storage tanks may be made with 

industry accepted colormetric tubes.

B. Each operator shall immediately notify the Arkansas Oil and Gas Commission of any accidental 

release of Hydrogen Sulfide (H2S) gas which measures 15 ppm or greater from any point on a 

radius which exceeds 100 feet from the point of release, or includes any portion of a public area. 

Such notification shall be followed by a written report which shall be sent to the Commission 

within ten (10) days of the incident.

C. Each operator shall notify the AOGC before conducting any well servicing activity on any well(s) 

operated under the provisions of this rule.

D. For all operations subject to a radius of exposure (ROE), that radius shall be determined by the 

following Pasquill-Gifford Equations

 

1. ROE = 100 ppm X = [(1.589)(mole fraction of H2S)(Q)].6258

2. ROE = 500 ppm X = [(0.4546)(mole fraction of H2S)(Q)].6258
GENERAL RULES AND REGULATIONS

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Where X = radius of exposure in feet

 H2S = mole fraction of hydrogen sulfide in the gaseous mixture established by 

an industry accepted method.

 Q =maximum volume of escapable gas in cubic feet per day.

For drilling of a well where insufficient data exist to calculate a ROE, but where Hydrogen 

Sulfide may be expected, then a radius of exposure shall be three thousand (3000) feet. A lesser -

assumed radius may be considered upon written request setting out the justification for same.

E. Wind indicators shall be installed at strategic locations on or near the drilling, workover, or 

production facility to indicate the wind direction at all times and the safe upwind areas in the 

event Hydrogen Sulfide becomes present.

II. STORAGE TANK PROVISIONS

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 (H2S) concentration in 

excess of 100 ppm, shall be subject to the following:

A. No determination of a radius of exposure shall be made for storage tanks as herein described.

B. A warning sign shall be posted on or within fifty (50) feet of the facility to alert the general 

public of the potential danger.

C. All tank hatches shall be kept closed at all times except for when it is necessary to inspect or 

gauge such tanks. All storage tanks that are not fenced as required in (D.) below are required to 

be kept secured by lock the hatches on all such tanks when not being inspected or gauged.

D. Entry should be restricted to essential personnel only. As a security measure, fencing is required 

when storage tanks are inside the limits of a city, townsite or are reasonably exposed to the 

public. All means of entry shall be locked when the facility is unattended.

E. All H2S fumes and vapors shall be either recovered by a vapor recovery unit, flared through a 

flare stack with a permanent pilot attached thereon or on a case by case basis vented by permit 

only. Permits to vent will be reviewed with respect to the distance to the nearest public receptor, 

the concentration of H2S gas and the volume to be released.

III. WARNING AND MARKER PROVISION

A. A warning sign shall be maintained on all streets or roads which provide access to the facility.

B. Marker signs shall be installed along the pipeline when it is located within a public area and at 

each public road crossing 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.

C. The marker sign shall contain sufficient information to establish the ownership and existence of 

the line and shall indicate by the use of the words: “Poison Gas” that a potential danger exists.

D. In satisfying the sign requirement, the following will be acceptable:

1. Sign of sufficient size to be readable at a reasonable distance from the facility.
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2. Existing signs installed prior to the effective date of this section will be acceptable if they 

indicate the existence of a potential hazard.

IV. CONTROL AND EQUIPMENT SAFETY PROVISION

Operators subject to this provision shall install safety devices and maintain them in an operable 

condition and shall establish safety procedures designed to prevent the undetected continuing escape 

of Hydrogen Sulfide (H2S). Safety devices should be tested annually and a record of each test 

maintained.

V. DRILLING AND WORKOVER PROVISIONS

A. A certificate of compliance form (HS-1) must be filed with each intent to drill a well in an area 

and to a depth known to or that may contain Hydrogen Sulfide Gas.

B. Drilling operations are required to be in compliance with the provisions of the rule when the 

drilled depth is within 1,000 feet of a zone known to or that may contain Hydrogen Sulfide. A 

variance from the compliance depth may be approved upon written request setting out 

justification, however the compliance depth will not be less than 500 feet.

C. Protective breathing equipment shall be maintained for all personnel at the site.

D. As a minimum, hydrogen sulfide sensors for drilling or workover rigs shall be located at the rig 

floor, bell nipple, shale shaker and mud pits unless otherwise approved by the Director. 

E. Blowout preventers and well control systems shall be pressure tested initially either to a minimum 

of 3,000 psig or to 75% of the internal yield (burst) pressure taken from the API casing properties 

table for the size and grade of casing being used, whichever is less. Thereafter, all well control 

systems shall be tested prior to reaching compliance depth. The Oil and Gas Commission shall be 

notified at least four (4) hours prior to the initial “Blowout Preventer and Well Control System 

Test”. The Commission shall have the authority to vary test procedures as is deemed necessary.

F. Secondary remote control of blowout prevention and choke equipment shall be located away 

from the rig floor at a safe distance from the wellhead.

G. The operator shall install a choke manifold, mud-gas separator and flare line, and provide a 

suitable method for lighting the flare.

H. Drill Stem Testing:

1. Drill stem testing of Hydrogen Sulfide (H2S) zones is permitted only in daylight hours.

2. The Oil and Gas Commission shall be notified a minimum of 12 hours in advance of the 

intention to conduct a drill stem test of a formation containing Hydrogen Sulfide (H2S). In 

the event that Hydrogen Sulfide (H2S) is anticipated during the drill stem test, all testing and 

safety equipment shall be on location for use as deemed necessary by the Commission.

3. All gas produced from the test shall be flared through a flare system with a pilot and an 

automatic igniter.

4. Every precaution should be made not to affect the public during the well test. In the event, 

residents are within the Radius of Exposure or may be affected by a Drill Stem Test, the 

operator should contact those residents and inform them of the pending action. Special 

consideration should be given residents with children and/or medical ailments.
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112

I. A supervisory employee or safety company representative that is specifically trained in the 

operation, maintenance, and testing of all safety equipment and is knowledgeable of the 

contingency plan and safety procedures must be on site from the compliance depth through the 

cementing of the long string (production) casing and during the time in which the actual 

completion work is being performed on the well.

J. API Publication RP-49 and RP-68 is referenced as a suggested guideline for drilling and 

workover of wells subject to the provision.

VI. CONTINGENCY PLAN PROVISION

A. All operators whose operations are subject to this provision shall develop a written contingency 

plan complete with all requirements before Hydrogen Sulfide (H2S) operations are begun.

B. The purpose of the contingency plan shall be to provide an organized plan of action for alerting 

and protecting the public following the accidental release of a potentially hazardous volume of 

Hydrogen Sulfide (H2S).

C. The contingency plan shall be activated immediately upon the detection of an accidental release 

of Hydrogen Sulfide (H2S) which exceeds fifteen (15) ppm or greater from any point on a radius 

which exceeds 100 feet from the point of release, or includes any portion of a public area.

D. Conditions that might exist in each area of exposure shall be considered when preparing a 

contingency plan.

E. The plan shall include instructions and procedures for alerting the general public and public 

safety personnel of the existence of an emergency.

F. The plan shall include a procedure for requesting assistance and for follow-up action to evacuate 

the public from an area of exposure.

G. The plan shall include a call list which will include the following as they may be applicable:

1. Local supervisory personnel

2. Arkansas Oil and Gas Commission

3. County Sheriff

4. State Police

5. Ambulance Service

6. Hospital

7. Fire Department

8. Contractors for supplemental equipment

9. Office of Emergency Services

10. Other public agencies as needed
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H. The plan shall include a plat detailing the area of exposure. The plat shall include the locations of 

private dwellings, 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. A separate list of all phone numbers should be attached to the plat.

I. A schematic of the facility indicating all equipment on location should be included.

J. The Oil and Gas Commission shall be notified immediately if the contingency plan is activated.

K. The retention of the contingency plan shall be as follows: 

1. The plan shall be available for Commission inspection at the well location.

2. The plan shall be retained at the location which lends itself best to activation of the plan.

L. The plan shall be kept updated to insure its current applicability. Each plan must be reviewed and 

updated annually and a copy of the updated plan submitted to the Commission in January of each 

calendar year.

VII. TRAINING PROVISION

Each operator and contractor shall provide appropriate Hydrogen Sulfide (H2S) training for its employees 

who will be on-site. All personnel must have in their possession, current proof of annual training. This 

training should include the following:

1. Hazards and characteristics of Hydrogen Sulfide (H2S).

2. Operations of safety equipment and life support systems.

3. First aid in the event of an employee exposure.

4. Use and operation of Hydrogen Sulfide (H2S) monitoring equipment.

5. Emergency response procedures to include corrective actions, shutdown procedures, 

evacuation routes and rescue methods.

(Source: 1991 rule book)
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RULE B-42: SEISMIC RULES AND REGULATIONS

(a) Definitions:

1. “Field Seismic Operations” shall mean any geophysical method performed on the surface 

of the land utilizing certain instruments operating under the laws of physics respecting 

vibration or sound to determine conditions below the surface of the earth which may 

contain oil or gas and is inclusive of but not limited to the preliminary line survey, the 

acquisition of necessary permits, the selection and marking of shot-hole locations, 

necessary clearing of vegetation, shot-hole drilling, implantation of charge, placement of 

geophones, detonation and backfill of shot-holes. 

2. “Seismic Shoot” shall mean a specific project during which field seismic operations shall 

be conducted with due diligence, not to exceed or substantially vary from those seismic 

operations indicated in the original permit application. 

(b) Any person desiring to perform field seismic operations within the State of Arkansas shall obtain 

a permit for each seismic shoot from the Commission prior to commencing field seismic 

operations. A copy of the approved permit shall be maintained in the central recording unit used 

for the seismic shoot. Such permit shall be valid for a period of one year from the date of 

issuance.

(c) The applicant shall make application on a form prescribed by the Director. 

(d) Each application as filed shall be accompanied by an application fee of Five Hundred Dollars 

($500.00). 

(e) Each application for a 2D seismic shoot shall include information and maps, (i) to identify the 

seismic shoot area, (ii) to indicate the proposed location of all 2D seismic lines, and (iii) to 

designate an area (each, a “2D Seismic Line Corridor” within which a 2D seismic line may be 

located or relocated by permitee). No 2D Seismic Line Corridor shall extend farther than one-half 

(1/2) mile in either direction from the proposed location of the relevant 2D seismic line. 

Applicants may omit areas within the outer boundaries of any 2D Seismic Line Corridor from the 

2D Seismic Line Corridor. Each application for a 3D seismic shoot shall include information and 

maps to identify the seismic shoot area including the 3D project outline for such seismic shoot. 

Any relocations of a 2D seismic line or any portion thereof outside the 2D Seismic Line Corridor 

designated therefore or any increase in a 3D survey outline shall be immediately reported to the 

Director. The applicant shall also be required to file an amended application showing the revised 

location of such relocated 2D seismic lines, if applicable. The applicant may also file a request, in 

writing, that the application with all information and maps, be kept confidential for a period not to 

exceed twelve (12) months from the date of the filing of the original application. Subject to any 

applicable exceptions, including without limitation the trade secret exception to the general 

requirements of Ark. Code Ann. (1987) § 25-19-101 et. seq., said application and any information 

and maps submitted may be released to the extent required by a court of law or by applicable state 

law, regardless of the request that such be kept confidential. Said application and any 

information and maps may also be introduced by the Commission as evidence in any public 

hearing before the Commission or in any judicial action, regardless of such request; provided, 

however, that permit holder shall retain the right to object to their admissibility and to seek a 

closed hearing or a protective order with respect thereto. 

(f) The application shall be accompanied with evidence of the appropriate type(s) of financial 

assurance, as described in General Rule B-2 (d)(1), (2), (3) and (4), and subject to those 

conditions listed therein. 
GENERAL RULES AND REGULATIONS

115

1. The financial assurance shall be at least fifty thousand dollars ($50,000), but not more 

than two hundred fifty thousand dollars ($250,000), provided that the aggregate amount 

of financial assurance required for any applicant for all permits and expired permits 

issued pursuant to this Rule shall not exceed two hundred fifty thousand dollars 

($250,000).

2. The amount of the financial assurance shall be determined by the Director based on, but 

not limited to, the proximity of the seismic shoot to populated areas, cultural features, 

sensitive environmental areas, and past Commission enforcement history against the 

applicant.

3. The financial assurance required to be filed shall remain in effect for one year following 

the conclusion of all field seismic operations by the permit holder in the State of 

Arkansas.

(g) Upon review of a completed permit application, the Director shall either issue the permit or deny 

the permit application. If the permit application is denied, the applicant may file an application 

for a hearing to appeal the Director’s decision in accordance with General Rule A-2, A-3, and 

other applicable hearing procedures. 

(h) No entry shall be made by any person to conduct field seismic operations, upon the lands where 

such field seismic operations are to be conducted, without the permit holder having first given 

notice at least ten (10) calendar days prior to commencement of field seismic operations.

1. The notice shall be in writing and given either personally or by certified United States 

mail to the surface owners reflected in the tax records of the counties where the lands are 

located, at the mailing addresses identified for such surface owners in such records

2. In instances where it can be reasonably ascertained that there are occupants residing on 

the lands who are not the surface owners, such notice shall also be given such occupants, 

unless there is no known mailing address and personal notice cannot reasonably be given. 

Any such notice to an occupant shall be deemed delivered if delivered personally or 

deposited in the United States mail postage prepaid to said occupants at the mailing 

address of the lands.

3. Written notice shall also be given either personally or by certified United States mail to 

operators, as reflected in the records of the AOGC, of producing wells within the seismic 

shoot area, at the mailing addresses identified for such operators in said records. 

4. The notice shall contain the:

A. Name of the person or entity that is conducting the field seismic operations;

B. Proposed location of the field seismic operations; and

C. Approximate date the person or entity proposes to commence field seismic 

operations;

(i) The permit holder shall also notify the Commission within five (5) business days of the 

commencement and completion of each seismic shoot.
GENERAL RULES AND REGULATIONS

116

(j) All vehicles utilized by the permit holder, or its agents or contractors, shall be clearly identified 

by signs or markings, utilizing letters and /or numbers a minimum of three (3) inches in height 

and one-half (1/2) inch wide, indicating the name of such agent. 

(k) No shot-hole shall be drilled nor charge detonated within two hundred feet (200’) of any 

residence, water well, oil well, gas well, brine well, injection well or other structure without 

having first secured the express written authority of the owner(s) thereof and the permit holder 

shall be responsible for any resulting damages in accordance with this rule. Written authority 

must also be obtained from the owner(s) if any charge exceeds the maximum allowable charge 

within the scaled distance below:

MAXIMUM

 ALLOWABLE

DISTANCE TO CHARGE

STRUCTURE (FT)* WEIGHTS (LBS)*

50 0.5

100 2.0

150 4.5

200 8.0

250 12.0

300 18.0

350 25.0

* Based upon a charge weight of seventy (70) FT/LB 1⁄2

(l) The maximum allowable charge weight (lbs.) is 25.0, unless the permit holder requests and 

secures the prior written authorization from the Director.

(m) All holes drilled for field seismic activity shall be properly back filled with soils and/or other 

suitable material and tamped. A mound may be left over the hole for settling allowance.

(n) All seismic sources placed for detonation for use in field seismic operations shall contain 

additives to accelerate the biodegradation thereof and shall be handled with due care in 

accordance with industry standards. The cap leads for any seismic sources that fail to detonate 

shall be buried at least three (3) feet deep.

(o) All vegetation cleared to the ground for the purposes of field seismic activity shall be cleared in a 

competent and workmanlike manner in the exercise of due care.

(p) Unless otherwise consented to by the surface owner in writing, permit holder shall not cut down 

any tree measuring six (6) inches or more in diameter, as measured at a height of three (3) feet 

from the ground surface unless there are no reasonable alternatives to the removal of such tree(s) 

available to permit holder. Permit holder shall compensate surface owner the value of all such 

trees as determined by a forester licensed by the State of Arkansas.

(q) All excessive rutting or soil disturbances resulting from seismic activity shall be repaired or 

restored to the original condition and contour to the extent reasonable, unless otherwise agreed to 

by the permit holder and the surface owner in writing.

(r) All fences removed for the purposes of field seismic activity shall be replaced, unless otherwise 

agreed to by the permit holder and the surface owner in writing.

(s) All debris associated with the seismic activity shall be removed and properly disposed.
GENERAL RULES AND REGULATIONS

117

(t) Any person who conducts any field seismic operations for a seismic shoot in the state without 

having obtained a permit therefore shall be subject to a civil penalty of one thousand dollars 

($1,000) for each day such field seismic operations continue. Any person who does not fully 

comply with any other provision of this rule shall be subject to a civil penalty of one thousand 

dollars ($1,000) for each violation.

(u) Failure to comply with the provisions of this rule or Ark. Code Ann. (1987) § 15-71-114 as 

amended or any other applicable orders, rules, or regulations of the Commission may result in the 

forfeiture of the financial assurance to remediate damages or recover civil penalties assessed in 

accordance with subparagraph (t) above. 

(v) In addition, any surface owner may seek to recover damages from the financial assurance, as 

follows:

1. Any surface owner seeking to recover under such financial assurance for damages caused 

by the performance of such field seismic operations must file written notice of claim, on a 

form prescribed by the Director, within one (1) year of the date of expiration of the 

permit; provided however, that such claim shall be subordinate to the rights of the 

Commission.

2. Any claim received from a surface owner shall be investigated by the Director and a 

decision shall be rendered by the Director. If the Director’s decision is not satisfactory to 

either the surface owner or the permit holder, either party may file an application for a 

hearing to appeal the Director’s decision in accordance with General Rule A-2, A-3, and 

other applicable hearing procedures. At a hearing, the surface owner must prove that (a) 

actual damages occurred, (b) such damages were caused by (i) the negligence of the 

permit holder, (ii) a violation of this rule by permit holder or (iii) an unreasonable or 

excessive use of the surface owner’s land by the permit holder under the applicable oil 

and gas lease or other agreement under which the surface owner and/or mineral owner 

consents to the use of the surface for seismic operations, and (c) the amount of such 

damages.

3. If the Commission finds that the permit holder is liable to the surface owner for any such 

damages, the permit holder shall have 30 days from the effective date of the order to pay 

the surface owner the amount specified by the Commission. If the permit holder fails to 

pay the amount specified by the Commission to the surface owner, the Director may 

initiate bond forfeiture proceedings as described in General Rule B-2 (k) to pay damages 

specified by the Commission, provided however, that such amount shall be subordinate to 

the rights of the Commission. 

4. If the permit holder’s financial assurance is forfeited, the permit holder shall cease all 

field seismic operations until another bond in the same amount of the original bond is 

filed with the Commission for the same purposes as the original bond.

(Source: 1991 rule book; amended July 3, 2003; amended June 15, 2008)
GENERAL RULES AND REGULATIONS

118

RULE B-43: ESTABLISHMENT OF DRILLING UNITS FOR GAS PRODUCTION 

FROM CONVENTIONAL AND UNCONVENTIONAL SOURCES OF SUPPLY 

OCCURRING IN CERTAIN PROSPECTIVE AREAS NOT COVERED BY FIELD 

RULES

(a) For purposes of this rule, unconventional sources of supply shall mean those common sources of 

supply that are identified as the Fayetteville Shale, the Moorefield Shale, and the Chattanooga 

Shale Formations, or their stratigraphic shale equivalents, as described in published stratigraphic 

nomenclature recognized by the Arkansas Geological Survey or the United States Geological 

Survey.

(b) For purposes of this rule, conventional sources of supply shall mean all common sources of 

supply that are not defined as unconventional sources of supply in section (a) above.

(c) This rule is applicable to all occurrences of conventional and unconventional sources of supply in 

Arkansas, Cleburne, Conway, Cross, Faulkner, Independence, Jackson, Lee, Lonoke, Monroe, 

Phillips, Prairie, St. Francis, Stone, Van Buren, White and Woodruff Counties, Arkansas and 

shall be called the “section (c) lands”. The development of the conventional and unconventional 

sources of supply within the section (c) lands shall be subject to the provisions of this rule.

(d) This rule is further applicable to all occurrences of unconventional sources of supply in Crawford, 

Franklin, Johnson, and Pope Counties, Arkansas and shall be called the “section (d) lands”. The 

development of the unconventional sources of supply within the section (d) lands shall be subject 

to the provisions of this rule. For purposes of this rule, the section (d) lands and the section (c) 

lands may collectively be referred to as the “covered lands”.

(e) All Commission approved Fayetteville Shale and non-Fayetteville Shale fields that are situated 

within the section (c) lands and that are in existence on the date this rule is adopted (collectively, 

the “existing fields”), are abolished and the lands heretofore included within the existing fields 

are included within the section (c) lands governed by this rule. Further, all amendments that 

added the Fayetteville Shale Formation to previously established fields for conventional sources 

of supply occurring in the section (d) lands are abolished and continuing development of the 

Fayetteville Shale and other unconventional sources of supply in these lands shall be governed by 

the provisions of this rule. All existing individual drilling units however, contained within the 

abolished fields shall remain intact.

(f) All drilling units established for conventional and unconventional sources of supply within the 

section (c) lands and all drilling units established for unconventional sources of supply within the 

section (d) lands shall be comprised of single governmental sections, typically containing an area 

of approximately 640 acres in size. Each drilling unit shall be characterized as either an 

“exploratory drilling unit” or an “established drilling unit”. An “exploratory drilling unit” shall be 

defined as any drilling unit that is not an established drilling unit. An “established drilling unit” 

shall be defined as any drilling unit that contains a well that has been drilled and completed in a 

conventional or unconventional source of supply (a “subject well”), and for which the operator or 

other person responsible for the conduct of the drilling operation has filed, with the Commission, 

all appropriate documents in accordance with General Rule B-5, and been issued a certificate of 

compliance. Upon the filing of the required well and completion reports for a subject well and 

the issuance of a certificate of compliance with respect thereto, the exploratory drilling unit upon 

which the subject well is located and all contiguous governmental sections shall be automatically 

reclassified as established drilling units.

(g) The filing of an application to integrate separately owned tracts within an exploratory drilling 

unit, as defined in Section (f) above and as contemplated by A.C.A. § 15-72-302(e), is 
GENERAL RULES AND REGULATIONS

119

permissible, provided that one or more persons who collectively own at least an undivided fifty 

percent (50%) interest in the right to drill and produce oil or gas, or both, from the total acreage 

assigned to such exploratory drilling unit support the filing of the application. In determining 

who shall be designated as the operator of the exploratory drilling unit that is being integrated, the 

Commission shall apply the following criteria: 

1) Each integration application shall contain a statement that the applicant has sent written 

notice of its application to integrate the drilling unit to all working interest owners of 

record within such drilling unit. This notice shall contain a well proposal and AFE for 

the initial well and may be sent at the same time the integration application is filed.

2) If any non-applicant working interest owner in the drilling unit owns, or has the written 

support of one or more working interest owners that own, separately or together, at least a 

fifty percent (50%) working interest in the drilling unit, such non-applicant working 

interest owner may (i) object to the applicant being named operator (a “section (g) 

operator challenge”) or (ii) file a competing integration application (a “section (g) 

competing application”) that challenges any aspect of the original integration application 

for such drilling unit. Any contested matter that is limited to a section (g) operator 

challenge shall be heard at the Commission hearing that was originally scheduled for 

such integration application. Any contested matter that involves the filing of a section (g) 

competing application shall be postponed until the next month’s regularly scheduled 

Commission hearing if postponement is requested by either competing applicant.

3) If a party desiring to be named operator of a drilling unit is supported by a majority-ininterest of the total working interest ownership in the drilling unit (the “majority owner”), 

the majority owner shall be designated unit operator.

4) In the event two parties desiring to be named operator own, or have the written support of 

one or more working interest owners that own, exactly, an undivided 50% share of the 

drilling unit and either a section (g) operator challenge is submitted or a section (g) 

competing application is filed, operatorship shall be determined by the Commission, 

based on the factors it deems relevant and the evidence submitted by the parties or as 

otherwise provided by subsequent rule.

5) If the person designated as operator by the Commission in the adjudication of a section 

(g) operator challenge or a section (g) competing application does not commence actual 

drilling operations on the drilling unit within the twelve (12) month period set out in the 

integration order, such operator shall not be entitled to be designated as operator under 

the subsequent integration of such drilling unit unless (i) the operator’s failure to 

commence such drilling operations was due to force majeure, or (ii) a majority-in-interest 

of the total working interest ownership in the drilling unit (excluding such designated 

operator) support such operator.

(h) The filing of an application to integrate separately owned tracts within an established drilling 

unit, as defined in Section (f) above and as contemplated by A.C.A. § 15-72-303 is permissible, 

without a minimum acreage requirement, provided that one or more persons owning an interest in 

the right to drill and produce oil or gas, or both, from the total acreage assigned to such 

established drilling unit requests such integration. In determining who shall be designated as the 

operator of the established drilling unit that is being integrated, the Commission shall apply the 

following criteria:

1) Each integration application shall contain a statement that the applicant has sent written 

notice of its application to integrate the drilling unit to all working interest owners of 
GENERAL RULES AND REGULATIONS

120

record within such drilling unit. This notice shall contain a well proposal and AFE for 

the initial well and may be sent at the same time the integration application is filed.

2) Any non-applicant working interest owner in the drilling unit may object to the applicant 

being named operator (a “section (h) operator challenge”). In addition, if an objecting 

party owns, or has the written support of one or more working interest owners that own, 

separately or together, a larger percentage working interest in the drilling unit than the 

applicant, such objecting party may file a competing integration application (a “section 

(h) competing application”) that challenges any aspect of the original integration 

application for such drilling unit. Any contested matter that is limited to a section (h) 

operator challenge shall be heard at the Commission hearing that was originally 

scheduled for such integration application. Any contested matter that involves the filing 

of a section (h) competing application shall be postponed until the next month’s regularly 

scheduled Commission hearing if postponement is requested by either competing 

applicant.

3) If a party desiring to be named operator of a drilling unit is a majority owner (as defined

in subsection (g)(3) above), the majority owner shall be designated unit operator.

4) If a party desiring to be named operator of a drilling unit is not a majority owner, but is 

supported by the largest percentage interest of the total working interest ownership in the 

drilling unit (the “plurality owner”), there shall be a rebuttable presumption that the 

plurality owner shall be designated unit operator. If a section (h) operator challenge to a 

plurality owner being designated unit operator is submitted by a party that owns, or has 

the written support of one or more owners that own, separately or together, the next 

largest percentage share of the working interest ownership in the drilling unit (the 

“minority owner”), the Commission may designate the minority owner operator if the 

minority owner is able to show that, based on the factors the Commission deems relevant 

and the evidence submitted by the parties, the Commission should designate the minority 

owner as unit operator.

5) If two or more parties that desire to be named operator own, or have the support of one or 

more working interest owners that own, separately or together, the same working interest 

ownership in the drilling unit, operatorship shall be determined by the Commission, 

based on the factors it deems relevant and the evidence submitted by the parties or as 

otherwise provided by subsequent rule.

6) If the person designated as operator by the Commission in the adjudication of a section 

(h) operator challenge or a section (h) competing application does not commence actual 

drilling operations on the drilling unit within the twelve (12) month period set out in the 

integration order, such operator shall not be entitled to be designated operator under the 

subsequent integration of such drilling unit unless (i) the original operator’s failure to 

commence drilling operations on the initial well was due to force majeure, or (ii) a 

majority-in-interest of the total working interest ownership in the drilling unit (excluding 

the original operator) support the original operator.

(i) The well setback from drilling unit boundary lines and spacing between wells, for wells drilled in 

drilling units for unconventional sources of supply within the covered lands are as follows:

1) Each well location (as defined in Section (a)(2) of General Rule B-3) shall be at least 560 

feet from any drilling unit boundary line, unless an exception is granted by the 

Commission after notice and hearing in accordance with General Rules A-2 and A-3, and 

other applicable hearing requirements, or in accordance with paragraph (o) below;
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121

2) The perforated interval of the wellbore shall be at least 560 feet in any direction from 

any other wellbore perforated interval in the same common source of supply that extends 

across or encroaches upon drilling unit boundaries an exception is granted in accordance 

with subparagraph (i)5) below);

3) The perforated interval of the wellbore shall be at least 448 feet in any direction, an 

allowed 20% variance, from all other wellbore perforated intervals in the same common 

source of supply within an established drilling unit, unless an exception is granted in 

accordance with subparagraph (i)5) below);

4) No more than 16 wells may be drilled per unit for each separate unconventional source of 

supply within an established drilling unit unless an exception is granted by the 

Commission after notice and hearing in accordance with General Rules A-2 and A-3, and 

other applicable hearing requirements. For purposes of this subsection only, a well is any 

vertical well, directional well, horizontal well with at a minimum 560 feet of perforated 

interval in the drilling unit, or if a horizontal does not contain a minimum of 560 feet of 

perforated lateral in any one drilling unit, then the horizontal well shall be counted in the 

drilling unit in which the majority of the perforated lateral occurs); and

5) The Director or his designee is authorized to approve an application requesting an 

exception to subsection (i)2) and/or (i)3) administratively, if the following conditions are 

met:

A. Each such application shall be submitted on a form prescribed by the Director of 

Production and Conservation, and include the name and address of each owner, 

as defined in Ark. Code Ann. (1987) § 15-72-102(9), within each of the drilling 

units in which the proposed well is to be drilled and/or completed.

B. Concurrently with the filing of the application for an exceptional location in 

accordance with subsection (i)2) and or (i)3) above, the applicant shall send to all 

owners, as defined in Ark. Code Ann. (1987) § 15-72-102(9), whose mailing 

addresses may reasonably be ascertained, in all affected units, a notice of the 

application’s filing and verify such mailing by affidavit, setting out the names 

and addresses of all owners and the date(s) of mailing. Additionally, if there are 

any owners, as defined in Ark. Code Ann. (1987) § 15-72-102(9), whose 

addresses were not reasonably ascertained and notice was not mailed, then the 

applicant shall also submit proof of publication of such notice in a newspaper of 

general circulation within the county or counties within which all the units are 

located that appeared at least one time no earlier than three (3) days prior to filing 

the application, and no later than five (5) days after filing the application, prior to 

the Director approving the application administratively.

C. Any owner, as defined in Ark. Code Ann. (1987) § 15-72-102(9), so noticed shall 

have the right to object to the granting of such application within fifteen (15) 

days after the receipt of the application by the Commission. Each objection must 

be made in writing and filed with the Director. If a timely written objection is 

filed, then the applicant shall be promptly furnished a copy and such application 

shall be denied, unless the objection is withdrawn within the original fifteen day 

time period after receipt of the application. If the application is denied under this 

section, the applicant may request to have the application referred to the 

Commission for determination in accordance with General Rules A-2 and A-3, 

and other applicable hearing requirements.
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122

D. If no timely objection is received, or if one is received and withdrawn within the 

original fifteen day time period after receipt of the application, the Director is 

authorized to approve the application administratively. 

E. An application may be referred to the Commission for determination when the 

Director deems it necessary that the Commission make such determination for 

the purpose of protecting correlative rights of all parties, in order to prevent 

waste, or for any other reason. Promptly upon such determination, and not later 

than fifteen (15) days after receipt of the application, the Director shall give the 

applicant written notice, citing the reason(s) for referral to the full Commission 

for determination. If the application is referred under this section, the applicant 

shall file a request for a hearing, in accordance with General Rules A-2 and A-3, 

and other applicable hearing requirements, except that no additional filing fee is 

required.

F. If the Applicant has satisfied all applicable provisions, the Director has not 

notified the applicant of the determination to refer the application to the 

Commission within the fifteen (15) day period in accordance with the foregoing 

provisions, and if no objection is received at the office of the Commission within 

the fifteen (15) days as provided for in subsection (i)5)C. above, the application 

shall be approved and a permit issued. 

G. Any such application requesting administrative approval may be granted, 

provided the above criteria is satisfied, prior to the drilling of a well, while a well 

is being drilled, or after a well has been drilled and completed, but prior to 

commencement of production.

 6) Applications for exceptions to these well location provisions, relative to a drilling unit 

boundary or other locations in a common source of supply, may be brought before the 

Commission. 

(j) The well spacing for wells drilled in drilling units for conventional sources of supply within the 

section (c) lands are as follows:

1) Only a single well completion will be permitted to produce from each separate 

conventional source of supply within each established drilling unit, unless additional 

completions are approved in accordance with General Rule D-19;

2) Each well location (as defined in Section (a) 2) of General Rule B-3) shall be at least 

1120 feet from any drilling unit boundary line;

3) Well completions located closer than 1120 feet from all established drilling unit 

boundaries, shall be subject to approval in accordance with General Rule B-40; and

4) Applications for exceptions to these well location provisions, relative to a drilling unit 

boundary or other location in a common source of supply, may be brought before the 

Commission.

(k) The casing programs for all wells drilled in exploratory and established drilling units established 

by this rule and occurring in the covered lands specified by this rule shall be in accordance with 

General Rule B-15.

(l) Wells completed in and producing from only conventional sources of supply, as defined in 

Section (b), shall be subject to the testing provisions of General Rule D-16 and production 
GENERAL RULES AND REGULATIONS

123

allowable provisions of General Rule D-21. Wells completed in and producing from only 

unconventional sources of supply, as defined in Section (a), shall not be subject to the testing 

provisions of General Rule D-16 and allowable provisions of General Rule D-21 There shall be 

no production allowable established for wells producing from unconventional sources of supply 

located within the covered lands. Wells completed in and producing from only unconventional 

sources of supply, within the covered lands, shall report on a form prescribed by the Director, the 

highest twenty-four (24) hour production rate during the first forty (40) days of production, which 

form shall be filed within sixty (60) days of the date of first production from the well.

(m) The commingling of completions for unconventional and/or conventional sources of supply 

within each well situated on an established drilling unit, shall be subject to the provisions and 

approval process outlined in General Rule D-18. If an unconventional source of supply is 

approved to be commingled with a conventional source of supply within a well situated on an 

established drilling unit, the well shall be subject to the production allowable provisions of 

General Rule D-21.

(n) The reporting requirements of General Rule B-5 shall apply to all wells subject to the provisions 

of this rule. In addition, the operator of each such well shall be required to file monthly gas 

production reports in accordance with General Rule D-8.

(o) The Commission specifically retains jurisdiction to consider applications brought before the 

Commission from a majority in interest of all owners, as defined by Ark. Code Ann. (1987) § 15-

72-102(9), in two or more adjoining drilling units seeking the authority to drill, produce and/or 

share the costs of and the proceeds of production from one or more separately metered wells 

that extend across or encroach upon drilling unit boundaries and that are drilled and completed in 

one or more unconventional sources of supply within the covered lands. All such applications 

shall contain a proposed agreement on the formula for the sharing of costs, production and royalty 

from the affected drilling units.

1) Encroaching Wells. If a well encroaches upon but does not cross the drilling unit 

boundary of an adjoining drilling unit (an “encroaching well”), the Commission shall not 

consider the encroached upon drilling unit to be held by production from the encroaching 

well. 

2) Administrative Approval of Wells that Extend Across or Encroach Upon Drilling Unit 

Boundaries. If the majority in interest of all owners, as defined by Ark. Code Ann. (1987) 

§ 15-72-102(9), within each drilling unit agree to share a proposed well, a well that is 

being drilled, or a well which has been drilled, but prior to commencement of production, 

between two or more adjoining drilling units which are all integrated or are 100% leased 

utilizing the below methodology for sharing of costs, production and royalty among the 

affected drilling units, the Director or his designee is authorized to approve the 

application administratively, if the following conditions are met:

A. The application provides proof that:

i) There is at least one well located, as defined in subsection (a)(2) of 

General Rule B-3, at a non-exceptional well location and located entirely 

within each included drilling unit that is producing or capable of 

producing gas; or

ii) Within twelve (12) months following the date the well for which 

administrative approval is granted is spud, there will be at least one well 

located, as defined in subsection (a)(2) of General Rule B-3, at a non-
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124

exceptional well location and located entirely within each included 

drilling unit that is either a well that is producing gas, or a well that is 

capable of producing gas and awaiting connection to a pipeline; or

iii) There is at least one well or a combination of multiple wells, including 

cross unit wells and/or encroaching wells located, as defined in 

subsection (a)(2) of General Rule B-3, within each included drilling unit 

that have a total combined perforated lateral length within the drilling 

unit of not less than 4160 feet, and are producing or are capable of 

producing gas; or 

iv) Within twelve (12) months following the date the well for which 

administrative approval is granted is spud, there will be at least one well 

or a combination of multiple wells, including cross unit wells and or 

encroaching wells located, as defined in subsection (a)(2) of General 

Rule B-3, within each included drilling unit that have a total combined 

perforated lateral length within the drilling unit of not less than 4160 

feet, and are producing or are capable of producing gas and awaiting

connection to a pipeline; or

v) At least seventy five percent (75%) of the fee mineral ownership within 

each included drilling unit that does not contain one or more wells 

satisfying the requirements of subpart 2)A.i) or subpart 2)A. iii) above 

agree in writing to the well; and 

B. Notice has been given to all owners, as defined by Ark. Code Ann. (1987) § 15-

72-102(9) and no objections were received by the Director in accordance with 

subsection 2) I) below; and 

C. The application includes detailed plat maps indicating current well locations and 

potential future well development plans in all included drilling units. 

D. If administrative approval is granted, based upon either or both of subsection 

2)A.ii) or iv) above, and the applicant fails to satisfy one of the conditions 

specified in subsection 2)A.ii) or iv) above, the drilling permit and all other 

authorities for the well shall be automatically revoked, and the well shall be shut 

in, unless the applicant has filed a request in accordance with General Rule A-2, 

A-3, and other applicable hearing procedures prior to the expiration of the time 

period specified in such subsections, or the Commission otherwise approves the 

application.

E. The method for sharing the costs of and the proceeds of production from one or 

more separately metered wells shall be based on acreage allocation as follows: 

i) An area measured 560 feet along and on both sides of the entire length of 

the horizontal perforated section of the well, and including an area 

formed by a 560 feet radius from the beginning point of the perforated 

interval, and a 560 feet radius from the ending point of the perforated 

interval shall be calculated for each such separately metered well (the 

“calculated area”). 
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125

ii) Each calculated area shall be allocated and assigned to each drilling unit 

according to that portion of the calculated area occurring within each 

drilling unit. 

F. Each such application for utilizing the above methodology shall be submitted on 

a form prescribed by the Director of Production and Conservation, accompanied 

by an application fee of $500.00 and include the name and address of each 

owner, as defined in Ark. Code Ann. (1987) § 15-72-102(9), within each of the 

drilling units in which the proposed well is to be drilled and/or completed. 

G. Concurrently with the filing of an application utilizing the above methodology, 

the applicant shall send to each owner specified in subsection 2)F. above a notice 

of the application filing and verify such mailing by affidavit, setting out the 

names and addresses of all owners, as defined by Ark. Code Ann. (1987) § 15-

72-102(9), and the date(s) of mailing.

H. Any owner, as defined by Ark. Code Ann. (1987) § 15-72-102(9), noticed in 

accordance with subsection 2) G) above shall have the right to object to the 

granting of such application within fifteen (15) days after the receipt of the 

application by the Commission. Each objection must be made in writing and 

filed with the Director. If a timely written objection is filed as herein provided, 

then the applicant shall be promptly furnished a copy and such application shall 

be denied. If the application is denied under this section, the applicant may 

request to have the application referred to the Commission for determination, in 

accordance with General Rules A-2 and A-3, and other applicable hearing 

requirements, except that no additional filing fee is required.

I. An application may be referred to the Commission for determination when the 

Director deems it necessary that the Commission make such determination for 

the purpose of protecting correlative rights of all parties, in order to prevent 

waste, or for any other reason. Promptly upon such determination, and not later 

than fifteen (15) days after receipt of the application, the Director shall give the 

applicant written notice, citing the reason(s) for referral to the full Commission 

for determination. If the application is referred under this section, the applicant 

shall file a request for a hearing, in accordance with General Rules A-2 and A-3, 

and other applicable hearing requirements, except that no additional filing fee is 

required.

J. If the Director has not notified the applicant of the determination to refer the 

application to the Commission within the fifteen (15) day period in accordance 

with the foregoing provisions, and if no objection is received at the office of the 

Commission within the fifteen (15) days as provided for in subsection 2)I, the 

application shall be approved and a drilling permit issued. 

K. Upon receipt of the drilling permit, the applicant shall give the other owners, as 

defined by Ark. Code Ann. (1987) § 15-72-102(9), written notice that the drilling 

permit has been issued. The owners, as defined by Ark. Code Ann. (1987) § 15-

72-102(9), who have not previously made an election, shall have fifteen (15) 

days after receipt of said notice within which to make an election to participate in 

the well or be deemed as electing non-consent and subject to the non-consent 

penalty set out in the existing Joint Operating Agreement(s) covering their 

respective drilling unit or units.
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126

L. Following completion of the well and prior to the issuance of the Certificate of 

Compliance to commence production, the final location of the perforated interval 

shall be submitted to the Director to verify the proposed portion of the calculated 

area occurring within each drilling unit as specified in subsection 2) E) above. 

3) Filing of Affidavit. The Applicant shall also file an affidavit or other document showing 

the calculated area allocated and assigned to each drilling unit, according to the final 

calculation of the area, occurring within each drilling unit with the Director and in the 

real estate property records in all counties where any portion of the drilling units are 

located.

(p) The Commission shall retain jurisdiction to consider applications, brought before the 

Commission, from a majority in interest of working interest owners in two or more adjoining 

governmental sections seeking the authority to combine such adjoining governmental sections 

into one drilling unit for the purpose of developing one or more unconventional sources of 

supply. In any such multi-section drilling unit, production shall be allocated to each tract therein 

in the same proportion that each tract bears to the total acreage within such drilling unit.

(q) The Commission shall retain jurisdiction to consider applications, brought before the 

Commission, from a majority in interest of working interest owners in a drilling unit seeking the 

authority to omit any lands from such drilling unit that are owned by a governmental entity and 

for which it can be demonstrated that such governmental entity has failed or refused to make such 

lands available for leasing.

(Source: new rule October 16, 2006; amended December 16, 2007, amended June 15, 2008, amended 

December 14, 2008; amended March 25, 2010; amended July 05, 2010; amended August 01, 2014; 

amended October 1, 2015)
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127

RULE B-44: ESTABLISHMENT OF DRILLING UNITS FOR GAS PRODUCTION 

FROM ALL SOURCES OF SUPPLY OCCURING IN CERTAIN PRODUCING AREAS 

IN FRANKLIN, LOGAN, SCOTT, SEBASTIAN AND YELL COUNTIES

(a) Definitions:

(1) “Unconventional Sources of Supply” shall mean those common sources of supply that are 

identified as the Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale 

Formations, or their stratigraphic shale equivalents, as described in published 

stratigraphic nomenclature recognized by the Arkansas Geological Survey or the United 

States Geological Survey.

(2) “Conventional Sources of Supply” shall mean all common sources of supply that are not 

defined as unconventional sources of supply in section (a)(1) above or the Middle Atoka 

as defined in section (a)(4) below, or a tight gas formation as defined in section (a) (3) 

below.

(3) “Tight Gas Formation” shall mean tight gas formation as defined in Ark. Code Ann. 

(1987) § 26-58-101.

(4) “Middle Atoka” shall mean the tight gas formation that is the stratigraphic equivalent, 

from the top of the Basham Formation to the base of Borum Formation, which includes 

the Hartford Series, within the covered lands specified in section (b) below.

(b) This rule is applicable to all sources of supply occurring in the “covered lands,” except the 

Hartshorne Coal Formation or any other coal formation. The development of these sources of 

supply within the covered lands shall be subject to the provisions of this rule. The covered lands 

are specified as follows:

(1) Sections 19-36, T7N R28W; Sections 1-3 and 11, T6N, R29W all in Franklin County; 

(2) Sections 19-36 T7N R27W; Sections 19-36 T7N R26W; Sections 13-36 T7N R25W; 

Sections 13-36 T7N R24W; Sections 13-36 T7N R23W; all of T6N R28W; all of T6N 

R27W; all of T6N R26W; all of T5N R29W; all of T5N R28W; all of T5N R27W; all of 

T5N R26W; Sections 1, 2, 3, 10, 11, 12 T4N R29W; Sections 1-12 T4N R28W; Sections 

1-12 T4N R27W; Sections 1-12 T4N R26W all in Logan County and those portions of 

T6N R25W, T6N R24W and T6N R23W located in Logan County;

(3) That portion of T5N R30W, T4N R29W, T4N R28W, T4N R27W, and T4N R26W 

located in Scott County; and all of T4N R30W in Scott County; 

(4) Sections 31-36 T7N R31W; Sections 31 and 32 T7N R30W; all of T6N R32W; all of 

T6N R31W; all of T6N R30W; all of T5N R32W; all of T5N R31W; all of T4N R32W 

and all of T4N R31W in Sebastian County and that portion of T6N R29W and T5N 

R30W located in Sebastian County; 

(5) All of T5N R25W; all of T5N R24W; all of T5N R23W; all of T4N R25W; all of T4N 

R24W; all of T4N R23W; All of T6N R22W; all of T5N R22W; all of T4N R22W all in 

Yell County and those portions of T6N R25W, T6N R24W, T6N R23W located in Yell 

County;
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128

(6) After notice and hearing, the Commission shall retain jurisdiction to expand the covered 

lands above, to include other lands proven to possess production characteristics similar to 

the lands initially contained within the covered lands.

(c) The Commission shall retain jurisdiction, after notice and hearing, to determine which other 

formations, in addition to the Middle Atoka, qualify as tight gas formations within the covered 

lands.

(d) All Commission approved fields, except those applicable to the Hartshorne Coal Formation or 

any other coal formation, that are situated within the covered lands and that are in existence on 

the date this rule is adopted (collectively, the “existing fields”), are abolished and the lands 

heretofore included within the existing fields are included within the covered lands governed by 

this rule. However, all existing portions of the abolished fields which are not included in the 

covered lands, those portions of the fields shall remain intact and operate under the existing field 

rules for that field or upon order of the Commission may be joined to other existing adjacent 

fields. All existing individual drilling units however, contained within the abolished fields shall 

remain intact.

(e) All drilling units established for sources of supply within the covered lands shall be comprised of 

single governmental sections, typically containing an area of approximately 640 acres in size, 

unless a different size and/or configuration is approved for any unit or units by Order of the 

Commission. Each drilling unit shall be characterized as either an “exploratory drilling unit” or 

an “established drilling unit”. An “exploratory drilling unit” shall be defined as any drilling unit 

that is not an established drilling unit. An “established drilling unit” shall be defined as any 

drilling unit that contains a well that has been drilled and completed in any source of supply (a 

“subject well”), and for which the operator or other person responsible for the conduct of the 

drilling operation has filed, with the Commission, all appropriate documents in accordance with 

General Rule B-5, and has been issued a certificate of compliance. Upon the filing of the 

required well and completion reports for a subject well and the issuance of a certificate of 

compliance with respect there, the exploratory drilling unit upon which the subject well is 

located and all contiguous governmental sections shall be automatically reclassified as 

established drilling units. All existing “exploratory drilling units” contiguously located to drilling 

units with established production at the time this rule is adopted, shall be automatically 

reclassified as established drilling units.

(f) The filing of an application to integrate separately owned tracts within an exploratory drilling 

unit, as defined in Section (e) above and as contemplated by A.C.A. § 15-72-302(e), is 

permissible, provided that one or more persons who own at least an undivided fifty percent (50%) 

interest in the right to drill and produce oil or gas, or both, from the total acreage assigned to such

exploratory drilling unit agree. In determining who shall be designated as the operator of the 

exploratory drilling unit that is being integrated, the Commission shall apply the following 

criteria: 

1) Each integration application shall contain a statement that the applicant has sent written 

notice of its application to integrate the drilling unit to all working interest owners of 

record within such drilling unit. This notice shall contain a well proposal and AFE for the 

initial well and may be sent at the same time the integration application is filed. 

2) If any non-applicant working interest owner in the drilling unit owns, or has the written 

support of one or more working interest owners that own, separately or together, at least a 

fifty percent (50%) working interest in the drilling unit, such non-applicant working 

interest owner may (i) object to the applicant being named operator (a “section (f) 

operator challenge”) or (ii) file a competing integration application (a “section (f) 
GENERAL RULES AND REGULATIONS

129

competing application”) that challenges any aspect of the original integration application 

for such drilling unit. Any contested matter that is limited to a section (f) operator 

challenge shall be heard at the Commission hearing that was originally scheduled for 

such integration application. Any contested matter that involves the filing of a section (f) 

competing application shall be postponed until the next month’s regularly scheduled 

Commission hearing if postponement is requested by either competing applicant. 

3) If a party desiring to be named operator of a drilling unit is supported by a majority-ininterest of the total working interest ownership in the drilling unit (the “majority owner”), 

the majority owner shall be designated unit operator.

4) In the event two parties desiring to be named operator own, or have the written support of 

one or more working interest owners that own, exactly, an undivided 50% share of the 

drilling unit and either a section (f) operator challenge is submitted or a section (f) 

competing application is filed, operatorship shall be determined by the Commission, 

based on the factors it deems relevant and the evidence submitted by the parties or as 

otherwise provided by subsequent rule. 

5) If the person designated as operator by the Commission in the adjudication of a section 

(f) operator challenge or a section (f) competing application does not commence actual 

drilling operations on the drilling unit within the twelve (12) month period set out in the 

integration order, such operator shall not be entitled to be designated as operator under 

the subsequent integration of such drilling unit unless (i) the operator’s failure to 

commence such drilling operations was due to force majeure, (ii) a majority-in-interest of 

the total working interest ownership in the drilling unit (excluding such designated 

operator) support such operator.

(g) The filing of an application to integrate separately owned tracts within an established drilling 

unit, as defined in Section (e) above and as contemplated by A.C.A. § 15-72-303 is permissible, 

without a minimum acreage requirement, provided that one or more persons owning an interest in 

the right to drill and produce oil or gas, or both, from the total acreage assigned to such 

established drilling unit requests such integration. In determining who shall be designated as the 

operator of the established drilling unit that is being integrated, the Commission shall apply the 

following criteria: 

1) Each integration application shall contain a statement that the applicant has sent written 

notice of its application to integrate the drilling unit to all working interest owners of 

record within such drilling unit. This notice shall contain a well proposal and AFE for the 

initial well and may be sent at the same time the integration application is filed. 

2) Any non-applicant working interest owner in the drilling unit may object to the applicant 

being named operator (a “section (g) operator challenge”). In addition, if an objecting 

party owns, or has the written support of one or more working interest owners that own, 

separately or together, a larger percentage working interest in the drilling unit than the 

applicant, such objecting party may file a competing integration application (a “section 

(g) competing application”) that challenges any aspect of the original integration 

application for such drilling unit. Any contested matter that is limited to a section (g) 

operator challenge shall be heard at the Commission hearing that was originally 

scheduled for such integration application. Any contested matter that involves the filing 

of a section (g) competing application shall be postponed until the next month’s regularly 

scheduled Commission hearing if postponement is requested by either competing 

applicant. 
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130

3) If a party desiring to be named operator of a drilling unit is a majority owner (as defined 

in subsection (f) (3) above), the majority owner shall be designated unit operator. 

4) If a party desiring to be named operator of a drilling unit is not a majority owner, but is 

supported by the largest percentage interest of the total working interest ownership in the 

drilling unit (the “plurality owner”), there shall be a rebuttable presumption that the 

plurality owner shall be designated unit operator. If a section (g) operator challenge to a 

plurality owner being designated unit operator is submitted by a party that owns, or has 

the written support of one or more owners that own, separately or together, the next 

largest percentage share of the working interest ownership in the drilling unit (the 

“minority owner”), the Commission may designate the minority owner operator if the 

minority owner is able to show that, based on the factors the Commission deems relevant 

and the evidence submitted by the parties, the Commission should designate the minority 

owner as unit operator. 

5) If two or more parties that desire to be named operator own, or have the support of one or 

more working interest owners that own, separately or together, the same working interest 

ownership in the drilling unit, operatorship shall be determined by the Commission, 

based on the factors it deems relevant and the evidence submitted by the parties or as 

otherwise provided by subsequent rule. 

6) If the person designated as operator by the Commission in the adjudication of a section 

(g) operator challenge or a section (g) competing application does not commence actual 

drilling operations on the drilling unit within the twelve (12) month period set out in the 

integration order, such operator shall not be entitled to be designated operator under the 

subsequent integration of such drilling unit unless (i) the original operator’s failure to 

commence drilling operations on the initial well was due to force majeure, (ii) a majorityin-interest of the total working interest ownership in the drilling unit (excluding the 

original operator) support the original operator.

(h) The well spacing for wells drilled in exploratory and established drilling units for all 

unconventional sources of supply within the covered lands are as follows:

1) Each well location, as defined in General Rule B-3 (a)(2), shall be at least 560 

feet from any drilling unit boundary line, unless an exception is approved in 

accordance with subparagraph (p) below or in accordance with General Rule B40;

2) Each well location, as defined in General Rule B-3 (a)(2), shall be at least 560 

feet from other well locations within an established drilling unit, within common 

sources of supply, unless an exception to this rule is approved by the 

Commission, following notice and hearing. 

(i) The well spacing for wells drilled in exploratory and established drilling units for the Middle 

Atoka, and any other tight gas formation source of supply within the covered lands are as follows:

1) Each well location, as defined in General Rule B-3 (a)(2), shall be at least 560 

feet from any drilling unit boundary line, unless an exception is approved in 

accordance with subparagraph (p) below or in accordance with General Rule B40;

2) Each well location, as defined in General Rule B-3 (a)(2) shall be at least 560 

feet from other well locations within an established drilling unit, unless the 
GENERAL RULES AND REGULATIONS

131

common sources of supply are stratigraphically different named intervals, 

approved in accordance with subparagraph (i) (3) below, or an exception to this 

rule is approved by the Commission, following notice and hearing. 

3) Application for approval of well locations less than 560 feet from other well 

locations within an established unit, for common sources of supply from 

stratigraphically different named intervals, shall be submitted on a form 

prescribed by the Director, and contain, at a minimum, the following 

information:

A) The location of the unit;

B) The location or proposed location of all wells being encroached upon, 

showing the productive zones in each well;

C) A cross-section, containing the location or proposed location of all wells 

being encroached upon, demonstrating the productive zone will be from 

stratigraphically different named intervals; 

D) In addition, each application shall provide proof of written notice to all 

owners, as defined in Ark. Code Ann. § 15-72-102(9), in the subject unit;

E) The notice shall contain at a minimum, the name of the applicant, the 

name and location of the encroaching wells, and instructions as to the 

filing with the Director written objections within fifteen (15) days after 

receipt of the application by the Director.

F) Any owner noticed in accordance with sub-paragraph i) 3) E) above shall 

have the right to object to the granting of such application within fifteen 

(15) days after receipt of the application by the Director.

G) If an objection is not received within fifteen (15) days after the receipt of 

the application, and that the productive zone will be from 

stratigraphically different named intervals, the Director shall approve the 

application. 

H) If an objection is received, or if the application does not satisfy the 

requirements of this Rule and is denied by the Director, the Applicant 

may request to have the matter placed, in accordance with General Rules 

A-2, A-3 and other established procedures, on the docket of a regularly 

scheduled Commission hearing.

(j) The well spacing for wells drilled in exploratory and established drilling units for the Upper 

Atoka and the Freiburg conventional sources of supply within the covered lands are as follows:

1) Each well location, as defined in General Rule B-3 (a)(2), shall be at least 560 

feet from any drilling unit boundary line, unless an exception is approved in 

accordance with subparagraph (p) below or in accordance with General Rule B40;

2) Each well location, as defined in General Rule B-3 (a)(2) shall be at least 560 

feet from other well locations within an established drilling unit, within common 
GENERAL RULES AND REGULATIONS

132

sources of supply, unless an exception to this rule is approved by the 

Commission, following notice and hearing. 

(k) The well spacing for wells drilled in exploratory and established drilling units for all other 

conventional sources of supply within the covered lands are as follows:

1) Only a single well completion will be permitted to produce from each separate 

conventional source of supply within each exploratory or established drilling unit, unless 

additional completions are approved in accordance with General Rule D-19;

2) Each well location, as defined in General Rule B-3 (a)(2), shall be at least 1120 feet from 

any drilling unit boundary line, unless an exception is approved in accordance with 

subparagraph (p) below or General Rule B-40;

(l) The casing programs for all wells drilled in exploratory and established drilling units established 

by this rule, and occurring in the covered lands specified by this rule, shall be in accordance with 

General Rule B- 15 or other applicable General Rules.

(m) Wells completed in and producing from all sources of supply, within the covered lands, shall be 

subject to the testing provisions of General Rule D-16 and allowable provisions of General Rule 

D-21, except that unconventional sources of supply shall not be subject to an allowable.

(n) The commingling of completions in all sources of supply, within each well, shall be subject to the 

provisions in General Rule D-18. 

(o) The reporting requirements of General Rule B-5 shall apply to all wells subject to the provisions 

of this rule. In addition, the operator of each such well shall be required to file monthly gas 

production reports, on a Form approved by the Director, no later than 45 days after the last day of 

each month.

(p) The Commission specifically retains jurisdiction to consider applications brought before the 

Commission from a majority in interest of working interest owners in two or more adjoining 

exploratory or established drilling units seeking the authority to drill, produce and share the costs 

of and the proceeds of production from a separately metered well that extends across or 

encroaches upon drilling unit boundaries and that are drilled and completed in one or more 

sources of supply within the covered lands. All such applications shall contain a proposed 

agreement on the formula for the sharing of costs, production and royalty from the affected 

drilling units.

1) However, if the majority in interest of working interest owners agree to share a proposed 

well between two or more adjoining drilling units, which have been previously 

integrated, utilizing the below methodology for sharing of costs, production and royalty 

among the affected drilling units, or if the well encroaches upon the drilling unit 

boundaries specified by this rule, the Director or his designee is authorized to approve the 

application administratively utilizing the following methodology: 

A) The sharing of well costs and the proceeds of production from one or more 

separately metered wells, between the affected drilling units, shall be based on an 

allocation based on an area (acreage) calculation as specified below. 

B) For horizontal wells, an area (equal to the setback footage for that source of 

supply as specified in section (h), (i), (j) or (k) above) along and on both sides of 

the entire length of the horizontal perforated section of the well, and including an 
GENERAL RULES AND REGULATIONS

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area formed by a radius (equal to the setback footage for that source of supply as 

specified in section (h), (i), (j) or (k) above) from the beginning point of the 

perforated interval and from the ending point of the perforated interval. The area 

formed shall be calculated for each such separately metered well and referred to 

as the “calculated area”.

C) For vertical wells, an area (equal to the setback footage for that source of supply 

as specified in section (h), (i), (j) or (k) above) extending around the perforated 

interval as defined in General Rule B-3, shall be calculated for each such 

separately metered well and referred to as the “calculated area”. 

D) Each calculated area shall be allocated and assigned to each drilling unit 

according to that portion of the calculated area occurring within each drilling 

unit. 

2) Each such application for utilizing the above methodology shall be submitted on a form 

prescribed by the Director of Production and Conservation, accompanied by an 

application fee of $500.00 and include the name and address of each owner, as defined in 

A.C.A. § 15-72-102(9), within each of the drilling units in which the proposed well is to 

be drilled and/or completed. 

3) Concurrently with the filing of an application utilizing the above methodology, the 

applicant shall send to each owner specified in subsection (p)(2) above a notice of the 

application filing and verify such mailing by affidavit, setting out the names and 

addresses of all owners and the date(s) of mailing.

4) Any owner noticed in accordance with subsection (p)(3) above shall have the right to 

object to the granting of such application within fifteen (15) days after the receipt of the 

application by the Commission. Each objection must be made in writing and filed with 

the Director. If a timely written objection is filed as herein provided, then the applicant 

shall be promptly furnished a copy and the application shall be denied. If the application 

is denied under this section, the applicant may request to have the application referred to 

the Commission for determination, in accordance with applicable state laws and General 

Rules A-2 and A-3, except that no additional filing fee is required.

5) An application may be referred to the Commission for determination when the Director 

deems it necessary that the Commission make such determination for the purpose of 

protecting correlative rights of all parties. Promptly upon such determination, and not 

later than fifteen (15) days after receipt of the application, the Director shall give the 

applicant written notice, citing the reason(s) for denial of the application under this rule 

and the referral to the full Commission for determination, in accordance with applicable 

state laws and General Rules A-2 and A-3. 

6) If the Director has not notified the applicant of the determination to refer the application 

to the Commission within the fifteen (15) day period in accordance with the foregoing 

provisions, and if no objection is received at the office of the Commission within the 

fifteen (15) days as provided for in subsection (p)(4), the application shall be approved 

and a drilling permit issued.

7) Upon receipt of the drilling permit, the applicant shall give the other working interest 

parties written notice that the drilling permit has been issued. The working interest 

parties, who have not previously made an election, shall have 15 days after receipt of said 

notice within which to make an election to participate in the well or be deemed as 
GENERAL RULES AND REGULATIONS

134

electing non-consent and subject to the non-consent penalty set out in the existing Joint 

Operating Agreement(s) covering their respective drilling unit or units.

8) Following completion of the well and prior to the issuance by the Commission of the 

Certificate of Compliance to commence production, the final location of the perforated 

interval shall be submitted to the Commission to verify the proposed portion of the 

calculated area occurring within each drilling unit as specified in subsection (p)(1) above.

(q) The Commission shall retain jurisdiction to consider applications, brought before the 

Commission, from a majority in interest of working interest owners in two or more adjoining 

governmental sections seeking the authority to combine such adjoining governmental sections 

into one drilling unit for the purpose of developing one or more unconventional sources of 

supply. In any such multi-section drilling unit, production shall be allocated to each tract therein 

in the same proportion that each tract bears to the total acreage within such drilling unit.

(r) The Commission shall retain jurisdiction to consider applications, brought before the 

Commission, from a majority in interest of working interest owners in a drilling unit seeking the 

authority to omit any lands from such drilling unit that are owned by a governmental entity and 

for which it can be demonstrated that such governmental entity has failed or refused to make such 

lands available for leasing.

(Source: new rule June 15, 2008; amended January 22, 2009; amended August 01, 2014)
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135

RULE B-45: ESTABLISHMENT OF WELL SET-BACK REQUIREMENTS FOR DRY 

GAS PRODUCTION WELLS OCCURING IN ESTABLISHED FIELDS IN 

CRAWFORD, FRANKLIN, JOHNSON, LOGAN, MADISON, POPE, SCOTT, YELL, 

SEBASTIAN AND WASHINGTON COUNTIES

a) Applicability

1) Except as provided in subparagraph a) 2) below, this rule applies to all controlled sources 

of supply, as defined in Ark Code Ann. § 15-71-107, occurring within any existing field 

created by an order of the Commission within Crawford, Franklin, Johnson, Logan, 

Madison, Pope, Scott, Yell, Sebastian and Washington Counties.

2) This rule does not apply to:

A) The Hartshorne Coal Formation or any other coal formation; 

B) Any uncontrolled conventional source of supply occurring within the 

Commission established fields covered by this rule; 

C) Any source of supply governed by General Rule B-43, or

D) Any source of supply governed by General Rule B-44.

3) After notice and hearing, the Commission shall retain jurisdiction to extend the 

provisions of this rule to any new fields established by the Commission.

4) This rule applies to wells in which controlled and uncontrolled sources of supply are 

commingled.

b) Definitions 

1) “Encroachment Footage” shall mean the actual footage of the New or Existing PRU 

from the drilling unit boundary, when that footage is less than the Setback Footage 

specified by rule.

2) “Existing PRU” shall mean a production reporting unit, which is either an individual 

producing zone or approved commingled producing zones within a dry natural gas well 

which was previously productive prior to the effective date of this rule.

3) “FUB” shall mean distance from a drilling unit boundary line.

4) “New PRU” shall mean a production reporting unit, which is either an individual 

producing zone (in a newly drilled dry natural gas well or a new zone in an existing dry 

natural gas well) or approved commingled producing zones within a dry natural gas well 

which becomes productive after the effective date of this rule.

5) “Penalty Allowable” shall mean the PRU Deliverability of the New or Existing PRU, 

subject to a Penalty Factor, a New or Existing PRU is allowed to produce and sell on a 

per day basis.

6) “Penalty Factor” shall mean the factor which is multiplied by the New or Existing PRU 

to impose a penalty (or reduction) upon the PRU Deliverability.
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136

7) "PRU Deliverability" shall mean the measured volume of dry natural gas from an 

Existing or New PRU under normal operating conditions for that Existing or New PRU 

as determined by the IOPT or Production Test. 

8) “Setback Footage” shall mean the required minimum distance a New or Existing PRU 

must be from the drilling unit boundary.

c) After the effective date of this rule, the Setback Footage for all drilling units subject to this rule 

shall be as follows:

1) For all existing drilling units with a Setback Footage that is less than 660 feet, the 

Setback Footage shall remain unchanged. 

2) For all existing drilling units with a Setback Footage that is 660 feet or greater, the 

revised Setback Footage shall be re-established to 660 feet. 

d) After the effective date of this rule, any Existing PRU not subject to a Penalty Allowable may 

produce at the PRU Deliverability.

e) After the effective date of this rule, any New PRU not subject to a Penalty Allowable may 

produce at the PRU Deliverability. 

f) The Penalty Allowable, for any Existing or New PRU, after the effective date of this rule shall be 

determined as follows:

 

1) For any Existing PRU where the Setback Footage is equal to or greater than 660 feet, and 

where the Setback Footage has been re-established to 660 feet in accordance with 

subparagraph c) 2) above, the previously imposed penalty on the allowable established 

prior to the adoption of this rule shall be removed and the Existing PRU allowed to 

produce at the PRU Deliverability.

2) For any Existing PRU where there is Encroachment Footage, and where the Setback 

Footage has been re-established to a 660 feet in accordance with subparagraph c) 2) 

above, the previously imposed penalty on the allowable established prior to the adoption 

of this rule shall be re-calculated based on the revised Setback Footage of 660 feet in 

order to calculate the Penalty Allowable, except that any Existing PRU that has a recalculated Penalty Allowable of less than 75 MCFD shall be assigned a Penalty 

Allowable of 75 MCFD.

3) For any Existing PRU, where the Setback Footage remains unchanged in accordance with 

subparagraph c) 1) above, the Penalty Allowable established prior to the adoption of this 

rule shall remain in effect, except that any Existing PRU that has a re-calculated Penalty 

Allowable of less than 75 MCFD shall be assigned a Penalty Allowable of 75 MCFD.

4) No New PRU may be located less than 660 feet FUB where the Setback Footage has 

been re-established to a 660 feet in accordance with subparagraph c) 2) above, or closer 

than the applicable Setback Footage that remained unchanged in accordance with 

subparagraph c) 1) above, unless approved in accordance with General Rule B-40, or an 

alternative is approved by the Commission after notice and hearing.

g) In accordance with subparagraph f) 2) above, the Penalty Allowable shall be calculated as 

follows:
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137

1) If the Encroachment Footage encroaches upon only one boundary of said drilling unit, the 

Penalty Allowable shall be the greater of 75 MCFD or calculated as follows: 

Penalty Allowable = PRU Deliverability x Penalty Factor (Encroachment Footage ÷ 

Setback Footage) x proposed drilling unit acreage ÷ 640 acres or applicable established 

drilling unit acreage 

2) If the Encroachment Footage encroaches upon two boundaries of said drilling unit, then 

the Penalty Allowable shall be the greater of 75 MCFD or the cumulative of the penalties 

calculated as follows: 

Penalty Allowable = PRU Deliverability x Penalty Factor [(1st Encroachment Footage + 

2nd Encroachment Footage) ÷ Setback Footage – 1] x proposed drilling unit acreage ÷ 

640 acres or applicable established drilling unit acreage 

h) Sales in Excess of the Penalty Allowable 

 

1) An Existing or New PRU subject to a Penalty Allowable in accordance with this rule 

shall have an annual balancing date of July 1, where the preceding 12 month (July 1 –

June 30) sales must be reconciled with the preceding 12 month Penalty Allowable to 

determine if the PRU had excess sales.

2) An Existing or New PRU subject to a Penalty Allowable which has sales in excess of the 

assigned Penalty Allowable must be shut-in on the annual balancing date of July 1 and 

remain shut-in until all excess sales is eliminated. The shut-in period shall be determined 

by dividing the excess sales by the Penalty Allowable. 

3) Any Existing or New PRU subject to a Penalty Allowable which has excess sales on the 

annual balancing date of July 1 and which fails to shut-in within 30 days after the July 1, 

may be subject to a civil penalty not to exceed two thousand five hundred dollars 

($2,500.00) per day for every day the PRU produced beyond the 30 day period, and may 

be subject to further enforcement actions in accordance with General Rule A-5, and Ark. 

Code Ann. § 15-72-401 through 15-72-406.

(Source: new rule August 01, 2014)
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GENERAL RULE C - OIL

RULE C-1: FIELDS OR POOLS IN WHICH PRODUCTION WILL BE 

CONTROLLED

All common sources of supply of crude oil discovered after January 1, 1937, if so found necessary by the 

Commission, will have the production of oil controlled or regulated as provided in Act 105, General 

Assembly, 1939.

(Source: 1991 rule book)
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139

RULE C-2: REPORTS BY PRODUCERS

A. Each producer of oil in any field, and each producer of hydrocarbons in liquid form at the well head 

by ordinary production methods from a gas well in any field, shall execute in triplicate and file with 

the Oil and Gas Commission, El Dorado, Arkansas, a “Producer’s Certificate of Compliance and 

Authorization to Transport Oil or Gas from Lease,” for each lease that is capable of producing on or 

after July 15, 1955.

After the above date, whenever there shall occur a change in operating ownership of any lease in a 

field within the State of Arkansas, or whenever there shall occur a change of transporter from any 

lease in a field within the State of Arkansas, a new “Producer’s Certificate of Compliance and 

Authorization to Transport Oil or Gas from Lease,” shall be executed and filed in accordance with 

instructions appearing on such form, except that in the case of temporary change in transporter 

involving less than the allowable for one month, the producer may, in lieu of filing a new 

certificate, notify the Oil and Gas Commission at El Dorado, Arkansas, and the transporter then 

authorized by certificate on file with the Oil and Gas Commission, by letter of the estimated amount 

of oil to be moved by the temporary transporter and the name of such temporary transporter and a 

copy of such notice shall also be furnished such temporary transporter. In no instance shall the 

temporary transporter move any greater quantity of oil than the estimated amount shown in said 

notice.

The “Producer’s Certificate of Compliance and Authorization to Transport Oil or Gas from Lease,” 

when properly executed and approved by the Oil and Gas Commission, shall constitute 

authorization to the pipeline or other carrier to transport oil from the lease named therein, and shall 

remain in force and effect until:

(1) The operating ownership of the lease changes, or

(2) The transporter is changed, or

(3) The permit is cancelled by the Oil and Gas Commission.

Where a transporter disconnects from a particular lease or ceases to remove oil therefrom and 

another transporter connects to such lease or begins to take oil therefrom, during a month, the 

transporter who ceases to take oil shall furnish to the connecting transporter a certified statement 

under oath, showing: the legal quantity of oil on hand 7 a.m., the first day of such month; the 

scheduled allowable to the date disconnected; and the quantity of oil moved from the particular 

lease during the current month. In such case the producer shall furnish to the connecting transporter 

a certified statement under oath showing the lease stock on hand 7 a.m., the date of new connection. 

No connecting transporter shall move oil from any such lease until after it shall have received such 

statements, except with the written permission of the Oil and Gas Commission or their authorized 

agent.

Each producer is prohibited from delivering illegal oil to any transporter, and each transporter is 

prohibited from removing any illegal oil from producer’s lease tanks. Each transporter shall 

maintain necessary records of lease allowables and quantities of oil removed from the leases to 

which he is connected, whereby he can determine the calculated quantity of legal oil on hand at the 

close of each calendar month with respect to such leases. The calculated quantity of legal oil on 

hand with respect to any lease shall be determined for each succeeding month by adding to the 

quantity of legally produced oil on hand at the first of the month, the scheduled allowable quantity 

of oil for the respective lease for the current month, as established by the Oil and Gas Commission, 

less the quantity of oil removed from the respective lease tanks during the current month. If the 

calculated balance so determined is less than the actual gauged quantity on hand as reported by the 
GENERAL RULES AND REGULATIONS

140

producer on “Producer’s Monthly Report,” the transporter shall not remove during the following 

month any part of the oil on hand on the first day of the month in excess of the calculated legal 

balance so established. If the actual quantity of oil on hand with respect to a particular lease equals 

or is less than the quantity of legal oil established by the above method, the transporter may remove 

any part or all of such quantity of oil during the current month. Where actual quantity of oil on 

hand with respect to a particular lease is less than the calculated quantity of legal oil established by 

the above method, the transporter, in determining the quantity of legal oil for the next succeeding 

month, shall substitute the actual quantity on hand for the calculated quantity on hand. Where there 

is more than one transporter moving oil from the same lease, the producer and transporters are 

required to furnish to each other information as the quantity of oil on hand, the quantity transported 

from lease tanks and any additional information necessary to establish to the satisfaction of each 

person involved the legal status of the oil produced.

B. Each producer of oil in any controlled oil field, and each producer of hydrocarbons in liquid form at 

the wellhead by ordinary production methods from a gas well in any controlled gas field, shall 

furnish for each calendar month a “Producer’s Monthly Report”, setting forth complete information 

and data indicated by such forms representing oil and/or liquid hydrocarbons produced from each 

lease operated by said producer in controlled fields in the State of Arkansas. Such report for each 

month shall be prepared and filed according to the instructions on the form, on or before the 15th of 

the next succeeding month.

(Source: 1991 rule book)
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141

RULE C-3: RESERVOIR SURVEYS

By special order of the Commission periodical surveys of the reservoirs containing oil and gas in the state 

will be made. These surveys will be thorough and complete and shall be under the supervision of the 

petroleum and natural gas engineers of the Commission. The surveys shall be an investigation into the 

condition of the reservoirs containing oil and gas and an investigation into the practices and methods 

employed in obtaining oil and gas from the reservoir. These surveys and investigations shall specifically 

include the volume and source of crude oil and natural gas; the reservoir pressure of the reservoir as an 

average; the area of the regional or differential pressure; stabilized gas-oil ratios and the producing 

characteristics of the field as a whole and the individual wells within the field.

(Source: 1991 rule book)
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142

RULE C-4: OPERATORS TO ASSIST IN RESERVOIR SURVEYS

All operators of oil wells are required to permit and assist the agents of the Oil and Gas Commission in 

making any and all tests including bottom hole pressure and gas-oil ratio determinations that may be 

required by the Oil and Gas Commission on any or all of his wells.

(Source: 1991 rule book)
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143

RULE C-5: OIL ASSESSMENT

Oil conservation assessment, in order to pay the costs in connection with oil and gas conservation 

administration, not otherwise provided for, shall be made as follows:

A. There shall be assessed a charge not to exceed fifty (50) mills (Acts 2001, No. 1188, General 

Assembly) on each barrel of crude oil or petroleum marketed or used from a field or pool each 

month. Said charge and assessment shall only apply to the first purchase or use of oil from the 

producer and not to subsequent transfers commonly referred to as “tenderships.” Effective on and 

after January 1, 2002, the oil conversation assessment shall be 43 mills.

B. The first purchaser, user or holder for a period of thirty days of the production, who is hereby 

defined to be the person holding the Division Order and issuing checks to pay for any working

interest or royalty interest, shall before issuing checks or otherwise paying for the production, deduct 

the amount assessed per barrel of oil marketed, used or held for a period or thirty (30) days from the 

lease each month, and remit the amounts.

C. Said remittance shall be made by the fifteenth of the month following the month in which the oil was 

purchased in a single check if the purchaser so desires, and the only accounting necessary by the 

purchaser shall be the show the deductions under this order on the regular payment statements to 

producers and royalty owners or parties in interest.

D. Any person purchasing oil in this state at the well, under any contract or agreement requiring 

payment for such production to the respective owners thereof, in respect of which production any 

sums assessed under this rule as payable to the Commission, is hereby authorized, empowered and 

required to deduct from any sum so payable to any such person the amount due the Commission by 

virtue of any such assessment and remit that sum to the Commission in the manner stated. Further, 

any person taking oil from any well in this state for use or resale, in respect of which production any 

sums assessed under the provisions of this rule are payable to the Commission, shall remit any sum 

so due to the Commission in accordance with these rules and regulations.

(Source: 1991 rule book; amended Novermber 27, 2001)
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144

RULE C-6: MONTHLY REPORTS-COSTS

The Commission shall prescribe a reasonable and necessary charge or fee per copy and per subscription 

for notices and reports prepared and published by the Commission, deemed necessary to reimburse the 

Commission for the cost thereof.

(Source: 1991 rule book)

RULE C-7: REPEALED

Rule Repealed Effective July 17, 2009
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145

RULE C-8: FLUID REPRESSURING AND WATER FLOODING OF OIL AND GAS 

PROPERTIES

A. Application and Approval

The owner or operator of any well may inject water or other liquids under pressure into the formation 

containing oil or gas for the purpose of obtaining oil or gas from the reservoir, upon application to 

and approval by the Commission.

B. Casing and Cement

Wells used for the injection of water into the producing formation or repressuring wells shall be cased 

with sound casing so as not to permit leakage and the casing cemented in such manner that damage 

will not be caused to oil, gas or fresh water resources. Newly constructed wells shall be completed 

as follows:

1. Set and cement surface casing 250 feet below the lowermost USDW and cement the long string 

casing for at least 250 feet above the injection zone; or

2. Set and cement surface casing through the base of the fresh water and cement the long string 

casing back to the surface.

The mechanical integrity of each new injection well shall be established by pressure testing or 

such other method as the Commission first approves and the mechanical integrity of each 

injection well shall be re-tested periodically thereafter at least every five (5) years.

C. Application, Contents, Notice, Objection, Hearing, and Approval

1. No liquid shall be injected into a well for flooding purposes until so ordered by the Commission 

pursuant to application, and notice as herein required.

2. The application shall be verified and filed with the Commission, showing:

(a) the location of the Intake Well

(b) the location of oil and gas wells and dry holes, the names of operators of producing wells 

located within one-half mile of the Intake Well

(c) the formation from which wells are producing or have produced

(d) the name, description and depth of the formations to be flooded

(e) the open hole depths of each formation to be flooded

(f) the elevations of the top of the oil or gas bearing formation in the Intake Wells and the wells 

producing from the same formation within a one-half (1/2) mile radius of the Intake Well

(g) the log of the Intake Well or such information as is available

(h) descriptions of the Intake Well casing

(i) descriptions of the liquid, stating the kind, where obtained and the estimated amounts to be 

injected daily
GENERAL RULES AND REGULATIONS

146

(j) the names and addresses of the operators

(k) each application shall be accompanied by evidence satisfactory to the Commission of the 

financial responsibility of the applicant to plug an abandon the injection well or wells by the 

method and procedure required by the Commission or the applicant shall be required to 

furnish a good and sufficient bond therefor in an amount to be determined by the Commission 

but not to exceed the principal sum of One Hundred Thousand and No/100 Dollars 

($100,000.00) conditioned upon the performance of such duty to plug each well to be 

abandoned.

(l) such other information as the Commission may require to ascertain whether the flooding may 

be safely and legally made.

3. Applications may be made to include the use of more than one Intake Well on the same lease or 

on more than one lease.

4. Applications shall be executed by all operators who are to participate in the proposed flooding 

plan; or by the Operator designated in the Unit Operating Agreement as the Operator thereof.

5. Notice of the application shall be given by the applicant by one (1) publication in a legal 

newspaper having a general circulation in the county, or in each county, if there shall be no more 

than one, in which the lands embraced within the application are situated, and by mailing or 

delivering a copy of the application to each operator of producing and drilling wells within a onehalf mile radius of the proposed disposal well. Such notice shall be published, mailed or 

delivered at least ten (10) days, but not more than thirty (30) days, prior to the date on which the 

application is mailed to or filed with the Commission. The cost of such publication shall be paid 

for by the applicant therein.

6. Objections or complaints, stating the reasons why the proposed plan as contained in the 

application may cause damage by oil, gas or fresh water resources must be filed within ten days 

after the application is filed.

7. In the event any such objection or complaint is filed with the Commission on its own motion 

deems that there should be a hearing on the application, a hearing shall be had after reasonable 

notice of the time, place and subject matter of such hearing has been given to the parties in 

interest.

8. Orders approving the flooding plan will not be made within ten days of the filing of the 

application unless the written consent of all persons entitled to notice is filed with the 

Commission within such time.

9. An annual assessment of One Hundred Dollars ($100.00) for each injection well must be paid on 

or before July 1st of each year.

D. Notice of Commencement and Discontinuance of Flooding Operations

1. Immediately upon the commencement of flooding operations, the applicant shall notify the 

Commission of the same and the date of commencement.

2. Within ten days after the discontinuance of flooding operations the applicant or the one in charge 

thereof shall notify the Commission of the date of such discontinuance and the reasons therefor.
GENERAL RULES AND REGULATIONS

147

3. Before any Intake Well shall be abandoned, notice shall be served on the Commission and the 

same procedure shall be followed in the plugging of such wells as provided for the plugging of oil 

and gas wells.

E. Records

The owner or operator of an Intake Well shall keep an accurate record of the amount of liquid 

injected into the Intake Well and such information shall be furnished the Commission monthly.

(Source: 1991 rule book, amended (Order No. 1-98) January 27, 1998)
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148

RULE C-9: PRESSURE MAINTENANCE OR REPRESSURING WITH GAS OF OIL 

AND GAS PROPERTIES

A. Application and Approval

The owner or operator of any well may inject gas under pressure into the formation containing oil or 

gas for the purpose of obtaining oil or gas from the reservoir, upon application to and approval by the 

Commission.

B. Casing and Cement

Wells used for the injection of gas into the producing formation or repressuring wells shall be cased 

with sound casing so as not to permit leakage and the casing cemented in such manner that damage 

will not be caused to any oil, gas or fresh water resources. Newly constructed wells shall be 

completed as follows:

1. Set and cement surface casing 250 feet below the lowermost USDW and cement the long string 

casing for at least 250 feet above the injection zone.

2. Set and cement surface casing through the base of the fresh water and cement the long string 

casing back to the surface.

The mechanical integrity of each new injection well shall be established by pressure testing or such 

other method as the Commission first approves and the mechanical integrity of each injection well 

shall be retested periodically thereafter at least every five (5) years.

C. Application, Contents, Notice, Objection, Hearing, and Approval

1. No gas shall be injected into a well for pressure maintenance or repressuring purposes until so 

ordered by the Commission pursuant to application, and notice as herein required.

2. The application shall be verified and filed with the Commission showing:

(a) the location of the Intake Well

(b) the location of all oil and gas wells including abandoned and drilling wells and dry holes, and 

the names of land owners and lessees within one-half mile of the Intake Well;

(c) the formations from which wells are producing or have produced;

(d) the name, description and depth of the formations to be repressured;

(e) the open hole depths of each formation to be repressured;

(f) the elevations of the top of the oil or gas bearing formation in the Intake Well and the wells 

producing from the same formation within a one-half mile radius of the Intake Well;

(g) the log of the Intake Well or such information as is available;

(h) descriptions of the Intake Well casing;

(i) descriptions of the gas, stating the kind, where obtained and the estimated amounts to be

injected daily;
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149

(j) the names and addresses of the operators;

(k) each application shall be accompanied by evidence satisfactory to the Commission of the 

financial responsibility of the applicant to plug and abandon the injection well or wells by the 

method and procedure required by the Commission or the applicant shall be required to 

furnish a good and sufficient bond therefor in an amount to be determined by the Commission 

but not to exceed the principal sum of One Hundred Thousand and No/100 Dollars 

($100,000.00) conditioned upon the performance of such duty to plug each well to be 

abandoned;

(l) such other information as the Commission may require to ascertain whether the repressuring 

may be safely and legally made.

3. Applications may be made to include the use of more than one Intake Well on the same lease or 

on more than one lease.

4. Applications shall be executed by all operators who are to participate in the proposed repressuring 

plan.

5. Notice of the application shall be given by the applicant by one (1) publication in a legal 

newspaper having a general circulation in the county, or in each county, if there shall be more 

than one, in which the lands embraced within the application are situated, and by mailing or 

delivering a copy of the application of each operator of producing and drilling wells within a onehalf mile radius of the proposed disposal well. Such notice shall be published, mailed or 

delivered at least ten (10) days, but not more than thirty (30) days, prior to the date on which the 

application is mailed to or filed with the Commission. The cost of such publication shall be paid 

for by the applicant therein.

6. Objections or complaints, stating the reasons why the proposed plan as contained in the 

application may cause damage to oil, gas, or fresh water resources must be filed within ten days 

after the application is filed.

7. In the event any such objection or complaint is filed or the Commission on its own motion deems 

that there should be a hearing on the application, a hearing shall be had after reasonable notice of 

the time, place and subject matter of such hearing has been given to the parties in interest.

8. Orders approving the repressuring will not be made within ten days of the filing of the application 

unless the written consent of all persons entitled to notice is filed with the Commission within 

such time.

D. Notice of Commencement and Discontinuance of Repressuring Operations

1. Immediately upon the commencement of repressuring operations, the applicant shall notify the 

Commission of the same and the date of commencement.

2. Within ten days after the discontinuance of repressuring operations the applicant or the one in 

charge thereof shall notify the Commission of the date of such discontinuance and the reasons 

therefor.

3. Before any Intake Well shall be abandoned, notice shall be served on the Commission and the 

same procedure shall be followed in the plugging of such well as providing for the plugging of oil 

and gas wells.
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E. Records

The owner or operator of an Intake Well shall keep an accurate record of the amount of gas injected 

into the Intake Well and such information shall be made available to the Commission or its agents.

F. Individual Cases

The Commission will make such special orders, rules and regulations for the individual case as the 

conditions may justify. 

(Source: 1991 rule book, amended (Order No. 1-98) January 27, 1998)
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151

RULE C-10: ESTABLISHMENT OF WELL SET-BACK REQUIREMENTS FOR OIL 

PRODUCTION WELLS

a) This rule pertains to oil well setback provisions specified in certain established field rules in 

Ashley, Bradley, Calhoun, Columbia, Hempstead, Lafayette, Miller, Nevada, Ouachita, 

and Union Counties. 

b) In all established field rules covered by this general rule, all oil well set back provisions 

which are measured from a boundary other than the drilling unit boundary, and which are 

commonly referred to as “bull’s-eye” or “race-track” locations for:

1) ten (10) acre drilling units, described as a quarter (1⁄4) quarter (1⁄4) quarter (1⁄4) of a 

governmental section; 

2) twenty (20) acre drilling units, described as the east one-half (E/2), west one-half 

( W/2), north one-half (N/2) or south one-half (S/2) of a quarter (1⁄4) quarter ( 1⁄4) 

of a governmental section; 

3) forty (40) acre drilling units, described as a quarter (1⁄4) quarter (1⁄4) of a 

governmental section; and

4) eighty (80) acre drilling units described as the east one-half (E/2), west one-half ( 

W/2), north one-half (N/2) or south one-half (S/2) of a quarter (1⁄4) of a 

governmental section; 

are set at two hundred and eighty (280) feet from the drilling unit boundary and all 

existing “bull’s-eye” or “race-track” field rule setback requirements for the above drilling 

units are abolished. 

c) Established field rules with well setback requirements less than two hundred and eighty 

(280) feet from the above drilling unit boundaries, shall remain unchanged.

d) Applications for exceptions to these well location provisions, relative to a drilling unit boundary 

or other location in a common source of supply, may be approved by the Commission after notice 

and a hearing in accordance with General Rules A-2, A-3 and other applicable hearing 

procedures. 

(Source: new rule February 19, 2009)
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GENERAL RULE D - GAS

RULE D-1: REPEALED

Rule Repealed Effective October 16, 1953.

RULE D-2: REPEALED

Rule Repealed Effective February 19, 2009

RULE D-3: REPEALED

Rule Repealed Effective February 19, 2009

RULE D-4: REPEALED

Rule Repealed Effective February 19, 2009

RULE D-5: REPEALED

Rule Repealed Effective February 19, 2009

RULE D-6: REPEALED

Rule Repealed Effective February 19, 2009
GENERAL RULES AND REGULATIONS

153

RULE D-7: NATURAL GAS TO BE METRED

a) Wellhead Production Meters:

1) For protection of correlative rights of all parties, the operator of a natural gas well shall 

meter or caused to be metered all natural gas produced from a well, utilizing a standard 

industry meter approved by the American Gas Association and capable of recording 

accurately the volume of natural gas produced at each well, unless another methodology, 

approved by the Director, is utilized to provide for proper production allocation back to 

the individual well from a central point production meter or central point sales meter, 

which ever meter occurs first.

2) All required meters shall be calibrated at least once per calendar year. The records of 

such calibration shall be maintained or made available by the operator of the well and 

shall be available for inspection by the Commission. Such records shall be maintained by 

the operator for a period of at least five (5) years. 

3) All required meters shall be accessible and viewable by the Commission for the purpose 

of monitoring daily, monthly and/or cumulative production volumes from individual 

wells.

b) Sales Meters:

All meters, measuring the volume of gas sold, shall be calibrated at least once per year. The 

Director or his designee shall be notified not less than seventy-two (72) hours prior to conducting 

the meter calibration, so as to allow the Commission to witness such calibration. The records of 

such calibration shall be maintained by the person responsible for the meter and shall be available 

for inspection by the commission. Such records shall be maintained by the person responsible for 

the meter for a period of 5 years. 

(Source: 1991 rule book; amended January 22, 2009)
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RULE D-8: MONTHLY NATURAL GAS PRODUCTION REPORTS

a) All natural gas produced and sold from oil wells and from gas wells within the State of Arkansas, 

except natural gas taken into a gasoline, cycling or other extraction plant gathering system, which 

is required to be reported in accordance with the provisions of Rule F-3, shall be reported by the 

operator monthly in a form prescribed by the Director. In cases where gas is sold by any person 

other than the operator, the operator shall remain responsible for reporting all production sold, 

unless the operator notifies the Director in writing of the name and address of the person other 

than the operator who has sold gas, the specific month or months for which the person other than 

the operator who sold gas has failed to report the necessary information to the operator and the 

approximate well ownership percentage of the person other than the operator who has sold gas. 

Any person other than the operator who sold gas and failed to report the necessary information to 

the operator shall then be responsible for reporting the monthly production sold, not otherwise 

reported by the operator, to the commission. 

b) Monthly reports specifying the amount of natural gas produced and sold are required to be filed 

for each individual producing zone or approved commingled producing zones within a well, 

regardless of whether or not there was natural gas produced and sold during the month. The 

reports shall be filed on a form prescribed by the Director and shall be filed with the commission 

sixty (60) days after the end of each month. Reports for inactive wells shall continue to be 

submitted until such time as the commission determines monthly reports are no longer required in 

accordance with applicable commission rules and regulations.

c) Where natural gas is delivered to a gasoline extraction plant, cycling plant or any other plant at 

which butane, propane condensate, kerosene, oil, or other liquid products are extracted from 

natural gas, such gas shall be reported in accordance with General Rule F-3.

(Source: 1991 rule book; amended November 16, 2008; amended August 21, 2009)
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RULE D-9: GAS-OIL RATIO

No well shall be permitted to produce gas in excess of the maximum ratio determined for a common 

source of supply unless all gas produced in excess thereof is returned to the common source of supply 

from which it was produced.

(Source: 1991 rule book)
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RULE D-10: GAS-OIL RATIO SURVEYS AND REPORTS

By special order the Commission will authorize periodic gas-oil ratio surveys and reports to be filed on 

forms furnished by the Commission and including thereon for each well:

Field, reservoir and county in which the well is located; lease name and well number; elevation; 

producing formation; size and length of tubing; size and length of casing (oil string); size choke (if 

pumping well, so designate); tubing pressure, casing pressure, and trap pressure; production of water; oil 

and gas (in thousands of cubic feet) during the test; gas-oil ratio; and the A.P.I. gravity of the oil; duration 

of test.

All data requested is for each well separately and the gas-oil ratio shall be determined according to the 

following procedure:

(1) FLOWING WELLS CONTINUOUSLY PRODUCED:

The oil flow shall be stabilized during the 24-hour period immediately preceding the test at a rate 

fixed as nearly as possible to its allowable as shown on the Commission’s current oil proration 

schedule. Major adjustments in the rate of flow shall be made during the first 12 hours of the 

stabilization period and only minor adjustments made during the last 12 hours. No adjustments shall 

be made during the time in which the well is being tested and the rate of production during the test 

shall not be less than the well’s daily allowable. Should gas be withdrawn from the casing in an 

attempt to maintain a fluid seal, or for any other reason, this volume of gas must be added to gas 

produced through tubing in computing the gas-oil ratio.

(2) FLOWING WELLS INTERMITTENTLY (STOP-COCKED) PRODUCED:

In computing the operating gas-oil ratio the total volume of gas and the total barrels of oil that are 

produced in order to obtain the daily oil allowable must be used regardless of the flowing time in the 

24-hour period.

(3) GAS LIFT OR JET WELLS:

The total volume of gas to be used in computing the operating gas-oil ratio is the total output volume 

minus the total input volume.

(4) PUMPING WELLS:

Should gas be withdrawn from the casing in an attempt to maintain a fluid seal, or for any other 

reason, this volume of gas must be added to gas produced through tubing in computing the gas-oil 

ratio.

(Source: 1991 rule book)
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157

RULE D-11: PIPELINE MAPS

Pipeline maps indicating the location, size, extensions and any portions abandoned or not used shall be 

filed at the request of the Commission.

(Source: 1991 rule book)
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158

RULE D-12: GAS UTILIZATION

After the expiration of seven (7) days from the time of encountering gas in a gas well, no gas from such 

well shall be permitted to escape, into the air, and all gas produced therefrom shall be utilized for the

following purposes:

(A) No gas well gas shall be utilized except for:

(1) Light or fuel.

(2) Efficient chemical manufacturing.

(3) Bona fide introduction of gas into oil, or gas bearing horizon, in order to maintain or 

increase the reservoir pressure or otherwise increase the ultimate recovery of oil or gas 

from such horizon.

(4) The extraction of natural gasoline therefrom when the residue is returned to the horizon 

from which it is produced.

(B) Casinghead gas may be used for any beneficial purpose.

(C) Any producer of gas may use the same as gas lift in the bona fide production of oil where such 

gas is not used in excess of ten thousand (10,000) cubic feet per barrel of oil produced; provided 

that in order to prevent waste in any case where the facts in such warrant it, the Commission may 

permit the use of additional quantities of gas to lift oil, provided all such gas so used in excess of 

ten thousand (10,000) cubic feet for each barrel of oil shall be processed for natural gasoline 

when same is reproduced.

(Source: 1991 rule book)
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159

RULE D-13: USE OF GAS FOR OTHER THAN LIGHT OR FUEL

Before any person shall engage in the utilization of gas for purposes other than light and fuel he shall file 

with the Commission a verified statement setting for the name and addresses of the person or persons who 

are to engage in the proposed operations, the location of the plant of plants where the proposed utilization 

is to be carried on, the kind and probable volume of the gas that is to be used, the reservoir from which it 

is to be taken, the general type of the process, and the kind and condition of the equipment that is to be 

used, the results to be obtained in so far as such results can be reasonably anticipated, and such other 

pertinent facts as the Commission may require. Upon filing said statement the Commission may, if it 

deems the same necessary, conduct a public hearing with reference to the proposed utilization in order to 

determine whether such utilization or the use of the proposed processes and equipment will constitute 

waste.

(Source: 1991 rule book)
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160

RULE D-14: GAS ASSESSMENT

An assessment to pay the conservation expenses and other costs in connection with administration of gas 

conservation, not otherwise provided for, may be made as follows:

(A) There shall be assessed against the persons involved, a charge not to exceed ten (10) mills on 

each one thousand (1,000) cubic feet of gas produced and saved each month from a well. Said 

assessments shall apply only to the first purchase of gas, or the original taking from the well, and 

not the subsequent transfers, commonly referred to as “tenderships.” Effective on and after 

January 1, 2002, the gas conservation assessment shall be 9 mills. 

(B) The person selling gas at the first point of sale, who is hereby defined to be the party initially 

responsible for distributing the 1/8 royalty interest shall, before paying for the production, deduct 

nine (9) mills for every thousand cubic feet of gas produced and removed from the lease each 

month, and remit the amounts so deducted to the Commission at the same time and periods as 

said purchasers make their regular gas payments.

(C) Said remittances may be made each month in a single check if the person selling gas at the first 

point of sale so desires and no accounting by the person selling gas at the first point of sale shall 

be required except to show all deductions on the regular payment statements to producers and 

royalty owners or the parities in interest.

(D) The assessment herein provided for shall not apply to gas which is being returned to the ground 

for repressuring or pressure maintenance purposes within the field, but shall apply only to such 

gas as is produced and removed from the lease and returned to the ground for storage purposes.

(E) Any person selling gas at the first point of sale in this state at the well, under any contract or 

agreement requiring payment for such production to the respective owners thereof, in respect of 

which production any sums assessed under these rules are payable to the Commission, is hereby 

authorized, empowered and required to deduct from any sum so payable to any such person the 

amount due the Commission by virtue of any such assessment and remit that sum to the 

Commission.

Further, any person taking gas from any well in this state for use or resale, in respect of which 

production any sums assessed under the provisions of this rule are payable to the Commission, 

shall remit any sum so due to the Commission in accordance with these rules and regulations.

(Source: 1991 rule book; amended Novermber 27, 2001; amended October 24, 2009)
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161

RULE D-15: MEASURING GAS AT CUSTODY TRANSFER POINTS

(a) No meter or meter run used for measuring gas at custody transfer points will be equipped with a 

manifold which will allow gas flow to be diverted or bypassed around the metering element with 

the following exceptions:

(1) Equipment which permits the changing of the orifice plate without bleeding the pressure 

off the gas meter run shall not be considered a bypass if flow is bypassed only during 

normal maintenance or verification operations.

(2) A manifold having block valves on each end of the meter run, and two bypass valves 

with a bleeder between the bypass valves. During normal operations, the two bypass 

valves will be closed, with at least one bypass valve sealed, and the bleeder valve will be 

open and unplugged.

(b) Whenever the manifold described in Section (a)(2) is employed, a notation will be made on the 

orifice meter chart any time a seal is broken or replaced. This notation will include the seal 

number broken, the seal number replaced, the reasons for this action, and graphic representation 

of the estimated gas flow during the time the meter is out of service.

(c) The party choosing to utilize, construct, or operate a bypass of the type described in Section (a)(2) 

will assume all risks, responsibilities, and liabilities associated with said bypass.

(d) Existing meters used for measuring gas at custody transfer points shall be retrofitted in 

conformity herewith within twenty-four (24) months from the effective date hereof; provided, 

however, that meters to be installed at additional transfer points from and after the effective date 

hereof shall be in conformity herewith.

(Source: 1991 rule book)
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162

RULE D-16: BACK PRESSURE TESTS FOR NATURAL GAS PRODUCTION 

ALLOWABLE DETERMINATION

a) Applicability

This rule shall only apply to dry natural gas wells for which it is necessary to determine the PRU 

Deliverability in accordance with General Rules A-7, B-43, B-44, D-19, D-21, or the request of 

the Director, or his designee, to conduct a back pressure test on a dry natural gas well.

b) Definitions 

1) “Existing PRU” shall mean a production reporting unit, which is either an individual 

sources of supply or approved commingled producing zones within a dry natural gas well 

which was previously productive prior to the effective date of this rule.

2) “IOPT” shall mean an Initial One-Point Test performed to determine PRU Deliverability.

3) “New PRU” shall mean a production reporting unit, which is either an individual 

producing zone (in a newly drilled dry natural gas well or a new zone in an existing dry 

natural gas well) or approved commingled producing zones within a dry natural gas well 

which becomes productive after the effective date of this rule.

4) “Permit Holder” shall mean the person to whom the permit is issued and is responsible 

for all regulatory requirements relative to the production well. 

5) “Production Test” shall mean any One-Point Test that is performed to determine PRU 

Deliverability which occurs after a successful One-Point Test has been performed. 

6) "PRU Deliverability" shall mean the measured volume of dry natural gas from an 

Existing or New PRU under normal operating conditions for that Existing or New PRU 

as determined by the IOPT or Production Test.

c) An IOPT shall be conducted for any New PRU for the purpose of determining the PRU 

Deliverability. If a New PRU cannot be tested to determine the PRU Deliverability, a written 

explanation setting forth in detail the reasons why such IOPT cannot be obtained shall be 

submitted, along with a request for an alternative methodology to determine the PRU 

Deliverability. 

d) Further Production Testing of an Existing or New PRU following an IOPT is not required except 

for purposes of retesting at the request of the Permit Holder to establish a penalty allowable in 

accordance with General Rule D-21, determining marginal well status for severance tax purposes 

in accordance with General Rule A-7, an additional completion request in accordance with D-19, 

or if requested by the Director or his designee. 

e) IOPT or Production Testing Requirements: 

1) Notice – The Permit Holder of the PRU shall provide notice in the manner prescribed by 

the Director, or his designee, at least seventy-two (72) hour notice in advance of an IOPT 

or a Production Test. 

2) When to Conduct Test – The Permit Holder shall conduct the IOPT within ten (10) 

calendar days of commencement of production of a New PRU. The Director, or his 

designee, shall retain the right to require a re-test of an Existing or New PRU at any time. 
GENERAL RULES AND REGULATIONS

163

Additionally, the Permit Holder shall have the right to request a retest of an Existing or 

New PRU at any time.

3) Filing of Documents – The Permit Holder shall submit the results of the IOPT or 

Production Test within ten (10) business days of the test date.

4) AOGC Staff Witness – The IOPT is required to be witnessed by a representative of the 

AOGC unless the Permit Holder is notified by the AOGC that the test shall not be 

witnessed. Production tests for purposes of establishing marginal well determination, in 

accordance with General Rule A-7, are required to be witnessed by a representative of the 

AOGC. AOGC staff witness will be subject to notice by the Permit Holder in 

accordance with subparagraph (e) (1) above and subject to availability of an AOGC staff 

witness. All tests shall be conducted during normal working hours of the Commission 

unless otherwise approved by the Director or his designee.

f) Testing Methodology – An IOPT or Production Test shall be conducted to determine the PRU 

Deliverability. All tests shall be reported on a form prescribed by the Director, or his designee, 

and conducted as follows: 

1) Before a test is started, the wellbore should be cleared of any accumulated fluids.

2) The Dry Natural Gas from the Existing or New PRU shall be flowed through the 

production facilities into the pipeline for a minimum of 24 hours. All flow rate 

measurements shall be obtained by the use of an orifice meter or other authorized 

metering device in good operating condition previously approved the Director or his 

designee.

3) Should the flow rate not be obtained to determine PRU Deliverability, the Permit Holder 

shall provide a written explanation setting forth in detail the reasons why such flow rate 

could not be obtained in accordance with this procedure. The Director, or his designee, 

may authorize an alternative method to determine PRU Deliverability.

(Source: 1991 rule book; amended (Order No. 74-94) October 25, 1994; amended October 1, 2000; 

amended January 14, 2008; amended February 19, 2009; amended August 21, 2009; amended August 01, 

2014)
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164

RULE D-17: GENERAL RULE FOR THE REGULATION OF NATURAL GAS 

PIPELINES

a) Definitions

1) Jurisdictional Pipeline means any onshore natural gas pipeline regulated under Federal 

Regulation 49 CFR Part 192 as amended, which is within the jurisdiction of the Arkansas 

Oil and Gas Commission in accordance with Ark. Code Ann. § 15-71-110 as amended. 

2) Non-Jurisdictional Pipeline means any onshore natural gas pipeline, including but not 

limited to flowlines, production lines, or gathering lines, not under jurisdiction of Federal 

Regulation 49 CFR Part 192 as amended, which is within the jurisdiction of the Arkansas 

Oil and Gas Commission in accordance with Ark. Code Ann. § 15-71-110 as amended. 

3) Perennial Stream means: a stream that has flowing water year-round during a typical 

year, the water table is located above the stream bed for most of the year, groundwater is 

the primary source of water for stream flow, and runoff from rainfall is a supplemental 

source of water for stream flow.

4) Pipeline Operator means any person who owns or operates and is responsible for the 

construction, operation and maintenance of a natural gas pipeline which transports natural 

gas from the well within the jurisdiction of the Arkansas Oil and Gas Commission in 

accordance with Ark Code Ann. § 15-71-110 as amended.

b) Applicability

1) For purposes of this Rule, the jurisdiction of the Arkansas Oil and Gas Commission, as 

specified in Ark Code Ann. Ann. § 15-71-110 as amended, extends and includes:

A) The production process or production facility as defined in Ark Code Ann. § 15-

71-110 as amended; or

B) A natural gas pipeline or associated facility whose owner is not affiliated with an 

Arkansas natural gas public utility and the majority owner is either a production 

company or an affiliate of a production company.

2) Every Pipeline Operator transporting natural gas by pipeline from the well is subject to 

the applicable provisions of this rule. Natural gas pipelines from the well, to a custodial 

transfer meter located on the well pad, are exempt from the provisions of this rule. 

c) General Requirements for all Jurisdictional and Non-Jurisdictional Pipelines:

1) Each Pipeline Operator shall apply, on a form prescribed by the Director, for an initial 

statewide permit to construct and operate a natural gas pipeline system. The initial permit 

application shall contain at a minimum the following: 

A) Name, address and contact information for the Pipeline Operator;

B) Map, or other media acceptable to the Director, showing the location of all 

natural gas pipelines from the producing wells through any production or 

processing equipment or treating facility, and to the termination point of the 

jurisdiction of the Arkansas Oil and Gas Commission, including all public road, 

railroads and perennial stream crossings;
GENERAL RULES AND REGULATIONS

165

C) A determination as to what pipelines are jurisdictional; 

D) Submission of the applicable permit fee as follows:

(i) no permit fee is required for 1 mile or less, provided the pipeline

does not cross a public road, railroad or perennial stream.

(ii) less than 50 miles of pipeline, including pipelines in (c)(1)(D)(i) above 

which cross public roads, railroads or perennial streams - $500.00

(iii) 50 miles to less than 100 miles of pipeline - $1,500.00

(iv) 100 miles to less than 250 miles of pipeline -$2,500.00

(v) 250 miles or more of pipelines - $5,000.00

2) Each Pipeline Operator shall be required to submit an annual permit renewal by January 

31 of each year.

3) The renewal permit shall include a revised pipeline map showing any new pipeline 

additions constructed during the previous year, an annual report on a form prescribed by 

the Director, along with a permit renewal fee in accordance with paragraph (c)(1)(D) 

above. The renewal permit shall also contain the Pipeline Operator’s determination as to 

which pipelines are jurisdictional.

4) Each Pipeline Operator shall submit a Notice of Construction or Repair, on a form 

prescribed by the Director, prior to commencing construction or within 48 hours after 

completing repair, for each segment or project length of pipeline constructed during the 

year. The Notice shall indicate the location and extent of the natural gas pipelines to be 

constructed or repaired.

5) Each Pipeline Operator shall notify the Director, or his or her designee, within five (5) 

calendar days of exceeding any natural gas pipeline’s established maximum allowable 

operating pressure. This shall be submitted on a form prescribed by the Director.

6) Each Pipeline Operator shall submit a Notice of Incident, on a form prescribed by the 

Director for each incident of release due to natural gas pipeline failure which results in:

A) A death or personal injury requiring in-patient hospitalization; or

B) A total cost of repair, including the value of natural gas lost, of ten thousand 

dollars ($10,000) or more; or

C) An event that is significant, in the judgment of the operator, even though it did 

not meet the criteria of subparagraphs (A) or (B) above.

d) Requirements for all Non-Jurisdictional Pipelines

1) All pipelines crossing any stream or stream bed shall comply with applicable state and 

federal rules and regulations. Additionally, any stream crossing of perennial streams, 

constructed on or after December 16, 2007, shall maintain a minimum of fifty (50) feet of 

undisturbed stream bank for the protection of the stream. However, the fifty (50) feet of 
GENERAL RULES AND REGULATIONS

166

undisturbed stream bank requirement may be modified by the Director provided that the 

Pipeline Operator provides proof that the Pipeline Operator has received approval for the 

crossing from a state or federal agency.

2) Each Pipeline Operator shall place and maintain appropriate signage at all natural gas 

pipeline crossings of public roads and railroads. The marker should include the words 

“Warning”, “Caution” or “Danger” followed by the words “Gas Pipeline” along with the 

Pipeline Operator’s name and telephone number where the Pipeline Operator can be 

reached at all times.

3) Each Pipeline Operator which operates natural gas pipelines within the limits of any 

incorporated or unincorporated city, town or village, shall be a member of a qualified 

one-call program. 

4) All natural gas pipelines, constructed after the effective date of this rule, shall be buried

at least twenty-four (24) inches below ground surface, or in accordance with other 

applicable state or federal laws.

e) Requirements for Jurisdictional Pipelines

1) All Jurisdictional Pipelines shall be in compliance with construction, operation and

maintenance requirements contained in Federal Regulations 49 CFR Part 192 Subpart A 

thru Subpart P as amended, which are herein incorporated by reference.

2) All Jurisdictional Pipelines shall be subject to the applicable enforcement provisions of 

Federal Regulation 49 CFR Part 190 as amended, which are herein incorporated by 

reference.

3) All Jurisdictional Pipelines shall be subject to the applicable incident and other reporting 

requirements contained in Federal Regulation 49 CFR Part 191 as amended, which are 

herein incorporated by reference, and all such reports shall be submitted to the Arkansas 

Oil and Gas Commission.

4) All Pipeline Operator of Jurisdictional Pipelines shall be subject to the applicable drug 

and alcohol testing requirements contained in Federal Regulation 49 CFR Part 199 as 

amended, which are herein incorporated by reference.

5) All Jurisdictional Pipelines which contain over 100 PPM hydrogen sulfide shall also be 

subject to the provisions of subparagraph (f) below, unless the provisions of 

subparagraph (f) are less stringent than any applicable requirement of this subparagraph 

(e).

f) Additional Requirements for All Pipelines Containing 100 PPM or Greater Hydrogen Sulfide. 

1) Construction, Operating and Maintenance Requirements:

A) All pipeline materials must be chemically compatible with any natural gas 

transported by the natural gas pipeline and such pipeline shall maintain structural 

integrity under the anticipated temperatures and environmental conditions for 

which the natural gas pipeline may be exposed, and 
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167

B) All piping must be of sufficient thickness or must be installed with adequate 

protection to withstand anticipated external pressures and loads that will be 

imposed on the pipe after installation, and

C) No natural gas pipeline may be operated after new construction, repair or 

relocation until it has been successfully tested for at least one hour with a 

minimum pressure of 1.25 times the maximum operating pressure to substantiate 

the maximum operating pressure with all leaks located and eliminated, and

D) All metallic natural gas pipelines must be adequately protected from both 

external and internal corrosion and the Pipeline Operator is required to submit an 

annual report, by March 31st of every year for the preceding calendar year, of the 

effectiveness of the company’s corrosion program, with such protection efforts 

performed by an independent contractor specializing in the control of corrosion.

2) Each Pipeline Operator shall prepare, maintain and follow for each natural gas pipeline, a 

manual of written procedures for conducting operations, maintenance activities and 

emergency response. This plan must be reviewed and updated as often as necessary. A 

review must be conducted annually but not to exceed 15 months between reviews. 

3) Each Pipeline Operator shall have a procedure for continuing surveillance of its facilities 

and take appropriate action regarding, failures, corrosion and operating conditions.

4) Each Pipeline Operator must develop and carry out a damage prevention program to 

prevent damage to its natural gas pipelines from excavation activities. Each Pipeline 

Operator shall be a member of the state wide “one-call” system. The plan must have a 

method of communicating to excavators in the area where the natural gas pipeline is 

located of the existence of the natural gas pipeline, provide a means of receiving and 

recording notification of planned excavation activities, provide for temporary marking of 

the natural gas pipeline and inspection of the natural gas pipeline when the Pipeline 

Operator has reason to believe it could be damaged by excavation activities.

5) Each Pipeline Operator shall establish written procedures to minimize the hazards 

resulting from a natural gas pipeline emergency event. Each plan must include at a 

minimum:

A) Methods of receiving and identifying an event which requires immediate 

response; and

B) Methods for establishing and maintaining adequate communication with 

appropriate emergency response and public officials; and

C) Methods for determining safe areas related to evacuation and security during an 

event; and

D) Methods for training employees of their duties and responsibilities during an 

event.

6) Each Pipeline Operator shall develop and implement a written continuing public 

awareness plan which includes provisions for educating the public, appropriate 

governmental organizations and persons engaged in excavation activities. Use of a onecall notification prior to conducting excavation, possible hazards associated with 

unintended releases from the natural gas pipeline, physical indications that such a release 
GENERAL RULES AND REGULATIONS

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may have occurred, steps that should be taken for the safety of the public, procedures for 

reporting such an event. The program must include activities to advise affected 

municipalities, schools, businesses and residents along the pipeline right of way. The 

program and media used must be as comprehensive as necessary to reach all areas in 

which the Pipeline Operator shall transport gas.

7) Each Pipeline Operator shall establish procedures for analyzing accidents and failures for 

the purpose of determining the cause of the failure and minimizing the possibility of 

subsequent reoccurrence.

8) Each Pipeline Operator shall not operate any natural gas pipeline at a pressure that 

exceeds the documented pressure at which the natural gas pipeline may be safely 

operated.

9) Each Pipeline Operator shall have a patrol program to observe surface conditions on and 

adjacent to its pipeline right-of-way for indications of leaks, construction activity, 

erosion, condition of signage, conditions at public road and railroad crossings and other 

factors affecting safety and operation of the pipeline. Patrols shall be conducted and 

documented at least twice each calendar year, not to exceed 7 1⁄2 months between patrols.

10) Each Pipeline Operator shall maintain appropriate pipeline markers at all public road and 

railroad crossings and along the pipeline at intervals necessary to identify the location of 

the buried pipeline. The marker should include the words “Warning”, “Caution” or 

“Danger” followed by the words “Gas Pipeline” along with the Pipeline Operator’s name 

and telephone number where the Pipeline Operator can be reached at all times.

11) Each pressure relieving device in a compressor station, pressure limiting station or 

regulator station must be inspected, tested and operated at the pipelines maximum 

operating pressure, once each calendar year and not to exceed 15 months to determine 

proper operation.

12) Each remote controlled shutdown device must be inspected and tested once each calendar 

year and not to exceed 15 months to determine proper operation.

13) Each line valve that serves to block a segment of pipeline and or might be used in an 

emergency, must be inspected and partially operated once each calendar year and not to 

exceed 15 months.

14) Each Pipeline Operator shall maintain records associated with operation and maintenance 

of the pipeline required in this section.

15) Each natural gas pipeline abandoned in place must be disconnected from all sources of 

gas, purged of gas, filled with freshwater or inert material and sealed at both ends. When 

a pipeline is being purged all efforts must be taken to (i) prevent the formation of a 

hazardous mixture of gas and air, (ii) ensure that all safety equipment necessary is 

present, (iii) remove all non-essential persons from the area and (iv) ensure the public is 

adequately protected.

(Source: (Order No. 90-97) October 28, 1997; amended December 16, 2007; amended September 14, 

2008; amended October 24, 2009; amended January 20, 2014)
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169

RULE D-18: AUTHORITY TO COMMINGLE

a) This rule authorizes the Director of Production and Conservation, or his designee, to approve 

certain commingle requests as detailed in this rule. This rule is applicable for administrative 

approval of commingling of multiple common sources of supply on an individual well basis only, 

and includes previously completed and/or uncompleted sources of supply in a well, with no 

restriction on rate of production. The rule is not applicable on a field-wide basis.

b) All common sources of supply classified by the Commission as uncontrolled, are exempt from 

the provisions of this rule and are permitted to be commingled without application, only when 

commingled with other uncontrolled sources of supply. Upon completion of the commingling 

activities, reporting in accordance with Rule B-5 is required. 

c) All common sources of supply previously approved and commingled in wells before the effective 

date of this rule are allowed to continue in effect for the life of the well.

d) Commingling is permitted without application for the Middle Atoka, as defined by General Rule 

B-44 (a) (4). Upon completion of commingling activities, reporting in accordance with Rule B-5 

is required.

e) Requests for the commingle of common sources of supply with a well, or at the surface of a well 

in the following well categories, are not subject to the administrative approval process set forth in 

this rule, and must be brought before the Commission for approval following proper notice and 

hearing:

1) A wildcat well; or

2) A well located within an exploratory unit established by Commission Order; or

3) A well in which the commingling of multiple common sources of supply will result in an 

unapproved additional completion within the drilling unit; or

4) A well in which the primary reservoir drive mechanism for a requested zone to be 

commingled is a water drive; or

5) A well in which the ownership between the commingled zones is not common, unless all 

owners, as defined in Ark. Code. Ann. (1987) § 15-72-102(9), in the well agree in 

writing; or

6) A well in which spacing requirements are different between commingled zones.

f) Application to commingle common sources of supply in accordance with this rule shall be 

submitted on a form prescribed by the Director of Production and Conservation and shall include, 

at a minimum:

1) The operator’s contact information;

2) The name and location of the well;

3) The perforated intervals to be commingled; 

4) A plat showing well locations in the unit indicating all common sources of supply to be 

commingled;
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5) A statement as to whether the primary reservoir drive mechanism for the requested 

commingled zone is a water drive;

6) A statement as to whether all zones to be commingled have common spacing 

requirements;

7) A statement as to whether any of the requested zones to be commingled are subject to a 

location exception order, the penalty for which will be applied to the commingled 

production; 

8) Proof of notice sent to all offset operators, of the right to drill and produce in all adjacent 

units, of the intent to commingle.

g) Upon review and approval of the application and if no objections are received by the Director of 

Production and Conservation within 15 days of the date of the notice sent to each adjacent offset 

operator or if the application is accompanied by written acceptance by the offset operators of the 

commingle request, the application for commingling shall be approved. Approved applications 

are only valid for one year from date of issuance, unless commingling activities have been 

commenced prior to that time.

h) Following approval of the commingle application, the applicant shall submit to the Director of 

Production and Conservation, the following: 

1. Completed Well Completion and Recompletion Report, and

2. Rates and pressures for each commingled zone, unless a staged frac completion technique 

has been used in the well.

i) If the Director of Production and Conservation receives an objection to a commingle application 

during the notice period specified in (f) above, or if the application does not satisfy the 

requirements of this Rule and is denied by the Director, the applicant may request to have the 

matter placed, in accordance with General Rules A-2, A-3, and other established procedures, on 

the docket of a regularly scheduled Commission hearing.

(Source: new rule February 2, 2006; amended January 22, 2009; amended June 5, 2009)
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RULE D-19: ADDITIONAL COMPLETIONS WITHIN COMMON SOURCESOF 

SUPPLY WITHIN A DRILLING UNIT

a) This rule is applicable for administrative approval, by the Director of Production and 

Conservation, of additional completions, within common sources of supply, within established 

drilling units located in fields covered by field rules.

b) This rule is not applicable on a field-wide basis, or within Exploratory Units.

c) Application for additional completions shall be submitted to the Director of Production and 

Conservation on a form prescribed by the Director, and contain the following information:

1) The location of the unit;

2) The location of all well(s) showing the productive zones in each well within the unit for 

which the additional completions are requested;

3) Initial and current pressure(s) and current rates and, cumulative production for each 

completion within a common source of supply;

4) A structure and isopach map of the common source of supply; 

5) A unit cross-section, including the wells for which the additional completion is requested; 

6) A statement as to whether there is common ownership within the wells producing from 

the common source of supply within the unit; and 

7) If applicable, the drainage characteristics for each well within the common source of 

supply;

d) In addition, each application shall provide proof of written notice to all owners, as defined in Ark. 

Code Ann. § 15-72-102(9), in the subject unit and all offset operators in all adjacent established 

units including all owners, as defined by Ark. Code Ann. § 15-72-102(9) in any offset unit where 

the operator is the same as the applicant. 

e) The notice shall contain at a minimum, the name of the applicant, the name and location of the 

well, the zone subject to the additional completion request, and instructions as to the filing with

the Director of Production and Conservation written objections within fifteen (15) days after 

receipt of the application by the Director of Production and Conservation 

f) Any offset operator or owner noticed in accordance with paragraph e) above shall have the right 

to object to the granting of such application within fifteen (15) days after receipt of the 

application by the Director of Production and Conservation.

g) Upon review of the application and if the submitted evidence or requested additional evidence 

indicates that:

1) Stratigraphic or structural separation of the common source of supply can reasonably be 

demonstrated; or

2) The irregular shape and/or size of the drilling unit relative to the drainage characteristic 

of the well within the common source of supply necessitate an additional completion; or
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172

3) The drainage characteristics of the well within the common source of supply in a regular 

shape and size drilling unit demonstrate an additional completion is necessary to 

effectively drain the unit; or

4) The pressure data from the common source of supply indicates less than a 20% reduction 

in the original pressure 5 years after the first completion in that same source of supply; or

5) The other unit completion(s) in the common source of supply have each produced less 

than 75 MCF per day over the twelve month period prior to the additional completion 

application or a newly drilled well, which is the subject of the additional completion 

request, and which is only able to produce less than 75 MCF per day absolute open flow; 

and

6) If ownership within the wells in the common source of supply within the unit is not 

common, but evidence of agreement between the owners is provided with the additional 

completion application; and 

7) If an objection is not received within 15 days after the receipt of the application, the 

Director of Production and Conservation shall approve the application. 

h) If an objection is received or if the application does not satisfy the requirements of this Rule, the 

application shall be denied. If an application is denied, or if the reason for an additional 

completion request is not addressed by this rule, the Applicant may request to have the matter 

placed, in accordance with established procedures, on the docket of a regularly scheduled 

Commission hearing.

(Source: new rule February 2, 2006; amended April 13, 2008)
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173

RULE D-20: NOISE LEVEL REQUIREMENTS FOR NON-WELLHEAD 

COMPRESSOR FACILITIES

a) Applicability: 

1) The provisions of this rule apply to all non-wellhead compressor facilities or stations 

used in the production process, as defined in Ark Code Ann. § 15-71-110 as amended, or 

whose owner is not affiliated with an Arkansas natural gas public utility and the majority 

owner is either a production company or an affiliate of a production company.

2) All non-wellhead compressor facilities in operation as of the initial effective date of this 

rule shall be in compliance with the provisions of this rule by July 1, 2012.

3) All non-wellhead compressor facilities that become operational after the initial effective 

date of this rule shall be in compliance with the provisions of the rule within one year of 

commencing compressing operations.

b) Definitions:

1) “ANSI” means the American National Standards Institute, and any reference to an ANSI 

publication shall refer to the version that was in effect as of January 1, 2011, unless 

otherwise stated.

2) “Leq” means the Equivalent Continuous Sound Level which is the notional sound 

pressure level which, if maintained constant over a given time, delivers the same amount 

of acoustic energy at some point as the time-varying sound pressure level would deliver 

at the same point and over the same period of time.

3) “Noise sensitive area" means a building with an established mailing address that is being 

utilized as a private residence, school, hospital, church, nursing home, or other building 

of a type that is regularly used for overnight accommodation.

4) “Non-well head compressor facility or station” means any compressor facility or station 

used for the purpose of compressing natural gas for pipeline transportation. This shall 

not include a compressor facility or station located on a well pad for the purpose of 

enhancing production of natural gas from the well or wells located on the pad.

5) “Normal full-load operating conditions” means the normal operating condition of the 

non-wellhead compressor facility or station, excluding accidents, emergency situations, 

other unforeseen temporary operational deviations, including without limitation the 

performance of maintenance or construction activities. 

c) The noise levels for a non-wellhead compressor facility or station during normal full-load 

operating conditions shall not exceed 55 dB(A) Leq, as measured from the exterior of the nearest 

noise sensitive area existing at the time of commencement of initial construction of the nonwellhead compressor facility or station. 

d) Noise levels shall be measured as follows:

1) By utilizing a Type 1 sound level meter, as defined in ANSI S1.4, set for A-weighting per 

ANSI S1.11, and slow meter response.
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174

2) Sound level measurements shall be in substantial compliance with standard 

environmental acoustical measurement practices as outlined in ANSI S12.9.

3) The Leq contribution due to a non-wellhead compressor facility or station shall be 

determined using short-term sound level averages taken during periods with minimal 

audible intrusion from extraneous sources other than the non-wellhead compressor 

facility or station under test. The following extraneous noise shall be excluded from the 

measurements to the fullest extent possible:

a) Wind;

b) Vehicular Traffic;

c) Residential heating, ventilating, and air conditioning;

d) Aircraft over-flights;

e) Bird sounds; 

f) Insect sounds; and 

g) Other noise generating equipment unrelated to the non-wellhead compressor 

facility or station.

e) Any owner or operator of a non-well head compressor facility or station found to be in violation 

of the provisions of this rule shall pursue with reasonable diligence a remedy to correct the 

violation. Any violation shall be considered an “operational” violation in accordance with 

General Rule A-5.

(Source: new rule November 1, 2011)
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175

RULE D-21: PROCEDURES FOR DETERMINING THE PRODUCTION 

ALLOWABLE FOR DRY NATURAL GAS PRODUCTION WELLS

a) Applicability

This rule shall only apply to dry natural gas wells for which it is necessary to determine the PRU 

Deliverability in accordance with General Rules B-43, B-44 and other applicable General Rules, 

Field Rules or Commission Orders. This rule shall not apply to any PRU subject to provisions of 

General Rule B-45.

b) Definitions 

1) “Allowable” shall mean the PRU Deliverability for a New or Existing PRU is allowed to 

produce and sell on a per day basis.

2) “Encroachment Footage” shall mean the actual footage of the New or Existing PRU 

from the drilling unit boundary, when that footage is less than the Setback Footage 

specified by rule.

3) “Existing PRU” shall mean a production reporting unit, which is either an individual 

producing zone or approved commingled producing zones within a dry natural gas well 

which was previously productive prior to the effective date of this rule.

4) “New PRU” shall mean a production reporting unit, which is either an individual 

producing zone (in a newly drilled dry natural gas well or a new zone in an existing dry 

natural gas well) or approved commingled producing zones within a dry natural gas well 

which becomes productive after the effective date of this rule.

5) “Penalty Allowable” shall mean the PRU Deliverability of the New or Existing PRU, 

subject to a Penalty Factor, a New or Existing PRU is allowed to produce and sell on a 

per day basis.

6) “Penalty Factor” shall mean the factor which is multiplied by the New or Existing PRU 

to impose a penalty (or reduction) upon the PRU Deliverability.

7) "PRU Deliverability" shall mean the measured volume of dry natural gas from an 

Existing or New PRU under normal operating conditions for that Existing or New PRU 

as determined by the IOPT or Production Test conducted in accordance with General 

Rule D-16. 

8) “Setback Footage” shall mean the required minimum distance a New or Existing PRU 

must be from the drilling unit boundary.

9) “FUB” shall mean distance from a drilling unit boundary line.

c) Any New or Existing PRU, not subject to a Penalty Factor in accordance with subparagraph f) 

below, shall be subject to an allowable as follows: 

1) A New or Existing PRU shall have an allowable determined as follows: Allowable =

PRU Deliverability x (proposed drilling unit acreage ÷ 640 acres or applicable 

established drilling unit acreage) 

2) A New or Existing PRU with a PRU Deliverability of less than 75 MCFD shall have an 
GENERAL RULES AND REGULATIONS

176

allowable determined as follows: Allowable = 75 MCFD. PRU Deliverability of less than 

75 MCFD shall be demonstrated by either:

A) Conducting a test utilizing the methodology specified in General Rule D-16; or

B) Utilizing the most recent six month average daily rate of production for the PRU 

under actual operating conditions calculated by dividing the total gas reported by 

the number of days produced during the applicable six month period.

d) Any New or Existing PRU subject to a Penalty Allowable, the Penalty Allowable shall be 

determined as calculated as follows:

1) If the Encroachment Footage encroaches upon only one boundary of said drilling unit, the 

Penalty Allowable shall be the greater of 75 MCFD or calculated as follows: 

Penalty Allowable = PRU Deliverability x Penalty Factor (Encroachment Footage ÷ 

Setback Footage) x proposed drilling unit acreage ÷ 640 acres or applicable established 

drilling unit acreage. 

2) If the Encroachment Footage encroaches upon two boundaries of said drilling unit, then 

the Penalty Allowable shall be the greater of 75 MCFD or the cumulative of the penalties 

calculated as follows: 

Penalty Allowable = PRU Deliverability x Penalty Factor [(1st Encroachment Footage + 

2nd Encroachment Footage) ÷ Setback Footage -1] x proposed drilling unit acreage ÷ 640 

acres or applicable established drilling unit acreage 

e) Sales in Excess of the Penalty Allowable 

 

1) An Existing or New PRU subject to a Penalty Allowable in accordance with this rule 

shall have an annual balancing date of July 1, where the preceding 12 month (July 1 –

June 30) sales must be reconciled with the preceding 12 month Penalty Allowable to 

determine if the PRU had excess sales.

2) An Existing or New PRU subject to a Penalty Allowable which has sales in excess of the 

assigned Penalty Allowable must be shut-in on the annual balancing date of July 1 and 

remain shut-in until all excess sales is eliminated. The shut-in period shall be determined 

by dividing the excess sales by the Penalty Allowable. 

3) Any Existing or New PRU subject to a Penalty Allowable which has excess sales on the 

annual balancing date of July 1 and which fails to shut-in within 30 days after the July 1, 

may be subject to a civil penalty not to exceed two thousand five hundred dollars 

($2,500.00) per day for every day the PRU produced beyond the 30 day period, and may 

be subject to further enforcement actions in accordance with General Rule A-5, and Ark. 

Code Ann. § 15-72-401 through 15-72-406.

(Source: new rule August 01, 2014)
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RULE D-22 – REQUIREMENTS FOR LEASE RIGHTS GAS SUPPLY LINES 

a) Definitions

 

1) “Director” shall mean the Director of the Oil and Gas Commission.

2) “Lease Rights Gas Supply Line” shall mean a pipeline, under jurisdiction of the Arkansas 

Oil and Gas Commission (“AOGC”) as defined in Ark. Code Ann. § 15-71-110, which 

transports natural gas from a Well Operator Connection, located at a natural gas well, or 

other natural gas production equipment located upstream of the production meter on the 

well location to a single end user. 

3) “Lease Rights Gas Supply Line Operator” shall mean a Lease Rights Gas Supply Line 

owner who has an agreement authorizing natural gas supply, who accesses directly from 

the Well Operator Connection, and who owns or operates and is responsible for the 

construction, operation and maintenance of a Lease Rights Gas Supply Line.

4) “Lease Rights Gas” shall mean the gas owned and controlled by the Lease Rights Gas 

Supply Line Operator once it passes the Well Operator Connection.

5) “Well Operator Connection” shall mean the point at which the Operator provided access 

point connects to the Lease Rights Gas Supply Line and at which point the control of the 

gas by the Operator terminates and is assumed by the Lease Rights Gas Supply Line 

Operator.

b) All Lease Rights Gas Supply Lines located downstream of a production meter at the natural gas 

well or other natural gas production equipment located on the well location, and which is under 

the jurisdiction of AOGC as defined in Ark. Code Ann. § 15-71-110, are not subject to the 

provisions of this rule, but shall be subject to all other applicable Federal and State rules and 

regulations governing natural gas pipelines.

c) All new Lease Rights Gas Supply Lines originating at a Well Operator Connection, constructed 

after the effective of this rule, are subject to the provisions of this rule at the time of construction.

d) Within ninety (90) days of the effective date of this Rule, for all existing Lease Rights Gas 

Supply Lines, the Operators providing a Well Operator Connection shall provide the Director 

with a list of names and addresses of the legally entitled recipients of the Lease Rights Gas, as 

reflected in the records of the Operator. The Director shall send a letter to each Lease Rights Gas 

Supply Line Operator notifying them of the requirements of this Rule

e) Within six (6) months from the date the notification letter was sent in accordance with

subparagraph (d) above, all Lease Rights Gas Supply Line Operators existing at the time this Rule 

is adopted, shall document compliance with items 1 through 6 below, by the submission of 

documentation to the Director or his or her designee demonstrating compliance. If the Lease 

Rights Gas Supply Line Operator fails to submit the required documentation demonstrating 

compliance with items 1 through 6 below, or if the Lease Rights Gas Supply Line Operator fails 

to comply with items 1 through 6 below, the Director or his or her designee may authorize the 

Operator to disconnect the Lease Rights Gas Supply Line until such time as the Lease Rights Gas 

Supply Line Operator is in full compliance with the provisions of this Rule. The Lease Rights 

Gas Supply Line Operator shall:

1) Utilizing the services of a plumber licensed by the State of Arkansas, properly install one 

or more properly-sized regulator(s) on the Lease Rights Gas Supply Line at the Well 
GENERAL RULES AND REGULATIONS

178

Operator Connection point and all necessary piping to accommodate appropriate 

odorization, gas utilization metering equipment, and a properly-sized regulator at the 

dwelling or structure where the natural gas is utilized. All materials used shall be 

designed for natural gas service and provide structural integrity where necessary; 

2) Utilizing the services of a plumber licensed by the State of Arkansas, properly install an 

excess flow valve on the Lease Rights Gas Supply Line as close to the Well Operator 

Connection as feasible;

3) Utilizing the services of a plumber licensed by the State of Arkansas, properly install 

appropriate dehydration and odorization facilities on the Lease Rights Gas Supply Line 

downstream from the Well Operator Connection; 

4) Utilizing the services of a plumber licensed by the State of Arkansas, properly install a 

new Lease Rights Gas Supply Line or test an existing Lease Rights Gas Supply Line, as 

follows:

A) New Lease Rights Gas Supply Lines shall be constructed of steel or plastic which 

is designed, manufactured and intended for natural gas service in accordance 

with industry standards. Each newly constructed gas supply line must be tested 

and free of leaks prior to placing into service. Each test shall be at a pressure of 

fifty (50) psig for a period of thirty (30) minutes. All piping shall be installed in 

a manner which will minimize strain or external loading. If plastic pipe is used, 

it shall be installed so as to minimize tensile stresses and must have a tracer wire 

or means of locating the pipe while underground. Tracer wire may not be 

wrapped around the plastic pipe and contact with the pipe should be avoided with 

at least two (2) inches between the wire and the Lease Rights Gas Supply Line;

B) All newly constructed Lease Rights Gas Supply Lines shall be buried and have a 

minimum of eighteen (18) inches of cover or greater if necessary to not pose a 

safety hazard to surface activities conducted along the Lease Rights Gas Supply 

Line right-of-way;

C) All existing Lease Rights Gas Supply Lines must be pressure tested in 

accordance with e) 4) A) above; and 

D) All repairs or relocation of a Lease Rights Gas Supply Line must be performed 

by a plumber licensed by the State of Arkansas and be in accordance with all 

applicable above provisions.

5) Install and maintain signage within the line of sight along the Lease Rights Gas Supply 

Line, with such signs to include words 1” in height and 1⁄4” in stroke “WARNING –

DANGER – NATURAL GAS PIPELINE”, and including the name, address and 24-hour

contact information of the Lease Rights Gas Supply Line Operator; and

6) Provide the Director, or his or her designee, and the Operator written notification of the 

name, address, and telephone number that should be used to notify the Lease Rights Gas 

Supply Line Operator of any emergency condition. The Lease Rights Gas Supply Line 

Operator shall ensure that this information is kept current with the Director, or his or her 

designee, and the Operator.

f) The Lease Rights Gas Supply Line Operator shall, utilizing the services of a plumber licensed by 

the State of Arkansas, inspect the Lease Rights Gas Supply Line and associated equipment on an 
GENERAL RULES AND REGULATIONS

179

annual basis, make proper repairs as necessary and provide evidence of such inspection and repair 

to both the Operator and the Director or his or her designee.

g) Produced fluids collected by the Lease Rights Gas Supply Line Operator shall be removed from 

the site and disposed in accordance with applicable Arkansas Oil and Gas Commission and 

Arkansas Department of Environmental Quality rules and regulations. Produced fluids shall not 

be discharged onto the ground surface or into waters of the state. Any spill of produced fluids 

shall be remediated in accordance with applicable Arkansas Oil and Gas Commission and 

Arkansas Department of Environmental Quality rules and regulations.

h) All Lease Rights Gas Supply Lines existing at the time this Rule is adopted which are servicing 

multiple domestic or end users are prohibited, and within six (6) months from the date the 

notification letter sent in accordance with subparagraph (d) above, the Lease Rights Gas Supply 

Line Operator shall reconfigure the Lease Rights Gas Supply Line to only allow for a single 

domestic or end user per Lease Rights Gas Supply Line.

i) Lease Rights Gas Supply Lines Operators shall maintain compliance with the provisions of this 

Rule. If a Lease Rights Gas Supply Line Operator fails to comply with the provisions of this 

Rule, the Director or his or her designee shall give Notice of the Violation, in accordance with 

General Rule A-5, to the Lease Rights Gas Supply Line Operator. The Lease Rights Gas Supply 

Line Operator shall have thirty (30) days to comply with the Notice of Violation. If the Lease 

Rights Gas Supply Line Operator fails to comply or properly request a review or appeal in 

accordance with General Rule A-5, then the Director or his or her designee may authorize the 

Operator to disconnect the Lease Rights Gas Supply Line until such time as the Lease Rights Gas 

Supply Line Operator is in full compliance with the provisions of this Rule. Any appeal of a 

Director’s Decision for a Notice of Violation issued in accordance with this subparagraph shall 

not be subject to the filing fee required in accordance with General Rule A-2 or A-3.

j) Lease Rights Gas Supply Line Operators are no longer subject to the provisions of this rule if the 

well, where the Well Operator Connection is located, is transferred to the Lease Rights Gas 

Supply Line Operator in accordance with General Rule B-11. 

(Source: new rule January 15, 2015)
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GENERAL RULE E - TRANSPORTATION

RULE E-1: PIPE LINES, PURCHASERS AND TRANSPORTERS

(A) No carrier by pipe line and no gathering system shall transport oil from any lease or wells if the said 

pipe line or gathering system has reason to believe the owner or operator of said lease or wells to 

which it is connected has violated any rule, regulation or order of the Commission or any 

conservation laws of the State with reference to oil and gas.

(B) No pipe line company shall transport oil from any gathering system which the said pipe line 

company has reason to believe has violated any rule, regulation or order of the Commission or any 

conservation law of this state with reference to oil and gas. 

It shall be the duty of the pipe line company to suspend transportation of any oil from said gathering 

system until such time as such pipe line company is notified in writing by the agent of the 

Commission that the violation on the part of the gathering system has been discontinued and that the 

gathering system is complying with the rules, regulations and orders of the Commission and the 

conservation laws of the State of Arkansas.

(C) In order to carry out the spirit and purposes of this and other regulations tending to provide orderly 

production of crude oil without waste and to give equal opportunity for marketing oil to all operators 

bringing wells into production in said field, all pipe line companies are hereby directed to make 

connection of their lines to the lease tanks on properties or leases in rotation as wells are completed, 

regardless of ownership. Connections shall be accepted and taken by the pipe line which by 

geographical location and least expense is the logical connection unless some other line is willing to 

accept the same. All wells which are at the present time unconnected shall be given connection by 

the pipeline to which the same are or may be allocated before the owners of such pipe lines make 

connections to their own wells or wells of affiliated companies.

(Source: 1991 rule book)
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RULE E-2: REPORTS FROM OIL PIPE LINES, TRANSPORTERS AND STORERS

Each transporter of oil within the State of Arkansas shall furnish for each calendar month a 

“Transporter’s and Storer’s Monthly Report”, containing complete information and data indicated by 

such form respecting stocks of oil on hand and all movements of oil by pipe line within the State of 

Arkansas and all movements of oil by watercraft, or by trucks or other conveyances except railroads, 

from leases to storers or refiners; between transporters within the State; between storers within the 

State; between refiners within the State; and between storers and refiners within the State.

Each storer of oil within the State of Arkansas shall furnish for each calendar month a “Transporter’s 

and Storer’s Monthly Report”, containing complete information and data indicated by such form 

respecting the storage of oil within the State of Arkansas.

The transporters and storers reports for each month shall be prepared and filed according to 

instructions on the form, on or before the 15th day of the next succeeding month.

(Source: 1991 rule book)
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RULE E-3: EXPLORATION AND PRODUCTION FLUID GATHERING, HANDLING 

AND TRANSPORTATION

a) Definitions

1) "Class II Fluids" means:

A) Produced water and/or other fluids brought to the surface in connection with 

drilling, completion or fracture treatments, workover or recompletion and 

plugging of oil, natural gas, Class II or wells that are required to be permitted as 

water supply wells by the Commission; enhanced recovery operations; or natural 

gas storage operations, or

B) Produced water and/or other fluids from A) above, which prior to re-injection 

have been used on site for purposes integrally associated with well drilling, 

completion or fracture treatments, workover or recompletions or plugging oil, 

natural gas, Class II or wells that are required to be permitted as water supply 

wells by the Commission; enhanced recovery operations; natural gas storage 

operations; or chemically treated or altered to the extent necessary to make them 

usable for purposes integrally related to well drilling, completion, workover or 

recompletions or plugging oil, natural gas, Class II or wells that are required to 

be permitted as water supply wells by the Commission; enhanced recovery 

operations; natural gas storage operations, or commingled with fluid wastes 

resulting from fluid treatments outlined above, provided the commingled fluid 

wastes do not constitute a hazardous waste under the Resource Conservation and 

Recovery Act.

2) "Exploration and Production Fluid” means crude oil bottom sediments and all Class II 

fluids, to the extent those fluids are now or hereafter exempt from the provisions of 

Subtitle C of the Federal Resource Conservation Recovery Act of 1976. 

3) "Exploration and Production Fluid Transportation System" means any motor vehicle 

licensed for highway use on a public highway or used on a public highway, that is 

equipped for either carrying or pulling a Transportation Tank containing Exploration and 

Production Fluids, from the point of any fluid generation or collection site to any 

subsequent off-site storage facility, surface disposal facility or an injection well disposal 

facility.

4) “Exploration and Production Fluid Transporter” means an operator of an Exploration and 

Production Fluid Transportation System.

5) "Transportation Tank" means an assembly, compartment, tank or other container that is 

used for transporting or delivering Exploration and Production Fluid.

b) No person shall operate an Exploration and Production Fluid Transportation System without an 

Exploration and Production Fluid Transportation System permit. Application for which shall be 

made on forms prescribed by the Director. The application shall be executed under penalties of 

perjury, and accompanied by an Exploration and Production Fluid Transportation System permit 

fee in the amount specified below. 

c) If the application does not contain all of the required information or documents, the Director or 

his or her designee shall notify the applicant in writing. The notification shall specify the 

additional information or documents necessary to process the application, and shall advise the 
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applicant that the application will be deemed denied unless the additional information or 

documents are submitted within 30 days following the date of notification.

d) The application shall, at a minimum, include:

1) A permit fee of $100.00 per Transportation Tank.

2) The name, address, and business and emergency telephone numbers of the proposed 

Exploration and Production Fluid Transporter, including Arkansas contact information if 

the transporter is located outside of the state of Arkansas.

3) A brief description of the number and type of Transportation Tanks to be used in the 

system; specifying whether Transportation Tanks will be owned, leased or otherwise 

arranged for and including tank capacity and a manufacturers serial number or other 

identifying number for Transportation Tank.

4) An Entity Organizational Report on a form prescribed by the Director.

e) If the applicant satisfies all requirements of this rule, the Director shall issue an Exploration and 

Production Fluid Transportation System permit and permit sticker for each Transportation Tank. 

The Exploration and Production Fluid Transportation System permit shall be kept in the Arkansas 

office of the Exploration and Production Fluid Transportation System permit holder. The permit 

sticker shall be affixed to the back of the Transportation Tank and shall be kept visible and 

readable at all times.

f) Exploration and Production Fluid Transportation System permits are not transferable. 

g) Exploration and Production Fluid Transportation System permits shall be renewed annually on 

July 1 of each year, commencing on July 1, 2010; and Amended applications, including any 

additional permit fees, are required to be submitted within thirty (30) days of the addition of any 

Transportation Tanks to the Exploration and Production Fluid Transportation System.

h) Exploration and Production Fluid Transportation System recordkeeping requirements:

1) Each Exploration and Production Fluid Transportation System permit holder shall 

maintain a record of all Exploration and Production Fluids received, transported, 

delivered or disposed of, which shall include the well lease or unit name, well or facility 

operator (fluid generator), the date received, the amount per pick up, type of fluid, and 

the name and location of the permitted off-site temporary storage facility, permitted 

surface disposal facility or permitted injection well disposal facility.

2) Records shall be maintained a minimum of three (3) years at the Arkansas office of the 

Exploration and Production Fluid Transportation System permit holder, and shall be 

made available to commission staff for inspection during normal business hours.

i) Exploration and Production Fluid Transportation System operating requirements:

1) All Transportation Tanks and associated piping and valves must be kept in leak free 

condition. 

2) Exploration and Production Fluid Transporters shall only transport Exploration and 

Production Fluid to a permitted well for re-use in the well drilling or well completion 

process, a permitted off-site temporary storage facility, a permitted surface disposal 
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facility or a permitted injection well disposal facility. Exploration and Production Fluid

shall not be released or discharged onto the ground surface or into Waters of the State, 

unless otherwise authorized by the Arkansas Department of Environmental Quality.

3) All Exploration and Production Fluids stored at a permitted temporary storage facility 

shall be contained in tanks or permitted temporary storage pits. 

4) Exploration and Production Fluid shall not be commingled or blended with non-exempt 

waste (such as used motor or compressor oil) under Subtitle C of the Federal Resource 

Conservation and Recovery Act of 1976.

5) All Transportation Tanks shall contain the name and phone number of the Exploration 

and Production Fluid Transporter in a legible manner.

j) No person shall engage, employ or contract with any other person except a permitted Exploration 

and Production Fluid Transporter to transport Exploration and Production Fluids.

k) Failure to comply with provisions of this rule may result in revocation of the Exploration and 

Production Fluid Transportation System permit, and/or the assessment of civil penalties in 

accordance with General Rule A-5. 

(Source: new rule January 22, 2009; amended October 24, 2009)
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GENERAL RULE F - PROCESSING

RULE F-1: GENERAL ORDER

The Commission will, if deemed necessary, issue special rules, regulations and orders relating to the 

erection and operation of any plant or factory separating products from oil or gas or both.

(Source: 1991 rule book)

RULE F-2: REFINERY REPORTS

Each refiner of oil within the State of Arkansas shall furnish for each calendar month a “Refiner’s 

Monthly Report”, containing the information and data indicated by such form, respecting oil and products 

involved in such refiner’s operations during each month. Such report for each month shall be prepared 

and filed according to instructions on the form, on or before the 15th day of the next succeeding month.

(Source: 1991 rule book)

RULE F-3: GASOLINE PLANT REPORTS

Each operator of a gasoline plant, cycling plant or any other plant at which gasoline, butane, propane 

condensate, kerosene, oil, or other liquid products are extracted from natural gas within the State of 

Arkansas, shall furnish for each calendar month a “Monthly Gasoline or Other Extraction Plant Monthly 

Report”, containing the information indicated by such form respecting natural gas and products involved 

in the operation of each plant during each month.

Such reports for each month shall be prepared and filed according to instructions on the form on or before 

the 15th day of the next succeeding month.

(Source: 1991 rule book)
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GENERAL RULE G - ABANDONED AND ORPHAN WELL 

PLUGGING PROGRAM

RULE G-1: ABANDONED OR LEAKING WELL AND WELL SITE REMEDIATION

a) This rule is applicable for the following types of wells:

1) oil and gas production wells,

2) water supply wells used in enhanced oil and gas recovery projects,

3) UIC Class II Disposal and Class II Commercial Disposal wells, and

4) UIC Class II water injection wells used in enhanced oil and gas recovery projects.

b) Definitions

1) “Abandoned Well” means:

A) an oil and gas production well which has not produced for over 2 years; or

B) a UIC Class II saltwater disposal or UIC Class II water injection well which is no 

longer used due to the plugging of all the wells on the lease or unit or for which 

and agreement to continue use of the well has not been granted by the lease 

holder, or

C) a well for which the underlying lease has been released in writing by the lessee or 

has been declared forfeited or invalid by a court order, and such order is final and 

the appeal period has lapsed; and the lessor states in writing that the lessor has 

not leased out the oil and gas working interest to any other person and does not 

intend to so lease, and that the lessor does not intend to operate the well, and that 

the lessor desires that the well be plugged; or

D) a well owned or operated by a Permit Holder who has made no payment by 

March 1 of a current annual well fee assessment in accordance with Ark Code 

Ann. §15-71-116; or

E) a well that has been ordered to be plugged by the Commission and the Permit 

Holder has failed to do so within the time frame specified in the Commission 

Order; or

F) a well site which has not been properly restored following the completion of well 

plugging activities.

2) “Well Site Equipment” means the equipment, including but not limited to an associated 

tank battery, production and injection facility equipment, hydrocarbons from the well that 

are stored in tanks located on the lease, and hydrocarbons recovered during the plugging 

operation. 

3) “Well Site” means the area around and near the well, including any associated pits, crude 

oil or produced water storage tanks or other related production facility equipment, such as

injection pumps, compressors or gas processing equipment. 
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187

4) “Director” means the Oil and Gas Commission Director of Production and Conservation.

5) “Leaking Well” means a well drilled for the exploration, development, storage or 

production of oil or gas, or for injection, saltwater disposal, saltwater source, observation, 

and geological or structure test which is leaking salt water, oil, gas, or other deleterious 

substance into any fresh water formation or onto the surface of the land in the vicinity of 

the well.

6) “Well Site Restoration" means remediation of a well site, including but not limited to the 

following activities: an emergency clean-up of spilled crude oil or saltwater; remediation 

of conditions endangering the public health or safety, or contaminating or potentially 

contaminating surface waters, groundwater, or the surface of the land; work to repair or 

contain leaks of produced fluids from wells, production or injection equipment, pits or 

other containment structures, which are contaminating or potentially contaminating 

surface waters, groundwaters or the surface of the land; or a repairing a well leaking 

natural gas or hydrogen sulfide gas endangering or potentially endangering public safety 

or creating a potential a fire hazard. 

c) If the Director finds, upon inspection and/or review of Commission records, that a well drilled for 

the exploration, development, storage or production of oil or gas, or for injection, saltwater 

disposal, saltwater source, observation, and geological or structure test, may be abandoned; well 

site restoration has not been completed; is a leaking well; or the well or well site creates an 

imminent danger to the health or safety of the public, the Director may schedule a hearing, in 

accordance with established procedures. 

d) If after notice and a hearing, the Commission finds that a well drilled for the exploration, 

development, storage or production of oil or gas, or for injection, saltwater disposal, saltwater 

source, observation, a geological or structure test, may be abandoned; well site restoration has 

not completed; is a leaking well; or the well or well site creates an imminent danger to the health 

or safety of the public; the Commission shall issue an order requiring the Permit Holder to 

properly plug, re-plug, repair, or restore so as to remedy the situation.

e) If the Permit Holder fails to properly plug, re-plug, repair, or restore so as to remedy the situation 

within 30 days from the time frame prescribed by the Commission order, the abandoned well or 

well site; leaking well; a well or well site that creates an imminent danger to the health or safety 

of the public; or a well site restoration has not been completed, the well or well site shall be 

subject to the provisions of this Rule.

f) The Director may then authorize any person to enter upon the land and properly plug, re-plug, 

repair, or restore so as to remedy the situation. The Director may dispose of all well site 

equipment and hydrocarbons, to offset the costs of properly plugging, re-plugging, repairing, or 

restoring so as to remedy the situation. Proceeds from any public sale, auction or private sale of 

all well site equipment or hydrocarbons shall be deposited into the Plugging Fund or used to 

offset plugging costs. All work completed under this rule shall be paid with funds from the 

Abandoned and Orphan Well Plugging Fund. 

g) The Permit Holder shall reimburse the Commission for all costs expended to remedy the 

situation. All payments shall be by cashier’s checks or money order, and shall be deposited in the 

Abandoned and Orphaned Well Plugging Fund. Failure to reimburse the Commission will result 

in the initiation of Commission enforcement action to recover the expended funds. Prior to 

repayment of all expended funds, the Permit Holder shall not be permitted to operate any other 

existing wells in the Permit Holder’s name. Upon repayment and prior to being permitted to 
GENERAL RULES AND REGULATIONS

188

operate any wells, the Permit Holder may be required to post additional bond, as determined by 

the Director in accordance with General Rule B-2, to insure against the plugging of future 

abandoned wells not plugged by the Permit Holder. 

(Source: new rule April 13, 2008; amended November 26, 2009)
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RULE G-2: PLUGGING OF ORPHAN WELLS

a) Definitions:

1) “Orphan Well” means a well for which a Permit Holder can not be located, there is no 

record the well is covered by a Commission required bond by the last known permit 

holder of record, and no fees have ever been paid on the well in accordance with Ark. 

Code Ann. § 15-71-110. 

2) “Well Site Equipment” means the equipment, including but not limited to an associated 

tank battery, production and injection facility equipment, hydrocarbons from the well that 

are stored in tanks located on the lease, and hydrocarbons recovered during the plugging 

operation 

3) “Well Site” means the area around and near the well, including any associated pits, crude 

oil or produced water storage tanks or other related production facility equipment, such as 

injection pumps, compressors or gas processing equipment. 

4) “Director” means the Oil and Gas Commission Director of Production and Conservation.

b) If after review of the Commission records, the Director determines a well or well site to be 

orphaned, that well or well site may be administratively determined to be eligible for plugging, 

without the need for a hearing. Following designation as an orphaned well or well site, the 

Director may elect to properly plug, re-plug, or restore so as to remedy the situation, and 

authorize any person to enter upon the land properly plug, re-plug, or restore so as to remedy the 

situation. 

c) All work completed under this rule shall be paid with funds from the Abandoned and Orphan 

Well Plugging Fund. Additionally, the Director may dispose of all well site equipment and 

hydrocarbons, to offset the cost of the well plugging and well site restoration operations. Proceeds 

from any public sale, auction or private sale of all well site equipment or hydrocarbons shall be 

deposited into the Plugging Fund or used to offset plugging costs.

(Source: new rule April 13, 2008)
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190

RULE G-3: TRANSFER OF WELLS IN THE ABANDONED AND ORPHANED WELL 

PLUGGING PROGRAM

a) Definitions

1) “Well” as used in this Rule (G-3) shall only mean wells that are abandoned as defined in 

General Rule G-1 (a) (1), or orphaned as defined in General Rule G-2 (a) (1).

2) “Commission” means the Arkansas Oil and Gas Commission.

3) “Director” means the Director of Production and Conservation.

b) When a transfer request is received, on a form prescribed by the Director, for a well, the 

following documentation must be submitted by the proposed new Permit Holder:

1) a signed new base lease properly recorded in the county where the well is located; or

2) an affidavit stating a new base lease has been obtained and properly recorded in the 

county where the well is located;

c) Upon review and acceptance of the transfer request, and prior to approval of the transfer request, 

the proposed new Permit Holder shall:

1) pay a salvage value for the downhole well equipment as follows:

A) $500 per well for wells less than 3000 feet in depth; and

B) $1000 per well for wells equal to or greater than 3000 feet in depth; and

2) pay a salvage value for the tanks, pumping units, and other related equipment, as 

determined by submission of 2 independent salvage value estimates from commercial 

salvage oil and gas production equipment dealers and approved by the Director or his or 

her designee;

3) pay the fair market value per barrel, to be determined at the time of the transfer approval, 

for all oil fluids (hydrocarbons) stored on the lease or unit: and

4) if applicable, provide financial assurance in accordance with General Rule B-2 and file 

all other required organizational and registration forms. 

d) All payments shall be by cashier’s checks or money order, payable to the Commission, and shall 

be deposited in the Abandoned and Orphaned Well Plugging Fund.

e) The Director has sole discretion to approve or deny requests for transfer of the well. If, upon 

review of a transfer request for the well, the Director determines that property rights, 

environmental or public safety and welfare concerns will be advanced through plugging the well, 

the transfer request may be denied.

(Source: new rule April 13, 2008)
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GENERAL RULE H - CLASS II UIC WELLS

RULE H-1: CLASS II DISPOSAL AND CLASS II COMMERCIAL DISPOSAL WELL 

PERMIT APPLICATION PROCEDURES

a) Definitions:

1) "Class II Disposal Well"-- means: 

A) A permitted Class II well in which Class II Fluids are injected into zones not 

productive of oil and gas, and brine used to produce bromine, within the field 

boundary established by an order of the Commission for the production of liquid 

hydrocarbons or brine used to produce bromine, where the well is located or will 

be located, for the purpose of disposal of those fluids; or 

B) A permitted Class II well in which Class II Fluids are injected into a zone or 

zones which are not commercially productive of dry gas, within the same 

common source of supply, where the well is located or will be located, for the 

purpose of disposal of those fluids. 

2) “Class II Commercial Disposal Well"-- means a permitted Class II well in which Class II 

Fluids are injected, for which the Permit Holder receives deliveries of Class II Fluids by 

tank truck from multiple oil and gas well operators, and either charges a fee at the 

disposal well facility or purchases the Class II Fluids at the source for subsequent 

transport to the disposal well facility for the specific purpose of disposal of the delivered 

Class II Fluids.

3) "Class II Fluids" means:

A) Produced water and/or other fluids brought to the surface in connection with 

drilling, completion, or fracture treatments, workover or recompletion and 

plugging of oil and natural gas wells; Class II or wells that are required to be 

permitted as water supply wells by the Commission; enhanced recovery 

operations; or natural gas storage operations; or

B) Produced water and/or other fluids from (A) above, which prior to re-injection 

have been used on site for purposes integrally associated to oil and natural gas 

well drilling, completion, or fracture treatments, workover or recompletion and 

plugging of oil and natural gas wells; Class II or wells that are required to be 

permitted as water supply wells by the Commission; enhanced recovery 

operations; or natural gas storage operations, or chemically treated or altered to 

the extent necessary to make them usable for purposes integrally related to oil

and natural gas well drilling, completion, workover and plugging, oil and gas 

production, enhanced recovery operations, or natural gas storage operations, or 

commingled with fluid wastes resulting from fluid treatments outlined above, and 

including any other exempted oil and gas related fluids under the Resource 

Conservation and Recovery Act, provided the commingled fluid wastes do not 

constitute a hazardous waste under the Resource Conservation and Recovery Act; 

or

C) Waste fluids from gas plants (including filter backwash, precipitated sludge, iron 

sponge, hydrogen sulfide and scrubber liquid) which are an integral part of oil 

and gas production operations; and waste fluids from gas dehydration plants 
GENERAL RULES AND REGULATIONS

192

(including glycol-based compounds and filter backwash), unless the gas plant or 

gas dehydration plant wastes are classified as hazardous under the federal 

Resource Conservation and Recovery Act.

4) “Confining layer” means a geological formation, group of formations, or part of a 

formation that is capable of limiting fluid movement above an injection zone. It is 

composed of rock layers that are impermeable or distinctly less permeable than the 

injection zone beneath it. There may be multiple confining layers above an injection 

zone.

5) “Permit Holder” means the entity or person to whom the permit is issued and who is 

responsible for all regulatory requirements relative to the Class II Disposal or Class II 

Commercial Disposal Well.

6) “USDW” means Underground Source of Drinking Water which is defined in Title 40, 

Code of Federal Regulations (40 CFR) Section 144.3, as an aquifer or its portion which:

A) Supplies any public water system (see 40 CFR); or

B) Contains a sufficient quantity of groundwater to supply a public water system 

(see 40 CFR) and currently supplies drinking water for human consumption; or

C) Contains fewer than 10,000 mg/l total dissolved solids (see 40 CFR); and

D) Which is not an exempted aquifer (see 40 CFR).

b) No person shall drill, deepen, re-enter, recomplete or operate any well for use as a Class II 

Disposal or Class II Commercial Disposal Well or inject into any well, without the applicable 

permits from the Commission, application for which shall be made on forms prescribed by the 

Director. Permits are valid only for the Permit Holder stated on the permit, and shall remain valid 

only with ongoing compliance with established operating requirements specified in General Rule 

H-2 or H-3, except that permits to drill, deepen, or re-enter shall automatically expire six (6) 

months from the date of issuance, unless commencement of the drilling, deepening or re-entry of 

plugged well operations authorized by the permit has occurred, which are to be continued with 

due diligence, but not to exceed one (1) year from the date of commencement of the drilling, 

deepening or re-entry of plugged well operations authorized by the permit, at which time the well 

shall be plugged, injection casing set, or a new permit application, along with a new permit fee 

and plat, must be filed. Failure to comply with the operating requirements in General Rule H-2 

or H-3 may result in revocation of the Class II Disposal Well or Class II Commercial Disposal 

Well permit in accordance with subparagraph q) below.

1) Authority to conduct an injectivity test, step rate test or trial injection test prior to, or after 

the issuance of a permit may be approved as follows: 

A) An injectivity test, step rate test or trial injection test of less than twelve (12) 

hours duration may be approved by the Director upon review of the well 

construction to determine well mechanical integrity for the protection of the 

USDW’s and oil and gas resources during the test. The Director shall establish 

the protective parameters of the test, require the submittal of any information or 

test data deemed necessary and may require the witnessing by Commission staff 

of the test.
GENERAL RULES AND REGULATIONS

193

B) An Applicant may request approval from the Commission, by filing an 

application in accordance with General A-2 and A-3 and other applicable hearing 

procedures, of an injectivity test, step rate test or trial injection test of twelve (12) 

hours or more in duration. 

2) No Class II Disposal or Class II Commercial Disposal Well may be drilled at a surface 

location other than that specified on the permit, except that if a permit holder has 

commenced drilling operations and the Class II Disposal or Class II Commercial 

Disposal Well is lost due to adverse drilling conditions prior to surface casing being set, 

the permit holder may request an amendment of the permit without a fee for the new 

location, provided the Class II Disposal or Class II Commercial Disposal Well remains 

on the same surface owners property where the Class II Disposal or Class II Commercial 

Disposal Well was originally permitted and all other aspects of the permit request remain 

the same. Movement of the Class II Disposal or Class II Commercial Disposal Well 

location off the original surface owners’ property, or after surface casing has been set, 

will require the filing of a new permit application, along with a new permit fee and plat. 

Drilling may not commence prior to the issuance of a new permit.

3) Permits to recomplete or operate shall automatically expire one year from the date of 

issuance, unless commencement of the operations authorized by the permit has occurred, 

or a new permit application, along with a new permit fee has been filed.

4) Upon issuance of a permit, a copy of the permit shall be displayed at the site where the 

Class II Disposal or Class II Commercial Disposal Well is being drilled for review by 

Commission staff.

5) Permits to drill, deepen, or re-enter a Class II Disposal or Class II Commercial Disposal 

Well may only be issued if the location complies with General Rule B-3.

c) The application to drill, deepen, re-enter, recomplete or operate a Class II Disposal or Class II 

Commercial Disposal Well shall include at a minimum:

1) The information required by subparagraph (h) below, for the existing or proposed well 

and any additional information deemed necessary by the Director for the protection of 

USDWs; and

2) Accompanied by a permit fee in the amount of $300.00 if the Class II Disposal or Class II 

Commercial Disposal Well is drilled, deepened, or re-entered; and

3) Accompanied by a non-refundable fee of $100.00 for a Class II Disposal Well or $500.00 

for a Class II Commercial Disposal Well to recomplete or operate the Class II Disposal or 

Class II Commercial Disposal Well; and

4) Accompanied by the required financial assurance in accordance with General Rule B-2; 

and

5) Accompanied by a Form 1 Organizational Report in accordance with General Rule B-13; 

and

6 Be executed under penalties of perjury; and

7) If the applicant is a corporation, limited liability company, limited liability partnership or 

other business entity, it must be incorporated, organized, or authorized to do business in 
GENERAL RULES AND REGULATIONS

194

the State of Arkansas, and by filing an application, the applicant irrevocably waives, to 

the fullest extent permitted by law, any objection to a hearing before the Commission or 

in a court of competent jurisdiction in Arkansas; and 

8) If the applicant is an individual, partnership, or other entity that is not a resident of 

Arkansas, the applicant must be authorized to do business in Arkansas, and by filing an 

application, the applicant irrevocably waives, to the fullest extent permitted by law, any 

objection to a hearing before the Commission or in a court of competent jurisdiction in 

Arkansas; and

9) Proof that the Class II Disposal or Class II Commercial Well location complies with 

General Rule B-3.

d) No person shall inject into USDWs or be issued a permit to inject into USDWs unless an aquifer 

exemption has been granted in accordance with US Environmental Protection Agency 

procedures. 

e) Unless otherwise approved by the Commission, no person shall inject into a well which does not 

have at a minimum, five hundred (500) feet for a Class II Disposal Well or seven hundred-fifty 

(750) feet for a Class II Commercial Disposal Well, of confining layers between the base of the 

lowermost USDWs and the top of the injection interval, with no individual confining layer being 

less than 50 feet in thickness. A lesser amount of confining layer(s) may be approved, provided 

the Applicant provides substantial information as to the integrity of the confining layers to inhibit 

the upward migration of the injection fluids so as not to endanger the lowermost USDW in the 

area of the well.

f) If the application does not contain all of the required information or documents, the Director shall 

notify the Applicant in writing. The notification shall specify the additional information or 

documents necessary for an evaluation of the application and shall advise the Applicant that the 

application will be deemed denied unless the information or documents are submitted within sixty 

(60) days following the date of notification. 

g) Applications for a Class II Disposal Well shall contain the names of all permit holders who are to 

utilize the proposed disposal well.

h) Contents of Application

1) A specification as to the type of Class II well being permitted as a Class II Disposal Well 

or a Class II Commercial Disposal Well.

2) The Applicant shall provide the name, address, phone, fax and e-mail (if available) of the 

local or on-site supervisory or field personnel responsible for the disposal well.

3) If the well is not located within the boundaries of an operating oil and gas leasehold or 

drilling unit, the Applicant shall provide documentation, in the form of a surface use 

agreement or an affidavit of a surface use agreement, indicating the Applicant’s right to 

drill and to operate the proposed disposal well. If the well is located within the 

boundaries of an operating oil and gas leasehold or drilling unit, and the Applicant is 

someone other than the operator of the leasehold or drilling unit, the Applicant shall 

provide documentation, in the form of a surface use agreement, or an affidavit of a 

surface use agreement, indicating the Applicant's right to drill and to operate the 

proposed disposal well.
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195

4) A survey plat of the location and ground elevation of the proposed disposal well or if the 

application is for an existing well, the well name and permit number of the existing well. 

A new survey is not required for a well to be converted or deepened well or a plugged 

well to be re-entered, if the original well location was surveyed, a copy of which shall be 

submitted with the application.

5) The name, geologic description and the approximate top and bottom elevation, from subsea, of the formation (indicating the perforated or open hole interval) into which fluid 

will be injected and the geologic description and top and bottom elevation, from sub-sea, 

of the above confining layers, in the proposed or existing disposal well. If an existing 

well is to be converted, a geophysical log of the well shall be submitted showing the 

above information. For a proposed well, an induction log from a well in the immediate 

vicinity of the proposed disposal well shall be submitted. If the geologic name of the 

interval is unclear include any additional geological evidence such as a cross section, 

structure or isopach map that may be necessary to adequately define the proposed 

injection interval.

6) A well bore diagram of the proposed or existing well showing casing for the injection 

well, indicating from the well head to total depth of the well, all casings and cementing of 

casings, any obstructions within well, all plugs set, tubing and packer setting depth, and 

all perforations and or open hole intervals. If application is for an existing well, a cement 

bond log (CBL) shall be submitted with the application, or if submitted after the 

application is filed, the CBL shall be submitted prior to commencement of operations as a 

condition of the permit. 

7) The proposed daily amounts to be injected, the source and the type of fluid to be injected, 

and standard laboratory report from an accredited laboratory reporting the laboratory 

results of a representative sample of the proposed disposal fluids for the following 

parameters: chloride, pH, specific gravity, total dissolved solids (TDS) and total percent 

hydrocarbon (TPH). The sample shall be obtained and analyzed no earlier than one 

hundred-eighty (180) days prior to the date of filing of the application and analyzed in a 

timely fashion after collection.

8) The maximum injection pressure. 

A) The Director shall determine the maximum permitted injected pressure, measured 

at the wellhead, by multiplying the results of the formula below by ninety percent 

(90%):

i) A maximum fracture gradient not to exceed 1.1 psi/ft (x) depth to 

injection formation (-) weight of fluid column (specific gravity of 

injection fluid) (+) injection tubing friction loss in Ashley, Bradley, 

Calhoun, Columbia, Hempstead, Lafayette Miller, Nevada, Ouachita, 

and Union counties for injection into formations below the Midway 

Shale Formation; or

ii) A maximum fracture gradient not to exceed 1.0 psi/ft (x) depth to

injection formation (-) weight of fluid column (specific gravity of 

injection fluid) (+) injection tubing friction loss in all other counties for 

injection into formations below the Fayetteville Shale Formation in the 

areas covered by General Rule B-43 (c) and (d), General Rule B-44, and 

the portions of Franklin, Logan, Scott, Sebastian, and Yell Counties not 

covered by General Rule B-44; or
GENERAL RULES AND REGULATIONS

196

iii) A maximum fracture gradient not to exceed 0.73 psi/ft (x) depth to 

injection formation (-) weight of fluid column (specific gravity of 

injection fluid) (+) injection tubing friction loss for all other formations 

and/or counties.

The following calculation is included only as an example, and for informational and demonstrative 

purposes only. For purposes of this example, assume the well is in Columbia County, the total depth to 

the injection formation is 2,500 feet, the specific gravity is 1.085, and the injection tubing friction loss is 

250 psi. Using the formula provided above, the maximum permitted injection pressure for the well would 

be 1,642 psig, calculated as follows:

Step 1: 0.9 x [(1.1 psi/ft x 2500 ft) – [0.433psi/ft x 2500 ft) x 1.085 (specific gravity)] + 250 tubing 

friction loss]

Step 2: 0.9 x [2750 psi – 1175 + 250 tubing friction loss]

Step 3: 0.9 x [1825]

Step 4: Result = 1642 psig 

B) An Applicant may request an increase in the maximum injection pressure 

specified in subparagraph h) 8) A) above, or appeal a Director’s decision to issue 

a permit utilizing a fracture gradient less than the maximum fracture gradient 

specified in subparagraph h) 8) A) above, by filing an application in accordance 

with General A-2, A-3 and other applicable hearing procedures. Any increase in 

the maximum injection pressure may be granted if the Applicant presents 

sufficient evidence to justify the requested increased injection pressure will not 

initiate or propagate fractures in the overlying confining layer(s) that could 

enable the injection fluid or the fluid in the injection interval to leave the 

permitted injection intervals or cause movement of the injection fluid or 

formation fluids into USDWs. 

9) A map showing: 

A) The surveyed location of the well proposed to be drilled, deepened or converted, 

showing distances to the nearest property or lease lines; and 

B) The location of all known plugged and unplugged wells, which penetrate the 

proposed injection interval, within the 1/2 mile radius from the proposed disposal 

well, and showing the status of each well as producing, shut-in, disposal, 

enhanced recovery, plugged and abandoned, or other status.

10) The Applicant shall submit evidence, where available, that all plugged and unplugged 

wells which penetrate the injection formation, within the 1⁄2 mile radius shown on the 

above plat in subparagraph h) 9) B), contain an adequate amount of cement and are 

constructed or plugged in a manner which will prevent the injection fluid and the fluid in 

the injection formation from entering USDWs. The types of evidence that will be 

considered acceptable include, but are not limited to: well completion reports, cementing 

records, well construction records, cement bond logs, tracer surveys, oxygen activation 

logs, and plugging records. 
GENERAL RULES AND REGULATIONS

197

11) The Applicant shall submit evidence and/or information showing that the proposed 

injection interval or formation is not a USDW.

12) The Applicant shall submit information as to the depth (subsea) of the fresh water supply 

in the nearest known private water well and in the nearest known public water system 

water well. 

13) If the application is for a Class II UIC Commercial Disposal Well, a listing of all 

previous and current violations of any statute, rule, regulation, permit condition, or order 

of the Commission, the Arkansas Department of Environmental Quality, the Arkansas 

Pollution Control and Ecology Commission, or any other state or federal environmental 

regulatory agency, including those of other states, regarding oil or gas related activities.

i) Notice of the application shall be given by the Applicant by one (1) publication in a legal 

newspaper having a general circulation in the county, or in each county, if there shall be more 

than one, in which the one-half mile radius from the proposed disposal well is situated, and by 

mailing via certified mail, FedEx, UPS, or other method that provides proof of mailing and 

delivery, a copy of the application to each permit holder of all permitted, drilling or producing 

wells within a one-half mile radius of the proposed disposal well. Such notice shall be published 

or mailed no more than thirty (30) days, prior to the date on which the application is filed with the 

Commission. The cost of such notice and mailing of the application shall be paid for by the 

Applicant. Attached to the application shall be evidence that the application was mailed or sent as

required and a proof of publication of the application from the newspaper.

j) If notice is for a commercial disposal well, in addition to compliance with subparagraph i) above, 

the commercial disposal well application shall also be sent via certified mail, FedEx, or UPS to 

the County Judge of the county where the well is located and to the landowner (surface owner) 

where the well is located. In addition, the public notice should be large font and surrounded by a 

printed border to highlight the published notice. 

k) Objections received by the Director, must be received by the Director within fifteen (15) days 

after the publication date of the notice and the date of mailing or sending to all parties specified in 

subparagraphs i) and j) above. 

l) If an objection is received the application shall be deemed denied. If the application is denied 

under this section, the Applicant may request to have the application referred to the Commission 

for determination, in accordance with General Rules A-2 and A-3, and other applicable hearing 

procedures, except that no additional filing fee is required.

m) If an objection is not received by the Director and the application is deemed complete, the permit 

shall be issued following the required notice period specified in subparagraph i) above, unless the 

Director deems it necessary, for the purpose of protecting USDWs or oil and gas resources, that 

the application may be referred to the Commission for determination, and no additional filing fee 

is required from the applicant.

n) If the application does not satisfy the requirements of this Rule, the application shall be denied. If 

the application is denied under this section, the Applicant may request to have the application 

referred to the Commission for determination, in accordance with General Rules A-2 and A-3, 

and other applicable hearing procedures. 

o) If the Applicant satisfies the requirements of all applicable statutes and this Rule, a permit shall 

be issued, unless:
GENERAL RULES AND REGULATIONS

198

1) The Applicant has falsified or otherwise misstated any material information on or relative 

to the permit application; or

2) For purposes of Class II Commercial Disposal Wells, the Applicant:

A) Has an owner, officer, director, partner, or member or manager of a limited 

liability company, or other person with an interest in the entity exceeding 5%;

i) That has failed to abate an outstanding violation of the oil and gas 

statutes or rules, regulations, or comply with an orders of the 

Commission as specified in a final administrative decision of the 

Commission; or

ii) For which funds have been obligated and remain outstanding from the 

Plugging and Restoration Fund to plug wells, under General Rule G-1 or 

G-2; or 

iii) Who is delinquent in payment of any annual well fees under General 

Rule B-2. 

B) Was an owner, officer, director, partner, or member or manager of a limited 

liability company, or other person with an interest exceeding 5%;

i) That has failed to abate an outstanding violation of the oil and gas 

statutes or rules, regulations, or comply with an orders of the 

Commission as specified in a final administrative decision of the 

Commission; or

ii) For which funds have been obligated and remain outstanding from the 

Plugging and Restoration Fund to plug wells, under General Rule G-1 or 

G-2; or 

iii) Who is delinquent in payment of any annual well fees under General 

Rule B-2.

C) Is a Permit Holder or an owner, officer, director, partner, or member or manager 

of a limited liability company, or other person with an interest exceeding 5%;

i) That has failed to abate an outstanding violation of the oil and gas 

statutes or rules, regulations, or comply with an orders of the 

Commission as specified in a final administrative decision of the 

Commission; or

ii) For which funds have been obligated and remain outstanding from the 

Plugging and Restoration Fund to plug wells, under General Rule G-1 or 

G-2; or 

iii) Who is delinquent in payment of any annual well fees under General 

Rule B-2.

D) If the Director determines that the applicant, or an owner, officer, director, 

partner, or member or manager of a limited liability company, or other person 

with an interest exceeding 5% in the applicant, has a history of violating an oil 
GENERAL RULES AND REGULATIONS

199

and gas statute, rule, regulation, permit condition or order of the Commission, the 

Arkansas Department of Environmental Quality, the Arkansas Pollution and 

Ecology Commission, or any other state or federal environmental regulatory 

agency, including those of other states, regarding oil or gas related activities, 

which pose a potential danger to the environment and public health and safety. In 

making the determination, the Director may consider:

i) The danger to the environment and public health and safety if the 

applicant's proposed activity is not conducted in a competent and 

responsible manner; and

ii) The degree to which past and present oil and gas related activities 

directly bear upon the reliability, competence, and responsibility of the 

applicant.

E) If a permit is not issued in accordance with subparagraph o) 2) above, the 

Applicant may request to have the permit application referred to the Commission 

for determination, in accordance with General Rules A-2 and A-3, and other 

applicable hearing procedures, except that no additional filing fee is required.

p) The Commission retains jurisdiction to determine zones suitable for disposal injection based on 

the porosity, permeability, fluid capacity, structure, geology and overall suitability of the zone as 

a disposal injection interval with respect to protection of USDWs and oil and gas resources. 

q) Class II Disposal or Class II Commercial Disposal Well Drilling Permit or Transfer Revocation 

Procedures

1) The Director may revoke a Class II Disposal or Class II Commercial Disposal Well 

permit or transfer approval if the Permit Holder fails to meet permit conditions as 

specified in the Class II Disposal or Class II Commercial Disposal Well permit or transfer 

approval, the Class II Disposal or Class II Commercial Disposal Well permit or transfer 

approval was issued in error, or the Permit Holder falsified or otherwise misstated any 

material information in the application form. 

2) The Director shall notify the Permit Holder of the Class II Disposal or Class II 

Commercial Disposal Well permit or transfer revocation in writing. Following the 

revocation notice the Permit Holder is required to plug the Class II Disposal or Class II 

Commercial Disposal Well. The Permit holder shall have thirty (30) days from the date 

of the Class II Disposal or Class II Commercial Disposal Well permit or transfer 

revocation to appeal the Director’s Decision to revoke the Class II Disposal or Class II 

Commercial Disposal Well permit or transfer approval in accordance with General Rule 

A-2, A-3 and other applicable hearing procedures. Operations may not commence or 

continue during the appeal process. A revocation of a Class II Disposal or Class II 

Commercial Disposal Well permit or transfer approval for which an appeal has not been 

filed, shall become a final administrative decision of the Commission thirty (30) days 

following the date of the revocation. 

r) Class II Disposal or Class II Commercial Disposal Well Transfer Procedures 

1) Definitions

A) "Current Permit Holder" means the individual or entity required to hold the 

permit or to whom the permit was issued and who is the owner of the right to 
GENERAL RULES AND REGULATIONS

200

operate said Class II Disposal or Class II Commercial Disposal Well(s), 

possesses the full rights and responsibilities for operating the Class II Disposal or 

Class II Commercial Disposal Well(s) in accordance with applicable Arkansas 

law and has the current obligation to plug said Class II Disposal or Class II 

Commercial Disposal Well(s), who is the assignor, transferor or seller (whether 

voluntary or involuntary) of the Class II Disposal or Class II Commercial 

Disposal Well(s).

B) "New Permit Holder" means the individual or entity acquiring the Class II 

Disposal or Class II Commercial Disposal Well(s) and the right to operate said 

Class II Disposal or Class II Commercial Disposal Well(s), who obtains the full 

rights and responsibilities for operating the Class II Disposal or Class II 

Commercial Disposal Well(s) in accordance with applicable Arkansas law and/or 

rule, regulation, or order of the Commission, whom will obtain the obligation to 

plug said Class II Disposal or Class II Commercial Disposal Well(s), and who as 

owner or operator in accordance with applicable Arkansas law and/or rule, 

regulation, or order of the Commission is required to hold the permit. 

C) “Transfer” means any assignment, devise, release, transfer, takeover, buyout, 

merger, sale, conveyance, or other transfer of any kind, whether voluntarily or 

involuntarily.

2) The provisions of this subparagraph apply to all transfers of the interest of the individual 

or entity required to hold and to whom the Class II Disposal or Class II Commercial 

Disposal Well transfer approval is issued (Permit Holder), including but not limited to:

A) a change of ownership of the right to drill and/or operate said Class II Disposal or 

Class II Commercial Disposal Well(s), along with the full rights and 

responsibilities for operating the Class II Disposal or Class II Commercial 

Disposal Well(s) and the obligation to ultimately plug said Class II Disposal or 

Class II Commercial Disposal Well(s); or

B) a change in the designation of the owner or operator under an operating or other 

similar agreement; or

C) a change pursuant to the action of the owners of separate interests who designate 

an owner to be Permit Holder; or

D) a change required by the appointment, by a court of competent jurisdiction, of a 

trustee or a receiver to exercise custody and control over the Class II Disposal or 

Class II Commercial Disposal Well(s), including the right to drill and/or operate 

said well(s) along with the full right and responsibilities for operating the well(s).

3) The provisions of this subparagraph shall not apply to the transfer of working interests 

not affecting the rights or responsibilities of the Permit Holder.

4) The provisions of this subparagraph shall not apply to transfers of Class II Disposal or 

Class II Commercial Disposal Well(s) abandoned or orphaned in accordance General 

Rule G-1 or G-2. Transfers of Class II Disposal or Class II Commercial Disposal Wells 

deemed abandoned or orphaned are subject to the transfer provisions in General Rule G3.
GENERAL RULES AND REGULATIONS

201

5) Notification of a transfer shall be given to the Director, or his designee, by the Current 

Permit Holder, on a form prescribed by the Director, of the transfer of any Class II 

Disposal or Class II Commercial Disposal Well or any Class II Disposal or Class II 

Commercial Disposal Well required to be permitted within thirty (30) days after the 

effective date of the transfer.

6) A separate form shall be completed for each lease, Class II Disposal or Class II 

Commercial Disposal Well, or other unit transferred.

7) The notification shall be signed by the Current Permit Holder and the New Permit 

Holder, or by authorized representatives specified on the Organizational Report filed in 

accordance with General Rule B-13, except as follows:

A) In lieu of the signature of the Current Permit Holder, the New Permit Holder may 

submit a court order or other legal document evidencing ownership of the lease 

or unit to be transferred in the event that the Current Permit Holder cannot be 

located or refuses to sign the notification of transfer form.

B) In lieu of the signature of the New Permit Holder, the Current Permit Holder may 

submit documentation evidencing transfer of the ownership of the Class II 

Disposal or Class II Commercial Disposal Well, lease, or unit in the event the 

New Permit Holder refuses to sign the notification of transfer form.

8) A New Permit Holder may operate Class II Disposal or Class II Commercial Disposal 

Wells covered by the Class II Disposal or Class II Commercial Disposal Well transfer 

request, until such time as the transfer request has been approved or denied by the 

Director or his designee, provided the request was submitted within thirty (30) days of 

the actual transfer of the Class II Disposal or Class II Commercial Disposal Well. 

However, Class II Disposal or Class II Commercial Disposal Wells may not be operated 

by the New Permit Holder, until a Class II Disposal or Class II Commercial Disposal 

Well transfer request is approved, if the request was received by the Director, or his 

designee, more than thirty (30) days after the actual transfer of the Class II Disposal or 

Class II Commercial Disposal Well.

9) A New Permit Holder that acquires the right to operate a Class II Disposal or Class II 

Commercial Disposal Well(s) pursuant to a transfer shall apply for and must receive 

transfer approval from the Director, or his designee, prior to operating the Class II 

Disposal or Class II Commercial Disposal Well(s) beyond the timeframe specified in 

subparagraph (r)(8) above. 

10) Prior to the Director, or his designee, approving the transfer request, the New Permit 

Holder shall provide the required financial assurance, if applicable, in accordance with 

General Rule B-2, and file the required organizational report, if applicable, in accordance 

with General Rule B-13.

11) A transfer to a New Permit Holder may be denied by the Director, or his designee, if the 

New Permit Holder meets any of the conditions specified in subparagraph o) above. 

12) The New Permit Holder shall be responsible for all regulatory requirements relative to all 

Class II Disposal or Class II Commercial Disposal Wells and all other surface production 

facilities in existence at the time of the transfer related to the Class II Disposal or Class II 

Commercial Disposal Wells. The New Permit Holder shall not be responsible for 

regulatory requirements relative to spills of crude oil or other production fluids which 
GENERAL RULES AND REGULATIONS

202

occurred prior to the date of the transfer, unless the New Permit Holder has otherwise 

agreed with the Current Permit Holder.

13) If any Class II Disposal or Class II Commercial Disposal Well, or any lease or other unit 

associated with the Class II Disposal or Class II Commercial Disposal Well, is in 

violation at the time of the transfer request to the New Permit Holder, the transfer request 

shall be denied pending abatement of all violations by the Current Permit Holder. 

However, if the New Permit Holder, after being notified of the violation(s), agrees in 

writing to the transfer approval including conditions to abate all violations, the transfer 

may be approved by the Director, or his designee. Failure to abate the violations within 

the time period specified by the Director or his designee may result in revocation of the 

transfer approval in accordance with subparagraph q) above, and/or other applicable 

enforcement actions in accordance with General Rule A-5.

14) The Current Permit Holder is not responsible for any regulatory violation caused by the 

actions of the New Permit Holder during the permit transfer process, after notice is given 

to the Director, or his designee, by the Current Permit Holder of the pending transfer if 

the transfer is approved. However, if the transfer is denied by the Director or his 

designee, the Current Permit Holder assumes all responsibility for the violations caused 

by the New Permit Holder. Nothing in this subsection shall affect the contractual rights 

and obligations between the person or entity transferring the Class II Disposal or Class II 

Commercial Disposal Well(s) and the person or entity acquiring the Class II Disposal or 

Class II Commercial Disposal Well(s).

15) The transfer approval pursuant to this subparagraph shall not affect the rights of the 

Commission, or any obligation or duty of the Current Permit Holder arising under any 

applicable Arkansas laws, or rules, regulations, or orders of the Commission. Any cause 

of action accruing or any action or proceeding which has commenced, whether 

administrative, civil or criminal, may be instituted or continued without regard to the 

transfer approval.

16) The Director shall notify the Current and New Permit Holder of the transfer approval or 

denial in writing. Following the approval or denial of the transfer approval request, the 

Current or New Permit holder shall have thirty (30) days from the date of the approval or 

denial to appeal the Director’s Decision in accordance with General Rule A-2, A-3 and 

other applicable hearing procedures. A transfer request approval or denial, for which an 

appeal has not been filed, shall become a final administrative decision of the Commission 

thirty (30) days following the date of the approval or denial.

s) Miscellaneous Provisions and Requirements for Class II Disposal or Class II Commercial 

Disposal Wells Within General Rule B-43 Section c) lands.

1) Definitions:

a. “Regional Fault” means the identified fault zones named by the Arkansas 

Geological Survey as the Clinton, Center Ridge, Heber Springs, Enders and 

Morrilton Fault zones; and which are part of a general east-west turning northeast (approximately N55oE to N75oE) trending, down thrown to the south, fault 

system generally occurring below the Fayetteville Shale Formation displacing the 

Lower Mississippian through Precambrian strata and truncating upward at the 

unconformity between the Mississippian and Pennsylvanian age strata; and 

which are identified on the Arkansas Geological Survey map attached hereto as 
GENERAL RULES AND REGULATIONS

203

Exhibit 1 to this Rule; and as updated for purposes of this Rule following notice 

and a hearing in accordance with General Rule A-2.

b. “Moratorium Zone Deep Faults” means deeper faults associated with the GuyGreenbrier Earthquake Swarm; and which are part of a general northeastsouthwest (approximately N30oE) trending deeper fault system displacing the 

Lower Ordovician through Precambrian strata occurring in the general B-43 

Section c) lands area.

2) Unless otherwise approved by the Commission after notice and a hearing, no permit to 

drill, deepen, re-enter, recomplete or operate a Class II Disposal or Class II Commercial 

Disposal Well may be granted for any Class II or Class II Commercial Disposal wells in 

any formation within the following area (“Moratorium Zone”) located in Cleburne, 

Conway, Faulkner, Van Buren, and White Counties:
GENERAL RULES AND REGULATIONS

204

Sections Township Range 

ALL 4N 13W 

ALL 5N 12W 

ALL 5N 13W 

ALL 5N 14W 

ALL 6N 12W 

ALL 6N 13W 

ALL 7N 11W 

ALL 7N 12W 

ALL 7N 13W 

ALL 8N 11W 

ALL 8N 12W 

ALL 8N 13W 

ALL 9N 10W 

ALL 9N 11W 

ALL 9N 12W 

ALL 10N 10W 

ALL 10N 11W 

ALL 11N 10W 

ALL 11N 11W 

1-12, 14-23, 27-33 

1-30, 35-36 

1-2, 10-15, 23-25 

4-9, 17-20, 30-31 

25, 35-36 

6

4N 

4N

4N

5N

5N

6N

12W 

14W 

15W 

11W 

15W 

10W 

1-23, 26-34 

1-4, 9-36 

24-25, 36 

3-9, 16-20, 29-31 

1, 11-14, 22-27, 34-36 

6-7

6N 

6N 

6N 

7N 

7N 

8N

11W 

14W 

15W 

10W 

14W 

9W 

1-24, 26-35 

25, 36 

3-10, 15-21, 29-32 

1-5, 7-36 

1-23, 27-34 

1-3, 9-17, 19-36 

25, 33, 34, 36 

17-22, 27-35 

13, 23-27, 34-36 

8N 

8N 

9N 

9N 

10N 

10N 

10N 

11N 

11N 

10W 

14W 

9W 

13W 

9W 

12W 

13W 

9W 

12W 
GENERAL RULES AND REGULATIONS

205

3) Unless otherwise approved by the Commission after notice and a hearing, no permit to 

drill or re-enter, a new Class II Disposal or Class II Commercial Disposal Well may be 

granted within one (1) mile of a Regional Fault or within five (5) miles of a known or 

identified Moratorium Zone Deep Fault within any remaining B-43 Section c) lands. 

4) Unless otherwise approved by the Commission after notice and a hearing, no permit to 

deepen or re-complete any existing Class II Disposal or Class II Commercial Disposal 

Well in a zone stratigraphically below the Fayetteville Shale formation, may be granted 

within one (1) mile of a Regional Fault or within five (5) miles of a known or identified 

Moratorium Zone Deep Fault within any remaining B-43 Section c) lands.

5) Unless otherwise approved by the Commission after notice and a hearing, the following 

provisions shall apply to any permit to drill, deepen, or operate a new Class II Disposal or 

Class II Commercial Disposal Well proposed to be located within in any remaining B-43 

Section c) lands:

a) No Class II Disposal or Class II Commercial Disposal Well disposing in a zone 

occurring stratigraphically below the Fayetteville Shale formation shall be 

located within five (5) miles of another Class II Disposal or Class II Commercial 

Disposal Well disposing in a zone occurring stratigraphically below the 

Fayetteville Shale formation. 

b) No Class II Disposal or Class II Commercial Disposal well disposing in a zone 

occurring stratigraphically above the Fayetteville Shale formation shall be 

located within one-half (1/2) mile of another Class II Disposal or Class II 

Commercial Disposal Well disposing in a zone occurring stratigraphically above 

the Fayetteville Shale formation.

6) The Applicant shall provide technical information to the Director in support of the 

application. The technical justification shall include information related to the location of 

any Moratorium Zone Deep Fault within five (5) miles or Regional Fault within two 

miles (2) of the proposed location of the Class II Disposal or Class II Commercial 

Disposal Well, with special emphasis on identifying any deep faults occurring below the 

Fayetteville Shale formation which extend to the basement rock.

7) Flow meters, or other measuring devices approved by the Director, shall be installed on 

all Class II Disposal and Class II Commercial Disposal Wells and Permit Holders shall 

submit accurate injection volume and pressure information, on no less than a daily basis, 

on a form prescribed by the Director.

(Source: new rule July 17, 2009; amended November 26, 2009; amended July 30, 2010; amended July 29, 

2011; Amended February 17, 2012)
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206

RULE H-2: WELL CONSTRUCTION, OPERATING AND REPORTING

REQUIREMENTS FOR CLASS II DISPOSAL WELLS

a) No Class II Disposal Well, as defined in General Rule H-1 a) 1) (hereinafter referred to as “Class 

II Disposal Well”), for which a permit has been issued in accordance with General Rule H-1, 

shall be operated until well internal mechanical integrity has been established in accordance with 

sub-paragraph o) below, and an authority for initial commencement of injection operations is 

issued by the Director.

b) The permit holder shall provide notice to the Commission Regional Office where the Class II 

Disposal Well is located, prior to performing any well servicing activity, cementing, or any 

wireline logging activities, so as to allow commission staff to be present to observe the activity. 

Any well servicing which requires the resetting of the packer shall require an internal mechanical 

integrity test be run in accordance with subparagraph o) below, prior to re-commencement of 

injection.

c) All well records for newly drilled Class II Disposal Wells shall be submitted in accordance 

General Rule B-5. Completion or recompletion reports and wireline logs for all subsequent well 

servicing, cementing or wireline logging activity performed on the well shall be filed no later than 

fifteen (15) days after completion of these activities.

d) Following issuance of the permit to Drill and or Operate a Class II Disposal Well, an annual fee 

of $100 per well shall be due each July 1st for the life of the well until the well is plugged.

e) Surface and production casing requirements.

1) Class II Disposal Wells shall be cased and cemented, in such manner that damage will 

not be caused to any USDW, as defined in General Rule H-1 a) 5) (hereinafter referred to 

as “USDW”), or oil and gas resources. 

2) For newly drilled Class II Disposal Wells

A) Set and cement surface casing 250 feet below the base of the lowermost USDW, 

and cement production casing to at least 250 feet above the proposed disposal 

zone; or

B) Set and cement surface casing fifty (50) feet below the base of the lowermost 

formation utilized for a public water system (see 40 CFR) in the area of the Class 

II Disposal Well, with a minimum of five hundred (500) feet of surface casing 

required, and cement production casing back to the surface.

3) For existing wells converted to Class II Disposal Wells

A) Unless otherwise approved by the Director, production casing in the existing well 

is required to be cemented to at least 250 feet above the proposed disposal zone. 

A cement bond (CBL), gamma ray (GR) and density log (VDL) shall be required 

to verify the presence of the required casing cement. The CBL should indicate at 

a minimum an 80% bond index over the 250 foot cemented interval.

B) If a casing liner is required to provide well bore integrity above the required 

production cementing requirements in subparagraph e) 3) A) above, the liner 

must be set, at a minimum, below the cemented portion of the production casing 

and cemented back to surface.
GENERAL RULES AND REGULATIONS

207

f) Tubing and packer requirements. 

1) All injection shall be through tubing and packer. The packer shall be placed no higher 

than 100 feet above the uppermost perforations or the casing seat in an open hole 

completion, provided the packer is within the cemented portion of the production casing, 

provided the packer is no less than 500 feet below the base of the USDW. 

2) If the tubing and packer cannot be set or utilized in accordance with subsection f) 1) 

above, due to existing well construction conditions, the Permit Holder may request the 

Director to authorize an alternative packer setting depth or well construction. In 

determining an alternative packer setting depth or alternative well construction, the 

Director shall take into consideration the current construction of the well, the depth of the 

USDWs and the nature of the obstruction. If an alternative packer setting depth or well 

construction is authorized, the Director may require additional or more frequent internal 

mechanical integrity tests be performed on the well, or may require additional remedial or 

corrective work to assure that injection does not endanger USDWs.

3) The Permit Holder shall contact the Regional Office in which the well is located at least 

24 hours prior to the initial setting or any resetting of the packer in a Class II Disposal 

Wells to enable an inspector to be present when the packer is set. 

g) The wellhead shall be maintained in a leak-free condition, and must have a working pressure 

guage in excess of the maximum discharge pressure of the pump. The wellhead shall be 

configured to include a one half inch female fitting, with shut-off valve, to allow monitoring of 

the annulus between the production casing and the injection tubing and a one half inch female 

fitting, with shut-off valve, installed on the tubing to measure the injection pressure. 

h) The injection pressure shall not exceed the maximum injection pressure established in accordance 

with General Rule H-1 h) 8).

i) No change shall be made in the permitted injection zones unless the new zone is permitted in 

accordance with General Rule H-1. 

j) Injection fluids shall be confined to the permitted injection zones. If the Director has reason to 

believe, based upon well records or field observations, that injection fluids are migrating into 

zones not permitted for injection or into USDWs or to the surface or is causing fluid migration 

into the USDWs, due to the operation of any Class II Disposal Well or resulting from a failure of 

internal or external mechanical integrity of the well, the Permit Holder shall be required to shut-in 

the well until all necessary corrective work, which may include plugging of the well, is 

completed. 

k) Internal mechanical integrity shall be maintained in accordance with subparagraph o) below.

l) Only Class II Fluids, as defined in General Rule H-1 a) 3), and/or fresh water can be injected into 

a Class II Disposal Well. 

m) Each well shall have a legible sign placed near the well showing the Permit Holder and the well 

name and number and permit number and section, township and range as shown on the permit in 

the Commission records.

n) The Permit Holder of each Class II Disposal Well shall file a Quarterly Well Status Report on 

forms prescribed by the Director. The report shall be filed within thirty (30) days after the end of 
GENERAL RULES AND REGULATIONS

208

each quarter of a calendar year commencing on January 1 of each year. The report shall include 

at a minimum:

1) Name and permit number of the well;

2) Names of all injection intervals;

3) Maximum daily injection rates and pressures; and

4) Monthly volumes of fluid injected.

o) Establishment of Internal Mechanical Integrity.

1) Internal mechanical integrity must be maintained at all times. If internal mechanical 

integrity is lost, the Permit Holder shall shut-in the well immediately and notify the 

Regional Office where the well is located, of loss of internal mechanical integrity. The 

well shall remain shut-in until the necessary remedial action necessary to restore internal 

mechanical integrity is completed and a new internal mechanical integrity test run and 

successfully passed.

2) An internal mechanical integrity test shall be performed:

A) Prior to initial injection into a newly permitted Class II Disposal Well;

B) Prior to initial injection into a Class II Disposal Well after a change to a newly 

permitted injection zone;

C) Prior to resuming injection into any Class II Disposal Well after any workover of 

the well involving the resetting or movement of a packer;

D) Whenever the Director has reason to believe, based upon well records or field 

observation, that the Class II Disposal Wells may be leaking or improperly 

constructed; and

E) At least once every five (5) years measured from the date of the last successful 

test.

3) Internal mechanical integrity test

A) The following tests shall be performed on Class II Disposal Wells to establish the 

internal mechanical integrity of the tubing, casing and packer of the well. The 

Permit Holder shall contact the Regional Office in which the well is located at 

least 48 hours prior to conducting the test to enable an inspector to be present 

when the test is done. 

i) Pressure Test

The casing-tubing annulus above the packer shall be tested under the 

supervision of a Commission representative at a minimum pressure 

differential between the tubing and the annulus of fifty (50) psig for a 

period of thirty (30) minutes. The casing-tubing annulus starting test 

pressure shall not be less than three hundred (300) psig and may vary no 

more than ten (10) percent of the starting test pressure during the test. 
GENERAL RULES AND REGULATIONS

209

The pressure at which the test is to be performed shall be fifty (50) psig 

over the permitted injection pressure, with a maximum of one thousand 

(1000) psig.

ii) Radioactive Tracer Survey Test

For those wells in which alternative well construction has been approved 

by the Director in accordance with subparagraph f) 2) above, a 

radioactive tracer survey may be run in the well at a frequency to be 

determined by the Director to evidence mechanical integrity of the well 

by demonstrating that the injected fluid is being injected into the 

approved disposal zone.

B) Any Class II Disposal Well which fails an internal mechanical integrity test, or 

on which an internal mechanical integrity test has not been performed when 

required, shall be shut in until the well is successfully tested or remedial work is 

commenced and completed or the well is plugged. The necessary work shall be 

completed and an internal mechanical integrity test successfully completed 

within ninety (90) days. The Director may approve up to an additional ninety 

(90) days, with any greater length of time to be established by the Commission 

upon application by the operator.

p) If the Director has reason to believe, based upon well records or field observation, that any Class 

II Disposal Well is causing fluid migration into the USDWs resulting from a failure of internal or 

external mechanical integrity, the Permit Holder shall shut in the well until any necessary 

corrective work is commenced and completed and internal and external mechanical integrity is 

established. 

q) Class II Disposal Wells no longer in service for periods greater than 24 months shall be plugged 

or temporarily abandoned in accordance with General Rule B-7.

(Source: new rule July 17, 2009; amended October 24, 2009)
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210

RULE H-3: WELL CONSTRUCTION, OPERATING AND REPORTING

REQUIREMENTS FOR CLASS II COMMERCIAL DISPOSAL WELLS

a) No Class II Commercial Disposal Well, as defined in General Rule H-1 a) 2) (hereinafter referred 

to as “Class II Commercial Disposal Well”) for which a permit has been issued in accordance 

with General Rule H-1, shall be operated until well internal mechanical integrity has been 

established in accordance with sub-paragraph o) below, and an authority for initial 

commencement of injection operations is issued by the Director.

b) Notice shall be provided to the Commission Regional Office where the Class II Commercial 

Disposal Well is located, prior to performing any well servicing activity, cementing, or any 

wireline logging activities, so as to allow Commission staff to be present to observe the activity. 

Any well servicing which requires the resetting of the packer shall required an internal 

mechanical integrity test be run in accordance with subparagraph o) below, prior to recommencement of injection.

c) All well records for newly drilled Class II Commercial Disposal Wells shall be submitted in 

accordance General Rule B-5. Completion or recompletion reports and wireline logs for all 

subsequent well servicing, cementing or wireline logging activity performed on the well shall be 

filed no later than fifteen (15) days after completion of these activities.

d) Following issuance of the permit to Drill and or Operate a Class II Commercial Disposal Well, an 

annual fee of $100 per well shall be due each July 1st for the life of the well until the well is 

plugged.

e) Surface and production casing requirements.

1) Class II Commercial Disposal Wells shall be cased and cemented, in such manner that 

damage will not be caused to oil and gas resources or any USDW, as defined in General 

Rule H-1 a) 5) (hereinafter referred to as “USDW”). 

2) Existing wells shall be prohibited for re-completion as a Class II Commercial Disposal 

Well unless the well had been constructed at the time of original completion in 

accordance with subparagraph e) 3) below.

3) Newly drilled Class II Commercial Disposal Wells:

A) Set and cement surface casing 250 feet below the base of the lowermost USDW, 

and cement production casing to at least 500 feet above the proposed disposal 

zone; or

B) Set and cement surface casing fifty (50) feet below the base of the lowermost 

formation utilized for a public water system (see 40 CFR) in the area of the Class 

II Commercial Disposal Well, with a minimum of five hundred (500) feet of 

surface casing required, and cement production casing back to the surface.

C) A cement bond (CBL), gamma ray (GR) and density log (VDL) shall be required 

to verify the presence of the required casing cement. The CBL should indicate at 

a minimum an 80% bond index over the 500 foot cemented interval.

f) Tubing and packer requirements. 
GENERAL RULES AND REGULATIONS

211

1) All injection shall be through tubing and packer. The packer shall be placed no higher 

than 100 feet above the uppermost perforations or the casing seat in an open hole 

completion, provided the packer is within the cemented portion of the production casing,

provided the packer is no less than 750 feet below the base of the lowermost USDW. 

2) The Permit Holder shall contact the District Office in which the well is located at least 24 

hours prior to the initial setting or any resetting of the packer in a Class II Commercial 

Disposal Well to enable an inspector to be present when the packer is set.

g) The wellhead shall be maintained in a leak-free condition, and must have a working pressure 

gauge in excess of the maximum discharge pressure of the pump. The wellhead shall be 

configured to include a one half inch female fitting, with shut-off valve, to allow monitoring of 

the annulus between the production casing and the injection tubing and a one half inch female 

fitting, with shut-off valve, installed on the tubing to measure the injection pressure.

h) The injection pressure shall not exceed the maximum injection pressure established in accordance 

with General Rule H-1 h) 8).

i) No change shall be made in the permitted injection zones unless the new zone is permitted in 

accordance with General Rule H-1. 

j) Injection fluids shall be confined to the permitted injection zones. If the Director has reason to 

believe, based upon well records or field observations, that injection fluids are migrating into 

zones not permitted for injection or into USDWs, or to the surface, or is causing fluid migration 

into the USDWs, due to the operation of any Class II Commercial Disposal Well or resulting 

from a failure of internal or external mechanical integrity of the well, the Permit Holder shall be 

required to shut-in the well until all necessary corrective work, which may include plugging of 

the well, is completed. 

k) Internal mechanical integrity shall be maintained in accordance with subparagraph o) below.

l) Only Class II Fluids, as defined in General Rule H-1 a) 3), and/or fresh water can be injected into 

a Class II Commercial Disposal Well. 

m) Each well shall have a legible sign placed near the well showing the Permit Holder and the well 

name and number and permit number and section, township and range as shown on the permit in 

the Commission records and an emergency telephone number.

n) The Permit Holder of each Class II Commercial Disposal Well shall file a Monthly Well Status 

Report on forms prescribed by the Director. The report shall be filed within thirty (30) days after 

the end of each month of a calendar year commencing on January 1 of each year. The report shall 

include at a minimum:

1) Name and permit number of the well;

2) Names of all injection intervals;

3) Maximum daily injection rates and pressures; and

4) Monthly volumes of fluid injected.

5) In addition, each Class II Commercial Disposal Well facility must keep an accurate log of 

each shipment of fluids to be disposed. This log shall include the generator (operator) of 
GENERAL RULES AND REGULATIONS

212

the fluid, well name, number and location or permit number of the well, amount of fluid 

and the date the shipment was received. A copy of this log must accompany the above 

Monthly Well Status Report.

o) Establishment of Internal Mechanical Integrity.

1) Internal mechanical integrity must be maintained at all times. If internal mechanical 

integrity is lost, the Permit Holder shall shut-in the well immediately and notify the 

Regional Office where the well is located, of loss of internal mechanical integrity. The 

well shall remain shut-in until the necessary remedial action necessary to restore internal 

mechanical integrity is completed and a new internal mechanical integrity test run and 

successfully passed.

2) An internal mechanical integrity test shall be performed:

A) Prior to initial injection into a newly permitted Class II Commercial Disposal 

Well;

B) Prior to initial injection into a Class II Commercial Disposal Well after a change 

to a newly permitted injection zone;

C) Prior to resuming injection into any Class II Commercial Disposal Well after any 

workover of the well involving the resetting or movement of a packer;

D) Whenever the Director has reason to believe, based upon well records or field 

observation, that the Class II Commercial Disposal Well may be leaking or 

improperly constructed; and

E) At least once every year measured from the date of the last successful test.

3) Internal mechanical integrity test

A) The following test shall be performed on Class II Commercial Disposal Wells to 

establish the internal mechanical integrity of the tubing, casing and packer of the 

well. The Permit Holder shall contact the Regional Office in which the well is 

located at least forty-eight (48) hours prior to conducting the test to enable an 

inspector to be present when the test is done. The casing-tubing annulus above 

the packer shall be tested under the supervision of a Commission representative 

at a minimum pressure differential between the tubing and the annulus of fifty 

(50) psig for a period of thirty (30) minutes and may vary no more than ten (10) 

percent of the starting test pressure during the test. The pressure at which the 

mechanical integrity test is to be performed shall be fifty (50) psig over the 

permitted injection pressure with a maximum of one thousand (1,000) psig. The 

minimum test pressure shall be three hundred (300) psig.

B) Any Class II Commercial Disposal Well which fails an internal mechanical 

integrity test, or on which an internal mechanical integrity test has not been 

performed when required, shall be shut in until the well is successfully tested or 

remedial work is commenced and completed or the well is plugged. The 

necessary work shall be completed and an internal mechanical integrity test 

successfully completed within ninety (90) days. The Director may approve up to 

an additional ninety (90) days, with any greater length of time to be established 

by the Commission upon application by the operator.
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213

p) All commercial facilities must have restricted entry to all nonessential traffic. A lockable gate 

must be maintained and shall be locked during all unmanned hours. Additionally, the Director 

may require a fence to limit entry to the facility.

q) Permit Holders may be required to take periodic samples of the injection fluid and have those 

samples analyzed at a certified lab. Samples of the injection fluid may also be taken periodically 

by a Commission representative. Samples will be checked for compliance with Class II fluids as 

defined in General Rule H-1.

r) If the Director has reason to believe, based upon well records or field observation, that any Class 

II Commercial Disposal Well is causing fluid migration into the USDWs resulting from a failure 

of internal or external mechanical integrity, the Permit Holder shall shut in the well until any 

necessary corrective work is commenced and completed and internal and external mechanical 

integrity is established. 

s) Class II Commercial Disposal Wells no longer in service for periods greater than 12 months shall 

be plugged in accordance with General Rule B-7.

(Source: new rule July 17, 2009; amended October 24, 2009)