RULE 178.00.08-011 - General Rules B-13: Organization Reports, B-44: Establishment of Drilling Units for Gas Production From All Sources of Supply Occurring in Certain Producing Areas in Franklin, Logan, Scott, Sebastian And Yell Counties, D-7: Natural Gas to be Metered, D-18: Authority to Commingle and E-3: Exploration and Production Fluid Gathering Handling and Transportation

RULE 178.00.08-011. General Rules B-13: Organization Reports, B-44: Establishment of Drilling Units for Gas Production From All Sources of Supply Occurring in Certain Producing Areas in Franklin, Logan, Scott, Sebastian And Yell Counties, D-7: Natural Gas to be Metered, D-18: Authority to Commingle and E-3: Exploration and Production Fluid Gathering Handling and Transportation

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.

GENERAL 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;

(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) 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-in-interest 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.

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 majority-in-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 B-40;

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 B-40;

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 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 B-40;

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.

(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 and production allowable provisions of General Rule D-16 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 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 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.

RULE D-7 NATURALGAS TO BE METERED

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.

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; 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;

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.

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 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 off-site temporary storage facility, a permitted surface disposal 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.

(1/15/2009)

The following state regulations pages link to this page.