# Title 43 — Industrial Commission

## Article 43-02 — Mineral Exploration and Development

## Chapter 43-02-03 — Oil and Gas Conservation

Gas

Saltwater Handling Facilities - Suspension of Drilling

or Saltwater Handling Facility
Underground Injection, Commingling, Converting Mineral Wells to Freshwater
Wells, and Central Tank Battery or Central Production Facilities Applications
### § 43-02-03-01. Definitions.

The terms used throughout this chapter have the same meaning as in North Dakota Century Code
chapter 38-08 except:
1. "Adjusted allowable" means the allowable production a proration unit receives after all
adjustments are applied.
2. "Allocated pool" is one in which the total oil or natural gas production is restricted and
allocated to various proration units therein in accordance with proration schedules.
3. "Allowable production" means that number of barrels of oil or cubic feet of natural gas
authorized to be produced from the respective proration units in an allocated pool.

4. "Barrel" means forty-two United States gallons [158.99 liters] measured at sixty degrees
Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three hundredths pounds per
square inch absolute [1034.19 grams per square centimeter].
5. "Barrel of oil" means forty-two United States gallons [158.99 liters] of oil after deductions for
the full amount of basic sediment, water, and other impurities present, ascertained by
centrifugal or other recognized and customary test.
6. "Bottom hole or subsurface pressure" means the pressure in pounds per square inch gauge
under conditions existing at or near the producing horizon.
7. "Bradenhead gas well" means any well capable of producing gas through wellhead
connections from a gas reservoir which has been successfully cased off from an underlying oil
or gas reservoir.
8. "Casinghead gas" means any gas or vapor, or both gas and vapor, indigenous to and
produced from a pool classified as an oil pool by the commission.
9. "Certified or registered mail" means any form of service by the United States postal service,
federal express, Pitney Bowes, and any other commercial, nationwide delivery service that
provides the mailer with a document showing the date of delivery or refusal to accept delivery.
10. "Commercial injection well" means one that only receives fluids produced from wells operated
by a person other than the principal on the bond.
11. "Common purchaser for natural gas" means any person now or hereafter engaged in
purchasing, from one or more producers, gas produced from gas wells within each common
source of supply from which it purchases, for processing or resale.
12. "Common purchaser for oil" means every person now engaged or hereafter engaging in the
business of purchasing oil in this state.
13. "Common source of supply" is synonymous with pool and is a common accumulation of oil or
gas, or both, as defined by commission orders.
14. "Completion" means an oil well shall be considered completed when the first oil is produced
through wellhead equipment into tanks from the ultimate producing interval after casing has
been run. A gas well shall be considered complete when the well is capable of producing gas
through wellhead equipment from the ultimate producing zone after casing has been run. A
dry hole shall be considered complete when all provisions of plugging are complied with as set
out in this chapter.
15. "Condensate" means the liquid hydrocarbons recovered at the surface that result from
condensation due to reduced pressure or temperature of petroleum hydrocarbons existing in a
gaseous phase in the reservoir.
16. "Cubic foot of gas" means that volume of gas contained in one cubic foot [28.32 liters] of
space and computed at a pressure of fourteen and seventy-three hundredths pounds per
square inch absolute [1034.19 grams per square centimeter] at a base temperature of sixty
degrees Fahrenheit [15.56 degrees Celsius].
17. "Director" means the director of oil and gas of the industrial commission, the assistant director
of oil and gas of the industrial commission, and their designated representatives.
18. "Enhanced recovery" means the increased recovery from a pool achieved by artificial means
or by the application of energy extrinsic to the pool, which artificial means or application
includes pressuring, cycling, pressure maintenance, or injection to the pool of a substance or

form of energy but does not include the injection in a well of a substance or form of energy for
the sole purpose of:
a. Aiding in the lifting of fluids in the well; or
b. Stimulation of the reservoir at or near the well by mechanical, chemical, thermal, or
explosive means.
19. "Exception well location" means a location which does not conform to the general spacing
requirements established by the rules or orders of the commission but which has been
specifically approved by the commission.
20. "Flow line" means a pipe or conduit of pipes used for the transportation, gathering, or conduct
of a mineral from a wellhead to a separator, treater, dehydrator, tank battery, or surface
reservoir.
21. "Gas lift" means any method of lifting liquid to the surface by injecting gas into a well from
which oil production is obtained.
22. "Gas-oil ratio" means the ratio of the gas produced in cubic feet to a barrel of oil concurrently
produced during any stated period.
23. "Gas-oil ratio adjustment" means the reduction in allowable of a high gas-oil ratio proration
unit to conform with the production permitted by the limiting gas-oil ratio for the particular pool
during a particular proration period.
24. "Gas transportation facility" means a pipeline in operation serving one or more gas wells for
the transportation of natural gas, or some other device or equipment in like operation whereby
natural gas produced from gas wells connected therewith can be transported.
25. "Gas well" means a well producing gas or natural gas from a common source of gas supply as
determined by the commission.
26. "High gas-oil ratio proration unit" means a proration unit with a producing oil well with a gas-oil
ratio in excess of the limiting gas-oil ratio for the pool.
27. "Inactive pipeline" means any underground gathering pipeline system or portion thereof that
has not transported fluid for more than one year.
28. "Injection or input well" means any well used for the injection of air, gas, water, or other fluids
into any underground stratum.
29. "Injection pipeline" means a pipe or conduit of pipes used for the transportation of fluids,
typically via an injection pump, from a storage tank or tank battery directly to an injection well.
30. "Limiting gas-oil ratio" means the gas-oil ratio assigned by the commission to a particular oil
pool to limit the volumes of casinghead gas which may be produced from the various
oil-producing units within that particular pool.
31. "Log or well log" means a systematic, detailed, and correct record of formations encountered
in the drilling of a well, including commercial electric logs, radioactive logs, dip meter logs, and
other related logs.
32. "Multiple completion" means the completion of any well so as to permit the production from
more than one common source of supply.
33. "Natural gas or gas" means and includes all natural gas and all other fluid hydrocarbons not
herein defined as oil.

34. "Occupied dwelling" or "permanently occupied dwelling" means a residence which is lived in
by a person at least six months throughout a calendar year.
35. "Official gas-oil ratio test" means the periodic gas-oil ratio test made by order of the
commission and by such method and means and in such manner as prescribed by the
commission.
36. "Offset" means a well drilled on a forty-acre [16.19-hectare] tract cornering or contiguous to a
forty-acre [16.19-hectare] tract having an existing oil well, or a well drilled on a one hundred
sixty-acre [64.75-hectare] tract cornering or contiguous to a one hundred sixty-acre
[64.75-hectare] tract having an existing gas well; provided, however, that for wells subject to a
fieldwide spacing order, "offset" means any wells located on spacing units cornering or
contiguous to the spacing unit or well which is the subject of an inquiry or a hearing.
37. "Oil well" means any well capable of producing oil or oil and casinghead gas from a common
source of supply as determined by the commission.
38. "Operator" is the principal on the bond covering a well and such person shall be responsible
for drilling, completion, and operation of the well, including plugging and reclamation of the
well site.
39. "Overage or overproduction" means the amount of oil or the amount of natural gas produced
during a proration period in excess of the amount authorized on the proration schedule.
40. "Potential" means the properly determined capacity of a well to produce oil, or gas, or both,
under conditions prescribed by the commission.
41. "Pressure maintenance" means the injection of gas or other fluid into a reservoir, either to
increase or maintain the existing pressure in such reservoir or to retard the natural decline in
the reservoir pressure.
42. "Proration day" consists of twenty-four consecutive hours which shall begin at seven a.m. and
end at seven a.m. on the following day.
43. "Proration month" means the calendar month which shall begin at seven a.m. on the first day
of such month and end at seven a.m. on the first day of the next succeeding month.
44. "Proration schedule" means the periodic order of the commission authorizing the production,
purchase, and transportation of oil or of natural gas from the various units of oil or of natural
gas proration in allocated pools.
45. "Proration unit for gas" consists of such geographical area as may be prescribed by special
pool rules issued by the commission.
46. "Recomplete" means the subsequent completion of a well in a different pool.
47. "Reservoir" means pool or common source of supply.
48. "Saltwater handling facility" means and includes any container and site used for the handling,
storage, disposal of substances obtained, or used, in connection with oil and gas exploration,
development, and production and can be a stand-alone site or an appurtenance to a well or
treating plant.
49. "Shut-in pressure" means the pressure noted at the wellhead when the well is completely shut
in, not to be confused with bottom hole pressure.
50. "Spacing unit" is the area in each pool which is assigned to a well for drilling, producing, and
proration purposes in accordance with the commission's rules or orders.

51. "Stratigraphic test well" means any well or hole, except a seismograph shot hole, drilled for the
purpose of gathering information with no intent to produce oil or gas from or inject into such
well.
52. "Subsurface observation well" means a well used to observe subsurface phenomena,
including the presence of carbon dioxide, pressure fluctuations, fluid levels and flow,
temperature, and in situ water chemistry.
53. "Tank bottoms" means that accumulation of hydrocarbon material and other substances which
settle naturally below crude oil in tanks and receptacles that are used in handling and storing
of crude oil, and which accumulation contains basic sediment and water in an amount
rendering it unsalable to an ordinary crude oil purchaser; provided, that with respect to lease
production and for lease storage tanks, a tank bottom shall be limited to that volume of the
tank in which it is contained that lies below the bottom of the pipeline outlet thereto.
54. "Treating plant" means any plant permanently constructed or portable used for the purpose of
wholly or partially reclaiming, treating, processing, or recycling tank bottoms, waste oils,
drilling mud, waste from drilling operations, produced water, and other wastes related to crude
oil and natural gas exploration and production. This is not to be construed as to include
saltwater handling and disposal operations which typically recover skim oil and solids from
their operations, treating mud or cuttings at a well site during drilling operations, treating
flowback water during completion operations at a well site, or treating tank bottoms at the well
site or facility where they originated.
History: Amended effective January 1, 1983; May 1, 1992; July 1, 1996; December 1, 1996;
September 1, 2000; July 1, 2002; January 1, 2008; April 1, 2014; October 1, 2016; April 1, 2018; April 1,
2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-02. Scope of chapter.

This chapter contains general rules of statewide application which have been adopted by the
industrial commission to conserve the natural resources of North Dakota, to prevent waste, and to
provide for operation in a manner as to protect correlative rights of all owners of crude oil and natural
gas. Special rules, pool rules, field rules, and regulations and orders have been and will be issued
when required and shall prevail as against general rules, regulations, and orders if in conflict therewith.
However, wherever this chapter does not conflict with special rules heretofore or hereafter adopted, this
chapter will apply in each case. The commission may grant exceptions to this chapter, after due notice
and hearing, when such exceptions will result in the prevention of waste and operate in a manner to
protect correlative rights.
History: Amended effective May 1, 1992.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-03. Promulgation of rules, regulations, or orders.

Repealed effective January 1, 1983.
### § 43-02-03-04. Emergency rule, regulation, or order.

Repealed effective January 1, 1983.

### § 43-02-03-05. Enforcement of laws, rules, and regulations dealing with conservation of oil

and gas.
The commission, its agents, representatives, and employees are charged with the duty and
obligation of enforcing all rules and statutes of North Dakota relating to the conservation of oil and gas.
However, it shall be the responsibility of all the owners, operators, and contractors to obtain information
pertaining to the regulation of oil and gas before operations have begun.
History: Amended effective May 1, 2004; April 1, 2012; April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-06. Waste prohibited.

All operators, contractors, drillers, carriers, gas distributors, service companies, pipe pulling and
salvaging contractors, or other persons shall at all times conduct their operations in the drilling,
equipping, operating, producing, plugging, and site reclamation of oil and gas wells in a manner that will
prevent waste.
History: Amended effective January 1, 1983; May 1, 1992.
General Authority: NDCC 38-08-03
Law Implemented: NDCC 38-08-03
### § 43-02-03-07. United States government leases.

The commission recognizes that all persons drilling and producing on United States government
land shall comply with the United States government regulations. Such persons shall also comply with
all applicable state rules and regulations. Copies of the sundry notices, reports on wells, and well data
required by this chapter of the wells on United States government land shall be furnished to the
commission at no expense to the commission.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1994; April 1, 2022.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-08. Classifying and defining pools.

Repealed effective January 1, 1983.
### § 43-02-03-09. Forms.

Forms required by the commission will be furnished upon request. The commission will provide
electronic submission for most requests and reports.
History: Amended effective April 1, 2022.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-10. Authority to cooperate with other agencies.

The commission may from time to time enter agreements with state and federal government
agencies, tribal governments, industry committees, and individuals with respect to special projects,
services, and studies relating to conservation of oil and gas.
History: Amended effective April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04

### § 43-02-03-11. Organization reports.

Every person acting as principal or agent for another or independently engaged in the drilling of oil
or gas wells, or in the production, storage, transportation, refining, reclaiming, treating, marketing, or
processing of crude oil or natural gas, engaged in the disposal of produced water, engaged in treating
plant operations, or engaged in pipeline operations in North Dakota shall immediately file with the
director the name under which such business is being conducted or operated; and name and
post-office address of such person, the business or businesses in which the person is engaged; the
plan of organization, and in case of a corporation, the law under which it is chartered; and the names
and post-office addresses of any person acting as trustee, together with the names and post-office
addresses of any officials thereof on an organization report (form 2). In each case where such business
is conducted under an assumed name, such organization report shall show the names and post-office
addresses of all owners in addition to the other information required. A new organization report shall be
filed when and if there is a change in any of the information contained in the original report.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; April 1,
2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-12. Reservoir surveys.

By special order of the commission, periodic surveys may be made of the reservoirs in this state
containing oil and gas. These surveys will be thorough and complete and shall be made using methods
approved by the director. The condition of the reservoirs containing oil and gas and the practices and
methods employed by the operators shall be investigated. The produced volume and source of crude
oil and natural gas, the reservoir pressure of the reservoir as an average, the areas of 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 shall be specifically included.
All operators of oil wells are required to permit and assist the agents of the commission in making
any and all special tests that may be required by the commission on any or all wells.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-13. Record of wells.

The director shall maintain a record of official well names, to be known as the well-name register, in
which shall be entered: (1) the name and location of each well; (2) the well file number; (3) the name of
the operator, or the operator's agent; and (4) any subsequent name or names assigned to the well and
approved by the director.
The last name assigned to a well in the well-name register shall be the official name of the well,
and the one by which it shall be known and referred to.
The director may, at the director's discretion, grant or refuse an application to change the official
name. The application shall be accompanied by a fee of twenty-five dollars, which fee is established to
cover the expense of recording the change. If the application is refused, the fee shall be refunded.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04

### § 43-02-03-14. Access to sites and records.

The commission, director, and their representatives shall have access to all records wherever
located. All owners, operators, drilling contractors, drillers, service companies, or other persons
engaged in drilling, completing, producing, operation, or servicing oil and gas wells, pipelines, injection
wells, stratigraphic test wells, subsurface observation wells, or treating plants shall permit the
commission, director, and their representatives to come upon any lease, property, pipeline right-of-way,
well, or drilling rig operated or controlled by them, complying with state safety rules, and to inspect the
records and operation, and to have access at all times to any and all records. If requested, copies of
such records must be filed with the commission. The confidentiality of any data submitted which is
confidential pursuant to subdivision f of subsection 1 of North Dakota Century Code section 38-08-04
and section 43-02-03-31 must be maintained.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; April 1, 2014;
October 1, 2016; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-14.1. Verification of certified welders.

Repealed effective July 1, 1996.
### § 43-02-03-14.2. Oil and gas metering systems.

1. Application of section. This section is applicable to all allocation and custody transfer
metering stations measuring production from oil and gas wells within the state of North
Dakota, including private, state, and federal wells. If these rules differ from federal
requirements on measurement of production from federal oil and gas wells, the federal rules
take precedence.
2. Definitions. As used in this section:
a. "Allocation meter" means a meter used by the producer to determine the volume from an
individual well before it is commingled with production from one or more other wells prior
to the custody transfer point.
b. "Calibration test" means the process or procedure of adjusting an instrument, such as a
gas meter, so its indication or registration is in satisfactorily close agreement with a
reference standard.
c. "Custody transfer meter" means a meter used to transfer oil or gas from the producer to
transporter or purchaser.
d. "Gas gathering meter" means a meter used in the custody transfer of gas into a
gathering system.
e. "Meter factor" means a number obtained by dividing the net volume of fluid (liquid or
gaseous) passed through the meter during proving by the net volume registered by the
meter.
f. "Metering proving" means the procedure required to determine the relationship between
the true volume of a fluid (liquid or gaseous) measured by a meter and the volume
indicated by the meter.
3. Inventory filing requirements. The owner of meter proving equipment shall file with the
director an inventory of all conventional pipe provers or master-meter provers used to test the

accuracy of oil meters. Inventories must be updated on an annual basis, and filed with the
director on or before the first day of each year, or they may be updated as frequently as
monthly, at the discretion of the operator. Inventories must include the following:
a. Meter information:
(1) Prover:
(a) Type.
(b) Serial number.
(c) Prover volume.
(d) Most recent water draw certificate.
(2) Master meter:
(a) Make and model.
(b) Size.
(c) Serial number.
(d) Master meter factor.
(e) Most recent meter proving certificate.
(3) An inventory of all meters used for custody transfer and allocation of production
from oil and gas wells, or both must be filed with the director upon request.
4. Installation and removal of meters. The director must be notified of all custody transfer
meters placed in service. The owner of the custody transfer equipment shall notify the director
of the date a meter is placed in service, the make and model of the meter, and the meter or
station number. The director must also be notified of all metering installations removed from
service. The notice must include the date the meter is removed from service, the serial
number, and the meter or station number. The required notices must be filed with the director
within thirty days of the installation or removal of a meter.
All allocation meters must be approved prior to installation and use. The application for
approval must be on a facility sundry notice and shall include the make and model number of
the meter, the meter or station number, the serial number, the well name, its location, and the
date the meter will be placed in service.
Meter installations for measuring production from oil or gas wells, or both, must be constructed
to American petroleum institute or American gas association standards or to meter
manufacturer's recommended installation. Meter installations constructed in accordance with
American petroleum institute or American gas association standards in effect at the time of
installation shall not automatically be required to retrofit if standards are revised. The director
will review any revised standards, and when deemed necessary will amend the requirements
accordingly.
5. Registration of persons proving or testing meters. All persons engaged in meter proving
or testing of oil and gas meters must be registered with the director. Those persons involved in
oil meter testing, by flowing fluid through the meter into a test tank and then gauging the tank,
are exempted from the registration process. However, such persons must notify the director
prior to commencement of the test to allow a representative of the director to witness the

testing process. A report of the results of such test shall be filed with the director within thirty
days after the test is completed. Registration must include the following:
a. Name and address of company.
b. Name and address of measurement personnel.
c. Qualifications, listing experience or specific training.
Any meter tests performed by a person not registered with the director will not be accepted as
a valid test.
6. Calibration requirements. Oil and gas metering equipment must be proved or tested to
American petroleum institute or American gas association standards or to the meter
manufacturer's recommended procedure to establish a meter factor or to ensure
measurement accuracy. The owner of a custody transfer meter or allocation meter shall notify
the director at least ten days prior to the testing of any meter.
a. Oil allocation meter factors shall be maintained within two percent of original meter factor.
If the factor change between provings or tests is greater than two percent, meter use
must be discontinued until successfully reproven after being repaired or replaced.
b. Oil custody transfer meter factors must be maintained within one-quarter of one percent
of the previous meter factor. If the factor change between provings or tests is greater
than one-quarter of one percent, meter use must be discontinued until successfully
reproven after being repaired or replaced.
c. Copies of all oil allocation meter test procedures are to be filed with and reviewed by the
director to ensure measurement accuracy.
d. All gas meters must be tested with a minimum of a three-point test for static and
differential pressure elements and a two-point test for temperature elements. The test
reports must include an as-found and as-left test and a detailed report of changes.
e. Test reports must include the following:
(1) Company name of test contractor.
(2) Pipeline company name.
(3) Meter owner name.
(4) Producer name.
(5) Well or central tank battery (CTB) name.
(6) Well file number or CTB number.
(7) Test personnel's name.
(8) Station or meter number.
f. Unless required more often by the director, minimum frequency of meter proving or
calibration tests are as follows:
(1) Oil meters used for custody transfer shall be proved monthly for all measured
volumes which exceed two thousand barrels per month. For volumes two thousand
barrels or less per month, meters shall be proved at each two thousand barrel
interval or more frequently at the discretion of the operator.

(2) Quarterly for oil meters used for allocation of production in a diverse ownership
central production facility. Semiannually for oil meters used for allocation of
production in a common ownership central production facility.
(3) Semiannually for gas meters used for allocation of production in a diverse
ownership central production facility. Annually for gas meters used for allocation of
production in a common ownership central production facility.
(4) Semiannually for gas meters in gas gathering systems.
(5) For meters measuring more than one hundred thousand cubic feet [2831.68 cubic
meters] per day on a monthly basis, orifice plates shall be inspected semiannually,
and meter tubes shall be inspected at least every five years to ensure continued
conformance with the American gas association meter tube specifications.
(6) For meters measuring one hundred thousand cubic feet [2831.68 cubic meters] per
day or less on a monthly basis, orifice plates shall be inspected annually.
g. Accuracy of all equipment used to test oil or gas meters must be traceable to the
standards of the national institute of standards and technology. The equipment must be
certified as accurate either by the manufacturer or an independent testing facility. The
certificates of accuracy for all equipment used to test gas meters must be made available
upon request. The owner of a conventional pipe prover or master meter prover shall
notify the director at least ten days prior to the testing of any prover. Certification of the
equipment must be updated as follows:
(1) Annually for all equipment used to test the pressure and differential pressure
elements.
(2) Annually for all equipment used to determine temperature.
(3) Biennially for all conventional pipe provers.
(4) Annually for all master meters.
(5) Five years for equipment used in orifice tube inspection.
h. All meter test reports, including failed meter test reports, must be filed within thirty days
of completion of proving or calibration tests unless otherwise approved. Test reports are
to be filed on, but not limited to, all meters used for allocation measurement of oil or gas,
all meters used in custody transfer, conventional pipe provers, and master meter provers.
7. Variances. Variances from all or part of this section may be granted by the director provided
the variance does not affect measurement accuracy. All requests for variances must be on a
facility sundry notice.
A register of variances requested and approved must be maintained by the director.
History: Effective May 1, 1994; amended effective July 1, 1996; September 1, 2000; July 1, 2002;
April 1, 2018; April 1, 2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-15. Bond and transfer of wells.

1. Bond requirements. Prior to commencing construction of a site or appurtenance or road
access thereto, any person who proposes to drill a well for oil, gas, injection, or source well for
use in enhanced recovery operations, shall submit to the director and obtain the approval of

the director, a surety bond or cash bond. An alternative form of security may be approved by
the commission after notice and hearing, as provided by law. The operator of such well shall
be the principal on the bond covering the well. Each surety bond shall be executed by a
responsible surety company authorized to transact business in North Dakota.
2. Bond amounts and limitations. The bond shall be in the amount of fifty thousand dollars
when applicable to one well only. Wells drilled to a total depth of less than two thousand feet
[609.6 meters] may be bonded in a lesser amount if approved by the director. When the
principal on the bond is drilling or operating a number of wells within the state or proposes to
do so, the principal may submit a bond conditioned as provided by law. Wells utilized for
commercial injection operations must be bonded in the amount of one hundred thousand
dollars. A blanket bond covering more than one well shall be in the amount of one hundred
thousand dollars, provided the bond shall be limited to no more than six of the following in
aggregate:
a. A well that is a dry hole and is not properly plugged;
b. A well that is plugged and the site is not properly reclaimed;
c. A well that is abandoned pursuant to subsection 1 of North Dakota Century Code section
reclaimed; and
d. A well that is temporarily abandoned under section 43-02-03-55 for more than seven
years.
If this aggregate of wells is reached, all well permits, for which drilling has not commenced,
held by the principal of such bond are suspended. No rights may be exercised under the
permits until the aggregate of wells drops below the required limit, or the operator files the
appropriate bond to cover the permits, at which time the rights given by the drilling permits are
reinstated. A well with an approved temporary abandoned status for no more than seven years
shall have the same status as an oil, gas, or injection well. The commission may, after notice
and hearing, require higher bond amounts than those referred to in this section. Such
additional amounts for bonds must be related to the economic value of the well or wells and
the expected cost of plugging and well site reclamation, as determined by the director. The
director may refuse to accept a bond or to add wells to a blanket bond if the operator or surety
company has failed in the past to comply with statutes, rules, or orders relating to the
operation of wells; if a civil or administrative action brought by the commission is pending
against the operator or surety company; or for other good cause.
3. Unit bond requirements. Prior to commencing unit operations, the operator of any area
under unitized management shall submit to the director and obtain the approval of the director,
a surety bond or cash bond. An alternative form of security may be approved by the
commission after notice and hearing, as provided by law. The operator of the unit shall be the
principal on the bond covering the unit. The amount of the bond shall be specified by the
commission in the order approving the plan of unitization. Each surety bond shall be executed
by a responsible surety company authorized to transact business in North Dakota.
Prior to transfer of a unit to a new operator, the commission, after notice and hearing, may
revise the bond amount for a unit, or in the case when the unit was not previously bonded, the
commission may require a bond and set a bond amount for the unit.
4. Bond terms. Bonds shall be conditioned upon full compliance with North Dakota Century
Code chapter 38-08, and all administrative rules and orders of the commission. It shall be a
plugging bond, as well as a drilling bond, and is to endure up to and including approved
plugging of all oil, gas, and injection wells as well as dry holes. Approved plugging shall also

include practical reclamation of the well site and appurtenances thereto. If the principal does
not satisfy the bond's conditions, then the surety shall satisfy the conditions or forfeit to the
commission the face value of the bond.
5. Transfer of wells under bond. Transfer of property does not release the bond. In case of
transfer of property or other interest in the well and the principal desires to be released from
the bond covering the well, such as producers, not ready for plugging, the principal must
proceed as follows:
a. The principal must notify the director, in writing, of all proposed transfers of wells at least
thirty days before the closing date of the transfer. The director may, for good cause,
waive this requirement.
(1) The principal shall submit a schematic drawing identifying all lines owned by the
principal which leave the constructed pad or facility and shall provide any details the
director deems necessary.
(2) The principal shall submit to the director a form 15 reciting that a certain well, or
wells, describing each well by quarter-quarter, section, township, and range, is to be
transferred to a certain transferee, naming such transferee, for the purpose of
ownership or operation. The date of assignment or transfer must be stated and the
form signed by a party duly authorized to sign on behalf of the principal.
(3) On said transfer form the transferee shall recite the following: "The transferee has
read the foregoing statement and does accept such transfer and does accept the
responsibility of such well under the transferee's one-well bond or, as the case may
be, does accept the responsibility of such wells under the transferee's blanket bond,
said bond being tendered to or on file with the commission." Such acceptance must
likewise be signed by a party authorized to sign on behalf of the transferee and the
transferee's surety.
b. When the director has passed upon the transfer and acceptance and accepted it under
the transferee's bond, the transferor shall be released from the responsibility of plugging
the well and site reclamation. If such wells include all the wells within the responsibility of
the transferor's bond, such bond will be released by the director upon written request.
Such request must be signed by an officer of the transferor or a person authorized to
sign for the transferor. The director may refuse to transfer any well from a bond if any well
on the bond is in violation of a statute, rule, or order. No abandoned well may be
transferred from a bond unless the transferee has obtained a single well bond in an
amount equal to the cost of plugging the well and reclaiming the well site.
c. The transferee (new operator) of any well shall be responsible for the plugging and site
reclamation of any such well and appurtenance thereto where the reclamation and
restoration of land and water resources impacted by oil and gas development is in an
inadequate reclamation status. For that purpose the transferee shall submit a new bond
or, in the case of a surety bond, produce the written consent of the surety of the original
or prior bond that the latter's responsibility shall continue and attach to such well. The
original or prior bond shall not be released as to the plugging and reclamation
responsibility of any such transferor until the transferee shall submit to the director an
acceptable bond to cover such well. All liability on bonds shall continue until the plugging
and site reclamation of such wells is completed and approved.
6. Treating plant bond. Prior to commencing site or road access construction, any person
proposing to operate a treating plant must submit to the director and obtain the approval of the
director, a surety bond or cash bond. An alternative form of security may be approved by the
commission after notice and hearing, as provided by law. The person responsible for the

operation of the plant shall be the principal on the bond. Each surety bond shall be executed
by a responsible surety company authorized to transact business in North Dakota. The
amount of the bond must be as prescribed in section 43-02-03-51.3. It is to remain in force
until the operations cease, all equipment is removed from the site, and the site and
appurtenances thereto are reclaimed, or liability of the bond is transferred to another bond that
provides the same degree of security. If the principal does not satisfy the bond's conditions,
then the surety shall satisfy the conditions or forfeit to the commission the face value of the
bond.
7. Saltwater handling facility bond. Prior to commencing site or road access construction, any
person proposing to operate a saltwater handling facility that is not already bonded as an
appurtenance shall submit to the director and obtain the approval of the director, a surety
bond or cash bond. An alternative form of security may be approved by the commission after
notice and hearing, as provided by law. The person responsible for the operation of the
saltwater handling facility must be the principal on the bond. Each surety bond must be
executed by a responsible surety company authorized to transact business in North Dakota.
The amount of the bond must be as prescribed in section 43-02-03-53.3. It is to remain in
force until the operations cease, all equipment is removed from the site, and the site and
appurtenances thereto are reclaimed, or liability of the bond is transferred to another bond that
provides the same degree of security. If the principal does not satisfy the bond's conditions,
the surety shall satisfy the conditions or forfeit to the commission the face value of the bond.
Transfer of property does not release the bond. The director may refuse to transfer any
saltwater handling facility from a bond if the saltwater handling facility is in violation of a
statute, rule, or order.
8. Crude oil and produced water underground gathering pipeline bond. The bonding
requirements for crude oil and produced water underground gathering pipelines are not to be
construed to be required on flow lines, injection pipelines, pipelines operated by an enhanced
recovery unit for enhanced recovery unit operations, or on piping utilized to connect wells,
tanks, treaters, flares, or other equipment on the production facility.
a. Any owner of an underground gathering pipeline transferring crude oil or produced water,
after April 19, 2015, shall submit to the director and obtain the approval of the director, a
surety bond or cash bond prior to July 1, 2017. Any owner of a proposed underground
gathering pipeline to transfer crude oil or produced water shall submit to the director and
obtain the approval of the director, a surety bond or cash bond prior to placing into
service. An alternative form of security may be approved by the commission after notice
and hearing, as provided by law. The person responsible for the operation of the crude oil
or produced water underground gathering pipeline must be the principal on the bond.
Each surety bond must be executed by a responsible surety company authorized to
transact business in North Dakota. The bond must be in the amount of fifty thousand
dollars when applicable to one crude oil or produced water underground gathering
pipeline system only. Such underground gathering pipelines that are less than one mile
[1609.34 meters] in length may be bonded in a lesser amount if approved by the director.
When the principal on the bond is operating multiple gathering pipeline systems within
the state or proposes to do so, the principal may submit a blanket bond conditioned as
provided by law. A blanket bond covering one or more underground gathering pipeline
systems must be in the amount of one hundred thousand dollars. The owner shall file
with the director, as prescribed by the director, a geographical information system layer
utilizing North American datum 83 geographic coordinate system and in an
environmental systems research institute shape file format showing the location of all
associated above ground equipment and the pipeline centerline from the point of origin to
the termination point of all underground gathering pipelines on the bond. Each layer must
include at least the following information:

(1) The name of the pipeline gathering system and other separately named portions
thereof;
(2) The type of fluid transported;
(3) The pipeline composition;
(4) Burial depth; and
(5) Approximate in-service date.
b. The blanket bond covering more than one underground gathering pipeline system is
limited to no more than six of the following instances of noncompliance in aggregate:
(1) Any portion of an underground gathering pipeline system that has been removed
from service for more than one year and is not properly abandoned pursuant to
section 43-02-03-29.1; and
(2) An underground gathering pipeline right-of-way, including associated above ground
equipment, which has not been properly reclaimed pursuant to section
43-02-03-29.1.
If this aggregate of underground gathering pipeline systems is reached, the director may
refuse to accept additional pipeline systems on the bond until the aggregate is brought
back into compliance. The commission, after notice and hearing, may require higher
bond amounts than those referred to in this section. Such additional amounts for bonds
must be related to the economic value of the underground gathering pipeline system and
the expected cost of pipeline abandonment and right-of-way reclamation, as determined
by the director. The director may refuse to accept a bond or to add underground
gathering pipeline systems to a blanket bond if the owner or surety company has failed in
the past to comply with statutes, rules, or orders relating to the operation of underground
gathering pipelines; if a civil or administrative action brought by the commission is
pending against the owner or surety company; if an underground gathering pipeline
system has exhibited multiple failures; or for other good cause.
c. The underground gathering pipeline bond is to remain in force until the pipeline has been
abandoned, as provided in section 43-02-03-29.1, and the right-of-way, including all
associated above ground equipment, has been reclaimed as provided in section
43-02-03-29.1, or liability of the bond is transferred to another bond that provides the
same degree of security. If the principal does not satisfy the bond's conditions, the surety
shall satisfy the conditions or forfeit to the commission the face value of the bond.
d. Transfer of underground gathering pipelines under bond. Transfer of property does not
release the bond. In case of transfer of property or other interest in the underground
gathering pipeline and the principal desires to be released from the bond covering the
underground gathering pipeline, the principal must proceed as follows:
(1) The principal shall notify the director, in writing, of all proposed transfers of
underground gathering pipelines at least thirty days before the closing date of the
transfer. The director, for good cause, may waive this requirement.
Notice of underground gathering pipeline transfer. The principal shall submit, as
provided by the director, a geographical information system layer utilizing North
American datum 83 geographic coordinate system and in an environmental systems
research institute shape file format showing the location of all associated above
ground equipment and the pipeline centerline from the point of origin to the
termination point of all underground gathering pipelines to be transferred to a certain

transferee, naming such transferee, for the purpose of ownership or operation. The
date of assignment or transfer must be stated and the form 15pl signed by a party
duly authorized to sign on behalf of the principal.
The notice of underground gathering pipeline transfer must recite the following: "The
transferee has read the foregoing statement and does accept such transfer and
does accept the responsibility of such underground gathering pipelines under the
transferee's pipeline bond or, as the case may be, does accept the responsibility of
such underground gathering pipelines under the transferee's pipeline systems
blanket bond, said bond being tendered to or on file with the commission." Such
acceptance must likewise be signed by a party authorized to sign on behalf of the
transferee and the transferee's surety.
(2) When the director has passed upon the transfer and acceptance and accepted it
under the transferee's bond, the transferor must be released from the responsibility
of abandoning the underground gathering pipelines and right-of-way reclamation. If
such underground gathering pipelines include all underground gathering pipeline
systems within the responsibility of the transferor's bond, such bond will be released
by the director upon written request. Such request must be signed by an officer of
the transferor or a person authorized to sign for the transferor. The director may
refuse to transfer any underground gathering pipeline from a bond if the
underground gathering pipeline is in violation of a statute, rule, or order.
(3) The transferee (new owner) of any underground gathering pipeline is responsible for
the abandonment and right-of-way reclamation of any such underground gathering
pipeline. For that purpose the transferee shall submit a new bond or, in the case of a
surety bond, produce the written consent of the surety of the original or prior bond
that the latter's responsibility shall continue and attach to such underground
gathering pipeline. The original or prior bond may not be released as to the
abandonment and right-of-way reclamation responsibility of any such transferor until
the transferee submits to the director an acceptable bond to cover such
underground gathering pipeline. All liability on bonds continues until the
abandonment and right-of-way reclamation of such underground gathering pipeline
is completed and approved by the director.
9. Geological storage facility bond requirements. Before commencing injection operations,
the operator of any storage facility shall submit to the director and obtain the approval of the
director, a surety bond or cash bond in the amount specified by the commission in the order
approving the storage facility. An alternative form of security may be approved by the
commission after notice and hearing, as provided by law. The operator of the storage facility
shall be the principal on the bond covering the storage facility. Each surety bond must be
executed by a responsible surety company authorized to transact business in North Dakota.
10. Enhanced oil recovery potential well bond. Before the director may approve a nonunit well
for enhanced oil recovery potential status, the operator shall submit to the director and obtain
the approval of the director for, a blanket surety bond or cash bond in the amount of one
hundred thousand dollars, provided the bond shall be limited to no more than six wells that
have been inactive for more than twelve years. Wells within an approved enhanced recovery
unit approved for enhanced oil recovery potential status may remain on the unit bond at the
discretion of the director. An alternative form of security may be approved by the commission
after notice and hearing, as provided by law. The operator of such well shall be the principal
on the bond covering the well. Each surety bond must be executed by a responsible surety
company authorized to transact business in North Dakota. Each such bond may be subject to
an annual review to determine if the bond amount is sufficient and the commission may, after
notice and hearing, require a higher bond amount. Such additional amounts for bonds must be

related to the economic value of the well or wells and the expected cost of plugging and well
site reclamation, as determined by the director. The director may refuse to accept a bond or to
add wells to an enhanced oil recovery potential blanket bond if the operator or surety
company has failed in the past to comply with statutes, rules, or orders relating to the
operation of wells; if a civil or administrative action brought by the commission is pending
against the operator or surety company; or for other good cause.
11. Bond termination. The director shall, in writing, advise the principal and any sureties on any
bond as to whether the plugging and reclamation is approved. If approved, liability under such
bond may be formally terminated upon receipt of a written request by the principal. The
request must be signed by an officer of the principal or a person authorized to sign for the
principal.
12. Director's authority. The director is vested with the power to act for the commission as to all
matters within this section, except requests for alternative forms of security, which may only be
approved by the commission.
History: Amended effective April 30, 1981; March 1, 1982; January 1, 1983; May 1, 1990; May 1, 1992;
May 1, 1994; July 1, 1996; December 1, 1996; September 1, 2000; July 1, 2002; May 1, 2004;
January 1, 2006; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022;
April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-16. Application for permit to drill and recomplete.

Before any person shall begin any well-site preparation for the drilling of any well other than
surveying and staking, such person shall obtain approval from the director. An application for permit to
drill must be filed with the director, together with a permit fee of one hundred dollars. Site construction,
or appurtenance or road access thereto, may not commence until such application is approved and a
permit to drill is issued by the director. Verbal approval may be given for site preparation by the director
in extenuating circumstances to include contractual obligations, an expiring lease, or an expiring right-
of-way.The application must be accompanied by the bond pursuant to section 43-02-03-15 or the
applicant must have previously filed such bond with the director, otherwise the application is
incomplete. An incomplete application received by the director has no standing and will not be deemed
filed until it is completed.
The application for permit to drill shall be accompanied by an accurate plat certified by a registered
surveyor showing the location of the proposed well with reference to true north and the nearest lines of
a governmental section, the latitude and longitude of the proposed well location to the nearest tenth of
a second, the ground elevation, and the proposed road access to the nearest existing public road.
Information to be included in such application shall be the proposed depth to which the well will be
drilled, estimated depth to the top of important markers, estimated depth to the top of objective
horizons, the proposed mud program, the proposed casing program, including size and weight thereof,
the depth at which each casing string is to be set, the proposed pad layout, including cut and fill
diagrams, and the proposed amount of cement to be used, including the estimated top of cement.
For wells permitted on new pads built after July 31, 2013, permit conditions imposed by the director
may include, upon request of the owner of a permanently occupied dwelling within one thousand feet of
the proposed well, requiring the location of all flares, tanks, and treaters utilized in connection with the
permitted well be located at a greater distance from the occupied dwelling than the well head, if the
location can be reasonably accommodated within the proposed pad location. If the facilities are
proposed to be located farther from the dwelling than the well bore, the director can issue the permit
without comment from the dwelling owner. The applicant shall give any such owners written notice of
the proposed facilities personally or by certified mail, return receipt requested, and addressed to their
last-known address listed with the county property tax department. The director must receive written

comments from such owner within five business days of the owner receiving said notice. An application
for permit must include an affidavit from the applicant identifying each owner's name and address, and
the date written notice was given to each owner. The owner's notice must include:
1. A copy of North Dakota Century Code section 38-08-05.
2. The name, telephone number, and if available the electronic mail address of the applicant's
local representative.
3. A sketch of the area indicating the location of the owner's dwelling, the proposed well, and
location of the proposed flare, tanks, and treaters.
4. A statement indicating that any such owner objecting to the location of the flare, tanks, or
treaters, must notify the director within five business days of receiving the notice.
Prior to the commencement of recompletion operations or drilling horizontally in the existing pool,
an application for permit must be approved by the director. Such application shall be filed to reenter a
well by drilling horizontally, deepening, or plugging back to any source of supply other than the
producing horizon in an existing well. Such notice shall include the name and file number and exact
location of the well, the approximate date operations will begin, the proposed procedure, the estimated
completed total depth, the anticipated hydrogen sulfide content in produced gas from the proposed
source of supply, the weight and grade of all casing currently installed in the well unless waived by the
director, the casing program to be followed, and the original total depth with a permit fee of fifty dollars.
The director may deny any application if it is determined, in accordance with the latest version of
ANSI/NACE MR0175/ISO 15156, that the casing currently installed in the well would be subject to
sulfide stress cracking.
The applicant shall provide all information, in addition to that specifically required by this section, if
requested by the director. The director may impose such terms and conditions on the permits issued
under this section as the director deems necessary.
The director shall deny an application for a permit under this section if the proposal would cause, or
tend to cause, waste or violate correlative rights. The director of oil and gas shall state in writing to the
applicant the reason for the denial of the permit. The applicant may appeal the decision of the director
to the commission.
A permit to drill automatically expires one year after the date it was issued, unless the well is drilling
or has been drilled below surface casing. A permit to recomplete or to drill horizontally automatically
expires one year after the date it was issued, unless such project has commenced. The director may
extend a permit to drill and a permit to recomplete or drill horizontally for up to one year upon request.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; September 1,
2000; July 1, 2002; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2020; April 1,
2024.
General Authority: NDCC 38-08-05
Law Implemented: NDCC 38-08-05
### § 43-02-03-16.1. Designation and responsibilities of operator.

The principal on the bond covering a well, treating plant, or facility is the operator. The operator is
responsible for compliance with all applicable laws. A dispute over designation of the operator may be
addressed by the commission. In doing so, the factors the commission may consider include those set
forth in subsection 1 of section 43-02-03-16.2.
History: Effective December 1, 1996; amended effective April 1, 2014; April 1, 2022.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04

### § 43-02-03-16.2. Revocation and limitation of drilling permits.

1. After notice and hearing, the commission may revoke a drilling, recompletion, or reentry permit
or limit its duration. The commission may act upon its own motion or upon the application of
an owner in the spacing or drilling unit. In deciding whether to revoke or limit a permit, the
factors that the commission may consider include:
a. The technical ability of the permitholder and other owners to drill and complete the well.
b. The experience of the permitholder and other owners in drilling and completing similar
wells.
c. The number of wells in the area operated by the permitholder and other owners.
d. Whether drainage of the spacing or drilling unit has occurred or is likely to occur in the
immediate future and whether the permitholder has committed to drill a well in a timely
fashion.
e. Contractual obligations such as an expiring lease.
f. The amount of ownership the permitholder and other owners hold in the spacing or
drilling unit. If the permitholder is the majority owner in the unit or if its interest when
combined with that of its supporters is a majority of the ownership, it is presumed that the
permitholder should retain the permit. This presumption, even if not rebutted, does not
prohibit the commission from limiting the duration of the permit. However, if the amount of
the interest owned by the owner seeking revocation or limitation and its supporters are a
majority of the ownership, the commission will presume that the permit should be
revoked.
2. The commission may suspend a permit that is the subject of a revocation or limitation
proceeding, although a permit will not be suspended after operations have commenced.
3. If the commission revokes a permit upon the application of an owner and issues a permit to
that owner or to another owner who supported revocation, the commission may limit the
duration of such permit. The commission may also, if the parties fail to agree, order the owner
acquiring the permit to pay reasonable costs incurred by the former permitholder and the
conditions under which payment is to be made. The costs for which reimbursement may be
ordered may include those involving survey of the well site, title search of surface and mineral
title, and preparation of an opinion of mineral ownership.
4. If the commission declines to revoke a permit or limit the time within which it must be
exercised, it may include a term in its order restricting the ability of the permitholder to renew
the permit or to acquire another permit within the same spacing or drilling unit.
History: Effective December 1, 1996; amended effective January 1, 2006; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-16.3. Recovery of a risk penalty.

The following govern the recovery of the risk penalty pursuant to subsection 3 of North Dakota
Century Code section 38-08-08 and subsection 3 of North Dakota Century Code section 38-08-09.4:
1. An owner may recover the risk penalty under the provisions of subsection 3 of North Dakota
Century Code section 38-08-08, provided the owner gives, to the owner from whom the
penalty is sought, a written invitation to participate in the risk and cost of drilling a well,
including reentering a plugged and abandoned well, or the risk and cost of reentering an

existing well to drill deeper or a horizontal lateral. If the nonparticipating owner's interest is not
subject to a lease or other contract for development, an owner seeking to recover a risk
penalty must also make a good-faith attempt to have the unleased owner execute a lease.
a. The invitation to participate in drilling must be in writing and contain the following:
(1) The approximate surface location of the proposed or existing well, proposed
completion and total depth, objective zone, and completion location if other than a
vertical well.
(2) An itemization of the estimated costs of drilling and completion.
(3) The approximate date upon which the well was or will be spudded or reentered.
(4) A written election to participate and a statement indicating the invitation or election
must be accepted within thirty days of receiving it. Such election to participate must
be received by the owner giving the invitation within thirty days of the participating
party's receipt.
(5) Notice that the participating owners plan to impose a risk penalty and that the
nonparticipating owner may object to the risk penalty by either responding in
opposition to the petition for a risk penalty, or if no such petition has been filed, by
filing an application or request for hearing with the commission.
(6) Drilling or spacing unit description.
b. An invitation to participate and an election to participate must be served personally, by
mail requiring a signed receipt, or by overnight courier or delivery service requiring a
signed receipt. Failure to accept mail requiring a signed receipt constitutes service.
c. An election to participate is only binding upon an owner electing or declining to
participate if the well is spudded or reentry operations are commenced on or before
ninety days after the date the owner extending the invitation to participate sets as the
date upon which an election response to the invitation is to be received. It also expires if
the permit to drill or reenter expires without having been exercised. If an election to
participate lapses, a risk penalty can only be collected if the owner seeking it again
complies with the provisions of this section.
2. An owner may recover the risk penalty under the provisions of subsection 3 of North Dakota
Century Code section 38-08-09.4, provided the owner gives, to the owner from whom the
penalty is sought, a written invitation to participate in the unit expense. If the nonparticipating
owner's interest is not subject to a lease or other contract for development, an owner seeking
to recover a risk penalty must also make a good-faith attempt to have the unleased owner
execute a lease.
a. The invitation to participate in the unit expense must be in writing and contain the
following:
(1) A description of the proposed unit expense, including the location, objectives, and
plan of operation.
(2) An itemization of the estimated costs.
(3) The approximate date upon which the proposal was or will be commenced.
(4) A written election to participate and a statement indicating the invitation or election
must be accepted within thirty days of receiving it. Such election to participate must

be received by the owner giving the invitation within thirty days of the participating
party's receipt.
(5) Notice that the participating owners plan to impose a risk penalty and that the
nonparticipating owner may object to the risk penalty by either responding in
opposition to the petition for a risk penalty, or if no such petition has been filed, by
filing an application or request for hearing with the commission.
b. An invitation to participate and an election to participate must be served personally, by
mail requiring a signed receipt, or by overnight courier or delivery service requiring a
signed receipt. Failure to accept mail requiring a signed receipt constitutes service.
c. An election to participate is only binding upon an owner electing or declining to
participate if the unit expense is commenced within ninety days after the date the owner
extending the invitation request to participate sets as the date upon which an election
response to the request invitation is to be received. If an election to participate lapses, a
risk penalty can only be collected if the owner seeking it again complies with the
provisions of this section.
d. An invitation to participate in a unit expense covering monthly operating expenses shall
be effective for all such monthly operating expenses for a period of five years if the unit
expense identified in the invitation to participate is first commenced within ninety days
after the date set in the invitation to participate as the date upon which an election
response to the invitation to participate must be received. An election to participate in a
unit expense covering monthly operating expenses is effective for five years after
operations are first commenced. If an election to participate in a unit expense comprised
of monthly operating expenses expires or lapses after five years, a risk penalty may only
be assessed and collected if the owner seeking the penalty once again complies with this
section.
3. Upon its own motion or the request of a party, the commission may include in a pooling order
requirements relating to the invitation to participate and election to participate, in which case
the pooling order will control to the extent it is inconsistent with this section.
History: Effective December 1, 1996; amended effective May 1, 2004; January 1, 2006; January 1,
2008; April 1, 2010; April 1, 2012; April 1, 2014; April 1, 2020; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04, 38-08-08
### § 43-02-03-17. Sign on well and facility.

Every well and facility associated with the production, transportation, purchasing, storage, treating,
or processing of oil, gas, and water except plugged wells shall be identified by a sign. The sign shall be
of durable construction and the lettering thereon shall be kept in a legible condition. The wells on each
lease or property shall be numbered in nonrepetitive sequence, unless some other system of
numbering was adopted by the owner prior to the adoption of this chapter. Each sign must show the
facility name or well name and number (which shall be different or distinctive for each well or facility),
the name of the operator, current emergency phone number, file or facility number (if applicable), and
the location by quarter-quarter, section, township, and range.
History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000; April 1, 2014;
October 1, 2016; April 1, 2018; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04

### § 43-02-03-18. Drilling units - Well locations.

In the absence of an order by the commission setting spacing units for a pool:
1. a. Vertical or directional oil wells projected to a depth not deeper than the Mission Canyon
formation must be drilled upon a governmental quarter-quarter section or equivalent lot,
located not less than five hundred feet [152.4 meters] to the boundary of such
governmental quarter-quarter section or equivalent lot. No more than one well shall be
drilled to the same pool on any such governmental quarter-quarter section or equivalent
lot, except by order of the commission, nor shall any well be drilled on any such
governmental quarter-quarter section or equivalent lot containing less than thirty-six
acres [14.57 hectares] except by order of the commission.
b. Vertical or directional oil wells projected to a depth deeper than the Mission Canyon
formation must be drilled on a governmental quarter section or equivalent lots, located
not less than six hundred sixty feet [201.17 meters] to the boundary of such
governmental quarter section or equivalent lots. No more than one well shall be drilled to
the same pool on any such governmental quarter section or equivalent lots, except by
order of the commission, nor shall any well be drilled on any such governmental quarter
section or equivalent lots containing less than one hundred forty-five acres [58.68
hectares] except by order of the commission.
2. a. Horizontal wells with a horizontal displacement of the well bore drilled at an angle of at
least eighty degrees within the productive formation of at least five hundred feet [152.4
meters], projected to a depth not deeper than the Mission Canyon formation, must be
drilled upon a drilling unit described as a governmental section or described as two
adjacent governmental quarter sections within the same section or equivalent lots,
located not less than five hundred feet [152.4 meters] to the outside boundary of such
tract. The horizontal well proposed to be drilled must, in the director's opinion, justify the
creation of such drilling unit. No more than one well may be drilled to the same pool on
any such tract, except by order of the commission.
b. Horizontal wells with a horizontal displacement of the well bore drilled at an angle of at
least eighty degrees within the productive formation of at least five hundred feet [152.4
meters], projected to a depth deeper than the Mission Canyon formation, must be drilled
upon a drilling unit described as a governmental section, located not less than five
hundred feet [152.4 meters] to the outside boundary of such tract. The horizontal well
proposed to be drilled must, in the director's opinion, justify the creation of such drilling
unit. No more than one well may be drilled to the same pool on any such tract, except by
order of the commission.
3. a. Gas wells projected to a depth not deeper than the Mission Canyon formation shall be
drilled upon a governmental quarter section or equivalent lots, located not less than five
hundred feet [152.4 meters] to the boundary of such governmental quarter section or
equivalent lots. No more than one well shall be drilled to the same pool on any such
governmental quarter section or equivalent lots, except by order of the commission, nor
shall any well be drilled on any such governmental quarter section or equivalent lot
containing less than one hundred forty-five acres [58.68 hectares] except by order of the
commission.
b. Gas wells projected to a depth deeper than the Mission Canyon formation shall be drilled
upon a governmental quarter section or equivalent lots, located not less than six hundred
sixty feet [201.17 meters] to the boundary of such governmental quarter section or
equivalent lots. No more than one well shall be drilled to the same pool on any such
governmental quarter section or equivalent lots, except by order of the commission, nor
shall any well be drilled on any such governmental quarter section or equivalent lot

containing less than one hundred forty-five acres [58.68 hectares] except by order of the
commission.
4. Within thirty days, or a reasonable time thereafter, following the discovery of oil or gas in a
pool not then covered by an order of the commission, a spacing hearing shall be docketed.
Following such hearing the commission shall issue an order prescribing a temporary spacing
pattern for the development of the pool. This order shall continue in force for a period of not
more than three years at the expiration of which time a hearing shall be held at which the
commission may require the presentation of such evidence as will enable the commission to
determine the proper spacing for the pool.
During the interim period between the discovery and the issuance of the temporary order, no
permits shall be issued for the drilling of an offset well to the discovery well, unless approved
by the director. Approval shall be consistent with anticipated spacing for the orderly
development of the pool.
Any well drilled within one mile [1.61 kilometers] of an established field shall conform to the
spacing requirements in that field except when it is apparent that the well will not produce from
the same common source of supply. In order to assure uniform and orderly development, any
well drilled within one mile [1.61 kilometers] of an established field boundary shall conform to
the spacing and special field rules for the field, and for the purposes of spacing and pooling,
the field boundary shall be extended to include the spacing unit for such well and any
intervening lands. The foregoing shall not be applicable if it is apparent that the well will not
produce from the same common source of supply as wells within the field.
5. If the director denies an application for permit, the director shall advise the applicant
immediately of the reasons for denial. The decision of the director may be appealed to the
commission.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; July 1, 1996;
July 1, 2002; January 1, 2006; April 1, 2010; April 1, 2012.
General Authority: NDCC 38-08-04, 38-08-07
Law Implemented: NDCC 38-08-04, 38-08-07
### § 43-02-03-18.1. Exception location.

If upon application for an exception location, the commission finds that a well drilled at the location
prescribed by any applicable rule or order of the commission would not produce in paying quantities,
that surface conditions would substantially add to the burden or hazard of such well, or that the drilling
of such well at a location other than the prescribed location is otherwise necessary either to protect
correlative rights, to prevent waste, or to effect greater ultimate recovery from oil and gas, the
commission may enter an order, after notice and hearing, permitting the well to be drilled at a location
other than that prescribed and shall include in such order suitable provisions to prevent the production
from that well of more than its just and equitable share of the oil and gas in the pool. The application for
an exception well location shall set forth the names of the lessees of adjoining properties and the
names of any unleased mineral owners of the adjoining properties. The application shall be
accompanied by a plat or sketch accurately showing the property for which the exception well location
is sought, the location of the proposed well, and all other completed and drilling wells on this property
and on the adjoining properties. The applicant or its attorney shall certify that a copy of the application
has been sent to all lessees and all unleased mineral owners of properties adjoining the tract which
would be affected by the exception location. If the applicant is the lessee of adjoining tracts that would
be affected by the exception, the applicant must give notice, as prescribed above, to its lessors of such
tracts.
History: Effective January 1, 1983; amended effective May 1, 1990; May 1, 1994; July 1, 1996;
January 1, 2008.

General Authority: NDCC 38-08-04, 38-08-07
Law Implemented: NDCC 38-08-04, 38-08-07
### § 43-02-03-19. Site construction.

In the construction of a well site, saltwater handling facility, treating plant, access road, and all
associated facilities, the topsoil shall be removed, stockpiled, and stabilized or otherwise reserved for
use when the area is reclaimed. "Topsoil" means the suitable plant growth material on the surface;
however, in no event shall this be deemed to be more than the top twelve inches [30.48 centimeters] of
soil or deeper than the depth of cultivation, whichever is greater. Soil stabilization materials, liners,
fabrics, and other materials to be used onsite, on access roads or associated facilities, must be
reported on a sundry notice (form 4) to the director within thirty days after application. The reclamation
plan for such materials shall also be included.
When necessary to prevent pollution of the land surface and freshwaters, the director may require
the site to be sloped and diked.
Sites shall not be located in, or hazardously near, bodies of water, nor shall they block natural
drainages. Sites and associated facilities shall be designed to divert surface drainage from entering the
site.
Sites or appropriate parts thereof shall be fenced if required by the director.
Within six months after the completion of a well or construction of a saltwater handling facility or
treating plant, the portion of the site not used for operations shall be reclaimed, unless waived by the
director. Operators shall file a sundry notice (form 4) detailing the work that was performed and a
current site diagram, which identifies the stockpiled topsoil location and its volume. Sites shall be
stabilized to prevent erosion.
History: Amended effective March 1, 1982; January 1, 1983; May 1, 1992; July 1, 2002; January 1,
2008; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-19.1. Fencing, screening, and netting of drilling and reserve pits.

All open pits and ponds which contain saltwater must be fenced. All pits and ponds which contain
oil must be fenced, screened, and netted.
This is not to be construed as requiring the fencing, screening, or netting of a drilling pit or reserve
pit used solely for drilling, completing, recompleting, or plugging unless such pit is not reclaimed within
ninety days after completion of drilling operations.
History: Effective May 1, 1992; amended effective April 1, 2012.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-19.2. Disposal of waste material.

All waste material associated with exploration or production of oil and gas must be properly
disposed of in an authorized facility in accordance with all applicable local, state, and federal laws and
regulations.
All waste material recovered from spills, leaks, and other such events shall immediately be
disposed of in an authorized facility, although the remediation of such material may be allowed onsite if
approved by the director.

This is not to be construed as requiring the offsite disposal of drilling mud from shallow wells or drill
cuttings associated with the drilling of a well. However, water remaining in a drilling or reserve pit used
in the drilling and completion operations is to be removed from the pit and disposed of in an authorized
disposal well or used in a manner approved by the director. The disposition or use of the water must be
included on the sundry notice (form 4) reporting the plan of reclamation pursuant to sections
History: Effective May 1, 1992; amended effective May 1, 1994; September 1, 2000; April 1, 2012.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-19.3. Earthen pits and receptacles.

Except as otherwise provided in this section and sections 43-02-03-19.4, 43-02-03-19.5, and
43-02-03-51.3, no saltwater, drilling mud, crude oil, waste oil, or other waste may be stored in earthen
pits or open receptacles except in an emergency and upon approval by the director.
A lined earthen pit or open receptacle may be temporarily used to retain oil, water, cement, solids,
or fluids generated in well plugging operations. A pit or receptacle used for this purpose must be
sufficiently impermeable to provide adequate temporary containment of the oil, water, or fluids. The
contents of the pit or receptacle must be removed within seventy-two hours after operations have
ceased and must be disposed of at an authorized facility in accordance with section 43-02-03-19.2.
Within thirty days after operations have ceased, the earthen pit shall be reclaimed and the open
receptacle shall be removed. The director may grant an extension of the thirty-day time period to no
more than one year for good reason.
The director may permit pits or receptacles used solely for the purpose of flaring casinghead gas. A
pit or receptacle used for this purpose must be sufficiently impermeable to provide adequate temporary
containment of fluids. Permission for such pit or receptacle must be conditioned on locating the pit not
less than one hundred fifty feet [45.72 meters] from the vicinity of wells and tanks and keeping it free of
any saltwater, crude oil, waste oil, or other waste. Saltwater, drilling mud, crude oil, waste oil, or other
waste must be removed from the pit or receptacle within twenty-four hours after being discovered and
must be disposed of at an authorized facility in accordance with section 43-02-03-19.2.
The director may permit pits used solely for storage of freshwater used in completion and well
servicing operations. Permit applications for freshwater pits must be submitted on a sundry notice and
must be valid for a period of one year but may be reauthorized upon application. Freshwater pits must
be lined and no pit constructed for this purpose may be wholly or partially constructed in fill dirt unless
approved by the director. The director may approve chemical treatment to municipal drinking water
standards upon application.
The freshwater pit must have signage on all sides accessible to vehicular traffic clearly identifying
the usage as freshwater only.
The director may permit portable-collapsible receptacles used solely for storage of fluids used in
completion and well servicing operations, although no flowback fluids may be allowed. Permit
applications for such receptacles must be submitted on a sundry notice and must be valid for a period
of one year but may be reauthorized upon application. Such receptacles must utilize a sealed inner
bladder, erected to conform to American petroleum institute standards, and may not be wholly or
partially constructed on fill dirt unless approved by the director. Such receptacles must have signage on
all sides accessible to vehicular traffic clearly identifying the fluid contained within.
The director may permit portable-collapsible single sidewall, double liner open top receptacles used
solely for storage of fluids used in completion and well servicing operations, although no flowback fluids
may be allowed. Such receptacles must have signage on all sides accessible to vehicular traffic clearly
identifying the fluid contained within. Permits for such receptacles must be submitted on a sundry

notice and must be valid for a period of one year but may be reauthorized upon application. Permits for
such receptacles must include at least the following information:
1. The name and address of the operator.
2. Legal location of the site where the open top receptacle will be located.
3. Structural engineering analysis of the open top receptacle including panels and connection
system.
4. Schematic drawings depicting the following:
a. As-built or proposed cut and fill diagram showing how the open top receptacle will be
located in a cut area of the site.
b. The site that includes its dimensions or proposed dimensions and the height, location,
and calculated capacity of the perimeter berm and any other spill containment structures.
c. Fill pipe or filling mechanism designed to protect the liner system from the initial force of
water entering the open top receptacle.
d. Isolation valves in the produced water and freshwater flow lines.
e. Location of the concrete jersey barriers around the open top receptacle to avert vehicular
traffic and impede the flow of water in the event of a breach.
5. Descriptions of the following:
a. The double liner system including liner specifications.
b. Sand pad and geotextile liner used to protect the liner system.
c. Real-time leak detection and monitoring system, including between the liners and visual
inspections.
d. Overfill and low-level detection systems.
e. Mechanical integrity testing plan using freshwater of the system.
f. Emergency plan for emptying the open top receptacle and addressing resources on
standby in the event of a breach.
g. Estimated setup and deconstruction dates.
The director may docket the permit application for hearing to gather additional information
necessary to evaluate the proposed open top receptacle and site.
Permits may contain such terms and conditions as the director deems necessary.
Any permit issued under this section may be revoked by the commission after notice and hearing if
the permittee fails to comply with the terms and conditions of the permit, any directive of the director, or
any applicable rule or statute.
Any permit issued under this section may be modified or suspended by the director for good cause.
Permits are transferable only with approval of the director.
History: Effective September 1, 2000; amended effective April 1, 2010; April 1, 2012; October 1, 2016;
April 1, 2020; April 1, 2024.

General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-19.4. Drilling pits.

A pit may be utilized to bury drill cuttings and solids generated during well drilling and completion
operations, providing the pit can be constructed, used, and reclaimed in a manner that will prevent
pollution of the land surface and freshwaters. In special circumstances, the director may prohibit
construction of a cuttings pit or may impose more stringent pit construction and reclamation
requirements. Reserve and circulation of mud system through earthen pits are prohibited unless a
waiver is granted by the director. All pits shall be inspected by an authorized representative of the
director prior to lining and use. Under no circumstances shall pits be used for disposal, dumping, or
storage of fluids, wastes, and debris other than drill cuttings and solids recovered while drilling and
completing the well.
Drill cuttings and solids must be stabilized in a manner approved by the director prior to placement
in a cuttings pit. Any liquid accumulating in the cuttings pit shall be promptly removed. The pit shall be
diked in a manner to prevent surface water from running into the pit.
A small lined pit can be authorized by the director for temporary containment of incidental fluids
such as trench water and rig wash, if emptied and covered prior to the rig leaving the site.
Pits shall not be located in, or hazardously near, bodies of water, nor shall they block natural
drainages. No pit shall be wholly or partially constructed in fill dirt unless approved by the director.
When required by the director, the drilling pit or appropriate parts thereof shall be fenced.
Within thirty days after the drilling of a well or expiration of a drilling permit, drilling pits shall be
reclaimed. The director may grant an extension of the thirty-day time period to no more than one year
for good reason. Prior to reclaiming the pit, the operator or the operator's agent shall obtain verbal
approval from the director of a pit reclamation plan.
A subsequent sundry notice (form 4) shall be filed detailing the pit reclamation and shall include:
1. The name and address of the reclamation contractor;
2. The name and address of the surface owner; and
3. A description of the work completed, including details on treatment and disposition of the
drilling waste.
Any water or oil accumulated on the pit must be removed prior to reclamation. Drilling waste shall
be encapsulated in the pit and covered with at least four feet [1.22 meters] of backfill and topsoil and
surface sloped, when practicable, to promote surface drainage away from the reclaimed pit area.
History: Effective April 1, 2012; amended effective April 1, 2014.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-19.5. Reserve pit for drilling mud and drill cuttings from shallow wells.

For wells drilled to a strata or formation, including lignite or coal strata or seam, located above the
depth of five thousand feet [1524 meters] below the surface, or located more than five thousand feet
[1524 meters] below the surface but above the top of the Rierdon formation, a container or reserve pit
of sufficient size to contain said material or fluid, and the accumulation of drill cuttings may be utilized to
contain solids and fluids used and generated during well drilling and completion operations, providing
the pit can be constructed, used and reclaimed in a manner that will prevent pollution of the land

surface and freshwaters. A reserve pit may be allowed by an order of the commission after notice and
hearing, provided the reserve pit can be constructed, used, and reclaimed in a manner that will prevent
pollution of the land surface and freshwaters, for (a) wells drilled within a specified field and pool more
than five thousand feet [1524 meters] below the surface and below the top of the Rierdon formation
provided the proposed well or wells utilized a low sodium content water-based mud system or (b) for
wells drilled and completed, outside an established field which has defined the pool to include the
Bakken or Three Forks formation, when separate reserve pits will be utilized to segregate each mud
system and associated drill cuttings and any oil skim accumulated on any reserve pit utilized for a
water-based mud system will be removed immediately after completion of drilling operations so as not
to cause any significant delay in the reclamation of the reserve pit. In special circumstances, based on
site-specific conditions, the director or authorized representative may prohibit construction of a reserve
pit or may impose more stringent pit construction and reclamation requirements, including reserve pits
previously authorized by a commission order within a specified field and pool. Under no circumstances
shall reserve pits be used for disposal, dumping, or storage of fluids, wastes, and debris other than drill
cuttings and fluids used or recovered while drilling and completing the well.
Reserve pits shall not be located in, or hazardously near, bodies of water, nor shall they block
natural drainages. No reserve pit shall be wholly or partially constructed in fill dirt unless approved by
the director.
Within a reasonable time, but not more than one year after the completion of a shallow well, or prior
to drilling below the surface casing shoe on any other well, the reserve pit shall be reclaimed. Prior to
reclaiming the pit, the operator or the operator's agent shall file a sundry notice (form 4) with the
director and obtain approval of a pit reclamation plan. Verbal approval to reclaim the pit may be given.
The notice shall include:
1. The name and address of the reclamation contractor;
2. The name and address of the surface owner;
3. The location and name of the disposal site for the pit water; and
4. A description of the proposed work, including details on treatment and disposition of the
drilling waste.
All pit water must be removed prior to reclamation. Drilling waste should be encapsulated in the pit and
covered with at least four feet [1.22 meters] of backfill and topsoil and surface sloped, when
practicable, to promote surface drainage away from the reclaimed pit area.
History: Effective April 1, 2012; amended effective April 1, 2014.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-20. Sealing off strata.

During the drilling of any well, all oil, gas, and water strata must be sealed or separated where
necessary in order to prevent their contents from passing into other strata.
All freshwaters and waters of present or probable value for domestic, commercial, or stock
purposes must be confined to their respective strata and must be adequately protected by methods
approved by the director. Special precautions must be taken in drilling and plugging wells to guard
against any loss of artesian water from the strata in which it occurs and the contamination of artesian
water by objectionable water, oil, or gas.
All water must be shut off and excluded from the various oil-bearing and gas-bearing strata which
are penetrated. Water shutoffs ordinarily must be made by cementing casing or landing casing with or
without the use of mud-laden fluid.

History: Amended effective May 1, 1992; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-21. Casing, tubing, and cementing requirements.

All wells drilled shall be constructed with strings of casing which must be properly cemented at
sufficient depths to adequately protect and isolate all formations containing water, oil, or gas or any
combination of these; protect the pipe through salt sections encountered; and isolate the uppermost
sand of the Dakota group.
Drilling of the surface hole must be with freshwater-based drilling mud or other method approved by
the director which will protect all freshwater-bearing strata. This includes water used during the
cementing of surface casing for displacement. The surface casing must consist of new or reconditioned
pipe that has been previously tested to one thousand pounds per square inch [6900 kilopascals]. The
surface casing must be set and cemented at a point not less than fifty feet [15.24 meters] below the
base of the Fox Hills formation. Sufficient cement must be used on surface casing to fill the annular
space behind the casing to the bottom of the cellar, if any, or to the surface of the ground. If the annulus
space is not adequately filled with cement, the director must be notified immediately. The operator shall
diligently perform remedial work after obtaining approval from the director. All strings of surface casing
must stand cemented under pressure for at least twelve hours before drilling the plug. The term "under
pressure" as used herein must be complied with if one float valve is used or if pressure is otherwise
held. Cementing must be by the pump and plug method while the drilling rig is on the well or other
methods approved by the director. An appropriate accurate gauge must be maintained on the surface
casing of any well, not properly plugged and abandoned, to detect any buildup of pressure caused by
the migration of fluids. Surface casing pressure must be monitored and maintained to keep the
hydrostatic pressure at the surface casing shoe below the pressure the formation integrity test was
performed at.
Surface casing strings must be allowed to stand under pressure until the tail cement has reached a
compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler
cements utilized must reach a compressive strength of at least two hundred fifty pounds per square
inch [1725 kilopascals] within twenty-four hours and at least three hundred fifty pounds per square inch
[2415 kilopascals] within seventy-two hours. All compressive strengths on surface casing cement must
be calculated at a temperature of eighty degrees Fahrenheit [26.67 degrees Celsius].
Production or intermediate casing strings must consist of new or reconditioned pipe that has been
previously tested to two thousand pounds per square inch [13800 kilopascals]. Such strings must be
allowed to stand under pressure until the tail cement has reached a compressive strength of at least
five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a
compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within
twenty-four hours and at least five hundred pounds per square inch [3450 kilopascals] within
seventy-two hours, although in any horizontal well performing a single stage cement job from a
measured depth of greater than thirteen thousand feet [3962.4 meters], the filler cement utilized must
reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals]
within forty-eight hours and at least five hundred pounds per square inch [3450 kilopascals] within
ninety-six hours. All compressive strengths on production or intermediate casing cement must be
calculated at a temperature found in the Mowry formation using a gradient of 1.2 degrees Fahrenheit
per one hundred feet [30.48 meters] of depth plus eighty degrees Fahrenheit [26.67 degrees Celsius].
At a formation temperature at or in excess of two hundred thirty degrees Fahrenheit [110 degrees
Celsius], cement blends must include additives to address compressive strength regression.
Each surface casing string must be tested by application of pump pressure of at least one thousand
pounds per square inch [6900 kilopascals] and each other casing string shall be tested by application of
pump pressure of at least one thousand five hundred pounds per square inch [10350 kilopascals]

immediately after cementing, while the cement is in a liquid state, or the casing string must be pressure
tested after all cement has reached five hundred pounds per square inch [3450 kilopascals]
compressive strength. If, at the end of thirty minutes, this pressure has dropped more than ten percent,
the casing must be repaired after receiving approval from the director. Thereafter, the casing again
must be tested in the same manner. Further work may not proceed until a satisfactory test has been
obtained. The casing in a horizontal well may be tested by use of a mechanical tool set near the casing
shoe after the horizontal section has been drilled.
All flowing wells must be equipped with tubing. A tubing packer must also be utilized unless a
waiver from the director is obtained after demonstrating the casing will not be subjected to excessive
pressure or corrosion. The packer must be set as near the producing interval as practicable, but in all
cases must be above the perforations.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1,
1997; September 1, 2000; July 1, 2002; May 1, 2004; January 1, 2006; April 1, 2010; April 1, 2012;
April 1, 2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-22. Defective casing or cementing.

In any well that appears to have defective casing or cementing, the operator shall conduct a
mechanical integrity test, unless deemed unnecessary by the director, and report the test and defect to
the director on a sundry notice (form 4). Prior to attempting remedial work on any casing, the operator
must obtain approval from the director and proceed with diligence to conduct tests, as approved or
required by the director, to properly evaluate the condition of the well bore and correct the defect. The
director is authorized to require subsequent pressure tests to verify casing integrity if its competence is
questionable. The director may allow the well bore condition to remain if correlative rights can be
protected without endangering potable waters. The well shall be properly plugged if requested by the
director.
Any well with open perforations above a packer shall be considered to have defective casing.
History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000; July 1, 2002; May 1,
2004; January 1, 2008; April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-23. Blowout prevention.

In all drilling operations, proper and necessary precautions shall be taken for keeping the well
under control, including the use of a blowout preventer and high pressure fittings attached to properly
cemented casing strings adequate to withstand anticipated pressures. During the course of drilling, the
pipe rams shall be functionally operated at least once every twenty-four-hour period. The blind rams
shall be functionally operated each trip out of the well bore. The blowout preventer shall be pressure
tested at installation on the wellhead, after modification of any equipment, and every thirty days
thereafter. For pad drilling operations, moving from one wellhead to another within the thirty days,
pressure testing is required on connections when the integrity of a pressure seal is broken or a
component appears to be damaged or compromised. The director may postpone such pressure test if
the necessity therefor can be demonstrated to the director's satisfaction. All tests shall be noted in the
driller's record.
In all workover operations, proper and necessary precautions must be taken for keeping the well
under control, including the use of a blowout preventer and high pressure fittings attached to properly
cemented casing strings adequate to withstand anticipated pressures.

History: Amended effective January 1, 1983; September 1, 2000; July 1, 2002; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-24. Pulling string of casing.

In pulling strings of casing from any well, the space above the casing stub must be kept and left full
of fluid with adequate gel strength and specific gravity, cement, or combination thereof, to seal off all
freshwater and saltwater strata and any strata bearing oil or gas not producing. No casing may be
removed without the prior approval of the director.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-25. Deviation tests and directional surveys.

When any well is drilled or deepened, tests to determine the deviation from the vertical shall be
taken at least every one thousand feet [304.8 meters]. The director is authorized to waive the deviation
test for a shallow gas well if the necessity therefor can be demonstrated to the director's satisfaction.
When the deviation from the vertical exceeds five degrees at any point, the director may require that
the hole be straightened. Directional surveys may be required by the director, whenever, in the
director's judgment, the location of the bottom of the well is in doubt.
A directional survey shall be made and filed with the director on any well utilizing a whipstock or
any method of deviating the well bore. The obligation to run the directional survey may be waived by
the director when a well bore is deviated to sidetrack junk in the hole, straighten a crooked hole, control
a blowout, or if the necessity therefor can be demonstrated to the director's satisfaction. The survey
contractor shall file with the director free of charge one certified electronic copy of all surveys, in a form
approved by the director, within thirty days of attaining total depth. Such survey shall be in reference to
true north. The director may require the directional survey to be filed immediately after completion if the
survey is needed to conduct the operation of the director's office in a timely manner. Special permits
may be obtained to drill directionally in a predetermined direction as provided above, from the director.
If the director denies a request for a permit to directionally drill, the director shall advise the
applicant immediately of the reasons for denial. The decision of the director may be appealed to the
commission.
History: Amended effective April 1, 1980; April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992;
May 1, 1994; September 1, 2000; January 1, 2006; April 1, 2010; April 1, 2012.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-26. Multiple zone completions.

Multiple zone completions in any pool may be permitted by the director.
An application for a multiple zone completion shall be accompanied by an exhibit showing the
location of all wells on the applicant's lease and all offset wells on offset leases and shall set forth all
material facts on the common sources of supply involved and the manner and method of completion
proposed.
Multiple completed wells shall at all times be operated, produced, and maintained in a manner to
ensure the complete segregation of the various common sources of supply. The director may require
such tests as the director deems necessary to determine the effectiveness of the segregation of the
different sources of supply.

History: Amended effective January 1, 1983; May 1, 1992.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-27. Perforating, fracturing, and chemically treating wells.

The director may prescribe pretreatment casing pressure testing as well as other operational
requirements designed to protect wellhead and casing strings during treatment operations. If damage
results to the casing or the casing seat from perforating, fracturing, or chemically treating a well, the
operator shall immediately notify the director and proceed with diligence to use the appropriate method
and means for rectifying such damage, pursuant to section 43-02-03-22. If perforating, fracturing, or
chemical treating results in irreparable damage which threatens the mechanical integrity of the well, the
commission may require the operator to plug the well.
History: Amended effective January 1, 1983; May 1, 1992; April 1, 2010.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-27.1. Hydraulic fracture stimulation.

1. Prior to performing any hydraulic fracture stimulation, including refracs, through a frac string
run inside the casing string:
a. Remedial work must be performed on all casing strings deemed defective pursuant to
section 43-02-03-22 prior to performance at the discretion of the director.
b. The frac string must be either stung into a liner with the hanger/packer located in
cemented casing or run with a packer set at a minimum depth of one hundred feet [30.48
meters] below the top of cement or a minimum depth of one hundred feet [30.48 meters]
below the top of the Inyan Kara formation, whichever is deeper.
c. The casing-frac string annulus must be pressurized and monitored during frac
operations. If there is a suspected frac string or casing failure, the operator of the well
shall verbally notify the director as soon as practicable.
d. An adequately sized, function tested pressure relief valve must be utilized on the treating
lines from the pumps to the wellhead, with suitable check valves to limit the volume of
flowback fluid should the relief valve open. The relief valve must be set to limit line
pressure to no more than eighty-five percent of the internal yield pressure of the frac
string.
e. An adequately sized, function tested pressure relief valve and an adequately sized
diversion line must be utilized to divert flow from the casing to a pit or containment vessel
in case of frac string failure. The relief valve must be set to limit annular pressure to no
more than eighty-five percent of the lowest internal yield pressure of the casing string or
no greater than the pressure test on the intermediate casing, less one hundred pounds
per square inch gauge, whichever is less.
f. The surface casing must be fully open and connected to a diversion line rigged to a pit or
containment vessel.
g. An adequately sized, function tested remote operated frac valve must be utilized at a
location on the christmas tree that provides isolation of the well bore from the treating line
and must be remotely operated from the edge of the location or other safe distance.

h. Notify the director within twenty-four hours after the commencement of hydraulic fracture
stimulation operations, in an electronic format approved by the director, identifying the
subject well and verifying a frac string was run in the well.
i. Within sixty days after the hydraulic fracture stimulation is performed, the owner,
operator, or service company shall post on the fracfocus chemical disclosure registry all
elements made viewable by the fracfocus website.
2. Prior to performing any hydraulic fracture stimulation, including refracs, through a casing
string:
a. Remedial work must be performed on all casing strings deemed defective pursuant to
section 43-02-03-22 prior to performance at the discretion of the director.
b. The maximum treating pressure may not be greater than eighty-five percent of the
American petroleum institute rating of the affected casing string.
c. Casing evaluation tools to verify adequate wall thickness of any affected casing string
must be run from the wellhead to a depth as close as practicable to one hundred feet
[30.48 meters] above the completion formation and a visual inspection with photographs
shall be made of the top joint of the casing and the wellhead flange. The visual inspection
and photograph requirement may be waived by the director for good cause.
If the casing evaluation tool or visual inspection indicates wall thickness is below the
American petroleum institute minimum or a lighter weight of casing than the well design
called for, calculations must be made to determine the reduced pressure rating. If the
reduced pressure rating is less than the anticipated treating pressure, a frac string must
be run inside the casing.
d. Cement evaluation tools to verify adequate cementing of each casing string shall be run
from the wellhead to a depth as close as practicable to one hundred feet [30.48 meters]
above the completion formation.
(1) If the cement evaluation tool indicates defective casing or cementing, a frac string
must be run inside the casing.
(2) If the cement evaluation tool indicates the casing string cemented in the well fails to
satisfy section 43-02-03-21, a frac string must be run inside the casing.
e. Each affected casing string and the wellhead must be pressure tested for at least thirty
minutes with less than five percent loss to a pressure equal to or in excess of the
maximum frac design pressure.
f. If the pressure rating of the wellhead does not exceed the maximum frac design
pressure, a wellhead and blowout preventer protection system must be utilized during the
frac.
g. An adequately sized, function tested pressure relief valve must be utilized on the treating
lines from the pumps to the wellhead, with suitable check valves to limit the volume of
flowback fluid should be the relief valve open. The relief valve must be set to limit line
pressure to no greater than the test pressure of the casing, less one hundred pounds per
square inch [689.48 kilopascals].
h. The surface casing value must be fully open and connected to a diversion line rigged to a
pit or containment vessel.

i. An adequately sized, function tested remote operated frac valve must be utilized
between the treating line and the wellhead.
j. If there is a suspected casing failure, the operator of the well shall verbally notify the
director as soon as practicable.
k. Notify the director within twenty-four hours after the commencement of hydraulic fracture
stimulation operations, in an electronic format approved by the director, identifying the
subject well and verifying all logs and pressure tests have been performed as required.
l. Within sixty days after the hydraulic fracture stimulation is performed, the owner,
operator, or service company shall post on the fracfocus chemical disclosure registry all
elements made viewable by the fracfocus website.
3. If during the stimulation, the pressure in the casing-surface casing annulus exceeds three
hundred fifty pounds per square inch [2413 kilopascals] gauge, the owner or operator shall
verbally notify the director as soon as practicable but no later than twenty-four hours following
the incident.
History: Effective April 1, 2012; amended effective April 1, 2014; April 1, 2020; April 1, 2022; April 1,
2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-28. Safety regulation.

During drilling operations all oil wells must be cleaned into a pit or tank, not less than forty feet
[12.19 meters] from the derrick floor and one hundred fifty feet [45.72 meters] from any fire hazard.
All flowing oil wells must be produced through an approved oil and gas separator or emulsion
treater of ample capacity and in good working order. No boiler, electric generator, flare, or treater may
be placed nearer than one hundred fifty feet [45.72 meters] to any producing well or oil tank that is not
an oil processing vessel as defined in American Society of Mechanical Engineers (ASME) section VIII.
Placement as close as one hundred twenty-five feet [38.10 meters] may be allowed if a spark or flame
arrestor is utilized on the equipment. Placement of an oil processing vessel as defined in ASME
section VIII as close as fifty feet [15.24 meters] may be allowed if approved by the director. The
required distances above must be measured horizontally from closest vessel edge to closest edge of
the boiler, generator, flare, or treater or closest vessel edge to flame arrestor or burner air inlet edge.
Any rubbish or debris that might constitute a fire hazard must be removed to a distance of at least one
hundred fifty feet [45.72 meters] from the vicinity of wells and tanks. All waste must be burned or
disposed of in such manner as to avoid creating a fire hazard. All vegetation must be removed to a safe
distance from any production or injection equipment to eliminate a fire hazard.
The director may require remote operated or automatic shutdown equipment to be installed on, or
shut in for no more than forty days, any well that is likely to cause a serious threat of pollution or injury
to the public health or safety.
Surface casing may not be plumbed into the production flow line to relieve pressure without
approval from the director.
No well shall be drilled nor production or injection equipment installed nor saltwater handling facility
or treating plant constructed less than five hundred feet [152.40 meters] from an occupied dwelling
unless agreed to in writing by the owner of the dwelling or authorized by order of the commission.
Subsurface pressure must be controlled during all drilling, completion, and well-servicing
operations with appropriate fluid weight and pressure control equipment. The operator conducting any
well hydraulic fracture stimulation shall give prior written notice, up to thirty-one days and not less than

twenty-one days, to any operator of a well completed in the same or adjacent pool, if publicly available
information indicates or if the operator is made aware, if the completion intervals are within two
thousand six hundred and forty feet [804.67 meters] of one another. Notice must include twenty-four-
hour emergency contact information, planned start and end dates, and contact information for
scheduling updates.
History: Amended effective January 1, 1983; May 1, 1990; September 1, 2000; January 1, 2006;
January 1, 2008; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2020; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-29. Well and lease equipment and gas gathering pipelines.

Wellhead and lease equipment with a working pressure at least equivalent to the calculated or
known pressure to which the equipment may be subjected shall be installed and maintained.
Equipment on producing wells shall be installed to facilitate gas-oil ratio tests, and static bottom hole or
other pressure tests. Valves shall be installed and maintained in good working order to permit pressure
readings to be obtained on both casing and tubing.
All newly constructed underground gas gathering pipelines must be devoid of leaks and
constructed of materials resistant to external corrosion and to the effects of transported fluids. All such
pipelines installed in a trench must be installed in a manner that minimizes interference with agriculture,
road and utility construction, the introduction of secondary stresses, the possibility of damage to the
pipe, and tracer wire shall be buried with any nonconductive pipes installed. When a trench for an
underground gas gathering pipeline is backfilled, it must be backfilled in a manner that provides firm
support under the pipe and prevents damage to the pipe and pipe coating from equipment or from the
backfill material.
1. The operator of any underground gas gathering pipeline placed into service on August 1,
2011, to June 30, 2013, shall file with the director, by January 1, 2015, a geographical
information system layer utilizing North American datum 83 geographic coordinate system
(GCS) and in an environmental systems research institute (Esri) shape file format showing the
location of the pipeline centerline. The operator of any underground gas gathering pipeline
placed into service after June 30, 2013, shall file with the director, within one hundred eighty
days of placing into service, a geographical information system layer utilizing North American
datum 83 geographic coordinate system (GCS) and in an environmental systems research
institute (Esri) shape file format showing the location of all compressor sites, buried drip tanks,
and the pipeline centerline. An affidavit of completion shall accompany each layer containing
the following information:
a. A statement that the pipeline was constructed and installed in compliance with section
43-02-03-29.
b. The outside diameter, minimum wall thickness, composition, internal yield pressure, and
maximum temperature rating of the pipeline, or any other specifications deemed
necessary by the director.
c. The anticipated operating pressure of the pipeline.
d. The type of fluid that will be transported in the pipeline and direction of flow.
e. Pressure to which the pipeline was tested prior to placing into service.
f. The minimum pipeline depth of burial.
g. In-service date.

h. Leak detection and monitoring methods that will be utilized after in-service date.
i. Pipeline name.
j. Accuracy of the geographical information system layer.
2. When an underground gas gathering pipeline or any part of such pipeline is abandoned, the
operator shall leave such pipeline in a safe condition by conducting the following:
a. Disconnect and physically isolate the pipeline from any operating facility or other pipeline.
b. Cut off the pipeline or the part of the pipeline to be abandoned below surface at pipeline
level.
c. Purge the pipeline with fresh water, air, or inert gas in a manner that effectively removes
all fluid.
d. Remove cathodic protection from the pipeline.
e. Permanently plug or cap all open ends by mechanical means or welded means.
3. Within one hundred eighty days of completing the abandonment of an underground gas
gathering pipeline the operator of the pipeline shall file with the director a geographical
information system layer utilization North American datum 83 geographic coordinate system
(GCS) and in an environmental systems research institute (Esri) shape file format showing the
location of the pipeline centerline and an affidavit of completion containing the following
information:
a. A statement that the pipeline was abandoned in compliance with section 43-02-03-29.
b. The type of fluid used to purge the pipeline.
4. Aboveground pipeline markers must be placed and maintained over each buried underground
gas gathering pipeline or portion thereof at the discretion of the director when necessary to
protect public health and safety. The markers must contain at least the following on a
background of sharply contrasting color: the word "Warning", "Caution", or "Danger" followed
by the fluid transported pipeline, the name of the operator, and current emergency phone
number.
The requirement to submit a geographical information system layer is not to be construed to be
required on buried piping utilized to connect flares, tanks, treaters, or other equipment located entirely
within the boundary of a well site or production facility.
History: Amended effective January 1, 1983; January 1, 2006; April 1, 2014; October 1, 2016; April 1,
2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-29.1. Crude oil and produced water underground gathering pipelines.

1. Application of section. This section is applicable to all underground gathering pipelines
designed for or capable of transporting crude oil or produced water from an oil and gas
production facility for the purpose of disposal, storage, or for sale purposes. If these rules
differ from the pipeline manufacturer's prescribed installation and operation practices, the
pipeline manufacturer's prescribed installation and operation practices take precedence.
The requirements in this section are not applicable to flow lines, injection pipelines, pipelines
operated by an enhanced recovery unit for enhanced recovery unit operations, or on piping

utilized to connect wells, tanks, treaters, flares, or other equipment located entirely within the
boundary of a well site or production facility.
If these rules differ from or are preempted by federal requirements on federally regulated
pipelines, the federal rules take precedence. The pipeline owner shall provide sufficient
documentation to the director confirming the pipeline is federally regulated.
2. Definitions. The terms used throughout this section apply to this section only.
a. "Crude oil or produced water underground gathering pipeline" means an underground
gathering pipeline designed or intended to transfer crude oil or produced water from a
production facility for disposal, storage, or sale purposes.
b. "New construction" means a new gathering pipeline installation project or an alteration or
reroute of an existing gathering pipeline where the location, composition, size, design
temperature, or design pressure changes.
c. "Pipeline repair" is the work necessary to restore a pipeline system to a condition suitable
for safe operations that does not change the design temperature or pressure.
d. "Gathering system" is a group of connected pipelines which have been designated as a
gathering system by the operator. A gathering system must have a unique name and
must be interconnected.
e. "In-service date" is the first date fluid was transported down the underground gathering
pipeline for disposal, storage, or sale purposes after construction.
3. Notifications.
a. The underground gathering pipeline owner shall notify the director, at least seven days
prior to commencing new construction of any underground gathering pipeline. The notice
of intent to construct automatically expires after one year and for any project not built
within one year; a new notice of intent to construct must be submitted.
(1) The notice of intent to construct a crude oil or produced water underground
gathering pipeline must include the following:
(a) The proposed date construction is scheduled to begin.
(b) A statement that the director will be verbally notified approximately forty-eight
hours prior to commencing the construction.
(c) A geographical information system layer utilizing North American datum 83
geographic coordinate system (GCS) and in an environmental systems
research institute (Esri) shape file format showing the proposed route of the
pipeline from the point of origin to the termination point.
(d) The proposed underground gathering pipeline design drawings, including all
associated above ground equipment.
[1] The proposed pipeline composition, specifications (i.e. size, weight,
grade, wall thickness, coating, and standard dimension ratio).
[2] The type of fluid to be transported.
[3] The method of testing pipeline integrity (e.g. hydrostatic or pneumatic
test) prior to placing the pipeline into service.

[4] Proposed burial depth of the pipeline.
[5] The location and type of all road crossings (i.e. bored and cased or bored
only).
[6] The location of all environmentally sensitive areas, such as wetlands,
streams, or other surface waterbodies that the pipeline may traverse, if
applicable.
b. The underground gathering pipeline owner shall file a sundry notice (form 4 or form
provided by the director) with the director providing notification of any underground
gathering pipeline system or portion thereof that has been removed from service for more
than one year.
c. If damage occurs to any underground gathering pipeline, flow line, or other underground
equipment used to transport crude oil, natural gas, carbon dioxide, or water produced in
association with oil and gas, during construction, operation, maintenance, repair, or
abandonment of an underground gathering pipeline, the responsible party shall verbally
notify the director immediately.
d. The pipeline owner shall file a sundry notice (form 4 or form provided by the director)
within thirty days of the in-service date reporting the date of first service.
4. Design and construction.
The following applies to newly constructed crude oil and produced water underground
gathering pipelines, including tie-ins to existing systems:
a. Underground gathering pipelines must be devoid of leaks and constructed of materials
resistant to external corrosion and to the effects of transported fluids.
b. Underground gathering pipelines must be designed in a manner that allows for line
maintenance, periodic line cleaning, and integrity testing.
c. Installation crews must be trained in all installation practices for which they are tasked to
perform.
d. Underground gathering pipelines must be installed in a manner that minimizes
interference with agriculture, road and utility construction, the introduction of secondary
stresses, and the possibility of damage to the pipe. Tracer wire must be buried with any
nonconductive pipe installed.
e. Unless the manufacturer's installation procedures and practices provide guidance,
pipeline trenches must be constructed to allow for the pipeline to rest on undisturbed
native soil and provide continuous support along the length of the pipe. Trench bottoms
must be free of rocks greater than two inches in diameter, debris, trash, and other foreign
material not required for pipeline installation. If a trench bottom is over excavated, the
trench bottom must be backfilled with appropriate material and compacted prior to
installation of the pipe to provide continuous support along the length of the pipe.
The width of the trench must provide adequate clearance on each side of the pipe.
Trench walls must be excavated to ensure minimal sluffing of sidewall material into the
trench. Subsoil from the excavated trench must be stockpiled separately from previously
stripped topsoil.

f. Underground gathering pipelines that cross a township, county, or state graded road
must be bored unless the responsible governing agency specifically permits the owner to
open cut the road.
g. No pipe or other component may be installed unless it has been visually inspected at the
site of installation to ensure that it is not damaged in a manner that could impair its
strength or reduce its serviceability.
h. The pipe must be handled in a manner that minimizes stress and avoids physical
damage to the pipe during stringing, joining, or lowering in. During the lowering in
process the pipe string must be properly supported so as not to induce excess stresses
on the pipe or the pipe joints or cause weakening or damage to the outer surface of the
pipe.
i. When a trench for an underground gathering pipeline is backfilled, it must be backfilled in
a manner that provides firm support under the pipe and prevents damage to the pipe and
pipe coating from equipment or from the backfill material. Sufficient backfill material must
be placed in the haunches of the pipe to provide long-term support for the pipe. Backfill
material that will be within two feet of the pipe must be free of rocks greater than two
inches in diameter and foreign debris. Backfilling material must be compacted as
appropriate during placement in a manner that provides support for the pipe and reduces
the potential for damage to the pipe and pipe joints.
j. Cover depths must be a minimum of four feet [1.22 meters] from the top of the pipe to the
finished grade. The cover depth for an undeveloped governmental section line must be a
minimum of six feet [1.83 meters] from the top of the pipe to the finished grade.
k. Underground gathering pipelines that traverse environmentally sensitive areas, such as
wetlands, streams, or other surface waterbodies, must be installed in a manner that
minimizes impacts to these areas. Any horizontal directional drilling plan prepared by the
owner or required by the director, must be filed with the director, prior to the
commencement of horizontal directional drilling.
l. Clamping or squeezing as a method of connecting any produced water underground
gathering pipeline must be approved by the director. Prior to clamping or squeezing the
pipeline, the owner shall file a sundry notice (form 4 or form provided by the director) with
the director and obtain approval of the clamping or squeezing plan. The notice must
include documentation that the pipeline can be safely clamped or squeezed as
prescribed by the manufacturer's specifications. Any damaged portion of a produced
water underground gathering pipeline that has been clamped or squeezed must be
replaced before it is placed into service.
5. Pipeline reclamation.
a. When utilizing excavation for pipeline installation, repair, or abandonment, topsoil must
be stripped, segregated from the subsoils, and stockpiled for use in reclamation.
"Topsoil" means the suitable plant growth material on the surface; however, in no event
shall this be deemed to be more than the top twelve inches [30.48 centimeters] of soil or
deeper than the depth of cultivation, whichever is greater.
b. The pipeline right-of-way must be reclaimed as closely as practicable to original
condition. All stakes, temporary construction markers, cables, ropes, skids, and any other
debris or material not native to the area must be removed from the right-of-way and
lawfully disposed of.

c. During right-of-way reclamation all subsoils and topsoils must be returned in proper order
to as close to the original depths as practicable. Right-of-way reclamation must be
completed within one year of the pipeline being placed into service. An extension may be
granted at the director's discretion.
d. The reclaimed right-of-way soils must be stabilized to prevent excessive settling, sluffing,
cave-ins, or erosion.
e. The crude oil and produced water underground gathering pipeline owner is responsible
for their right-of-way reclamation and maintenance until such pipeline is released by the
director from the pipeline bond pursuant to section 43-02-03-15.
6. Inspection.
All newly constructed crude oil and produced water underground gathering pipelines must be
inspected by third-party independent inspectors to ensure the pipeline is installed as
prescribed by the manufacturer's specifications and in accordance with the requirements of
this section. A list of all third-party independent inspectors and a description of each
independent inspector's qualifications, certifications, experience, and specific training must be
provided to the director upon request. A person may not be used to perform inspections
unless that person has been trained and is qualified in the phase of construction to be
inspected. The third-party independent inspector may not be an employee of the gathering
pipeline owner/operator or the contractor hired to construct and install the pipeline. The
number of third-party independent inspectors must be adequate for the size of the pipeline
construction project to ensure proper pipeline installation.
7. Associated pipeline facility.
No associated above ground equipment may be installed less than five hundred feet [152.40
meters] from an occupied dwelling unless agreed to in writing by the owner of the dwelling or
authorized by order of the commission.
All associated above ground equipment used to store crude oil or produced water must be
devoid of leaks and constructed of materials resistant to the effects of crude oil, produced
water, brines, or chemicals that may be contained therein. The above materials requirement
may be waived by the director for tanks presently in service and in good condition. Unused
tanks and associated above ground equipment must be removed from the site or placed into
service, within a reasonable time period, not to exceed one year.
Dikes must be erected around all produced water or crude oil tanks at any new facility prior to
placing the associated underground gathering pipeline into service. Dikes must be erected
and maintained around all crude oil or produced water tanks or above ground equipment,
when deemed necessary by the director. Dikes as well as the base material under the dikes
and within the diked area must be constructed of sufficiently impermeable material to provide
emergency containment. Dikes must be of sufficient dimension to contain the total capacity of
the largest tank plus one day's fluid throughput. The required capacity of the dike may be
lowered by the director if the necessity therefor can be demonstrated to the director's
satisfaction. Discharged crude oil or produced water must be properly removed and may not
be allowed to remain standing within or outside of any diked areas.
The underground gathering pipeline owner shall take steps to minimize the amount of solids
stored at the pipeline facility, although the remediation of such material may be allowed onsite,
if approved by the director.
8. Underground gathering pipeline as built.

The owner of any underground gathering pipeline placed into service after July 31, 2011, shall
file with the director, as prescribed by the director, within one hundred eighty days of placing
into service, a geographical information system layer utilizing North American datum 83
geographic coordinate system (GCS) and in an environmental systems research institute
(Esri) shape file format showing the location of all associated above ground equipment and
the pipeline centerline from the point of origin to the termination point. An affidavit of
completion shall accompany each layer containing the following information:
a. A third-party inspector certificate that the pipeline was constructed and installed in
compliance with section 43-02-03-29.1.
b. The outside diameter, minimum wall thickness, composition, and maximum temperature
rating of the pipeline, or any other specifications deemed necessary by the director.
c. The maximum allowable operating pressure of the pipeline.
d. The specified minimum yield strength and internal yield pressure of the pipeline if
applicable to the composition of pipe.
e. The type of fluid that will be transported in the pipeline.
f. Pressure and duration to which the pipeline was tested prior to placing into service.
g. The minimum pipeline depth of burial from the top of the pipe to the finished grade.
h. In-service date.
i. Leak protection and monitoring methods that will be utilized after in-service date.
j. Any leak detection methods that have been prepared by the owner.
k. The name of the pipeline gathering system and any other separately named portions
thereof.
l. The geographical information system layer must be within twenty feet [6.10 meters] of
horizontal accuracy.
9. Operating requirements.
The maximum operating pressure for all crude oil and produced water underground gathering
pipelines may not exceed the manufacturer's specifications of the pipe or the manufacturer's
specifications of any other component of the pipeline, whichever is less. The maximum
operating pressure of any portion of an underground gathering system may not exceed the
test pressure from the most recent integrity test demonstration following modification or repair
for which it was tested.
The crude oil or produced water underground gathering pipeline must be equipped with
adequate controls and protective equipment to prevent the pipeline from operating above the
maximum operating pressure.
10. Leak protection, detection, and monitoring.
All crude oil and produced water underground gathering pipeline owners shall file with the
director any leak protection and monitoring plan prepared by the owner or required by the
director, pursuant to North Dakota Century Code section 38-08-27.
If any leak detection plan has been prepared by the owner, it must be submitted to the
director.

All crude oil or produced water underground gathering pipeline owners shall develop and
maintain a data sharing plan and file a copy with the director. The plan must provide for real-
time sharing of data between the operator of the production facility, the crude oil or produced
water underground gathering pipeline owner, and the operator at the point or points of
disposal, storage, or sale. If a discrepancy in the shared data is observed, the party observing
the data discrepancy shall notify all other parties and action must be taken to determine the
cause. A record of all data discrepancies must be retained by the crude oil or produced water
underground gathering pipeline owner. If requested, copies of such records must be filed with
the director.
11. Spill response.
All crude oil and produced water underground gathering pipeline owners shall maintain a spill
response plan during the service life of any crude oil or produced water underground
gathering pipeline. The plan should detail the necessary steps for an effective and timely
response to a pipeline spill. The spill response plan should be tailored to the specific risks in
the localized area. Response capabilities should address access to equipment and tools
necessary to respond, as well as action steps to protect the health and property of impacted
landowners, citizens, and the environment.
12. Corrosion control.
a. Underground gathering pipelines must be designed to withstand the effects of external
corrosion and maintained in a manner that mitigates internal corrosion.
b. All metallic underground gathering pipelines installed must have sufficient corrosion
control.
c. All coated pipe must be electronically inspected prior to placement using coating
deficiency (i.e. holiday) detectors to check for any faults not observable by visual
examination. The holiday detector must be operated in accordance with manufacturer's
instructions and at a voltage level appropriate for the electrical characteristics of the
pipeline system being tested. During installation all joints, fittings, and tie-ins must be
coated with materials compatible with the coatings on the pipe. Coating materials must:
(1) Be designed to mitigate corrosion of the buried pipeline;
(2) Have sufficient adhesion to the metal surface to prevent under film migration of
moisture;
(3) Be sufficiently ductile to resist cracking;
(4) Have enough strength to resist damage due to handling and soil stress;
(5) Support any supplemental cathodic protection; and
(6) If the coating is an insulating type, have low moisture absorption and provide high
electrical resistance.
d. Cathodic protection systems must meet or exceed the minimum criteria set forth in the
National Association of Corrosion Engineers standard practice Control of External
Corrosion on Underground or Submerged Metallic Piping Systems.
e. If internal corrosion is anticipated or detected, the underground gathering pipeline owner
shall take prompt remedial action to correct any deficiencies, such as increased pigging,
use of corrosion inhibitors, internal coating of the pipeline (e.g. an epoxy paint or other
plastic liner), or a combination of these methods. Corrosion inhibitors must be used in

sufficient quantity to protect the entire part of the pipeline system that the inhibitors are
designed to protect.
13. Pipeline integrity.
A crude oil or produced water underground gathering pipeline owner may not operate a
pipeline unless it has been pressure tested and demonstrated integrity. In addition, an owner
may not return to service a portion of pipeline which has been repaired, replaced, relocated, or
otherwise changed until it has demonstrated integrity.
a. The crude oil and produced water underground gathering pipeline owner shall notify the
director at least forty-eight hours prior to commencement of any pipeline integrity test to
allow a representative of the director to witness the testing process and results. The
notice must include the pipeline integrity test procedure.
b. The crude oil and produced water underground gathering pipeline owner shall submit
within sixty days of the underground gathering pipeline being placed into service the
integrity test results which must include the following:
(1) The name of the pipeline gathering system and any other separately named
portions thereof;
(2) The date of the test;
(3) The duration of the test;
(4) The length of pipeline which was tested;
(5) The maximum and minimum test pressure;
(6) The starting and ending pressure;
(7) A copy of the appropriately scaled chart recorder or digital log results;
(8) A geographical information system layer utilizing North American datum 83
geographic coordinate system (GCS) and in an environmental systems research
institute (Esri) shape file format showing the location of the centerline of the portion
of the pipeline that was tested;
(9) A copy of the test procedure used; and
(10) A third-party inspector certificate summarizing the pipeline has been pressure tested
and whether it demonstrated integrity, including the identification of any leaks,
ruptures, or other integrity issues encountered, and an explanation for any
substantial pressure gain or losses during the integrity test, if applicable.
c. All crude oil and produced water underground gathering pipeline owners shall maintain a
pipeline integrity demonstration plan during the service life of any crude oil or produced
water underground gathering pipeline. The director, for good cause, may require a
pipeline integrity demonstration on any crude oil or produced water underground
gathering pipeline.
14. Pipeline repair.
Each owner, in repairing an underground gathering pipeline or pipeline system, shall ensure
that the repairs are made in a manner that prevents damage to persons or property.

An owner may not use any pipe, valve, or fitting, for replacement or repair of an underground
gathering pipeline, unless it is designed to meet the maximum operating pressure.
a. At least forty-eight hours prior to any underground gathering pipeline repair or
replacement, the underground gathering pipeline owner shall notify the director, except in
an emergency.
b. Within one hundred eighty days of repairing or replacing any underground gathering
pipeline the owner of the pipeline shall file with the director a geographical information
system layer utilizing North American datum 83 geographic coordinate system (GCS)
and in an environmental systems research institute (Esri) shape file format showing the
location of the centerline of the repaired or replaced pipeline and an affidavit of
completion containing the following information:
(1) A statement that the pipeline was repaired in compliance with section
43-02-03-29.1.
(2) The reason for the repair or replacement.
(3) The length of pipeline that was repaired or replaced.
(4) Pressure and duration to which the pipeline was tested prior to returning to service.
c. Clamping or squeezing as a method of repair for any produced water underground
gathering pipeline must be approved by the director. Prior to clamping or squeezing the
pipeline, the owner shall file a sundry notice (form 4) with the director and obtain
approval of the clamping or squeezing plan. The notice must include documentation that
the pipeline can be safely clamped or squeezed as prescribed by the manufacturer's
specifications. If an emergency requires clamping or squeezing, the owner or the owner's
agent shall obtain verbal approval from the director and the notice shall be filed within
seven days of completing the repair. Any damaged portion of a produced water
underground gathering pipeline that has been clamped or squeezed must be replaced
before it is returned to service.
15. Pipeline abandonment.
a. At least forty-eight hours prior to abandoning any underground gathering pipeline, the
underground gathering pipeline owner shall notify the director verbally.
b. When an underground gathering pipeline or any part of such pipeline is abandoned as
defined under subsection 1 of North Dakota Century Code section 38-08-02 after
March 31, 2014, the owner shall leave such pipeline in a safe condition by conducting the
following:
(1) Disconnect and physically isolate the pipeline from any operating facility, associated
above ground equipment, or other pipeline.
(2) Cut off the pipeline or the part of the pipeline to be abandoned below surface at
pipeline level.
(3) Purge the pipeline with fresh water, air, or inert gas in a manner that effectively
removes all fluid.
(4) Remove cathodic protection from the pipeline.
(5) Permanently plug or cap all open ends by mechanical means or welded means.

(6) The site of all associated above ground equipment must be reclaimed pursuant to
section 43-02-03-34.1.
(7) If the bury depth is not at least three feet below final grade, such portion of pipe
must be removed.
c. Within one hundred eighty days of completing the abandonment of an underground
gathering pipeline the owner of the pipeline shall file with the director a geographical
information system layer utilizing North American datum 83 geographic coordinate
system (GCS) and in an environmental systems research institute (Esri) shape file format
showing the location of the pipeline centerline and an affidavit of completion containing
the following information:
(1) A statement that the pipeline was abandoned in compliance with section
43-02-03-29.1.
(2) The type of fluid used to purge the pipeline.
(3) The date of pipeline abandonment.
(4) The length of pipeline abandoned.
16. Pipeline markers.
a. Aboveground pipeline markers must be placed and maintained over each buried crude
oil or produced water underground gathering pipeline or portion thereof at the discretion
of the director when necessary to protect public health and safety. The markers must
contain at least the following on a background of sharply contrasting color: the word
"Warning", "Caution", or "Danger" followed by the name of the fluid transported pipeline,
the name of the operator, and current emergency phone number.
History: Effective October 1, 2016; amended effective April 1, 2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-30. Notification of fires, leaks, spills, or blowouts.

All persons controlling or operating any well, pipeline and associated aboveground equipment,
receiving tank, storage tank, facility, treating plant, or any other receptacle or production facility
associated with oil, gas, or water production, injection, processing, or well servicing shall verbally notify
the director immediately and follow up utilizing the online initial notification report within twenty-four
hours after discovery of any fire, leak, spill, blowout, or release of fluid. The initial report must include
the name of the reporting party, including telephone number and address, date and time of the incident,
location of the incident, type and cause of the incident, estimated volume of release, containment
status, waterways involved, immediate potential threat, and action taken. If any such incident occurs or
travels offsite of a facility, the persons, as named above, responsible for proper notification shall within
a reasonable time also notify the surface owners upon whose land the incident occurred or traveled.
Notification requirements prescribed by this section do not apply to any leak or spill involving only
freshwater or to any leak, spill, or release of crude oil, produced water, or natural gas liquid that is less
than one barrel total volume and remains onsite of a site where any well thereon was spud before
September 2, 2000, or on a facility that was constructed before September 2, 2000, and do not apply to
any leak or spill or release of crude oil, produced water, or natural gas liquid that is less than ten barrels
total volume cumulative over a fifteen-day time period, and remains onsite of a site where all wells
thereon were spud after September 1, 2000, or on a facility that was constructed after September 1,
2000. The initial notification must be followed by a written report within ten days after cleanup of the
incident, unless deemed unnecessary by the director. Such report must include the following
information: the operator and description of the facility, the legal description of the location of the

incident, date of occurrence, date of cleanup, amount and type of each fluid involved, amount of each
fluid recovered, steps taken to remedy the situation, root cause of the incident unless deemed
unnecessary by the director, and action taken to prevent reoccurrence, and if applicable, any additional
information pursuant to subdivision e of subsection 1 of North Dakota Century Code section
37-17.1-07.1. The name, title, and telephone number of the company representative must be included
on such report. The persons, as named above, responsible for proper notification shall within a
reasonable time also provide a copy of the written report to the surface owners upon whose land the
incident occurred or traveled.
The commission, however, may impose more stringent spill reporting requirements if warranted by
proximity to sensitive areas, past spill performance, or careless operating practices as determined by
the director.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1,
2008; April 1, 2010; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-30.1. Leak and spill cleanup.

At no time shall any spill or leak be allowed to flow over, pool, or rest on the surface of the land or
infiltrate the soil. Discharged fluids must be properly removed and may not be allowed to remain
standing within or outside of diked areas, although the remediation of such fluids may be allowed onsite
if approved by the director. Operators and responsible parties must respond with appropriate resources
to contain and clean up spills.
A sundry notice (form 4) must be submitted within ten days after cleanup of any spill or leak in
which fluids are not properly removed or appropriate resources are not utilized to contain and clean up
the spill unless deemed unnecessary by the director. The notice must include the date of the
occurrence, date of cleanup, amount and type of each fluid involved, identification of the site affected,
root cause of the incident, and explanation of how the volume was determined.
History: Effective April 1, 2012; amended effective October 1, 2016; April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-31. Well log, completion, and workover reports.

After the plugging of a well, a plugging record (form 7) must be filed with the director. After the
completion of a well, recompletion of a well in a different pool, or drilling horizontally in an existing pool,
a completion report (form 6 or form provided by the director) must be filed with the director. In no case
shall oil or gas be transported from the lease prior to the filing of a completion report unless approved
by the director. The operator shall cause to be run an open hole electrical, radioactivity, or other similar
log, or combination of open hole logs, of the operator's choice, from which formation tops and porosity
zones can be determined. The operator shall cause to be run a gamma ray log from total depth to
ground level elevation of the well bore. Within six months of reaching total depth and prior to
completing the well, the operator shall cause to be run a cement evaluation log from which the
presence and quality of bonding of cement can be determined in every well in which production or
intermediate casing has been set. The initial cement evaluation log must be run without the addition of
pressure at surface, except at depths where the cement evaluation tool may need appropriate pressure
applied to function properly. The obligation to log may be waived or postponed by the director if the
necessity therefor can be demonstrated to the director's satisfaction. Waiver will be contingent upon
such terms and conditions as the director deems appropriate. All logs run must be available to the
director at the well site prior to proceeding with plugging or completion operations. All logs run shall be
submitted to the director free of charge. Logs must be submitted as one digital TIFF (tagged image file
format) copy and one digital LAS (log ASCII) formatted copy, or a format approved by the director. In

addition, operators shall file one copy of drill stem test reports and charts, formation water analyses,
core analyses, geologic reports, and noninterpretive lithologic logs or sample descriptions if compiled
by the operator.
All information furnished to the director on permits, except the operator name, well name, location,
permit date, confidentiality period, spacing or drilling unit description, spud date, rig contractor, central
tank battery number, any production runs, or volumes injected into an injection well, must be kept
confidential from the date a request by the operator is received in writing until the six-month
confidentiality period has ended. The six-month period commences on the date the well is completed or
the date the written request is received, whichever is earlier. If the written request accompanies the
application for permit to drill or is filed after permitting but prior to spudding, the six-month period
commences on the date the well is spudded. The director may release such confidential completion
and production data to health care professionals, emergency responders, and state, federal, or tribal
environmental and public health regulators if the director deems it necessary to protect the public's
health, safety, and welfare.
All information furnished to the director on recompletions, restimulation wells, or reentries, except
the operator name, well name, location, permit date, confidentiality period, spacing or drilling unit
description, spud date, rig contractor, any production runs, or volumes injected into an injection well,
must be kept confidential for not more than six months if requested by the operator in writing. The
six-month period shall commence on the date the well is completed, recompleted, or restimulated or
the date a request by the operator is received in writing, whichever is earlier. Any information furnished
to the director prior to approval of the recompletion, restimulation, or reentry must remain public.
Approval must be obtained on a well sundry form from the director prior to perforating or
recompleting a well in a pool other than the pool in which the well is currently permitted.
After the completion of any remedial work, or attempted remedial work such as plugging back or
drilling deeper, acidizing, shooting, formation fracturing, squeezing operations, setting liner, perforating,
reperforating, or other similar operations not specifically covered herein, a report on the operation shall
be filed on a sundry notice (form 4) with the director. The report must present a detailed account of all
work done and the date of such work; the daily production of oil, gas, and water both prior to and after
the operation; the shots per foot, size, and depth of perforations; the quantity of sand, crude, chemical,
or other materials employed in the operation; and any other pertinent information or operations which
affect the original status of the well and are not specifically covered herein.
Upon the installation of pumping equipment on a flowing well, or change in type of pumping
equipment designed to increase productivity in a well, the operator shall submit a sundry notice (form 4)
of such installation. The notice must include all pertinent information on the pump and the operation
thereof including the date of such installation, and the daily production of the well prior to and after the
pump has been installed.
All forms, reports, logs, and other information required by this section must be submitted within
thirty days after the completion of such work, although a completion report must be filed immediately
after the completion or recompletion of a well in a pool or reservoir not then covered by an order of the
commission.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; May 1, 1994;
July 1, 1996; September 1, 2000; July 1, 2002; January 1, 2006; January 1, 2008; April 1, 2010; April 1,
2012; October 1, 2016; April 1, 2020; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04

### § 43-02-03-32. Stratigraphic test and core holes.

Stratigraphic test and core holes shall be permitted the same as oil and gas wells, although no
setback from a drilling unit shall be required.
History: Amended effective April 30, 1981; January 1, 1983; July 1, 2002.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-33. Notice of intention to plug well.

The operator or the operator's agent shall file a notice of intention (form 4) to plug with the director,
and obtain the approval of the director, prior to the commencement of plugging or plug-back operations.
The notice shall state the name and location of the well, the name of the operator, and the method of
plugging, which must include a detailed statement of proposed work, and a well bore diagram showing
the current conditions downhole, including all data pertinent to plugging the well in an effective manner.
In the case of a recently completed test well that has not had production casing in the hole, the
operator may commence plugging by giving reasonable notice to, and securing verbal approval of, the
director as to the method of plugging, and the time plugging operations are to begin. Within thirty days
after the plugging of any well has been accomplished, the owner or operator thereof shall file a
plugging record (form 7), and, if requested, a copy of the cementer's trip ticket or job receipt, with the
director setting forth in detail the method used in plugging the well.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; January 1, 2006; April 1,
2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-34. Method of plugging.

All wells shall be plugged in a manner which will confine permanently all oil, gas, and water in the
separate strata originally containing them. This operation shall be accomplished by the use of
mud-laden fluid, cement, and plugs, used singly or in combination as may be approved by the director.
All casing strings shall be cut off at least three feet [91.44 centimeters] below the final surface contour,
and a cap with file number shall be welded thereon. Core or stratigraphic test holes drilled to or below
sands containing freshwater shall be plugged in accordance with the applicable provisions recited
above. After plugging, the site must be reclaimed pursuant to section 43-02-03-34.1.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; July 1, 2002;
April 1, 2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-34.1. Reclamation of surface.

1. Within a reasonable time, but not more than one year, after a well is plugged, or if a permit
expires, has been canceled or revoked, or a treating plant or saltwater handling facility is
decommissioned, the site, access road, and other associated facilities constructed must be
reclaimed as closely as practicable to original condition pursuant to North Dakota Century
Code section 38-08-04.12. Prior to site reclamation, the operator or the operator's agent shall
file a well sundry form or facility sundry notice with the director and obtain approval of a
reclamation plan. The operator or operator's agent shall provide a copy of the proposed
reclamation plan to the surface owner at least ten days prior to commencing the work unless
waived by the surface owner. Verbal approval to reclaim the site may be given. The notice
must include:
a. The name and address of the reclamation contractor;

b. The name and address of the surface owner and the date when a copy of the proposed
reclamation plan was provided to the surface owner;
c. A description of the proposed work, including topsoil redistribution and reclamation plans
for the access road and other associated facilities; and
d. Reseeding plans, if applicable.
The commission will mail a copy of the approved notice to the surface owner.
All equipment, waste, and debris shall be removed from the site. All pipelines shall be purged
and abandoned pursuant to section 43-02-03-29.1. Flow lines shall be removed if buried less
than three feet [91.44 centimeters] below final contour.
2. Gravel or other surfacing material must be removed, stabilized soil shall be remediated, and
the site, access road, and other associated facilities constructed for the well, treating plant, or
saltwater handling facility shall be reshaped as near as practicable to original contour.
3. The stockpiled topsoil must be distributed evenly over the disturbed area and, where
applicable, the area revegetated with native species or according to the reasonable
specifications of the appropriate government land manager or surface owner.
4. A site assessment may be required by the director, before and after reclamation of the site.
5. Within thirty days after completing any reclamation, the operator shall file a sundry notice with
the director reporting the work performed.
6. The director, with the consent of the appropriate government land manager or surface owner,
may waive the requirement of reclamation of the site and access road after a well is plugged
or treating plant or saltwater handling facility is decommissioned. The director shall record
documentation of the waiver with the recorder of the county in which the site or road is
located.
History: Effective April 1, 2012; amended effective April 1, 2014; October 1, 2016; April 1, 2018; April 1,
2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-35. Conversion of mineral wells to freshwater wells.

Any person desiring to convert a mineral well to a freshwater well, as provided by North Dakota
Century Code section 61-01-27, shall file an application for approval with the commission. The
application must include, but is not limited to, the following:
1. If the well is to be used for other than individual domestic and livestock use, a conditional
water permit issued by the department of water resources.
2. An affidavit by the person desiring to obtain approval for the conversion stating that such
person has the authority and assumes all liability for the use and plugging of the proposed
freshwater well.
3. The procedure which will be followed in converting the mineral well to a freshwater well.
4. If the well is not currently plugged and abandoned, an affidavit must be executed by the
operator of the well indicating that the parties responsible for plugging the mineral well have
no objection to the conversion of the mineral well to a freshwater well.

If the commission, after notice and hearing, determines that a mineral well may safely be used as a
freshwater well, the commission may approve the conversion.
History: Amended effective April 30, 1981; January 1, 1983; September 1, 1987; July 1, 2002; April 1,
2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-36. Liability.

The owner and operator of any well, core hole, or stratigraphic test hole, whether cased or
uncased, shall be liable and responsible for the plugging and site reclamation thereof in accordance
with the rules and regulations of the commission.
History: Amended effective January 1, 1983; May 1, 1994.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-37. Slush pits.

Repealed effective January 1, 1983.
### § 43-02-03-38. Preservation of cores and samples.

Repealed effective January 1, 1983.
### § 43-02-03-38.1. Preservation of cores and samples.

Unless waived by the director, operators shall have a well site geologist or mudlogger on location
for at least the first well drilled on a multiwell pad to collect sample cuttings and to create a mudlog and
geologic report. Sample cuttings of formations, taken at intervals prescribed by the state geologist, in all
wells drilled for the production of oil or gas, injection, disposal, storage operations, or geological
information in North Dakota, shall be washed and packaged in standard sample envelopes which in
turn shall be placed in proper order in a standard sample box; carefully identified as to operator, well
name, well file number, American petroleum institute number, location, depth of sample; and shall be
sent free of cost to the state core and sample library within thirty days after completion of drilling
operations.
The operator of any well drilled for the production of oil or gas, injection, disposal, storage
operations, or geological information in North Dakota, during the drilling of or immediately following the
completion of any well, shall inform the director of all intervals that are to be cored, or have been cored.
Unless specifically exempted by the director, all cores taken shall be preserved, placed in a standard
core box and the entire core forwarded to the state core and sample library, free of cost, within one
hundred eighty days after completion of drilling operations. The director may grant an extension of the
one hundred eighty-day time period for good reason. If an exemption is granted, the operator shall
advise the state geologist of the final disposition of the core.
This section does not prohibit the operator from taking such samples of the core as the operator
may desire for identification and testing. The operator shall furnish the state geologist with the results of
all identification and testing procedures within thirty days of the completion of such work. The state
geologist may grant an extension of the thirty-day time period for good reason.
The size of the standard envelopes, sample boxes, and core boxes shall be determined by the
director and indicated in the cores and samples letter.

History: Effective October 1, 1990; amended effective January 1, 2006; April 1, 2014; April 1, 2020;
April 1, 2022.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-39. Limiting gas-oil ratio.

In the event the commission has not set a limiting gas-oil ratio for a particular pool, the operator of
any well in such pool whose gas-oil ratio exceeds two thousand shall demonstrate to the director that
production from such well should not be restricted pending a hearing before the commission to
establish a limiting gas-oil ratio. The director may restrict production of any well with a gas-oil ratio
exceeding two thousand, until the commission can determine that restrictions are necessary to
conserve reservoir energy.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; January 1, 2006.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-39.1. Oil production limitation.

In the event the commission has not established spacing and special field rules for a particular oil
pool, oil production from any well completed therein shall be a maximum of two thousand barrels per
day until the commission issues a decision after hearing. The director shall have the authority to waive
production limitations for good cause, and for special tests.
History: Effective July 1, 1996.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-40. Gas-oil ratio test.

Each operator shall take a gas-oil ratio test within thirty days following the completion or
recompletion of an oil well. Each test shall be conducted using standard industry practices unless
otherwise specified by the director. The initial gas-oil ratio must be reported on the well completion or
recompletion report (form 6 or form provided by the commission). Subsequent gas-oil ratio tests must
be performed on producing wells when the producing pool appears to have reached bubble point. After
the discovery of a new pool, each operator shall make additional gas-oil ratio tests as directed by the
director or provided for in field rules. During tests each well shall be produced at a maximum efficient
rate. The director may shut in any well for failure to make such test until such time as a satisfactory test
can be made, or satisfactory explanation given. The results of all gas-oil ratio tests shall be submitted to
the director on form 9, which shall be accompanied by a statement that the data on form 9 is true and
correct.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000;
October 1, 2016; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-41. Subsurface pressure tests.

The operator shall make a subsurface pressure test on the discovery well of any new pool hereafter
discovered and shall report the results thereof to the director within thirty days after the completion of
such discovery well. Drill stem test pressures are acceptable. After the discovery of a new pool, each
operator shall make additional subsurface pressure tests as directed by the director or provided for in
field rules. All tests shall be made by a person qualified by both training and experience to make such
tests and with an approved subsurface pressure instrument. All wells must remain completely shut in
for at least forty-eight hours prior to the test. The subsurface determination must be obtained as close

as possible to the top of the formation containing the productive interval of the reservoir. The report of
the reservoir pressure test shall be filed on form 9a.
The director may shut in any well for failure to make such test as herein above described until such
time as a satisfactory test has been made or satisfactory explanation given.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; April 1,
2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-42. Commingling of oil from pools.

Except as directed by the commission after hearing, each pool shall be produced as a single
common reservoir without commingling in the well bore of fluids from different pools. After fluids from
different pools have been brought to surface, such fluids may be commingled provided that the amount
of production from each pool is determined by a method approved by the director.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-43. Control of multiply completed wells.

Repealed effective January 1, 1983.
### § 43-02-03-44. Metered casinghead gas.

All casinghead gas produced must be reported monthly to the director in units of one thousand
cubic feet [28.32 cubic meters] computed at a pressure of fourteen and seventy-three hundredths
pounds per square inch absolute [1034.19 grams per square centimeter] at a base temperature of sixty
degrees Fahrenheit [15.56 degrees Celsius]. Associated gas production may not be transported from a
well premises or central production facility until its volume has been determined through the use of
properly calibrated measurement equipment. All measurement equipment and volume determinations
must conform to American gas association standards. The operator of a well shall notify the director
within thirty days on a well sundry form of the connection date to a gas gathering system, the metering
equipment, transporter, and purchaser of the gas. Any gas produced and used on lease for fuel
purposes or flared may be estimated or measured and must be reported on a gas production report
(form 5b) in accordance with section 43-02-03-52.1. Meters used to determine the use on lease or
flared gas volumes must be installed and calibrated in accordance with American petroleum institute or
American gas association standards or to the meter manufacturer's recommendations.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; September 1,
2000; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-45. Vented casinghead gas.

Pending arrangements for disposition for some useful purpose, all vented casinghead gas shall be
burned. Each flare shall be equipped with an automatic ignitor or a continuous burning pilot, unless
waived by the director for good reason. The estimated volume of gas used and flared shall be reported
to the director on a gas production report (form 5b) on or before the fifth day of the second month
succeeding that in which gas is produced.

History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; September 1,
2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-46. Use of vacuum pumps.

Repealed effective January 1, 1983.
### § 43-02-03-47. Produced water.

Monthly water production from each well must be determined through the use of properly calibrated
meter measurements, tank measurements, or an alternate measurement method approved by the
director. This includes allocating water production back to individual wells on a monthly basis, provided
the method of volume determination and allocation procedure results in reasonably accurate production
volumes. Operators shall report monthly to the director the amount of water produced by each well on
form 5. The reports must be filed on or before the first day of the second month following that in which
production occurred.
History: Amended effective January 1, 1983; May 1, 1992; May 1, 1994; September 1, 2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-48. Measurement of oil.

Oil production may not be transported from a well premises, central production facility, treating
plant, or saltwater handling facility until its volume has been determined through the use of properly
calibrated meter measurements or tank measurements. All meter and tank measurements, and volume
determinations must conform to American petroleum institute standards and be corrected to a base
temperature of sixty degrees Fahrenheit [15.56 degrees Celsius] and fourteen and seventy-three
hundredths pounds per square inch absolute [1034.19 grams per square centimeter].
History: Amended effective April 30, 1981; March 1, 1982; January 1, 1983; May 1, 1992; May 1, 1994;
July 1, 1996; April 1, 2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-48.1. Central production facility - Commingling of production.

1. The director may approve requests to consolidate production equipment at a central location.
The applicant shall provide all information requested by the director. The director may impose
such terms and conditions as the director deems necessary.
2. Commingling of oil and gas production from two or more wells in a central production facility is
prohibited unless approved by the director. There are two types of central production facilities
in which production from two or more wells is commingled that may be approved by the
director.
a. A central production facility in which all production going into the facility has common
ownership. For purposes of this section, production with common ownership is defined
as production from wells that do not have diverse ownership.
b. A central production facility in which production going into the facility has diverse
ownership. For purposes of this section, production with diverse ownership is defined as
production from wells that are:

(1) In different drilling or spacing units; and
(2) Which have different mineral ownership.
3. The commingling of oil and gas production in a central production facility from two or more
wells having common ownership may be approved by the director provided the production
from each well can be accurately determined at reasonable intervals. Commingling of oil and
gas production in a central production facility from two or more wells having diverse ownership
may be approved by the director provided the production from each well is accurately metered
prior to commingling. Commingling of oil and gas production in a central production facility
from two or more wells having diverse ownership that is not metered prior to commingling may
only be approved by the commission after notice and hearing.
a. Common ownership central production facility. The application for permission to
commingle oil, gas, or both in a central production facility with common ownership must
be submitted on a facility sundry notice and shall include the following:
(1) A plat or map showing thereon the location of the central facility and the name, well
file number, and location of each well and flow lines from each well that will produce
into the facility.
(2) A schematic drawing of the facility which diagrams the testing, treating, routing, and
transferring of production. All pertinent items such as treaters, tanks, flow lines,
valves, meters, recycle pumps, etc., should be shown.
(3) An affidavit executed by a person who has knowledge indicating that common
ownership as defined above exists.
(4) An explanation of the procedures or method to be used to determine, accurately,
individual well production at periodic intervals. Such procedures or method shall be
performed at least once every three months.
(5) List of all allocation meters to be used and the meter type.
A copy of all tests are to be filed with the director on a central tank battery well test form
within thirty days after the tests are completed.
b. Diverse ownership central production facility. The application for permission to
commingle oil, gas, or both in a central production facility having diverse ownership must
be submitted on a facility sundry notice and shall include the following:
(1) A plat or map showing thereon the location of the central facility and the name, well
file number, and location of each well, and flow lines from each well that will produce
into the facility.
(2) A schematic drawing of the facility which diagrams the testing, treating, routing, and
transferring of production. All pertinent items such as treaters, tanks, flow lines,
valves, meters, recycle pumps, etc., should be shown.
(3) The name of the manufacturer, size, and type of meters to be used. The meters
must be proved at least once every three months and the results reported to the
director within thirty days following the completion of the test.
(4) An explanation of the procedures or method to be used to determine, accurately,
individual well production at periodic intervals. Such procedures or method shall be
performed monthly.

(5) List of all allocation meters to be used and the meter type.
A copy of all tests are to be filed with the director on a central tank battery well test form
within thirty days after the tests are completed.
4. The commingling of produced water in a central production facility from two or more wells may
be approved by the director provided the produced water production can be accurately
determined at reasonable intervals. The application for permission to commingle water in a
central production facility must be submitted on a facility sundry notice and shall include the
following:
a. A plat or map showing thereon the location of the central facility and the name, well file
number, and location of each well, and flow lines from each well that will produce into the
facility.
b. A schematic drawing of the facility which diagrams the testing, treating, routing, and
transferring of production. All pertinent items such as treaters, tanks, flow lines, valves,
meters, recycle pumps, etc., should be shown.
c. An affidavit executed by a person who has knowledge indicating that common ownership
as defined above exists; or an indication that it is not common ownership.
d. An explanation of the procedures or method to be used to determine, accurately,
individual well production at periodic intervals. Such procedures or method shall be
performed quarterly for common ownership and monthly for diverse ownership central
production facilities.
e. List of all allocation meters to be used and the meter type.
5. Any changes to a previously approved central production facility must be reported on a sundry
notice (form 4) and approved by the director.
History: Effective May 1, 1992; amended effective September 1, 2000; May 1, 2004; April 1, 2020,
April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-49. Oil production equipment, dikes, and seals.

Storage of oil in underground or partially buried tanks or containers is prohibited. Surface oil tanks
and production equipment must be devoid of leaks and constructed of materials resistant to the effects
of produced fluids or chemicals that may be contained therein. Unused tanks and production equipment
must be removed from the site or placed into service, within a reasonable time period, not to exceed
one year.
Dikes must be erected around oil tanks, flowthrough process vessels, and recycle pumps at any
new production facility prior to completing any well. Dikes must be erected and maintained around oil
tanks at all facilities unless a waiver is granted by the director. Dikes as well as the base material under
the dikes and within the diked area must be constructed of sufficiently impermeable material to provide
emergency containment. Dikes around oil tanks must be of sufficient dimension to contain the total
capacity of the largest tank plus one day's fluid production. Dikes around flowthrough process vessels
must be of sufficient dimension to contain the total capacity of the vessel. The required capacity of the
dike may be lowered by the director if the necessity therefor can be demonstrated to the director's
satisfaction.
Within one hundred eighty days from the date the operator is notified by the commission, a
perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed and maintained.

The berm must be constructed of sufficiently impermeable material to provide emergency containment
and to divert surface drainage away from the site around all storage facilities and production sites that
include storage tanks, have a daily throughput of more than one hundred barrels of fluid per day, and
include production equipment or load lines that are not contained within secondary containment dikes.
The director may consider an extension of time to implement these requirements if conditions prevent
timely construction, or a modification of these requirements if other factors are present that provide
sufficient protection from environmental impacts. Prior to removing any perimeter berm, the operator or
owner shall obtain approval by the director.
Numbered weather-resistant security seals shall be properly utilized on all oil access valves and
access points to secure the tank or battery of tanks.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; July 1,
2002; May 1, 2004; April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2018; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-50. Tank cleaning permit.

No tank bottom waste shall be removed from any tank used for the storage or sale of crude oil
without prior approval by the director. Verbal approval may be given. Prior approval to remove tank
bottom waste from tanks not used for the storage or sale of crude oil is not required.
Within thirty days of the removal of the tank bottom waste of any tank used for the storage or sale
of crude oil, the owner or operator shall submit a report (form 23) showing an accurate gauge of the
contents of the tank and the amount of merchantable oil determinable from a representative sample of
the tank bottom by the standard centrifugal test as prescribed by the American petroleum institute's
code for measuring, sampling, and testing crude oil.
Within thirty days of the removal of the tank bottom waste of any permanent tank not used for the
storage or sale of crude oil, the owner or operator shall submit a sundry notice (form 4) detailing the
cleaning operation.
All tank bottom waste must be disposed of in a manner authorized by the director and in
accordance with all applicable local, state, and federal laws and regulations. Nothing contained in this
section shall apply to reclaiming of pipeline break oil or the treating of tank bottoms at a pipeline station,
crude oil storage terminal, or refinery or to the treating by a gasoline plant operator of oil and other
catchings collected in traps and drips in the gas gathering lines connected to gasoline plants and in
scrubbers at such plants.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; September 1,
2000; May 1, 2004.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-51. Treating plant.

No treating plant may be constructed or site or access road construction commenced without
obtaining a permit from the commission after notice and hearing. A written application for a treating
plant permit shall state in detail the location, type, capacity of the plant contemplated, method of
processing proposed, and the plan of operation for all plant waste. The director shall give the county
auditor notice at least fifteen days prior to the hearing of any application in which a request for a
treating plant is received.
History: Amended effective January 1, 1983; May 1, 1990; May 1, 1992; September 1, 2000; April 1,
2012; April 1, 2014; April 1, 2020.
General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04
### § 43-02-03-51.1. Treating plant permit requirements.

1. The treating plant permit application must be submitted on form 1tp and shall include at least
the following information:
a. The name and address of the operator.
b. An accurate plat certified by a registered surveyor showing the location of the proposed
treating plant and the center of the site with reference to true north and the nearest lines
of a governmental section. The plat shall also include the latitude and longitude of the
center of the proposed treating plant location to the nearest tenth of a second, and the
ground elevation. The plat shall also depict the outside perimeter of the treating plant and
verification that the site is at least five hundred feet [152.4 meters] from an occupied
dwelling.
c. A schematic drawing of the proposed treating plant site, drawn to scale, detailing all
facilities and equipment, including the size, location, and purpose of all tanks, the height
and location of all dikes, the location of all flow lines, and the location of the topsoil
stockpile. It shall also include the proposed road access to the nearest existing public
road and the authority to build such access.
d. Cut and fill diagrams.
e. An affidavit of mailing identifying each owner of any permanently occupied dwelling within
one-quarter mile of the proposed treating plant and certifying that such owner has been
notified of the proposed treating plant.
f. Appropriate geological data on the surface geology and its suitability for fluid
containment.
g. Schematic drawings of the proposed diking and containment, including calculated
containment volume and all areas underlain by a synthetic liner.
h. Monitoring plans and leak detection for all buried or partially buried structures and any
concrete structure upon which waste or product is in direct contact.
i. The capacity and operational capacity of the treating plant.
j. A narrative description of the process and how the waste and recovered product streams
travel through the treating plant.
k. A review of the surficial aquifers within one mile of the proposed treating plant site or
surface facilities.
l. Any other information required by the director to evaluate the proposed treating plant or
site.
2. Permits may contain such terms and conditions as the director deems necessary.
3. Any permit issued under this section may be revoked by the commission after notice and
hearing if the permittee fails to comply with the terms and conditions of the permit, any
directive of the director, or any applicable rule or statute. Any permit issued under this section
may be suspended by the director for good cause.
4. Permits are transferable only with approval of the director.

5. Permits may be modified by the director.
6. A permit must automatically expire one year after the date it was issued, unless dirtwork
operations have commenced to construct the site. The director may extend a treating plant
permit for up to one year upon request.
7. If the treating plant is abandoned and reclaimed, the permit must expire and be of no further
force and effect.
History: Effective April 1, 2014; amended effective October 1, 2016; April 1, 2020; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-51.2. Treating plant siting.

All treating plants shall be sited in such a fashion that they are not located in a geologically or
hydrologically sensitive area.
History: Effective April 1, 2014.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-51.3. Treating plant construction and operation requirements.

1. Before construction of a treating plant, treating plant site, or access road begins, the operator
shall file with the director a surety bond or cash bond conditioned upon compliance with all
laws, rules and regulations, and orders of the commission. The bond amount must be
specified in the commission order authorizing the treating plant and shall be based upon the
location, type, and capacity of the plant, processing method, and plan of operation for all plant
waste approved in the commission order and shall be payable to the industrial commission. In
no case may the bond amount be set lower than fifty thousand dollars.
2. Treating plant sites and associated facilities or appropriate parts thereof must be fenced if
required by the director. All fences installed within or around any facility must be constructed in
a manner that promotes emergency ingress and egress.
3. All storage tanks must be kept free of leaks and in good condition. Storage tanks for saltwater
must be constructed of, or lined with, materials resistant to the effects of saltwater. Open tanks
are allowed if approved by the director.
4. All waste, recovered solids, and recovered fluids must be stored and handled in such a
manner to prevent runoff or migration offsite.
5. Dikes of sufficient dimension to contain the total capacity of the maximum volume stored must
be erected and maintained around all storage and processing tanks. Dikes as well as the base
within the diked area must be lined with a synthetic impermeable liner to provide emergency
containment unless waived by the director. All processing equipment shall be underlain by a
synthetic impermeable material, unless waived by the director. The site must be sloped and
diked to divert surface drainage away from the site. The operations of the treating plant shall
be conducted in such a manner as to prevent leaks, spills, and fires. All discharged fluids and
wastes shall be promptly and properly removed and shall not be allowed to remain standing
within the diked area or on the treating plant premises. All such incidents must be properly
cleaned up, subject to approval by the director. All such reportable incidents must be promptly
reported to the director and a detailed account of any such incident must be filed with the
director in accordance with section 43-02-03-30.

6. A perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed of
sufficiently impermeable material to provide emergency containment around the treating plant
and to divert surface drainage away from the site if deemed necessary by the director.
7. Within thirty days following construction or modification of a treating plant, a sundry notice
(form 4) must be submitted detailing the work and the dates commenced and completed. The
sundry notice must be accompanied by a schematic drawing of the treating plant site drawn to
scale, detailing all facilities and equipment, including the size, location, and purpose of all
tanks; the height and location of all dikes as well as a calculated containment volume; all
areas underlain by a synthetic liner; any leak detection system installed; the location of all
flowlines; the stockpiled topsoil location and its volume; and the road access to the nearest
existing public road.
8. Immediately upon the commencement of treatment operations, the operator shall notify the
director in writing of such date.
9. The operator of a treating plant shall provide continuing surveillance and conduct such
monitoring and sampling as the director may require.
10. Storage pits, waste pits, or other earthen storage areas must be prohibited unless authorized
by an appropriate regulatory agency. A copy of said authorization must be filed with the
director.
11. Burial of waste at any treating plant site shall be prohibited. All residual water and waste, fluid
or solid, must be disposed of in an authorized facility.
12. The operator shall take steps to minimize the amount of residual waste generated and the
amount of residual waste temporarily stored onsite. Solid waste shall not be stockpiled onsite
unless authorized by an appropriate regulatory agency. A copy of said authorization shall be
filed with the director.
13. If deemed necessary by the director, the operator shall cause to be analyzed any waste
substance contained onsite. Such chemical analysis shall be performed by a certified
laboratory and shall adequately determine if chemical constituents exist which would
categorize the waste as hazardous by department of environmental quality standards.
14. Treating plants must be constructed and operated so as not to endanger surface or
subsurface water supplies or cause degradation to surrounding lands and shall comply with
section 43-02-03-28 concerning fire hazards and proximity to occupied dwellings.
15. The beginning of month inventory, the amount of waste received and the source of such
waste, the volume of oil sold, the amount and disposition of water, the amount and disposition
of residue waste, fluid or solid, and the end of month inventory for each treating plant shall be
reported monthly on form 5p with the director on or before the first day of the second
succeeding month, regardless of the status of operations.
16. Records necessary to validate information submitted on form 5p must be maintained in North
Dakota.
17. All proposed changes to any treating plant must have prior approval by the director.
18. The operator shall comply with all applicable rules and orders of the commission. All rules in
this chapter governing oil well sites shall also apply to any treating plant site.
19. The operator shall immediately cease operations if so ordered by the director for failure to
comply with the statutes of North Dakota, commission rules or orders, or directives of the
director.

History: Effective April 1, 2014; amended effective October 1, 2016; April 1, 2018; April 1, 2020; April 1,
2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-51.4. Treating plant abandonment and reclamation requirements.

Notice of intention to abandon. The operator or the operator's agent shall file a notice of intention
(form 4) to abandon and obtain the approval of the director, prior to the commencement of reclamation
operations pursuant to section 43-02-03-34.1.
History: Effective April 1, 2014; amended effective April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-52. Report of oil production.

The operator of each well completed in any pool shall, on or before the first day of the second
month succeeding the month in which production occurs or could occur, file with the director the
amount of production made by each such well upon form 5 or approved computer sheets no larger than
eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both
the person responsible for the report and the person witnessing the signature. The printed name and
title of both the person signing the report and the person witnessing the signature shall be included.
Wells for which reports of production are not received by the close of business on said first day of the
month may be shut in for a period not to exceed thirty days. The director shall notify, by certified mail,
the operator and authorized transporter of the shut-in period for such wells. Any oil produced during
such shut-in period shall be deemed illegal oil and subject to the provisions of North Dakota Century
Code section 38-08-15.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; December 1, 1997;
September 1, 2000; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-52.1. Report of gas produced in association with oil.

The operator of each well completed in any pool shall, on or before the fifth day of the second
month succeeding the month in which production occurs or could occur, file with the director the
amount of gas produced by each such well upon form 5b or approved computer sheets no larger than
eight and one-half by eleven inches [21.59 by 27.94 centimeters]. The report shall be signed by both
the person responsible for the report and the person witnessing the signature. The printed name and
title of both the person signing the report and the person witnessing the signature shall be included.
Wells for which reports of production are not received by the close of business on said fifth day of the
month may be shut in for a period not to exceed thirty days. The director shall notify, by certified mail,
the operator and authorized transporter of the shut-in period for such wells. Any gas produced during
such shut-in period must be deemed illegal gas and subject to the provisions of North Dakota Century
Code section 38-08-15.
History: Effective May 1, 1992; amended effective December 1, 1997; September 1, 2000; October 1,
2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-53. Saltwater handling facilities.

1. A saltwater handling facility may not be constructed without obtaining a permit from the
director. Saltwater handling facilities in existence prior to October 1, 2016, which are not

currently bonded as an appurtenance to a well or treating plant, have ninety days from the
date notified by the director that a permit is required to submit the required information in order
for the director to approve such facility.
2. All saltwater liquids or brines produced with oil and natural gas shall be processed, stored,
and disposed of without pollution of freshwater supplies.
3. Underground injection of saltwater liquids and brines shall be in accordance with chapter
43-02-05.
4. The permitting and bonding requirements for a saltwater handling facility set forth in sections
43-02-03-53, 43-02-03-53.1, and 43-02-03-53.3 are not to be construed to be required if the
facility is bonded as a well or treating plant appurtenance. Such facilities will be considered in
the permit application for the well or treating plant.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; July 1,
2002; May 1, 2004; April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-53.1. Saltwater handling facility permit requirements.

1. A permit for construction of a saltwater handling facility, saltwater handling facility site, or
access road must be approved by the director prior to construction. The saltwater handling
facility permit application must be submitted on a facility sundry notice and include at least the
following information:
a. The name and address of the operator.
b. An accurate plat certified by a registered surveyor showing the location of the proposed
saltwater handling facility and the center of the site with reference to true north and the
nearest lines of a governmental section. The plat also must include the latitude and
longitude of the center of the proposed saltwater handling facility location to the nearest
tenth of a second and the ground elevation. The plat also must depict the outside
perimeter of the saltwater handling facility and verification that the site is at least five
hundred feet [152.4 meters] from an occupied dwelling.
c. A schematic drawing of the proposed saltwater handling facility site, drawn to scale,
detailing all facilities and equipment, including the size, location, and purpose of all tanks,
the height and location of all dikes, the location of all flow lines, and the location and
thickness of the stockpiled topsoil. The schematic drawing also must include the
proposed road access to the nearest existing public road and the authority to build such
access.
d. Cut and fill diagrams.
e. Schematic drawings of the proposed diking and containment, including calculated
containment volume and all areas underlain by a synthetic liner, as well as a description
of all containment construction material.
f. The anticipated daily throughput of the saltwater handling facility.
g. A review of the surficial aquifers within one mile of the proposed treating plant site or
surface facilities.
h. Any other information required by the director to evaluate the proposed saltwater
handling facility or site.

2. Permits may contain such terms and conditions as the director deems necessary.
3. Any permit issued under this section may be revoked by the commission after notice and
hearing if the permittee fails to comply with the terms and conditions of the permit, any
directive of the director, or any applicable rule or statute. Any permit issued under this section
may be suspended by the director for good cause.
4. Permits are transferable only with approval of the director.
5. Permits may be modified by the director.
6. A permit automatically expires one year after the date it was issued, unless dirtwork
operations have commenced to construct the site. The director may extend a saltwater
handling facility permit for up to one year upon request.
7. If the saltwater handling facility is abandoned and reclaimed, the permit expires and is of no
further force and effect.
History: Effective October 1, 2016; amended effective April 1, 2020; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-53.2. Saltwater handling facility siting.

All saltwater handling facilities must be sited in such a fashion that they are not located in a
geologically or hydrologically sensitive area.
History: Effective October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-53.3. Saltwater handling facility construction and operation requirements.

1. Bond requirement. Before construction of a saltwater handling facility, saltwater handling
facility site, or access road begins, the operator shall file with the director a surety bond or
cash bond conditioned upon compliance with all laws, rules and regulations, and orders of the
commission. The bond must be in the amount of fifty thousand dollars and must be payable to
the industrial commission. The commission, after notice and hearing, may require a higher
bond amount. Such additional amounts for bonds must be related to the economic value of
the facility and the expected cost of decommissioning and site reclamation, as determined by
the commission. The commission may refuse to accept a bond if the operator or surety
company has failed in the past to comply with all laws, rules and regulations, and orders of the
commission; if a civil or administrative action brought by the commission is pending against
the operator or surety company; or for other good cause.
2. Saltwater handling facility sites or appropriate parts thereof must be fenced if required by the
director. All fences installed within or around any facility must be constructed in a manner that
promotes emergency ingress and egress.
3. All waste, recovered solids, and fluids must be stored and handled in such a manner to
prevent runoff or migration offsite.
4. Surface tanks may not be underground or partially buried, must be devoid of leaks, and
constructed of, or lined with, materials resistant to the effects of produced saltwater liquids,
brines, or chemicals that may be contained therein. The above materials requirement may be
waived by the director for tanks presently in service and in good condition. Unused tanks and

equipment must be removed from the site or placed into service, within a reasonable time
period, not to exceed one year.
5. Dikes must be erected and maintained around saltwater tanks at any saltwater handling
facility. Dikes must be erected around saltwater tanks at any new facility prior to introducing
fluids. Dikes as well as the base material under the dikes and within the diked area must be
constructed of sufficiently impermeable material to provide emergency containment. Dikes
must be of sufficient dimension to contain the total capacity of the largest tank plus one day's
fluid throughput. The required capacity of the dike may be lowered by the director if the
necessity therefor can be demonstrated to the director's satisfaction. The operations of the
saltwater handling facility must be conducted in such a manner as to prevent leaks, spills, and
fires. Discharged liquids or brines must be properly removed and may not be allowed to
remain standing within or outside of any diked areas. All such incidents must be properly
cleaned up, subject to approval by the director. All such reportable incidents must be promptly
reported to the director and a detailed account of any such incident must be filed with the
director in accordance with section 43-02-03-30.
6. Within one hundred eighty days from the date the operator is notified by the commission, a
perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed of
sufficiently impermeable material to provide emergency containment around the facility and to
divert surface drainage away from the site. The director may consider an extension of time to
implement these requirements if conditions prevent timely construction or a modification of
these requirements if other factors are present that provide sufficient protection from
environmental impacts.
7. The operator shall take steps to minimize the amount of solids stored at the facility.
8. Within thirty days following construction or modification of a saltwater handling facility, a
sundry notice (form 4) must be submitted detailing the work and the dates commenced and
completed. The sundry notice must be accompanied by a schematic drawing of the saltwater
handling facility site drawn to scale, detailing all facilities and equipment, including the size,
location, and purpose of all tanks; the height and location of all dikes as well as a calculated
containment volume; all areas underlain by a synthetic liner; any leak detection system
installed; the location of all flowlines; the stockpiled topsoil location and its volume; and the
road access to the nearest existing public road.
9. Immediately upon the commissioning of the saltwater handling facility, the operator shall notify
the director in writing of such date.
10. The operator of a saltwater handling facility shall provide continuing surveillance and conduct
such monitoring and sampling as the director may require.
11. Storage pits, waste pits, or other earthen storage areas must be prohibited unless authorized
by an appropriate regulatory agency. A copy of said authorization must be filed with the
director.
12. Burial of waste at any saltwater handling facility site is prohibited. All residual water and waste,
fluid or solid, must be disposed of in an authorized facility.
13. If deemed necessary by the director, the operator shall cause to be analyzed any waste
substance contained onsite. Such chemical analysis must be performed by a certified
laboratory and must adequately determine if chemical constituents exist which would
categorize the waste as hazardous by department of environmental quality standards.

14. Saltwater handling facilities must be constructed and operated so as not to endanger surface
or subsurface water supplies or cause degradation to surrounding lands and must comply with
section 43-02-03-28 concerning fire hazards and proximity to occupied dwellings.
15. All proposed changes to any saltwater handling facility are subject to prior approval by the
director.
16. Any salable crude oil recovered from a saltwater handling facility must be reported on a form 5
17. The operator shall comply with all laws, rules and regulations, and orders of the commission.
All rules in this chapter governing oil well sites also apply to any saltwater handling facility site.
18. The operator shall immediately cease operations if so ordered by the director for the failure to
comply with the statutes of North Dakota, commission rules or orders, or directives of the
director.
History: Effective October 1, 2016; amended effective April 1, 2018; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-53.4. Saltwater handling facility abandonment and reclamation requirements.

Notice of intention to abandon. The operator or the operator's agent shall file a notice of intention
(form 4) to abandon and obtain the approval of the director, prior to the commencement of reclamation
operations pursuant to section 43-02-03-34.1.
History: Effective October 1, 2016; amended effective April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-54. Investigative powers.

Upon receipt of a written complaint from any surface owner or lessee, royalty owner, mineral owner,
local, state, or federal official, alleging a violation of the oil and gas conservation statutes or any rule,
regulation, or order of the commission, the director shall within a reasonable time reply in writing to the
person who submitted the complaint stating that an investigation of such complaint will be made or the
reason such investigation will not be made. The person who submitted the complaint may appeal the
decision of the director to the commission. The director may also conduct such investigations on the
director's own initiative or at the direction of the commission. If, after such investigation, the director
affirms that cause for complaint exists, the director shall report the results of the investigation to the
person who submitted the complaint, if any, to the person who was the subject of the complaint and to
the commission. The commission shall institute such legal proceedings as, in its discretion, it believes
are necessary to enjoin further violations.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; April 1, 2012.
General Authority: NDCC 38-08-04, 38-08-12
Law Implemented: NDCC 38-08-04, 38-08-12
### § 43-02-03-55. Abandonment of wells, treating plants, underground gathering pipelines, or

saltwater handling facilities - Suspension of drilling.
1. The removal of production equipment or the failure to produce oil or gas for one year
constitutes abandonment of the well. The removal of production equipment or the failure to
produce water from a source well for one year constitutes abandonment of the well. The
removal of injection equipment or the failure to use an injection well for one year constitutes
abandonment of the well. The removal of monitoring equipment from or the failure to use a

subsurface observation well for one year constitutes abandonment of the well. The failure to
plug a stratigraphic test hole within one year of reaching total depth constitutes abandonment
of the well. The removal of treating plant equipment or the failure to use a treating plant for
one year constitutes abandonment of the treating plant. The removal of saltwater handling
facility equipment or the failure to use a saltwater handling facility for one year constitutes
abandonment of the saltwater handling facility. An abandoned well must be plugged and its
site must be reclaimed, an abandoned treating plant must be removed and its site must be
reclaimed, and an abandoned saltwater handling facility must be removed and its site must be
reclaimed, pursuant to sections 43-02-03-34 and 43-02-03-34.1. A well not producing oil or
natural gas in paying quantities for one year may be placed in abandoned-well status pursuant
to subsection 1 of North Dakota Century Code section 38-08-04. If an injection well is inactive
for extended periods of time, the commission may, after notice and hearing, require the
injection well to be plugged and abandoned. If an underground gathering pipeline is inactive
for seven years, the commission may, after notice and hearing, require the pipeline to be
properly abandoned pursuant to sections 43-02-03-29 and 43-02-03-29.1.
2. The director may waive for one year the requirement to plug and reclaim an abandoned well
by giving the well temporarily abandoned status for good cause. If a well is given temporarily
abandoned status, the well's perforations must be isolated, the integrity of its casing must be
proven, and its casing must be sealed at the surface, all in a manner approved by the director.
The director may extend a well's temporarily abandoned status and each extension may be
approved for up to one year. A fee of one hundred dollars shall be submitted for each
application to extend the temporary abandonment status of any well. A surface owner may
request a hearing to review a well temporarily abandoned for at least seven years pursuant to
subsection 1 of North Dakota Century Code section 38-08-04. Temporarily abandoned status
for oil and gas wells may be given only to wells that are to be used for purposes related to the
production of oil and gas within the next seven years.
3. The director may approve an oil well for enhanced oil recovery potential status if the subject oil
well was completed with surface casing set and cemented to properly isolate the Fox Hills
formation, additional strings of casing are properly cemented to adequately protect and isolate
all formations containing water, oil, or gas or any combination of these, protect the pipe
through salt sections encountered, and isolate the uppermost sand of the Dakota group, and
the director has deemed the subject well to have a potential use in an enhanced oil recovery
project. If a well is given enhanced oil recovery potential status, the well's perforations must be
isolated, the integrity of its casing must be proven, and its casing must be sealed at the
surface, all in a manner approved by the director. A surface owner may request a hearing to
review a well that has been on enhanced oil recovery potential status for at least twelve years,
pursuant to subsection 1 of North Dakota Century Code section 38-08-04.
4. In addition to the waiver in subsection 2, the director may also waive the duty to plug and
reclaim an abandoned well for any other good cause found by the director. If the director
exercises this discretion, the director shall set a date or circumstance upon which the waiver
expires.
5. The director may approve suspension of the drilling of a well. If suspension is approved, a
plug must be placed at the top of the casing to prevent any foreign matter from getting into the
well. When drilling has been suspended for thirty days, the well, unless otherwise authorized
by the director, must be plugged and its site reclaimed pursuant to sections 43-02-03-34 and
43-02-03-34.1.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; August 1,
1999; January 1, 2008; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2018; April 1,
2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04
### § 43-02-03-56. Underground disposal of water.

Repealed effective November 1, 1982.
### § 43-02-03-57. Determination of gas well potential.

After the completion or recompletion of a gas well, the operator shall conduct tests to determine the
daily open flow potential of the well. The test results together with an analyses of the gas shall be
reported to the director within thirty days after completion of the well.
Operators shall conduct either a stabilized one-point back-pressure test or a multipoint
back-pressure test in accordance with the "Manual of Back-Pressure Testing of Gas Wells" published
by the interstate oil and gas compact commission unless otherwise approved by the director.
History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-58. Method and time of shut-in pressure tests.

Repealed effective January 1, 1983.
### § 43-02-03-59. Production from gas wells to be measured and reported.

Gas production may not be transported from gas well premises until its volume has been
determined through the use of properly calibrated measurement equipment. All measurement
equipment and volume determinations must conform to American gas association standards and
corrected to a pressure of fourteen and seventy-three hundredths pounds per square inch absolute
[1034.19 grams per square centimeter] at a base temperature of sixty degrees Fahrenheit [15.56
degrees Celsius]. Gas production reports (form 5b) shall be filed with the director on or before the fifth
day of the second month succeeding that in which production occurs.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; May 1, 1994; July 1, 1996;
September 1, 2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-60. Natural gas utilization.

Repealed effective January 1, 1983.
### § 43-02-03-60.1. Valuation of flared gas.

The value of gas flared from an oil well in violation of North Dakota Century Code section
History: Effective October 1, 1990; amended effective May 1, 1992; May 1, 1994; May 1, 2004.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-06.4
### § 43-02-03-60.2. Flaring exemption.

The connection of a well to a natural gas gathering line is "economically infeasible" under North
Dakota Century Code section 38-08-06.4, if the direct costs of connecting the well to the line and the

direct costs of operating the facilities connecting the well to the line during the life of the well, are
greater than the amount of money the operator is likely to receive for the gas, less production taxes and
royalties, should the well be connected. In making this calculation, the applicant may add ten percent to
the amount of the cost of connecting the well and of operating the connection facilities used to
determine whether a connection is economically infeasible. This ten percent may be added in
consideration of the cost of money and other overhead costs that are not figured in the direct costs of
connecting the well and operating the connecting facilities.
An applicant for an exemption under North Dakota Century Code section 38-08-06.4 must, at the
minimum, present evidence covering the following areas:
1. Basis for the gas price used to determine whether it is economically infeasible to connect the
well to a natural gas gathering line;
2. Cost of connecting the well to the line and operating the facilities connecting the well to the
line;
3. Current daily rate of the amount of gas flared;
4. The amount of gas reserves and the amount of gas available for sale;
5. Documentation that it is economically infeasible to equip the well with an electrical generator
to produce electricity from gas; and
6. Documentation that it is economically infeasible to equip the well with a system that intakes
seventy-five percent of the gas and natural gas liquids volume from the well for beneficial
consumption by means of compression to liquid for use as fuel, transport to a processing
facility, production of petrochemicals or fertilizer, conversion to liquid fuels, and separating and
collecting over fifty percent of the propane and heavier hydrocarbons.
History: Effective May 1, 1994; amended effective April 1, 2014.
General Authority: NDCC 38-07-04
Law Implemented: NDCC 38-08-06.4
### § 43-02-03-60.3. Application to certify well for temporary gas tax exemption.

Any operator desiring to certify a well for purposes of eligibility for the gas tax incentive provided in
North Dakota Century Code chapter 57-51 shall submit to the director an application for certification as
an oil or gas well employing a system to avoid flaring. The operator has the burden of establishing
entitlement to certification and shall submit all data necessary to enable the commission to determine
whether a well is entitled to the tax exemption.
An application for a temporary gas tax exemption under North Dakota Century Code chapter 57-51
must, at the minimum, include the following information:
1. Name and address of the applicant and name and address of the person operating the well, if
different.
2. Name and number of the well and the legal description of the location of the well for which a
certification is requested.
3. If gas is collected and used at a well or facility site to power an electrical generator, the
following information must be included:
a. Name and manufacturer of the electrical generator.
b. Date electrical generation commenced.

c. Volume of gas consumed by the electrical generator during a minimum seven-day test
period and the volume of gas produced by the well during such test period.
4. If gas is collected at a well or facility site by a system that compresses gas and natural gas
liquids for beneficial consumption, the following information must be included:
a. Name and manufacturer of the compression equipment.
b. Date compression commenced.
c. Destination of the compressed products (i.e., fuel use, processing facility, fertilizer plant,
etc.).
d. Volume of gas compressed during a minimum seven-day test period and the amount of
gas produced by the well during such test period.
e. Analysis of a representative gas sample produced from the well.
5. If gas is collected at a well or facility site for a value-added process that will reduce the volume
or intensity of a flare by more than sixty percent, the following information must be included:
a. Name and manufacturer of the process equipment.
b. Date processing commenced.
c. Volume of gas processed during a minimum seven-day test period and the amount of
gas produced by the well during such test period.
d. Analysis of a representative gas sample produced from the well, detailing the Btu value
of the unprocessed gas and volume or mass as well as Btu value of each component
removed from the flared gas stream for value added use.
If the application does not contain sufficient information to make a determination, the director may
require the applicant to submit additional information.
History: Effective April 1, 2014.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04, 57-51-02.6
### § 43-02-03-61. Storage gas.

With the exception of the requirement to meter and report monthly the amount of gas injected and
the amount of gas withdrawn from storage, in the absence of waste, this chapter shall not apply to gas
being injected into or removed from storage.
History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-62. Carbon dioxide, coal bed methane, helium, and nitrogen.

Insofar as is applicable, the provisions of this chapter relating to gas, gas wells, and gas reservoirs
shall also apply to carbon dioxide, coal bed methane, helium, nitrogen, carbon dioxide wells, coal bed
methane wells, helium wells, nitrogen wells, carbon dioxide reservoirs, coal bed methane reservoirs,
helium reservoirs, and nitrogen reservoirs.
History: Amended effective January 1, 1983; September 1, 1987; July 1, 2002.
General Authority: NDCC 38-08-04

Law Implemented: NDCC 38-08-04
### § 43-02-03-63. Regulation of pools.

To prevent waste and to protect correlative rights, when the commission finds that total production
in an area significantly exceeds the reasonable market demand and undue marketing discrimination is
occurring, the commission may prorate or distribute the allowable production among proration units
upon a reasonable basis through rules, regulations, or orders pertaining to any pool or area after notice
and hearing.
History: Amended effective January 1, 1983; January 1, 2008.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-64. Rate of producing wells.

In allocated oil and gas pools the owner or operator of any proration unit shall not produce from the
unit during any proration period more oil or gas than the allowable production from such unit as shown
by the proration schedule, provided that such owners or operators shall be permitted to maintain a
uniform rate of production for each unit during the proration period. In order to maintain a uniform rate
of production from the pool during any proration period, any operator may produce a total volume of oil
and gas equal to that shown on the applicable proration schedule plus five days unit allowable, and any
such overproduction may be deducted from the total allowable for the well in the second month
following.
Where the commission has established spacing rules in any pool, proration units shall consist of
spacing units.
History: Amended effective January 1, 1983; September 1, 2000; January 1, 2008; April 1, 2008.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-65. Authorization for production, purchase, and transportation.

When necessary the commission shall hold a hearing to set proration unit allowables for the state.
The commission shall consider all evidence of market demand for oil and gas, including sworn
statements of individual demand as submitted by each purchaser or buyer in the state, and determine
the amount to be produced from all pools. The amount so determined will be allocated among the
various pools in accordance with existing regulations and in each pool in accordance with regulations
governing each pool. In allocated pools, effective the first day of each proration period, the commission
will issue a proration schedule which will authorize the production of oil and gas from the various units
in strict accordance with the schedule, and the purchase and transportation of such production.
Allowable for wells completed after the first day of the proration period will become effective from the
date of well completion. A supplementary order will be issued by the commission to the operator of a
newly completed or recompleted well, and to the purchaser or transporter of the production from a
newly completed or recompleted well, establishing the effective date of completion, the amount of
production permitted during the remainder of the proration period, and the authority to purchase and
transport same from said proration unit.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1,
2008.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06

### § 43-02-03-66. Application for allowable on new oil wells.

No well shall be placed on the proration schedule until a completion report (form 6 or form provided
by the commission) has been filed with the director.
The discovery well of any pool hereafter discovered shall be allowed to produce at a maximum
efficient rate until such time as proper spacing is set for the pool, and shall produce thereafter, only
pursuant to the general proration rules and regulations of the commission.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000;
January 1, 2008; April 1, 2020.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-67. Oil proration.

At the beginning of each calendar month, the distribution or proration to the respective proration
units shall be changed in order to take into account all new wells which have been completed and were
not in the proration schedule during the previous calendar month. Where any well is completed
between the first and last day of the calendar month, its proration unit shall be assigned an allowable
beginning at seven a.m., on the date of completion and for the remainder of that calendar month.
History: Amended effective January 1, 1983; January 1, 2008.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-68. Gas-oil ratio limitation.

In allocated pools containing a well or wells producing from a reservoir which contains both oil and
gas, each proration unit shall be permitted to produce only that volume of gas equivalent to the
applicable limiting gas-oil ratio multiplied by the proration unit oil allowable currently assigned to the
pool. In the event the commission has not set a gas-oil ratio limit for a particular oil pool, the limiting
gas-oil ratio shall be two thousand cubic feet [56.63 cubic meters] of gas for each barrel of oil
produced.
A gas-oil limit shall be placed on all allocated oil pools, and all proration units having a gas-oil ratio
exceeding the limit for the pool shall be adjusted unless previously exempted by the commission after
hearing, in accordance with the following formula:
1. Any proration unit which, on the basis of the latest official gas-oil ratio test has a gas-oil ratio in
excess of the limiting gas-oil ratio for the pool in which it is located, shall be permitted to
produce that number of barrels of oil which shall be determined by multiplying the proration
unit allowable by the fraction, the numerator of which shall be the limiting gas-oil ratio for the
pool and the denominator of which shall be the official gas-oil ratio test of the well.
2. Any unit containing a well or wells producing from a reservoir which contains both oil and gas
shall be permitted to produce only that volume of gas equivalent to the applicable limiting
gas-oil ratio multiplied by the proration unit allowable currently assigned to the pool.
All proration units to which gas-oil ratio adjustments are applied shall be so indicated in the
proration schedule with adjusted allowables stated. The adjustment shall be made effective on the first
day of the month following that in which the gas-oil ratio tests were reported for the pool, as set forth in
the special field rules applicable to the pool.
In cases of new pools the limiting gas-oil ratio shall be two thousand cubic feet [56.63 cubic meters]
per barrel until such time as changed by the commission after a hearing. After notice and hearing, the

commission shall determine or redetermine, the specific gas-oil ratio limit which is applicable to a
particular allocated oil pool.
History: Amended effective January 1, 1983; January 1, 2008.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-69. Allocation of gas production.

When the commission determines that allocation of gas production in a designated gas pool is
necessary to prevent waste, and to protect correlative rights, the commission, after notice and hearing,
shall consider the nominations of purchasers from that gas pool and other relevant data, and shall fix
the allowable production of that pool, and shall allocate production among the proration units in the pool
delivering to a gas transportation facility upon a reasonable basis.
The commission shall include in the proration schedule of such pool any proration unit which it finds
is being unreasonably discriminated against through denial of access to a gas transportation facility
which is reasonably capable of handling the type of gas producible from such proration unit.
History: Amended effective January 1, 1983; January 1, 2008.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-70. Gas proration period.

The gas proration period shall be set by order of the commission.
History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-71. Adjustment of gas allowables.

When the actual market demand from any allocated gas pool during a proration period is more than
or less than the allowable set by the commission for the pool for the period, the commission shall adjust
the gas proration unit allowables for the pool for the next proration period so that each gas proration
unit shall have a reasonable opportunity to produce its fair share of the gas production from the pool in
a manner that shall protect correlative rights.
History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-72. Gas proration units.

Before issuing a proration schedule for an allocated gas pool, the commission, after notice and
hearing, shall fix the gas proration unit for that pool.
General Authority: NDCC 38-08-04, 38-08-06
Law Implemented: NDCC 38-08-04, 38-08-06
### § 43-02-03-73. Permit for injection of gas, air, or water.

Repealed effective November 1, 1982.

### § 43-02-03-74. Casing and cementing of injection wells.

Repealed effective November 1, 1982.
### § 43-02-03-75. Notice of commencement and discontinuance of injection operations.

Repealed effective November 1, 1982.
### § 43-02-03-76. Records.

Repealed effective November 1, 1982.
### § 43-02-03-77. Application for unitized management under commission order.

Any plan of unitized management or any injection into a reservoir for the purpose of maintaining
reservoir pressure or for enhanced recovery operations shall be permitted only by order of the
commission after notice and hearing. The application for an order shall include a complete statement of
all matters required by North Dakota Century Code section 38-08-09 et seq.
The application shall be submitted to the commission, in duplicate, at least forty-five days prior to
the date requested for such hearings and shall be accompanied by all engineering, geological, and
other technical exhibits which will be introduced at the hearing.
In addition, the application shall set forth that all the provisions of North Dakota Century Code
section 38-08-09.5 have been complied with.
History: Amended effective November 1, 1982; January 1, 1983; May 1, 1992.
General Authority: NDCC 38-08-09
Law Implemented: NDCC 38-08-09
### § 43-02-03-78. Illegal sale prohibited.

Repealed effective January 1, 1983.
### § 43-02-03-79. Purchase of liquids from gas wells.

Provided that a supplemental order is issued authorizing such production on the proration
schedule, any common purchaser is authorized to purchase one hundred percent of the amount of
associated crude oil or condensate produced and recovered from a gas proration unit.
History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-06
Law Implemented: NDCC 38-08-06
### § 43-02-03-80. Reports of purchasers and transporters of crude oil.

On or before the first day of the second month succeeding that in which oil is removed, purchasers
and transporters, including truckers, shall file with the director the appropriate monthly reporting forms.
The purchaser shall file on form 10 and the transporter on form 10a the amount of all crude oil removed
and purchased by them from each well, central production facility, treating plant, or saltwater handling
facility during the reported month. The transporter shall report the disposition of such crude oil on
form 10b. All meter and tank measurements, and volume determinations of crude oil removed and
purchased from a well or central production facility must conform to American petroleum institute
standards and corrected to a base temperature of sixty degrees Fahrenheit [15.56 degrees Celsius]

and fourteen and seventy-three hundredths pounds per square inch absolute [1034.19 grams per
square centimeter].
Prior to removing any oil, purchasers and transporters shall obtain an approved copy of a
producer's authorization to purchase and transport oil (form 8) from either the producer or the director.
The operator of any oil rail facility shall report the amount of oil received and shipped out of such
facility on form 10rr.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; May 1, 1994;
July 1, 1996; September 1, 2000; April 1, 2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-81. Authorization to transport oil from a well, treating plant, central production

facility, or saltwater handling facility.
Before any crude oil is transported from a well, treating plant, central production facility, or saltwater
handling facility, the operator shall file with the director, and obtain the director's approval, an
authorization to purchase and transport oil (form 8).
Oil transported before the authorization is obtained or if such authorization has been revoked shall
be considered illegal oil.
The director may revoke the authorization to purchase and transport oil for failure to comply with
any rule, regulation, or order of the commission.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; September 1,
2000; April 1, 2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-81.1. Reports of purchases for resale and transporting of dry gas.

Transporters of and purchasers for the resale of dry gas shall file a report (form 8a) with the
director showing the amount of gas taken from each plant or well during the monthly reporting period.
All gas shall be reported monthly to the director in one thousand cubic feet [28.32 cubic meters]
computed at a pressure of fourteen and seventy-three hundredths pounds per square inch [1034.19
grams per square centimeter] absolute at a base temperature of sixty degrees Fahrenheit [15.56
degrees Celsius].
History: Effective January 1, 1983; amended effective May 1, 1992; July 1, 1996.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-82. Refinery reports.

Each refiner of oil within North Dakota shall furnish for each calendar month a report (form 13)
containing information and data respecting crude oil and products involved in such refiner's operations
during each month. The report for each month shall be prepared and filed on or before the fifteenth of
the next succeeding month with the director.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04

### § 43-02-03-83. Gas processing plant reports.

Each operator of a gas processing plant, cycling plant, or any other plant at which gas processing,
gasoline, butane, propane, condensate, kerosene, oil, or other products are extracted from gas shall
furnish to the director a report containing the amount of gas received from each lease or well on form
12a.
Crude oil recovered shall be reported to the director, on form 5 on or before the close of business
on the first day of the second month succeeding that in which oil is removed. Other operations shall be
reported to the director, on form 12 and 12a, on or before the fifth day of the second month following
that in which gas is processed.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-84. Additional information may be required.

This chapter shall not be taken or construed to limit or restrict the authority of the commission to
require the furnishing of such additional reports, data, or other information relative to production,
transportation, storing, refining, processing, or handling of crude oil, gas, or products as may appear to
be necessary or desirable, either generally or specifically, for the prevention of waste, protection of
correlative rights, and the conservation of natural resources.
History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-85. Books and records to be kept to substantiate reports.

All producers, transporters, storers, refiners, gasoline or extraction plant operators, and initial
purchasers within North Dakota shall make and keep appropriate books and records for a period not
less than six years, covering their operations in North Dakota from which they may be able to make and
substantiate the reports required by this chapter.
History: Amended effective January 1, 1983; July 1, 2002.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-86. Public hearing required.

Repealed effective January 1, 1983.
### § 43-02-03-87. Institute proceedings.

Repealed effective January 1, 1983.
### § 43-02-03-88. Application for hearing.

In any proceeding instituted upon application, the application shall be signed by the applicant or by
the applicant's attorney. An application shall state (1) the name and general description of the common
source or sources of supply affected by the order, rule, or regulation sought if any, unless same is
intended to apply to and affect the entire state, in which event the application shall so state, and such
statement shall constitute sufficient description; and (2) briefly the general nature of the order, rule, or
regulation sought in the proceedings.

History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-11
Law Implemented: NDCC 38-08-11
### § 43-02-03-88.1. Special procedures for increased density wells, pooling, flaring exemption,

underground injection, commingling, converting mineral wells to freshwater wells, and central
tank battery or central production facilities applications.
1. Applications to amend field rules to allow additional wells on existing spacing units, for pooling
under North Dakota Century Code section 38-08-08, for a flaring exemption under North
Dakota Century Code section 38-08-06.4 and section 43-02-03-60.2, for underground
injection under chapter 43-02-05, for commingling in one well bore the fluids from two or more
pools under section 43-02-03-42, for converting a mineral well to a freshwater well under
section 43-02-03-35, and for establishing central tank batteries or central production facilities
under section 43-02-03-48.1, must be signed by the applicant or the applicant's
representative. The application must contain or refer to attachments that contain all the
information required by law as well as the information the applicant wants the commission to
consider in deciding whether to grant the application. The application must designate an
employee or representative of the applicant to whom the commission can direct inquiries
regarding the application.
2. The commission shall give the county auditor notice at least fifteen days prior to the hearing of
any application in which a request for a disposal under chapter 43-02-05 is received.
3. The applications referred to in subsection 1 will be advertised and scheduled for hearing as
are all other applications received by the commission. The applicant, however, unless required
by the director, need not appear at the hearing scheduled to consider the application, although
additional evidence may be submitted prior to the hearing. Any interested party may appear at
the hearing to oppose or comment on the application. Any interested party may also submit
written comments on or objections to the application prior to the hearing date. Such
submissions must be received no later than five p.m. on the last business day prior to the
hearing date and may be part of the record in the case if allowed by the hearing examiner.
4. The director is authorized, on behalf of the commission, to grant or deny the applications
referred to in subsection 1.
5. In any proceeding under this section, the applicant, at the hearing, may supplement the record
by offering testimony and exhibits in support of the application.
6. In the event the applicant is not required by the director to appear at the hearing and an
interested party does appear to oppose the application or submits a written objection to the
application, the hearing examiner shall continue the hearing to a later date, keep the record
open for the submission of additional evidence, or take any other action necessary to ensure
that the applicant, who does not appear at the hearing as the result of subsection 3, is
accorded due process.
History: Effective May 1, 1992; amended effective May 1, 1994; May 1, 2004; April 1, 2012; April 1,
2014; April 1, 2018; April 1, 2022.
General Authority: NDCC 38-08-04, 38-08-11
Law Implemented: NDCC 38-08-04, 38-08-08
### § 43-02-03-88.2. Hearing participants by telephone.

In any hearing, the commission may, at its option, allow telephonic communication of witnesses
and interested parties. The procedure shall be as follows:

1. Telephonic communication of an applicant's witness will only be considered if a written request
is made at least two business days prior to the hearing date.
2. Telephonic communication of an interested party will only be considered if said party notifies
the applicant and the commission in writing at least three business days prior to the hearing
date. Such notice shall include the subject hearing, the name and telephone number of the
interested party, and the name and telephone number of the interested party's attorney or
representative that will be present at the hearing.
3. In the event an objection to any party's telephonic communication is received, the examiner
may disallow such communication by telephone and may reschedule for an in-person hearing.
The commission will notify all parties whether or not the request to participate by telephone is
granted or denied.
4. All parties participating by telephone shall have an attorney or representative present at the
hearing who shall be responsible for actually calling said party once the case is called for
hearing, for providing the commission at the time of the hearing with any documentary
evidence requested to be included in the record, and for any other matters necessary for the
party to participate by telephone.
5. All parties participating by telephone shall file an affidavit verifying the identity of such party.
The record of such telephonic communication shall not be considered evidence in the case
unless said affidavit is received by the examiner prior to an order being issued by the
commission. The commission shall provide a form affidavit. The commission has the discretion
to refuse to consider all or any part of the information received from any party participating by
telephone.
6. For all hearings allowing communication by telephone, the commission shall provide a hearing
room equipped with a speaker telephone.
7. The cost of telephonic communication shall be paid by the party requesting its use.
History: Effective July 1, 2002; amended effective May 1, 2004.
General Authority: NDCC 38-08-11
Law Implemented: NDCC 28-32-11
### § 43-02-03-89. Upon application hearing is set.

Repealed effective January 1, 1983.
### § 43-02-03-90. Hearings - Complaint proceedings - Emergency proceedings - Other

proceedings.
1. Except as more specifically provided in North Dakota Century Code section 38-08-11, the
rules of procedure established in subsection 1 of North Dakota Century Code section
2. For proceedings that do not involve a complaint and a specific-named respondent the
commission shall give at least fifteen days' notice (except in emergency) of the time and place
of hearing thereon by one publication of such notice in a newspaper of general circulation in
Bismarck, North Dakota, and in a newspaper of general circulation in the county where the
land affected or some part thereof is situated, unless in some particular proceeding a longer
period of time or a different method of publication is required by law, in which event such
period of time and method of publication shall prevail. The notice shall issue in the name of
the commission and shall conform to the other requirements provided by law.

3. In case an emergency is found to exist by the commission which in its judgment requires the
making of a rule or order without first having a hearing, the emergency rule or order shall have
the same validity as if a hearing with respect to the same had been held after notice. The
emergency rule or order permitted by this section shall remain in force no longer than forty
days from its effective date, and in any event, it shall expire when the rule or order made after
due notice and hearing with respect to the subject matter of such emergency rule or order
becomes effective.
Any person moving for a continuance of a hearing, and who is granted a continuance, shall submit a
twenty-five dollar fee to the commission, or if the cost of republication exceeds fifty dollars the
commission may bill the applicant, to pay the cost of republication of notice of the hearing.
History: Amended effective March 1, 1982; January 1, 1983; May 1, 1990; May 1, 1992; May 1, 1994;
July 1, 1996; July 1, 2002; October 1, 2016.
General Authority: NDCC 38-08-11
Law Implemented: NDCC 28-32-05, 38-08-11
### § 43-02-03-90.1. Investigatory hearings.

The commission may hold investigatory hearings upon the institution of a proceeding by application
or by motion of the commission. Notice of the hearing must be served upon all parties personally or by
certified mail at least five days before the hearing.
History: Effective May 1, 1992.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-90.2. Official record.

The evidence in each case heard by the commission, unless specifically excluded by the hearing
examiner, includes the certified directional surveys, and all oil, water, and gas production records, and
all injection records on file with the commission.
Any interested party may submit written comments on or objections to the application prior to the
hearing date. Such submissions must be received no later than five p.m. on the last business day prior
to the hearing date and may be part of the record in the case if allowed by the hearing examiner.
Settlement negotiations between parties to a contested case are only admissible as governed by North
Dakota Century Code section 28-32-24, although the hearing examiner may strike such testimony from
the record for good cause.
History: Effective May 1, 1992; amended effective April 1, 2010; April 1, 2012; October 1, 2016; April 1,
2022.
General Authority: NDCC 28-32-06
Law Implemented: NDCC 28-32-06
### § 43-02-03-90.3. Petitions for review of recommended order and oral arguments prohibited.

Neither petitions for review of a recommended order nor oral arguments following issuance of a
recommended order and pending issuance of a final order are allowed.
History: Effective May 1, 1992.
General Authority: NDCC 28-32-13
Law Implemented: NDCC 28-32-13

### § 43-02-03-90.4. Notice of order by mail.

The commission shall give notice of an order, and findings and conclusions upon which it is based,
to all parties pursuant to North Dakota Century Code section 38-08-11.
History: Effective May 1, 1992; amended effective April 1, 2022.
General Authority: NDCC 28-32-13
Law Implemented: NDCC 28-32-13
### § 43-02-03-90.5. Service and filing.

All pleadings, notices, written motions, requests, petitions, briefs, and correspondence to the
commission or commission employee from a party (or vice versa) relating to a proceeding after its
commencement, must be filed with the director and entered into the commission's official record of the
procedure provided the record is open at the time of receipt. All parties shall receive copies upon
request of any or all of the evidence in the record of the proceedings. The commission may charge for
the actual cost of providing copies of evidence in the record. Unless otherwise provided by law, filing
shall be complete when the material is entered into the record of the proceeding.
History: Effective May 1, 1992.
General Authority: NDCC 28-32-13
Law Implemented: NDCC 28-32-13
### § 43-02-03-91. Rehearing.

Repealed effective May 1, 1992.
### § 43-02-03-92. Burden of proof.

Repealed effective January 1, 1983.
### § 43-02-03-93. Designation of examiners.

The commission may by motion designate and appoint qualified individuals to serve as examiners.
The commission may refer any matter or proceeding to any legally designated and appointed examiner
or examiners.
History: Amended effective April 30, 1981; January 1, 1983.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-94. Matters to be heard by examiner.

Repealed effective January 1, 1983.
### § 43-02-03-95. Powers and duties of examiner.

The commission may by motion limit the powers and duties of any examiner in any particular case
to such issues or to the performance of such acts as the commission deems expedient; however,
subject only to such limitation as may be ordered by the commission, the examiner or examiners to
whom any matter or proceeding is referred under this chapter shall have full authority to hold hearings
on such matter or proceeding in accordance with and pursuant to this chapter. The examiner shall have
the power to regulate all proceedings before the examiner and to perform all acts and take all
measures necessary or proper for the efficient and orderly conduct of such hearing, including ruling on
prehearing motions, the swearing of witnesses, receiving of testimony and exhibits offered in evidence,

subject to such objections as may be imposed, and shall cause a complete record of the proceeding to
be made and retained.
History: Amended effective January 1, 1983; May 1, 1990.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-96. Matters heard by commission.

Repealed effective January 1, 1983.
### § 43-02-03-97. Examiner disinterested umpire.

Repealed effective January 1, 1983.
### § 43-02-03-98. Report of examiner.

Upon the conclusion of any hearing before an examiner, the examiner shall promptly consider the
proceedings in such hearing, and based upon the record of such hearing, the examiner shall prepare a
report and recommendations for the disposition of the matter or proceeding by the commission. Such
report and recommendations shall either be accompanied by a proposed order or shall be in the form of
a proposed order, and shall be submitted to the commission.
History: Amended effective January 1, 1983.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-99. Commission order from examiner hearing.

After receipt of the report and recommendations of the examiner, the commission shall enter its
order disposing of the matter or proceeding.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
### § 43-02-03-100. Hearing de novo before commission.

Repealed effective January 1, 1983.
### § 43-02-03-101. Prehearing motion practice.

In a matter pending before the commission, all prehearing motions must be served by the moving
party upon all parties affected by the motion. Service must be upon a party unless a party is
represented by an attorney, in which case service must be upon the attorney. Service must be made by
delivering a copy of the motion and all supporting papers in conformance with one of the means of
service provided for in rule 5(b) of the North Dakota Rules of Civil Procedure. Proof of service must be
made as provided in rule 4 of the North Dakota Rules of Civil Procedure or by the certificate of an
attorney showing that service has been made. Proof of service must accompany the filing of a motion.
Any motion filed without proof of service is not properly before the commission.
History: Effective May 1, 1990; amended effective January 1, 2006.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
