COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 1

DEPARTMENT OF NATURAL RESOURCES

Oil and Gas Conservation Commission Eff 09/30/2007

PRACTICE AND PROCEDURE Eff 09/30/2007

2 CCR 404-1 Eff 09/30/2007

[Editor’s Notes follow the text of the rules at the end of this CCR Document.] Eff 09/30/2007

100-SERIES DEFINITIONS

ACT shall mean the Oil and Gas Conservation Act of the State of Colorado. Eff 09/30/2007

ANCILLARY FACILITIES shall mean all of the equipment, buildings, structures, and improvements 

associated with or required for the operation of a well site, pipeline, or compressor facility. Ancillary 

facilities include, but are not limited to, roads, well pads, tank batteries, combustion equipment and pits 

and exclude gathering lines. 

APPLICANT shall mean the person who institutes a proceeding before the Commission which it has 

standing to institute under these rules. Eff 09/30/2007

AQUIFER shall mean a geologic formation, group of formations or part of a formation that can both store 

and transmit ground water. It includes both the saturated and unsaturated zone but does not include the 

confining layer which separates two (2) adjacent aquifers. Eff 09/30/2007

ASSEMBLY BUILDING shall mean any building or portion of building or structure used for the regular 

gathering of fifty (50) or more persons for such purposes as deliberation, education, instruction, worship, 

entertainment, amusement, drinking or dining, or awaiting transport.

AUTHORIZED DEPUTY shall mean a representative of the Director as authorized by the Commission.

BARREL shall mean 42 (U.S.) gallons at 60° F. at atmospheric pressure.

BATTERY shall mean the point of collection (tanks) and disbursement (tank, meter, lease automated 

custody transfer [LACT] unit) of oil or gas from producing well(s).

BEST MANAGEMENT PRACTICES (BMPs) are practices that are designed to prevent or reduce impacts 

caused by oil and gas operations to air, water, soil, or biological resources, and to prevent adverse 

impacts to public health, safety and welfare, including the environment and wildlife resources. 

BRADENHEAD TEST AREA shall mean any area designated as a bradenhead test area by the 

Commission under Rule 207.b.

BUILDING UNIT shall mean a building or structure intended for human occupancy. A dwelling unit is 

equal to one (1) building unit, every guest room in a hotel/motel is equal to one (1) building unit, and 

every five thousand (5.000) square feet of building floor area in commercial facilities, and every fifteen 

thousand (15,000) square feet of building floor area in warehouses, or other similar storage facilities, is 

equal to one (1) building unit.

CEASE AND DESIST ORDER shall mean an order issued by the Commission or the Director pursuant to 

C.R.S. §34-60-121(5).

CENTRALIZED E&P WASTE MANAGEMENT FACILITY shall mean a facility, other than a commercial 

disposal facility exclusively regulated by the Colorado Department of Public Health and Environment, that 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 2

is: (1) is either used exclusively by one owner or operator; or (2) used by more than one operator under 

an operating agreement; and (2) is operated for a period greater than three (3) years; and which (3) 

receives for collection, treatment, temporary storage, and/or disposal of produced water, drilling fluids, 

drill cuttings, completion fluids, and any other exempt E&P wastes that are generated from two or more 

production units or areas or from a set of commonly owned or operated leases. This definition includes 

the surface storage and disposal facilities that are present at Class II disposal well sites. This definition 

also includes oil-field naturally occurring radioactive materials (NORM) related storage, decontamination, 

treatment, or disposal. This definition excludes a facility that is permitted in accordance with Rule 903 

pursuant to Rule 902.e. 

CHEMICAL(S) shall mean any element, chemical compound, or mixture of elements and/or compounds. 

CHEMICAL INVENTORY shall mean a list of the Chemical Products (including Material Safety Data 

Sheets) brought to a well site for use downhole during drilling, completion, and workover operations,

including fracture stimulations, and the maximum capacity of fuel stored on the oil and gas location during 

those operations. The Chemical Inventory shall include how much of the Chemical Product was used, 

how it was used, and when it was used. 

CHEMICAL PRODUCT shall mean any substance consisting of one or more constituent chemicals that is 

marketed or sold as a commodity. Chemical Products shall not include substances that are known to be 

entirely benign, innocuous, or otherwise harmless, such as sand, walnut shells, and similar natural 

substances. 

CLASSIFIED WATER SUPPLY SEGMENT shall mean perennial or intermittent streams, which are 

surface waters classified as being suitable or intended to become suitable for potable water supplies by 

the Colorado Water Quality Control Commission, pursuant to the Basic Standards and Methodologies for 

Surface Water Regulations (5 C.C.R. 1002-31). 

COMMERCIAL DISPOSAL WELL FACILITY shall mean a facility whose primary objective is disposal of 

Class II waste from a third party for financial profit.

COMMISSION shall mean the Oil and Gas Conservation Commission of the State of Colorado.

COMPLETION. An oil well shall be considered completed when the first new oil is produced through 

wellhead equipment into lease tanks from the ultimate producing interval after the production string has 

been run. A gas well shall be considered completed when the well is capable of producing gas through 

wellhead equipment from the ultimate producing zone after the production string has been run. A dry hole 

shall be considered completed when all provisions of plugging are complied with as set out in these rules. 

Any well not previously defined as an oil or gas well, shall be considered completed ninety (90) days after 

reaching total depth. If approved by the Director, a well that requires extensive testing shall be considered 

completed when the drilling rig is released or six months after reaching total depth, whichever is later.

COMPLIANCE CHECKLIST shall mean a checklist of actions taken or on-site conditions that indicate 

compliance with specific regulatory requirements applicable to specific types of oil and gas facilities (e.g. 

drilling pads, pits, flowlines, etc.) or to specific types of oil and gas activities (e.g. closure, reclamation, 

spill response, etc.) developed by the Director. 

COMPREHENSIVE DRILLING PLAN shall mean a plan created by one or more operator(s) covering 

future oil and gas operations in a defined geographic area within a geologic basin. The Plan may (a) 

identify natural features of the geographic area, including vegetation, wildlife, and other attributes of the 

physical environment; (b) describe the operator’s future oil and gas operations in the area; (c) identify 

potential impacts from such activities; (d) develop agreed-upon measures to avoid, minimize, and mitigate 

the identified potential impacts; and (e) include other relevant information. 
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CONTAINER shall mean any portable device in which a hazardous material is stored, transported, 

treated, disposed of, or otherwise handled. 

CORNERING AND CONTIGUOUS UNITS when used in reference to an exception location shall mean 

those lands which make up the unit(s) immediately adjacent to and toward which a well is encroaching 

upon established setbacks.

CROP LAND shall mean lands which are cultivated, mechanically or manually harvested, or irrigated for 

vegetative agricultural production.

CUBIC FOOT of gas shall mean the volume of gas contained in one cubic foot of space at a standard 

pressure base and a standard temperature base. The standard pressure base shall be 14.73 psia, and 

the standard temperature base shall be 60° Fahrenheit.

D–J BASIN FOX HILLS PROTECTION AREA shall mean that area of the State consisting of Townships 5 

South through Townships 5 North, Ranges 58 West through 70 West, and Township 6 South, Ranges 65 

West through 70 West.

DAY shall mean a period of twenty-four (24) consecutive hours.

DEDICATED INJECTION WELL shall mean any well as defined under 40 C.F.R. §144.5 B, 1992 Edition, 

(adopted by the U.S. Environmental Protection Agency) used for the exclusive purpose of injecting fluids 

or gas from the surface. The definition of a dedicated injection well does not include gas storage wells.

DESIGNATED AGENT, when used herein shall mean the designated representative of any producer, 

operator, transporter, refiner, gasoline or other extraction plant operator, or initial purchaser.

DESIGNATED OUTSIDE ACTIVITY AREAS shall mean a well-defined outside area (such as a 

playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 

twenty (20) or more persons on at least forty (40) days in any twelve (12) month period or by at least five 

hundred (500) or more people on at least three (3) days in any twelve (12) month period.

DIRECTOR shall mean the Director of the Oil and Gas Conservation Commission of the State of 

Colorado or any member of the Director's staff authorized to represent the Director.

DOMESTIC GAS WELL shall mean a gas well that produces solely for the use of the surface owner. The 

gas produced cannot be sold, traded or bartered.

DRILLING PITS shall mean those pits used during drilling operations and initial completion of a well, and 

include:

ANCILLARY PITS used to contain fluids during drilling operations and initial completion 

procedures, such as circulation pits and water storage pits.

COMPLETION or FLOWBACK PITS used to contain fluids and solids produced during initial 

completion procedures, and not originally constructed for use in drilling operations.

RESERVE PITS used to store drilling fluids for use in drilling operations or to contain E&P waste 

generated during drilling operations and initial completion procedures.

EDUCATIONAL FACILITY shall mean any building used for legally allowed educational purposes for 

more than twelve (12) hours per week for more than six (6) persons. This includes any building or portion 

of building used for licensed day-care purposes for more than six (6) persons.

EMERGENCY ORDER shall mean an order issued by the Commission pursuant to C.R.S. §34-60-108(3).
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EMERGENCY SITUATION for purposes of C.R.S. §34-60-121(5) and the rules promulgated thereunder 

shall mean a fact situation which presents an immediate danger to public health, safety or welfare.

EXPLORATION AND PRODUCTION WASTE (E&P WASTE) shall mean those wastes associated with 

operations to locate or remove oil or gas from the ground or to remove impurities from such substances 

and which are uniquely associated with and intrinsic to oil and gas exploration, development, or 

production operations of whichthat are exempt from regulation under Subtitle C of the Resource 

Conservation and Recovery Act (RCRA), 42 USC Sections 6921, et seq. For a waste to be considered an 

E&P waste, it shall be associated with operations to locate or remove oil or gas from the ground or to 

remove impurities from such substances and it shall be intrinsic to and uniquely associated with oil and 

gas exploration, development or production. For natural gas, primary field operations include those 

production-related activities at or near the wellhead and at the gas plant (regardless of whether or not the 

gas plant is at or near the wellhead), but prior to transport of the natural gas from the gas plant to market. 

In addition, uniquely associated wastes derived from the production stream along the gas plant feeder 

pipelines are considered E&P wastes, even if a change of custody in the natural gas has occurred 

between the wellhead and the gas plant. In addition, wastes uniquely associated with the operations to 

recover natural gas from underground storage fields are considered to be E&P waste.

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

and “field” shall include the underground reservoir or reservoirs containing oil or gas or both. The words 

“field” and “pool” mean the same thing when only one underground reservoir is involved; however, “field”, 

unlike “pool”, may relate to two or more pools.

FINANCIAL ASSURANCE shall mean a surety bond, cash collateral, certificate of deposit, letter of credit, 

sinking fund, escrow account, lien on property, security interest, guarantee, or other instrument or method 

in favor of and acceptable to the Commission. With regard to third party liability concerns related to public 

health, safety and welfare, the term encompasses general liability insurance.

FIRST AID TREATMENT shall mean using a non-prescription medication at non-prescription strength; 

administering tetanus immunizations; cleaning, flushing, or soaking wounds on the surface of the skin; 

using wound coverings such as bandages, gauze pads, or butterfly bandages; using hot or cold therapy; 

using any non-rigid means of support such as elastic bandages; using temporary immobilization devices 

when transporting an accident victim; drilling of a fingernail or toenail to relieve pressure or draining fluid 

from a blister; using eye patches; removing foreign bodies from the eye using only irrigation or a cotton 

swab; removing splinters or foreign material from areas other than the eye by irrigation, tweezers, cotton 

swabs, or other simple means; using finger guards; using massages; or drinking fluids for the relief of 

heat stress. 

FLOWLINES shall mean those segments of pipe from the wellhead downstream through the production 

facilities ending at: Iin the case of gas lines, the gas metering equipment; or in the case of oil lines the oil 

loading point or LACT unit; or in the case of water lines, the water loading point, the point of discharge to 

a pit, or the injection wellhead, or the permitted surface water discharge point.

GAS FACILITY shall mean those facilities that process or compress natural gas after production-related 

activities which are conducted at or near the wellhead and prior to a point where the gas is transferred to 

a carrier for transport.

GAS STORAGE WELL means any well drilled for the injection, withdrawal, production, observation, 

and/or monitoring of natural gas stored in underground formations. The fact that any such well is used 

incidentally for the production of native gas or the enhanced recovery of native hydrocarbons shall not 

affect its status as a gas storage well.

GAS WELL shall mean a well, the principal production of which at the mouth of the well is gas, as defined 

by the Act.
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GATHERING LINE shall mean a pipeline and equipment described below that transports gas from a 

production facility (ordinarily commencing downstream of the final production separator at the inlet flange 

of the custody transfer meter) to a natural gas processing plant or transmission line or main. The term 

“gathering line” includes valves, metering equipment, communication equipment, cathodic protection 

facilities, and pig launchers and receivers, but does not include dehydrators, treaters, tanks, separators, 

or compressors located downstream of the final production facilities and upstream of the natural gas 

processing plants, transmission lines, or main lines. 

GREEN COMPLETION PRACTICES shall mean those practices intended to reduce emissions of salable 

gas and condensate vapors during cleanout and flowback operations prior to the well being placed on 

production. 

GROUNDWATER means subsurface waters in a zone of saturation.

HIGH DENSITY AREA shall mean any tract of land determined to be a high density area in accordance 

with Rule 603.b.

HOSPITAL, NURSING HOME, BOARD AND CARE FACILITIES shall mean buildings used for the 

licensed care of more than five (5) in-patients or residents.

INACTIVE WELL shall mean any shut-in well from which no production has been sold for a period of 

twelve (12) consecutive months; any well which has been temporarily abandoned for a period of six (6) 

consecutive months; or, any injection well which has not been utilized for a period of twelve (12) 

consecutive months.

INDIAN LANDS shall mean those lands located within the exterior boundaries of a defined Indian 

reservation, including allotted Indian lands, in which the legal, beneficial, or restricted ownership of the 

underlying oil, gas, or coal bed methane or of the right to explore for and develop the oil, gas, or coal bed 

methane belongs to or is leased from an Indian tribe.

INTERVENOR shall mean a local government, or the Colorado Department of Public Health and 

Environment intervening solely to raise environmental or public health, safety and welfare concerns, or 

the Colorado Division of Wildlife intervening solely to raise wildlife resource concerns, in which case the 

intervention shall be granted of right, or a person who has timely filed an intervention in a relevant 

proceeding and has demonstrated to the satisfaction of the Commission that the intervention will serve 

the public interest, in which case the person may be recognized as a permissive intervenor at the 

Commission's discretion.

JAIL shall mean those structures where the personal liberties of occupants are restrained, including but 

not limited to, mental hospitals, mental sanitariums, prisons, reformatories.

LACT (“Lease Automated Custody Transfer”) shall mean the transfer of produced crude oil or 

condensate, after processing or treating in the producing operations, from storage vessels or automated 

transfer facilities to pipelines or any other form of transportation. 

LAND APPLICATION shall mean the disposal method by which E&P waste is spread upon or sometimes 

mixed into soils.

LAND TREATMENT shall mean the treatment method by which E&P waste is applied to soils and treated 

to result in a reduction of hydrocarbon concentration by biodegradation and other natural attenuation 

processes. Land treatment may be enhanced by tilling, disking, aerating, composting and the addition of 

nutrients or microbes.
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LOCAL GOVERNMENT means a county, home rule or statutory city, town, territorial charter city or city 

and county, or any special district established pursuant to the Special District Act, C.R.S. §32-1-101 to 

32-1-1505.

LOCAL GOVERNMENTAL DESIGNEE means the office designated to receive, on behalf of the local 

government, copies of all documents required to be filed with the local governmental designee pursuant 

to these rules.

LOG or WELL LOG shall mean a systematic detailed record of formations encountered in the drilling of a 

well.

MATERIAL SAFETY DATA SHEET (MSDS) shall mean the most current version of written or printed 

material concerning a hazardous chemical. 

MEDICAL TREATMENT shall mean the management and care of a patient to combat a disease or 

disorder. An injury or illness is an abnormal condition or disorder. Injuries include cases such as, but not 

limited to, a cut, fracture, sprain, or amputation. Illnesses include both acute and chronic illnesses, such 

as, but not limited to, a skin disease, respiratory disorder, or poisoning. “Medical treatment” includes 

situations where a physician or other licensed health care professional recommends medical treatment 

but the employee does not follow the recommendation. “Medical treatment” does not include first aid 

treatment, as defined herein, visits to a physician or other licensed health care professional solely for 

observation or counseling, or the conduct of diagnostic procedures such as x-rays and blood tests, 

including the administration of prescription medications used solely for diagnostic purposes. 

MINIMIZE ADVERSE IMPACTS shall mean, wherever reasonably practicable, to avoid adverse impacts 

to wildlife resources or significant adverse impacts to the environment from oil and gas operations, 

minimize the extent and severity of those impacts that cannot be avoided, mitigate the effects of 

unavoidable remaining impacts, and take into consideration cost-effectiveness and technical feasibility 

with regard to actions and decisions taken to minimize adverse impacts. 

MINIMIZE EROSION shall mean implementing best management practices that are selected based on 

site-specific conditions and maintained to reduce erosion. Representative erosion control practices 

include, but are not limited to, revegetation of disturbed areas, mulching, berms, diversion dikes, surface 

roughening, slop drains, check dams, and other comparable measures. 

MITIGATION with respect to wildlife resources shall mean measures that compensate for adverse 

impacts to such resources, including, as appropriate, habitat enhancement, on-site habitat mitigation, offsite habitat mitigation, or mitigation banking. 

MULTI-WELL PITS shall mean pits used for treatment, storage, or disposal of E&P wastes generated 

from more than one (1) well that do not constitute a centralized E&P waste management facility.

MULTI-WELL SITE shall mean a common well pad from which multiple wells may be drilled to various 

bottomhole locations.

NON-CROP LAND shall mean all lands which are not defined as crop land, including range land.

OIL AND GAS FACILITY shall mean equipment or improvements used or installed at an oil and gas 

location for the exploration, production, withdrawal, gathering, treatment, or processing of oil or natural 

gas. 

OIL AND GAS LOCATION shall mean a definable area where an operator has disturbed or intends to 

disturb the land surface in order to locate an oil and gas facility. 
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OIL AND GAS OPERATIONS means exploration for oil and gas, including the conduct of seismic 

operations and the drilling of test bores; the siting, drilling, deepening, recompletion, reworking, or 

abandonment of an oil and gas well, underground injection well, or gas storage well; production 

operations related to any such well including the installation of flowlines and gathering systems; the 

generation, transportation, storage, treatment, or disposal of exploration and production wastes; and any 

construction, site preparation, or reclamation activities associated with such operations.

OIL WELL shall mean a well, the principal production of which at the mouth of the well is oil, as defined 

by the Act.

OPERATOR shall mean any person who exercises the right to control the conduct of oil and gas 

operations. 

ORDINARY HIGH-WATER LINE shall mean the line that water impresses on the land by covering it for 

sufficient periods to cause physical characteristics that distinguish the area below the line from the area 

above it. Characteristics of the area below the line include, when appropriate, but are not limited to, 

deprivation of the soil of substantially all terrestrial vegetation and destruction of its agricultural vegetative 

value. A flood plain adjacent to surface waters is not considered to lie within the surface waters’ ordinary 

high-water line.

ORPHAN WELL shall mean a well for which no owner or operator can be found, or where such owner or 

operator is unwilling or unable to plug and abandon such well.

ORPHANED SITE shall mean a site, where a significant adverse environmental impact may be or has 

been caused by oil and gas operations for which no responsible party can be found, or where such 

responsible party is unwilling or unable to mitigate such impact.

OWNER shall mean the person who has the right to drill into and produce from a pool and to appropriate 

the oil or gas produced therefrom either for such owner or others or for such owner and others, including 

owners of a well capable of producing oil or gas, or both.

PIT shall mean any natural or man-made depression in the ground used for oil or gas exploration or 

production purposes. Pit does not include steel, fiberglass, concrete or other similar vessels which do not 

release their contents to surrounding soils.

PLUGGING AND ABANDONMENT shall mean the cementing of a well, the removal of its associated 

production facilities, the removal or abandonment in-place of its flowline, and the remediation and 

reclamation of the wellsite.

POINT OF COMPLIANCE means one or more points or locations at which compliance with applicable 

groundwater standards established under Water Quality Control Commission Basic Standards for 

Groundwater, Section 3.11.4, must be achieved.

POLLUTION means man-made or man-induced contamination or other degradation of the physical, 

chemical, biological, or radiological integrity of air, water, soil, or biological resource.

The words POOL, PERSON, OWNER, PRODUCER, OIL, GAS, WASTE, CORRELATIVE RIGHTS and 

COMMON SOURCE OF SUPPLY are defined by the Act, and said definitions are hereby adopted in 

these Rules and Regulations. The word “operator” is used in these rules and regulations and 

accompanying forms interchangeably with the same meaning as the term “owner” except in Rules 301, 

323, 401 and 530 where the word “operator” is used to identify the persons designated by the owner or 

owners to perform the functions covered by those rules.
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PRODUCED AND MARKETED. These words, as used in the Act, shall mean, when oil shall have left the 

lease tank battery or when natural gas shall have passed the metering point and entered into the stream 

of commerce as its first step toward the ultimate consumer.

PRODUCTION FACILITIES shall mean all storage, separation, treating, dehydration, artificial lift, power 

supply, compression, pumping, metering, monitoring, flowline, and other equipment directly associated 

with oil wells, gas wells, or injection wells.

PRODUCTION PITS shall mean those pits used after drilling operations and initial completion of a well, 

including pits at natural gas gathering, processing and storage facilities, which constitutey pits, multi-well 

pits and:

SKIMMING/SETTLING PITS used to provide retention time for settling of solids and separation of 

residual oil for the purposes of recovering the oil or fluid.

PRODUCED WATER PITS used to temporarily store produced water prior to injection for 

enhanced recovery or disposal, off-site transport, or surface-water discharge.

PERCOLATION PITS used to dispose of produced water by percolation and evaporation through 

the bottom and/or sides of the pits into surrounding soils.

EVAPORATION PITS used to contain produced waters which evaporate into the atmosphere by 

natural thermal forces.

PROTESTANT shall mean a person who has timely filed a protest in a relevant proceeding and has 

demonstrated to the Commission's satisfaction that the person filing the protest would be directly and 

adversely affected or aggrieved by the Commission's ruling in the proceeding, and that any injury or 

threat of injury sustained would be entitled to legal protection under the act.

PUBLIC WATER SYSTEM shall mean those systems listed in Appendix VI to these Rules. These 

systems provide to the public water for human consumption through pipes or other constructed 

conveyances, if such systems have at least fifteen (15) service connections or regularly serve an average 

of at least twenty-five (25) individuals daily at least sixty (60) days out of the year. Such definition 

includes:

(i) Any collection, treatment, storage, and distribution facilities under control of the operator of 

such system and used primarily in connection with such system.

(ii) Any collection or pretreatment storage facilities not under such control, which are used 

primarily in connection with such system. 

The definition of “Public Water System” for purposes of Rule 317B does not include any “special irrigation 

district,” as defined in Colorado Primary Drinking Water Regulations (5 C.C.R. 1003.1). 

RECLAMATION shall mean the process of returning or restoring the surface of disturbed land as nearly 

as practicable to its condition prior to the commencement of oil and gas operations or to landowner 

specifications with an approved variance under Rule 502.b. 

REFERENCE AREA shall mean an area either (1) on a portion of the site that will not be disturbed by oil 

and gas operations, if that is the desired final reclamation; or (2) another location that is undisturbed by oil 

and gas operations and proximate and similar to a proposed oil and gas location in terms of vegetative 

potential and management, owned by a person who agrees to allow periodic access to it by the Director 

and the operator for the purpose of providing baseline information for reclamation standards, and 

intended to reflect the desired final reclamation. 
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RELEASE shall mean any unauthorized discharge of E&P waste to the environment over time.

REMEDIATION shall mean the process of reducing the concentration of a contaminant or contaminants 

in water or soil to the extent necessary to ensure compliance with the allowable concentrations and levels 

in Table 910-1 and other applicable ground water standards and classifications.

RESERVE PITS shall mean those pits used to store drilling fluids for use in drilling operations or to 

contain E&P waste generated during drilling operations and initial completion procedures.

RESPONDENT shall mean a party against whom a proceeding is instituted, or a PROTESTANT 

protestant who protests the granting of the relief sought in the application as provided in Rule 50911.

RESPONSIBLE PARTY shall mean an owner or operator person who conducts an oil and gas operation 

in a manner which is in contravention of any then-applicable provision of the aAct, or of any rule, 

regulation, or order of the Commission, or of any permit, that threatens to cause, or actually causes, a 

significant adverse environmental impact to any air, water, soil, or biological resource. RESPONSIBLE 

PARTY includes any person who disposes of any other waste by mixing it with exploration and production 

waste so as to threaten to cause, or actually cause, a significant adverse environmental impact to any air, 

water, soil, or biological resource.

RESTRICTED SURFACE OCCUPANCY AREA shall mean the following: 

• rocky mountain bighorn sheep production areas; 

• desert bighorn sheep production areas; 

• areas within 0.6 miles of any greater sage-grouse, Gunnison sage-grouse, and lesser prairie 

chicken leks (strutting and booming grounds); 

• areas within 0.4 miles of any Columbian sharp-tailed grouse or plains sharp-tailed grouse leks 

(strutting grounds); 

• areas within 1/4 mile of active Bald Eagle nest sites, Golden Eagle nest sites, or Osprey nest 

sites; 

• areas within 1/2 mile of active Ferruginous Hawk nest sites, Northern Goshawk nest sites, 

Peregrine Falcon nest sites, or Prairie Falcon nest sites; 

• areas located within 300 feet of the ordinary high-water mark of any stream segment located 

within designated Cutthroat Trout habitat; and 

• areas within 300 feet of the ordinary high-water mark of a stream or lake designated by the 

Colorado Division of Wildlife as “Gold Medal.” 

Maps showing and spatial data identifying the individual and combined extents of the above habitat areas 

shall be maintained by the Commission and made available on the Commission website. The extent of 

restricted surface occupancy areas is subject to update on a periodic but no more frequent than annual 

basis and may be modified only through the Commission’s rulemaking process, as provided in Rule 529. 

Any changes to restricted surface occupancy areas shall not affect Form 2As or Comprehensive Drilling 

Plans approved prior to the effective date of such changes. 

SEISMIC OPERATIONS shall mean all activities associated with acquisition of seismic data including but 

not limited to surveying, shothole drilling, recording, shothole plugging and reclamation.
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SENSITIVE AREA is an area vulnerable to potential significant adverse groundwater impacts, due to 

factors such as the presence of shallow economically usable groundwater or pathways for communication 

with deeper economically usable groundwater; proximity to surface water, including lakes, rivers, 

perennial or intermittent streams, creeks, irrigation canals, and wetlands. Additionally, areas classified for 

domestic use by the Water Quality Control Commission, local (water supply) wellhead protection areas, 

areas within 1/8 mile of a domestic water well, areas within 1/4 mile of a public water supply well, ground 

water basins designated by the Colorado Ground Water Commission, and surface water supply areas are 

sensitive areas. The procedure for identifying Sensitive Areas is set forth in the Sensitive Area 

identification Decision Tree and Guidance Document.

SENSITIVE WILDLIFE HABITAT shall mean:

• mule deer critical winter range (being both mule deer winter concentration areas (that part of the 

winter range where densities are at least 200% of the surrounding winter range density during the 

same period used to define winter range in 5 out of 10 winters), and mule deer severe winter 

range (that part of the winter range where 90% of the individuals are located during the average 5 

winters out of 10 from the first heavy snowfall to spring green-up)) (west of Interstate 25 and 

excluding Las Animas County); 

• elk winter concentration areas (west of Interstate 25 and excluding Las Animas County); 

• pronghorn antelope winter concentration areas (west of Interstate 25); 

• bighorn sheep winter range; 

• elk production areas (being that part of the overall range occupied by the females for calving) 

(west of Interstate 25 and excluding Las Animas County); 

• Columbian sharp-tailed grouse and plains sharp-tailed grouse production areas (being an area 

that contains 80% of nesting and brood rearing habitat for any identified population); 

• greater sage-grouse and Gunnison sage-grouse production areas (being an area that contains 

80% of nesting and brood rearing habitat for any population identified in the Colorado Greater 

Sage-Grouse Conservation Plan (CDOW, 2008) or the Gunnison Sage-Grouse Range-Wide 

Conservation Plan (May 2005), respectively); 

• lesser prairie chicken production areas (being an area that includes 80% of nesting and brood 

rearing habitat); 

• black-footed ferret release areas; 

• Bald Eagle nest sites and winter night roost sites; and 

• Golden Eagle nest sites. 

Maps showing and spatial data identifying the individual and combined extents of the above habitat areas 

shall be maintained by the Commission and made available on the Commission website. The extent of 

sensitive wildlife habitat is subject to update on a biennial basis and may be modified only through the 

Commission’s rulemaking procedures, as provided in Rule 529. Any modifications to sensitive wildlife 

habitat shall not affect Form 2As or Comprehensive Drilling Plans approved prior to the effective date of 

such changes. 

SHUT-IN WELL shall mean a well which is capable of production or injection by opening valves, 

activating existing equipment or supplying a power source.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 11

SIMULTANEOUS INJECTION WELL shall mean any well in which water produced from oil and gas 

producing zones is injected into a lower injection zone and such water production is not brought to the 

surface.

SOLID WASTE shall mean any garbage, refuse, sludge from a waste treatment plant, water supply plant, 

air pollution control facility, or other discarded material; including solid, liquid, semisolid, or contained 

gaseous material resulting from industrial operations, commercial operations, or community activities. 

Solid waste does not include any solid or dissolved materials in domestic sewage, or agricultural wastes, 

or solid or dissolved materials in irrigation return flows, or industrial discharges which are point sources 

subject to permits under the provisions of the Colorado Water Quality Control Act, Title 25, Article 8, 

C.R.S. or materials handled at facilities licensed pursuant to the provisions on radiation control in Title 25, 

Article 11, C.R.S. Solid waste does not include: (1) materials handled at facilities licensed pursuant to the 

provisions on radiation control in Title 25, Article 11, C.R.S.; (b) excluded scrap metal that is being 

recycled; or (c) shredded circuit boards that are being recycled. 

SOLID WASTE DISPOSAL shall mean the storage, treatment, utilization, processing, or final disposal of 

solid wastes. 

SPECIAL FIELD RULES shall mean those rules promulgated for and which are limited in their application 

to individual pools or fields within the State of Colorado.

SPECIAL PURPOSE PITS shall mean those pits used in oil and gas operations, including pits at natural 

gas gathering, processing and storage facilities, which constitutey pits, multi-well pits, and:

BLOWDOWN PITS used to collect material resulting from, including but not limited to, the 

emptying or depressurizating of wells, vessels, or gas gathering systems.

FLARE PITS used exclusively for flaring gas.

EMERGENCY PITS used to contain liquids on a temporary basis due to during an initial phase of 

emergency response operations related to a spill/release or process upset conditions.

BASIC SEDIMENT/TANK BOTTOM PITS used to temporarily store or treat the extraneous 

materials in crude oil which may settle to the bottoms of tanks or production vessels and which 

may contain residual oil.

WORKOVER PITS used to contain liquids during the performance of remedial operations on a 

producing well in an effort to increase production.

PLUGGING PITS used for containment of fluids encountered during the plugging process.

SPILL shall mean any unauthorized sudden discharge of E&P waste to the environment.

STORMWATER RUNOFF shall mean rain or snowmelt that flows over land and does not percolate into 

soil and includes stormwater that flows onto and off of an oil and gas location or facility. 

STRATIGRAPHIC WELL means a well drilled for stratigraphic information only. Wells drilled in a 

delineated field to known productive horizons shall not be classified as “stratigraphic.” . Neither the term 

“well” nor “stratigraphic well” shall include seismic holes drilled for the purpose of obtaining geophysical 

information only.

SUBSURFACE DISPOSAL FACILITY means a facility or system for disposing of water or other oil field 

wastes into a subsurface reservoir or reservoirs.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 12

SURFACE WATER INTAKE shall mean the works or structures at the head of a conduit through which 

water is diverted from a classified water supply segment and/or source (e.g., river or lake) into the 

treatment plant.

SURFACE WATER SUPPLY AREA shall mean the classified water supply segments within five (5) 

stream miles upstream of a surface water intake on a classified water supply segment. Surface Water 

Supply Areas shall be identified on the Public Water System Surface Water Supply Area Map or through 

use of the Public Water System Surface Water Supply Area Applicability Determination Tool described in 

Rule 317B.b. Surface Water Supply Areas include surface water intakes, springs, seeps, and 

groundwater which are under the influence of surface water, as defined in the Colorado Primary Drinking 

Water Regulations (5 C.C.R. 1003.1), used as a public water supply. 

TANK shall mean a stationary vessel that is used to contain fluids, constructed of non-earthen materials 

(e.g. concrete, steel, plastic) that provide structural support. 

TEMPORARILY ABANDONED WELL shall mean a well which is incapable of production or injection 

without the addition of one or more pieces of wellhead or other equipment, including valves, tubing, rods, 

pumps, heater-treaters, separators, dehydrators, compressors, piping or tanks.

TIER 1 OIL AND GAS LOCATION shall mean an oil and gas location where the slope is less than five 

percent (5%), the soil has low erosion potential, vegetative cover or permanent erosion resistance cover 

is greater than seventy-five percent (75%), the distance from a perennial stream or Classified Water 

Supply Segment is greater than five hundred (500) feet, and the oil and gas location size is less than one 

(1) acre, measured by the amount of surface disturbance.

TRADE SECRET shall mean any confidential formula, pattern, process, device, information, or 

compilation of information that is used in an employer’s business, and that gives the employer an 

opportunity to obtain an advantage over competitors who do not know or use it. 

TRADE SECRET CHEMICAL PRODUCT shall mean a Chemical Product the composition of which is a 

Trade Secret. 

VOLUNTARY SELF-EVALUATION shall mean a self-initiated assessment, audit, or review, not otherwise 

expressly required by environmental law, that is performed by any person or entity, for itself, either by an 

employee or employees employed by such person or entity who are assigned the responsibility of 

performing such assessment, audit, or review or by a consultant engaged by such person or entity 

expressly and specifically for the purpose of performing such assessment, audit, or review to determine 

whether such person or entity is in compliance with environmental laws.

WATERS OF THE STATE mean any and all surface and subsurface waters which are contained in or 

flow in or through this state, but does not include waters in sewage systems, waters in treatment works of 

disposal systems, water in potable water distribution systems, and all water withdrawn for use until use 

and treatment have been completed. Waters of the state include, but are not limited to, all streams, lakes, 

ponds, impounding reservoirs, wetlands , watercourses, waterways, wells, springs, irrigation ditches or 

canals, drainage systems, and all other bodies or accumulations of water, surface and underground, 

natural or artificial, public or private, situated wholly or partly within or bordering upon the State.

WELL when used alone in these Rules and Regulations, shall mean an oil or gas well, a hole drilled for 

the purpose of producing oil or gas, a well into which fluids are injected, a stratigraphic well, a gas storage 

well, or a well used for the purpose of monitoring or observing a reservoir.

WELL SITE shall mean the areas that are directly disturbed during the drilling and subsequent operation 

of, or affected by production facilities directly associated with, any oil well, gas well, or injection well and 

its associated well pad. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 13

WILDCAT (EXPLORATORY) WELL means any well drilled beyond the known producing limits of a pool. 

WILDLIFE RESOURCES shall mean fish, wildlife, and their aquatic and terrestrial habitats. 

ZONE OF INCORPORATION shall mean the soil layer from the soil surface to a depth of twelve (12) 

inches below the surface. 

ALL OTHER WORDS used herein shall be given their usual customary and accepted meaning, and all 

words of a technical nature, or peculiar to the oil and gas industry, shall be given that meaning which is 

generally accepted in said oil and gas industry. 

200-SERIES GENERAL RULES

201. EFFECTIVE SCOPE OF RULES AND REGULATIONS

All rules and regulations of a general nature herein promulgated to prevent waste and to conserve oil and 

gas in the State of Colorado while protecting public health, safety, and welfare, including the environment 

and wildlife resources, shall be effective throughout the State of Colorado and be in force in all pools and 

fields except as may be amended, modified, altered or enlarged generally or in specific individual pools or 

fields by orders heretofore or hereafter issued by the Commission, and except where special field rules 

apply, in which case the special field rules shall govern to the extent of any conflict.

Nothing in these rules shall establish, alter, impair, or negate the authority of local and county 

governments to regulate land use related to oil and gas operations, so long as such local regulation is not 

in operational conflict with the Act or regulations promulgated thereunder. 

These rules shall not apply to: (i) Indian trust lands and minerals; or (ii) the Southern Ute Indian Tribe 

within the exterior boundaries of the Southern Ute Indian Reservation. These rules shall apply to nonIndians conducting oil and gas operations on lands within the exterior boundaries of the Southern Ute 

Indian Reservation where both the surface and oil and gas estates are owned in fee by persons or 

entities other than the Southern Ute Indian Tribe, regardless of whether such lands are communitized or

pooled. Additionally, the State of Colorado shall exercise criminal and civil jurisdiction within the Town of 

Ignacio, Colorado or within any other municipality within the Southern Ute Indian Reservation 

incorporated under the laws of Colorado, as provided by Sec. 5, Public Law No. 98-290 (1984). 

If any portion of these Rules is found to be invalid, the remaining portion of the Rules shall remain in force 

and effect. 

201A. EFFECTIVE DATE OF AMENDMENTS

Unless otherwise specified in the rules, amendments to these rules adopted by the Commission in 

December 2008 shall become effective on May 1, 2009 for federal land and April 1, 2009 for all other 

land. 

202. OFFICE AND DUTIES OF DIRECTOR

The office of Director of the Commission is hereby created. It shall be the duty of the Director to aid the 

Commission in the administration of the Act, as may be required of the Director from time to time and to 

act as hearing officer when so directed by the Commission.

203. OFFICE AND DUTIES OF SECRETARY

The office of Secretary to the Commission is hereby created. The duties of the Secretary shall be as 

determined from time to time by the Commission.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 14

204. GENERAL FUNCTIONS OF DIRECTOR

The Director and the authorized deputies shall also have the right at all reasonable times to go upon and 

inspect any oil and/or gas properties, disposal facilities, or transporters facilities and wells for the purpose 

of making any investigation or tests to ascertain whether the provisions of the Act or these rules or any 

special field rules are being complied with, and shall report any violation thereof to the Commission.

205. ACCESS TO RECORDS

a. All owners, producers, operators, transporters, refiners, gasoline or other extraction plant operators 

and initial purchasers of oil and gas within this State, shall make and keep appropriate books and 

records covering their operations in the State, including natural gas meter calibration reports,

from which they may be able to make and substantiate the reports required by the Commission or 

the Director. 

b. Beginning May 1, 2009 on federal land and April 1, 2009 on all other land, owners or operators shall 

maintain MSDS sheets for any Chemical Products brought to a well site for use downhole during 

drilling, completion, and workover operations, including fracture stimulation. 

c. Beginning June 1, 2009, owners or operators shall maintain a Chemical Inventory by well site for each 

Chemical Product used downhole or stored for use downhole during drilling, completion, and 

workover operations, including fracture stimulation, in an amount exceeding five hundred (500) 

pounds during any quarterly reporting period. Owners or operators shall also maintain a Chemical 

Inventory by well site for fuel stored at the well site during drilling, completion, and workover 

operations, including fracture stimulation, in an amount exceeding five hundred (500) pounds 

during any quarterly reporting period.

The five hundred (500) pound reporting threshold shall be based on the cumulative maximum 

amount of a Chemical Product present at the well site during the quarterly reporting period. 

Entities maintaining Chemical Inventories under this section shall update these inventories 

quarterly throughout the life of the well site. These records must be maintained in a readily 

retrievable format. The Colorado Department of Public Health and Environment may obtain 

information provided to the Commission or Director in a Chemical Inventory upon written request 

to the Commission or the Director. 

d. Where the composition of a Chemical Product is considered a Trade Secret by the vendor or service 

provider, Owners or Operators shall only be required to maintain the identity of the Trade Secret 

Chemical Product and shall not be required to maintain information concerning the identity of 

chemical constituents in a Trade Secret Chemical Product or the amounts of such constituents. 

The vendor or service provider shall provide to the Commission a list of the chemical constituents 

contained in a Trade Secret Chemical Product upon receipt of a letter from the Director stating 

that such information is necessary to respond to a spill or release of a Trade Secret Chemical 

Product or a complaint from a potentially adversely affected landowner regarding impacts to 

public health, safety, welfare, or the environment. Upon receipt of a written statement of 

necessity, information regarding the chemical constituents contained in a Trade Secret Chemical 

Product shall be disclosed by the vendor or service provider directly to the Commission’s 

Environmental Manager or his or her designee. 

The Environmental Manager or designee may disclose information regarding those chemical 

constituents to additional Commission staff members to the extent that such disclosure is 

necessary to allow the Commission staff member receiving the information to assist in responding 

to the spill, release, or complaint, provided that such individuals shall not disseminate the 

information further. In addition, the Environmental Manager may disclose information regarding 

those chemical constituents to any Commissioner, the relevant County Public Health Director or 

Emergency Manager, or to the Colorado Department of Public Health and Environment’s Director 

of Environmental Programs upon request by that individual. Any information so disclosed to the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 15

Environmental Manager, a Commission staff member, a Commissioner, a County Public Health 

Director or Emergency Manager, or to the Colorado Department of Public Health and 

Environment’s Director of Environmental Programs shall at all times be considered confidential 

and shall not become part of the Chemical Inventory, nor shall it be construed as publicly 

available. The Colorado Department of Public Health and Environment’s Director of 

Environmental Programs, or his or her designee, may disclose information regarding the chemical 

constituents contained in a Trade Secret Chemical Product to Colorado Department of Public 

Health and Environment staff members under the same terms and conditions as apply to the 

Commission’s Environmental Manager. 

e. The vendor or service provider shall also provide the chemical constituents of a Trade Secret 

Chemical Product to any health professional who requests such information in writing if the health 

professional provides a written statement of need for the information and executes a 

Confidentiality Agreement, Form 35. The written statement of need shall be a statement that the 

health professional has a reasonable basis to believe that (1) the information is needed for 

purposes of diagnosis or treatment of an individual, (2) the individual being diagnosed or treated 

may have been exposed to the chemical concerned, and (3) knowledge of the chemical 

constituents of such Trade Secret Chemical Product will assist in such diagnosis or treatment. 

The Confidentiality Agreement, Form 35, shall state that the health professional shall not use the 

information for purposes other than the health needs asserted in the statement of need, and that 

the health professional shall otherwise maintain the information as confidential. Where a health 

professional determines that a medical emergency exists and the chemical constituents of a 

Trade Secret Chemical Product are necessary for emergency treatment, the vendor or service 

provider shall immediately disclose the chemical constituents of a Trade Secret Chemical Product 

to that health professional upon a verbal acknowledgement by the health professional that such 

information shall not be used for purposes other than the health needs asserted and that the 

health professional shall otherwise maintain the information as confidential. The vendor or service 

provider may request a written statement of need, and a Confidentiality Agreement, Form 35,

from all health professionals to whom information regarding the chemical constituents was 

disclosed, as soon as circumstances permit. Information so disclosed to a health professional 

shall not become part of the Chemical Inventory and shall in no way be construed as publicly 

available. 

f. Such books, records, inventories, and copies of said reports required by the Commission or the 

Director shall be kept on file and available for inspection by the Commission for a period of at 

least five years except for the Chemical Inventory, which shall be kept on file and available for 

inspection by the Commission for the life of the applicable oil and gas well or oil and gas location 

and for five (5) years after plugging and abandonment. Upon the Commission’s or the Director’s 

written request for information required to be maintained or provided under this section, the 

record-keeping entity or third-party vendor shall supply the Commission or the Director with the 

requested information within three (3) business days in a format readily-reviewable by the 

Commission or the Director, except in the instance where such information is necessary to 

administer emergency medical treatment in which case such information shall be provided as 

soon as possible. Information provided to the Commission or the Director under this section that 

is entitled to protection under state or federal law, including C.R.S. § 24-72-204, as a trade 

secret, privileged information, or confidential commercial, financial, geological, or geophysical 

data shall be kept confidential and protected against public disclosure unless otherwise required, 

permitted, or authorized by other state or federal law. Any disclosure of information entitled to 

protection under any state or federal law made pursuant to this section shall be made only to the 

persons required, permitted, or authorized to receive such information under state or federal law 

in order to assist in the response to a spill, release, or complaint and shall be subject to a 

requirement that the person receiving such information maintain the confidentiality of said 

information. The Commission or the Director shall notify the owner, holder, or beneficiary of any 

such protected information at least one (1) business day prior to any required, permitted, or 

authorized disclosure. This notification shall include the name and contact information of the 

intended recipient of such protected information, the reason for the disclosure, and the state or 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 16

federal law authorizing the disclosure. Information so disclosed shall not become part of the 

Chemical Inventory and shall in no way be construed as publicly available. 

g. The Director and the authorized deputies shall have access to all well records wherever located. All 

ownersoperators, drilling contractors, drillers, service companies, or other persons engaged in 

drilling or servicing wells, shall permit the Director, or authorized deputy, at the Director's or their 

risk, in the absence of negligence on the part of the owner, to come upon any lease, property, or 

well operated or controlled by them, and to inspect the record and operation of such wells and to 

have access at all times to any and all records of wells; provided, that information so obtained 

shall be kept confidential and shall be reported only to the Commission or its authorized agents.

h. In the event that the vendor or service provider does not provide the information required by Rules 

205.d, 205.e, or 205.f directly to the Commission, the owner or operator is responsible for 

providing the required information.

i. In the event the owner or operator establishes to the satisfaction of the Director that it lacks the right to 

obtain the information required by Rules 205.d, 205.e, or 205.f and to provide it directly to the 

Commission, the owner or operator shall receive a variance from these rule provisions from the 

Director. 

206. REPORTS

a. All producers, operators, transporters, refiners, gasoline and other extraction plant operators, and 

initial purchasers of oil and gas within the State shall from time to time file accurate and complete 

reports containing such information and covering such geographic areas or periods as the 

Commission or Director shall require.

b. Compliance Checklist. Operators with oil and gas facilities in Garfield, Mesa, Gunnison, or Rio 

Blanco County shall complete and retain a Compliance Checklist, Form 36, for each oil and gas 

facility concerning actions taken or current on-site conditions that indicate compliance with 

specific requirements necessary to minimize adverse impacts. 

(1) The Compliance Checklist, Form 36, shall demonstrate on-going compliance with 

requirements relating to stormwater management, protection of surface water drinking 

water supply areas, odor management, management of exploration and production 

waste, and maintenance of a Chemical Inventory. 

(2) A new Compliance Checklist, Form 36, shall be completed and signed by an operator’s 

authorized representative for each oil and gas facility on or before August 15, 2009 and 

annually thereafter. An operator shall retain a current Compliance Checklist, Form 36, at 

the operator’s local field office at all times. 

(3) An operator required to complete and retain a Compliance Checklist, Form 36, shall provide a 

copy of an oil and gas facility’s current Compliance Checklist, Form 36, to the Director 

within five (5) days of receiving a written request. 

(4) The Compliance Checklist, Form 36, is not considered a report, record, account, or 

memorandum for purposes of C.R.S. § 34-60-121(2). 

207. TESTS AND SURVEYS

a. Tests and surveys. When deemed necessary or advisable, the Commission is authorized to require 

that tests or surveys be made to determine the presence of waste or occurrence of pollution. The 

Commission, in calling for reports under Rule 206 and tests or surveys to be made as provided in 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 17

this rule, shall designate the time allowed the operator for compliance, which provisions as to time 

shall prevail over any other time provisions in these rules.

b. Bradenhead monitoring.

(1) The Director shall have authority to designate specific fields or portions of fields as 

bradenhead test areas within which, on any well, the bradenhead access to the annulus 

between the production and surface casing, as well as any intermediate casing, shall be 

equipped with fittings to allow safe and convenient determinations of pressure and fluid 

flow. Any such proposed designation shall occur by notice describing the proposed 

bradenhead test area. Such notice shall be given to all operators of record within such 

area and by publication. The proposed designation, if no protests are timely filed, shall be 

placed upon the Commission consent agenda for the regular monthly meeting of the 

Commission following the month in which such notice is given, and shall be approved or 

heard by the Commission in accordance with Rule 520. Such designation shall be 

effective immediately, upon approval by the Commission.

(2) All operators within any bradenhead test area shall have thirty (30) days after the effective 

date of the designation to commence the taking of bradenhead pressure readings in all 

wells located therein which are equipped for such readings. The operator shall equip any 

well which is not so equipped within ninety (90) days of the effective date, and within 

thirty (30) days thereafter the operator shall take the required reading. Such readings 

shall include the date, time and pressure of each reading, and the type of fluid reported. 

Such readings shall be taken in bradenhead test areas annually, maintained at the 

operator's office for a period of five (5) years, and shall be reported to the Director upon 

written request.

208. CORRECTIVE ACTION

The Commission shall require correction, in a manner to be prescribed or approved by it, of any condition 

which is causing or is likely to cause waste or pollution; and require the proper plugging and 

abandonment of any well or wells no longer used or useful in accordance with such reasonable plan as 

may be prescribed by it.

209. PROTECTION OF COAL SEAMS AND WATER-BEARING FORMATIONS

In the conduct of oil and gas operations each owner shall exercise due care in the protection of coal 

seams and water-bearing formations as required by the applicable statutes of the State of Colorado.

Special precautions shall be taken in drilling and abandoning wells to guard against any loss of artesian 

water from the straturn stratum in which it occurs and the contamination of fresh water by objectionable 

water, oil, or gas. Before any oil or gas well is completed as a producer, all oil, gas and water strata 

above and below the producing horizon shall be sealed or separated in order to prevent the intermingling 

of their contents.

210. SIGNS AND MARKERS

The operator shall mark each and every well in a conspicuous place, from the time of initial drilling until 

final abandonment, as follows:

a. Drilling and Recompletion Operations. Directional signs, no less than three (3) and no more than 

six (6) square feet in size, shall be provided during any drilling or recompletion operation, by the 

operator or drilling contractor. Such signs shall be at locations sufficient to advise emergency 

crews where drilling is taking place; at a minimum, such locations shall include (i) the first point of 

intersection of a public road and the rig access road and (ii) thereafter at each intersection of the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 18

rig access route, except where the route to the rig is clearly obvious to uninformed third parties. 

Signs not necessary to meet other obligations under these rules shall be removed as soon as 

practicable after the operation is complete.

b. Permanent Designations.

(1) Wells. Within sixty (60) days after the completion of a well, a permanent sign shall be located 

at the wellhead which shall identify the well and provide its legal location, including the 

quarter quarter section. When no associated battery is present, the additional 

information required under Rule 210.b.(2) shall be required on the sign.

(2) Batteries. Within sixty (60) days after the installation of a battery, a permanent sign shall be 

located at the battery. At the option of the operator, or at the request of local emergency 

response authorities, the sign may be placed at the intersection of the lease access road 

with a public, farm or ranch road if the referenced battery is readily apparent from such 

location. Such sign, which shall be no less than three (3) square feet and no more than 

six (6) square feet, shall provide: the name of the operator; a phone number at which the 

operator can be reached at all times; a phone number for local emergency services (911 

where available); the lease name or well name(s) associated with the battery; the public 

road used to access the site; and, the legal location, including the quarter quarter section. 

In lieu of providing the legal location on the permanent sign, it may be stenciled on a tank 

in characters visible from one-hundred (100) feet.

c. Centralized E&P Waste Management Facilities. The main point of access to a centralized E&P 

waste management facility shall be marked by a sign captioned “(operator name) E&P Waste 

Management Facility.” . Such sign, which shall be no less than three (3) square feet and no more 

than six (6) square feet shall provide: a phone number at which the operator can be reached at all 

times; a phone number for local emergency services (911 where available); the public road used 

to access the facility; and, the legal location, including quarter quarter section, of the facility.

d. Tanks and Containers.

(1) All tanks with a capacity of ten (10) barrels or greater shall be labeled or posted with the 

following information:

A. Name of operator;

B. Operator’s emergency contact telephone number;

C. Tank capacity;

D. Tank contents; and

E. National Fire Protection Association (NFPA) Label. 

(2) Containers that are used to store, treat, or otherwise handle a hazardous material and which 

are required to be marked, placarded, or labeled in accordance with the U.S. Department 

of Transportation’s Hazardous Materials Regulations, shall retain the markings, placards, 

and labels on the container. Such markings, placards, and labels must be retained on the 

container until it is sufficiently cleaned of residue and purged of vapors to remove any 

potential hazards. 

de. General sign requirements. No sign required under this Rule 210. shall be installed at a height 

exceeding six (6) feet. Operators shall maintain signs in a legible condition, and shall replace 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 19

damaged or vandalized signs within sixty (60) days. New operators shall update signs within sixty

(60) days after change of operator approval is received from the Commission.

211. NAMING OF FIELDS

All oil and gas fields discovered in the State subsequent to the adoption of these rules and regulations 

shall be named by the Director or at the Director's direction.

212. SAFETY

For safety regulations regarding industry personnel, contact the U.S. Department of Labor, Occupational 

Safety and Health Administration, Regional Administrator, Colorado Region VIII, 1961 Stout Street, Suite 

1576, Denver, Colorado 80201, telephone (303) 844-3061. For State Safety regulations regarding public 

safety see Rules 601-6086.9.

213. FORMS UPON REQUEST

Forms required by the Commission will be furnished upon request. (Please see Procedures and Forms 

Guidelines)

214. LOCAL GOVERNMENTAL DESIGNEE

Each local government which designates an office for the purposes set forth in the 100 Series shall 

provide the Commission written notice of such designation, including the name, address and telephone 

number, facsimile number, electronic mail address, local emergency dispatch and other emergency 

numbers of the local governmental designee. It shall be the responsibility of such local governmental 

designee to ensure that all documents provided to the local governmental designee by oil and gas 

operators and the Commission or the Director are distributed to the appropriate persons and offices.

215. GLOBAL POSITIONING SYSTEMS

Global Positioning Systems (GPS) may be used to locate facilities used in oil and gas operations 

provided they meet the following minimum standards of the Commission:

a. Instruments rated as Differential Global Positioning System (DGPS) shall be used.

b. Instruments shall be capable of precision shall be no less than one (1) meter accuracy after differential 

correction.

c. All GPS data shall be differentially corrected by post processing prior to data submission.

d. Position dilution of precision (PDOP) values shall not be higher than six (6) and shall be included with 

location data.

e. Elevation mask (lowest acceptable height above the horizon) shall be no less than fifteen degrees 

(15o)

f. Latitude and longitude coordinates shall be provided in decimal degrees with an accuracy and 

precision of five (5) decimals of a degree using the North American Datum (NAD) of 1983 (e.g.; 

latitude 37.12345 N, longitude 104.45632 W).

g. Raw and corrected data files shall be held for a period of three (3) years.

h. Measurements shall be made by a trained GPS operator familiar with the theory of GPS, the use of 

GPS instrumentation, and typical constraints encountered during field activities.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 20

216. COMPREHENSIVE DRILLING PLANS

a. Purpose. Comprehensive Drilling Plans are intended to identify foreseeable oil and gas activities in a 

defined geographic area, facilitate discussions about potential impacts, and identify measures to 

minimize adverse impacts to public health, safety, welfare, and the environment, including wildlife 

resources, from such activities. An operator’s decisions to initiate and enter into a Comprehensive 

Drilling Plan are voluntary. 

b. Scope. A Comprehensive Drilling Plan shall cover more than one (1) proposed oil and gas location 

within a geologic basin, but its scope may otherwise be customized by the operator to address 

specific issues in particular areas. Although operators are encouraged to develop joint 

Comprehensive Drilling Plans covering the proposed activities of multiple operators where 

appropriate, Comprehensive Drilling Plans will typically cover the activities of one operator. 

c. Information requirements. Operators are encouraged to submit the most detailed information 

practicable about the future activities in the geographic area covered by the Comprehensive 

Drilling Plan. Detailed information is more likely to lead to identification of specific impacts and 

agreement regarding measures to minimize adverse impacts. The information included in the 

Comprehensive Drilling Plan shall be decided upon by the operator, in consultation with other 

participants. Information provided by operators to federal agencies to obtain approvals for surface 

disturbing activities on federal land may be submitted in support of a Comprehensive Drilling 

Plan. The following information may be included as part of a Comprehensive Drilling Plan, 

depending on the circumstances:

(1) A U.S. Geological Survey 1:24,000 topographic map showing the proposed oil and gas 

locations, including proposed access roads and gathering systems reasonably known to 

the operator(s); 

(2) A current aerial photo showing the proposed oil and gas locations displayed at the same 

scale as the topographic map to facilitate use as an overlay; 

(3) Overlay maps showing the proposed oil and gas locations, including all proposed access 

roads and gathering systems, drainages and stream crossings, and existing and 

proposed buildings, roads, utility lines, pipelines, known mines, oil or gas wells, water 

wells known to the operator(s) and those registered with the State Engineer’s Office, and 

riparian areas as mapped in the Colorado Division of Wildlife’s Natural Diversity 

Information Source (NDIS) data set;

(4) A list of all proposed oil and gas facilities to be installed within the area covered by the 

Comprehensive Drilling Plan over the time of the Plan and the anticipated timing of the 

installation; 

(5) A plan for the management of exploration and production waste; 

(6) A description of the wildlife resources at each oil and gas location; 

(7) Wildlife information that is determined necessary after consultation with the Colorado Division 

of Wildlife; 

(8) Locations of all proposed reference areas to be used as guides for interim and final 

reclamation; 

(9) Past economic uses to which the land has been put in the previous ten (10) years reasonably 

known to the operator(s); 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 21

(10) Any planned variance requests that are reasonably known to the operator; 

(11) Proposed best management practices or mitigation to minimize adverse impacts to 

resources such as air, water, or wildlife resources; and

(12) A list of all parties that participated in creating the Comprehensive Drilling Plan pursuant to 

Rule 216.d.(2). 

d. Procedure.

(1) One or more operator(s) may submit a proposed Comprehensive Drilling Plan to the 

Commission, describing the operator’s known foreseeable oil and gas development 

activities in a specified geographic area within a geologic basin. The Director may 

request an operator to initiate a Comprehensive Drilling Plan, but the decision to do so 

rests solely with the operator. 

(2) The operator(s) shall invite the Colorado Department of Public Health and Environment, the 

Colorado Division of Wildlife, local governmental designee(s), and all surface owners to 

participate in the development of the Comprehensive Drilling Plan. In many cases, 

participation by these agencies and individuals will facilitate identification of potential 

impacts and development of presumptive conditions of approval to minimize adverse 

impacts. 

(3) The operator(s), the Director, and participants involved in the Comprehensive Drilling Plan 

process shall review the proposal, identify information needs, discuss operations and 

potential impacts, and establish presumptive measures to minimize adverse impacts 

resulting from oil and gas development activities covered by the Plan. 

(4) The Director shall place on the Commission’s consent agenda in a timely manner a 

Comprehensive Drilling Plan that has been agreed to in writing by the operator(s) and 

that the Director considers suitable after consultation with the Colorado Department of 

Public Health and Environment and the Colorado Division of Wildlife, as applicable, and 

consideration of any other comments. 

(5) The Director shall identify and document the agreed-upon conditions of approval for activities 

within the geographic area covered by the accepted Comprehensive Drilling Plan. 

(6) Comprehensive Drilling Plans that have been accepted by the Commission shall be posted 

on the COGCC website, subject to any confidential or proprietary information belonging 

to the operator or other parties being withheld. Written information obtained or compiled 

from landowners and operators in conjunction with development of a Comprehensive 

Drilling Plan is exempt from disclosure to the public, provided that any page containing 

information subject to withholding under the Colorado Open Records Act is clearly 

labeled with the words “Confidential Information.” The Commission, the Colorado 

Department of Public Health and Environment, and the Colorado Division of Wildlife will 

keep all such data and information confidential to the extent allowed by the Colorado 

Open Records Act.

(7) Before initiating a Comprehensive Drilling Plan, operators are encouraged to discuss with the 

Director and, as appropriate, the Colorado Department of Public Health and Environment 

and the Colorado Division of Wildlife, the scope of the Plan, the schedule for its 

preparation, the information to be included, any public participation opportunities, and 

whether the Plan is intended to satisfy Form 2A requirements. 

e. Variances and site-specific approvals.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 22

(1) A Comprehensive Drilling Plan may incorporate variances to any of these rules, provided that 

all of the requirements for granting variances are met. 

(2) Practices and conditions agreed to in an accepted Comprehensive Drilling Plan shall be: 

A. Included as presumptive conditions of approval in any Form 2 or other permit for 

individual wells or other ground-disturbing activity covered by the Plan, where no 

Form 2A is required under Rule 303.d.(2).B.

B. Included as presumptive conditions of approval in any Form 2, Form 2A, or other 

permit for individual wells or other ground-disturbing activity covered by the Plan, 

where a Form 2A is required under Rule 303.d.(1). 

Any permit-specific condition of approval for wildlife habitat protection will be included 

only with the consent of the surface owner. 

f. Incentives. The following incentives shall apply as a means to facilitate and encourage the 

development of Comprehensive Drilling Plans by operators: 

(1) Where the Comprehensive Drilling Plan contains information substantially equivalent to that 

which would be required in a Form 2A for the proposed oil and gas location and the 

Comprehensive Drilling Plan has been subject to procedures substantially equivalent to 

those required for a Form 2A, then a Form 2A shall not be required for a proposed oil and 

gas location that was included in the Comprehensive Drilling Plan and does not involve a 

variance from the Plan or a variance from these rules not addressed in the 

Comprehensive Drilling Plan. 

(2) Where the Comprehensive Drilling Plan does not contain information substantially equivalent 

to that which would be required in a Form 2A for the proposed oil and gas location or the 

Comprehensive Drilling Plan has not been subject to procedures substantially equivalent 

to those required for a Form 2A or the operator seeks a variance from the 

Comprehensive Drilling Plans or a provision of these rules that is not addressed in the 

Plan, then a Form 2A shall be required for a proposed oil and gas location included in the 

Comprehensive Drilling Plan. However, the Director shall modify the informational and 

procedural requirements for such Form 2A to reflect the information included in and 

procedures used to approve the Comprehensive Drilling Plan and with input, where 

appropriate, from the Colorado Department of Public Health and Environment and the 

Colorado Division of Wildlife. 

(3) Where a proposed oil and gas location is covered by an approved Comprehensive Drilling 

Plan and no variance is sought from such Plan or these rules not addressed in the 

Comprehensive Drilling Plan, then the Director shall give priority to and approve or deny 

an Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, 

within thirty (30) days of a determination that such application is complete pursuant to 

Rule 303.h unless significant new information is brought to the attention of the Director. 

(4) Where the Director does not issue a decision on an Application for Permit-to-Drill, Form 2, or 

an Oil and Gas Location Assessment, Form 2A, for an oil and gas location covered by an 

accepted Comprehensive Drilling Plan within thirty (30) days, then within five (5) days the 

Director shall provide the operator with a written explanation for the delay and the 

anticipated decision date, and the operator may request a hearing before the 

Commission. Such a hearing shall be expedited but will be held only after both the 20 

days’ notice and the newspaper notice are given as required by Section 34-60-108, 

C.R.S. However, the hearing may be held after the newspaper notice if all of the entities 

listed under Rule 503.b waive the 20-day notice requirement.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 23

(5) Any party requesting a hearing pursuant to Rule 503.b.(7) on the Director’s approval of an 

Application for Permit-to-Drill, Form 2, or an Oil and Gas Location Assessment, Form 2A, 

for an oil and gas location that includes conditions of approval arrived at as part of an 

accepted Comprehensive Drilling Plan shall bear the burden of establishing that the 

conditions of approval are insufficient to protect public health, safety, welfare, the 

environment, and wildlife resources due to new information or changed circumstances 

occurring since the Comprehensive Drilling Plan was accepted by the Commission. 

g. Duration. Once accepted by the Commission, a Comprehensive Drilling Plan shall be valid for a 

period of six (6) years. 

h. Modification. An accepted Comprehensive Drilling Plan may be modified using the same process as 

that leading to acceptance of the original Plan either upon the initiative of the operator or upon the 

initiative of the Director and upon a showing that there has been a change in an applicable 

provision in these rules or a significant change to the basis upon which the Plan was developed. 

The review and approval of the modification shall focus only on the proposed modification(s). 

300-SERIES DRILLING, DEVELOPMENT, PRODUCTIONING AND ABANDONMENT

301. RECORDS, REPORTS, NOTICES-GENERAL

Any written notice of intention to do work or to change plans previously approved must be filed with the 

Director, and must reach the Director and receive approval before the work is begun, or such approval 

may be given orally and, if so given, shall thereafter be confirmed to the Director in writing.

In case of emergency, or any situation where operations might be unduly delayed, any notice or 

information required by these rules and regulations to be given to the Director may be given orally or by 

wire, and if approval is obtained the transaction shall be promptly confirmed in writing to the Director, as a 

matter of record.

Immediate notice shall be given to the Director when public health or safety is in jeopardy. Notice shall 

also be given to the Director of any other significant downhole problem or mechanical failure in any well 

within ten (10) days.

The owner shall keep on the leased premises, or at the owner's headquarters in the field, or otherwise 

conveniently available to the Director, accurate and complete records of the drilling, redrilling, deepening, 

repairing, plugging or abandoning of all wells, and of all other well operations, and of all alterations to 

casing. These records shall show all the formations penetrated, the content and quality of oil, gas or 

water in each formation tested, and the grade, weight and size, and landed depth of casing used in 

drilling each well on the leased premises, and any other information obtained in the course of well 

operation. Such records on each well shall be maintained by any subsequent owner.

Whenever a person has been designated as an operator by an owner or owners of the lease or well, such 

an operator may submit the reports as herein required by the Commission.

302. COGCC Form 1. REGISTRATION FOR OIL AND GAS OPERATIONS

a. Prior to the commencement of its operations, all producers, operators, transporters, refiners, gasoline 

or other extraction plant operators, and initial purchasers who are conducting operations subject 

to this Act in the State of Colorado, shall, for purposes of the Act, file a Registration For Oil and 

Gas Operations, Form 1, with the Director in the manner and form approved by the Commission. 

Any producer, operator, transporter, refiner, gasoline or other extraction plant operator, and initial 

purchaser conducting operations subject to the Act who has not previously filed a Registration 

For Oil and Gas Operations, Form 1, shall do so. Any person providing financial assurance for oil 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 24

and gas operators in Colorado shall file a Form 1 with the Director. All changes of address of the 

parties required to file a Form 1 shall be immediately reported by submitting a new Form 1.

b. Designation of Agent, Form 1A. Any party may act on or for the behalf of the owner/operator 

provided the owner/operator has filed a Designation of Agent, Form 1A. Operator employees 

approved to submit documents shall be listed on a completed Designation of Agent, Form 1A. A 

company/individual other than the operator may be designated as an agent, and its 

representatives shall be listed on a completed Designation of Agent, Form 1A. This agency shall 

remain in effect until it is terminated in writing by the owner/operatorsubmitting a new Designation 

of Agent, Form 1A. All changes of address of the agent to reported agent information shall be 

immediately reported by submitting a new Designation of Agent, Form 1A.

303. REQUIREMENTS FOR FORM 2, APPLICATION FOR PERMIT-TO-DRILL, DEEPEN, RE-ENTER, 

OR RECOMPLETE, AND OPERATE; FORM 2A, OIL AND GAS LOCATION ASSESSMENT.

[THE FOLLOWING LANGUAGE WILL BE PLACED ON THE APD BY THE DIRECTOR’S SIGNATURE: 

“BASED ON THE INFORMATION PROVIDED HEREIN, THIS APPLICATION FOR PERMIT-TO-DRILL 

COMPLIES WITH COGCC RULES AND APPLICABLE ORDERS AND IS HERBY APPROVED.]

a. FORM 2. APPLICATION FOR PERMIT-TO-DRILL, DEEPEN, RE-ENTER, OR RECOMPLETE, AND 

OPERATE.

(1) Approval by Director. Before any person shall commence operations for the drilling or reentry of any well, such person shall file with the Director an application on Form 2 for a 

Permit-to-Drill, a completed (or, where it has been approved in advance, an approved) Oil 

and Gas Location Assessment, Form 2A, pay a filing and service fee established by the 

Commission (see Appendix III), and obtain the Director's approval before commencement 

of operations with heavy equipment.

(2) Final agency action. The Director's approval of a Permit-to-Drill shall be considered final 

agency action for purpose of judicial review.

(23) Operational conflicts. The Permit-to-Drill shall be binding with respect to any operationally 

conflicting local governmental permit or land use approval process.

(34) Exemptions. Wells drilled for stratigraphic information only shall be exempt from paying the 

filing and service fee. The re-entry of a well in a unitized, storage, or secondary recovery 

operation shall be exempt from the filing of Form 2 and from paying the filing and service 

fee. The notice of such intent to re-enter a well shall be filed on a Sundry Notice, Form 4.

b. A request to recomplete or deepen a well to a different reservoir or to side-track a well shall be filed on 

an Application for Permit-to-Drill, Form 2, with a filing and service fee established by the 

Commission (see Appendix III), along with a Sundry Notice, Form 4, detailing the work, and a 

wellbore diagram.

c. Attached to and part of the Permit-to-Drill, Form 2, as filed shall be a current 81⁄2" by 11" scaled 

drawing of the entire section(s) containing the proposed well location with the following minimum 

information:

(1) Dimensions on adjacent exterior section lines sufficient to completely describe the 

quarter section containing the proposed well shall be indicated. If dimensions are 

not field measured, state how the dimensions were determined.

(2) The latitude and longitude of the proposed well location shall be provided on the 

drawing with a minimum of five (5) decimal places of accuracy and precision 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 25

using the North American Datum (NAD) of 1983 (e.g.; latitude 37.12345 N, 

longitude 104.45632 W). If GPS technology is utilized to determine the latitude 

and longitude, all GPS data shall meet the requirements set forth in Rule 215. a. 

through h.

(3) For directional drilling into an adjacent section, that section shall also be shown on 

the location plat and dimensions on exterior section lines sufficient to completely 

describe the quarter section containing the proposed productive interval and 

bottom hole location shall be indicated. (Additional requirements related to 

directional drilling are found in Rule 321.)

(4) For irregular, partial or truncated sections, dimensions will be furnished to completely 

describe the entire section containing the proposed well.

(5) The field-measured distances from the nearer north/south and nearer east/west 

section lines shall be measured at ninety (90) degrees from said section lines to 

the well location and referenced on the plat. For unsurveyed land grants and 

other areas where an official public land survey system does not exist, the well 

locations shall be spotted as footages on a protracted section plat using Global 

Positioning System (GPS) technology and reported as latitude and longitude in 

accordance with Rule 215.

(6) A map legend.

(7) A north arrow.

(8) A scale expressed as an equivalent (e.g. - 1" = 1000').

(9) A bar scale.

(10) The ground elevation.

(11) The basis of the elevation (how it was calculated or its source).

(12) The basis of bearing or interior angles used.

(13) Complete description of monuments and/or collateral evidence found; all aliquot 

corners used shall be described.

(14) The legal land description by section, township, range, principal meridian, baseline 

and county.

(15) Operator name.

(16) Well name and well number.

(17) Date of completion of scaled drawing.

(18) All visible improvements within two hundred (200) feet of a wellhead (or, in a high 

density area within four hundred (400) feet of a wellhead) shall be physically tied 

in and plotted on the well location plat or on an addendum, with a horizontal 

distance and approximate bearing from the well location. Visible improvements 

shall include, but not be limited to, all buildings, publicly maintained roads and 

trails, major above-ground utility lines, railroads, pipelines, mines, oil wells, gas 

wells, injection wells, water wells, visible plugged wells, sewers with manholes, 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 26

standing bodies of water, and natural channels including permanent canals and 

ditches through which water may flow. If there are no visible improvements 

within two hundred (200) feet of a wellhead (or in a high density area within four 

hundred (400) feet of a wellhead), it shall be so noted on the Permit-to-Drill, Form 

2.

(19) Surface use shall be described within the two hundred (200) foot radius of a 

wellhead (or in a high density area within the four hundred (400) foot radius of a 

wellhead).

(20) In addition to the scaled drawing, the applicant shall attach to the Permit-to-Drill, 

Form 2, an 81⁄2" by 11" vicinity or U.S.G.S. topographic map of at least a three (3) 

mile radius around the proposed well which clearly shows access from one (1) or 

more public roads.

d. FORM orm 2/2A, OIL AND GAS LOCATION ASSESSMENTapplication and copies to local 

governmental designees.

(1) Drill Site/Access Road Reclamation Form, A completed Oil and Gas Location Assessment, 

Form 2A, shall be submitted for any new oil and gas location, unless exempted as set 

forth below. For purposes of this section, “new oil and gas location” shall mean surface 

disturbance at a previously undisturbed site or surface disturbance for purposes of 

modifying or expanding an oil and gas location in existence on May 1, 2009 on federal 

land or April 1, 2009 on all other land. In addition to the above, an applicant filing a 

Permit-to-Drill, Form 2, shall also attach a completed Form 2A, except that the Form 2A 

shall not be required on federal or Indian owned surface lands when a Federal 13 Point 

Surface Use Plan is included. 

(2) Exemptions. A new Form 2A shall not be required for the following: 

A. Surface disturbance, other than drilling a new well or constructing a drilling or 

production pit, occurring at an existing oil and gas facility within the originally 

disturbed area, even if interim reclamation has been performed; 

B. For an oil and gas location covered by an approved Comprehensive Drilling Plan and 

where such Comprehensive Drilling Plan contains information substantially 

equivalent to that which would be required for a Form 2A for the proposed oil 

and gas location and the Comprehensive Drilling Plan has been subject to 

procedures substantially equivalent to those required for a Form 2A, including but 

not limited to consultation with surface owners, local governments, the Colorado 

Department of Public Health and Environment or Colorado Division of Wildlife, 

where applicable, and public notice and opportunity to comment, and where the 

operator does not seek a variance from the Comprehensive Drilling Plan or a 

provision of these rules that is not addressed in the Plan; 

C. Gathering lines; 

D. Seismic operations; 

E. Pipelines for oil, gas, or water; or

F. Roads. 

(3) Information requirements. In all instances, tThe Form 2A requires the attachment of the 

following information. Where the information required under this section has been 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 27

included in a federal Surface Use Plan of Operations meeting the requirements of 

Onshore Oil and Gas Order Number 1 (72 Fed. Reg. 10308 (March 7, 2007)), or for a 

federal Right of Way, Form 299, then the operator may attach the completed pertinent 

information and identify on the Form 2A where the information required under this section 

may be found therein. 

A. Aa minimum of two four (24) color photographs;, one (1) of the staked location from 

each cardinal directionand one (1) of the existing or proposed access road. Each 

photograph shall be identified by: date taken, well or location name, location and 

direction of view.. Permit-to-Drill, Form 2, shall be filed with the Director in 

duplicate for wells on all private, state and federal surface lands.

B. A list of major equipment components to be used in conjunction with drilling and 

operating the well(s), including all tanks, pits, flares, combustion equipment, 

separators, and other ancillary equipment and a description of any pipelines for 

oil, gas, or water. 

C. A scaled drawing showing all visible improvements within four hundred (400) feet of 

the proposed oil and gas location, with a horizontal distance and approximate 

bearing from the oil and gas location. Visible improvements shall include, but not 

be limited to, all buildings or residences, publicly maintained roads and trails, 

major above-ground utility lines, railroads, pipelines, mines, oil wells, gas wells, 

injection wells, water wells known to the operator and those registered with the 

Colorado State Engineer, known springs, plugged wells, known sewers with 

manholes, standing bodies of water, and natural channels including permanent 

canals and ditches through which water may flow. A description of surface uses 

within the four hundred (400) foot radius of a proposed oil and gas location, if 

any, shall be attached to the scaled drawing. If there are no visible improvements 

within four hundred (400) feet of a proposed oil and gas location, it shall be so 

noted on the Form 2A.

D. A topographic map showing all surface waters and riparian areas within one thousand 

(1,000) feet of the proposed oil and gas location, with a horizontal distance and 

approximate bearing from the oil and gas location, as mapped in the Colorado 

Division of Wildlife’s Natural Diversity Information Source (NDIS) data set.

E. An 8 1/2” by 11” vicinity or U.S. Geological Survey topographic map showing the 

access road from the highway or county road providing access to the proposed 

oil and gas location.

F. Designation of the current land use(s) and landowner’s designated final land use(s) 

and basis for setting reclamation standards. 

i. If the final land use includes residential, industrial/commercial, or cropland and 

does not include any other uses, the land use should be indicated and no 

further information is needed.

ii. If the final land use includes rangeland, forestry, recreation, or wildlife habitat, 

then a reference area shall be selected and the following information 

shall be submitted:

aa. A topographic map showing the location of the site, and the location 

of the reference area; and
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 28

bb. Four (4) color photographs of the reference area, taken during the 

growing season of vegetation and facing each cardinal direction. 

Each photograph shall be identified by date taken, well or oil and 

gas location name, and direction of view. Provided that these 

photographs may be submitted at any time up to twelve (12) 

months after the Form 2A. 

G. Natural Resources Conservation Service (NRCS) soil map unit description.

H. If the oil and gas location disturbance is to occur on lands with a slope ten percent 

(10%) or greater, or one (1) foot of elevation gain or more in ten (10) foot 

distance, then the following shall be required:

i. Construction layout drawing (construction and operation); and

ii. Location cross-section plot (construction and operation). 

I. Where the proposed oil and gas location is for multiple wells on a single pad, a 

drawing showing proposed wellbore trajectory with bottom-hole locations. 

J. A description of any applicant-proposed Best Management Practices or, where a 

variance from a provision of these rules is sought, any applicant-proposed 

measures to meet the standards for such a variance. With the consent of the 

surface owner, this may include mitigation measures contained in the relevant 

surface use agreement. 

K. Where the proposed oil and gas location is covered by a Comprehensive Drilling Plan 

accepted pursuant to Rule 216, a list of any presumptive conditions of approval.

L. Contact information for the surface owner(s) and an indication as to whether there is a 

surface use agreement(s) or any other agreement(s) between the applicant and 

the surface owner(s) for the proposed oil and gas location.

M. Designation of whether the proposed oil and gas location is within sensitive wildlife 

habitat or a restricted surface occupancy area.

N. Where the proposed oil and gas location is within a zone defined in Rule 317B, Table 

1, documentation that the applicant has provided notification of the application 

submittal to potentially impacted public water systems within fifteen (15) stream 

miles downstream. 

O. Any additional data as reasonably required by the Commission as a result of 

consultation with the Colorado Department of Public Health and Environment or 

the Colorado Division of Wildlife. 

(4) Form 2A requiring approval.

A. The Oil and Gas Location Assessment, Form 2A, requires Commission or Director 

approval prior to approval of Permits-to-Drill, Form 2, or other permit applications, 

in the following circumstances: 

i. The proposed oil and gas location will disturb more than one (1) acre and is 

located in one of the following counties in Colorado: 

aa. Garfield;
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 29

bb. Mesa;

cc. Gunnison; or

dd. Rio Blanco. 

ii. The proposed oil and gas location requires consultation with the Colorado 

Division of Wildlife or the Colorado Department of Public Health and 

Environment, pursuant to Rules 306.c and 306.d, respectively; 

iii. The local governmental designee requests consultation on the proposed oil 

and gas location pursuant to Rule 306.b; or

iv. Where the proposed oil and gas location requires submittal of a Form 2A and 

the proposed oil and gas facility:

aa. Is a production facility; 

bb. Is servicing multiple wells; and

cc. Would not require any other Commission permit or facility 

registration. 

B. Where the Oil and Gas Location Assessment, Form 2A, requires approval, the 

operator shall file the Form 2A prior to or concurrent with a Permit-to-Drill, Form

2, for individual wells to be constructed at the oil and gas location. 

(5) Form 2A informational report.

Where a proposed oil and gas location is outside those situations described in Rule 

303.d.(4), the Oil and Gas Location Assessment, Form 2A, is a report that does not 

require approval prior to approval of Permits-to-Drill, Form 2. 

In these circumstances, the Form 2A shall be submitted concurrently with the Application 

for Permit-to-Drill, Form 2, or other permit applications, and it will be subject to 

completeness review pursuant to Rule 303.h.

(2) Form 2/2A to local governmental designee. A single, informational copy of the Permit-toDrill, Form 2 and Form 2A and all attachments shall be delivered by the applicant to the 

local governmental designee(s) of the county or municipal corporation within whose 

jurisdiction the activity is occurring or is proposed to occur at or before the time of filing 

with the Director. It shall be the responsibility of the Director to promptly provide the local 

governmental designee(s) with formal notification of the filing of the Permit-to-Drill, Form 

2, by posting the Permit-to-Drill, Form 2, and the posting date on the COGCC website.

(3) Comment period for local governmental designee. Any comments from the local 

governmental designee concerning the Permit-to-Drill, Form 2, and Form 2A as filed shall 

be provided to the Director and to the applicant in writing within ten (10) days after the 

date on which the Permit-to-Drill, Form 2 was posted on the COGCC website by the 

Director. The Director shall take no action with respect to the Permit-to-Drill, Form 2, prior 

to the expiration of the ten (10) day comment period, except under the circumstances 

provided for in Rule 303.j.(1) and (2), or when the Director has received notice from the 

local governmental designee(s) waiving the ten (10) day comment period. Upon written 

request by the local governmental designee to the Director received prior to the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 30

expiration of the ten (10) day comment period, the local governmental designee shall be 

granted an extension of up to twenty (20) additional days to consider the application.

(4) Application for hearing by Local Governmental Designee. If, prior to the expiration of the 

comment period provided herein, including any extension, and after participation in an 

onsite consultation under Rule 306.a.(3), the local governmental designee files an 

application for hearing on the Permit-to-Drill, Form 2, under Rule 503.b.(6), alleging 

significant impacts on public health, safety and welfare, including the environment, the 

Director shall withhold approval of such permit except that the provisions of Rule 303.k. 

shall apply.

e. Processing time for approvals under this section.

(1) In accordance with Rule 216.f.(3), where a proposed oil and gas location is covered by an 

approved Comprehensive Drilling Plan and no variance is sought from such Plan or these 

rules not addressed in the Comprehensive Drilling Plan, the Director shall give priority to 

and approve or deny an Application for Permit-to-Drill, Form 2, or, where applicable, Oil 

and Gas Location Assessment, Form 2A, within thirty (30) days of a determination that 

such application is complete pursuant to Rule 303.h, unless significant new information is 

brought to the attention of the Director. 

(2) If the Director has not issued a decision on an Application for Permit-to-Drill, Form 2, or, 

where approval is required, an Oil and Gas Location Assessment, Form 2A, within 

seventy-five (75) days of a determination that such application is complete, the operator 

may request a hearing before the Commission on the permit application. Such a hearing 

shall be expedited but will be held only after both the 20 days’ notice and the newspaper 

notice are given as required by Section 34-60-108, C.R.S. However, the hearing can be 

held after the newspaper notice if all of the entities listed under Rule 503.b waive the 20-

day notice requirement. 

ef. Oil and gas locations Well sites and access roads in wetlands. In the event that an operator, 

otherwise required to file a Form 2A, acquires an Army Corps of Engineers permit pursuant to 33 

U.S.C.A. §1342 and 1344 of the Water Pollution and Control Act (Section 404 of the federal 

“Clean Water Act”) for construction of an oil and gas location wellsite, access road, or production 

facility, the operator shall so indicate on the Oil and Gas Location Assessment, Form 2A.

fg. Revisions to Form 2 or Form / 2A. Prior to approval of the Form 2 or Form /2A permit application, 

minor revisions or requested information may be provided by contacting the COGCC staff. After 

approval, any substantive changes shall be submitted for approval on a Form 2 or Form /2A. A 

Sundry Notice, Form 4, shall be submitted, along with supplemental information requested by the 

Director, when non-substantive revisions are made after approval, and no additional fee shall be 

imposed.

gh. Incomplete applications. Applications for pPermit-to-dDrill, Form 2, or Oil and Gas Location 

Assessments, Form 2A, which are submitted without the required information and necessary 

attachments, the proper signature, or the required information, shall be considered incomplete 

and shall not be reviewed or approved. The COGCC staff shall notify the applicant in not more 

than thirty ten (310) days of permit application its receipt of the application of such inadequacies, 

except that the Director shall notify the applicant of inadequacies within three (3) business days of 

its receipt where the proposed oil and gas location is covered by an accepted Comprehensive 

Drilling Plan. The applicant shall then have thirty (30) days from the date that it was which they 

were contacted to correct and/or provide requested information for that well, otherwise the permit 

application shall be considered withdrawn and the fee shall not be refunded.

i. Information requests after completeness determination. Subsequent to deeming an Application for 

Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, complete, the Director 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 31

may request from the operator additional information needed to complete review of and make a 

decision on such an application. Such an information request shall not affect an operator’s ability 

to request a hearing pursuant to Rule 303.e seventy-five (75) days from the date the Form 2 or 

Form 2A was originally determined to be complete pursuant to Rule 303.h. 

hj. Permit expiration.

(1) For Applications for Permit-to-Drill, Form 2. If drilling operations are not commenced on 

the permitted well within one (1) year after the date of approval, then the permit approval 

shall become null and void. The Director shall not approve extensions to applications for 

Permit-to-Drill, Form 2.

(2) For Oil and Gas Location Assessments, Form 2A. If construction operations are not 

commenced on an approved oil and gas location within three (3) years after the date of 

approval, then the approval shall become null and void. The Director shall not approve 

extensions to Oil and Gas Location Assessments, Form 2A. 

ik. Permits in areas pending Commission hearing. The Director may withhold the issuance of a permit 

and the granting of approval of any Permit-to-Drill, Form 2, for any well or proposed well that is 

located in an area for which an application has been filed, or which the Commission has sought, 

by its own motion, to establish drilling units or to designate any tract of land as a high density 

area, in which case the hearing thereon shall be held at the next meeting of the Commission at 

which time the matter can be legally heard.

jl. Special circumstances for permit issuance without notice or consultation. The Director may 

issue a permit at any time in the event that an operator files a sworn statement and demonstrates 

therein to the Director's satisfaction that:

(1) The operator had the right or obligation under the terms of an existing contract to drill a well; 

and the owner or operator has a leasehold estate or a right to acquire a leasehold estate 

under said contract which will be terminated unless the operator is permitted to 

immediately commence the drilling of said well; or

(2) Due to exigent circumstances (including a recent change in geological interpretation), 

significant economic hardship to a drilling contractor will result or significant economic 

hardship to an operator in the form of drilling standby charges will result.

In the event the Director issues a permit under this rule, the operator shall not be required to meet 

obligations to surface owners, and local governmental designees, the Colorado Department of 

Public Health and Environment, or the Colorado Division of Wildlife under Rule 305 (except Rules 

305.e.(4) and 305.e.(6), for which compliance will still be required)s 303.d., 305.b.(1) & (3), and 

306.a. The Director shall report permits granted in such manner to the Commission at regularly 

scheduled monthly hearings.

km. Special circumstances for wWithholding approval of aApplication for Permit-to-Drill, Form 2, 

or Oil and Gas Location Assessment, Form 2A.

(1) The Director may withhold approval of any Application for Permit-to-Drill, Form 2, or Oil and 

Gas Location Assessment, Form 2A, for any proposed well or oil and gas location when, 

based on information supplied in a written complaint submitted by any party with standing 

under Rule 522.a.(1), other than a local governmental designee, or by staff analysis, the 

Director has reasonable cause to believe the proposed well or oil and gas location is in 

material violation of the Commission's rules, regulations, orders or statutes, or otherwise 

presents an imminent threat to public health, safety and welfare, including the 

environment or wildlife resources. Any such withholding of approval shall be limited to the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 32

minimum period of time necessary to investigate and dismiss the complaint, or to resolve 

the alleged violation or issue. If the complaint is dismissed or the matter resolved to the 

dissatisfaction of the complainant, such person may consult with the parties identified in 

local governmental designee pursuant to Rule 503.b.(7)303.d.(4).

(2) The Director shall withhold approval of any Application for Permit-to-Drill, Form 2, for any 

proposed well, when a request for a hearing is made by a local governmental designee in 

accordance with Rules 303.d.(4) and 503.b.(6), unless the local government has been 

disqualified from making such request under Rule 501.b.

(23) In the event the Director withholds approval of any Application for Permit-To-Drill, Form 2, or 

Oil and Gas Location Assessment, Form 2A, under this Rule 303.km., an operator may 

ask the Commission to issue an emergency order rescinding the Director's decision.

4) Any hearing granted pursuant to this Rule 303.k. shall be expedited and the matter shall be 

heard at the next scheduled Commission hearing, and all parties shall be deemed to 

have waived any notice requirements to the contrary. The Director shall use best efforts 

to notify the parties of any such hearing.

ln. Suspending approved Permit-To-Drill, Form 2. Prior to the spudding of the well, the Director shall 

suspend an approved Permit-to-Drill, Form 2, if the Director has reasonable cause to believe that 

information submitted on the Permit-to-Drill, Form 2 was materially incorrect. Under the 

circumstances described in Rule 303.lj.(1) or (2), an operator may ask the Commission to issue 

an emergency order rescinding the Director's decision.

mo. Reclassification of stratigraphic well. If a test for productivity is made in a stratigraphic well, the 

well must be reclassified as a well drilled for oil or gas and is subject to all of the rules and 

regulations for well drilled for oil or gas, including filing of reports and mechanical logs.

np. Provisions for avoiding mine sites. Any person holding, or who has applied for, a permit issued or 

to be issued under §34-33-101 to 137, C.R.S., may at their election, notify the Director of such 

permit or application. Such notice shall include the name, mailing address and facsimile number 

of such person and designate by legal description the life-of-mine area permitted, or applied for, 

with the Division of Reclamation, Mining, and SafetyMinerals and Geology. As soon as 

practicable after receiving such notice and designation, the Director shall inform the party 

designated therein each time that a Permit-to-Drill, Form 2, is filed with the Director which 

pertains to a well or wells located or to be located within said life-of-mine area as designated. The 

provisions of Rule 303.jl.(1) and (2) will not be applicable to this rule.

304. FINANCIAL ASSURANCE REQUIREMENTS

Prior to drilling or assuming the operations for a well an operator shall provide financial assurance in 

accordance with the 700 Series rules. When an operator's existing wells are not in compliance with the 

700 Series, the Director may withhold action on an Application for Permit-to-Drill, Form 2, or Oil and Gas 

Location Assessment, Form 2A, until such time as a hearing on the permit application is held by the 

Commission. Such hearing shall be held at the next regularly scheduled Commission hearing at which 

time the matter can be legally heard.

305. NOTICES OF OIL AND GAS OPERATIONS

a. The provisions of this Rule 305, shall not be applicable on federal or Indian owned surface lands.

b. Notices .
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 33

(1) Notice of drilling . Before an operator shall commence operations for the drilling of any well, 

such operator shall evidence its intention to conduct such operations by giving the 

surface owner and local governmental designee written notice thereof as provided in 

subparagraph c. below. Such notice of drilling shall be mailed or hand delivered to the 

surface owner not less than thirty (30) days prior to the date of estimated commencement 

of operations with heavy equipment as set forth in the notice and shall be mailed to the 

local governmental designee not less than thirty (30) days prior to the date of estimated 

commencement of operations with heavy equipment as set forth in the notice. Operators 

shall retain a record of such notice of drilling for a minimum of one (1) year. Such written 

notice also shall be posted on or near the proposed drillsite at least thirty (30) days prior 

to commencement of operations with heavy equipment. If notice for the commencement 

of operations is waived by the surface owner under this rule, the local governmental 

designee notice under this Rule 305.b. shall be received no later than the business day 

preceding commencement of operations with heavy equipment. The operator shall 

confirm that the surface owner notice requirements of this Rule 305.b have been 

completed or waived before the Director approves an Application for Permit-to-Drill, Form 

2.

(2) Notice of subsequent well operations . Before an operator shall commence subsequent 

well operations, such operator shall evidence its intention to conduct such operations by 

giving the surface owner written notice thereof in accordance with paragraph c. below 

Subsequent well operations shall mean those operations that will materially impact 

surface areas beyond the existing access road or well site for any well, including 

operations such as fracturing or recompletion of the well but shall not include routine 

service and maintenance operations including but not limited to the changing of pumps. 

The notice of subsequent operations shall be mailed or hand delivered not less than 

seven (7) days prior to the date of estimated commencement of operations with heavy 

equipment as set forth in the notice.

(3) Notice during irrigation season . If a well is to be drilled on irrigated crop lands between 

March 1 and October 31, the operator, in addition to meeting the consultation 

requirements of Rule 306., shall contact the surface owner, or at the request of the 

surface owner, the tenant at least fourteen (14) days prior to the commencement of 

surface activities by the operator and arrange to coordinate drilling operations to avoid 

unreasonable interference with irrigation plans and activities.

(4) Final reclamation notice . The following notice requirement shall apply only to final 

reclamation operations commenced more than thirty (30) days after the completion of a 

well.

A Not less than thirty (30) days before any final reclamation operations are to take place 

pursuant to Rule 1004., the operator shall notify the surface owner in accordance 

with paragraph c. below. Final reclamation operations shall mean those 

reclamation operations to be undertaken when a well is to be plugged and 

abandoned or when production facilities are to be permanently removed.

c Notice requirements . As to notices to be given pursuant to this Rule 305., included with each such 

notice shall be the following.

(1) The estimated date that the operations for which notice is being given are to commence.

(2) The name of the operator and the name, address and phone number of the individual 

representing the operator who can be contacted concerning the proposed operations.

(3) The legal description (or plat) indicating the quarter quarter section upon which the operations 

will be conducted.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 34

(4) A statement that the surface owner has responsibility for notifying any affected tenant of the 

proposed operations.

(5) With respect to the notices of drilling, the notice mailed or hand delivered to the surface 

owner shall also include a return addressed, postage prepaid postcard upon which 

surface owners may request their preference with respect to the consultation requirement 

under Rule 306., including the preference to appoint a tenant for consultation. If the 

surface owner appoints a tenant for consultation, that person's name, address, and 

telephone number must be provided to the operator by the surface owner on the 

postcard.

(6) A copy of the Commission's informational brochure for surface owners, containing the rules 

pertaining to notice of oil and gas operations and opportunities for consultation thereon, 

as well as the rules of procedure for filing complaints and making applications for hearing. 

The brochure shall provide contact information for the Commission's main office, field 

offices and website, and shall describe the services and information available to the 

public, including access to a listing of local governmental designees. The brochure shall 

contain a prominent disclaimer advising surface owners to obtain legal advice as may be 

appropriate to their particular circumstances.

d Identifying surface owner . In determining the identity and address of a surface owner for the 

purpose of giving all notices under this Rule 305., the records of the assessor for the county in 

which the lands are situated may be relied upon.

e Tenants . With respect to notices given under this Rule 305., it shall be the responsibility of the 

notified surface owner to give notice of the proposed operation to the tenant farmer, lessee or 

other party that may own or have an interest in any crops or surface improvements that could be 

affected by such proposed operation.

f Waiver . Any and all of the surface owner notice requirements set forth in this Rule 305, may be 

waived by the affected surface owner at any time. Any and all local governmental designee notice 

requirements set forth in this Rule 305, may be waived by the affected local governmental 

designee(s) at any time.

305. NOTICE, COMMENT, APPROVAL

a. Applicability. The provisions of Rule 305.e regarding surface owners shall not apply to federal or 

Indian-owned surface lands. 

b. Posting.

(1) Form 2A. Upon receipt of an Oil and Gas Location Assessment, Form 2A, the Director shall, 

as provided by Rule 303.h, determine if the application is complete and, if so, post such 

Form 2A on the Commission’s website. The Commission shall provide concurrent 

electronic notice of such posting to the relevant local governmental designee (LGD) and 

the Colorado Division of Wildlife (where consultation is triggered pursuant to Rule 306.c) 

and the Colorado Department of Public Health and Environment (where consultation is 

triggered pursuant to Rule 306.d). The website posting shall clearly indicate:

A. The date on which the Form 2A was posted; 

B. The date by which public comments must be received to be considered; 

C. The address(es) to which the public may direct comments; and
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 35

D. Where the proposed oil and gas location is covered by an accepted Comprehensive 

Drilling Plan, directions for review of the Plan. 

(2) Form 2. If an Application for Permit-to-Drill, Form 2, is concurrently filed with a Form 2A, that 

fact shall be noted in the posting provided herein. If a Form 2 is subsequently filed, only a 

summary notice of such filing, indicating that a Form 2A covering the well has been 

previously approved, shall be posted, with concurrent notice to the local governmental 

designee and, where consultation with one of those agencies is triggered, the Colorado 

Division of Wildlife or Colorado Department of Public Health and Environment. 

c. Comment period. The Director shall not approve the Form 2A, or any associated Form 2, for twenty 

(20) days from posting pursuant to Rule 305.b, and shall accept and post on the Commission’s 

website immediately upon their receipt any comments received from the public, the local 

governmental designee, the Colorado Department of Public Health and Environment, or the 

Colorado Division of Wildlife regarding the proposed oil and gas location. The Director shall 

extend the comment period to thirty (30) days upon the written request during the twenty (20) day 

comment period by the local governmental designee, the Colorado Department of Public Health 

and Environment, the Colorado Division of Wildlife, the surface owner, or an owner of surface 

property who receives notice under Rule 305.e. The Director shall post the extension on the 

COGCC website within twenty-four (24) hours of receipt of the extension request. 

d. Conditions of approval; issuance of permit. Upon the conclusion of the comment period and, where 

applicable, consultation with the Colorado Division of Wildlife or Colorado Department of Public 

Health and Environment pursuant to Rules 306.c. or 306.d, respectively, the Director may attach 

technically feasible and economically practicable conditions of approval to the Form 2 or Form 2A 

as the Director deems necessary to implement the provisions of the Act or these rules pursuant to 

Commission staff analysis or to respond to legitimate concerns expressed during the comment 

period. Provided, that an applicant under Rule 503 who claims that such a condition is not 

technically feasible, economically practicable, or necessary to implement the provisions of the Act 

or these rules, or to respond to legitimate concerns shall have the burden of proof on that issue 

before the Commission. 

(1) Notice of decision. Upon making a decision on an Application for Permit-to-Drill, Form 2, or 

Oil and Gas Location Assessment, Form 2A, the Director shall promptly provide 

notification of the decision and any conditions of approval to the operator and to any party

with standing to request a hearing before the Commission pursuant to Rule 503.b, unless 

such a party has waived in writing its right to such notice and the Director has been 

provided a copy of such waiver. 

(2) Suspension of approval. If a party with standing to do so requests a hearing before the 

Commission pursuant to Rule 503.b on an Application for Permit-to-Drill, Form 2, or Oil 

and Gas Location Assessment, Form 2A, then it shall notify the Director in writing within 

ten (10) days after the issuance of the decision, setting forth the basis for the objection. 

Upon receipt of such an objection, the Director shall suspend the approval of the Form 2 

or Form 2A and set the matter for an expedited adjudicatory hearing. Such a hearing 

shall be expedited but will only be held after both the 20 days’ notice and the newspaper 

notice are given as required by Section 34-60-108, C.R.S. However, the hearing can be 

held after the newspaper notice if all of the entities listed under Rule 503.b waive the 20-

day notice requirement. If such an objection is not received, the permit shall issue as 

proposed by the Director.

(3) Appeal. If the approval of a Form 2 or Form 2A is not suspended as provided for herein, the 

issuance of the approved Form 2 or Form 2A by the Director shall be deemed a final 

decision of the Commission, subject to judicial appeal. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 36

e. Landowner notice; copy of advance notice to Local Governmental Designee. An operator making 

application for approval of an Oil and Gas Location Assessment, Form 2A, shall, upon receipt of a 

completeness determination from the Director, promptly provide the surface owner and owners of 

surface property within five hundred (500) feet of the proposed oil and gas location with the 

information set out in Rule 305.e.(1).A, below (“landowner notice”); provided that notice to the 

owners of surface property within five hundred (500) feet of the proposed oil and gas location 

shall not be required in an area covered by Rules 318A or 318B. This notice is in addition to the 

statutorily required notice to surface owners (“advance notice”), which must be provided thirty 

(30) days in advance of commencement of operations with heavy equipment for the drilling of a 

well. The operator may rely on the tax records of the assessor for the county in which the affected 

lands are located to identify the surface owner and the owners of surface property within five 

hundred (500) feet of the proposed oil and gas location for purposes of this section. A copy of the 

advance notice shall also be provided to the local government in whose jurisdiction the well is to 

be drilled, if such local government has registered its local governmental designee with the 

Commission. The notices required herein shall be accomplished by hand delivery or by certified 

mail, return-receipt requested. 

(1) Content of notices.

A. Landowner Notice. The landowner notice shall include the Form 2A itself (without 

attachments), a copy of the information required under Rule 303.d.(3).B, 

303.d.(3).C, and 303.d.(3).E and any additional information the operator deems 

appropriate and inform the recipient that the complete application (including 

attachments) may be reviewed on the COGCC website and that he or she may

submit comments to the Director, as provided on the COGCC website. For the 

surface owner, this notice shall include a copy of the COGCC Informational 

Brochure for Surface Owners, a postage-paid, return-addressed post card 

whereby the surface owner may request consultation pursuant to Rule 306, and, 

where the oil and gas location is not subject to a surface-use agreement, a copy 

of the COGCC Onsite Inspection Policy (See Appendix or COGCC website). 

B. Advance Notice. The advance notice must provide the operator’s name and contact 

information for a representative who may be contacted, describe on a site 

diagram or plat the proposed location of the well and any associated roads and 

production facilities, and indicate the expected date of commencement of 

operations with heavy equipment. 

(2) Appointment of agent. The surface owner may appoint an agent, including its tenant, for 

purposes of subsequent notice and for consultation under Rule 306. Such appointment 

shall be made in writing to the operator and must provide the agent’s name, address, and 

telephone number. 

(3) Tenants. With respect to notices given under this Rule 305, it shall be the responsibility of the 

notified surface owner to give notice of the proposed operation to the tenant farmer, 

lessee, or other party that may own or have an interest in any crops or surface 

improvements that could be affected by such proposed operation. 

(4) Notice of subsequent well operations. An operator shall provide to the surface owner or 

agent at least seven (7) days advance notice of subsequent well operations with heavy 

equipment that will materially impact surface areas beyond the existing access road or 

well site, such as recompletion or refracturing of the well. 

(5) Notice during irrigation season. If a well is to be drilled on irrigated crop lands between 

March 1 and October 31, the operator shall contact the surface owner or agent at least 

fourteen (14) days prior to commencement of operations with heavy equipment to 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 37

coordinate drilling operations to avoid unreasonable interference with irrigation plans and 

activities. 

(6) Final reclamation notice. Not less than thirty (30) days before any final reclamation 

operations are to take place pursuant to Rule 1004, the operator shall notify the surface 

owner. Final reclamation operations shall mean those reclamation operations to be 

undertaken when a well is to be plugged and abandoned or when production facilities are 

to be permanently removed. Such notice is required only where final reclamation 

operations commence more than thirty (30) days after the completion of a well. 

(7) Waiver. Any of the notices required herein may be waived in writing by the surface owner, its 

agent, or the local governmental designee, provided that a waiver by a surface owner or 

its agent shall not prevent the surface owner or any successor-in-interest to the surface 

owner from rescinding that waiver if such rescission is in accordance with applicable law. 

f. Posting. The operator shall, concurrent with the advance notice, post a sign at the intersection of the 

lease road and the public road providing access to the well site, of not less than two-feet by twofeet, providing the name of the proposed well, the legal location thereof, and the estimated date 

of commencement. Such sign shall be maintained until completion operations at the well are 

concluded. 

306. CONSULTATION.

In locating roads, production facilities and well sites, and in preparation for reclamation and final 

abandonment, tThe operator shall use its best efforts to consult in good faith, as provided below. with the 

affected surface owner, or the surface owner's appointed tenant as provided for in Rule 305. Consultation 

with local governmental designees is addressed in Rule 306.a. (3) below. The following shall apply to 

each such consultation:

a. Drilling cConsultation with surface owner. In locating roads, production facilities, and well sites, or 

other oil and gas operations, and in preparation for reclamation and abandonment, the operator 

shall consult in The good faith with the surface owner, or the surface owner’s appointed agent as 

provided for in Rule 305. Such consultation effort to consult shall occur at a time mutually agreed 

to by the parties prior to the commencement of operations with heavy equipment upon the lands 

of the surface owner. The operator shall confirm that the surface owner consultation requirements 

of this Rule 306, have been completed or waived before the Director approves an Application for 

Permit-to-Drill, Form 2.

(1) Information provided by operator. When consulting with the surface owner or appointed 

tenantagent, the operator shall furnish a description or diagram of the proposed drilling 

location; dimensions of the drill site; topsoil management practices to be employed; and, 

if known, the location of associated production or injection facilities, pipelines, roads and 

any other areas to be used for oil and gas operations (if not previously furnished to such 

surface owner or if different from what was previously furnished).

(2) Good faith consultation. Such good faith consultation shall allow the surface owner or 

appointed tenant agent the opportunity to provide comments to the operator regarding 

preferences for the timing of oil and gas operations and preferred locations for wells and 

associated facilities.

(3) Waiver. The requirement to consult with the surface owner may be waived by the affected 

surface owner or the surface owner’s appointed agent at any time by submittal to the 

operator in writing. 

(3)b. Consultation with lLocal government consultation. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 38

(1) Local governments which that have appointed a local governmental designee and have 

indicated to the Director a desire for onsite consultation shall be given an opportunity to 

engage in such consultation concerning an application for Permit-to-Drill, Form 2, or an 

Oil and Gas Location Assessment, Form 2A, for the location of roads, production facilities 

and well sites prior to the commencing of operations with heavy equipment.

(2) Within fourteen (14) days of its notification pursuant to Rule 305, the local governmental 

designee may notify the Commission and the Colorado Department of Public Health and 

Environment by electronic mail of its desire to have the Colorado Department of Public 

Health and Environment consult on a proposed oil and gas location, based on concerns 

regarding public health, safety, welfare, or impacts to the environment. 

c. Consultation with the Colorado Division of Wildlife.

(1) Consultation to occur.

A. Subject to the provisions of Rule 1202.d, an operator shall consult with the 

Commission, the surface owner, and the Colorado Division of Wildlife on an Oil 

and Gas Location Assessment, Form 2A, where:

i. Consultation is required pursuant to a provision in the 1200-Series of these 

rules; 

ii. The operator seeks a variance from a provision in the 1200-Series of these 

rules; or

iii. The Colorado Division of Wildlife requests consultation because the proposed 

oil and gas location would be within areas of known occurrence or 

habitat of a federally threatened or endangered species, as shown on the 

Colorado Division of Wildlife Species Activity Mapping (SAM) system. 

B. The Commission shall consult with the Colorado Division of Wildlife when an operator 

requests a modification of an existing Commission order to increase well density 

or otherwise proposes to increase well density to more than one (1) well per forty 

(40) acres, or the Commission develops a basin-wide order involving wildlife or 

wildlife-related environmental concerns or protections.

C. Notwithstanding the foregoing, the requirement to consult with the Colorado Division 

of Wildlife may be waived by the Colorado Division of Wildlife at any time. 

(2) Procedure for consultation.

A. The operator shall provide: 

i. A description of the oil and gas operation to be considered, including location; 

ii. Any other relevant available information on the oil and gas operation, the 

affected wildlife resource, or the provision(s) of the 1200-Series Rules 

upon which the consultation is based; and

iii. Proposed mitigation for the affected wildlife resource. 

B. The Commission shall take into account the information submitted by the operator 

consistent with Rule 1202.c. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 39

C. The operator, the Commission, the surface owner, and the Colorado Division of 

Wildlife shall have forty (40) days to conduct the consultation called for in this 

section. Such consultation shall begin concurrent with the start of the public 

comment period. If no consultation occurs within such 40-day period, the 

requirement to consult shall be deemed waived, and the Director shall consider 

the operator’s application on the basis of the materials submitted by the operator. 

(3) Results of consultation under Rule 306.c.

A. As a result of consultation called for in this subsection, the Colorado Division of 

Wildlife may make written recommendations to the Commission on conditions of 

approval necessary to minimize adverse impacts to wildlife resources. Where 

applicable, the Colorado Division of Wildlife may also make written 

recommendations on whether a variance request should be granted, under what 

conditions, and the reasons for any such recommendations. 

B. Agreed-upon conditions of approval. Where the operator, the Director, the 

Colorado Division of Wildlife, and the surface owner agree to conditions of 

approval for oil and gas locations as a result of consultation, these conditions of 

approval shall be incorporated into approvals of an Oil and Gas Location 

Assessment, Form 2A, or Application for Permit-to-Drill, Form 2, where 

applicable. 

C. Permit-specific conditions. Where the consultation called for in this subsection 

results in permit-specific conditions of approval to minimize adverse impacts to 

wildlife resources, the Director shall attach such permit-specific conditions only 

with the consent of the affected surface owner. 

D. Standards for consultation and initial decision. Following consultation and subject 

to subsection C above and Rule 1202.c, the Director shall decide whether to 

attach conditions of approval to a Form 2A or Form 2, where applicable. In 

making this decision, the Director shall apply the criteria of Rule 1202. 

E. Notification of decision to consulting agency. Where consultation occurs under 

Rule 306.c, the Director shall provide to the Colorado Division of Wildlife the 

conditions of approval for the Application for Permit-to-Drill, Form 2, or Oil and 

Gas Location Assessment, Form 2A, on the same day that he or she announces 

a decision to approve the application. 

d. Consultation with the Colorado Department of Public Health and Environment.

(1) Consultation to occur.

A. The Commission shall consult with the Colorado Department of Public Health and 

Environment on an Oil and Gas Location Assessment, Form 2A, where: 

i. The local governmental designee requests, within fourteen (14) days of notice, 

the participation of the Colorado Department of Public Health and 

Environment in the Commission’s consideration of an Application for 

Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, 

based on concerns regarding public health, safety, welfare, or impacts to 

the environment; 

ii. The operator seeks from the Director a variance from, or consultation is 

otherwise required or permitted under, a provision of one of the following 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 40

rules intended for the protection of public health, safety, welfare, or the 

environment: 

aa. Rule 317B. Public Water System Protection;

bb. Rule 325. Underground Disposal of Water; 

cc. Rule 603. Drilling and Well Servicing Operations and High Density 

Area Rules;

dd. Rule 608. Coalbed Methane Wells; 

ee. Rule 805. Odors and Dust. 

ff. 900-Series E&P Waste Management; or

gg. Rule 1002.f. Stormwater Management. 

All requests for variances from these rules must be made at the time an 

operator submits a Form 2A. 

B. The Commission shall consult with the Colorado Department of Public Health and 

Environment when an operator requests a modification of an existing 

Commission order to increase well density or otherwise proposes to increase 

well density to more than one (1) well per forty (40) acres, or the Commission 

develops a basin-wide order that can reasonably be anticipated to have impacts 

on public health, welfare, safety, or environmental concerns or protections. 

C. Notwithstanding the foregoing, the requirement to consult with the Colorado 

Department of Public Health and Environment may be waived by the Colorado 

Department of Public Health and Environment at any time. 

(2) Procedure for consultation.

A. Where required, the Commission and the Colorado Department of Public Health and 

Environment shall have forty (40) days to conduct the consultation called for in 

this section. Such consultation shall begin concurrent with the start of the public 

comment period. If no consultation occurs within such 40-day period, the 

requirement to consult shall be waived, and the Director shall consider the 

operator’s application on the basis of the materials submitted by the operator. 

B. The consultation called for in this section shall focus on identifying potential impacts to 

public health, safety, welfare, or the environment from activities associated with 

the proposed oil and gas location, and development of conditions of approval or 

other measures to minimize adverse impacts. 

C. Where consultation occurs pursuant to Rule 306.d.(1).A, it may include:

i. Review of the permit application; 

ii. Discussions with the local governmental designee to better understand local 

government’s concerns; 

iii. Discussions with the Commission, operator, surface owner, or those 

potentially affected; and 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 41

iv. Review of public comments. 

D. Where consultation occurs pursuant to Rule 306.d.(1).A.ii, the Colorado Department 

of Public Health and Environment shall have the opportunity to: 

i. Review the permit application, the request for variance, and the basis for the 

request; and

ii. Discuss the request with the operator, the surface owner, and the 

Commission. 

E. Where consultation occurs pursuant to Rule 306.d.(1).B, the Colorado Department of 

Public Health and Environment shall have the opportunity to: 

i. Review the well-density increase application or draft Commission order; and

ii. Discuss the request with the operator or proponent, the Commission, and the 

local governmental designee. 

(3) Results of consultation under Rule 306.d.

A. As a result of consultation called for in this subsection, the Colorado Department of 

Public Health and Environment may make written recommendations to the 

Commission on conditions of approval necessary to protect public health, safety, 

and welfare or the environment. Such recommendations may include, but are not 

limited to, monitoring requirements or best management practices. Where 

applicable, the Colorado Department of Public Health and Environment may also 

make written recommendations on whether a variance request should be 

granted, under what conditions, and the reasons for any such recommendations. 

B. Agreed-upon conditions of approval. Where the operator, the Director, the 

Colorado Department of Public Health and Environment, and the surface owner 

agree to conditions of approval for oil and gas locations as a result of 

consultation, these conditions of approval shall be incorporated into approvals of 

an Oil and Gas Location Assessment, Form 2A, or Applications for Permit-toDrill, Form 2, where applicable. 

C. Standards for consultation and Director decision. Following consultation, the 

Director shall decide whether to attach conditions of approval recommended by 

the Colorado Department of Public Health and Environment to a Form 2A or 

Form 2, where applicable. This decision shall minimize significant adverse 

impacts to public health, safety, and welfare, including the environment, 

consistent with other statutory obligations. 

D. Notification of decision to consulting agency. Where consultation occurs under 

Rule 306.d, the Director shall provide to the Colorado Department of Public 

Health and Environment the conditions of approval for the Application for Permitto-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, on the same day 

that he or she announces a decision to approve the application. 

be. Final reclamation consultation. In preparing for final reclamation and plugging and abandonment, 

the operator shall use its best efforts to consult in good faith with the affected surface owner (or 

the tenant when the surface owner has requested that such consultation be made with the 

tenant). Such good faith consultation shall allow the surface owner (or appointed tenantagent) the 

opportunity to provide comments concerning preference for timing of such operations and all 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 42

aspects of final reclamation, including, but not limited to, the desired final land use and seed mix 

to be applied.

c. Tenants. Operators shall have no obligation to consult with tenant farmers, lessees, or any other party 

(“tenant” ) that may own or have an interest in any crops or surface improvements that could be 

affected by the proposed operation unless the surface owner appoints such person as its agent 

tenant for such purposes. Nothing shall prevent the surface owner from including the a tenant 

during in any the consultation, whether or not appointed as the surface owner’s agent.

d. Waiver. The requirement to consult with the surface owner under this Rule 306, may be waived by the 

affected surface owner or the surface owner's appointed tenant at any time.

307. COGCC Form 4. SUNDRY NOTICES AND REPORTS ON WELLS

The Sundry Notice, Form 4, is a multipurpose form which shall be used by an operator to request 

approval from or provide notice to the Director as required by rule or when no other specific form exists, 

i.e., well name or number change. The rules requiring the use of the Sundry Notice, Form 4, are listed in 

Appendix I.

308A. COGCC Form 5. DRILLING COMPLETION REPORT

Within thirty (30) days of the setting of production casing, the plugging of a dry hole, the deepening or 

sidetracking of a well, or any time the wellbore configuration is changed, the operator shall transmit to the 

Director the Drilling Completion Report, Form 5, and two (2) copies of all logs run, be they mechanical, 

mud, or other, submitted as one (1) paper copy and, as available, one (1) digital LAS (log ASCII) 

formatted copy, or a format approved by the Director. Additionally, if drill stem tests, core analyses, or 

directional surveys are run, they shall be submitted at the same time and together with this completion 

report. All Sections 1 - 22 (if applicable) and the attachment checklist shall be completely filled out. The 

latitude and longitude coordinates in decimal degrees to an accuracy and precision of five (5) decimals of 

a degree using the North American Datum (NAD) of 1983 (e.g.; latitude 37.12345 N, longitude 104.45632 

W), Position Dilution of Precision (PDOP) reading, instrument operator’s name and the date of the 

measurement of the “as drilled” well location shall be reported on the Form 5. If GPS technology is 

utilized to determine the latitude and longitude, all GPS data shall meet the requirements set forth in Rule 

215. a. through h.

Within thirty (30) days of the suspension of commenced drilling activities prior to reaching total depth, the 

operator shall file a Drilling Completion Report, Form 5, notifying the Director of the date of such 

suspension of drilling activity stating the reason for suspension and the anticipated date and method of 

resumption of drilling, showing the details of all work performed to date. In cases of an uncompleted well, 

the initial Drilling Completion Report, Form 5, shall state "preliminary" at the top of the form. A 

supplementary Form 5 shall be submitted within thirty (30) days of reaching total depth.

308B. COGCC Form 5A. COMPLETED INTERVAL REPORT

The Completed Interval Report, Form 5A, shall be submitted within thirty (30) days of completing a 

formation (successful or not), when a formation is temporarily abandoned or permanently abandoned, for 

a recompletion, reperforation or restimulation, or when a formation is commingled.

In order to resolve completed interval information uncertainties, the Director may require an operator to 

submit a Completed Interval Report, Form 5A.

308C. CONFIDENTIALITY

Upon submittal of a Sundry Notice, Form 4, request by the operator, completion reports, including Drilling 

Completion Reports, Form 5 and Completed Interval Reports, Form 5A, and mechanical logs of 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 43

exploratory or wildcat wells shall be marked “confidential” by the Director and kept confidential for six (6) 

months after the date of completion, unless the operator gives written permission to release such logs at 

an earlier date.

309. COGCC Form 7. OPERATOR'S MONTHLY PRODUCTION REPORT

Each producer or operator of an oil or gas well shall file with the Commission, within forty-five (45) days 

after the month in which production occurs, a report on Operator's Monthly Production Report, Form 7, 

containing all information required by said form. In addition, all fluids produced during the initial testing 

and completion shall be reported on Operator's Monthly Production Report, Form 7 within forty-five (45) 

days after the month in which testing and completion occurs.

310. COGCC Form 8. MILL LEVY

On or before March 1, June 1, September 1 and December 1 of each year, every producer or purchaser, 

whichever disburses funds directly to each and every person owning a working interest, a royalty interest, 

an overriding royalty interest, a production payment and other similar interests from the sale of oil or 

natural gas subject to the charge imposed by §34-60-122(1) (a) C.R.S., 1973, as amended, shall file a 

return with the Director showing by operator, the volume of oil, gas or condensate produced or purchased 

during the preceding calendar quarter, including the total consideration due or received at the point of 

delivery. No filing shall be required when the charge imposed is zero mill ($0.0000) per dollar value. Eff 

09/30/2007

The levy shall be an amount fixed by order of the Commission. The levy amount may, from time to time, 

be reduced or increased to meet the expenses chargeable against the oil and gas conservation and 

environmental response fund. The present charge imposed, as of July 1, 2007, is seven tenths of a mill 

($0.0007) per dollar value. Eff 09/30/2007

311. COGCC Form 6. WELL ABANDONMENT REPORT

Notice shall be given to the Director, and approval obtained in advance of the time the operator expects 

to abandon a well on Form 6. When filing an intent to abandon, the form shall be completed and 

attachments included to fully describe the proposed operations. This includes the proposed depths of 

mechanical plugs and casing cuts, the proposed depths and volumes of all cement plugs, the amount, 

size and depth of casing and junk to be left in the well, the volume and weight of fluid to be left in the 

wellbore and the nature and quantities of any other materials to be used in the plugging. If the well is not 

plugged within six (6) months of intent approval a new intent shall be filed.

Within thirty (30) days after abandonment, the Well Abandonment Report, Form 6, shall be filed with the 

Director. The abandonment details shall include an account of the manner in which the abandonment or 

plugging work was performed. Additionally, plugging verification reports detailing all procedures are 

required. A Plugging Verification Report shall be submitted for each person or contractor actually setting 

the plugs. The Well Abandonment Report, Form 6, and the Plugging Verification Reports shall detail the 

depths of mechanical plugs and casing cuts, the depths and volumes of all cement plugs, the amount, 

size and depth of casing and junk left in the well, the volume and weight of fluid left in the wellbore and 

the nature and quantities of any other materials used in the plugging. Plugging Verification Reports shall 

conform with the operator's report and both shall show that plugging procedures are at least as extensive 

as those approved by the Director. When filing a subsequent report of abandonment, the entire form shall 

be completed except for the second block, background information. (See Rule 319 for well abandonment 

requirements and procedures.)

312. COGCC Form 10. CERTIFICATE OF CLEARANCE AND/OR CHANGE OF OPERATOR

a. Each operator of any oil or gas well completed after April 30, 1956, shall file with the Director, within 

thirty (30) days after initial sale of oil or gas a Certificate of Clearance and/or Change of Operator, 

Form 10, in accordance with the instructions appearing on such form, for each well producing oil 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 44

or gas or both oil and gas. A Certificate of Clearance shall be filed for any well from which oil, gas 

or other hydrocarbon is being produced.

A Certificate of Clearance shall be filed within thirty (30) days should the oil transporter (first 

purchaser) and/or the gas gatherer (first purchaser) change. In addition, within fifteen (15) days of 

an operator change for any well, a Change of Operator, Form 10, shall be filed with a filing and 

service fee as set by the Commission. (See Appendix III)

b. Each operator of a Class II injection well shall file a new Form 10 with the Director within fifteen (15) 

days of the transfer of ownership.

c. Whenever there shall occur a change in the producer or operator filing the certificate under Rule 310.

(a) hereof, or whenever there shall occur a change of transporter from any well within the State, a 

new Form 10 shall be executed and filed within fifteen (15) days in accordance with the 

instructions appearing on such form. In the case of temporary use of oil for well treating or 

stimulating purposes, no new form need be executed. In the case of other temporary change in 

transporter involving the production of less than one (1) month, the producer or operator may, in 

lieu of filing a new certificate, notify the Commission and the transporter authorized by the 

certificate on file with the Commission by letter of the estimated amount to be moved by the 

temporary transporter and the name of such temporary transporter. A copy of such notice shall 

also be furnished such temporary transporter.

d. In no instance shall the temporary transporter move any quantity greater than the estimated amount 

shown in said notice.

e. The certificate, when properly executed and approved by the Commission, shall constitute 

authorization to the pipeline or other transporter to transport the authorized volume from the well 

named therein; provided that this section shall not prevent the production or transportation in 

order to prevent waste, pending execution and approval of said certificate. Permission for the 

transportation of such production shall be granted in writing to the producer and transporter.

f. The certificate shall remain in force and effect until:

(1) The producer or operator filing the certificate is changed; or

(2) The transporter is changed; or

(3) The certificate is canceled by the Commission.

g. A copy of each Form 10 to be filed hereunder shall be sent by the Director to those local governmental 

designees who so request.

h. It is the operator's responsibility to mail approved copies of the Certificate of Clearance and/or Change 

cof Operator, Form 10, to the transporter and/or gatherer for each well listed.

i. A completed Form 10 shall be required for any change of operator for all oil and gas facilities, excluding 

gathering systems, gas-processing plants, and gas storage facilities as those shall be changed 

with a Form 12, Gas Facility Registration/Change of Operator. 

313. COGCC Form 11. MONTHLY REPORT OF GASOLINE OR OTHER EXTRACTION PLANTS

All operators of gasoline or other extraction plants shall make monthly reports to the Director on Form 11 

Such forms shall contain all information required thereon and shall be filed with the Director on or before 

the twenty-fifth (25th) day of each month covering the preceding month.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 45

314. COGCC Form 17. BRADENHEAD TEST REPORT

Results of bradenhead tests, as required by Rule 207.b., shall be submitted to the Director within ten (10) 

days of completion. A wellbore diagram shall be submitted if not previously submitted or if the wellbore 

configuration has changed. If sampled, then the results of any gas and liquid analysis shall be submitted.

315. REPORT OF RESERVOIR PRESSURE TEST

Where the Director believes it is necessary to prevent waste, protect correlative rights, or prevent a 

significant adverse impact, the Director may require subsurface pressure measurements. Whenever such 

measurements are made, results shall be reported on Sundry Notice, Form 4, within twenty (20) days 

after completion of tests, or submitted on any company form approved by the Director containing the 

same information.

316A. COGCC Form 14. MONTHLY REPORT OF FLUIDS INJECTED

Except for fluids involved with fracturing, acidizing or other similar treatment elsewhere required to be 

reported on a Completed Interval Report, Form 5A, all operators engaged in the injection of fluids into any 

formation in dedicated injection wells shall file monthly with the Commission a detailed account of such 

operation on Form 14, or any company form containing the same information previously approved by the 

Director. Types of chemicals used to treat injection water, as well as the date of initial fluid injection for 

new injection wells, are to be reported on said form under Remarks. The type and amount of fluids 

received from transporters shall be included on the report. Operators of simultaneous injection wells shall, 

by March 1 of each year, report to the Director the calculated injected volume for the previous year by 

month on Form 14. Operators of gas storage projects shall, by March 1 of each year, report to the 

Director the amount of gas injected and withdrawn for the previous year and the amount of gas remaining 

in the reservoir as of December 31 of that year.

316B. COGCC Form 21. MECHANICAL INTEGRITY TEST

Results of mechanical integrity tests of injection wells or shut-in wells shall be submitted on Form 21, 

within thirty (30) days after the test. A pressure chart shall accompany this report. Not less than ten (10) 

days prior to the performance of any mechanical integrity test the Director shall be notified, in writing, of 

the scheduled date on which the test will be performed. The form shall be completely filled out except for 

Part II, which is required only if the well is a permitted or pending injection well.

317. GENERAL DRILLING RULES

Unless altered, modified, or changed for a particular field or formation upon hearing before the 

Commission the following shall apply to the drilling or deepening of all wells.

a. Blowout prevention equipment (“BOPE” ). The operator shall take all necessary precautions for 

keeping a well under control while being drilled or deepened. BOPE, if any, shall be indicated on 

the Application for Permit to Drill, Deepen, Re-enter, or Recomplete and Operate (Form 2), as 

well as any known subsurface conditions (e.g. under or over-pressured formations). The working 

pressure of any BOPE shall exceed the anticipated surface pressure to which it may be 

subjected, assuming a partially evacuated hole with a pressure gradient of 0.22 psi/ft. [For BOPE 

requirements in high density areas see Rule 603.b.(4)B. For statewide BOPE specification, 

inspection, operation and testing requirements see Rule 603.f.]

(1) The Director shall have the authority to designate specific areas, fields or formations as 

requiring certain BOPE. Any such proposed designation shall occur by notice describing 

the area, field or formation in question and shall be given to all operators of record within 

such area or field and by publication. The proposed designation, if no protest is timely 

filed, shall be placed on the Commission consent agenda for its next regularly scheduled 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 46

meeting following the month in which such notice was given. The matter shall be 

approved or heard by the Commission in accordance with Rule 520. Such designation 

shall be effective immediately upon approval by the Commission, except as to any 

previously-approved Form 2.

(2) The Director shall have the authority, outside areas designated pursuant to Rule 317.a.(1), to 

condition approval of any application for permit to drill by requiring BOPE which the 

Director determines to be necessary for keeping the well under control. Should the 

operator object to such condition of approval, the matter shall be heard at the next 

regularly scheduled meeting of the Commission, subject to the notice requirements of 

Rule 507.

b. Bottom hole location. Unless authorized by the provisions of Rule 321., all wells shall be so drilled 

that the horizontal distance between the bottom of the hole and the location at the top of the hole 

shall be at all times a practical minimum.

c. Requirement to post permit at the rig and provide spud notice. A copy of the approved Application 

for Permit to Drill, Deepen, Re-enter, or Recomplete and Operate, Form 2, shall be posted in a 

conspicuous place on the drilling rig or workover rig. A notice shall be provided to the Director on 

a Sundry Notice, Form 4, no later than five (5) days following the spudding of a well. The Director 

may apply a condition of approval for Application for Permit to Drill, Deepen, Re-enter, or 

Recomplete and Operate, Form 2 requiring not less than twenty-four (24) hours nor more than 

seventy-two (72) hours verbal or written notice prior to spud.

d. Casing program to protect hydrocarbon horizons and ground water. The casing program adopted 

for each well must be so planned and maintained as to protect any potential oil or gas bearing 

horizons penetrated during drilling from infiltration of injurious waters from other sources, and to 

prevent the migration of oil, gas or water from one (1) horizon to another, that may result in the 

degradation of ground water. A Sundry Notice, Form 4, including a detailed work plan and a 

wellbore diagram, shall be submitted and approved by the Director prior to any routine or planned 

casing repair operations. During well operations, prior verbal approval for unforeseen casing 

repairs followed by the filing of a Sundry Notice, Form 4, after completion of operations shall be 

acceptable.

e. Surface casing where subsurface conditions are unknown. In areas where pressure and 

formations are unknown, sufficient surface casing shall be run to reach a depth below all known 

or reasonably estimated utilizable domestic fresh water levels and to prevent blowouts or 

uncontrolled flows, and shall be of sufficient size to permit the use of an intermediate string or 

strings of casings. Surface casing shall be set in or through an impervious formation and shall be 

cemented by pump and plug or displacement or other approved method with sufficient cement to 

fill the annulus to the top of the hole, all in accordance with reasonable requirements of the 

Director. In the D–J Basin Fox Hills Protection Area surface casing will be set in accordance with 

Rule 317A. (See also subparagraph g.).

f. Surface casing where subsurface conditions are known. For wells drilled in areas where 

subsurface conditions have been established by drilling experience, surface casing, size at the 

owner's option, shall be set and cemented to the surface by the pump and plug or displacement 

or other approved method at a depth and in a manner sufficient to protect all fresh water and to 

ensure against blowouts or uncontrolled flows. In the D–J Basin Fox Hills Protection Area surface 

casing shall be set in accordance with Rule 317A. (See also subparagraph g.).

g. Alternate aquifer protection by stage cementing. In areas where fresh water aquifers are of such 

depth as to make it impractical or uneconomical to set the full amount of surface casing 

necessary to comply fully with the requirement to cover or isolate all fresh water aquifers as 

required in subparagraph e. and f., the owner may, at its option, comply with this requirement by 

stage cementing the intermediate and/or production string so as to accomplish the required 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 47

result. If unanticipated fresh water aquifers are encountered after setting the surface pipe they 

shall be protected or isolated by stage cementing the intermediate and/or production string with a 

solid cement plug extending from fifty (50) feet below each fresh water aquifer to fifty (50) feet 

above said fresh water aquifer or by other methods approved by the Director in each case. In the 

D–J Basin Fox Hills Protection Area any stage cementing shall occur only in accordance with 

Rule 317A. If the stage cement is not circulated to surface, a temperature log or cement bond log 

shall be run to determine the top of the stage cement to ensure aquifers are protected.

h. Surface and intermediate casing cementing. The operator shall ensure that all surface and 

intermediate casing cement required under this rule shall be of adequate quality to achieve a 

minimum compressive strength of three hundred (300) psi after twenty-four (24) hours and eight 

hundred (800) psi after seventy-two (72) hours measured at ninety-five degrees fahrenheit (95 °F) 

and at eight hundred (800) psi. All surface casing shall be cemented with a continuous column 

from the bottom of the casing to the surface. After thorough circulation of the wellbore, cement 

shall be pumped behind the intermediate casing to at least two hundred (200) feet above the top 

of the shallowest known production horizon and as required in 317.g. Cement placed behind the 

surface and intermediate casing shall be allowed to set a minimum of eight (8) hours, or until 

three hundred (300) psi calculated compressive strength is developed, whichever occurs first, 

prior to commencing drilling operations. If the surface casing cement level falls below the surface, 

to the extent safety or aquifer protection is compromised, remedial cementing operations shall be 

performed.

i. Production casing cementing. The operator shall ensure that all cement required under this rule 

placed behind production casing shall be of adequate quality to achieve a minimum compressive 

strength of at least three hundred (300) psi after twenty-four (24) hours and eight hundred (800) 

psi after seventy-two (72) hours measured at ninety-five degrees fahrenheit (95 °F) and at eight 

hundred (800) psi. After thorough circulation of a wellbore, cement shall be pumped behind the 

production casing (200) feet above the top of the shallowest known producing horizon. All fresh 

water aquifers which are exposed below the surface casing shall be cemented behind the 

production casing. All such cementing around an aquifer shall consist of a continuous cement 

column extending from at least fifty (50) feet below the bottom of the fresh water aquifer which is 

being protected to at least fifty (50) feet above the top of said fresh water aquifer. Cement placed 

behind the production casing shall be allowed to set seventy-two (72) hours, or until eight 

hundred (800) psi calculated compressive strength is developed, whichever occurs first, prior to 

the undertaking of any completion operation.

j. Production casing pressure testing. The installed production casing shall be adequately pressure 

tested for the conditions anticipated to be encountered during completion and production 

operations.

k. Protection of aquifers and production stratum and suspension of drilling operations before 

running production casing. In the event drilling operations are suspended before production 

string is run, the Director shall be notified immediately and the operator shall take adequate and 

proper precautions to assure that no alien water enters oil or gas strata, nor potential fresh water 

aquifers during such suspension period or periods. If alien water is found to be entering the 

production stratum or to be causing significant adverse environmental impact to fresh water 

aquifers during completion testing or after the well has been put on production, the condition shall 

be promptly remedied.

l. Flaring of gas during drilling and notice to local emergency dispatch. Any gas escaping from the 

well during drilling operations shall be, so far as practicable, conducted to a safe distance from 

the well site and burned. The operator shall notify the local emergency dispatch as provided by 

the local governmental designee of any such flaring. Such notice shall be given prior to the flaring 

if the flaring can be reasonably anticipated, and in all other cases as soon as possible but in no 

event more than two (2) hours after the flaring occurs.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 48

m. Protection of productive strata during deepening operations. If a well is deepened for the 

purpose of producing oil and gas from a lower stratum, such deepening to and completion in the 

lower stratum shall be conducted in such a manner as to protect all upper productive strata.

n. Requirement to evaluate disposal zones for hydrocarbon potential. If a well is drilled as a 

disposal well then the disposal zone shall be evaluated for hydrocarbon potential. The proposed 

hydrocarbon evaluation method shall be submitted in writing and approved by the Director prior to 

implementation. The productivity results shall be submitted to the Director upon completion of the 

well.

o. Requirement to log well. For all new drilling operations, the operator shall be required to run a 

minimum of a resistivity log with gamma-ray or other petrophysical log(s) approved by the 

Director that adequately describe the stratigraphy of the wellbore. A cement bond log shall be run 

on all production casing or, in the case of a production liner, the intermediate casing, when these 

casing strings are run. This log and all other logs run shall be submitted with the Well Completion 

or Recompletion Report and Log, Form 5. Open hole logs shall be run at depths that to 

adequately verify the setting depth of surface casing and any aquifer coverage. These 

requirements shall not apply to the unlogged open hole completion intervals, or to wells in which 

no open hole logs are run.

p. Remedial cementing during recompletion. The Director may apply a condition of approval for 

Application for Permit to Drill, Deepen, Re-enter, or Recomplete and Operate, Form 2, to require 

remedial cementing during recompletion operations consistent with the provisions for protecting 

aquifers and hydrocarbon bearing zones in this Rule 317.

317A. SPECIAL DRILLING RULES - D–J BASIN FOX HILLS PROTECTION AREA

The following special drilling rules shall apply to wells in the D–J Basin Fox Hills Protection Area as 

defined in the 100 Series of the Rules and Regulations:

a. Surface Casing - Minimum Requirements for Well Control. In all wells drilled within the D–J Basin 

Fox Hills Protection Area, surface casing shall be run to a minimum depth of five percent (5%) of 

the projected total depth to which the well is to be drilled, provided that in no event shall the 

surface casing be run to a depth less than two hundred (200) feet. The Director may, on a caseby-case basis, grant variances in this five percent (5%) requirement where the Director finds that 

the well is a development well in which pressures can be accurately predicted and finds that, 

based upon those predictions, the five percent (5%) requirement should be varied to achieve 

effective well control. In all cases, however, the actual depth at which the surface casing is set 

shall be calculated to position the casing seat to a depth within a competent formation (preferably 

shale) which will contain the maximum pressure to which the casing will be exposed during 

normal drilling operations.

b. Surface Casing - Aquifer Protection. For purposes of aquifer protection, surface casing must be set 

as follows in wells which are not exploratory wells:

(1) Surface casing shall be run to a depth at least fifty (50) feet below the Fox Hills transition 

zone in wells drilled within Townships 5 South through 5 North, Ranges 65 West through 

70 West or within Townships 3 North through 5 North, Range 64 West.

(2) With respect to Townships 5 South through 5 North, Ranges 58 West through 63 West, 

Townships 5 South through 2 North, Range 64 West; and Township 6 South, Ranges 65 

West through 70 West, in all wells located within one (1) mile of a permitted producing 

water well, surface casing shall be set to a depth sufficient to protect the deepest 

permitted producing water well within such one mile area. Said depth shall be at least fifty 

(50) feet below the depth of the base of the aquifer from which said deepest water well is 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 49

producing, or fifty (50) feet below the base of the Fox Hills Transition Zone if such 

deepest water well produces from the Fox Hills Aquifer.

Upon the request of the operator, the Director (or the Commission upon appeal) may grant a 

variance to the requirements of this subparagraph b. upon a showing to the Director, or the 

Commission upon appeal, that the variance does not violate the basic intent of said requirements. 

For such variance purpose, the basic intent of said requirements is stated to be to provide 

reasonable aquifer protection for the water well(s) which are permitted by the State of Colorado 

Division of Water Resources and are currently producing in the area potentially affected by the oil 

or gas well to be drilled.

c. Exploratory Wells. For purposes of the D–J Basin Fox Hills Protection Area only, the term exploratory 

well means any well:

(1) Which targets the classically demonstrated zones with limited geographic extent such as 

channel, bar, valley fill and levee type sandstones that were deposited prior to the xbentonite time stratigraphic event; or

(2) Which can be demonstrated to be separated from a known producing horizon by a dry hole; 

or

(3) Which can be demonstrated to be targeted to a horizon which is geologically separate from 

the producing horizon in an offsetting producing well, or

(4) Which the Director, or the Commission upon appeal, may define as an exploratory well by 

variance, it being the basic intent of this definition that the requirements of subparagraph 

b. not operate to discourage the drilling of high risk wells.

317B. PUBLIC WATER SYSTEM PROTECTION

a. Definitions. For purposes of this Rule 317B: 

(1) Drilling, Completion, Production and Storage (“DCPS”) Operations shall mean 

operations at (i) well sites for the drilling, completion, recompletion, workover, or 

stimulation of wells or chemical and production fluid storage, and (ii) any other oil and gas 

location at which production facilities are operated. DCPS Operations shall exclude 

roads, gathering lines, pipelines, and routine operations and maintenance.

(2) Existing Oil and Gas Location shall mean an oil and gas location, excluding roads, 

pipelines, and gathering lines, permitted or constructed prior to the later of May 1, 2009 

for federal land or April 1, 2009 for all other land or the date that the oil and gas location 

becomes subject to Rule 317B by virtue of its proximity to a Classified Water Supply 

Segment. 

(3) New Oil and Gas Location shall mean an oil and gas location, excluding roads, pipelines, 

and gathering lines, that is not an existing oil and gas location. 

(4) New Surface Disturbance shall mean surface disturbance that expands the area of surface 

covered by an oil and gas location beyond that initially disturbed in the construction of the 

oil and gas location. 

(5) Non-Exempt Linear Feature shall mean a road, gathering line, or pipeline that is not 

necessary to cross a stream or connect or access a well or a gathering line. 

b. Applicability Determination.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 50

(1) Rule 317B is applicable to DCPS Operations within Surface Water Supply Areas. The 

applicability of Rule 317B will be determined by reviewing the Public Water System 

Surface Water Supply Area Map, located on the Commission website, or by entering the 

longitude and latitude coordinates into the Public Water System Surface Water Supply 

Area Applicability Determination Tool, also located on the Commission website. 

(2) The Public Water Systems subject to the protections of this Rule 317B are those listed in 

Appendix VI. Any additions or deletions to the Public Water Systems listed in Appendix VI 

or the Public Water System Surface Water Supply Area Map, also located in Appendix 

VI, shall be by Commission rulemaking, as provided in Rule 529.

(3) DCPS Operations at New Oil and Gas Locations within a Surface Water Supply Area will be 

subject to the requirements in Rules 317B.c, 317B.d, or 317B.e based on the buffer 

zones defined in Table 1, below. DCPS Operations at Existing Oil and Gas Locations 

within a Surface Water Supply Area at which no new surface disturbance has occurred 

after the date Rule 317B became applicable to that oil and gas location will be subject to 

the requirements in Rule 317B.f.(1) based on the buffer zones defined in Table 1. DCPS 

Operations at Existing Oil and Gas Locations within a Surface Water Supply Area at 

which new surface disturbance has occurred after the date Rule 317B became applicable 

to that oil and gas location will be subject to the requirements in Rule 317B.f.(2) based on 

the buffer zones defined in Table 1. 

(4) For Classified Water Supply Segments that are perennial and intermittent streams, buffer 

zones shall be determined by measuring from the ordinary high water line of each bank 

to the near edge of the disturbed area at the oil and gas location at which the DCPS 

Operations will occur. 

(5) The buffer zones shall apply only to DCPS Operations located on the surface. The buffer 

zones shall not apply to subsurface boreholes and equipment or materials contained 

therein. The buffer zones shall not apply to DCPS Operations located in an area that 

does not drain to a classified water supply segment protected by this Rule 317B. 

TABLE 1. Buffer Zones Associated with DCPS Operations. 

Zone Classified Water

Supply Segments (ft)

Internal Buffer 0 - 300

Intermediate Buffer 301 - 500

External Buffer 501 - 2,640

c. Requirements for DCPS Operations Conducted at New Oil and Gas Locations in the Internal 

Buffer Zone. 

DCPS Operations conducted and Non-Exempt Linear Features located at New Oil and Gas Locations 

within a Surface Water Supply Area may not occur in whole or in part within the Internal Buffer Zone 

identified in Table 1 unless a variance is granted pursuant to Rule 502.b and consultation with the 

Colorado Department of Public Health and Environment occurs pursuant to Rule 306.d and a Form 2A or 

Form 2 with appropriate conditions of approval has been approved, or the Director has approved a 

Comprehensive Drilling Plan pursuant to Rule 216 that covers the operation. In determining appropriate 

conditions of approval for such operations, the Director shall consider the extent to which the conditions 

of approval are required to prevent impacts to the Public Water System. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 51

(1) The Commission shall grant a variance if the operator demonstrates that: 

A. The proposed DCPS Operations and applicable best management practices and 

operating procedures will result in substantially equivalent protection of drinking 

water quality in the Surface Water Supply area; and

B. Either:

i. Conducting the DCPS Operation outside the Internal Buffer Zone would pose a 

greater risk to public health, safety, or welfare, including the environment 

and wildlife resources, such as may be the case where conducting the 

DCPS Operations outside the Internal Buffer Zone would require 

construction in steep or erosion-prone terrain or result in greater surface 

disturbance due to an inability to use infrastructure already constructed 

such as roads, well sites, or pipelines; or

ii. Conducting DCPS Operations beyond the Internal Buffer Zone is technically 

infeasible and prevents the operator from exercising its correlative rights.

(2) At a minimum, for any DCPS Operation at a New Oil and Gas Location within the Internal 

Buffer Zone, the Director shall include as conditions of approval in the Form 2A, Form 2, 

or Comprehensive Drilling Plan, the requirements of Rule 317B.d. 

d. Requirements for DCPS Operations at New Oil and Gas Locations in the Intermediate Buffer 

Zone.

The following shall be required for all DCPS Operations at New Oil and Gas Locations within a Surface 

Water Supply Area and in the Intermediate Buffer Zone as defined in Table 1. 

(1) Pitless drilling systems;

(2) Flowback and stimulation fluids contained within tanks that are placed on a well pad or in an 

area with downgradient perimeter berming; 

(3) Berms or other containment devices shall be constructed in compliance with Rule 603.e.(12) 

around crude oil, condensate, and produced water storage tanks; and

(4) When sufficient water exists in the Classified Water Supply Segment, collection of baseline 

surface water data consisting of a pre-drilling surface water sample collected immediately 

downgradient of the oil and gas location and follow-up surface water data consisting of a 

sample collected at the same location three (3) months after the conclusion of any drilling 

activities and operations or completion. The sample parameters shall include: 

A. pH; 

B. Alkalinity; 

C. Specific conductance; 

D. Major cations/anions (chloride, fluoride, sulfate, sodium); 

E. Total dissolved solids; 

F. BTEX/GRO/DRO;
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 52

G. TPH;

H. PAH’s (including benzo(a)pyrene); and 

I. Metals (arsenic, barium, calcium, chromium, iron, magnesium, selenium). 

Current applicable EPA-approved analytical methods for drinking water must be used 

and analyses must be performed by laboratories that maintain state or nationally 

accredited programs. 

Copies of all test results described above shall be provided to the Commission and the 

potentially impacted Public Water System(s) within three (3) months of collecting the 

samples. In addition, the analytical results and surveyed sample locations shall be 

submitted to the Commission in an electronic data deliverable format.

(5) Notification of potentially impacted Public Water Systems within fifteen (15) stream miles 

downstream of the DCPS Operation prior to commencement of new surface disturbing 

activities at the site.

(6) An emergency spill response program that includes employee training, safety, and 

maintenance provisions and current contact information for downstream Public Water 

System(s) located within fifteen (15) stream miles of the DCPS Operation, as well as the 

ability to notify any such downstream Public Water System(s) with intake(s) within fifteen 

(15) stream miles downstream of the DCPS operations. 

In the event of a spill or release, the operator shall immediately implement the emergency 

response procedures in the above-described emergency response program. 

If a spill or release impacts or threatens to impact a Public Water System, the operator 

shall notify the affected or potentially affected Public Water System(s) immediately 

following discovery of the release, and the spill or release shall be reported to the 

Commission in accordance with Rule 906.b.(3), and to the Environmental 

Release/Incident Report Hotline (1-877-518-5608) in accordance with Rule 906.b.(4). 

e. Requirements for DCPS Operations at New Oil and Gas Locations within the External Buffer 

Zone.

The following shall be required when DCPS Operations are conducted at New Oil and Gas Locations 

within a Surface Water Supply Area and in the External Buffer Zone as defined in Table 1.

(1) Pitless drilling systems or containment of all drilling flowback and stimulation fluids pursuant 

to Rule 904; and 

(2) When sufficient water exists in the Classified Water Supply Segment, collection of baseline 

surface water data consisting of a pre-drilling surface water sample collected immediately 

downgradient of the oil and gas location and follow-up surface water data consisting of a 

sample collected at the same location three (3) months after the conclusion of any drilling 

activities and operations or completion. The sample parameters shall include: 

A. pH;

B. Alkalinity;

C. Specific conductance;
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 53

D. Major cations/anions (chloride, fluoride, sulfate, sodium);

E. Total dissolved solids; 

F. BTEX/GRO/DRO;

G. TPH;

H. PAH’s (including benzo(a)pyrene); and 

I. Metals (arsenic, barium, calcium, chromium, iron, magnesium, selenium). 

Current applicable EPA-approved analytical methods for drinking water must be used 

and analyses must be performed by laboratories that maintain state or nationally 

accredited programs. 

Copies of all test results described above shall be provided to the Commission and the 

potentially impacted Public Water System(s) within three (3) months of collecting the 

samples. In addition, the analytical results and surveyed sample locations shall be 

submitted to the Commission in an electronic data deliverable format. 

(3) Notification of potentially impacted Public Water Systems within fifteen (15) stream miles 

downstream of the DCPS Operation prior to commencement of new surface disturbing 

activities at the site. 

(4) An emergency spill response program that includes employee training, safety, and 

maintenance provisions and current contact information for downstream Public Water 

System(s) located within fifteen (15) stream miles of the DCPS Operation, as well as the 

ability to notify any such downstream Public Water System(s) with intake(s) within fifteen 

(15) stream miles downstream of the DCPS operations. 

In the event of a spill or release, the operator shall immediately implement the emergency 

response procedures in the above-described emergency response program. 

If a spill or release impacts or threatens to impact a Public Water System, the operator 

shall notify the affected or potentially affected Public Water System(s) immediately 

following discovery of the release, and the spill or release shall be reported to the 

Commission in accordance with Rule 906.b.(3), and to the Environmental 

Release/Incident Report Hotline (1-877-518-5608) in accordance with Rule 906.b.(4). 

f. Requirements for DCPS Operations at Existing Oil and Gas Locations.

(1) Existing Oil and Gas Locations and DCPS Operations at Existing Oil and Gas Locations 

within a Surface Water Supply Area and within zones specified in Table 1 shall be subject 

to the following requirements instead of the requirements of Rules 317B.c, 317B.d, or 

317B.e provided that no new surface disturbance at the Existing Oil and Gas Location 

occurs after the later of May 1, 2009 for federal land or April 1, 2009 for all other land or 

the date Rule 317B became applicable to the oil and gas location: 

A. Collection of surface water data from a Classified Water Supply Segment consisting 

of a sample collected immediately downgradient of the oil and gas operation will 

occur by the latest of June 1, 2009, within six (6) months after the date Rule 

317B became applicable to the oil and gas location, or when sufficient water 

exists in the stream: 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 54

i. pH;

ii. Alkalinity;

iii. Specific conductance;

iv. Major cations/anions (chloride, fluoride, sulfate, sodium); 

v. Total dissolved solids; 

vi. BTEX/GRO/DRO;

vii. TPH;

viii. PAH’s (including benzo(a)pyrene); and 

ix. Metals (arsenic, barium, calcium, chromium, iron, magnesium, selenium). 

Current applicable EPA-approved analytical methods for drinking water must be 

used and analyses must be performed by laboratories that maintain state or 

nationally accredited programs. 

Copies of all test results described above shall be provided to the Commission 

and the potentially impacted Public Water System(s) within three (3) months of 

collecting the samples. In addition, the analytical results and surveyed sample 

locations shall be submitted to the Commission in an electronic data deliverable 

format. 

B. An emergency spill response program that includes employee training, safety, and 

maintenance provisions and current contact information for downstream Public 

Water System(s) located within fifteen (15) stream miles of the DCPS Operation, 

as well as the ability to notify any such downstream Public Water System(s) with 

intake(s) within fifteen (15) stream miles downstream of the DCPS Operations. 

In the event of a spill or release, the operator shall immediately implement the 

emergency response procedures in the above-described emergency response 

program. 

If a spill or release impacts or threatens to impact a Public Water System, the 

operator shall notify the affected or potentially affected Public Water System(s) 

immediately following discovery of the release, and the spill or release shall be 

reported to the Commission in accordance with Rule 906.b.(3), and to the 

Environmental Release/Incident Report Hotline (1-877-518-5608) in accordance 

with Rule 906.b.(4). 

C. Operators shall employ and maintain Best Management Practices, as necessary, to 

comply with this rule. 

(2) Existing Oil and Gas Locations and DCPS Operations at Existing Oil and Gas Locations 

within a Surface Water Supply Area and within zones specified in Table 1 for which new 

surface disturbance occurs on or after May 1, 2009 for federal land or on or after April 1, 

2009 for all other land shall be subject to the requirements of Rule 317B.f.(3) instead of 

the requirements of Rules 317B.c, 317B.d, or 317B.e where the additional new surface 

disturbance is addressed in a Comprehensive Drilling Plan accepted pursuant to Rule 

216, or if:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 55

A. The new disturbance from the DCPS Operation will not increase the existing disturbed 

area prior to interim reclamation by more than one hundred (100) percent up to a 

maximum of three (3) acres, and

B. The new surface disturbance occurs in a direction away from the stream or no closer 

to the stream if moving away from the stream would result in more damaging 

surface disturbance such as location on a steep slope, in an area of high soil 

erosion potential, or in a wetland. 

(3) Where the provisions of Rule 317B.f.(2) apply, the following zone requirements shall apply: 

A. For all zones, the requirements of Rule 317B.f.(1), except that the sampling 

parameters in Rule 317B.f.(1).A shall occur no later than six (6) months after 

commencing the DCPS Operations at the Existing Oil and Gas Location. 

B. For External and Intermediate Buffer Zones: pitless drilling systems or containment of 

drilling, flowback, and stimulation fluids with impervious liners, as provided in 

Rule 904. 

C. For Internal Buffer Zones: 

i. Pitless drilling systems;

ii. Flowback and stimulation fluids contained within tanks and placed on a well 

pad or in an area with downgradient perimeter berming;

iii. Berms constructed in compliance with Rule 603.e.(12) around all crude oil, 

condensate, and produced water tanks; and

iv. Notification of potentially impacted Public Water Systems within fifteen (15) 

stream miles downstream of the DCPS Operation prior to 

commencement of new surface disturbing activities at the site. 

318. LOCATION OF WELLS

All wells drilled for oil or gas to a common source of supply shall have the following setbacks:

a. Wells deeper than 2.,500 feet or greater in depth. A well to be dorilled in excess of two thousand 

five hundred (2,.500) feet or greater in depth shall be located not less than six hundred (600) feet 

from any lease line, and shall be located not less than one thousand two hundred (1.,200) feet 

from any other producible or drilling oil or gas well when drilling to the same common source of 

supply, unless authorized by order of the Commission upon hearing.

b. Wells less than 2,500 feet in depth. A well to be drilled to less than a depth of two thousand five 

hundred (2,500) feet below the surface shall be located not less than two hundred (200) feet from 

any lease line, and not less than three hundred (300) feet from any other producible oil or gas 

well, or drilling well, in said source of supply, except that only one producible oil or gas well in 

each such source of supply shall be allowed in each governmental quarter-quarter section unless 

an exception under Rule 318.c. is obtained.

c. Exception locations. The Director may grant an operator's request for a well location exception to the 

requirements of this rule or any order because of geologic, environmental, topographic or 

archaeological conditions, irregular sections, a surface owner request, or for other good cause 

shown provided that a waiver or consent signed by the lease owner toward whom the well 

location is proposed to be moved, agreeing that said well may be located at the point at which the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 56

operator proposes to drill the well and where correlative rights are protected. If the operator of the 

proposed well is also the operator of the drilling unit or unspaced offset lease toward which the 

well is proposed to be moved, waivers shall be obtained from the mineral interest owners under 

such lands. If waivers cannot be obtained from all parties and no party objects to the location, the 

operator may apply for a variance under Rule 502.b. If a party or parties object to a location and 

cannot reach an agreement, the operator may apply for a Commission hearing on the exception 

location.

d. Exemptions to Rule 318.

(1) This rule shall not apply to authorized secondary recovery projects.

(2) This rule shall apply to fracture or crevice production found in shale, except from fields 

previously exempted from this rule.

(3) In a unit operation, approved by federal or state authorities, the rules herein set forth shall not 

apply except that no well in excess of two thousand five hundred (2,.500) feet in depth 

shall be located less than so hundred (600) feet from the exterior or interior (if there be 

one) boundary of the unit area and no well less than two thousand five hundred (2,.500) 

feet in depth below the surface shall be located less than two hundred (200) feet from the 

exterior or interior (if there be one) boundary of the unit area unless otherwise authorized 

by the order of the Commission after proper notice to owners outside the unit area.

e. Wells located near a mine. No well drilled for oil or gas shall be located within two hundred (200) feet 

of a shaft or entrance to a coal mine not definitely abandoned or sealed, nor shall such well be 

located within one hundred (100) feet of any mine shaft house, mine boiler house, mine engine 

house, or mine fan; and the location of any proposed well shall insure that when drilled it will be at 

least fifteen (15) feet from any mine haulage ofr airway.

318A. GREATER WATTENBERG AREA SPECIAL WELL LOCATION, SPACING AND UNIT 

DESIGNATION RULE

a. GWA, GWA wells, GWA windows and unit designations. The Greater Wattenberg Area ("GWA") 

is defined to include those lands from and including Townships 2 South to 7 North and Ranges 61 

West to 69 West, 6th P.M. In the GWA, operators may utilize the following described surface 

drilling locations (“GWA windows”) to drill, twin, deepen, or recomplete a well ("GWA well") and to 

commingle any or all of the Cretaceous Age formations from the base of the Dakota Formation to 

the surface:

(1) A square with sides four hundred (400) feet in length, the center of which is the center of any 

governmental quarter-quarter section (“400’ window”); and,

(2) A square with sides eight hundred (800) feet in length, the center of which is the center of any 

governmental quarter section (“800’ window”).

(3) Absent a showing of good cause, which shall include the existence of a surface use or other 

agreement with the surface owner authorizing a surface well location outside of a GWA 

window, all surface wellsites shall be located within a GWA window.

(4) Unit designations.

A. 400’ window. When completing a GWA well in a 400’ window to a spaced formation, 

the operator shall designate drilling and spacing units in accordance with existing 

spacing orders.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 57

B. 800’ window. When completing a GWA well in an 800’ window, whether in spaced or 

unspaced formations, the operator shall: (i) designate drilling and spacing units in 

accordance with existing spacing orders where units are not smaller than a 

governmental quarter section; or (ii) form a voluntary drilling and spacing unit 

consisting of a governmental quarter section; or (iii) where designating a drilling 

and spacing unit smaller than a governmental quarter section, secure waiver(s) 

from the operator or from the mineral owners (if the operator is also the holder of 

the mineral lease) of the lands in the governmental quarter section that are not to 

be included in the spacing unit; or (iv) apply to the Commission to form an 

alternate unit or to respace the area.

C. Unspaced areas and wellbore spacing units. When completing a GWA well to an 

unspaced formation, the operator shall designate a drilling and spacing unit not 

smaller than a governmental quarter-quarter section if such well is proposed to 

be located greater than four hundred sixty (460) feet from the quarter-quarter 

section boundary in which it is located. If a well is proposed to be located less 

than four hundred sixty (460) feet from the governmental quarter-quarter section 

boundary, a wellbore spacing unit (“wellbore spacing unit”) for such well shall be 

comprised of the four (4) governmental quarter-quarter sections nearest to the 

wellbore regardless of section or quarter section lines.

b. Recompletion/commingling of existing wells. Any GWA well in existence prior to the effective date 

of this rule, which is not located as described above, may also be utilized for deepening to or 

recompletion in any Cretaceous Age formation and for the commingling of production therefrom.

c. Surface locations. Prior to the approval of any Application for Permit-to-Drill submitted for a GWA 

well, the proposed surface well location shall be reviewed in accordance with the following 

criteria:

(1) A new surface well location shall be approved in accordance with Commission rules when it 

is less than fifty (50) feet from an existing surface well location.

(2) When the operator is requesting a surface well location greater than fifty (50) feet from a well 

(unless safety or mechanical considerations of the well to be twinned or topographical or 

surface constraints justify a location greater than fifty (50) feet), the operator shall provide 

a consent to the exception signed by the surface owner on which the well is proposed to 

be located in order for the Director to approve the well location administratively.

(3) If there is no well located within a GWA window but there is an approved exception location 

well located outside of a GWA window that is attributed to such window, the provisions of 

subsections (1) and (2) of this subsection c. shall be applicable to such location.

d. Prior wells excepted. This rule does not alter the size or configuration of drilling units for GWA wells 

in existence prior to the effective date of this rule. Where deemed necessary by an operator for 

purposes of allocating production, such operator may allocate production to any drilling and 

spacing unit with respect to a particular Cretaceous Age formation consistent with the provisions 

of this rule.

e. GWA infill. This subsection applies to the following area of the GWA: Township 1 North, Ranges 66 

West through 68 West; Township 1 North, Range 69 West: E1⁄2; Township 2 North, Ranges 64 

West through 68 West; Township 2 North, Range 69 West: E1⁄2; Township 3 North, Ranges 64 

West through 67 West; Township 4 North, Ranges 63 through 67 West; Township 5 North, 

Ranges 63 West through 67 West; Township 6 North, Ranges 63 West through 66 West, 6th 

P.M.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 58

(1) Interior infill wells. Additional bottom hole locations for the “J” Sand, Codell and Niobrara 

Formations are hereby established greater than four hundred sixty (460) feet from the 

outer boundary of any existing 320-acre drilling and spacing unit (“interior infill wells” ). 

Pursuant to the well location provisions of subsection a., above, interior infill well 

locations shall be reached by utilizing directional drilling techniques from the GWA 

windows.

A. If a bottom hole location for an interior infill well is proposed to be located less than 

four hundred sixty (460) feet from the outer boundary of an existing drilling and 

spacing unit, a wellbore spacing unit as defined in a.(4)C., above, shall be 

designated by the operator for such well.

B. If a bottom hole location for an interior infill well is proposed to be located greater than 

four hundred sixty (460) feet from an existing 80-acre or existing 320-acre drilling 

and spacing unit, the spacing unit for such well shall conform to the existing 80-

acre or existing 320-acre drilling and spacing unit.

(2) Boundary wells. Additional bottom hole locations for the “J” Sand, Codell and Niobrara 

Formations are hereby established less than four hundred sixty (460) feet from the outer 

boundary of a 320-acre governmental half section or from the outer boundary of any 

existing 320-acre drilling and spacing unit (“boundary wells”). A wellbore spacing unit as 

defined in a.(4)C., above, shall be designated by the operator for such well.

(3) Additional producing formations. An operator wanting to complete an interior infill well or 

boundary well in a formation other than the “J” Sand, Codell, or Niobrara Formations 

(“additional producing formation”) must request an exception location prior to completing 

the additional producing formation. The spacing unit dedicated to the exception location 

shall comply with subsections (1) or (2), above, as appropriate.

(4) Water well sampling. The Director shall require initial baseline testing prior to the first 

interior infill well or boundary well (“proposed GWA infill well”) drilled within a 

governmental section. The following shall be used as guidance for the Director in 

establishing initial baseline testing:

A. Within the governmental quarter section of the proposed GWA infill well, the closest 

water well (“water quality testing well”) completed in the Laramie/Fox Hills Aquifer 

shall be sampled.

B. If no Laramie/Fox Hills water wells are located within the governmental quarter 

section, then the deepest representative water quality testing well within the 

governmental quarter section of the proposed GWA infill well shall be sampled.

C. If no water wells are located within the governmental quarter section, a water quality 

testing well (preferably completed in the Laramie/Fox Hills Aquifer) within onehalf (1⁄2) mile of the proposed GWA infill well shall be selected.

D. If there are no water quality testing wells that meet the foregoing criteria, then initial 

baseline testing shall not be required.

E. Initial baseline testing shall include laboratory analysis of all major cations and anions, 

total dissolved solids, iron and manganese, nutrients (nitrates, nitrites, selenium), 

dissolved methane, pH, and specific conductance.

F. If free gas or a methane concentration level greater than 2 mg/l is detected in a water 

quality testing well, compositional analysis shall be performed to determine gas 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 59

type (thermogenic, biogenic or an intermediate mix of both). If the testing results 

reveal biogenic gas, no further isotopic testing shall be required. If the testing 

results reveal thermogenic gas, carbon isotopic analyses of methane carbon 

shall be conducted. The Director may require further water well sampling at any 

time as a result of the laboratory results or in response to complaints from water 

well owners.

G. Copies of all test results described above shall be provided to the Director and the 

landowner where the water quality testing well is located within three (3) months 

of collecting the samples used for the test. Laboratory results shall also be 

submitted to the Director in an electronic format.

(5) Existing production facilities. To the extent reasonably practicable, operators shall utilize 

existing roads, pipelines, tank batteries and related surface facilities for all interior infill 

wells and boundary wells.

(6) Notice and hearing procedures. For proposed boundary wells, wellbore spacing units, and 

additional producing formations provided by this subsection e., the following process shall 

apply:

A. Notice shall be given by certified mail by the operator of a proposed boundary well or 

wellbore spacing unit to all owners in the proposed wellbore spacing unit. Notice 

shall be given by certified mail by the operator of a proposed additional producing 

formation to all owners in cornering and contiguous spacing units of the 

requested completion and the proposed spacing unit; if the additional producing 

formation is unspaced only the owner in the proposed spacing unit needs to be 

notified.

B. Each owner shall have a twenty (20) day period after receipt of such notice to object 

in writing to the operator to such well location, proposed spacing unit, or 

additional producing formation. If a timely objection is received, the matter shall 

be set on the docket at the next available Commission hearing. Absent receipt of 

an objection by the operator from an owner within such twenty (20) day period, 

the Director may administratively approve the boundary well, wellbore spacing 

unit, or additional producing formation, provided that it does not exceed eight (8) 

producing completions in the “J” Sand, Codell or Niobrara Formations in the 160-

acre governmental quarter section as set forth in subsection f. below. A location 

plat evidencing the well location, wellbore spacing unit, or additional producing 

formation and applicable spacing unit shall be submitted to the Director together 

with copies of any surface waivers and a certification that no timely objections 

were received. An Application for Permit-to-Drill, Form 2, specifically identifying 

that a boundary well, a wellbore spacing unit, or an additional producing 

formation is proposed, shall also be filed with the Director in accordance with 

Rule 303.

(7) The Commission shall review the effectiveness of this subsection e. no later than March 1, 

2008 and may require operators to submit data related to infill drilling performed under 

this subsection.

f. Limit on locations. This rule does not limit the number of formations that may be completed in any 

GWA drilling and spacing unit nor, subject to subsection c., above, does it limit the number of 

wells that may be located within the GWA windows. However, absent Commission order 

otherwise, there shall be no more than eight (8) producing completions in the “J” Sand, Codell or 

Niobrara Formations in any 160-acre governmental quarter section.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 60

g. GWA water sampling. The Director may apply appropriate drilling permit conditions to require water 

well sampling near any proposed GWA wells in accordance with the guidelines set forth in 

subsection e.(4), above.

h. Exception locations. The provisions of Rule 318.c. respecting exception locations shall be applicable 

to GWA wells, however, absent timely objection, boundary wells, wellbore spacing units, and 

additional producing formations shall be administratively approved as provided in subsection e.(6) 

above.

i. Correlative rights. This rule shall not serve to bar the granting of relief to owners who file an 

application alleging abuse of their correlative rights to the extent that such owners can 

demonstrate that their opportunity to produce Cretaceous Age formations from the drilling 

locations herein authorized does not provide an equal opportunity to obtain their just and 

equitable share of oil and gas from such formations.

j. Supersedes orders and policy. Subject to paragraph d. above, this rule supersedes all prior 

Commission drilling and spacing orders affecting well location and density requirements of GWA 

wells and supersedes and replaces the “Policy on Staff Administrative Application of the Greater 

Wattenberg Area Well Location Rule 318A.,” dated April 26, 1999.

k. The landowner notice provision for the owner(s) of surface property within five hundred (500) feet of 

the proposed oil and gas location under Rule 305.e shall not apply to any such locations that are 

subject to the provisions of this subsection 318A. 

Rule No. 318B. Yuma/Phillips County Special Well Location Rule

a. This Special Well Location Rule (“WLR”) governs wells drilled to and completed in the Niobrara 

Formation for the following lands: Eff 07/30/2006

Township 1 North Range 44 West: Sections 7, 18, 19, 30 through 33 Range 45 West: 

Sections 7 through 36 Range 46 West: Sections 4 through 9 Range 47 West: All 

Range 48 West: All Eff 07/30/2006

Township 2 North Range 46 West: All Range 47 West: All Range 48 West: All Eff 

07/30/2006

Township 3 North Range 45 West: Sections 1 through 18 Range 46 West: All Range 

47 West: All Range 48 West: All Eff 07/30/2006

Township 4 North Range 45 West: All Range 46 West: All Range 47 West: All 

Range 48 West: All Eff 07/30/2006

Township 5 North Range 45 West: All Range 46 West: All Range 47 West: All 

Range 48 West: All Eff 07/30/2006

Township 6 North Range 45 West: All Range 46 West: All Range 47 West: All 

Range 48 West: All Eff 07/30/2006

Township 7 North Range 45 West: All Range 46 West: All Range 47 West: All Eff 

07/30/2006

Township 8 North Range 45 West: All Range 46 West: All Range 47 West: All Eff 

07/30/2006

Township 9 North Range 45 West: Sections 19 through 36 Range 46 West: Sections 19 

through 36 Range 47 West: Sections 19 through 36 Eff 07/30/2006
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 61

Township 1 South Range 44 West: Sections 3 through 10, 16 through 21, 27 through 34 

Range 45 West: Sections 3 through 5 Range 46 West: Sections 4 through 9, 16 through 

36 Range 47 West: All Range 48 West: All Eff 07/30/2006

Township 2 South Range 44 West: Sections 3 through 6 Range 45 West: Section 7: 

W1⁄2, Section 18: W1⁄2, Section 19: All Range 46 West: Sections 1 through 24 Range 47 

West: All Range 48 West: All Eff 07/30/2006

Township 3 South Range 48 West: All Eff 07/30/2006

Township 4 South Range 48 West: All Eff 07/30/2006

Within the WLR Area, operators may conduct drilling operations to the Niobrara Formation as 

follows: Eff 07/30/2006

(1) Four (4) Niobrara Formation wells may be drilled in any quarter section. Eff 07/30/2006

(2) No more than one (1) well may be located in any quarter quarter section. Eff 07/30/2006

(3) No minimum distance shall be required between wells producing from the Niobrara Formation 

in any quarter section. Eff 07/30/2006

(4) Wells shall be located at least three hundred (300) feet from the outer boundary of said 

quarter section, and wells located outside any drilling units already established by the 

Commission in the WLR Area prior to this WLR’s effective date (July 30, 2006) shall, in 

addition, be located at least three hundred (300) feet from any lease line. Further, wells 

shall be located not less than nine hundred (900) feet from any producible well drilled to 

the Niobrara Formation prior to this WLR’s effective date (July 30, 2006) located in a 

contiguous or cornering quarter section unless exception is approved by the Director. Eff 

07/30/2006

b. Any well drilled to the Niobrara Formation in the WLR Area prior to the effective date (July 30, 2006) of 

this WLR which is legally located when this WLR becomes effective but is not located as listed 

above shall be treated as properly located for purposes of this WLR. Eff 07/30/2006

c. This WLR does not alter the size or configuration of any drilling units already established by the 

Commission in the WLR Area prior to this WLR’s effective date (July 30, 2006). Eff 07/30/2006

d. This WLR shall not serve to bar the granting of relief to owners who file an application alleging abuse 

of their correlative rights to the extent that such owners can demonstrate that their opportunity to 

produce from the Niobrara Formation at locations herein authorized does not provide an equal 

opportunity to obtain their just and equitable share of oil and gas from such formation. Eff 

07/30/2006

e. Well exception locations to this WLR shall be subject to the provisions of Rule 318.c. Eff 07/30/2006

f. This WLR is a well location rule and supersedes existing Commission orders in effect at the time of its 

adoption only to the extent that the existing orders relate to permissible well locations and the 

number of wells that may be drilled in a quarter section. Commission orders in effect when this 

Rule 318B. is adopted nonetheless apply with respect to the size of drilling units already 

established by the Commission in the WLR Area. This WLR is not intended to establish well 

spacing. Accordingly, when an area subject to Rule 318B. is otherwise unspaced, it does not act 

to space the area but instead provides the permissible locations for any new Niobrara Formation 

wells. Similarly, Rule 318B. does not affect production allocation for existing or future wells. An 

operator may allocate production in accordance with the applicable lease, contract terms or 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 62

established drilling and spacing units recognizing the owner’s right to apply to the COGCC to 

resolve any outstanding correlative rights issues. Eff 07/30/2006

g. The landowner notice provisions for owner(s) of surface property within five hundred (500) feet of the 

proposed oil and gas location under Rule 305.e shall not apply to any such locations that are 

subject to the provisions of this Rule 318B. 

319. ABANDONMENT

The requirements for abandoning a well shall be as follows:

a. Plugging

(1) A dry or abandoned well, seismic, core, or other exploratory hole, must be plugged in such a 

manner that oil, gas, water, or other substance shall be confined to the reservoir in which 

it originally occurred. Any cement plug shall be a minimum of fifty (50) feet in length and 

shall extend a minimum of fifty (50) feet above each zone to be protected. The material 

used in plugging, whether cement, mechanical plug, or some other equivalent method 

approved in writing by the Director, must be placed in the well in a manner to 

permanently prevent migration of oil, gas, water, or other substance from the formation or 

horizon in which it originally occurred. The preferred plugging cement slurry is that 

recommended by the American Petroleum Institute (API) Environmental Guidance 

Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and 

Production Operations, i.e., a neat cement slurry mixed to API standards. However, 

pozzolan, gel and other approved extenders may be used if the operator can document 

to the Director's satisfaction that the slurry design will achieve a minimum compressive 

strength of three hundred (300) psi after twenty-four (24) hours and eight hundred (800) 

psi after seventy-two (72) hours measured at ninety-five degrees fahrenheit (95 °F) and 

at eight hundred (800) psi.

(2) The operator shall have the option as to the method of placing cement in the hole by (a) 

dump bailer, (b) pumping a balanced cement plug through tubing or drill pipe, (c) pump 

and plug, or (d) equivalent method approved by the Director prior to plugging. Unless 

prior approval is given, all wellbores shall have water, mud or other approved fluid 

between all plugs.

(3) No substance of any nature or description other than normally used in plugging operations 

shall be placed in any well at any time during plugging operations. All final reports of 

plugging and abandonment shall be submitted on a Well Abandonment Report, Form 6, 

and accompanied by a job log or cement verification report from the plugging contractor 

specifying the type of fluid used to fill the wellbore, type and slurry volume of API Class 

cement used, date of work, and depth the plugs were placed.

(4) In order to protect the fresh water strata, no surface casing shall be pulled from any well 

unless authorized by the Director.

(5) All abandoned wells shall have a plug or seal placed at the surface of the ground or the 

bottom of the cellar in the hole in such manner as not to interfere with soil cultivation or 

other surface use. The top of the pipe must be sealed with either a cement plug and a 

screw cap, or cement plug and a steel plate welded in place or by other approved 

method, or in the alternative be marked with a permanent monument which shall consist 

of a piece of pipe not less than four (4) inches in diameter and not less than ten (10) feet 

in length, of which four (4) feet shall be above the general ground level, the remainder to 

be embedded in cement or to be welded to the surface casing.
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(6) The operator must obtain approval from the Director of the plugging method prior to plugging, 

and shall notify the Director of the estimated time and date the plugging operation of any 

well is to commence, and identify the depth and thickness of all known sources of 

groundwater. For good cause shown, the Director may require that a cement plug be 

tagged if a cement retainer or bridge plug is not used. If requested by the operator, the 

Director shall furnish written follow-up documentation for a requirement to tag cement 

plugs.

(7) Wells Used for Fresh Water. When the well, seismic, core, or other exploratory hole to be 

plugged may safely be used as a fresh water well, and such utilization is desired by the 

landowner, the well need not be filled above the required sealing plug set below fresh 

water; provided that written authority for such use is secured from the landowner and, in 

such written authority, the landowner assumes the responsibility to plug the well upon its 

abandonment as a water well in accordance with these rules. Such written authority and 

assumption of responsibility shall be filed with the Commission, provided further that the 

landowner furnish a copy of the permit for a water well approved by the Division of Water 

Resources.

b. Shut-in and Temporary Abandonment.

(1) A well may be shut-in or temporarily abandoned when completed, upon approval of the 

Director, for a period not to exceed six (6) months provided the hole is cased or left in 

such a manner as to prevent migration of oil, gas, water or other substance from the 

formation or horizon in which it originally occurred. All shut-in or temporarily abandoned 

wells shall be closed to the atmosphere with a swedge and valve or packer, or other 

approved method. The well sign shall remain in place. If an operator requests shut-in or 

temporary abandonment status in excess of six (6) months the operator shall state the 

reason for requesting such extension and state plans for future operation. A Sundry 

Notice, Form 4, or other form approved by the Director, shall be submitted annually 

stating the status of method the well is closed to the atmosphere and plans for future 

operation.

(2) The manner in which the well is to be maintained should be reported to the Commission, and 

bonding requirements, as provided for in Rule 304, kept in force until such time as the 

well is permanently abandoned.

(3) A well which has ceased production or injection or and is incapable of production or injection 

shall be abandoned within six (6) months thereafter unless the time is extended by the 

Director upon application by the owner. The application shall indicate why the well is 

shut-in or temporarily abandoned and future plans for utilization. In the event the well is 

covered by a blanket bond, the Director may require an individual plugging bond on the 

shut-in or temporarily abandoned well. Gas storage wells are to be considered active at 

all times unless physically plugged.

(4) In addition to the requirements of Rule 324326, an injection well that is shut-in or temporarily 

abandoned shall have a mechanical integrity test performed within two years after the 

shut-in date in order to be retained in shut-in or temporarily abandoned status.

(5) If an injection well which has been shut-in or temporarily abandoned is determined not to 

have mechanical integrity as a result of any test required by the Commission rules and 

regulations, it must, within six (6) months following such a test, be either repaired and 

pass a mechanical integrity test or be plugged and abandoned.

320. LIABILITY
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The owner and operator of any well drilled for oil or gas production or injection purposes, or any seismic, 

core, or other exploratory holes, whether cased or uncased, shall be liable and responsible for the 

plugging thereof in accordance with the rules and regulations of the Commission regardless of whether 

the cost of such plugging and abandonment exceeds the amount of security as set forth in Rule 304.

321. DIRECTIONAL DRILLING

If an operator intends to drill a horizontal or deviated wellbore utilizing controlled directional drilling 

methods, other than whipstocking due to hole conditions, the plans shall accompany an application for 

Permit-to-Drill, Form 2. In addition to the information required on the plat in Rule 303.c., the plat shall also 

show the surface and bottom hole location. If the surface location is in a different section than the bottom 

hole location, a plat depicting each section is required. Additionally, the proposed directional survey 

including two (2) wellbore deviation plots, one depicting the plan view and one depicting the side view, 

shall accompany the application.

Within thirty (30) days of completion the operator shall submit a Drilling Completion Report, Form 5, 

according to Rule 308., with a copy of the directional survey coordinate listing and the wellbore deviation 

plots (plan and side views). The survey data shall be provided in a single analysis report with sufficient 

detail to determine the location of the wellbore from the base of the surface casing to the kick off point 

and from that point to total depth. It shall be the operator’s responsibility to ensure that the wellbore 

complies with the setback requirements in Commission orders or rules prior to producing the well. 

322. COMMINGLING

The commingling of production from multiple formations or wells is encouraged in order to maximize the 

efficient use of wellbores and to minimize the surface disturbance from oil and gas operations. 

Commingling may be conducted at the discretion of an operator, unless the Commission has issued an 

order or promulgated a rule excluding specific wells, geologic formations, geographic areas, or field from 

commingling in response to an application filed by a directly and adversely affected or aggrieved party or 

on the Commission's own motion.

This rule supercedes the procedural requirements to establish commingling and allocation contained in 

any Commission order as of the effective date of this rule, but does not supersede any allocation made 

under such order.

323. OPEN PIT STORAGE OF OIL OR HYDROCARBON SUBSTANCES

Storage of oil or any other produced liquid hydrocarbon substance in earthen pits or reservoirs is 

considered to constitute waste, except in emergencies where such substances cannot be otherwise 

contained. In such cases, these substances must be reclaimed and such storage eliminated as soon as 

practicable after the emergency is controlled, unless special permission to delay or continue is obtained 

from the Director.

324A. POLLUTION

a. The operator shall take precautions to prevent significant adverse environmental impacts to air, water, 

soil, or biological resources to the extent necessary to protect public health, safety and welfare, 

including the environment and wildlife resources, by using taking into consideration costeffectiveness and technically feasibility le measures to protect environmental quality and to 

prevent the unauthorized discharge or disposal of oil, gas, E&P waste, chemical substances, 

trash, discarded equipment or other oil field waste.

b. No operator, in the conduct of any oil or gas operation shall perform any act or practice which shall 

constitute a violation of water quality standards or classifications established by the Water Quality 

Control Commission for waters of the state, or any point of compliance established by the 
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Director pursuant to Rule 322D324D. The Director may establish one or more points of 

compliance for any event of pollution, which shall be complied with by all parties determined to be 

a responsible party for such pollution.

c. No owner, in the conduct of any oil or gas operation, shall perform any act or practice which shall 

constitute a violation of any comprehensive plan adopted by applicable air quality laws, 

regulations, and permits as administered by the Air Quality Control Commission or any other local 

or federal agency with authority for regulating air quality associated with such activitiesfor the 

prevention, control and abatement of pollution of the air of the state.

d. No injection shall be authorized pursuant to Rule 323 325 or Rule 401 unless the person applying for 

authorization to conduct the injection activities demonstrates that those activities will not result in 

the presence in an underground source of drinking water of any physical, chemical, biological or 

radiological substance or matter which may cause a violation of any primary drinking water 

regulation in effect as of July 12, 1982 and found at 40 C.F.R. Part 1412, or may otherwise 

adversely affect the health of persons. An underground source of drinking water is an aquifer or 

its portion:

(1) (a)A which supplies any public water system; or

(b)B which contains a sufficient quantity of ground water to supply a public water system; 

and

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

(ii) contains fewer than 10,000 milligrams per liter total dissolved solids; and

(2) which is not an exempted aquifer.

e. No person shall accept water produced from oil and gas operations, or other oil field waste for disposal 

in a commercial disposal facility, without first obtaining a Certificate of Designation from the 

County in which such facility is located, in accord with the regulations pertaining to solid waste 

disposal sites and facilities as promulgated by the Colorado Department of Public Health and 

Environment.

324B . EXEMPT AQUIFERS

a. Criteria for aquifer exemption. An aquifer or a portion thereof may be designated by the Director or 

the Commission as an exempted aquifer, in connection with the filing of an application pursuant 

to Rule 325, or Rule 401, and after notification to the Colorado Department of Public Health and 

Environment, Water Quality Control Division, if it meets the following criteria

(1) It does not currently serve as a source of drinking water;, and either subparagraph (2) or (3) 

below apply;

(2) It cannot now and will not in the future serve as a source of drinking water because:

A. It is mineral, hydrocarbon or geothermal energy producing, or can be demonstrated 

by a person filing an application pursuant to Rule 324325, or Rule 401, to contain 

minerals or hydrocarbons that, considering their quantity and location, are 

expected to be commercially producible; or

B. It is situated at a depth or location which makes recovery of water for drinking water 

purposes economically or technologically impractical; or
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C. It is so contaminated that it would be economically or technologically impractical to 

render the water fit for human consumption;

(3) The total dissolved solids content of the ground water is more than three thousand (3,000) 

and less than ten thousand (10,000) milligrams per liter and it is not reasonably expected 

to supply a public water system.

b. Aquifer exemption public notice. If an aquifer exemption is required as part of an injection permit 

process, the injection well applicant shall apply for an aquifer exemption. This application shall 

contain data and information which show that applicable aquifer exemption criteria set forth in 

Rule 324B.a. are met. After evaluation of the application and prior to designating an aquifer or a 

portion thereof as an exempted aquifer, the Director shall publish a notice of proposed 

designation in a newspaper of general circulation serving the area where the aquifer is located. 

The notice shall identify such aquifer or portion thereof which the Director proposes to designate 

as exempted, and shall state that any person who can make a showing to the Director that the 

requested designation does not meet the criteria set forth in Rule 324B.a. may request the 

Commission to hold a hearing thereon.

c. Evaluation of written requests for public hearing. Written requests for a public hearing before the 

Commission shall be reviewed and evaluated by the Director in consultation with the applicant to 

determine if the criteria set forth in Rule 324B.a. have been met. If, within thirty (30) days after 

publication of the notice, the Commission receives a hearing request for which the Director

determines the criteria set forth in Rule 324B.a. have not been met, the Commission shall hold 

such a hearing in accordance with the provisions of §34-60-108, C.R.S., 1973, as amended, and 

shall make a final determination regarding designation.

d. Aquifer exemption designation. If, within thirty (30) days after publication of the notice described in 

subparagraph b. above, the Commission does not receive a hearing request or receives a 

hearing request for which the Director determines the criteria set forth in Rule 324B.a. have been 

met, said aquifer or portion thereof shall be considered exempted thirty (30) days after publication 

of the notice.

324C. QUALITY ASSURANCE FOR CHEMICAL ANALYSIS

For the purpose of application for a permit for all wells authorized under Rule 323 and Rule 401, 

collection and analysis of water samples must comply with the Commission's approved quality assurance 

project plan.

324D. CRITERIA TO ESTABLISH POINTS OF COMPLIANCE

In determining a point of compliance, the Director shall take into consideration recommendations of the 

operator or any responsible party or parties, if applicable, including technical and economic feasibility, 

together with the following factors:

a. The classified use established by the Water Quality Control Commission, for any groundwater or 

surface water which will be impacted by contamination. If not so classified, the Director shall 

consider the quality, quantity, potential economic use and accessibility of such water;

b. The geologic and hydrologic characteristics of the site, such as depth to groundwater, groundwater 

flow, direction and velocity, soil types, surface water impacts, and climate;

c. The toxicity, mobility, and persistence in the environment of contaminants released or discharged from 

the site;

d. Established wellhead protection areas;
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e. The potential of the site as an aquifer recharge area; and

f. The distance to the nearest permitted domestic water well or public water supply well completed in the 

same aquifer affected by the event.

g. The distance to the nearest permitted livestock or irrigation water well completed in the same aquifer 

affected by the event.

325. UNDERGROUND DISPOSAL OF WATER

a. No person shall commence operations for the underground disposal of water, or any other fluids, into 

a Class II well, or any well regulated by the Commission, nor shall any person commence 

construction of such a well, without having first obtained written authorization for such operations 

from the Director. Persons wishing to obtain authorization to conduct underground disposal 

activities shall file with the Director an Underground Injection Formation Permit Application, Form 

31 and an Injection Well Permit Application, Form 33. If the disposal well is to be drilled, this 

application shall be submitted concurrently with the Application for Permit-to-Drill, Form 2, along 

with a service and filing fee to be determined by the Commission. (See Appendix III)

b. Withholding approval of underground disposal of water. The Director may withhold the issuance 

of a permit and the granting of approval of any Underground Injection Formation Permit 

Application, Form 31 and any Injection Well Permit Application, Form 33 for any proposed 

disposal well when the Director has reasonable cause to believe that the proposed disposal well 

could result in a significant adverse impact on the environment or public health, safety and 

welfare. In the event such approval is not granted, the Director shall immediately advise the 

operator and bring the matter to the Commission at its next regularly scheduled hearing.

c. The application for a dedicated injection well shall include the following information:

(1) The name, description and depth of the formation into which water is to be injected, and all 

underground sources of drinking water which may be affected by the proposed operation. 

A water analysis of the injection formation (if the total dissolved solids of the injection 

formation is determined to less than ten thousand (10,000) milligrams per liter, the aquifer 

must be exempted in accordance with Rule 322B.). The fracture pressure or fracture 

gradient of the injection formation.

(2) A base plat covering the area within one-quarter (1/4) mile of the proposed disposal well 

showing location of the proposed disposal well or wells and the location of all oil and gas 

wells, domestic and irrigation wells of public record and the identification of all oil and gas 

wells currently producing from the proposed injection zone within one-half (1/2) mile of 

the disposal zone. The names, addresses and holdings of all surface and mineral owners 

as defined in C.R.S. 34-60-103 (7), within one-quarter (1/4) mile of the proposed disposal 

well or wells, or all owners of record in the field if a field-wide system is proposed. These 

owners shall be specifically outlined and identified on the base plat. A list of all domestic 

and irrigation wells of public record, within one-quarter (1/4) mile of the proposed disposal 

well or wells, including their location and depth. (This information may be obtained at the 

Colorado Division of Water Resources.) Remedial action shall be required for any well 

within one-quarter (1/4) mile of the proposed disposal well or wells in which the injection 

zone is not adequately confined. The applicant shall include information regarding the 

need for remedial action on any well(s) penetrating the injection zone within one-quarter 

(1/4) mile of the proposed disposal well or wells, which the applicant may or may not 

operate and a plan for the performance of any such remedial work. A copy of all plans 

and specifications for the system and its appurtenances.
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(3) A resistivity log, run from the bottom of the surface casing to total depth of the disposal well or 

wells or any well within one (1) mile together with a log from that well that can be 

correlated with the injection well. If the disposal well is to be drilled, a description of the 

typical stratigraphic level of the disposal formation in the disposal well or wells, and any 

other available logging or testing data, on the disposal well or wells.

(4) A full description of the casing in the disposal well or wells. This shall include any information 

available on any remedial cement work performed to any casing string. This shall also 

include a schematic drawing showing all casing strings with cement volumes and tops, 

existing or as proposed, plug back total depth, depth of any existing open or squeezed 

perforations, setting depths of any bridge plugs existing or proposed, planned 

perforations in the injection zone, tubing and packer size and setting depth. A diagram of 

the surface facility showing all pipelines and tanks associated with the system. A listing of 

all leases connected directly by pipelines to the system.

(5) A listing of all sources of water, by lease and well, to be injected shall be submitted on a 

Source of Produced Water for Disposal, Form 26.

(6) Any proposed stimulation program.

(7) The estimated minimum and maximum amount of water to be injected daily with anticipated 

injection pressures. Maximum injection pressure will be set by the Director upon 

approval.

(8) The names and addresses of those persons notified by the applicant, as required by 

subparagraph i. of this rule.

d. The application for a simultaneous injection well shall include the following:

(1) The name, description and depth of the formation into which water is to be injected, and all 

underground sources of drinking water which may be affected by the proposed operation. 

A water analysis of the injection formation (if the total dissolved solids of the injection 

formation is determined to be less than ten thousand (10,000) milligrams per liter, the 

aquifer must be exempted in accordance with Rule 324B.); a water analysis from the 

producing formation; and go fracture pressure or fracture gradient of the injection 

formation.

(2) A base plat covering the area within one-quarter (1/4) mile of the proposed well showing the 

location of the proposed well or wells and the location of all oil and gas wells, domestic 

and irrigation wells of public record and the identification of all oil and gas wells currently 

producing from the proposed injection zone within one-half (1/2) mile of the disposal zone 

and the names, addresses and holdings of all mineral owners as defined in §34-60-103 

(7), C.R.S., within one-quarter (1/4) mile of the proposed disposal well or wells, or all 

owners of record in the field if a field-wide system is proposed. These owners shall be 

specifically outlined and identified on the base plat. Remedial action shall be required for 

any well within one-quarter (1/4) mile of the proposed well or wells in which the injection 

zone is not adequately confined. The applicant shall include information regarding the 

need for remedial action on any well(s) penetrating the injection zone within one-quarter 

(1/4) mile of the proposed disposal well or wells, which the applicant may or may not 

operate and a plan for the performance of any such remedial work and a copy of all plans 

and specifications for the system and its appurtenances.

(3) A resistivity log, run from the bottom of the surface casing to total depth of the disposal zone 

or such log from a well within one (1) mile together with a log from that well that can be 

correlated with the simultaneous injection well. If the simultaneous injection well is to be 
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drilled, a description of the typical stratigraphic level of the injection formation in the 

simultaneous injection well or wells, and any other available logging or testing data, on 

the simultaneous injection well or wells.

(4) A full description of the casing in the simultaneous injection well or wells. This shall include 

any information available on any remedial cement work performed to any casing string. 

This shall also include a schematic drawing showing all casing strings with cement 

volumes and tops, existing or as proposed, plug back total depth, depth of any existing 

open or squeezed perforations, setting depths of any bridge plugs existing or proposed, 

planned perforations in the injection zone, downhole pump setting depth and any tubing 

and or packer size and setting depth.

(5) Any proposed stimulation program.

(6) The estimated amount of water to be injected daily.

(7) Downhole pump specifications, together with a calculation of maximum discharge pressure 

created under proposed wellbore configuration. Downhole pump configurations shall be 

designed to inject below the injection zone fracture gradient.

(8) The names and addresses of those persons notified by the applicant, as required by 

subparagraph j. of this rule.

The following rules shall apply to both dedicated injection well and simultaneous injection well 

applications.

e. Mechanical integrity testing requirement. Prior to application approval, the proposed disposal well 

must satisfactorily pass a mechanical integrity test in accordance with Rule 326.

f. Centralized and commercial disposal well requirements. Prior to application approval, the 

appurtenant centralized and commercial disposal well operations shall comply with the 

requirements of Rules 704. and 908.

g. Multiple well applications. Application may be made to include the use of more than one (1) disposal 

well on the same lease, or on more than one (1) lease. Wherever feasible and applicable, the 

application shall contemplate a coordinated plan for the entire field.

h. The designated operator of a unitized or cooperative project shall execute the application.

i. Notice of the application for a dedicated injection well shall be given by the applicant by registered or 

certified mail or by personal delivery, to each surface owner and owner as defined in §34-60-

103(7), C.R.S., within one-quarter (1/4) mile of the proposed well or wells and to owners and 

operators of oil and gas wells producing from the injection zone within one-half (1/2) mile of the 

disposal well or to owners of cornering and contiguous units where injection will occur into the 

producing zones, whichever is the greater distance.

j. Notice of the application for a simultaneous injection well shall be given by the applicant by registered 

or certified mail or by personal delivery, to each owner as defined in §34-60-103(7), C.R.S., 

within one-quarter (1/4) mile of the proposed well or wells and to owners and operators of oil and 

gas wells producing from the injection zone within one-half (1/2) mile of the disposal well or to 

owners of cornering and contiguous units where injection will occur into the producing zones, 

whichever is the greater distance.

k. A copy of the notice of application shall be included with the disposal application filed with the 

Commission, and the applicant shall certify that notice by registered or certified mail or by 
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personal delivery, to each of the owners specified in subparagraphs i. and j., has been 

accomplished.

l. Notice of application requirements. The notice shall describe the proposed operation and shall state 

that any person who would be directly and adversely affected or aggrieved by the authorization of 

the underground disposal into the propose injection zone may file, within fifteen (15) days of 

notification, a written request for a public hearing before the Commission, provided such request 

meets the protest requirements specified in subparagraph m. of this rule. The notice shall also 

state that additional information on the operation of the proposed disposal well may be obtained 

at the Commission office.

m. Evaluation of written requests for public hearing. Written requests for public hearing before the 

Commission by a person, notified in accordance with subparagraphs i. and j. of this rule, who 

may be directly and adversely affected or aggrieved by the authorization of the underground 

disposal into the proposed injection zone, shall be reviewed and evaluated by the Director in 

consultation with the applicant. Written protests shall specifically provide information on:

(1) Possible conflicts between the injection zone's proposed disposal use and present or future 

use as a source of drinking water or present or future use as a source of hydrocarbons, 

or

(2) Operations at the well site which may affect potential and current sources of drinking water.

n. Dedicated injection well public notice. The Director shall publish a notice of the proposed disposal 

permit for dedicated injection wells in a newspaper of general circulation serving the area where 

the well(s) is (are) located. The notice shall briefly describe the disposal application and include 

legal location, proposed injection zone, depth of injection and other relevant information. 

Comment period on the proposed disposal application shall end thirty (30) days after date of 

publication. If any data, information, or arguments submitted during the public comment period 

appear to raise substantial questions concerning potential impacts to the environment, public 

health, safety and welfare raised by the proposed disposal well permit the Director may request 

that the Commission hold a hearing.

o. Injection application deadlines. If all of the data or information necessary to approve the disposal 

application has not been received within six (6) months of the date of receipt, the application will 

be withdrawn from consideration. However, for good cause shown, a ninety (90) day extension 

may be granted, if requested prior to the date of expiration.

326. MECHANICAL INTEGRITY TESTING

For the purpose of this rule, a mechanical integrity test of a well is a test designed to determine if there is 

a significant leak in the casing, tubing, or packer of the well, and there is significant fluid movement into 

an underground source of drinking water through vertical channels adjacent to the wellbore.

a. Injection Wells - A mechanical integrity test shall be performed on all injection wells.

(1) The mechanical integrity test shall include one (1) of the following tests to determine whether 

significant leaks are present in the casing, tubing, or packer:

A. A pressure test with liquid or gas at a pressure of not less than three hundred (300) 

psi or the minimum injection pressure, whichever is greater, and not more than 

the maximum injection pressure; or
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 71

B. The monitoring and reporting to the Director, on a monthly basis for sixty (60) 

consecutive months, of the average casing-tubing annulus pressure, following an 

initial pressure test; or

C. In lieu of A. and B. any equivalent test or combinations of tests approved by the 

Director.

(2) The mechanical integrity test shall include one (1) of the following tests to determine whether 

there are significant fluid movements in vertical channels adjacent to the well bore:

A. Cementing records which shall only be valid for injection wells in existence prior to 

July 1, 1986;

B. Tracer surveys;

C. Cement bond log or other acceptable cement evaluation log;

D. Temperature surveys; or

E. In lieu of A.-D., any other equivalent test or combination of tests approved by the 

Director.

(3) No person shall inject fluids into a new injection well unless a mechanical integrity test on the 

well has been performed and supporting documents including Mechanical Integrity Test, 

Form 14B, submitted and approved by the Director. Verbal approval may be granted for 

continuous injection following the test.

(4) Following the performance of the initial mechanical integrity test required by subparagraph 

(3), additional mechanical integrity tests shall be performed on each type of injection well 

as follows:

A. Dedicated injection well. As long as it is used for the injection of fluids, mechanical 

integrity tests shall be performed at the rate of not less than one (1) test every 

five (5) years. The first five (5) year period shall commence on the date the initial 

mechanical integrity test is performed.

B. Simultaneous injection well. No additional tests will be required after the initial 

mechanical integrity test.

(5) Following the performance of the initial mechanical integrity test required by subparagraph 

(3), additional mechanical integrity tests shall be performed on each well, as long as it is 

used for the injection of fluids, at the rate of not less than one (1) test every five (5) years. 

The first five (5) year period shall commence on the date the initial mechanical integrity 

test is performed.

b. Shut-in Wells - All shut-in wells shall pass a mechanical integrity test.

(1) A mechanical integrity test shall be performed on each shut-in well within two (2) years of the 

initial shut-in date. A mechanical integrity test shall be performed on each shut-in well on 

five (5) year intervals from the date the initial mechanical integrity test was performed. If, 

at any time, surface equipment is removed or the well becomes incapable of production, 

a mechanical integrity test must be performed within thirty (30) days. The mechanical 

integrity test for a shut-in well shall be:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 72

A. Isolation of the wellbore with a bridge plug or similar approved isolating device set one 

hundred (100) feet or less above the highest perforations and a pressure test 

with liquid or gas at a pressure of not less than three hundred (300) psi surface 

pressure or any equivalent test or combination of tests approved by the Director.

B. Following the performance of the initial mechanical integrity test for shut-in wells, 

additional tests, other than the five (5) year interval test, may be required.

c. Not less than ten (10) days prior to the performance of any mechanical integrity test required by this 

rule, any person required to perform the test shall notify the Director, in writing, of the scheduled 

date on which the test will be performed.

d. All wells shall maintain mechanical integrity. All wells which lack mechanical integrity shall be repaired 

or plugged and abandoned within six (6) months of failing a mechanical integrity test or of a 

determination through any other means that the well lacks mechanical integrity, and the well site 

reclaimed in accordance with Rule 1004.a. All injection wells which fail a mechanical integrity test, 

or which are determined through any other means to lack mechanical integrity, shall be shut-in 

immediately.

327. LOSS OF WELL CONTROL

The operator shall take all reasonable precautions, in addition to fully complying with Rule 317. to prevent 

any oil, gas or water well from blowing uncontrolled and shall take immediate steps and exercise due 

diligence to bring under control any such well, and shall report such occurrence to the Director as soon as 

practicable, but no later than twenty-four (24) hours following the incident. Within fifteen (15) days after all 

occurrences the operator shall submit a written report giving all details. The Director shall maintain these 

written reports in a central file.

328. MEASUREMENT OF OIL

The volume of all oil production from a lease or a production unit shall be measured and recorded prior to 

removal from the lease or production unit. The volume of production of oil shall be computed in terms of 

barrels of clean oil on the basis of properly calibrated meter measurements or tank measurements of oillevel differences, made and recorded to the nearest one-quarter (1/4) inch of one hundred percent 

(100%) capacity tables, subject to the following corrections in items a., b., and c. below. This rule shall be 

used consistently with standards established by the American Society for Testing and Materials (ASTM), 

the American Petroleum Institute (API) Manual of Petroleum Measurement Standards, the American Gas 

Association (AGA), the Gas Processors Association (GPA), or other applicable standards-setting 

organizations, and pursuant to contractual rights or obligations. Only those editions of standards cited 

within this rule shall apply to this rule; later amendments do not apply. The material cited in this rule is 

available for public inspection during normal business hours from the Public Room Administrator at the 

office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, these 

materials may be examined at any state publication depository library. Eff 05/30/2008

a. Correction for Impurities. The percentage of impurities (water, sand and other foreign substances 

not constituting a natural component part of the oil) shall be determined to the satisfaction of the 

Director, and the observed gross volume of oil shall be corrected to exclude the entire volume of 

such impurities. Eff 05/30/2008

b. Temperature Correction. The observed volume of oil corrected for impunrities shall be further 

corrected to the standard volume of sixty degrees fahrenheit (60°F) in accordance with ASTM D1250 Table 7, or any revisions thereof and any supplements thereto or any close approximation 

thereof approved by the Director. Eff 05/30/2008
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 73

c. Gravity Determination. The gravity of oil at sixty degrees fahrenheit 60° F. shall be determined in 

accordance with ASTM D-1250 Table 5, or any revisions thereof and any supplements thereto or 

any close approximation thereof approved by the Director. Eff 05/30/2008

d. Tank Gauging. Measurement by tank gauging shall be completed in accordance with industry 

standards as specified in API CH. 3 Gauging of Tanks (Section 3.1a Second Edition August 2005 

and Section 3.1b Second Edition June 2001) and the API CH. 18.1, Measure Procedures for 

Crude Oil Gathered from Small Tanks by Truck (Second Edition April 1997). Eff 05/30/2008

e. Metering Station. Measurement shall be completed in accordance with industry standards as 

specified in API CH. 4 Proving Systems (Section 2, Third Edition September 2003 and Section 8, 

First Edition November 1995), API CH. 5 Metering (CH. 5.1 Fourth Edition October 2005, CH. 5.2 

Third Edition October 2005, CH. 5.3 Fifth Edition September 2005, CH. 5.4 Second Edition July 

2005, CH. 5.5 Second Edition July 2005, and CH. 5.6 First Edition October 2002), API CH. 7 

Temperature Determination (First Edition June 2001), API CH. 8 Sampling (CH. 8.1 Third Edition 

October 1995 and CH. 8.2 Second Edition October 1995), and the API CH. 12, Calculation of 

Quantities (CH. 12.1 Part 1 Second Edition November 2001). Eff 05/30/2008

f. Lact Meters. Measurement utilizing lact units shall be in accordance with industry specifications or 

standards as specified in API SPEC. 6.1, Lease Automatic Custody Transfer Systems (Second 

Edition May 1991). Eff 05/30/2008

g. Sales Reconciliation. RESERVED Eff 05/30/2008

329. MEASUREMENT OF GAS

The volume of all gas produced from a lease or a production unit shall be measured and recorded prior to 

removal from the lease or production unit. Production of gas of all kinds shall be measured by meter 

unless otherwise agreed to by the Director. For computing volume of gas to be reported to the 

Commission, the standard pressure base shall be fourteen point seventy-three (14.73) psia, regardless of 

atmospheric pressure at the point of measurement, and the standard temperature base shall be sixty 

degrees fahrenheit (60°F). All volumes of gas to be reported to the Commission shall be adjusted by 

computation to these standards, regardless of pressures and temperatures at which the gas was actually 

measured, unless otherwise authorized by the Director. This rule shall be used consistently with 

standards established by the American Society for Testing and Materials (ASTM), the American 

petroleum Institute (API) Manual of Petroleum Measurement Standards, the American Gas Association 

(AGA), the Gas Processors Association (GPA), or other applicable standards-setting organizations, and 

pursuant to contractual rights and obligations. Only those editions of standards cited within this rule shall 

apply to this rule; later amendments do not apply. The material cited in this rule is available for public 

inspection during normal business hours from the Public Room Administrator at the office of the 

Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, these materials may 

be examined at any state publication depository library. Eff 05/30/2008

a. Metering Station. Installation and operation of gas measurement stations shall be in accordance with 

industry standards as specified in API CH. 14.3, Orifice Measurement (Part 2, Fourth Edition April 

2000 and Part 3, Third Edition August 1992 and Part 4, Third Edition November 1992); API CH. 

21.1, Electronic Measurement (gas) (First Edition September 1993); AGA Report #7, Turbine 

Measurement (January 2006); AGA Report #9, Ultrasonic Measurement (April 2007); and AGA 

Report #11, Coriolis Measurement (January 2003). Eff 05/30/2008

b. Metering Equipment. The devices used to measure the differential, line pressure, and temperature 

shall have accepted accuracy ratings established in industry standards as specified in API CH. 

22, Testing Protocol Standards (CH. 22.1 First Edition November 2006 and CH. 22.2 First Edition 

August 2005). Eff 05/30/2008
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 74

c. Meter Calibration. Meters shall be calibrated annually unless more frequent calibration is required by 

contractual obligations or by the Director. All calibration reports shall be created, maintained, and 

made available as operation records pursuant to Rule 205. In the event two consecutive meter 

calibrations exceed a 2% error, the operator shall report the test results to the Director who may 

require the operator to show cause why the meter should not be replaced. Eff 05/30/2008

d. Gas Quality. The heating value of produced natural gas shall be representative of the flowing gas 

stream at the lease or unit boundary, as determined by chromatographic analysis of a sample 

obtained in close proximity to the volume measurement device and shall be reported on an 

Operator’s Monthly Production Report, Form 7. Gas sampling and analysis shall occur annually 

unless more frequent sampling is required by contractual obligations or by the Director. Gas 

sampling, gas chromatography, and the resulting analysis data shall be in accordance with 

industry standards as specified in API CH. 14.1, Gas Sampling (Fifth Edition February 2006); 

GPA 2166, Gas Sampling (Revised 2005); GPA 2261, Gas Analysis (Revised 2000); GPA 2286, 

Extended Analysis; GPA 2145, Gas Physical Properties (Revised 2003); and GPA 2172, Gas 

Heating Value (Revised 1996). Eff 05/30/2008

e. Sales Reconciliation. RESERVED Eff 05/30/2008

330. MEASUREMENT OF PRODUCED AND INJECTED WATER

a. The volume of produced water shall be computed and reported in terms of barrels on the basis of 

properly calibrated meter measurements or tank measurements of water-level differences, made 

and recorded to the nearest one-quarter (1/4) inch of one hundred (100%) percent capacity 

tables. If measurements are based on oil/water ratios, the oil/water ratio must be based on a 

production test performed during the last calendar year. Other equivalent methods for 

measurement of produced water may be approved by the Director.

b. The volume of water injected into a Class II dedicated injection well shall be computed and reported in 

term of barrels on the basis of property calibrated meter measurements or tank measurements of 

water-level differences made and recorded to the nearest one-quarter (1/4) inch of one hundred 

percent (100%) capacity tables. If water is transported to an injection facility by means other than 

direct pipeline, measurement of water is required by a properly calibrated meter

c. The volume of water injected and produced in simultaneous injection wells shall be computed and 

reported in terms of barrels on the basis of calculated pump volumes, on the basis of property 

calibrated meter measurements, or on the basis of a produced gas to water ratio based on an 

annual production test.

331. VACUUM PUMPS ON WELLS

The installation of vacuum pumps or other devices for the purpose of imposing a vacuum at the wellhead 

or on any oil or gas bearing reservoir may be approved by the Director upon application therefore, except 

as herein provided. The application shall be accompanied by an exhibit showing the location of all wells 

on adjacent premises and all offset wells on adjacent lands, and shall set forth all material facts involved 

and the manner and method of installation proposed. Notice of the application shall be given by the 

applicant by registered or certified mail, or by delivering a copy of the application to each producer within 

one-half (1/2) mile of the installation.

In the event no producer within one-half (1/2) mile of the installation or the Commission itself files written 

objection or complaint to the application within fifteen (15) days of the date of application, then the 

application shall be approved, but if any producer within one-half (1/2) mile of said installation or the 

Commission itself files written objection within fifteen (15) days of the date of application, then a hearing 

shall be held as soon as practicable.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 75

332. USE OF GAS FOR ARTIFICIAL GAS LIFTING

Gas may be used for artificial gas lifting of oil where all such gas returned to the surface with the oil is 

used without waste. Where the returned gas is not to be so used, the use of gas for artificial gas lifting of 

oil is prohibited unless otherwise specifically ordered and authorized by the Commission upon hearing.

333. SEISMIC OPERATIONS

a. COGCC Form 20, Notice of Intent to Conduct Seismic Operations. Seismic operations require an 

approved Form 20 which shall be submitted to the Director prior to commencement of shothole 

drilling or recording operations. An informational copy of the Form 20 shall be filed by the 

operator with the local governmental designee at or before the time of filing with the Director. Any 

change of plans or line locations may be implemented without Director approval provided that 

after such change is performed, the Director shall receive written notice of the change within five 

(5) days.

A map shall be included with the notice. This map shall be at a scale of at least 1:48,000 showing 

sections, townships and ranges and providing the location of the proposed seismic lines, 

including source and receiver line locations.

The Notice of Intent to Conduct Seismic Operations, Form 20, shall be in effect for six (6) months 

from the date of approval. An extension of time may be granted upon written request submitted 

prior to the expiration date.

b. Surface owner consultation. Prior to the commencement of any seismic operation, a good faith effort 

shall be made to consult with all surface owners of the lands included in the seismic project area.

c. Exploration requiring the drilling of shotholes:

(1) Explosive storage. All explosives shall be legally and safely stored and accounted for in 

magazines when not in use in accordance with relevant regulations of the Alcohol, 

Tobacco and Firearms Division of the Federal Department of the Treasury.

(2) Blasting safety setbacks. Blasting shall be kept a safe distance from occupied a building

units, water wells or springs, unless by special written permission of the surface owner or 

lessee, according to the following minimum setback distances:

CHARGES IN LBS. 

GREATER THAN

CHARGES IN LBS. UP 

TO AND INCLUDING

MINIMUM SETBACK 

DISTANCE IN FEET

0 2 200

2 5 300

5 6 360

6 7 420

7 8 480

8 9 540

9 10 600

10 11 649

11 12 696

12 13 741

13 14 784

14 15 825

15 16 864

16 17 901
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 76

CHARGES IN LBS. 

GREATER THAN

CHARGES IN LBS. UP 

TO AND INCLUDING

MINIMUM SETBACK 

DISTANCE IN FEET

17 18 936

18 19 969

19 20 1000

20 1320

(3) Prior to any shothole drilling, the operator shall contact the Utility Notification Center of 

Colorado at 1-800-922-1987.

(4) Drilling and plugging. The following guidelines shall be used to plug shotholes unless the 

operator can demonstrate that another method will provide adequate protection to ground 

water quality and movement and long-term land stability:

A. Any slurry, drilling fluids, or cuttings which are deposited on the surface around the 

seismic hole shall be raked or otherwise spread out to at least within one (1) inch 

of the surface, such that the growth of the natural grasses or foliage shall not be 

impaired.

B. All shotholes shall be preplugged or anchored to prevent public access if not 

immediately shot. In the event the preplug does not hold, seismic holes shall be 

properly plugged and abandoned as soon as practical after the shot has been 

fired. However, a fired hole shall not be left unplugged for more than thirty (30) 

days without approval of the Director. In no event shall shotholes be left open, 

but shall be covered with a tin hat or other similar cover until they are properly 

plugged. The hats shall be imprinted with the seismic contractor's name or 

identification number or mark.

C. The hole shall be filled to a depth of approximately three (3) feet below ground level 

by returning the cuttings to the hole and tamping the returned cuttings to ensure 

the hole is not bridged. A non-metallic perma-plug either imprinted or tagged with 

the operator name or the identification number or mark described in the notice of 

intent shall be set at a depth of three (3) feet, and the remaining hole shall be 

filled and tamped to the surface with cuttings and native soil. A sufficient mound 

of native soil shall be left over the hole to allow for settling.

D. When non-artesian water is encountered while drilling seismic shotholes, the holes 

shall be filled from the bottom up with a high grade coarse ground bentonite to 

ten (10) feet above the static water level or to a depth of three (3) feet from the 

surface; the remaining hole shall be filled and tamped to the surface with cuttings 

and native soil, unless the operator otherwise demonstrates that use of another 

suitable plugging material may be substituted for bentonite without harm to 

ground water resources.

E. If artesian flow (water rising above the depth at which encountered) is encountered in 

the drilling of any seismic hole, cement or high grade coarse ground bentonite 

shall be used to seal off the water flow with the selected material placed from the 

bottom of the hole to the surface or at least fifty (50) feet above the top of the 

water-bearing material, thereby preventing cross-flow between aquifers, erosion 

or contamination of fresh water supplies. Said holes shall be plugged 

immediately.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 77

d. COGCC Form 20A, Completion Report for Seismic Operations. A Form 20A shall be 

submitted to the Director within sixty (60) days after completion of the project. The report 

shall include: maps (with a scale not less than 1:48,000) showing the location of all 

receiver lines, energy source lines and any shotholes. Shotholes encountering artesian 

flow shall be indicated on the map.

If the program included any shotholes, then the completion report shall be accompanied 

by the following:

(1) a certification by the party responsible for plugging the holes that all shotholes are 

plugged as prescribed by these rules and approved by the Director, and

(2) the latitude and longitude of each shothole location. The latitude and longitude 

coordinates shall be referenced in decimal degrees to an accuracy and precision 

of five decimals of a degree using the North American Datum (NAD) of 1983 

(e.g.; latitude 37.12345 N, longitude 104.45632 W) or reported in other form as 

approved by the Director. If GPS technology is utilized to determine the latitude 

and longitude, all GPS data shall meet the requirements set forth in Rule 215. a. 

through h.

e. Bonding Requirements. The company submitting the Notice of Intent to Conduct Seismic 

Operations, Form 20, shall file financial assurance in accordance with Rule 705. prior to the 

commencement of operations. The bond shall remain in effect until a request is made by the 

company to release the bond for the following reasons:

(1) The shotholes have been properly plugged and abandoned, and source and receiver lines 

have been reclaimed in accordance with this Rule 333., and

(2) There are no outstanding complaints received from surface owners that have not been 

investigated by the Director and addressed as provided for in Rule 522.

f. Reclamation requirements. Upon completion of seismic operations the surface of the land shall be 

restored as nearly as practicable to its original condition at the commencement of seismic 

operations. Appropriate reclamation of disturbed areas will vary depending upon site specific 

conditions and may include compaction alleviation and revegetation. All flagging, stakes, cables, 

cement, mud sacks or other materials associated with seismic operations shall be removed.

334. PUBLIC HIGHWAYS AND ROADS

All persons subject to the act and these rules and regulations while using public highways or roads shall 

be subject to the State Vehicles and Traffic Laws pursuant to Title 42, C.R.S. and the State Highway and 

Roads Laws, Title 43, C.R.S., pertaining to the use of public highways or roads within the state.

335. COGCC Form 15. PIT CONSTRUCTION REPORT/PERMIT

A Pit Construction Report/Permit, Form 15, shall be submitted for approval by the Director in accordance 

with Rule 903.

336. COGCC Form 18. COMPLAINT FORM

Any party who wishes to file a complaint regarding oil and gas operations is encouraged to submit a Form 

18. The Director shall investigate any complaint and determine what, if any, action shall be taken in 

accordance with Rule 522.

337. COGCC Form 19. SPILL/RELEASE REPORT
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 78

All spills and releases of E&P waste exceeding five (5) barrels shall be reported on a Spill/Release 

Report, Form 19. Form 19 shall be filed with the Director pursuant to the reporting requirements in Rule 

906.

338. COGCC Form 24. SOIL ANALYSIS REPORT

Soil Analysis Report, Form 24, shall be submitted where soil composition data is required, in accordance 

with Rule 910.

339. COGCC Form 25. WATER ANALYSIS REPORT

Water Analysis Report, Form 25, shall be submitted where water quality data is required, in accordance 

with Rule 910.

340. COGCC Form 27. SITE INVESTIGATION AND REMEDIATION WORKPLAN

Site Investigation and Remediation Workplan, Form 27, shall be submitted when required in accordance 

with Rule 909.

341. BRADENHEAD MONITORING DURING WELL STIMULATION OPERATIONS

The placement of all stimulation fluids shall be confined to the objective formations during treatment to the 

extent practicable. 

During stimulation operations, bradenhead annulus pressure shall be continuously monitored and 

recorded on all wells being stimulated. In lieu of recording annulus pressure, the bradenhead valve may 

be left open to monitor the annulus for flow during stimulation. Any abnormal flow shall be reported in the 

same manner as a pressure increase. For wells deeper than three thousand (3,000) feet or when surface 

casing is set deeper than five hundred (500) feet, prior approval from the Director will be required for this 

alternate method. 

If at any time during stimulation operations the bradenhead annulus pressure increases more than 200 

psig the operator shall verbally notify the Director as soon as practicable, but no later than twenty-four 

(24) hours following the incident. Within fifteen (15) days after the occurrence, the operator shall submit a 

Sundry Notice, Form 4, giving all details, including corrective actions taken. 

If intermediate casing has been set on the well being stimulated, the pressure in the annulus between the 

intermediate casing and the production casing shall also be monitored and recorded. 

The operator shall keep all well stimulation records and pressure charts on file and available for 

inspection by the Commission for a period of at least five (5) years.

400-SERIES UNIT OPERATIONS, ENHANCED RECOVERY PROJECTS, AND STORAGE OF LIQUID 

HYDROCARBONS

401. AUTHORIZATION

a. No person shall perform any enhanced recovery operations, cycling or recycling operations including 

the extraction and separation of liquid hydrocarbons from natural gas in connection therewith, or 

operations for the storage of gaseous or liquid hydrocarbons, nor shall any person carry on any 

other method of unit or cooperative development or operation of a field or a part of either, without 

having first obtained written authorization from the Commission to perform the aforementioned 

activities or operations. No person shall commence construction of a well for use in either 

enhanced recovery operations or for storage of gaseous or liquid hydrocarbons without having 

first obtained written authorization from the Commission to do so. These provisions shall not 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 79

apply to existing gas storage projects or to projects that have received approval of the Federal 

Energy Regulatory Commission; provided however, that a copy of such application and approval 

shall be submitted to the Commission and made a part of their records.

b. Persons wishing to obtain such authorization shall file an application for authorization with the 

Commission. The application may be filed by any one or more of the parties involved, or by the 

operator of the project for which authorization is sought. The application shall include the 

following:

(1) A plat showing the area involved, together with the well or wells, including drilling wells, dry 

and abandoned wells located thereon, all properly designated. If the plan of operation 

involves injection of fluids for enhanced recovery operations, or storage of liquid 

hydrocarbons, such plat shall show the names of owners of record within one-quarter 

(1/4) mile of the injection well or wells indicating whether they are surface owners, 

mineral interest owners, or working interest owners. The application shall also include 

information regarding the need for remedial action on wells penetrating the injection zone 

within one-quarter (1/4) mile of each injection well and a plan for the performance of any 

such remedial work.

(2) A full description of the particular operation for which authorization is required.

(3) Copies of the unit or co-operative agreement and operating agreement, unless these 

agreements have already been provided to the Commission.

(4) Where injection of fluids for enhanced recovery operations or storage of liquid hydrocarbons 

is proposed, the application shall also contain:

A. the name, description, thickness and depth of the following formations: those from 

which wells are producing or having produced; those which will receive any fluids 

to be injected; those capable of limiting the movement of any fluids to be injected;

B. the name and the depth to the bottom of all underground sources of drinking water 

which may be affected by the proposed activity or operation;

C. a resistivity log, run from the bottom of the surface casing to total depth of the 

injection well or wells, or a resistivity log of any well within one (1) mile together 

with a log from that well that can be correlated with a similar log of the injection 

well. If the injection well is to be drilled, a description of the typical stratigraphic 

level of the injection formation and any other available logging or testing data;

D. a description of the casing of the injection well or wells or the proposed casing 

program, including a schematic drawing of the surface and subsurface 

construction details of the system and a full description of cement jobs already in 

place or proposed;

E. a statement specifying the type of fluid to be injected, chemical analysis of the fluid to 

be injected, the source of the fluid, the estimated amounts to be injected daily, 

the anticipated injection pressures, water analysis of receiving formation, any 

available data on the compatibility of the fluid with the receiving formations and 

known or calculated fracture gradient (maximum authorized surface injection 

pressure will be set by the Director);

F. a description of any proposed stimulation program;
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 80

G. the name and address of the operator or operators of the project and those persons 

notified by the applicant.

(5) This Rule does not apply to gas storage projects in existence on August 18, 1986.

402. NOTICE AND DATE OF HEARING

Upon the filing of any application, the Commission shall issue notice thereof, as provided by the Act and 

these regulations. Said application shall be set for public hearing at such time as the Commission may fix.

403. ADDITIONAL NOTICE

If injection of fluids is proposed by said application, in addition to the notice required by the Act, a copy of 

such application shall be given in person or by first class mail to each owner of record of the reservoir 

involved within one-quarter (1/4) mile of the proposed intake well or wells. Such delivery, whether in 

person or by mail, shall take place on or before the date the application is filed. An affidavit shall be 

attached to the application showing the parties to whom the notice has been given and their addresses.

404. CASING AND CEMENTING OF INJECTION WELLS

Wells used for injection of fluids into the producing formation shall be cased with safe and adequate 

casing or tubing so as to prevent leakage, and shall be so set or cemented that damage will not be 

caused to oil, gas or fresh water resources. (Each injection well must satisfactorily pass a mechanical 

integrity test in accord with Rule 324 prior to injection.)

405. NOTICE OF COMMENCEMENT AND DISCONTINUANCE OF INJECTION OPERATIONS

The following provisions shall apply to all injection projects whether or not they are approved by the 

Commission:

a. Immediately upon the commencement of injection operations, the operator shall notify the Commission 

of the injection date.

b. Within ten (10) days after the discontinuance of injection operations the operator shall notify the 

Commission of the date of such discontinuance and the reasons therefore.

c. When any well in an approved enhanced recovery unit operation is converted to or from an injection 

status, notice shall be given on a Sundry Notice, Form 4, within thirty (30) days.

d. Before any intake well shall be plugged, notice shall be given to the Commission by the owner of said 

well, and the same procedure shall be followed in the plugging of such well as is provided for the 

plugging of oil and gas wells.

500-SERIES RULES OF PRACTICE AND PROCEDURE

501. APPLICABILITY OF RULES OF PRACTICE AND PROCEDURE

a. General. These rules shall be known and designated as “Rules of Practice and Procedure before the 

Oil and Gas Conservation Commission of the State of Colorado,” and shall apply to all 

proceedings before the Commission. These rules shall be liberally construed to secure just, 

speedy, and inexpensive determination of all issues presented to the Commission.

b. Prohibition of abuse. Notwithstanding any provision of these rules, the Commission shall, upon its 

own motion or upon the motion of a party to a proceeding, act to prohibit or terminate any abuse 

of process by an applicant, protestant, intervenor, witness or party offering a statement pursuant 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 81

to Rule 510. in a proceeding. Such action may include, but is not limited to, summary dismissal of 

an application, protest, intervention or other pleading; limitation or prohibition of harassing or 

abusive testimony; and finding a party in contempt. Grounds for such action include, but are not 

limited to, the use of the Commission's procedures for reasons of obstruction and delay; 

misrepresentation in pleadings or testimony; or, other inappropriate or outrageous conduct.

c. Judicial review. Any rule, regulation, or final order of the Commission, or any approval of an 

Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, by the 

Director for which a hearing is not requested within ten (10) days pursuant to Rule 305.d.(2), shall 

be subject to judicial review in accordance with the provisions of the Administrative Procedure 

Act, §24-4-101 to -108, C.R.S., and any other applicable provisions of law. The statutory time 

period for filing a notice of appeal from any Commission decision shall commence on the date the 

order is served or that is three (3) business days after the date the order is mailed. 

502. PROCEEDINGS NOT REQUIRING THE FILING OF AN APPLICATION

a. Commission's own motion. The Commission may, on its own motion, initiate proceedings upon any 

questions relating to conservation of oil and gas or the conduct of oil and gas operations in the 

State of Colorado, or to the administration of the Act, by notice of hearing or by issuance of an 

emergency order without notice of hearing. Such emergency order shall be effective upon 

issuance and shall remain effective for a period not to exceed fifteen (15) days. Notice of an 

emergency order shall be given as soon as possible after issuance.

b. Variances.

(1) Variances to any Commission rules, regulations, or orders may be granted in writing by the 

Director without a hearing upon written request by an operator to the Director, or by the 

Commission after hearing upon application. The operator or the applicant requesting the 

variance shall make a showing that it has made a good faith effort to comply, or is unable 

to comply with the specific requirements contained in these rules, regulations, or orders, 

from which it seeks a variance, including, without limitation, to securinge a waiver or an 

exception, if any, and that the requested variance will not violate the basic intent of the 

Oil and Gas Conservation Act.

(2) No variance to the rules and regulations applicable to the Underground Injection Control 

Program shall be granted by the Director without consultation with the U.S. 

Environmental Protection Agency, Region VIII, Waste Water Management Division 

Director.

(3) The Director shall report any variances granted at the monthly Commission hearing following 

the date on which such variance was granted.

503. ALL OTHER PROCEEDINGS COMMENCED BY FILING AN APPLICATION

a. All proceedings other than those initiated by the Commission or variance requests submitted for 

Director approval shall be commenced by filing with the Commission the original and thirteen (13) 

nine (9) copies of a typewritten or printed petition which shall be titled “application.” Whenever 

possible, tThe application shall also be submitted on compatible electronic media. The application 

shall set forth in reasonable detail the relief requested and the legal and factual grounds for such 

relief. The original of the application shall be executed by a person with authority to do so on 

behalf of the applicant, and the contents thereof shall be verified by a party with sufficient 

knowledge to confirm the facts contained therein. With the exception of those from state and local 

government agencies, eEach application shall be accompanied by a docket fee established by 

the Commission (see Appendix III), except applications seeking an order finding violation or an 

emergency order.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 82

b. Applications to the Commission may be filed by the following applicants:

(1) For purposes of applications for the creation of drilling units, applications for additional wells 

within existing drilling units, other applications for modifications to existing drilling unit 

orders, or applications for exceptions to Rule 318., only those owners within the proposed 

drilling unit, or within the existing drilling unit to be affected by the application, may be 

applicants.

(2) For purposes of applications for involuntary pooling orders made pursuant to §34-60-116, 

C.R.S., only those persons who own an interest in the mineral estate of the tracts to be 

pooled may be applicants.

(3) For purposes of applications for unitization made pursuant to §34-60-118, C.R.S., only those 

persons who own an interest in the mineral estate underlying the tract or tracts to be 

unitized may be applicants.

(4) For purposes of seeking an order finding violation, only the Director or a party who made a 

complaint under Rule 522. may be an applicant.

(5) For purposes of seeking a variance from the Commission, only the operator, mineral owner, 

surface owner or tenant of the lands which will be affected by such variance, other state 

agencies, any local government within whose jurisdiction the affected operation is 

located, or any person who may be directly and adversely affected or aggrieved if such 

variance is not granted, may be an applicant.

(6) For purposes of seeking a hearing on a Permit-to-Drill, Form 2, under Rules 303.d. and 

303.k.(2), the relevant local government shall be the applicant, and the hearing shall be 

conducted in similar fashion as is specified in Rule 508.j., k. and l. with respect to a public 

issues hearing. It shall be the burden of the local government applicant to bring forward 

evidence sufficient for the Commission to make the preliminary findings specified in 

subsection j. of Rule 508. at the outset of such hearing.

(6) For purposes of seeking a hearing pursuant to Rules 216.f.(4), 303.e.(2), or 303.m.(2), the 

operator seeking approval of the Application for Permit-to-Drill, Form 2, or an Oil and Gas 

Location Assessment, Form 2A, may be the applicant. 

(7) For purposes of seeking a hearing on approval of an Application for Permit-to-Drill, Form 2, or 

an Oil and Gas Location Assessment, Form 2A, under Rule 305.d.(2), any of the 

following may be the applicant: 

A. The operator; 

B. The surface owner, solely to raise issues that reasonably relate to potential significant 

adverse impacts to public health, safety, and welfare, including the environment 

and wildlife resources, that are within the Commission’s jurisdiction to remedy 

and where the potential impacts were not adequately addressed by the Director’s 

approval of the Application for Permit-to-Drill, Form 2, or Oil and Gas Location 

Assessment, Form 2A, or by the rules and regulations of the Commission; 

C. The relevant local government, provided that the hearing shall be conducted in similar 

fashion as is specified in Rules 508.j, 508.k, and 508.l with respect to a public 

issues hearing. It shall be the burden of the local government to bring forward 

evidence sufficient for the Commission to make the preliminary findings specified 

in Rule 508.j at the outset of such hearing; 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 83

D. The Colorado Department of Public Health and Environment, solely to raise issues 

relating to protection of public health, safety, and welfare, including the 

environment or wildlife resources; and

E. The Colorado Division of Wildlife, solely to raise issues relating to minimizing adverse 

impacts to wildlife resources. 

(8) For purposes of seeking a hearing on provisions related to measurement pursuant to Rule 

328 or 329, the mineral interest owner may be the applicant. 

(9) For purposes of seeking a hearing for an order limiting surface density pursuant to Rule 

1202.d.(5), the operator shall be the applicant. 

(710) For purposes of seeking relief or a ruling from the Commission on any other matter not 

described in (1) through (69) above, only persons who can demonstrate that they are 

directly and adversely affected or aggrieved by the conduct of oil and gas operations or 

an order of the Commission and that their interest is entitled to legal protection under the 

aAct may be an applicant.

c. Applications subject to the requirements for local public forums under Rule 508.a. shall be 

accompanied by a proposed plan (the “Proposed Plan” ) to address protection of the 

environment, public health, safety, and welfare, including the environment and wildlife resources,

and a description of the current surface occupancy/use. The Proposed Plan shall include the 

rules and regulations of the Commission as they are applied to oil and gas operations in the 

application lands along with any procedures or conditions the applicant will voluntarily follow to 

address the protection of the environment, public health, safety, and welfare, including the 

environment and wildlife resources.

d. Upon the filing of an application, the Secretary shall set the matter for hearing and ensure that notice 

is given. 

de. No later than seven (7) days after the application is filed, the applicant shall submit to the 

Commission a certificate of service demonstrating that the applicant served a copy of the 

application on all persons entitled to notice pursuant to these rules by mailing a copy thereof, firstclass postage prepaid, to the last known mailing address of the person to be served, or by 

personal delivery. The applicant shall at the same time submit to the Commission a list of all 

persons entitled to notice pursuant to these rules on compatible electronic media. If the applicant 

is unable to submit an electronic media list of persons noticed the applicant shall submit a written 

list of persons noticed no later than seven (7) days after the application is filed.

ef. The applicant shall enjoy a rebuttable presumption that it has properly served notice on persons 

entitled to notice of the proceeding by demonstrating through certification or testimony that notice 

was provided pursuant to Rules 507. and 508.

fg. In order to continue to receive copies of the pleadings filed in a specific proceeding a party who 

receives notice of the application shall file with the Secretary a protest or intervention in 

accordance with these rules.

gh. Subsequent to the initiation of a proceeding, all pleadings filed by any party shall be offered by filing 

with the Secretary the original and thirteen (13) nine (9) copies bearing the cause number 

assigned to such proceeding. Each pleading shall include the certificate of the party filing the 

pleading that the pleading has been served on all persons who have filed a protest or intervention 

in accordance with these rules, by mailing a copy thereof, first-class postage prepaid, to the last 

known mailing address of the person to be served, or by personal delivery.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 84

504. DOCKET NUMBER OF PROCEEDINGS

When a proceeding is initiated the Secretary of the Commission shall assign it a new docket number and 

enter on a separate page of a docket provided for such purpose, the proceeding with the date of the filing 

of the application, or the date of the entry of the Commission order, initiating such proceeding. All 

subsequent pleadings shall be assigned the same docket number and shall be noted with the date of 

filing upon the docket page or continued docket page, for such proceeding, as the case may be.

505. REQUIREMENT OF PUBLIC HEARING

Before the Commission adopts any rule or , regulation, or enters any order, or amendment thereof or 

grants any variance pursuant to Rule 502., the Commission shall hold a public hearing, scheduled in 

accordance with Rule 506. at such time and place as may be prescribed by the Commission. Any party 

shall be entitled to be heard as provided in these rules and regulations. The foregoing shall not apply to 

the issuance of an emergency order, notice of alleged violation, or cease and desist order.

506. HEARING DATE/CONTINUANCE

a. All applications shall be filed no later than fifty (50) days in advance of the hearing date for which the 

applicant proposes the matter be docketed provided the docket has not been filled by the 

Secretary. The Secretary shall have the discretion to accept applications later than fifty (50) days 

prior to the hearing date, subject to docket availability and the notice requirements of Rules 507. 

and 508. The Secretary shall grant the first request by an applicant for a continuance of any 

matter three (3) business days before the scheduled hearing, provided that a protest has not 

been filed. For contested matters the Secretary shall have the discretion to grant any motion for 

continuance stipulated to by the applicant and any protestants or intervenors. The Secretary shall 

notify the Commission of any continuances granted at the next regularly scheduled Commission 

meeting. The Commission may at any time direct the Secretary to discontinue granting 

continuances in any matter. In all other cases, requests for continuance shall be reviewed by the 

Commission before approval or denial. When a continuance request is heard by the Commission 

the moving party shall demonstrate good cause in order for the Commission to grant the 

continuance.

b. In all rulemaking proceedings, hearings shall be held in accordance with Rule 529.

c. The Commission may for good cause cancel or continue any hearing to another date by issuing written 

notice at any time prior to the close of the record, or by announcement at hearing. Good cause 

shall include, but shall not be limited to the Commission's acknowledgment that it will not have 

sufficient time at any regularly scheduled meeting to hear any matter. Any continuance of a 

hearing shall not extend the filing deadline for the filing of protests or interventions in accordance 

with Rule 509., unless the application is amended, or as otherwise allowed by the Commission.

d. When a Commission hearing is scheduled for multiple days the Secretary may estimate the time and 

date that a given matter may be heard by the Commission. The Commission may change at its 

discretion the proposed hearing docket, including the time or date of any scheduled hearing. It 

shall be the responsibility of the participating party and its attorney to be present when the 

Commission hears the matter.

507. NOTICE FOR HEARING

a. General notice provisions.

(1) When any proceeding has been initiated, the Commission shall cause notice of such 

proceeding to be given to all persons specified in the relevant sections of Rules 507. b 

and 507. c. at least twenty (20) days in advance of any Commission hearing at which the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 85

matter will first be heard. Notice shall be provided in accordance with the requirements of 

§34-60-108(4), C.R.S.

(2) The applicant shall assume the cost for publication, and if the number of notices exceeds one 

hundred (100), responsibility for mailing the notices.

(3) The Secretary shall give notice to any person who has filed a request to be placed on the 

Commission hearing notice list, and paid the annual fee therefor. Notice by publication or 

notice provided pursuant to the hearing notice list shall not confer interested party status 

on any person.

b. Notice for specific applications.

(1) Applications affecting drilling units. For purposes of applications for the creation of drilling 

units, applications for additional wells within existing drilling units or other applications for 

modifications of or exceptions to existing drilling unit orders (except for applications for 

well exception locations to existing orders which are addressed in subsection 45 of this 

rule) notice of the application shall be served on the owners within the proposed drilling 

unit or within the existing drilling unit to be affected by the applications.

(2) Applications for involuntary pooling. For purposes of applications for involuntary pooling 

orders made pursuant to §34-60-116,. C.R.S. notice of the application shall be served on 

those persons who own any interest in the mineral estate of the tracts to be pooled, 

except owners of an overriding royalty interest.

(3) Applications for unitization. For purposes of applications for unitization made pursuant to 

§34-60-118, C.R.S., notice of the application shall be served on those persons who own 

any interest in the mineral estate underlying the tract or tracts to be unitized and the 

owners within one-half (1/2) mile of the tract or tracts to be unitized.

(4) Applications changing certain well location setbacks. For purposes of applications that 

change the permitted minimum setbacks for established drilling and spacing units, notice 

of the application shall be served on those owners of contiguous or cornering tracts who 

may be affected by such change.

(5) Applications for well location exception. For purposes of applications made for exceptions 

to Rule 318, exceptions to legal locations within drilling and spacing units, or for an 

exception location to an existing order, notice of the application shall be served on the 

owners of any contiguous or cornering tract toward which the well location is proposed to 

be moved, provided that when the applicant owns any interest covering such tract, the 

person who owns the mineral estate underlying the tract covered by such lease shall also 

be notified. If there is more than one owner within a single drilling unit and the owners 

have designated a party as the operator on their behalf, notice shall be presumed 

sufficient if served upon the designated operator of the affected formation.

(6) Orders related to violations. With respect to the resolution of a Notice of Alleged Violation 

(NOAV) through an Administrative Order by Consent (AOC), and to applications for an 

Order Finding Violation (OFV), notice shall be provided to the complainant, to the violator, 

responsible party, or operator, as applicable, and by publication in accordance with §34-

60-108(4), C.R.S.

c. Notice to local government, Colorado Department of Public Health and Environment, and 

Colorado Division of Wildlife. For purposes of intervention pursuant to Rule 509. notice shall 

also be given to the local governmental designee, the Colorado Department of Public Health and 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 86

Environment, and the Colorado Division of Wildlife of applications made under subsections b.(1),

and (3) and (4) of this rule at the same time that notice is provided to the Commission.

508. LOCAL PUBLIC FORUMS, HEARINGS ON APPLICATIONS FOR INCREASED WELL DENSITY 

AND PUBLIC ISSUES HEARINGS.

a. Applicability of rule. The provisions of this Rule 508 only apply to aApplications that would result in 

more than one (1) well site or multi-well site per forty (40) acre nominal governmental quarterquarter section or that request approval for additional wells that would result in more than one (1) 

well site or multi-well site per forty (40) acre nominal governmental quarter-quarter section, within 

existing drilling units, not previously authorized by Commission order (together, for purposes of 

this rule, an “application for increased well density” or “application”) shall be subject to the 

provisions of this Rule 508.

b. Local public forum.

(1) The rules and regulations of the Oil and Gas Conservation Commission as they are applied to 

oil and gas operations are expected to adequately address impacts to the environment 

and public health, safety and welfare, including the environment and wildlife resources,

which may be raised by an application for increased well density.

(2) A local public forum may, however, be convened to consider potential issues related to the 

environment or public health, safety, and welfare, including the environment and wildlife 

resources, that may be raised by an application for increased well density that may not 

be completely addressed by these rules or the Proposed Plan submitted with the 

application to address protection of the environment, public health, safety, and welfare as 

described in pursuant to Rule 503.c.

A. A local public forum shall be convened on the Commission's own motion, or upon 

request from thea local governmental designee or the applicant.

B. A local public forum may be convened at the Director's discretion, or upon receipt of a 

request for a local public forum from a citizen of the county(ies) in which the 

application area is situated, after the Director's consideration of the following 

factors:

(i) The size of the application area and the number and density of surface 

location requested;

(ii) The population density of the application area;

(iii) The distribution of Indian, federal and fee lands within the application area;

(iv) The level of current or past public interest in increased well density in the 

vicinity of the application area;

(v) Whether the application is limited to the deepening or recompletion of 

existing wells, or directional drilling from existing surface locations,; or;

(vi) Whether the application is limited to an exploratory unit formed for 

involuntary pooling purposes.

(3) The Director shall notify the local governmental designee, the Colorado Department of Public 

Health and Environment, and the Colorado Division of Wildlife of any application for 

increased well density no later than five (5) days after receipt of such application. If the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 87

local governmental designee elects to require a local public forum it shall notify the 

Director of its decision within five (5) days of receipt of notice of the application.

(4) The Director shall notify the applicant of any decision to convene a local public forum no later 

than ten (10) days after receipt of the application.

c. Local public forums on federal and Indian lands.

(1) If the surface and the minerals of the application area are comprised in their entirety of 

federal or Indian lands no local public forum shall be convened because potential impacts 

to the environment or public health, safety, and welfare on such lands are subject to 

federal or tribal requirements. All proceedings on any application for increased well 

density on federal or Indian lands shall be conducted to comply with the obligations 

contained in any intergovernmental or tribal memoranda of understanding governing the 

conduct of oil and gas operations on federal or Indian lands.

(2) If the application area is comprised in part of federal or Indian lands, the Director shall consult 

with the appropriate federal or Indian authorities before scheduling any public forum on 

the application. Insofar as the application includes federal or Indian lands, proceedings 

thereon shall be conducted in accordance with this rule and any obligations contained in 

any intergovernmental or tribal memoranda of understanding governing the conduct of oil 

and gas operations on federal or Indian lands.

(3) The Director shall notify the appropriate federal and Indian authorities of any local public 

forum to be convened to evaluate an application area that includes federal or Indian 

lands. Federal or Indian participation in the local public forum may include, without 

limitation, presentation of the most recent applicable resource management plan(s) and 

any environmental assessment(s) or environmental impact statement(s) that cover or 

include all or any portion of the application area.

d. Notice of the local public forum.

(1) Within five (5) days from the date the applicant receives notice from the Director that a local 

public forum shall be convened, the applicant shall submit to the Director a list of the 

surface owners within the application area. In determining the identity and address of a 

surface owner for the purpose of giving all notices under this rule the records of the 

assessor for the county in which the lands are situated may be relied upon.

(2) At least twenty (20) days before the date of the local public forum the Director shall mail to 

the listed surface owners notice thereof.

(3) Within ten (10) days of receipt of an application for increased well density the Director shall,

by regular or electronic mail or by facsimile copy, provide to the local governmental 

designee(s), the Colorado Department of Public Health and Environment, and the 

Colorado Division of Wildlife notice of the local public forum or notice that based on the 

factors in Rule 508.b.(2). B. above, the Director will not conduct a local public forum

(4) At least ten (10) days before the date of the local public forum the Director shall publish 

notice thereof in a newspaper of general circuliation in the county(ies) where the 

application lands are located.

(5) The notice for the local public forum shall state that the forum is being conducted to consider 

any issues raised by the application that may affect the environment or public health, 

safety, and welfare, including the environment and wildlife resources that are not 

addressed by the rules or the Proposed Plan.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 88

(6) Within five (5) days of receipt of an application for increased well density, the Director shall 

post a description of such application on the COGCC internet web pageCommission 

website.

e. Timing and location of the local public forum.

(1) As soon as practicable after publication of notice, but at least ten (10) days prior to the 

scheduled Commission hearing on the application, the Director shall conduct the local 

public forum at a location reasonably proximate to the lands affected by the application. 

In the alternative, if the hearing is to be held at a location reasonably proximate to the 

lands affected by the application, the local public forum shall be replaced by the 

presentation of statements in accordance with Rule 510. during the hearing on the 

application.

(2) The Director shall immediately notify the applicant of the scheduled time and location of the 

local public forum.

(3) To the extent practicable, the local public forum shall be scheduled to accommodate the 

Director or the Director’s designee, the participants, and the applicant.

(4) If the application area is comprised of lands located in more than one jurisdiction the Director 

shall coordinate the local public forum to provide for a single forum at a reasonable 

location reasonably proximate to the lands affected by the application.

f. Conduct of the local public forum.

(1) A COGCC Hearing Officer shall preside over the local public forum. The COGCC Hearing 

Officer shall provide to the participants an explanation of the purpose of the local public 

forum and how the Commission may use the information obtained from the local public 

forum. The purpose of the local public forum is to address the sufficiency of the rules or 

the Proposed Plan with respect to protection of the environment or public health, safety, 

and welfare, including the environment and wildlife resources.

(2) The conduct of the local public forum shall be informal, and participants shall not be required 

to be sworn, represented by attorneys, or subjected to cross examination.

(3) Attendance or participation at the local public forum by a Commissioner shall not constitute a 

violation of Rule 515.

(4) The applicant shall participate in the local public forum and present information related to the 

application.

(5) The Director shall create a record of the local public forum by video-tape, audio-tape, or by 

court reporter. Such record shall be made available to all Commissioners for review prior 

to the hearing on the application and may be relied upon in making a decision to convene 

a public issues hearing.

g. Statements.

The local public forum shall be conducted to allow elected officials, local government personnel, and 

citizens to express concerns not completely addressed by the rules or the Proposed Plan or make 

statements regarding the potential impacts from applications for increased well density that relate to the 

environment or public health, safety, and welfare, including the environment and wildlife resources. 

Issues raised in the local public forum may include the following:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 89

(1) Impact to local infrastructure;.

(2) Impact to the environment;.

(3) Impact to wildlife resources;.

(4) Impact to ground water resources;.

(5) Potential reclamation impact; and

(6) Other impact to public health, safety, and welfare

The local public forum shall be limited to matters that are within the jurisdiction of the 

Commission.

h. Report to the Commission. At the conclusion of the local public forum the presiding Hearing Oofficer 

shall prepare and submit to the Commission a report of the proceedings. A copy of the report 

shall be made available, no later than five (5) days prior to the hearing on the application, to the 

Commissioners, the applicant, the Colorado Department of Public Health and Environment or the 

Colorado Division of Wildlife if it consulted on the application, any affected local government and 

the public and shall be posted to on the Commission COGCC Internet website page. The report 

on the local public forum presented to the Commission shall be included in the administrative 

record for the application, taking into consideration the nature of the local public forum process.

i. Conduct of the hearing on the application for increased well density.

(1) The hearing on the application shall be conducted in accordance with Rule 528.

(2) The Commission shall approve or deny the application based solely on the application’s 

technical merits in accordance with §34-60-116, C.R.S.

(3) The presiding Hearing Oofficer for any local public forum shall present to the Commission the 

report of the local public forum.

(4) At the conclusion of the hearing on the application, the Commission shall consider and decide 

whether to convene a public issues hearing based on the local public forum or 

statements made under Rule 510. and any motions to intervene, and the Commission 

may:

A. Approve the application without condition;

B. Approve the application with conditions based on the technical testimony presented at 

the hearing on the application;

C. Approve the application, and with the applicant's consent, attach to the order on the 

application conditions the Commission determines are necessary to address 

issues related to the environment or public health, safety or welfare, including the 

environment and wildlife resources;

D. Approve the application and stay its effective date to convene a public issues hearing 

in accordance with Rule 508.j; or.

E. Deny the application.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 90

(5) If the Commission orders a public issues hearing it shall set the public issues hearing for the 

next regularly scheduled Commission meeting unless the applicant requests at a 

prehearing conference, and the Commission agrees, to convene the public issues 

hearing immediately following the hearing on the application.

(6) If the Commission orders a public issues hearing it shall set the public issues hearing for the 

next regularly scheduled Commission meeting.

j. Public issues hearing.

Upon a request by an applicant, protestant, or intervenoer, or on the Commission's own motion, a 

public issues hearing shall be convened provided the Commission makes the following 

preliminary findings:

(1) That the public issues raised by the application reasonably relate to potential significant 

adverse impacts to the environment or public health, safety and welfare, including the 

environment and wildlife resources, that are within the Commission's jurisdiction to 

remedy; and

(2) That the potential impacts were not adequately addressed by:

A. In the case of an application for increased well density, the application or by the 

Proposed Plan; or

B. In the case of an Application for Permit-to-Drill, by such permit.; and

(3) That the potential impacts are not adequately addressed by the rules and regulations of the 

Commission.

k. Conduct of the public issues hearing.:

(1) The rules and regulations of the Commission shall apply to all participants in the public issues 

hearing.

(2) The public issues hearing shall be conducted, to the extent practicable, in accordance with 

Rule 528.

(3) After the public issues hearing the Commission may attach conditions to its order on the 

application to protect the environment from significant adverse impacts or to protect 

public health, safety and welfare, including the environment and wildlife resources, as are 

warranted by the relevant testimony, and that are not otherwise addressed by these rules 

and regulations and the Proposed Plan. In addition, the Commission may without 

limitation:

A. Direct the applicant to amend its Proposed Plan for Commission review and approval 

for all or a portion of the application area to address specific issues related to the 

environment or public health, safety and welfare, including the environment and 

wildlife resources, including any identified impacts of increased well density 

within all or a portion of the application area, rather than on a single well basis.

B. Include in any order a provision to allow the Director discretion to attach specific 

conditions to individual well permits as the Commission determines are 

reasonable and necessary to protect the environment or public health, safety, 

and welfare, including the environment and wildlife resources.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 91

(4) Any plan or conditions imposed by Commission order that would affect federal or Indian lands 

shall take into account conditions imposed by the federal or Indian authorities and any 

federal environmental analysis in order to facilitate regulatory consistency and minimize 

duplicative regulatory efforts.

(5) Any plan or conditions imposed shall take into account cost effectiveness and technical 

feasibility, and shall not be applied to prevent the drilling of new wells per se.

l. The Director and the Commission shall use best efforts to comply with the provisions of this Rule 508., 

however, any deviation from this rule shall not invalidate the give rise to a challenge to 

Commission’s action on the local public forum, the application for increased well density, or the 

public issues hearing.

509. PROTESTS/INTERVENTIONS/PARTICIPATION IN ADJUDICATORY PROCEEDINGS

a. The applicant and persons that have filed with the Commission a timely and proper protest or 

intervention pursuant to this rule shall have the right to participate formally in any adjudicatory 

proceeding. In the case of a local government, intervention shall be granted by right and without 

fee to the relevant local government, to the Colorado Department of Public Health and 

Environment solely to raise environmental or public health, safety, and welfare concerns, and to 

the Colorado Division of Wildlife solely to raise concerns about adverse impacts to wildlife 

resources.

(1) The protest or intervention shall be filed with the Secretary, and served on the applicant and 

its counsel at least ten (10) business days prior to the first hearing date on the matter.

(2) Description of affected interest:

A. A protest shall include information to demonstrate that the person is a protestant 

under these rules in order for the protest to be accepted by the Commission.

B. A local government, the Colorado Department of Public Health and Environment, or 

the Colorado Division of Wildlife intervening as a matter of right shall include in 

the intervention information describing concerns relating to the environmental or 

public health, safety and welfare, including the environment and wildlife 

resources, concerns raised by the application. When an intervention is filed by 

any local government, the Colorado Department of Public Health and 

Environment, the Colorado Division of Wildlife, or any person on an application 

subject to Rule 508.a., information on the following shall be included:

i. That the public issues raised by the application reasonably relate to potential 

significant adverse impacts to the environment or public health, safety 

and welfare, including the environment and wildlife resources, that are 

within the Commission's jurisdiction to remedy; and

ii. That the potential impacts were not adequately addressed by the application 

or by the Proposed Plan; and

iii. That the potential impacts are not adequately addressed by the rules and 

regulations of the Commission.

C. A party desiring to intervene by permission of the Commission shall include in the 

intervention information to demonstrate why the intervention will serve the public 

interest, in which case granting the intervention shall be at the Commission's sole 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 92

discretion. The Commission, at its discretion, may limit the scope of the 

permissive intervenor's participation at the hearing.

(3) The pleading shall include:

A. A general statement of the factual or legal basis for the protest or intervention;,

B. The relief requested;

C. A description of the intended presentation including a list of proposed witnesses;

D. A time estimate to hear the protest or intervention; and

E. A certificate of service attesting that the pleading has been served, at least ten (10) 

business days prior to the first hearing date on the matter, on the applicant and

any other party which has filed a protest or intervention in the proceeding. If the 

pleading is served by mail the party filing the pleading shall provide an electronic 

or a facsimile copy of the pleading to the applicant and other persons who have 

filed a proper protest or intervention in the matter on or before the final date for 

protest or intervention. If for any reason the party filing the pleading is not able to 

furnish a copy of the pleading to the applicant and the other persons who have 

filed a proper protest or intervention on or before the final date for protest or 

intervention, the party filing the pleading shall so notify the Secretary, the 

applicant and the other parties to the proceeding.

b. The Secretary or the Director may require any additional information necessary pursuant to these 

rules to ensure the application,. protest, or intervention is complete on its face.

c. Any person shall have the right to participate in an adjudicatory proceeding by making a 510. 

statement in accordance with these rules.

d. All pleadings filed pursuant to this rule shall be submitted with an original and nine thirteen (139) 

copies, and shall be accompanied by a docket fee established by the Commission (see Appendix 

III). The docket fee shall be refunded if an intervention is denied. In cases of extreme hardship, 

the docket fee may be refunded at the discretion of the Commission.

e. If the application is contested, the Commission or the Director, at its discretion, may direct the parties 

to engage in a prehearing conference in accordance with Rule 527. A prehearing conference may 

result in a continuance of the hearing, or bifurcation of hearing issues as determined by the 

Director, Hearing Officer, or Hearing Commissioner. 

fe. Participation at the hearing:

(1) Adjudicatory hearings shall be conducted in accordance with Rule 528. and any applicable 

prehearing orders of the Commission, or its designated Hearing Officer.

(2) Testimony and cross-examination by a protestant or intervenor shall be limited to those 

issues that reasonably relate to the interests that the protestant or intervenor seeks to 

protect, and which may be adversely affected by an order of the Commission.

510. STATEMENTS AT HEARING

a. Any person may make an oral statement at a hearing or submit a written statement, a form for which is 

available on the COGCC website, prior to or at any hearing that relates to the proceeding before 

the Commission. The Commission, at its discretion, may limit the length of any oral statement or 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 93

restrict repetitive statements. In an adjudicatory hearing, an oral statement shall not be accepted 

into the record unless:

(1) The statement is made under oath,; and

(2) The parties to the hearing are allowed to cross-examine the maker of the statement.

b. The Commission, at its discretion, may accept a sworn written statement into the record with due 

regard to the fact the statement was not subject to cross-examination.

c. The parties to the hearing shall have the right to object to inclusion of any statement under this Rule 

510. into the record. The Commission shall note the objection for the record. If the Commission 

accepts the basis for excluding the 510. statement from the record the substance of the 

statement shall not be considered by the Commission in making a decision on the matter at 

issue.

511. UNCONTESTED HEARING APPLICATIONS PROCEDURE

a. Upon the filing of an application, the Secretary shall set the matter for hearing and ensure that notice 

is given.

ba. If the matter is uncontested, the applicant may request, and the Director may recommend, approval 

without a hearing based on review on the basis of the merits of the merits of the verified 

application and the supporting exhibits. If the Director does not recommend approval of the 

application without hearing, the applicant may request an administrative hearing on the 

application. For purposes of this rule an uncontested matter shall mean any application that is not 

subject to a protest or an intervention objecting to the relief requested in the application and shall 

include matters in which all interested parties have consented in writing to the granting of an 

application without a hearing.

b. Uncontested matters may be reviewed or heard administratively by a Hearing Officer and 

recommended for approval on the Commission’s consent agenda. The Hearings Manager shall 

confer with hearing applicants as to which option under c. or d., below, is appropriate for each 

uncontested application. From time to time, uncontested applications recommended for approval 

by a Hearing Officer that may be of special interest to the Commission may be recommended for 

presentation to the Commission. 

c. Applications where hearing officer review of sworn written testimony and exhibits is 

appropriate. If the application is contested, the Commission or the Director, at their discretion, 

may direct the parties to engage in a prehearing conference in accordance with Rule 527. A 

prehearing conference may result in a continuance of the hearing, or bifurcation of hearing issues 

as determined by the Director, Hearing Officer or Hearing Commissioner.An applicant shall:

(1) Submit the following hard-copy documents to the Hearings Manager no later than close of 

business on the day following the scheduled protest/intervention day:

A. One (1) original written request for approval under Rule 511 briefly describing reasons 

the application may be a candidate for recommendation for approval without a 

hearing based on review of the merits of the verified application and the 

supporting exhibits (rather than necessitating an administrative hearing before a 

Hearing Officer); 

B. One (1) set of resumes/curricula vitae and sworn written testimony of witnesses 

verifying facts and accompanied by attachments or exhibits that adequately 

support the relief requested in the application; 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 94

C. A person having knowledge of the stated facts shall, under oath, sign a statement 

attesting to the facts stated in the written testimony and any attachments or 

exhibits. The sworn statement need not be notarized, but it shall contain 

language indicating that the signatory is affirming the testimony and supporting 

documents are true and correct to the best of the signatory’s knowledge and 

belief and, if applicable, that they were prepared by the signatory or under the 

signatory’s supervision; 

D. A sworn statement that is a summary of the testimony to support the relief requested 

in the application, including a request to take administrative notice of repetitive 

general, technical, or scientific evidence, where appropriate; 

E. One (1) set of exhibits which shall contain relevant highlights in bullet-point format on 

each exhibit; and

F. A draft proposed order with findings of fact and conclusions of law related to land, 

geology, engineering, and other appropriate subjects to support the relief 

requested in the application. Reference to testimony, exhibits, and previous 

Commission orders shall be included as findings in the draft proposed order. 

(2) Submit one (1) email for each application containing editable attachments for each of the 

following documents to the Hearings Assistant:

A. Written request for approval; 

B. Written testimony;

C. Summary of testimony; and 

D. Draft proposed order. 

d. Applications where an administrative hearing before one or more Hearing Officer is 

appropriate. An applicant shall: 

(1) Submit the following hard-copy documents to the Hearings Manager no later than at the time 

the administrative hearing is held: 

A. Two (2) sets of resumes/curricula vitae for the witnesses; 

B. A written summary of the testimony to support the relief requested in the application, 

including a request to take administrative notice of repetitive general, technical, 

or scientific evidence, where appropriate; 

C. Two (2) sets of exhibits which shall contain relevant highlights in bullet-point format on 

each exhibit; and 

D. A draft proposed order providing land, geology, engineering, and other appropriate 

findings to support the relief requested in the application. Reference to previous 

testimony, exhibits, and orders shall be included as findings in the draft proposed 

order. 

(2) Submit one (1) email for each application containing editable attachments for each of the 

following documents to the Hearings Assistant:

A. Written request for approval; 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 95

B. Written testimony; 

C. Summary of testimony; and 

D. Draft proposed order.

512. COMMISSION MEMBERS REQUIRED FOR HEARINGS AND/OR DECISIONS

Four Five (45) members of the Commission constitute a quorum for the transaction of business. 

Testimony may be taken and oath or affirmation administered by any member of the Commission.

513. RESERVED.GEOGRAPHIC AREA PLANS

a. Purpose. Geographic Area Plans are intended to enable the Commission to adopt basin-specific rules 

that promote the purposes of the Act. 

b. Scope. Geographic Area Plans shall cover an entire oil and gas field or geologic basin, likely 

encompassing the activities of multiple operators, in multiple sub-basins or drainages, over a 

period of ten (10) years or more. 

c. Procedure.

(1) The Commission’s adoption of a Geographic Area Plan shall follow Rule 529.

(2) The Commission may initiate a Geographic Area Plan for a basin by publishing notice of its 

intent to do so, and it may adopt a Geographic Area Plan after a public hearing, which 

shall include submittal of information from the public and public testimony. In addition to 

any other publication requirements in these rules, notice shall be published in a 

newspaper of local circulation in the area covered by the Geographic Area Plan and 

provided to the local governmental designee(s). 

(3) In adopting a Geographic Area Plan, the Commission shall consult with the Colorado 

Department of Public Health and Environment, Colorado Division of Wildlife, and local 

governmental designee(s). The Commission shall also consider any local government 

comprehensive plans or other local government long-range planning tools. 

(4) The Geographic Area Plan may include alternative development scenarios, designate units, 

adopt spacing orders, implement sampling or monitoring plans, or require consolidation 

of facilities within the area covered by the Plan subject to the Act. 

514. JUDICIAL REVIEWRESERVED

Any Commission order constitutes final agency action for the purpose of judicial review except as may 

otherwise be specified under these rules. The statutory time period for filing a notice of appeal from any 

Commission decision shall commence on the date the order is mailed or served.

515. EX PARTE COMMUNICATIONS

a. The following provisions shall be applied in any adjudicatory proceeding before the Commission or a 

Hearing Officer.

(1) No person shall make or knowingly cause to be made to any member of the Commission or a 

Hearing Officer, an ex parte communication concerning the merits of a proceeding which 

has been noticed for hearing.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 96

(2) No Commissioner or Hearing Officer shall make or knowingly cause to be made to any 

interested person an ex parte communication concerning the merits of a proceeding 

which has been noticed for hearing.

(3) A Commissioner or Hearing Officer who receives, or who makes or knowingly causes to be 

made, a communication prohibited by this rule shall place on the public record of a 

proceeding:

A. All such written communications and any responses thereto; and

B. Memoranda stating the substance of any such oral communications and any 

responses thereto.

(4) Upon receipt of a communication knowingly made or knowingly caused to be made by a 

person in violation of this rule, the Commission or a Hearing Officer may require the 

person to show cause why their claim or interest in the proceeding should not be 

dismissed, denied, or otherwise adversely affected on account of such violation.

b. Oral or written communication with individual Commission members is permissible in a rulemaking 

proceeding. If such information is relied upon in final decision- making it shall be made part of the 

record by the Commission. After the rulemaking record is closed new information that is intended 

for the rulemaking record shall be presented to the Commission as a whole upon approval of a 

request to reopen the rulemaking record.

c. This rule shall not limit the right to challenge a decision of the Commission or a Hearing Officer on the 

grounds of bias or prejiudice due to any ex parte communication.

516. STANDARDS OF CONDUCT

a. The purpose of this rule is to ensure that the Commission's decisions are free from personal bias and 

that its decision- making processes are consistent with the concept of fundamental fairness. The 

provisions of this rule are in addition to the requirements for Commission members set forth in 

Title 24, Article 18, Section 108.5 of the Colorado Revised Statutes. This rule should be 

construed and applied to further the objectives of fair and impartial decision making. To achieve 

these standards Commissioners and Hearing Officers should:

(1) Discharge their responsibilities with high integrity.

(2) Respect and comply with the law. Their conduct, at all times, should promote public 

confidence in the integrity and impartiality of the Commission.

(3) Not lend the prestige of the office to advance their own private interests, or the private 

interests of others, nor should they convey, or permit others to convey, the impression 

that special influence can be brought to bear on them.

b. Conflicts of interest. A conflict of interest exists in circumstances where a Commissioner or Hearing 

Officer has a personal or financial interest that prejudices that Commissioner's or Hearing 

Officer's ability to participate objectively in an official act.

(1) A Commissioner or a Hearing Officer shall disclose the basis for a potential conflict of interest 

to the Commission and others in attendance at the hearing before any discussion begins 

or as soon thereafter as the conflict is perceived. A conflict of interest may also be raised 

by other Commissioners, the applicant, any protestant or intervenor, or any member of 

the public.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 97

(2) In response to an assertion of a conflict of interest, a Commissioner may withdraw or the 

Director may designate an alternate Hearing Officer. If the Commissioner does not agree 

to withdraw, the other Commissioners, after discussion and comments from any member 

of the public,. shall vote on whether a conflict of interest exists. Such vote shall be 

binding on the Commissioner disclosing the conflict.

(3) In determining whether there is a conflict of interest that warrants withdrawal the Commission 

members or Hearing Officer shall take the following into consideration:

A. Whether the official act will have a direct economic benefit on a business or other 

undertaking in which the Commissioner or Hearing Officer has a direct or 

substantial financial interest.

B. Whether the potential conflict will result in the Commissioner or Hearing Officer not 

being capable of judging a particular controversy fairly on the basis of its own 

circumstances.

C. Whether the potential conflict will result in the Commissioner or Hearing Officer 

having an unalterablye closed mind on matters critical to the disposition of the 

proceeding.

c. Discharge of duties. In the performance of their official duties, the Commission shall apply the 

following standards:

(1) To be faithful to and constantly strive to improve their competence in regulatory principles, 

and to be unswayed by partisan interests, public clamor, or fear of criticism.

(2) To maintain order and decorum in the proceedings before them.

(3) To be patient, dignified and courteous to litigants, witnesses, lawyers and others with whom 

the Commission deals in an official capacity, and to require similar conduct of attorneys, 

staff, and others subject to their direction and control.

(4) To afford to every person who is legally interested in a proceeding, or their attorney, full right 

to be heard according to law.

(5) To diligently discharge their administrative responsibilities, maintain professional confidence 

in Commission administration, and facilitate the performance of the administrative 

responsibilities of other staff officials.

517. REPRESENTATION AT ADMINISTRATIVE AND COMMISSION HEARINGS

a. Natural persons may appear on their own behalf and represent themselves at hearings before the 

Commission, and persons allowed to make oral or written statements may do so without counsel. 

Pro se participants shall be subject to these rules and regulations.

b. Except as provided in a. and c. of this rule, representation at hearings before the Commission shall be 

by attorneys licensed to practice law in the State of Colorado, and provided that any attorney duly 

admitted to practice law in a court of record of any state or territory of the United States or in the 

District of Columbia,. but not admitted to practice in Colorado, who appears at a hearing before 

the Commission may, upon motion, be admitted for the purpose of that hearing only, if that 

attorney has associated for purposes of that hearing with any attorney who:

(1) Is admitted to practice law in Colorado;:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 98

(2) Is a resident or maintains a law office within Colorado; and

(3) Is personally appearing with the applicant in the matter and in all proceedings connected with 

it.

The resident attorney shall continue in the case unless other resident counsel is submitted. Any 

notice,. pleading, or other paper may be served upon the resident attorney with the same effect 

as if personally served on the non-resident attorney within this state. Resident counsel shall be 

present before the Commission unless otherwise ordered by the Commission.

c. The Commission has the discretion to allow representation by a corporate officer or director of a 

community organization, a closely held corporation, a citizens' group duly authorized under 

Colorado law, or if a limited liability corporation, the member/manager in the following 

circumstances:

(1) Where the agency is adopting a rule of future effect;:

(2) Local public forums; or

(3) When an individual is appearing on behalf of a closely held corporation as provided in §13-1-

127, C.R.S.;

d. Unless a non-attorney is appearing pro se or pursuant to §13-1-127, C.R.S., or the Director is 

participating pursuant to Rule 528.c., a non-attorney shall not be permitted to examine or crossexamine witnesses, make objections or resist objections to the introduction of testimony, or make 

legal arguments.

e. At administrative hearings before the Director, attorneys shall not be required.

518. SUBPOENAS

The Commission may, through the Secretary, issue subpoenas requiring attendance of witnesses and the 

production of books, papers, and other instruments to the same extent and in the same manner and in 

accordance with the procedure provided in the Colorado Rules of Civil Procedure which authorize 

issuance of subpoenas by Clerks of District Courts. A party seeking a subpoena shall submit the form of 

the subpoena to the Secretary for execution. Upon execution, the party requesting the subpoena has the 

responsibility to serve the subpoena in accordance with the Rules of Civil Procedure. Upon receipt of an 

objection to any subpoena issued by the Commission, the Commission has the discretion to limit the 

scope of the subpoena to matters that are within the scope of the Commission's jurisdiction under the Act.

519. APPLICABILITY OF COLORADO COURT RULES AND ADMINISTRATIVE NOTICE.

a. The Commission adopts the rules of practice and procedure contained in the Colorado Rules of Civil 

Procedure insofar as the same may be applicable and not inconsistent with the rules herein set 

forth.

b. In general, the rules of evidence applicable before a trial court without a jury shall be applicable, 

providing that such rules may be relaxed, where, by so doing, the ends of justice will be better 

served.

(1) To promote uniformity in the admission of evidence, the Commission, to the extent practical, 

shall observe and conform to the Colorado rules of evidence applicable in civil non-jury 

cases in the district courts of Colorado.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 99

(2) When necessary to ascertain facts affecting substantial rights of the parties to a proceeding, 

the Commission may receive and consider evidence not admissible under the rules of 

evidence, if the evidence possesses probative value commonly accepted by reasonable 

and prudent persons in the conduct of their affairs.

(3) Informality in any proceeding or in the manner of taking testimony shall not invalidate any 

Commission order, decision, rule or regulation.

c. Administrative notice. The Commission may take administrative notice of:

(1) Constitutions and statutes of any state and of the United States;

(2) Rules, regulations, official reports, decisions, and orders of state and federal administrative 

agencies;

(3) Decisions and orders of federal and state courts;

(4) Reports and other documents in the files of the Commission;

(5) Matters of common knowledge and undisputed technical or scientific fact;

(6) Matters that may be judicially noticed by a Colorado district court in a civil non-jury case; and

(7) Matters within the expertise of the Commission.

520. TIME OF HEARINGS AND HEARING/CONSENT AGENDA

a. Regular hearings will shall be held before the Commission on such days as may be set by the 

Commission.

b. The Secretary shall place on the consent agenda those matters recommended by a Hearing Officer for 

approval, those matters in which an Administrative Order by Consent (AOC) has been negotiated, 

and those uncontested matters for which a decision has been requested based on the verified 

application.

(1) All matters on Tthe consent agenda shall be voted on together, without deliberation and 

without the necessity of reading the individual items. However, except any 

Commissioner may request clarification from the Director or from the attorney or other 

representative of the applicant for any matter on the consent agenda.

(2) Any Commissioner may remove a matter from the consent agenda prior to voting thereon.

(3) Any matter removed from the consent agenda shall be heard at the end of the remaining 

agenda, if practicable and agreeable to the applicant, or, if not, scheduled for hearing at 

the next regularly scheduled meeting of the Commission.

521. RESERVED

522. PROCEDURE TO BE FOLLOWED REGARDING ALLEGED VIOLATIONS

a. Notice of Alleged Violation.

(1) A complaint requesting that the Director issue a Notice of Alleged Violation (NOAV) may be 

made by the mineral owner, surface owner or tenant of the lands upon which the alleged 

violation took place, by other state agencies, by the local government within whose 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 100

boundaries the lands are located upon which the alleged violation took place, or by any 

other person who may be directly and adversely affected or aggrieved as a result of the 

alleged violation.

(2) Oral complaints shall be confirmed in writing. Persons making a complaint are encouraged to 

submit a Complaint Form, Form 18.

(3) If the Director, on the Director's own initiative or based on a complaint, has reasonable cause 

to believe that a violation of the Act, or of any rule, regulation, or order of the 

Commission, or of any permit issued by the Director, has occurred, the Director shall 

cause the operator to voluntarily remedy the violation, or shall issue an NOAV to the 

operator. Reasonable cause requires, at least, physical evidence of the alleged violation, 

as verified by the Director.

(4) If the Director, after investigating a complaint made in accordance with this Rule 522.a.(1), 

decides not to issue an NOAV, the complainant may file an application to the 

Commission pursuant to Rule 503.b.(4), requesting the Commission enter an Order 

Finding Violation (OFV) in accordance with this rule.

(5) NOAV process.

A. An NOAV issued by the Director shall be served on the operator or the operator's 

designated agent, or on the operator if no agent has been designated, by 

personal delivery or by certified mail, return receipt requested.

B. The NOAV shall not be placed on the Commission docket, except as part of an 

application filed pursuant to subparagraph c. of this rule.

CB. The NOAV does not constitute final agency action for purposes of judicial appeal.

DC. The NOAV shall identify the statute, rule, regulation, order, permit or permit 

condition subject to Commission jurisdiction allegedly violated and the facts 

alleged to constitute the violation. The NOAV may propose appropriate corrective 

action and an abatement schedule if any, that the Director elects to require. The 

NOAV shall also describe the penalty, if any, which the Director may propose, to 

be recommended in accordance with Rule 523.

b. Resolution of a Notice of Alleged Violation.

(1) Informal procedures to resolve issues raised by an NOAV with the Director are encouraged.

Such procedures may include, but are not limited to, meetings, phone conferences and 

the exchange of information. If, as a result of such procedures, the Director determines 

that no violation has occurred, the Director shall revoke the NOAV in writing and shall 

provide a copy of the written notification to the complainant, if any.

(2) NOAVs may be resolved by written agreement of the operator and the Director as to the 

appropriate corrective action and abatement schedule, a copy of which shall be provided 

by the Director to the complainant, if any. Such agreements do not require Commission 

approval and shall not be placed on the Commission docket, except at the request of the 

operator.

(3) NOAVs which are not resolved by written agreement for correction and abatement or which 

recommend the imposition of a penalty may be provisionally resolved by negotiation 

between the operator and the Director. If such negotiations result in a proposed 

agreement, an Administrative Order By Consent (AOC) containing such agreement shall 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 101

be prepared and noticed for review and approval by the Commission. The Director may 

propose the terms for an AOC directly to the alleged violator. Upon Commission 

approval, the AOC shall become a final order, and the agreed penalty imposed. The AOC 

shall be placed on the consent agenda and Commission approval may be granted 

without hearing, unless an objection protest thereto is filed by the complainant. Unless 

the operator so agrees,. such AOC shall not constitute an admission of the alleged 

violation.

(4) The Director shall advise the complainant of any informal procedures used to facilitate 

resolution of the NOAV. A complainant may object to the proposed resolution by an AOC. 

At the Director's discretion the AOC may be reviewed and modified based on the 

complainant's concerns,. with the consent of the operator. If the complainant objects to 

the Director's final decision to revoke or settle the NOAV, the complainant shall have the 

right to file with the Commission an application for an Order Finding Violation (OFV). 

Such application shall be filed pursuant to Rule 503 within forty-five (45) days of the 

receipt of the Director's decision written determinationand shall be served on the Director 

and the operator. For purposes of this rule, the Director’s written determination shall be 

deemed to be received three (3) business days after mailing a copy thereof, first-class 

postage prepaid, to the last known address of the complainant. The application shall be 

served on the Director and the operator. The complainant shall have the burden of proof 

in an OFV hearing for which the complainant applies.

c. Order Finding Violation.

(1) If the operator contests the NOAV, as to the existence of the violation, the appropriate 

corrective action and abatement schedule, or as to any proposed penalty, the Director 

shall make application to the Commission for an OFV and shall place the matter on the 

next available Commission docket, providing that at least twenty (20) days’ notice of such 

application is provided to the operator.

(2) If the Director decides not to issue an NOAV, the Commission may conduct a hearing to 

consider whether to issue an OFV upon twenty (20) days’ notice to the affected operator 

under the following circumstances:

A. On the Commission's own initiative if it believes that the Director has failed to enforce 

a provision of statute, rule, regulation, order, permit or permit condition subject to 

Commission jurisdiction.

B. On the application of a complainant pursuant to Rule 503.b.(4), provided that such 

complainant has first made a written request to the Director to issue an NOAV 

and the Director has determined in writing not to do so. An application for 

hearing by a complainant shall be filed within forty-five (45) days of the receipt of 

the Director's written determination. For purposes of this rule, the Director's 

written determination shall be deemed to be received three (3) business days 

after mailing a copy thereof, first-class postage prepaid, to the last known 

address of the complainant. The application shall be served on the Director and 

the operator. The complainant shall have the burden of proof in an OFV hearing 

for which the complainant applies. 

(3) Upon an operator's request, a settlement conference shall be held with the Director no less 

than five (5) days before the hearing on an OFV. If an agreement is reached, an AOC 

containing such agreement shall be prepared and noticed for review and approval by the 

Commission, at its discretion. Upon such approval, the AOC shall become a final order 

and the agreed penalty shall be imposed. Such approval may be granted without hearing, 

unless an objection is filed hearing thereon is requested by a complainant. Unless the 

operator so agrees, such AOC shall not constitute an admission of the alleged violation. If 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 102

the complainant objects to settlement of the matter by an AOC, the complainant shall 

have the right to file with the Commission an application for an OFV. Such application 

shall be filed pursuant to Rule 503.b.(4) within forty-five (45) days of the receipt of the 

Director’s written determination. For purposes of this rule, the Director’s written

determination shall be deemed to be received three (3) business days after mailing a 

copy thereof, first-class postage prepaid, to the last known address of the complainant. 

The application shall be served on the Director and the operator. The complainant shall 

have the burden of proof in an OFV hearing for which the complainant applies. 

(4) A hearing to consider whether to issue an OFV shall be a de novo proceeding, unless the 

parties stipulate as to the facts, or as to the appropriate corrective action and abatement 

schedule,. in which case the hearing may be accordingly limited.

(5) The Director is always a necessary party to a hearing on an OFV. The operator against which 

an OFV is sought is always a necessary party but need not present a case. Any person, 

which is not the applicant for an OFV, but whose complaint initiated the enforcement 

proceeding, shall be granted intervenor status if so requested, pursuant to Rule 509., 

except that the filing fee shall be waived.

d. Cease and Desist Orders.

(1) The Commission or the Director may issue a cease and desist order whenever an operator 

fails to take corrective action required by final AOC or OFV.

(2) Whenever the Commission has evidence that a violation of any provision of the Act, any rule. 

permit, or order of the Commission has occurred under circumstances deemed to 

constitute an emergency situation, the Commission or the Director may issue a cease 

and desist order. If the order is entered by the Director it shall be immediately reported to 

the Commission for review and approval. Except as provided in subsection (3) below, 

sSuch order shall be considered a final order for purposes of judicial review.

(3) The order shall be served by personal delivery or by certified mail,. return receipt requested, 

or by confirmed electronic or facsimile copy followed by a copy provided by certified mail, 

return receipt requested, to on the operator or the operator's designated agent, or on the 

operator if no agent has been designated. for service of process and shall state the 

provision alleged to have been violated, the facts alleged to constitute the violation, the 

time by which the acts or practices cited are required to cease, and any corrective action 

the Commission or the Director elects to require of the operator. Any protest by an 

operator to a cease and desist order issued by the Director shall automatically stay the 

effective date of the order, in which case the order shall not be considered final for 

purposes of judicial review until such protest is heard.

(4) In the event an operator fails to comply with a cease and desist order, the Commission may 

request the attorney general to bring suit pursuant to §34-60-109, C.R.S.

523. PROCEDURE FOR ASSESSING FINES

a. Fines. An operator who violates any provision of the Act or any rule, permit, or order issued by the 

Commission shall be subject to a fine which shall be imposed only by order of the Commission, 

after nhearing, or by an AOC approved by the Commission. All fines shall be calculated using the 

base fine amount for the particular violation as set forth in the fine schedule in subparagraph c. of 

this Rule 523. subject to the following:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 103

(1) The Commission may in its discretion find that each day a violation exists constitutes a 

separate violation:; however, no fine for any single violation shall exceed one thousand 

dollars ($1.,000) per day.

(2) All fines shall be subject to adjustment based upon the factors listed in subparagraph d. of 

this Rule 523.

(3) For a violation which does not result in significant waste of oil and gas resources., damage to 

correlative rights, or a significant adverse impact on public health, safety or welfare, 

including the environment or wildlife resources,. the maximum penalty for any single 

violation shall not exceed ten thousand dollars ($10.,000) regardless- of the number of 

days of such violation.

(4) Fines for violations for which no base fine is listed shall be determined by the Commission at 

its discretion subject to subparagraphs (1), (2), and (3) of this Rule 523.a.

b. Voluntary disclosure. Any operator who conducts a voluntary self-evaluation as defined in the 100 

Series of the rules and makes a voluntary disclosure to the Director of a significant adverse 

impact on the environment or of a failure to obtain or comply with any necessary permits, shall 

enjoy a rebuttable presumption against the imposition of a fine for any violation relating to such 

impact or failure, under the following conditions:

(1) The disclosure is made promptly after the operator learns of the violation as a result of the 

voluntary self-evaluation;

(2) The operator making the disclosure cooperates with the Director regarding investigation of 

the issue identified in the disclosure; and

(3) The operator making the disclosure has achieved or commits to achieve compliance within a 

reasonable time and pursues compliance with due diligence.

The Commission shall deny the presumption against the imposition of fines only, if, after hearing, 

it finds that any of the preceding conditions have not been met, or that the use of this process 

was engaged in for fraudulent purposes.

c. Base fine schedule. The following table sets forth the base fine for violation of the rules listed

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404_1_48.jpg

RULE NUMBER BASE FINE

205 $5001000

206 $5001000

207 $5001000

208 $5001000

209 $1000

210 $250500

RULE NUMBER BASE FINE

301 $1000

302 $5001000

303 $1000

305 $1000

306 $1000

307 $250500
COGCC Final Draft Rules: Commission Review Copy 

(Nov. 7, 2008) 104

308$5001000

309$5001000

310$5001000

311$250500

312$250500

313$250500

313A $1000

314A$250500

315$250500

316A$5001000

316B $1000

317 $1000

317A $1000

317B $1000

318 $1000

319 $1000

320 $1000

321$5001000

322$5001000

323 $1000

324 $1000

325 $1000

326 $1000

327 $1000

328$5001000

329$5001000

330$5001000

331$5001000

332$5001000

333 $1000

341 $1000

RULE NUMBER BASE FINE

401$5001000

403$2501000

404 $1000

405$250500

RULE NUMBER BASE FINE

602 $1000

603 $1000

604 $1000

605 $750

606A$7501000

606B$7501000

607$7501000

608 $1000

RULE NUMBER BASE FINE

703 $1000 704 $1000
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 105

705 $1000

706 $1000

707 $1000

708 $1000

709 $1000

711 $1000

712 $1000

RULE NUMBER BASE FINE

802 $1000

803 $250500

804 $250500

805 $1000

RULE NUMBER BASE FINE

901 $1000

902 $1000

903 $1000

904 $1000

905 $1000

906 $1000

907 $1000

908 $1000

909 $1000

910 $1000

911 $1000

912 $1000

RULE NUMBER BASE FINE

1002 $1000

1003 $1000

1004 $1000

RULE NUMBER BASE FINE

1101 $1000

1102 $1000

1103 $1000

RULE NUMBER BASE FINE

1201 $1000

1203 $1000

1204 $1000

1205 $1000

d. Adjustment. The fine may be increased (if base fine is less than $1000) or decreased by application 

of the aggravating and mitigating factors set forth below.

Aggravating factors.

(1) The violation was intentional or reckless.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 106

(2) The violation had a significant negative impact, or threat of significant negative impact, on the 

environment or on public health, safety, or welfare.

(3) The violation resulted in significant waste of oil and gas resources.

(4) The violation had a significant negative impact on correlative rights of other parties.

(5) The violation resulted in or threatened to result in significant loss or damage to public or 

private property.

(6) The violation involved recalcitrance or recidivism upon the part of the violator.

(7) The violation involved intentional false reporting or recordkeeping.

(8) The violation resulted in economic benefit to the violator, including the economic benefit 

associated with noncompliance with the applicable rule, in which case the amount of 

such benefit may be taken into consideration.

(9) The violation results in significant, avoidable loss of wildlife or wildlife resources, including the 

ability of the land to produce vegetation supportive of wildlife. 

Mitigating factors.

(1) The violator self-reported the violation.

(2) The violator demonstrated prompt, effective and prudent response to the violation, including 

assistance to any impacted parties.

(3) The violator cooperated with the Commission, or other agencies with respect to the violation.

(4) The cause(s) of the violation was (were) outside of the violator's reasonable control and 

responsibility, or is (are) customarily considered to be force majeure.

(5) The violator made a good faith effort to comply with applicable requirements prior to the 

Commission learning of the violation.

(6) The cost of correcting the violation reduced or eliminated any economic benefit to the 

operatorviolator.

(7) The operator violator has demonstrated a history of compliance with Commission rules, 

regulations and orders.

e. Public projects. In lieu of or in reduction of fine amounts, an AOC may provide for the initiation of or 

participation in operator projects which are beneficial to the environment or public health, safety 

and welfare, including the environment and wildlife resources, and the Commission encourages 

AOCs which so provide.

f. Payment of fines. An operator against whom the Commission enters an order to pay a fine must pay 

the amount due within thirty (30) days of the effective date of the order., unless the Commission 

grants a longer period or unless the operator files for judicial appeal, in which event payment of 

the penalty shall be stayed pending resolution of such appeal. An operator's obligations to comply 

with the provisions of a Commission order requiring compliance with the Act, a permit condition,

or these rules and regulations shall not be stayed pending resolution of an appeal unless the stay 

is ordered by the court.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 107

524. DETERMINATION OF RESPONSIBLE PARTY

In all cases initiated by the Commission or at the request of the Director, it shall be the burden of the 

Director to present sufficient evidence to the Commission to determine responsible party status. In all 

other cases, the applicant shall have the burden to present sufficient evidence to the Commission to 

determine responsible party status. 

a. A hearing may be initiated on the Commission’ s own motion, upon application, or at the request of the 

Director to decide responsible party status upon at least twenty (20) days’ notice to the potentially 

responsible parties.

b. Potentially responsible parties shall be those persons that have or should have submitted Registration 

for Oil and Gas Operation, Form 1, or that have or should have submitted financial assurance for 

oil and gas operations pursuant to requirements of the 700-Series Rules. 

bc. Potentially responsible parties Operators shall provide to the Commission or Director such 

information as the Commission or Director may reasonably require in making such determination.

cd. The Commission shall make the determination under this section without regard to any contractual 

assignments of liability or other legal defenses between parties.

de. An operator shall enjoy a rebuttable presumption against mitigation liability under §34-60-124(7) 

C.R.S., for ongoing significant adverse environmental impacts where the violation which led to 

such impacts was committed by a predecessor operator and where the operator has conducted 

an environmental investigation, with reasonable due diligence, of the environmental condition of 

the particular asset or activity and such investigation did not reveal such significant adverse 

environmental impacts. The failure to report any condition which is causing such impacts, upon 

subsequent knowledge by the operator, shall negate the rebuttable presumption against 

mitigation liability.

ef. Where multiple persons are determined to be responsible parties, they shall share in the mitigation 

liability in proportion to their respective shares of production, respective periods of ownership or 

respective contributions to the problem, or any other factors as may serve the interests of 

fairness.

fg. The determination of responsible party status and mitigation liability shall require a showing that the 

responsible party conducted operations that have resulted in or have threatened to cause a 

significant adverse environmental impact to any air, water, soil or biological resource based on 

the conduct of oil or gas operations in contravention of any then applicable historic provisions of 

the Act or rules, whether or not the Commission has entered an order finding violation.

525. PERMIT-RELATED PENALTIES

a. If the Commission determines, after a hearing, that an operator failed to perform any required 

corrective action/abatement or failed to comply with a cease and desist order issued by the 

Director or the Commission with regard to violation of a permit provision, the Commission may 

issue an order suspending, modifying or revoking the a permit or permits authorizing the 

operation. The order shall provide the condition(s) which must be met by the operator for 

reinstatement of the permit(s). An operator which is subject to an order that suspends, modifies or 

revokes a permit or permits shall continue the affected operations only for the purpose of bringing 

them into compliance with the permit(s) or modified permit(s) and shall do so under the 

supervision of the Director. Once the condition for reinstatement has been met to the satisfaction 

of the Director and any fine not subject to judicial review or appeal has been paid, the Director 

shall inform the Commission, and the Commission, if in agreement, shall reinstate the permit(s).
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 108

b. Whenever the Commission or the Director has evidence that an operator is responsible for a pattern of

vioilation of any provision of the Act, or of any rule, permit or order of the Commission, the 

Commission or the Director shall issue a notice to such operator to appear for a hearing before 

the Commission. If the Commission finds, after such hearing, that a knowing and willful pattern of 

violation exists, it may issue an order which shall prohibit the issuance of any new permits to such 

operator. When such operator cdemonstrates to the satisfaction of the Commission that it has 

brought each of the violations into compliance and that any fine not subject to judicial review or 

appeal has been paid, such order denying new permits shall be vacated.

526. ADMINISTRATIVE HEARINGS IN UNCONTESTED MATTERS

a. As to applications where there has been no protest or intervention filed with the Commission in 

accordance with Rule 509., and where the Director has not recommended approval based on the 

content of the verified application and supporting exhibits., the application may be heard 

administratively prior to or on the date of the scheduled Commission hearing. The date and time 

of the administrative hearing shall be scheduled for the mutual convenience of the applicant and 

the Hearing Officer. The administrative hearing may be conducted prior to the protest or 

intervention date, but no order shall be entered by the Commission until it has fully considered 

any timely and properly filed protest or intervention.

b. One or more duly appointed Hearing Officers may hear the application at the administrative hearing.

Administrative hearings shall proceed informally in a meeting format. The applicant may present 

its case using exhibits and witnesses. All witnesses shall be sworn. At the conclusion of the 

administrative hearing., the Hearing Officer shall make a decision concerning approval or denial 

of the application and so inform the applicant. The Hearing Officer shall put such decision in a 

written report to the Commission containing findings of fact., conclusions of law, if any, and a 

recommended order. If the Hearing Officer recommends denial or qualified approval of the 

application, the applicant shall be entitled to a hearing de novo at the next scheduled hearing of 

the Commission.

c. The Commission may appoint Hearing Officers from the Commission staff for the purpose of hearing 

uncontested matters, presiding at local public forums or otherwise representing the Commission.

The service of the Hearing Officers shall be at the Director’ s discretion.

527. PREHEARING PROCEDURES FOR CONTESTED ADJUDICATORY PROCEEDINGS BEFORE

THE COMMISSION

a. The Commission encourages the use of prehearing conferences between parties to a contested 

matter in order to facilitate settlement, narrow the issues, identify any stipulated facts, resolve any 

other pertinent issues., and reduce the hearing time before the Commission. A prehearing 

conference shall be conducted at the direction of the Commission or the Director upon receipt of 

a protest or an intervention, or upon the request of the applicant or any person who has filed a 

protest or intervention. For matters in which a staff analysis has been prepared, the Director shall 

participate in the prehearing conference to advise the parties of the content of the preliminary 

staff analysis. The prehearing conference shall be conducted under the following general 

guidelines.

b. The Director., a Hearing Officer, or Hearing Commissioner shall preside over any prehearing 

conference and rule on preliminary matters in any proceeding pending before the Commission

c. The Secretary shall notify the applicant and any person who has filed a protest or intervention of the 

prehearing conference, and shall direct the attorneys for the parties, and pro se parties, to appear 

in order to expedite the hearing or settle issues, or both.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 109

d. All parties shall be prepared to discuss all procedural and substantive issues, and shall be authorized 

to make binding commitments on all procedural matters.

e. Preparation should include advance study of all materials filed and materials obtained through 

discovery.

f. Failure of any person to attend the prehearing conference, after being notified of the date, time, and 

place shall be a waiver of any objection and shall be deemed to be a concurrence to any 

agreement reached, or to any order or ruling made at the prehearing conference.

g. A prehearing statement may be required of any party.

h. At any prehearing conference, the following matters may be considered:

(1) Offers of settlement or designation of issues;

(2) Simplification of and establishment of a list or summary of the issues;

(3) Bifurcation of issues for hearing purposes;

(4) Admissions as to, or stipulations of facts not remaining in dispute or the authenticity of 

documents;

(5) Limitation of the number of fact and expert witnesses;

(6) Limitation on methods and extent of discovery, and a discovery schedule;

(7) Disposition of procedural motions; and

(8) Other matters raised by the parties, the Commission, or presiding Hearing Oofficer.

i. At any prehearing conference, the following information may be required:

(1) aAn exchange and acceptance of service of exhibits proposed to be offered in evidence, and 

establishment of a list of exhibits to be offered;

(2) eEstablishment of a list of witnesses to be called and anticipated testimony times; and

(3) A timetable for the completion of discovery, if discovery is allowed.

j. The parties shall reduce to writing any agreement reached or orders issued at a prehearing 

conference, which shall be filed with the presiding Hearing Oofficer, who shall enter a decision 

approving or disapproving it, or recommend modification as a condition for approval. An 

agreement which is disapproved shall be privileged and inadmissible as evidence in any 

Commission proceeding.

k. It is the intent of this rule that a prehearing order shall be binding upon the participating parties.

l. Subsequent to the prehearing conference and poor prior to the hearing on a contested matter, the 

parties shall each prepare and submit to the Hearing Officer a recommended order for the 

Commission to consider for adoption at the time of hearing.

528. CONDUCT OF ADJUDICATORY HEARINGS.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 110

a. Contested applications. Every party shall have the right to present its case by oral and/or 

documentary evidence. The following shall be the order of presentation unless otherwise 

established by the Commission at the hearing:

(1) Determination of whether any Commission members have a conflict of interest;

(2) Presentation of any prehearing order;

(3) Presentation of any motions and disposition of procedural matters;.

(4) Presentation of the any stipulations;, if any.

(5) Opening statement by the applicant;

(6) Opening statements by the respondent (and intervenoer, if any);

(7) Presentation of the case-in-chief by the applicant;

(8) Presentations by respondent (and intervener, if any);

(9) Presentation of statements under Rule 510., if any;

(10) Presentation of staff analysis, if requested by the Commission;.

(11) Rebuttal by the applicant;

(12) Rebuttal by the respondent (and intervenor, if any);

(13) Closing statement by the applicant;

(14) Closing statements by the respondent (and intervenor, if any);.

(15) Rebuttal closing statement by the applicant;.

(16) Upon motion and for good cause shown, the Commission may permit surrebuttal;.

(17) Closing of the record.

b. Uncontested applications not approved administratively. For uncontested applications not 

approved administratively pursuant to Rule 526., the applicant may present evidence in support 

of its application to the Commission. The order of presentation shall be as follows, unless 

otherwise established by the Commission at the hearing:

(1) Determination of whether any Commission members have a conflict of interest;

(2) Presentation of staff analysis, if requested by the Commission. The Commission, at its 

discretion. or upon request of the Director, may defer staff testimony until all of the 

evidence has been presented.

(3) Presentation of the case-in-chief by the applicant;

(4) Closing statement by the applicant;.

(5) Closing of the record.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 111

c. Enforcement hearings. In order to assure that all parties against whom a fine or penalty may be 

imposed are afforded due process of law, the Commission shall, at any hearing, permit the 

Director or the complainant pursuant to Rule 522.b.(4) to present evidence and argument and to 

conduct cross-examination required for a full disclosure of the facts. The enforcement matter shall 

be heard by the Commission de novo unless the operator waives its right to a de novo hearing 

prior to or at the Commission hearing. The order of presentation in a hearing for an enforcement 

matter shall be as follows, unless otherwise established by the Commission at the hearing:

(1) Determination of whether any Commission members have a conflict of interest;.

(2) Opening statements by all parties;

(3) Presentation by the Director;

(4) Presentation by any complainant under Rule 522.b.(4).,;

(5) Presentation by the operator;

(6) Rebuttal by the Director;

(7) Rebuttal by the respondent;

(8) Closing statements by the parties;

(9) Finding regarding existence of violation;

(10) If the Commission first determines by a preponderance of the evidence that a violation or 

violations exist, presentation by the Director of any recommended fine or permit-related 

penalty, and/or recommended corrective action/abatement to be taken by the operator;

(11) Response by any complainant under Rule 522.b.(4).;

(12) Presentation of statements under Rule 510., if any;

(13) Response by the operator;

(14) Rebuttal by the Director; and

(15) Closing statements by all parties;

(16) Closing of the record.

d. Closing of record. At the conclusion of closing statements, the record shall be closed to the 

presentation of any further evidence, testimony, or statements, except as such may occur in 

response to questions from the Commission.

e. Witnesses. Each witness shall take an oath or affirmation before testifying. After a witness has 

testified, the applicant., the protestant or participating intervenors and any Commissioner may 

cross-examine that witness in the order established by the chairperson of the Commission.

f. Limitations of testimony. Where two or more protestants or intervenors have substantially similar 

interests and positions, the Commission may limit cross-examination or argument on motions and 

objections to fewer than all the intervenors. The Commission may also limit testimony to avoid 

undue delay, waste of time or needless presentation of cumulative evidence.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 112

g. Commission findings and order. After due consideration of written and oral statements,. the 

testimony, and the arguments presented at hearing, the Commission shall make its findings and 

order,. based upon evidence in the record and,. as appropriate,. consistent with the Act and any 

rule,. permit,. or order made pursuant thereto.

529. PROCEDURES FOR RULEMAKING PROCEEDINGS

a. Institution Initiation of rulemaking. The Commission may institute initiate rulemaking on its motion 

or in response to an application filed by any person.

b. Applications for rulemaking. Any person may petition the Commission to initiate rulemaking. All 

applications for rulemaking shall contain the following information:

(1) The name, address, and telephone number of the person requesting the rulemaking;

(2) A copy of the rule proposed in the application and a general statement of the reasons for the 

requested rule; and

(3) A proposed statement of the basis and purpose for the rule.

c. Notice of proposed rulemaking. All rulemaking hearings of the Commission shall be noticed by 

publication in the Colorado Register not less than twenty (20) days and not more than sixty (60) 

days prior to the hearing and as otherwise specified in the Administrative Procedure Act, C.R.S. 

§24-4-103.

d. Time for rulemaking. The rulemaking hearing shall not be held until the expiration of six (6) months 

from the date of application unless the Commission, in its discretion, decides that an earlier 

hearing is appropriate.

ed. Development of proposed rules. Prior to the notice of proposed rulemaking, the Commission or 

Director may use informal procedures to gather information, including, but not limited to public 

forums, investigation by Commission staff, and formation of rulemaking teams. Commissioners 

may participate in such informal proceedings.

fe. Content of notice. The notice shall state the time, date, place, and general subject matter of the 

hearing to be held. It may include a statement indicating whether an informal public meeting will 

be held, the time, date, place, and general purpose of the meeting, any special procedures the 

Commission deems appropriate for the particular rulemaking proceeding and a statement 

encouraging public participation. The notice shall state that the proposed regulations will be 

available upon request from the office of the Commission, the date of availability, and any fee. 

The notice shall include a short and plain statement which summarizes the intended action and 

states generally the basis and purpose of the rule.

gf. The rulemaking hearing. The Commission shall hold a formal public hearing before promulgating 

any rules or regulations. At that hearing, the Commission shall afford any person an opportunity 

to submit data, views or arguments. The Commission may limit such testimony or presentation of 

evidence at its discretion and may prohibit repetitive, irrelevant, or harassing testimony

hg. Conduct of rulemaking hearings.

(1) The Commission encourages any person to participate at rulemaking hearings. The times at 

which the public may participate will shall be determined at the discretion of the 

Commission. The Commission may, at its discretion, limit the amount of time a person 

may use to comment or make public statements. Oaths shall not be required for public 

participation.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 113

(2) The Commission encourages witnesses to make plain, brief, and simple statements of their 

positions. It also encourages submittal of written statements prior to hearing, with only an 

oral summary of such a statement at the hearing.

(3) The order of presentation at a rulemaking hearing shall be as established by the Commission 

at the hearing.

(4) The Commission has the discretion to continue rulemaking hearings by announcement at the 

rulemaking hearing without republication of republishing the proposed rule.

530. INVOLUNTARY POOLING PROCEEDINGS

a. An application for involuntary pooling pursuant to §34-60-116, C.R.S., may be filed at any time an

nonconsenting owner within a the drilling and spacing unit established by Commission order fails 

or refuses to agree to bear his its proportionate share of the costs and risks of drilling and 

operating the well or to lease its minerals. An application for involuntary pooling may be filed at 

any time prior to or after the drilling of a well; however, any involuntary pooling order issued shall 

be retroactive to the date the application is filed with the Commission unless the payor agrees 

otherwise. As used herein a nonconsenting owner shall mean an 

b. An owner shall be deemed a nonconsenting owner in the area to be pooled whoif, after at least thirty 

(30) days’ written notice of the following information, the owner does not elect in writing to 

consent to participate in the cost of the well concerning which the pooling order is sought:

(1) The location and objective depth of the well;.

(2) The estimated drilling and completion cost of the well.; and

(3) The estimated spud date for the well or range of time within which spudding is to occur.

(4) An authority for expenditure prepared by the operator and containing the information required 

above, together with additional information deemed appropriate by the operator shall 

satisfy this obligation.

bc. An unleased owner shall be deemed a nonconsenting owner if, after at least thirty (30) days’ written 

notice, the unleased owner has failed or refused a reasonable offer to lease. In determining

whether a reasonable offer to lease has been tendered under §34-60-116(7)(d), C.R.S., the 

Commission shall consider the lease terms listed below for the drilling and spacing unit in the 

application and for all cornering and contiguous units that are under the proposed lease:

(1) Date of lease and primary term or offer with acreage in lease;

(2) Annual rental per acre;

(3) Bonus payment or evidence of its non-availability;

(4) Mineral interest royalty; and

(5) Such other lease terms as may be relevant.

600-SERIES SAFETY REGULATIONS

601. INTRODUCTION
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 114

The rules and regulations in this section are promulgated to protect the health, safety and welfare of the 

general public during the drilling, completion and operation of oil and gas wells and producing facilities. 

They do not apply to parties or requirements regulated under the Federal Occupational Safety and Health 

Act of 1970 (See Rule 212).

602. GENERAL

The training and action of employees, as well as proper location and operation of equipment is an 

important part of any safety program. While this section is general in nature, it is considered a basic part 

of the foundation of any safety program.

a. Employees shall be familiarized with these rules and regulations as provided herein as they relate to 

their function in their respective jobs. Each new employee should have his job outlined, explained 

and demonstrated.

b. Unsafe and potentially dangerous conditions as defined by these rules, should be reported 

immediately by employees to the supervisor in charge and shall be remedied as soon as 

practical. Any accident involving injury to wellsite personnel or to a member of the general public 

which requires medical treatmenthospitalization, or significant damage to equipment or the 

wellsite shall be reported to the Director Oil and Gas Conservation Commission as soon as 

practicable, but in no event later than twenty-four (24) hours after the accident. A COGCC 

Accident Report, Form 22, shall be submitted to the Director within ten (10) days of the accident. 

Accidents that require only first aid treatment are not subject to these reporting requirements. 

Where unsafe or potentially dangerous conditions exist, the owner or operator shall respond as 

directed by an agency with demonstrated authority to do so (such as sheriff, fire district director, 

etc.).

c. Vehicles of persons not involved in drilling, production, servicing, or seismic operations shall be 

located a minimum distance of one hundred (100) feet from the wellbore, or a distance equal to 

the height of the derrick or mast, whichever is greater. Equivalent safety measures shall be taken 

where terrain, location or other conditions do not permit this minimum distance requirements.

d. Existing wells are exempt from the provisions of these regulations as they relate to the location of the 

well.

e. Existing producing facilities shall be exempt from the provisions of these regulations with respect to 

minimum distance requirements and setbacks unless they are found by the Director to be unsafe.

f. Self-contained sanitary facilities shall be provided during drilling operations and at any other similarly 

staffed oil and gas operations facility.

603. DRILLING AND WELL SERVICING OPERATIONS AND HIGH DENSITY AREA RULES

a. Statewide setbacks. Subparagraph (1) below shall apply to all areas of the state except as provided 

under subparagraphs b. and e. of this rule. Subparagraph (2) below shall apply to all areas of the 

state.

(1) aAt the time of initial drilling of the well, the wellhead shall be located a distance of one 

hundred fifty (150) feet or one and one-half (1-1/2) times the height of the derrick, 

whichever is greater, from any occupied building unit, public road, major above ground 

utility line, or railroad.

(2) A well shall be a minimum distance of one hundred fifty (150) feet from a surface property 

line. An exception may be granted by the Director if it is not feasible for the operator to 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 115

meet this minimum distance requirement and a waiver is obtained from the offset surface 

owner(s). An exception request letter stating the reasons for the exception shall be 

submitted to the Director and accompanied by a signed waiver(s) from the offset surface 

owner(s). Such waiver shall be written and filed in the county clerk and recorder's office 

and with the Director.

b. High density area rules for building units. A high density area shall be determined at the time the 

well is permitted on a well-by-well basis by calculating the number of occupied building units 

within the seventy-two (72) acre area defined by a one thousand (1000) foot radius from the 

wellhead or production facility. If thirty-six (36) or more actual or platted building units (as defined 

in the 100 Series rules) are within the one thousand (1000) foot radius or eighteen (18) or more 

building units are within any semi-circle of the one thousand (1000) foot radius (i.e., an average 

density of one (1) building unit per two (2) acres), it shall be deemed a high density area. If 

platted building units are used to determine the density, then fifty percent (50%) of said platted 

units shall have building units under construction or constructed.

c. High density area rules for other facilities. If an educational facility, assembly building, hospital, 

nursing home, board and care facility, or jail is located within one thousand (1000) feet of a 

wellhead or production facility, high density area rules shall apply.

d. Designated outside activity area. The Commission, upon application and hearing, shall determine 

the appropriate boundary and setbacks for a designated outside activity area as defined in the 

100 sSeries rules. The minimum setback from the boundary of the designated outside activity 

area shall be three hundred fifty (350) feet.

e. The following rules shall apply in high density and designated outside activity areas:

(1) Provisions for encroaching development. If, by virtue of subsequent future surface 

development, an area becomes a high density area, subsections (2), (3), (7) and (14) 

shall not apply to the operator.

(2) Setbacks for wellheads. At the time of initial drilling of the well, the wellhead location shall 

be not less than three hundred fifty (350) feet from any building unit, educational facility, 

assembly building, hospital, nursing home, board and care facility, or jail.

(3) Setbacks for production equipment. At the time of initial installation or construction, 

production tanks, pits, and/or associated on-site production equipment shall be located 

not less than three hundred fifty (350) feet from any building unit., and, if requested by 

the local governmental designee, Such production tanks, pits, or associated on-site 

production equipment shall be located five hundred (500) feet from an educational facility, 

assembly building, hospital, nursing home, board and care facility, jail or designated 

outside activity area. However, such five hundred (500) foot setback shall be decreased 

to the maximum achievable setback if five hundred (500) feet would extend beyond the 

area on which the operator has a legal right to place or construct such facilities. Should 

the operator object to such five hundred (500) foot setback for any reason, a variance 

hearing shall be conducted at the next regularly scheduled meeting of the Commission, 

subject to the notice requirements of Rule 507.

(4) A. Blowout preventer equipment (“BOPE” ) for high density area drilling operations.

Blowout prevention equipment for drilling operations shall consist of (at a minimum):

i. Rig with Kelly. Double ram with blind ram and pipe ram; annular preventer or 

a rotating head.

ii. Rig without Kelly. Double ram with blind ram and pipe ram.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 116

i. Rig with kelley double ram with blind 

ram and pipe ram; 

annular preventer or a 

rotating head

ii. Rig without kelley double ram with blind 

ram and pipe ram

Mineral Management certification or Director approved training for blowout 

prevention shall be required for at least one (1) person at the wellsite during 

drilling operations.

B. BOPE testing for high density area drilling operations. Upon initial rig-up and at 

least once every thirty (30) days during drilling operations thereafter, pressure 

testing of the casing string and each component of the blowout prevention 

equipment including flange connections shall be performed to seventy percent 

(70%) of working pressure or seventy percent (70%) of the internal yield of 

casing, whichever is less. Pressure testing shall be conducted and the 

documented results shall be retained by the operator for inspection by the 

Director for a period of one (1) year. Activation of the pipe rams for function 

testing shall be conducted on a daily basis when practicable.

C. Pit level indicators. Pit level indicators shall be used.

D. Drill stem tests. Closed chamber drill stem tests shall be allowed in high density 

areas. All other drill stem tests shall require approval by the Director.

(5) A. BOPE for well servicing operations. Adequate blowout prevention equipment shall be 

used on all well servicing operations.

B. Backup stabbing valves shall be required on well servicing operations during 

reverse circulation. Valves shall be pressure tested before each well servicing 

operation using both low- pressure air and high- pressure fluid.

(6) Location requirement exceptions and waivers. Exceptions to the location requirements set 

out in (2) and (3) above shall be granted by the Director if the Director determines that 

Rule 318. has been complied with and that a copy of waivers from each person owning 

an occupied building unit or building permitted for construction within three hundred fifty 

(350) feet of the proposed oil and gas location is submitted as part of the Form 2, and 

that the proposed location complies with all other safety requirements of the rules and 

regulations.

(7) Fencing requirements. At the time of initial installation, if a wellsite falls within a high density 

area, all pumps, pits, wellheads and production facilities shall be adequately fenced to 

restrict access by unauthorized persons. For security purposes, all such facilities and 

equipment used in the operation of a completed well shall be surrounded by a fence six 

(6) feet in height, constructed in conformance with local written standards as long as the 

material is non-combustible and allows for adequate ventilation, and the gate(s) shall be 

locked.

(8) Control of fire hazards. Any material not in use that might constitute a fire hazard shall be 

removed a minimum of twenty-five (25) feet from the wellhead, tanks and separator. Any 

electrical equipment installations inside the bermed area shall comply with API RP 500 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 117

classifications and comply with the current national electrical code as adopted by the 

State of Colorado.

(9) Loadlines. In high density areas, all loadlines shall be bullplugged or capped.

(10) Removal of surface trash. All surface trash, debris, scrap or discarded material connected 

with the operations of the property shall be removed from the premises or disposed of in 

a legal manner.

(11) Guy line anchors. All guy line anchors left buried for future use shall be identified by a 

marker of bright color not less than four (4) feet in height and not greater than one (1) foot 

east of the guy line anchor.

(12) Berm construction. Berms or other secondary containment devices in high density areas 

shall be constructed around crude oil, condensate, and produced water storage tanks 

and shall enclose an area sufficient to contain and provide secondary containment for 

one-hundred fifty percent (150%) of the largest single tank. Berms or other secondary 

containment devices shall be sufficiently impervious to contain any spilled or released 

material. All newly installed or replaced berms in high density areas, in the absence of 

remote impounding, shall be constructed around crude oil and condensate storage tanks 

and shall enclose an area sufficient to contain one hundred fifty percent (150%) of the 

largest single tank. No more than two (2) crude oil and or condensate storage tanks shall 

be located within a single berm. All bBerms and containment devices shall be inspected 

at regular intervals and containment integrity maintained in good condition. No potential 

ignition sources shall be installed inside the secondary containment area unless the 

containment area encloses a fired vessel. Refer to American Petroleum Institute 

Recommended Practices, API RP - D16.

(13) Tank specifications. All newly installed or replaced crude oil and condensate storage tanks 

in high density areas shall be designed, constructed, and maintained in accordance with 

National Fire Protection Association's latest edition (NFPA 30) Code 30 (2008 version). 

The operator shall maintain written records verifying proper design, construction, and 

maintenance, and shall make these records available for inspection by the Director. Only 

the 2008 version of NFPA Code 30 applies to this rule. This rule does not include later 

amendments to, or editions of, the NFPA Code 30. NFPA Code 30 may be examined at 

any state publication depository library. Upon request, the Public Room Administrator at 

the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203, 

will provide information about the publisher and the citation to the material. 

(14) Access roads. If a wellsite falls within a high density area at the time of construction, all 

leasehold roads shall be constructed to accommodate local emergency vehicle access 

requirements, and shall be maintained in a reasonable condition.

(15) Well site cleared. Within ninety (90) days after a well is plugged and abandoned, the well 

site shall be cleared of all non-essential equipment, trash, and debris. For good cause 

shown, an extension of time may be granted by the Director.

(16) Identification of plugged and abandoned wells in high density areas. The operator shall 

identify the location of the wellbore with a permanent monument as specified in Rule 

319.a.(5). The operator shall also inscribe or imbed the well number and date of plugging 

upon the permanent monument.

(17) Development from existing well pads. Where possible, operators shall provide for the 

development of multiple reservoirs by drilling on existing pads or by multiple completions 

or commingling in existing wellbores (see Rule 322). If any operator asserts it is not 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 118

possible to comply with, or requests relief from, this requirement, the matter shall be set 

for hearing by the Commission and relief granted as appropriate.

f. Statewide rig floor safety valve requirements. When drilling or well servicing operations are in 

progress on a well where there is any indication the well will flow hydrocarbons, either through 

prior records or present conditions, there shall be on the rig floor a safety valve with connections 

suitable for use with each size and type of tool joint or coupling being used on the job.

g. Statewide static charge requirements. Rig substructure, derrick, or mast shall be designed and 

operated to prevent accumulation of static charge.

h. Statewide well servicing pressure check requirements. Prior to initiating well servicing operations, 

the well shall be checked for pressure and steps taken to remove pressure or operate safely 

under pressure before commencing operations.

i. Statewide well control equipment and other safety requirements. Well control equipment and other 

safety requirements are:

(1) When there is any indication that a well will flow, either through prior records, present well 

conditions, or the planned well work, blowout prevention equipment shall be installed in 

accordance with Rule 317 or any special orders of the Commission.

(2) Blowout prevention equipment when required by Rule 317 shall be in accordance with API 

RP 53: Recommended Practices for Blowout Prevention Equipment Systems, or 

amendments thereto.

(3) While in service, blowout prevention equipment shall be inspected daily and a preventer 

operating test shall be performed on each round trip, but not more than once every 

twenty-four (24) hour period. Notation of operating tests shall be made on the daily 

report.

(4) All pipe fittings, valves and unions placed on or connected with blowout prevention 

equipment, well casing, casinghead, drill pipe, or tubing shall have a working pressure 

rating suitable for the maximum anticipated surface pressure and shall be in good 

working condition as per generally accepted industry standards.

(5) Blowout prevention equipment shall contain pipe rams that enable closure on the pipe being 

used. The choke line(s) and kill line(s) shall be anchored, tied or otherwise secured to 

prevent whipping resulting from pressure surges.

(6) Pressure testing of the casing string and each component of the blowout prevention 

equipment, if blowout prevention equipment is required, shall be conducted prior to 

drilling out any string of casing except conductor pipe. The minimum test pressure shall 

be five hundred (500) psi, and shall hold for fifteen (15) minutes without pressure loss in 

order for the casing string to be considered serviceable. Upon demand the operator shall 

provide to the Commission the pressure test evidence. Drilling operations shall not 

proceed until blowout prevention equipment is tested and found to be serviceable.

(7) If the blind rams are closed for any purpose except operational testing, the valves on the 

choke lines or relief lines below the blind rams should be opened prior to opening the 

rams to bleed off any pressure.

(8) All rig employees shall have adequate understanding of and be able to operate the blowout 

prevention equipment system. New employees shall be trained in the operation of 

blowout prevention systems as soon as practicable to do so.
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(9) Drilling contractors shall place a sign or marker at the point of intersection of the public road 

and rig access road.

(10) The number of the public road to be used in accessing the rig along with all necessary 

emergency numbers shall be posted in a conspicuous place on the drilling rig.

j. Statewide equipment, weeds, waste, and trash requirements. All locations, including wells and 

surface production facilities, shall be kept free of the following: equipment, vehicles, and supplies 

not necessary for use on that lease; weeds; rubbish, and other waste material. The burning or 

burial of such material on the premises shall be performed in accordance with may be subject to 

other applicable local, state, or federal solid waste disposal regulations and in accordance with 

the 900-Series Ruleslaws. In addition, material may be burned or buried on the premises only 

with the prior written consent of the surface owner.

k. Statewide equipment anchoring requirements. All equipment at drilling and production sites in 

geological hazard and floodplain areas shall be anchored to the extent necessary to resist 

flotation, collapse, lateral movement, or subsidence.

604. PRODUCTION OIL AND GAS FACILITIES.

a. Crude Oil and Condensate Tanks.

(1) Atmospheric tanks used for crude oil storage shall be built in accordance with the following 

standards as applicable:

A. Underwriters Laboratories, Inc., No. UL-142, “Standard for Steel above ground Tanks 

for Flammable and Combustible Liquids”;

B. American Petroleum Institute Standard No. 650, “Welded Steel Tanks for Oil 

Storage”;

C. American Petroleum Institute Standard No. 12B, “Bolted Tanks for Storage of 

Production Liquids”;

D. American Petroleum Institute Standard No. 12D, “Field Welded Tanks for Storage of 

Production Liquids”; or

E. American Petroleum Institute Standard No. 12F, “Shop Welded Tanks for Storage of 

Production Liquids”.

(2) Tanks shall be located at least two (2) diameters or three hundred fifty (350) feet, whichever 

is smaller, from the boundary of the property on which it is built. Where the property line 

is a public way the tanks shall be two thirds (2/3) of the diameter from the nearest side of 

the public way or easement.

A. Tanks less than three thousand (3,000) barrels capacity shall be located at least three 

(3) feet apart.

B. Tanks three thousand (3,000) or more barrels capacity shall be located at least onesixth (1/6) the sum of the diameters apart. When the diameter of one tank is less 

than one-half (1/2) the diameter of the adjacent tank, the tanks shall be located at 

least one-half (1/2) the diameter of the smaller tank apart.
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(3) At the time of installation, tanks shall be a minimum of two hundred (200) feet from any 

building unitresidences, normally occupied buildings, or well defined normally occupied 

outside areas.

(4) Berms or other secondary containment devices shall be constructed around crude oil, 

condensate, and produced water tanks, in the absence of remote impounding to provide 

secondary containment for the largest single tank and sufficient freeboard to contain

precipitation. Berms and secondary containment devices and all containment areas shall 

be sufficiently impervious to contain any spilled or released material. both methods shall 

enclose an area with sufficient volume to contain the entire contents of the largest tank in 

the enclosure. Berms and secondary containment devices shall be inspected at regular 

intervals and maintained in good condition. When a berm is provided around tanks nNo 

potential ignition sources shall be installed inside theat area secondary containment area 

unless the containment area encloses a fired vessel.

(5) Tanks shall be a minimum of seventy-five (75) feet from a fired vessel or heater-treater.

(6) Tanks shall be a minimum of fifty (50) feet from a separator, well test unit, or other non-fired 

equipment.

(7) Tanks shall be a minimum of seventy-five (75) feet from a compressor with a rating of 200 

horsepower, or more.

(8) Tanks shall be a minimum of seventy-five (75) feet from a wellhead.

(9) Gauge hatches on atmospheric tanks used for crude oil storage shall be closed at all times 

when not in use.

(10) Vent lines from individual tanks shall be joined and ultimate discharge shall be directed 

away from the loading racks and fired vessels in accord with API RP 12R-1.

(11) During hot oil treatments on tanks containing thirty-five (35) degree or higher API gravity oil, 

hot oil units shall be located a minimum of one hundred (100) feet from any tank being 

serviced.

(12) Labeling of tanks. All tanks and containers shall be labeled in accordance with Rule 210.d. 

b. Fired Vessel, Heater-Treater.

(1) Fired vessels (FV) including heater-treaters (HT) shall be minimum of fifty (50) feet from 

separators or well test units.

(2) FV-HT shall be a minimum of fifty (50) feet from a lease automatic custody transfer unit 

(LACT).

(3) FV-HT shall be a minimum of forty (40) feet from a pump.

(4) FV-HT shall be a minimum of seventy-five (75) feet from a well.

(5) At the time of installation, fired vessels and heater treaters shall be a minimum of two 

hundred (200) feet from residences, occupied building units, or well defined normally 

occupied outside areas.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 121

(6) Vents on pressure safety devices shall terminate in a manner so as not to endanger the 

public or adjoining facilities. They shall be designed so as to be clear and free of debris 

and water at all times.

(7) All stacks, vents, or other openings shall be equipped with screens or other appropriate 

equipment to prevent entry by wildlife, including migratory birds. 

c. Special Equipment. Under unusual circumstances special equipment may be required to protect 

public safety. The Director shall determine if such equipment should be employed to protect 

public safety and if so, require the operator to employ same. If the operator or the affected party 

does not concur with the action taken, the Director shall bring the matter before the Commission 

at public hearing.

(1) All wells located within one hundred fifty (150) feet of a residence(s), normally occupied 

building units, or well defined normally occupied outside area(s), shall be equipped with 

an automatic control valve that will shut the well in when a sudden change of pressure, 

either a rise or drop, occurs. Automatic control valves shall be designed so they fail safe.

(2) Pressure control valves required in (a) shall be activated by a secondary gas source supply, 

and shall be inspected at least every three (3) months to assure they are in good working 

order and the secondary gas supply has volume and pressure sufficient to activate the 

control valve.

(3) All pumps, pits, and producing facilities shall be adequately fenced to prevent access by 

unauthorized persons when the producing site or equipment is easily accessible to the 

public and poses a physical or health hazard.

(4) Sign(s) shall be posted at the boundary of the producing site where access exists, identifying 

the operator, lease name, location, and listing a phone number, including area code, 

where the operator may be reached at all times unless emergency numbers have been 

furnished to the county commission or it's designee.

d. Mechanical Conditions. All valves, pipes and fittings shall be securely fastened, inspected at regular 

intervals, and maintained in good mechanical condition.

e. Buried or partially buried tanks, vessels, or structures. Buried or partially buried tanks, vessels, or 

structures used for storage of E&P waste shall be properly designed, constructed, and installed, 

and operated in a manner to contain materials safely. Such vessels shall be tested for leaks after 

installation and maintained, repaired, or replaced to prevent spills or releases of E&P waste.

f. Produced water pits, special use and buried or partially buried vessels, or structures. At the time 

of initial construction, pits shall be located not less than two hundred (200) feet from any building 

unit. 

605. RESERVED

606A. FIRE PREVENTION AND PROTECTION

a. Gasoline-fueled engines shall be shut down during fueling operations if the fuel tank is an integral part 

of the engine.

b. Handling, connecting and transfer operations involving liquefied petroleum gas (LPG) shall conform to 

the requirements of the State Oil Inspector.

c. Flammable liquids storage areas within any building or shed shall:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 122

(1) be adequately vented to the outside air;

(2) have two (2) unobstructed exits leading from the building in different directions if the building 

is in excess of five hundred (500) square feet.

(3) be maintained with due regard to fire potential with respect to housekeeping and materials 

storage;

(4) be identified as a hazard and appropriate warning signs posted;

d. Flammable liquids shall not be stored within fifty (50) feet of the wellbore, except for the fuel in the 

tanks of operating equipment or supply for injection pumps. Where terrain and location 

configuration do not permit maintaining this distance, equivalent safety measures should be 

taken.

e. Liquefied petroleum gas (LPG) tanks larger than two hundred fifty (250) gallons and used for heating 

purposes, shall be placed as far as practical from and parallel to the adjacent side of the rig or 

wellbore as terrain and location configuration permit. Installation shall be consistent with 

provisions of NFPA 58, “Standards for the Storage and Handling of Liquid Petroleum Gases”.

f. Smoking shall be prohibited at or in the vicinity of operations which constitute a fire hazard and such 

locations shall be conspicuously posted with a sign, “No Smoking or Open Flame”. Matches and 

all smoking equipment may not be carried into “No Smoking” areas.

g. No source of ignition shall be permitted in an area where smoking has been prohibited unless it is first 

determined to be safe to do so by the supervisor in charge or his designated representative.

h. Open fires, transformers, or other sources of ignition shall be permitted only in designated areas 

located at a safe distance from the wellhead or flammable liquid storage areas.

i. Only approved heaters for Class I Division 2 areas, as designated by API RB 500B, shall be permitted 

on or near the rig floor. The safety features of these heaters shall not be altered.

j. Combustible materials such as oily rags and waste shall be stored in covered metal containers.

k. Material used for cleaning shall have a flash point of not less than one hundred (100° F) degrees 

Fahrenheit. For limited special purposes, a lower flash point cleaner may be used when it is 

specifically required and should be handled with extreme care.

l. Firefighting equipment shall not be tampered with and shall not be removed for other than fire 

protection and firefighting purposes and services. A firefighting water system may be used for 

wash down and other utility purposes so long as its firefighting capability is not compromised. 

After use, water systems must be properly drained or properly protected from freezing.

m. An adequate amount of fire extinguishers and other firefighting equipment shall be suitably located, 

readily accessible, and plainly labeled as to their type and method of operation.

n. Fire protection equipment shall be periodically inspected and maintained in good operating condition 

at all times.

o. Firefighting equipment shall be readily available near all welding operations. When welding, cutting or 

other hot work is performed in locations where other than a minor fire might develop, a person 

shall be designated as a fire watch. The area surrounding the work shall be inspected at least 

one (1) hour after the hot work is completed.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 123

p. Portable fire extinguishers shall be tagged showing the date of last inspection, maintenance or 

recharge. Inspection and maintenance procedures shall comply with the latest edition of the 

National Fire Protection Association's publication NFPA 10.

q. Personnel shall be familiarized with the location of fire control equipment such as drilling fluid guns, 

water hoses and fire extinguishers and trained in the use of such equipment. They shall also be 

familiar with the procedure for requesting emergency assistance as terrain and location 

configuration permit. Installation shall be consistent with provisions of NFPA 58, “Standards for 

the Storage and Handling of Liquefied Petroleum Gases”.

606B. AIR AND GAS DRILLING

a. Drilling compressors (air or gas) shall be located at least one hundred twenty five (125) feet from the 

wellbore and in a direction away from the air or gas discharge line.

b. The air or gas discharge line shall be laid in as nearly as a straight line as possible from the wellbore 

and be a minimum of one hundred fifty (150) feet in length. The line shall be securely anchored.

c. A pilot flame shall be maintained at the end of the air or gas discharge line at all times when air, gas, 

mist drilling, or well testing is in progress.

d. All combustible material shall be kept at least one hundred (100) feet away from the air and gas 

discharge line and burn pit.

e. The air line from the compressors to the standpipe shall be of adequate strength to withstand at least 

the maximum discharge pressure of the compressors used, and shall be checked daily for any 

evidence of damage or weakness.

f. Smoking shall not be allowed within seventy-five (75) feet of the air and gas discharge line and burn 

pit.

g. All operations associated with the drilling, completion or production of a well shall be subject to the 

Colorado Air Quality Control Act, Section25-7-101, C.R.S.

607. HYDROGEN SULFIDE GAS

a. When well servicing operations take place in zones known to contain at or above one hundred (100) 

ppm hydrogen sulfide gas, as measured in the gas stream, the operator shall file a hydrogen 

sulfide drilling operations plan (United States Department of the Interior, Bureau of Land

Management, Onshore Order No. 6, November 23, 1990).

b. When proposing to drill a well in areas where hydrogen sulfide gas in excess of one hundred (100) 

ppm can reasonably be expected to be encountered, the operator shall submit as part of the 

Form 2, Application-for-Permit-to-Drill, a hydrogen sulfide drilling operations plan (United States 

Department of the Interior, Bureau of Land Management, Onshore Order No. 6, November 23, 

1990).

c. Any gas analysis indicating the presence of hydrogen sulfide gas shall be reported to the Commission 

and the local governmental designee.

608. COALBED METHANE WELLS

a. Assessment and monitoring of plugged and abandoned wells within one-quarter (1/4) mile of 

proposed coalbed methane (CBM) well.
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(1) Based upon examination of the Commission and other publicly available records, operators 

shall identify all plugged and abandoned (P&A) wells located within one-quarter (1/4) mile 

of a proposed coalbed methane (CBM) well. The operator shall assess the risk of leaking 

gas or water to the ground surface or into subsurface water resources, taking into 

account plugging and cementing procedures described in any recompletion or P&A report 

filed with the Commission. The operator shall notify the Director of the results of the 

assessment of the plugging and cementing procedures. The Director shall review the 

assessment and take appropriate action to pursue further investigation and remediation if 

warranted and in accordance with Colorado Revised Statute 34-60-124(4)(A). 

(2) Operators shall use reasonable good faith efforts to obtain access to all P&A wells identified 

under Rule 608.a.(1) above to conduct a soil gas survey at all P&A wells located within 

one-quarter (1/4) mile of a proposed CBM well prior to production from the proposed 

CBM well and again one (1) year and thereafter every three (3) years after production 

has commenced. Operators shall submit the results of the soil gas survey to the Director 

within three (3) months of conducting the survey or advise the Director that access to the 

P&A wells could not be obtained. 

b. Water well sampling.

(1) If a conventional gas well or P&A well exists within one-quarter (1/4) mile of a proposed CBM 

well, then the two (2) closest water wells within a one-half (1/2) mile radius of the 

conventional gas well or the P&A well shall be sampled (“Water Quality Testing Wells”). If 

possible, the water wells selected should be on opposite sides of the conventional gas 

well or the P&A well not exceeding a one-half (1/2) mile radius. If water wells on opposite 

sides of the conventional gas well or the P&A well cannot be identified, then the two (2) 

closest wells within a one-half (1/2) mile radius of the conventional gas well or the P&A 

well shall be sampled. If two (2) or more conventional wells or P&A wells are located 

within one-quarter (1/4) mile of the proposed CBM well, then the conventional well or the 

P&A well closest to a proposed CBM well shall be used for selecting water wells for 

sampling. 

If there are no conventional gas wells or P&A wells located within a one-quarter (1/4) mile 

radius of the proposed CBM well, then the selected water wells shall be within onequarter (1/4) mile of the proposed CBM well. In areas where two (2) or more water wells 

exist within one-quarter (1/4) mile of the proposed CBM well, then the two (2) closest 

water wells shall be sampled. If possible, the water wells selected should be on opposite 

sides of the proposed CBM well. If water wells on opposite sides of the proposed CBM 

well cannot be identified, then the two (2) closest wells within one-quarter (1/4) mile 

radius shall be sampled. If two (2) water wells do not exist within a one-quarter (1/4) mile 

radius, then the closest single water well within either a one-quarter (1/4) mile radius or 

within a one-half (1/2) mile radius shall be selected. 

If no water well is located within a one-quarter (1/4) mile radius area as described above 

or if access is denied, then a water well within one-half (1/2) mile of the proposed CBM 

well shall be selected. If no water wells meet the foregoing criteria, then sampling shall 

not be required. If the Commission has already acquired data on a water well within onequarter (1/4) mile of the conventional well or the P&A well, but it is not the closest water 

well, then it shall be given preference in selecting a water well to be tested. 

(2) The “initial baseline testing” described in this section shall include all major cations and 

anions, total dissolved solids (TDS), iron, manganese, selenium, nitrates and nitrites, 

dissolved methane, field pH, sodium adsorption ration (SAR), presence of bacteria (iron 

related, sulfate reducing, slime, and coliform), and specific conductance. Hydrogen 

sulfide shall also be measured using a field test method. Field observations such as odor, 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 125

water color, sediment, bubbles, and effervescence shall also be included. The location of 

the water well shall be surveyed in accordance with Rule 215. 

(3) If free gas or a dissolved methane concentration level greater than two (2) milligrams per liter 

(mg/l) is detected in a water well, gas compositional analysis and stable isotope analysis 

of the methane (carbon and deuterium) shall be performed to determine gas type. If the 

test results indicate biogenic gas, no further isotopic testing shall be done. If the test 

results indicate thermogenic or a mixture of thermogenic and biogenic gas, then the 

operator shall submit to the Director an action plan to determine the source of the gas. If 

the methane concentration increases by more than five (5) mg/l between sampling 

periods, or increases to more than ten (10) mg/l, the operator shall notify the Director and 

the owner of the water well immediately. 

(4) Operators shall make a good faith effort to conduct initial baseline testing of the selected 

water wells prior to the drilling of the proposed CBM well; however, not conducting 

baseline testing because access to water wells cannot be obtained shall not be grounds 

for denial of an Application for Permit-to-Drill, Form 2. Within one (1) year after 

completion of the proposed CBM well, a “post-completion” test shall be performed for the 

same analytical parameters listed above and repeated three (3) and six (6) years 

thereafter or in accordance with the requirements of field rules developed pursuant to 

Rule 608.f. If the methane concentration increases by more than five (5) mg/l between 

sampling periods or increases to more than ten (10) mg/l, the operator shall prepare an 

action plan to determine the source of the gas and notify the Director and the water well 

owner immediately. If no significant changes from the baseline have been identified after 

the third test (i.e. the six-year test), no further testing shall be required. Additional “postcompletion” test(s) may be required if changes in water quality are identified during 

follow-up testing. The Director may require further water well sampling at any time in 

response to complaints from water well owners. 

(5) Copies of all test results described above shall be provided to the Commission and the water 

well owner within three (3) months of collecting the samples. The analytical data and 

surveyed well locations shall also be submitted to the Director in an electronic data 

deliverable format. 

c. Coal outcrop and coal mine monitoring.

(1) If the CBM well is within two (2) miles of the outcrop of the stratigraphic contact between the 

coal-bearing formation and the underlying formation, or within two (2) miles of an active, 

inactive, or abandoned coal mine, the operator shall make a good faith effort to obtain the 

access necessary to survey the outcrop or mine prior to drilling the CBM well to 

determine whether there are gas seeps and springs or water seeps that discharge from 

the coal-bearing formation in the area. 

(2) If a gas seep is identified during the survey, then its location and areal extent shall be 

surveyed in accordance with Rule 215 and the concentration of the soil gas shall be 

determined. If possible, a sample of gas shall be collected from the seep for 

compositional analysis and stable isotope analysis of the methane (carbon and 

deuterium). Thereafter, the operator will inspect the gas seep, survey its areal extent, and 

measure soil gas concentrations annually, if access can be obtained. The operator shall 

submit the results of the outcrop or mine monitoring to the Commission and the 

landowner within three (3) months of its completion of the field work. The analytical data 

shall also be submitted to the Director in an electronic data deliverable format. 

(3) If a gas seep is identified during the survey, the Director shall advise the landowners, local 

government, Colorado Geological Survey (CGS), and the Colorado Division of 

Reclamation, Mining, and Safety (DRMS), as appropriate, of the findings. In collaboration 
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with state, local, and private interests, the CGS, DRMS, and the Commission may elect 

to develop a geologic hazard survey and determine whether the area should be 

recommended to be designated as a geologic hazard in accordance with Colorado 

Revised Statute 34-1-103 and 24-65.1-103. 

(4) If the CBM well is within two (2) miles of the outcrop of the stratigraphic contact between the 

coal-bearing formation and the underlying formation, the operator shall survey the 

outcrop, review publicly available geologic and hydrogeologic data, and interview 

landowners to identify springs or water seeps that discharge from the coal-bearing 

formation. 

If such a water feature is identified, then the operator shall survey its location and areal 

extent in accordance with Rule 215, measure the flow rate, photograph the feature, and 

collect and analyze a water sample in accordance with Rule 608.b.(2). Thereafter, the 

operator will inspect, survey the areal extent of, and measure the flow rate of the spring 

or water seep annually, if access can be obtained. The operator shall submit the results 

of the spring or water seep monitoring to the Commission and the landowner within three 

(3) months of its completion of the field work. The analytical data shall also be submitted 

to the Director in an electronic data deliverable format. 

d. Prior to producing - static bottom-hole pressure survey. Prior to producing the well, the operator 

shall obtain a static bottom-hole pressure test on at least the first well drilled on a government 

quarter (1/4) section. The survey shall be conducted by either a direct static bottom-hole pressure 

measurement or by a static fluid level measurement. The data acquired by the operator and a 

description of the procedures used to gather the data shall be reported on a Bottom Hole 

Pressure, Form 13, and submitted with the Completed Interval Report, Form 5A, filed with the 

Director. After reviewing the quality of the static bottom-hole pressure data and the adequacy of 

the geographic distribution of the data, or at the request of the operator, the Director may vary the 

number of wells subject to the static bottom-hole pressure survey requirement. If an application 

for increased well density or down spacing is filed with the Commission, then additional testing 

may be required. 

e. Bradenhead testing. Upon completion of any well, and on wells presently completed, the operator

shall equip the bradenhead access to the annulus between the production and surface casing, as 

well as any intermediate casing, with approved fittings to allow safe and convenient determination 

of pressure and fluid flow. This rule shall apply to all wells, regardless of function, completed for 

CBM production or below the coal-bearing formation. All wells capable of production, injection, or 

observation shall be tested by the operator for pressure and flow, with results submitted to the 

Director on a bradenhead test report, Form 17, and to other applicable regulatory agencies. 

Bradenhead tests shall be performed on all wells on a biennial basis. Remedial requirements 

shall be determined by the appropriate regulatory agency. The bradenhead testing requirement 

shall not apply if the operator demonstrates to the satisfaction of the Director annular cement 

coverage greater than fifty (50) feet above the base of surface casing and zonal isolation is 

confirmed by the following: a cement bond log or cementing ticket indicating that the height of 

cement coverage is fifty (50) feet above the base of the surface casing; and zonal isolation is 

confirmed by two consecutive bradenhead tests preceded by a minimum shut-in period of seven 

(7) days.

f. Locally specific field orders. The provisions of this Rule 608 may, with the Director’s approval, be 

modified or superseded on a basin, region, or county specific basis by field orders developed by 

the Commission in consultation with affected parties, including operators, county governments, 

and other state or local agencies, taking into account the goals of the 600-Series Rules and 

particular local geologic and operational conditions. In addition, the operator or other affected 

party shall have the right to file an application with the Commission to develop field orders for the 

basin, region, or county that modify the Rule 608 requirements as provided herein, which 

application shall set forth an explanation of good cause for the development of such orders. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 127

700-SERIES FINANCIAL ASSURANCE AND OIL AND GAS CONSERVATION AND 

ENVIRONMENTAL RESPONSE FUND

701. SCOPE

The rules in this series pertain to the provision of financial assurance by operators to ensure the 

performance of certain obligations imposed by the Oil and Gas Conservation Act (the Act), §34-60-106 

(3.5), (11), (12) and (17) C.R.S., as well as the use of the Oil and Gas Conservation and Environmental 

Response Fund (ERF), §34-60-124 C.R.S., as a mechanism to plug and abandon orphan wells, perform 

orphaned site reclamation, and remediation, and to conduct other authorized environmental activities.

702. General. 

Operators are required to provide financial assurance to the Commission to demonstrate that they are 

capable of fulfilling the obligations imposed by the Act, as described in this series. Except as otherwise 

specified herein, a surety bond, in a form and from a company acceptable to the Commission, is an 

approved method of providing financial assurance. Any other method of providing financial assurance 

identified in §34-60-106(B13), C.R.S., shall be submitted to the Commission for approval, and shall be 

equivalent to the protection provided by a surety bond and may require detailed Commission review on 

an ongoing basis, including the use of third party consultants, the reasonable expense for which shall be 

charged to the operator proposing such alternative financial assurance.

a. When the Director has reasonable cause to believe that the Commission may become burdened with 

the costs of fulfilling the statutory obligations described herein because an operator has 

demonstrated a pattern of non-compliance with oil and gas regulations in this or other states, 

because special geologic, environmental, or operational circumstances exist which make the 

plugging and abandonment of particular wells more costly, or due to other special and unique 

circumstances, the Director may petition the Commission for an increase in any individual or 

blanket financial assurance required in this series.

b. The requirements of this series do not apply to situations where financial assurance has been 

provided to federal or iIndian agencies for operations regulated solely by such agencies.

703. Surface owner protection. 

Operators shall provide financial assurance to the Commission, prior to commencing any operations with 

heavy equipment, to protect surface owners who are not parties to a lease, surface use or other relevant 

agreement with the operator from unreasonable crop loss or land damage caused by such operations. 

The determination that crop loss or land damage is unreasonable shall be made by the Commission after 

the affected surface owner has filed an application in accordance with the 500 Series rules. Financial 

assurance for the purpose of surface owner protection shall not be required for operations conducted on 

state lands when a bond has been filed with the State Board of Land Commissioners.

The financial assurance required by this section shall be in the amount of two thousand dollars ($2,000) 

per well for non-irrigated land, or five thousand dollars ($5,000) per well for irrigated land. In lieu of such 

individual amounts, operators may submit statewide, blanket financial assurance in the amount of twenty 

five thousand dollars ($25,000). Relief granted by the Commission upon application by a surface owner 

pursuant to this section may include an order requiring the operator to conduct corrective or remedial 

action, and any monetary award for unreasonable crop loss or land damage that cannot be remediated or 

corrected is not limited to the amount of the operator’s financial assurance hereunder. 

704. Centralized E&P waste management facilities. 

An operator which makes application for an offsite, centralized E&P waste management facility shall, 

upon approval and prior to commencing construction, provide to the Commission financial assurance in 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 128

an amount equal to the estimated cost necessary the amount of fifty thousand dollars ($50,000) to ensure 

the proper reclamation, closure, and abandonment of such facility as set forth in Rule 908.g, or in an 

amount voluntarily agreed to with the Director, or in an amount to be determined by order of the 

Commission. Operators of centralized E&P waste management facilities permitted prior to May 1, 2009 

on federal land and April 1, 2009 for all other land shall, by July 1, 2009, comply with Rule 908.g and this 

Rule 704. This section does not apply to underground injection wells and multi-well pits covered under 

Rules 706. and 707.

705. Seismic operations. 

Any operator submitting a Notice of Intent to Conduct Seismic Operations, Form 20, shall, prior to 

commencing such operations, provide financial assurance to the Commission in the amount of twenty five 

thousand dollars ($25,000) statewide blanket financial assurance to ensure the proper plugging and 

abandonment of any shot holes and any necessary surface reclamation.

706. Soil protection and plugging and abandonment. 

Prior to commencing the drilling of a well, an operator shall provide financial assurance to the 

Commission to ensure the protection of the soil, and the proper plugging and abandonment of the well, 

and the reclamation of the site in accordance with the 300 Series of drilling regulations, the 900 Series of 

E&P waste management, the 1000 Series of reclamation regulations, and the 1100 Series of flowline 

regulations. 

a. The financial assurance required by this section shall be in the amount of five ten thousand dollars 

($510,000) per well for wells less than three thousand (3,000) feet in total measured depth and 

twenty thousand dollars ($20,000) per well for wells greater than or equal to three thousand 

(3,000) feet in total measured depth. 

b. In lieu of such individual per-well amount, an operator may submit statewide blanket financial 

assurance in the amount of thirty sixty thousand dollars ($360,000) for the drilling and operation 

of less than one hundred (100) wells, or one hundred thousand dollars ($100,000) for the drilling 

and operation of one hundred (100) or more wells.

c. All oil and gas wells, excluding domestic gas wells, with financial assurance posted prior to May 1, 

2009 for federal land and April 1, 2009 for all other land, as well as all new domestic gas wells, 

must have financial assurances in compliance with this Rule 706 in place on July 1, 2009. Under 

Rule 502.b.(1), an operator may seek a variance from these financial assurance requirements 

under appropriate circumstances. 

707. Inactive wells

a. To the extent that an operator's inactive well count exceeds such operator's financial assurance 

amount divided by five ten thousand dollars ($510,000) for inactive wells less than three thousand 

(3,000) feet in total measured depth or twenty thousand dollars ($20,000) for inactive wells 

greater than or equal to three thousand (3,000) feet in total measured depth, such additional wells 

shall be considered “excess inactive wells.” . For each excess inactive well, an operator's 

required financial assurance amount under Rule 706. shall be increased by five ten thousand 

dollars ($510,000) for inactive wells less than three thousand (3,000) feet in total measured depth 

or twenty thousand dollars ($20,000) for inactive wells greater than or equal to three thousand 

(3,000) feet in total measured depth. This requirement shall be modified or waived if the 

Commission approves a plan submitted by the operator for reducing such additional financial 

assurance requirement, for returning wells to production in a timely manner, or for plugging and 

abandoning such wells on an acceptable schedule.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 129

In determining whether such plan is acceptable, the Commission shall take into consideration 

such factors as: the number of excess inactive wells; the cost to plug and abandon such wells; 

the proportion of such wells to the total number of wells held by the operator; any business 

reason the operator may have for shutting-in or temporarily abandoning such wells; the extent to 

which such wells may cause or have caused a significant adverse environmental impact; the 

financial condition of the operator,; the capability of the operator to manage such plan in an 

orderly fashion; and the availability of plugging and abandonment services. If an increase in 

financial assurance is ordered pursuant to this subsection, the operator may, at its option and in 

compliance with these 700 Series rules, submit new financial assurance or supplement its 

existing financial assurance.

b. Operators shall identify and list any shut-in or temporarily abandoned wells on their monthly 

production/injection report. In addition, when equipment is removed from a well so as to render it 

temporarily abandoned, operators shall file a Sundry Notice, Form 4, with the Commission within 

thirty (30) days describing such activity.

c. Any person, other than the operator, who causes equipment from a well to be removed so as to render 

it temporarily abandoned shall, prior to conducting such activity, file a notice of intent to remove 

equipment and receive the approval of the Director. The Director may condition such approval on

concurrent plugging and abandonment of the well or on provision of the financial assurance 

required of operators in this series.

708. Public health, safety and welfareGeneral Liability Insurance. 

All operators shall maintain general liability insurance coverage for property damage and bodily injury to 

third parties in the minimum amount of five hundred thousand dollars ($500,000) per occurrence. 

Operators with wells or production facilities located in “high density areas” as defined in Rule 603.b. shall 

maintain such coverage in the minimum amount of one million dollars ($1,000,000) per occurrence. Such 

policies shall include the Commission as a “certificate holder” so that the Commission may receive 

advance notice of cancellation.

709. Financial assurance. 

All financial assurance provided to the Commission pursuant to this Series shall remain in-place until 

such time as the Director determines an operator has complied with the statutory obligations described 

herein, or until such time as the Director determines that a successor-in-interest has filed satisfactory 

replacement financial assurance, at which time the Director shall provide written approval for release of 

such financial assurance. Whenever an operator fails to fulfill any statutory obligation described herein, 

and the Commission undertakes to expend funds to remedy the situation, the Director shall make 

application to the Commission for an order calling or foreclosing the operator's financial assurance.

a. Operators and third party providers of financial assurance shall be served with a copy of such 

application pursuant to Rule 503. and shall be accorded an opportunity to be heard thereon. Any 

third party provider of financial assurance which subsequently fails to comply with a Commission 

order to make such financial assurance available shall be considered an unacceptable provider of 

any new financial assurance to operators in Colorado, until such time as it applies for and 

receives an order of reinstatement. This provision shall be stayed by the filing of a judicial appeal. 

In addition, the Commission may institute suit to recover such monies.

b. If an operator's financial assurance is called or foreclosed by the Commission, the called or foreclosed 

amount shall be deposited in the Oil and Gas Conservation and Environmental Response Fund to 

be expended by the Director for the purposes referenced in Rule 701., and an overhead recovery 

fee of ten percent (10%) of the funds expended by the Director as direct costs shall be charged 

against any excess of the financial assurance over such costs. Any remainder of such financial 

assurance after such cost recovery shall be returned to its provider. In no circumstances will the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 130

liability of a third party provider of financial assurance exceed the face amount of such financial 

assurance.

c. If an operator's financial assurance is called or foreclosed by the Commission, such operator's 

Certificates of Clearance, Form 10, are forthwith suspended and no sales of gas or oil shall be 

allowed, except as may be allowed by the Commission order, until such time as the operator's 

financial assurance has been replaced or restored.

d. The Director shall not approve a new Operator Registration, Form 1, or a new Certificate of Clearance, 

Form 10, when wells are sold or transferred until the successor operator has filed satisfactory 

financial assurance under the 700-Series Rules. 

710. Oil and Gas Conservation and Environmental Response Fund. 

The Commission shall ensure that the two-year average of the unobligated portion of It is the intent of the 

Oil and Gas Conservation Commission that and Environmental Response Fund (ERF) is maintained at a 

level of approximately, but not to exceed, four million dollars ($4,000,000), and that there is an adequate 

balance in the fund to address environmental response needs“emergency reserve” of unobligated funds 

be maintained in the amount of one million dollars ($1,000,000), which may be used in accordance with 

the Act and Rule 701.

711. Natural gas gathering, natural gas processing and underground natural gas storage 

facilities.

Operators of natural gas gathering, natural gas processing, or underground natural gas storage facilities 

shall be required to provide statewide blanket financial assurance to ensure compliance with the 900 

Series rules in the amount of fifty thousand dollars ($50,000), or in an amount voluntarily agreed to with 

the Director, or in an amount to be determined by order of the Commission. Operators of small systems 

gathering or processing less than five (5) MMSCFD may provide individual financial assurance in the 

amount of five thousand dollars ($5,000).

712. Surface facilities and structures appurtenant to Class II Commercial Underground Injection 

Control wells.

Operators of Class II commercial Underground Injection Control (UIC) wells shall be required to provide 

financial assurance to ensure compliance with the 900-Series Rules in the amount of fifty-thousand 

dollars ($50,000) for each facility, or in an amount voluntarily agreed to with the Director, or in an amount 

to be determined by order of the Commission. The financial assurance required by this Rule 712 shall 

apply to the surface facilities and structures appurtenant to the Class II commercial injection well and 

used prior to the disposal of E&P wastes into such well and shall be in place by July 1, 2009. The 

financial assurance requirements for the plugging and abandonment of Class II commercial UIC wells are 

specified in Rule 706. 

800-SERIES AESTHETIC AND NOISE CONTROL REGULATIONS

801. INTRODUCTION

The rules and regulations in this section are promulgated to control aesthetics and noise impacts during 

the drilling, completion and operation of oil and gas wells and production facilities. Any Colorado county, 

home rule or statutory city, town, territorial charter city or city and county may, by application to the 

Commission, seek a determination that the rules and regulations in this section, or any individual rule or 

regulation, shall not apply to oil and gas activities occurring within the boundaries, or any part thereof, of 

any Colorado county, home rule or statutory city, town, territorial charter city or city and county, such 

determination to be based upon a showing by any Colorado county, home rule or statutory city, town, 

territorial charter city or city and county that, because of conditions existing therein, the enforcement of 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 131

these rules and regulations is not necessary within the boundaries of any Colorado county, home rule or 

statutory city, town, territorial charter city or city and county for the protection of public health, safety and 

welfare.

802. NOISE ABATEMENT

a. The goal of this rule is to identify noise sources related to oil and gas operations that impact 

surrounding landowners and to implement cost-effective and technically-feasible mitigation 

measures to bring oil and gas facilities into compliance with the allowable noise levels identified in 

subsection c. Operators should be aware that noise control is most effectively addressed at the 

siting and design phase, especially with respect to centralized compression and other 

downstream “gas facilities” (see definition in the 100 Series of these rules).

b. Oil and gas operations at any well site, production facility, or gas facility, shall comply with the 

following maximum permissible noise levels. Operations involving pipeline or gas facility 

installation or maintenance, the use of a drilling rig, completion rig, workover rig, or stimulation is 

subject to the maximum permissible noise levels for industrial zones. The type of land use of the 

surrounding area shall be determined by the Commission in consultation with the local 

governmental designee taking into consideration any applicable zoning or other local land use 

designation.

c. In the hours between 7:00 a.m. and the next 7:00 p.m. the noise levels permitted below may be 

increased ten (10) db(A) for a period not to exceed fifteen (15) minutes in any one (1) hour 

period. The allowable noise level for periodic, impulsive or shrill noises is reduced by five (5) 

db(A) from the levels shown.

ZONE 7:00 am to next 7:00 pm 7:00 pm to next 7:00 am

Residential/Agricultural/Rural 

Construction commencing 

after January 1, 2007

55 db(A) 50db(A) 50 db(A) 45 db(A)

Commercial 60 db(A) 55 db(A)

Light industrial 70 db(A) 65 db(A)

Industrial 80 db(A) 75 db(A)

In remote locations, where there is no reasonably proximate occupied structure or designated 

outside activity area, the light industrial standard may be applicable.

Pursuant to Commission inspection or upon receiving a complaint from a nearby property owner 

or local governmental designee regarding noise related to oil and gas operations, the 

Commission shall conduct an onsite investigation and take sound measurements as prescribed 

herein.

The following provide guidance for the measurement of sound levels and assignment of points of 

compliance for oil and gas operations:

(1) Sound levels shall be measured at a distance of three hundred and fifty (350) feet from the 

noise source. At the request of the complainant, the sound level shall also be measured 

at a point beyond three hundred fifty (350) feet that the complainant believes is more 

representative of the noise impact. If an oil and gas well site, production facility, or gas 

facility is installed closer than three hundred fifty (350) feet from an existing occupied 

structure, sound levels shall be measured at a point twenty-five (25) feet from the 

structure towards the noise source. Noise levels from oil and gas facilities located on 

surface property owned, leased, or otherwise controlled by the operator shall be 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 132

measured at three hundred and fifty (350) feet or at the property line, whichever is 

greater.

In situations where measurement of noise levels at three hundred and fifty (350) feet is 

impractical or unrepresentative due to topography, the measurement may be taken at a 

lesser distance and extrapolated to a 350-foot equivalent using the following formula:

db(A) DISTANCE 2 = db(A) DISTANCE 1 – 20 x log 10 (distance 2/distance 1)

(2) Sound level meters shall be equipped with wind screens, and readings shall be taken when 

the wind velocity at the time and place of measurement is not more than five (5) miles per 

hour.

(3) Sound level measurements shall be taken four (4) feet above ground level.

(4) Sound levels shall be determined by averaging minute-by-minute measurements made over 

a minimum fifteen (15) minute sample duration if practicable. The sample shall be taken 

under conditions that are representative of the noise experienced by the complainant 

(e.g., at night, morning, evening, or during special weather conditions).

(5) In all sound level measurements, the existing ambient noise level from all other sources in the 

encompassing environment at the time and place of such sound level measurement shall 

be considered to determine the contribution to the sound level by the oil and gas 

operation(s).

d. In situations where the complaint or Commission onsite inspection indicates that low frequency noise 

is a component of the problem, the Commission shall obtain a sound level measurement twentyfive (25) feet from the exterior wall of the residence or occupied structure nearest to the noise 

source, using a noise meter calibrated to the db(C) scale. If this reading exceeds 65 db(C), the 

Commission shall require the operator to obtain a low frequency noise impact analysis by a 

qualified sound expert, including identification of any reasonable control measures available to 

mitigate such low frequency noise impact. Such study shall be provided to the Commission for 

consideration and possible action.

e. Exhaust from all engines, motors, coolers and other mechanized equipment shall be vented in a 

direction away from all occupied building units.

f. All facilities within four hundred (400) feet of occupied building units with engines or motors which are 

not electrically operated shall be equipped with quiet design mufflers or equivalent. All mufflers 

shall be properly installed and maintained in proper working order.

803. LIGHTING

To the extent practicable, site lighting shall be directed downward and internally so as to avoid glare on 

public roads and occupied building units within seven (700) hundred feet.

804. VISUAL IMPACT MITIGATION

Production facilities, regardless of construction date, constructed or substantially repainted after May 30, 

1992 which are observable from any public highway shall be painted with uniform, non-contrasting, nonreflective color tones, (similar to the Munsell Soil Color Coding System), and with colors matched to but 

slightly darker than the surrounding landscape by September 1, 2010.

805. ODORS AND DUST
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 133

a. General. Oil and gas facilities and equipment shall be operated in such a manner that odors and dust 

do not constitute a nuisance or hazard to public welfare.

b. Odors.

(1) Compliance.

A. Oil and gas operations shall be in compliance with the Department of Public Health 

and Environment, Air Quality Control Commission, Regulation No. 2 Odor 

Emission, 5 C.C.R. 1001-4. 

B. No violation of Rule 805.b.(1) shall be cited by the Commission, provided that the 

practices identified in Rule 805.b.(2) are used. 

(2) Production Equipment and Operations.

A. Condensate Tanks. All condensate tanks with a potential to emit volatile organic 

compounds (VOC) of five (5) tons per year (tpy) or greater, located in Garfield, 

Mesa, or Rio Blanco County and within 1/4 mile of a building unit, educational 

facility, assembly building, hospital, nursing home, board and care facility, jail, or 

designated outside activity area shall utilize a control device capable of achieving 

95% control efficiency of VOC and shall hold a valid permit from the Colorado 

Department of Public Health and Environment, Air Pollution Control Division, for 

the tank and control device. Condensate tanks meeting the above criteria and 

existing on May 1, 2009 on federal lands and on April 1, 2009 on all other lands

shall be in compliance with this subsection by October 1, 2009. 

B. Crude Oil and Produced Water Tanks. All crude oil and produced water tanks with a 

potential to emit VOC of five (5) tpy or greater, located in Garfield, Mesa, or Rio 

Blanco County and within 1/4 mile of a building unit, educational facility, 

assembly building, hospital, nursing home, board and care facility, jail, or 

designated outside activity area shall utilize a control device capable of achieving 

95% control efficiency of VOC and shall hold a valid permit from the Colorado 

Department of Public Health and Environment, Air Pollution Control Division, for 

the tank and control device. Crude oil and produced water tanks meeting the 

above criteria and existing on May 1, 2009 on federal lands and on April 1, 2009 

on all other lands shall be in compliance with this subsection by October 1, 2009. 

C. Glycol Dehydrators. All glycol dehydrators with a potential to emit VOC of five (5) tpy 

or greater, located in Garfield, Mesa, or Rio Blanco County and within 1/4 mile of 

a building unit, educational facility, assembly building, hospital, nursing home, 

board and care facility, jail, or designated outside activity area shall utilize a 

control device capable of achieving 90% control efficiency of VOC and shall hold 

a valid permit from the Colorado Department of Public Health and Environment, 

Air Pollution Control Division, for the glycol dehydrator and control device. Glycol 

dehydrators meeting the above criteria and existing on May 1, 2009 on federal 

lands and on April 1, 2009 on all other lands shall be in compliance with this 

subsection by October 1, 2009. 

D. Pits. Pits constructed on or after May 1, 2009 on federal land or on or after April 1, 

2009 on all other land with a potential to emit VOC of five (5) tpy or greater and

located in Garfield, Mesa, or Rio Blanco County shall not be located within 1/4 

mile of a building unit, educational facility, assembly building, hospital, nursing 

home, board and care facility, jail, or designated outside activity area. For the 

purposes of this section, compliance with Rule 902.c shall be considered a 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 134

required practice. Operators may provide site-specific data and analyses to 

COGCC staff establishing that pits potentially subject to this subsection do not 

have a potential to emit VOC of five (5) tpy or greater. 

E. Pneumatic Devices. In instances when new, replaced, or repaired pneumatic 

devices are installed, low or no bleed valves must be used, where technically 

feasible. 

(3) Well completions.

A. Green completion practices are required on oil and gas wells where reservoir 

pressure, formation productivity, and wellbore conditions, based upon offset well 

performance, are likely to enable the well to be capable of naturally flowing 

hydrocarbon gas in flammable or greater concentrations at a stabilized rate in 

excess of five hundred (500) MCFD to the surface against an induced surface 

backpressure of five hundred (500) psig or sales line pressure, whichever is 

greater. Green completion practices are not required for exploratory wells, where 

the wells are not sufficiently proximate to sales lines, or where green completion 

practices are otherwise not technically and economically feasible. 

B. Green completion practices shall include, but not be limited to, the following emission 

reduction measures:

i. The operator shall employ sand traps, surge vessels, separators, and tanks as 

soon as practicable during flowback and cleanout operations to safely 

maximize resource recovery and minimize releases to the environment. 

ii. Well effluent during flowback and cleanout operations prior to encountering 

hydrocarbon gas of salable quality or significant volumes of condensate 

may be directed to open-top tanks or pits (where permitted) such that oil 

or condensate volumes shall not be allowed to accumulate in excess of 

twenty (20) barrels and must be removed within twenty-four (24) hours. 

The gaseous phase of non-flammable effluent may be directed to a flare 

pit or vented from open-top tanks for safety purposes until flammable gas 

is encountered. 

iii. Well effluent containing more than ten (10) barrels per day of condensate or 

within two (2) hours after first encountering hydrocarbon gas of salable 

quality shall be directed to a combination of sand traps, separators, 

surge vessels, and tanks or other equipment as needed to ensure safe 

separation of sand, hydrocarbon liquids, water, and gas and to ensure 

salable products are efficiently recovered for sale or conserved and that 

non-salable products are disposed of in a safe and environmentally 

responsible manner. 

iv. If it is safe and technically feasible, closed-top tanks shall utilize backpressure 

systems that exert a minimum of four (4) ounces of backpressure and a 

maximum that does not exceed the pressure rating of the tank to 

facilitate gathering and combustion of tank vapors. Vent/backpressure 

values, the combustor, lines to the combustor, and knock-outs shall be 

sized and maintained so as to safely accommodate any surges the 

system may encounter. 

v. All salable quality gas shall be directed to the sales line as soon as practicable 

or shut in and conserved. Temporary flaring or venting shall be permitted 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 135

as a safety measure during upset conditions and in accordance with all 

other applicable laws, rules, and regulations. 

C. An operator may request a variance from the Director if it believes that employing 

green completion practices is not feasible because of well or field conditions or 

that following them in a specific instance would endanger the safety of well site 

personnel or the public. 

D. In instances where green completion practices are not technically feasible or are not 

required, operators shall employ Best Management Practices to reduce 

emissions. Such BMPs may include measures or actions, considering safety, to 

minimize the time period during which gases are emitted directly to the 

atmosphere, or monitoring and recording the volume and time period of such 

emissions. Such examples could include the flaring or venting of gas. 

c. Fugitive dust.

Operators shall employ practices for control of fugitive dust caused by their operations. Such practices 

shall include but are not limited to the use of speed restrictions, regular road maintenance, and restriction 

of construction activity during high-wind days. Additional management practices such as road surfacing, 

wind breaks and barriers, or automation of wells to reduce truck traffic may also be required if 

technologically feasible and economically reasonable to minimize fugitive dust emissions. 

900-SERIES E&P WASTE MANAGEMENT

901. INTRODUCTION

a. General. The rules and regulations of this series establish the permitting, construction, operating and 

closure requirements for pits, methods of E&P waste management, procedures for spill/release 

response and reporting, and sampling and analysis for remediation activities. The 900 Series 

rules are applicable only to E&P waste, as defined in § 34-60-103(4.5), C.R.S., or other solid 

waste where the Colorado Department Of Public Health And Environment (“CDPHE” ) has 

allowed remediation and oversight by the Commission.

b. COGCC reporting forms. The reporting required by the rules and regulations of this series shall be 

made on forms provided by the Director. Alternate forms may be used where equivalent 

information is supplied and the format has been approved by the Director.

c. Additional requirements. Whenever the Director has reasonable cause to believe that an operator, in 

the conduct of any oil or gas operation, is performing any act or practice which threatens to cause 

or causes a violation of Table 910-1 and with consideration of water quality standards or 

classifications established by the Water Quality Control Commission (“WQCC” ) for waters of the 

state, the Director may impose additional requirements, including but not limited to, sensitive area 

determination, sampling and analysis, remediation, monitoring, permitting and the establishment 

of points of compliance. Any action taken pursuant to this Rule shall comply with the provisions of 

Rules 324A. through D. and the 500 Series rules.

d. Alternative compliance methods. Operators may propose for prior approval by the Director 

alternative methods for determining the extent of contamination, sampling and analysis, or 

alternative cleanup goals using points of compliance or risk-based approaches.

e. Sensitive area determination. When the operator or Director has data that indicate an impact or 

threat of impact to ground water or surface water, the Director may require the oOperator tos 

shall make a sensitive area determination and that determination shall be subject to the Director’s 

approval. The sensitive area determination shall be made using appropriate geologic and 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 136

hydrogeologic data the Sensitive Area Determination Decision Tree, Figure 901-1 to evaluate the 

potential for impact to ground water and surface water, such as appropriate percolation tests that 

demonstrate that seepage will not reach underlying ground water or waters of the State and 

impact current or future uses of these waters. Operators shall and submit data evaluated and 

analysis used in the determination to the Director. for the following operations or remediation 

activities:

(1) Construction of drilling pits designed for use with fluids containing hydrocarbon 

concentrations exceeding 20,000 parts per million (“ppm” ) total petroleum hydrocarbon 

(“TPH” ) or chloride concentrations at total well depth exceeding 15,000 ppm.

(2) Construction of production and special purpose pits;

(3) Construction of centralized E&P waste management facilities;

(4) Management and remediation of spills/releases exceeding twenty (20) barrels net loss of 

E&P waste; or

(5) When the operator or Director has data that indicate an impact or threat of impact to ground 

water.

f. Sensitive area operations. Operations in sensitive areas shall incorporate adequate measures and 

controls to prevent significant adverse environmental impacts and ensure compliance with the 

allowable concentrations and levels in Table 910-1, with consideration to WQCC standards and 

classifications. Unlined production and special purpose pits in sensitive areas are generally not 

approved.

902. PITS - GENERAL AND SPECIAL RULES

a. Pits used for exploration and production of oil and gas shall be constructed and operated to protect 

public health, safety, and welfare and the environment, including soil, the waters of the state, and 

wildlife, from significant adverse environmental, public health, or welfare impacts from E&P 

waste, except as permitted by applicable laws and regulations.

b. Topsoil and subsoil removed in the construction of the pit shall be segregated and stockpiled in a 

manner described in Rule 1002. and used for reclamation of the site.

cb. Pits shall be constructed, monitored, and operated to provide for a minimum of two (2) feet of 

freeboard at all times between the top of the pit wall at its point of lowest elevation and the fluid 

level of the pit. A method of monitoring and maintaining freeboard shall be employed. Any 

unauthorized release of fluids from a pit shall be subject to the reporting requirements of Rule 

906. 

dc. Any accumulation of oil in a pit shall be removed within twenty-four (24) hours of discovery. Operators 

shall use skimming, steam cleaning of exposed liners, or other safe and legal methods as 

necessary to maintain pits in clean condition and to control hydrocarbon odors. Only de minimis 

amounts of hydrocarbons may be present unless the pit is specifically permitted for oil or 

condensate recovery or disposal use. A Form 15 pit permit may be revoked by the Director and 

the Director may require that the pit be closed if an operator repeatedly allows more than de 

minimis amounts of condensate to accumulate in a pit. This requirement is not applicable to 

properly permitted and properly fenced, lined, and or netted skim pits that are designed, 

constructed, and operated to prevent impacts to wildlife, including migratory birds.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 137

ed. Where necessary to protect public health, safety and welfare or to prevent significant adverse 

environmental impacts resulting from access to a pit by wildlife, migratory birds, domestic 

animalis, or members of the general public, operators shall install appropriate netting or fencing.

fe. Multi-well pits. Production and special purpose pPits used for storage, recycling, reuse, treatment, or 

disposal of E&P waste or fresh water, as applicable, generated from more than one well may be 

permitted in accordance with Rule 903. to service multiple wellsas a multi-well pit, subject to 

Director approval.

gf. Unlined drilling pits shall not be constructed on fill material.

hg. Except as allowed under Rule 904.a, unlined pits shall not be constructed in areas where pathways 

for communication with ground water or surface water are likely to exist. 

h. Produced water shall be treated in accordance with Rule 907. before being placed in a production pit.

i. Operators shall utilize bleach or other safe biocide treatments to control bacterial growth and related 

odors as needed. 

903. PIT PERMITTING/REPORTING REQUIREMENTS

a. An Earthen Pit Report/Permit, Form 15, shall be submitted to the Director for prior approval for the 

following pitsDrilling pits, production pits, and special purpose pits shall be permitted or reported 

as follows:

(1) All production pits.

(2) Special purpose pits except those reported under Rule 903.b.(1) or Rule 903.b.(2). 

Pit Construction Report/Permit, Form 15, shall be submitted for prior Director approval for the 

following:

(3)A. Drilling pits designed for use with fluids containing hydrocarbon concentrations exceeding 

210,000 ppm TPH or chloride concentrations at total well depth exceeding 15,000 ppm in 

sensitive areas or 50,000 ppm outside sensitive areas.

B. Production pits and unlined special purpose pits in sensitive areas.

C. Unlined production pits and special purpose pits outside sensitive areas, excluding 

those pits permitted in accordance with Rule 903.a.(2).B.

(4) Multi-well pits containing produced water, drilling fluids, or completion fluids that will be 

recycled or reused, except those pits where drilling fluids are moved from one (1) oil and 

gas location to another such location for reuse there. 

(2)b. An Earthen Pit Construction Report/Permit, Form 15, shall be submitted within thirty (30) calendar 

days after construction for the following:

A. Lined production pits outside sensitive areas.

B. Unlined production pits outside sensitive areas receiving produced water at an 

average daily rate of five (5) or less barrels per day calculated on a monthly basis 

for each month of operation.

C.(1) Lined sSpecial purpose pits used in the initial phase of emergency response.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 138

D.(2) Flare pits where there is no risk of condensate accumulation.

(3)c. An Earthen Pit Construction Report/Permit, Form 15, shall not be required for drilling pits using 

water-based bentonitic drilling fluids with concentrations of TPH and chloride below those 

referenced in Rule 903.a.(31).A.

bd. The An Earthen Pit Construction Report/Permit, Form 15, shall be completed in accordance with the 

instructions in Appendix I. Failure to complete the form in full may result in delay of approval or 

return of form.

ce. The Director shall endeavor to review any properly completed Earthen Pit Construction 

Report/Permit, Form 15, within thirty (30) calendar days after receipt. In order to allow adequate 

time for pit permit review and approval, operators should shall submit required an Earthen Pit 

Report/Permit, Form 15, pit construction permit requests for approval at the same time as the with 

an Application for Permit to Drill, Form 2, is submitted. The Director may condition permit 

approval upon compliance with additional terms, provisions, or requirements necessary to protect 

the waters of the state, public health, or the environment.

904. PIT LINING REQUIREMENTS AND SPECIFICATIONS

a. Pit lining requirements. The following pits shall be lined if they are constructed on or after May 1, 

2009 on federal land, or on or after April 1, 2009 on other land or if they were required to be lined 

under the rules in effect at the time of their construction:

(1) Drilling pits designed for use with fluids containing hydrocarbon concentrations exceeding 

210,000 ppm TPH or chloride concentrations at total well depth exceeding 15,000 ppm in 

sensitive areas or 50,000 ppm outside sensitive areas.

(2) Production pits in sensitive areas, other than skim pits, unless the operator demonstrates to 

the Director’s satisfaction that the quality of the produced water is equivalent to or better 

than that of the underlying groundwater or the operator can clearly demonstrate by 

substantial evidence, such as by appropriate percolation tests, that seepage will not 

reach the underlying aquifer or waters of the state at contamination levels in excess of 

applicable standards. Subject to Rule 901.c, this requirement shall not apply in 

Washington, Yuma, Logan, Morgan, Huerfano, or Las Animas Counties until May 1, 2011 

on federal land or until April 1, 2011 on other land.

(3) Special purpose pits, except emergency pits constructed during initial emergency response to 

spills/releases, or flare pits where there is no risk of condensate accumulation.

(4) Skim pits.

(5) Multi-well pits used to contain produced water, drilling fluids, or completion fluids that will be 

recycled or reused, except those pits where drilling fluids are moved from one oil and gas 

location to another such location for reuse there. 

(6) Pits at centralized E&P waste management facilities and UIC facilities. 

b. The following specifications shall apply to all pits that are required to be lined:

(1) Materials used in lining pits shall be of a synthetic material that is impervious, has high 

puncture and tear strength, has adequate elongation, and is resistant to deterioration by 

ultraviolet light, weathering, resistant and resistant to deterioration when in contact with 

hydrocarbons, aqueous acids, alkali, fungi or other substances in the produced water.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 139

(2) All pit lining systems shall be designed, constructed, installed, and maintained in accordance 

with the manufacturers’ specifications and good engineering practices. Soil liners shall 

have a minimum thickness of six (6) inches after compaction, shall cover the entire 

bottom and interior sides of the pit, and shall be constructed so that the hydraulic 

conductivity of the liner shall not exceed 1.0 X 10 -6 cm/sec. Bentonite liners shall be 

constructed to provide equivalent protection. Operators shall perform post-construction 

tests either in a laboratory or in the field. All test results shall be filed with the Director.

(3) Field seams must be installed and tested in accordance with manufacturer specifications and 

good engineering practices. Testing results must be maintained by the operator and 

provided to the Director upon request. 

(4) Pit sidewall slopes shall be consistent with the manufacturer’s specifications for the synthetic 

liner used. 

c. The following specifications shall also apply to pits that are required to be lined, except those at 

centralized E&P waste management facilities, unless an oil and gas operator demonstrates to the 

satisfaction of the Director that a liner system offering equivalent protection to public health, 

safety, and welfare, including the environment and wildlife resources, will be used: 

(1) Synthetic or fabricated lLiners shall have a minimum thickness of twelve (12) twenty-four (24) 

mils. and shall be resistant to deterioration by ultraviolet light, weathering, chemicals, 

punctures and tearing, and designed for the life of the well. The foundation for the liner 

shall be constructed to prevent punctures from soils or other materials beneath the liner.

The synthetic or fabricated liner shall cover the bottom and interior sides of the pit with 

the edges secured with at least a twelve (12) inch deep anchor trench around the pit 

perimeter. The anchor trench shall be designed to secure, and prevent slippage or 

destruction of, the liner materials. 

(2) The foundation for the liner shall be constructed with soil having a minimum thickness of 

twelve (12) inches after compaction covering the entire bottom and interior sides of the 

pit, and shall be constructed so that the hydraulic conductivity shall not exceed 1.0 x 10-7

cm/sec after testing and compaction. Compaction and permeability test results measured 

in the laboratory and field must be maintained by the operator and provided to the 

Director upon request. 

(3) As an alternative to the soil foundation described in Rule 904.c.(2), the foundation may be 

constructed with bedding material that exceeds a hydraulic conductivity of 1.0 x 10-7

cm/sec, if a double synthetic liner system is used; however, the bottom and sides of the 

pit shall be padded with soil or synthetic matting type material and shall be free of sharp 

rocks or other material that are capable of puncturing the liner. Each synthetic liner shall 

have a minimum thickness of twenty-four (24) mils. 

d. The following specifications shall also apply to pits used at centralized E&P waste management 

facilities, unless an oil and gas operator demonstrates to the satisfaction of the Director that a 

liner system offering equivalent protection to public health, safety, and welfare, including the 

environment and wildlife resources, will be used: 

(1) Liners shall have a minimum thickness of sixty (60) mils. The synthetic or fabricated liner 

shall cover the bottom and interior sides of the pit with the edges secured with at least a 

twelve (12) inch deep anchor trench around the pit perimeter. The anchor trench shall be 

designed to secure, and prevent slippage or destruction of, the liner materials. 

(2) The foundation for the liner shall be constructed with soil having a minimum thickness of 

twenty-four (24) inches after compaction covering the entire bottom and interior sides of 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 140

the pit, and shall be constructed so that the hydraulic conductivity shall not exceed 1.0 x 

10-7cm/sec after testing and compaction. Compaction and permeability test results 

measured in the laboratory and field must be maintained by the operator and provided to 

the Director upon request. 

(3) As an alternative to the soil foundation described in Rule 904.d.(2), a secondary liner 

consisting of a geosynthetic clay liner, which is a manufactured hydraulic barrier typically 

consisting of bentonite clay or other very low permeability material, supported by 

geotextiles or geomembranes, which are held together by needling, stitching, or chemical 

adhesives, may be used. 

(4)e. In Sensitive Areas, the Director may require a leak detection system for the pit or other equivalent 

protective measures, including but not limited to, increased record-keeping requirements, 

monitoring systems, and underlying gravel fill sumps and lateral systems. In making such 

determination, the Director shall consider the surface and subsurface geology, the use and 

quality of potentially-affected ground water, the quality of the produced water, and the hydraulic 

conductivity of the surrounding soils, the depth to ground water, the distance to surface water and 

water wells, and the type of liner.

905. CLOSURE OF PITS, AND BURIED OR PARTIALLY BURIED PRODUCED WATER VESSELS.

a. Drilling pits shall be closed in accordance with the 1000-Series Rules. 

b. Pits not used exclusively for drilling operations, buried or partially buried produced water vessels, and 

Unlined production and special purpose pits, except emergency pits constructed during initial 

response to spills/releases, shall be closed in accordance with an approved Site Investigation and 

Remediation Workplan, Form 27. The workplan shall be submitted for prior Director approval and 

shall include a description of the proposed investigation and remediation activities in accordance 

with Rule 909. Emergency pits shall be closed and remediated as soon as the initial phase of 

emergency response operations are complete or process upset conditions are controlled.

b. Lined pits and buried or partially buried produced water vessels:

(1) Operators shall ensure that soils and ground water meet the allowable concentration levels of 

Table 910-1.

(2) Pit evacuation. Prior to backfilling and site reclamation, E&P waste shall be treated or 

disposed in accordance with Rule 907.

(3) Liners shall be disposed as follows:

A. Synthetic liner disposal. On irrigated crop land, liner material shall be removed and 

disposed in accordance with applicable legal requirements for solid waste 

rulesdisposal. On non-irrigated crop land and on non-crop land, liner material 

may be left in place with surface owner approval.

B. Constructed soil liners. Constructed soil liner material may be removed for 

treatment or disposal, or, where left in place, the material shall be ripped and 

mixed with native soils in a manner to alleviate compaction and prevent an 

impermeable barrier to infiltration and ground water flow and shall meet soil 

standards listed in Table 910-1.

(4) Soil beneath the low point of the pit must be sampled to verify no leakage of the managed 

fluids. Soil left in place shall meet the standards listed in Table 910-1. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 141

c. Discovery of a spill/release during closure. When a spill/release is discovered during closure 

operations, operators shall report the spill/release on the Spill/Release Report, Form 19, in 

accordance with Rule 906. Leaking pits and buried or partially buried produced water vessels 

shall be closed and remediated in accordance with Rules 909. and 910.

d. Emergency pits. Emergency pits constructed during initial response to contain and mitigate 

spills/releases shall not be subject to lining requirements. These pits shall be closed and 

remediated in accordance with Rule 906.

ed. Unlined drilling pits. Unlined drilling pits shall be closed and reclaimed in accordance with the 1000 

Series rules and operators shall ensure that soils and ground water meet the concentration levels 

in Table 910-1.

906. SPILLS AND RELEASES

a. General. Spills/releases of E&P waste, including produced fluids, shall be controlled and contained 

immediately upon discovery to protect the environment, public health, safety, and welfare, and 

wildlife. Impacts resulting from spills/releases shall be investigated and cleaned up as soon as 

practicable. The Director may require additional activities to prevent or mitigate threatened or 

actual significant adverse environmental impacts on any air, water, soil or biological resource, or 

to the extent necessary to ensure compliance with the allowable concentrations and levels in 

Table 910-1, with consideration to WQCC ground water standards and classifications.

b. Reportable spills and reporting requirements for spills/releasesing.

(1) Spills/releases of E&P waste or produced fluid exceeding five (5) barrels, including those 

contained within lined or unlined berms, shall be reported on COGCC Spill/Release 

Report, Form, 19. Such report shall include information relating to initial mitigation, site 

investigation and remediation, and shall be submitted to the Director within ten (10) days 

of discovery of the spill/release.

(2) In addition, sSpills/releases which exceed twenty (20) barrels of an E&P waste shall be 

reported on COGCC Spill/Release Report, Form 19, and shall also be verbally reported 

to the Director as soon as practicable, but not more than within twenty-four (24) hours of 

after discovery.

(3) In addition, sSpills/releases of any size which impact or threaten to impact any waters of the 

state, residence or occupied structure, livestock, or public byway, shall be reported on 

COGCC Spill/Release Report, Form 19, and shall also be verbally reported to the 

Director as soon as practicable, but not more than twenty-four (24) hours, after discovery.

(4) Spills/releases of any size which impact or threaten to impact any surface water supply area 

shall be reported to the Director and to the Environmental Release/Incident Report 

Hotline (1-877-518-5608). Spills and releases that impact or threaten a surface water 

intake shall be verbally reported to the emergency contact for that facility immediately 

after discovery. 

(5) For all reportable spills, operators shall submit a Spill/Release Report, Form 19, within ten 

(10) days after discovery. An 8 1/2 x 11 inch topographic map showing the governmental 

section and location of the spill shall be included. Such report shall also include 

information relating to initial mitigation, site investigation, and remediation. The Director 

may require additional information. 

(6) Chemical spills and releases shall be reported in accordance with applicable state and 

federal laws, including the Emergency Planning and Community Right-to-Know Act, the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 142

Comprehensive Environmental Response, Compensation, and Liability Act, the Oil 

Pollution Act, and the Clean Water Act, as applicable. 

c. Surface owner notification and consultation. The operator shall notify the affected surface owner or 

the surface owner’s appointed tenant of reportable spills as soon as practicable, but not more 

than twenty-four (24) hours, after discovery. The operator also shall make good faith efforts to 

notify and consult with the affected surface owner, or the surface owner’s appointed tenant, prior 

to commencing operations to remediate E&P waste from a spill/release in an area not being 

utilized for oil and gas operations.

d. Remediation of spills/releases.

(1) Remediation workplan. When threatened or actual significant adverse environmental impacts on 

any air, water, soil or other environmental biological resource from a spill/release exists or when 

necessary to ensure compliance with the allowable concentrations and levels in Table 910-1, with 

consideration to WQCC ground water standards and classifications, the Director may require 

operators to submit a Site Investigation and Remediation Workplan, Form 27. Such 

spills/releases shall be remediated in accordance with Rules 909. and 910.

(2) Remediation requirements. Spills/releases shall be remediated to meet the allowable 

concentrations in Table 910-1. Spills/releases exceeding twenty (20) barrels net loss of 

E&P waste shall be remediated in accordance with Rules 909. and 910.

e. Spill/release prevention.

(1) Secondary containment. Secondary containment shall be constructed or installed around all 

tanks containing crude oil, condensate, or produced water with greater than 10,0003,500

milligrams per liter (mg/l) total dissolved solids (TDS) and shall be sufficient to contain the 

contents of the largest single tank and sufficient freeboard to contain precipitation. 

Secondary containment structures shall be sufficiently impervious to contain discharged 

material. Operators are also subject to crude oil tank and containment requirements 

under Rules 603. and 604. This requirement shall not apply to water tanks with a capacity 

of one hundred (100) fifty (50) barrels or less.

(2) Spill/release evaluation. Operators shall determine the cause of a spill/release, and, to the 

extent practicable, shall implement measures to prevent spills/releases due to similar 

causes in the future. For reportable spills, operators shall submit this information to the 

Director on the Spill/Release Report, Form 19, within ten (10) days after discovery of the 

spill/release.

907. MANAGEMENT OF E&P WASTE

a. General requirements.

(1) Operator obligations. Operators shall ensure that E&P waste is properly stored, handled, 

transported, treated, recycled, or disposed to prevent threatened or actual significant 

adverse environmental impacts to air, water, soil or biological resources or to the extent 

necessary to ensure compliance with the allowable concentrations and levels in Table 

910-1, with consideration to WQCC ground water standards and classifications.

(2) E&P waste management activities shall be conducted, and facilities constructed and 

operated, to protect the waters of the state from significant adverse environmental 

impacts from E&P waste, except as permitted by applicable laws and regulations.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 143

(3) Reuse and recycling. To encourage and promote waste minimization, operators may 

propose plans for managing E&P waste through beneficial use, reuse, and recycling by 

submitting a written management plan to the Director for approval on a Sundry Notice, 

Form 4, if applicable. Such plans shall describe, at a minimum, the type(s) of waste, the 

proposed use of the waste, method of waste treatment, product quality assurance, and 

shall include a copy of any certification or authorization that may be required by other 

laws and regulations. The Director may require additional information. 

b. Waste transportation.

(1) E&P waste, when transported off-site within Colorado for treatment or disposal, shall be 

transported to facilities authorized by the Director or waste disposal facilities approved to 

receive E&P waste by the Colorado Department of Public Health and Environment. When 

transported to facilities outside of Colorado for treatment or disposal, E&P waste shall be 

transported to facilities authorized and permitted by the appropriate regulatory agency in 

the receiving state. 

(2) Waste generator requirements. Generators of E&P waste shall maintain, for not less than 

three (3) five (5) years, copies of each invoice, bill, or ticket and such other records as 

necessary to document the following requirements A through Finformation from a 

transporter or disposal site, describing the disposal of E&P waste from each location:

A. The date of the transport;

B. The identity of the waste generator;

C. The identity of the waste transporter;

D. The location of the waste pickup site;

E. The type and volume of waste; and

F. The name and location of the treatment or disposal site.

Such records shall be signed by the transporter, made available for inspection by the 

Director during normal business hours, and copies -thereof shall be furnished to the 

Director upon request.

c. Produced water.

(1) Treatment of produced water. Produced water shall be treated prior to placement in a 

production pit to prevent crude oil and condensate from entering the pit.

(2) Produced water disposal. Produced water may be disposed as follows:

A. Injection into a Class II well, permitted in accordance with Rule 325.;

B. Evaporation/percolation in a properly permitted lined or unlined pit;

C. Disposal at permitted commercial facilities; or

D. Disposal by roadspreading on lease roads outside sensitive areas for produced 

waters with less than 5,000 3,500 mg/l TDS when authorized by the surface 

owner. Roadspreading of produced waters shall not impact waters of the state, 

shall not result in pooling or runoff, of produced waters and the adjacent soils 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 144

shall meet the allowable concentration levels in Table 910-1. Flowback fluids 

shall not be used for dust suppression. 

E. Discharging into state waters, in accordance with the Water Quality Control Act and 

the rules and regulations promulgated thereunder. Produced water discharged 

pursuant to this subsection (2)E. may be put to beneficial use in accordance with 

applicable state statutes and regulations governing the use and administration of 

water.

i. Operators shall provide the Colorado discharge permit number, latitude and 

longitude coordinates, in accordance with Rule 215.f, of the discharge 

outfall, and sources of produced water on a Source of Produced Water 

for Disposal, Form 26, and shall include a U.S.G.S. topographic map 

showing the location of the discharge outfall. 

ii. Produced water discharged pursuant to this subsection (2).E. may be put to 

beneficial use in accordance with applicable state statutes and 

regulations governing the use and administration of water. 

F. Evaporation in a properly lined pit at a centralized E&P waste management facility 

permitted in accordance with Rule 908. 

(3) Produced water reuse and recycling. Produced water may be reused for enhanced 

recovery, drilling, and other approved uses in a manner consistent with existing water 

rights and in consideration of water quality standards and classifications established by 

the WQCC for waters of the state, or any point of compliance established by the Director 

pursuant to Rule 324D.

(4) Mitigation. Water produced during operation of an oil or gas well may be used to provide an 

alternative domestic water supply to surface owners within the oil or gas field, in 

accordance with all applicable laws, including, but not limited to, obtaining the necessary 

approvals from the WQCD for constructing a new “waterworks,” as defined by Section 

25-1-107(1)(X)(II)(A), C.R.S. Any produced water not so used shall be disposed of in 

accordance with subsection (2) or (3). Provision of Providing produced water for domestic 

use within the meaning of this subsection (4) shall not constitute an admission by the 

operator that the well is dewatering or impacting any existing water well. The water 

produced shall be to the benefit of the surface owner within the oil and gas field and may 

not be sold for profit or traded. 

d. Drilling fluids.

(1) Drilling pit fluid rRecycling and reuse. Drilling pit contents may be recycled to another 

drilling pit for reuse consistent with Rule 903.

(2) Drilling fluids tTreatment and disposal. Drilling fluids may be treated or disposed as 

follows:

A. Injection into a Class II well permitted in accordance with Rule 325;

B. Disposal at a commercial solid waste disposal facility; or

C. Land treatment or land application at a centralized E&P waste management facility 

permitted in accordance with Rule 908.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 145

(3) Additional authorized disposal of water-based bentonitic drilling fluids. Water-based 

bentonitic drilling fluids may be disposed as follows:

A. Drying and burial in drilling pits on non-crop land. The resulting concentrations shall 

not exceed the concentration levels in Table 910-1, below; or

B. Land application as follows:

i. Applicability. Acceptable methods of land application include, but are not 

limited to, production facility construction and maintenance, and lease 

and farm road maintenance, or lining of stock ponds and irrigation 

ditches.

ii. Land application requirements. The average thickness of water-based 

bentonitic drilling fluid waste applied shall be no more than three (3) 

inches prior to incorporation. The waste shall be applied to prevent 

ponding or erosion and shall be incorporated as a beneficial amendment 

into the native soils within ten (10) days of applicationas soon as 

practicable. The resulting concentrations shall not exceed those in Table 

910-1.

iii. Surface owner approval. Operators shall obtain written authorization from 

the surface owner prior to land application of water-based bentonitic 

drilling fluids.

iv. Operator obligations. Operators shall maintain a record of the source, the 

volume, and the location where the land application of the water-based 

bentonitic drilling fluid occurred. Upon the Director’s written request, this 

information shall be provided within five (5) business days, in a format 

readily reviewable by the Director. Operators with control and authority 

over the wells from which the water-based bentonitic drilling fluid wastes 

are obtained retain responsibility for the land application operation, and 

shall diligently cooperate with the Director in responding to complaints 

regarding land application of water-based bentonitic drilling fluids.

v. Approval. Prior Director approval is not required for reuse of water-based 

bentonitic drilling fluids for land application as a soil amendment or lining 

material.

e. Oily waste. Oily waste includes those materials containing crude oil, condensate or other 

hydrocarbon-containing E&P waste, such as soil, frac sand, drilling fluids, and pit sludge that 

contain hydrocarbonsworkover fluids, pit sludge, tank bottoms, pipeline pigging wastes, and 

natural gas gathering, processing and storage wastes.

(1) Oily waste may be treated or disposed as follows:

A. Disposal at a commercial solid waste disposal facility;

B. Land treatment onsite or with prior written surface owner approval, offsite land 

treatment; or

C. Land treatment at a centralized E&P waste management facility permitted in 

accordance with Rule 908.

(2) Land treatment requirements:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 146

A. Free oil shall be removed from the oily waste prior to land treatment.

B. Oily waste shall be spread evenly to prevent pooling, ponding, or runoff.

C. Contamination of stormwater runoff, ground water, or surface water shall be 

prevented.

D. Biodegradation shall be enhanced by disking, tilling, aerating, or addition of nutrients, 

microbes, water or other amendments, as appropriate.

E. Land-treated oily waste incorporated in place or beneficially reused shall not exceed 

the allowable concentrations in Table 910-1.

F. When a threatened or significant adverse environmental impact from onsite land 

treatment exists, operators shall the Director may require operators to submit a 

Site Investigation Aand Remediation Workplan, Form 27, for approval by the 

Director. Treatment shall thereafter be completed in accordance with the 

workplan and Rules 909. and 910.

G. When land treatment occurs in an area not being utilized for oil and gas operations, 

operators shall obtain prior written surface owner approval.

f. Other E&P Waste. Other E&P waste such as workover fluids, tank bottoms, pigging wastes from 

gathering and flow lines, and natural gas gathering, processing, and storage wastes may be 

treated or disposed of as follows: 

(1) Disposal at a commercial solid waste disposal facility; 

(2) Treatment at a centralized E&P waste management facility permitted in accordance with Rule 

908; 

(3) Injection into a Class II injection well permitted in accordance with Rule 325; or

(4) An alternative method proposed in a waste management plan in accordance with rule 

907.a.(3) and approved by the Director. 

907A. MANAGEMENT OF NON-E&P WASTE

a. Certain wastes generated by oil and gas-related activities are non-E&P wastes and are exempt from 

regulation as solid or hazardous wastes. These wastes need to be properly identified and 

disposed of in accordance with state and federal regulations. 

b. Certain wastes generated by oil and gas-related activities can either be E&P wastes or non-E&P 

wastes depending on the circumstances of their generation. 

c. The hazardous waste regulations require that a hazardous waste determination be made for any nonE&P solid waste. Hazardous wastes require storage, treatment, and disposal practices in 

accordance with 6 C.C.R. 1007-3. All non-hazardous/non-E&P wastes are considered solid waste 

which require storage, treatment, and disposal in accordance with 6 C.C.R. 1007-2. 

908. CENTRALIZED E&P WASTE MANAGEMENT FACILITIES

a. Applicability. Operators may establish non-commercial, centralized E&P waste management facilities 

for the treatment, disposal, recycling or beneficial reuse of E&P waste. This rule applies only to 

non-commercial facilities, which means the operator does not represent itself as providing E&P 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 147

waste management services to third parties, except as part of a unitized area or joint operating 

agreement or in response to an emergency. Centralized facilities may include components such 

as land treatment or land application sites, pits, and recycling equipment.

b. Permit requirements. Before any person shall commence construction of a centralized E&P waste 

management facility, such person shall file with the Director an application on Form 28 and pay a 

filing and service fee established by the Commission (see Appendix III), and obtain the Director’s 

approval. An application for permit including the following information shall be submitted to the 

Director for prior approval along with a filing and service fee established by the Commission 

(Appendix III)The application shall contain the following:

(1) The name, address, phone and fax number of the operator, and a designated contact person.

(2) The name, address, and phone number of the surface owner of the site, if not the operator, 

and the written authorization of such surface owner.

(3) The legal description of the site.

(4) A general topographic, geologic, and hydrologic description of the site, including immediately 

adjacent land uses, a topographic map of a scale no less than 1:24,000 showing the 

location, and the average annual precipitation and evaporation rates at the site.

(5) Centralized facility siting requirements.

A. A site plan showing drainage patterns and any diversion or containment structures, 

and facilities such as roads, fencing, tanks, pits, buildings, and other construction 

details.

B. Scaled drawings of entire sections containing the proposed facility. The field 

measured distances from the nearer north or south and nearer east or west 

section lines shall be measured at ninety (90) degrees from said section lines to 

facility boundaries and referenced on the drawing. A survey shall be provided 

including a complete description of established monuments or collateral evidence 

found and all aliquot corners.

C. The facility shall be designed to control public access, prevent unauthorized vehicular 

traffic, provide for site security both during and after operating hours, and prevent 

illegal dumping of wastes. Appropriate measures shall also be implemented to 

limit prevent access to the centralized facility by wildlife, or domestic animals, 

and members of the general public shall be implemented.

D. Centralized facilities shall have a fire lane of at least ten (10) feet in width around the 

active treatment areas and within the perimeter fence. In addition, a buffer zone 

of at least ten (10) feet shall be maintained within the perimeter fire lane.

E. Surface water diversion structures, including, but not limited to, berms and ditches, 

shall be constructed to accommodate a one hundred (100) year, twenty four (24) 

hour event. The facility shall be designed and constructed with a run-on control 

system to prevent flow onto the facility during peak discharge and a run-off 

control system to contain the water volume from a twenty-five (25) year, twentyfour (24) hour storm. 

(6) Waste profile. For each type of waste, the amounts to be received and managed by the 

facility shall be estimated on a monthly average basis. For each waste type to be treated, 

a characteristic waste profile shall be completed.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 148

(7) Facility design and engineering. Facility design and engineering data, including plans and 

elevations, design basis, calculations, and process description.

A. Geologic data, including, but not limited to: 

i. Type and thickness of unconsolidated soils; 

ii. Type and thickness of consolidated bedrock, if applicable; 

iii. Local and regional geologic structures; and

iv. Any geologic hazards that may affect the design and operation of the facility. 

B. Hydrologic data, including, but not limited to: 

i. Surface water features within two (2) miles; 

ii. Depth to shallow ground water and major aquifers; 

iii. Water wells within one (1) mile of the site boundary and well depth, depth to 

water, screened intervals, yields, and aquifer name; 

iv. Hydrologic properties of shallow ground water and major aquifers including 

flow direction, flow rate, and potentiometric surface;

v. Site location in relation to the floodplain of nearby surface water features; 

vi. Existing quality of shallow ground water; and

vii. An evaluation of the potential for impacts to nearby surface water and ground 

water. 

C. Engineering data, including, but not limited to:

i. Type and quantity of material required for use as a liner, including design 

components; 

ii. Location and depth of cut for liners; 

iii. Location, dimensions, and grades of all surface water diversion structures; 

iv. Location and dimensions of all surface water containment structures; and

v. Location of all proposed facility structures and access roads. 

(8) Operating plan. An operating plan, including, but not limited to:

A. A, a detailed description of the method of treatment, loading rates, and application of 

nutrients and soil amendments;,

B. Ddust and moisture control;,

C. Ssampling;,

D. Iinspection and maintenance;,
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 149

E. Eemergency response;,

F. Rrecord-keeping;,

G. Ssite security;,

H. Hhours of operation;,

I. Noise and odor mitigation; and 

J. Ffinal disposition of waste. Where treated waste will be beneficially reused, a 

description of reuse and method of product quality assurance shall be included.

(9) Ground water monitoring.

A. Water Wells.

Water samples shall be collected from water wells within a one (1) mile radius of the 

proposed facility and shall be analyzed to establish baseline water quality. Analytical 

parameters shall be selected based upon the proposed waste stream and shall include, 

at a minimum, all major cations and anions, total dissolved solids, iron and manganese, 

nutrients (nitrates, nitrites, selenium), benzene, toluene, ethylbenzene, xylenes, pH, and 

specific conductance. Operators shall use reasonable good faith efforts to obtain access 

to such water wells for the purpose of collecting water samples. If access cannot be 

obtained, then the operator shall notify the Director of the wells for which access was not 

obtained and sampling of such wells by the operator shall not be required. Not 

conducting sampling because access to water wells cannot be obtained shall not be 

grounds for denial of the proposed facility. 

Copies of all test results described above shall be provided to the Director and the water 

well owner within three (3) months of collecting the samples. Laboratory results shall also 

be submitted to the Director in an electronic data deliverable format. 

B. Site-specific monitoring wells.

i. Where applicable, Tthe Director may shall require ground water monitoring for 

the purpose of preventing and mitigating threatened or actual significant 

adverse environmental impact or to ensure compliance with the 

allowable concentrations and levels in Table 910-1 and, with 

consideration to WQCC standards and classifications by establishing 

points of compliance, unless an oil and gas operator demonstrates to the 

satisfaction of the Director that an alternative method offering equivalent 

protection of public health, safety, and welfare, including the environment 

and wildlife resources, can be employed and provided the operator 

employs a dual liner with a leak detection system that provides for 

immediate leak detection from the uppermost liner. All monitoring well 

construction must be completed in accordance with the State Engineer’s 

regulations on well construction, “Water Well Construction Rules” (2 

C.C.R. 402-2).

Bii. Where monitoring is required, the direction of flow, ground water gradient 

and quality of water shall be established by the installation of a minimum 

of three (3) monitor wells, including an up-gradient well and two (2) 

down-gradient wells that will serve as points of compliance, or other 

methods authorized by the Director.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 150

(10) Surface water monitoring. Where applicable, the Director shall require baseline and 

periodic surface water monitoring to ensure compliance with WQCC surface water 

standards and classifications.

(11) Contingency plan. A contingency plan that describes the emergency response operations 

for the facility, 24-hour contact information for the person who has authority to initiate 

emergency response actions, and an outline of responsibilities under the joint operating 

agreement regarding maintenance, closure, and monitoring of the facility. 

c. Permit approval. The Director shall endeavor to approve or deny the properly completed permit within 

thirty (30) days after receipt and may condition permit approval as necessary to prevent any 

threatened or actual significant adverse environmental impact on air, water, soil or biological 

resources or to the extent necessary to ensure compliance with the allowable concentrations and

levels in Table 910-1, with consideration to WQCC ground water standards and classifications.

d. Financial assurance. The operator of a centralized E&P waste management land treatment facility 

shall submit for the Director's approval such financial assurance as required by Rule 704. prior to 

issuance of the operating permit. 

e. Facility modifications. Throughout the life of the facility the operator shall submit proposed 

modifications to the facility design, operating plan, permit data, or permit conditions to the Director 

for prior approval.

f. Annual permit review. To ensure compliance with permit conditions and the 900 Series rules, the 

facility permit shall be subject to an annual review by the Director. To facilitate this review, the 

operator shall submit an annual report summarizing operations, including the types and volumes 

of waste actually handled at the facility. The Director may require additional information. 

g. Closure. A preliminary plan for closure shall be submitted with the centralized facility permit. A Site 

Investigation and Remediation Workplan, Form 27 shall be submitted sixty (60) days prior to 

closure for approval by the Director. The workplan shall describe the final closure plan.

(1) Preliminary closure plan. A general preliminary plan for closure shall be submitted with the 

centralized E&P waste management facility permit, Form 28. The preliminary closure 

plan shall include, but not be limited to:

A. A general plan for closure and reclamation of the entire facility, including a description 

of the activities required to decommission and remove all equipment, close and 

reclaim pits, dispose of or treat residual waste, collect samples as needed to 

verify compliance with soil and ground water standards, implement post-closure 

monitoring, and complete other remediation, as required. 

B. The preliminary closure plan shall include an estimate of the cost to close and reclaim 

the entire facility and to conduct post-closure monitoring. Cost estimates shall be 

subject to review by the Director. 

(2) Final closure plan. A detailed Site Investigation and Remediation Workplan, Form 27, shall 

be submitted at least sixty (60) days prior to closure for approval by the Director. The 

workplan shall include, but not be limited to, a description of the activities required to 

decommission and remove all equipment, close and reclaim pits, dispose of or treat 

residual waste, collect samples as needed to verify compliance with soil and ground 

water standards, implement post-closure monitoring, and complete other remediation, as 

required. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 151

h. Operators may be subject to local requirements for zoning and construction of facilities and shall 

provide copies of notifications to local governments or other agencies to the Directorany approval 

notices, permits, or other similar types of notifications for the facility from local governments or 

other agencies to the Director for review prior to issuance of the operating permit.

909. SITE INVESTIGATION, REMEDIATION, AND CLOSURE

a. Applicability. This section applies to the closure and remediation of pits other than drilling pits 

constructed pursuant to Rule 903.a.(3);. Iinvestigation, reporting and remediation of 

spills/releases; permitted waste management facilities including treatment facilities; plugged and 

abandoned wellsites; sites impacted by E&P waste management practices; or other sites as 

designated by the Director.

b. General site investigation and remediation requirements.

(1) Sensitive Area Determination. Operators shall complete a sensitive area determination in 

accordance with Rule 901.e.

(2) Sampling and analyses. Samplinges and analysis of soil and ground water shall be 

conducted in accordance with Rule 910. to determine the horizontal and vertical extent of 

any contamination in excess of the allowable concentrations in Table 910-1.

(3) Management of E&P waste. E&P waste shall be managed in accordance with Rule 907.

(4) Pit evacuation. Prior to backfilling and site reclamation, E&P waste shall be treated or 

disposed in accordance with Rule 907. and the 1000 Series rules.

(5) Remediation. Remediation shall be performed in a manner to mitigate, remove, or reduce 

contamination that exceeds the allowable concentrations in Table 910-1 in order to 

ensure protection of public health, safety, and welfare, and to prevent and mitigate 

significant adverse environmental impacts. Soil that does not meet allowable 

concentrations in Table 910-1 shall be remediated. Ground water that does not meet 

allowable concentrations in Table 910-1 shall be remediated in accordance with a Site 

Investigation and Remediation Workplan, Form 27.

(6) Reclamation. Remediation sites shall be reclaimed in accordance with the 1000 Series rules 

for reclamation.

c. Site Investigation And Remediation Workplan, Form 27. Operators shall prepare and submit for 

prior Director approval a Site Investigation and Remediation Workplan, Form 27, for the following 

operations and remediation activities:

(1) Unlined pit closure when required by Rule 905.

(2) Remediation of spills/releases in accordance with Rule 906.

(3) Land treatment of oily waste in accordance with Rule 907.e.(2).F.

(4) Closure of centralized E&P waste management facilities in accordance with Rule 908.g.

(5) Remediation of impacted ground water in accordance with Rule 910.b.(4).

d. Multiple sites. Remediation of multiple sites may be submitted on a single workplan with prior Director 

approval.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 152

e. Closure.

(1) Remediation and reclamation shall be complete upon compliance with the allowable 

concentrations in Table 910-1, or upon compliance with an approved workplan.

(2) Notification of completion. Within thirty (30) days after conclusion of site remediation and 

reclamation activities operators shall provide the following notification of completion:

A. Operators conducting remediation operations in accordance with Rule 909.b. shall 

submit to the Director a Site Investigation and Remediation Workplan, Form 27, 

containing information sufficient to demonstrate compliance with these rules.

B. Operators conducting remediation under an approved workplan shall submit to the 

Director, by adding or attaching to the original workplan, information sufficient to 

demonstrate compliance with the workplan.

f. Release of financial assurance. Financial assurance required by Rule 706. may be held by the 

Director until the required remediation of soil and/or ground water impacts is completed in 

accordance with the approved workplan, or until cleanup goals are met.

910. ALLOWABLE CONCENTRATIONS AND SAMPLING FOR SOIL AND GROUND WATER

a. Soil and groundwater allowable concentrations. The allowable concentrations for soil and ground 

water are in Table 910-1. Ground water standards and analytical methods are derived from the 

ground water standards and classifications established by WQCC.

b. Sampling and analysis.

(1) Existing workplans. Sampling and analysis for sites subject to an approved workplan shall 

be conducted in accordance with the workplan and the sampling and analysis 

requirements described in this rule.

(2) Methods for sampling and analysis. Sampling and analysis for site investigation or 

confirmation of successful remediation shall be conducted to determine the nature and 

extent of impact and confirm compliance with appropriate allowable concentration levels

in Table 910-1.

A. Field analysis. Field measurements and field tests shall be conducted using 

appropriate equipment, calibrated and operated according to manufacturer 

specifications, by personnel trained and familiar with the equipment.

B. Sample collection. Samples shall be collected, preserved, documented, and shipped 

using standard environmental sampling procedures in a manner to ensure 

accurate representation of site conditions.

C. Laboratory analytical methods. Laboratories shall analyze samples using standard 

methods (such as EPA SW-846 or API RP-45) appropriate for detecting the 

target analyte. The method selected shall have detection limits less than or equal 

to the allowable concentrations in Table 910-1.

D. Background sampling. Samples of comparable, nearby, non-impacted, native soil, 

ground water or other medium may be required by the Director for establishing 

background conditions.

(3) Soil sampling and analysis.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 153

A. Applicability. If soil contamination is suspected or known to exist as a result of 

spills/releases or E&P waste management, representative samples of soil shall 

be collected and analyzed in accordance with this rule.

B. Sample collection. Samples shall be collected from areas most likely to have been 

impacted, and the horizontal and vertical extent of contamination shall be 

determined. The number and location of samples shall be appropriate to the 

impact.

C. Sample analysis. Soil samples shall be analyzed for contaminants listed in Table 

910-1 as appropriate to assess the impact or confirm remediation. The analytical 

parameters shall be selected based on site-specific conditions and process 

knowledge and shall be agreed to and approved by the Director.

D. Reporting. Soil Analysis Report, Form 24, shall be used when the Director requires

results of soil analyses.

E. Soil impacted by produced water. For impacts to soil due to produced water, 

samples from comparable, nearby non-impacted, native soil shall be collected 

and analyzed for purposes of establishing background soil conditions including 

pH and electrical conductivity (EC). Where EC of the impacted soil exceeds the 

allowable level in Table 910-1, the sodium adsorption ratio (SAR) shall also be 

determined.

F. Soil impacted by hydrocarbons. For impacts to soil due to hydrocarbons, samples 

shall be analyzed for TPH.

(4) Ground water sampling and analysis.

A. Applicability. Operators shall collect and analyze representative samples of ground 

water in accordance with these rules under the following circumstances:

(i) Where ground water contamination is suspected or known to exceed the 

allowable concentrations in Table 910-1;

(ii) Where impacted soils are in contact with ground water; or

(iii) Where impacts to soils extend down to the high water table.

B. Sample collection. Samples shall be collected from areas most likely to have been 

impacted, downgradient or in the middle of excavated areas. The number and 

location of samples shall be appropriate to determine the horizontal and vertical 

extent of the impact. If the concentrations in Table 910-1 are exceeded, the 

direction of flow and a ground water gradient shall be established, unless the 

extent of the contamination and migration can otherwise be adequately 

determined.

C. Sample analysis. Ground water samples shall be analyzed for benzene, toluene, 

ethylbenzene, xylene, and API RP-45 constituents, or other parameters 

appropriate for evaluating the impact. The analytical parameters shall be 

selected based on site-specific conditions and process knowledge and shall be 

agreed to and approved by the Director. 

D. Reporting. Water Analysis Report, Form 25, shall be used when the Director requires 

results of water analyses.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 154

E. Impacted ground water. Where ground water contaminants exceed the allowable 

concentrations listed in Table 910-1, operators shall notify the Director, and 

submit to the Director for prior approval a Site Investigation and Remediation 

Workplan, Form 27, for the investigation, remediation, or monitoring of ground 

water to meet the required allowable concentrations in Table 910-1.

911. PIT, BURIED OR PARTIALLY BURIED PRODUCED WATER VESSEL, BLOWDOWN PIT, AND 

BASIC SEDIMENT/TANK BOTTOM PIT MANAGEMENT REQUIREMENTS PRIOR TO 

DECEMBER 30, 1997.

a. Applicability. This rule applies to the management, operation, closure and remediation of drilling, 

production and special purpose pits, buried or partially buried produced water vessels, blowdown 

pits, and basic sediment/tank bottom pits put into service prior to December 30, 1997 and unlined 

skim pits put into service prior to July 1, 1995. For pits constructed after December 30, 1997 and 

skim pits constructed after July 1, 1995, operators shall comply with the requirements contained 

in Rules 901. through 910.

b. Inventory. Operators were required to submit to the Director no later than December 31, 1995, an 

inventory identifying production pits, buried or partially buried produced water vessels, blowdown 

pits, and basic sediment/tank bottom pits that existed on June 30, 1995. The inventory required 

operators to provide the facility name, a description of the location, type, capacity and use of 

pit/vessel, whether netted or fenced, lined or unlined, and where available, water quality data. 

Operators who have failed to submit the required inventory are in continuing violation of this rule.

c. Sensitive area determination.

(1) For unlined production and special purpose pits constructed prior to July 1, 1995 and not 

closed by December 30, 1997, operators were required to determine whether the pit was 

located within a sensitive area in accordance with the Sensitive Area Determination 

Decision Tree, Figure 901-1, (now Rule 901.e.), and submit data evaluated and analysis 

used in the determination to the Director on a Sundry Notice, Form 4. In December 

2008, Figure 901-1 was deleted from the 900-Series Rules. 

(2) For steel, fiberglass, concrete, or other similar produced water vessels that were buried or 

partially buried and located in sensitive areas prior to December 30, 1997, operators 

were required to test such vessels for integrity, unless a monitoring or leak detection 

system was put in place.

d. The following permitting/reporting requirements applied to pits constructed prior to December 30, 

1997:

(1) A Sundry Notice, Form 4, including the name, address, and phone number of the primary 

contact person operating the production pit for the operator, the facility name, a 

description of the location, type, capacity and use of pit, engineering design, installation 

features and water quality data, if available, was required for the following:

A. Lined production pits and lined special purpose pits constructed after July 1, 1995.

B. Unlined production pits constructed prior to July 1, 1995 which are lined in 

accordance with Rule 905. by December 30, 1997.

(2) An Application For Permit For Unlined Pit, Form 15 was required for the following:

A. Unlined production pits and special purpose pits in sensitive areas constructed prior to 

July 1, 1995, and not closed by December 30, 1997.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 155

B. Unlined production pits outside sensitive areas constructed after July 1, 1995 and not 

closed by December 30, 1997.

(3) An Application For Permit For Unlined Pit, Form 15 and a variance under Rule 904.e.(1). 

(repealed, now Rule 502.b.) was required for unlined production pits and unlined special 

purpose pits in sensitive areas constructed after July 1, 1995.

(4) A Sundry Notice, Form 4 was required for unlined production pits outside sensitive areas 

receiving produced water at an average daily rate of five (5) or less barrels per day 

calculated on a monthly basis for each month of operation constructed prior to December 

30, 1997.

e. The Director may have established points of compliance for unlined production pits and special 

purpose pits and for lined production pits in sensitive areas constructed after July 1, 1995.

f. Closure requirements.

(1) Operators of production or special purpose pits existing on July 1, 1995 which were closed 

before December 30, 1997, were required to submit a Sundry Notice, Form 4, within thirty 

(30) days of December 30, 1997. The Sundry Notice, Form 4 shall include a copy of the 

existing pit permit, if a permit was obtained, and a description of the closure process.

(2) Pits closed prior to December 30, 1997 were required to be reclaimed in accordance with the 

1000 Series rules. Pits closed after December 30, 1997 shall be closed in accordance 

with the 900 Series rules and reclaimed in accordance with the 1000 Series rules.

(3) Operators of steel, fiberglass, concrete or other similar produced water vessels buried or 

partially buried and located in sensitive areas were required to repair or replace vessels 

and tanks found to be leaking. Operators shall repair or replace vessels and tanks found 

to be leaking. Operators shall submit to the Director a Sundry Notice, Form 4, describing 

the integrity testing results and action taken within thirty (30) days of December 30, 1997.

(4) Closure of pits and steel, fiberglass, concrete or other similar produced water vessels, and 

associated remediation operations conducted prior to December 30, 1997 are not subject 

to Rules 905., 906., 907., 909. and 910.

912. VENTING OR FLARING NATURAL GAS

a. The unnecessary or excessive venting or flaring of natural gas produced from a well is prohibited.

b. Except for gas flared or vented during an upset condition, well maintenance, well stimulation flowback, 

purging operations, or a productivity test, gas from a well shall be flared or vented only after 

notice has been given and approval obtained from the Director on a Sundry Notice, Form 4, 

stating the estimated volume and content of the gas. The notice shall indicate whether the gas 

contains more than one (1) ppm of hydrogen sulfide. If necessary to protect the public health, 

safety or welfare, the Director may require the flaring of gas.

c. Gas flared, vented or used on the lease shall be estimated based on a gas-oil ratio test or other 

equivalent test approved by the Director, and reported on Operator's Monthly Production Report, 

Form 7.

d. Flared gas that is subject to Sundry Notice, Form 4, shall be directed to a controlled flare in 

accordance with Rule 903.b.(2) or other combustion device operated as efficiently as possible to 

provide maximum reduction of air contaminants where practicable and without endangering the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 156

safety of the well site personnel and the publicPrior to flaring of any gas, operators shall construct 

a special purpose pit in compliance with Rule 903.

e. Operators shall notify the local emergency dispatch or the local governmental designee of any natural 

gas flaring. Notice shall be given prior to flaring when flaring can be reasonably anticipated, or as 

soon as possible, but in no event more than two (2) hours after the flaring occurs.

Table 910-1 ALLOWABLE CONCENTRATIONS AND LEVELS

404-1_912.jpg

Figure 901-1 SENSITIVE AREA DETERMINATION Decision Tree

404_1_49.jpg

Table 910-1

ALLOWABLE CONCENTRATIONS AND LEVELS1

Contaminant of Concern Allowable Concentrations

Organic Compounds in Soil: EPA Method 8015 (modified)

TPH-Non-Sensitive Area 10,000 mg/kg

TPH (total volatile and extractable petroleum 

hydrocarbons)-Sensitive Area

 1,000 500 mg/kg

Benzene 0.17 mg/kg2

Toluene 85 mg/kg2

Ethylbenzene 100 mg/kg2

Xylenes (total 175 mg/kg2

Acenaphthene 1,000 mg/kg2

Anthracene 1,000 mg/kg2

Benzo(A)anthracene 0.22 mg/kg2

Benzo(B)fluoranthene 0.22 mg/kg2

Benzo(K)fluoranthene 2.2 mg/kg2

Benzo(A)pyrene 0.022 mg/kg2

Chrysene 22 mg/kg2

Dibenzo(A,H)anthracene 0.022 mg/kg2

Fluoranthene 1,000 mg/kg2

Fluorene 1,000 mg/kg2

Indeno(1,2,3,C,D)pyrene 0.22 mg/kg2

Napthalene 23 mg/kg2

Pyrene 1,000 mg/kg2

Organic Compounds in Ground Water: EPA Method 8020 1

Benzene 5 g/l 13

Toluene 560 to 1,000 g/l 13

 

Ethylbenzene 700 g/l 13

 

Xylenes (Total) 1,400 to 10,000 g/l 53,4

 

Inorganics in Soils4

Electrical Conductivity (EC) <4 mmhos/cm or 2x background

Sodiumn Adsorption Ratio (SAR) <125

pH 6-9

Inorganics in Ground Water

Total Dissolved Solids (TDS) <1.25 x background 13 

Chlorides <1.25 x background 13 

Sulfates <1.25 x background 13 

Total Metals in Soils: EPA Method 3050 4

Arsenic 410.39 mg/kg 22

Barium (LDNR True Total Barium) 18015,000 mg/kg 22 

Boron (Hot Water Soluble) 2 mg/l 32 

Cadmium 2670 mg/kg 3,62 

Chromium (III) 1,500120,000 mg/kg 22

Chromium (VI) 23 mg/kg2,6
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 157

Copper 7503,100 mg/kg 22 

Lead (inorganic) 3400 mg/kg 22 

Mercury 1723 mg/kg 22 

Molybdenum 

3 

Nickel (soluble salts) 2101,600 mg/kg 22,6 

Selenium 390 mg/kg2,6

 

3 

Silver 100390 mg/kg 22 

Zinc 1,40023,000 mg/kg 22,6 

Liquid Hydrocarbons in Soils and Ground Water

Liquid hydrocarbons including condensate 

and oil

Below detection level

COGCC recommends that the latest version of EPA SW 846 analytical methods be used where possible and 

that analyses of samples be performed by laboratories that maintain state or national accreditation programs. 

1 Consideration shall be given to background levels in native soils and ground water. 

21 Concentrations taken from CDPHE-HMWMD Table 1 Colorado Soil Evaluation Values (December 2007).

3 Concentrations taken from CDPHE-WQCC Regulation 41 - The Basic Standards for Ground Water. 

4 For this range of standards, the first number in the range is a strictly health-based value, based on the WQCC’s 

established methodology for human health-based standards. The second number in the range is a maximum 

contaminant level (MCL), established under the Federal Safe Drinking Water Act which has been determined to be an 

acceptable level of this chemical in public water supplies, taking treatability and laboratory detection limits into 

account. The WQCC intends that control requirements for this chemical be implemented to attain a level of ambient 

water quality that is at least equal to the first number in the range except as follows: 1) where ground water quality 

exceeds the first number in the range due to a release of contaminants that occurred prior to September 14, 2004 

(regardless of the date of discovery or subsequent migration of such contaminants) clean-up levels for the entire 

contaminant plume shall be no more restrictive than the second number in the range or the ground water quality 

resulting from such release, whichever is more protective, and 2) whenever the WQCC has adopted alternative, sitespecific standards for the chemical, the site-specific standards shall apply instead of these statewide standards. 

2 Concentrations taken from API Metals Guidance: Maximum Soil Concentrations

3 Concentrations are dependent on site-specific conditions

4 Consideration shall be given to background levels in native soils

5

 Analysis by USDA Agricultural Handbook 60 method (20B) with soluble cations determined by method (2). Method 

(20B) = estimation of exchangeable sodium percentage and exchangeable potassium percentage from soluble 

cations. Method (2) = saturated paste method (note: each analysis requires a unique sample of at least 500 grams). If 

soils are saturated, USDA Agricultural Handbook 60 with soluble cations determined by method (3A) saturation 

extraction method. 

6

 The table value for these inorganic constituents is taken from the CDPHE-HMWMD Table 1 Colorado Soil 

Evaluation Values (December 2007). However, because these values are high, it is possible that site-specific 

geochemical conditions may exist that could allow these constituents to migrate into ground water at levels exceeding 

ground water standards even though the concentrations are below the table values. Therefore, when these 

constituents are present as contaminants, a secondary evaluation of their leachability must be performed to ensure 

ground water protection. 

5 For this range of standards, the first number in the range is a strictly health-based value, based on the WQCC’s 

established methodology for human health-based standards. The second number in the range is a maximum 

contaminant level (MCL), established under the Federal Safe Drinking Water Act which has been determined to be an 

acceptable level of this chemical in public water supplies, taking treatability and laboratory detection limits into account. 

The WQCC intends that control requirements for this chemical be implemented to attain a level of ambient water quality 

that is at least equal to the first number in the range except as follows: 1) where ground water quality exceeds the first 

number in the range due to a release of contaminants that occurred prior to September 14, 2004 (regardless of the date 

of discovery or subsequent migration of such contaminants) clean-up levels for the entire contaminant plume shall be no 

more restrictive than the second number in the range or the ground water quality resulting from such release, whichever 

is more protective, and 2) whenever the WQCC has adopted alternative, site-specific standards for the chemical, the 

site-specific standards shall apply instead of these statewide standards.

1000-SERIES RECLAMATION REGULATIONS

1001. INTRODUCTION
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 158

a. General. The rules and regulations of this series establish the proper reclamation of the land and soil 

affected by oil and gas operations and ensure the protection of the topsoil of said land during 

such operations. The surface of the land shall be restored as nearly as practicable to its condition 

at the commencement of drilling operations.

b. Additional requirements. Notwithstanding the provisions of the 1000 sSeries rules, when the 

Director has reasonable cause to believe that a proposed oil and gas operation could res ult in a 

significant adverse en vironmental impact on any air, water, soil, or biological resource, the 

Director shall conduct an onsite inspection and may request an emergency meeting of the 

Commission to address the issue.

1001. RECLAMATION VARIANCES

c. Surface owner waiver of 1000-Series Rules. The Commission shall not require compliance with 

Rules 1002. (except Rules 1002.e.(1), 1002.e.(4), and 1002.f, for which compliance will continue 

to be required), Rule 1003., or Rule 1004 (except Rules 1004.c.(4) and 1004.c.(5), for which 

compliance will continue to be required). a. b. or c.(1), (2), Or (3), if the operator can demonstrate 

to the Director's or the Commission's satisfaction both that compliance with such rules is not 

necessary to protect the public health, safety and welfare, including prevention of significant 

adverse environmental impacts, and that the operator has entered into an agreement with the 

surface owner regarding topsoil protection and reclamation of the land. Absent bad faith conduct 

by the operator, penalties may only be imposed for non-compliance with a Commission order 

issued after a determination that, not withstanding such agreement, compliance is necessary to 

protect public health, safety and welfare. Prior to final reclamation approval as to a specific well, 

the operator shall either comply with the rules or obtain a variance under Rule 502.(b). This rule 

shall not have the effect of relieving an operator from compliance with the 900 Series Rules.

1002. SITE PREPARATION AND STABILIZATION

a. Effective June 1, 1996:

(1) Fencing of drill sites and access roads on crop lands. During drilling operations on crop 

lands, when requested by the surface owner, the operator shall delineate each drillsite 

and access road on crop lands constructed after such date by berms, single strand fence,

or other equivalent method in order to discourage unnecessary surface disturbances.

(2) Fencing of reserve pit when livestock is present. During drilling operations where 

livestock is in the immediate area and is not fenced out by existing fences, the operator, 

at the request of the surface owner, will install a fence around the reserve pit.

(3) Fencing of well sites. Subsequent to drilling operations, where livestock is in the immediate 

area and is not fenced out by existing fences, the operator, at the request of the surface 

owner, will install a fence around the wellhead, pit, and production equipment to prevent 

livestock entry.

b. Soil removal and segregation.

(1) Soil removal and segregation on crop land. As to all excavation operations undertaken 

after June 1, 1996 on crop land,, the operator shall separate and store the various A, B, 

and C soil horizons separately from one another and mark or document stockpile 

locations to facilitate subsequent reclamation. When separating soil horizons, the 

operator shall segregate horizons based upon noted changes in physical characteristics 

such as organic content, color, texture, density, or consistency. On crop land below the C 

horizon, the soil horizons shall also be seqregated based on the above noted physical 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 159

characteristics. Segregation will be performed to the extent practicable to a depth of six 

(6) feet or bedrock, whichever is shallower.

(2) Soil removal and segregation on non crop- land. As to all excavation operations 

undertaken after July 1, 1997 on non- crop land, the operator shall separate and store the 

A topsoil horizon or the top six (6) inches, whichever is deeper, and mark or document 

stockpile locations to facilitate subsequent reclamation. When separating the A soil 

horizons, the operator shall segregate the horizon based upon noted changes in physical 

characteristics such as organic content, color, texture, density, or consistency.

(3) Horizons too rocky or too thin. When the soil horizons are too rocky or too thin for the 

operator to practicably segregate, then the topsoil shall be segregated to the extent 

possible and stored. Too rocky shall mean that the soil horizon consists of greater than 

thirty five percent (35%) by volume rock fragments larger than ten (10) inches in 

diameter. Too thin shall mean soil horizons that are less than six (6) inches in thickness. 

The operator shall segregate remaining soils on crop land to the extent practicable to a 

depth of three (3) feet below the ground surface or bedrock, whichever is shallower, 

based upon noted changes in physical characteristics such as color, texture, density or 

consistency and such soils shall be stockpiled to avoid loss and mixing with other soils.

c. Protection of soils. All stockpiled soils shall be protected from degradation due to contamination, 

compaction and, to the extent practicable, from wind and water erosion during drilling and 

production operations. Best management practices to prevent weed establishment and to 

maintain soil microbial activityminimize erosion and offsite sedimentation by controlling 

stormwater runoff shall be implemented.

d. Drill pad location. The drilling location shall be designed and constructed to provide a safe working 

area while reasonably minimizing the total surface area disturbed. Consistent with applicable 

spacing orders and well location orders and regulations, in locating drill pads, steep slopes shall 

be avoided when reasonably possible. The drill pad site shall be located on the most level 

location obtainable that will accommodate the intended use. If not avoidable, dDeep vertical cuts 

and steep long fill slopes shall be constructed to the least percent slope practical. Where feasible, 

operators shall use directional drilling to reduce cumulative impacts and adverse impacts on 

wildlife resources. Best management practices to minimize erosion and offsite sedimentation by 

controlling stormwater runoff shall be implemented.

e. Surface disturbance minimization; stormwater management.

(1) In order to reasonably minimize land disturbances and facilitate future reclamation, well sites, 

production facilities, gathering pipelines, and access roads shall be located, adequately 

sized, constructed, and maintained so as to reasonably control dust, and minimize 

erosion, alteration of natural features, and removal of surface materials, and degradation 

due to contamination. Best management practices to minimize erosion and offsite 

sedimentation by controlling stormwater runoff shall be implemented. These practices will 

vary with site specific conditions, such as slope, vegetative cover and proximity to water 

bodies, and may include silt fencing, straw bales, plant buffers, rock filter dikes, slope 

roughening, mulch and other measures designed to reduce erosion and minimize the 

transport of soil from disturbed areas.

(2) Operators shall avoid or minimize impacts to wetlands and riparian habitats to the degree 

practicable. 

(3) Where practicable, operators shall consolidate facilities and pipeline rights-of-way in order to 

minimize adverse impacts to wildlife resources, including fragmentation of wildlife habitat, 

as well as cumulative impacts. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 160

f.(4) Access roads. Existing roads shall be used to the greatest extent practicable to avoid 

erosion and minimize the land area devoted to oil and gas operations. Best management 

practices to minimize erosion and offsite sedimentation by controlling stormwater runoff 

shall be implemented. Roadbeds shall be engineered to avoid or minimize impacts to 

riparian areas or wetlands to the extent practicable. Unavoidable impacts shall be 

mitigated. Road crossings of streams shall be designed and constructed to allow fish 

passage, where practicable or appropriate. Where feasible and practicable, operators are 

encouraged to share access roads in developing a field. Where feasible and practicable, 

roads shall be routed to compleiment other land usage. To the greatest extent 

practicable, all vehicles used by the operator, contractors, and other parties associated 

with the well shall not travel outside of the original access road boundary. Repeated or 

flagrant instance(s) of failure to restrict lease access to lease roads which result in 

unreasonable land damage or crop losses shall be subject to a penalty under Rule 523.

f. Stormwater management.

(1) All oil and gas locations are subject to the Best Management Practices requirements of Rule 

1002.f.(2). In addition, upon the termination of a construction stormwater permit issued by 

the Colorado Department of Public Health and Environment for an oil and gas location, 

such oil and gas location is subject to the Post-Construction Stormwater Program 

requirements of Rule 1002.f.(3), except that such requirements are not applicable to Tier 

1 Oil and Gas Locations. 

(2) Oil and gas operators shall implement and maintain Best Management Practices (BMPs) at 

all oil and gas locations to control stormwater runoff in a manner that minimizes erosion, 

transport of sediment offsite, and site degradation. BMPs shall be maintained until the 

facility is abandoned and final reclamation is achieved pursuant to Rule 1004. Operators 

shall employ BMPs, as necessary to comply with this rule, at all oil and gas locations, 

including, but not limited to, well pads, soil stock piles, access roads, tank batteries, 

compressor stations, and pipeline rights of way. BMPs shall be selected based on sitespecific conditions, such as slope, vegetation cover, and proximity to water bodies, and 

may include maintaining in-place some or all of the BMPs installed during the 

construction phase of the facility. Where applicable based on site-specific conditions, 

operators shall implement BMPs in accordance with good engineering practices,

including measures such as: 

A. Covering materials and activities and stormwater diversion to minimize contact of 

precipitation and stormwater runoff with materials, wastes, equipment, and 

activities with potential to result in discharges causing pollution of surface waters.

B. Materials handling and spill prevention procedures and practices implemented 

for material handling and spill prevention of materials used, stored, or disposed 

of that could result in discharges causing pollution of surface waters. 

C. Erosion controls designed to minimize erosion from unpaved areas, including 

operational well pads, road surfaces and associated culverts, stream crossings, 

and cut/fill slopes. 

D. Self-inspection, maintenance, and good housekeeping procedures and 

schedules to facilitate identification of conditions that could cause breakdowns 

or failures of BMPs. These procedures shall include measures for maintaining 

clean, orderly operations and facilities and shall address cleaning and 

maintenance schedules and waste disposal practices. In conducting inspections 

and maintenance relative to stormwater runoff, operators shall consider seasonal 

factors, such as winter snow cover and spring runoff from snowmelt, to ensure 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 161

site conditions and controls are adequate and in place to effectively manage 

stormwater. 

E. Spill response procedures for responding to and cleaning up spills. The necessary 

equipment for spill cleanup shall be readily available to personnel. Spill 

Prevention, Control, and Countermeasure plans incorporated by reference must 

be identified in the Post-Construction Stormwater Management Program 

specified in Rule 1002.f.(3). 

F. Vehicle tracking control practices to control potential sediment discharges from 

operational roads, well pads, and other unpaved surfaces. Practices could 

include road and pad design and maintenance to minimize rutting and tracking, 

controlling site access, street sweeping or scraping, tracking pads, wash racks, 

education, or other sediment controls. 

(3) Operators of oil and gas facilities shall develop a Post-Construction Stormwater Program in 

compliance with this section no later than the time of termination of stormwater permits 

issued by the Colorado Department of Public Health and Environment for construction of 

oil and gas facilities. 

A. The Post-Construction Stormwater Program shall reflect good faith efforts by 

operators to select and implement BMPs intended to serve the purposes of this 

rule. BMPs shall be selected to address potential sources of pollution which may 

reasonably be expected to affect the quality of discharges associated with the 

ongoing operation of production facilities during the post-construction and 

reclamation operation of the facilities. Pollutant sources that must be addressed 

by BMPs, if present, include: 

i. Transport of chemicals and materials, including loading and unloading 

operations;

ii. Vehicle/equipment fueling; 

iii. Outdoor storage activities, including those for chemicals and additives; 

iv. Produced water and drilling fluids storage; 

v. Outdoor processing activities and machinery; 

vi. Significant dust or particulate generating processes;

vii. Erosion and vehicle tracking from well pads, road surfaces, and pipelines;

viii. Waste disposal practices; 

ix. Leaks and spills; and

x. Ground-disturbing maintenance activities.

B. The Post-Construction Stormwater Program shall be developed, supervised, 

documented, and maintained by a qualified person(s) with training or prior work 

experience specific to stormwater management. Employees and subcontractors 

shall be trained to make them aware of the BMPs implemented and maintained 

at the site and procedures for reporting needed maintenance or repairs. 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 162

Documentation shall include a description of the BMPs selected to ensure proper 

implementation, operation, and maintenance. 

C. Facility-specific maps, installation specification, and implementation criteria shall also 

be included when general operating procedures and descriptions are not 

adequate to clearly describe the implementation and operation of BMPs. 

1003. INTERIM RECLAMATION

a. General. Debris and waste materials other than de minimis amounts, including, but not limited to, 

concrete, sack bentonite and other drilling mud additives, sand plastic, pipe and cable, as well as 

equipment associated with the drilling, re-entry, or completion operations shall be removed. All 

E&P waste shall be handled according to the 900 Series rules. All pits, cellars, rat holes, and 

other bore holes unnecessary for further lease operations, excluding the drilling pit, will be 

backfilled as soon as possible after the drilling rig is released to conform with surrounding terrain. 

On crop land, if requested by the surface owner, guy line anchors shall be removed as soon as 

reasonably possible after the completion rig is released. When permanent guy line anchors are 

installed, it shall not be mandatory to remove them. When permanent guy line anchors are 

installed on cropland, care shall be taken to minimize disruption or cultivation, irrigation, or 

harvesting operations. If requested by the surface owner or its representative, the anchors shall 

be specifically marked, in addition to the marking required below, so as to facilitate farming 

operations. All guy line anchors left buried for future use shall be identified by a marker of bright 

color not less than four (4) feet in height and not greater than one (1) foot east of the guy line 

anchor. Material may be burned or buried on the premises only with the prior written consent of 

the surface owner, and with prior written notice to the surface tenant. Such burning or burial may 

be prohibited by other applicable law.In addition, all well sites and surface production facilities 

shall be maintained in accordance with Rule 603.j.

b. Interim reclamation of areas no longer in use. All disturbed areas affected by drilling or subsequent 

operations, except areas reasonably needed for production operations or for subsequent drilling 

operations to be commenced within twelve (12) months, shall be reclaimed as early and as nearly 

as practicable to their original condition or their final land use as designated by the surface owner 

and shall be maintained to control dust and minimize erosion to the extent practicable. As to crop 

lands, if subsidence occurs in such areas additional topsoil shall be added to the depression and 

the land shall be re-leveled as close to its original contour as practicable. Interim reclamation 

shall occur no later than three (3) months on crop land or twelve (12) six (6) months on non-crop 

land after such operations unless the Director extends the time period because of conditions 

outside the control of the operator. Areas reasonably needed for production operations or for 

subsequent drilling operations to be commenced within twelve (12) months shall be compacted, 

covered, paved, or otherwise stabilized and maintained in such a way as to minimize dust and 

erosion to the extent practicable. 

c. Compaction alleviation. All areas compacted by drilling and subsequent oil and gas operations which 

are no longer needed following completion of such operations shall be cross-ripped. On crop 

land, such compaction alleviation operations shall be undertaken when the soil moisture at the 

time of ripping is below thirty-five percent (35%) of field capacity. Ripping shall be undertaken to a 

depth of eighteen (18) inches unless and to the extent bed rock is encountered at a shallower 

depth.

d. Drilling pit closure. As part of interim reclamation, drilling pits shall be closed in the following manner:

(1) Drilling pit closure on crop land and within 100-year floodplain. On crop land or within 

the 100-year floodplain, water-based bentonitic drilling fluids, except de minimis

amounts, shall be removed from the drilling pit and disposed of in accordance with the 

900 Series rules. Operators shall ensure that soils meet the concentration levels of Table 

910-1, above. Drilling pit reclamation, including the disposal of drilling fluids and cuttings, 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 163

shall be performed in a manner so as to not result in the formation of an impermeable 

barrier. Any cuttings removed from the pit for drying shall be returned to the pit prior to 

backfilling, and no more than de minimis amounts may be incorporated into the surface 

materials. After the drilling pit is sufficiently dry, the pit shall be backfilled. The backfilling 

of the drilling pit shall be done to return the soils to their original relative positions.

Closing and reclamation of drilling pits shall occur no later than three (3) months after 

drilling and completion activities conclude. 

(2) Drilling pit closure on non-crop land. All drilling fluids shall be disposed of in accordance 

with the 900 Series rules. Operators shall ensure that soils meet the concentration levels 

of Table 910-1, above. After the drilling pit is sufficiently dry, the pit shall be backfilled. 

Materials removed from the pit for drying shall be returned to the pit prior to the 

backfilling. No more than de minimis amounts may be incorporated into the surface 

materials. The backfilling of the drilling pit will be done to return the soils to their as of 

August 30, 2001.original relative positions so that the muds and associated solids will be 

confined to the pit and not squeezed out and incorporated in the surface materials.

Closure and reclamation of drilling pits shall occur no later than six (6) months after 

drilling and completion activities conclude. 

(3) Minimum cover. On crop lands, a minimum of three (3) feet of backfill cover shall be applied 

over any remaining drilling pit contents. As to both crop lands and non-crop lands, during 

the two (2) year period following drilling pit closure, if subsidence occurs over the closed 

drilling pit location additional topsoil shall be added to the depression and the land shall 

be re-leveled as close to its original contour as practicable.

e. Restoration and revegetation. When a well is completed for production, all disturbed areas no longer 

needed will be restored and revegetated as soon as practicable.

(1) Revegetation of crop lands. All segregated soil horizons removed from crop lands shall be 

replaced to their original relative positions and contour, and shall be tilled adequately to 

re-establish a proper seedbed. The area shall be treated if necessary and practicable to 

prevent invasion of undesirable species and noxious weeds, and to control erosion. Any 

perennial forage crops that were present before disturbance shall be re-established.

(2) Revegetation of non-crop lands. All segregated soil horizons removed from non-crop lands

shall be replaced to their original relative positions and contour as near as practicable to 

achieve erosion control and long-term stability, and shall be tilled adequately in order to 

establish a proper seedbed. The disturbed area then shall be reseeded in the first 

favorable season following rig demobilization. Reseeding with species consistent with the 

adjacent plant community is encouraged. In the absence of an agreement between the 

operator and the affected surface owner as to what seed mix should be used, the 

operator shall consult with a representative of the local soil conservation district to 

determine the proper seed mix to use in revegetating the disturbed area. In an area 

where an operator has drilled or plans to drill multiple wells, in the absence of an 

agreement between the operator and the affected surface owner, the operator may rely 

upon previous advice given by the local soil conservation district in determining the 

proper seed mixes to be used in revegetating each type of terrain upon which operations 

are to be conducted.

Interim reclamation of all disturbed areas no longer in use shall be considered complete 

when all ground surface disturbing activities at the site have been completed, and all 

disturbed areas have been either built on, compacted, covered, paved, or otherwise 

stabilized in such a way as to minimize erosion to the extent practicable, or a uniform 

vegetative cover has been established that reflects pre-disturbance or reference area 

forbs, shrubs, and grasses with total percent plant cover of at least eighty percent (80%) 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 164

of pre-disturbance levels or reference areas, excluding noxious weeds. Re-seeding alone 

is not sufficient. 

(3) Interim reclamation completion notice, Form 4. The operator shall submit a Sundry 

Notice, Form 4, which describes the interim reclamation procedures and any associated 

mitigation measures performed, any changes, if applicable in the landowner’s designated 

final land use, and at a minimum four (4) photographs taken during the growing season 

facing each cardinal direction which document the success of the interim reclamation and 

one (1) photograph which documents the total cover of live perennial vegetation of 

adjacent or nearby undisturbed land or the reference area. Each photograph shall be 

identified by date taken, well name, GPS location, and direction of view.

f. Weed control. During drilling, production, and reclamation operations, all disturbed areas shall be kept 

reasonably as free of all undesirable plant species designated to be noxious weeds and 

undesirable species as practicable. Weed control measures shall be conducted in compliance 

with the Colorado Noxious Weed Act, C.R.S. §35-5.5-115 and the current rules pertaining to the 

administration and enforcement of the Colorado Noxious Weed Act. It is recommended that the 

operator consult with the local weed control agency or other weed control authority when weed

infestation occurs. It is the responsibility of the operator to monitor affected and reclaimed lands 

for noxious weed infestations. If applicable, the Director may require a weed control plan. 

1004. FINAL RECLAMATION OF WELL SITES AND ASSOCIATED PRODUCTION FACILITIES

a. Well sites and associated production facilities. Upon the plugging and abandonment of a well, all 

pits, mouse and rat holes and cellars shall be backfilled. All debris, abandoned gathering line 

risers and flowline risers, and surface equipment shall be removed within three (3) months of 

plugging a well. All access roads to plugged and abandoned wells and associated production 

facilities shall be closed, graded and recontoured. Culverts and any other obstructions that were 

part of the access road(s) shall be removed. Well locations, access roads and associated 

facilities shall be reclaimed. As applicable, compaction alleviation, restoration, and revegetation of 

well sites, associated production facilities, and access roads shall be performed to the same 

standards as established for interim reclamation under Rule 1003. All other equipment, supplies, 

weeds, rubbish, and other waste material shall be removed. The burning or burial of such 

material on the premises shall be performed in accordance with applicable local, state, or federal 

solid waste disposal regulations and in accordance with the 900-Series Rules. In addition, 

material may be burned or buried on the premises only with the prior written consent of the 

surface owner. Material may be burned or buried on the premises only with the prior written 

consent of the surface owner, and with prior written notice to the surface tenant. Such burning or 

burial shall be subject to applicable state and local law. All such reclamation work shall be 

completed within three (3) months on crop land and twelve (12) months on non-crop land after 

plugging a well or final closure of associated production facilities. The Director may grant an 

extension where unusual circumstances are encountered, but every reasonable effort shall be 

made to complete reclamation before the next local growing season.

b. Production and special purpose pit closure. The operator shall comply with the 900 series rules for 

the removal or treatment of E&P waste remaining in a production or special purpose pit before 

the pit may be closed for final reclamation. After any remaining E&P waste is removed or treated, 

all such pits must be back-filled to return the soils to their original relative positions. As to both 

crop lands and non-crop lands, if subsidence occurs over closed pit locations, additional topsoil 

shall be added to the depression and the land shall be re-leveled as close to its original contour 

as practicable.

c. Final reclamation threshold for release of financial assurance. Successful reclamation of the well 

site and access road will be considered completed when:
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 165

(1) On crop land, reclamation has been performed as per Rules 1003 and 1004, and observation 

by the Director over two growing seasons has indicated no significant unrestored 

subsidence.

(2) On non-crop land, reclamation has been performed as per Rules 1003 and 1004, and 

disturbed areas have been either built on, compacted, covered, paved, or otherwise 

stabilized in such a way as to minimize erosion to the extent practicable, or the total 

cover of live perennial vegetation, excluding noxious weeds, provides sufficient soils 

erosion control a uniform vegetative cover has been established that reflects predisturbance or reference area forbs, shrubs, and grasses with total percent plant cover of 

at least eighty percent (80%) of pre-disturbance or reference area levels, excluding 

noxious weeds, as determined by the Director through a visual appraisal. The Director 

shall consider the total cover of live perennial vegetation of adjacent or nearby 

undisturbed land, not including overstory or tree canopy cover, having similar soils, slope 

and aspect of the reclaimed area.

(3) Disturbances resulting from flow line installations shall be deemed adequately reclaimed 

when the disturbed area is reasonably capable of supporting the pre-disturbance land 

use.

(4) A Sundry Notice Form 4, has been submitted by the operator which describes the final 

reclamation procedures, any changes, if applicable, in the landowner’s designated final 

land use, and any mitigation measures associated with final reclamation performed by 

the operator, and

(5) A final reclamation inspection has been completed by the Director, there are no outstanding 

compliance issues relating to Commission rules, regulations, orders, permit conditions or 

the act, and the Director has notified the operator that final reclamation has been 

approved.

d. Final reclamation of all disturbed areas shall be considered complete when all activities disturbing the 

ground have been completed, and all disturbed areas have been either built upon, compacted, 

covered, paved, or otherwise stabilized in such a way as to minimize erosion, or a uniform 

vegetative cover has been established that reflects pre-disturbance or reference area forbs, 

shrubs, and grasses with total percent plant cover of at least eighty percent (80%) of predisturbance or reference area levels, excluding noxious weeds, or equivalent permanent, physical 

erosion reduction methods have been employed. Re-seeding alone is not sufficient. 

e. Weed control. All areas being reclaimed shall be kept as free as practicable of all undesirable plant 

species designated to be noxious weeds. Weed control measures shall be conducted in 

compliance with the Colorado Noxious Weed Act, C.R.S. §35-5.5-115 and the current rules 

pertaining to the administration and enforcement of the Colorado Noxious Weed Act. It is 

recommended that the operator consult with the local weed control agency or other weed control 

authority when weed infestation occurs. It is the responsibility of the operator to monitor affected 

and reclaimed lands for noxious weed infestations. If applicable, the Director may require a weed 

control plan.

1100-SERIES PIPELINE REGULATIONS

1101. INSTALLATION AND RECLAMATION

a. Notice. As of June 1, 2006, an operator of a gathering line which has segments subject to safety 

regulation by the Office of Pipeline Safety, U.S. Department of Transportation, shall notify the 

Commission thirty (30) days in advance of construction by filing a plan of construction in a format 

acceptable to the Director. Such plan shall also be provided to each local governmental designee 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 166

or local government jurisdiction traversed by such gathering line. The plan shall include the 

general design, construction schedule and route, including a map showing all crossings of public 

by-ways and natural and manmade watercourses.

ba. Material.

(1) Materials for pipe and other components of pipelines shall be:

A. Able to maintain the structural integrity of the pipeline under temperature, pressure, 

and other conditions that may be anticipated;

B. Compatible with the substances to be transported.

C. Locatable by a tracer line or location device placed adjacent to or in the trench of all 

buried nonmetallic pipelines to facilitate the location of such pipelines.

cb. Design. Each component of a pipeline shall be designed and installed to prevent failure from 

corrosion and to withstand anticipated operating pressures and other loadings without impairment 

of its serviceability. The pipe shall have sufficient wall thickness or be installed with adequate 

protection to withstand anticipated external pressures and loads that will be imposed on the pipe 

after installation.

dc. Cover.

(1) All installed pipelines shall have cover sufficient to protect them from damage. On crop land, 

all pipelines shall have a minimum cover of three (3) feet.

(2) Where an underground structure, geologic, economic or other uncontrollable condition 

prevent pipelines from being installed with minimum cover, or when there is a written 

agreement between the surface owner and the operator, the line may be installed with 

less than minimum cover or above ground.

ed. Excavation, backfill and reclamation.

(1) When pipelines cross crop lands, unless waived by the surface owner, the operator shall 

segregate topsoil while trenching, and trenches shall be backfilled so that the soils shall

be returned to their original relative positions and contour. This requirement to segregate 

and backfill topsoil shall not apply to trenches which are twelve (12) inches or less in 

width. Reasonable efforts shall be made to run pipelines parallel to crop irrigation rows on 

flood irrigated land.

(2) On crop lands and non-crop lands, pipeline trenches shall be maintained in order to correct 

subsidence and reasonably minimize erosion. Interim and final reclamation, including 

revegetation, shall be performed in accordance with the applicable 1000 Series rules.

fe. Pressure testing of flowlines.

(1) Before operating a segment of flowline it shall be tested to maximum anticipated operating 

pressure. In conducting tests, each operator shall ensure that reasonable precautions 

are taken to protect its employees and the general public. The testing may be conducted 

using well head pressure sources and well bore fluids, including natural gas. Such 

pressure tests shall be repeated once each calendar year to maximum anticipated 

operating pressure, and operators shall maintain records of such testing for Commission 

inspection for at least three (3) years.
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(2) Flowline segments operating at less than fifteen (15) psig are excepted from pressure testing 

requirements.

1102. OPERATIONS, MAINTENANCE, AND REPAIR

a. Maintenance.

(1) Each operator shall take reasonable precautions to prevent failures, leakage and corrosion of 

pipelines.

(2) Whenever an operator discovers any condition that could adversely affect the safe and 

proper operation of its pipeline, it shall correct it within a reasonable time. However, if the 

condition is of such a nature that it presents an immediate hazard to persons or property, 

the operator shall not operate the affected part of the system until it has corrected the 

unsafe condition.

b. Repair.

(1) Each operator shall, in repairing its pipelines, ensure that the repairs are made in a safe 

manner and are made so as to prevent injury to persons and damage to property.

(2) No operator shall use any pipe, valve, or fitting in repairing pipeline facilities unless the 

components meet the installation requirements of this section.

c. Marking.

(1) In designated high density areas, and where crossing public rights-of-way or utility easement, 

a marker shall be installed and maintained to identify the location of pipelines.

(2) The following shall be written legibly on a background of sharply contrasting color on each 

line marker:

"Warning", "Caution" or "Danger" followed by the words "gas (or name of natural gas or 

petroleum transported) pipeline" in letters at least one (1) inch high with one-quarter (1⁄4) inch 

stroke and the name of the operator and the telephone number where the operator can be 

reached at all times.

d. One Call participation. As to any pipelines over which the Commission has jurisdiction, each operator 

shall become a member of the Utility Notification Center of Colorado and participate in Colorado's 

One Call notification system, the requirements of which are established by §9-1.5-101., C.R.S. et 

seq.

e. Emergency response. As to gathering lines with segments subject to safety regulation by the Office 

of Pipeline Safety, U.S. Department of Transportation, the operator shall prepare and submit an 

emergency response plan to the Commission and to the county sheriff and each local 

government jurisdiction traversed by such pipeline segment.

1103. ABANDONMENT

Each pipeline abandoned in place shall be disconnected from all sources and supplies of natural gas and 

petroleum, purged of liquid hydrocarbons, depleted to atmospheric pressure, and cut off three (3) feet 

below ground surface, or the depth of the pipeline, whichever is less and sealed at the ends. This 

requirement shall also apply to compressor or gas plant feeder pipelines upon decommissioning or 

closure of a portion or all of a compressor station or gas plant. Notice of such abandonment shall be filed 

with the Commission and with the local governmental designee or local government jurisdiction.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 168

1200-SERIES PROTECTION OF WILDLIFE RESOURCES

1201. IDENTIFICATION OF WILDLIFE SPECIES AND HABITATS

Prior to the preparation of a Comprehensive Drilling Plan or the submittal of a Form 2A for a proposed 

new oil and gas location, an operator shall review the Sensitive Wildlife Habitat map and the Restricted 

Surface Occupancy map maintained by the Commission on its website to determine whether the 

proposed oil and gas location falls within Sensitive Wildlife Habitat or a Restricted Surface Occupancy 

area. The operator shall include this determination in the Form 2A or Comprehensive Drilling Plan.

1202. CONSULTATION

a. The purpose of consultation under Rule 306.c is to allow the Director to determine whether conditions 

of approval are necessary to minimize adverse impacts from the proposed oil and gas operations 

in the identified sensitive wildlife habitat and to evaluate requests for variances from the 

provisions of the 1200-Series Rules. For purposes of this rule, minimize adverse impacts shall 

mean wherever reasonably practicable, to (i) avoid adverse impacts from oil and gas operations 

on wildlife resources, (ii) minimize the extent and severity of those impacts that cannot be 

avoided, (iii) mitigate the effects of unavoidable remaining impacts, and (iv) take into 

consideration cost-effectiveness and technical feasibility with regard to actions taken and 

decisions made to minimize adverse impacts to wildlife resources, consistent with the other 

provisions of the Act. 

b. Unless excepted as set forth in Rule 1202.d, when a proposed new oil and gas location is located in 

sensitive wildlife habitat, the Colorado Division of Wildlife shall consult with the operator, the 

surface owner, and the Director in accordance with Rule 306.c prior to approval of a Form 2A to 

identify possible conditions of approval. 

c. Any conditions of approval resulting from such consultation shall be guided by the list of Best 

Management Practices for Wildlife Resources maintained on the Commission website. In 

selecting conditions of approval from such Best Management Practices or other sources, the 

Director shall consider the following factors, among other considerations: 

(1) The Best Management Practices for the producing geologic basin in which the oil and gas 

location is situated; 

(2) Site-specific and species-specific factors of the proposed new oil and gas location; 

(3) Anticipated direct and indirect effects of the proposed oil and gas location on wildlife 

resources; 

(4) The extent to which conditions of approval will promote the use of existing facilities and 

reduction of new surface disturbance; 

(5) The extent to which legally accessible, technologically feasible, and economically practicable 

alternative sites exist for the proposed new oil and gas location; 

(6) The extent to which the proposed oil and gas operations will use technology and practices 

which are protective of the environment and wildlife resources; 

(7) The extent to which the proposed oil and gas location minimizes surface disturbance and 

habitat fragmentation; 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 169

(8) The extent to which the proposed oil and gas location is within land used for residential, 

industrial, commercial, agricultural, or other purposes, and the existing disturbance 

associated with such use; and

(9) Permit conditions, lease terms, and surface use agreements that predate December 11, 

2008. 

d. Consultation under Rule 306.c shall not be required if: 

(1) The Director or Commission has previously approved a Form 2A or Comprehensive Drilling 

Plan which includes the proposed new oil and gas location; 

(2) The Colorado Division of Wildlife has previously approved, in writing, a wildlife mitigation plan 

or other wildlife protection or conservation plan that remains in effect for the area that 

includes the proposed new oil and gas location and the oil and gas location is in 

compliance with such plan; 

(3) The operator demonstrates that the identified habitat and/or species, where applicable, is not 

in fact present to support the identified species and use, such as where the proposed oil 

and gas location is located in a high density area, designated pursuant to Rule 603.b, or 

within an incorporated homeowners association or city or town limits; 

(4) The proposed new well would involve a one-time increase in surface disturbance of one (1) 

acre or less per well site at or immediately adjacent to an existing well site; 

(5) The operator applies for and obtains a Commission order pursuant to Rule 503 providing that 

there will not be more than three (3) well sites per section, with ground disturbing activity 

during the period from January 1 to March 31 (or other alternative period up to ninety (90) 

consecutive days as determined by the Director for bighorn sheep winter range, elk 

production areas, bald or golden eagle nest or roost sites, columbian or plains sharptailed grouse production areas, greater or Gunnison sage grouse production areas, or 

lesser prairie chicken production areas) limited to one (1) such well site, as determined 

by the Director. This exemption from consultation shall not apply to operations in 

occupied greater sage grouse sensitive wildlife habitat in Moffat, Routt, or Jackson 

Counties or in occupied Gunnison sage grouse sensitive wildlife habitat in Delta, Mesa, 

Gunnison, San Miguel, Dolores, or Montezuma Counties; 

(6) The Director grants a variance pursuant to Rule 502.b; or 

(7) The Colorado Division of Wildlife waives the consultation requirement. 

e. No permit-specific condition of approval for wildlife habitat protection under this rule shall be imposed 

without surface owner consent, including any permit-specific conditions for wildlife habitat 

protection that modify, add to, or differ materially from the general operating requirements in 

Rules 1203 and 1204. If the surface owner fails to consent to any such permit-specific condition 

of approval, then the parties shall consult with the surface owner regarding alternative conditions 

of approval acceptable to the surface owner. 

1203. GENERAL OPERATING REQUIREMENTS IN SENSITIVE WILDLIFE HABITAT

a. General Operating Requirements. Within sensitive wildlife habitat, operators shall comply with the 

operating requirements listed below. 

(1) During pipeline construction for trenches that are left open for more than five (5) days and are 

greater than five (5) feet in width, install wildlife crossovers and escape ramps where the 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 170

trench crosses well-defined game trails and at a minimum of one quarter (1/4) mile 

intervals where the trench parallels well-defined game trails.

(2) Inform and educate employees and contractors on wildlife conservation practices, including 

no harassment or feeding of wildlife.

(3) Consolidate new facilities to minimize impact to wildlife.

(4) Minimize rig mobilization and demobilization where practicable by completing or recompleting 

all wells from a given well pad before moving rigs to a new location.

(5) To the extent practicable, share and consolidate new corridors for pipeline rights-of-way and 

roads to minimize surface disturbance.

(6) Engineer new pipelines to reduce field fitting and reduce excessive right-of-way widths and 

reclamation.

(7) Use boring instead of trenching across perennial streams considered critical fish habitat. 

(8) Treat waste water pits and any associated pit containing water that provides a medium for 

breeding mosquitoes with Bti (Bacillus thuringiensis v. israelensis) or take other effective 

action to control mosquito larvae that may spread West Nile Virus to wildlife, especially 

grouse. 

(9) Use wildlife appropriate seed mixes wherever allowed by surface owners and regulatory 

agencies. 

(10) Mow or brushhog vegetation where appropriate, leaving root structure intact, instead of 

scraping the surface, where allowed by the surface owner. 

(11) Limit access to oil and gas access roads where approved by surface owners, surface 

managing agencies, or local government, as appropriate. 

(12) Post speed limits and caution signs to the extent allowed by surface owners, Federal and 

state regulations, local government, and land use policies, as appropriate. 

(13) Use wildlife-appropriate fencing where acceptable to the surface owner. 

(14) Use topographic features and vegetative screening to create seclusion areas, where 

acceptable to the surface owner. 

(15) Use remote monitoring of well production to the extent practicable. 

(16) Reduce traffic associated with transporting drilling water and produced liquids through the 

use of pipelines, large tanks, or other measures where technically feasible and 

economically practicable. 

b. Exceptions. If the operator believes that any of the foregoing operating requirements should be 

waived for any proposed oil and gas location, it shall so specify in a Form 2A for Director 

consideration. 

1204. OTHER GENERAL OPERATING REQUIREMENTS

a. The operating requirements identified below shall apply in all areas.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 171

(1) In black bear habitat west of Interstate 25 and on Raton Mesa east of Interstate 25, operators 

shall install and utilize bear-proof dumpsters and trash receptacles for food-related trash 

at all facilities that generate such trash. 

(2) In designated Cutthroat Trout habitat, as identified on the Colorado Division of Wildlife 

Species Activity Mapping (SAM) system, operators shall disinfect water suction hoses 

and water transportation tanks withdrawing from or discharging into surface waters (other 

than contained pits) used previously in another river, lake, pond, or wetland and discard 

rinse water in an approved disposal facility. Disinfection practices shall be repeated after 

completing work or before moving to the next water body. Disinfection may be performed 

by removing mud and debris and then implementing one of the following practices: 

A. Spray/soak equipment with a disinfectant solution capable of killing whirling disease 

spores; or

B. Spray/soak equipment with water greater than 140 degrees Fahrenheit for at least 10 

minutes. 

(3) Plan new transportation networks and new oil and gas facilities to minimize surface 

disturbance and the number and length of oil and gas roads and utilize common roads, 

rights of way, and access points to the maximum extent practicable, consistent with an 

operator’s operational requirements and any requirements imposed by federal and state 

land management agencies, local government regulations, and surface use agreements, 

and taking into account cost effectiveness and technical feasibility. 

(4) Establish new staging, refueling, and chemical storage areas outside of riparian zones and 

floodplains. 

(5) Use minimum practical construction widths for new rights-of-way where pipelines cross 

riparian areas, streams, and critical habitats. 

b. Exceptions. If the operator believes that any of the foregoing operating requirements should be 

waived for any proposed oil and gas location, it shall so specify in a Form 2A for Director 

consideration. 

1205. REQUIREMENTS IN RESTRICTED SURFACE OCCUPANCY AREAS

a. Operators shall avoid Restricted Surface Occupancy areas to the maximum extent technically and 

economically feasible when planning and conducting new oil and gas development operations, 

except: 

(1) When authorized following consultation under Rule 306.c.(3); 

(2) When authorized by a Comprehensive Drilling Plan; 

(3) Upon demonstration that the identified habitat is not in fact present; 

(4) When specifically exempted by the Colorado Division of Wildlife; or

(5) In the event of situations posing a risk to public health, safety, welfare, or the environment. 

b. As set forth in Rule 1205.a, new ground disturbing activities are to be avoided in Restricted Surface 

Occupancy areas, including construction, drilling and completion, non-emergency workovers, and 

pipeline installation activity, to minimize adverse impacts to wildlife resources. Production, routine 
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 172

maintenance, repairs and replacements, emergency operations, reclamation activities, or habitat 

improvements are not prohibited in Restricted Surface Occupancy areas. 

c. Applicability. The requirements of Rule 1205 are not applicable to Applications for Permit-to-Drill, 

Form 2, or Oil and Gas Location Assessments, Form 2A, which are approved prior to May 1, 

2009 on federal land or April 1, 2009 on all other land. The requirements of Rule 1205 are also 

not applicable until January 1, 2010, for any proposed oil and gas location in a Restricted Surface 

Occupancy area where the operator has in good faith initiated and is diligently pursuing 

consultation on the proposed oil and gas location prior to May 1, 2009 on federal land or April 1, 

2009 on all other land, pursuant to Rule 306.c or otherwise. 

State of Colorado Oil & Gas Conservation Commission

404_1_50.jpg

APPENDIX PART III FEE STRUCTURE

As of July 1, 1999 Eff 09/30/2007

DRILLING PERMIT Form 2 $0/well

RECOMPLETION PERMIT Form 2 $0/well

PIT PERMIT Form 15 $0/pit

CHANGE OF OPERATOR Form 10 $0/well

DISPOSAL/INJECTION 

PERMIT

Form 2 $0/well

OFFSITE LAND 

TREATMENT

Form 28 $0/site

HEARING APPLICATION _ $0

HEARING 

PROTEST/INTERVENTION

_ $0

GENERAL MAILING 

SUBSCRIPTION

_ $36.00/year

_____________________________________________________ Eff 09/30/2007

Editor’s Notes

History Eff 09/30/2007

Section 310 eff. 9/30/2007. Delete Section 310B eff. 9/30/2007. Eff 09/30/2007
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 173

Rule 319: Suggested Alternative Rule and Statement of Basis & Purpose Language 

During deliberations, the Commission provisionally approved the reinsertion of references to “shut-in” 

wells in Rule 319.B. 

The alternative rule language and additional statement of basis and purpose language, highlighted below, 

is suggested for adoption in the Commission’s final deliberations on December 9-11. This language was 

not included in the Final Draft Rules or addressed in the Final Draft Statement of Basis & Purpose 

distributed to the Commission on November 7, 2009. 

ALTERNATIVE RULE LANGUAGE

319. ABANDONMENT

The requirements for abandoning a well shall be as follows:

a. Plugging

(1) A dry or abandoned well, seismic, core, or other exploratory hole, must be plugged in such a 

manner that oil, gas, water, or other substance shall be confined to the reservoir in which 

it originally occurred. Any cement plug shall be a minimum of fifty (50) feet in length and 

shall extend a minimum of fifty (50) feet above each zone to be protected. The material 

used in plugging, whether cement, mechanical plug, or some other equivalent method 

approved in writing by the Director, must be placed in the well in a manner to 

permanently prevent migration of oil, gas, water, or other substance from the formation or 

horizon in which it originally occurred. The preferred plugging cement slurry is that 

recommended by the American Petroleum Institute (API) Environmental Guidance 

Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and 

Production Operations, i.e., a neat cement slurry mixed to API standards. However, 

pozzolan, gel and other approved extenders may be used if the operator can document 

to the Director's satisfaction that the slurry design will achieve a minimum compressive 

strength of three hundred (300) psi after twenty-four (24) hours and eight hundred (800) 

psi after seventy-two (72) hours measured at ninety-five degrees fahrenheit (95 °F) and 

at eight hundred (800) psi.

(2) The operator shall have the option as to the method of placing cement in the hole by (a) 

dump bailer, (b) pumping a balanced cement plug through tubing or drill pipe, (c) pump 

and plug, or (d) equivalent method approved by the Director prior to plugging. Unless 

prior approval is given, all wellbores shall have water, mud or other approved fluid 

between all plugs.

(3) No substance of any nature or description other than normally used in plugging operations 

shall be placed in any well at any time during plugging operations. All final reports of 

plugging and abandonment shall be submitted on a Well Abandonment Report, Form 6, 

and accompanied by a job log or cement verification report from the plugging contractor 

specifying the type of fluid used to fill the wellbore, type and slurry volume of API Class 

cement used, date of work, and depth the plugs were placed.

(4) In order to protect the fresh water strata, no surface casing shall be pulled from any well 

unless authorized by the Director.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 174

(5) All abandoned wells shall have a plug or seal placed at the surface of the ground or the 

bottom of the cellar in the hole in such manner as not to interfere with soil cultivation or 

other surface use. The top of the pipe must be sealed with either a cement plug and a 

screw cap, or cement plug and a steel plate welded in place or by other approved 

method, or in the alternative be marked with a permanent monument which shall consist 

of a piece of pipe not less than four (4) inches in diameter and not less than ten (10) feet 

in length, of which four (4) feet shall be above the general ground level, the remainder to 

be embedded in cement or to be welded to the surface casing.

(6) The operator must obtain approval from the Director of the plugging method prior to plugging, 

and shall notify the Director of the estimated time and date the plugging operation of any 

well is to commence, and identify the depth and thickness of all known sources of 

groundwater. For good cause shown, the Director may require that a cement plug be 

tagged if a cement retainer or bridge plug is not used. If requested by the operator, the 

Director shall furnish written follow-up documentation for a requirement to tag cement 

plugs.

(7) Wells Used for Fresh Water. When the well, seismic, core, or other exploratory hole to be 

plugged may safely be used as a fresh water well, and such utilization is desired by the 

landowner, the well need not be filled above the required sealing plug set below fresh 

water; provided that written authority for such use is secured from the landowner and, in 

such written authority, the landowner assumes the responsibility to plug the well upon its 

abandonment as a water well in accordance with these rules. Such written authority and 

assumption of responsibility shall be filed with the Commission, provided further that the 

landowner furnish a copy of the permit for a water well approved by the Division of Water 

Resources.

b. Shut-in and Temporary Abandonment.

(1) A well may be shut-in or temporarily abandoned when completed, upon approval of the 

Director, for a period not to exceed six (6) months provided the hole is cased or left in 

such a manner as to prevent migration of oil, gas, water or other substance from the 

formation or horizon in which it originally occurred. All shut-in or temporarily abandoned 

wells shall be closed to the atmosphere with a swedge and valve or packer, or other 

approved method. The well sign shall remain in place. If an operator requests shut-in or

temporary abandonment status in excess of six (6) months the operator shall state the 

reason for requesting such extension and state plans for future operation. A Sundry 

Notice, Form 4, or other form approved by the Director, shall be submitted annually 

stating the status of method the well is closed to the atmosphere and plans for future 

operation.

(2) The manner in which the well is to be maintained should be reported to the Commission, and 

bonding requirements, as provided for in Rule 304, kept in force until such time as the 

well is permanently abandoned.

(3) A well which has ceased production or injection or and is incapable of production or injection 

shall be abandoned within six (6) months thereafter unless the time is extended by the 

Director upon application by the owner. The application shall indicate why the well is 

shut-in temporarily abandoned and future plans for utilization. In the event the well is 

covered by a blanket bond, the Director may require an individual plugging bond on the 

shut-in or temporarily abandoned well. Gas storage wells are to be considered active at 

all times unless physically plugged.

(4) In addition to the requirements of Rule 324326, an injection well that is shut-in or temporarily 

abandoned shall have a mechanical integrity test performed within two years after the 

shut-in date in order to be retained in shut-in or temporarily abandoned status.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 175

(5) If an injection well which has been shut-in or temporarily abandoned is determined not to 

have mechanical integrity as a result of any test required by the Commission rules and 

regulations, it must, within six (6) months following such a test, be either repaired and 

pass a mechanical integrity test or be plugged and abandoned.

ADDITIONAL STATEMENT OF BASIS & PURPOSE LANGUAGE

Prior to the amendment, this requirement applied to both shut-in and abandoned wells. The rationale for 

deleting references to shut-in wells in this Rule is that operators must account for all shut-in wells every 

month on Form 7, Operator’s Monthly Report of Operations. While the COGCC has a great interest in the 

status of shut-in wells, it does not need to require operators to submit such information twice (monthly on 

a Form 7 and annually on a Form 4).

Rule 341: Suggested Alternative Rule and Statement of Basis & Purpose Language

During deliberations on Rule 341, the Commission provisionally approved a change that would provide 

operators with flexibility in monitoring pressure during well stimulation, particularly for shallow wells. 

The alternative rule language and additional statement of basis and purpose language, highlighted below, 

is suggested for adoption in the Commission’s final deliberations on December 9-11. This language was 

not included in the Final Draft Rules or addressed in the Final Draft Statement of Basis & Purpose 

distributed to the Commission on November 7, 2009. 

ALTERNATIVE RULE LANGUAGE

341. BRADENHEAD MONITORING DURING WELL STIMULATION OPERATIONS

The placement of all stimulation fluids shall be confined to the objective formations during treatment to the 

extent practicable. In lieu of recording annulus pressure, the bradenhead valve may be left open to 

monitor the annulus for flow during stimulation. Any abnormal flow shall be reported in the same manner 

as a pressure increase. For wells deeper than three thousand (3,000) feet or when surface casing is set 

deeper than five hundred (500) feet, prior approval from the Director will be required for this alternate 

method.

During stimulation operations, bradenhead annulus pressure shall be continuously monitored and 

recorded on all wells being stimulated. 

If at any time during stimulation operations the bradenhead annulus pressure increases more than 200 

psig the operator shall verbally notify the Director as soon as practicable, but no later than twenty-four 

(24) hours following the incident. Within fifteen (15) days after the occurrence, the operator shall submit a 

Sundry Notice, Form 4, giving all details, including corrective actions taken. 

If intermediate casing has been set on the well being stimulated, the pressure in the annulus between the 

intermediate casing and the production casing shall also be monitored and recorded. 

The operator shall keep all well stimulation records and pressure charts on file and available for 

inspection by the Commission for a period of at least five (5) years. Under Rule 502.b.(1), an operator 

may seek a variance from these bradenhead monitoring, recording, and reporting requirements under 

appropriate circumstances.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 176

ADDITIONAL STATEMENT OF BASIS & PURPOSE LANGUAGE

This rule includes a provision authorizing an operator to seek a variance from the bradenhead monitoring, 

recording, and reporting requirements under appropriate circumstances. The Commission discussed 

situations in which an operator may prefer to monitor the annulus for flow during stimulation rather than 

recording annulus pressure. If an operator proposes to do so, the Director could require the operator to 

report any abnormal flow in the same manner as a pressure increase. 

Multi-Well Pits: Suggested Alternative Rule and Statement of Basis & Purpose Language

During deliberations on Rule 902, the Commission provisionally approved a definition of the term “multiwell pits” and a rule provision allowing the Director to permit certain wells in accordance with Rule 903 to 

service multiple well sites. 

The alternative rule language and additional statement of basis and purpose language, highlighted below, 

is suggested for adoption in the Commission’s final deliberations on December 9-11. This language was 

not included in the Final Draft Rules or addressed in the Final Draft Statement of Basis & Purpose 

distributed to the Commission on November 7, 2009. 

ALTERNATIVE RULE LANGUAGE

100-SERIES DEFINITION

MULTI-WELL PITS shall mean pits used for treatment, storage, or disposal of E&P wastes generated 

from more than one (1) well that do not constitute a centralized E&P waste management facility and that 

will be in use for no more than three (3) years.

902. PITS - GENERAL AND SPECIAL RULES

a. Pits used for exploration and production of oil and gas shall be constructed and operated to protect 

public health, safety, and welfare and the environment, including soil, the waters of the state, and 

wildlife, from significant adverse environmental, public health, or welfare impacts from E&P 

waste, except as permitted by applicable laws and regulations.

b. Topsoil and subsoil removed in the construction of the pit shall be segregated and stockpiled in a 

manner described in Rule 1002. and used for reclamation of the site.

cb. Pits shall be constructed, monitored, and operated to provide for a minimum of two (2) feet of 

freeboard at all times between the top of the pit wall at its point of lowest elevation and the fluid 

level of the pit. A method of monitoring and maintaining freeboard shall be employed. Any 

unauthorized release of fluids from a pit shall be subject to the reporting requirements of Rule 

906. 

dc. Any accumulation of oil in a pit shall be removed within twenty-four (24) hours of discovery. Operators 

shall use skimming, steam cleaning of exposed liners, or other safe and legal methods as 

necessary to maintain pits in clean condition and to control hydrocarbon odors. Only de minimis 

amounts of hydrocarbons may be present unless the pit is specifically permitted for oil or 

condensate recovery or disposal use. A Form 15 pit permit may be revoked by the Director and 

the Director may require that the pit be closed if an operator repeatedly allows more than de 

minimis amounts of condensate to accumulate in a pit. This requirement is not applicable to 

properly permitted and properly fenced, lined, and or netted skim pits that are designed, 

constructed, and operated to prevent impacts to wildlife, including migratory birds.
COGCC Final Draft Rules: Commission Review Copy (Nov. 7, 2008) 177

ed. Where necessary to protect public health, safety and welfare or to prevent significant adverse 

environmental impacts resulting from access to a pit by wildlife, migratory birds, domestic 

animalis, or members of the general public, operators shall install appropriate netting or fencing.

fe. Multi-well pits. Production and special purpose pPits to be used for a period of no more than three 

(3) years for storage, recycling, reuse, treatment, or disposal of E&P waste or fresh water, as 

applicable, generated from more than one well may be permitted in accordance with Rule 903. to 

service multiple wellsas a multi-well pit, subject to Director approval.

gf. Unlined drilling pits shall not be constructed on fill material.

hg. Except as allowed under Rule 904.a, unlined pits shall not be constructed in areas where pathways 

for communication with ground water or surface water are likely to exist. 

h. Produced water shall be treated in accordance with Rule 907. before being placed in a production pit.

i. Operators shall utilize bleach or other safe biocide treatments to control bacterial growth and related 

odors as needed. 

ADDITIONAL STATEMENT OF BASIS & PURPOSE LANGUAGE

100-SERIES DEFINITION

Centralized E&P waste management facility pits are defined to be those in use for more than three (3) 

years; therefore, multi-well pits should be defined to be those in use for no more than three (3) years to 

avoid overlap. This distinction is important because the permitting, lining, financial assurance, clean-up,

and closure requirements applicable to those two categories of pits differ.

Rule 902.e

The purpose of adding the three (3) year temporal requirement is to further clarify the difference between: 

centralized E&P waste management facility pits that must be permitted under to Rule 908; and other pits 

for the storage, recycling, reuse, treatment, or disposal of E&P waste from multiple wells that may be 

permitted under Rule 903. The Commission intends that Rule 903 not be used to permit pits that store, 

recycle, reuse, treat, or dispose of E&P waste from multiple wells and that will be in use for more than 

three (3) years. This is because the Commission believes that such pits generally present greater risks to 

public health, safety, welfare and the environment which are better addressed under Rule 908. This 

clarification also provides additional clarity and consistency to Rule 902.e.